Edgar Filing: GENESIS ENERGY LP

form10k.htm

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

xANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2008

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.

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	Business	4
Item 1A.	Risk Factors	19
Item 1B.	Unresolved Staff Comments	35
Item 2.	Properties	35
Item 3.	Legal Proceedings	35
Item 4.	Submission of Matters to a Vote of Security Holders	35

Part II

Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	35
Item 6.	Selected Financial Data	37
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	39
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	60
Item 8.	Financial Statements and Supplementary Data	63
Item 9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure	63
Item 9A.	Controls and Procedures	63
Item 9B.	Other Information	65

Part III

Item 10.	Directors, Executive Officers and Corporate Governance	65
Item 11.	Executive Compensation	67
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	87
Item 13.	Certain Relationships and Related Transactions, and Director Independence	89
Item 14.	Principal Accountant Fees and Services	92

Part IV

Item 15.	Exhibits and Financial Statement Schedules	92

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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.

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PART I

Item 1. Business

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; “CO2” 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 CO2 producers; industrial and commercial enterprises that use CO2 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, CO2 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 CO2 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” CO2 pipeline that extends from Denbury’s CO2 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 CO2 on the Free State pipeline for Denbury’s use in its tertiary recovery operations. We also own a small CO2 pipeline in Mississippi to transport CO2 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.

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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.

CO2 — We supply CO2 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 CO2 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 CO2 to our industrial customers is the effective difference between the price at which we sell our CO2 under each contract and the price at which we acquired our CO2 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 CO2 for sale to other customers for uses ranging from completing oil and natural gas producing wells to food processing. The Sandhill facility acquires CO2 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 CO2 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 CO2 tertiary recovery expertise along with large deposits of CO2 reserves, approximately 5.6 trillion cubic feet of estimated proved CO2 reserves as of December 31, 2008. Other than the CO2 reserves owned by Denbury, we are not aware of any significant natural sources of CO2 from East Texas to Florida. Denbury is conducting its CO2 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.

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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.

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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:

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; CO2 producers; industrial and commercial enterprises that use CO2 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.

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.

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 Supports 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.

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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.

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 CO2 pipelines - the NEJD and Free State CO2 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 CO2 transported therein, with a minimum monthly payment of $0.1 million.

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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 CO2 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 CO2 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.

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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.

CO2 Pipelines

We also transport CO2 for a fee. The Free State Pipeline is an 86-mile, 20” pipeline that extends from Denbury’s CO2 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” CO2 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 CO2 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.

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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 CO2 flooding around our Mississippi System, we became familiar with CO2-related activities and, ultimately, began our CO2 business in 2003. Our relationships with industrial customers who use CO2 have continued to expand, which has introduced us to potential opportunities associated with other industrial gases. We (i) supply CO2 to industrial customers, (ii) process raw CO2 and sell that processed CO2, and (iii) manufacture and sell syngas, a combination of carbon monoxide and hydrogen.

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CO2 – Industrial Customers

We supply CO2 to industrial customers under seven long-term CO2 sales contracts. We acquired those contracts, as well as the CO2 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 CO2 (in the aggregate), from Denbury. We sell our CO2 to customers who treat the CO2 and sell it to end users for use for beverage carbonation and food chilling and freezing. Our compensation for supplying CO2 to our industrial customers is the effective difference between the price at which we sell our CO2 under each contract and the price at which we acquired our CO2 pursuant to our VPPs, minus transportation costs. We expect some seasonality in our sales of CO2. The dominant months for beverage carbonation and freezing food are from April to October, when warm weather increases demand for beverages and the approaching holidays increase demand for frozen foods. At December 31, 2008, we have 153.8 Bcf of CO2 remaining under the VPPs.

Currently, all of our CO2 supply is from our interests – our VPPs - in fields producing naturally occurring CO2. The agreements we executed with Denbury when we acquired the VPPs provide that we may acquire additional CO2 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 CO2 supply from Denbury, from other sources, or discontinue the CO2 supply business. Denbury will have no obligation to provide us with CO2 once our VPPs expire, and Denbury has the right to compete with us in the CO2 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 CO2 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.

CO2 - 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 CO2 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 CO2 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 CO2 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 CO2 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 CO2 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.

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Competition

Currently, all of our CO2 supply is from our interest – our VPPs – in fields producing naturally occurring sources. In the future we may have to obtain our CO2 supply from manufactured processes. Naturally-occurring CO2, like that from the Jackson Dome area, occurs infrequently, and only in limited areas east of the Mississippi River, including the fields controlled by Denbury. Our industrial CO2 customers have facilities that are connected to the NEJD CO2 pipeline, which makes delivery easy and efficient. Once our existing VPPs expire, we will have to obtain CO2 from Denbury or other suppliers should we choose to remain in the CO2 supply business, and the competition and pricing issues we will face at that time are uncertain.

With regard to our CO2 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 CO2 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 CO2. As discussed above, the limited amounts of naturally-occurring CO2 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.

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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.

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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.

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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 CO2 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.

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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 CO2, 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 CO2 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.

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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 CO2. 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 CO2 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 CO2 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.

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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.genesisenergylp.com) our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 as soon as reasonably practicable after we electronically file the material with, or furnish it to, the SEC.

Item 1A. Risk Factors

Risks Related to Our Business

We may not 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.

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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;

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the demand for our trucking, barge and pipeline transportation services;

the volumes of CO2 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;

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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 competitive 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 CO2 - 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 CO2— 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 CO2 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.

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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.

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Fluctuations in commodity prices could adversely affect our business.

Oil, natural gas, other petroleum products, and CO2 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.

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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 CO2 operations involves us supplying CO2 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 CO2 operations involves us supplying CO2 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 CO2 and enter into sales arrangements that generate substantially similar economics, our cash flow could decline significantly around 2015.

Fluctuations in demand for CO2 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 CO2.

Our wholesale CO2 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.

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Our CO2 operations are exposed to risks related to Denbury’s operation of its CO2 fields, equipment and pipeline as well as any of our facilities that Denbury operates.

Because Denbury produces the CO2 and transports the CO2 to our customers (including Denbury), any major failure of its operations could have an impact on our ability to meet our obligations to our CO2 customers (including Denbury). We have no other supply of CO2 or method to transport it to our customers. Sandhill relies on us for its supply of CO2 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.

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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.

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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

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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 CO2 used for tertiary oil recovery east of the Mississippi River and may manage these reserves in a manner that could adversely affect our CO2 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.

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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

CO2 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.

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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 CO2 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.

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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.

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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.

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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 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.

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Item 1B. Unresolved Staff Comments

None.

Item 2. Properties

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 Proceedings

We are involved from time to time in various claims, lawsuits and administrative proceedings incidental to our business. In our opinion, the ultimate outcome, if any, of such proceedings is not expected to have a material adverse effect on our financial condition, results of operations or cash flows. (See Note 19 of the Notes to Consolidated Financial Statements.)

Item 4. Submission of Matters to a Vote of Security Holders

No matters were submitted to a vote of the security holders during the fiscal year covered by this report.

PART II

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

Our common units are listed on the 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.

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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.

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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
CO2 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
CO2 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

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	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
CO2 pipeline (Mcf per day) (5)		160,220		-		-		-		-
CO2 sales (Mcf per day)		78,058		77,309		72,841		56,823		45,312
NaHS sales (DST) (6)		162,210		69,853		-		-		-

(1)

Our 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 CO2 pipeline in 2008.

(6)	Volumes relate to operations acquired in July 2007.

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Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operation

Included in Management’s Discussion and Analysis are the following sections:

Overview of 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.

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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.

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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 CO2 pipelines - the NEJD and Free State CO2 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 CO2 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.

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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 CO2 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 CO2 based tertiary recovery operations, Denbury may need crude oil gathering and CO2 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.

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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 CO2 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 CO2 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 CO2 pipeline in Mississippi to transport CO2 from Denbury’s main CO2 pipeline to Brookhaven oil field. Denbury has the exclusive right to use this CO2 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 CO2 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

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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 CO2 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 CO2 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.

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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 CO2 sales to industrial customers and our share of the available cash generated by our 50% joint ventures, T&P Syngas and Sandhill.

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Operating Results

Operating results for our industrial gases segment were as follows.

	Year Ended December 31,
	2008			2007			2006
	(in thousands)
Revenues from CO2 marketing	$	17,649		$	16,158		$	15,154
CO2 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:
CO2 marketing - Mcf		78,058			77,309			72,841

CO2 – Industrial Customers

We supply CO2 to industrial customers under seven long-term CO2 sales contracts. The terms of our contracts with the industrial CO2 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 CO2. The dominant months for beverage carbonation and freezing food are from April to October, when warm weather increases demand for beverages and the approaching holidays increase demand for frozen foods. The table below depicts these seasonal fluctuations. The average daily sales (in Mcfs) of CO2 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 CO2 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.

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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.

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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.

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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.

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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 CO2 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 CO2 volumetric payments is based on the units-of-production method. We acquired three volumetric production payments totaling 280 Mcf of CO2 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 CO2 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.

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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 CO2 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.

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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 CO2 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 CO2 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.

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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