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, 2008

OR
 
o  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
(State or other jurisdiction of
 incorporation or organization)
76-0513049
(I.R.S. Employer
Identification No.)
   
919 Milam, Suite 2100, Houston, TX
(Address of principal executive offices)
77002
(Zip code)

Registrant's telephone number, including area code:
(713) 860-2500
 
Securities registered pursuant to Section 12(b) of the Act:
 
Title of Each Class
Name of Each Exchange on Which Registered
Common Units
NYSE Alternext US

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.
Yes  o    No  þ

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  o    No  þ
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  þ    No  o
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.

o  
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company.  See the definitions of “large accelerated filer”, ”accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer o
Accelerated filer     þ
Non-accelerated filer  o
Smaller reporting company o
 
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2) of the Act).

Yes  o   No  þ

The aggregate market value of the common units held by non-affiliates of the Registrant on June 30, 2008 (the last business day of Registrant’s most recently completed second fiscal quarter) was approximately $280,949,000 based on $18.45 per unit, the closing price of the common units as reported on the NYSE Alternext US (formerly the American Stock Exchange.)  For purposes of this computation, all executive officers, directors and 10% owners of the registrant are deemed to be affiliates.  Such a determination should not be deemed an admission that such executive officers, directors and 10% beneficial owners are affiliates.  On February 28, 2009, the Registrant had 39,456,774 common units outstanding.
 
 
 
 

GENESIS ENERGY, L.P.
2008 FORM 10-K ANNUAL REPORT
Table of Contents



   
Page
Part I
 
     
Item 1
4
Item 1A.
19
Item 1B.
35
Item 2.
35
Item 3.
35
Item 4.
35
     
Part II
 
     
Item 5.
35
Item 6.
37
Item 7.
39
Item 7A.
60
Item 8.
63
Item 9.
63
Item 9A.
63
Item 9B.
65
     
Part III
 
     
Item 10.
65
Item 11.
67
Item 12.
87
Item 13.
89
Item 14.
92
     
Part IV
 
     
Item 15.
92

2

FORWARD-LOOKING INFORMATION
 
The statements in this Annual Report on Form 10-K that are not historical information may be “forward looking statements” within the meaning of the various provisions of the Securities Act of 1933 and the Securities Exchange Act of 1934.  All statements, other than historical facts, included in this document that address activities, events or developments that we expect or anticipate will or may occur in the future, including things such as plans for growth of the business, future capital expenditures, competitive strengths, goals, references to future goals or intentions and other such references are forward-looking statements.  These 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”, sodium hydrosulfide and caustic soda 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 or bankruptcy 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.

3

PART I
 
Item 1.  B usine ss
 
Unless the context otherwise requires, references in this annual report to “Genesis Energy, L.P.,” “Genesis,” “we,” “our,” “us” or like terms refer to Genesis Energy, L.P. and its operating subsidiaries (including DG Marine, as defined); “DG Marine” means DG Marine Transportation, LLC and its subsidiaries; “Denbury” means Denbury Resources Inc. and its subsidiaries; “CO 2 ” means carbon dioxide; and “NaHS”, which is commonly pronounced as “nash”, means sodium hydrosulfide.
 
DG Marine is a joint venture in which we own an effective 49% economic interest.  Our joint venture partner holds a 51% economic interest and controls decision-making over most key operational matters.  For financial reporting purposes, we consolidate DG Marine as discussed in Note 3 to the Consolidated Financial Statements.  References in this annual report to DG Marine include 100% of the operations and activities of DG Marine unless the context indicates differently.
 
 Except to the extent otherwise provided, the information contained in this form is as of December 31, 2008.
 
General
 
We are a growth-oriented limited partnership focused on the midstream segment of the oil and gas industry in the Gulf Coast region of the United States, primarily Texas, Louisiana, Arkansas, Mississippi, Alabama and Florida.  We were formed in 1996 as a master limited partnership, or MLP.  We have a diverse portfolio of customers, operations and assets, including refinery-related plants, pipelines, storage tanks and terminals, barges, and trucks and truck terminals.  We provide services to refinery owners; oil, natural gas and CO 2 producers; industrial and commercial enterprises that use CO 2 and other industrial gases; and individuals and companies that use our trucking services.  Substantially all of our revenues are derived from providing services to integrated oil companies, large independent oil and gas or refinery companies, and large industrial and commercial enterprises.
 
We manage our businesses through four divisions which constitute our reportable segments:
 
Pipeline Transportation —We transport crude oil, CO 2 and, to a lesser extent, natural gas for others for a fee in the Gulf Coast region of the U.S. through approximately 590 miles of pipeline.  We own and operate three crude oil common carrier pipelines, two CO 2 pipelines and three small natural gas pipelines.  Our 235-mile Mississippi System provides shippers of crude oil in Mississippi indirect access to refineries, pipelines, storage, terminaling and other crude oil infrastructure located in the Midwest. Our 100-mile Jay System originates in southern Alabama and the panhandle of Florida and can deliver crude oil to a terminal near Mobile, Alabama.  Our 90-mile Texas System transports crude oil from West Columbia to Webster, Webster to Texas City and Webster to Houston.   Our crude oil pipeline systems include a total of approximately 0.7 million barrels of leased and owned tankage.  In addition, we lease the NEJD Pipeline System, described below, to Denbury.
 
The Free State Pipeline is an 86-mile, 20” CO 2 pipeline that extends from Denbury’s CO 2 source fields at the Jackson Dome, near Jackson, Mississippi, to Denbury’s oil fields in east Mississippi.  In 2008, we entered into a twenty-year transportation services agreement to deliver CO 2 on the Free State pipeline for Denbury’s use in its tertiary recovery operations.  We also own a small CO 2 pipeline in Mississippi to transport CO 2 to a Denbury oil field.
 
In 2008, we entered into a twenty-year financing lease transaction with Denbury valued at $175 million related to Denbury’s North East Jackson Dome (NEJD) Pipeline System.  The NEJD Pipeline System is a 183-mile, 20” pipeline extending from the Jackson Dome, near Jackson, Mississippi, to near Donaldsonville, Louisiana, and is currently being leased and used by Denbury for its Phase I area of tertiary operations in southwest Mississippi.  We recorded this lease arrangement in our consolidated financial statements as a direct financing lease.
 
Refinery Services —We provide services to eight refining operations located predominantly in Texas, Louisiana and Arkansas. These refineries generally are owned and operated by large companies, including ConocoPhillips, CITGO and Ergon. Our refinery services primarily involve processing high sulfur (or “sour”) natural gas streams, which are separated from hydrocarbon streams, to remove the sulfur. Our refinery services contracts, which usually have an initial term of two to ten years, have an average remaining term of five years.


Supply and Logistics —We provide terminaling, blending, storing, marketing, gathering and transporting (by trucks and barges), and other supply and logistics services to third parties, as well as to support our other businesses.  Our terminaling, blending, marketing and gathering activities are focused on crude oil and petroleum products, primarily fuel oil.  We own or lease over 280 trucks, 550 trailers and 1.1 million barrels of liquid storage capacity at eight different locations. Through our investment in DG Marine, we own and operate barges used primarily for the inland marine transportation of fuel oil and similar petroleum products.  We also conduct certain crude oil aggregating operations, including purchasing, gathering and transporting (by trucks and pipelines operated by us and trucks, pipelines and barges operated by others), and reselling that crude oil to help ensure (among other things) a base supply source for our crude oil pipeline systems.  Usually, our supply and logistics segment experiences limited commodity price risk because it involves 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 7 years.  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 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.
 
 
·
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 high-pressure steam and syngas (a combination of carbon monoxide and hydrogen).  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 that facility through at least 2016, and Praxair has the option to extend that contract term for two additional five year periods.  Praxair also is our partner in the joint venture and owns the remaining 50% interest.
 
 
·
Sandhill Group LLC – Through our 50% interest in a joint venture, we process raw CO 2 for sale to other customers for uses ranging from completing oil and natural gas producing wells to food processing. The Sandhill facility acquires CO 2 from us under one of the long-term supply contracts described above.
 
We conduct our operations through subsidiaries and joint ventures.  As is common with publicly-traded partnerships, or MLPs, 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.
 
Denbury Resources Inc. (NYSE:DNR) indirectly owns more than a majority interest of the equity interest in, and controls, our general partner, which owns all of our general partner interest, all of our incentive distribution rights, and  7.2% of our outstanding common units.  Another Denbury subsidiary owns an additional 3% of our outstanding common units.  Denbury, a large independent energy company with an equity market capitalization of approximately $3.2 billion as of February 27, 2009, operates primarily in Mississippi, Louisiana and Texas, emphasizing the tertiary recovery of oil using CO 2 flooding.  Denbury is the largest producer (based on average barrels produced per day) of oil in Mississippi, and it is one of only a handful of producers in the U.S. that possesses CO 2 tertiary recovery expertise along with large deposits of  CO 2 reserves, approximately 5.6 trillion cubic feet of estimated proved CO 2 reserves as of December 31, 2008.  Other than the CO 2 reserves owned by Denbury, we are not aware of any significant natural sources of CO 2 from East Texas to Florida.  Denbury is conducting its 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 oil. We believe Denbury’s equity ownership interests in us provide Denbury with economic and strategic incentives to occasionally utilize certain services we provide, whether through transportation agreements or other transactions.
 
Although Denbury is one of our customers from time to time, Denbury is not obligated to enter into any additional transactions with (or to offer any opportunities to) us or to promote our interest, and none of Denbury or any of its affiliates (including our general partner) has any obligation or commitment to contribute or sell any assets to us or enter into any type of transaction with us, and each of them, other than our general partner, has the right to act in a manner that could be beneficial to its interests and detrimental to ours.  Further, Denbury may, at any time, and without notice, alter its business strategy, including determining that it no longer desires to use us as a provider of any services.  Additionally, if Denbury were to make one or more offers to us, we cannot say that we would elect to pursue or consummate any such opportunity.   In addition, though our relationship with Denbury is a strength, it also is a source of potential conflicts.


Our Objectives and Strategies
 
Our primary business objectives are to generate stable cash flows to allow us to make quarterly cash distributions to our unitholders and to increase those distributions over time.  We plan to achieve those objectives by executing the following strategies:
 
 
·
Maintaining a balanced and diversified portfolio of midstream energy and industrial gases assets, operations and customers.   We intend to maintain a balanced and diversified portfolio of midstream energy and industrial gases assets, operations and customers.  We believe our cash flows are likely to continue to be relatively stable due to the diversity of our customer base, the nature and increasing array of services  we provide to both producers and refiners, and the geographic location of our operations.
 
 
·
Maintaining, on average, a conservative capital structure that will allow us to execute our growth strategy while, over the longer term, enhancing our credit ratings.   We intend to maintain, on average, a conservative capital structure that will allow us to execute our growth strategy while, over the longer term, enhancing our credit ratings.  We intend to maintain a balanced approach to our existing capital availability by focusing on opportunities that provide stable cash flows and strategic opportunities utilizing our existing assets.  We had approximately $176.5 million available to borrow under our senior secured credit facility as of December 31, 2008.
 
 
·
Increasing the utilization rates for, and enhancing the profitability of, our existing assets.   We intend to increase the utilization rates and, thereby, enhance the profitability of our existing assets.  We own some pipelines and terminals that have available capacity and others for which we can increase the capacity at a relatively nominal cost.  We also intend to enhance profitability of our existing assets through further integration of our operations.
 
 
·
Increasing stable cash flows generated through fee-based services, longer-term contractual arrangements and managing commodity price risks.   We intend to generate more stable cash flows, when practical, by (i) emphasizing fee-based compensation under longer term contracts, and (ii) using contractual arrangements, including back-to-back contracts and derivatives.  We charge fee-based arrangements for substantially all of our services.  We are able to enter into longer term contracts with most of our customers in our refinery services and industrial gases divisions.  Our marketing activities do not include speculative transactions.
 
 
·
Expanding our asset base through strategic and accretive acquisitions and strategic construction and development projects .   We intend to expand our asset base through strategic and accretive acquisitions and strategic construction and development projects in new and existing markets.  Such acquisitions or projects could be structured as, among other things, purchases, leases, tolling or similar agreements or joint ventures.
 
 
·
Creating strategic arrangements and sharing capital costs and risks through joint ventures and strategic alliances.   We intend to continue to create strategic arrangements with customers and other industry participants, and to share capital costs and risks, through the formation of joint ventures and strategic alliances.
 
 
·
Optimizing our CO2 and other industrial gases expertise and infrastructure.   We intend to continue to pursue opportunities to create growth from our experience with CO2 and other industrial gases.
 
 
·
Attracting new refinery customers and expanding the services we provide those customers.   We expect to attract new refinery customers as more sour crude is imported (or produced) and refined in the U.S., and we plan to expand the services we provide to our refinery customers by offering a broader array of services, leveraging our strong relationships with refinery owners and producers, and deploying our proprietary knowledge.
 
 
·
Leveraging our oil handling capabilities with Denbury’s tertiary recovery projects .  Because we have facilities in close proximity to certain properties on which Denbury is conducting tertiary recovery operations, we believe we are likely to have the opportunity to provide some oil transportation, gathering, blending and marketing services to it and other producers as production from those properties increases.


Our Key Strengths
 
We believe we are well positioned to execute our strategies and ultimately achieve our objectives due primarily to the following competitive strengths:
 
Ø
Diversified and Balanced Portfolio of Customers, Operations and Assets.   We have a diversified and well-balanced portfolio of customers, operations and assets throughout the Gulf Coast region of the United States. Through our diverse assets, we provide stand-alone and integrated gathering, transporting, processing, blending, storing and marketing services, among others, to four distinct customer groups: refinery owners; CO 2 producers; industrial and commercial enterprises that use CO 2 and other industrial gases; and individuals and companies that use our transportation services. Our operations and assets are characterized by:
 
 
·
Strategic Locations.   Our oil pipelines and related assets are predominantly located near areas that are experiencing increasing oil production, (in large part because of Denbury’s tertiary recovery operations) or near inland refining operations that we believe are contemplating expansion of capacity or ability to handle sour gas streams.
 
 
·
Cost-Effective Expansion and Enhancement Opportunities.   We own pipelines, terminals and other assets that have available capacity or that have opportunities for expansion of capacity without incurring material expenditures.
 
 
·
Cash Flow Stability.   Our cash flow is relatively stable due to a number of factors, including our long-term, fee-based contracts with our refinery services and industrial gases customers; our diversified base of customers, assets and services; and our relatively low exposure to volatile fluctuations in commodity prices.
 
Ø
Financial Liquidity and Flexibility.    We have the financial liquidity and flexibility to pursue additional growth projects. As of December 31, 2008, we had $320 million of loans and $3.5 million in letters of credit outstanding under our $500 million credit facility, resulting in $176.5 million of remaining credit, all of which was available under our borrowing base. Our borrowing base fluctuates each quarter based on our earnings before interest, taxes, depreciation and amortization, or EBITDA. Our borrowing base may be increased to the extent of EBITDA attributable to acquisitions, with approval of the lenders.  In addition we had $19.0 million of cash on hand at December 31, 2008.
 
Ø
Experienced, Knowledgeable and Motivated Senior Management Team with Proven Track Record. Our senior management team has an average of more than 25 years of experience in the midstream sector. They have worked together and separately in leadership roles at a number of large, successful public companies, including other publicly-traded partnerships. To help ensure that our senior management team is incentivized to create value for our equity holders by maintaining and increasing (over time) the distribution rate we pay on our common units, our general partner has provided the members of our senior management team with long-term, incentive equity compensation that generally increases in value as our incentive distribution rights increase in value.  To take advantage of this opportunity, our senior executive team must grow the distributions we pay our common unitholders.
 
Ø
Supply and Logistics Division  Support s Full Suite of Services.   In addition to its established customers, our supply and logistics division can, from time to time, attract customers to our other divisions and/or create synergies that may not be available to our competitors.  Several examples include:
 
 
·
our refinery services division can effectively compete with refineries, on a stand alone basis, to remove sulfur partially due to the synergies created from our ability to economically source, transport and store large supplies of caustic soda (the main component in the NaHS sulfur removal process), as well as our ability to store, transport and market NaHS;
 
 
·
our pipeline transportation division receives throughput related to the gathering and marketing services that our supply and logistics division provides to producers;
 
 
·
our supply and logistics division gives us the opportunity to bundle services in certain circumstances; for example, in the future, we hope to gather disparate qualities of oil and use our terminal and storage assets to customize blends for some of our customers needing fuel supplies; and
 
 
·
our supply and logistics division gives us the opportunity to blend, store and distribute products made by our refinery customers.


Ø
Unique Platform, Limited Competition and Anticipated Growing Demand in Our Refinery Services Operations.   We provide services to eight refining operations located predominantly in Texas, Louisiana and Arkansas. Our refinery services primarily involve processing sour natural gas streams, which are separated from hydrocarbon streams, to remove the sulfur.  Refineries contract with us for a number of reasons, including the following:
 
 
·
sulfur handling and removal is typically not a core business of our refinery customers;
 
 
·
over a long period of time, we have developed and maintained strong relationships with our refinery services customers, which relationships are based on our reputation for high standards of performance, reliability and safety;
 
 
·
the proprietary sulfur removal process we use -- the NaHS sulfur removal process -- is, generally, more reliable and less capital and labor intensive than the conventional “Claus” process employed at most refineries, and it generates a marketable by-product, NaHS;
 
 
·
we have the scale of operations and supply and logistics capabilities to make the NaHS sulfur removal process extremely reliable as a means to remove sulfur efficiently while working in concert with the refineries to ensure uninterrupted refinery operations;
 
 
·
other than the refinery owners (who remove their own sulfur), we have few competitors for our refinery services business; and
 
 
·
we believe that the demand for sulfur removal at U.S. refineries will increase in the years ahead as the quality of the oil supply used by refineries in the U.S. continues to drop (or become more “sour”).  As that occurs, we believe more refineries will seek economic and proven sulfur removal processes from reputable service providers that have the scale and logistical capabilities to efficiently perform such services.  In addition, we have an increasing array of services we can offer to our refinery customers.
 
Ø
Relationship with Denbury .  We believe Denbury has an economic and strategic incentive to execute some business transactions with us. We also believe that we can leverage our operations (and our relationship with Denbury) into oil transportation and storage opportunities with third parties, such as other producers and refinery operators, in the areas into which Denbury expands its operations.
 
2008 Developments
 
Investment in DG Marine Transportation, LLC
 
On July 18, 2008, we acquired an interest in DG Marine which acquired the inland marine transportation business of Grifco Transportation, Ltd. (“Grifco”) and two of Grifco’s affiliates.  DG Marine is a joint venture with TD Marine, LLC, an entity formed by members of the Davison family, who are owners of approximately 30% of our common units.  (See discussion below on the acquisition of the Davison family businesses in 2007.). TD Marine owns (indirectly) a 51% economic interest in DG Marine, and we own (directly and indirectly) a 49% economic interest.  This acquisition gives us the capability to provide transportation services of petroleum products by barge and complements our other supply and logistics operations.
 
Denbury Drop-Down Transactions
 
We completed two “drop-down” transactions with Denbury in 2008 involving two of their existing CO 2 pipelines - the NEJD and Free State CO 2 pipelines. We paid for these pipeline assets with $225 million in cash and 1,199,041 common units valued at $25 million based on the average closing price of our units for the five trading days surrounding the closing date of the transaction. Under the twenty-year agreements with Denbury related to the NEJD and Free State pipelines, we expect to receive approximately $30 million per annum, in the aggregate.  Future payments for the NEJD pipeline are fixed at $20.7 million per year during the term of the financing lease, and the payments related to the Free State pipeline are dependent on the volumes of CO 2 transported therein, with a minimum monthly payment of $0.1 million.


Fourteen Consecutive Distribution Rate Increases
 
We have increased our quarterly distribution rate for fourteen consecutive quarters.  On February 13, 2009, we paid a cash distribution of $0.33 per unit to unitholders of record as of February 3, 2009, an increase per unit of $0.0075 (or 2.3%) from the distribution in the prior quarter, and an increase of 15.8% from the distribution in February 2008.  As in the past, future increases (if any) in our quarterly distribution rate will be dependent on our ability to execute critical components of our business strategy.
 
Florida Oil Pipeline System Expansion
 
In the second quarter of 2009, we expect to complete construction of an extension of our existing Florida oil pipeline system that would extend to producers operating in southern Alabama. That new lateral extension consists of approximately 33 miles of 8” pipeline originating in the Little Cedar Creek Field in Conecuh County, Alabama to a connection to our Florida Pipeline System in Escambia County, Alabama. That project also includes gathering connections to approximately 35 wells and oil storage capacity of 20,000 barrels in the field.  Our capital costs in 2008 related to this project totaled $7.4 million, and we expect to expend $4.1 million to complete the project in 2009.

Description of Segments and Related Assets
 
We conduct our business through four primary segments: Pipeline Transportation, Refinery Services, Industrial Gases and Supply and Logistics. These segments are strategic business units that provide a variety of energy-related services.  Financial information with respect to each of our segments can be found in Note 12 to our Consolidated Financial Statements.
 
Pipeline Transportation
 
Crude Oil Pipelines
 
Overview.   Our core pipeline transportation 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 for other shippers pursuant to tariff rates regulated by the Federal Energy Regulatory Commission, or 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 oil quality deductions.  Such allowances and deductions are offset by measurement gains and losses.  When our actual volume losses are less than the related allowances and deductions, we recognize the difference as income and inventory available for sale valued at the market price for the crude oil.
 
The margins from our crude oil 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 235-mile Mississippi System provides shippers of crude oil in Mississippi indirect access to refineries, pipelines, storage, terminaling and other crude oil infrastructure located in the Midwest.  Our 100-mile Jay System originates in southern 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.
 
Mississippi System .  Our Mississippi System extends from Soso, Mississippi to Liberty, Mississippi and includes tankage at various locations with an aggregate owned storage capacity of 247,500 barrels.  This 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, and it owns more developed CO 2 reserves than anyone in the Gulf Coast region of the U.S.  As Denbury continues to implement its tertiary recovery strategy, its anticipated increased production could create increased demand for our crude oil transportation services because of the close proximity of those pipelines to Denbury’s projects.
 
We provide transportation services on our Mississippi pipeline to Denbury under 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.


Jay System .  Our Jay System begins near oil fields in southern 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.  Recent changes in ownership of the more mature producing fields in the area surrounding our Jay System have led to interest in further development activities regarding those fields which we believe may lead to increases in production.  As a result of new production in the area surrounding our Jay System, volumes have stabilized on that system.
 
We expect to complete construction of an extension of our existing Florida oil pipeline system in the second quarter of 2009 that would extend to producers operating in southern Alabama. The new lateral will consist of approximately 33 miles of 8” pipeline originating in the Little Cedar Creek Field in Conecuh County, Alabama to a connection to our Florida Pipeline System in Escambia County, Alabama. The project will also include gathering connections to approximately 35 wells and additional oil storage capacity of 20,000 barrels in the field.
 
Texas System .  The active segments of the Texas System extend from West Columbia to Webster, Webster to Texas City and Webster to Houston.  Those segments include approximately 90 miles of pipeline.  The Texas System receives all of its volume from connections to other pipeline carriers.  We earn a tariff 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 its 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 55,000 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 with the primary shipper on our Texas System to reimburse us for the lease of this storage capacity at Webster.
 
CO 2 Pipelines
 
We also transport CO 2 for a fee.  The Free State Pipeline is an 86-mile, 20” pipeline that extends from Denbury’s CO 2 source fields at Jackson Dome, near Jackson, Mississippi, to Denbury’s oil fields in east Mississippi.  In addition, the NEJD Pipeline System, a 183-mile, 20” CO 2 pipeline that we lease to Denbury extends from the Jackson Dome, near Jackson, Mississippi, to near Donaldsonville, Louisiana, currently being used by Denbury for its tertiary operations in southwest Mississippi.
 
Denbury has exclusive use of the NEJD Pipeline and is responsible for all operations and maintenance on that system and will bear and assume all obligations and liabilities with respect to that system.  We are responsible for owning, operating and maintaining and making improvements to the Free State Pipeline, however Denbury has rights to exclusive use and is required to use the Free State Pipeline to supply CO 2 to its current and certain of its other tertiary operations in East Mississippi.
 
 Customers
 
Denbury is the sole shipper (other than us) on our Mississippi System and the Free State Pipeline.  Denbury also has exclusive right to use the Free State Pipeline and the NEJD Pipeline.  The customers on our Jay and Texas Systems are primarily large, energy companies.  Revenues from customers of our pipeline transportation segment did not account for more than ten percent of our consolidated revenues.
 
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 pipeline systems, comparable in size and scope to our pipelines, will be built in the same geographic areas in the near future.
 
Refinery Services
 
We acquired our refinery services segment in the Davison transaction in July 2007.  That segment provides services to eight refining operations primarily located in Texas, Louisiana and Arkansas.  In our processing, we apply proprietary technology that uses large quantities of caustic soda (the primary input used by our process). Our refinery services business generates revenue by providing a service for which it receives NaHS as consideration and by selling the NaHS, the by-product of our process, to approximately 100 customers.  As such, we believe we are one of the largest marketers of NaHS in North America.


NaHS is used in the specialty chemicals business, in pulp and paper business, in connection with mining operations and also has environmental applications.  NaHS is used in various industries for applications including, but not limited to, agricultural, dyes, and other chemical processing; waste treatment programs requiring stabilization and reduction of heavy and toxic metals through precipitation; and sulfidizing oxide ores (most commonly to separate copper from molybdenum). NaHS is also used in the Kraft pulping process to prepare synthetic cooking liquor (white liquor); as a make-up chemical to replace lost sulfur values; as a scrubbing media for residual chlorine dioxide generated and consumed in mill bleach plants; and for removing hair from hides at the beginning of the tannery process.
 
Our refinery service contracts typically have an initial term from two to ten years.  Because of our reputation, experience and logistical capability to transport, store and deliver both NaHS and caustic soda, we believe such contracts will likely be renewed upon the expiration of their primary terms.  We also believe that the demand for sulfur removal at U.S. refineries will increase in the years ahead as the quality of the oil supply used by refineries in the U.S. continues to drop (or become more “sour”).  As that occurs, we believe more refineries will seek economic and proven sulfur removal processes from reputable service providers that have the scale and logistical capabilities to efficiently perform such services.   Because of our existing scale, we believe we will be able to attract some of these refineries as new customers for our sulfur handling/removal services.
 
The largest cost component of providing our sulfur removal service is acquiring and delivering caustic soda to our operations. Caustic soda, or NaOH, is the scrubbing agent introduced in the sour gas stream to remove the sulfur and generate the by-product, NaHS. Therefore the contribution to segment margin includes the revenues generated from the sales of NaHS less our total cost of providing the services, including the costs of acquiring and delivering caustic soda to our service locations.  Because the activities of these service arrangements can fluctuate, we do, from time to time engage in other activities such as selling caustic soda, buying NaHS from other producers for re-sale to our customers and buying and selling sulfur, the financial results of which are also reported in our refinery services segment.
 
Our sulfur removal facilities consist of NaHS units that are located at sites leased at five refineries, primarily in the southeastern United States.  While some of our customers have elected to own the sulfur removal facilities located at their refineries, we operate those facilities.
 
Customers
 
Refinery Services:  At December 31, 2008, we provided services to eight refining operations.
 
NaHS Marketing:  We sell our NaHS to customers in a variety of industries, with the largest customers involved in copper mining and the production of paper.  We sell to customers in the copper mining industry in the western United States as well as customers who export the NaHS to South America for mining in Peru and Chile.  Many of the paper mills that purchase NaHS from us are located in the southeastern United States.  No customer of the refinery services segment is responsible for more than ten percent of our consolidated revenues.  Approximately 13% of the revenues of the refinery services segment in 2008 resulted from sales to Kennecott Utah Copper, a subsidiary of Rio Tinto plc.  While the market price of copper and other ores has declined in 2008 creating a reduction in mining operations and economic circumstances have reduced demand of paper products from the paper mills who acquire NaHS, the provisions in our service contracts with refiners allow us to adjust our service levels to maintain a balance between NaHS supply and demand.
 
Competition for Refinery Services Business
 
We believe that the U.S. refinery industry’s demand for sulfur extraction services will increase because we believe sour oil will constitute an ever-increasing portion of the total worldwide supply of crude oil.  In addition, we have an increasing array of services we can offer to our refinery customers and we believe our proprietary knowledge, scale, logistics capabilities and safety and service record will encourage such customers to continue to outsource their existing refinery services needs to us.  While other options exist for the removal of sulfur from sour oil, we believe our existing customers are unlikely to change to another method due to the costs involved.  Other than the refinery owners (who may process sulfur themselves), we have few competitors for our refinery services business.
 
Industrial Gases
 
Overview
 
Our industrial gases segment is a natural outgrowth from our pipeline transportation business.  Because of Denbury’s tertiary recovery operations utilizing CO 2 flooding 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 continued to expand, which has introduced us to potential opportunities associated with other industrial gases.  We (i) supply CO 2 to industrial customers, (ii) process raw CO 2 and sell that processed CO 2 , and (iii) manufacture and sell syngas, a combination of carbon monoxide and hydrogen.


CO 2 – Industrial Customers
 
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.  We purchased those contracts, along with three VPPs representing 280.0 Bcf of CO 2 (in the aggregate), from Denbury.  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 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. At December 31, 2008, we have 153.8 Bcf of CO 2 remaining under the VPPs.
 
Currently, all of our CO 2 supply is from our interests – our VPPs - in fields producing naturally occurring CO 2 .  The agreements we executed with Denbury when we acquired the VPPs provide that we may acquire additional CO 2 from Denbury under terms similar to the original agreements should additional volumes be needed to meet our obligations under the existing customer contracts.  Based on the current volumes being sold to our customers, we believe that we will need to acquire additional volumes from Denbury in 2015.  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 once our VPPs expire, and Denbury has the right to compete with us in the CO 2 supply business.  See “Risks Related to Our Partnership Structure” for a discussion of the potential conflicts of interest between Denbury and us.
 
One of the parties that we supply with CO 2 under a long-term sales contract is Sandhill Group, LLC.  On April 1, 2006, we acquired a 50% interest in Sandhill Group, LLC as discussed below.
 
CO 2 - Processing
 
We own a 50% partnership interest in Sandhill.  Reliant Processing Ltd. owns the remaining 50% of Sandhill.  Sandhill is a limited liability company that owns a CO 2 processing facility located in Brandon, Mississippi. Sandhill is engaged in the production and distribution of liquid carbon dioxide for use in the food, chemicals and oil industries. The facility acquires CO 2 from us under a long-term supply contract.  This contract expires in 2023, and provides for a maximum daily contract quantity of 16,000 Mcf per day with a take-or-pay minimum quantity of 2,500,000 Mcf per year.
 
Syngas
 
We own a 50% partnership interest in T&P Syngas.  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, which Praxair has the option to extend for two additional five year terms.  Praxair owns the remaining 50% interest in that joint venture.
 
Customers
 
Five of our seven contracts for supplying CO 2 are with large international companies.  One of the remaining contracts is with Sandhill Group, LLC, of which we own 50%.  The remaining contract is with a smaller company with a history in the CO 2 business.  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, a worldwide provider of industrial gases.
 
Sandhill sells to approximately 20 customers, with sales to three of those customers representing approximately 67% of Sandhill’s total revenues of approximately $11 million in 2008.  In 2008, Sandhill sold approximately $2.4 million of CO 2 to affiliates of Reliant Processing, Ltd., our partner in Sandhill, as discussed above.  Sandhill has long-term relationships with those customers and has not experienced collection problems with them.


Competition
 
Currently, all of our CO 2 supply is from our interest – our VPPs – in fields producing naturally occurring sources.  In the future we may 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 the NEJD CO 2 pipeline, which makes 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 supply business, and the competition and pricing issues we will face at that time are uncertain.
 
With regard to our CO 2 supply business, our contracts have long terms and generally include take-or-pay provisions requiring annual minimum volumes that each customer must pay for even if the CO 2 is not taken.
 
Due to the long-term contract and location of our syngas facility, as well as the costs involved in establishing facilities, we believe it is unlikely that competing facilities will be established for our syngas processing services.
 
Sandhill has competition from the other industrial customers to whom we supply CO 2 .  As discussed above, the limited amounts of naturally-occurring CO 2 east of the Mississippi River makes it difficult for competitors of Sandhill to significantly increase their production or sales and, thereby, increase their market share.
 
Supply and Logistics
 
Our supply and logistics segment has the capabilities and assets to provide a wide array of services to oil producers and refiners in the Gulf Coast region.  These services include gathering of crude oil at the wellhead, marketing of crude oil to refiners and other supply companies, transporting crude oil by truck to pipeline injection points or directly to the refiners, and acquiring the resulting petroleum products from the refiners for transportation by truck and barge primarily to third parties in fuels markets and some end-users.   Our profit for those services is derived from the difference between the price at which we re-sell the crude oil and petroleum products less the price at which we purchase the oil and products, minus the associated costs of aggregation and transportation.
 
Our crude oil gathering and marketing operations are concentrated in Texas, Louisiana, Alabama, Florida and Mississippi.  Those operations help to ensure (among other things) a base supply source for our oil pipeline systems.   In addition, our 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 most substantial component of our aggregating costs relates to operating our fleet of leased trucks.
 
When the crude oil markets are in contango (oil prices for future deliveries are higher than for current deliveries), we may purchase and store crude oil as inventory for delivery in future months.  When we purchase this inventory, we simultaneously enter into a contract to sell the inventory in the future period, either with a counterparty or in the crude oil futures market. We generally will account for this inventory and the related derivative hedge as a fair value hedge in accordance with Statement of Financial Accounting Standards No. 133.  See Note 17 of the Notes to the Consolidated Financial Statements.
 
With the Davison acquisition in 2007, we added trucks, trailers and existing leased and owned storage, and we expanded our activities to include transporting, storing and blending intermediate and finished refined products.  In our petroleum products marketing operations, we primarily supply fuel oil, asphalt, diesel and gasoline to wholesale markets and some end-users such as paper mills and utilities.  We also provide services to refineries by purchasing their products that do not meet the specifications they desire, transporting them to one of our terminals and blending them to a quality that meets the requirements of our customers.   We cannot predict when the opportunities to provide this service will arise.  However, when such opportunities arise, their contribution to margin as a percentage of the revenues tends to be higher than the same percentage attributable to our recurring operations.
 
Our supply and logistics operations utilize a variety of assets.  Those assets include leased and owned tankage at terminals in our area of concentration with total storage capacity of 1.1 million barrels, over 280 trucks and over 550 trailers, as well as barges owned and operated by DG Marine.  DG Marine owns nine pushboats and sixteen double hulled, hot-oil asphalt-capable barges with capacities ranging from 30,000 to 38,000 barrels each.  DG Marine also will take delivery of four additional barges and acquire one additional pushboat in the first half of 2009.  Several of our terminals are located on waterways in the southeastern United States that are accessible by barge.


We believe we are well positioned to provide a full suite of logistical services to both independent and integrated refinery operators, ranging from upstream (the procurement and staging of refinery inputs) to downstream (the transportation, staging and marketing) of refined products.
 
Customers and Competition
 
In our supply and logistics segment, we sell crude oil and petroleum products and provide transportation services to hundreds of customers.  During 2008, more than ten percent of our consolidated revenues were generated from Shell Oil Company.  We do not believe that the loss of any one customer for crude oil or petroleum products would have a material adverse effect on us as these products are readily marketable commodities.
 
Our largest competitors in the purchase of leasehold crude oil production are Plains Marketing, L.P., Shell (US) Trading Company, and TEPPCO Partners, L.P.  Additionally we compete with many regional and local gatherers who may have significant market share in the areas in which they operate.  In our petroleum products marketing operations and our trucking and barge operations, we compete primarily with regional suppliers. Competitive factors in our supply and logistics business include price, personal relationships, range and quality of services, knowledge of products and markets, availability of trade credit and capabilities of risk management systems.
 
Geographic Segments
 
All of our operations are in the United States.
 
Credit Exposure
 
Due to the nature of our operations, a disproportionate percentage of our trade receivables constitute obligations of oil companies, independent refiners, and mining and other companies that purchase NaHS.  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 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 and petroleum products and NaHS, 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. We use similar procedures to manage our exposure to our customers in the pipeline transportation and industrial gases segments.
 
Some of our customers experienced cash flow difficulties in the latter half of 2008 as a result of the tightening of the credit markets.  These customers generally purchase petroleum products and NaHS from us.  We have strengthened our credit monitoring procedures to perform more frequent review of our customer base.  As a result of cash flow difficulties of some of our customers, we have experienced a delay in collections from these customers and have established an allowance for possible uncollectible receivables at December 31, 2008 in the amount of $1.1 million.
 
Employees
 
To carry out our business activities, our general partner employed, at February 27, 2009, approximately 610 employees.  Additionally, DG Marine employed 133 employees.  None of those employees are represented by labor unions, and we believe that relationships with those employees are good.


Organizational Structure
 
Genesis Energy, LLC, a Delaware limited liability company, serves as our sole general partner and as our general partner of all of our subsidiaries.  Our general partner is owned and controlled by Denbury Gathering & Marketing, Inc., a subsidiary of Denbury, and certain members of our Senior Management own an interest as described below.  Below is a chart depicting our ownership structure.
 
 
(1) The incentive compensation arrangement between our general partner and our Senior Executives (see Item 11. Executive Compensation.), provides them long-term incentive equity compensation that generally increases in value as the incentive distribution rights held by our general partner increase in value. The maximum amount of this interest is 20% (17.2% currently awarded) and will fluctuate in value with increases or decreases in our distributions to our partners and our success in generating available cash.
 
 
Regulation
 
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, or 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.
 
Barge Regulations
 
DG Marine’s inland marine transportation operations are subject to regulation by the United States Coast Guard (USCG), federal and state laws.  The Jones Act is a federal cabotage law that restricts domestic marine transportation in the U.S. to vessels built and registered in the U.S., manned by U.S. citizens and owned and operated by U.S. citizens.  The crews employed on the pushboats are required to be licensed by the USCG.  Federal regulations require that all tank barges engaged in the transportation of oil and petroleum in the U.S. be double hulled by 2015.  All of DG Marine’s barges are double-hulled.
 
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 and compliance with 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 our operations, including 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, typically increasing in stringency through time, 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, or 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.  We also may incur liability under the Resource Conservation and Recovery Act, as amended, or RCRA, and analogous state laws which impose requirements and also liability relating to the management and disposal of solid and hazardous wastes.  In cases of environmental contamination, it is also 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 currently own or lease, and have in the past owned or leased, properties that have been in use for many years in connection with the gathering and transportation of hydrocarbons including crude oil and other activities that could cause an environmental impact.  We also generate, handle and dispose of regulated materials in the course of our operations, including some characterized as “hazardous substances” under CERCLA and “hazardous wastes” under RCRA.  We may therefore be subject to liability and regulation under CERCLA, RCRA and analogous state laws for hydrocarbons or other substances that may have been disposed of or released on or under our current or former properties or at other locations where wastes have been taken for disposal.  Under these laws and regulations, we could be required to undertake investigations into suspected contamination, 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 the Oil Pollution Act, or OPA, and analogous state laws and regulations promulgated thereunder impose restrictions and controls regarding the discharge of pollutants, including crude oil, into federal and state waters.  The Clean Water Act and OPA provide administrative, civil and criminal penalties for any unauthorized discharges of pollutants, including oil, and impose liabilities for the costs of remediation of spills.  Federal and state permits for water discharges also may be required.  OPA also requires operators of offshore facilities and certain onshore facilities near or crossing waterways to provide financial assurance generally 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 OPA as well as the federal Department of Transportation, the federal Occupational and Safety Health Act, or OSHA, and state laws and regulations.  We believe this plan meets regulatory requirements as to notification, procedures, response actions, response resources and spill impact considerations in the event of an oil spill.
 
The Clean Air Act, as amended, and analogous state and local laws and regulations restrict the emission of air pollutants, and impose permit requirements and other obligations.  Regulated emissions occur as a result of our operations, including 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, or 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 environmental assessment be required for any proposed pipeline extensions or additions, NEPA may prevent or delay construction or alter the proposed location, design or method of construction.
 
DG Marine is subject to many of the same regulations as our other operations, including the Clean Water Act, OPA and the Clean Air Act.  OPA and CLERCA require DG Marine to obtain a Certificate of Financial Responsibility for each barge and most of its pushboats to evidence financial ability to satisfy statutory liabilities for oil and hazardous substance water pollution.
 
Recent scientific studies have suggested that emissions of certain gases, including CO 2 , methane and certain other gases may be contributing to the warming of the Earth’s atmosphere.  In response to such studies, it is anticipated that the U.S. Congress will continue to actively consider legislation to restrict or further regulate the emission of greenhouse gases, primarily through the development of emission inventories and/or regional greenhouse gases cap and trade programs.  Also, on April 2, 2007, the U.S. Supreme Court in Massachusetts, et al. v. EPA held that CO 2 may be regulated as an “air pollutant” under the federal Clean Air Act and the EPA must consider whether it is required to regulate greenhouse gases from mobile sources such as cars and trucks.  The Court’s holding in Massachusetts that greenhouse gases fall under the Clean Air Act also may result in future regulation of greenhouse gas emissions from stationary sources.  In July 2008, the EPA released an Advance Notice of Proposed Rulemaking regarding possible future regulation of greenhouse gas emissions under the Clean Air Act, in response to the Supreme Court’s decision in Massachusetts .  In the notice, the EPA evaluated the potential regulation of greenhouse gases under the Clean Air Act and other potential methods of regulating greenhouse gases.  Although the notice did not propose any specific, new regulatory requirements for greenhouse gases, it indicates that federal regulation of greenhouse gas emissions could occur in the near future.  Thus, there may be restrictions imposed on the emission of greenhouse gases if Congress does not adopt new legislation specifically addressing emissions of greenhouse gases.


Operational components of our stationary facilities that require the combustion of carbon-based fuel (such as internal combustion engine-driven pumps) produce greenhouse gas emissions in the form of CO 2 .  Although it is not possible at this time to predict how legislation that may be enacted or new regulations that may be adopted to address greenhouse gas emissions would impact our business, any such new federal, regional or state restrictions on emissions of CO2 or other greenhouse gases that may be imposed in the areas in which we conduct business could result in increased compliance costs or additional operating restrictions, and could have a material adverse effect on our business, financial condition, demand for our services, results of operations, and cash flows.
 
 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, or 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, or 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, or IMP, regulations. The IMP regulations require that we perform baseline assessments of all pipelines that could affect a High Consequence Area, or 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 required that the baseline assessment be completed by April 1, 2008, with 50% of the mileage assessed by September 30, 2004.  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.
 
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 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 federal Department of Transportation regulations requiring qualification of all pipeline personnel.  The Operator Qualification, or OQ, program requires operators to develop and submit a written program.  The regulations also require 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, refined products and refinery services operations are also subject to the requirements of OSHA and comparable state statutes.  We believe that our 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 operations employees 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.
 
We have an operating authority issued by the Federal Motor Carrier Administration of the Department of Transportation for our trucking operations, and we are 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 subject to federal EPA regulations for the development of written Spill Prevention Control and Countermeasure, or SPCC, Plans for our trucking facilities and crude oil injection stations.  Annually, trucking employees receive training regarding the transportation of hazardous materials and the SPCC Plans.
 
The USCG regulates occupational health standards related to DG Marine’s vessel operations.   Shore-side operations are subject to the regulations of OSHA and comparable state statutes.  The Maritime Transportation Security Act requires, among other things, submission to and approval of the USCG of vessel security plans.
 
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
 
When 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.
 
Website Access to Reports
 
We make available free of charge on our internet website ( www.genesis energylp .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 F acto rs
 
Risks Related to Our Business
 
We may not be able to fully execute our growth strategy if we are unable to raise debt and equity capital at an affordable price.
 
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.
 
The capital and credit markets have been, and continue to be, disrupted and volatile as a result of adverse conditions.  There can be no assurance that government response to the disruptions in the financial markets will restore investor or customer confidence, stabilize such markets, or increase liquidity and the availability of credit to businesses. If the credit markets continue to experience volatility and the availability of funds remains limited, we may experience difficulties in accessing capital for significant growth projects or acquisitions which could adversely affect our strategic plans.
 
In addition, we experience 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.
 
Economic developments in the United States and worldwide in credit markets and concerns about economic growth could impact our operations and materially reduce our profitability and cash flows.
 
Recent disruptions in the credit markets and concerns about local and global economic growth have had a significant adverse impact on global financial markets and commodity prices, both of which have contributed to a decline in our unit price and corresponding market capitalization.  If these disruptions, which existed throughout the fourth quarter of 2008, continue, they could negatively impact our profitability.  The current financial turmoil affecting the banking system and financial markets, and the possibility that financial institutions may consolidate or go out of business has resulted in a tightening of the credit markets, a low level of liquidity in many financial markets, and extreme volatility in fixed income, credit and equity markets.  Our credit facility arrangements involve over fifteen different lending institutions.  While none of these institutions have combined or ceased operations, further consolidation of the credit markets could result in lenders desiring to limit their exposure to an individual enterprise.  Additionally, some institutions may desire to limit exposure to certain business activities in which we are engaged.  Such consolidations or limitations could limit our access to capital and could impact us when we desire to extend or make changes to our existing credit arrangements.
 
Additionally, significant decreases in our operating cash flows could affect the fair value of our long-lived assets and result in impairment charges.  At December 31, 2008, we had $325 million of goodwill recorded on our consolidated balance sheet.
 
Fluctuations in interest rates could adversely affect our business.
 
We have exposure to movements in interest rates. The interest rates on our credit facility are variable.   Global financial market conditions have reduced interest rates to unprecedented low rates, reducing our interest costs.  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 in interest rates.
 
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 refinery services, pipeline transportation, logistics and supply and industrial gases businesses which will fluctuate from quarter to quarter based on, among other things:
 
 
·
the volumes and prices at which we purchase and sell crude oil, refined products, and caustic soda;
 
 
·
the volumes of sodium hydrosulfide, or NaHS, that we receive for our refinery services and the prices at which we sell NaHS;


 
·
the demand for our trucking, barge and pipeline transportation services;
 
 
·
the volumes of CO 2 we sell and the prices at which we sell it;
 
 
·
the demand for our terminal storage services;
 
 
·
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.
 
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 indebtedness could adversely restrict our ability to operate, affect our financial condition, and prevent us from complying with our requirements under our debt instruments and could prevent us from paying cash distributions to our unitholders.
 
We have outstanding debt and the ability to incur more debt. As of December 31, 2008, we had approximately $320 million outstanding of senior secured indebtedness.
 
We must comply with various affirmative and negative covenants contained in our credit facilities. Among other things, these 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;
 
 
·
make guarantees;
 
 
·
enter into any hedging agreement for speculative purposes;


 
·
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 unitholders. For example, they could:
 
 
·
increase our vulnerability to general adverse economic and industry conditions;
 
 
·
limit our ability to make distributions; 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 competit ive disadvantage as compared to our competitors that have less debt.
 
We may incur additional indebtedness (public or private) in the future, 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 profitability and cash flow are dependent on our ability to increase or, at a minimum, maintain our current commodity - oil, refined products, NaHS and CO 2 - volumes, which often depends on actions and commitments by parties beyond our control.
 
Our profitability and cash flow are dependent on our ability to increase or, at a minimum, maintain our current commodity— oil, refined products, NaHS 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 reserves by others and other matters beyond our control.
 
The oil and other products available to us are derived from reserves produced from existing wells, and these 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 unitholders 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, or refined products are produced, in the areas accessed by our facilities, we may not be chosen by the producers or refiners to gather, refine, market, transport, store or otherwise handle any of these reserves, NaHS or refined products produced. 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;
 
 
·
logistical efficiency in all of our operations;
 
 
·
operational efficiency in our refinery services business;
 
 
·
customer relationships; 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 or availability of refined products or NaHS, such as those caused by refinery downtime or shutdowns, can negatively affect our operating results. Reduced demand in areas we service with our pipelines and trucks 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 transported 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 products, and CO 2 prices are volatile and could have an adverse effect on our profits and cash flow. Our operations are affected by price reductions in those commodities. Price reductions in those commodities can cause material long and short term reductions in the level of throughput, volumes and margins in our logistic and supply businesses.  Price changes for NaHS and caustic soda affect the margins we achieve in our refinery services business.
 
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 pipeline transportation 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 those refineries or connecting carriers to which we deliver could adversely affect our pipeline transportation 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 business activities.
 
When we market any of our products or services, 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 very large volumes, 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.
 
We sell petroleum products to many wholesalers and end-users that are not large companies and are privately-owned operations.  While those sales are not large volume sales, they tend to be frequent transactions such that a large balance can develop quickly.  Even if our credit review and analysis mechanisms work properly, we have, and we could continue to experience losses in dealings with other parties.
 
Additionally, many of our customers are impacted by the weakening economic outlook and declining commodity prices in a manner that could influence the need for our products and services.
 
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, our operations are subject to environmental protection and safety laws and regulations that restrict our operations, impose relatively harsh consequences for noncompliance, and require us to expend resources in an effort to maintain compliance. Moreover, our operations, including the transportation and storage of crude oil and other commodities involves a risk that crude oil and related hydrocarbons or other substances 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.


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.
 
A substantial portion of our CO 2 operations involves us supplying CO 2 to industrial customers using reserves attributable to our volumetric production payment interests, which are a finite resource and projected to terminate around 2015.
 
The cash flow from our CO 2 operations involves us supplying CO 2 to industrial customers using reserves attributable to our volumetric production payments, which are projected to terminate around 2015. 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 2015.
 
Fluctuations in demand for CO 2 by our industrial customers could have a material adverse impact on our profitability, results of operations and cash available for distribution.
 
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 and our syngas operations are dependent on one customer.
 
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, and we cannot assure unitholders that an unanticipated deterioration in those customers’ ability to meet their obligations to us might not occur.
 
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 unitholders that unanticipated deterioration of its ability to meet its obligations to the syngas joint venture might not occur.


Our CO 2 operations are exposed to risks related to Denbury’s operation of its CO 2 fields, equipment and pipeline as well as any of our facilities that Denbury operates.
 
Because Denbury produces the CO 2 and transports the CO 2 to our customers (including Denbury), any major failure of its operations could have an impact on our ability to meet our obligations to our CO 2 customers (including Denbury). We have no other supply of CO 2 or method to transport it to our customers.  Sandhill relies on us for its supply of CO 2 therefore our share of the earnings of Sandhill would also be impacted by any major failure of Denbury’s operations.
 
Our refinery services division is dependent on contracts with less than fifteen refineries and much of its revenue is attributable to a few refineries.
 
If one or more of our refinery customers that, individually or in the aggregate, generate a material portion of our refinery services revenue experience financial difficulties or changes in their strategy for sulfur removal such that they do not need our services, our cash flows could be adversely affected.  For example, in 2008, approximately 63% of our refinery services’ division NaHS by-product was attributable to Conoco’s refinery located in Westlake, Louisiana.  That contract requires Conoco to make available minimum volumes of acid gas to us (except during periods of force majeure).  Although the primary term of that contract extends until 2018, if Conoco is excused from performing, or refuses or is unable to perform, its obligations under that contract for an extended period of time, such non-performance could have a material adverse effect on our profitability and cash flow.
 
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.
 
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, accident, terrorist attack or other interruption event involving us could result in severe personal injury, property damage and/or environmental damage, which could curtail our operations and otherwise adversely affect our assets and cash flow.
 
Some of our operations involve significant 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.
 
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.
 
We cannot cause our joint ventures 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 ventures 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, or in the case of DG Marine, only one of which is appointed by us.  In addition, the other 50% owners in our T&P Syngas and Sandhill joint ventures operate those joint venture facilities and the other 51% owner of our DG Marine joint venture controls key operational decisions of the joint venture. Thus, without the concurrence of the other joint venture participant, we cannot cause our joint ventures to take or not to take certain actions, even though those actions may be in the best interest of the joint ventures or us.


Our refinery services operations are dependent upon the supply of caustic soda and the demand for NaHS, as well as the operations of the refiners for whom we process sour gas.
 
Caustic soda is a major component used in the provision of sour gas treatment services provided by us to refineries. NaHS, the resulting product from the refinery services we provide, is a vital ingredient in a number of industrial and consumer products and processes. Any decrease in the supply of caustic soda could affect our ability to provide sour gas treatment services to refiners and any decrease in the demand for NaHS by the parties to whom we sell the NaHS could adversely affect our business. The refineries' need for our sour gas services is also 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.
 
Our operating results from our trucking operations may fluctuate and may be materially adversely affected by economic conditions and business factors unique to the trucking industry.
 
Our trucking business is dependent upon factors, many of which are beyond our control. Those factors include excess capacity in the trucking industry, difficulty in attracting and retaining qualified drivers, significant increases or fluctuations in fuel prices, fuel taxes, license and registration fees and insurance and claims costs, to the extent not offset by increases in freight rates. Our results of operations from our trucking operations also are affected by recessionary economic cycles and downturns in customers’ business cycles. Economic and other conditions may adversely affect our trucking customers and their ability to pay for our services.
 
In the past, there have been shortages of drivers in the trucking industry and such shortages may occur in the future. Periodically, the trucking industry experiences substantial difficulty in attracting and retaining qualified drivers. If we are unable to continue to retain and attract drivers, we could be required to adjust our driver compensation package, let trucks sit idle or otherwise operate at a reduced level, which could adversely affect our operations and profitability.
 
Significant increases or rapid fluctuations in fuel prices are major issues for the transportation industry. Increases in fuel costs, to the extent not offset by rate per mile increases or fuel surcharges, have an adverse effect on our operations and profitability.
 
Denbury is the only shipper (other than us) on our Mississippi System.
 
Denbury is our only customer on the Mississippi System. This relationship may subject our operations to increased risks. Any adverse developments concerning Denbury could have a material adverse effect on our Mississippi System business. Neither our partnership agreement nor any other agreement requires Denbury to pursue a business strategy that favors us or utilizes our Mississippi System. Denbury may compete with us and may manage their assets in a manner that could adversely affect our Mississippi System business.
 
Our investment in DG Marine exposes us to certain risks that are inherent to the barge transportation industry as well certain risks applicable to our other operations.
 
DG Marine’s inland barge transportation business has exposure to certain risks which are significant to our other operations and certain risks inherent to the barge transportation industry.  For example, unlike our other operations, DG Marine operates barges that transport products to and from numerous marine locations, which exposes us to new risks, including:
 
 
·
being subject to the Jones Act and other federal laws that restrict U.S. maritime transportation to vessels built and registered in the U.S. and owned and manned by U.S. citizens, with any failure to comply with such laws potentially resulting in severe penalties, including permanent loss of U.S. coastwise trading rights, fines or forfeiture of vessels;
 
 
·
relying on a limited number of customers;
 
 
·
having primarily short-term charters which DG Marine may be unable to renew as they expire; and


 
·
competing against businesses with greater financial resources and larger operating crews than DG Marine.
 
In addition, like our other operations, DG Marine’s refined products transportation business is an integral part of the energy industry infrastructure, which increases our exposure to declines in demand for refined petroleum products or decreases in U.S. refining activity.
 
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 unitholder detriment.
 
Denbury indirectly owns the majority interest in, and controls, our general partner. Conflicts of interest may arise between Denbury 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 to pursue a business strategy that favors us or utilizes our assets. Denbury’s directors and officers have a fiduciary duty to make these decisions in the best interest of the stockholders of Denbury;
 
 
·
Denbury may compete with us. Denbury 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, 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.
 
Denbury is not obligated to enter into any transactions with (or to offer any opportunities to) us, although we expect to continue to enter into substantial transactions and other activities with Denbury and its subsidiaries because of the businesses and areas in which we and Denbury currently operate, as well as those in which we plan to operate in the future.


Further, Denbury’s 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 makes the final determination regarding how any particular conflict of interest is resolved.
 
Some more recent transactions in which we, on the one hand, and Denbury and its subsidiaries, on the other hand, had a conflict of interest include:
 
 
·
transportation services
 
 
·
pipeline monitoring services; and
 
 
·
CO 2 volumetric production payment.
 
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 partner. 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 our general partner without cause. If our general partner is removed without cause, (i) Denbury 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 our general partner, its affiliates, their transferees, and persons who acquired such units with the prior approval of the board of directors of our general partner, cannot vote on matters relating to the succession, election, removal, withdrawal, replacement or substitution of our general partner. 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 our general partner to a third party. The new owner of our general partner would then be in a position to replace the board of directors and officers of our general partner with its own choices and to control the decisions made 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 or members of the Davison family 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, 2008 our general partner and its affiliates own 4,028,096 (approximately 10.2%) of our common units and members of the Davison family owned 11,781,379 (approximately 30%) of our common units. In the future, any such parties 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  Additionally, we have filed a shelf registration statement for the units held by members of the Davison family, and the Davison family may sell their common units at any time, subject to certain restrictions under securities laws.
 
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 controls our general partner, is a significant stakeholder in our limited partner interests and has historically, with its affiliates, employed the personnel who operate our businesses.  In addition, we are parties to numerous agreements with Denbury, including the lease of the NEJD CO 2 pipeline and the transportation arrangements related to the Free State pipeline.  Denbury is also a significant customer of our Mississippi System.  See “Our General Partner and Our Relationship with Denbury Resources Inc.” under Item 1 – Business.  We could be adversely affected if Denbury experiences any adverse developments or fails to pay us timely.
 
We may issue additional common units without unitholder’s 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 unitholders to sell their 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, unitholders may be required to sell their common units at an undesirable time or price and may not receive any return on their investment. Unitholders may also incur a tax liability upon a sale of their 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.
 
An impairment of goodwill and intangible assets could adversely affect some of our accounting and financial metrics and, possibly, result in an event of default under our revolving credit facility.
 
At December 31, 2008, our balance sheet reflected $325.0 million of goodwill and $166.9 million of intangible assets. Goodwill is recorded when the purchase price of a business exceeds the fair market value of the tangible and separately measurable intangible net assets. Generally accepted accounting principles in the United States (“GAAP”) require us to test goodwill for impairment on an annual basis or when events or circumstances occur indicating that goodwill might be impaired. Long-lived assets such as intangible assets with finite useful lives are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. Financial and credit markets volatility directly impacts our fair value measurements for tests of impairment through our weighted average cost of capital that we use to determine our discount rate.  If we determine that any of our goodwill or intangible assets were impaired, we would be required to record the impairment.  Our assets, equity and earnings as recorded in our financial statements would be reduced, and it could adversely affect certain of our borrowing metrics.  While such a write-off would not reduce our primary borrowing base metric of EBITDA, it would reduce our consolidated capitalization ratio, which, if significant enough, could result in an event of default under our credit agreement.  At December 31, 2008, such a write-off would need to exceed $330 million in order to result in an event of default.
 
Tax Risks to Common Unitholders
 
Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as our not being subject to a material amount of entity-level taxation by individual states.  A publicly-traded partnership can lose its status as a partnership for a number of reasons, including not having enough “qualifying income.”  If the IRS were to treat us as a corporation or if we were to become subject to a material amount of entity-level taxation for state tax purposes, then our cash available for distribution to unitholders would be substantially reduced.
 
The anticipated after-tax economic benefit of an investment in us depends largely on our being treated as a partnership for federal income tax purposes.  Section 7704 of the Internal Revenue Code provides that publicly traded partnerships will, as a general rule, be taxed as corporations.  However, an exception, referred to in this discussion as the “Qualifying Income Exception,” exists with respect to publicly traded partnerships 90% or more of the gross income of which for every taxable year consists of “qualifying income.”  If less than 90% of our gross income for any taxable year is “qualifying income” from transportation or processing of natural resources including crude oil, natural gas or products thereof, interest, dividends or similar sources, we will be taxable as a corporation under Section 7704 of the Internal Revenue Code for federal income tax purposes for that taxable year and all subsequent years.


In addition, 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.  Any change to current law could negatively impact the value of an investment in our common units.  In addition, because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation.  Imposition of any such taxes may substantially reduce the cash available for distribution to our unitholders.
 
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 reduce our cash available for distribution to 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 positions we take. It may be necessary to resort to administrative or court proceedings to sustain some of the positions we take. A court may not agree with some or all of the 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.
 
Unitholders will be required to pay taxes on income from us even if they do not receive any cash distributions from us.
 
Unitholders will be required to pay any federal income taxes and, in some cases, state and local income taxes on their share of our taxable income even if unitholders receive no cash distributions from us. Unitholders may not receive cash distributions from us equal to their 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 unitholders sell their common units, they will recognize a gain or loss equal to the difference between the amount realized and their tax basis in those common units. Prior distributions to unitholders in excess of the total net taxable income unitholders were allocated for a common unit, which decreased their tax basis in that common unit, will, in effect, become taxable income to unitholders if the common unit is sold at a price greater than their tax basis in that common unit, even if the price is less than their original cost. A substantial portion of the amount realized, whether or not representing gain, may be ordinary income. In addition, if unitholders sell their units, they may incur a tax liability in excess of the amount of cash they receive from the sale.
 
Tax-exempt entities 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), 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. 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. persons will be required to file federal income tax returns and pay tax on their share of our taxable income.
 
We will treat each purchaser of common units as having the same tax benefits without regard to the actual common 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.


Unitholders will likely be subject to state and local taxes in states where they do not live as a result of an investment in the common units.
 
In addition to federal income taxes, unitholders 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 unitholders do not live in any of those jurisdictions. Unitholders 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, unitholders may be subject to penalties for failure to comply with those requirements. We own assets and do business in more than 25 states including Texas, Louisiana, Mississippi, Alabama, Florida, Arkansas and Oklahoma.  Many of the states we currently do business in   impose a personal income tax. It is unitholders’ responsibility to file all United States federal, foreign, state and local tax returns.
 
We have subsidiaries that are treated as corporations for federal income tax purposes and subject to corporate-level income taxes.
 
We conduct a portion of our operations through subsidiaries that are, or are treated as, corporations for federal income tax purposes.  We may elect to conduct additional operations in corporate form in the future.  These corporate subsidiaries will be subject to corporate-level tax, which will reduce the cash available for distribution to us and, in turn, to our unitholders.  If the IRS were to successfully assert that these corporate subsidiaries have more tax liability than we anticipate or legislation was enacted that increased the corporate tax rate, our cash available for distribution to our unitholders would be further reduced.
 
 We prorate our items of income, gain, loss and deduction between transferors and transferees of our common units each month based upon the ownership of our common units on the first day of each month, instead of on the basis of the date a particular common unit is transferred.
 
We prorate our items of income, gain, loss and deduction between transferors and transferees of our common units each month based upon the ownership of our common units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The use of this proration method may not be permitted under existing Treasury regulations. If the IRS were to successfully challenge this method or new Treasury regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders.
 
We have adopted certain valuation methodologies that may result in a shift of income, gain, loss and deduction between our general partner and our unitholders. The IRS may challenge this treatment, which could adversely affect the value of the common units.
 
When we issue additional common units or engage in certain other transactions, we determine the fair market value of our assets and allocate any unrealized gain or loss attributable to our assets to the capital accounts of our unitholders and our general partner.  Our methodology may be viewed as understating the value of our assets.  In that case, there may be a shift of income, gain, loss and deduction between certain unitholders and our general partner, which may be unfavorable to such unitholders.  Moreover, subsequent purchasers of common units may have a greater portion of their Internal Revenue Code Section 743(b) adjustment allocated to our tangible assets and a lesser portion allocated to our intangible assets.  The IRS may challenge our methods, or our allocation of the Section 743(b) adjustment attributable to our tangible and intangible assets, and allocations of income, gain, loss and deduction between our general partner and certain of our unitholders.
 
A successful IRS challenge to these methods or allocations could adversely affect the amount of taxable income or loss being allocated to our unitholders.  It also could affect the amount of gain from a unitholder’s sale of common units and could have a negative impact on the value of the common units or result in audit adjustments to the unitholder’s tax returns.
 
The sale or exchange of 50% or more of our capital and profits interests during any twelve-month period will result in the termination of our partnership for federal income tax purposes.
 
We will be considered to have terminated for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period.  Our termination would, among other things, result in the closing of our taxable year for all unitholders, which would result in us filing two tax returns (and unitholders receiving two Schedule K-1’s) for one fiscal year.  Our termination could also result in a deferral of depreciation deductions allowable in computing our taxable income.  In the case of a common unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of our taxable year may result in more than twelve months of our taxable income or loss being includable in his taxable income for the year of termination.  Our termination currently would not affect our classification as a partnership for federal income tax purposes, but instead, we would be treated as a new partnership for tax purposes.  If treated as a new partnership, we must make new tax elections and could be subject to penalties if we are unable to determine that a termination occurred.


Item 1B.  U nresolv ed Staff Comments
 
None.
 
Item 2.  P rope rties
 
See Item 1.  Business.  We also have various operating leases for rental of office space, office and field equipment, and vehicles.  See “Commitments and Off-Balance Sheet Arrangements” in Management’s Discussion and Analysis of Financial Condition and Results of Operations, and Note 19 of the Notes to Consolidated Financial Statements for the future minimum rental payments.  Such information is incorporated herein by reference.
 
Item 3.  Legal Pro ceedi ngs
 
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 19 of the Notes to Consolidated Financial Statements.)
 
Item 4.  Subm issio n 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 R egi strant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
 
Our common units are listed on the NYSE Alternext US (formerly 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)
 
                   
2009
                 
First Quarter (through February 27, 2009)
  $ 12.60     $ 7.57     $ 0.3300  
                         
2008
                       
Fourth Quarter
  $ 16.00     $ 6.42     $ 0.3225  
Third Quarter
  $ 19.85     $ 11.75     $ 0.3150  
Second Quarter
  $ 22.09     $ 17.02     $ 0.3000  
First Quarter
  $ 25.00     $ 15.07     $ 0.2850  
                         
2007
                       
Fourth Quarter
  $ 28.62     $ 20.01     $ 0.2700  
Third Quarter
  $ 37.50     $ 27.07     $ 0.2300  
Second Quarter
  $ 35.98     $ 20.01     $ 0.2200  
First Quarter
  $ 22.01     $ 18.76     $ 0.2100  

_____________________
(1)  Cash distributions are shown in the quarter paid and are based on the prior quarter’s activities.


At February 27, 2009, we had 39,456,774 common units outstanding, including 2,829,055 common units held by our general partner and 1,199,041 held by Denbury.  As of December 31, 2008, we had approximately 10,100 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 incorporated by reference 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.  See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources – Distributions” and Note 10 of the Notes to our Consolidated Financial Statements for further information regarding restrictions on our distributions.
 
EQUITY COMPENSATION PLAN INFORMATION
 
The following table summarizes information about our equity compensation plans as of December 31, 2008.
 
Plan Category
 
Number of securities to be issued upon exercise of outstanding options, warrants and rights
(a)
   
Weighted-average exercise price of outstanding options, warrants and rights
(b)
   
Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a))
(c)
 
Equity Compensation plans approved by security holders:
                 
2007 Long-term Incentive Plan (2007 LTIP)
    78,388    
(1)
      915,429  
 
(1)  Awards issued under our 2007 LTIP are phantom units for which the grantee will receive one common unit for each phantom unit upon vesting.  There is no exercise price.  For additional discussion of our 2007 LTIP, see Note 15 of the Notes to the Consolidated Financial Statements.
 
Recent Sales of Unregistered Securities
 
None.
 


Item 6.  Selected Financial Data
 
The table below includes selected financial and other data for the Partnership for the years ended December 31, 2008, 2007, 2006, 2005, and 2004 (in thousands, except per unit and volume data) .
 
   
Year Ended December 31,
 
   
2008 (1)
   
2007 (1)
   
2006
   
2005
   
2004
 
Income Statement Data:
                             
Revenues:
                             
Supply and logistics (2)
  $ 1,852,414     $ 1,094,189     $ 873,268     $ 1,038,549     $ 901,902  
Refinery services
    225,374       62,095       -       -       -  
Pipeline transportation, including natural gas sales
    46,247       27,211       29,947       28,888       16,680  
CO 2 marketing
    17,649       16,158       15,154       11,302       8,561  
Total revenues
    2,141,684       1,199,653       918,369       1,078,739       927,143  
Costs and expenses:
                                       
Supply and logistics costs (2)
    1,815,090       1,078,859       865,902       1,034,888       897,868  
Refinery services operating costs
    166,096       40,197       -       -       -  
Pipeline transportation, including natural gas purchases
    15,224       14,176       17,521       19,084       8,137  
CO 2 marketing transportation costs
    6,484       5,365       4,842       3,649       2,799  
General and administrative expenses
    29,500       25,920       13,573       9,656       11,031  
Depreciation and amortization
    71,370       38,747       7,963       6,721       7,298  
(Gain) loss from sales of surplus assets
    29       266       (16 )     (479 )     33  
Impairment Expense (3)
    -       1,498       -       -       -  
Total costs and expenses
    2,103,793       1,205,028       909,785       1,073,519       927,166  
Operating income (loss) from continuing operations
    37,891       (5,375 )     8,584       5,220       (23 )
Earnings from equity in joint ventures
    509       1,270       1,131       501       -  
Interest expense, net
    (12,937 )     (10,100 )     (1,374 )     (2,032 )     (926 )
Income (loss) from continuing operations before cumulative effect of change in accounting principle, income taxes and minority interest
    25,463       (14,205 )     8,341       3,689       (949 )
Income tax benefit
    362       654       11       -       -  
Minority interest
    264       1       (1 )     -       -  
Income (loss) from continuing operations before cumulative effect of change in accounting principle
    26,089       (13,550 )     8,351       3,689       (949 )
Income (loss) from discontinued operations
    -       -       -       312       (463 )
Cumulative effect of changes in accounting principle
    -       -       30       (586 )     -  
Net income (loss)
  $ 26,089     $ (13,550 )   $ 8,381     $ 3,415     $ (1,412 )
Net income (loss) per common unit - basic
                                       
Continuing operations
  $ 0.61     $ (0.64 )   $ 0.59     $ 0.38     $ (0.10 )
Discontinued operations
    -       -       -       0.03       (0.05 )
Cumulative effect of change in accounting principle
    -       -       -       (0.06 )     -  
Net income (loss)
  $ 0.61     $ (0.64 )   $ 0.59     $ 0.35     $ (0.15 )
                                         
Cash distributions per common unit
  $ 1.2225     $ 0.93     $ 0.74     $ 0.61     $ 0.60  


   
Year Ended December 31,
 
   
2008 (1)
   
2007 (1)
   
2006
   
2005
   
2004
 
Balance Sheet Data (at end of period):
                             
Current assets
  $ 168,127     $ 214,240     $ 99,992     $ 90,449     $ 77,396  
Total assets
    1,178,674       908,523       191,087       181,777       143,154  
Long-term liabilities
    394,940       101,351       8,991       955       15,460  
Minority interests
    24,804       570       522       522       517  
Partners' capital
    632,658       631,804       85,662       87,689       45,239  
                                         
                                         
Other Data:
                                       
Maintenance capital expenditures (4)
    4,454       3,840       967       1,543       939  
Volumes - continuing operations:
                                       
Crude oil pipeline (barrels per day)
    64,111       59,335       61,585       61,296       63,441  
CO 2 pipeline (Mcf per day) (5)
    160,220       -       -       -       -  
CO 2 sales (Mcf per day)
    78,058       77,309       72,841       56,823       45,312  
NaHS sales (DST) (6)
    162,210       69,853       -       -       -  

(1) 
O ur operating results and financial position have been affected by acquisitions in 2008 and 2007, most notably the Grifco acquisition in July 2008 and the Davison acquisition, which was completed in July 2007. The results of these operations are included in our financial results prospectively from the acquisition date. For additional information regarding these acquisitions, see Note 3 of the Notes to Consolidated Financial Statements included under Item 8 of this annual report.
(2) 
Supply and logistics revenues, costs and crude oil wellhead volumes are reflected net of buy/sell arrangements since April 1, 2006.
(3) 
 In 2007, we recorded an impairment charge of $1.5 million related to our natural gas pipeline assets.
(4) 
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.
(5) 
Volume per day for the period we owned the Free State CO 2 pipeline in 2008.
(6) 
Volumes relate to operations acquired in July 2007.


Item 7.  Mana geme nt’s Discussion and Analysis of Financial Condition and Results of Operation
 
Included in Management’s Discussion and Analysis are the following sections:
 
 
·
Overview of 2008
 
 
·
Available Cash before Reserves
 
 
·
Acquisitions in 2008
 
 
·
Results of Operations
 
 
·
Significant Events
 
 
·
Capital Resources and Liquidity
 
 
·
Commitments and Off-Balance Sheet Arrangements
 
 
·
Critical Accounting Policies and Estimates
 
 
·
Recent 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.  During the fourth quarter of 2008, we revised the manner in which we internally evaluate our segment performance.  As a result, we changed our definition of segment margin to include within segment margin all costs that are directly associated with a business segment.  Segment margin now includes costs such as general and administrative expenses that are directly incurred by a business segment.  Segment margin also includes all payments received under direct financing leases.  In order to improve comparability between periods, we exclude from segment margin the non-cash effects of our stock-based compensation plans which are impacted by changes in the market price for our common units.  Previous periods have been restated to conform to this segment presentation.  We now define segment margin as revenues less cost of sales, operating expenses (excluding depreciation and amortization), and segment general and administrative expenses, plus our equity in distributable cash generated by our joint ventures.  In addition, our segment margin definition excludes the non-cash effects of our stock-based compensation plans, and includes the non-income portion of payments received under direct financing leases.  Our chief operating decision maker (our Chief Executive Officer) evaluates segment performance based on a variety of measures including segment margin, segment volumes where relevant, and maintenance capital investment.  A reconciliation of segment margin to income from before income taxes and minority interests is included in our segment disclosures in Note 12 to the consolidated financial statements.
 
Available Cash before Reserves (a non-GAAP measure) is net income as adjusted for specific items, the most significant of which are the addition of non-cash expenses (such as depreciation), the substitution of cash generated by our joint ventures in lieu of our equity income attributable to our joint ventures, the elimination of gains and losses on asset sales (except those from the sale of surplus assets) and the subtraction of maintenance capital expenditures, which are expenditures that are necessary to sustain existing (but not to provide new sources of) cash flows.   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 2008
 
 In 2008, we reported net income of $26.1 million, or $0.61 per common unit.  Non-cash depreciation and amortization totaling $71.4 million reduced net income during the year.    See additional discussion of our depreciation and amortization expense in “Results of Operations – Other Costs and Interest” below.
 
Segment margin for all of our operating segments increased in 2008.  The acquisitions of the Davison family business in July 2007, the two drop down transactions with Denbury in May 2008 and the acquisition in July 2008 of our interest in DG Marine which owns the inland marine transportation business of Grifco were the primary factors contributing to this improvement.  During 2008, we continued to integrate these acquisitions with our existing operations.
 
Increases in cash flow generally result in increases in Available Cash before Reserves, from which we pay distributions quarterly to holders of our common units and our general partner.  During 2008, we generated $89.8 million of Available Cash before Reserves, and we distributed $50.5 million to holders of our common units and general partner.  Cash provided by operating activities in 2008 was $94.8 million.  Our total distributions attributable to 2008 increased 109% over the total distributions attributable to 2007.


Additionally, on January 8, 2009, we declared our fourteenth consecutive increase in our quarterly distribution to our common unitholders relative to the fourth quarter of 2008.  This distribution of $0.33 per unit (paid in February 2009) represents a 16% increase from our distribution of $0.285 per unit for the fourth quarter of 2007. During the fourth quarter of 2008, we paid a distribution of $0.3225 per unit related to the third quarter of 2008.
 
The current economic crisis has restricted the availability of credit and access to capital in our business environment.  Despite efforts by treasury and banking regulators to provide liquidity to the financial sector, capital markets continue to remain constrained.  While we anticipate that the challenging economic environment will continue for the foreseeable future, we believe that our current cash balances, future internally-generated funds and funds available under our credit facility will provide sufficient resources to meet our current working capital liquidity needs.  The financial performance of our existing businesses, $195.5 million in cash and existing debt commitments and no need, other than opportunistically, to access the capital markets, may allow us to take advantage of acquisition and/or growth opportunities that may develop.
 
Our ability to fund large new projects or make large acquisitions in the near term may be limited by the current conditions in the credit and equity markets due to limitations in our ability to issue new debt or equity financing.  We will consider other arrangements to fund large growth projects and acquisitions such as private equity and joint venture arrangements.
 
Available Cash before Reserves
 
Available Cash before Reserves for the year ended December 31, 2008 is as follows (in thousands):
 
   
Year Ended
 
   
December 31, 2008
 
Net income
  $ 26,089  
Depreciation and amortization
    71,370  
Cash received from direct financing leases not included in income
    2,349  
Cash effects of sales of certain assets
    760  
Effects of available cash generated by equity method investees not included in income
    1,830  
Cash effects of stock appreciation rights plan
    (385 )
Non-cash tax benefits
    (2,782 )
Earnings of DG Marine in excess of distributable cash
    (2,821 )
Other non-cash items, net
    (2,172 )
Maintenance capital expenditures
    (4,454 )
Available Cash before Reserves
  $ 89,784  

 
We have reconciled Available Cash before Reserves (a non-GAAP measure) to cash flow from operating activities (the most comparable GAAP measure) for the year ended December 31, 2008 in “Capital Resources and Liquidity – Non-GAAP Reconciliation” below.  For the year ended December 31, 2008, cash flows provided by operating activities were $94.8 million.
 
Acquisitions in 2008
 
Investment in DG Marine Transportation, LLC
 
On July 18, 2008, we completed the acquisition of an effective 49% economic interest in DG Marine, which acquired the inland marine transportation business of Grifco Transportation, Ltd. (“Grifco”) and two of Grifco’s affiliates.  TD Marine, LLC, an entity formed by members of the Davison family (See discussion below on the acquisition of the Davison family businesses in 2007) owns (indirectly) a 51% economic interest in the joint venture.  This acquisition gives us the capability to provide transportation services of petroleum products by barge and complements our other supply and logistics operations.


Grifco received initial purchase consideration of approximately $80 million, comprised of $63.3 million in cash and $16.7 million, or 837,690 of our common units.  DG Marine acquired substantially all of Grifco’s assets, including twelve barges, seven push boats, certain commercial agreements, offices and the rights and obligations to acquire a total of eight new barges.  Through December 31, 2008, DG Marine had taken delivery of four new barges and acquired two new push boats at a total cost of approximately $16 million.  DG Marine expects to take delivery of the remaining new barges and one additional push boat in first half of 2009 (at a total cost of approximately $14.6 million). Upon delivery of the first four new barges and two new push boats in the latter half of 2008, DG Marine paid additional purchase consideration to Grifco of $6 million.  After delivery of the remaining four barges and push boat, and after placing the barges and push boats into commercial operations, DG Marine will be obligated to pay additional purchase consideration of up to $6 million.   The estimated discounted present value of that $6 million obligation is included in current liabilities in our consolidated balance sheets.
 
The Grifco acquisition and related closing costs were funded with $50 million of aggregate equity contributions from us and TD Marine, in proportion to our ownership percentages, and with borrowings of $32.4 million under a $90 million revolving credit facility which is non-recourse to us and TD Marine (other than with respect to our  investments in DG Marine).  Although DG Marine’s debt is non-recourse to us, our ownership interest in DG Marine is pledged to secure its indebtedness and we have guaranteed $7.5 million of its indebtedness.  The guarantee will expire on May 31, 2009 if DG marine’s leverage ratio under its revolving credit agreement is less than 4.0 to 1.0. We funded our $24.5 million equity contribution with $7.8 million of cash and 837,690 of our common units, valued at $19.896 per unit, for a total value of $16.7 million.  At closing, we also redeemed 837,690 of our common units from the Davison family. The total number of our outstanding common units did not change as a result of that investment.
 
We consolidate DG Marine’s financial results even though we do not own a majority interest in it.  We also do not control the key operational decisions of DG Marine.  See Note 3 of the Notes to the Consolidated Financial Statements for more information on DG Marine.
 
Drop-down Transactions
 
We completed two “drop-down” transactions with Denbury in 2008 involving two of their existing CO 2 pipelines - the NEJD and Free State CO 2 pipelines. We paid for these pipeline assets with $225 million in cash and 1,199,041 common units valued at $25 million based on the average closing price of our units for the five trading days surrounding the closing date of the transaction. We expect to receive approximately $30 million per annum, in the aggregate, under the lease agreement for the NEJD pipeline and the Free State pipeline transportation services agreement.  Future payments for the NEJD pipeline are fixed at $20.7 million per year during the term of the financing lease, and the payments related to the Free State pipeline are dependent on the volumes of CO 2 transported therein, with a minimum monthly payment of $0.1 million.
 
The NEJD Pipeline System is a 183-mile, 20” pipeline extending from the Jackson Dome, near Jackson, Mississippi, to near Donaldson, Louisiana, and is currently being used by Denbury for its Phase I area of tertiary operations in southwest Mississippi.  Denbury has the rights to exclusive use of the NEJD Pipeline System and is responsible for all operations and maintenance on the system, and will bear and assume all obligations and liabilities with respect to the pipeline.
 
On August 5, 2008, Denbury announced that the economic impact of an approved tax accounting method change providing for an acceleration of tax deductions will likely affect certain types of future asset “drop-downs” to us.  Transactions which are not sales for tax purposes for Denbury, such as the lease arrangement for the NEJD pipeline, would not be affected provided the transactions meet other tax structuring criteria for Denbury and us.  There can be no assurances as to the amount, or timing, of any potential future asset “drop-downs” from Denbury to us.


Results of Operations
 
The contribution of each of our segments to total segment margin in each of the last three years was as follows:
 
   
Year Ended December 31,
 
   
2008
   
2007
   
2006
 
   
(in thousands)
 
Pipeline transportation
  $ 33,149     $ 14,170     $ 13,280  
Refinery services
    55,784       19,713       -  
Industrial gases
    13,504       13,038       12,844  
Supply and logistics
    32,448       10,646       5,017  
Total segment margin
  $ 134,885     $ 57,567     $ 31,141  
 
Pipeline Transportation Segment
 
We operate three common carrier crude oil pipeline systems and a CO 2 pipeline in a four state area.  We refer to these pipelines as our Mississippi System, Jay System, Texas System and Free State Pipeline.  Volumes shipped on these systems for the last three years are as follows (barrels per day):
 
Pipeline System
 
2008
   
2007
   
2006
 
                   
Mississippi-Bbls/day
    25,288       21,680       16,931  
Jay - Bbls/day
    13,428       13,309       13,351  
Texas - Bbls/day
    25,395       24,346       31,303  
Free State - Mcf/day
    160,220 (1)     -       -  

(1)  Daily average for the period we owned the pipeline in 2008.
 
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 over the last three years and we will continue to make further improvements.
 
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.  As Denbury continues to acquire and develop old oil fields using CO 2 based tertiary recovery operations, Denbury may need crude oil gathering and CO 2 supply infrastructure to those fields, which could create some opportunities for us.
 
Two segments of crude oil pipeline connect producing fields operated by Denbury to our Mississippi System.  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 and Alabama ships crude oil from mature producing fields in the area as well as production from new wells drilled in the area.  The increase in crude oil prices in 2007 and 2008 led to interest in further development of the mature fields.  We do not know what long-term impact the decline in crude oil prices in the fourth quarter of 2008 may have on the continued production from the mature fields, and the volumes transported on our pipeline.
 
The new production in the area produces greater tariff revenue for us due to the greater distance that the crude oil is transported on the pipeline.  This increased revenue, increases in tariff rates each year on the remaining segments of the pipeline, sales of pipeline loss allowance volumes, and operating efficiencies that have decreased operating costs have contributed to increases in our cash flows from the Jay System.  The recent decline in crude oil market prices will also impact our sales of pipeline loss allowance volumes.
 
As we have consistently been able to increase our pipeline tariffs as needed and due to the new production in the area surrounding our Jay System, we do not believe that a decline in volumes or revenues from sales of pipeline loss allowance volumes will affect the recoverability of the net investment that remains for the Jay System.
 
Volumes on our Texas System averaged 25,395 barrels per day during 2008.  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.  We have a joint tariff with TEPPCO under which we earn $0.31 per barrel on the majority of the barrels we deliver to the shipper’s facilities.  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. We lease tankage in Webster on the Texas System of approximately 165,000 barrels.  We have a tank rental reimbursement agreement 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 entered into a twenty-year transportation services agreement to deliver CO 2 on the Free State pipeline for Denbury’s use in its tertiary recovery operations.    Under the terms of the transportation services agreement, we are responsible for owning, operating, maintaining and making improvements to the pipeline.  Denbury has rights to exclusive use of the pipeline and is required to use the pipeline to supply CO 2 to its current and certain of its other tertiary operations in east Mississippi.  The transportation services agreement provides for a $0.1 million per month minimum payment plus a tariff based on throughput. Denbury has two renewal options, each for five years on similar terms.
 
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.
 
In May 2008, we entered into a twenty-year financing lease transaction with Denbury valued at $175 million related to Denbury’s North East Jackson Dome (NEJD) Pipeline System.  Denbury Onshore makes fixed quarterly base rent payments to us of $5.2 million per quarter or approximately $20.7 million per year.
 
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 operations for our pipeline transportation segment were as follows.
 
   
Year Ended December 31,
 
   
2008
   
2007
   
2006
 
   
(in thousands)
 
Pipeline transportation revenues, excluding natural gas
  $ 41,097     $ 22,755     $ 21,742  
Natural gas tariffs and sales, net of gas purchases
    232       334       612  
Pipeline operating costs, excluding non-cash charges for stock-based compensation
    (10,529 )     (9,488 )     (9,605 )
Non-income payments under direct financing leases
    2,349       569       531  
Segment margin
  $ 33,149     $ 14,170     $ 13,280  

 
Year Ended December 31, 2008 Compared with Year Ended December 31, 2007
 
Pipeline segment margin increased $19.0 million in 2008 as compared to 2007.  This increase is primarily attributable to the following factors:
 
 
·
An increase in revenues from the lease of the NEJD pipeline to Denbury beginning in May 2008 added $12.1 million to segment margin;
 
 
·
an increase in revenues from the Free State pipeline beginning in May 2008 added a total of $5.1 million to CO 2 tariff revenues, with the transportation fee related to 34.3 MMcf totaling $4.4 million and the minimum monthly payments totaling $0.7 million;
 
 
·
an increase in revenues from crude oil tariffs and direct financing leases of $1.4 million; and

 
 
·
an increase in revenues from sales of pipeline loss allowance volumes of $1.7 million, resulting from an increase in the average annual crude oil market prices of $26.73 per barrel, offset by a decline in allowance volumes of approximately 15,000 barrels.
 
 
·
Partially offsetting the increase in segment margin was an increase of $1.0 million in pipeline operating costs.
 
Tariff and direct financing lease revenues from our crude oil pipelines increased primarily due to volume increases on all three pipeline systems totaling 4,776 barrels per day. These volume increases occurred despite the brief disruptions in operations caused by Hurricanes Gustav and Ike which affected power supplies on the Gulf Coast.
 
The tariff on the Mississippi System is an incentive tariff, such that the average tariff per barrel decreases as the volumes increase, however the overall impact of an annual tariff increase on July 1, 2008 with the volume increase still resulted in improved tariff revenues from this system of $0.6 million.  As a result of the annual tariff increase on July 1, 2008, average tariffs on the Jay System increased by approximately $0.06 per barrel between the two periods.  Combined with the 119 barrels per day increase in average daily volumes, the Jay System tariff revenues increased $0.4 million.  The impact of volume increases on the Texas System on revenues is not very significant due to the relatively low tariffs on that system.  Approximately 75% of the 2008 volume on that system was shipped on a tariff of $0.31 per barrel.
 
As is common in the industry, our crude oil tariffs incorporate a loss allowance factor that is intended to, among other things, offset losses due to evaporation, measurement and other losses in transit.  We value the variance of allowance volumes to actual losses at the average market value at the time the variance occurred and the result is recorded as either an increase or decrease to tariff revenues.  As compared to 2007, volumes from loss allowance were 15,000 barrels less, however the average price of crude oil was significantly higher during 2008 as compared to 2007.  Based on historic volumes, a change in crude oil market prices of $10 per barrel has the effect of decreasing or increasing our pipeline loss allowance revenues by approximately $0.1 million per month.
 
Pipeline operating costs increased $1.0 million, with approximately $0.4 million of that amount due to an increase in IMP testing and repairs, $0.2 million related to the Free State pipeline acquired in May 2008 and $0.1 million related to increased electricity costs.  Fluctuations in the cost of our IMP program are a function of the length and age of the segments of the pipeline being tested each year and the type of test being performed.  Electricity costs in 2008 were higher due to market increases in the cost of power.  The remaining $0.3 million of increased pipeline operating costs were related to various operational and maintenance items.
 
Year Ended December 31, 2007 Compared with Year Ended December 31, 2006
 
Pipeline segment margin increased $0.9 million, or 7%, for 2007, as compared to 2006.  Revenues from crude oil and CO 2 tariffs and related sources were responsible for the increase for the period.  Net profit from natural gas transportation and sales decreased slightly and pipeline operating costs increased, slightly offsetting the increase from tariffs and other sources.
 
Tariff revenues from transportation of crude oil and CO 2 increased $0.6 million in 2007 compared to the prior year period due primarily to increased volumes on the Mississippi System of 4,749 barrels per day and tariff increases on the Jay System. The volumes on the Jay System were almost identical to the prior year period. As a result of the annual tariff increase on July 1, 2007, average tariffs on the Jay System increased by approximately $0.04 per barrel between the two periods. The effect on revenues of a decline in volumes on the Texas System was not significant due to the relatively low tariffs on that system.
 
Higher market prices for crude oil added $0.4 million to pipeline loss allowance revenues.  During 2007, average crude oil market prices, as referenced by the prices posted by Shell Trading (US) Company for West Texas/New Mexico Intermediate grade crude oil, were $6.20 higher than in 2006.
 
Net profit from natural gas pipeline activities decreased in total $0.3 million from 2006 amounts.  The natural gas pipeline activities were negatively impacted by production difficulties of a producer attached to the system.  Due to the declines we have experienced in the results from our natural gas pipelines, we reviewed these assets to determine if the fair market value of the assets exceeded the net book value of the assets.  As a result of this review, we recorded an impairment loss in 2007 related to these assets.  See “Other Costs and Interest – Depreciation, Amortization and Impairment” below.
 
Operating costs decreased $0.1 million.  The decrease in 2007 was due primarily to a decline in pipeline lease fees and insurance related to our pipeline operations.


Refinery Services Segment
 
Segment margin from our refinery services for 2008 was $55.8 million.  Segment margin from our refinery services for the five months we owned this business in 2007 was $19.7 million.  Annualizing the 2007 results and comparing those results to the 2008 segment margin would indicate that segment margin increased by approximately $8.5 million between the periods.
 
We provide a service to refiners – processing the refiner’s sour gas streams to reduce the sulfur content.  The key cost components of the provision of this service are the purchase and transportation of caustic soda for use in the processing of the gas streams.  Market prices for caustic soda were somewhat volatile in 2008, ranging from an average monthly low spot price of approximately $400 per dry short ton (DST) during the first quarter of 2008 as published by the Chemical Market Associates, Inc. (CMAI) to a high of $850 per DST in the fourth quarter of 2008.   Our freight costs during 2008 fluctuated with freight demand and fuel prices.  The price of diesel fuel ranged from a low of approximately $2.26 per gallon to a high of approximately $4.73 per gallon.  In 2008, we believe that we were successful in mitigating some of the impact on segment margin of the volatility of these costs through our management of caustic acquisition and freight costs and by indexing our sales prices for NaHS to CMAI caustic market prices and adjusting sales prices for fluctuations in fuel surcharges.  Additionally, we do, from time to time, engage in other activities such as selling caustic soda, buying NaHS from other producers for re-sale to our customers and buying and selling sulfur, the financial results of which are also reported in our refinery services segment.
 
We receive NaHS as consideration for provision of our services to the refiners.  We sell the NaHS for use in applications including, but not limited to, agriculture, dyes and other chemical processing; waste treatment programs requiring stabilization and reduction of heavy and toxic metals; sulfidizing oxide ores (most commonly to separate copper from molybdenum; and certain applications in paper production and tannery processes.    The table below reflects information about NaHS sales for 2008 and similar information for 2007 and 2006 volumes and sales prices on a pro forma basis based on historic data related to the refinery services operations.
 
   
Year Ended
   
Pro Forma Year
 
   
December 31,
   
Ended December 31,
 
   
2008
   
2007
   
2006
 
                   
NaHS Sales
                 
Dry Short Tons (DST)
    162,210       164,059       159,952  
Average sales price per DST, net of delivery costs
  $ 888     $ 591     $ 561  

 
NaHS sales prices per DST increased as we adjusted these prices throughout 2008 for fluctuations in the cost components of our services.  As discussed above, market prices for caustic were volatile in 2008.  Additionally, freight costs for delivering NaHS to our customers fluctuated in 2008 in a manner similar to the freight costs associated with our caustic supply as discussed above.  We were generally successful in increasing our sales prices for NaHS to compensate for these cost fluctuations by indexing approximately 60% of our NaHS sales volumes to market prices for caustic soda and by adjusting sales prices for NaHS as fuel surcharges billed to us increased.
 
Our NaHS sales volumes declined slightly in 2008, with almost all of the decline occurring in the fourth quarter resulting primarily from the slowdown in worldwide economic activity.
 
Industrial Gases Segment
 
Our industrial gases segment includes the results of our CO 2 sales to industrial customers and our share of the available cash generated by our 50% joint ventures, T&P Syngas and Sandhill.


Operating Results
 
Operating results for our industrial gases segment were as follows.
 
   
Year Ended December 31,
 
   
2008
   
2007
   
2006
 
   
(in thousands)
 
Revenues from CO 2 marketing
  $ 17,649     $ 16,158     $ 15,154  
CO 2 transportation and other costs
    (6,484 )     (5,365 )     (4,842 )
Available cash generated by equity investees
    2,339       2,245       2,532  
Segment margin
  $ 13,504     $ 13,038     $ 12,844  
                         
Volumes per day:
                       
CO 2 marketing - Mcf
    78,058       77,309       72,841  
 
 
CO 2 – Industrial Customers
 
We supply CO 2 to industrial customers under seven long-term CO 2 sales contracts.  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 97,625 Mcf.  Under the minimum take-or-pay volumes, the customers must purchase a total of 51,048 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.  At December 31, 2008, we have no liabilities to customers for gas paid for but not taken.
 
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.
 
Based on historical data for 2004 through 2008, we 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 2008 and 2007 under these contracts were as follows:
 
Quarter
 
2008
   
2007
 
First
    73,062       67,158  
Second
    79,968       75,039  
Third
    83,816       85,705  
Fourth
    75,164       80,667  

 
The increasing margins from the industrial gases segment between the periods were the result of an increase in volumes and increases in the average revenue per Mcf sold of 8% from 2007 to 2008 and 1% from 2006 to 2007.  Inflation adjustments in the contracts and variations in the volumes sold under each contract cause the changes in average revenue per Mcf.
 
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 average rate in 2008 increased 4% over the 2007 rate. The average rate per Mcf in 2007 increased 6% over the 2006 rate.  In 2008, we also recorded a charge for approximately $0.9 million related to a commission on one of the industrial gas sales contracts.  We expect this commission to continue in future years at a cost of approximately $0.3 million annually.
 
Equity Method Joint Ventures
 
Our share of the available cash before reserves generated by equity investments in each year primarily resulted from our investment in T&P Syngas.  Our share of the available cash before reserves generated by T&P Syngas for 2008, 2007, and 2006 was $2.2 million, $1.9 million and $2.3 million, respectively.


Supply and Logistics Segment
 
Our supply and logistics segment is focused on utilizing our knowledge of the crude oil and petroleum markets and our logistics capabilities from our terminals, trucks and barges to provide suppliers and customers with a full suite of services.  These services include:
 
 
·
purchasing and/or transporting crude oil from the wellhead to markets for ultimate use in refining;
 
 
·
supplying petroleum products (primarily fuel oil, asphalt, diesel and gasoline) to wholesale markets and some end-users such as paper mills and utilities;
 
 
·
purchasing products from refiners that do not meet the specifications they desire, transporting the products to one of our terminals and blending the products to a quality that meets the requirements of our customers; and
 
 
·
utilizing our fleet of trucks and trailers and barges to take advantage of logistical opportunities primarily in the Gulf Coast states and inland waterways.
 
We also use our terminal facilities to take advantage of contango market conditions for crude oil gathering and marketing, and to capitalize on regional opportunities which arise from time to time for both crude oil and petroleum products.
 
Many U.S. refineries have distinct configurations and product slates that require crude oil with specific characteristics, such as gravity, sulfur content and metals content.  The refineries evaluate the costs to obtain, transport and process their preferred choice of feedstock.  Despite crude oil being considered a somewhat homogenous  commodity, many refiners are very particular about the quality of crude oil feedstock they will process.  That particularity provides us with opportunities to help the refineries in our areas of operation identify crude oil sources meeting their requirements, and to purchase the crude oil and transport it to the refineries for sale.  The imbalances and inefficiencies relative to meeting the refiners’ requirements can provide opportunities for us to utilize our purchasing and logistical skills to meet their demands and take advantage of regional differences.  The pricing in the majority of our purchase contracts contain a market price component, unfixed bonuses that are based on several other market factors and a deduction to cover the cost of transporting the crude oil and to provide us with a margin. Contracts sometimes 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.
 
When crude oil markets are in contango (oil prices for future deliveries are higher than for current deliveries), we may purchase and store crude oil as inventory for delivery in future months.  When we purchase this inventory, we simultaneously enter into a contract to sell the inventory in the future period for a higher price, either with a counterparty or in the crude oil futures market. The storage capacity we own for use in this strategy is approximately 420,000 barrels, although maintenance activities on our pipelines can impact the availability of a portion of this storage capacity.  We generally account for this inventory and the related derivative hedge as a fair value hedge in accordance with Statement of Financial Accounting Standards No. 133.  See Note 17 of the Notes to the Consolidated Financial Statements.
 
In our petroleum products marketing operations, we supply primarily fuel oil, asphalt, diesel and gasoline to wholesale markets and some end-users such as paper mills and utilities.  We also provide a service to refineries by purchasing their products that do not meet the specifications they desire, transporting them to one of our terminals and blending them to a quality that meets the requirements of our customers.   The opportunities to provide this service cannot be predicted, but their contribution to margin as a percentage of their revenues tend to be higher than the same percentage attributable to our recurring operations.  We utilize our fleet of 280 trucks and 550 trailers and DG Marine’s sixteen “hot-oil” barges in combination with our 1.1 million barrels of existing leased and owned storage to service our refining customers and store and blend the intermediate and finished refined products.


Operating results from continuing operations for our supply and logistics segment were as follows.
 
   
Year Ended December 31,
 
   
2008
   
2007
   
2006
 
   
(in thousands)
 
Supply and logistics revenue
  $ 1,852,414     $ 1,094,189     $ 873,268  
Crude oil and products costs
    (1,736,637 )     (1,041,738 )     (851,671 )
Operating and segment general and administrative costs, excluding non-cash charges for stock-based
    (83,329 )     (41,805 )     (16,580 )
Segment margin
  $ 32,448     $ 10,646     $ 5,017  
                         
Volumes of crude oil and petroleum products (mbbls)
    17,410       14,246       13,571  
 
Year Ended December 31, 2008 Compared with Year Ended December 31, 2007
 
In 2008, our supply and logistics segment margin included a full year of contribution from the assets acquired in July 2007 from the Davison family, as compared to only five months in 2007.  This additional seven months of activity in 2008 was the primary factor in the increase in segment margin.
 
The dramatic rise in commodity prices in the first nine months of 2008 provided significant opportunities to us to take advantage of purchasing and blending of “off-spec” products.  The average NYMEX price for crude oil rose from $95.98 per barrel at December 31, 2007 to a high of $145.29 per barrel in July 2008, and then declined to $44.60 per barrel at December 31, 2008.  Grade differentials for crude oil widened significantly during this period as refiners sought to meet consumer demand for gasoline and diesel.  This widening of grade differentials provided us with opportunities to acquire crude oil with a higher specific gravity and sulfur content (heavy or sour crude oil) at significant discounts to market prices for light sweet crude oil and sell it to refiners at prices providing significantly greater margin to us than sales of light sweet crude oil.
 
The absolute market price for crude oil also impacts the price at which we recognize volumetric gains and losses that are inherent in the handling and transportation of any liquid product. In 2008 our average monthly volumetric gains were approximately 2,000 barrels.
 
In the first half of 2007, crude oil markets were in contango, providing an opportunity for us to increase segment margin.  This opportunity did not exist in most of 2008.  Late in 2008, crude oil price markets were again in contango, so we anticipate that opportunities will exist to profit from this strategy in 2009.
 
The demand for gasoline by consumers during most of 2008 also led refiners to focus on producing the “light” end of the refined barrel.  Some refiners were willing to sell the heavy end of the refined barrel, in the form of fuel oil or asphalt, as well as product not meeting their specifications for use in making gasoline, at discounts to market prices in order to free up capacity at their refineries to meet gasoline demand.  Our ability to utilize our logistics equipment to transport product from the refiner’s facilities to one of our terminals increased the opportunity to acquire the product at a discount.
 
As a result of the actions we took in light of the opportunities presented to us in the market, our average margin per barrel increased to $6.65 in 2008 from $3.68 per barrel in 2007.  Before consideration of the costs of providing our services, we generated $63.3 million of additional margin from our supply and logistics activities,
 
Our operating and segment general and administrative (G&A) costs increased by $41.5 million in 2008 as compared to 2007.  The costs of operating the logistical equipment and terminals acquired in the Davison acquisition for an additional seven months in 2008 accounted for approximately $30.2 million of this difference.  Our inland marine transportation operations acquired in July 2008 added approximately $8.4 million to our costs in 2008.  The remaining increase in costs of $2.9 million is attributable to the crude oil portion of our supply and logistics operations.  The most significant components of our operating and segment G&A costs consist of fuel for our fleet of trucks, maintenance of our trucks, terminals and barges, and personnel costs to operate our equipment.  In 2008, fuel costs for our trucks increased significantly as result of market prices for diesel fuel.
 
Year Ended December 31, 2007 Compared with Year Ended December 31, 2006
 
The portions of our supply and logistics operations acquired in the Davison transaction added approximately $8.6 million to our supply and logistics segment margin for the five months we owned these operations in 2007.  Our existing crude oil gathering and marketing operations contribution for 2007 was $0.6 million less than the contribution for 2006, however the contribution was actually the result of offsetting fluctuations as discussed below. Contribution by our crude oil operations is derived from sales of crude oil and from the transportation of crude oil volumes that we did not purchase by truck for a fee, with costs for this part of the operation relating to the purchase of the crude oil and the related aggregation and transportation costs.


An increase in the operating and segment general and administrative costs related to our crude oil activities of $4.1 million was the largest contributor to the decrease in segment margin from crude oil operations.   Compensation and related costs accounted for $1.8 million of the increased costs.  In order to remain competitive in retaining drivers for our crude oil trucking, we increased compensation rates.  We also had increased costs for fuel and repairs to our trucks and related equipment that combined to increase our operating costs in the crude oil area by $1.2 million.  We increased the accrual for the remediation of a former trucking station by $0.3 million. Additionally we incurred costs of $0.7 million related to the operation of the Port Hudson facility which we acquired in 2007.
 
Partially offsetting these increased operating costs was an increase of 1,429 barrels per day in crude oil volumes that we transported for a fee.  Most of this increase in volume was attributable to transportation of Denbury’s production from its wellheads to our pipeline.  The increase in the fees for these services was $2.7 million between 2006 and 2007.  On a like-kind basis, volumes purchased and sold decreased by 2,531 barrels per day.  We focused on volumes in 2007 that met our targets for profitability, and we were impacted by significant volatility between crude quality differentials between the periods, with the overall impact on margin of a decrease of $0.6 million.  The margins generated from the storage of crude oil inventory in the contango market were $0.2 million greater in 2007 than 2006.
 
Other Costs and Interest
 
General and administrative expenses were as follows .
 
   
Year Ended December 31,
 
   
2008
   
2007
   
2006
 
   
(in thousands)
 
General and administrative expenses not separately identified below
  $ 25,131     $ 16,760     $ 9,007  
Bonus plan expense
    4,763       2,033       1,747  
Stock-based compensation plans (credit) expense
    (394 )     1,593       1,279  
Compensation expense related to management team
    -       3,434       -  
Management team transition costs
    -       2,100       1,540  
Total general and administrative expenses
  $ 29,500     $ 25,920     $ 13,573  
 
As a result of the substantial growth we have experienced beginning in 2006 and continuing through 2008, our general and administrative expenses have increased each year.  We added a new senior management team in August 2006 and additional personnel in our financial, human resources and other functions to support the operations we acquired in 2008 and 2007 in the Davison and Grifco transactions.  As we have grown, we have incurred increased legal, audit, tax and other consulting and professional fees, and additional director fees and expenses.  Late in 2008, we moved to larger headquarters offices, incurring costs for moving as well as increased rent and related costs.
 
The expense we have recorded under our bonus plan increased substantially as a result of the improvement in our Available Cash before Reserves in each year and the tripling of our personnel count in mid 2007.  The amounts paid under our bonus plan are a function of both the Available Cash before Reserves that we generate in a year and the improvement in our safety record, and are approved by our Compensation Committee of our Board of Directors.  The bonus plan for employees is described in Item 11, “Executive Compensation” below.
 
We record stock-based compensation expense for phantom units issued under our long-term incentive plan and for our stock appreciation rights (SAR) plan.  (See additional discussion in Item 11, “Executive Compensation” below and Note 15 to the Consolidated Financial Statements.)  The fair value of phantom units issued under our long-term incentive plan is calculated at the grant date and charged to expense over the vesting period of the phantom units.  Unlike the accounting for the SAR plan, the total expense to be recorded is determined at the time of the award and does not change except to the extent that phantom unit awards do not vest due to employee terminations.  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.  We determine the fair value of the SARs at the end of each reporting period and the fair value is charged to expense over the period during which the employee vests in the SARs.   Changes in our common unit market price affect the computation of the fair value of the outstanding SARs.   The change in fair value combined with the elapse of time and its effect on the vesting of SARs create the expense we record.  Additionally any difference between the expected value for accounting purposes that an employee will receive upon exercise of his rights and the actual value received when the employee exercise the SARs creates additional expense.  Due to fluctuations in the market price for our common units, expense for outstanding and exercised SARs has varied significantly between the periods.


Our senior management team was hired in August 2006.  Throughout 2006, 2007 and until December 2008, Denbury negotiated with that team to finalize a compensation package.  Although the terms of these arrangements were not agreed to and completed at December 31, 2007, we recorded expense of $3.4 million in 2007, representing an estimated value of compensation attributable to our Chief Executive Officer and Chief Operating Officer for services performed during 2007. Although this compensation is to ultimately come from our general partner, we have recorded the expense in our Consolidated Statements of Operations in G&A expense due to the “push-down” rules for accounting for transactions where the beneficiary of a transaction is not the same as the parties to the transaction.  On December 31, 2008, we finalized the arrangements with our senior management team. See additional discussion of the compensation arrangements with our senior management team in Item 11, “Executive Compensation.”
 
Additionally, we recorded transition costs primarily in the form of severance costs when members of our management team changed in December 2007 and August 2006.  Our general partner made a cash contribution to us of $1.4 million in 2007 to partially offset the $2.1 million cash cost of the severance payment to a former member of our management team.
 
Depreciation, amortization and impairment expense was as follows:
 
   
Year Ended December 31,
 
   
2008
   
2007
   
2006
 
Depreciation on Genesis assets
  $ 17,331     $ 8,909     $ 3,719  
Depreciation of acquired DG Marine property and equipment
    3,084       -       -  
Amortization on acquired Davison intangible assets
    46,326       25,350       -  
Amortization on acquired DG Marine intangible assets
    92       -       -  
Amortization of CO 2 volumetric production payments
    4,537       4,488       4,244  
Impairment expense on natural gas pipeline assets
    -       1,498       -  
Total depreciation, amortization and impairment expense
  $ 71,370     $ 40,245     $ 7,963  
 
 Depreciation, amortization and impairment increased in 2007 and 2008 due primarily to the depreciation and amortization expense recognized on the fixed assets and intangible assets acquired from the Davison family in July 2007 and the DG Marine acquisition in July 2008.
 
Our intangible assets are being amortized over the period during which the intangible asset is expected to contribute to our future cash flows.  As intangible assets such as customer relationships and trade names are generally most valuable in the first years after an acquisition, the amortization we will record on these assets will be greater in the initial years after the acquisition.  As a result, we expect to record significantly more amortization expense related to our intangible assets in 2008 through 2010 than in years subsequent to that time. See Note 9 to the Consolidated Financial Statements for information on the amount of amortization we expect to record in each of the next five years.
 
  Amortization of our CO 2 volumetric payments is based on the units-of-production method.  We acquired three volumetric production payments totaling 280 Mcf of CO 2 from Denbury between 2003 and 2005.  Amortization is based on volumes sold in relation to the volumes acquired.  In each annual period, the volume of CO 2 sold has increased.
 
In 2007 and 2006, our natural gas pipeline activities were impacted by production difficulties of a producer attached to the system.  Due to declines we experienced in the results from our natural gas pipelines, we reviewed these assets in 2007 to determine if the fair market value of the assets exceeded the net book value of the assets.  As a result of this review, we recorded an impairment loss of $1.5 million related to these assets.


Interest expense, net was as follows :
 
   
Year Ended December 31,
 
   
2008
   
2007
   
2006
 
   
(in thousands)
 
Interest expense, including commitment fees, excluding DG Marine
  $ 10,738     $ 10,103     $ 781  
Amortization of facility fees, excluding DG Marine facility
    664       441       300  
Interest expense and commitment fees - DG Marine
    2,269       -       -  
Capitalized interest
    (276 )     (59 )     (9 )
Write-off of facility fees and other fees
    -       -       500  
Interest income
    (458 )     (385 )     (198 )
Net interest expense
  $ 12,937     $ 10,100     $ 1,374  
 
Our average outstanding debt balance, excluding the DG Marine credit facility, increased $107.0 million to $225 million in 2008 over the average outstanding debt balance in 2007, primarily due to the Davison acquisition in July 2007 and the CO 2 pipeline dropdown transactions in May 2008.  The average interest rate on our debt, however, was 3.52% lower during 2008, partially offsetting the effects of the higher debt balance, resulting in an overall increase for the year for interest and commitment fees on our credit facility of $0.6 million, and an average interest rate of 4.26%.
 
DG Marine incurred interest expense in 2008 of $2.3 million under its credit facility.   Additionally DG Marine recorded accretion of the discount on the payments to Grifco related upon successful launch of the barges under construction.  (See Note 3 to the Consolidated Financial Statements.)  The net effect of these changes was an increase in net interest expense between the 2008 and 2007 of $2.8 million.
 
Net interest expense increased $8.7 million from 2006 to 2007.  This increase in interest resulted form the borrowings in July 2007 to fund the Davison acquisition, with a reduction in debt in December 2007 from the proceeds from an equity offering. Our average outstanding balance of debt was $118.5 million during 2007, an increase of $115.1 million over 2006. Our average interest rate during 2007 was 7.78%, a decrease of 0.64% from 2006.  As a result of the termination of our prior credit facility to enter into the new facility we obtained in November 2006, we wrote-off $0.5 million of deferred facility fees related to the prior credit facility in 2006.
 
Income taxes .  A portion of the operations we acquired in the Davison transaction are owned by wholly-owned corporate subsidiaries that are taxable as corporations.  As a result, a substantial portion of the income tax expense we record relates to the operations of those corporations, and will vary from period to period as a percentage of our income before taxes based on the percentage of our income or loss that is derived from those corporations.  The balance of the income taxes expense we record relates to state taxes imposed on our operations that are treated as income taxes under generally accepted accounting principles.  In 2008 and 2007, we recorded an income tax benefit totaling $0.4 million and $0.7 million, respectively.   The current income taxes we expect to pay for 2008 are approximately $2.4 million, and we provided a deferred tax benefit of $4.2 million related to temporary differences between the relevant basis of our assets and liabilities for financial reporting and tax purposes.
 
Liquidity and Capital Resources
 
Capital Resources/Sources of Cash
 
The current economic crisis has restricted the availability of credit and access to capital in our business environment.  Despite efforts by treasury and banking regulators to provide liquidity to the financial sector, capital markets continue to remain constrained.  While we anticipate that the challenging economic environment will continue for the foreseeable future, we believe that our current cash balances, future internally-generated funds and funds available under our credit facility will provide sufficient resources to meet our current working capital liquidity needs.  The cash flow generated by our existing businesses, the $19.0 million in cash on hand, our existing debt commitments, and the absence of any need to access the capital markets, may allow us to take advantage of acquisition and/or growth opportunities that may develop.
 
Long-term, we continue to pursue a growth strategy that requires significant capital.  We expect our long-term capital resources to include equity and debt offerings (public and private) and other financing transactions, in addition to cash generated from our operations. Accordingly, we expect to access the capital markets (equity and debt) from time to time to partially refinance our capital structure and to fund other needs including acquisitions and ongoing working capital needs.  Our ability to satisfy future capital needs will depend on our ability to raise substantial amounts of additional capital, to utilize our current credit facility and to implement our growth strategy successfully. No assurance can be made that we will be able to raise the necessary funds on satisfactory terms.  If we are unable to raise the necessary funds, we may be required to defer our growth plans until such time as funds become available.


As of December 31, 2008, we had $320 million of loans and $3.5 million in letters of credit outstanding under our $500 million credit facility, resulting in $176.5 million of remaining credit, all of which was available under our borrowing base. Our borrowing base fluctuates each quarter based on our earnings before interest, taxes, depreciation and amortization, or EBITDA. Our borrowing base may be increased to the extent of EBITDA attributable to acquisitions, with approval of the lenders.
 
The terms of our credit facility also effectively limit the amount of distributions that we may pay to our general partner and holders of common units.  Such distributions may not exceed the sum of the distributable cash generated for the eight most recent quarters, less the sum of the distributions made with respect to those quarters. See Note 10 of the Notes to the Consolidated Financial Statements for additional information on our credit facility.
 
As of December 31, 2008, DG Marine had $55.3 million of loans outstanding under its $90 million credit facility.  DG Marine will utilize this facility to fund its acquisition of additional barges and a push boat in the first half of 2009.
 
Uses of Cash
 
Our cash requirements include funding day-to-day operations, maintenance and expansion capital projects, debt service, and distributions on our common units and other equity interests.  We expect to use cash flows from operating activities to fund cash distributions and maintenance capital expenditures needed to sustain existing operations.  Future expansion capital – acquisitions or capital projects – will require funding through various financing arrangements, as more particularly described under “Liquidity and Capital Resources – Capital Resources/Sources of Cash” above.
 
Cash Flows from Operations. We utilize the cash flows we generate from our operations to fund our working capital needs.  Excess funds that are generated are used to repay borrowings from our credit facilities and to fund capital expenditures.  Our operating cash flows can be impacted by changes in items of working capital, primarily variances in the timing of payment of accounts payable and accrued liabilities related to capital expenditures.
 
Debt and Other Financing Activities.   Our sources of cash are primarily from operations and our credit facilities.  Our net borrowings under our credit facility and the DG Marine credit facility totaled $295.3 million.  These borrowings related to the CO 2 pipeline drop-down transactions in May 2008 and the acquisition by DG Marine of the Grifco assets in July 2008.  Our joint venture partner in DG Marine (members of the Davison family) also contributed $25.5 million for its 51% interest and we redeemed $16.7 million of common units from those members of the Davison family at the time of the Grifco acquisition.  In connection with our issuance of 1,199,041 common units to Denbury for a portion of the consideration in the drop-down transactions, our general partner contributed $0.5 million as required under our partnership agreement to maintain its two percent general partner capital account balance.
 
We paid distributions totaling $50.5 million to our limited partners and our general partner during 2008.  See the details of distributions paid in “Distributions” below.  DG Marine paid credit facility fees of $2.3 million in 2008.
 
Investing .  We utilized cash flows to make acquisitions and for capital expenditures.  The most significant investing activities in 2008 were the CO 2 pipeline drop-down transactions in May 2008 for which we expended $225 million in cash as consideration (along with the issuance of $25 million of our common units) and the acquisition of the inland marine transportation assets of Grifco in July 2008.  We paid Grifco $66.0 million in cash consideration at closing of the transaction (along with the issuance of $16.7 million of our common units and an agreement to pay an additional $12.0 million consideration, with one-half payable in December 2008 and the remainder in December 2009).  On December 31, 2008 we expended $6.0 million for the first payment of the deferred consideration.  We also expended approximately $16.0 million for additional barges and push boats.  Additional information on our capital expenditures and business acquisitions is provided below.


Capital Expenditures, and Business and Asset Acquisitions
 
A summary of our expenditures for fixed assets, businesses and other asset acquisitions in the three years ended December 31, 2008, 2007, and 2006 is as follows:
 
   
Years Ended December 31,
 
   
2008
   
2007
   
2006
 
   
(in thousands)
 
Capital expenditures for business combinations and asset purchases:
                 
DG Marine acquisition
  $ 94,072     $ -     $ -  
Free State Pipeline acquisition, including transaction costs
    76,193       -       -  
NEJD Pipeline transaction, including transaction costs
    177,699       -       -  
Davison acquisition
    -       631,476       -  
Port Hudson acquisition
    -       8,103       -  
Total
    347,964       639,579       -  
                         
Capital expenditures for property, plant and equipment:
                       
Maintenance capital expenditures:
                       
Pipeline transportation assets
    719       2,880       611  
Supply and logistics assets
    729       440       175  
Refinery services assets
    1,881       469       -  
Administrative and other assets
    1,125       51       181  
Total maintenance capital expenditures
    4,454       3,840       967  
                         
Growth capital expenditures:
                       
Pipeline transportation assets
    7,589       3,712       360  
Supply and logistics assets
    22,659       650       -  
Refinery services assets
    3,609       979       -  
Total growth capital expenditures
    33,857       5,341       360  
Total
    38,311       9,181       1,327  
                         
Capital expenditures attributable to unconsolidated affiliates:
                       
Sandhill investment
    -       -       5,042  
Faustina project
    2,397       1,104       1,016  
Total
    2,397       1,104       6,058  
Total capital expenditures
  $ 388,672     $ 649,864     $ 7,385  
 
During 2009, we expect to expend approximately $12.7 million for maintenance capital projects in progress or planned.  Those expenditures are expected to include approximately $1.9 million of improvements in our refinery services business, $2.6 million in our crude oil pipeline operations, including $2.0 million for rehabilitation of a segment of the Mississippi System as a result of IMP testing, $3.6 million related to integration and upgrades of our information technology systems, $2.7 related to improvements at our terminals and the remainder on projects related to our truck transportation operations, including $1.7 for replacement vehicles.  In future years we expect to spend $4 million to $5 million per year on vehicle replacements.
 
We will also complete construction of an expansion of our existing Jay System that will extend the pipeline to producers operating in southern Alabama.  That expansion will consist of approximately 33 miles of pipeline and gathering connections to approximately 35 wells and will include storage capacity of 20,000 barrels.  We expect to spend a total of approximately $4.1 million in 2009 to complete this project, including the acquisitions of crude oil linefill.
 
DG Marine is expected to expend approximately $14.6 million in 2009 for four new barges and one additional push boat.  Upon receipt of these vessels, DG Marine will have twenty barges and ten push boats.  DG Marine’s capital expenditures are funded through its credit facility.
 
Expenditures for capital assets to grow the partnership distribution will depend on our access to debt and equity capital discussed above in “ Capital Resources -- Sources of Cash .”  We will look for opportunities to acquire assets from other parties that meet our criteria for stable cash flows.  The arrangement that Denbury has made with our new senior executive management team provide incentives to them to increase the available cash for our common unitholders.  See “Item 11. Executive Compensation” for a description of these arrangements.


Distributions
 
Our partnership agreement requires us 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 have increased our distribution for each of the last fourteen quarters, including the distribution paid for the fourth quarter of 2008, as shown in the table below (in thousands, except per unit amounts).  Each quarter, the Board of Directors of our general partner determines the distribution amount per unit based upon various factors such as our operating performance, available cash, future cash requirements and the economic environment.  As a result, the historical trend of distribution increases may not be a good indicator of future increases.
 
                         
General
       
             
Limited
   
General
   
Partner
       
             
Partner
   
Partner
   
Incentive
       
       
Per Unit
   
Interests
   
Interest
   
Distribution
   
Total
 
Distribution For
 
Date Paid
 
Amount
   
Amount
   
Amount
   
Amount
   
Amount
 
                 
Fourth quarter 2006
 
February 2007
  $ 0.2100     $ 2,895     $ 59     $ -     $ 2,954  
First quarter 2007
 
May 2007
  $ 0.2200     $ 3,032     $ 62     $ -     $ 3,094  
Second quarter 2007
 
August 2007
  $ 0.2300     $ 3,170 (1)   $ 65     $ -     $ 3,235 (1)
Third quarter 2007
 
November 2007
  $ 0.2700     $ 7,646     $ 156     $ 90     $ 7,892  
Fourth quarter 2007
 
February 2008
  $ 0.2850     $ 10,902     $ 222     $ 245     $ 11,369  
First quarter 2008
 
May 2008
  $ 0.3000     $ 11,476     $ 234     $ 429     $ 12,139  
Second quarter 2008
 
August 2008
  $ 0.3150     $ 12,427     $ 254     $ 633     $ 13,314  
Third quarter 2008
 
November 2008
  $ 0.3225     $ 12,723     $ 260     $ 728     $ 13,711  
Fourth quarter 2008
 
February 2009 (2)
  $ 0.3300     $ 13,021     $ 266     $ 823     $ 14,110  

 
(1)  The distribution paid on August 14, 2007 to holders of our common units is net of the amounts payable with respect to the common units issued in connection with the Davison transaction.  The Davison unitholders and our general partner waived their rights to receive such distributions, instead receiving purchase price adjustments with us.
 
(2)  This distribution was paid on February 13, 2009 to our general partner and unitholders of record as of February 3, 2009.
 
Our credit facility also includes a restriction on the amount of distributions we can pay in any quarter.  At December 31, 2008, our restricted net assets (as defined in Rule 4-03 (e)(3) of Regulation S-X) were $573.6 million.
 
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 to our common unitholders in excess of $0.25 per unit, 23.5% of any distributions to our common unitholders in excess of $0.28 per unit, and 49% of any distributions to our common unitholders 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 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.
 
Non-GAAP Reconciliation
 
This annual report includes the financial measure of Available Cash before Reserves, which is a “non-GAAP” measure because it is not contemplated by or referenced in accounting principles generally accepted in the U.S., also referred to as GAAP.  The accompanying schedule provides a reconciliation of this non-GAAP financial measure to its most directly comparable GAAP financial measure.  Our non-GAAP financial measure should not be considered as an alternative 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 before Reserves, also referred to as distributable 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 before Reserves excludes some, but not all, items that affect net income or loss and because these measures may vary among other companies, the Available Cash before Reserves 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 before Reserves is net cash provided by operating activities.
 
Available Cash before Reserves 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 before Reserves (a non-GAAP liquidity measure) to cash flow from operating activities (the GAAP measure) for the year ended December 31, 2008, is as follows (in thousands):
 
   
Year Ended
 
   
December 31, 2008
 
Cash flows from operating activities
  $ 94,808  
Adjustments to reconcile operating cash flows to Available Cash:
       
Maintenance capital expenditures
    (4,454 )
Proceeds from sales of certain assets
    760  
Amortization of credit facility issuance fees
    (1,437 )
Effects of available cash generated by equity method investees not included in cash flows from operating activities
    1,067  
Available cash from NEJD pipeline not yet received and included in cash flows from operating activities
    1,723  
Earnings of DG Marine in excess of distributable cash
    (2,821 )
Other items affecting available cash
    (1,124 )
Net effect of changes in operating accounts not included in calculation of Available Cash
    1,262  
Available Cash before Reserves
  $ 89,784  

 
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 and petroleum products.  The table below summarizes our obligations and commitments at December 31, 2008.
 
   
Payments Due by Period
 
Commercial Cash Obligations and Commitments
 
Less than one year
   
1 - 3 years
   
3 - 5 Years
   
More than 5 years
   
Total
 
                               
Contractual Obligations:
                             
Long-term debt (1)
  $ -     $ 375,300     $ -     $ -     $ 375,300  
Estimated interest payable on long-term debt (2)
    14,428       27,487       -       -       41,915  
Operating lease obligations
    5,324       7,961       4,417       11,067       28,769  
Capital expansion projects (3)
    14,713       -       -       -       14,713  
Unconditional purchase obligations (4)
    57,975       -       -       -       57,975  
Remaining purchase obligation to Grifco (5)
    6,000       -       -       -       6,000  
                                         
Other Cash Commitments:
                                       
Asset retirement obligations   (6)
    150       -       -       4,438       4,588  
FIN 48 tax liabilities (7)
    -       -       2,599       -       2,599  
Total
  $ 98,590     $ 410,748     $ 7,016     $ 15,505     $ 531,859  
 
(1)
Our credit facility allows us to repay and re-borrow funds at any time through the maturity date of November 15, 2011.  The DG Marine credit facility allows it to repay and re-borrow funds at any time through the maturity date of July 18, 2011.
(2)
Interest on our long-term debt is at market-based rates. The amount shown for interest payments represents the amount that would be paid if the debt outstanding at December 31, 2008 remained outstanding through the final maturity dates of July 18, 2011 and November 15, 2011 and interest rates remained at the December 31, 2008 market levels through the final maturity dates.
(3)
We expect to complete the expansion of our Jay System in the first quarter of 2009.  We also have signed commitments to purchase four newly-constructed barges.  See “Capital Expenditures and Business Acquisitions” under “Liquidity and Capital Resources – Uses of Cash” above.
(4)
Unconditional purchase obligations include agreements to purchase goods and services that are enforceable and legally binding and specify all significant terms.  Contracts to purchase crude oil and petroleum products are generally at market-based prices.  For purposes of this table, estimated volumes and market prices at December 31, 2008, were used to value those obligations.  The actual physical volumes and settlement prices may vary from the assumptions used in the table.  Uncertainties involved in these estimates include levels of production at the wellhead, changes in market prices and other conditions beyond our control.
(5)
DG Marine will pay Grifco $6 million after delivery of four new barges and boats.  See Note 3 to the Consolidated Financial Statements.
(6)
Represents the estimated future asset retirement obligations on an undiscounted basis.  The present discounted asset retirement obligation is $1.4 million, as determined under FIN 47 and SFAS 143, and is further discussed in Note 5 to the Consolidated Financial Statements.
(7)
The estimated FIN 48 tax liabilities will be settled as a result of expiring statutes or audit activity. The timing of any particular settlement will depend on the length of the tax audit and related appeals process, if any, or an expiration of statute. If a liability is settled due to a statute expiring or a favorable audit result, the settlement of the FIN 48 tax liability would not result in a cash payment.

We have guaranteed 50% of the $3.0 million debt obligation to a bank of Sandhill; however, we believe we are not likely to be required to perform under this guarantee as Sandhill is expected to make all required payments under the debt obligation.
 
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.
 
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. We base these estimates and assumptions on historical experience and other information that are believed to be reasonable under the circumstances.  Estimates and assumptions about future events and their effects cannot be perceived with certainty, and, accordingly, these estimates may change as new events occur, as more experience is acquired, as additional information is obtained and as the business environment in which we operate changes.  Significant accounting policies that we employ are presented in the notes to the consolidated financial statements (See Note 2 Summary of Significant Accounting Policies.)


We have defined critical accounting policies and estimates as 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 measurement of the fair value of assets and liabilities in business acquisitions, depreciation, amortization and impairment of long-lived assets, asset retirement obligations, equity plan compensation accruals and contingent and environmental liabilities.  We discuss these policies below.
 
Fair Value of Assets and Liabilities Acquired and Identification of Associated Goodwill and Intangible Assets.  
 
In conjunction with each acquisition we make, we must allocate the cost of the acquired entity to the assets and liabilities assumed based on their estimated fair values at the date of acquisition. As additional information becomes available, we may adjust the original estimates within a short time period subsequent to the acquisition. In addition, we are required to recognize intangible assets separately from goodwill. Determining the fair value of assets and liabilities acquired, as well as intangible assets that relate to such items as customer relationships, contracts, trade names, and non-competes involves professional judgment and is ultimately based on acquisition models and management’s assessment of the value of the assets acquired, and to the extent available, third party assessments. Uncertainties associated with these estimates include fluctuations in economic obsolescence factors in the area and potential future sources of cash flow.  We cannot provide assurance that actual amounts will not vary significantly from estimated amounts.   In connection with the Grifco acquisition in 2008 and the Davison and Port Hudson acquisitions in 2007, we performed allocations of the purchase price.  See Note 3 of the Notes to the Consolidated Financial Statements.
 
Depreciation and Amortization of Long-Lived Assets and Intangibles
 
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 compute depreciation using the straight-line method based on these estimated useful lives. The actual period over which we will use the asset may differ from the assumptions we have made about the estimated useful life.  We adjust the remaining useful life as we become aware of such circumstances.
 
Intangible assets with finite useful lives are required to be amortized over their respective estimated useful lives.  If an intangible asset has a finite useful life, but the precise length of that life is not known, that intangible asset shall be amortized over the best estimate of its useful life.  At a minimum, we will assess the useful lives and residual values of all intangible assets on an annual basis to determine if adjustments are required.   We are recording amortization of our customer and supplier relationships, licensing agreements and trade names based on the period over which the asset is expected to contribute to our future cash flows.  Generally, the contribution of these assets to our cash flows is expected to decline over time, such that greater value is attributable to the periods shortly after the acquisition was made.  Our favorable lease and other intangible assets are being amortized on a straight-line basis over their expected useful lives.
 
Impairment of Long-Lived Assets including Intangibles and Goodwill
 
When events or changes in circumstances indicate that the carrying amount of a fixed asset or intangible 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.  If we determine that an asset’s unamortized cost may not be recoverable due to impairment; we may be required to reduce the carrying value and the subsequent useful life of the asset. Any such write-down of the value and unfavorable change in the useful life of an intangible asset would increase costs and expenses at that time.
 
Goodwill represents the excess of the purchase prices we paid for certain businesses over their respective fair values and is primarily associated with the Davison acquisition in 2007. We do not amortize goodwill; however, we test our goodwill (at the reporting unit level) for impairment during the fourth quarter of each fiscal year, and more frequently, if circumstances indicate it is more likely than not that the fair value of goodwill is below its carrying amount. Our goodwill testing involves the determination of a reporting unit’s fair value, which is predicated on our assumptions regarding the future economic prospects of the reporting unit. Such assumptions include (i) discrete financial forecasts for the assets contained within the reporting unit, which rely on management’s estimates of operating margins, (ii) long-term growth rates for cash flows beyond the discrete forecast period, (iii) appropriate discount rates and (iv) estimates of the cash flow multiples to apply in estimating the market value of our reporting units. If the fair value of the reporting unit (including its inherent goodwill) is less than its carrying value, a charge to earnings is required to reduce the carrying value of goodwill to its implied fair value. At December 31, 2008, the carrying value of our goodwill was $325.0 million. We did not record any goodwill impairment charges during 2008.


Due to the recent disruptions in the credit markets and macroeconomic conditions, we will continue to monitor the market to determine if a triggering event occurs that would indicate that the fair value of a reporting unit is less than its carrying value.  If we determine that a triggering event has occurred, we will perform an interim goodwill impairment analysis.
 
For additional information regarding our goodwill, see Notes 3 and 9 of the Notes to Consolidated Financial Statements.
 
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 and to decommission barges when we take them out of service.  We estimate the future costs of these obligations, discount those costs to their present values, and record a corresponding asset and liability in our Consolidated Balance Sheets.  The values ultimately derived are based on many significant estimates, including the ultimate expected cost of the obligation, the expected future date of the required cash payment, and interest and inflation rates. Revisions to these estimates may be required based on changes to cost estimates, the timing of settlement, and changes in legal requirements. Any such changes that result in upward or downward revisions in the estimated obligation will result in an adjustment to the related capitalized asset and corresponding liability on a prospective basis and an adjustment in our depreciation expense in future periods. See Note 5 to our Consolidated Financial Statements for further discussion regarding our asset retirement obligations.
 
Equity Compensation Plan Accruals
 
We accrue for the fair value of our liability for the stock appreciation rights (“SAR”) awards we have issued to our employees and directors under the provisions of SFAS No. 123(R), Share-Based Payments, as amended and interpreted.  Under our SAR plan, grantees receive cash for the difference between the market value of our common units and the strike price of the award at the time of exercise.  We estimate the fair value of SAR awards at each balance sheet date using the Black-Scholes option pricing model. The Black-Scholes valuation model requires the input of somewhat subjective assumptions, including expected stock price volatility and expected term. Other assumptions required for estimating fair value with the Black-Scholes model are the expected risk-free interest rate and our expected distribution yield. The risk-free interest rates used are the U.S. Treasury yield for bonds matching the expected term of the option on the date of grant. Our SAR plan was instituted December 31, 2003, so we have very limited experience from which to determine the expected term of the awards.  As a result, we use the simplified method allowed by the Securities and Exchange Commission to determine the expected life, which results in an expected life of 6 to 7 years at the time an award it granted.
 
We recognize the stock-based compensation expense on a straight-line basis over the requisite service period for the awards. The expense we recognize is net of estimated forfeitures. We estimate our forfeiture rate at each balance sheet date based on prior experience. As of December 31, 2008, there was $0.2 million of total compensation cost to be recognized in future periods related to non-vested SARs. The cost is expected to be recognized over a weighted-average period of less than one year.  We also record compensation cost for changes in the estimated liability for vested SARs.  The liability recorded for vested SARs fluctuates with the market price of our common units.  See Note 15 to our Consolidated Financial Statements for further discussion regarding our SAR plan.
 
For phantom unit awards granted under our 2007 Long-Term Incentive Plan, the total compensation expense recognized over the service period is determined by the grant date fair value of our common units that become earned.  Uncertainties involved in the estimate of the compensation cost we record for our phantom units relate to the assumptions regarding the continued employment of personnel who have been awarded phantom units.


On December 31, 2008, our general partner completed compensation arrangements with our senior executive team.  See Item 11 – Executive Compensation  - The Class B Membership Interest in our General Partner.  The Class B Membership Interests awarded to our senior executives will be accounted for as liability awards under the provisions of SFAS 123(R).  As such, the fair value of the compensation cost we record for these awards will be recomputed at each measurement date and the expense to be recorded will be adjusted based on that fair value.  Management’s estimates of the fair value of these awards are based on assumptions regarding a number of future events, including estimates of the Available Cash before Reserves we will generate each quarter through the final vesting date of December 31, 2012, estimates of the future amount of incentive distributions we will pay to our general partner, and assumptions about appropriate discount rates.    Additionally the determination of fair value will be affected by the distribution yield of ten publicly-traded entities that are the general partners in publicly-traded master limited partnerships, a factor over which we have no control.  Included within the assumptions used to prepare these estimates are projections of available cash and distributions to our common unitholders and general partner, including an assumed level of growth and the effects of future new growth projects during the four-year vesting period.  At December 31, 2008, management estimates that the fair value of the Class B Membership Awards and the related deferred compensation awards granted to our Senior Executives on that date is approximately $12 million.  The fair value of these incentive awards will be recomputed each quarter beginning with the quarter ending March 31, 2009 through the final settlement of the awards.   Compensation expense of $3.4 million was recorded in the fourth quarter of 2007 related to the previous arrangements between our general partner and our Senior Executives. The fair value to be recorded by us as compensation expense will be the excess of the recomputed estimated fair value over the previously recorded compensation expense of $3.4 million.  Due to the vesting conditions for the awards, the amount to which the Senior Executives were entitled on December 31, 2008 for the Class B Membership Awards and the related deferred compensation was zero.  Management’s estimates of fair value are made in order to record non-cash compensation expense over the vesting period, and do not necessarily represent the contractual amounts payable under these awards at December 31, 2008. This expense will be recorded on an accelerated basis to align with the requisite service period of the award.  Changes in our assumptions will change the amount of compensation cost we record.  Changes in these assumptions would not, however, affect our Available Cash before Reserves, as the cash cost of the Class B Membership Interests will be borne by Denbury.
 
  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.
 
At December 31, 2008, we are not aware of any contingencies or liabilities that will have a material effect on our financial position, results of operations, or cash flows.
 
Recent Accounting Pronouncements .
 
SFAS 141(R)
 
In December 2007, the FASB issued SFAS No. 141(R) “Business Combinations” (SFAS 141(R)).  SFAS 141(R) replaces FASB Statement No. 141, “Business Combinations.”  This statement retains the purchase method of accounting used in business combinations but replaces SFAS 141 by establishing principles and requirements for the recognition and measurement of assets, liabilities and goodwill, including the requirement that most transaction costs and restructuring costs be charged to expense as incurred.  In addition, the statement requires disclosures to enable users of the financial statements to evaluate the nature and financial effects of the business combination.  SFAS 141(R) is effective for business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008.  We adopted SFAS 141(R) on January 1, 2009.  Adoption will impact our accounting for acquisitions we complete subsequent to that date.


SFAS 160
 
In December 2007, the FASB issued SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements - an amendment of ARB No. 51” (SFAS 160). This statement establishes accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary in an effort to improve the relevance, comparability and transparency of the financial information that a reporting entity provides in its consolidated financial statements.  SFAS 160 is effective for fiscal years beginning after December 15, 2008.  We adopted SFAS 160 on January 1, 2009.  We are assessing the impact of this statement on our financial statements, but expect it to impact the presentation of the non-controlling interest in our operating partnership.
 
SFAS 161
 
 In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities-an amendment of FASB Statement No.133” (SFAS 161). This Statement requires enhanced disclosures about (i) how and why an entity uses derivative instruments, (ii) how derivative instruments and related hedged items are accounted for under SFAS 133, and its related interpretations, and (iii) how derivative instruments and related hedged items affect an entity’s financial position, financial performance and cash flows. This statement is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008. We adopted SFAS No. 161 on January 1, 2009. Adoption did not have any material impact on our financial position, results of operations or cash flows.
 
EITF 07-4
 
In March 2008, the Emerging Issues Task Force (or EITF) of the FASB issued EITF 07-4, “Application of the Two-Class Method under FASB Statement No. 128, Earnings per Share , to Master Limited Partnerships” (EITF 07-4).  EITF 07-4 addresses the application of the two-class method under SFAS No. 128 “Earnings Per Share” in determining income per unit for master limited partnerships having multiple classes of securities that may participate in partnership distributions.  To the extent the partnership agreement does not explicitly limit distributions to the general partner, any earnings in excess of distributions are to be allocated to the general partner and limited partners utilizing the distribution formula for available cash specified in the partnership agreement.  When current period distributions are in excess of earnings, the excess distributions are to be allocated to the general partner and limited partners based on their respective sharing of losses specified in the partnership agreement for the period.  EITF 07-4 is to be applied retrospectively for all financial statements presented and is effective for financial statements issued for fiscal years beginning after December 15, 2008, and interim periods within those fiscal years.  Earlier application is not permitted.  We adopted EITF 07-04 on January 1, 2009.  Adoption will impact the net income available to limited partners used in our computation of earnings per unit, but will not impact our distributions to limited partners, financial position, results of operations, or cash flows.   For additional information on our incentive distribution rights, see Note 11 to the Consolidated Financial Statements.
 
FASB Staff Position No. 142-3
 
In April 2008, the FASB issued FASB Staff Position No. 142-3, “Determination of the Useful Life of Intangible Assets” (FSP 142-3).  This FSP amends the factors that should be considered in developing renewal or extension assumptions used to determine the useful life of an intangible asset under Statement of Financial Accounting Standards No. 142, “Goodwill and other Intangible Assets.” The purpose of this FSP is to develop consistency between the useful life assigned to intangible assets and the cash flows from those assets.  FSP 142-3 is effective for fiscal years beginning after December 31, 2008.  We are currently evaluating the impact, if any, that the standard will have on our consolidated financial statements.
 
Item 7a.  Quantitative and Qualitative Dis closu res About Market Risk
 
We are exposed to various market risks, primarily related to volatility in crude oil and petroleum products prices, NaHS and NaOH prices, and interest rates. Our policy is to purchase only commodity products for which we have a market, and to structure our sales contracts so that price fluctuations for those products do not materially affect the segment margin we receive.  We do not acquire and hold futures contracts or other derivative products for the purpose of speculating on price changes.
 
Our primary price risk relates to the effect of crude oil and petroleum products price fluctuations on our inventories and the fluctuations each month in grade and location differentials and their effect on future contractual commitments.  Our risk management policies are designed to monitor our physical volumes, grades, and delivery schedules to ensure our hedging activities address the market risks that are inherent in our gathering and marketing activities.


We utilize NYMEX commodity based futures contracts and option contracts to hedge our exposure to these market price fluctuations as needed.  All of our open commodity price risk derivatives at December 31, 2008 were categorized as non-trading. On December 31, 2008, we had entered into NYMEX future contracts that will settle between February 2009 and August 2009 and NYMEX options contracts that will settle during February and March 2009.  Although the intent of our risk-management activities is to hedge our margin, none of our derivative positions at December 31, 2008 qualified for hedge accounting.  This accounting treatment is discussed further under Note 17 to our Consolidated Financial Statements.
 
The table below presents information about our open derivative contracts at December 31, 2008.  Notional amounts in barrels, the weighted average contract price, total contract amount and total fair value amount in U.S. dollars of our open positions are presented below.  Fair values were determined by using the notional amount in barrels multiplied by the December 31, 2008 quoted market prices on the NYMEX.  All of the hedge positions offset physical exposures to the cash market; none of these offsetting physical exposures are included in the table below.
 


 
   
Sell (Short)
   
Buy (Long)
 
   
Contracts
   
Contracts
 
             
Futures Contracts:
           
             
Crude Oil:
           
Contract volumes (1,000 bbls)
    146       107  
Weighted average price per bbl
  $ 53.25     $ 47.94  
                 
Contract value (in thousands)
  $ 7,774       5,129  
Mark-to-market change (in thousands)
    (169 )     (357 )
Market settlement value (in thousands)
  $ 7,605     $ 4,772  
                 
                 
Heating Oil:
               
Contract volumes (1,000 bbls)
    35       -  
Weighted average price per gal
  $ 1.43     $ -  
                 
Contract value (in thousands)
  $ 2,099       -  
Mark-to-market change (in thousands)
    21       -  
Market settlement value (in thousands)
  $ 2,120     $ -  
                 
Natural Gas:
               
Contract volumes (10,000 mmBtus)
            5  
Weighted average price per mmBtu
  $ -     $ 6.09  
                 
Contract value (in thousands)
  $ -       304  
Mark-to-market change (in thousands)
    -       (23 )
Market settlement value (in thousands)
  $ -     $ 281  
                 
                 
NYMEX Option Contracts:
               
                 
Crude Oil- Written/Purchased Calls
               
Contract volumes (1,000 bbls)
    90       6  
Weighted average premium received/paid
  $ 2.23     $ 0.10  
                 
Contract value (in thousands)
  $ 200     $ 1  
Mark-to-market change (in thousands)
    11       1  
Market settlement value (in thousands)
  $ 211     $ 2  
                 
Natural Gas-Written Calls
               
Contract volumes (10,000 mmBtus)
    10          
Weighted average premium received
  $ 0.33          
                 
Contract value (in thousands)
  $ 33          
Mark-to-market change (in thousands)
    (10 )        
Market settlement value (in thousands)
  $ 23          

 
We manage our risks of volatility in NaOH prices by indexing prices for the sale of NaHS to the market price for NaOH in most of our contracts.
 
We are also exposed to market risks due to the floating interest rates on our credit facility and the DG Marine credit facility.  Our debt bears interest at the LIBOR Rate or Prime Rate, at our option, plus the applicable margin.  We have not, historically hedged our interest rates.  On December 31, 2008, we had $320.0 million of debt outstanding under our credit facility and $55.3 million outstanding under the DG Marine credit facility.  DG Marine hedged a portion of its debt through July 2011.


Item 8.  Fin anc ial 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 97.
 
Item 9.  Changes in and Disa greem ents with Accountants on Accounting and Financial Disclosure
 
None.
 
Item 9A.  Controls and Pro cedu res
 
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 effective in providing  assurance of the timely recording, processing, summarizing and reporting of information, and in accumulation and communication to management 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 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.  Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
 
Management assessed the effectiveness of the Partnership’s internal control over financial reporting as of December 31, 2008.  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, 2008, the Partnership’s internal control over financial reporting is effective based on those criteria.
 
Pursuant to Section 404 of the Sarbanes-Oxley Act of 2002, our management included a report of their assessment of the design and effectiveness of our internal controls over financial reporting as part of this Annual Report on Form 10-K for the fiscal year ended December 31, 2008. Deloitte & Touche LLP, the Company’s independent registered public accounting firm, has issued an attestation report on the effectiveness of the Company’s internal control over financial reporting. Deloitte & Touche’s attestation report on 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, LLC and Unitholders of
Genesis Energy, L.P.
Houston, Texas
 
We have audited the internal control over financial reporting of Genesis Energy, L.P. and subsidiaries (the "Partnership") as of December 31, 2008, 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, included in the accompanying Management’s Report on Internal Control over Financial Reporting.  Our responsibility is to express an opinion on 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, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances.  We believe that our audit provides a reasonable basis for our opinion.
 
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, the Partnership maintained, in all material respects, effective internal control over financial reporting as of December 31, 2008, 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 and financial statement schedule as of and for the year ended December 31, 2008 of the Partnership and our report dated March 11, 2009 expressed an unqualified opinion on those financial statements and financial statement schedule and included an explanatory paragraph regarding the Partnership's adoption of new accounting standards.
 
 
/s/ Deloitte & Touche LLP
DELOITTE & TOUCHE LLP
 
Houston, Texas
March 11, 2009


Item 9B.  Other In form ation
 
None.
 
Part III
 
Item 10.  Directors, Executive Officer s and Corporate Governance
 
Management of Genesis Energy, L.P.
 
Our general partner manages our operations and activities. Our general partner is not elected by our unitholders and will not be subject to re-election on a regular basis in the future. Unitholders are not entitled to elect the directors of our general partner or directly or indirectly participate in our management or operation. However, in connection with the Davison acquisition, our general partner has agreed to let the Davison family designate two directors through July 27, 2010 and, subsequent to that date, one director so long as it holds at least 10% of our common units.  Our general partner owes a fiduciary duty to our unitholders, but our partnership agreement contains various provisions modifying and restricting the fiduciary duty. Our general partner is liable, as general partner, for all of our debts (to the extent not paid from our assets), except for indebtedness or other obligations that are made expressly nonrecourse to it. Our general partner therefore may cause us to incur indebtedness or other obligations that are nonrecourse to it.
 
The directors of our general partner oversee our operations. As of February 28, 2009 our general partner has eleven directors. Denbury, indirectly, elects all members to the board of directors of our general partner other than the Davison appointee.  Currently nine members of the board of directors, which we refer to as our Board, were selected by Denbury and two were selected by the Davisons.  The independence standards established by the NYSE Alternext US (formerly the American Stock Exchange) require us to have at least three independent directors on the Board.  NYSE Alternext US does not require a listed limited partnership like us to have a majority of independent directors on the Board of our general partner or to establish a compensation committee or a nominating committee.   Although we currently have a compensation committee, it does not satisfy the independence standards established by NYSE Alternext US, and we are not required to maintain a compensation committee in the future.
 
 The compensation committee of our general partner oversees compensation decisions for the employees of our general partner, as well as the compensation plans of our general partner.  The members of the Compensation Committee are Gareth Roberts and Susan O. Rheney, both of whom are non-employee directors of our general partner.  The Compensation Committee adopted a written Compensation Committee charter that is available on our website.
 
In addition, our general partner has an audit committee composed of directors who meet the independence and experience standards established by NYSE Alternext US and the Securities Exchange Act of 1934, as amended.  Susan O. Rheney, David C. Baggett and Martin G. White serve as the members of the audit committee.  The audit committee assists the board in its oversight of the quality and integrity of our financial statements and our compliance with legal and regulatory requirements and partnership policies and controls. The audit committee has the following responsibilities:
 
 
·
has the sole authority to retain and terminate our independent registered public accounting firm, approve all auditing services and related fees and the terms thereof, and pre-approve any non-audit services to be rendered by our independent registered public accounting firm;
 
 
·
is responsible for confirming the independence and objectivity of our independent registered public accounting firm;
 
 
·
can help us resolve conflicts of interest; and
 
 
·
oversees our anonymous complaint procedure established for our employees.
 
Our independent registered public accounting firm is given unrestricted access to the audit committee. The Board 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 audit committee adopted a written Audit Committee Charter in August 2003.  The full text of the Audit Committee Charter is available on our website.
 
In addition, the members of our Audit Committee may review specific matters that the board believes may involve conflicts of interest.  When requested to by our general partner, the audit committee determines if the resolution of the conflict of interest is fair and reasonable to us. The members of the audit committee may not be officers or employees of our general partner or directors, officers, or employees of its affiliates, and must meet the independence and experience standards established by the NYSE Alternext US and the Securities Exchange Act of 1934, as amended, to serve on an audit committee of a board of directors, and certain other requirements. Any matters approved by the audit committee in good faith will be conclusively deemed to be fair and reasonable to us, approved by all of our partners, and not a breach by our general partner of any duties it may owe us or our unitholders.


As is common with MLPs, we do not have any employees. All of our executive management personnel are employees of our general partner. Such personnel devote all of their time to conduct our business and affairs. The officers of our general partner manage the day-to-day affairs of our business, operate our business, and provide us with general and administrative services. We reimburse our general partner for allocated expenses of operational personnel who perform services for our benefit, allocated general and administrative expenses and certain direct expenses.
 
Directors and Executive Officers of our general partner
 
Set forth below is certain information concerning the directors and executive officers of our general partner.  All executive officers serve at the discretion of our general partner.
 
Name
 
Age
 
Position
         
Gareth Roberts
 
56
 
Director and Chairman of the Board
Grant E. Sims
 
53
 
Director and Chief Executive Officer
Mark C. Allen
 
40
 
Director
David C. Baggett
 
47
 
Director
James E. Davison
 
71
 
Director
James E. Davison, Jr.
 
42
 
Director
Ronald T. Evans
 
46
 
Director
Susan O. Rheney
 
49
 
Director
Phil Rykhoek
 
52
 
Director
J. Conley Stone
 
77
 
Director
Martin G. White
 
63
 
Director
Joseph A. Blount, Jr.
 
48
 
President and Chief Operating Officer
Robert V. Deere
 
54
 
Chief Financial Officer
Ross A. Benavides
 
55
 
Senior Vice President, General Counsel and Secretary
Karen N. Pape
 
50
 
Senior Vice President and Controller

 
Gareth Roberts has served as a director and chairman of the Board 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.
 
Grant E. Sims has served as Director and Chief Executive Officer of our general partner since August 2006.   Mr. Sims had been a private investor since 1999.  He was affiliated with Leviathan Gas Pipeline Partners, L.P. from 1992 to 1999, serving as the Chief Executive Officer and a director beginning in 1993 until he left to pursue personal interests, including investments.  Leviathan (subsequently known as El Paso Energy Partners, L.P. and then GulfTerra Energy Partners, L.P.) was an NYSE-listed MLP that merged with Enterprise Products Partners, L.P. on September 30, 2004.
 
Mark C. Allen has served as a director of our general partner since June 2006.  Mr. Allen is Vice President and Chief Accounting Officer of Denbury, and has been employed by Denbury since April 1999.
 
David C. Baggett has served as a director of our general partner since March 2008.  Mr. Baggett is the founder and managing partner of Opportune LLP, a financial consulting firm formed in June 2005.  From April 2003 until June 2005 he was a private investor.  From October 1998 until April 2003, he held various positions at American Plumbing and Mechanical, including President, Chief Operating Officer, Chief Financial Officer and board member.
 
James E. Davison   has served as a director of our general partner since July 2007. Mr. Davison served as chairman of the board of Davison Transport, Inc. for over 30 years. He also serves as President of Terminal Storage, Inc. Mr. Davison has over forty years experience in the energy-related transportation and refinery services businesses.
 
James E. Davison, Jr . has served as a director of our general partner since July 2007. Mr. Davison is also a director of Community Trust Bank and serves on its executive, audit, finance and compensation committees.
 
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.


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.  Ms. Rheney serves on the board of directors, audit committee and finance committee of CenterPoint Energy, Inc., an energy delivery company headquartered in Texas.
 
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.
 
Martin G. White has served as a director of our general partner since March 2008.  Mr. White retired in 2006 from Occidental Chemical Corporation (OxyChem) after most recently serving as Vice President of OxyChem’s joint venture, OxyVinyls, a position he held since the formation of OxyVinyls in May 1999.
 
Joseph A. Blount, Jr. has served as President and Chief Operating Officer of our general partner since August 2006.  Mr. Blount served as President and Chief Operating Officer of Unocal Midstream & Trade from March of 2000 to September of 2005.  Upon the acquisition of Unocal by Chevron in September of 2005, Mr. Blount left to pursue personal interests, including investments.
 
Robert V. Deere has served as Chief Financial Officer of our general partner since October 2008.  Mr. Deere served as Vice President, Accounting and Reporting at Royal Dutch Shell (Shell) for the last five years, and in positions of increasing responsibility with Shell for five years prior to that appointment.
 
Ross A. Benavides has served as General Counsel and Secretary of our general partner since December 1999.  He previously also held the position of Chief Financial Officer from October 1998 until October 2008.
 
Karen N. Pape served as Vice President and Controller of our general partner since March 2002, and was named Senior Vice President in 2007.  Ms. Pape served as Controller and as Director of Finance and Administration of our general partner since December 1996.
 
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) Beneficial Ownership Reporting 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 our equity securities to file reports of ownership and changes in ownership with the SEC and the NYSE Alternext US.  Based solely on our review of the copies of such reports received by us, or written representations from certain reporting persons to us, we are aware of one filing that was not timely made by Mr. Martin G. White, Director, who failed to timely file a Form 4 reporting the purchase of 100 common units in September 2008.  Such transaction was subsequently included on a Form 5.
 
Item 11.  Executive C omp ensation
 
We are managed by our general partner, who employs our executive officers and employees.  Under the terms of our partnership agreement, we are required to reimburse our general partner for expenses relating to managing our operations, including salaries and bonuses of employees employed on our behalf, as well as the costs of providing benefits to such persons under employee benefit plans and for the costs of health and life insurance.  Our general partner has agreed that it will not seek reimbursement for compensation pursuant to the Class B Membership Interest Awards and deferred compensation awards discussed below.  See "Certain Relationships and Related Transactions."
 
Compensation Discussion and Analysis
 
Compensation Committee.   The compensation committee of our Board, or the Committee, consists of the chairman of the board of directors and one independent director.  The Committee is responsible for making recommendations to the Board regarding compensation policies, incentive compensation policies and employee benefit plans, and recommends awards thereunder.  The Committee recommends specific compensation levels for our named executive officers, or NEOs. The Committee also administers our Stock Appreciation Rights Plan, 2007 Long-Term Incentive Plan, Bonus Plan, and Severance Protection Plan. Our Board has adopted a Compensation Committee Charter setting forth the Committee’s purpose and responsibilities.


Board Process .   Following the end of the year, management reviews the compensation of all employees of our general partner, and, based on their review, the results of the Partnership as a whole, and the internal recommendations of supervisory personnel, makes a proposal to the Committee.  Final review of this recommendation is made by the Committee and the Board in February.  Depending on the magnitude of the anticipated changes, there may also be additional Committee meetings and discussions with management in advance of the February meeting.
 
Committee and Board Approval.   The Committee approves all compensation and long-term awards for all executive officers, taking into consideration the recommendation of the Senior Executives (defined below) with regard to compensation for the Other Executives (defined below).  The Committee also reviews and approves our overall compensation programs for all employees, taking into consideration the recommendation of management described above, and any significant changes to these programs.  The Committee administers all of our compensation plans (other than our 401(k) plan, health and other fringe benefit plans), including our Bonus Plan, 2007 Long-Term Incentive Compensation Plan, and Stock Appreciation Rights Plan, under which all of our long-term equity awards are granted.  The Board considers, reviews and ratifies the compensation package based on a recommendation from the Committee.  Following approval of the entire compensation program in February, any applicable salary increases and/or long-term incentive are made or awarded in the first quarter of the year.  Bonuses are paid in March.
 
Executive Officers.  Our NEOs consist of our Senior Executives: Grant E. Sims, our chief executive officer, Joseph A. Blount, Jr., our president and chief operating officer and Robert V. Deere, our chief financial officer. Our Other Executives: consist of Ross A. Benavides, our senior vice president and general counsel, and Karen N. Pape, our senior vice president and controller.
 
Compensation Objectives and Philosophy .  Our compensation programs are designed by the Committee to attract, retain, and motivate key personnel who possess the skills and qualities necessary to perform effectively in an MLP in the industries in which we operate.  We pay base salaries at a level that we feel are appropriate for the skills and qualities of the individual employees based on their past performance and current responsibilities with the Partnership.  The other components of employees’ compensation are consistent among employee groups and generally are proportional to base salary.  We reward employees primarily for the effort and results of the Partnership as a whole, the results of the business segment, and for individual performance.
 
On December 31, 2008, we finalized the compensation arrangements (including underlying documentation) for our Senior Executives.  These arrangements are intended to incentivize our Senior Executives to create value for our common unitholders by maintaining and increasing (over time) the distribution rate we pay on our common units.
 
As described in more detail below, we believe that the combination of base salaries, cash bonuses, Long-Term Incentive Plans and the Class B Membership Interests provides an appropriate balance of short-term and long-term incentives, cash and non-cash based compensation, and an alignment of the incentives for our executives and employees with the interests of our common unitholders and Denbury, the owner of the majority of our general partner.  Our Bonus Plan is driven by the generation of available cash, which is an important metric of value for our unitholders, before reserves and bonuses, and our safety record.  Our Stock Appreciation Rights Plan and 2007 Long Term Incentive Plan are linked primarily to the appreciation in our common unit price.  The Class B Membership Interests have the potential to provide participation in our incentive distribution rights to our Senior Executives, as well as redemption of those rights in specified circumstances, including most events involving their termination of employment.  The level of participation by our Senior Executives in the Class B Membership Interests is largely driven by the generation of available cash as well as the level of distributions we pay to our common unitholders and general partner.
 
Components of our Compensation Program.  Two distinct compensation programs apply to our employees.  The first applies to our Senior Executives, the second applies to our Other Executives and to certain other employees.  The elements of the compensation program for our Senior Executives consist of:
 
 
·
base salaries,
 
 
·
an ability to earn a increasing share of the cash distributions attributable to the incentive distribution rights (IDRs) held by our general partner, referred to as the Class B Membership Interests below, and


 
·
other compensation (including reimbursement for certain self-employment taxes and other costs borne by the executive as a result of their status as members of our general partner).
 
The elements of our Company-wide compensation program that applies to the Other Executives and to certain other employees (excluding the Senior Executives) consist of:
 
 
·
base salaries,
 
 
·
annual cash bonuses (performance-based cash incentive compensation),
 
 
·
a Stock Appreciation Rights Plan (however participation will cease in 2009),
 
 
·
our 2007 Long Term Incentive Plans (phantom units and distribution equivalent rights),
 
 
·
a Severance Protection Plan, and
 
 
·
other compensation (including contributions to the 401(k) plan and annual term life insurance premiums).
 
The Other Executives’ compensation programs are generally available to other members of our management team.
 
Base Salaries.
 
Senior Executives .  On December 31, 2008, each of our Senior Executives,  Messrs. Sims, Blount and Deere, entered into an employment agreement with our general partner under which he will receive an annual salary of $340,000, $300,000, and $369,600, respectively, subject to certain upward adjustments.  Each senior executive’s annual salary rate will be increased by (i) $30,000 if our market capitalization is at least $1.0 billion for any 90-consecutive-day period, and (ii) an additional amount equal to 10% of his then effective base salary each time our market capitalization increases by an additional $300 million.  See additional disclosure in the Employment Agreements section below.
 
Other Executives.   The Committee seeks to establish and maintain base salaries for our Other Executives at a competitive level based on several factors.  These factors include our objectives, the nature and responsibility of the position (considering our size and complexity), the expertise of the individual executive, and the recommendation of the Senior Executives.  In making recommendations, the Committee exercises subjective judgment using no specific weights for these factors.  Base salaries are the primary part of the compensation package whereby a distinction is made for individual performance of the Other Executives.
 
The Other Executives received salary increases mid-year in 2007 and did not receive salary increases for 2008.  For 2009, the Other Executives, Mr. Benavides and Ms. Pape,  will receive a salary increase of three percent to a base salary of $234,300, and a salary increase of thirteen percent to a base salary of $225,000, respectively.  For 2008, all employees other than the Senior Executives and Other Executives received average salary increases of approximately four percent.  For 2009, other employees will average salary increases of approximately three percent.
 
The Class B Membership Interest in Our General Partner.
 
Senior Executives.   As part of finalizing the compensation arrangements for our Senior Executives in December 2008, our general partner awarded them an equity interest in our general partner as long-term incentive compensation. These Class B Membership Interests compensate the holders thereof by providing rewards based on increased shares of the cash distributions attributable to our incentive distribution rights (or IDRs) to the extent we increase Cash Available Before Reserves, or CABR (defined below) (from which we pay distributions on our common units) above specified targets.   CABR generally means Available Cash before Reserves, as defined in Item 7 – “Management’s Discussion and Analysis” above, less Available Cash before Reserves generated from specific transactions with our general partner and its affiliates (including Denbury Resources Inc.) The Class B Membership Interests do not provide any Senior Executive with a direct interest in any assets (including our IDRs) owned by our general partner.
 
These arrangements are intended to incentivize our Senior Executives to create value for our common unitholders and general partner by maintaining and increasing (over time) the distribution rate to them.  Each holder of a Class B Membership Interest is entitled (a) to receive from our general partner quarterly cash distributions in an amount equal to a varying percentage of the incentive distributions we make to our general partner, and (b) upon the occurrence of specified events and circumstances, to receive from our general partner a payment of cash (or, in certain circumstances, common units owned by our general partner) in redemption of such Class B Membership Interests.


Our Board has made the following awards of Class B Membership Interests:

 
   
Class B
     
   
Membership
 
Potential
   
Interest
 
IDR
Senior Executive
 
Percentage
 
Percentage
             
Grant E. Sims
    38.7 %     7.74 %
Joseph A. Blount, Jr.
    33.3       6.66  
Robert V. Deere
    14.0       2.80  
Total Awarded
    86.0       17.20  
Available for Future Awards
    14.0       2.80  
Total
    100.0 %     20.00 %

 
Our general partner is not obligated to award the remaining 14.0% of the unissued Class B Membership Interests.
 
The potential IDR percentage will be subject to the effects of vesting and future levels of available cash and distributions to our common unitholders and general partner, as discussed below, in determining the portion  of the general partner’s IDRs distributable to them.
 
The amount of the quarterly cash distribution, if any, a Class B Membership Interest holder is entitled to receive from our general partner will vary depending on the amount of cash we distribute in respect of our IDRs and the amount by which the growth in Cash Available before Reserves, or CABR, per common unit for an annual period ending with the current quarter exceeds specified base levels.  CABR generally means Available Cash before Reserves, as defined in Item 7 – “Management’s Discussion and Analysis” above, less Available Cash before Reserves generated from specific transactions with our general partner and related Denbury affiliates  In other words, all other things being equal, if our Available Cash before Reserves increases on a per unit basis (other than from specific transactions with our general partner and its affiliates) above specified base levels and our distribution rate on our common units increases above specified thresholds such that our incentive distributions to our general partner increase, each Senior Executive would be entitled to receive distributions from our general partner that constitute a larger share of our general partner’s IDR distributions.
 
Each holder will be entitled to receive a quarterly distribution in an amount equal to the product of (i) the IDR distributions made by us to our general partner and attributable to the applicable quarter, (ii) that Senior Executive’s Class B Membership Interest percentage and (iii) the percentage associated with the growth in CABR per common unitt actually achieved for an annual period ending with the current quarter over specified base levels.  The CABR per unit base levels, as well as the related target percentages, are set forth below. Based on the CABR per unit for the annual period ending at December 31, 2008, the percentages associated with our CABR per unit  were 14% for Messrs. Sims and Blount and zero for Mr. Deere.  For purposes of determining the applicable base percentage for a relevant quarter, Messrs. Sims’ and Blount’s base levels per unit are $0.925, and Mr. Deere’s base level per unit is $1.975.
 
 
   
Applicable
Excess of our CABR per Unit
 
Percentage
for the relevant quarter over
 
(for the relevant
each Senior Executive's Base Amount per Unit: (1)
 
quarter)
     
Excess of $0.14 or less of CABR per Unit over Senior Executive's Base Amount per Unit
 
0%
Excess of $0.14 through $0.29 of CABR per Unit over Senior Executive's Base Amount per Unit
 
2%
Excess of $0.30 through $0.44 of CABR per Unit over Senior Executive's Base Amount per Unit
 
4%
Excess of $0.45 through $0.59 of CABR per Unit over Senior Executive's Base Amount per Unit
 
6%
Excess of $0.60 through $0.74 of CABR per Unit over Senior Executive's Base Amount per Unit
 
8%
Excess of $0.75 through $0.89 of CABR per Unit over Senior Executive's Base Amount per Unit
 
10%
Excess of $0.90 through $1.04 of CABR per Unit over Senior Executive's Base Amount per Unit
 
12%
Excess of $1.05 through $1.19 of CABR per Unit over Senior Executive's Base Amount per Unit
 
14%
Excess of $1.20 through $1.34 of CABR per Unit over Senior Executive's Base Amount per Unit
 
16%
Excess of $1.35 through $1.49 of CABR per Unit over Senior Executive's Base Amount per Unit
 
18%
Excess of $1.50 or greater of CABR per Unit over Senior Executive's Base Amount per Unit
 
20%
___________
 
(1)  Senior Executive’s Base Amount per Unit is specified in his Class B Membership Interest Award Agreement.  The base amount for Messrs. Sims and Blount is $0.925.  The base amount for Mr. Deere is $1.975 .
 
For example, our Senior Executives received the following distributions from our general partner in the first quarter of 2009 with respect to the quarter ended December 31, 2008:
 
   
Distribution
 
Senior Executive
 
Amount
 
       
Grant E. Sims
  $ 44,595  
Joseph A. Blount, Jr.
    38,373  
Robert V. Deere
    -  
Total
  $ 82,968  

 
The above distributions were calculated as follows (in thousands, except per unit amounts):

   
Total
 
       
Available Cash before Reserves generated for the four quarters
  $ 89,784  
Less:  Adjustment to Available Cash before Reserves relating to specific Transaction with our general partner and its affiliates
    11,628  
CABR for the four quarters
  $ 78,156  
         
Weighted average units outstanding, including implied general partner units (1)
    39,089  
         
Adjusted annual CABR at December 31, 2008 per adjusted unit (2)
  $ 2.00  
         
Base amount for Messrs. Sims and Blount
    0.925  
         
Excess of CABR per Unit over base amount
  $ 1.075  
         
Applicable Percentage for Messrs. Sims and Blount for the quarter
    14 %

 
____________
 
(1)  Adjusted units outstanding is calculated separately for each quarter in the annual period and applied to the CABR for the respective quarter.  The calculation excludes common units issued to our general partner and its affiliates resulting from any transaction between us and our general partner and its affiliates after March 31, 2008.
 
(2)  This amount represents the sum of the individual quarterly calculations in the annual period.
 

The distribution that Mr. Sims received for the quarter is calculated as the product of (i) $823,093  (which is the amount of IDR distributions attributable to that quarter that we actually paid to our general partner) (ii) the CABR-related percentage of 14%, and (iii) Mr. Sims Class B Membership Interest of 38.7%.  The calculation of Mr. Blount’s distribution amount is similar to that of Mr. Sims utilizing his Class B Membership Interest of 33.3%.  Mr. Deere was not entitled to a distribution for the quarter because the adjusted annual CABR per adjusted unit only exceeded his base amount of $1.975 by $0.025.
 
In addition, our general partner has agreed to redeem each Senior Executive’s equity interest for cash (or, in specified circumstances, for common units owned by our general partner) in certain circumstances including most events involving termination of that Senior Executive’s employment with our general partner or when a change of control occurs.  The amount of the redemption payment will depend on the nature of the triggering event (i.e. termination with or without cause or good reason or due to death, disability or a change of control) and/or the time at which the triggering event occurs. In general, each Senior Executive will be entitled to receive a redemption amount if our general partner did not terminate his employment for cause, which redemption amount is subject to vesting as described below.

The redemption amount for each executive will be an amount equal to the vested portion of the excess, if any, of (a) the then current value of the general partner’s future IDRs multiplied by the product of (i) the relevant member’s Class B Membership Interest percentage and (ii) his then effective CABR-related percentage over (b) $1,007,229 for Mr. Sims, $866,685 for Mr. Blount, and zero for Mr. Deere.  The determined value of our IDRs will be the present value of the annualized cash flows attributable to the IDRs at the time of the triggering event discounted at an annual interest rate equal to the average of the annualized yield of ten specified publicly-traded entities which are general partners of publicly traded master limited partnerships.  The vesting percentage of each executive will be the percentage, in general, determined as of the relevant valuation date, indicated below:
 
(i)
termination for cause:
 
0%
(ii)
after a change of control; upon such Class B Member’s termination for good reason; or upon a termination during the period beginning six months prior to and ending on a change of control other than termination by our general partner for cause or termination by the Class B Member without good reason:
 
100%
(iii)
if the Class B Member voluntarily terminates his employment other than for good reason, if termination occurs:
 
 
 
(a )
prior to the 1 st anniversary of the Class B Member’s award:
 
0%
 
(b)
on or after the 1 st anniversary, and prior to the 2 nd anniversary, of the Class B Member’s award:
 
25%
 
(c)
on or after the 2 nd anniversary, and prior to the 3 rd anniversary, of the Class B Member’s award:
 
50%
 
(d)
on or after the 3 rd anniversary, and prior to the 4 th anniversary, of the Class B Member’s award:
 
75%
 
(e)
after the 4 th anniversary of the Class B Member’s award:
 
100%

 
On December 31, 2008, the redemption amount for each Class B Member was zero ($0).To the extent our general partner or any of its affiliates own any of our common units, a Class B Member may elect to receive any portion of his redemption payment in the form of such common units (in lieu of cash), the number of which would be based on the average closing price of our common units during a specified five trading day period.
 
In general, the holders of the Class B Membership Interests will not have any contractual rights limiting the manner in which our general partner may operate its business.  For example, without obtaining the consent of any holder of the Class B Membership Interest, our general partner could sell all or any portion of our IDRs or merge, consolidate or otherwise reorganize.  If our general partner sells all or any portion of our IDRs, the distribution and redemption payments due to the holders of its Class B Membership Interest will be determined based on the assets our general partner receives in exchange for such IDRs.
 
Our general partner has agreed that it will not seek reimbursement (on behalf of itself or its affiliates) under our partnership agreement for the costs of these Senior Executive compensation arrangements to the extent relating to their ownership of Class B Membership Interests (including current cash distributions and redemption payments made by our general partner in respect thereof) and the deferred compensation amounts.  Our general partner has retained its right to (and intends to) seek reimbursement for the costs of these Senior Executive compensation arrangements to the extent relating to the employment agreements (including base salary and fringe benefits) and cash bonuses, if any, which costs will be borne by us.


Although our general partner will not seek reimbursement for the costs of the Class B Membership Interests and deferred compensation plan arrangements, we will record non-cash expense during the four-year vesting period.   The Class B Membership Interests awarded to our senior executives will be accounted for as liability awards under the provisions of SFAS 123(R).  As such, the fair value of the compensation cost we record for these awards will be recomputed at each measurement date and the expense to be recorded will be adjusted based on that fair value.  Management’s estimates of the fair value of these awards are based on assumptions regarding a number of future events, including estimates of the Available Cash before Reserves we will generate each quarter through the final vesting date of December 31, 2012, estimates of the future amount of incentive distributions we will pay to our general partner, and assumptions about appropriate discount rates.  Additionally the determination of fair value will be affected by the distribution yield of ten publicly-traded entities that are the general partners in publicly-traded master limited partnerships, a factor over which we have no control.  Included within the assumptions used to prepare these estimates are projections of available cash and distributions to our common unitholders and general partner, including an assumed level of growth and the effects of future new growth projects during the four-year vesting period.  At December 31, 2008, Management estimates that the fair value of the Class B Membership Awards and the related deferred compensation awards granted to our Senior Executives on that date is approximately $12 million.  The fair value of these incentive awards will be recomputed each quarter beginning with the quarter ending March 31, 2009 through the final settlement of the awards.  Compensation expense of $3.4 million was recorded in the fourth quarter of 2007 related to the previous arrangements between our general partner and our Senior Executives.  The fair value to be recorded by us as compensation expense will be the excess of the recomputed estimated fair value over the previously recorded $3.4 million.  Due to the vesting conditions for the awards, the amount to which the Senior Executives were entitled on December 31, 2008 for the Class B Membership Awards and the related deferred compensation was zero.  Management’s estimates of fair value are made in order to record non-cash compensation expense over the vesting period, and do not necessarily represent the contractual amounts payable under these awards at December 31, 2008.
 
Other Executives.   Only our Senior Executives may hold Class B Membership Interests.
 
Bonuses and Deferred Compensation Awards.
 
Senior Executives.   In connection with the Senior Executives’ compensation agreements, we paid a bonus to each of Messrs. Sims and Blount of $107,751 and $97,599, respectively, in December 2008.
 
Additionally, our general partner adopted an unfunded, nonqualified deferred compensation plan and made awards under that plan to Messrs. Sims and Blount in a maximum amount of $1,007,229 and $866,685, respectively.
 
Our deferred compensation plan provides Messrs. Sims and Blount with incentive compensation that is deferred until after such participant’s separation from service with our general partner.  Under that plan, Messrs. Sims and Blount were awarded a maximum deferred compensation amount equal to the lesser of $1,007,229 for Mr. Sims and $866,685 for Mr. Blount, or the value of such participant’s Class B Membership Interest on the date such interest is valued for purposes of determining the redemption amount.  In general, each participant will be entitled to receive his deferred compensation award to the same extent he will be entitled to receive a payment in respect of the redemption of his Class B Membership Interest, subject to the same general vesting requirements summarized above regarding each executive’s redemption amount.
 
Like the redemption payment, a participant may elect to receive his deferred compensation payment in the form of our common units (in lieu of cash) to the extent our general partner or any of its affiliates own any of our common units.
 
Bonus Plan for Other Executives and other employees.   In January 2009, the Committee of the Board of our general partner approved a bonus program, referred to below as the “Bonus Plan,” for all employees of our general partner that is applicable to 2008.  The Senior Executives are excluded from participation in the Bonus Plan.  The Bonus Plan is paid at the discretion of our Board based on the recommendation of the Committee, and can be amended or changed at any time.  Since the determination of whether bonuses will be paid each year and in what amounts is determined by the Committee on a company-wide basis, the Other Executives only receive bonuses if other employees receive bonuses.


The Bonus Plan is based primarily on the amount of money we generate for distributions to our unitholders, and is measured on a calendar-year basis.  For 2008, two metrics are used to determine the general bonus pool – the level of Available Cash before Reserves (before subtracting bonus expense and related employer tax burdens) that we generate and our company-wide safety record improvement. The level of Available Cash before Reserves generated for the year as a percentage of a target set by our Committee is weighted ninety percent and the achieved level of the targeted improvement in our safety record is weighted ten percent.  The sum of the weighted percentage achievement of these targets is multiplied by the eligible compensation and the target percentages established by our Committee for the various levels of our employees to determine the maximum general bonus pool.
 
The general bonus pool will be distributed as follows:
 
 
·
Each eligible employee will be eligible to receive a bonus after the end of the year up to a specified percentage of their year-to-date gross wages.  Certain compensation, such as awards under our Stock Appreciation Rights Plan, car allowances and relocation expenses, will be excluded from the calculation.  Each employee must be a regular, full-time active employee, not on probation, at the time the bonus is paid in order to be eligible to receive a bonus.  The date of payment of the bonuses is at the discretion of management, but is expected to be before March 15 each year.
 
 
·
There are five levels of participation in the Bonus Plan. Employees in each level will be eligible for a bonus each year in accordance with the following table.  The determination of what level applies to each employee will be made by the Committee based on the recommendation of the Senior Executives.
 
 
·
The percentage of adjusted year-to-date gross wages paid as a bonus will be a function of the general bonus pool available and the employee’s Participation Level in the Bonus Plan.  The bonus amount each employee will be eligible to receive will be determined in accordance with the table shown below.  The bonus may be adjusted up or down to reflect business unit contribution and individual performance.  These adjustments are discretionary and will be determined by the Senior Executives with approval by the Committee.
 
Bonus Targets
Job Classifications
   
0 - 10%
Operations and administrative clerical personnel
0 - 20%
Professional/supervisory personnel
0 - 25%
Senior professionals/management personnel
0 - 50%
Senior management/executive personnel
0 - 100%
Key executive personnel, including the Other Executives
 
A separate marketing bonus pool is available for compensating certain marketing personnel that is based on the contribution of that group to Available Cash before Reserves.  A minimum level of contribution to Available Cash before Reserves is required before any amounts are allocated to the marketing bonus pool.  Our Other Executives do not participate in this pool.
 
The Bonus Plan is designed to enhance our financial performance by rewarding employees for achieving financial performance and safety objectives.  Since Available Cash before Reserves is an important factor in determining the amount of distributions to our unitholders and is a significant factor in the market’s perception of the value of common units of an MLP, we believe the Bonus Plan is designed to reward employees on a basis that is aligned with the interests of the unitholders.  We believe that this generates a bonus that represents a meaningful level of compensation for the employee population and that encourages employees to operate as a unified team to generate results that are aligned with the interests of the unitholders.  By including safety improvement in the calculation of the Bonus Pool, we encourage our employees to focus on the impact their job performance has on the environment in which we operate.
 
For 2008, the Committee established a target of approximately $81 million for Available Cash before Reserves and before bonus expense and related employer tax burdens, with a hurdle rate of 105%.  We achieved 117% of the target which exceeded the target level set at the beginning of the 2008 for Available Cash before Reserves.  We did not achieve our safety incident rate goal for 2008.  As a result, the Bonus Pool for 2008 bonuses to be paid in March 2009 was calculated as 90% of 117% divided by 105%, or 100%. In accordance with the Bonus Plan, the total pool available for bonuses for 2008 was $5.1 million.  Our Committee approved bonuses totaling $4.5 million, which represents approximately 15.5 percent of total eligible compensation.  These bonuses were paid in March 2009.


Long-Term Incentive Compensation and Stock Appreciation Rights.
 
The 2007 Long-Term Incentive Compensation Plan (2007 LTIP).
 
Senior Executives.  Our Senior Executives are not eligible and do not participate in our 2007 LTIP.
 
Non-Employee Directors, Other Executives and other Employees.   Our unitholders approved a Long-Term Incentive Plan on December 18, 2007 which provides for awards of Phantom Units and Distribution Equivalent Rights to our non-employee directors and employees.  Phantom units are notional units representing unfunded and unsecured promises to deliver a common unit to the participant should specified vesting requirements be met.  Distribution Equivalent Rights are rights to receive an amount of cash equal to all or a portion of the cash distributions made by us during a specified period.  The 2007 LTIP is administered by the Committee.  Subject to adjustment as provided in the 2007 LTIP, awards with respect to up to an aggregate of 1,000,000 units may be granted under the 2007 LTIP.
 
The 2007 LTIP is intended to provide a means whereby employees and directors providing services to us may develop a sense of proprietorship and personal involvement in our development and financial success through the award of phantom units, and/or distribution equivalent rights; and the 2007 LTIP allows for various forms of equity or equity-based awards, providing flexible incentives to employees and directors.
 
The Committee (at its discretion) will designate participants in the 2007 LTIP, determine the types of awards to grant to participants, determine the number of units to be covered by any award, and determine the conditions and terms of any award including vesting, settlement and forfeiture conditions.  The 2007 LTIP may be amended or terminated at any time by the Board or the Committee; however, any material amendment, such as a material increase in the number of units available under the 2007 LTIP or a change in the types of awards available under the 2007 LTIP, will also require the approval of our unitholders.  The Committee is also authorized to make adjustments to the terms and conditions of and the criteria included in awards under the plan in specified circumstances.  The 2007 LTIP is effective until December 18, 2017 or, if earlier, the time which all available units under the 2007 LTIP have been delivered to participants or the time of termination of the plan by the Board or the Committee.
 
In February 2009, the Committee approved awards granting phantom units with a total value (assuming a market price of $13 per common unit) as of February 26, 2009 of $0.6 million (47,601 phantom units) to 17 employees of our general partner.  Grants were made to Mr. Benavides and Ms. Pape with values in amounts of $113,800 (8,750 phantom units) and $100,000 (7,692 phantom units) respectively, or approximately 50 percent of their base salaries.  The amounts awarded were entirely discretionary and were based on the recommendation of the Senior Executives to the Committee.
 
Additionally, the Committee awarded each non-employee director an award of 3,500 phantom units on February 26, 2009.
 
Stock Appreciation Rights Plan.
 
Other Executives and employees.   In December 2003, the Board approved a Stock Appreciation Rights plan or SAR plan.  Under the terms of this plan, regular, full-time active employees and the members of the Board, excluding the Senior Executives, are eligible to participate in the plan.  The plan is administered by the Committee, who shall determine, in its full discretion, the number of rights to award, the grant date of the rights and the formula for allocating rights to the participants and the strike price of the rights awarded.
 
Beginning in 2009, rights will be awarded to our professional/supervisory personnel, senior professional/managerial personnel and senior management/executive personnel.  Our Senior Executives and key executive personnel, including our Other Executives, as well as our directors, will no longer receive awards under the Stock Appreciation Rights plan.  Our operations and administrative clerical personnel will also no longer participate in this plan.
 
In February 2008, awards of rights were made to all personnel including our Other Executives.  Grants of SARs were made to all personnel in February 2008 totaling 500,983 units.  This grant included the personnel of the Davison entities, who received initial grants in 2008 totaling 387,512 SARs in individual allocations similar to what they would have received had they been employed in 2003, and 113,471 SARs to the personnel employed in the operations we owned prior to the Davison acquisition.  The total SARs allocated to the employees of the legacy operations was approximately the same number of SARs awarded at the end of 2006.   Mr. Benavides and Ms. Pape received grants at February 14, 2008 of 5,448 and 4,790 rights, respectively.  The number of SARs allocated to these individuals was a product of the total 113,471 and the ratio of the maximum bonus for Mr. Benavides and Ms. Pape under the Bonus Plan in effect in 2007 to the total of the maximum bonuses for all employees who participated in the Bonus Plan in 2007.


The exercise price of the annual awards of rights has been the average of the closing market price of our units for the ten days prior to the date of the grant.  This methodology has been used by the Committee for annual grants so that the exercise price is not unduly influenced by trading of our units on one particular date.  The volume of units that trade each day is frequently small, such that one or a few small trade can have a significant influence on the price.  Additionally, we may see unusual trading occur in the late months of the year at prices that do not necessarily correspond to the latest market prices. For 2009, we will adjust the exercise price to reflect a more accurate representation of the unit value in the current market environment, but not below the closing price of our common units on the grant date. This methodology is subject to change for any grant in the future.  Additional details describing the operation of the SAR plan are included below.
 
Other Compensation and Benefits.
 
Severance Benefits.  We believe that companies should provide reasonable severance benefits to employees.  With respect to our Other Executives, these severance benefits should reflect the fact that it may be difficult for employees to find comparable employment within a short period of time.  Although we typically pay severance when we terminate any employee unless such termination is for “cause”, we do not have any pre-defined severance benefits for our Other Executives, except in the case of a change in control, a plan adopted in June 2005.   This plan is described under “Change of Control” below.
 
Other Benefits. Each Senior Executive is entitled to vacation, medical and health coverage, and similar fringe benefits received by the Other Executives; provided; however, that none of our Senior Executives will be eligible to participate in our general partner’s Stock Appreciation Rights Plan, Severance Protection Plan, or 2007 Long-Term Incentive Plan.  Our Senior Executives and Other Executives participate in our benefit plans on the same terms as our other employees.  These plans include medical, dental, disability and life insurance, and matching and profit-sharing contributions to our 401(k) plan.  We match up to 100 percent of the first three percent that the participant contributes to the 401(k) plan and 50 percent of the next three percent contributed.  Additionally, we make a contribution to our 401(k) plan in the amount of three percent as a profit-sharing contribution to our 401(k) for each eligible employee.  As reflected in the Summary Compensation Table, the cost to Genesis of the 401(k) matching contributions and profit-sharing contributions and term life premiums aggregated $69,331 in 2008 for our Senior Executives and Other Executives.  As a result of their status as Class B Members in our general partner, our Senior Executives will be reimbursed for the additional taxes they will owe individually related to certain benefits they receive from us including medical, dental, disability and life insurance, and matching and profit-sharing contributions to our 401(k) plan, as well as the self-employment taxes they will owe.  These reimbursements will begin in 2009.
 
Our only retirement benefits are our 401(k) plan and a retirement vesting provision included in our Stock Appreciation Rights Plan. We do not have any pension plans or post-retirement medical benefits.
 
Compensation Committee Report
 
The information contained in this report shall not be deemed to be soliciting material or filed with the SEC or subject to the liabilities of Section 18 of the Exchange Act, except to the extent that we specifically incorporate it by reference into a document filed under the Securities Act of the Exchange Act.
 
The Compensation Committee has reviewed and discussed with management the Compensation Discussion and Analysis included above.  Based on the review and discussions, the Compensation Committee approved that the Compensation Discussion and Analysis be included in this Form 10-K.
 
This report is submitted by the Compensation Committee.
 

Gareth Roberts (Chairman)
Susan O. Rheney


Executive Compensation

 
2008 SUMMARY COMPENSATION TABLE
 
The following table summarizes certain information regarding the compensation paid or accrued by Genesis during 2008 to those persons who served as NEOs at the end of 2008.
 
2008 Summary Compensation Table
 
                                               
Name & Principal Position
 
Year
 
Salary ($)
   
Bonus (1) ($)
   
Stock Awards (2) ($)
   
Option Awards (3) ($)
   
Non-Equity Incentive Plan Compen- sation (4) ($)
   
All Other Compen- sation (5) ($)
   
Total ($)
 
                                               
Grant E. Sims (6)
 
2008
    310,000       107,751       -       -       -       9,834       427,585  
Chief Executive Officer
 
2007
    310,000       -       -       -       -       1,838,476       2,148,476  
(Principal Executive Officer)
 
2006
    112,077       -       -       -       -       56       112,133  
                                                             
Joseph A. Blount, Jr. (6)
 
2008
    270,000       97,599       -       -       -       19,936       387,535  
President & Chief Operating
 
2007
    270,000       -       -       -       -       1,618,984       1,888,984  
 Officer
 
2006
    97,615       -       -       -       -       4,449       102,064  
                                                             
Robert V. Deere (7) (8)
 
2008
    89,557       -       -       -       -       621       90,178  
Chief Financial Officer (Principal Financial Officer)
                                                           
                                                             
Ross A. Benavides   (8)
 
2008
    227,500       170,000       65,638       (215,195 )     -       19,584       267,527  
Senior Vice President and
 
2007
    211,000       68,250       2,511       100,448       111,581       16,680       510,470  
General Counsel
 
2006
    195,000       -       -       101,231       78,000       16,668       390,899  
                                                             
Karen N. Pape
 
2008
    200,000       180,000       58,341       (164,728 )     -       19,356       292,969  
Senior Vice President &
 
2007
    184,000       52,500       2,232       77,139       94,577       16,680       427,128  
Controller (Principal Accounting Officer)
 
2006
    150,000       -       -       77,430       60,000       15,032       302,462  

 
 
(1)
Amounts in this column represent for Mr. Sims and Mr. Blount represent the amount that was paid as a bonus at the time of execution of their employment agreements.  Amounts in this column for Mr. Benavides and Ms. Pape for 2008 represent bonuses paid in March 2009 relative to 2008 under our bonus program that was effective for 2008.  Amounts in this column for Mr. Benavides and Ms. Pape in 2007 represent the amount that was paid as a retention bonus in September 2007.
 
(2)
Amounts in this column represent the amounts, before consideration of expected forfeiture rate, that are included in the determination of net income for the period under the provisions of SFAS 123(R) for awards of phantom units under our 2007 LTIP.  The forfeiture rate that was applied to these awards at December 31, 2008 and 2007 was zero.
 
(3)
Amounts in this column represent the amounts, before consideration of expected forfeiture rate, that are included in the determination of net income for in each period under the provisions of SFAS 123(R) for awards under our Stock Appreciation Rights plan.  The forfeiture rate that was applied to these amounts in each year was 10%.  Because of the decline in our common unit market price and the effects of that decline on the fair value of outstanding stock appreciation rights, we recorded a reduction in the liability for these awards in 2008.  These reductions are reflected as negative amounts in the table above.
 
(4)
Amounts in this column represent the amount that will be paid to the Named Executive Officer as an award under our Bonus Plan.  Messrs. Sims, Blount and Deere do not participate in the Bonus Plan.
 
(5)
Information on the amounts included in this column is included in the table below.
 
(6)
Mr. Sims and Mr. Blount were employed by our general partner effective August 6, 2006.
 
(7)
Mr. Deere was employed by our general partner effective October 6, 2008.
 
(8)
Mr. Deere served as Chief Financial Officer from October 2008 to the present.  Mr. Benavides served as Chief Financial Officer from January to October 2008.



Name
 
Year
 
401(k) Matching Contributions (a)
   
401(k) Profit-Sharing Contributions (b)
   
Insurance Premiums (c)
   
Other Compensation (d)
   
Totals
 
                                   
Grant E. Sims
 
2008
  $ -     $ 7,350     $ 2,484     $ -     $ 9,834  
   
2007
  $ -     $ 6,600     $ 180     $ 1,831,696     $ 1,838,476  
   
2006
  $ -     $ -     $ 56     $ -     $ 56  
                                             
Joseph A. Blount, Jr.
 
2008
  $ 10,350     $ 7,350     $ 2,236     $ -     $ 19,936  
   
2007
  $ 9,900     $ 6,600     $ 180     $ 1,602,304     $ 1,618,984  
   
2006
  $ 4,393     $ -     $ 56     $ -     $ 4,449  
                                             
Robert V. Deere
 
2008
  $ -     $ -     $ 621     $ -     $ 621  
                                             
Ross A. Benavides
 
2008
  $ 10,350     $ 7,350     $ 1,884     $ -     $ 19,584  
   
2007
  $ 9,900     $ 6,600     $ 180     $ -     $ 16,680  
   
2006
  $ 9,900     $ 6,600     $ 168     $ -     $ 16,668  
                                             
Karen N. Pape
 
2008
  $ 10,350     $ 7,350     $ 1,656     $ -     $ 19,356  
   
2007
  $ 9,900     $ 6,600     $ 180     $ -     $ 16,680  
   
2006
  $ 8,264     $ 6,600     $ 168     $ -     $ 15,032  


Amounts in this table represent:
 
 
(a)
Matching contributions by Genesis to our 401(k) plan on each NEO’s behalf.
 
 
(b)
Profit-sharing contributions by Genesis to our 401(k) plan on each NEO’s behalf.
 
 
(c)
Term life insurance premiums paid by Genesis on each NEO’s behalf.
 
 
(d)
Represents an amount for the estimated value of the compensation earned in 2007 under the proposed arrangements between the Senior Executive and our general partner that existed at that time.   Beginning in 2009, the fair value of the awards of the Class B Membership Interests and the deferred compensation awards, less these previously recorded amounts, will be recorded as non-cash compensation expense over their four-year vesting period, and adjusted quarterly until final settlement.  The expense recorded for this arrangement in 2007 was an amount agreed to by the parties as a fair representation of the value provided and earned in 2007.  While our general partner will bear the cash cost of the Class B Membership Interests and the deferred compensation awards to our Senior Executives, the expense will be recognized as compensation by us and as a capital contribution by our general partner, as the purpose of the Senior Executive compensation arrangements is to incentivize these individuals to grow the partnership.
 
Employment Agreements.
 
On December 31, 2008, each of our Senior Executives, Messrs. Sims, Blount and Deere, entered into an employment agreement with our general partner under which he will receive an annual salary of $340,000, $300,000, and $369,600, respectively, subject to certain upward adjustments.  Each senior executive’s annual salary rate will be increased by (i) $30,000 if our market capitalization is at least $1.0 billion for any 90-consecutive-day period, and (ii) an additional amount equal to 10% of his then effective base salary each time our market capitalization increases by an additional $300 million.
 
Under his employment agreement, each Senior Executive will be entitled to specified severance benefits under certain circumstances.  No Senior Executive will be entitled to severance benefits if our general partner terminates him for cause.  Each Senior Executive (or family) will be entitled to continued health benefits for 18 months after his termination and to the payment of his base salary through December 31, 2012 if he dies, if he is terminated due to a disability or if he terminates his employment for good reason.  If our general partner terminates a Senior Executive (other than for cause) within two years after a change of control, he will be entitled to continued health benefits for 18 months after his termination and to the payment of his base salary through the later of December 31, 2012 or three years from his date of termination.


Each employment agreement contains customary non-solicitation and non-competition provisions that prohibit our Senior Executives from competing with us after termination, including working for, supervising, assisting, or participating in any competing business (as defined in the employment agreements)  in any capacity in the states of Louisiana, Mississippi, and Texas during the term of the employment agreement and for a  period of two years after termination if the employment agreement is terminated for cause or without good reason, and for a period of one year after termination if the employment agreement is terminated other than by our general partner for cause or by the Senior Executive without good reason.
 
Either our general partner or a Senior Executive may terminate his agreement at any time subject to the economic consequences resulting from such termination.  For example, if a Senior Executive terminates his employment agreement prior to December 31, 2012 other than for good reason, he will not receive any severance payments or continuing fringe benefits under his employment agreement, and he will effectively forfeit his Class B Membership Interest and his deferred compensation award.  On the other hand, if our general partner terminates a Senior Executive’s employment prior to that date without cause or due to a disability, or if that Senior Executive terminates his employment for good reason, of if our general partner terminates a Senior Executive’s employment without cause within two years after a change of control, that Senior Executive will be entitled to receive a severance payment and continuing fringe benefits under his employment agreement, as well as a payment of the redemption amount (if any) in redemption of his Class B Membership Interest.
 
Change in Control and Other Termination Payments .
 
Senior Executives.  Based upon a hypothetical termination date of December 31, 2008, the change in control termination benefits for our Senior Executives would have been as follows:
 
   
Grant E.
   
Joseph A.
   
Robert V.
 
   
Sims
   
Blount, Jr.
   
Deere
 
                   
Severance payment pursuant to employment agreement
  $ 1,020,000     $ 900,000     $ 1,108,800  
Healthcare and other insurance benefits
    23,238       23,238       23,238  
Class B Membership Interest and deferred compensation (1)
    4,609,185       3,966,043       1,667,405  
Total
  $ 5,652,423     $ 4,889,281     $ 2,799,443  

 
(1) 
Upon termination due to a change in control, each Senior Executive will be entitled to his deferred compensation amount, if any, and redemption of his Class B Membership Interest.  Such payment will be paid no later than sixty days after our general partner receives its distribution payment from us for the quarter ended September 30, 2010, and will be based on the IDR payment for such quarter.  Additionally each Senior Executive will be entitled to continue to receive a share of the quarterly IDR payment our general partner receives from us through the quarter ended September 30, 2010.  These amounts will be computed assuming that each Senior Executive’s CABR-related percentage is no less than 16%.  The amounts in this table represent management ’ s estimates of the amount each Senior Executive would receive using assumptions regarding a number of future events, including estimates of the Available Cash before Reserves we will generate each quarter through the September 30, 2010 and estimates of the future amount of incentive distributions we will pay to our general partner related to quarters through September 30, 2010.  Additionally our estimate of the redemption of the Class B Membership Interests assumes that the distribution yield of ten publicly-traded entities that are the general partners in publicly-traded master limited partnerships will be the same as the average at December 31, 2008.
 
Based upon a hypothetical termination date of December 31, 2008, the termination benefits for our Senior Executives for voluntary termination or termination for cause would be zero.  Based upon a hypothetical termination date of December 31, 2008, the termination benefits for our Senior Executives for termination without cause or for good reason, including death or disability would have been:
 
   
Grant E.
   
Joseph A.
   
Robert V.
 
   
Sims
   
Blount, Jr.
   
Deere
 
                   
Severance payment pursuant to employment agreement
  $ 1,020,000     $ 900,000     $ 1,108,800  
Healthcare and other insurance benefits
    23,238       23,238       23,238  
Class B Membership Interest and deferred compensation (1)
    3,456,888       2,974,532       -  
Total
  $ 4,500,126     $ 3,897,770     $ 1,132,038  

 
(1)
As with a termination for a change in control, termination without cause or for good reason would entitle each Senior Executive to his deferred compensation amount, if any, and redemption of his Class B Membership Interest.  The termination payment would be paid no later than sixty days after our general partner receives its distribution payment from us for the quarter ended September 30, 2010, and will be based on the IDR payment for such quarter.  Additionally each Senior Executive will be entitled to continue to receive a share of the quarterly IDR payment our general partner receives from us through the quarter ended September 30, 2010.  The difference from a termination for a change in control is that these amounts will be computed utilizing each Senior Executive’s CABR-related percentage at the date of termination.  The amounts in this table were calculated similarly to the amounts for a change in control, except the CABR-related percentages were 12% for Messrs. Sims and Blount and zero for Mr. Deere at December 31, 2008.


Other Executives. Based upon a hypothetical termination date of December 31, 2008, the change in control termination benefits for our Other Executives would have been as follows (based on the closing price for our units of $8.69 at that time):
 
   
Ross A.
   
Karen N.
 
   
Benavides
   
Pape
 
             
Severance plan payment
  $ 1,069,247     $ 910,616  
Healthcare and other insurance benefits
    12,751       12,322  
Fair market value of stock appreciation rights
    -       -  
Fair market value of phantom units
    79,739       70,876  
Total
  $ 1,161,737     $ 993,814  
 
It is our belief that the interests of unitholders will best be served if the interests of our Other Executives are aligned with theirs.  Providing change of control benefits should eliminate, or at least reduce, the reluctance of management to pursue potential change of control transactions that may be in the best interests of our unitholders.
 
We have two benefits for our employees and Other Executives in the event of a change of control:  (i) our cash Severance Protection Plan, and (ii) vesting of SARs.  Under the terms of our Severance Protection Plan, an employee is entitled to receive a severance payment if a change of control occurs and the employee is terminated within two years of that change (i.e. a “double trigger” award).  The Severance Protection Plan will not apply to any employee who is terminated for cause or by an employee’s own decision for other than good reason (e.g., change of job status or a required move of more than 25 miles).  If entitled to severance payments under the terms of the Severance Protection Plan, Mr. Benavides and Ms. Pape will receive three times the sum of their annual salary and the average of their bonus amounts in the last twenty-four months, certain other members of management will receive two times the sum of their annual salary and the average of their bonus amounts in the last twenty-four months, and all other employees will receive between one-third to one and one-half times the sum of their annual salary and the average of their bonus amounts in the last twenty-four months depending upon their salary level and length of service with us.  All employees will also receive medical and dental reimbursement benefits for one-half the number of months for which they receive severance benefits.
 
A change in control is defined in the Severance Protection 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 our assets.
 
The Severance Protection Plan also provides that if our Other Executives are subject to the “parachute payment” excise tax under IRC Section 4999, then we will pay the employee under the severance plan an additional amount to “gross up” the severance payment so that the employee will receive the full amount due under the terms of the severance plan after payment of the excise tax.
 
If a participant in our SAR Plan is terminated within one year of a change in control, all SARs would immediately vest.


Other Compensation
 
Long Term Incentive Plan
 
As discussed in the Compensation Discussion and Analysis, our unitholders approved the Genesis Energy, Inc. 2007 Long Term Incentive Plan, or 2007 LTIP, on December 18, 2007 which provides for awards of Phantom Units and Distribution Equivalent Rights to non-employee directors and employees of Genesis Energy, LLC, our general partner.  Phantom Units are notional units representing unfunded and unsecured promises to deliver a common unit to the participant should specified vesting requirements be met.  Distribution Equivalent Rights are rights to receive an amount of cash equal to all or a portion of the cash distributions made by us during a specified period.  The 2007 LTIP will be administered by the Committee.  Subject to adjustment as provided in the 2007 LTIP, awards with respect to up to an aggregate of 1,000,000 units may be granted under the 2007 LTIP.
 
The Committee (at its discretion) will designate participants in the 2007 LTIP, determine the types of awards to grant to participants, determine the number of units to be covered by any award, and determine the conditions and terms of any award including vesting, settlement and forfeiture conditions.  The 2007 LTIP may be amended or terminated at any time by the Board or the Committee; however, any material amendment, such as a material increase in the number of units available under the 2007 LTIP or a change in the types of awards available under the 2007 LTIP, will also require the approval of our unitholders.  The Committee is also authorized to make adjustments in the terms and conditions of and the criteria included in awards under the plan in specified circumstances.  The 2007 LTIP is effective until December 18, 2017 or, if earlier, the time which all available units under the 2007 LTIP have been delivered to participants or the time of termination of the plan by the Board or the Committee.
 
Stock Appreciation Rights Plan
 
As discussed in the Compensation Discussion and Analysis, we have a Stock Appreciation Rights plan, or SAR, for our employees.  Our Senior Executives do not participate in this plan and, beginning in 2009, our Other Executives, certain key employees and the Board will no longer receive awards under this plan.  Under the terms of this plan, certain employees are eligible to participate in the plan.  The plan is administered by the Committee, who shall determine, in its full discretion, the number of rights to award, the grant date of the rights, the vesting period of the rights awarded 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.  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 us 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.
 
Bonus Program
 
As discussed in the Compensation Disclosure and Analysis, we have a bonus program for all eligible employees of our general partner, with the exception of our Senior Executives.  This program provides for our Other Executives to receive bonuses annually at the discretion of our Board based on the recommendation of the Committee.  A bonus pool is determined based on our achieving certain levels of Available Cash before Reserves and bonus expense and the improvement in our safety record. Each eligible employee will be eligible to receive a bonus; however, the actual amounts paid will be determined by the Senior Executives with the approval of the Committee.  The total paid for 2008 bonuses was $4.5 million.
 
GRANTS OF PLAN BASED AWARDS IN FISCAL YEAR 2008
 
The following tables show the non-equity incentive plan awards granted to the Other Executives for 2008 and the outstanding SARs and phantom units awards at December 31, 2008 that were issued to our Other Executives.  Information on rights granted to non-employee directors is included in the section entitled Director Compensation.  These tables do not include the phantom unit awards made to Mr. Benavides and Ms. Pape in February 2009 of 8,750 and 7,692, respectively.
 
 
Grants of Plan-Based Awards in Fiscal Year 2008
 
                             
                             
Name
 
Grant Date
 
All Other Stock Awards: Number of Shares of Stock or Units (#) (1)
   
Exercise or Base Price of Option Awards ($/Sh) (2)
   
Market Price of Common Units on Award Date (3)
   
Grant Date Fair Value of Stock and Option Awards
 
                             
Grant E. Sims
 
12/31/2008
                    $ 6,225,068 (4)
                               
                               
Joseph A. Blount, Jr.
 
12/31/2008
                    $ 5,356,454 (4)
                               
                               
Robert V. Deere
 
12/31/2008
                    $ 429,222 (4)
                               
                               
Ross A. Benavides
 
2/14/2008
    5,448     $ 20.92     $ 21.19     $ 22,031 (5)
                                     
                                     
Karen N. Pape
 
2/14/2008
    4,790     $ 20.92     $ 21.19     $ 19,370 (5)

 
(1)
The amounts in this column represent stock appreciation rights granted to the named Executive Officer during 2008.
(2)
We accrue for the fair value of our liability for the SARs we have issued to our employees and directors under the provisions of SFAS No. 123(R), Share-Based Payments, as amended and interpreted.  These provisions require us to make estimates that affect the determination of the fair value of the outstanding stock appreciation rights, including estimates of the expected life of the rights, expected forfeiture rates of the rights, expected future volatility of our unit price and expected future distribution yield on our units. We base our estimates of these factors on historical experience and internal data.  A summary of the assumptions used for the valuation at December 31, 2008 is included in Note 15 of the Notes to our Consolidated Financial Statements.  The actual timing and amounts of payments to employees that will ultimately be made under the SAR plan will most likely differ from the estimates that are used in determining fair value.  Since the value of our common units is affected more by actual cash distributions and Available Cash and expectations for growth of our business, which factors are not fully contemplated under the methodology of SFAS 123(R), our Committee does not consider the accounting method for the SAR plan in determining the amount of SARs to grant our employees.
(3)
For the awards granted on February 14, 2008, the exercise price represents the average of the closing market price of our units for the ten days preceding February 14, 2008.  The closing market price for our units on February 14, 2008 was $21.19.
(4)
Amount represents management’s estimate of the fair value of the Class B Membership award and deferred compensation award granted on December 31, 2008 to the NEO.  See a description of these awards at “The Class B Membership Interest in Our General Partner” above in “Compensation Discussion and Analysis.”  This fair value was estimated under the methodology of SFAS 123(R) and will be recorded as non-cash compensation expense during the four-year vesting period that begins in 2009.   Subsequent to the vesting period, the previously recorded compensation expense will be adjusted to fair value at each reporting date.
(5)
The amounts in this column represent the fair value of the award on the date of the grant, February 14, 2008, as calculated in accordance with the provisions of SFAS 123(R).
 
 
The compensation described in the table above for our Senior Executives is a result of finalizing their compensation arrangements (including the underlying documentation) in December 2008.  These arrangements are intended to incentivize our Senior Executives to create value for our common unitholders and general partnerby maintaining and increasing (over time) the distribution rate we pay to them.  Our Senior Executives, including Mr. Deere, will be rewarded based on whether the shares of the cash distributions attributable to our incentive distribution rights (or IDRs) increase, which is based upon the extent to which we increase Cash Available Before Reserves, or CABR (defined below) per unit and cash distributions.   CABR generally means Available Cash before Reserves, as defined in Item 7 – “Management’s Discussion and Analysis” above, less Available Cash before Reserves generated from specific transactions with our general partner and other Denbury affiliates.  These specific transactions include the Free State Pipeline, the NEJD Pipeline, and any future transactions.
 
In summary, each of our Senior Executives has received an equity interest in our general partner (Class B Membership Interest) and is entitled to receive a base salary and to participation in our customary fringe benefits, such as health, medical and severance benefits, with reimbursement of taxes for the effects of the receipt of the base salary and fringe benefits as a member in the general partner rather than as an employee.  Messrs. Sims and Blount also received awards under a deferred compensation plan.  The Class B Membership Interests awarded to our senior executives will be accounted for as liability awards under the provisions of SFAS 123(R).  As such, the fair value of the compensation cost we record for these awards will be recomputed at each measurement date and the expense to be recorded will be adjusted based on that fair value.  Management’s estimates of the fair value of these awards are based on assumptions regarding a number of future events, including estimates of the Available Cash before Reserves we will generate each quarter through the final vesting date of December 31, 2012, estimates of the future amount of incentive distributions we will pay to our general partner, and assumptions about appropriate discount rates.    Additionally the determination of fair value will be affected by the distribution yield of ten publicly-traded entities that are the general partners in publicly-traded master limited partnerships, a factor over which we have no control.  Included within the assumptions used to prepare these estimates are projections of available cash and distributions to our common unitholders and general partner, including an assumed level of growth and the effects of future new growth projects during the four-year vesting period.  At December 31, 2008, management estimates that the fair value of the Class B Membership Awards and the related deferred compensation awards granted to our Senior Executives on that date is approximately $12 million.  The fair value of these incentive awards will be recomputed each quarter beginning with the quarter ending March 31, 2009 through the final settlement of the awards.  Compensation expense of $3.4 million was recorded in the fourth quarter of 2007 related to the previous arrangements between our general partner and our Senior Executives. The fair value to be recorded by us as compensation expense will be the excess of the recomputed estimated fair value over the previously recorded $3.4 million.  Due to the vesting conditions for the awards, the amount to which the Senior Executives were entitled on December 31, 2008 for the Class B Membership Awards and the related deferred compensation was zero.  Management’s estimates of fair value are made in order to record non-cash compensation expense over the vesting period, and do not represent necessarily contractual amounts payable under these awards at December 31, 2008. This expense will be recorded on an accelerated basis to align with the requisite service period of the award.  Changes in our assumptions will change the amount of compensation cost we record.  Changes in these assumptions would not, however, affect our Available Cash before Reserves, as the cash cost of the Class B Membership Interests will be borne by Denbury.

OUTSTANDING EQUITY AWARDS AT 2008 FISCAL YEAR-END

The following table presents information regarding the outstanding equity awards to our Other Executives at December 31, 2008.
 

Outstanding Equity Awards at 2008 Fiscal Year-End
 
                                       
                                       
   
Stock Appreciation Rights
 
Stock Awards
 
Name
 
Number of Securities Underlying Stock Appreciation Rights (#) Exercisable
   
Number of Securities Underlying Unexercised Stock Appreciation Rights (#) Unexercisable (1)
   
Stock Appreciation Rights Exercise Price ($)
 
Stock Appreciation Rights Expiration Date
 
Number of Phantom Units That Have Not Vested (#) (2)
   
Market Value of Phantom Units That Have Not Vested ($)
   
Fair Value of Class B Membership Interests That Have Not Vested (3)
 
                                       
Grant E. Sims
                                  $ 6,225,068  
                                         
Joseph A. Blount, Jr.
                                  $ 5,356,454  
                                         
Robert V. Deere
                                  $ 429,222  
                                         
Ross A. Benavides
    15,889           $ 9.26  
12/31/2013
                   
              3,777     $ 12.48  
12/31/2014
                   
              4,015     $ 11.17  
12/31/2015
                   
              1,003     $ 16.95  
8/29/2016
                   
              5,270     $ 19.57  
12/29/2016
                   
              5,448     $ 20.92  
2/14/2018
                   
                                9,176     $ 79,739          
                                                   
                                                   
Karen N. Pape
    12,153             $ 9.26  
12/31/2013
                       
              2,889     $ 12.48  
12/31/2014
                       
              3,071     $ 11.17  
12/31/2015
                       
              767     $ 16.95  
8/29/2016
                       
              4,254     $ 19.57  
12/29/2016
                       
              4,790     $ 20.92  
2/14/2018
                       
                                8,156     $ 70,876          

 
(1)
The unexercisable rights of each named executive officer vest on the following dates in the order they are listed:  January 1, 2009, January 1, 2010, January 1, 2010, December 31, 2010 and February 14, 2012.
 
(2)
These phantom units vest on December 18, 2010.
 
(3)
Amount represents management’s estimate of the fair value of the Class B Membership award and deferred compensation award granted on December 31, 2008 to the NEO.  See a description of these awards at “The Class B Membership Interest in Our General Partner” above in “Compensation Discussion and Analysis.”  This fair value was estimated under the methodology of SFAS 123(R) and will be recorded as non-cash compensation expense during the four-year vesting period that begins in 2009.   Subsequent to the vesting period, the previously recorded compensation expense will be adjusted to fair value at each reporting date.


DIRECTOR COMPENSATION FOR FISCAL YEAR 2008
 
The table below reflects compensation for the directors. Directors who are employees of our general partner, like Mr. Sims, do not receive compensation for service as a director.  During 2008, compensation for the independent and Davison directors consisted of an annual fee of $40,000.  The Audit Committee Chairman received an additional annual fee of $10,000.  Audit Committee members received an additional annual fee of $2,500.  We paid Denbury fees totaling $160,000 for providing four of its executives as directors of Genesis.   Additionally, non-employee directors received a fee for attendance at meetings of $2,000 for each meeting attended in person and $1,000 for meetings attended telephonically.  This fee was applicable to meetings of the Board and committee meetings, however only one meeting fee could be earned per day.   Meeting fees for the four executives provided by Denbury as directors totaling $35,000 were paid to Denbury.
 
Director Compensation in Fiscal 2008
 
                         
                         
Name
 
Fees Earned or Paid in Cash ($) (1)
   
Stock Awards ($) (2)
   
Option Awards ($) (3)
   
Total
 
                         
Mark C. Allen (4)
  $ 50,000     $ 26,805     $ (9,692 )   $ 67,113  
                                 
David C. Baggett, Jr.
  $ 49,250     $ 26,805     $ -     $ 76,055  
                                 
James E. Davison
  $ 50,000     $ 26,805     $ 165     $ 76,970  
                                 
James E. Davison, Jr.
  $ 51,000     $ 26,805     $ 165     $ 77,970  
                                 
Ronald T. Evans (4)
  $ 50,000     $ 26,805     $ (34,691 )   $ 42,114  
                                 
Susan O. Rheney
  $ 73,000     $ 26,805     $ (45,964 )   $ 53,841  
                                 
Gareth Roberts (4)
  $ 45,000     $ 26,805     $ (34,691 )   $ 37,114  
                                 
Phil Rykhoek (4)
  $ 50,000     $ 26,805     $ (30,926 )   $ 45,879  
                                 
J. Conley Stone
  $ 60,250     $ 26,805     $ (24,354 )   $ 62,701  
                                 
Martin G. White
  $ 49,875     $ 26,805     $ -     $ 76,680  


(1)
Amounts include annual retainer fees and fees for attending meetings.
(2)
Amounts in this column represent the amounts, before consideration of expected forfeiture rate, that are included in the determination of net income for the period under the provisions of SFAS 123(R) for awards of phantom units under our 2007 LTIP.  The forfeiture rate that was applied to the phantom unit awards at December 31, 2008 was zero.  Each director received an award of 2,300 phantom units.  The grant date fair value of these awards was $20.12 per phantom unit.
(3)
Amounts in this column represent the amounts, before consideration of expected forfeiture rate, that are included in the determination of net income for the period under the provisions of SFAS123(R) for awards of stock appreciation rights.  The forfeiture rate that was applied to these stock appreciation rights at December 31, 2008 was ten percent.  Under our stock appreciation rights plan, the director will receive cash upon exercise of the right.  Because of the decline in our common unit market price and the effects of that decline on the fair value of outstanding stock appreciation rights, we recorded a reduction in the liability for most of these awards in 2008.  These reductions are reflected as negative amounts in the table above.
(4)
Fees were paid in cash for these directors to Denbury.  The phantom unit and stock appreciation rights awards are individual awards of the named director.


OUTSTANDING EQUITY AWARDS AT 2008 FISCAL YEAR END

The outstanding awards of stock appreciation rights to the directors of our general partner are shown in the table below.
 
Oustanding Equity Awards at 2008 Fiscal Year-End to Directors
 
                                 
   
Stock Appreciation Rights
 
Stock Awards
 
Name
 
Number of Securities Underlying Stock Appreciation Rights (#) Exercisable
   
Number of Securities Underlying Unexercised Stock Appreciation Rights (#) Unexercisable
   
Stock Appreciation Rights Exercise Price ($)
 
Stock Appreciation Rights Expiration Date
 
Number of Phantom Units That Have Not Vested (#) (1)
   
Market Value of Phantom Units That Have Not Vested ($) (2)
 
                                 
Mark C. Allen (3)
    1,288           $ 15.77  
9/29/2016
           
              1,000     $ 19.57  
12/29/2016
           
              1,000     $ 20.92  
2/14/2018
           
                                2,300       19,987  
                                           
David C. Baggett
                              2,300       19,987  
                                           
James E. Davison (4)
            1,000     $ 20.92  
2/14/2018
               
                                2,300       19,987  
                                           
James E. Davison, Jr. (4)
            1,000     $ 20.92  
2/14/2018
               
                                2,300       19,987  
                                           
Ronald T. Evans (5)
    2,576             $ 9.26  
12/31/2013
               
              612     $ 12.48  
12/31/2014
               
              651     $ 11.17  
12/31/2015
               
              1,000     $ 19.57  
12/29/2016
               
              1,000     $ 20.92  
2/14/2018
               
                                2,300       19,987  
                                           
Susan O. Rheney (5)
    3,435             $ 9.26  
12/31/2013
               
              816     $ 12.48  
12/31/2014
               
              868     $ 11.17  
12/31/2015
               
              1,000     $ 19.57  
12/29/2016
               
              1,000     $ 20.92  
2/14/2018
               
                                2,300       19,987  
                                           
Gareth Roberts (5)
    2,576             $ 9.26  
12/31/2013
               
              612     $ 12.48  
12/31/2014
               
              651     $ 11.17  
12/31/2015
               
              1,000     $ 19.57  
12/29/2016
               
              1,000     $ 20.92  
2/14/2018
               
                                2,300       19,987  
                                           
Phil Rykhoek (5)
    2,576             $ 11.00  
8/25/2014
               
              612     $ 12.48  
12/31/2014
               
              651     $ 11.17  
12/31/2015
               
              1,000     $ 19.57  
12/29/2016
               
              1,000     $ 20.92  
2/14/2018
               
                                2,300       19,987  
                                           
J. Conley Stone (5)
    773             $ 9.26  
12/31/2013
               
              735     $ 12.48  
12/31/2014
               
              781     $ 11.17  
12/31/2015
               
              1,000     $ 19.57  
12/29/2016
               
              1,000     $ 20.92  
2/14/2018
               
                                2,300       19,987  
                                           
Martin G. White
                              2,300       19,987  


(1)
These phantom units vest on June 3, 2009.
(2)
The market value of the phantom units that have not vested was determined by multiplying the number of phantom units by the closing price of our common units on December 31, 2008 of $8.69.
(3)
Mr. Allen’s first stock appreciation rights award will vest one-fourth annually beginning September 29, 2007 through September 29, 2010.  Mr. Allen’s remaining unexercisable stock appreciation rights will vest on January 1, 2011 and February 14, 2012.
(4)
The unexercisable stock appreciation rights of this director vest on February 14, 2012.
(5)
The unexercisable stock appreciation rights of this director vest on the following dates in the order they are listed:  January 1, 2009, January 1, 2010, January 1, 2011 and February 14, 2012.

 
Compensation Committee Interlocks and Insider Participation
 
None of the members of the Compensation Committee has at any time been an officer or employee of our general partner or us.  None of our executive officers serves, or in the past year has served, as a member of the board of directors or compensation committee of any entity that has one or more of its executive officers serving on our Compensation Committee.
 

Item 12.  Security Owner ship of Certain Beneficial Owners and Management and Related Stockholder Matters
 
Securities Authorized for Issuance Under Equity Compensation Plans
 
See Item 5 – Equity Compensation Plans.
 
Beneficial Ownership of Partnership Units
 
The following table sets forth certain information as of February 28, 2009, 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 and Address of Beneficial Owner
 
Number of Units
   
of Class
 
               
Genesis Energy, L.P.
Genesis Energy, LLC
    2,829,055       7.2  
    Common Units
Gareth Roberts (1)
    12,300       *  
 
Grant E. Sims (2)
    6,000       *  
 
Mark C. Allen (1)
    7,300       *  
 
David C. Baggett, Jr. (1)
    2,300       *  
 
James E. Davison (1) (3) (4)
    2,877,838       7.3  
 
James E. Davison, Jr. (1) (5)
    3,157,067       8.0  
 
Ronald T. Evans (1)
    15,300       *  
 
Susan O. Rheney (1)
    3,000       *  
 
Phil Rykhoek (1)
    12,300       *  
 
J. Conley Stone (1)
    4,300       *  
 
Martin G. White (1)
    4,400       *  
 
Ross A. Benavides (6)
    18,459       *  
 
Karen N. Pape (7)
    11,542       *  
                   
 
All directors and executive
               
 
officers as a group (13 in total)
    6,132,106       15.5  
                   
 
Denbury Onshore LLC (8)
               
 
5100 Tennyson Parkway
    1,199,041       3.0  
 
Plano, Texas 75024
               
                   
 
Todd A. Davison (9)
    2,875,537       7.3  
 
Steven K. Davison (10)
    2,875,537       7.3  
 
Terminal Service, Inc. (11)
    1,010,835       2.6  
                   
 
Swank Capital, LLC, Swank
               
 
Energy Income Advisors,
               
 
L.P. and Mr. Jerry V. Swank (12)
    2,871,087       7.3  
 
3300 Oak Lawn Ave., Suite 650
               
 
Dallas, Texas 75219
               
                   
 
Neuberger Berman, Inc. (13)
    2,181,894       5.5  
 
605 Third Avenue
               
 
New York, NY 10158
               
 
 
(1)
Number of units includes phantom units for which the holder has the right to receive 2,300 common units upon vesting on June 3, 2009.
 
(2)
1,000 of these common units are held by Mr. Sims’ father.  Mr. Sims disclaims beneficial ownership of these units.
 
(3)
James E. Davison is the sole stockholder of Davison Terminal Service, Inc., which directly owns 1,010,835 units.


(4)
We have been granted a lien on 1,327,007 of these units to secure the Davison unitholders indemnification obligations to us under the terms of our acquisition of the Davison businesses.
 
(5)
We have been granted a lien on 1,352,226 of these units to secure the Davison unitholders indemnification obligations to us under the terms of our acquisition of the Davison businesses.
 
(6)
Includes 9,176 phantom units which will vest on December 18, 2010.
 
(7)
Includes 8,156 phantom units which will vest on December 18, 2010.
 
(8)
Denbury Onshore, LLC is an affiliate of our general partner and a wholly-owned subsidiary of Denbury.
 
(9)
Todd A. Davison is the son of James E. Davison and the brother of James E. Davison, Jr., and an employee of our general partner.  The mailing address for Mr. Davison is 2000 Farmerville Hwy., Ruston, LA 71270.   We have been granted a lien on 1,352,226 of these units to secure the Davison unitholders indemnification obligations to us under the terms of our acquisition of the Davison businesses.
 
(10)
Steven K. Davison is the son of James E. Davison and the brother of James E. Davison, Jr. and Todd A. Davison, and an employee of our general partner.  The mailing address for Mr. Davison is 207 W.   Alabama, Ruston, LA 71270.  We have been granted a lien on 1,352,226 of these units to secure the Davison unitholders indemnification obligations to us under the terms of our acquisition of the Davison businesses.
 
(11)
This entity is owned by James E. Davison.  It was formerly known as Davison Terminal Service, Inc.  The mailing address of this entity is PO Box 607, Ruston, LA 71273.
 
(12)
Information based on Schedule 13G filed with the SEC on February 17, 2009.  Swank Capital, LLC and Mr. Jerry V. Swank claim sole voting and dispositive powers over these units.  Swank Energy Income Advisors, L.P. claims shared voting and dispositive powers over these units.
 
(13)
Information based on Schedule 13G filed with the SEC on February 12, 2009.
 
Except as noted, each unitholder in the above table is believed to have sole voting and investment power with respect to the units beneficially held, subject to applicable community property laws.
 
The mailing address for Genesis Energy, LLC and all officers and directors is 919 Milam, Suite 2100, Houston, Texas, 77002.
 
Beneficial Ownership of General Partner Interest
 
Genesis Energy, LLC owns all of our 2% general partner interest and all of our incentive distribution rights, in addition to 7.2% of our units.  Genesis Energy, LLC is a majority-owned subsidiary of Denbury.  Denbury has advised us that it has not pledged any of its interest in our general partner under any agreements or arrangements.
 
Item 13.  Certain R elation ships and Related Transactions, and Director Independence
 
Our General Partner
 
Our operations are managed by, and our employees are employed by, Genesis Energy, LLC, 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 2008, these reimbursements totaled $51.9 million.  As of December 31, 2008, we owed our general partner $2.1 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 to our common unitholders in excess of $0.25 per unit, 23.5% of the amounts we distribute to our common unitholders in excess of $0.28 per unit, and 49% of the amounts we distribute to our common unitholders in excess of $0.33 per unit.  See Item 11. Executive Compensation for information regarding our Senior Executives interest in the incentive distribution rights owned by our general partner.
 
Our general partner also owns 2,829,055 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 2008, our general partner received a total of $6.5 million from us as distributions, with $3.5 million attributable to its limited partner units, $1.0 million for its general partner interest, and $2.0 million related to its incentive distribution rights.
 
Relationship with Denbury Resources, Inc.
 
Historically, we have entered into transactions with Denbury and its subsidiaries to acquire assets from time to time.  We have instituted specific procedures for evaluating and valuing our material transactions with Denbury and its subsidiaries.  Before we consider entering into a material 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, (3) would comply with our partnership agreement, and (4) would be fair to us and our limited partners.  In addition, our general partner’s board of directors may seek “Special Approval” (as defined in our partnership agreement) from our Audit Committee, which is comprised solely of independent directors.  That committee:
 
 
·
evaluates and, where appropriate, negotiates the proposed transaction;
 
 
·
engages an independent legal counsel and, if it deems appropriate, an independent financial advisor to assist with its evaluation of the proposed transaction; and
 
 
·
determines whether to reject or approve and recommend the proposed transaction.
 
Traditionally, we have consummated proposed material acquisitions or dispositions with Denbury only when we have evaluated the transaction, our Audit Committee has approved and recommended the transaction and our general partner’s full board has approved the transaction, however, such approvals are not required under our partnership agreement.
 
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.  In May 2008, we completed two transactions with Denbury involving CO 2 pipelines.  We acquired the Free State CO 2 pipeline for $75 million, comprised of $50 million of cash and $25 million of our common units.  These common units are owned by Denbury Onshore LLC, a wholly-owned subsidiary of Denbury and an affiliate of our general partner.  Additionally, we entered into a twenty-year financing lease transaction with Denbury valued at $175 million related to Denbury’s NEJD Pipeline System.
 
Additionally we enter into transactions with Denbury in the ordinary course of our operations.  During 2008, these transactions included:
 
 
·
Provision of transportation services for crude oil by truck totaling $3.6 million.
 
·
Provision of crude oil pipeline transportation services totaling $10.7 million.
 
·
Provision of CO 2 and crude oil pipeline transportation services under lease arrangements for which we received payments totaling $11.5 million.
 
·
Provision of CO 2 transportation services to our wholesale industrial customers by Denbury’s pipeline.  The fees for this service totaled $6.4 million in 2008.
 
·
Provision of pipeline monitoring services to Denbury for its CO 2 pipelines totaling $120,000 in 2008.
 
·
Provision of services by Denbury officers as directors of our general partner.  We paid Denbury $195,000 for these services in 2007.
 
At December 31, 2008, we owed Denbury $1.0 million for provision of CO 2 transportation services.  Denbury owed us $2.0 million for crude oil trucking and pipeline transportation services.
 
Our partnership agreement provides that, with the approval of at least a majority of our limited partners, our general partner also may be removed without cause.  Any limited partner interests held by our general partner and its affiliates would be excluded from such a vote.  If it is proposed that the removal is without cause and an affiliate of Denbury is 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.  Additionally, in the event our general partner is removed by our common unitholders without the approval of Denbury, Denbury has the option to prepay its obligation under the NEJD Pipeline lease.


Relationship with Davison family
 
We have entered into an aircraft interchange agreement with the Davison family where each party will make available to the other party its aircraft on an as-available basis, in exchange for equal flight-time on the other party’s aircraft any appropriate difference between the cost of owning, operating, and maintaining the aircraft.  The estimated value of the equal flight-time owed to the Davison family at December 31, 2008 was approximately $16,000.
 
In connection with the terms of our acquisition of the Davison businesses, the Davison unitholders have registration rights with respect to their units.
 
These rights include the following provisions:
 
 
·
the right to require us to file a shelf registration statement, which we filed in 2008;
 
·
the right to demand five registrations of their units, one per calendar year, and piggyback rights for other unit registrations; and
 
·
the Davison unitholders have agreed to specified restrictions on the sale and transfer of the units they received in consideration of this acquisition.  The Davison unitholders cannot sell any of the units issued as consideration except that portion provided below (subject to certain exceptions):

At closing (July 25, 2007)
    20 %
At July 25, 2008
    20 %
At January 25, 2009
    20 %
At July 25, 2009
    30 %
At July 25, 2010
    10 %
      100 %

 
Pursuant to a unitholder agreement between the Davison unitholders and us, executed on July 25, 2007, the Davison unitholders have the right to designate up to two directors to our board of directors, depending on their continued level of ownership in us.  Until July 25, 2010, the Davison unitholders have the right to designate two directors to our board of directors.  Thereafter, the Davison unitholders will have the right to designate (i) one director if they beneficially own at least 10% but less than 35% of our outstanding common units, or (ii) two directors if they beneficially own 35% or more of our outstanding common units.  If their percentage ownership in our common units drops below 10% after July 25, 2010, the Davison unitholders would have no rights to designate directors.  At December 31, 2008, the Davison unitholders held approximately 30% of our outstanding common units.
 
On July 25, 2007, the Davison unitholders designated James E. Davison and James E. Davison, Jr. as directors to the Board of Directors of our general partner.
 
To secure their indemnification obligations under the agreement with us for the acquisition of their businesses, the Davison unitholders have granted to us a lien on 5,383,684 units, or 40% of the units they received as consideration.  On July 24, 2009, 4,037,763 of these units will be released, with the remaining 1,345,921 units released on July 26, 2010.
 
Our joint venture partner in DG Marine is TD Marine, LLC, an entity owned by James E. Davison and two of his sons.    Additionally, Community Trust Bank is a 17% participant in the DG Marine credit facility.  Davison family members own approximately 14% of Community Trust Bank, and James E. Davison, Jr. serves on the board of the holding company that owns Community Trust Bank.
 
During 2008, we sold $1.3 million of petroleum products to businesses owned and operated by members of the Davison family in the ordinary course of our operations.
 
Director Independence
 
Susan O. Rheney, David C. Baggett and Martin G. White, all members of our Audit Committee, meet the listing standard requirements of NYSE Alternext US, and the SEC rules to be considered independent directors of Genesis.  Additionally, J. Conley Stone also meets the requirements to be considered an independent director.  The term “independent director” means a person other than an officer or employee of our general partner, the Partnership or its subsidiaries, or Denbury or its subsidiaries, or any other individual having a relationship that, in the opinion of the Board of Directors, would interfere with the exercise of independent judgment in carrying out the responsibilities of a director.  To be considered independent, neither the director nor an immediate family member of the director has had any direct or indirect material relationship with Genesis.


The independent directors meet regularly in executive sessions outside of the presence of the non-independent directors or members of our management after each of the regularly scheduled quarterly Audit Committee meetings.  See additional discussion of director independence at Item 10. Directors, Executive Officers and Corporate Governance – Management of Genesis Energy, L.P .
 
Item 14.  Principal Acc ounting Fees and Services
 
The following table summarizes the fees for professional services rendered by Deloitte & Touche LLP for the years ended December 31, 2008 and 2007.
 
   
2008
   
2007
 
   
(in thousands)
 
Audit Fees (1)
  $ 3,634     $ 3,107  
Audit-Related Fees (2)
    296       1,945  
Tax Fees (3)
    368       165  
All Other Fees (4)
    3       2  
Total
  $ 4,301     $ 5,219  
 
 
 
(1)
Includes fees for the annual audit and quarterly reviews (including internal control evaluation and reporting), SEC registration statements and accounting and financial reporting consultations and research work regarding Generally Accepted Accounting Principles.  Also includes audits of our general partner and separate audits of certain of our consolidated subsidiaries and joint ventures.
 
(2)
Includes fees for the audit of our employee benefit plan and assistance in the documentation of internal controls over financial reporting.  Also includes fees for audits of acquired businesses.
 
(3)
Includes fees for tax return preparation and tax consultations.
 
(4)
Includes fees associated with licenses for accounting research software.

 
Pre-Approval Policy
 
The services by Deloitte in 2008 and 2007 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 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.
 
In considering the nature of the non-audit services provided by Deloitte in 2008 and 2007, 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.
 
Item 15.  Exh ibits and Financial Statement Schedules
 
(a)(1) Financial Statements
 
 See “Index to Consolidated Financial Statements and Financial Statement Schedules” set forth on page 97.
 
(a)(2)  Financial Statement Schedules
 
See “Index to Consolidated Financial Statements and Financial Statement Schedules” set forth on page 97.

(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 to Form 8-K dated June 15, 2005)
       
 
3.3
 
Amendment No. 1 to Fourth Amended and Restated Agreement of Limited Partnership of Genesis  (incorporated by reference to Exhibit 3.3 to Form 10-K dated December 31, 2007)
       
 
3.4
 
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)
       
 
3.5
 
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)
       
 
3.6
 
Certificate of Conversion of Genesis Energy, Inc., a Delaware corporation, into Genesis Energy, LLC, a Delaware limited liability company (incorporated by reference to Exhibit 3.1 to Form 8-K dated January 7, 2009)
       
 
3.7
 
Certificate of Formation of Genesis Energy, LLC  (incorporated by reference to Exhibit 3.1 to Form 8-K dated January 7, 2009)
       
 
3.8
 
Limited Liability Company Agreement of Genesis Energy, LLC dated December 29, 2008  (incorporated by reference to Exhibit 3.1 to Form 8-K dated January 7, 2009)
       
 
3.9
 
First Amendment to Limited Liability Company Agreement of Genesis Energy, LLC dated December 31, 2008  (incorporated by reference to Exhibit 3.1 to Form 8-K dated January 7, 2009)
     
 
 
4.1
 
Form of Unit Certificate of Genesis Energy, L.P.  (incorporated by reference to Exhibit 4.1 to Form 10-K dated December 31, 2007)
       
 
10.1
 
First Amended and Restated Credit Agreement dated as of May 30, 2008 among Genesis Crude Oil, L.P., Genesis Energy, L.P., the Lenders Party Hereto, Fortis Capital Corp., and Deutsche Bank Securities Inc. (incorporated by reference to Exhibit 10.4 to Form 8-K dated June 5, 2008)
     
 
 
10.2
 
First Amendment to First Amended and Restated Credit Agreement, dated as of July 18, 2008, among Genesis Crude Oil, L.P., Genesis Energy, L.P., the lenders party thereto, Fortis Capital Corp. and Deutsche Bank Securities Inc. (incorporated by reference to Exhibit 10.3 to Form 8-K dated July 22, 2008)
       
*
 
Production Payment Purchase and Sale Agreement between Denbury Resources, Inc. and Genesis Crude Oil, L.P.
       
*
 
Carbon Dioxide Transportation Agreement between Denbury Resources, Inc. and Genesis Crude Oil, L.P.
       
 
10.5
 
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)
       
 
10.6
 
Second Carbon Dioxide Transportation Agreement between Denbury Onshore, LLC and Genesis Crude Oil, L.P. (incorporated by reference to Exhibit 99.2 to Form 8-K dated August 24, 2004)
       
 
10.7
 
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)

 
 
10.8
 
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)
     
 
 
10.9
 
Contribution and Sale Agreement by and among Davison Petroleum Products, L.L.C., Davison Transport, Inc., Transport Company, Davison Terminal Service, Inc., Sunshine Oil & Storage, Inc., T&T Chemical, Inc. Fuel Masters, LLC, TDC, L.L.C. and Red River Terminals, L.L.C. dated April 25, 2007 (incorporated by reference to Exhibit 10.1 to Form 8-K dated July 31, 2007)
     
 
 
10.10
 
Amendment No. 1 to the Contribution and Sale Agreement dated July 25, 2007 (incorporated by reference to Exhibit 10.2 to Form 8-K dated July 31, 2007)
       
 
10.11
 
Amendment No. 2 to the Contribution and Sale Agreement dated October 15, 2007 (incorporated by reference to Exhibit 10.1 to Form 8-K dated October 19, 2007)
       
 
10.12
 
Amendment No. 3 to the Contribution and Sale Agreement dated March 3, 2008  (incorporated by reference to Exhibit 10.21 to Form 10-K dated December 31, 2007)
       
 
10.13
 
Registration Rights Agreement (incorporated by reference to Exhibit 10.3 to Form 8-K dated July 31, 2007)
       
 
10.14
 
Amendment No. 1 to the Registration Rights Agreement dated November 16, 2007 (incorporated by reference to Exhibit 10.1 to Form 8-K dated November 16, 2007)
       
 
10.15
 
Amendment No. 2 to the Registration Rights Agreement dated December 6, 2007 (incorporated by reference to Exhibit 10.1 to Form 8-K dated December 12, 2007)
       
 
10.16
 
Unitholder Rights Agreement (incorporated by reference to Exhibit 10.4 to Form 8-K dated July 31, 2007)
       
 
10.17
 
Amendment No. 1 to the Unitholder Rights Agreement dated October 15, 2007 (incorporated by reference to Exhibit 10.2 to Form 8-K dated October 19, 2007)
       
 
10.18
 
Pledge and Security Agreement (incorporated by reference to Exhibit 10.5 to Form 8-K dated July 31, 2007)
       
 
10.19
 
Pipeline Financing Lease Agreement by and between Genesis NEJD Pipeline, LLC, as Lessor and Denbury Onshore, LLC, as Lessee for the North East Jackson Dome Pipeline dated May 30, 2008 (incorporated by reference to Exhibit 10.1 to Form 8-K dated June 5, 2008)
     
 
 
10.20
 
Purchase and Sale Agreement between Denbury Onshore, LLC and Genesis Free State Pipeline, LLC dated May 30, 2008 (incorporated by reference to Exhibit 10.2 to Form 8-K dated June 5, 2008)
       
 
10.21
 
Transportation Services Agreement between Genesis Free State Pipeline, LLC and Denbury Onshore, LLC dated May 30, 2008 (incorporated by reference to Exhibit 10.3 to Form 8-K dated June 5, 2008)
     
 
 
10.22
 
Contribution and Sale Agreement by and Among Grifco Transportation, Ltd., Grifco Transportation Two, Ltd., and Shore Thing, Ltd. and Genesis Marine Investments, LLC and Genesis Energy, L.P. and TD Marine, LLC (incorporated by reference to Exhibit 10.1 to Form 8-K dated July 22, 2008)
       
 
10.23
 
Omnibus Agreement dated as of June 11, 2008 by and among TD Marine, LLC, James E. Davison, Steven K. Davison, Todd A Davison and Genesis Energy, L.P. (incorporated by reference to Exhibit 10.1 to Form 8-K dated July 22, 2008)
       
*
+
Genesis Energy, LLC First Amended and Restated Stock Appreciation Rights Plan
       
*
+
Form of Stock Appreciation Rights Plan Grant Notice
       
 
10.26
+
Genesis Energy, LLC Amended and Restated Severance Protection Plan (incorporated by reference to Exhibit 10.1 to Form 8-K dated December 12, 2006)
       
*
+
Amendment to the Genesis Energy Severance Protection Plan

 
 
10.28
+
Genesis Energy, Inc. 2007 Long Term Incentive Plan (incorporated by reference to Exhibit 10.1 to Form 8-K dated December 21, 2007)
       
 
10.29
+
Form of 2007 Phantom Unit Grant Agreement (3-Year Graded) (incorporated by reference to Exhibit 10.2 to Form 8-K dated December 21, 2007)
       
 
10.30
+
Form of 2007 Phantom Unit Grant Agreement (3-Year Cliff) (incorporated by reference to Exhibit 10.3 to Form 8-K dated December 21, 2007)
       
 
10.31
+
Employment Agreement by and between Genesis Energy, LLC and Grant E. Sims, dated December 31, 2008 (incorporated by reference to Exhibit 10.1 to Form 8-K dated January 7, 2009)
       
 
10.32
+
Employment Agreement by and between Genesis Energy, LLC and Joseph A. Blount, Jr., dated December 31, 2008  (incorporated by reference to Exhibit 10.2 to Form 8-K dated January 7, 2009)
       
 
10.33
+
Employment Agreement by and between Genesis Energy, LLC and Robert V. Deere, dated December 31, 2008 (incorporated by reference to Exhibit 10.3 to Form 8-K dated January 7, 2009)
       
 
10.34
+
Genesis Energy, LLC Deferred Compensation Plan, effective December 31, 2008 (incorporated by reference to Exhibit 10.4 to Form 8-K dated January 7, 2009)
       
 
10.35
+
Genesis Energy, LLC Award – Individual Class B Interest for Grant E. Sims dated December 31, 2009 (incorporated by reference to Exhibit 10.5 to Form 8-K dated January 7, 2009)
       
 
10.36
+
Genesis Energy, LLC Award – Individual Class B Interest for Joseph A. Blount, Jr. dated December 31, 2009 (incorporated by reference to Exhibit 10.6 to Form 8-K dated January 7, 2009)
       
 
10.37
+
Genesis Energy, LLC Award – Individual Class B Interest for Robert V. Deere dated December 31, 2009 (incorporated by reference to Exhibit 10.7 to Form 8-K dated January 7, 2009)
       
 
10.38
+
Deferred Compensation Grant – Genesis Energy, LLC – Grant E. Sims (incorporated by reference to Exhibit 10.8 to Form 8-K dated January 7, 2009)
       
 
10.39
+
Deferred Compensation Grant – Genesis Energy, LLC – Joseph A. Blount, Jr. (incorporated by reference to Exhibit 10.9 to Form 8-K dated January 7, 2009)
       
 
11.1
 
Statement Regarding Computation of Per Share Earnings (See Notes 2 and 11 to the Consolidated Financial Statements
       
*
 
Subsidiaries of the Registrant
       
*
 
Consent of  Deloitte & Touche LLP
       
*
 
Certification by Chief Executive Officer Pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934
       
*
 
Certification by Chief Financial Officer Pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934
       
*
 
Certification by Chief Executive Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
       
*
 
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.
 
   
GENESIS ENERGY, L.P.
(A Delaware Limited Partnership)
 
By:
GENESIS ENERGY, LLC,
as        General Partner
Date: March 16, 2009
By:
   /s/   Grant E. Sims                                            
   
Grant E. Sims
Chief Executive Officer

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.

 
NAME
 
TITLE
 
DATE
     
(OF GENESIS ENERGY, LLC)*
   
           
/s/
Grant E. Sims
 
Director and Chief Executive Officer
 
March 16, 2009
 
Grant E. Sims
 
(Principal Executive Officer
   
           
/s/
Robert V. Deere
 
Chief Financial Officer,
 
March 16, 2009
 
Robert V. Deere
 
(Principal Financial Officer)
   
           
/s/
Karen N. Pape
 
Senior Vice President and Controller
 
March 16, 2009
 
Karen N. Pape
 
(Principal Accounting Officer)
   
           
/s/
Gareth Roberts
 
Chairman of the Board and
 
March 16, 2009
 
Gareth Roberts
 
Director
   
           
/s/
Mark C. Allen
 
Director
 
March 16, 2009
 
Mark C. Allen
       
           
/s/
David C. Baggett, Jr.
 
Director
 
March 16, 2009
 
David C. Baggett, Jr.
       
           
/s/
James E. Davison
 
Director
 
March 16, 2009
 
James E. Davison
       
           
/s/
James E. Davison, Jr.
 
Director
 
March 16, 2009
 
James E. Davison, Jr.
       
           
/s/
Ronald T. Evans
 
Director
 
March 16, 2009
 
Ronald T. Evans
       
           
/s/
Susan O. Rheney
 
Director
 
March 16, 2009
 
Susan O. Rheney
       
           
/s/
Phil Rykhoek
 
Director
 
March 16, 2009
 
Phil Rykhoek
       
           
/s/
J. Conley Stone
 
Director
 
March 16, 2009
 
J. Conley Stone
       
           
/s/
Martin G. White
 
Director
 
March 16, 2009
 
Martin G. White
       

*Genesis Energy, LLC is our general partner.


GENESIS ENERGY, L.P.
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
AND FINANCIAL STATEMENT SCHEDULES



 
Page
Financial Statements
 
   
Report of Independent Registered Public Accounting Firm
98
   
Consolidated Balance Sheets, December 31, 2008 and 2007
99
   
Consolidated Statements of Operations for the Years Ended December 31, 2008, 2007 and 2006
100
   
Consolidated Statements of Comprehensive Income (Loss) for the Years Ended December 31, 2008, 2007 and 2006
101
   
Consolidated Statements of Partners’ Capital for the Years Ended December 31, 2008, 2007 and 2006
102
   
Consolidated Statements of Cash Flows for the Years Ended December 31, 2008, 2007 and 2006
103
   
Notes to Consolidated Financial Statements
104
   
Financial Statement Schedules
 
   
Schedule I – Condensed Financial Information (Parent Company Only)
144

 

All other financial statement schedules have been omitted because they are not applicable or the required information is presented in the consolidated financial statements or the notes to the consolidated financial statements.
 
 
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
 
 
To the Board of Directors of Genesis Energy, LLC 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, 2008 and 2007, 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, 2008.  Our audits also included the financial statement schedule listed in the Index at Item 15.  These financial statements and financial statement schedule are the responsibility of the Partnership's management.  Our responsibility is to express an opinion on the financial statements and financial statement schedule 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, 2008 and 2007, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2008, in conformity with accounting principles generally accepted in the United States of America.  Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.
 
As described in Note 2 to the consolidated financial statements and effective as of January 1, 2008, the Partnership adopted Statement of Financial Accounting Standards (“SFAS”) No. 157, which established new accounting and reporting standards for fair value measurements of certain financial assets and liabilities.
 
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Partnership's internal control over financial reporting as of December 31, 2008, 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 11, 2009 expressed an unqualified opinion on the Partnership's internal control over financial reporting.
 
 
/s/ Deloitte & Touche LLP
DELOITTE & TOUCHE LLP
 
Houston, Texas
March 11, 2009
 
 
GENESIS ENERGY, L.P.
 
CONSOLIDATED BALANCE SHEETS
 
(In thousands)
 
             
   
December 31,
   
December 31,
 
   
2008
   
2007
 
             
ASSETS
           
CURRENT ASSETS:
           
Cash and cash equivalents
  $ 18,985     $ 11,851  
Accounts receivable - trade, net of allowance for doubtful accounts of $1,132 at December 31, 2008
    112,229       178,658  
Accounts receivable - related party
    2,875       1,441  
Inventories
    21,544       15,988  
Net investment in direct financing leases, net of unearned income -current portion - related party
    3,758       609  
Other
    8,736       5,693  
Total current assets
    168,127       214,240  
                 
FIXED ASSETS, at cost
    349,212       150,413  
Less:  Accumulated depreciation
    (67,107 )     (48,413 )
Net fixed assets
    282,105       102,000  
                 
NET INVESTMENT IN DIRECT FINANCING LEASES, net of unearned income - related party
    177,203       4,764  
CO 2 ASSETS, net of amortization
    24,379       28,916  
EQUITY INVESTEES AND OTHER INVESTMENTS
    19,468       18,448  
INTANGIBLE ASSETS, net of amortization
    166,933       211,050  
GOODWILL
    325,046       320,708  
OTHER ASSETS, net of amortization
    15,413       8,397  
                 
TOTAL ASSETS
  $ 1,178,674     $ 908,523  
                 
LIABILITIES AND PARTNERS' CAPITAL
               
CURRENT LIABILITIES:
               
Accounts payable - trade
  $ 96,454     $ 154,614  
Accounts payable - related party
    3,105       2,647  
Accrued liabilities
    26,713       17,537  
Total current liabilities
    126,272       174,798  
                 
LONG-TERM DEBT
    375,300       80,000  
DEFERRED TAX LIABILITIES
    16,806       20,087  
OTHER LONG-TERM LIABILITIES
    2,834       1,264  
MINORITY INTERESTS
    24,804       570  
COMMITMENTS AND CONTINGENCIES (Note 19)
               
                 
PARTNERS' CAPITAL:
               
Common unitholders, 39,457 and 38,253 units issued and outstanding at December 31, 2008 and 2007, respectively
    616,971       615,265  
General partner
    16,649       16,539  
Accumulated other comprehensive loss
    (962 )     -  
Total partners' capital
    632,658       631,804  
                 
TOTAL LIABILITIES AND PAR T NERS' CAPITAL
  $ 1,178,674     $ 908,523  

The accompanying notes are an integral part of these consolidated financial statements.
 
99

GENESIS ENERGY, L.P.
 
CONSOLIDATED STATEMENTS OF OPERATIONS
 
(In thousands, except per unit amounts)
 
                   
   
Year Ended December 31,
 
   
2008
   
2007
   
2006
 
REVENUES:
                 
Supply and logistics:
                 
Unrelated parties (including revenues from buy/sell arrangements of $69,772 in 2006)
  $ 1,847,575     $ 1,092,398     $ 872,443  
Related parties
    4,839       1,791       825  
Refinery services
    225,374       62,095       -  
Pipeline transportation, including natural gas sales:
                       
Transportation services - unrelated parties
    19,469       17,153       17,119  
Transportation services - related parties
    21,730       5,754       4,948  
Natural gas sales revenues
    5,048       4,304       7,880  
CO 2 marketing:
                       
Unrelated parties
    15,423       13,376       13,098  
Related parties
    2,226       2,782       2,056  
Total revenues
    2,141,684       1,199,653       918,369  
COSTS AND EXPENSES:
                       
Supply and logistics costs:
                       
Product costs - unrelated parties (including costs from buy/sell arrangements of $68,899 in 2006)
    1,736,637       1,041,637       850,106  
Product costs - related parties
    -       101       1,565  
Operating costs
    78,453       37,121       14,231  
Refinery services operating costs
    166,096       40,197       -  
Pipeline transportation costs:
                       
Pipeline transportation operating costs
    10,306       10,054       9,928  
Natural gas purchases
    4,918       4,122       7,593  
CO 2 marketing costs:
                       
Transportation costs - related party
    6,424       5,213       4,640  
Other costs
    60       152       202  
General and administrative
    29,500       25,920       13,573  
Depreciation and amortization
    71,370       38,747       7,963  
Net loss (gain) on disposal of surplus assets
    29       266       (16 )
Impairment expense
    -       1,498       -  
Total costs and expenses
    2,103,793       1,205,028       909,785  
OPERATING INCOME (LOSS)
    37,891       (5,375 )     8,584  
Equity in earnings of joint ventures
    509       1,270       1,131  
Interest income
    458       385       198  
Interest expense
    (13,395 )     (10,485 )     (1,572 )
Income (loss) before income taxes and minority interest
    25,463       (14,205 )     8,341  
Income tax benefit
    362       654       11  
Minority interest
    264       1       (1 )
Income (loss) before cumulative effect adjustment
    26,089       (13,550 )     8,351  
Cumulative effect adjustment of adoption of new accounting principle
    -       -       30  
NET INCOME (LOSS)
  $ 26,089     $ (13,550 )   $ 8,381  
 
100

GENESIS ENERGY, L.P.
 
CONSOLIDATED STATEMENTS OF OPERATIONS - CONTINUED
 
(In thousands, except per unit amounts)
 
                   
   
Year Ended December 31,
 
   
2008
   
2007
   
2006
 
                   
NET INCOME (LOSS) PER COMMON UNIT:
                 
BASIC
  $ 0.61     $ (0.64 )   $ 0.59  
DILUTED
  $ 0.60     $ (0.64 )   $ 0.59  
                         
OUTSTANDING COMMON UNITS:
                       
BASIC
    38,961       20,754       13,784  
DILUTED
    39,025       20,754       13,784  
                         
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,
 
   
2008
   
2007
   
2006
 
                   
Net income (loss)
  $ 26,089     $ (13,550 )   $ 8,381  
Interest rate swap loss
    (962 )     -       -  
Comprehensive income (loss)
  $ 25,127     $ (13,550 )   $ 8,381  
                         
The accompanying notes are an integral part of these consolidated financial statements.
 
 
101

GENESIS ENERGY, L.P.
 
CONSOLIDATED STATEMENTS OF PARTNERS' CAPITAL
 
(In thousands)
 
                               
   
Partners' Capital
 
                     
Accumulated
       
   
Number of
               
Other
       
   
Common
   
Common
   
General
   
Comprehensive
       
   
Units
   
Unitholders
   
Partner
   
Loss
   
Total
 
                               
Partners' capital, January 1, 2006
    13,784     $ 85,870     $ 1,819     $ -     $ 87,689  
Net income
    -       8,214       167       -       8,381  
Cash distributions
    -       (10,200 )     (208 )     -       (10,408 )
Partners' capital, December 31, 2006
    13,784       83,884       1,778       -       85,662  
Net loss
    -       (13,279 )     (271 )     -       (13,550 )
Cash contributions
    -       -       1,412       -       1,412  
Contribution for management compensation (Note 11)
    -       -       3,434       -       3,434  
Cash distributions
    -       (16,743 )     (432 )     -       (17,175 )
Issuance of units
    24,469       561,403       10,618       -       572,021  
Partners' capital, December 31, 2007
    38,253       615,265       16,539       -       631,804  
Net income
    -       23,485       2,604       -       26,089  
Cash contributions
    -       -       511       -       511  
Cash distributions
    -       (47,529 )     (3,005 )     -       (50,534 )
Issuance of units
    2,037       41,667       -       -       41,667  
Unit based compensation expense
    5       750       -       -       750  
Redemption of units
    (838 )     (16,667 )     -       -       (16,667 )
Interest rate swap loss
    -       -       -       (962 )     (962 )
Partners' capital, December 31, 2008
    39,457       616,971       16,649       (962 )     632,658  
                                         
The accompanying notes are an integral part of these consolidated financial statements.
 
 
102

GENESIS ENERGY, L.P.
 
CONSOLIDATED STATEMENTS OF CASH FLOWS
 
(In thousands)
 
   
Year Ended December 31,
 
   
2008
   
2007
   
2006
 
CASH FLOWS FROM OPERATING ACTIVITIES:
                 
Net income (loss)
  $ 26,089     $ (13,550 )   $ 8,381  
Adjustments to reconcile net income (loss) to net cash provided by operating activities -
                       
Depreciation and amortization
    71,370       40,245       7,963  
Amortization and write-off of credit facility issuance costs
    1,437       779       969  
Amortization of unearned income and initial direct costs on direct financing leases
    (10,892 )     (620 )     (655 )
Payments received under direct financing leases
    11,519       1,188       1,186  
Equity in earnings of investments in joint ventures
    (509 )     (1,270 )     (1,131 )
Distributions from joint ventures - return on investment
    1,272       1,845       1,565  
Non-cash effect of unit-based compensation plans
    (2,063 )     910       1,929  
Non-cash compensation charge
    -       3,434       -  
Deferred and other tax liabilities
    (2,771 )     (2,658 )     (11 )
Other non-cash items
    618       346       (61 )
Net changes in components of operating assets and liabilities, net of working capital acquired (See Note 14)
    (1,262 )     3,280       (8,873 )
Net cash provided by operating activities
    94,808       33,929       11,262  
                         
CASH FLOWS FROM INVESTING ACTIVITIES:
                       
Payments to acquire fixed assets
    (37,354 )     (8,235 )     (1,260 )
CO 2 pipeline transactions and related costs
    (228,891 )     -       -  
Distributions from joint ventures - return of investment
    886       395       528  
Investments in joint ventures and other investments
    (2,397 )     (1,104 )     (6,042 )
Acquisition of Grifco assets
    (65,693 )     -       -  
Acquisition of Davison assets, net of cash acquired
    (993 )     (301,640 )     -  
Acquisition of Port Hudson assets
    -       (8,103 )     -  
Other, net
    718       (2,655 )     (68 )
Net cash used in investing activities
    (333,724 )     (321,342 )     (6,842 )
                         
CASH FLOWS FROM FINANCING ACTIVITIES:
                       
Bank borrowings
    531,712       392,200       8,000  
Bank repayments
    (236,412 )     (320,200 )     -  
Additional purchase price consideration paid to Grifco
    (6,000 )     -       -  
Credit facility issuance fees
    (2,255 )     (2,297 )     (2,726 )
Issuance of common units for cash
    -       231,433       -  
Redemption of common units for cash
    (16,667 )     -       -  
General partner contributions
    511       12,030       -  
Minority interest contributions, net of distributions
    25,500       49       (1 )
Distributions to common unitholders
    (47,529 )     (16,743 )     (10,200 )
Distributions to general partner interest
    (3,005 )     (432 )     (208 )
Other, net
    195       906       (66 )
Net cash provided by (used in) financing activities
    246,050       296,946       (5,201 )
                         
Net increase (decrease) in cash and cash equivalents
    7,134       9,533       (781 )
Cash and cash equivalents at beginning of period
    11,851       2,318       3,099  
                         
Cash and cash equivalents at end of period
  $ 18,985     $ 11,851     $ 2,318  
                         
The accompanying notes are an integral part of these consolidated financial statements.
 
 
103

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



1.  Organization
 
We are a growth-oriented limited partnership focused on the midstream segment of the oil and gas industry in the Gulf Coast area of the United States.  We conduct our operations through our operating subsidiaries and joint ventures.  We manage our businesses through four divisions:
 
 
·
Pipeline transportation of crude oil, carbon dioxide (or CO 2 ) and, to a lesser degree, natural gas;
 
 
·
Refinery services involving processing of high sulfur (or “sour”) gas streams for refineries to remove the sulfur, and sale of the related by-product, sodium hydrosulfide (or NaHS, commonly pronounced nash);
 
 
·
Industrial gas activities, including wholesale marketing of CO 2 and processing of syngas through a joint venture; and
 
 
·
Supply and logistics services, which includes terminaling, blending, storing, marketing, and transporting by trucks and barge of crude oil and petroleum products.
 
 Our 2% general partner interest is held by Genesis Energy, LLC, a Delaware limited liability company and an indirect, majority-owned subsidiary of Denbury Resources Inc.  Denbury and its subsidiaries are hereafter referred to as Denbury.  Our general partner and its affiliates also own 10.2% of our outstanding common units.
 
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, 2008 and 2007 and our results of operations, cash flows and changes in partners’ capital for the years ended December 31, 2008, 2007 and 2006.  All intercompany transactions have been eliminated.  The accompanying consolidated financial statements include Genesis Energy, L.P. and its operating subsidiaries, Genesis Crude Oil, L.P. and Genesis NEJD Holdings, LLC, and their subsidiaries.
 
Except per unit amounts, or as noted within the context of each footnote disclosure, the dollar amounts presented in the tabular data within these footnote disclosures are stated in thousands of dollars.
 
Joint Ventures
 
We participate in three joint ventures:  DG Marine Transportation, LLC (DG Marine), T&P Syngas Supply Company (T&P Syngas) and Sandhill Group, LLC (Sandhill).  As of the acquisition date in July 2008, DG Marine is consolidated in our financial statements.  We account for our 50% investments in T&P Syngas and Sandhill by the equity method of accounting. See Note 8.
 
DG Marine Transportation, LLC
 
In July 2008, we acquired an interest in DG Marine which acquired the inland marine transportation business of Grifco Transportation, Ltd and two of its affiliates.  DG Marine is a joint venture with TD Marine, LLC, an entity owned by members of the Davison family.  We own an effective 49% economic interest and TD Marine, LLC owns a 51% economic interest in DG Marine.  TD Marine, LLC controls the DG Marine joint venture and the day-to-day operations are conducted by and managed by DG Marine employees.  The provisions of Financial Interpretation No. 46(R) “Consolidation of Variable Interest Entities” (FIN 46R), require us to consolidate DG Marine in our consolidated financial statements.  See Note 3.  The results of the operations of DG Marine have been included in our consolidated financial statements since the date of the acquisition.
 
T&P Syngas Supply Company


GENESIS ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
 
We own a 50% interest in T&P Syngas, a Delaware general partnership.  Praxair Hydrogen Supply Inc. (“Praxair”) owns the remaining 50% partnership interest in T&P Syngas.  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.
 
Sandhill Group, LLC
 
We own a 50% interest in Sandhill.  At December 31, 2008, Reliant Processing Ltd. held the other 50% interest in Sandhill.  Sandhill owns a CO 2 processing facility located in Brandon, Mississippi. Sandhill is engaged in the production and distribution of liquid carbon dioxide for use in the food, beverage, chemical and oil industries. The facility acquires CO 2 from us under a long-term supply contract that we acquired in 2005 from Denbury.
 
Minority Interests
 
Our general partner owns a 0.01% general partner interest in Genesis Crude Oil, L.P. and TD Marine, LLC, a related party, owns the remaining 51% economic interest in DG Marine.  The net interest of those parties in our results of operations and financial position are reflected in our financial statements as minority interests.
 
In July 2007, we acquired the energy-related businesses of the Davison family.  See Note 3.  The results of the operations of these businesses have been included in our consolidated financial statements since August 1, 2007.
 
Use of Estimates
 
The preparation of our consolidated financial statements 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.  We based these estimates and assumptions on historical experience and other information that we believed to be reasonable under the circumstances.  Significant estimates that we make include: (1) estimated useful lives of assets, which impacts depreciation and amortization, (2) liability and contingency accruals, (3) estimated fair value of assets and liabilities acquired and identification of associated goodwill and intangible assets, (4) estimates of future net cash flows from assets for purposes of determining whether impairment of those assets has occurred, and (5) estimates of future asset retirement obligations.  Additionally, for purposes of the calculation of the fair value of awards under equity-based compensation plans, we make estimates regarding the expected life of the rights, expected forfeiture rates of the rights, volatility of our unit price and expected future distribution yield on our units.  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.  We periodically assess the financial condition of the institutions where these funds are held and believe that our credit risk is minimal.
 
Accounts Receivable
 
Our accounts receivable are primarily from purchasers of crude oil and petroleum products, and, to a lesser extent, purchasers of NaHS and CO 2 .  These purchasers include refineries, marketing and trading companies.  The majority of our accounts receivable relate to our supply and logistics activities that can be described as high volume and low margin activities.
 
Volatility in the financial markets in the latter half of 2008 combined with significant energy price volatility has caused liquidity issues impacting many companies, which in turn have increased the potential credit risks associated with certain counterparties with which we do business.  We utilize our credit review process to monitor these conditions and to make a determination with respect to the amount, if any, of credit to be extended to any given customer and the form and amount of financial performance assurances we require.
 
We review our outstanding accounts receivable balances on a regular basis and record a reserve for amounts that we expect will not be fully recovered.  Actual balances are not applied against the reserve until substantially all collection efforts have been exhausted.


GENESIS ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
 
The following table presents the activity of our allowance for doubtful accounts for the year ended December 31, 2008:
 
   
Year Ended
 
   
December 31,
 
   
2008
 
Balance at beginning of period
  $ -  
Charged to costs and expenses
    1,152  
Amounts written off
    (20 )
Balance at end of period
  $ 1,132  
 
Inventories
 
Crude oil and petroleum products 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.  Caustic soda and NaHS inventories are stated at the lower of cost or market. Cost is determined principally under the average cost method within specific inventory pools.
 
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, 25 years for push boats and barges, 10 to 20 years for machinery and equipment, 40 years for tanks, 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.
 
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.
 
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.
 
Asset Retirement Obligations
 
Some of our assets have contractual or regulatory obligations to perform dismantlement and removal activities, and in some instances remediation, when the assets are abandoned.  In general, our future asset retirement obligations relate to future costs associated with the removal of our oil, natural gas and CO 2 pipelines, barge decommissioning, removal of equipment and facilities from leased acreage and land restoration. The fair value of a liability for an asset retirement obligation is recorded in the period in which it is incurred, discounted to its present value using our credit adjusted risk-free interest rate, and a corresponding amount capitalized by increasing the carrying amount of the related long-lived asset. The capitalized cost is depreciated over the useful life of the related asset.  Accretion of the discount increases the liability and is recorded to expense.  See Note 5.
 
Direct Financing Leasing Arrangements
 
We lease four pipelines to Denbury under direct financing leases.  Three of these leases of pipeline segments to Denbury will expire in 2013 to 2015.  The NEJD Pipeline System lease to Denbury will expire in 2028, subject to certain extension options.

 
GENESIS ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
     
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 6.
 
CO 2 Assets
 
Our 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 7.
 
Intangible Assets
 
Statement of Financial Accounting Standards No. 142, “Goodwill and Other Intangible Assets,” (SFAS 142) requires that intangible assets with finite useful lives be amortized over their respective estimated useful lives.  If an intangible asset has a finite useful life, but the precise length of that life is not known, that intangible asset shall be amortized over the best estimate of its useful life.  At a minimum, we will assess the useful lives and residual values of all intangible assets on an annual basis to determine if adjustments are required.   We are recording amortization of our customer and supplier relationships, licensing agreements and trade name based on the period over which the asset is expected to contribute to our future cash flows.  Generally, the contribution of these assets to our cash flows is expected to decline over time, such that greater value is attributable to the periods shortly after the acquisition was made.  The favorable lease and other intangible assets are being amortized on a straight-line basis.
 
We test 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, 2008, no impairment has occurred of intangible assets.
 
Goodwill
 
Goodwill represents the excess of purchase price over fair value of net assets acquired.  We account for goodwill under SFAS 142, which prohibits amortization of goodwill, but instead requires testing for impairment at least annually.  We test goodwill for impairment annually at October 1, and more frequently if indicators of impairment are present.  If the fair value of the reporting unit exceeds its book value including associated goodwill amounts, the goodwill is considered to be unimpaired and no impairment charge is required. If the fair value of the reporting unit is less than its book value including associated goodwill amounts, a charge to earnings is recorded to reduce the carrying value of the goodwill to its implied fair value.  In the event that we determine that goodwill has become impaired, we will incur a charge for the amount of impairment during the period in which the determination is made.  See Note 9.
 
Environmental Liabilities
 
We provide for the estimated costs of environmental contingencies when liabilities are probable to occur and a reasonable estimate of the associated costs can be made.  Ongoing environmental compliance costs, including maintenance and monitoring costs, are charged to expense as incurred.
 
Unit-Based Compensation
 
On January 1, 2006, we adopted the provisions of SFAS No. 123(R), “Share-Based Payments”.  This statement requires that the compensation cost associated with our stock appreciation rights plan, which upon exercise will result in the payment of cash to the employee, 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 is calculated using a fair value method that takes into consideration the expected future value of the rights at their expected exercise dates.
 
Our 2007 Long-term Incentive Plan provides for awards of phantom units to our non-employee directors and to the employees of our general partner.   SFAS No. 123(R) requires that compensation cost related to phantom units issued under our 2007 Long-term Incentive Plan be recognized in our consolidated financial statements based on estimated fair value at the date of the grant.  See Note 15.


GENESIS ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
 
On December 31, 2008, our general partner awarded Class B Membership Interests in our general partner to our senior executives.  SFAS 123(R) requires that the compensation cost related to these interests be re-measured at each reporting date based on the fair value of the interests, and changes in that fair value be recognized over the vesting period. Recorded expense will be subsequently adjusted to fair value until final settlement.  See Note 15.
 
Revenue Recognition
 
Product Sales - Revenues from the sale of crude oil, petroleum products, natural gas, caustic soda and NaHS are recognized when title to the inventory is transferred to the customer, collectibility is reasonably assured and there are no further significant obligations for future performance by us.  Most frequently, title transfers upon our delivery of the inventory to the customer at a location designated by the customer, although in certain situations, title transfers when the inventory is loaded for transportation to the customer.  Our crude oil, natural gas and petroleum products are typically sold at prices based off daily or monthly published prices.  Many of our contracts for sales of NaHS incorporate the price of caustic soda in the pricing formulas.
 
Pipeline Transportation - Revenues from transportation of crude oil or natural gas by our pipelines are based on actual volumes at a published tariff.  Tariff revenues are recognized either at the point of delivery or at the point of receipt pursuant to the specifications outlined in our regulated tariffs.
 
In order to compensate us for bearing the risk of volumetric losses in volumes that occur to crude oil in our pipelines due to temperature, crude quality and the inherent difficulties of measurement of liquids in a pipeline, our tariffs include the right for us 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, we have 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.
 
Income from direct financing leases is being recognized ratably over the term of the leases and is included in pipeline revenues.
 
CO 2 Sales - 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 and Operating Expenses
 
Supply and logistics costs and expenses include the cost to acquire the product and the associated costs to transport it to our terminal facilities or to a customer for sale.  Other than the cost of the products, the most significant costs we incur relate to transportation utilizing our fleet of trucks and barges, including personnel costs, fuel and maintenance of our equipment.
 
When we enter into buy/sell arrangements concurrently or in contemplation of one another with a single counterparty, we reflect the amounts of revenues and purchases for these transactions as a net amount in our consolidated statements of operations beginning with April 2006.  Transactions for periods prior to April 2006 are not reflected as a net amount; however the amounts are disclosed parenthetically on the consolidated statements of operations, in accordance with the provision of Emerging Issues Task Force Issue No. 04-13, “Accounting for Purchases and Sales of Inventory with the Same Counterparty.”  Had this provision been in effect in the first quarter of 2006, our reported supply and logistics revenues from unrelated parties for the year ended December 31, 2006 would have been reduced by $69 million to $803 million.  Our reported supply and logistics product costs from unrelated parties for the year ended December 31, 2006 would have been reduced by $69 million to $781 million.  This change had no effect on operating income, net income or cash flows.
 
The most significant operating costs in our refinery services segment consist of the costs to operate NaHS plants located at various refineries, caustic soda used in the process of processing the refiner’s sour gas stream, and costs to transport the NaHS and caustic soda.
 
Pipeline operating costs consist primarily of power costs to operate pumping equipment, personnel costs to operate the pipelines, insurance costs and costs associated with maintaining the integrity of our pipelines.


GENESIS ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
 
Cost of sales for the CO 2 marketing activities consists of a transportation fee charged by Denbury to transport the CO 2 to the customer through Denbury’s pipeline and insurance costs.  The transportation fee charged by Denbury is adjusted annually for inflation.  For the years ended December 31, 2008, 2007 and 2006, the fee averaged $0.1927, $0.1848 and $0.1740 per Mcf, respectively.
 
Excise and Sales Taxes
 
The Company collects and remits excise and sales taxes to state and federal governmental authorities on its sales of fuels.  These taxes are presented on a net basis, with any differences due to rebates allowed by those governmental entities reflected as a reduction of product cost in the consolidated income statements.
 
Income Taxes
 
We are a limited partnership, organized as a pass-through entity for federal income tax purposes. As such, we do not directly pay federal income tax. Our taxable income or loss, which may vary substantially from the net income or net loss we report in our consolidated statement of operations, is includable in the federal income tax returns of each partner.
 
Some of our corporate subsidiaries pay U.S. federal, state, and foreign income taxes. Deferred income tax assets and liabilities for certain operations conducted through corporations are recognized for temporary differences between the assets and liabilities for financial reporting and tax purposes. Changes in tax legislation are included in the relevant computations in the period in which such changes are effective. Deferred tax assets are reduced by a valuation allowance for the amount of any tax benefit not expected to be realized.  Penalties and interest related to income taxes will be included in income tax expense in the consolidated statements of operations.
 
Derivative Instruments and Hedging Activities
 
We minimize our exposure to price risk by limiting our inventory positions.  However when we hold inventory positions in crude oil and petroleum products, we use derivative instruments to hedge exposure to price risk.  DG Marine uses interest rate swap contracts to manage its exposure to interest rate risk.
 
We 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.  We must formally designate the derivative as a hedge and document and assess the effectiveness of derivatives associated with transactions that receive hedge accounting.   Accordingly,  changes in the fair value of derivatives are included in earnings in the current period for (i) derivatives accounted for as fair value hedges; (ii) derivatives that do not qualify for hedge accounting and (iii) the portion of cash flow hedges that is not highly effective in offsetting changes in cash flows of hedged items.  Changes in the fair value of cash flow hedges are deferred in Accumulated Other Comprehensive Income (“AOCI”) and reclassified into earnings when the underlying position affects earnings.  See Note 17.
 
Fair Value of Current Assets and Current Liabilities
 
The carrying amount of cash and cash equivalents, accounts receivable, inventories, other current assets, accounts payable, other current liabilities and derivatives approximates their fair value due to their short-term nature.  The fair values of these instruments are represented in our consolidated balance sheets.
 
Net Income Per Common Unit
 
Our net income is first allocated to the general partner based on the amount of incentive distributions.  The remainder is then allocated 98% to the limited partners and 2% to the general partner.  Basic net income per limited partner unit is determined by dividing net income attributable to limited partners by the weighted average number of outstanding limited partner units during the period.  Diluted net income per common unit is calculated in the same manner, but also considers the impact to common units for the potential dilution from phantom units outstanding. (See Note 15 for discussion of phantom units.)
 
In a period of net operating losses, incremental phantom units are excluded from the calculation of diluted earnings per unit due to their anti-dilutive effect. During 2008, we have reported net income; therefore incremental phantom units have been included in the calculation of diluted earnings per unit.


GENESIS ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
 
EITF 03-06 addresses the computation of earnings per share by entities that have issued securities other than common stock that contractually entitle the holder to participate in dividends and earnings of the entity when, and if, it declares dividends on its common stock (or partnership distributions to unitholders).  EITF 03-06 applies to any accounting period where our aggregate net income exceeds our aggregate distribution.  In such periods, we are required to present earnings per unit as if all of the earnings for the periods were distributed, regardless of the pro forma nature of this allocation and whether those earnings would actually be distributed from an economic or practical perspective.  EITF 03-06 does not impact our overall net income or other financial results; however, for periods in which aggregate net income exceeds our aggregate distributions for such period, it would have the impact of reducing the earnings per limited partner units.  This result occurs as a larger portion of our aggregate earnings is allocated (as if distributed) to our general partner, even though we make cash distributions on the basis of cash available for distributions (as defined in our partnership agreement), not earnings, in any given period.  Our aggregate net earnings have not exceeded our aggregate distributions; therefore EITF 03-06 has not had an impact on our calculation of earnings per unit.
 
Effective January 1, 2009, we adopted EITF 07-04 and EITF 03-06 will no longer be applied.  See “Recent and Proposed Accounting Announcements – Implemented January 1, 2009” below.
 
Recent and Proposed Accounting Pronouncements
 
Implemented in 2008
 
FASB Staff Position FIN 46(R)-8
 
In December 2008, the FASB issued FASB Staff Position FIN 46(R)-8, “Disclosures about Variable Interest Entities” (FSP FIN 46(R)-8). FSP FIN 46(R)-8 requires enhanced disclosures about a company’s involvement in variable interest entities (VIEs). The enhanced disclosures required by this FSP are intended to provide users of financial statements with an greater understanding of: (1) the significant judgments and assumptions made by a company in determining whether it must consolidate a VIE and/or disclose information about its involvement with a VIE; (2) the nature of restrictions on the assets of  a VIE that are consolidated and  reported by a company in its statement of financial position, including the carrying amounts of such assets; (3) the nature of, and changes in, the risks associated with a company’s involvement with a VIE; (4) how a company’s involvement with a VIE affects the company’s financial position, financial performance, and cash flows. This FSP was effective for us on December 31, 2008. See Note 3 for disclosures regarding our involvement with VIEs.
 
SFAS 157
 
We adopted Statement of Financial Accounting Standards (SFAS) No. 157, “Fair Value Measurements” (SFAS 157), with respect to financial assets and financial liabilities that are regularly adjusted to fair value, as of January 1, 2008.  SFAS 157 provides a common fair value hierarchy to follow in determining fair value measurements in the preparation of financial statements and expands disclosure requirements relating to how such measurements were developed. SFAS 157 does not require any new fair value measurements, but rather applies to all other accounting pronouncements that require or permit fair value measurements.  On February 12, 2008 the Financial Accounting Standards Board (FASB) issued Staff Position No. 157-2, “Effective Date of FASB Statement No. 157” (FSP 157-2) which amends SFAS 157 to delay the effective date for all non-financial assets and non-financial liabilities, except for those that are recognized at fair value in the financial statements on a recurring basis.  The partial adoption of SFAS 157 as described above had no material impact on us.  We have not yet determined the impact, if any, that the second phase of the adoption of SFAS 157 in 2009 will have relating to its fair value measurements of non-financial assets and non-financial liabilities.  See Note 18 for further information regarding fair-value measurements.
 
SFAS 159
 
In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities” (SFAS 159).  This statement was effective for us as of January 1, 2008. SFAS 159 permits entities to choose to measure many financial instruments and certain other items at fair value that are not currently required to be measured at fair value. We did not elect to utilize voluntary fair value measurements as permitted by the standard.
 
Implemented January 1, 2009
 
SFAS 141(R)
 
In December 2007, the FASB issued SFAS No. 141(R) “Business Combinations” (SFAS 141(R)).  SFAS 141(R) replaces FASB Statement No. 141, “Business Combinations.”  This statement retains the purchase method of accounting used in business combinations but replaces SFAS 141 by establishing principles and requirements for the recognition and measurement of assets, liabilities and goodwill, including the requirement that most transaction costs and restructuring costs be charged to expense as incurred.  In addition, the statement requires disclosures to enable users of the financial statements to evaluate the nature and financial effects of the business combination.  SFAS 141(R) is effective for business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008.  We adopted SFAS 141(R) on January 1, 2009.  Adoption will impact our accounting for acquisitions we complete subsequent to that date.

 
GENESIS ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
 
SFAS 160
 
In December 2007, the FASB issued SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements - an amendment of ARB No. 51” (SFAS 160). This statement establishes accounting and reporting standards for noncontrolling interests, which have been referred to as minority interests in prior literature.  A noncontrolling interest is the portion of equity in a subsidiary not attributable, directly or indirectly, to a parent company.  This new standard requires, among other things, that (i) ownership interests of noncontrolling interests be presented as a component of equity on the balance sheet (i.e. elimination of the mezzanine “minority interest” category); (ii) elimination of minority interest expense as a line item on the statement of operations and, as a result, that net income be allocated between the parent and the noncontrolling interests on the face of the statement of operations; and (iii) enhanced disclosures regarding noncontrolling interests.  SFAS 160 is effective for fiscal years beginning after December 15, 2008.  We adopted SFAS 160 on January 1, 2009.  Such adoption will impact the presentation of the minority interests in Genesis Crude Oil, L.P. held by our general partner and DG Marine held by our joint venture partner.
 
SFAS 161
 
 In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities-an amendment of FASB Statement No.133” (SFAS 161). This Statement requires enhanced disclosures about (i) how and why an entity uses derivative instruments, (ii) how derivative instruments and related hedged items are accounted for under SFAS 133, and its related interpretations, and (iii) how derivative instruments and related hedged items affect an entity’s financial position, financial performance and cash flows. This statement is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008. We adopted SFAS No. 161 on January 1, 2009. Adoption did not have any material impact on our financial position, results of operations or cash flows.
 
EITF 07-4
 
In March 2008, the Emerging Issues Task Force (or EITF) of the FASB issued EITF 07-4, “Application of the Two-Class Method under FASB Statement No. 128, Earnings per Share , to Master Limited Partnerships” (EITF 07-4).  EITF 07-4 addresses the application of the two-class method under SFAS No. 128 “Earnings Per Share” in determining income per unit for master limited partnerships having multiple classes of securities that may participate in partnership distributions.  To the extent the partnership agreement does not explicitly limit distributions to the general partner, any earnings in excess of distributions are to be allocated to the general partner and limited partners utilizing the distribution formula for available cash specified in the partnership agreement.  When current period distributions are in excess of earnings, the excess distributions are to be allocated to the general partner and limited partners based on their respective sharing of losses specified in the partnership agreement for the period.  EITF 07-4 is to be applied retrospectively for all financial statements presented and is effective for financial statements issued for fiscal years beginning after December 15, 2008, and interim periods within those fiscal years.  Earlier application is not permitted.  We adopted EITF 07-04 on January 1, 2009.  Adoption will impact the net income available to limited partners used in our computation of earnings per unit, but will not impact our distributions to limited partners, financial position, results of operations, or cash flows.  For additional information on our incentive distribution rights, see Note 10.
 
FASB Staff Position No. 142-3
 
In April 2008, the FASB issued FASB Staff Position No. 142-3, “Determination of the Useful Life of Intangible Assets” (FSP 142-3).  This FSP amends the factors that should be considered in developing renewal or extension assumptions used to determine the useful life of an intangible asset under Statement of Financial Accounting Standards No. 142, “Goodwill and other Intangible Assets.” The purpose of this FSP is to develop consistency between the useful life assigned to intangible assets and the cash flows from those assets.  FSP 142-3 is effective for fiscal years beginning after December 31, 2008.  We are currently evaluating the impact, if any, that the standard will have on our consolidated financial statements.


GENESIS ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
3.  Acquisitions
 
DG Marine Transportation Investment
 
On July 18, 2008, DG Marine completed the acquisition of the inland marine transportation business of Grifco Transportation, Ltd. (“Grifco”) and two of Grifco’s affiliates.  DG Marine is a joint venture we formed with TD Marine, LLC, an entity owned by members of the Davison family.  (See discussion below on the acquisition of the Davison family businesses in 2007.). TD Marine owns (indirectly) a 51% economic interest in the joint venture, DG Marine, and we own (directly and indirectly) a 49% economic interest.  This acquisition gives us the capability to provide transportation services of petroleum products by barge and complements our other supply and logistics operations.
 
Grifco received initial purchase consideration of approximately $80 million, comprised of $63.3 million in cash and $16.7 million, or 837,690 of our common units.  A portion of the units are subject to certain lock-up restrictions. DG Marine acquired substantially all of Grifco’s assets, including twelve barges, seven push boats, certain commercial agreements, and offices.  Additionally, DG Marine and/or  its subsidiaries acquired the rights, and assumed the obligations, to take delivery of four new barges in late third quarter of 2008 and four additional new barges late in first quarter of 2009 (at a total price of approximately $27 million). Upon delivery of the eight new barges, the acquisition of three additional push boats (at an estimated cost of approximately $6 million), and after placing the barges and push boats into commercial operations, DG Marine will be obligated to pay additional purchase consideration of up to $12 million.   At December 31, 2008, DG Marine had taken delivery of four of the new barges and $6 million of the additional purchase price consideration was paid.  At December 31, 2008, the $5.9 million estimated present value of the remaining $6 million obligation is included in “Accrued Liabilities” in our consolidated balance sheet.  The effective interest rate of the obligation was 4.7%
 
The Grifco acquisition and related closing costs were funded with $50 million of aggregate equity contributions from us and TD Marine, in proportion to our ownership percentages, and with borrowings of $32.4 million under a revolving credit facility which is non-recourse to us and TD Marine (other than with respect to our  investments in DG Marine).  Although DG Marine’s debt is non-recourse to us, our ownership interest in DG Marine is pledged to secure its indebtedness. We funded our $24.5 million equity contribution with $7.8 million of cash and 837,690 of our common units, valued at $19.896 per unit, for a total value of $16.7 million.  At closing, we also redeemed 837,690 of our common units from the Davison family.  See Notes 10 and 11.
 
We have entered into a subordinated loan agreement with DG Marine whereby we may (at our sole discretion) lend up to $25 million to DG Marine.  The loan agreement provides for DG Marine to pay us interest on any loans at the rate at which we borrowed funds under our credit facility plus 4%.  Those loans will mature on January 31, 2012.  Under that subordinated loan agreement, DG Marine is required to make monthly payments to us of principal and interest to the extent DG Marine has any available cash that otherwise would have been distributed to the owners of DG Marine in respect of their equity interest.  DG Marine’s revolving credit facility includes restrictions on DG Marine’s ability to make specified payments under the subordinated loan agreement and distributions in respect of our equity interest.  At December 31, 2008, there were no amounts outstanding under the subordinated loan agreement. We have, however, provided a $7.5 million guaranty to the lenders under DG Marine’s credit facility.  This guaranty will expire on May 31, 2009, if DG Marine’s leverage ratio under its credit facility is less than 4.00 to 1.00 at May 31, 2009.
 
The provisions of Financial Interpretation No. 46(R) “Consolidation of Variable Interest Entities” (FIN 46R), require the primary beneficiary to consolidate variable interest entities.  As stated in FIN 46R, in determining the primary beneficiary of a variable interest entity ("VIE") that is held between two or more related parties the primary beneficiary is considered to be the party that is "most closely associated" with the VIE.  We are considered to be the primary beneficiary due to (i) our involvement in the design of DG Marine, (ii) the ongoing involvement with regards to financial and operating decision making of DG Marine, excluding matters related to new contracts and vessel disposal which are decided solely by TD Marine, and (iii) the financial support we provide to DG Marine.  TD Marine has no requirements to make any additional contributions to DG Marine.


GENESIS ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
 
As we are considered the primary beneficiary, DG Marine is consolidated in our consolidated financial statements and the 51% ownership interest of TD Marine in the net assets and net income of DG Marine is included in minority interests in our consolidated financial statements.
 
The acquisition cost allocated to the assets consists of $63.3 million of cash, $16.7 million of value from the issuance of our limited partnership units to Grifco, $11.7 million related to the discounted value of the additional consideration that will be owed to Grifco when the barges under construction are placed in service and $2.4 million of transaction costs.  The acquisition cost has been allocated to the assets acquired based on estimated fair values.  Such fair values were developed by management.
 
The allocation of the acquisition cost is summarized as follows:
 
Property and equipment
  $ 91,772  
Amortizable intangible assets:
       
Customer relationships
    800  
Trade name
    900  
Non-compete agreements
    600  
Total allocated cost
  $ 94,072  
 
The weighted average amortization period for the intangible assets at the date of acquisition is 10 years for customer relationships, 3 years for the trade name and 7 years for the non-compete agreements.  The weighted average amortization period for all intangible assets acquired in the Grifco transaction was 6 years.
 
See additional information on intangible assets and goodwill in Note 9.
 
At December 31, 2008, our Consolidated Balance Sheets included the following amounts related to DG Marine:
 
Cash
  $ 623  
Accounts receivable - trade
    2,812  
Other current assets
    859  
Fixed assets, at cost
    110,214  
Accumulated depreciation
    (3,084 )
Intangible assets, net
    2,208  
Other assets
    2,178  
Total assets
  $ 115,810  
         
Accounts payable
  $ 1,072  
Accrued liabilities
    9,258  
Long-term debt
    55,300  
Other long-term liabilities
    1,393  
Minority interests
    24,233  
Total liabilities
  $ 91,256  
 
2008 Denbury Drop-Down Transactions
 
On May 30, 2008, we completed two “drop-down” transactions with Denbury Onshore LLC, (Denbury Onshore), a wholly-owned subsidiary of Denbury Resources Inc., the indirect owner of our general partner.
 
NEJD Pipeline System
 
In 2008, we entered into a twenty-year financing lease transaction with Denbury valued at $175 million and related to Denbury’s North East Jackson Dome (NEJD) Pipeline System.  The NEJD Pipeline System is a 183-mile, 20” pipeline extending from the Jackson Dome, near Jackson, Mississippi, to near Donaldsonville, Louisiana, and is currently being leased and used by Denbury for its Phase I area of tertiary operations in southwest Mississippi.  We recorded this lease arrangement in our consolidated financial statements as a direct financing lease. Under the terms of the agreement, Denbury Onshore began making quarterly rent payments beginning August 30, 2008.  These quarterly rent payments are fixed at $5,166,943 per quarter or approximately $20.7 million per year during the lease term at an interest rate of 10.25%.  At the end of the lease term, we will convey all of our interests in the NEJD Pipeline to Denbury Onshore for a nominal payment.


GENESIS ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
 
The NEJD Pipeline System is a 183-mile, 20” CO 2 pipeline extending from the Jackson Dome, near Jackson, Mississippi, to near Donaldson, Louisiana, currently being used by Denbury for its tertiary operations in southwest Mississippi.  Denbury has the rights to exclusive use of the NEJD Pipeline System, will be responsible for all operations and maintenance on that system, and will bear and assume all obligations and liabilities with respect to that system.  The NEJD transaction was funded with borrowings under our credit facility.
 
See additional discussion of this direct financing lease in Note 6.
 
Free State Pipeline System
 
We purchased Denbury’s Free State Pipeline for $75 million, consisting of $50 million in cash which we borrowed under our credit facility, and $25 million in the form of 1,199,041 of our common units.  The number of common units issued was based on the average closing price of our common units from May 28, 2008 through June 3, 2008.
 
The Free State Pipeline is an 86-mile, 20” pipeline that extends from Denbury’s CO 2 source fields at Jackson Dome, near Jackson, Mississippi, to Denbury’s oil fields in east Mississippi.  We entered into a twenty-year transportation services agreement to deliver CO 2 on the Free State pipeline for Denbury’s use in its tertiary recovery operations.    Under the terms of the transportation services agreement, we are responsible for owning, operating, maintaining and making improvements to that pipeline.  Denbury has rights to exclusive use of that pipeline and is required to use that pipeline to supply CO 2 to its current and certain of its other tertiary operations in east Mississippi.  The transportation services agreement provides for a $100,000 per month minimum payment, which is accounted for as an operating lease, plus a tariff based on throughput. Denbury has two renewal options, each for five years on similar terms. Any sale by us of the Free State Pipeline and related assets or of an ownership interest in our subsidiary that holds such assets would be subject to a right of first refusal purchase option in favor of Denbury.
 
Davison Businesses Acquisition
 
On July 25, 2007, we acquired five energy-related businesses from several entities owned and controlled by the Davison family of Ruston, Louisiana (the “Davison Acquisition”).  The businesses include the operations that comprise our refinery services division, and other operations included in our supply and logistics division, which transport, store, procure and market petroleum products and other bulk commodities.  The assets acquired in this transaction provide us with opportunities to expand our services to energy companies in the areas in which we operate.
 
For financial reporting purposes, the consideration for this acquisition consisted of $623 million of value, net of cash acquired.  The consideration is comprised of $293 million in cash, (which is net of $21.7 million of cash acquired), and 13,459,209 common units of Genesis valued at $330 million.  In accordance with EITF, No. 99-12, “Determination of the Measurement Date for the Market Price of Acquirer Securities Issued in a Purchase Business Combination,” the fair value of Genesis common units issued was determined using an average price of $24.52, which was the average closing price of Genesis common units for the two days before and after the date on which the terms of the acquisition were agreed to and announced.  The direct transaction costs totaled $8.9 million and consist primarily of legal and accounting fees and other external costs related directly to the acquisition.
 
The Davison family is our largest unitholder, with approximately 33% of our outstanding common units.  It has designated two of the family members to the board of directors of our general partner, and as long as it maintains a specified minimum percentage of our common units, it will have the continuing right to designate up to two directors.  The Davison family has agreed to restrictions that limit its ability to sell specified percentages of its common units through July 26, 2010.  Pursuant to an agreement between us and the Davison unitholders, the Davison unitholders have registration rights with respect to their common units. These rights include the right to require us to file a Form S-3 shelf registration statement, if we are eligible.


GENESIS ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
 
The purchase price has been allocated to the assets acquired and liabilities assumed based on estimated fair values.  Such fair values were developed by management. The allocation of the purchase price is summarized as follows:
 
Cash and cash equivalents
  $ 21,686  
Accounts receivable
    55,631  
Inventories
    10,825  
Other current assets
    982  
Other assets
    294  
Property and equipment
    67,655  
Goodwill
    316,739  
Amortizable intangible assets:
       
Customer relationships
    129,284  
Supplier agreements
    36,469  
Licensing agreements
    38,678  
Trade name
    17,988  
Covenants not-to-compete
    695  
Favorable lease agreement
    13,260  
Accounts payable and accrued expenses
    (35,230 )
Deferred tax liabilties assumed
    (21,794 )
Total allocation
  $ 653,162  
 
See additional information on intangible assets and goodwill in Note 9.  Goodwill represents the residual of the purchase price over the fair value of net tangible and identifiable intangible assets acquired.
 
The following table presents selected unaudited pro forma financial information incorporating the historical operating results of the Davison businesses.  The effective closing date of our purchase of the Davison businesses was July 25, 2007.  As a result, our Consolidated Statements of Operations for the year ended December 31, 2007 includes five months of results of operations of these acquired businesses.  The pro forma financial information has been prepared as if the acquisition had been completed on the first day of each period presented rather than the actual closing date.  The pro forma financial information has been prepared based upon assumptions deemed appropriate by us and may not be indicative of actual results.
 
   
Year Ended December 31,
 
   
2007
   
2006
 
Pro Forma Earnings Data:
           
Revenue
  $ 1,574,730     $ 1,479,174  
Costs and expenses
    1,572,809       1,477,275  
Operating income
    1,921       1,899  
(Loss) Income before extraordinary items
    (29,666 )     (19,664 )
Net (loss) income
    (29,666 )     (19,664 )
                 
Basic and diluted (loss) earnings per unit:
               
As reported units outstanding
    20,754       13,784  
Pro forma units outstanding
    28,319       28,319  
As reported net (loss) income per unit
  $ (0.64 )   $ 0.59  
Pro forma net (loss) income per unit
  $ (1.05 )   $ (0.69 )

 
Port Hudson Assets Acquisition
 
Effective July 1, 2007, we paid $8.1 million for BP Pipelines (North America) Inc.’s Port Hudson crude oil truck terminal, marine terminal, and marine dock on the Mississippi River, which includes 215,000 barrels of tankage, a pipeline and other related assets in East Baton Rouge Parish, Louisiana. The acquisition was funded with borrowings under our credit facility.


GENESIS ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
 
The purchase price has been allocated to the assets acquired based on estimated fair values.  The allocation of the purchase price is summarized as follows:
 

Property and equipment
  $ 4,134  
Goodwill
    3,969  
Total
  $ 8,103  
 
See additional information on goodwill in Note 9.

 
4.  Inventories
 
The major components of inventories were as follows:
 
   
December 31,
 
   
2008
   
2007
 
Crude oil
    1,878       3,710  
Petroleum products
    5,589       6,527  
Caustic soda
    7,139       1,998  
NaHS
    6,923       3,557  
Other
    15       196  
Total inventories
  $ 21,544     $ 15,988  


Our inventory at December 31, 2008 is net of charges totaling $1.2 million that we recorded to reduce the cost basis of our crude oil and petroleum products inventory to reflect market value.  The lower of cost or market adjustment is included in “Product Costs” of our Supply & Logistics segment on our consolidated statements of operations.  The costs of inventories did not exceed market values at December 31, 2007.
 
 
5.  Fixed Assets and Asset Retirement Obligations
 
Fixed Assets
 
Fixed assets consisted of the following.
 
   
December 31,
 
   
2008
   
2007
 
Land, buildings and improvements
  $ 13,549     $ 11,978  
Pipelines and related assets
    139,184       63,169  
Machinery and equipment
    22,899       25,097  
Transportation equipment
    32,833       32,906  
Barges and push boats
    96,865       -  
Office equipment, furniture and fixtures
    4,401       2,759  
Construction in progress
    27,906       7,102  
Other
    11,575       7,402  
Subtotal
    349,212       150,413  
Accumulated depreciation and impairment
    (67,107 )     (48,413 )
Total
  $ 282,105     $ 102,000  


In 2008, 2007 and 2006, $276,000, $57,000 and $9,000 of interest cost, respectively, were capitalized related to the construction of pipelines and related assets.
 
Depreciation expense was $20,415,000, $8,909,000 and $3,719,000 for the years ended December 31, 2008, 2007, and 2006, respectively.
 
Asset Impairment Charge
 
During the fourth quarter of 2007, changes in the source of the supply of natural gas to our natural gas gathering pipelines (which are included in our pipeline transportation segment) indicated to us that the carrying amount of our natural gas gathering pipelines might not be recoverable.  We made certain assumptions when estimating future cash flows to be generated from the assets including declines in future sales volumes and costs of testing required for integrity purposes.  As a result, we tested the carrying value of these assets for recoverability, and determined that we should record an impairment charge of $1,498,000 related to these assets.


GENESIS ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
 
Asset Retirement Obligations
 
In general, our future asset retirement obligations relate to future costs associated with the removal of certain segments of our oil, natural gas and CO 2 pipelines, barge decommissioning, removal of equipment and facilities from leased acreage and land restoration. The fair value of a liability for an asset retirement obligation is recorded in the period in which it is incurred, discounted to its present value using our credit adjusted risk-free interest rate, and a corresponding amount capitalized by increasing the carrying amount of the related long-lived asset. The capitalized cost is depreciated over the useful life of the related asset.  Accretion of the discount increases the liability and is recorded to expense.
 
 A reconciliation of our liability for asset retirement obligations is as follows:
 
Asset retirement obligations as of December 31, 2006
  $ 708  
Liabilities incurred and assumed in the current period
    468  
Revisions in estimated retirement obligations
    (81 )
Accretion expense
    78  
Asset retirement obligations as of December 31, 2007
    1,173  
Liabilities incurred and assumed in the current period
    121  
Accretion expense
    136  
Asset retirement obligations as of December 31, 2008
  $ 1,430  
 

 
At December 31, 2008, $0.2 million of our asset retirement obligation was classified in “Accrued liabilities” under current liabilities in our Consolidated Balance Sheets. Liabilities incurred and assumed during the period are for properties acquired during each year.   Certain of our unconsolidated affiliates have asset retirement obligations recorded at December 31, 2008 and 2007 relating to contractual agreements.  These amounts are immaterial to our consolidated financial statements.
 
6.  Net Investment in Direct Financing Leases
 
In the fourth quarter of 2004, we constructed two segments of crude oil pipeline and a CO 2 pipeline segment to transport crude oil from and CO 2 to producing fields operated by Denbury.  Denbury pays us a minimum payment each month for the right to use these pipeline segments.  Those arrangements have been accounted for as direct financing leases.  As discussed in Note 3, we entered into a lease arrangement with Denbury related to the NEJD Pipeline in May 2008 that is being accounted for as a direct financing lease.  Denbury pays us fixed payments of $5.2 million per quarter that began in August 2008.
 
The following table lists the components of the net investment in direct financing leases:
 
   
December 31,
 
   
2008
   
2007
 
Total minimum lease payments to be received
  $ 407,392     $ 7,039  
Estimated residual values of leased property (unguaranteed)
    1,287       1,287  
Unamortized initial direct costs
    2,580       -  
Less unearned income
    (230,298 )     (2,953 )
Net investment in direct financing leases
  $ 180,961     $ 5,373  
 
At December 31, 2008, minimum lease payments to be received for each of the five succeeding fiscal years are $21.9 million per year for 2009 through 2011, $21.8 million for 2012 and $21.3 million for 2013.


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

7.  CO 2 Assets
 
CO 2 assets consisted of the following.
 
   
December 31,
 
   
2008
   
2007
 
CO 2 volumetric production payments
  $ 43,570     $ 43,570  
Less - Accumulated amortization
    (19,191 )     (14,654 )
Net CO 2 assets
  $ 24,379     $ 28,916  

 
The volumetric production payments entitle us to a maximum daily quantity of CO 2 of 101,375 million cubic feet, or Mcf, per day through December 31, 2009, 91,875 Mcf per day for the calendar years 2010 through 2012 and 73,875 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.  During 2008 this fee averaged $0.1927 per Mcf.
 
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, with one small contract extending until 2023.
 
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 2008, 2007 and 2006, we recorded amortization of $4,537,000, $4,488,000 and $4,244,000, respectively.  We have 153.8 Bcf of CO 2 remaining under the volumetric production payments at December 31, 2008.  Based on the historical deliveries of CO 2 to the customers (which have exceeded minimum take-or-pay volumes), we expect amortization for the next five years to be approximately $4,537,000 from 2009 to 2010, $4,157,000 for 2011 and 2012 and $3,431,000 for 2013.
 
8.  Equity Investees and Other Investments
 
Equity Investees
 
We are accounting for our 50% ownership in each of two joint ventures, T&P Syngas and Sandhill under the equity method of accounting.   We paid $7.8 million more for our interest in these joint ventures than our share of capital on their balance sheets at the date of the acquisition.  This excess amount of the purchase price over the equity in the joint ventures has been allocated to the tangible and intangible assets of the joint ventures based on the fair value of those assets, with the remainder of the excess purchase price of $0.7 million allocated to goodwill.  The table below reflects information included in our consolidated financial statements related to our equity investees.
 
   
Year Ended December 31,
 
   
2008
   
2007
   
2006
 
Genesis' share of operating earnings
    1,137       1,898       1,690  
Amortization of excess purchase price
    (628 )     (628 )     (559 )
Net equity in earnings
  $ 509     $ 1,270     $ 1,131  
                         
Distributions received
  $ 2,158     $ 2,240     $ 2,093  
 
Other Projects
 
We have also invested $4.6 million in the Faustina Project, a petroleum coke to ammonia project that is in the development stage.  All of our investment may later be redeemed, with a return, or converted to equity after the project has obtained construction financing.  The funds we have invested are being used for project development activities, which include the negotiation of off-take agreements for the products and by-products of the plant to be constructed, securing permits and securing financing for the construction phase of the plant.  We have recorded our investment in this debt security at cost and classified it as held-to-maturity, since we have the intent and ability to hold it until it is redeemed.


GENESIS ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
 
No events or changes in circumstances have occurred that indicate a significant adverse effect on the fair value of our investment at December 31, 2008, therefore the investment is included in our consolidated balance sheet at cost.
 
9.  Intangible Assets, Goodwill and Other Assets
 
Intangible Assets
 
In connection with the Davison and DG Marine acquisitions (See Note 3), we allocated a portion of the purchase price to intangible assets based on their fair values.  The following table reflects the components of intangible assets being amortized at December 31, 2008:
 
         
December 31, 2008
   
December 31, 2007
 
   
Weighted Amortization Period in Years
   
Gross Carrying Amount
   
Accumulated Amortization
   
Carrying Value
   
Gross Carrying Amount
   
Accumulated Amortization
   
Carrying Value
 
                                           
                                           
Refinery services customer relationships
 
5
    $ 94,654     $ 26,017     $ 68,637     $ 94,654     $ 9,380     $ 85,274  
Supply and logistics customer relationships
 
5
      35,430       9,957       25,473       34,630       3,287       31,343  
Refinery services supplier relationships
 
2
      36,469       24,483       11,986       36,469       9,241       27,228  
Refinery services licensing agreements
 
6
      38,678       7,176       31,502       38,678       2,218       36,460  
Supply and logistics trade names - Davison and Grifco
 
7
      18,888       3,118       15,770       17,988       930       17,058  
Supply and logistics favorable lease
 
15
      13,260       671       12,589       13,260       197       13,063  
Other
 
5
      1,322       346       976       721       97       624  
Total
 
5
    $ 238,701     $ 71,768     $ 166,933     $ 236,400     $ 25,350     $ 211,050  

 
The licensing agreements referred to in the table above relate to the agreements we have with refiners to provide services.  The trade names are the Davison and Grifco names, which we retained the right to use in our operations.  The favorable lease relates to a lease of a terminal facility in Shreveport, Louisiana.
 
We are recording amortization of our intangible assets based on the period over which the asset is expected to contribute to our future cash flows.  Generally, the contribution to our cash flows of the customer and supplier relationships, licensing agreements and trade name intangible assets is expected to decline over time, such that greater value is attributable to the periods shortly after the acquisition was made.  The favorable lease and other intangible assets are being amortized on a straight-line basis.  Amortization expense on intangible assets was $46.4 million and $25.4 million for the years ended December 31, 2008 and 2007, respectively.
 
The following table reflects our estimated amortization expense for each of the five subsequent fiscal years:
 
   
2009
   
2010
   
2011
   
2012
   
2013
 
Refinery services customer relationships
  $ 15,433     $ 11,689     $ 8,972     $ 7,056     $ 7,116  
Supply and logistics customer relationships
    5,536       4,488       3,603       2,819       2,165  
Refinery services supplier relationships
    4,068       2,925       2,629       2,364       -  
Refinery services licensing agreements
    4,505       4,105       3,690       3,416       3,163  
Supply and logistics trade name
    2,326       2,086       1,851       1,432       1,237  
Supply and logistics favorable lease
    474       474       474       474       474  
Other
    285       187       53       54       56  
Total
  $ 32,627     $ 25,954     $ 21,272     $ 17,615     $ 14,211  
 

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

Goodwill
 
The carrying amount of goodwill by business segment at December 31, 2008 and 2007 was as follows:
 
   
Refinery
   
Supply &
       
   
Services
   
Logistics
   
Total
 
2007 Additions:
                 
Davison acquisition
  $ 297,621     $ 19,118     $ 316,739  
Port Hudson Assets Acquisition
    -       3,969       3,969  
Balance, December 31, 2007
    297,621       23,087       320,708  
Davison acquisition, due to purchase price adjustments
    4,338       -       4,338  
December 31, 2008
  $ 301,959     $ 23,087     $ 325,046  
 
We performed our annual goodwill impairment test pursuant to SFAS 142 on October 1, 2008.  The fair value of our supply and logistics and refinery services reporting units were estimated using a combined income (discounted cash flow) and market approach (guideline public company and comparable merged and acquired transactions) valuation method which indicated that the fair value of our net assets in each reporting unit exceeded the carrying value of that reporting unit, and an impairment charge was not required.  The estimated fair value of our reporting units is dependent on several significant assumptions and estimates, including our growth rates for revenues and costs, changes in operating margins, future capital expenditures related to our existing operations, our cost of capital (discount rate) and cash flow market multiples.  Our business plans and recent operating results also impact our estimate of the fair value of our reporting units.
 
SFAS 142 requires the performance of an interim goodwill impairment test if an event occurs or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying value.  Due to the ongoing deterioration of the credit markets and the overall macroeconomic conditions existing at December 31, 2008, we evaluated our fourth quarter performance and the outlook for our business segments, also considering the decline in our market capitalization, and concluded that we did not have a triggering event in the fourth quarter that would require the performance of an interim goodwill impairment test.
 
We will continue to monitor the general economic conditions, our operational and financial performance measures and our market capitalization to determine if a triggering event occurs and will perform an interim goodwill impairment analysis, if necessary.  We have not recognized any impairment losses related to goodwill for any of the periods presented.
 
Other Assets
 
Other assets consisted of the following.
 
   
December 31,
 
   
2008
   
2007
 
Credit facility fees - Genesis
  $ 5,022     $ 5,022  
Credit facility fees - DG Marine
    2,536       -  
Initial direct costs related to Free State Pipeline lease
    1,132       -  
Deferred tax asset
    1,543       941  
Other deferred costs and deposits
    7,502       3,284  
      17,735       9,247  
Less - Accumulated amortization
    (2,322 )     (850 )
Net other assets
  $ 15,413     $ 8,397  
 
Amortization of the initial direct costs related to the Free State Pipeline lease for the year ended December 31, 2008 was $35,000.  Amortization expense of credit facility fees for the years ended December 31, 2008, 2007 and 2006 was $1,437,000, $779,000 and $394,000, respectively.   In the fourth quarter of 2006, we also charged to expense $575,000 of unamortized fees related to the facility that we replaced in November 2006.   Total amortization of initial direct costs and credit facility fees for the next five years will be $1,993,000 for 2009 and 2010, $1,465,000 in 2011 and $60,000 in 2012 and 2013.


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

10.  Debt
 
At December 31, 2008 our obligations under credit facilities consisted of the following:
 
   
December 31, 2008
   
December 31, 2007
 
             
Genesis Credit Facility
  $ 320,000     $ 80,000  
DG Marine Credit Facility (non-recourse to Genesis)
    55,300       -  
Total Long-Term Debt
  $ 375,300     $ 80,000  
 
Genesis Credit Facility
 
We have a $500 million credit facility $100 million of which can be used for letters of credit, with a group of banks led by Fortis Capital Corp. and Deutsche Bank Securities Inc.  The borrowing base is recalculated quarterly and at the time of material acquisitions.  The borrowing base represents the amount that can be borrowed or utilized for letters of credit from a credit standpoint based on our EBITDA (earnings before interest, taxes, depreciation and amortization), computed in accordance with the provisions of our credit facility.
 
The borrowing base may be increased to the extent of pro forma additional EBITDA, as defined in the credit agreement, attributable to acquisitions or internal growth projects with approval of the lenders.  Our borrowing base as of December 31, 2008 exceeds $500 million.
 
At December 31, 2008, we had $320 million borrowed under our credit facility and we had $3.5 million in letters of credit outstanding.  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 November 15, 2011.  The total amount available for borrowings at December 31, 2008 was $176.5 million under our credit facility.
 
The key terms for rates under our credit facility are as follows:
 
 
·
The interest rate on borrowings 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 0.50% to the prime rate plus 1.875%.  The interest rate for LIBOR-based loans can range from the LIBOR rate plus 1.50% to the LIBOR rate plus 2.875%.  The rate is based on our leverage ratio as computed under the credit facility.  Our leverage ratio is recalculated quarterly and in connection with each material acquisition.   At December 31, 2008, our borrowing rates were the prime rate plus 0.50% or the LIBOR rate plus 1.50%.
 
 
·
Letter of credit fees will range from 1.50% to 2.875% based on our leverage ratio as computed under the credit facility.  The rate can fluctuate quarterly.  At December 31, 2008, our letter of credit rate was 1.50%.
 
 
·
We pay a commitment fee on the unused portion of the $500 million maximum facility amount.  The commitment fee will range from 0.30% to 0.50% based on our leverage ratio as computed under the credit facility.  The rate can fluctuate quarterly.  At December 31, 2008, the commitment fee rate was 0.30%.
 
Collateral under the credit facility consists of substantially all our assets, excluding our interest in the NEJD pipeline, our ownership interest in the Free State pipeline, and the assets of and our equity interest in, DG Marine. All of the equity interest of DG Marine is pledged to secure its credit facility, which is described below.  While our general partner is jointly and severally liable for all of our obligations unless and except to the extent those obligations provide that they are non-recourse to our general partner, our credit facility expressly provides that it is non-recourse to our general partner (except to the extent of its pledge of its general partner interest in certain of our subsidiaries), as well as to Denbury and its other subsidiaries.
 
Our credit facility contains customary covenants (affirmative, negative and financial) that limit the manner in which we may conduct our business.  Our credit facility contains three primary financial covenants - a debt service coverage ratio, leverage ratio and funded indebtedness to capitalization ratio – that require us to achieve specific minimum financial metrics.  In general, our debt service coverage ratio calculation compares EBITDA (as defined and adjusted in accordance with the credit facility) to interest expense.  Our leverage ratio calculation compares our consolidated funded debt (as calculated in accordance with our credit facility) to EBITDA (as adjusted).  Our funded indebtedness ratio compares outstanding debt to the sum of our consolidated total funded debt plus our consolidated net worth.
 

GENESIS ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
 
       
Required
 
Actual
       
Ratio through
 
Ratio as of
       
December 31,
 
December 31,
Financial Covenant
 
Requirement
 
2008
 
2008
             
Debt Service Coverage Ratio
 
Minimum
 
2.75 to 1.0
 
8.53 to 1.0
Leverage Ratio
 
Maximum
 
6.0 to 1.0
 
2.82 to 1.0
Funded Indebtedness Ratio
 
Maximum
 
0.80 to 1.0
 
0.39 to 1.0

 
Our credit facility includes provisions for the temporary adjustment of the required ratios following material acquisitions and with lender approval.  The ratios in the table above are the required ratios for the period following a material acquisition.  If we meet these financial metrics and are not otherwise in default under our credit facility, we may make quarterly distributions; however, the amount of such distributions may not exceed the sum of the distributable cash (as defined in the credit facility) generated by us for the eight most recent quarters, less the sum of the distributions made with respect to those quarters.  At December 31, 2008, the excess of distributable cash over distributions under this provision of the credit facility was $49.7 million.
 
DG Marine Credit Facility
 
In connection with its acquisition of the Grifco assets on July 18, 2008, DG Marine entered into a $90 million revolving credit facility with a syndicate of banks led by SunTrust Bank and BMO Capital Markets Financing, Inc.  In addition to partially financing the Grifco acquisition, DG Marine may borrow under that facility for general corporate purposes, such as paying for its newly constructed barges and funding working capital requirements, including up to $5 million in letters of credit.  That facility, which matures on July 18, 2011, is secured by all of the equity interests issued by DG Marine and substantially all of DG Marine’s assets.  Other than the pledge of our equity interest in DG Marine and our guaranty of $7.5 million, that facility is non-recourse to us and TD Marine.  At December 31, 2008, our consolidated balance sheet included $115.8 million of DG Marine’s assets in our total assets.
 
At December 31, 2008, DG Marine had $55.3 million outstanding under its credit facility.  Due to the revolving nature of loans under the DG Marine credit facility, additional borrowings and periodic repayments and re-borrowings may be made until the maturity date.  The total amount available for borrowings at December 31, 2008 was $34.7 million under this credit facility.
 
The key terms for rates under the DG Marine credit facility are as follows:
 
 
·
The interest rate on borrowings may be based on the prime rate or the LIBOR rate, at our option.  The interest rate on prime rate loans can range from the prime rate plus 1.50% to the prime rate plus 4.00%.  The interest rate for LIBOR-based loans can range from the LIBOR rate plus 2.50% to the LIBOR rate plus 5.00%.  The rate is based on DG Marine’s leverage ratio as computed under the credit facility. Under the terms of DG Marine’s credit facility, the rates will fluctuate quarterly based on the leverage ratio. At December 31, 2008, DG Marine’s borrowing rates were the prime rate plus 4.00% or the LIBOR rate plus 5.00%.
 
 
·
Letter of credit fees will range from 2.50% to 5.00% based on DG Marine’s leverage ratio as computed under the credit facility.  The rate can fluctuate quarterly.  At December 31, 2008, there were no letters of credit outstanding under the DG Marine credit facility.
 
 
·
DG Marine pays a commitment fee on the unused portion of the $90 million facility amount.  The commitment fee will range from 0.25% to 0.50% based on its leverage ratio as computed under the credit facility.  The rate will fluctuate quarterly based on the leverage ratio.  At December 31, 2008, the commitment fee rate was 0.50%.
 
In August 2008, DG Marine entered into a series of interest rate swap agreements to effectively fix the underlying LIBOR rate on $32.9 million of its borrowings under its credit facility through July 18, 2011. The fixed interest rates in the swap agreements range from the three-month interest rate of 3.20% in effect at December 31, 2008 to 4.68% at July 18, 2011.


GENESIS ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
 
DG Marine’s credit facility contains customary covenants (affirmative, negative and financial) that limit the manner in which it may conduct its business.  DG Marine’s credit facility contains three primary financial covenants – an interest coverage ratio, leverage ratio and asset coverage ratio – that require DG Marine to achieve specific minimum financial metrics.  In general, the interest coverage ratio calculation compares EBITDA (as defined and adjusted in accordance with the credit facility) to interest expense.  The leverage ratio calculation compares DG Marine’s funded debt (as calculated in accordance with the credit facility) to EBITDA (as adjusted).  The asset coverage ratio compares an estimated liquidation value of DG Marine’s boats and barges to DG Marine’s outstanding debt.
 
Maturities of long-term debt in the next five years, including the DG Marine credit facility, are $375.3 million in 2011.  We have estimated the fair value of our long-term debt to be approximately $358.4 million, or $16.9 million less than the carrying value of that debt based on consideration of our credit standing.
 
11.  Partners’ Capital and Distributions
 
Partner’s capital at December 31, 2008 consists of 39,456,774 common units, including 4,028,096 units owned by our general partner and its affiliates, 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.
 
Our general partner owns all of our general partner interest, including incentive distribution rights (IDRs), all of the 0.01% general partner interest in Genesis Crude Oil, L.P. (which is reflected as a minority interest in the Consolidated Balance Sheet at December 31, 2008) 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.  As discussed in Note 10, our credit facility limits the amount of distributions we may pay in any quarter.  At December 31, 2008, our restricted net assets (as defined in Rule 4-03(e)(3) of Regulations S-X) were $573.6 million.
 
Pursuant to our partnership agreement, our general partner receives incremental incentive cash distributions when unitholders’ cash distributions exceed certain target thresholds, in addition to its 2% general partner interest.  The allocations of distributions between our common unitholders and our general partner, including the incentive distribution rights is as follows:
 
         
General
 
   
Unitholders
   
Partner
 
Quarterly Cash Distribution per Common Unit:
           
Up to and including $0.25 per Unit
    98.00 %     2.00 %
First Target - $0.251 per Unit up to and including $0.28 per Unit
    84.74 %     15.26 %
Second Target - $0.281 per Unit up to and including $0.33 per Unit
    74.26 %     25.47 %
Over Second Target - Cash distributions greater than $.033 per Unit
    49.02 %     50.98 %


GENESIS ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
 
We paid distributions in 2007 and 2008 as follows:
 
                         
General
       
             
Limited
   
General
   
Partner
       
             
Partner
   
Partner
   
Incentive
       
       
Per Unit
   
Interests
   
Interest
   
Distribution
   
Total
 
Distribution For
 
Date Paid
 
Amount
   
Amount
   
Amount
   
Amount
   
Amount
 
                 
Fourth quarter 2006
 
February 2007
  $ 0.2100     $ 2,895     $ 59     $ -     $ 2,954  
First quarter 2007
 
May 2007
  $ 0.2200     $ 3,032     $ 62     $ -     $ 3,094  
Second quarter 2007
 
August 2007
  $ 0.2300     $ 3,170 (1)   $ 65     $ -     $ 3,235 (1)
Third quarter 2007
 
November 2007
  $ 0.2700     $ 7,646     $ 156     $ 90     $ 7,892  
Fourth quarter 2007
 
February 2008
  $ 0.2850     $ 10,902     $ 222     $ 245     $ 11,369  
First quarter 2008
 
May 2008
  $ 0.3000     $ 11,476     $ 234     $ 429     $ 12,139  
Second quarter 2008
 
August 2008
  $ 0.3150     $ 12,427     $ 254     $ 633     $ 13,314  
Third quarter 2008
 
November 2008
  $ 0.3225     $ 12,723     $ 260     $ 728     $ 13,711  
Fourth quarter 2008
 
February 2009
  $ 0.3300     $ 13,021     $ 266     $ 823     $ 14,110  

 
(1)  The distribution paid on August 14, 2007 to holders of our common units is net of the amounts payable with respect to the common units issued in connection with the Davison transaction.  The Davison unitholders and our general partner waived their rights to receive such distributions, instead receiving purchase price adjustments with us.
 
Net Income (Loss) per Common Unit
 
The following table sets forth the computation of basic net income per common unit.
 
   
Year Ended December 31,
 
   
2008
   
2007
   
2006
 
Numerators for basic and diluted net income (loss)per common unit:
                 
Income (loss) before cumulative effect adjustment
  $ 26,089     $ (13,550 )   $ 8,351  
Less: General partner's incentive distribution paid
    (2,035 )     -       -  
Subtotal
    24,054       (13,550 )     8,351  
Less: General partner 2% ownership
    (481 )     271       (167 )
Income (loss) before cumulative effect adjustment available for common unitholders
  $ 23,573     $ (13,279 )   $ 8,184  
                         
Income from cumulative effect adjustment
  $ -     $ -     $ 30  
Less: General partner 2% ownership
    -       -       -  
Income from cumulative effect adjustment available for common unitholders
  $ -     $ -     $ 30  
                         
Denominator for basic per common unit:
                       
Common Units
    38,961       20,754       13,784  
                         
Denominator for diluted per common unit:
                       
Common Units
    38,961       20,754       13,784  
Phantom Units
    64       -       -  
      39,025       20,754       13,784  
                         
Basic net income per common unit
  $ 0.61     $ (0.64 )   $ 0.59  
Diluted net income per common unit
  $ 0.60     $ (0.64 )   $ 0.59  


GENESIS ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
 
Equity Issuances and Contributions
 
During the last three years we have issued a total of 15,495,940 common units in the acquisition of assets.  A summary of these unit issuances is as follows:
 
             
Value
 
   
Acquisition
       
Attributed
 
Period
 
Transaction
 
Units
   
to Assets
 
July 2008
 
Grifco
    838     $ 16,667  
May 2008
 
Free State Pipeline
    1,199     $ 25,000  
July 2007
 
Davison
    13,459     $ 330,000  

 
We issued new common units to the public and our general partner for cash as follows:
 
   
Purchaser of
       
Gross
   
Issuance
   
GP
         
Net
 
Period
 
Common Units
 
Units
   
Unit Price
   
Value
   
Contributions
   
Costs
   
Proceeds
 
December 2007
 
Public
    9,200     $ 22.000     $ 202,400     $ -     $ 8,846     $ 193,554  
December 2007
 
General Partner
    735     $ 21.120     $ 15,518     $ 4,447     $ -     $ 19,965  
July 2007
 
General Partner
    1,075     $ 20.836     $ 22,361     $ 6,171     $ -     $ 28,532  

 
On July 18, 2008, we issued 837,690 of our common units to Grifco.  The units were issued at a value of $19.896 per unit, for a total value of $16.7 million, as a portion of the consideration for the acquisition of the inland marine transportation business of Grifco.
 
Additionally, on July 18, 2008, we redeemed 837,690 of our common units owned by members of the Davison family.  Those units had been issued as a portion of the consideration for the acquisition of the energy-related business of the Davison family in July 2007.  The redemption was at a value of $19.896 per unit, for a total value of $16.7 million.  After giving effect to the issuance and redemption described above, we did not experience a change in the number of common units outstanding
 
On May 30, 2008, we issued 1,199,041 common units to Denbury in connection with the acquisition of the Free State pipeline.  Our general partner also contributed $0.5 million to maintain its capital account balance.
 
On December 10, 2007 we issued 9,200,000 common units is a public offering, providing cash of $193.6 million after underwriters discount and offering costs.  Our general partner exercised its right to maintain its proportionate share of our outstanding units and purchased 734,732 common units from us for $15.5 million, or $21.12 per common unit.  Our general partner also contributed approximately $4.4 million to maintain its capital account balance.
 
In July 2007, we issued 13,459,209 common units to the entities owned and controlled by the Davison family as a portion of the purchase price.  Additionally at that time, our general partner exercised its right to maintain its proportionate share of our outstanding common units by purchasing 1,074,882 common units from us for $22.4 million cash, or $20.8036 per common unit.  As required under our partnership agreement, our general partner also contributed approximately $6.2 million to maintain its capital account balance.
 
Our general partner made a capital contribution of $1.4 million in December 2007 to offset a portion of the severance payment to a former executive.  We also recorded a non-cash capital contribution of $3.4 million from our general partner for the estimated value of the compensation earned in 2007 under the proposed arrangements with our senior management team related to an incentive interest in our general partner.   As the purpose of incentive interest is to incentivize these individuals to grow the partnership, the expense is recognized as compensation by us and a capital contribution by the general partner.
 
12.  Business Segment Information
 
Our operations consist of four operating segments:  (1) Pipeline Transportation – interstate and intrastate crude oil, and to a lesser extent, natural gas and CO 2 pipeline transportation; (2) Refinery Services – processing high sulfur (or “sour”) gas streams as part of refining operations to remove the sulfur and sale of the related by-product; (3) Industrial Gases – the sale of CO 2 acquired under volumetric production payments to industrial customers and our investment in a syngas processing facility, and (4) Supply and Logistics – terminaling, blending, storing, marketing, gathering and transporting by truck and barge crude oil and petroleum products. All of our revenues are derived from, and all of our assets are located in the United States.


GENESIS ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
 
During the fourth quarter of 2008, we revised the manner in which we internally evaluate our segment performance.  As a result, we changed our definition of segment margin to include within segment margin all costs that are directly associated with the business segment.  Segment margin now includes costs such as general and administrative expenses that are directly incurred by the business segment.  Segment margin also includes all payments received under direct financing leases.  In order to improve comparability between periods, we exclude from segment margin the non-cash effects of our stock-based compensation plans which are impacted by changes in the market price for our common units.  Previous periods have been restated to conform to this segment presentation.  We now define segment margin as revenues less cost of sales, operating expenses (excluding depreciation and amortization), and segment general and administrative expenses, plus our equity in distributable cash generated by our joint ventures.  Our segment margin definition also excludes the non-cash effects of our stock-based compensation plans, and includes the non-income portion of payments received under direct financing leases.  Our chief operating decision maker (our Chief Executive Officer) evaluates segment performance based on a variety of measures including segment margin, segment volumes where relevant and maintenance capital investment.
 

GENESIS ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
   
Pipeline
   
Refinery
   
Industrial
   
Supply &
       
   
Transportation
   
Services
   
Gases (a)
   
Logistics
   
Total
 
Year Ended December 31, 2008
                             
Segment margin excluding depreciation and amortization (b)
  $ 33,149     $ 55,784     $ 13,504     $ 32,448     $ 134,885  
                                         
Capital expenditures (c)
  $ 262,200     $ 5,490     $ 2,397     $ 118,585     $ 388,672  
Maintenance capital expenditures
  $ 719     $ 1,881     $ -     $ 1,854     $ 4,454  
Net fixed and other long-term assets (d)
  $ 285,773     $ 434,956     $ 44,003     $ 245,815     $ 1,010,547  
                                         
Revenues:
                                       
External customers
  $ 39,051     $ 233,871     $ 17,649     $ 1,851,113     $ 2,141,684  
Intersegment (e)
    7,196       (8,497 )     -       1,301       -  
Total revenues of reportable segments
  $ 46,247     $ 225,374     $ 17,649     $ 1,852,414     $ 2,141,684  
                                         
Year Ended December 31, 2007
                                       
Segment margin excluding depreciation and amortization (b)
  $ 14,170     $ 19,713     $ 13,038     $ 10,646     $ 57,567  
                                         
Capital expenditures (c)
  $ 6,592     $ 503,765     $ 1,104     $ 138,403     $ 649,864  
Maintenance capital expenditures
  $ 2,880     $ 469     $ -     $ 491     $ 3,840  
Net fixed and other long-term assets (d)
  $ 32,936     $ 468,068     $ 47,364     $ 145,915     $ 694,283  
                                         
Revenues:
                                       
External customers
  $ 23,226     $ 62,095     $ 16,158     $ 1,098,174     $ 1,199,653  
Intersegment (e)
    3,985       -       -       (3,985 )     -  
Total revenues of reportable segments
  $ 27,211     $ 62,095     $ 16,158     $ 1,094,189     $ 1,199,653  
                                         
Year Ended December 31, 2006
                                       
Segment margin excluding depreciation and amortization (b)
  $ 13,280     $ -     $ 12,844     $ 5,017     $ 31,141  
                                         
Capital expenditures (c)
  $ 971     $ -     $ 6,058     $ 356     $ 7,385  
Maintenance capital expenditures
  $ 611     $ -     $ -     $ 356     $ 967  
Net fixed and other long-term assets (d)
  $ 31,863     $ -     $ 51,630     $ 7,602     $ 91,095  
                                         
Revenues:
                                       
External customers
  $ 25,479     $ -     $ 15,154     $ 877,736     $ 918,369  
Intersegment (e)
    4,468       -       -       (4,468 )     -  
Total revenues of reportable segments
  $ 29,947     $ -     $ 15,154     $ 873,268     $ 918,369  
 

GENESIS ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
 
 
(a)
The industrial gases segment includes our CO 2 marketing operations and the income from our investments in T&P Syngas and Sandhill.
 
(b)
A reconciliation of segment margin to income before income taxes and minority interest for each year presented is as follows:

   
Year Ended December 31,
 
   
2008
   
2007
   
2006
 
Segment margin excluding depreciation and amortization
  $ 134,885     $ 57,567     $ 31,141  
Corporate general and administrative expenses
    (22,113 )     (17,573 )     (10,238 )
Depreciation and amortization
    (71,370 )     (40,245 )     (7,963 )
Net (loss) gain on disposal of surplus assets
    (29 )     (266 )     16  
Interest expense, net
    (12,937 )     (10,100 )     (1,374 )
Non-cash expenses not included in segment margin
    1,206       (1,855 )     (1,343 )
Other non-cash items affecting segment margin
    (4,179 )     (1,733 )     (1,898 )
Income (loss) before income taxes and minority interest
  $ 25,463     $ (14,205 )   $ 8,341  

 
 
(c)
Capital expenditures includes fixed asset additions and acquisitions of businesses.
 
 
(d)
Net fixed and other long-term assets is a measure used by management in evaluating the results of our operations on a segment basis.  Current assets are not allocated to segments as the amounts are not meaningful in evaluating the success of the segment’s operations.  Amounts for our Industrial Gases segment include investments in equity investees totaling $14.5 million, $16.2 million and $17.2 million at December 31, 2008, 2007 and 2006, respectively.
 
 
(e)
Intersegment sales were conducted on an arm’s length basis.
 
13.  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,
 
   
2008
   
2007
   
2006
 
                   
Truck transportation services provided to Denbury
  $ 3,578     $ 1,791     $ 825  
Pipeline transportation services provided to Denbury
  $ 10,727     $ 5,290     $ 4,228  
Payments received under direct financing leases from Denbury
  $ 11,519     $ 1,188     $ 1,186  
Pipeline transportation income portion of direct financing lease fees
  $ 11,011     $ 641     $ 655  
Pipeline monitoring services provided to Denbury
  $ 120     $ 120     $ 65  
Directors' fees paid to Denbury
  $ 195     $ 150     $ 120  
CO2 transportation services provided by Denbury
  $ 6,424     $ 5,213     $ 4,640  
Crude oil purchases from Denbury
  $ -     $ 101     $ 1,565  
Operations, general and administrative services provided by our general partner
  $ 51,872     $ 22,490     $ 16,777  
Distributions to our general partner on its limited partner units and general partner interest, including incentive distributions
  $ 6,463     $ 1,671     $ 963  
Sales of CO2 to Sandhill (for the period since Sandhill became a related party)
  $ 2,941     $ 2,783     $ 2,056  
Petroleum products sales to Davison family businesses
  $ 1,261     $ -     $ -  
Transition services costs to Davison family
  $ -     $ 9,880     $ -  

 
Transportation Services
 
We provide truck transportation services to Denbury to move their crude oil from the wellhead to our Mississippi pipeline.  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 supply and logistics revenues.
 
Denbury is the only shipper on our Mississippi pipeline other than us, and we earn tariffs for transporting their oil.  We earned fees from Denbury for the transportation of their CO 2 on our Free State pipeline.  We also earned fees from Denbury under the direct financing lease arrangements for the Olive and Brookhaven crude oil pipelines and the Brookhaven and NEJD CO 2 pipelines and recorded pipeline transportation income from these arrangements.
 
We also provide pipeline monitoring services to Denbury.  This revenue is included in pipeline revenues in the statements of operations.
 
Directors’ Fees
 
We paid Denbury for the services of each of four of Denbury’s officers who serve as directors of our general partner, at an annual rate and for attendance at meetings that are the same as the rates at which our independent directors were paid.
 
CO 2 Operations and Transportation
 
Denbury charges us a transportation fee of $0.16 per Mcf (adjusted for inflation) to deliver CO 2 for us to our customers.   In 2008, the inflation-adjusted transportation fee averaged $0.1927 per Mcf.
 
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, excluding any payments to our management team pursuant to their Class B Membership Interests.  See Note 15.


GENESIS ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
 
Amounts due to and from Related Parties
 
At December 31, 2008 and 2007, we owed Denbury $1.0 million, respectively, for CO 2 transportation charges.  Denbury owed us $2.0 million and $0.9 million for transportation services at December 31, 2008 and 2007, respectively.  We owed our general partner $2.1 million and $0.7 million for administrative services at December 31, 2008 and 2007, respectively.  At December 31, 2008 and 2007, Sandhill owed us $0.7 and $0.5 million for purchases of CO 2 , respectively.  At December 31, 2007, we owed the Davison family entities $0.8 million for reimbursement of costs paid primarily related to employee transition services.
 
Drop-down transactions
 
On May 30, 2008, we entered into a $175 million financing lease arrangement with Denbury Onshore for its NEJD Pipeline System, and acquired its Free State CO 2 pipeline system for $75 million, consisting of $50 million cash and $25 million of our common units.  See Note 3.
 
Unit redemption
 
As discussed in Note 11, we redeemed 837,690 of our common units owned by members of the Davison family.  The total value of the units redeemed was $16.7 million.
 
DG Marine joint venture
 
Our partner in the DG Marine joint venture is TD Marine, LLC, a joint venture consisting of three members of the Davison family.  See Note 3.
 
Financing
 
Our credit facility is non-recourse to our general partner, except to the extent of its pledge of its 0.01% general partner interest in Genesis Crude Oil, L.P.  Our general partner’s principal assets are its general and limited partnership interests in us.  Our credit agreement obligations are not guaranteed by Denbury or any of its other subsidiaries.  
 
We guarantee 50% of the obligation of Sandhill to a bank.  At December 31, 2008, the total amount of Sandhill’s obligation to the bank was $3.0 million; therefore, our guarantee was for $1.5 million.
 
Approximately 14% of the outstanding common shares of Community Trust Bank are held by Davison family members.  Community Trust Bank is a 17% participant in the DG Marine credit facility.  James E. Davison, Jr., a member of our board of directors, also serves on the board of the holding company that owns Community Trust Bank.
 
As discussed in Note 11, our general partner made capital contributions in order to maintain its capital account totaling $0.5 million and $10.6 million in 2008 and 2007, respectively.  Our general partner also purchased common units totaling $37.9 million in 2007. In addition, our general partner made a capital contribution of $1.4 million in December 2007 to offset a portion of the severance payment to a former executive.  In 2007, we recorded a capital contribution from our general partner of $3.4 million related to compensation recognized for our executive management team.  See Note 15.
 
In December 2008, our general partner established Class B Membership Interests in our general partner to be used as long-term incentive compensation for our senior executives.  See Note 15.


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

14.  Supplemental Cash Flow Information
 
The following table provides information regarding the net changes in components of operating assets and liabilities.
 
   
Year Ended December 31,
 
   
2008
   
2007
   
2006
 
Decrease (increase) in:
                 
Accounts receivable
  $ 61,126     $ (35,362 )   $ (6,472 )
Inventories
    (5,557 )     (143 )     (4,664 )
Other current assets
    (2,419 )     (1,887 )     870  
Increase (decrease) in:
                       
Accounts payable
    (58,224 )     34,523       1,359  
Accrued liabilities
    3,812       6,149       34  
Net changes in components of operating assets and liabilities,  net of working capital acquired
  $ (1,262 )   $ 3,280     $ (8,873 )

 
Cash received by us for interest during the years ended December 31, 2008, 2007 and 2006 was $0.1 million, $0.3 million and $0.2 million, respectively.  Payments of interest and commitment fees were $11.3 million, $8.4 million and $1.0 million, during the years ended December 31, 2008, 2007 and 2006, respectively.
 
Cash paid for income taxes in during the years ended December 31, 2008 and 2007 was $2.4 million and $1.6 million, respectively.
 
At December 31, 2008 and 2007, we had incurred liabilities for fixed asset additions totaling $1.7 million and $0.9 million, 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.  We had incurred liabilities for other assets totaling $0.3 million at December 31, 2007 that had not been paid at the end of the year and, therefore, are not included in the caption “Other, net” under investing activities on the Consolidated Statements of Cash Flows.
 
In May 2008, we issued common units with a value of $25 million as part of the consideration for the acquisition of the Free State Pipeline from Denbury.  In July 2008, we issued common units with a value of $16.7 million as part of the consideration for the acquisition of the inland marine transportation assets of Grifco. These common unit issuances are non-cash transactions and the value of the assets acquired is not included in investing activities and the issuance of the common units is not reflected under financing activities in our Consolidated Statements of Cash Flows.  Additionally, we deferred payment of $12 million ($11.7 million discounted) of the consideration in the acquisition from Grifco to December 2008 and 2009.  This deferral of the payment of consideration was a non-cash transaction and the value of the assets acquired is not included in investing activities and the payments due in December 2009 is not reflected under financing activities in our Consolidated Statements of Cash Flows.  The subsequent payment in December 2008 of one-half of the consideration is included in financing cash flows.
 
In July 2007, we issued common units with a value of $330 million as part of the consideration in the Davison acquisition.  This common unit issuance is a non-cash transaction and the value of the assets acquired is not included under investing activities and the issuance of the common units are not reflected under financing activities in our Consolidated Statements of Cash Flows.
 
In 2007, our general partner made a non-cash contribution to us in the amount of $3.4 million that is not included in financing activities in the Consolidated Statements of Cash Flows.  This contribution related to the estimated compensation earned by our management team for its services in 2007 under the proposed compensation arrangement with these individuals that existed at December 31, 2007.
 
15.  Employee Benefit Plans and Equity-Based Compensation 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 its 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 $2.2 million, $0.8 million, and $0.7 million for the years ended December 31, 2008, 2007 and 2006, 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 $1.7 million, $1.5 million, and $1.3 million in 2008, 2007 and 2006, respectively.  Effective January 1, 2008, the employees who operate the assets we acquired from the Davison family became participants in these plans.


GENESIS ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
 
Stock Appreciation Rights Plan
 
Under the terms of our stock appreciation rights plan, regular, full-time active employees (with the exception of our chief executive officer, chief operating officer and chief financial officer) 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, who shall receive awards under the plan, 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.  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 averages 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 compensation cost associated with our stock appreciation rights plan, which upon exercise will result in the payment of cash to the employee, is re-measured each reporting period based on the fair value of the rights.  Under SFAS No. 123 (revised December 2004), “Share-Based Payments.”, the liability is calculated using a fair value method that takes into consideration the expected future value of the rights at their expected exercise dates.
 
We have elected to calculate the fair value of the rights under the plan using the Black-Scholes valuation model.  This model requires that we include the expected volatility of the market price for our common units, the current price of our common units, the exercise price of the rights, the expected life of the rights, the current risk free interest rate, and our expected annual distribution yield.  This valuation is then applied to the vested rights outstanding and to the non-vested rights based on the percentage of the service period that has elapsed.  The valuation is adjusted for expected forfeitures of rights (due to terminations before vesting, or expirations after vesting).  The liability amount accrued on the balance sheet is adjusted to this amount at each balance sheet date with the adjustment reflected in the statement of operations.
 
The estimates that we make each period to determine the fair value of these rights include the following assumptions:
 
Assumptions Used for Fair Value of Rights
 
   
December 31, 2008
   
December 31, 2007
   
December 31, 2006
 
Expected life of rights (in years)
    1.25 - 6.00       2.25 - 6.25       3.25 - 7.00  
Risk-free interest rate
    0.57% - 1.71 %     3.12% - 3.65 %     4.53% - 4.57 %
Expected unit price volatility
    42.8 %     34.2 %     32.1 %
Expected future distribution yield
    6.00 %     6.00 %     6.00 %
 

GENESIS ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
 
 
·
In determining the expected life of the rights, we use the simplified method allowed by the Securities and Exchange Commission.  As our stock appreciation rights plan was not put in place until December 31, 2003, we have very limited experience with employee exercise patterns.
 
 
·
The expected volatility of our units is computed using the historical period we believe is representative of future expectations.  We determined the period to use as the historical period by considering our distribution history and distribution yield.
 
 
·
The risk-free interest rate was determined from the current yield for U.S. Treasury zero-coupon bonds with a term similar to the remaining expected life of the rights.
 
 
·
In determining our expected future distribution yield, we considered our history of distribution payments, our expectations for future payments, and the distribution yields of entities similar to us.  While current market conditions result in a higher distribution yield, we believe that the yield will be closer to 6% over the life of the outstanding rights.
 
 
·
We estimated the expected forfeitures of non-vested rights and expirations of vested rights.  We have very limited experience with employee forfeiture and expiration patterns, as our plan was not initiated until December 31, 2003. We reviewed the history available to us as well as employee turnover patterns in determining the rates to use.  We also used different estimates for different groups of employees.
 
The following table reflects rights activity under our plan as of January 1, 2008, and changes during the year ended December 31, 2008:
 
Stock Appreciation Rights
 
Rights
   
Weighted Average Exercise Price
   
Weighted Average Contractual Remaining Term (Yrs)
   
Aggregate Intrinsic Value
 
                         
Outstanding at January 1, 2008
    593,458     $ 15.45              
Granted during 2008
    536,308     $ 20.83              
Exercised during 2008
    (38,995 )   $ 19.52              
Forfeited or expired during 2008
    (72,786 )   $ 21.23              
Outstanding at December 31, 2008
    1,017,985     $ 18.09       7.9     $ -  
Exercisable at December 31, 2008
    381,016     $ 14.82       6.2     $ -  
 
The weighted-average fair value at December 31, 2008 of rights granted during 2008 was $0.67 per right, determined using the following assumptions:
 
Assumptions Used for Fair Value of Rights
 
Granted in 2008
 
Expected life of rights (in years)
    5.25 - 6.00  
Risk-free interest rate
    1.57% - 1.71 %
Expected unit price volatility
    42.8 %
Expected future distribution yield
    6.00 %

 
The total intrinsic value of rights exercised during 2008, 2007 and 2006 was $0.4 million, $1.6 million and $0.4 million, respectively, which was paid in cash to the participants.
 
At December 31, 2008, there was $0.2 million of total unrecognized compensation cost related to rights that we expect will vest under the plan.  This amount was calculated as the fair value at December 31, 2008 multiplied by those rights for which compensation cost has not been recognized, adjusted for estimated forfeitures.  This unrecognized cost will be recalculated at each balance sheet date until the rights are exercised, forfeited or expire.  For the awards outstanding at December 31, 2008, the remaining cost will be recognized over a weighted average period of approximately one year.


GENESIS ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
 
We recorded charges and credits related to our stock appreciation rights for three years ended December 31, 2008 as follows:
 
Expense (Credits to Expense) Related to Stock Appreciation Rights
 
                   
Statement of Operations
 
2008
   
2007
   
2006
 
Supply and logistics operating costs
  $ (997 )   $ 528     $ 362  
Refinery services operating costs
    23       -       -  
Pipeline operating costs
    (296 )     420       289  
General and administrative expenses
    (1,141 )     1,576       1,279  
Total
  $ (2,411 )   $ 2,524     $ 1,930  

 
2007 Long Term Incentive Plan
 
Our Genesis Energy, Inc. 2007 Long Term Incentive Plan (the “2007 LTIP”) provides for awards of Phantom Units and Distribution Equivalent Rights to non-employee directors and employees of Genesis Energy, LLC, our general partner. Phantom Units are notional units representing unfunded and unsecured promises to deliver a Partnership common unit to the participant should specified vesting requirements be met. Distribution Equivalent Rights are rights to receive an amount of cash equal to all or a portion of the cash distributions made by the Partnership during a specified period. The 2007 LTIP is administered by the Compensation Committee of the board of directors of our general partner (the “Board”).
 
The Compensation Committee (at its discretion) will designate participants in the 2007 LTIP, determine the types of awards to grant to participants, determine the number of units to be covered by any award, and determine the conditions and terms of any award including vesting, settlement and forfeiture conditions. The 2007 LTIP may be amended or terminated at any time by the Board or the Compensation Committee; however, any material amendment, such as a material increase in the number of units available under the 2007 LTIP or a change in the types of awards available under the 2007 LTIP, will also require the approval of our unitholders. The Compensation Committee is also authorized to make adjustments in the terms and conditions of and the criteria included in awards under the plan in specified circumstances.
 
The common units to be awarded under the 2007 Plan will be obtained by our general partner through purchases made on the open market, from us, from any affiliates of our general partner or from any other person; however, it is generally intended that units are to be acquired from us as newly-issued common units.
 
Subject to adjustment as provided in the 2007 LTIP, awards with respect to up to an aggregate of 1,000,000 units may be granted under the 2007 LTIP, of which 915,429 remain authorized for issuance at December 31, 2008.  Compensation expense is recognized on a straight-line basis over the vesting period.  The fair value of the units is based on the market price of the underlying common units on the date of grant and an allowance for estimated forfeitures.  Due to the positions of the small group of employees and non-employee directors who received these grants, we have assumed that there will be no forfeitures of these Phantom Units in our fair value calculation as of December 31, 2008.  The grant date fair value of the awards are measured by reducing the grant date market price by the present value of the distributions expected to be paid on the shares during the requisite service period, discounted at an appropriate risk-free interest rate.
 
The aggregate grant date fair value of Phantom Unit awards granted during 2008 and 2007 was $0.8 million and $0.9 million, respectively.  The total fair value of Phantom Units that vested during the year ended December 31, 2008 was $0.1 million.  Compensation expense recognized during 2008 for Phantom Units was $0.7 million.  Expense recorded during 2007 was less than $0.1 million.  As of December 31, 2008, there was $0.9 million of unrecognized compensation expense related to these units.  This unrecognized compensation cost is expected to be recognized over a weighted-average period of one year.


GENESIS ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
 
The following table summarizes information regarding our non-vested Phantom Unit grants as of December 31, 2008:
 
         
Weighted-Average
 
   
Number of
   
Grant-Date
 
Non-vested Phantom Unit Grants
 
Units
   
Fair Value
 
             
Non-vested at January 1, 2007
    -        
Granted during 2007
    39,362     $ 21.92  
Non-vested at December 31, 2007
    39,362     $ 21.92  
Granted during 2008
    45,209     $ 17.63  
Vested during 2008
    (6,183 )   $ 23.46  
Non-vested at December 31, 2008
    78,388     $ 19.32  
 
The weighted-average fair value of Phantom Units granted during 2007 and 2008 was determined using the following assumptions:
 
         
Expected
       
Year
 
Grant Date
   
Distribution
   
Risk Free
 
Granted
 
Price
   
Rate
   
Rate
 
2007
  $ 24.52     $ 0.27      
3.19% - 3.31%
 
2008
  $ 15.50 - $21.30     $ 0.285 - $0.315      
2.01% - 2.40%
 
 
Bonus Program
 
In January 2009, the Committee of the Board of our general partner approved a bonus program (referred to below as the Bonus Plan) for all employees of our general partner (with the exception of our Chief Executive Officer, Chief Operating Officer and Chief Financial Officer (collectively our “Senior Executives”)) that was applicable to 2008.  The Bonus Plan is paid at the discretion of our Board based on the recommendation of the Compensation Committee, and can be amended or changed at any time.  The Bonus Plan is designed to enhance the financial performance of the Partnership by rewarding employees for achieving financial performance and safety objectives.  While the maximum amount that will be paid each year as bonuses is calculated based on two metrics, the actual amounts paid individually are discretionary and may total to less than the maximum that might otherwise be available.
 
The Bonus Plan is based primarily on the amount of money we generate for distributions to our unitholders, and is measured on a calendar-year basis.  For 2008, two metrics were used to determine the bonus pool – the level of Available Cash before Reserves (before subtracting bonus expense and related employer tax burdens) that we generate and our company-wide safety record improvement. The level of Available Cash before Reserves generated for the year as a percentage of a target set by our Committee is weighted ninety percent and the achieved level of the targeted improvement in our safety record is weighted ten percent.  The sum of the weighted percentage achievement of these targets is multiplied by the eligible compensation and the target percentages established by our Compensation Committee for the various levels of our employees to determine the maximum bonus pool from which the majority of our employees are paid bonuses.
 
A separate marketing bonus pool is available for compensating certain marketing personnel that is based on the contribution of that marketing group to Available Cash before Reserves.  A minimum level of contribution to Available Cash before Reserves is required before any amounts are allocated to the marketing bonus pool.
 
For 2008, we accrued $4.0 million for the general bonus pool and $0.5 million for the marketing bonus pool in 2008.  These bonuses were paid to employees in March 2009.  In 2007 and 2006, we accrued $2.0 million and $1.8 million for bonuses under previous bonus arrangements.
 
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, or Severance Plan, for employees of our general partner (with the exception of the new senior management team.)  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.


GENESIS ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
 
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 two 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 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.
 
Class B Membership Interests
 
As part of finalizing the compensation arrangements for our Senior Executives on December 31, 2008, our general partner awarded them an equity interest in our general partner as long-term incentive compensation. These Class B Membership Interests compensate the holders thereof by providing rewards based on increased shares of the cash distributions attributable to our incentive distribution rights (or IDRs)(See Note 11) to the extent we increase Cash Available Before Reserves, or CABR (defined below) (from which we pay distributions on our common units) above specified targets.   CABR generally means Available Cash before Reserves, less Available Cash before Reserves generated from specific transactions with our general partner and its affiliates (including Denbury Resources Inc.) The Class B Membership Interests do not provide any Senior Executive with a direct interest in any assets (including our IDRs) owned by our general partner. During his employment with our general partner, each Senior Executive will be entitled to receive quarterly distributions in respect of his Class B Membership Interest from our general partner in amounts equal to a percentage of the distributions we pay in respect of our IDRs.  Each Senior Executive’s quarterly distribution percentage of our IDRs may vary from quarter-to-quarter based on a formula included in the agreements.  In addition, upon the occurrence of specified events and circumstances, our general partner will redeem a Senior Executive’s Class B Membership Interest when that executive’s employment with our general partner is terminated or when a change of control occurs.  Additionally our chief executive officer and chief operating officer participate in a deferred compensation plan, whereby they may be entitled to receive a cash payment upon termination of employment.
 
Our general partner has agreed that it will not seek reimbursement (on behalf of itself or its affiliates) under our partnership agreement for the costs of these Senior Executive compensation arrangements to the extent relating to their ownership of Class B Membership Interests (including current cash distributions made by the general partner out of its IDRs and payment of redemption amounts for those IDRs) and the deferred compensation amounts.
 
Although our general partner will not seek reimbursement for the costs of the Class B Membership Interests and deferred compensation plan arrangements, we will record non-cash expense.   The Class B Membership Interests awarded to our senior executives will be accounted for as liability awards under the provisions of SFAS 123(R).  As such, the fair value of the compensation cost we record for these awards will be recomputed at each measurement date and the expense to be recorded will be adjusted based on that fair value.  Management’s estimates of the fair value of these awards are based on assumptions regarding a number of future events, including estimates of the Available Cash before Reserves we will generate each quarter through the final vesting date of December 31, 2012, estimates of the future amount of incentive distributions we will pay to our general partner, and assumptions about appropriate discount rates.  Additionally the determination of fair value will be affected by the distribution yield of ten publicly-traded entities that are the general partners in publicly-traded master limited partnerships, a factor over which we have no control.  Included within the assumptions used to prepare these estimates are projections of available cash and distributions to our common unitholders and general partner, including an assumed level of growth and the effects of future new growth projects during the four-year vesting period.  These assumptions were used to estimate the total amount that would be paid under the Class B Membership awards through the final vesting date and are do not represent the contractual amounts payable under these awards at the reporting date. The estimated total amount was discounted to December 31, 2008 using a discount rate of 16%, representing the risks inherent in the assumptions we used and the time until final vesting.  Due to the limited number of participants in the Class B Membership awards, we assumed a forfeiture rate of zero.  At December 31, 2008, management estimates that the fair value of the Class B Membership Awards and the related deferred compensation awards granted to our Senior Executives on that date is approximately $12 million. The fair value of these incentive awards will be recomputed each quarter beginning with the quarter ending March 31, 2009 through the final settlement of the awards.  Compensation expense of $3.4 million was recorded in the fourth quarter of 2007 related to the previous arrangements between our general partner and our Senior Executives.   The fair value to be recorded by us as compensation expense will be the excess of the recomputed estimated fair value over the previously recorded $3.4 million.  Due to the vesting conditions for the awards, the amount to which the Senior Executives were entitled on December 31, 2008 for the Class B Membership Awards and the related deferred compensation was zero.  Management’s estimates of fair value are made in order to record non-cash compensation expense over the vesting period, and do not necessarily represent the contractual amounts payable under these awards at December 31, 2008. This expense will be recorded on an accelerated basis to align with the requisite service period of the award.  Changes in our assumptions will change the amount of compensation cost we record.


GENESIS ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
 
16.  Major Customers and Credit Risk
 
Due to the nature of our supply and logistics 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.
 
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.
 
Shell Oil Company accounted for 14.6% of total revenues in 2008.  Shell Oil Company and Occidental Energy Marketing, Inc. accounted for 20.7% and 11.2% of total revenues in 2007, respectively.  Occidental Energy Marketing, Inc., Shell Oil Company and Calumet Specialty Products Partners, L.P. accounted for 20.3%, 19.1% and 10.9% of total revenues in 2006, respectively.  The revenues from these five customers in all three years relate primarily to our supply and logistics operations.
 
17.  Derivatives
 
Our market risk in the purchase and sale of crude oil and petroleum products 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.  The derivative instruments that we use consist primarily of futures and options contracts traded on the NYMEX which we use to hedge our exposure to commodity prices, primarily crude oil, fuel oil and petroleum products.
 
Additionally, DG Marine entered into a series of interest rate swap contracts with two financial institutions related to $32.9 million of the outstanding debt under the DG Marine credit facility.  These swaps effectively convert this portion of DG Marine’s debt from floating LIBOR rate to a series of fixed rates through July 2011.  We have determined that these swaps are effective cash flow hedges of DG Marine’s interest rate exposure.
 
At December 31, 2008 and 2007, we had no commodity price risk derivatives that were designated as hedges for financial reporting purposes.  Therefore, the derivative contracts were marked to fair value based on the closing price for the contracts at the end of each period and an asset or liability was recorded for the fair value and the change in fair value was recorded in our consolidated statements of operations.


GENESIS ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
 
The following table summarizes the liabilities on our consolidated balance sheet that are related to the fair value of our open derivative positions:
 
   
December 31,
 
   
2008
   
2007
 
Decrease in other current assets
  $ (488 )   $ (744 )
Increase in accrued liabilities
    (698 )     -  
Increase in other long-term liabilities
    (1,266 )     -  
Total liabilities
  $ (2,452 )   $ (744 )
 
The liabilities related to the fair value of our open positions consists of unrealized gains/losses recognized in earnings and unrealized losses deferred to other comprehensive income (“OCI”) as follows, by category (losses designated in parentheses):
 
   
December 31, 2008
   
December 31, 2007
 
   
Total
         
Minority
         
Total
       
   
Liabilities
   
Losses
   
Interests
   
OCI
   
Liabilities
   
Losses
 
Commodity price risk derivatives
  $ (488 )   $ (488 )   $ -     $ -     $ (744 )   $ (744 )
Interest rate risk hedging by DG Marine
    (1,964 )     -       (1,002 )     (962 )     -       -  
Total
  $ (2,452 )   $ (488 )   $ (1,002 )   $ (962 )   $ (744 )   $ (744 )
 
In each year, the impact on earnings of our unrealized losses from commodity price risk derivatives in the table above is included in the Consolidated Statements of Operations under the caption “Supply and logistics costs.”
 
The net loss recorded in AOCI and minority interests is expected to be reclassified to future earnings contemporaneously as interest expense associated with the underlying debt under the DG Marine credit facility is recorded.  We expect the total net loss to be reclassified into earnings during the period the swaps are outstanding, with $0.7 million of net loss expected to be reclassified in 2009 and a total of $1.3 million reclassified to earnings during 2011 and 2012.  Because a portion of these amounts is based on market prices at the current period end, actual amounts to be reclassified to earnings will differ and could vary materially as a result of changes in market conditions.
 
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, 2008 and December 31, 2007.
 
18.  Fair-Value Measurements
 
As discussed in Note 2, effective January 1, 2008 we partially adopted SFAS 157.  As defined in SFAS 157, fair value as the price that would be received from selling an asset, or paid to transfer a liability in an orderly transaction between market participants at the measurement date.  Whenever possible, we use market data that market participants would use when pricing an asset or liability.  These inputs can be either readily observable or market corroborated.  We apply the market approach for recurring fair value measurements related to our derivatives.  SFAS 157 establishes a three-level fair value hierarchy that prioritizes the inputs used to measure fair value.  The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement)
 
The following table sets forth by level within the fair value hierarchy our financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2008.  As required by SFAS 157, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement.  Our assessment of the significance of a particular input to the fair value requires judgment and may affect the placement of assets and liabilities within the fair value hierarchy levels.
 
   
Fair Value at December 31, 2008
 
Recurring Fair Value Measures
 
Level 1
   
Level 2
   
Level 3
 
Commodity derivatives (based on quoted market prices on NYMEX)
  $ (488 )   $ -     $ -  
                         
Interest rate swaps
  $ -     $ -     $ (1,964 )


GENESIS ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
 
Level 1
 
Included in Level 1 of the fair value hierarchy are commodity derivative contracts are exchange-traded futures and exchange-traded option contracts.  The fair value of these exchange-traded derivative contracts is based on unadjusted quoted prices in active markets and is, therefore, included in Level 1 of the fair value hierarchy.
 
Level 3
 
Included within Level 3 of the fair value hierarchy are our interest rate swaps.  The fair value of our interest rate swaps is based on indicative broker price quotations. These derivatives are included in Level 3 of the fair value hierarchy because broker price quotations used to measure fair value are indicative quotations rather than quotations whereby the broker or dealer is ready and willing to transact.  However, the fair value of these Level 3 derivatives is not based upon significant management assumptions or subjective inputs.
 
The following table provides a reconciliation of changes in fair value of the beginning and ending balances for our derivatives measured at fair value using inputs classified as level 3 in the fair value hierarchy:
 
   
Year Ended
 
   
December 31, 2008
 
Balance as of January 1, 2008
  $ -  
Realized and unrealized gains (losses)-
       
Included in other comprehensive income
    (962 )
Included in minority interests
    (1,002 )
Balance as of December 31, 2008
  $ (1,964 )
 
See Note 17 for additional information on our derivative instruments.
 
We generally apply fair value techniques on a non-recurring basis associated with (1) valuing the potential impairment loss related to goodwill pursuant to SFAS 142, and (2) valuing potential impairment loss related to long-lived assets accounted for pursuant to SFAS 144.
 
19.  Commitments and Contingencies
 
Commitments and Guarantees
 
In 2008, we entered into a new office lease for our corporate headquarters that extends until January 31, 2016.  We lease office space for field offices under leases that expire between 2008 and 2013.  To transport products, we lease tractors and trailers for our crude oil gathering and marketing activities and lease barges and railcars for our refinery services segment.  In addition, we lease tanks and terminals for the storage of crude oil, petroleum products, NaHS and caustic soda.  Additionally, we lease a segment of pipeline where under the terms we make payments based on throughput.  We have no minimum volumetric or financial requirements remaining on our pipeline lease .
 
The future minimum rental payments under all non-cancelable operating leases as of December 31, 2008, were as follows (in thousands).
 
   
Office
   
Transportation
   
Terminals and
       
   
Space
   
Equipment
   
Tanks
   
Total
 
                         
2009
  $ 745     $ 3,322     $ 1,257     $ 5,324  
2010
    813       3,071       322       4,206  
2011
    794       2,639       322       3,755  
2012
    762       1,552       322       2,636  
2013
    733       726       322       1,781  
2014 and thereafter
    1,534       2,583       6,950       11,067  
Total minimum lease obligations
  $ 5,381     $ 13,893     $ 9,495     $ 28,769  


GENESIS ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
 
Total operating lease expense was as follows (in thousands).
 
Year ended December 31, 2008
  $ 8,757  
Year ended December 31, 2007
  $ 6,079  
Year ended December 31, 2006
  $ 3,258  


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.  Borrowings at December 31, 2008 were $320.0 million and are reflected in the consolidated balance sheet.  We have also guaranteed the payments by our operating partnership under the terms of our operating leases of tractors and trailers.  Such obligations are included in future minimum rental payments in the table above.
 
We guarantee $7.5 million of the outstanding debt of DG Marine under its credit facility.  This guarantee will expire on May 31, 2009, if DG Marine’s leverage ratio under its credit facility is less than 4.00 to 1.00.  The outstanding debt of DG Marine in included in our Consolidated Balance Sheets.  We believe the likelihood we would be required to perform or otherwise incur any significant losses associated with this guaranty is remote.
 
We guaranteed $1.2 million of residual value related to the leases of trailers.  We believe the likelihood we would be required to perform or otherwise incur any significant losses associated with this guaranty is remote.
 
We guaranty 50% of the obligations of Sandhill under a credit facility with a bank.  At December 31, 2008, Sandhill owed $3.0 million; therefore our guarantee was $1.5 million.  Sandhill makes principal payments for this obligation totaling $0.6 million per year.  We believe the likelihood we would be required to perform or otherwise incur any significant losses associated with this guaranty is remote.
 
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 expect that our annual expenditures for integrity testing, repairs and improvements under regulations requiring assessment of the integrity of crude oil pipelines to average from $1.0 million to $1.5 million.
 
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
 
Our facilities and operations may experience damage as a result of an accident or natural disaster.  These hazards can cause personal injury or loss of life, severe damage to and destruction of property and equipment, pollution or environmental damage and suspension of operations.  We maintain insurance that we consider adequate to cover our operations and properties, in amounts we consider reasonable.  Our insurance does not cover every potential risk associated with operating our facilities, including the potential loss of significant revenues.  The occurrence of a significant event that is not fully-insured could materially and adversely affect our results of operations.  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.
 
20.  Income Taxes
 
We are not a taxable entity for federal income tax purposes.  As such, we do not directly pay federal income taxes.  Other than with respect to our corporate subsidiaries and the Texas Margin Tax, our taxable income or loss is includible in the federal income tax returns of each of our partners.
 
A portion of the operations we acquired in the Davison transactions are owned by wholly-owned corporate subsidiaries that are taxable as corporations.  We pay federal and state income taxes on these operations.  The income taxes associated with these operations are accounted for in accordance with SFAS 109 “Accounting for Income Taxes.”


GENESIS ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
 
In May 2006, the State of Texas enacted a law which will require us to pay a tax of 0.5% on our “margin,” as defined in the law, beginning in 2008 based on our 2007 results.  The “margin” to which the tax rate is applied generally will be calculated as our revenues (for federal income tax purposes) less the cost of the products sold (for federal income tax purposes), in the State of Texas.
 
In June 2006, the FASB issued FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes—an interpretation of FASB Statement No. 109” (FIN 48). This Interpretation provides guidance on recognition, classification and disclosure concerning uncertain tax liabilities. The evaluation of a tax position requires recognition of a tax benefit if it is more likely than not it will be sustained upon examination. We adopted FIN 48 effective January 1, 2007. The adoption did not have any impact on our consolidated financial statements.
 
As of December 31, 2007 we had unrecognized tax benefits of $1.0 million.   At December 31, 2008 we have unrecognized tax benefits of $2.6 million.  The change in the unrecognized tax benefits are a result of additions related to current year tax positions.  If the unrecognized tax benefits at December 31, 2008 were recognized, $2.6 million would affect our effective income tax rate.  There are no uncertain tax positions as of December 31, 2008 for which it is reasonably possible that the amount of unrecognized tax benefits would significantly decrease during 2009.
 
Our income tax provision (benefit) is as follows:
 
   
Year Ended
 
   
December 31,
 
   
2008
   
2007
 
Current:
           
Federal
  $ 2,979     $ 1,665  
State
    872       339  
Total current income tax expense
    3,851       2,004  
                 
Deferred:
               
Federal
    (3,850 )     (2,432 )
State
    (363 )     (226 )
Total deferred income tax benefit
    (4,213 )     (2,658 )
Total income tax benefit
  $ (362 )   $ (654 )
 
Deferred income taxes relate to temporary differences based on tax laws and statutory rates in effect at the December 31, 2008 balance sheet date.  We believe we will utilize all of our deferred tax assets at December 31, 2008, and therefore have provided no valuation allowance against our deferred tax assets.  As of December 31, 2008, we have federal income tax net operating loss carryforwards of $4.1 million which, if not used, will begin to expire in 2027.  Deferred tax assets and liabilities consist of the following:


GENESIS ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
 
   
December 31,
 
   
2008
   
2007
 
Deferred tax assets:
           
Current:
           
Other current assets
  $ 271     $ 43  
Other
    97       17  
Total current deferred tax asset
    368       60  
Net operating loss carryforwards - federal
    1,415       861  
Net operating loss carryforwards - state
    128       80  
Total long-term deferred tax asset
    1,543       941  
Total deferred tax assets
    1,911       1,001  
                 
Deferred tax liabilities:
               
Current:
               
Other
    (2 )     (24 )
Long-term:
               
Fixed assets
    (9,868 )     (11,125 )
Intangible assets
    (6,938 )     (8,962 )
Total long-term liability
    (16,806 )     (20,087 )
Total deferred tax liabilities
    (16,808 )     (20,111 )
                 
Total net deferred tax liability
  $ (14,897 )   $ (19,110 )

 
Our income tax benefit varies from the amount that would result from applying the federal statutory income tax rate to income before income taxes as follows:
 
   
Year Ended
 
   
December 31,
 
   
2008
   
2007
 
             
Income (loss) before income taxes
  $ 25,463     $ (14,205 )
Partnership income (loss) not subject to tax
    (30,902 )     8,894  
Income (loss) subject to income taxes
    (5,439 )     (5,311 )
                 
Tax benefit at federal statutory rate
    (1,904 )   $ (1,859 )
State income taxes, net of federal benefit
    357       33  
Effects of FIN 48, federal and state
    1,431       1,168  
Return to provision, federal and state
    (258 )     -  
Other
    12       4  
Income tax benefit
  $ (362 )   $ (654 )
                 
Effective tax rate on income (loss) before income taxes
    -1 %     5 %
 

GENESIS ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
21.  Quarterly Financial Data (Unaudited)
 
The table below summarizes our unaudited quarterly financial data for 2008 and 2007.
 
   
2008 Quarters
   
Total
 
   
First
   
Second
   
Third
   
Fourth
   
Year
 
Revenues
  $ 486,185     $ 640,540     $ 636,919     $ 378,040     $ 2,141,684  
Operating income
  $ 1,759     $ 11,032     $ 13,381     $ 11,719     $ 37,891  
Net income
  $ 1,645     $ 7,328     $ 10,763     $ 6,353     $ 26,089  
Net income per common unit - basic
  $ 0.04     $ 0.17     $ 0.25     $ 0.14     $ 0.61  
Net income per common unit - diluted
  $ 0.04     $ 0.17     $ 0.25     $ 0.14     $ 0.60  
Cash distributions per common unit (1)
  $ 0.2850     $ 0.3000     $ 0.3150     $ 0.3225     $ 1.2225  
                                         
   
2007 Quarters
   
Total
 
   
First
   
Second
   
Third
   
Fourth
   
Year
 
Revenues
  $ 183,564     $ 201,016     $ 354,270     $ 460,803     $ 1,199,653  
Operating income (loss)
  $ 1,580     $ (1,319 )   $ 7,043     $ (12,679 )   $ (5,375 )
Net income (loss)
  $ 1,585     $ (1,372 )   $ 1,699     $ (15,462 )   $ (13,550 )
Net income (loss) per common unit - basic and diluted
  $ 0.11     $ (0.09 )   $ 0.07     $ (0.49 )   $ (0.64 )
Cash distributions per common unit (1)
  $ 0.21     $ 0.22     $ 0.23     $ 0.27     $ 0.93  
 
(1)  Represents cash distributions declared and paid in the applicable period.
 
 
Schedule I - Condensed Financial Information
 
                   
Genesis Energy, L.P. (Parent Company Only)
 
                   
                   
Condensed Statements of Income and Comprehensive Income
 
                   
   
Years Ended December 31,
 
   
2008
   
2007
   
2006
 
   
(in thousands)
 
                   
Equity in earnings (losses) of subsidiaries
  $ 26,089     $ (13,550 )   $ 8,381  
                         
Net income (loss)
    26,089       (13,550 )     8,381  
                         
Other comprehensive loss of subsidiary
    (962 )     -       -  
                         
Total comprehensive income (loss)
  $ 25,127     $ (13,550 )   $ 8,381  

 
Condensed Balance Sheets
 
             
   
December 31,
 
   
2008
   
2007
 
   
(in thousands)
 
Assets
           
Cash
  $ 3     $ 10  
Investment in subsidiaries
    665,334       664,480  
Advances to subsidiaries
    91       84  
Total Assets
  $ 665,428     $ 664,574  
                 
Partners' Capital
               
Limited Partners
  $ 649,046     $ 647,340  
General Partner
   
17,344
      17,234  
Accumulated other comprehensive income
    (962 )     -  
Total Partners' Capital
  $ 665,428     $ 664,574  
                 
See accompanying notes to condensed financial statements.
 
 
 
Schedule I - Condensed Financial Information - Continued
 
                   
Genesis Energy, L.P. (Parent Company Only)
 
                   
Condensed Statements of Cash Flows
 
                   
   
Years Ended December 31,
 
   
2008
   
2007
   
2006
 
   
(in thousands)
 
                   
Cash Flows from Operating Activities:
                 
Net income (loss)
  $ 26,089     $ (13,550 )   $ 8,381  
Equity in (earnings) losses of GCO
    (15,773 )     13,550       (8,381 )
Equity in (earnings) losses of GNEJD
    (10,316 )     -       -  
Change in advances to GCO
    (7 )     4       -  
Net cash (used in) provided by operating activities
    (7 )     4       -  
                         
Cash Flows from Investing Activities:
                       
Investment in GCO
    (510 )     (216,172 )     -  
Distributions from GCO - return of investment
    50,534       17,175       10,408  
Net cash provided by (used in) investing activities
    50,024       (198,997 )     10,408  
                         
Cash Flows from Financing Activities:
                       
Issuance of limited and general partner interests, net
    510       216,172       -  
Distributions to limited and general partners
    (50,534 )     (17,175 )     (10,408 )
Net cash (used in) provided by financing activities
    (50,024 )     198,997       (10,408 )
                         
Net (decrease) increase in cash
    (7 )     4       -  
Cash at beginning of period
    10       6       6  
Cash at end of period
  $ 3     $ 10     $ 6  
                         
See accompanying notes to condensed financial statements.
 


Schedule I – Condensed Financial Statements – Continued
 
Genesis Energy, L.P. (Parent Company Only)
 
Notes to Condensed Financial Statements
 

 
1.  Basis of Presentation
 
Genesis Energy, L.P., or GEL, is the owner of 99.99% of Genesis Crude Oil, L.P., or GCO and 100% of Genesis NEJD Holdings, LLC, or GNEJD.  These parent company only financial statements for GEL summarize the results of operations and cash flows for the years ended December 31, 2008, 2007 and 2006, and GEL’s financial position at December 31, 2008 and 2007.  In these statements, GEL’s investments in GCO and GNEJD are stated on the equity method basis of accounting.  The GEL statements should be read in conjunction with the consolidated financial statements of Genesis Energy, L.P.
 
As discussed in Note 10 of the Notes to the Consolidated Financial Statements, the terms of the credit facility with GCO, limit the amount of distributions that GCO and its subsidiaries may pay to GEL.   Such distributions may not exceed the sum of the distributable cash generated by GCO and its subsidiaries for the eight most recent quarters, less the sum of the distributions made with respect to those quarters. This restriction results in the restricted net assets (as defined in Rule 4-08 (e)(3) of Regulation S-X) of GEL’s subsidiary exceeding 25% of the consolidated net assets of GEL and its subsidiaries.
 
2.  Contingencies
 
GEL guarantees the obligations of GCO under our credit facility.  See Note 10 of the Notes to the Consolidated Financial Statements of Genesis Energy, L.P. for a description of GCO’s credit facility
 
GEL guarantees the obligations of GCO under our lease with Paccar Leasing Services.  See Note 19 of the Notes to the Consolidated Financial Statements of Genesis Energy, L.P.
 
GEL has guaranteed crude oil and petroleum products purchases of GCO and its subsidiaries.  These guarantees, totaling $40.8 million, were provided to counterparties.  To the extent liabilities exist under the contracts subject to these guarantees, such liabilities are included in the consolidated financial statements of Genesis Energy, L.P.
 
GEL has guaranteed $7.5 million of the outstanding debt of DG Marine under its credit facility.  This guarantee will expire on May 31, 2009, if DG Marine’s leverage ratio under its credit facility is less than 4.00 to 1.00.
 
3.  Supplemental Cash Flow Information
 
In May 2008, additional limited partner interests in GCO with a value of $25 million were issued to GEL. GEL issued common units with an equal value as part of the consideration in acquisition of the Free State Pipeline from Denbury.  In July 2008, additional limited partner interests in GCO with a value of $16.7 million were issued to GEL.  GEL issued common units with an equal value as part of the consideration in the Grifco acquisition.  These transactions are non-cash transactions and are not included in the Statements of Cash Flows in investing or financing activities.
 
 
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Exhibit 10.3
 
 
PRODUCTION PAYMENT PURCHASE AND SALE AGREEMENT


This PRODUCTION PAYMENT PURCHASE AND SALE AGREEMENT (the “ Agreement ”), executed as of November 14, 2003, and effective September 1, 2003 (the “ Effective Date ”), is between DENBURY RESOURCES INC. (“ Denbury ”), a Delaware corporation, whose address is 5100 Tennyson Parkway, Suite 3000, Plano, Texas 75024, and GENESIS CRUDE OIL, L.P. (“ Genesis ”), a Delaware limited partnership, whose address is 500 Dallas, Suite 2500, Houston, Texas 77002.  Denbury and Genesis are sometimes referred to individually as a “Party” and collectively as the “ Parties ”.

FOR AND IN CONSIDERATION of the payments and mutual covenants to be made in this Agreement by the Parties and the benefits derived by the Parties from this Agreement, the Parties agree as follows:

RECITALS

A.            Denbury owns certain undivided oil, gas and mineral leasehold, royalty and mineral interests in and to those lands commonly referred to as the Hollybush field, the South Pisgah field and the Goshen Springs field, as more particularly described in Exhibit A attached to the Assignment (as defined below).

B.             Denbury is currently engaged in a program with respect to the Subject Interests (as defined below) on the Subject Lands (as defined below) for the exploration, development, production and sale of carbon dioxide.

C.             Denbury desires to sell and convey and Genesis desires to purchase and pay for (1) all of Denbury’s rights, title and interests in and to certain contracts covering the sale of carbon dioxide   by Denbury, and (2) a volumetric production payment in and to the carbon dioxide   that is produced, saved and sold from the Subject Interests, upon and subject to the terms and conditions provided in the Assignment and this Agreement.

I.
CERTAIN DEFINITIONS

1.1            For purposes of this Agreement, the following capitalized terms shall have the meanings herein ascribed to them and the capitalized terms defined in the opening paragraph and subsequent paragraphs by inclusion in quotation marks and parentheses shall have the meanings ascribed to them:

“ Additional Volumes ” shall have the meaning given to such term in Section 4.4 .

“ Airgas Contract ” means the Industrial Sale Contract identified as the Airgas Contract in Exhibit A to the Contracts Assignment, as the same may have been amended prior to the date hereof.

“ Assigned Contract Interests ” shall have the meaning given to such term in Section 4.1 .

 
 
 

“ Assignment ” means the Assignment of Production Payment to be entered into between Denbury and Genesis in the form attached hereto as Exhibit A .

“ Audited Party ” shall have the meaning given to such term in Section 12.3 .

“ Bank One Liens ” means the liens created under or pursuant to that certain Third Amended and Restated Credit Agreement dated as of September 12, 2002 among Denbury, as borrower, the financial institutions listed therein, Bank One, N.A., as Administrative Agent, Credit Lyonnais New York Branch, and Fortis Capital Corp., as Syndication Agent, and Union Bank of California, as amended by instrument dated effective as of April 30, 2003, and as otherwise amended, supplemented or modified from time to time.

“ BOC-Brandon Contract ” means the Industrial Sale Contract identified as the BOC-Brandon Contract in Exhibit A to the Contracts Assignment, as the same may have been amended prior to the date hereof.

“ Call Option ” shall have the meaning given to such term in Section 2.4 .

“ Call Settlement Date ” shall have the meaning given to such term in Section 2.4 .

“ Claims ” shall have the meaning given to such term in Section 9.1.

“ Closing ” shall have the meaning given to such term in Section 10.1 .

“ Closing Date ” shall have the meaning given to such term in Section 10.1 .

“ CO 2 ” shall have the meaning given to such term in the Assignment.

“ Contracts Assignment ” means the Assignment of Contracts and Bill of Sale to be entered into between Denbury and Genesis attached hereto as Exhibit C .

“ Daily Maximum Quantity ” shall have the meaning given to such term in the Assignment.

“ Day ” shall have the meaning given to such term in the Assignment.

“ Deficiency ” shall have the meaning given to such term in Section 4.4 .

“ Delivery Points ” shall have the meaning given to such term in the T&P Agreement.

“ Denbury Indemnified Party ” shall have the meaning given to such term in Section 9.2 .

“ Denbury Pipeline ” shall have the same meaning as “Transporter’s Pipeline” as such term is defined in the T&P Agreement.

“ Effective Date ” shall have the meaning given to such term in the opening paragraph of this Agreement.

“ Environmental Claims ” shall have the meaning given to such term in Section 5.14 .

 
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“ Environmental Contaminants ” shall have the meaning given to such term in Section 5.14 .

“ Environmental Laws ” means all federal, state and local Governmental Requirements regulating or otherwise pertaining to the environment, including without limitation the following as from time to time amended and all others whether similar or dissimilar and whether now existing or hereafter enacted:  the Oil Pollution Act of 1990, as amended (“ OPA ”); the Comprehensive Environmental Response, Compensation, and Liability Act of 1980, as amended by the Superfund Amendments and Reauthorization Act of 1986; the Resource Conservation and Recovery Act of 1976, as amended by the Used Oil Recycling Act of 1980, the Solid Waste Disposal Act amendments of 1980, and the Hazardous and Solid Waste Amendments of 1984; the Hazardous Materials Transportation Act, as amended; the Toxic Substance Control Act, as amended; the Clean Air Act, as amended; the Clean Water Act, as amended; and all regulations promulgated pursuant thereunder.

“ Environmental Liabilities ” shall have the meaning given to such term in Section 5.14 .

“ Environmental Permits ” shall have the meaning given to such term in Section 5.14 .

“ Excess Volumes ” shall have the meaning given to such term in the Assignment.

“ Genesis Indemnified Party ” shall have the meaning given to such term in Section 9.1 .

“ Governmental Authority ” means any nation or government, any state or other political subdivision thereof and any person exercising executive, legislative, judicial, regulatory or administrative functions of or pertaining to government.

“ Governmental Requirement ” means any law, statute, code, ordinance, order, determination, rule, regulation, judgment, decree, injunction, franchise, permit, certificate, license, authorization or other directive or requirement, energy regulations and occupational, safety and health standards or controls, of any Governmental Authority.

“ Industrial Sale Contracts ” shall have the meaning given to such term in the Contracts Assignment.

“ Jackson Dome Plant ” means the Jackson Dome Processing Plant owned by Denbury located in Brandon, Rankin County, Mississippi.

“ Leases ” means the leases described, referred to or identified in Exhibit A to the Assignment, together with any renewals or extensions of such leases, and any replacement leases, insofar and only insofar as they cover the Subject Lands (or portion thereof).

“ Lost Interest ” shall have the meaning given to such term in Section 11.10 .

“ Master Documents ” means this Agreement and all agreements executed in connection herewith or pursuant hereto, including, but not limited to the Assignment, the Contracts Assignment, and the T&P Agreement.

 
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“ Material Adverse Effect ” means a material adverse effect upon (a) the validity or enforceability of the Master Documents, or (b) the financial condition of Denbury or Genesis, as applicable, or (c) the ability of Denbury or Genesis, as applicable, to perform its obligations under the Master Documents.

“ MCF ” shall have the meaning given to such term in the Assignment.

“ Month ” means a period beginning on the first Day of a calendar month and ending at the beginning of the first Day of the next succeeding calendar month.

“ Permitted Liens ” means (a) lessor’s royalties, overriding royalties, and division orders covering oil, gas and other hydrocarbons, reversionary interests and similar burdens existing as of the Effective Date; (b) operating agreements, unit agreements and similar agreements, and any and all federal and state regulatory orders and rules (including forced pooling orders) to which the Subject Interests are subject; (c) liens for Taxes or assessments not due or pursuant to which Denbury is not delinquent; (d) preferential rights to purchase and required third-party consents to assignments and similar agreements with respect to which (1) waivers or consents have been obtained from the appropriate parties, or (2) required notice has been given to the holders of such rights and the appropriate time period for asserting such rights has expired without an exercise of such rights; (e) all rights to consent by, required notices to, filings with, or other actions by governmental entities in connection with the sale or conveyance of oil, gas and mineral leases or interests therein if the same are customarily obtained after such sale or conveyance; (f) easements, rights-of-way, servitudes, permits, surface leases and other rights in respect of surface operations, pipelines, grazing, logging, canals, ditches, reservoirs or the like; and easement for streets, alleys, highways, pipelines, telephone lines, power lines, railways and other easements and rights-of-way, on, over or in respect of any of the Subject Interests; (g) liens of operators relating to obligations not due or pursuant to which Denbury is not delinquent; (h) title problems commonly encountered in the oil and gas business which would not be considered material by a reasonable and prudent person engaged in the business of the ownership, development and operation of oil and gas properties with knowledge of all the facts and appreciation of their legal significance; and (i) the Bank One Liens.

“ Person ” means any individual, natural person, corporation, joint venture, partnership, limited partnership, trust, estate, business trust, association, governmental entity or other entity.

“ Personal Property ” shall mean improvements, machinery, equipment, gathering lines, tanks, fixtures and other personal property and equipment of every kind and nature now or hereafter used or held for use in connection with the exploration, development or operation of the Subject Interests; provided, however, that the term “Personal Property” shall not include the Denbury Pipeline or the Jackson Dome Plant.

“ Praxair Contract ” means the Industrial Sale Contract identified as the Praxair Contract in Exhibit A to the Contracts Assignment, as the same may have been amended prior to the date hereof.

“ Production Payment ” shall have the meaning given to such term in the Assignment.

“ Production Payment Gas ” shall have the meaning given to such term in the Assignment.

 
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“ Receipt Point ” shall have the meaning given to such term in the T&P Agreement.

“ Reserve Report ”  shall mean “Data on Estimated Proved Carbon Dioxide Reserves as of December 31, 2002” of the Appraisal Report as of December 31, 2002 on Certain Properties Owned by Denbury Resources Inc., SEC Case, of DeGolyer and MacNaughton dated February 4, 2003.

“ Retained Obligations ” shall have the meaning given to such term in Section 11.12 .

“ Scheduled Delivery Volumes ” shall have the meaning given to such term in the Assignment.

“ Subject Interests ” shall have the meaning given to such term in the Assignment.

“ Subject Lands ” shall have the meaning given to such term in the Assignment.

“ Taxes ” shall have the meaning given to such term in the Assignment.

“ Term ” shall have the meaning given to such term in the Assignment.

“ T&P Agreement ” means the Carbon Dioxide Transportation Agreement to be entered into between Denbury and Genesis in the form attached hereto as Exhibit D .

“ Transportation Fee ” shall have the meaning given to such term in the T&P Agreement.

II.
PURCHASE AND SALE OF THE PRODUCTION PAYMENT

2.1            Subject to the terms of this Agreement, Denbury agrees to sell and convey and Genesis agrees to purchase and pay for the Production Payment.

2.2            The Production Payment will be assigned by Denbury to Genesis pursuant to the Assignment.

2.3            Genesis shall look solely to the receipt of Production Payment Gas as provided herein for satisfaction and discharge of the Production Payment, and Genesis shall not have any other recourse against Denbury for the payment and discharge of the Production Payment.  However, the foregoing provision shall not relieve Denbury of any obligation to respond in damages for any breach of any of the covenants, agreements and obligations of Denbury hereunder or under any other Master Document.

2.4            Genesis hereby grants Denbury the option to repurchase the Production Payment pursuant to the terms of this Section 2.4 (the “ Call Option ”).  If pursuant to Section 2.8 of the T&P Agreement, the Transporter (as defined in the T&P Agreement) elects to exercise its Call Option (or is deemed to have elected to exercise its Call Option), Denbury shall notify Genesis of the date on which the repurchase will be consummated (the “ Call Settlement Date ”), which date must be a Business Day and must occur no sooner than five Business Days and no later than 30 days after the date on which Transporter delivered (or was deemed to have delivered) notice of its intent to exercise the Call Option.  On the Call Settlement Date, Genesis and Denbury shall execute documentation sufficient to terminate the Production Payment and the other Master Documents, cause the reconveyance to and assumption by Denbury of the Industrial Sale Contracts, and contemporaneously therewith, Denbury shall pay to Genesis in immediately available funds, a purchase price equal to the estimated cash flow from the remaining volumes obligated to be delivered pursuant to the Production Payment discounted to present net value using a fifteen percent (15%) per annum discount rate.  The estimated cash flow from the remaining volumes obligated to be delivered pursuant to the Production Payment shall be based upon a forecast prepared by Denbury and furnished to Genesis, and if Genesis objects to such forecast, then such matter may be submitted to and resolved in accordance with the arbitration provisions contained in Article XIV .

 
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2.5            In the event of any express conflict between the terms and provisions of this Agreement and the terms and provisions of the Assignment, the terms and provisions of the Assignment shall control.  The inclusion in this Agreement of provisions not addressed in the Assignment shall not be deemed a conflict, and all such additional provisions contained herein shall be given full force and effect.

III.
PROCESSING AND TRANSPORTATION OF PRODUCTION PAYMENT GAS

3.1            After Closing, Denbury agrees to transport Production Payment Gas from the Receipt Points, and redeliver Production Payment Gas at the Delivery Points, in accordance with the provisions of the T&P Agreement.  All Production Payment Gas shall be delivered by Denbury to the Delivery Points in compliance with the requirements set out in the T&P Agreement with respect to pressure, quantity and quality specifications.  Under the T&P Agreement, Genesis will pay Denbury a Transportation Fee (as adjusted in accordance with the terms of the T&P Agreement), which initially shall be $0.16 per MCF, for transportation of the Production Payment Gas from the Receipt Points, processing of the Production Payment Gas through the Jackson Dome Plant, and redelivery of the Production Payment Gas to or on behalf of Genesis at the Delivery Points.

3.2            The processing and transportation of Production Payment Gas by Denbury as described in this Article shall be subject to the terms and provisions contained in this Article, as such terms and provisions may be further described or supplemented by the T&P Agreement.  In the event of any conflict between the terms and provisions of this Article and the terms and provisions of the T&P Agreement, the terms and provisions of the T&P Agreement shall control. The inclusion in this Agreement of provisions not addressed in the T&P Agreement shall not be deemed a conflict, and all such additional provisions contained herein shall be given full force and effect.

IV.
ASSIGNMENT OF INDUSTRIAL SALE CONTRACTS

4.1            At Closing, Denbury will assign to Genesis all of its rights and interests in and to the Industrial Sale Contracts (the “ Assigned Contract Interests ”), subject to the terms and conditions contained in the Industrial Sale Contracts.  The Assigned Contract Interests will be assigned by Denbury to Genesis pursuant to the Contracts Assignment.  Notwithstanding such assignment, Denbury shall be obligated to continue to comply with the Retained Obligations.

 
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4.2            At Closing, Genesis will assume the cost and responsibilities of administering the Assigned Contract Interests with respect to rights and obligations arising after the Effective Date and will report the sales and values of such sales to Denbury on a Monthly basis on or before the 10th day of each succeeding Month, in a manner and format agreed upon between the Parties, in order that Denbury can timely pay royalties attributable to the Production Payment Gas sold pursuant to the Industrial Sale Contracts.  Notwithstanding anything herein to the contrary, without the prior written consent of Denbury, Genesis shall not amend or otherwise modify any terms or provisions of any of the Industrial Sale Contracts if such amendment or modification of the Industrial Sale Contracts shall in any manner whatsoever, directly or indirectly, modify the Retained Obligations or otherwise increase any obligations of Denbury under any of the Master Documents, including but not limited to any increase of the sales and delivery requirements under the Industrial Sale Contracts.  If Denbury elects not to consent to any proposed amendment, Denbury shall provide a written explanation setting out the reasons for such election.

4.3            In the event of any conflict between the terms and provisions contained in this Article and the terms and provisions of the Contracts Assignment, the terms and provisions contained in the Contracts Assignment shall control.  The inclusion in this Agreement of provisions not addressed in the Assignment shall not be deemed a conflict, and all such additional provisions contained herein shall be given full force and effect.

4.4            If at any time or from time to time during the Term Genesis determines that 167.5 million MCF is not sufficient to satisfy the sales and delivery requirements of the Industrial Sale Contracts (a “ Deficiency ”), Genesis shall promptly furnish Denbury with written notice of such determination, and such notice shall contain sufficient detail that is reasonably calculated to enable Denbury to determine the basis for Genesis’ determination of such Deficiency.  If, after receipt of such notice, Denbury agrees with Genesis’ assessment of a Deficiency, Denbury agrees to amend the Production Payment to include such additional volumes of CO 2 that are necessary to enable Genesis to satisfy the sales and delivery requirements of the Industrial Sale Contracts.  If Denbury fails to agree with Genesis’ assessment of a Deficiency, then such matter shall be resolved pursuant to Article XIV .  The agreed-upon amount of additional volumes necessary to enable Genesis to satisfy the sales and delivery requirements of the Industrial Sale Contracts (the “ Additional Volumes ”) shall be sold by Denbury to Genesis on the same terms and conditions, mutatis mutandis, as applicable to the Production Payment by virtue of this Agreement, and the value of, and consequently the consideration to be paid by Genesis to Denbury for, the Additional Volumes shall be calculated based on estimated cash flow from the Additional Volumes discounted to present net value using a fifteen percent (15%) per annum discount rate.  Notwithstanding the foregoing, if it is determined that the Deficiency has occurred, in whole or in part, as a result of the sale by Genesis of Excess Volumes, Denbury shall not be obligated to deliver those Additional Volumes which are attributable to the sale of Excess Volumes by Genesis.

 
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V.
REPRESENTATIONS AND WARRANTIES OF DENBURY

Denbury hereby represents and warrants to Genesis as follows:

5.1            Denbury is a corporation duly organized, validly existing and in good standing under the laws of the State of Delaware.  Denbury possesses the legal right, power and authority, and qualifications to conduct its business and own its properties (including the Subject Interests), except where the failure to so possess would not, individually or collectively, have a Material Adverse Effect.  Denbury has the legal right, power and authority (i) to execute and deliver the Assignment and to convey to Genesis the Production Payment and all of the rights and privileges appurtenant thereto and (ii) to execute and deliver this Agreement and the other Master Documents and to perform all of its obligations hereunder and thereunder.

5.2            The execution, delivery and performance by Denbury of this Agreement and the other Master Documents are within its corporate powers and authority, have been duly authorized by all necessary board of director action on the part of Denbury and do not and will not (i) violate any Governmental Requirement currently in effect having applicability to Denbury, other than violations which would not, individually or collectively, cause a Material Adverse Effect, or (ii) violate any provision of Denbury’s articles of incorporation, bylaws, or other governing documents, or (iii) result in a breach of or constitute a default (excluding breaches or defaults which, individually or collectively, would not have a Material Adverse Effect) under any indenture, bank loan, or credit agreement or farm-out agreement, program agreement or operating agreement, or any other agreement or instrument to which Denbury is a party or by which Denbury or its properties may be currently bound or affected, or (iv) other than the Master Documents and/or other than matters which would not individually or collectively cause a Material Adverse Effect, result in or require the creation or imposition of any mortgage, lien, pledge, security interest, charge, or other encumbrance upon or of any of the properties or assets of Denbury (including the Subject Interests).

5.3            This Agreement and the other Master Documents have been duly executed and delivered by Denbury, and this Agreement and the Master Documents constitute the legal, valid, and binding acts and obligations of Denbury enforceable against Denbury in accordance with their terms, subject, however, to bankruptcy, insolvency, reorganization, and other laws affecting creditors’ rights generally and general principles of equity.  There are no bankruptcy, insolvency, reorganization, receivership or arrangement proceedings pending, being contemplated by or, to Denbury’s knowledge, threatened against Denbury.

5.4            Denbury is not in default under any Governmental Requirement, indenture, agreement, or instrument which would reasonably be expected to cause a Material Adverse Effect nor does any fact or condition exist at this time that would reasonably be expected to cause a Material Adverse Effect in the future under any Governmental Requirement, indenture, agreement or instrument; and all consents and waivers of preferential purchase or other rights required in connection with the valid conveyance to Genesis of the Production Payment or the execution and delivery of this Agreement and the other Master Documents have been obtained or the time for giving such consents or waivers has expired following a written request therefor, other than those consents and waivers which if not obtained, would not individually or collectively have a Material Adverse Effect.

 
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5.5            All advance notifications to third parties of the transactions contemplated herein and in the other Master Documents required in connection with the valid conveyance to Genesis of the Production Payment or execution and delivery of this Agreement and the other Master Documents have been timely and properly given, other than those notifications which, if not obtained, would not individually or collectively have a Material Adverse Effect.

5.6            All authorizations, consents, approvals, licenses, and exemptions of, and filings or registrations with, any Governmental Authority, that are required for the valid execution and delivery by Denbury of, or the performance by Denbury of its obligations under, this Agreement or the other Master Documents have been obtained or performed or the period for objection thereto expired, other than those which, if not obtained or performed, would not individually or collectively have a Material Adverse Effect.

5.7            To Denbury’s knowledge, the Reserve Report (i) was prepared in accordance with customary engineering practices, and (ii) is based on historical information that is accurate and complete in all material respects.  The Subject Interests constitute all of the properties and interests reflected in the Reserve Report that relate to the production of CO 2 .  Set forth on Exhibit B is a true and correct statement of Denbury's working interest and net revenue interest in and to each well noted on Exhibit B except to the extent that such interest is incorrect as the result of an act or omission that does not arise by, through or under Denbury and except for discrepancies which would not be considered material by a reasonable and prudent person engaged in the business of the ownership, development and operation of oil and gas properties with knowledge of all the facts and appreciation of their legal significance.  The interests reflected on Exhibit B are owned by Denbury free and clear of any lien or encumbrance arising by, through or under Denbury, other than Permitted Liens.

5.8            All Taxes imposed or assessed with respect to or measured by or charged against or attributable to the Subject Interests, the Personal Property, the Denbury Pipeline and the Jackson Dome Plant have been duly paid, except for Taxes not yet due and payable or pursuant to which Denbury is not delinquent.

5.9            There are no suits or proceedings pending or, to Denbury’s knowledge, threatened against Denbury, the Subject Interests, the Denbury Pipeline, the Jackson Dome Plant or any of the Personal Property before any Governmental Authority, that, if decided adversely to the interest of Denbury, would reasonably be expected to have a Material Adverse Effect; provided, however, that notwithstanding the foregoing, Schedule 5.9 includes a list of current litigation affecting Denbury, the Subject Interests, the Denbury Pipeline, the Jackson Dome Plant or the Personal Property.

5.10          Except with respect to those matters which would not individually or collectively have a Material Adverse Effect, (i) the Leases are in full force and effect, and (ii) Denbury has complied with the terms of all Governmental Requirements applicable to Denbury or applicable directly to the Subject Interests.

 
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5.11          All rents and royalties with respect to the Leases have been paid in a timely manner (excluding any failures to pay which would not individually or collectively have a Material Adverse Effect), and all liabilities of any kind or nature incurred with respect to the Leases have been paid before delinquent (excluding any liabilities or failures to pay which would not individually or collectively have a Material Adverse Effect); Denbury has not received any notice of default or claimed default with respect to the Subject Interests or any part thereof that would reasonably be expected to result in a Material Adverse Effect; and except for matters which would not individually or collectively have a Material Adverse Effect, all wells, facilities and equipment which constitute part of the Personal Property and the Denbury Pipeline and the Jackson Dome Plant are in good repair and working condition and have been designed, installed and maintained in accordance with generally accepted industry standards and all applicable Governmental Requirements.

5.12          Denbury has not violated any Governmental Requirement or failed to obtain any license, permit, franchise or other governmental authorization required for the ownership or operation of any of the Personal Property or the Denbury Pipeline or the Jackson Dome Plant, except for violations which would not individually or collectively have a Material Adverse Effect.  Except for matters which would not individually or collectively have a Material Adverse Effect, the Personal Property, the Denbury Pipeline and the Jackson Dome Plant have each been maintained, operated and developed in conformity with all applicable Governmental Requirements of all Governmental Authorities having jurisdiction and in conformity with the provisions of all leases, subleases or other contracts comprising a part of the Subject Interests .

5.13          Since the December 31, 2002, there has not been any reduction in the rate of production of CO 2 from any of the Subject Interests that would reasonably be expected to have a Material Adverse Effect.

5.14          Except as set forth on Schedule 5.14 and except with respect to those matters which would not individually or collectively reasonably be expected to result in a Material Adverse Effect, to Denbury’s knowledge:  (i) Denbury has obtained and maintained in effect all environmental and health and safety permits, licenses, approvals, consents, certificates and other authorizations required in connection with Denbury’s ownership or operation of the Subject Lands (“ Environmental Permits ”); (ii) Denbury’s operations on the Subject Lands are in compliance in all material respects with all applicable Environmental Laws and with all terms and conditions of all applicable Environmental Permits, and all prior instances of material non-compliance have been fully and finally resolved to the satisfaction of all Governmental Authorities with jurisdiction over such matters; (iii) Denbury’s operations on the Subject Lands are not subject to any third party environ­mental or health and safety claim, demand, filing, investigation, administrative proceeding, action, suit or other legal proceeding, whether direct, indirect, contingent, pending, threatened or otherwise (“ Environmental Claim ”), or Environmental Liabilities (as defined herein), arising from, based upon, associated with or related to Denbury’s operations on the Subject Lands; (iv) Denbury has not received any notice of any Environmental Claim, Environmental Liabilities or any violation or non-compliance with any Environmental Law or the terms or conditions of any Environmental Permit, arising from, based upon, associated with or related to Denbury’s operations on the Subject Lands; (v) no pollutant, waste, contaminant, or hazardous, extremely hazardous, or toxic material, substance, chemical or waste identified, defined or regulated as such under any Environmental Law (“ Environmental Contaminants ”) is present on, or has been handled, managed, stored, transported, processed, treated, disposed of, released, migrated or has escaped on, in, from, or under the Subject Lands as a result of Denbury’s operations on the Subject Lands in a manner that has caused an Environmental Claim, Environmental Liabilities or a violation of any applicable Environmental Law; and (iv) the executive management of Denbury is not aware of any facts, conditions or circumstances in connection with, related to or associated with any of the Properties or the ownership or operation, that as of the date of this Agreement could reasonably be expected to give rise to any material Environmental Claim or Environmental Liabilities.  As used in this Agreement, the term “ Environmental Liabilities ” shall mean any and all liabilities arising from, based upon, associated with or related to (i) any Environmental Claim, (ii) any applicable Environmental Permit, (iii) any applicable Environ­mental Law or (iv) the presence, handling, management, storage, transportation, processing, treatment, disposal, release, threatened release, migration or escape of Environmental Contaminants (including, without limitation, all costs arising under any theory of recovery, in law or at equity), whether based on negligence, strict liability, or otherwise, including, without limitation, remediation, removal, response, restoration, abate­ment, investigative, monitoring, personal injury, and property damage costs and all other related costs, expenses, losses, damages, penalties, fines, liabilities and obligations (including interest paid or accrued, attorneys’ fees, and court costs).

 
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5.15          Denbury has good title to each of the Industrial Sale Contracts, free and clear of all liens, encumbrances or claims (other than (i) Permitted Liens and (ii) the right of first refusal set out in the Airgas Contract), and each Industrial Sale Contract is, in full force and effect and enforceable against Denbury and, to Denbury’s knowledge, the counterparty thereto.  The Industrial Sale Contracts have been conveyed to Genesis free and clear of the Bank One Liens.

5.16          Except as set forth on Schedule 5.9 or Exhibit A to the Contracts Assignment, (a) there are no have been no amendments or modifications to the Industrial Sale Contracts; and (b) there are no breaches or defaults under any Industrial Sale Contract by Denbury or any counterparty to any Industrial Sale Contract which would reasonably be expected to prevent the practical realization by Genesis of the benefits intended to be provided to Genesis under such Industrial Sale Contract.

5.17          Upon due execution and delivery by Denbury of the Assignment, under Mississippi law, (i) the Assignment will constitute the legal, valid, and binding conveyance of the Production Payment and will constitute a burden upon all of the CO 2 production from the Subject Interests, and (ii) the Production Payment will constitute real property.

5.18          Except with respect to the Industrial Sale Contracts and/or as set forth in Schedule 5.18 , (i) neither the Subject Interests, the CO 2 attributable thereto nor the Denbury Pipeline are subject, committed or dedicated to any contract, agreement or arrangement regarding the transportation or sale of CO 2 production; (ii) no third party has any call, right of first refusal or preferential right to purchase or transport any such CO 2 that has not been waived or the time for giving such consents or waivers has expired in accordance with the terms of such call or rights; and (iii) no third party has any purchase option with respect to any such CO 2 or the Denbury Pipeline.

 
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VI.
REPRESENTATIONS AND WARRANTIES OF GENESIS

Genesis hereby represents and warrants to Denbury as follows:

6.1            Genesis is a limited partnership duly formed and validly existing under the laws of the State of Delaware.  Genesis possesses the legal right, power and authority, and qualifications to conduct its business and own its properties, except where the failure to so possess would not, individually or collectively, have a Material Adverse Effect.  Genesis has the legal right, power and authority to execute and deliver this Agreement, the Assignment and the other Master Documents and to perform all of its obligations hereunder and thereunder, including unanimous approval of the transactions by the audit committee of Genesis Energy, Inc., the general partner of Genesis, such audit committee consisting solely of independent directors (the “ Audit Committee ”).

6.2            The execution, delivery and performance by Genesis of this Agreement and the other Master Documents are within its powers and authority, have been duly authorized by all necessary board of director action on the part of Genesis Energy, Inc., (in its capacity as general partner of Genesis) and by the Audit Committee and do not and will not (i) violate any Governmental Requirement currently in effect having applicability to Genesis, other than violations which would not, individually or collectively, cause a Material Adverse Effect, or (ii) violate Genesis' limited partnership agreement or other governing documents, or (iii) result in a breach of or constitute a default (excluding breaches or defaults which, individually or collectively, would not have a Material Adverse Effect) under any indenture, bank loan, or credit agreement or farm-out agreement, program agreement or operating agreement, or any other agreement or instrument to which Genesis is a party or by which Genesis or its properties may be currently bound or affected.

6.3            Genesis is not in default under any Governmental Requirement, indenture, agreement, or instrument that would reasonably be expected to cause a Material Adverse Effect nor does any fact or condition exist at this time that would reasonably be expected to cause a Material Adverse Effect now or in the future under any Governmental Requirement, indenture, agreement or instrument;   and all consents or approvals under such indentures, agreements, and instruments necessary to permit the valid execution, delivery, and performance by Genesis of the Master Documents have been obtained.

6.4            This Agreement and the other Master Documents have been duly executed and delivered by Genesis, and this Agreement and the Master Documents constitute the legal, valid, and binding acts and obligations of Genesis enforceable against Genesis in accordance with their terms, subject, however, to bankruptcy, insolvency, reorganization, and other laws affecting creditors’ rights generally and general principles of equity.  There are no bankruptcy, insolvency, reorganization, receivership or arrangement proceedings pending, being contemplated by or, to the knowledge of Genesis, threatened against Genesis.

6.5            All authorizations, consents, approvals, licenses, and exemptions of, and filings or registrations with, any Governmental Authority, that are required for the valid execution and delivery by Genesis of, or the performance by Genesis of its obligations under, this Agreement or the other Master Documents have been obtained or performed or the period for objection thereto expired, other than those which, if not obtained or performed, would not individually or collectively have a Material Adverse Effect; and no consent or vote of the limited partners of Genesis is required for the execution, delivery or performance by Genesis of this Agreement and the other Master Documents under Genesis’ limited partnership agreement or other documents to which Genesis is a party.

 
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6.6            There are no suits or proceedings pending or, to Genesis' knowledge, threatened against Genesis before any Governmental Authority, that if decided adversely to the interest of Genesis would reasonably be expected to have a Material Adverse Effect.

6.7            The Production Payment to be acquired by Genesis pursuant to this Agreement is being acquired for Genesis’ own account and for investment and not for distribution in violation of applicable securities laws.

VII.
PAYMENT TO DENBURY

7.1            As consideration for the sale of the Production Payment to Genesis and the assignment of the Assigned Contract Interests to Genesis by Denbury, Genesis shall pay to Denbury at Closing, $24,925,000 in cash.

VIII.
DISCLAIMER OF WARRANTIES

8.1            Denbury has allowed Genesis the opportunity to review the title to the Subject Interests, to satisfy itself as to all matters pertaining to the transactions contemplated by this Agreement, including but not limited to the sufficiency of CO 2 reserves attributable to the Subject Interests to satisfy the CO 2 delivery requirements under the Assigned Contract Interests, and to conduct other due diligence with respect to the Production Payment, the Subjects Interests, the Subject Lands, the Denbury Pipeline, the Jackson Dome Plant and the Industrial Sale Contracts as Genesis deems necessary to consummate the transactions contemplated by this Agreement.

8.2            OTHER THAN THE EXPRESS REPRESENTATIONS AND WARRANTIES PROVIDED BY DENBURY HEREIN AND IN THE OTHER MASTER DOCUMENTS, DENBURY MAKES NO WARRANTIES AS TO (i) THE PRESENCE, QUALITY AND QUANTITY OF CO 2 RESERVES ATTRIBUTABLE TO THE SUBJECT INTERESTS, (ii) THE AMOUNT, VALUE, QUALITY, QUANTITY, VOLUME OR DELIVERABILITY OF ANY CO 2 OR CO 2 RESERVES IN, UNDER OR ATTRIBUTABLE TO THE SUBJECT LANDS, (iii) THE GEOLOGICAL OR ENGINEERING CONDITION OF THE SUBJECT LANDS, (iv) THE ABILITY OF THE SUBJECT LANDS TO PRODUCE CO 2 , INCLUDING WITHOUT LIMITATION, PRODUCTION RATES, DECLINE RATES AND RECOMPLETION OPPORTUNITIES, (v) ANY PROJECTIONS AS TO EVENTS THAT COULD OR COULD NOT OCCUR, (vi) THE ACCURACY, COMPLETENESS, OR MATERIALITY OF ANY DATA, INFORMATION OR RECORDS FURNISHED TO GENESIS IN CONNECTION WITH THE SUBJECT INTERESTS, SUBJECT LANDS, THE DENBURY PIPELINE AND JACKSON DOME PLANT, INCLUDING INFORMATION CONTAINED IN ANY EXHIBIT OF THIS AGREEMENT, ANY SEISMIC DATA AND DENBURY’S INTERPRETATION OR ANALYSIS OF SAME, OR (vii) ANY OTHER MATTERS CONTAINED IN OR OMITTED FROM ANY INFORMATION OR MATERIAL FURNISHED TO GENESIS BY DENBURY.  ANY DATA, INFORMATION OR OTHER RECORDS FURNISHED BY DENBURY ARE PROVIDED TO GENESIS AS A CONVENIENCE AND GENESIS’ RELIANCE ON OR USE OF THE SAME IS AT GENESIS’ SOLE RISK.

 
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IX.
INDEMNITY

9.1            Denbury hereby indemnifies Genesis and its successors and assigns and affiliates (each a “ Genesis Indemnified Party ”) against, and agrees to defend and hold each Genesis Indemnified Party harmless from and against, any and all obligations, liabilities, claims, demands, suits, debts, accounts, liens or encumbrances, and all costs and expenses, including reasonable attorneys’ fees relating thereto (collectively, “ Claims ”), that any Genesis Indemnified Party may suffer or incur and that result from (a) the ownership or operation of the Subject Interests, (b) the ownership of the Industrial Sale Contracts prior to the Effective Date, (c) any inaccuracy of any representation or warranty of Denbury contained in this Agreement or in any other Master Document, (d) any breach of any covenant or agreement of Denbury contained in this Agreement or in any other Master Document, including but not limited to the covenants relating to the Retained Obligations; provided, however, that such indemnification shall not be construed to cover or include any of the matters identified in Section 8.2 (including but not limited to disclaimers of warranties relating to CO 2 reserves or production) or any Claims to the extent, but only to the extent, such Claims are determined to be not payable because they fall within the scope of the force majeure provisions contained in the Master Documents or the Industrial Sale Contracts.

9.2            Genesis hereby indemnifies Denbury and its successors and assigns and Affiliates (each a “ Denbury Indemnified Party ”) against, and agrees to defend and hold each Denbury Indemnified Party harmless from and against, any and all Claims that each Denbury Indemnified Party may suffer or incur and that result from (a) except to the extent of any Claims arising solely as a result of Denbury’s execution of the Assignment, the ownership or operation of the Production Payment, (b) except to the extent of any Claims arising as a result of Denbury’s failure to comply with the Retained Obligations, the ownership of the Industrial Sale Contracts after the Effective Date, (c) any inaccuracy of any representation or warranty of Genesis contained in this Agreement or any other Master Document, or (d) any breach of any covenant or agreement of Genesis contained in this Agreement or any other Master Document; provided, however, that such indemnification shall not be construed to cover or include any Claims to the extent, but only to the extent, such Claims are determined to be not payable because they fall within the scope of  the force majeure provisions contained in the Master Documents or the Industrial Sale Contracts.

9.3            No person entitled to indemnification hereunder or otherwise to damages in connection with or with respect to the transactions contemplated in the Agreement and the other Master Documents  shall settle, compromise or take any other action with respect to any Claim that could prejudice or otherwise adversely impact the ability of the person providing such indemnification or potentially liable for such damages to defend or otherwise settle or compromise with respect to such Claim.

 
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9.4            Each Party entitled to indemnification hereunder or otherwise to damages in connection with the transactions contemplated in Agreement or the other Master Documents shall take all reasonable steps to mitigate all losses, costs, expenses and damages after becoming aware of any event or circumstance that could reasonably be expected to give rise to any losses, costs, expenses and damages that are indemnifiable or recoverable hereunder or in connection herewith.

9.5            The indemnification provisions provided for in this Agreement shall be applicable whether or not the losses, costs, expenses and damages in question arose solely or in part from the gross, active, passive or concurrent negligence, strict liability or other fault of Genesis or Denbury, as applicable.  The parties acknowledge that this statement complies with the express negligence rule and is conspicuous.

X.
CLOSING

10.1          Unless the Parties otherwise agree in writing, the closing of the transactions contemplated by this Agreement (the “ Closing ”) will occur on the date this Agreement is executed as first set forth above (the “ Closing Date ”)

10.2          At Closing, the following events shall occur, each being a condition precedent to the others and each being deemed to have occurred simultaneously with the others:

(a)            Genesis shall deliver to Denbury the cash consideration described in Section 7.1 by wire transferring immediately available funds to the account of Denbury pursuant to wiring instructions furnished by Denbury to Genesis prior to the Closing Date;

(b)            The Parties shall execute, acknowledge and deliver the Assignment and the Contracts Assignment;

(c)            The Parties shall execute and deliver the T&P Agreement;

(d)            Denbury shall obtain and deliver to Genesis multiple executed originals of the Agreement with Lenders executed by the holders of the Bank One Liens, in form and substance substantially similar to the Agreement with Lenders attached hereto as Exhibit F ;

(e)            Denbury shall obtain and deliver to Genesis multiple executed originals of an acceptable release of liens with respect to the Bank One Liens encumbering the Subject Interests conveyed to Genesis pursuant to the Assignment; and

 
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(f)             The Parties shall execute and deliver any other documents or instruments necessary or appropriate to effect or support the transactions contemplated in this Agreement.

10.3          Promptly following the Closing, Genesis will cause counterparts of the Assignment, a mutually agreeable Memorandum of T&P Agreement, Agreement with Lenders and financing statements to be filed for record in all appropriate records in appropriate filing locations.  Genesis will pay for all documentary, filing and recording fees required in connection with the filing and recording of the Master Documents.

XI.
COVENANTS AND AGREEMENTS OF DENBURY

During the Term, and unless Genesis otherwise agrees in writing, Denbury covenants as follows, and agrees and undertakes, to perform each and all of the following covenants at Denbury’s sole and entire cost and expense:

11.1          Denbury will (without regard to the burden of the Production Payment) conduct and carry on the development, maintenance and operation of the Subject Interests with reasonable and prudent business judgment and in accordance with good oil and gas field practices and all applicable Governmental Requirements, and will drill such wells as a reasonably prudent operator would drill from time to time in order to develop the Subject Interests and to protect them from drainage. Nothing contained in this Section, however, shall be deemed to prevent or restrict Denbury from electing not to participate in any operation that is to be conducted under the terms of any operating agreement, unit operating agreement, contract for development or similar instrument affecting or pertaining to the Subject Interests (or any portion thereof) and allowing consenting parties to conduct nonconsent operations thereon, if such election is made by Denbury in good faith and in conformity with sound field practices . After the date of this Agreement, Denbury shall not enter into any transaction(s) or agree to any arrangements which, after taking into account then current required third party sales (including sales under the Industrial Sale Contracts) and Denbury’s and its affiliates’ usage, would result or be reasonably anticipated to result in an inability of Denbury to deliver the Scheduled Delivery Volumes to Genesis.

11.2          Denbury shall not voluntarily abandon any well heretofore or hereafter completed for production of CO 2 on any of the Subject Lands or surrender, abandon or release any Subject Interest or any part thereof; provided however, that nothing in this Agreement shall obligate Denbury to continue to operate any well or to operate or maintain in force or attempt to maintain in force any Lease when, in Denbury’s reasonable opinion, exercised in good faith and as would a prudent operator not burdened by the Production Payment, such well or Lease ceases to produce or is not capable of producing in paying quantities (without regard to the burden of the Production Payment) and it would not be economically practical, in Denbury’s reasonable judgment (determined without regard to the burden of the Production Payment), to restore the productivity of such well by reworking, reconditioning, deepening, or plugging back such well.  The expiration of a Lease in accordance with its terms and conditions shall not be considered to be a voluntary surrender or abandonment of such lease.

 
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11.3          With respect to all oil, gas and mineral leases included in the Subject Interests, Denbury will in all material respects comply with, or cause to be complied with, all pertinent Governmental Requirements that from time to time are promulgated to regulate the production and sale or production or sale of CO 2 .

11.4          Certain of the Subject Interests may have been heretofore pooled and unitized for the production of CO 2 .  Such Subject Interests are and shall be subject to the terms and provisions of such pooling and unitization agreements, and the Production Payment shall apply to and affect only that portion of the production from such units that accrues to such Subject Interests as burdened, encumbered or otherwise affected by any and all applicable pooling and unitization agreements.  Denbury shall have the right and power to pool and unitize any of the Subject Interests and to alter, change or amend or terminate any pooling or unitization agreements heretofore or hereafter entered into, as to all or any part of the Subject Lands, upon such terms and provisions as Denbury shall in its sole discretion determine.  If and whenever through the exercise of such right and power, or pursuant to any Governmental Requirement hereafter enacted, any of the Subject Interests are pooled or unitized in any manner, the Production Payment, insofar as it affects such pooled or unitized Subject Interests shall also be pooled and unitized, and in any such event such Production Payment shall apply to and affect only the production that accrues to such Subject Interests, as burdened, encumbered or otherwise affected by such pooling and unitization.

11.5          Denbury shall pay, or cause to be paid, before delinquent, all Taxes, except Taxes being contested in good faith.  In the event that after the expiration of the Term, additional Taxes should be charged against Genesis which are attributable to Production Payment Gas produced during the Term and delivered to Genesis at the Receipt Point(s), Denbury shall be obligated to pay such Taxes.

11.6          Subject to the provisions of Section 2.4 hereof and Section 2.8 of the T&P Agreement, Denbury will at all times maintain, preserve and keep all Personal Property, the in good repair, working order and condition in all material respects, and promptly make all necessary and proper repairs, renewals, replacements and substitutions, to the end that the value of such Personal Property, shall in all material respects be fully preserved and kept in such condition as at all times to permit the most efficient and economical use and operation thereof.

11.7          Denbury will (i) use all commercially reasonable efforts to promptly pay, or cause to be paid, as and when due and payable all material rentals and royalties payable in respect of the Subject Interests or the production therefrom, and all material costs, expenses and liabilities for labor and material to the extent that the same are attributable to the Subject Interests, the Personal Property, the Denbury Pipeline or the Jackson Dome Plant, (ii) never permit any lien (other than Permitted Liens) to be affixed or burden the Subject Interests or Personal Property, even though inferior to the Production Payment, for any such bills which may be legally due and payable (other than Permitted Liens or liens which, individually or collectively, could not have a Material Adverse Effect), and (iii) never permit to be created or to exist in respect to any of the Subject Interests or the Personal Property, any other or additional lien on a parity with or superior to the Production Payment, except for Permitted Liens or other than liens which, individually or collectively, could not have a Material Adverse Effect.

 
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11.8          Denbury shall not resign as operator of any Subject Interest operated by Denbury until and unless the successor operator has been approved in writing by Genesis, such approval not to be unreasonably withheld or delayed.

11.9          Denbury agrees to furnish Genesis, upon request, with copies of all electrical logs, core analyses, and completion reports relating to any well now or hereafter drilled upon the Subject Lands.  Denbury agrees to furnish Genesis, upon request, with full information regarding the condition of the wells and the lease operations relating to the Subject Interests.  The reasonable cost of copying any data and information described in this Section shall be paid by Genesis.  Furthermore, Denbury’s disclosure of the data and information described in this Section is subject to and may be limited by any confidentiality obligations or other restrictions to which Denbury may be subject.

11.10        In the event that any Lease or other interest that constitutes a part of the Subject Interests should expire or terminate for any reason (a “ Lost Interest ”), and within one (1) year from date of such expiration or termination of such Lost Interest, Denbury should reacquire such Lost Interest, then such Lost Interest shall be charged and burdened with the Production Payment to the same extent that the Lost Interest was charged and burdened with the Production Payment, and Denbury agrees to execute such documents and agreements as may be necessary or appropriate to effect the intent and purpose of this section.

11.11         Airgas Obligations .

(a)
Section 4.2 of the Airgas Contract provides that Airgas at no time will pay a price for CO 2 delivered under the terms of the Airgas Contract that is greater than the lowest price paid by any other customer of the Seller (as defined therein) or its affiliates receiving CO 2 from the Source Field (as such terms are defined in the Airgas Contract).  Section 4.2 of the Airgas Contract is hereafter referred to as the “Favored Nations Clause.”  If at any time during the Term Denbury triggers the Favored Nations Clause, then Denbury agrees to (i) immediately notify Genesis of such sales and (ii) reimburse Genesis for the incremental reduction of proceeds received by Genesis under the Airgas Contract resulting from the payment of a reduced price by Airgas.  If at any time and from time to time Airgas notifies Genesis that it is entitled to a lower price pursuant to the Favored Nations Clause (a “ Reduced Price Notice ”), Genesis will immediately furnish the Reduced Price Notice to Denbury.  Genesis agrees not to take any action with respect to the Reduced Price Notice until Denbury has had an opportunity to review the matter described in the Reduced Price Notice and, if it deems appropriate, to contest such matter.

(b)
Section 11.4 of the Airgas Contract (the “ RFR Provision ”) provides that Airgas shall have the right to exercise its rights under the Right of First Refusal and Option to Purchase Agreement (as defined therein) upon the occurrence of certain events.  Each Party agrees to notify the other Party if it receives the notice provided in the RFR Provision or if it becomes aware that Airgas has failed to receive 75% of its daily requirements of CO 2   on more than 45 days in any rolling 12-month period (an “ RFR Delivery Failure ”).  If Genesis is the cause of the RFR Delivery Failure (for reasons other than force majeure (as defined in the Airgas Contract)), then for so long as Genesis allows such RFR Delivery Failure to continue, Denbury shall have the right to make direct deliveries to Airgas in satisfaction of the delivery requirements in the Airgas Contract and all volumes delivered by Denbury pursuant to this sentence shall reduce the Scheduled Delivery Volumes otherwise deliverable pursuant to the Production Payment and, furthermore, for purposes of the Term, the total aggregate volumes included in the Term shall be reduced by an amount equal to 200% of the volumes so delivered pursuant to this sentence.  If Denbury is the cause of the RFR Delivery Failure (for reasons other than (i) force majeure (as defined in the Airgas Contract) or (ii) a lack of reserves or insufficient deliverability  of reserves (provided such lack of reserves or insufficient deliverability of reserves is not the result of a failure of Denbury to comply with covenants set out in Article XI)), and Airgas exercises its purchase rights in accordance with the RFR Provision, then, in addition to any other remedies that may be available, the Parties shall use good faith efforts to reach an agreement with respect to the allocation of proceeds paid by Airgas and their application to the Production Payment after it exercises its rights under the RFR Provision, and if the Parties are unable to reach such agreement, then such matter shall be resolved in accordance with the arbitration provisions contained in Article XIV .

 
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(c)
Notwithstanding anything herein to the contrary, without the prior written consent of the other Party hereto, no Party shall amend or otherwise modify any terms or provisions of the Right of First Refusal and Option to Purchase Agreement.

11.12        Denbury acknowledges that, pursuant to this Agreement and the Contracts Assignment, Genesis is acquiring all of Denbury’s rights, interest and obligations in the Industrial Sale Contracts.  Notwithstanding such acquisition, there are certain covenants and obligations under the Industrial Sale Contracts that must be satisfied by the owner or operator of the Subject Interests.  Accordingly, Denbury covenants that, until the termination of each such Industrial Sale Contract and subject to the applicable force majeure provisions in the applicable Industrial Sale Contracts, it will fully and timely perform each and every covenant and agreement in each Industrial Sale Contract which must be performed by the Seller (as defined in each Industrial Sale Contract) and which relates to the ownership and operations of each Source Field, the production of carbon dioxide from each Source Field, and/or the measurement, metering, testing and other transportation services related thereto, including but not limited to the obligations and covenants in (a) Sections 2.5, 3.3, 5.3, 6.1, 6.2, 6.3, 6.4, 6.5, 6.6, 6.7, 7.1, 7.2, 7.3, 7.4, 8.1, 8.2 and 9.2 of the Airgas Contract; (b) Sections 2.5, 5.3, 6.1, 6.2, 6.3, 6.4, 6.5, 6.6, 6.7, 7.1, 7.2, 7.3, 7.4, 8.1 and 8.2 of the BOC-Brandon Contract; and (c) Sections 2.5, 5.3, 6.1, 6.2, 6.3, 6.4, 6.5, 6.6, 6.7, 7.1, 7.2, 7.3, 7.4, 8.1 and 8.2 of the Praxair Contract. The covenants and agreements of Denbury described in this section are collectively referred to herein as the “ Retained Obligations ”.

11.13        Denbury shall not sell CO 2 to any Buyer (as such term is defined in each of the Industrial Sale Contracts), unless each Buyer has purchased from Genesis, pursuant to each of the Industrial Sale Contracts, the total Daily Contract Quantity and Additional Volumes (as such terms are defined in each of the Industrial Sale Contracts) under each Industrial Sale Contract; provided, however, that notwithstanding the foregoing, Denbury shall be permitted to sell CO 2 to any such Buyers pursuant to and in accordance with the terms of the following contracts (and any amendments, replacements or renewals thereof that perpetuate only the rights and obligations currently existing under such contracts): (i) Contract for Sale of Carbon Dioxide Gas dated November ___, 1995 (presumed to be effective February 1, 1996), by and between Pennzoil Exploration and Production Company, as Seller, and Pisgah Partners, L.P., as Buyer; (ii) Contract for Sale of Carbon Dioxide Gas dated December 18, 2000, by and between Magna Carta Group LLC, as Seller, and Messer Greisheim Industries, Inc., as Buyer; and (iii) Carbon Dioxide Sale and Purchase Contract dated and effective February 1, 1996, by and between Shell Western E&P Inc., as Seller, and Liquid Carbonic Industries Corporation, as Buyer, as amended by Amendment No. 1 dated as of December 1, 1996, between Seller and Buyer.

 
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11.14        For so long as the Industrial Sale Contracts are in force and effect, the Production Payment Gas delivered by Denbury to Genesis shall meet the minimum quality specification set forth in the Industrial Sale Contracts.

XII.
EXCHANGE OF INFORMATION; AUDIT RIGHTS

12.1          After Closing, (a) Denbury will keep Genesis advised of Denbury’s activities in the fields encompassing the Subject Lands insofar as such activities relate to the terms and provisions of this Agreement, (b) each Party shall promptly give, or cause to be given to the other Party, written notice of any event or circumstance, including, but not limited to every adverse claim or demand made by any Person or any Governmental Authority, that could reasonably be expected to have a Material Adverse Effect, (c) each Party shall give or cause to be given to the other Party written notice of every default under any Industrial Sale Contract and every adverse claim or demand made by any Person or any Governmental Authority related to any Industrial Sale Contract, promptly upon obtaining knowledge of such default, claim or demand and shall include in such notice a description in reasonable detail of the default, claim or demand and if such Party obtained knowledge of such default, claim or demand as a result of the receipt of a written notice, a copy of such written notice, and (d) each Party shall also provide information to the other Party as needed to confirm compliance with each Party’s obligations under this Agreement and the other Master Documents, to keep the other Party updated as to matters relating to this Agreement and the other Master Documents, from time to time, and in response to reasonable inquiries by the other Party.

12.2          After Closing, each Party, by notice in writing to the other Party, shall have the right to audit the other Party’s accounts and records relating to the Production Payment, the Industrial Sale Contracts, and compliance with this Agreement and the other Master Documents.  Audit rights pertaining to the T&P Agreement are subject to the terms and provisions with respect to auditing as set forth in the T&P Agreement.  Audit rights otherwise pertaining to the Production Payment, the Industrial Sale Contracts, or other compliance issues under this Agreement and the other Master Documents are subject to the terms of Section 12.3 .

12.3          Audits shall not be conducted more than twice each year without prior approval of the Party whose records are being audited (the “ Audited Party ”), and shall be made at the expense of the Party conducting the audit.  The Audited Party shall reply in writing to an audit report within thirty (30) days after receipt of such report.  The Parties will endeavor to agree upon and make any adjustments revealed to be necessary by any audit reports submitted by the Audited Party pursuant to the provisions of this Section.  If the Parties cannot agree on any adjustment, the disputed adjustment will not be made, and such disputed adjustment shall be resolved in accordance with the dispute resolution provisions described in Section 14.1 .

 
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XIII.
NOTICES

13.1          All notices under this Agreement must be in writing.  Any notice with respect solely to the matters in the T&P Agreement shall be in accordance with the provisions pertaining to notices set forth in the T&P Agreement.  Any other notice under this Agreement may be given by personal delivery, facsimile or email transmission, U.S. mail (postage prepaid), or commercial delivery service, and will be deemed duly given when received by the Party charged with such notice and addressed as follows:

If to Denbury:
Denbury Resources Inc.
5100 Tennyson Parkway, Suite 3000
Plano, TX 75024
Attn: Ray Dubuisson
Telephone:       972-673-2044
 
Fax:                    972-672-2299
 
email:                 rayd@denbury.com

If to Genesis:
Genesis Crude Oil, L.P.
500 Dallas, Suite 2500
Houston, TX 77002
Attn:  Mark Gorman
Telephone:       (713) 860-2500
 
Fax:                    (713) 860-2640
 
email:                 mgorman@genesiscrudeoil.com

13.2          Either Party, by written notice to the other, may change the address or the individual to which or to whom notices are to be sent under this Agreement.

XIV.
DISPUTE RESOLUTION

14.1          Except as may be otherwise specifically provided herein, all disputes arising under or in connection with this Agreement shall be resolved in accordance with the procedures described in Exhibit E attached hereto and incorporated herein by reference for all purposes.

XV.
CURTAILMENTS AND INTERRUPTIONS

           15.1           If Denbury is unable on any day, whether due to interrupted or curtailed service at the Jackson Dome Plant, lack of deliverability from the producing wells, or lack of capacity on the Denbury Pipeline, or any other reason, to transport all volumes of CO 2 tendered for transportation through the Denbury Pipeline (inclusive of all volumes which Denbury may tender for transportation for its own account), and excluding those instances of inability to transport due to force majeure (in which cases the specific provisions as to force majeure in the Master Documents or in the relevant Industrial Sale Contracts will control), Denbury may interrupt or curtail service or receipt or delivery of CO 2 , without liability to or penalty payable to Genesis, in a manner (i) so that volumes attributable to the Airgas Contract (“ Airgas Volumes ”) are subject to curtailment only after complete curtailment of volumes attributable to all other parties, and then Airgas Volumes will be curtailed only as may be permitted under the Airgas Contract; (ii) so that the Excess Volumes and the volumes attributable to each of the BOC Contract and the Praxair Contract will be curtailed on a basis that is pro-rata to the volumes attributable to each of those contracts set forth in Schedule 5.18 and Denbury for its own account; provided that if the interruption or curtailment of service is longer than 45 consecutive days, then any volumes which Denbury tenders for transportation for its own account will not be included in the proration under clause (ii) above unless and until 100% of the Scheduled Delivery Volumes have been transported, determined in each case on a daily basis.  In all circumstances above requiring curtailment, all pro-rations of volumes shall be proportionately based on the actual average volumes which have been transported during the 30 days before the interruption or curtailment of service occur.

 
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XVI.
MISCELLANEOUS PROVISIONS

16.1          This Agreement and the other Master Documents constitute the entire understanding between the Parties relating to the subject matter hereof, and supersede all prior negotiations, discussions, agreements and understandings between the Parties, whether written or oral, regarding the subject matter of this Agreement.

16.2          This Agreement may be amended, modified, and supplemented only by written instrument executed by both Parties and explicitly referred to as an amendment to this Agreement.

16.3          The waiver by either Party of any breach of the provisions of this Agreement shall not constitute a continuing waiver of other breaches of the same or other provisions of this Agreement.

16.4          Neither Party shall be liable to the other for any special, indirect, consequential or punitive damages of any nature, or for attorneys’ fees.

16.5          The interests of the Parties in this Agreement, and the interests acquired by virtue of this Agreement and the interests retained by Denbury in the Subject Lands, may not be subsequently assigned, either in whole or in part, unless (i) any such assignee expressly agrees in writing to assume and perform all of the assignor's obligations under this Agreement and the other Master Documents, and (ii) such assignment is made and accepted expressly subject and subordinate to this Agreement and the other Master Documents.  Further, any subsequent assignment, either in whole or in part, to an entity that is not as financially creditworthy at the time of the assignment as the assignor shall require the consent of the other party hereto, which consent may not be unreasonably withheld or delayed.  Subject to the compliance with the terms of clauses (i) and (ii) above, either Party may encumber or pledge its respective interests in connection with a financing without the consent of the other Party.  Any purported assignment, sale, conveyance or other transfer in contravention of the foregoing terms shall be null and void.  Subject to the foregoing, this Agreement binds and inures to the benefit of the Parties and their respective permitted successors and assigns, and nothing contained in this Agreement, express or implied, is intended to confer upon any other person or entity any benefits, rights, or remedies.

 
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16.6          If any provision of this Agreement is found by a court of competent jurisdiction to be invalid or unenforceable, that provision will be deemed modified to the extent necessary to make it valid and enforceable, and if it cannot be so modified, it shall be deemed deleted and the remainder of the Agreement shall continue and remain in full force and effect.

16.7          This Agreement shall be governed by and construed according to the laws of the State of Texas, excluding any conflicts-of-law rule or principle that might apply the law of another jurisdiction.  Venue for any arbitration, lawsuit or other legal action in any way pertaining to this Agreement or any other Master Document shall be in Dallas, Dallas County, Texas.

16.8          The Parties agree to do, execute, acknowledge and deliver all further acts, conveyances and instruments as may be reasonably necessary or appropriate to carry out the provisions of this Agreement.

16.9          The omission of certain provisions of this Agreement from the Assignment does not constitute a conflict or inconsistency between this Agreement and the Assignment, and will not effect a merger of the omitted provisions.  To the fullest extent permitted by law, all provisions of this Agreement are hereby deemed incorporated into the Assignment by reference.  The headings and titles in this Agreement are for convenience only and shall have no significance in interpreting or otherwise affect the meaning of this Agreement.

16.10        This Agreement may be executed in counterparts, each of which shall constitute an original and all of which shall constitute one document.

16.11        This Agreement may be circulated and executed by facsimile transmission, and in such event, the signatures of the Parties on facsimiles shall be considered as original and self-proving for all purposes.

16.12        Genesis and Denbury agree to treat the Subject Interest as a production payment under Section 636(a) of the Code.  Both Genesis and Denbury agree (i) to file all federal income tax and state income tax returns consistent with this Section 16.12, and (ii) to use a comparable yield of 7.5% for purpose of Treasury Regulation Section 1.1275-4(b).

 
23
 

This Agreement is executed as of the date set out in the first paragraph of this Agreement, but shall be effective as of the Effective Date.

 
DENBURY RESOURCES INC.
           
           
 
By:
/s/ Phil Rykhoek                                             
   
Phil Rykhoek
   
Senior Vice President and
   
    Chief Financial Officer
           
           
 
GENESIS CRUDE OIL, L.P.
 
By:
Genesis Energy, Inc.
   
Its General Partner
           
           
   
By:
   /s/  Mark J. Gorman      
     
Name:
Mark J. Gorman
     
Title:
President
 
 
24
E xhib it 10.4


CARBON DIOXIDE TRANSPORTATION AGREEMENT

BETWEEN

DENBURY RESOURCES INC.

AS “TRANSPORTER”

AND

GENESIS CRUDE OIL, L.P.

AS “SHIPPER”

 
 

CARBON DIOXIDE TRANSPORTATION AGREEMENT

TABLE OF CONTENTS

 
   
Page
     
ARTICLE I - DEFINITIONS
1
1.1
Defined words and terms
1
     
ARTICLE II - SCOPE OF TRANSPORTATION SERVICE
3
2.1
Transportation of Carbon Dioxide
3
2.2
Redelivery of Carbon Dioxide
4
2.3
Non-Exclusive Transportation
4
2.5
Operation of Transporter’s Pipeline
4
2.6
Transporter’s Processing Rights
4
2.7
Excess Quantities
4
2.8
Call Option
5
     
ARTICLE III - RATES AND CHARGES
5
3.1
Initial Rate
5
3.2
Adjusted Rate
5
3.3
Minimum Rate
5
3.4
Tax Reimbursement
5
     
ARTICLE IV - TERM; EARLY TERMINATION FOR DEFAULT
6
4.1
Term
6
4.2
Default
6
4.3
Occurrence of Default
6
     
ARTICLE V - RECEIPT POINTS, DELIVERY POINTS AND PRESSURES
7
5.1
Receipt Points and Delivery Points
7
5.2
Responsibility
7
5.3
Pressure Criteria
7
     
ARTICLE VI - QUANTITY
7
6.1
Delivery Rates
7
6.2
Cooperation Regarding Deliveries
8
     
ARTICLE VII - QUALITY SPECIFICATIONS
8
7.1
Specification
8
7.2
Testing
8
7.3
Failure to Meet
8
     
ARTICLE VIII - OWNERSHIP AND OPERATION OF FACILITIES
9
8.1
Facility Ownership
9

 
i
 
 
ARTICLE IX – MEASUREMENT
9
9.1
Measurement Point
9
9.2
Procedure
9
9.3
Atmospheric Pressure
9
9.4
Meter Standards
9
9.5
Temperature
9
9.6
Density
9
9.7
Samples
9
     
ARTICLE X - FORCE MAJEURE
10
10.1
Definition
10
10.2
Extended Force Majeure
10
10.3
Strikes and Lockouts
10
     
ARTICLE XI - NOTICES
11
11.1
Transporter Notices
11
11.2
Shipper Notices
11
11.3
Change of Address
11
     
ARTICLE XII - PAYMENT, AUDIT AND FINANCIAL RESPONSIBILITY
11
12.1
Payment
11
12.2
Auditing
11
12.3
Failure to Pay
12
12.4
Financial Responsibility
12
     
ARTICLE XIII - WARRANTY
12
13.1
Warranty
12
     
ARTICLE XIV - GENERAL TERMS AND CONDITIONS
12
14.1
Waiver of Breach
13
14.2
Regulatory Bodies
13
14.3
CHOICE OF LAW
13
14.4
Joint Preparation
13
14.5
Assignment
13
14.6
Modification and Entire Agreement
13
14.7
Headings
13
14.8
Damage Limitation
14
14.9
Arbitration
14
14.10
Master Agreement; Conflicts
14

 
ii
 
 
CARBON DIOXIDE TRANSPORTATION AGREEMENT


THIS CARBON DIOXIDE TRANSPORTATION AGREEMENT (this “ Agreement ”), made and entered into effective as of September 1, 2003, by and between DENBURY RESOURCES INC., a Delaware corporation, hereinafter referred to as “ Transporter ”, and GENESIS CRUDE OIL, L.P., a Delaware limited partnership, hereinafter referred to as “ Shipper ”.

WITNESSETH :

WHEREAS , Shipper owns an interest in and/or has the right to market or otherwise control the disposition of Carbon Dioxide produced from certain wells located in the Jackson Dome area in Rankin County, Mississippi; and,

WHEREAS , Transporter owns and operates a gathering system connected to a mainline pipeline extending approximately one hundred eighty-three miles from a point at the outlet flange of a Carbon Dioxide dehydration facility located in Rankin County near Jackson, Mississippi, to a point in White Castle, Ascension Parish, Louisiana, which currently is capable of delivering Carbon Dioxide to the various delivery points; and,

WHEREAS , Transporter currently has available pipeline capacity for the transportation of Carbon Dioxide for Shipper; and,

WHEREAS , Shipper desires to arrange for the transportation of Carbon Dioxide through Transporter’s pipeline and Transporter desires to receive from, transport and redeliver to Shipper Carbon Dioxide in accordance with the terms and conditions stated in this Agreement.

NOW, THEREFORE , for and in consideration of the mutual benefits to be derived, the terms and conditions contained herein and other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, Transporter and Shipper hereby agree with each other as follows:

ARTICLE I
DEFINITIONS

1.1            Defined words and terms .  Except where the context otherwise indicates another or different meaning or intent, the following words and terms as used herein shall have the meanings indicated:

(a)           The term “ Airgas Contract ”  has the meaning set out in the Master Agreement.

 
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(b)           The term “ Bankruptcy Event ” means, with respect to either party, the entry of a decree or order by a court of competent jurisdiction adjudging the party a bankrupt or insolvent, or approving as properly filed a petition seeking reorganization, arrangement, adjustment or composition of or in respect of the party under the Federal Bankruptcy Code or any other applicable law, or appointing a receiver, liquidator, assignee, trustee, sequestrator (or other similar official) of the party or of any substantial part of its property, or ordering the winding up or liquidation of its affairs, and the continuance of any such decree or order unstayed and in effect for a period of sixty (60) consecutive days; or the consent by such party to the institution of bankruptcy or insolvency proceedings against it, or the filing by it of a petition or answer or consent seeking reorganization or similar relief under the Federal Bankruptcy Code or any other applicable law, or the consent by it to the filing of any such petition or to the appointment of a receiver, liquidator, assignee, trustee, sequestrator (or other similar official) of the party or of any substantial part of its property, or the making by it of an assignment for the benefit of creditors, or the admission by it in writing of its inability to pay its debts generally as they become due and its willingness to be adjudicated a bankrupt.

(c)           The terms “ Carbon Dioxide ” and “ CO2 ” each mean a substance primarily composed of molecules containing one atom of carbon and two atoms of oxygen and containing at least  95 percent by volume of such molecules.

(d)           The term “ Contract Year ” means a period of three hundred sixty-five (365) consecutive days beginning on the first day of a full month following the month in which deliveries commence under this Agreement or on any anniversary thereof; provided, however, that any such year which contains a date of February 29 th shall consist of three hundred sixty-six (366) consecutive days.  This definition of Contract Year contemplates the possibility of first deliveries occurring on a day other than the first day of a month.

(e)           The term “ cubic foot ” is the amount of Carbon Dioxide necessary to fill one cubic foot of space at a base pressure of 15.025 psia and at a base temperature of 60 degrees Fahrenheit.

(f)           The term “ Daily Maximum Quantity ” has the meaning set out in the Master Agreement.

(g)           The term “ day ” means a period beginning at 7:00 a.m. (local time) on a calendar day and ending at 7:00 a.m. (local time) on the next succeeding calendar day.  The date of a day shall be that of its beginning.

(h)           The term “ Delivery Points ” has the meaning stated in Section 2.2 .

(i)           The term “ Industrial Sale Contracts ” has the meaning set out in the Master Agreement.

(j)           The term “ Jackson Dome Plant ” means the Jackson Dome Processing Plant owned by Denbury located in Brandon, Rankin County, Mississippi.

 
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(k)           The term “ Master Agreement ” means that certain Production Payment Purchase and Sale Agreement executed contemporaneously herewith by Transporter and Shipper.

(l)            The term “ Master Documents ” means the Master Agreement and all agreements executed in connection therewith or pursuant thereto, including but not limited to this Agreement.

(m)           The term “ MCF ” means 1,000 cubic feet of Carbon Dioxide.

(n)           The term “ MMCF ” means 1,000,000 cubic feet of Carbon Dioxide.

(o)           The term “ month ” means a period beginning on the first day of a calendar month and ending at the beginning of the first day of the next succeeding calendar month.

(p)           The term “ pound-mass ” means the mass quantity of Carbon Dioxide equivalent to a pound-mass as defined by the United States National Bureau of Standards.

(q)           The term “ Production Payment ” has the meaning set out in the Master Agreement.

(r)           The term “ psia ” means pounds per square inch absolute.

(s)           The term “ psig ” means pounds per square inch gauge.

(t)           The term “ Receipt Points ” has the meaning stated in Section 2.1 .

(u)           The term “ Transportation Fee ” has the meaning stated in Article III .

(v)           The term “ Transporter’s Pipeline ” means Transporter’s existing gathering system and pipeline used for the gathering, dehydration and transportation of Carbon Dioxide from wells owned or controlled by Transporter   in Rankin County, Mississippi , which gathering system extends from various wellheads owned or controlled by Transporter to a point at the outlet flange of a Carbon Dioxide dehydration facility located in Rankin County, Mississippi, and which pipeline extends from that point to a point in Ascension Parish, Louisiana.

ARTICLE II
SCOPE OF TRANSPORTATION SERVICE

2.1            Transportation of Carbon Dioxide .  Subject to all of the terms, conditions, and limitations of this Agreement, each day during the term hereof Shipper shall have the right to tender to Transporter at the Receipt Points set forth in Exhibit A (the “ Receipt Points ”) for transportation hereunder any volume of Carbon Dioxide up to the Daily Maximum Quantity.

 
3
 
 
2.2            Redelivery of Carbon Dioxide .  Subject to all of the terms, conditions, and limitations of this Agreement, each day during the term hereof Transporter shall redeliver to Shipper, at the Delivery Points set forth in Exhibit B (the “ Delivery Points ”), the volume of Carbon Dioxide delivered by Shipper to Transporter at the Receipt Points on such day, as such volumes may be adjusted for Shipper’s proportionate share of reductions due to Carbon Dioxide lost and unaccounted for in Transporter’s Pipeline and any other loss or shrinkage factor generally applicable from time to time to Transporter’s Pipeline.

2.3            Non-Exclusive Transportation .  Subject to the qualification as to priority set out in Section 2.4 , nothing in this Agreement shall be construed to prohibit Transporter from transporting Carbon Dioxide for a person or persons other than Shipper.  Nothing in this Agreement shall be construed to require Shipper to tender any minimum quantity of Carbon Dioxide to Transporter for transportation hereunder.

 
2.4
INTENTIONALLY DELETED.

2.5            Operation of Transporter’s Pipeline .  Except as otherwise provided in Section 2.8 , Transporter will at all times maintain, preserve and keep all improvements, machinery, equipment, pipe lines, tanks, fixtures and other personal property and equipment of every kind and nature now or hereafter required in connection with operation of Transporter’s Pipeline in good repair, working order and condition, and promptly make all necessary and proper repairs, renewals, replacements and substitutions.  Subject to the forgoing and its other obligations hereunder, Transporter may, at its sole discretion, at any time and from time to time, expand, extend, repair, reconfigure or temporarily shutdown Transporter’s Pipeline and related equipment.   In exercising the foregoing rights, Transporter shall have no liability to Shipper hereunder and shall use all reasonable efforts to minimize any adverse impact on Shipper’s rights hereunder.

2.6            Transporter’s Processing Rights .  Transporter reserves the right, prior to delivery to Shipper at the Delivery Points set forth herein, at the sole cost of Transporter, to process and/or treat Carbon Dioxide received from Shipper hereunder for any purpose; provided, however, subject to Section 7.3 , Carbon Dioxide delivered to the Delivery Points shall meet the quality specifications of Article VII hereof.

2.7            Excess Quantities .  Shipper may, on any day and upon prior notice to Transporter, tender at the Receipt Point volumes of Carbon Dioxide in excess of the Daily Maximum Quantity, in which event Transporter may, in its sole judgment, transport all or any portion of such excess volumes on a fully interruptible basis.  However, the transportation of any excess volumes by Transporter shall otherwise be subject to all of the terms and provisions hereof.

 
4
 
 
2.8            Call Option .  In the event a Triggering Event (as hereinafter defined) occurs, Transporter shall have the right and option to either (i) repair, replace, restore and reconstruct Transporter’s Pipeline in substantially the form in which the same existed prior to any such Triggering Event or (ii) exercise (or cause the exercise of) the Call Option provided for in Section 2.4 of the Master Agreement.  Transporter shall notify Shipper in writing of its election of one of the options set forth above within thirty (30) days from the date of the Triggering Event.  If Transporter elects the option set out in clause (i) above, then Transporter shall commence the restoration work within thirty (30) days from the date of the Triggering Event and diligently prosecute and complete the restoration work within a reasonable time, in no event exceeding twelve (12) months from the date of the Triggering Event.  If Transporter elects the option set forth in clause (ii) above, the Call Option set forth in Section 2.4 of the Master Agreement shall be exercised in accordance with the terms thereof.  If Transporter fails to notify Shipper of its election of either clause (i) or (ii) above within thirty (30) days from the date of the Triggering Event, Transporter shall, as of such date, be deemed to have delivered notice to Shipper electing to exercise the option set forth in clause (i) above.  For purposes hereof, a “ Triggering Event ” means (a) the entire or partial destruction or damage of Transporter’s Pipeline by fire or any other casualty whatsoever; or (b) a mechanic failure or other breakdown of Transporter’s Pipeline, which in either case actually renders Transporter’s Pipeline inoperable for a minimum period of ninety-five (95) consecutive days.

ARTICLE III
RATES AND CHARGES

3.1            Initial Rate .  For the transportation and dehydration of each MCF of Shipper’s Carbon Dioxide received at the Receipt Points during any month, beginning with the date of first deliveries hereunder and continuing through the end of the first Contract Year, Shipper shall pay Transporter a transportation fee (the “ Transportation Fee ”), which fee shall initially be $0.16 (the “ initial rate ”).

3.2            Adjusted Rate .  Effective on the first day of each Contract Year after the first Contract Year, the Transportation Fee shall be adjusted, upward or downward.  Computations to determine such adjustments shall be made utilizing $0.16/Mcf as the base rate.  The adjustment shall be based upon the change in the annual average of the Producers Price Index, “PPI,” All Commodities, 1982 = 100, as published by the United States Department of Labor, Bureau of Labor Statistics.  To determine the adjusted rate for each subsequent Contract Year, the following formula shall be used:

Adjusted rate = Base rate x (0.10 + 0.90 x PPI current/PPI base) or the initial rate, whichever is greater.
Thus, by way of illustration, should the average PPI for the year 2002 be 125, and the average PPI for the year 2003 be 130, the adjusted price for the subsequent Contract Year, 2004, commencing on the anniversary of the Contract Year, would be computed as follows:

$0.16 x (0.10 + 0.90 x 130/125) = $0.16576

3.3            Minimum Rate .  Notwithstanding the foregoing, the Transportation Fee, as adjusted herein, shall never be less than $0.16 per MCF.

3.4            Tax Reimbursement .  In addition to the Transportation Fee provided for above, Shipper shall reimburse Transporter for all taxes which are levied upon and/or paid by Transporter with respect to the services performed under this Agreement, but only if and to the extent that Shipper has the right to receive reimbursement for such taxes from Shipper’s customers under the terms of Shipper’s resale contracts with its customers.

 
5
 
 
ARTICLE IV
TERM; EARLY TERMINATION FOR DEFAULT

4.1            Term .  Subject to the other provisions hereof, this Agreement shall be effective from the date hereof and shall continue in force and effect until the Production Payment is fully discharged.

4.2            Default .  The occurrence of one or more of the following matters shall constitute a default by a party:

(a)           the occurrence of a Bankruptcy Event involving such party;

(b)           the failure of such party to make any payment to the other party as and when due hereunder where such failure continues for thirty (30) days after the delivery of written notice by the other party of such failure to make such payment; and,

(c)           the breach by such party of any other material covenant, agreement, obligation, duty or provision of this Agreement, where such breach continues for thirty (30) days after its receipt of written notice thereof from the other party; provided, however, that if the matter which is the subject of the breach cannot by its nature with due diligence be remedied by such within said thirty (30) day period, and such party shall have prepared a plan for remedying such failure that is reasonably acceptable to the other party and such party is proceeding with diligence to implement such plan, such thirty (30) day period shall be extended by such additional time period as may be reasonably required to implement such plan, and, provided further, however, that the remedying of such potential default shall not affect the right of the other party to terminate this Agreement if other defaults occur before such potential default has been remedied.

4.3            Occurrence of Default .  Upon the occurrence of a default by a party, the other party may exercise any right or remedy it may have at law and/or in equity; provided that Transporter shall not be entitled to terminate this Agreement.  If pursuant to an arbitration proceeding conducted in accordance with Section 14.9, it is determined that as a result of a Shipper default Transporter has suffered a specified amount of damages, the arbitrators may provided as a remedy to Transporter that Transporter may sell a portion of Shipper’s carbon dioxide necessary to generate sufficient proceeds to reimburse Transporter for such damages.

 
6
 
 
ARTICLE V
RECEIPT POINTS, DELIVERY POINTS AND PRESSURES

5.1            Receipt Points and Delivery Points .  The Receipt Points are set forth on Exhibit A .  The Delivery Points are set forth on Exhibit B .  Shipper may request at any time and from time to time that Transporter agree to one or more additional Receipt Points or Delivery Points on Transporter’s Pipeline.  Transporter shall not unreasonably withhold its agreement to the addition of any additional Receipt Point or Delivery Point requested by Shipper as long as Shipper reimburses Transporter for all incremental costs incurred or to be incurred by Transporter as a result of the addition of such Receipt Point or Delivery Point and, with respect to requested Receipt Points only, so long as Transporter owns or controls the well or wells to be producing into the requested Receipt Point.  If Transporter’s estimated incremental cost to establish an additional Receipt Point or Delivery Point requested by Shipper exceeds $25,000, then Transporter shall be entitled to require that Shipper pay Transporter such estimated incremental cost before agreeing to add such additional Receipt Point or Delivery Point, with a “true-up” payment being made by the appropriate party to the other party when the final, actual incremental costs of such additional Receipt Point or Delivery Point are known.  Upon the addition of any Receipt Point or Delivery Point, the parties shall execute an amendment of this Agreement which shall reflect all of the Receipt Points or Delivery Points on a revised Exhibit A or Exhibit B , as appropriate.  The exact point at which delivery by Transporter to Shipper shall be deemed to be made shall be the flange or weld connecting the facilities of Transporter’s Pipeline with the facilities of Shipper or Shipper’s designee.

5.2            Responsibility .  As between the parties hereto, and subject to the limitations set forth in other provisions of this Agreement, Transporter shall be responsible for any injuries, losses, expenses, claims, liabilities, or damages caused by the Carbon Dioxide while it is in Transporter’s Pipeline until it shall have been delivered to Shipper or Shipper’s designee at the Delivery Points, and, after such delivery, Shipper shall be responsible for any injuries, losses, expenses, claims, liabilities, or damages caused thereby.  Subject to the limitations set forth in other provisions of this Agreement, each party (the “ Indemnifying Party ”) shall indemnify the other party in respect of any injuries, losses, expenses, claims, liabilities, or damages occurring while the Carbon Dioxide is in possession of the Indemnifying Party.  Transporter shall not take title to Shipper’s Carbon Dioxide in Transporter’s Pipeline merely by receipt of such Carbon Dioxide for Shipper’s account

5.3            Pressure Criteria .  All Carbon Dioxide tendered by Shipper at any Receipt Point shall be delivered at pressures sufficient to enter Transporter’s Pipeline at the working pressures maintained by Transporter at such Receipt Point from time to time.  Transporter shall deliver the volumes of Carbon Dioxide as provided for hereunder at the Delivery Points at pressures ranging from 1100 to 1400 psig.  Notwithstanding the foregoing, Transporter reserves the right at any time and from time to time, to revise the maximum and/or the minimum pressures set forth above on ten (10) days’ prior notice to Shipper to the extent the implementation of any such revision is prudent in light of the operating conditions on the Transporter’s Pipeline.

ARTICLE VI
QUANTITY

6.1            Delivery Rates .  Transporter and Shipper shall endeavor to deliver and to accept, respectively, Carbon Dioxide in as reasonable constant rates as is practicable.  Transporter and Shipper understand and agree that the amount of Carbon Dioxide delivered hereunder from time to time may not exactly equate with the volume of Carbon Dioxide requested for delivery hereunder since variations may occur due to the inherent fluctuations in normal pipeline operations.  Upon request from Shipper, Transporter may deliver Carbon Dioxide on any day in excess of the Daily Maximum Quantity, but Transporter shall not be obligated to do so.

 
7
 
 
6.2            Cooperation Regarding Deliveries .  Shipper or Shipper’s agent shall notify Transporter monthly, in advance, of Shipper’s estimated daily requirements at each of the Receipt Points and the Delivery Points for the next succeeding month and Transporter shall deliver such requirements, up to the Daily Maximum Quantity, out of the volumes received by Transporter at the Receipt Points for Shipper’s account.  Transporter and to the extent it will not result in a default under a Industrial Sale Contract, Shipper agree to fully cooperate with each other in adjusting monthly and daily deliveries hereunder.  Shipper or Shipper’s agent shall give twenty-four (24) hours’ prior notice of any additional changes in its daily requirements as may be necessary from time to time and, on receipt of such notice by Shipper, Transporter shall undertake as soon as practicable to conform its deliveries to Shipper’s revised daily requirements (up to the Daily Maximum Quantity) and shall notify Shipper as soon as practicable if Transporter is unable to do so.  In the event of an emergency which poses danger to life or property, no prior notice shall be necessary before partial or total shutdown by either party, but notice of such shutdown and the reason therefor shall be given as soon as practicable thereafter.  If a shutdown becomes necessary for either party on a non-emergency basis, such party shall give at least twenty-four (24) hours’ prior notice to the other party.

ARTICLE VII
QUALITY SPECIFICATIONS

7.1            Specification .  The Carbon Dioxide delivered by Transporter to Shipper at the Delivery Points shall meet the following specifications (collectively the “Quality Specification”):

(a)            Water .  The Carbon Dioxide shall not contain any free water and the water vapor content shall not exceed thirty (30) pounds per MMcf.

(b)            Hydrogen sulfide and sulfur .  The Carbon Dioxide shall not contain more than 10 parts by weight of hydrogen sulphide nor more than 35 parts by weight of total sulfur per 1,000,000 parts of Carbon Dioxide.

(c)            CO2 Volume .  The Carbon Dioxide shall be  95% pure (dry basis).

7.2            Testing .  Transporter shall ensure that tests to determine the quality of Carbon Dioxide are conducted as often as necessary in Transporter’s sole opinion, utilizing approved standard methods in general use.  Transporter may furnish Shipper with copies of all test results.  Transporter shall give Shipper reasonable notice of all such tests in order that Shipper or Shipper’s agent may have its representative present, if Shipper so desires.

7.3            Disclaimer . THE PARTIES HERETO RECOGNIZE AND AGREE THAT TRANSPORTER IS NOT A MERCHANT OF FOOD GRADE OR MERCHANTABLE CARBON DIOXIDE FOR USE IN FOOD OR DRINK OR OTHER CONSUMABLES AND TRANSPORTER IN NO WAY WARRANTS THE MERCHANTABILITY OR FITNESS OF ANY CARBON DIOXIDE DELIVERED OR TO BE DELIVERED HEREUNDER FOR ANY PARTICULAR PURPOSE.

 
8
 
 
ARTICLE VIII
OWNERSHIP AND OPERATION OF FACILITIES

8.1            Facility Ownership .  Transporter will own, operate and maintain the Transporter’s Pipeline, and the pipelines and measurement facilities, including any additional equipment installed by or at the request of Shipper, at each Receipt Point and at each Delivery Point.  Transporter will maintain Carbon Dioxide custody to the upstream flange of Shipper’s valve on the outlet side of Transporter’s measurement facilities at each Delivery Point.  Transporter shall be solely responsible for the delivery of Carbon Dioxide to the inlet side of Shipper’s tap valve at each Delivery Point.  All piping downstream from the Delivery Points shall be the responsibility of Shipper.

ARTICLE IX
MEASUREMENT

9.1            Measurement Point .  The Carbon Dioxide delivered hereunder shall be measured for custody transfer at the Delivery Points in accordance with the standards set out in this Article.

9.2            Procedure .  Custody transfer measurement of Carbon Dioxide shall be determined from pound-mass quantities, which will be converted to standard cubic feet quantities.  The molecular weight of the metered stream of Carbon Dioxide, calculated from the compositional analyses, shall be the basis for conversion of pound-mass measurement units to standard cubic feet measurement units.

9.3            Atmospheric Pressure .  The atmospheric pressure at the Delivery Point shall be based upon 14.73 psia at sea level, corrected to actual elevation, and may be assumed to be constant for calculation purposes.

9.4            Meter Standards .  The Carbon Dioxide delivered hereunder shall be measured with orifice meters constructed and installed in accordance with the October, 1981, compilation of standards in the American Petroleum Institute, Manual of Petroleum Standards , Chapter 14, with any subsequent amendments, revisions and additions which may be mutually acceptable to Transporter and Shipper.  Computations of pound mass shall also be made in accordance with said manual.

9.5            Temperature .  The temperature of the Carbon Dioxide shall be determined by an on-line temperature measuring device so installed that it will sense the temperature of the Carbon Dioxide flowing through the meter.

9.6            Density .  The density of the Carbon Dioxide shall be determined by an on-line density meter referenced to weight in a vacuum, or by calculation utilizing the pressure, temperature and composition of the Carbon Dioxide flowing through the meter.

9.7            Samples .  A composite sample of Transporter’s Pipeline Carbon Dioxide stream shall be accumulated during each month and analyzed for its composition by gas chromatograph or other methods agreed to by Transporter and Shipper, at Transporter’s expense.

 
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ARTICLE X
FORCE MAJEURE

10.1          Definition .  If, while this Agreement is in effect, either party is rendered unable, wholly or in part, by Force Majeure to carry out its obligations (except financial obligations) under this Agreement, it is agreed that, on such party’s giving notice and reasonably full particulars of such Force Majeure in writing to the other party within ten (10) business days after the occurrence of the Force Majeure relied on, then the obligations of the party giving such notice, so far as they are affected by such Force Majeure, shall be suspended during the continuance of any inability so caused, but for no longer period, and such cause shall so far as possible be remedied with all reasonable dispatch.  The term “Force Majeure”, as used herein, shall mean acts of God, strikes, lockouts or other industrial disturbances, acts of the public enemy, wars, terrorism, blockades, insurrections, riots, epidemics, landslides, lightning, earthquakes, fires, storms, floods, high water, washouts, arrests and restraints of government and people, civil disturbances, explosions, breakage or accident to machinery or lines of pipe, freezing of wells or lines of pipe, partial or entire failure of wells, and any other causes, whether of the kind herein enumerated or otherwise, not reasonably within the control of the party claiming Force Majeure.   Without limiting the generality of the foregoing, the term “Force Majeure” shall likewise include (a) in those instances where either party hereto is required to obtain servitudes, rights-of-way grants, permits or licenses to enable such party to perform hereunder, the inability of such party to acquire, or the delays on the part of such party in acquiring, at reasonable cost and after the exercise of reasonable diligence, such servitudes, rights-of-way grants, permits or licenses, and (b) in those instances where either party hereto is required to furnish materials and supplies for the purpose of constructing or maintaining facilities or is required to secure permits or permissions from any governmental agency to enable such party to perform hereunder, the inability of such party to acquire, or the delays on the part of such party in acquiring, at reasonable cost and after the exercise of reasonable diligence, such materials and supplies, permits and permissions.  An occurrence of Force Majeure affecting Transporter’s supply sources or processing facilities or gathering system or Transporter’s Pipeline shall be deemed to be an occurrence of Force Majeure affecting Transporter hereunder.

10.2          Extended Force Majeure .  If, after deliveries have commenced hereunder, an event of Force Majeure significantly affects the amount of Carbon Dioxide Transporter is capable of delivering for a consecutive period of 180 days, then, at any time after such period and prior to the time such event has been remedied, Shipper may cancel this Agreement.

10.3          Strikes and Lockouts .  It is understood and agreed that the settlement of strikes or lockouts shall be entirely within the discretion of the party having the difficulty and that the above requirement that any Force Majeure shall be remedied with all reasonable dispatch shall not require the settlement of strikes or lockouts by acceding to the demands of any opposing party when such course is inadvisable in the discretion of the party having the difficulty.

 
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ARTICLE XI
NOTICES

11.1          Transporter Notices .  All notices provided for herein shall be in writing and shall be deemed to be delivered to Transporter when deposited in the United States mail to the following address:

 
DENBURY RESOURCES INC.
 
Attn: Linda A. Miller
 
5100 Tennyson Parkway
 
Suite 3000
 
Plano, Texas  75024

11.2           Shipper Notices .  All notices provided for herein shall be in writing and shall be deemed to be delivered to Shipper when deposited in the United States mail to the following address :

 
GENESIS CRUDE OIL, L.P.
 
Attn: Mark J. Gorman
 
500 Dallas St. Suite 2500
 
Houston, Texas  77002

11.3          Change of Address .  Either party may change its address described in this Article by sending written notice to the other party in accordance with the provisions of this Article.

ARTICLE XII
PAYMENT, AUDIT AND FINANCIAL RESPONSIBILITY

12.1          Payment .  Transporter shall furnish Shipper a monthly statement showing (i) the total quantity of Carbon Dioxide received hereunder during the preceding month at each Receipt Point, (ii) the total quantity of Carbon Dioxide delivered hereunder during the preceding month at each Delivery Point, and (iii) the incremental costs incurred by Transporter to add any additional Delivery Points requested by Shipper.  Shipper shall make payment by wire transfer to such address as Transporter may designate from time to time on or before the later to occur of (x) the tenth day following the day that Transporter’s monthly statement was delivered or (y) the twentieth day of the month following the month that Carbon Dioxide was delivered, such wire transfer being for all amounts payable hereunder.

12.2          Auditing .  Each party shall have the right at reasonable business hours to examine the books, records, and measurement documents of the other party to the extent necessary to verify the accuracy of any statement, payment, calculation, or determination made pursuant to the provisions of this Agreement for any Contract Year within two (2) Contract Years following the end of such Contract Year.  If any such examination shall reveal, or if either party shall discover, any error or inaccuracy in its own or the other party’s statement, payment, calculation, or determination, then proper adjustment and correction thereof shall be made as promptly as practicable thereafter, except that no adjustment or correction shall be made for an error or inaccuracy if more than two (2) Contract Years have elapsed since the end of the Contract Year in which such error or inaccuracy occurred.

 
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12.3          Failure to Pay .  If Shipper fails to pay any amount payable to Transporter hereunder when due, interest thereon shall accrue and be payable at the lesser of (i) the highest legally permissible rate or (ii) the prime lending rate, plus an additional five percent (5%), established by the Chase Manhattan Bank, N.A., New York, from the date when payment was due until the date payment is made.  If such failure to pay any amount continues for  thirty (30) days or more after the due date of such amount for any reason, then (a) Transporter may suspend its deliveries of Carbon Dioxide hereunder, (b) Transporter shall have the right to make direct deliveries in satisfaction of the delivery requirements in the Industrial Sale Contracts, and (c) such matter shall be resolved in accordance with the arbitration provisions described in Section 14.9 .

12.4          Financial Responsibility .  Notwithstanding anything to the contrary in this Agreement, should Transporter reasonably believe it necessary to assure payment for transportation of Carbon Dioxide being delivered or to be delivered hereunder, Transporter may at any time, require (i) advance cash payment; (ii) a standby irrevocable letter of credit at Shipper’s expense in a form and from a bank acceptable to Transporter, in Transporter’s sole opinion; or (iii) other security of a type and form and amount which may be deemed reasonably satisfactory to Transporter.  In the event banking or credit information requested by Transporter has not been furnished within a reasonable time in Transporter’s sole opinion, Transporter shall have the right, with five (5) days’ prior notice, to withhold and/or suspend deliveries hereunder, in addition to any and all other remedies available hereunder; provided that Transporter shall not have the right to terminate this Agreement.

ARTICLE XIII
WARRANTY

13.1          Warranty .  Each party warrants, for itself, its successors, heirs, legal representatives and assigns, to the other party that at the time such party delivers Carbon Dioxide to the other party, such party will have good title to or the good right to deliver such Carbon Dioxide, and that such Carbon Dioxide shall be free and clear from liens, encumbrances and claims of every kind.  Each party shall indemnify and save the other party harmless from all suits, claims, liens, damages, costs, losses, expenses and encumbrances of whatsoever nature arising from and out of claims of any or all persons to said Carbon Dioxide, or title thereto, or to royalties, taxes, license fees, payments or other charges thereon applicable before the delivery of the Carbon Dioxide by such party to the other party.

ARTICLE XIV
GENERAL TERMS AND CONDITIONS

14.1          Waiver of Breach .  The waiver by any party of any breach of the provisions of this Agreement shall not constitute a continuing waiver of other breaches of the same or other provisions of this Agreement.

 
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14.2          Regulatory Bodies .  This Agreement, all operations contemplated hereunder and all terms and provisions contained herein, and the respective obligations of the parties are subject to applicable federal and state laws and the applicable orders, rules, and regulations of any state or federal regulatory authority having appropriate jurisdiction.  However, nothing contained herein shall be construed as a waiver of any right of any party to question or contest any such law, order, rule, or regulation in any forum having or alleging to have jurisdiction.  Shipper and Transporter each agree to comply with all applicable laws and regulations governing the operations and transactions involved in this Agreement, including, but not limited to, applicable regulations governing safety, pollution, and pipeline and other operations.  Transporter and Shipper understand that Shipper’s ability to deliver Carbon Dioxide hereunder is subject to existing and future governmental regulations affecting Transporter’s Pipeline.

14.3          CHOICE OF LAW .  THIS AGREEMENT SHALL BE GOVERNED BY AND INTERPRETED IN ACCORDANCE WITH THE LAWS OF THE STATE OF MISSISSIPPI, EXCLUDING ITS CONFLICTS OF LAW PROVISIONS.

14.4          Joint Preparation .  This Agreement was prepared by all parties hereto and not by any party to the exclusion of one or the other.

14.5          Assignment .  The interests of the parties in this Agreement, and Transporter’s interest in the Transporter’s Pipeline, may not be subsequently assigned, either in whole or in part, unless (i) any such assignee expressly agrees in writing to assume and perform all of the assignor’s obligations under this Agreement, and (ii) such assignment is made and accepted expressly subject and subordinate to this Agreement.  Further, any subsequent assignment, either in whole or in part, to an entity that is not as financially creditworthy at the time of the assignment as the assignor shall require the consent of the other party hereto, which consent may not be unreasonably withheld or delayed.  Subject to the compliance with the terms of clauses (i) and (ii) above, either party may encumber or pledge their respective interests in connection with a financing without the consent of the other party.  Any purported assignment, sale, conveyance or other transfer in contravention of the foregoing terms shall be null and void.  Subject to the foregoing, this Agreement binds and inures to the benefit of the parties and their respective permitted successors and assigns, and nothing contained in this Agreement, express or implied, is intended to confer upon any other person or entity any benefits, rights, or remedies.

14.6          Modification and Entire Agreement .  No amendment or other modification of the terms or provisions of this Agreement shall be made except by the execution of written agreements by both parties, and any attempted modification or amendment not in compliance with the terms of this sentence shall be void ab initio.  This Agreement and the other Master Documents contain the entire agreement between the parties with respect to the subject matter hereof, and supersede and terminate all prior negotiations, representations or agreements, whether written or oral, by and between the parties with respect to such subject matter

14.7          Headings .  The Table of Contents and headings contained in this Agreement are used solely for convenience and do not constitute a part of the agreement between the parties hereto, and they should not be used to aid in any manner in construing this Agreement.

 
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14.8          Damage Limitation .  Neither party shall be liable to the other for any special, indirect, consequential or punitive damages of any nature.

14.9          Arbitration .  In the event of a dispute between the parties as to any matter arising under this Agreement, such dispute shall be resolved in accordance with the dispute resolution provisions identified in Article XIV of the Master Agreement.

14.10        Master Agreement; Conflicts .  This Agreement is delivered pursuant to and as a part of the transactions under the Master Agreement and is made expressly subject thereto. In the event of any express conflict between the terms and provisions of this Agreement and the terms and provisions of the Master Agreement, the terms and provisions of this Agreement shall control.  The inclusion in the Master Agreement of provisions not addressed in this Agreement shall not be deemed a conflict, and all such additional provisions contained in the Master Agreement (including but not limited to Section 15.1 thereof) shall be given full force and effect.

 
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IN WITNESS WHEREOF, the parties hereto have caused this Agreement to be duly executed in multiple originals by their proper officers thereunto duly authorized, as of the date first hereinabove written.

 
TRANSPORTER
     
 
DENBURY RESOURCES INC .
     
     
 
By:
/s/  Phil Rykhoek
   
Phil Rykhoek
   
Senior Vice President and
   
    Chief Financial Officer
     
 
SHIPPER
     
 
GENESIS CRUDE OIL, L.P.
     
     
 
By:
/s/  Mark J. Gorman
   
Mark J. Gorman
   
President

 
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EXHIBIT “A”
TO
CARBON DIOXIDE TRANSPORTATION AGREEMENT BETWEEN
DENBURY RESOURCES INC. AND
GENESIS CRUDE OIL, L.P.
DATED EFFECTIVE AS OF SEPTEMBER 1, 2003


RECEIPT POINT LOCATIONS AND DAILY MAXIMUM QUANTITY


Daily Maximum Quantity : The Daily Maximum Quantity shall be the amount specified for such term in the Master Agreement.


Receipt Point Description
 
Daily Maximum Quantity at this Receipt Point (if applicable)
       
1.
AirGas
 
22,500 Mcf/d
 
217 Andrew Jackson Circle
   
 
Star, Mississippi 39167
   
       
2.
Praxair
 
8,750 Mcf/d
 
214 Carbonic Dr.
   
 
Brandon, Mississippi 39042
   
       
3.
BOC
 
17,500 Mcf/d
 
159 Andrew Chapel Rd.
   
 
Brandon, Mississippi 39042
   

 
 
 
 
EXHIBIT “B”
TO
CARBON DIOXIDE TRANSPORTATION AGREEMENT BETWEEN
DENBURY RESOURCES INC. AND
GENESIS CRUDE OIL, L.P.
DATED EFFECTIVE AS OF SEPTEMBER 1, 2003


DELIVERY POINT LOCATIONS

Delivery Point Description
Daily Maximum Quantity at this Delivery Point (if applicable)


Wells and wellhead meter numbers:

McKay #2
FQI 300
McKay #1 (not flowing)
FQI 301
Hauburg #4
FQI 302
Hauburg #3
FQI 303
Hauburg #1
FQI 304
Hauburg #2
FQI 305
Hauburg #6
FQI 306
Hauburg #5
FQI 307
Cruthirds #1
FQI 309
Denkmann
FQI 310
International Paper (IP)
FQI 311
Barksdale
FQI 312
 
 
Exhibit 10.24


GENESIS ENERGY, INC.
FIRST AMENDED AND RESTATED
STOCK APPRECIATION RIGHTS PLAN

Section 1
Purpose

The purpose of the Stock Appreciation Rights Plan (the "Plan") is to advance the interests of Genesis Energy, Inc. (the "Company") and its affiliates and owners by providing performance incentives to employees and Directors of the Company whose present and potential contributions are important to the continued success of the Company. The Plan is intended to enable the Company to attract and retain highly qualified persons for the successful conduct of its business.  These objectives are intended to be effected by creating a sense of equity participation in the Company through the sharing of the appreciation in the unit price of Genesis Energy, L.P.(“GEL”) Common Units.  Definitions for certain terms are contained in Section 14 below.

Section 2
Eligibility

In order to be eligible for and receive an allocation of Units granted under Section 4 below for a Plan Year, the Participant must be a regular, full-time active employee, not on probation, or a Director of the Company on the date of the allocation of Units.

Section 3
Administration of the Plan

The Plan shall be administered by the Compensation Committee of the Board of Directors of the Company (hereinafter referred to as the "Committee").  The Committee shall have full discretion and authority to administer the Plan.  Any interpretation by the Committee of the terms and conditions of the Plan shall be final.  The Plan shall be operated on a calendar year.

Section 4
Stock Appreciation Rights

(a)           Stock Appreciation Rights (the "Units") will be allocated to the accounts (the "Accounts") of the Plan participants (the "Participants") in a manner determined by the Committee in its full discretion.

(b)           The total number of Units authorized for allocation to the Participants in the Plan each year shall be determined by the Committee in its full discretion.

(c)           For each year, the Committee shall determine, in its full discretion, the grant date for the allocation of Units among the eligible Participants in the Plan.

 
 
 

(d)           The Committee shall determine, in its full discretion, a prescribed formula for allocating Units to new employees of the Company.

(d)           Each Unit shall have a term of 10 years (i.e., 120 months) from the grant date.

(e)           At the time a Unit is allocated to each Participant, the Committee will assign a strike price to the Unit, referenced to the market price of GEL units at that time, as determined by the Committee in its full discretion.

Section 5
Vesting and Forfeiture

Each Participant will have a vested percentage of the Units allocated to that Participant's Account determined as follows:

2003 Grant :

The Units allocated in 2003 and Units allocated to new employees pursuant to Section 4(d) will vest 25 percent per year for each full year of service from January 1, 2004.  Therefore, each Participant receiving an allocation of Units for 2003 will become 100 percent fully vested in such Units if such Participant remains in continuous full-time employment with the Company through December 31, 2007.  This can be summarized as follows:

Continuous Full-Time Employment Through
 
Vested Percentage
December 31, 2004
 
25%
December 31, 2005
 
50%
December 31, 2006
 
75%
December 31, 2007
 
100%

2004 through 2008 :

The Units allocated in 2004 and each year thereafter through December 31, 2008 will remain unvested for the first three years and then become 100 percent fully vested to a Participant, if such Participant remains in continuous full-time employment with the Company through December 31 of the fourth calendar year following the year of allocation.  In the case of the 2004 allocated Units, a qualified Participant will become fully vested on December 31, 2008.  This can be summarized as follows:

Continuous Full-Time Employment Through
 
Vested Percentage
December 31, 2005
 
    0%
December 31, 2006
 
    0%
December 31, 2007
 
    0%
December 31, 2008
 
100%

 
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2009 and Later Grants :

The Units allocated in 2009 and Units allocated to new employees pursuant to Section 4(d) after December 31, 2008 will vest 25 percent per year for each full year of service from the date of grant.  Therefore, each Participant receiving an allocation of Units for 2009 will become 100 percent fully vested in such Units if such Participant remains in continuous full-time employment with the Company through the anniversary date of the grant in 2013.  Assuming a grant date of February 24, 2009, this can be summarized as follows:

Continuous Full-Time Employment Through
 
Vested Percentage
February 24, 2010
 
25%
February 24, 2011
 
50%
February 24, 2012
 
75%
February 24, 2013
 
100%


If a Participant terminates employment for any reason other than death, Disability or Normal Retirement, the Participant will forfeit the nonvested Units in his or her Account.  Units forfeited in a Plan Year by any Participant will totally lapse and expire and will not become part of a pool of Units to be allocated to other Participants.

If a Participant terminates employment due to death, Disability or Normal Retirement, all Units allocated to such Participant's Account shall become fully vested.  If a Participant is terminated for any reason within one year after the effective date of a Change in Control, all Units allocated to such Participant’s Account shall become fully vested.

Section 6
Exercise and Distributions

Each Participant who has a vested Account balance under the Plan shall be entitled to exercise its Units to receive a cash payment as follows:

After a Unit has vested, during the Unit's term, the Participant may exercise any number of the Participant's vested Units by filing the prescribed form with the Committee.  As soon as administratively feasible following such exercise, the Participant shall be paid in cash, a lump sum amount equal to the excess of the average closing market price of GEL units as traded on the American Stock Exchange for the ten (10) trading days   preceding the date of exercise over the strike price of the exercised Unit.  The cash payment to each Participant upon exercise of a Unit shall 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 Company to make cash payments to Participants who have exercised Units under the Plan as soon as feasible following such exercise, the Committee may authorize deferring such payments until such time as it determines, in its full discretion, that it would not cause significant financial harm to the Company to make such deferred cash payments.  All deferred cash payments shall be made to the Participants in the order in which such Units were exercised.

 
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If upon the expiration of a Unit's term, the Participant has not terminated employment from and remains an employee of the Company, the Unit shall be deemed exercised as of the date of the Unit's expiration and cash payment shall be made as provided in this Section 6.

In the event of a Participant's termination of employment for any reason other than death, Disability or Normal Retirement, prior to exercise of all the Participant's vested Units, any remaining vested but unexercised Units must be exercised within 3 months following the Participant's termination of employment, after which time such Units shall lapse and expire and no longer be available for either future allocation under the Plan or exercise by any Participant.

In the event of a Participant’s termination of employment due to death, Disability or Normal Retirement prior to the exercise of all of the Participant’s vested units, any remaining vested but unexercised Units must be exercised within 12 months following the Participant's termination of employment.  If such Participant’s has not exercised such Units within 12 months following the Participant's termination of employment, such Units shall be deemed exercised as of the date 12 months following the Participant's termination of employment and cash payments shall be made as provided in this Section 6.

In the event of a Participant's death prior to exercise of all the Participant's vested Units, any further exercise shall be made by the Participant's designated beneficiary on file with the Committee.  If no such designation is on file or the beneficiary (or beneficiaries) designated therein does not survive the Participant, the exercise shall be made by the Participant's surviving spouse, or if none, by the trustee of the Participant's estate.  A Participant may submit to the Committee on the form prescribed therefor, the beneficiary or beneficiaries designated by the Participant to exercise the vested Units.  A Participant may update and supersede a prior beneficiary designation with a later one, which shall be controlling under the Plan if received by the Committee prior to the Participant's death.  Divorce shall automatically revoke a beneficiary designation of the divorced spouse.

Section 7
No Rights as L.P. Unit Holders

The Units under this Plan shall not carry any rights of a common unit of GEL.  The Participants under this Plan shall have no rights whatsoever as a unit holder of GEL   with respect to any Units under this Plan including but not limited to any right to vote or receive distributions of any kind with respect to such Units.  No amount shall be added to or credited to the account of any Participant pursuant to this Plan based on or because of any distribution made to the unit holders of GEL.

 
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Section 8
Employment

Nothing in this Plan shall be deemed to grant any right of continued employment to a Participant or to limit or waive any rights of the Company to terminate such employment at any time, with or without cause.

Section 9
Nonassignability of Units

The Participant's rights to any Units, any cash payment   from the Plan, or any other interest of the Participant under this Plan shall not be subject to assignment, alienation, pledge, attachment, foreclosure or any other form of transfer except in the case of death for transfers of the right to receive payment for Units by a Participant's will or under the laws of descent and distribution, or except for domestic relations orders determined by the Committee to be of a qualified nature similar to the rules under the Company's qualified 401(k) retirement savings plan.  The Company shall have no obligation to make payments under this Plan to any person other than the Participant (or designated beneficiary), unless directed to by a court of competent jurisdiction.

Section 10
No Trust Fund

Participants under the Plan shall have no interest in any fund or specific asset of the Company, GEL or any other affiliate or subsidiary of the Company or GEL.  No trust fund shall be created in connection with the Plan or any Units, and there shall be no advanced funding of any amounts that may become payable under the Plan.

Section 11
Adjustments in the Event of Changes in the
Capital Structure or Reorganization--Anti-Dilution

Changes in Capital Structure . - The Board shall make appropriate equitable adjustments to protect the Participants or the Company from any adverse financial impact which might result as a consequence of common unit splits or other changes in GEL’s   capital structure.
 
Section 12
Amendment and Termination

The Board shall have the sole right at any time to terminate or amend the Plan or any part thereof except that any termination or amendment of the Plan shall not materially reduce the benefits that have previously accrued to Participants, or have the effect of reducing a Participant's benefit with respect to any vested Units then allocated to such Participant's Account.

Upon a Plan termination, each Participant who has not yet terminated employment shall become fully vested in the Units in his Account and shall be entitled to a cash lump sum of the exercise value of such Units (as determined in conformity with Section 6 above) as soon as administratively feasible following the Plan termination.

 
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Section 13
Miscellaneous

(a)                        Expenses of the Plan . - Any expenses incurred in connection with the administration of the Plan shall be paid by the Company.

 
(b)                       Tax Withholding . - The Company shall deduct from any payments to a Participant or beneficiary under the Plan any taxes required by law to be withheld with respect to such payments.

 
(c)                        Applicable Law . - The terms and provisions of the Plan shall be construed in accordance with the law of the State of Texas, except to the extent preempted by federal law.

 
(d)                        ERISA . - This Plan is not intended to be a pension plan under ERISA.
 
Section 14
Definitions

(a)           "Account" means the account maintained for each Participant in the Plan reflecting the number of Units allocated to such Participant in accordance with Section 4 above, vested status of such Units, and any other information necessary to properly administer the rights of the Participants.

 
(b)           "Company" for purposes of this Plan shall, unless the Committee determines otherwise, include its affiliates and GEL.

 
(c)           “Change in Control” shall be deemed to have occurred on the earliest of the following dates:

 
(i)           The date any entity or person (including a “group” within the meaning of Section 13(d)(3) of the Securities Act of 1934, or any comparable successor provisions), other than the owners of the Company at the time this Plan is adopted, shall have become the beneficial owners of, or shall have obtained voting control over, fifty percent (50%) or more of the then outstanding shares of the Company; or

 
(ii)           The closing date of any transaction to sell or otherwise dispose of substantially all of the assets of GEL or to merge or consolidate GEL with or into another partnership or corporation, in which GEL is not the continuing or surviving partnership or corporation, or pursuant to which any common units of GEL would be converted into cash, securities or other property of another partnership or corporation.

 
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(d)           "Disability" means that the Participant satisfies the requirements for benefits under the Company’s long-term disability plan.

 
(e)           "Normal Retirement" means that the sum of Participant’s age and years of service with the Company equals or exceeds 75 years at the time the Participant terminates employment.

(f)           "Plan Year" means a calendar year.

(g)           "Units" means the stock appreciation rights or phantom units granted and allocated to the Participants under this Plan.

Section 15
Effective Date

Effective Date . - The effective date of this Amended and Restated Plan is February 24, 2009.
 
 
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Exhibit 10.25

Form of Notice of Stock Appreciation Right Grant

Effective _________, the Board of Directors of Genesis Energy, Inc. has awarded you a[n] [initial] grant of ____ units with a strike price of $___ per unit.  This grant will vest at 25% per year over a 4-year period.  Each unit entitles you to receive a cash payment equal to the difference between the strike price on the grant date and a valuation of the unit at the time you exercise your unit.  A description of the rules of operation of the Stock Appreciation Rights Plan can be found in the attached copy of the Plan Document.
 
 
Exhibit 10.27
 
AMENDMENT TO THE GENESIS ENERGY
SEVERANCE PROTECTION PLAN

This Amendment to the Genesis Energy Severance Protection Plan (the “ Plan ”), made pursuant to the right to amend reserved in Sections 8.2 and 8.3 of the Plan, amends the Plan effective as of December 31, 2008 as follows.

 
1.
Section 2.12 is hereby amended in its entirety to read as follows:

Section 2.12 Good Reason.  “Good Reason” shall mean the occurrence of any of the following events or conditions without the Participant’s consent:

(a) a material reduction of the Participant’s status, title, position or responsibilities (including reporting responsibilities) as in effect immediately prior thereto; the assignment to the Participant of any duties or responsibilities which are materially inconsistent with such status, title, position or responsibilities; or any removal of the Participant from, or failure to reappoint or reelect him to, any such position with the Employer, including, but not limited to corporate officer positions or positions as a member of the Investment Committee, except in connection with the termination of his employment for Cause or by the Participant other than for Good Reason;

(b) a material reduction in the Participant’s Base Salary, as such base salary may be increased from time to time thereafter, or a material reduction in the aggregate compensation and benefits (in terms of benefit levels and/or reward opportunities) provided for under the employee benefit plans, programs and practice as in effect immediately prior to the Change in Control (or as in effect following the Change in Control, if greater), including, but not limited to, any stock option plan, stock purchase plan, pension plan, life insurance plan, stock appreciation plan, phantom rights plan, health and accident plan or disability plan;

(c) the Employer’s requiring the Participant (without the consent of the Participant) to be based at any place outside a twenty-five (25) mile radius of his place of employment immediately prior to a Change in Control, except for reasonably required travel on the Employer’s business which is not materially greater than such travel requirements prior to the Change in Control, or, in the event the Participant consents to any relocation beyond such 25 mile radius, the material failure by the Employer to pay (or reimburse the Participant) for all reasonable moving expenses incurred by him relating to a change of his principal residence in connection with such relocation and to indemnify the Participant against any material loss (defined as the difference between the actual sale price of such residence and the higher of (i) his aggregate investment in such residence or (ii) the fair market value of such residence as determined by a real estate appraiser designated by the Participant and reasonably satisfactory to the Employer) realized on the sale of the Participant’s principal residence in connection with any such change of residence;

 
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(d) any material breach by the Employer of any provision of this Plan;

(e) any purported termination of the Participant’s employment for Cause by the Employer which does not otherwise comply with the terms of this Plan; or

(f) in the case of a Change in Control pursuant to Section 2.7(d), for any Participant who continues employment with the successor to all or substantially all of the business and/or assets of the Company, the failure of the Company to obtain the assumption of, or the agreement to perform, this Agreement by the purchaser or purchasers of the Company’s business or assets as contemplated in Article VII.

 
2.
Section 2.24 is hereby amended in its entirety to read as follows:

Section 2.24 Termination Date.  In the case of the Participant’s death, the Participant’s Termination Date shall be his date of death.  In all other cases, the Participant’s Termination Date is the date on which the Participant has a termination of employment that constitutes a “separation from service” as defined in Section Treas. Reg. § 1.409A-1(h)(1).  To the extent required by Section 409A of the Code, a reference in this Plan to a “termination of employment,” “employment termination” or similar term will be treated as a reference to a “separation from service,” as defined in Treas. Reg. § 1.409A-1(h)(1), with the Company and its entire controlled group (within the meaning of Code Sections 414(b) and (c)).  The Notice of Termination will specify the intended Termination Date for the Participant subject to the following:

(a) If the Participant's employment is terminated by the Employer for Cause, the date specified in the Notice of Termination shall be at least thirty (30) days from the date the Notice of Termination is given to the Participant; and

(b) If the Participant terminates his employment for Good Reason, the date specified in the Notice of Termination shall be at least thirty (30), but not be more than sixty (60), days from the date the Notice of Termination is given to the Employer.

 
2
 

 
3.
Section 3.1 is hereby amended in its entirety to read as follows:

Section 3.1 Participation.  Once a person, other than a person who could become entitled to severance benefits under an employment agreement or other arrangement with the Company, Partnership or any Subsidiary, is employed by their Employer, he or she will automatically become a Participant in the Plan.  In no event may a person who is a party to an agreement with or covered by another plan or arrangement of the Company, Partnership or any Subsidiary that provides severance benefits become a Participant in the Plan.

 
4.
Section 4.1(a) is hereby amended in its entirety to read as follows:

(a) After a Change in Control has occurred, a Participant will be entitled to receive from the Employer a Severance Benefit in the amount provided in Sections 4.2 and 4.3 if his employment is terminated during the period beginning six months prior to a Change in Control and ending on the second anniversary of the Change in Control, for any reason other than (i) termination by the Employer for Cause or (ii) termination by the Participant for other than Good Reason.  For purposes of this Plan, a Participant’s termination of employment will not be for Good Reason unless (I) the Participant has delivered a written Notice of Termination to the Employer describing in reasonable detail the occurrence or existence of any condition claimed to provide a basis for included within the definition of Good Reason under Section 2.12 within ninety (90) days of the initial occurrence or existence of the condition, (II) the Employer fails to remedy the condition on or before the thirtieth (30 th ) day following its receipt of such written notice, and (III) the Participant’s Termination Date occurs within two (2)-years following the initial occurrence, without the Participant’s consent, of any condition included within the definition of Good Reason under Section 2.12.

 
5.
Section 4.3(b) is hereby amended by replacing the third sentence thereof with the following:

The Employer also shall pay a lump sum equal to the amount of any additional income tax payable by the Participant and attributable to the benefits provided under subparagraph (a) of this Section, including any additional income tax resulting from the Employer’s payment of income tax pursuant to this subparagraph (b) of this Section, at the time any such tax is imposed upon the Participant, such that the Participant will be in the same economic position as if the benefits provided under subparagraph (a) were not includable in the Participant’s gross income.

 
3
 

 
6.
Section 4.6 is hereby amended by deleting the second and third sentences thereof, to read in its entirety as follows:

Section 4.6 Agreement to Plan.  By acceptance of any Severance Benefit from the Plan, the Participant shall be deemed to have agreed to adhere to all terms of the Plan.

 
7.
Article VI is hereby amended by adding a new Section 6.5 thereto to read as follows:

Section 6.5 Payment Deadline.  Notwithstanding anything in this Plan to the contrary, the Company shall pay the full amount of any Gross-Up Payment due pursuant to Section 6.1 and of any Underpayment due pursuant to Section 6.2 by the end of the Officer’s tax year next following the tax year in which the Officer remits the related taxes to the applicable taxing authority, and shall pay any reimbursement due to the Officer pursuant to Section 6.3(d) no later than the end of the Officer’s tax year next following the tax year in which the taxes that are the subject of such contest are remitted to the IRS or other applicable taxing authority, or where as a result of the audit or contest no taxes are remitted, the end of the Officer’s tax year next following the tax year in which the audit is completed or there is a final and nonappealable settlement or other resolution of the contest.

 
8.
Section 12.1 is hereby amended in its entirety to read as follows:

Section 12.1 Participant’s Legal Expenses.  The Company agrees to pay, upon written demand therefor by the Participant, fifty percent (50%) of all legal fees and expenses which the Participant may reasonably incur during the Participant’s lifetime in order to collect amounts to be paid or obtain benefits to be provided to such Participant under the Plan, plus in each case interest at the “applicable Federal rate” (as defined in Section 1274(d) of the Code).  In any such action brought by a Participant for damages or to enforce any provisions hereof, he shall be entitled to seek both legal and equitable relief and remedies, including, without limitation, specific performance of the Company’s obligations hereunder, in his sole discretion.  However, in any instance where a Participant receives, as the result of a final, nonappealable judgment of a court of competent jurisdiction or a mutually agreed upon settlement with the Company, Severance Benefits greater than those first offered by the Company or its successor to the Participant, then the Company shall pay one hundred percent (100%) of all such legal fees and expenses incurred by the Participant during the Participant’s lifetime.  The amount of expenses eligible for payment or reimbursement under this Section 12.1 during any taxable year of the Participant will not affect the expenses eligible for payment or reimbursement in any other taxable year, and the Participant’s right to payment or reimbursement of legal expenses is not subject to liquidation or exchange for any other benefit.  Notwithstanding anything in this Section 12.1 to the contrary, in no event will the reimbursement of any eligible legal expense be made after the last day of the Participant’s taxable year following the taxable year in which the Participant incurred the expense.

 
4
 

 
9.
Section 12.10 is hereby amended in its entirety to read as follows:

Section 12.10 Section 409A of the Code.  This Plan is intended to comply with Code Section 409A and the regulations and other interpretive guidance issued thereunder, and will be interpreted accordingly.  Articles IV and VI and this Plan will be administered and interpreted to maximize the short-term deferral exemption to Code Section 409A, and Participants are not permitted, directly or indirectly, to designate the taxable year of a payment made under this Plan.  The portion of any payment under this Plan that is paid within the short-term deferral period (as defined in Treas. Reg. § 1.409A-1(b)(4)) will be treated as a short-term deferral and not aggregated with other plans or payments.  Any other portion of the payment that does not meet the short-term deferral requirement will, to the maximum extent possible, be deemed to satisfy the exception from Code Section 409A provided under Treas. Reg. § 1.409A-1(b)(9)(iii) for involuntary separation pay and will not be aggregated with any other payment.  Payment dates provided for in this Plan are deemed to incorporate “grace periods” within the meaning of Code Section 409A.  For purposes of Code Section 409A, any right to a series of installment payments under this Plan will be treated as a right to a series of separate payments.  Any amount that is paid under this Plan as a short-term deferral within the meaning of Treas. Reg. § 1.409A-1(b)(4), or within the separation pay limit under Treas. Reg. § 1.409A-1(b)(9)(iii)(A) will be treated as a separate payment.

10.
Except as set forth above, all other provisions of the Plan are unchanged.

[Execution page follows]

 
5
 

IN WITNESS WHEREOF, Genesis Energy, Inc. has caused this Amendment to be executed by its duly authorized officer on this 31st day of December, 2008.


 
By:
/s/  Ross A. Benavides
 
Name:
Ross A. Benavides
 
Title:
General Counsel
 
 
6
E xh ibit 21.1
GENESIS ENERGY, L.P.
Subsidiaries of the Registrant


Genesis Crude Oil, L.P. – Delaware limited partnership (99.99% limited partner interest owned by Genesis Energy, L.P.) – holds 50% interest in Sandhill Group, LLC

Genesis Pipeline Texas, L.P. – Delaware limited partnership (100% limited partner interest owned by Genesis Crude Oil, L.P.)

Genesis Pipeline USA, L.P. – Delaware limited partnership (100% limited partner interest owned by Genesis Crude Oil, L.P.)

Genesis CO2 Pipeline, L.P. – Delaware limited partnership (100% limited partner interest owned by Genesis Crude Oil, L.P.)

Genesis Natural Gas Pipeline, L.P. – Delaware limited partnership (100% limited partner interest owned by Genesis Crude Oil, L.P.)

Genesis Syngas Investments, L.P. – Delaware limited partnership (100% limited partner interest owned by Genesis Crude Oil, L.P.) – holds 50% interest in T&P Syngas Supply Company

Genesis Pipeline Alabama, LLC – Alabama limited liability company (100% member interest owned by Genesis Crude Oil, L.P.)

Genesis Energy Finance Corporation – Delaware corporation (owned 100% by Genesis Crude Oil, L.P.)

Genesis Davison, LLC – Delaware limited liability company (100% member interest owned by Genesis Crude Oil, L.P.)

Davison Petroleum Supply, LLC – Delaware limited liability company (100% member interest owned by Genesis Davison, LLC)

Davison Transportation Services, LLC – Delaware limited liability company (100% member interest owned by Genesis Davison, LLC)

Davison Transportation Services, Inc. – Delaware corporation (owned 100% by Genesis Davison, LLC)

Red River Terminals, L.L.C. – Louisiana limited liability company (100% owned by Genesis Davison, LLC)
 
 
 
 
 
Fuel Masters, LLC – Texas limited liability company (100% owned by Davison Petroleum Supply, LLC)

TDC, L.L.C. – Louisiana limited liability company (100% owned by Davison Petroleum Supply, LLC)

TDC Services Corporation, Inc. – Delaware corporation (100% owned by Davison Transportation Services, Inc.)

Genesis NEJD Holdings, LLC - Delaware limited liability company (100% member interest owned by Genesis Energy, L.P.)

Genesis NEJD Pipeline, LLC - Delaware limited liability company (100% member interest owned by Genesis NEJD Holdings, LLC)

Genesis Free State Holdings, LLC - Delaware limited liability company (100% member interest owned by Genesis Crude Oil, L.P.)

Genesis Free State Pipeline, LLC - Delaware limited liability company (100% member interest owned by Genesis Free State Holdings, LLC)

Genesis Marine Investments, LLC - Delaware limited liability company (100% member interest owned by Genesis Crude Oil, L.P.) – holds effective 49% economic interest in DG Marine Transportation, LLC
 
 
E xhi bit 23.1
 
 
CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
 
We consent to the incorporation by reference in Amendment No. 1 to Registration Statement No. 333-150239 on Form S-3 and in Registration Statement No. 333-156084 on Form S-8 of our reports dated March 11, 2009, relating to the consolidated financial statements and financial statement schedule of Genesis Energy, L.P. and subsidiaries (the “Partnership”) (which report expresses an unqualified opinion and includes an explanatory paragraph relating to the adoption of Statement of Financial Accounting Standards No. 157, which established new accounting and reporting standards for fair value measurements of certain financial assets and liabilities), and the effectiveness of the Partnership’s internal control over financial reporting, appearing in the Annual Report on Form 10-K of Genesis Energy, L.P.   for the year ended December 31, 2008.
  
 
/s/ Deloitte & Touche LLP
DELOITTE & TOUCHE LLP
  
 
Houston, Texas
March 11, 2009

 
Exhibit 31.1

CERTIFICATION

I, Grant E. Sims, certify that:

 
1.
I have reviewed this annual report on Form 10-K of Genesis Energy, L.P.;

 
2.
Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

 
3.
Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

 
4.
The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and we have:

 
a)
designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

 
b)
designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;

 
c)
evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation, and

 
d)
disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

 
5.
The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions):

 
a)
all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

 
b)
any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:  March 16, 2009
 
/s/  Grant E. Sims
 
 
Grant E. Sims
 
 
President & Chief Executive Officer
 
 
 
Exhibit 31.2

CERTIFICATION

I, Robert V. Deere, certify that:

 
1.
I have reviewed this annual report on Form 10-K of Genesis Energy, L.P.;

 
2.
Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

 
3.
Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

 
4.
The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and we have:

 
a)
designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

 
b)
designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;

 
c)
evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation, and

 
d)
disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

 
5.
The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions):

 
a)
all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

 
b)
any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:  March 16, 2009
 
/s/  Robert V. Deere
 
 
Robert V. Deere
 
 
Chief Financial Officer
 
 
 
Exhibit 32.1

CERTIFICATION BY CHIEF EXECUTIVE OFFICER
PURSUANT TO 18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002



In connection with the Annual Report on Form 10-K of Genesis Energy, L.P. (the “Partnership”) for the period ended December 31, 2008 (the “Report”) filed with the Securities and Exchange Commission on the date hereof, I, Grant E. Sims, Chief Executive Officer of Genesis Energy, LLC, the general partner of the Partnership, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

(1)
the Partnership’s Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934 as amended; and

(2)
the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Partnership.



March 16, 2009
/s/  Grant E. Sims
 
 
Grant E. Sims
 
 
Chief Executive Officer,
 
 
Genesis Energy, LLC
 
 
 
Exhibit 32.2

CERTIFICATION BY CHIEF FINANCIAL OFFICER
PURSUANT TO 18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002



In connection with the Annual Report on Form 10-K of Genesis Energy, L.P. (the “Partnership”) for the period ended December 31, 2008 (the “Report”) filed with the Securities and Exchange Commission on the date hereof, I, Robert V. Deere, Chief Financial Officer of Genesis Energy, LLC, the general partner of the Partnership, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

(1)
the Partnership’s Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934 as amended; and

(2)
the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Partnership.



March 16, 2009
/s/ Robert V. Deere
 
 
Robert V. Deere
 
 
Chief Financial Officer,
 
 
Genesis Energy, LLC