form10-k.htm


UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C.  20549

Form 10-K

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

For the fiscal year ended December 31, 2007

OR

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

Commission file number 1-12295

GENESIS ENERGY, L.P.
(Exact name of registrant as specified in its charter)
 
 
Delaware
(State or other jurisdiction of  incorporation or organization)
 
76-0513049
(I.R.S. Employer Identification No.)
 
         
 
500 Dallas, Suite 2500, 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
 
American Stock Exchange
 

Securities registered pursuant to Section 12(g) of the Act:
NONE

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Exchange Act.
 
Yes ¨   No x

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

Yes ¨   No x
 
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Act during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Yes x   No ¨
 
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.

x
 
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, 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¨
Accelerated filer   x  
Non-accelerated filer ¨
Smaller reporting company¨
 
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2) of the Act).

Yes ¨   No x

The aggregate market value of the common units held by non-affiliates of the Registrant on June 29, 2007 (the last business day of Registrant’s most recently completed second fiscal quarter) was approximately $444,166,000 based on $34.88 per unit, the closing price of the common units as reported on the American Stock Exchange.  On February 29, 2008, the Registrant had 38,253,264 common units outstanding.
 


 
 

 

GENESIS ENERGY, L.P.
2007 FORM 10-K ANNUAL REPORT
Table of Contents



     
Page
Part I
       
Item 1
 
4
Item 1A.
 
19
Item 1B.
 
33
Item 2.
 
33
Item 3.
 
34
Item 4.
 
34
       
Part II
       
Item 5.
 
34
Item 6.
 
36
Item 7.
 
38
Item 7A.
 
61
Item 8.
 
62
Item 9.
 
62
Item 9A.
 
63
Item 9B.
 
65
     
 
Part III
       
Item 10.
 
65
Item 11.
 
67
Item 12.
 
84
Item 13.
 
85
Item 14.
 
88
       
Part IV
       
Item 15.
 
89

2


FORWARD-LOOKING INFORMATION
 
The statements in this Annual Report on Form 10-K that are not historical information may be “forward looking statements” within the meaning of the various provisions of the Securities Act of 1933 and the Securities Exchange Act of 1934.  All statements, other than historical facts, included in this document that address activities, events or developments that we expect or anticipate will or may occur in the future, including things such as plans for growth of the business, future capital expenditures, competitive strengths, goals, references to future goals or intentions and other such references are forward-looking statements.  These forward-looking statements are identified as any statement that does not relate strictly to historical or current facts.  They use words such as “anticipate,” “believe,” “continue,” “estimate,” “expect,” “forecast,” “intend,” “may,” “plan,” “position,” “projection,” “strategy” or “will” or the negative of those terms or other variations of them or by comparable terminology.  In particular, statements, expressed or implied, concerning future actions, conditions or events or future operating results or the ability to generate sales, income or cash flow are forward-looking statements.  Forward-looking statements are not guarantees of performance.  They involve risks, uncertainties and assumptions.  Future actions, conditions or events and future results of operations may differ materially from those expressed in these forward-looking statements.  Many of the factors that will determine these results are beyond our ability or the ability of our affiliates to control or predict.  Specific factors that could cause actual results to differ from those in the forward-looking statements include:
 
 
·
demand for, the supply of, changes in forecast data for, and price trends related to crude oil, liquid petroleum, natural gas and natural gas liquids or “NGLs”, sodium hydrosulfide and caustic soda in the United States, all of which may be affected by economic activity, capital expenditures by energy producers, weather, alternative energy sources, international events, conservation and technological advances;
 
 
·
throughput levels and rates;
 
 
·
changes in, or challenges to, our tariff rates;
 
 
·
our ability to successfully identify and consummate strategic acquisitions, make cost saving changes in operations and integrate acquired assets or businesses into our existing operations;
 
 
·
service interruptions in our liquids transportation systems, natural gas transportation systems or natural gas gathering and processing operations;
 
 
·
shut-downs or cutbacks at refineries, petrochemical plants, utilities or other businesses for which we transport crude oil, natural gas or other products or to whom we sell such products;
 
 
·
changes in laws or regulations to which we are subject;
 
 
·
our inability to borrow or otherwise access funds needed for operations, expansions or capital expenditures as a result of existing debt agreements that contain restrictive financial covenants;
 
 
·
loss of key personnel;
 
 
·
the effects of competition, in particular, by other pipeline systems;
 
 
·
hazards and operating risks that may not be covered fully by insurance;
 
 
·
the condition of the capital markets in the United States;
 
 
·
loss of key customers;
 
 
·
the political and economic stability of the oil producing nations of the world; and
 
 
·
general economic conditions, including rates of inflation and interest rates.
 
You should not put undue reliance on any forward-looking statements.  When considering forward-looking statements, please review the risk factors described under “Risk Factors” discussed in Item 1A.  Except as required by applicable securities laws, we do not intend to update these forward-looking statements and information.
 
3


PART I
 
Item 1.  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; “Denbury” means Denbury Resources Inc. and its subsidiaries; “CO2” means carbon dioxide; and “NaHS”, which is commonly pronounced as “nash”, means sodium hydrosulfide.  Except to the extent otherwise provided, the information contained in this form is as of December 31, 2007.
 
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, 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 dry-goods 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 and, to a lesser extent, natural gas and CO2 for others for a fee in the Gulf Coast region of the U.S. through approximately 500 miles of pipeline.  We own and operate three crude oil common carrier pipelines, a small CO2 pipeline and several 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.
 
Refinery Services—We provide services to eight refining operations located predominantly in Texas, Louisiana and Arkansas. These refineries generally are owned and operated by large companies, including ConocoPhillips, CITGO and Ergon. Our refinery services primarily involve processing high sulfur (or “sour”) natural gas streams, which are separated from hydrocarbon streams, to remove the sulfur. Our refinery services contracts, which usually have an initial term of two to ten years, have an average remaining term of five years.
 
Supply and Logistics—We provide terminaling, blending, storing, marketing, gathering and transporting (by trucks), and 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 approximately 300 trucks, 600 trailers and almost 1.5 million barrels of liquid storage capacity at eleven different locations. 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 generally 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 8 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 syngas (a combination of carbon monoxide and hydrogen) and high-pressure steam.  Under that processing agreement, Praxair provides the raw materials to be processed and receives the syngas and steam produced by the facility.  Praxair has the exclusive right to use 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.
 
4


 
·
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.
 
We continue to benefit from our strategic affiliation with Denbury Resources Inc. (NYSE:DNR), which indirectly owns 100% of our general partner interest, all of our incentive distribution rights and 7.4% of our outstanding common units.  Denbury, which had an equity market capitalization of approximately $7.7 billion as of February 29, 2008, 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, 2007.  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. In addition to the amounts it has already expended on the Free State and North East Jackson Dome, or NEJD, CO2 pipelines, Denbury has announced that it expects to spend approximately $775 million between December 31, 2007 and the end of 2009 to build CO2 pipelines to support its tertiary oil recovery expansions.
 
We believe Denbury’s equity ownership interests in us provide Denbury with economic and strategic incentives to furnish business opportunities to us in the form of acquisitions, leases, transportation agreements and other transactions. In fact, Denbury has indicated that it may use us as a vehicle to provide its midstream infrastructure needs, particularly with respect to CO2 pipelines. We believe Denbury may provide us with future growth opportunities due to the following additional factors, among others:
 
 
·
Denbury’s continued need to construct pipelines and gathering systems necessary to support its operations, which we may have an opportunity to provide for them;
 
·
Denbury’s significant economic and strategic interests in us;
 
·
the close proximity of certain of Denbury’s assets and operations to certain of our assets and operations; and
 
·
the extent of Denbury’s growth capital requirements.

Denbury has announced its intention, which it may change at any time, to drop down certain midstream assets.  We expect to complete a drop down transaction involving the Free State and NEJD CO2 pipelines in the first quarter of 2008.
Although our relationship with Denbury may provide us with a source of acquisition and other growth opportunities, Denbury is not obligated to enter into any 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 its midstream infrastructure.  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 significant strength, it also is a source of potential conflicts.
 
5


Our Objective 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:
 
 
·
Expanding our asset base through strategic and accretive acquisitions with third parties and Denbury. We intend to expand our asset base through strategic and accretive acquisitions from Denbury and third parties in new and existing markets.  Such acquisitions could be structured as, among other things, purchases, leases, tolling or similar agreements or joint ventures.
 
 
·
Expanding our asset base through strategic construction and development projects with third parties and Denbury.  We intend to expand our asset base through strategic and accretive construction and developments projects, or joint ventures, in new and existing markets.
 
 
·
Optimizing our CO2 and other industrial gases expertise and infrastructure. We intend to optimize our expertise regarding CO2 and other industrial gases to create growth opportunities.
 
 
·
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 oil transportation, gathering, blending and marketing services to them and other producers as production from those properties increases.
 
 
·
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 broad array of services, leveraging our strong relationships with refinery owners and producers, and deploying our proprietary knowledge.
 
 
·
Increasing the utilization rates 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 for a relatively nominal amount.
 
 
·
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.  While our refinery services division has some exposure to monthly changes in the prices of caustic soda and sodium hydrosulfide, also referred to as NaHS (pronounced “nash”), a natural by-product of those operations, prices for those commodities are not as volatile as prices for oil, natural gas and their derivatives.
 
 
·
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.  While we have the capability to provide an ever increasing array of integrated services to both producers and refineries, we believe our cash flows will continue to be relatively stable due to the diversity of our customer base, the nature of our services and the geographic location of our operations.
 
 
·
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 and operation of joint ventures and strategic alliances.
 
 
·
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.
 
6


Our Key Strengths
 
We believe we are well positioned to execute our strategies and ultimately achieve our objectives due primarily to the following competitive strengths:
 
Ø
Experienced, Knowledgeable and Motivated Senior Management Team with Proven Track Record. Our senior management team has over 40 years of combined 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 execute our growth strategy in a manner that is accretive on a “distribution per unit” basis, our general partner has undertaken to negotiate agreements relating to an equity-based  incentive compensation arrangement to provide the members of our senior management team with the opportunity to earn an interest in our general partner if performance criteria are met.  Those performance criteria are expected to include a correlation between earning the general partner interest with the successful completion of non-Denbury acquisitions and/or other organic growth that earn a reasonable rate of return.
 
Ø
Unique Platform, Limited Competition and Anticipated Growing Demand in 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, especially when employing our proprietary processes and expertise that result in the by-product of NaHS;
 
 
·
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 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;
 
 
·
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 possibility of each individual refinery employing its own sulfur removal operations, we do not have many competitors in the sulfur removal business; and
 
 
·
we believe that the demand for sulfur removal at U.S. refineries will increase in the years ahead as the quality of the oil supply used by refineries in the U.S. continues to drop (or become more “sour”).  As that occurs, we believe more refineries will seek economic and proven sulfur removal processes from reputable service providers that have the scale and logistical capabilities to efficiently perform such services.  In addition, we have an increasing array of services we can offer to our refinery customers.
 
Ø
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 input into 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 our supply and logistics division provides to producers;
 
7


 
·
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 refinery customers; and
 
 
·
our supply and logistics division gives us the opportunity to blend/store and distribute products made by our refinery customers.
 
Ø
Diversified and Balanced Portfolio of Customers, Operations and Assets.  We have a diversified and well-balanced portfolio of customers, operations and assets throughout the Gulf Coast region of the U.S. 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 dry-goods trucking 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,) and inland refining operations, that we believe are contemplating expansion.
 
 
·
Cost-Effective Expansion and Enhancement Opportunities.  We own pipelines, terminals and other assets that have available capacity or that have opportunities for expansion of capacity without incurring material expenditures.
 
 
·
Cash Flow Stability.  Our cash flow is relatively stable due to a number of factors, including our long-term, fee-based contracts with our refinery services and industrial gases customers, our diversified base of customers, assets and services, and our relatively low exposure to volatile fluctuations in commodity prices.
 
Ø
Financial Flexibility.  We have the financial flexibility to pursue additional growth projects. As of December 31, 2007, we had $80 million of loans and $5.3 million in letters of credit outstanding under our $500 million credit facility, resulting in $271 million of remaining credit availability under our borrowing base. Our borrowing base as of December 31, 2007 was approximately $356 million, and 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.
 
Ø
Relationship with Denbury.  We have a strong relationship with Denbury, the indirect owner of our general partner. Denbury has indicated that it may use us as a vehicle to provide its midstream infrastructure needs, particularly with respect to CO2 pipelines. We believe Denbury has an economic and strategic incentive to provide business opportunities to us. We also believe that, if we can become an instrumental component of Denbury’s future development projects, we can leverage those 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.
 
Recent Developments
 
Acquisition of Refinery Services Division and Other Businesses
 
On July 25, 2007, we acquired five energy-related businesses, including the operations that comprise our refinery services division, from several entities owned and controlled by the Davison family of Ruston, Louisiana. The other acquired businesses, which transport, store, procure and market petroleum products and other bulk commodities, are included in our supply and logistics segment.
 
Our acquisition agreement with the Davisons provided that we would deliver to them $563 million of consideration, half in common units (13,459,209 common units at an agreed-to value of $20.8036 per unit) and half in cash, subject to specified purchase price adjustments. Our financial statements at December 31, 2007 reflect a total acquisition price of $631.5 million, which includes purchase price adjustments, our transaction costs of $8.9 million, working capital acquired, net of cash acquired, and a valuation of the units at $24.52 per unit, which was the average closing price of our units during the five trading day period ending two days after we signed the acquisition agreement.
 
The Davison family was our largest unitholder at December 31, 2007, with a 33.0% interest in us (represented by 12,619,069 of our common units).  It has designated two of the members of the board of directors of our general partner, and as long as it maintains a specified minimum ownership percentage of our common units, it will have the continuing right to designate up to two directors. The Davison family has agreed to restrictions that limit its ability to sell specified percentages of its common units through July 26, 2010. For example, prior to July 25, 2008, the Davison family may not sell more than 20% of its common units.

8


Denbury Drop Down Transactions
 
We have reached substantial agreement and are in the process of finalizing the business issues with Denbury and the lenders in our credit facility as to the terms of the drop-down by Denbury to us of Denbury’s NEJD and Free State CO2 pipelines and the terms of a long-term transportation service arrangement for the Free State line and a 20-year financing lease for the NEJD system. We expect to pay for these pipeline assets with $225 million in cash and $25 million of our common units based on the average closing price of our units on the thirty days prior to the closing of the transaction. We expect to receive approximately $30 million per annum, in the aggregate, under the lease and the transportation services agreement (and a lesser pro-rated amount for 2008), with future payments for the NEJD pipeline fixed at $20.7 million per year during the term of the financing lease, and the payments relating to the Free State pipeline dependant on the volumes of CO2 transported therein. While the business terms of the transactions and associated documentation have been substantially completed, closing remains subject to completion of closing documentation, receipt of a fairness opinion and approval by the audit committee and the board of directors of our general partner.

Nine Consecutive Distribution Rate Increases
 
We have increased our quarterly distribution rate for nine consecutive quarters.  On February 14, 2008, we paid a cash distribution of $0.285 per unit to unitholders of record as of February 7, 2008, an increase per unit of $0.015 (or 5.6%) from the distribution in the prior quarter.  In the immediately preceding quarter, we increased our quarterly distribution rate by $0.04 (or 17.4%), and in each preceding quarter, we increased our distribution rate by $0.01.  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.
 
Acquired Terminal and Dock Facilities
 
Effective July 1, 2007, we paid $8.1 million for BP Pipelines (North America) Inc.’s Port Hudson oil truck terminal, marine terminal and marine dock on the Mississippi River, which includes 215,000 barrels of tankage, a pipeline and other related assets in East Baton Rouge Parish, Louisiana. That acquisition was funded with borrowings under our credit facility.

Florida Oil Pipeline System Expansion
 
We committed to construct an extension of our existing Florida oil pipeline system that would extend to producers operating in southern Alabama. That 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. That project also will include gathering connections to approximately 30 wells and oil storage capacity of 20,000 barrels in the field. We expect to place those facilities in service in the fourth quarter of 2008.

Description of Segments and Related Assets
 
We conduct our business through four primary segments: Pipeline Transportation, Refinery Services, Industrial Gases and Supply and Logistics. Our Supply and Logistics segment was previously known as Crude Oil Gathering and Marketing. With the Davison acquisition, we expanded our operations into petroleum products and other transportation services, and combined these operations due to their similarities and our approach to managing these operations. 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 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.
 
9


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.
 
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 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 recently committed to construct an extension of our existing Florida oil pipeline system 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 30 wells and additional oil storage capacity of 20,000 barrels in the field. The project is expected to be placed in service in the second half of 2008.
 
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 pipe.  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.
 
On a much smaller scale, we also transport CO2 and gather natural gas for a fee.  However, with the acquisition of the CO2 pipelines from Denbury expected in the first quarter of 2008, our CO2 pipelines (including leased lines) will extend approximately 280 miles.  See additional discussion in ‘Denbury Drop Down Transactions” above.

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Customers
 
Denbury, a large independent energy company, is the sole shipper (other than us) on our Mississippi System.   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 crude oil 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 proprietary 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, which we sell to approximately 100 customers.  As such, we believe we are one of the largest marketers of NaHS in North America.
 
NaHS is used in the specialty chemicals business and the 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 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.  We expect to complete an additional NaHS facility at a refinery in Utah in 2008.
 
Customers
 
Refinery Services:  At December 31, 2007, 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 11% of the revenues of the refinery services segment for the five month period of our ownership resulted from sales to Kennecott Utah Copper, a subsidiary of Rio Tinto plc.

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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 Denbury is conducting substantial 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.
 
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.  Since 2003, we have purchased those contracts, along with three VPPs representing 280.0 Bcf of CO2 (in the aggregate), from Denbury for a total of $43.1 million in cash.  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, 2007, we have 182.3 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 contracts.  Based on the current volumes being sold to our customers, we believe that we will need to acquire additional volumes from Denbury in 2014.  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 has the right to compete with us.  See “Risks Related to Our Partnership Structure” for a discussion of the potential conflicts of interest between Denbury and us.
 
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
 
On April 1, 2006, we acquired a 50% partnership interest in Sandhill for $5.0 million in cash, which we funded with cash on hand.  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 that we acquired in 2005 from Denbury.  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
 
On April 1, 2005, we acquired from TCHI, Inc., a wholly-owned subsidiary of ChevronTexaco Global Energy, Inc., a 50% partnership interest in T&P Syngas for $13.4 million in cash, which we funded with proceeds from our credit facility.  T&P Syngas is a partnership which owns a facility located in Texas City, Texas that manufactures syngas and high-pressure steam.  Under a long-term processing agreement, the joint venture receives  fees from its sole customer, Praxair Hydrogen Supply, Inc. during periods when processing occurs, and Praxair has the exclusive right to use the facility through at least 2016, which Praxair has the option to extend for two additional five year terms.  Praxair also is our partner in the joint venture and owns the remaining 50% interest.

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Customers
 
Five of the 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 two of those customers representing approximately 40% of Sandhill’s total revenues of approximately $11 million in 2007.  In addition, in 2007, Sandhill sold approximately $1.9 million of CO2 to affiliates of Reliant Processing, Ltd., a 50% owner of Sandhill, as discussed above.  Sandhill has long-term relationships with those customers and has not experienced collection problems with them.
 
Competition
 
Currently, all of our CO2 supply is from our interest – our VPPs – in fields producing naturally occurring sources.  We believe we have an adequate access to supply to service existing contracts through their terms.  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 Denbury’s 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 a competing facility, 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 was previously known as our crude oil gathering and marketing segment.  With the acquisition of the Davison businesses, we renamed the segment and we included the petroleum products, fuel logistics, terminaling and truck transportation activities we acquired from the Davisons.
 
Our crude oil gathering and marketing operations are concentrated in Texas, Louisiana, Alabama, Florida and Mississippi.  Those operations, which involve purchasing, gathering and transporting by trucks and pipelines operated by us and trucks, pipelines and barges operated by others, and reselling, help to ensure (among other things) a base supply source for our oil pipeline systems. Our profit for those services is derived from the difference between the price at which we re-sell the crude oil less the price at which we purchase that oil, minus the associated costs of aggregation and any cost of supplying credit. The most substantial component of our aggregating costs relates to operating our fleet of leased trucks. Our 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.
 
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.

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With the Davison acquisition, we gained approximately 225 trucks, 525 trailers and 1.3 million barrels of existing leased and owned storage and 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 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 the contribution to margin as a percentage of the revenues tends to be higher than in the same percentage attributable to our recurring operations.
 
We also have access through our terminals on waterways in the southeastern United States to provide our customers with product by barge.  In combination with our historical focus on crude oil, 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 2007, more than ten percent of our consolidated revenues were generated from each of two customers, Shell Oil Company and Occidental Energy Marketing, Inc.  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 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, mining and other companies which 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.
 
Employees
 
To carry out our business activities, our general partner employed, at February 29, 2008 approximately 655 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, Inc., a Delaware corporation, serves as our sole general partner and as our general partner of all of our subsidiaries.  Our general partner is owned by Denbury Gathering & Marketing, Inc., a subsidiary of Denbury.  Below is a chart depicting our ownership structure.
 
Diagram
 
(1)The incentive compensation arrangement with which our general partner has undertaken to negotiate definitive agreements with the Senior Executives (see Item 11. Executive Compensation.) would provide them the opportunity to earn up to 14.4% of the equity interest in our general partner.
 
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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.
 
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, 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.  In cases of environmental contamination, it is also not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment.  We 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.

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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 other environmental laws.  We may therefore be subject to liability and regulation under CERCLA, RCRA and analogous state laws for hydrocarbons or other wastes that may have been disposed of or released on or under our current or former properties at other locations where such 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 imposes 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 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.
 
 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.

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The IMP regulation required us to prepare an Integrity Management Plan that details the risk assessment factors, the overall risk rating for each segment of pipe, a schedule for completing the integrity assessment, the methods to assess pipeline integrity, and an explanation of the assessment methods selected.  The risk factors to be considered include proximity to population areas, waterways and sensitive areas, known pipe and coating conditions, leak history, pipe material and manufacturer, adequacy of cathodic protection, operating pressure levels and external damage potential.  The IMP regulations require that the baseline assessment be completed by 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.  At December 31, 2007, we had completed assessments and repairs on the major sections of our pipelines.  On the pipeline segments initially tested, we have started the process of reassessment required every five years.
 
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.
 
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 required operators to develop and submit a written program.  The regulations also required all pipeline operators to develop a training program for pipeline personnel and to qualify them on covered tasks at the operator’s pipeline facilities.  The intent of the OQ regulations is to ensure a qualified workforce by pipeline operators and contractors when performing covered tasks on the pipeline and its facilities, thereby reducing the probability and consequences of incidents caused by human error.
 
Our crude oil, 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.
 
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.

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Website Access to Reports
 
We make available free of charge on our internet website (www.genesiscrudeoil.com) our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 as soon as reasonably practicable after we electronically file the material with, or furnish it to, the SEC.
 
Item 1A.  Risk Factors
 
Risks Related to Our Business
 
We may not be able to fully execute our growth strategy if we are unable to raise debt and equity capital at an affordable price.
 
Our strategy contemplates substantial growth through the development and acquisition of a wide range of midstream and other energy infrastructure assets while maintaining a strong balance sheet. This strategy includes constructing and acquiring additional assets and businesses to enhance our ability to compete effectively, diversify our asset portfolio and, thereby, provide more stable cash flow. We regularly consider and enter into discussions regarding, and are currently contemplating, additional potential joint ventures, stand-alone projects and other transactions that we believe will present opportunities to realize synergies, expand our role in the energy infrastructure business, and increase our market position and, ultimately, increase distributions to unitholders.
 
We will need new capital to finance the future development and acquisition of assets and businesses. Limitations on our access to capital will impair our ability to execute this strategy. Expensive capital will limit our ability to develop or acquire accretive assets. Although we intend to continue to expand our business, this strategy may require substantial capital, and we may not be able to raise the necessary funds on satisfactory terms, if at all.
 
In addition, we are experiencing increased competition for the assets we purchase or contemplate purchasing. Increased competition for a limited pool of assets could result in our not being the successful bidder more often or our acquiring assets at a higher relative price than that which we have paid historically. Either occurrence would limit our ability to fully execute our growth strategy. Our ability to execute our growth strategy may impact the market price of our securities.
 
We may not have sufficient cash from operations to pay the current level of quarterly distribution following the establishment of cash reserves and payment of fees and expenses, including payments to our general partner.
 
The amount of cash we distribute on our units principally depends upon margins we generate from our refinery services, pipeline transportation, logistics and supply and industrial gases businesses which will fluctuate from quarter to quarter based on, among other things:
 
 
·
the volumes and prices at which we purchase and sell crude oil, refined products, and caustic soda;
 
 
·
the volumes of sodium hydrosulfide, or NaHS, that we receive for our refinery services and the prices at which we sell NaHS;
 
 
·
the demand for our trucking 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.

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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, 2007, we had approximately $80 million outstanding of senior secured indebtedness.
 
We must comply with various affirmative and negative covenants contained in our credit facilities. Among other things, these covenants limit our ability to:
 
 
·
incur additional indebtedness or liens;
 
 
·
make payments in respect of or redeem or acquire any debt or equity issued by us;
 
 
·
sell assets;
 
 
·
make loans or investments;
 
 
·
make guarantees;
 
 
·
enter into any hedging agreement for speculative purposes;
 
 
·
acquire or be acquired by other companies; and
 
 
·
amend some of our contracts.
 
The restrictions under our indebtedness may prevent us from engaging in certain transactions which might otherwise be considered beneficial to us and could have other important consequences to unitholders. For example, they could:
 
 
·
increase our vulnerability to general adverse economic and industry conditions;
 
 
·
limit our ability to make distributions; to fund future working capital, capital expenditures and other general partnership requirements; to engage in future acquisitions, construction or development activities; or to otherwise fully realize the value of our assets and opportunities because of the need to dedicate a substantial portion of our cash flow from operations to payments on our indebtedness or to comply with any restrictive terms of our indebtedness;

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·
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, natural gas 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, natural gas 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 and natural gas reserves by others and other matters beyond our control.
 
The oil, natural gas and other products available to us are derived from reserves produced from existing wells, and these reserves naturally decline over time. In order to offset this natural decline, our energy infrastructure assets must access additional reserves. Additionally, some of the projects we have planned or recently completed are dependent on reserves that we expect to be produced from newly discovered properties that producers are currently developing.
 
Finding and developing new reserves is very expensive, requiring large capital expenditures by producers for exploration and development drilling, installing production facilities and constructing pipeline extensions to reach new wells. Many economic and business factors out of our control can adversely affect the decision by any producer to explore for and develop new reserves. These factors include the prevailing market price of the commodity, the capital budgets of producers, the depletion rate of existing reservoirs, the success of new wells drilled, environmental concerns, regulatory initiatives, cost and availability of equipment, capital budget limitations or the lack of available capital, and other matters beyond our control. Additional reserves, if discovered, may not be developed in the near future or at all. We cannot assure unitholders that production will rise to sufficient levels to allow us to maintain or increase the commodity volumes we are experiencing.
 
We face intense competition to obtain commodity volumes.
 
Our competitors—gatherers, transporters, marketers, brokers and other aggregators—include independents and major integrated energy companies, as well as their marketing affiliates, who vary widely in size, financial resources and experience. Some of these competitors have capital resources many times greater than ours and control substantially greater supplies of crude oil.

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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 acquired from the Davison family.
 
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 crude oil gathering and marketing 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. Even if our credit review and analysis mechanisms work properly, we could still experience losses in dealings with other parties.
 
Our operations are subject to federal and state environmental protection and safety laws and regulations
 
Our operations are subject to the risk of incurring substantial environmental and safety related costs and liabilities. In particular, our operations are subject to environmental protection and safety laws and regulations that restrict our operations, impose relatively harsh consequences for noncompliance, and require us to expend resources in an effort to maintain compliance. Moreover, our operations, including the transportation and storage of crude oil and other commodities involves a risk that crude oil and related hydrocarbons or other substances may be released into the environment, which may result in substantial expenditures for a response action, significant government penalties, liability to government agencies for natural resources damages, liability to private parties for personal injury or property damages, and significant business interruption. These costs and liabilities could rise under increasingly strict environmental and safety laws, including regulations and enforcement policies, or claims for damages to property or persons resulting from our operations. If we are unable to recover such resulting costs through increased rates or insurance reimbursements, our cash flows and distributions to our unitholders could be materially affected.
 
FERC Regulation and a changing regulatory environment could affect our cash flow.
 
The FERC extensively regulates certain of our energy infrastructure assets engaged in interstate operations.  Our intrastate pipeline operations are regulated by state agencies. This regulation extends to such matters as:
 
 
·
rate structures;
 
 
·
rates of return on equity;

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·
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 2016.
 
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 2016. 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 2016.
 
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.
 
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.

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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 the last five months of 2007, approximately 65% of our refinery services’ division NaHS by-product was attributable to Conoco’s refinery located in Westlake, Louisiana.  That contract requires Conoco to make available minimum volumes of acid gas to us (except during periods of force majeure).  Although the primary term of that contract extends until 2018, if Conoco is excused from performing, or refuses or is unable to perform, its obligations under that contract for an extended period of time, such non-performance could have a material adverse effect on our profitability and cash flow.
 
Our growth strategy may adversely affect our results of operations if we do not successfully integrate the businesses that we acquire or if we substantially increase our indebtedness and contingent liabilities to make acquisitions.
 
We may be unable to integrate successfully businesses we acquire. We may incur substantial expenses, delays or other problems in connection with our growth strategy that could negatively impact our results of operations. Moreover, acquisitions and business expansions involve numerous risks, including:
 
 
·
difficulties in the assimilation of the operations, technologies, services and products of the acquired companies or business segments;
 
 
·
inefficiencies and complexities that can arise because of unfamiliarity with new assets and the businesses associated with them, including unfamiliarity with their markets; and
 
 
·
diversion of the attention of management and other personnel from day-to-day business to the development or acquisition of new businesses and other business opportunities.
 
If consummated, any acquisition or investment also likely would result in the incurrence of indebtedness and contingent liabilities and an increase in interest expense and depreciation, depletion and amortization expenses. A substantial increase in our indebtedness and contingent liabilities could have a material adverse effect on our business, as discussed above.
 
Our actual construction, development and acquisition costs could exceed our forecast, and our cash flow from construction and development projects may not be immediate.
 
Our forecast contemplates significant expenditures for the development, construction or other acquisition of energy infrastructure assets, including some construction and development projects with technological challenges. We may not be able to complete our projects at the costs currently estimated. If we experience material cost overruns, we will have to finance these overruns using one or more of the following methods:
 
 
·
using cash from operations;
 
 
·
delaying other planned projects;
 
 
·
incurring additional indebtedness; or
 
 
·
issuing additional debt or equity.
 
Any or all of these methods may not be available when needed or may adversely affect our future results of operations.

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Fluctuations in interest rates could adversely affect our business.
 
In addition to our exposure to commodity prices, we also have exposure to movements in interest rates. The interest rates on our credit facility are variable. Our results of operations and our cash flow, as well as our access to future capital and our ability to fund our growth strategy, could be adversely affected by significant increases or decreases in interest rates.
 
Our use of derivative financial instruments could result in financial losses.
 
We use financial derivative instruments and other hedging mechanisms from time to time to limit a portion of the adverse effects resulting from changes in commodity prices, although there are times when we do not have any hedging mechanisms in place. To the extent we hedge our commodity price exposure, we forego the benefits we would otherwise experience if commodity prices were to increase. In addition, we could experience losses resulting from our hedging and other derivative positions. Such losses could occur under various circumstances, including if our counterparty does not perform its obligations under the hedge arrangement, our hedge is imperfect, or our hedging policies and procedures are not followed.
 
A natural disaster, 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.  In addition, the other 50% owner in each of our joint ventures operates the joint venture facilities. 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.
 
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 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;
 
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·
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.
 
 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.
 
In addition, we have announced that Denbury and we are negotiating several significant transactions.  See “Our General Partner and Our Relationship with Denbury Resources Inc.” under Item 1 – Business.
 
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.
 
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.

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The vote of the holders of at least a majority of all outstanding units (excluding any units held by our general partner and its affiliates) is required to remove our general partner without cause. If our general partner is removed without cause, (i) Denbury will have the option to acquire a substantial portion of our Mississippi pipeline system at 110% of its then fair market value, and (ii) our general partner will have the option to convert its interest in us (other than its common units) into common units or to require our replacement general partner to purchase such interest for cash at its then fair market value. In addition, unitholders’ voting rights are further restricted by our partnership agreement provision providing that any units held by a person that owns 20% or more of any class of units then outstanding, other than our general partner, its affiliates, their transferees, and persons who acquired such units with the prior approval of the board of directors of our general partner, cannot vote on matters relating to the succession, election, removal, withdrawal, replacement or substitution of our general partner. Our partnership agreement also contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting the unitholders’ ability to influence the manner of direction of management.
 
As a result of these provisions, the price at which our common units trade may be lower because of the absence or reduction of a takeover premium.
 
The control of our general partner may be transferred to a third party without unitholder consent, which could affect our strategic direction and liquidity.
 
Our general partner may transfer its general partner interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of the unitholders. Furthermore, there is no restriction in our partnership agreement on the ability of the owner of our general partner from transferring its ownership interest in our general partner to a third party. The new owner of our general partner would then be in a position to replace the board of directors and officers of our general partner with its own choices and to control the decisions made by the board of directors and officers.
 
In addition, unless our creditors agreed otherwise, we would be required to repay the amounts outstanding under our credit facilities upon the occurrence of any change of control described therein. We may not have sufficient funds available or be permitted by our other debt instruments to fulfill these obligations upon such occurrence. A change of control could have other consequences to us depending on the agreements and other arrangements we have in place from time to time, including employment compensation arrangements.
 
Our general partner and its affiliates 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, 2007 our general partner and its affiliates own 2,829,055 (approximately 7.4%) of our common units. In the future, they may acquire additional interest or dispose of some or all of their interest. If they dispose of a substantial portion of their interest in the trading markets, the sale could reduce the market price of common units. Our partnership agreement, and other agreements to which we are party, allow our general partner and certain of its subsidiaries to cause us to register for sale the partnership interests held by such persons, including common units. These registration rights allow our general partner and its subsidiaries to request registration of those partnership interests and to include any of those securities in a registration of other capital securities by us.
 
Our general partner has anti-dilution rights.
 
Whenever we issue equity securities to any person other than our general partner and its affiliates, our general partner and its affiliates have the right to purchase an additional amount of those equity securities on the same terms as they are issued to the other purchasers. This allows our general partner and its affiliates to maintain their percentage partnership interest in us. No other unitholder has a similar right. Therefore, only our general partner may protect itself against dilution caused by the issuance of additional equity securities.

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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 owns 100 percent of 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, and we plan to enter into additional agreements, for example Denbury is a significant customer of our Mississippi System.  See “Our General Partner and Our Relationship with Denbury Resources Inc.” under Item 1 – Business.  We could be adversely affected if Denbury experiences any adverse developments or fails to pay us timely.
 
We may issue additional common units without unitholder’s approval, which would dilute their ownership interests.
 
We may issue an unlimited number of limited partner interests of any type without the approval of our unitholders.
 
The issuance of additional common units or other equity securities of equal or senior rank will have the following effects:
 
 
·
our unitholders’ proportionate ownership interest in us will decrease;
 
 
·
the amount of cash available for distribution on each unit may decrease;
 
 
·
the relative voting strength of each previously outstanding unit may be diminished; and
 
 
·
the market price of our common units may decline.
 
Our general partner has a limited call right that may require unitholders to sell their common units at an undesirable time or price.
 
If at any time our general partner and its affiliates own more than 80% of the common units, our general partner will have the right, but not the obligation, which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price not less than their then-current market price. As a result, unitholders may be required to sell their common units at an undesirable time or price and may not receive any return on their investment. Unitholders may also incur a tax liability upon a sale of their units.
 
The interruption of distributions to us from our subsidiaries and joint ventures may affect our ability to make payments on indebtedness or cash distributions to our unitholders.
 
We are a holding company. As such, our primary assets are the equity interests in our subsidiaries and joint ventures. Consequently, our ability to fund our commitments (including payments on our indebtedness) and to make cash distributions depends upon the earnings and cash flow of our subsidiaries and joint ventures and the distribution of that cash to us. Distributions from our joint ventures are subject to the discretion of their respective management committees. Further, each joint venture’s charter documents typically vest in its management committee sole discretion regarding distributions. Accordingly, our joint ventures may not continue to make distributions to us at current levels or at all.
 
We do not have the same flexibility as other types of organizations to accumulate cash and equity to protect against illiquidity in the future.
 
Unlike a corporation, our partnership agreement requires us to make quarterly distributions to our unitholders of all available cash reduced by any amounts reserved for commitments and contingencies, including capital and operating costs and debt service requirements. The value of our units and other limited partner interests will decrease in direct correlation with decreases in the amount we distribute per unit. Accordingly, if we experience a liquidity problem in the future, we may not be able to issue more equity to recapitalize.

30


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, 2007, our balance sheet reflected $320.7 million of goodwill and $211.1 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. 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.
 
Tax Risks to Common Unitholders
 
Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as our not being subject to a material amount of entity-level taxation by individual states.  A publicly-traded partnership can lose its status as a partnership for a number of reasons, including not having enough “qualifying income.”  If the IRS were to treat us as a corporation or if we were to become subject to a material amount of entity-level taxation for state tax purposes, then our cash available for distribution to unitholders would be substantially reduced.
 
The anticipated after-tax economic benefit of an investment in us depends largely on our being treated as a partnership for federal income tax purposes.  Section 7704 of the Internal Revenue Code provides that publicly traded partnerships will, as a general rule, be taxed as corporations.  However, an exception, referred to in this discussion as the “Qualifying Income Exception,” exists with respect to publicly traded partnerships 90% or more of the gross income of which for every taxable year consists of “qualifying income.”  If less than 90% of our gross income for any taxable year is “qualifying income” from transportation or processing of natural resources including crude oil, natural gas or products thereof, interest, dividends or similar sources, we will be taxable as a corporation under Section 7704 of the Internal Revenue Code for federal income tax purposes for that taxable year and all subsequent years.
 
In addition, current law may change so as to cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to entity-level taxation.  For example, in response to certain recent developments, members of Congress are considering substantive changes to the definition of qualifying income under Internal Revenue Code section 7704(d).  It is possible that these efforts could result in changes to the existing U.S. tax laws that affect publicly-traded partnerships, including us.  We are unable to predict whether any of these changes or other proposals will ultimately be enacted.  Any such changes 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 conclusions of our counsel expressed in this prospectus or from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of our counsel’s conclusions or the positions we take. A court may not agree with some or all of our counsel’s conclusions or positions we take. Any contest with the IRS may materially and adversely impact the market for our common units and the price at which they trade. In addition, our costs of any contest with the IRS will be borne indirectly by our unitholders and our general partner, and these costs will reduce our cash available for distribution.

31


Unitholders will be required to pay taxes on income from us even if they do not receive any cash distributions from us.
 
Unitholders will be required to pay any federal income taxes and, in some cases, state and local income taxes on their share of our taxable income even if unitholders receive no cash distributions from us. Unitholders may not receive cash distributions from us equal to their share of our taxable income or even the tax liability that results from that income.
 
Tax gain or loss on disposition of common units could be different than expected.
 
 If unitholders sell their common units, they will recognize a gain or loss equal to the difference between the amount realized and their tax basis in those common units. Prior distributions to unitholders in excess of the total net taxable income unitholders were allocated for a common unit, which decreased their tax basis in that common unit, will, in effect, become taxable income to unitholders if the common unit is sold at a price greater than their tax basis in that common unit, even if the price is less than their original cost. A substantial portion of the amount realized, whether or not representing gain, may be ordinary income. In addition, if unitholders sell their units, they may incur a tax liability in excess of the amount of cash they receive from the sale.
 
Tax-exempt entities and foreign persons face unique tax issues from owning common units that may result in adverse tax consequences to them.
 
Investment in common units by tax-exempt entities, such as individual retirement accounts (known as IRAs), and non-U.S. persons raises issues unique to them. For example, a significant amount of our income allocated to organizations exempt from federal income tax, including individual retirement accounts and other retirement plans, may be unrelated business taxable income and will be taxable to such a unitholder. Distributions to non-U.S. persons will be reduced by withholding tax at the highest effective tax rate applicable to individuals, and non-U.S. persons will be required to file federal income tax returns and pay tax on their share of our taxable income.
 
We will treat each purchaser of common units as having the same tax benefits without regard to the actual common units purchased. The IRS may challenge this treatment, which could adversely affect the value of our common units.
 
Because we cannot match transferors and transferees of common units, we adopt depreciation and amortization positions that may not conform with all aspects of applicable Treasury regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to a common unitholder. It also could affect the timing of these tax benefits or the amount of gain from a sale of common units and could have a negative impact on the value of the common units or result in audit adjustments to the common unitholder’s tax returns.
 
Unitholders will likely be subject to state and local taxes in states where they do not live as a result of an investment in the common units.
 
In addition to federal income taxes, unitholders will likely be subject to other taxes, including foreign, state and local taxes, unincorporated business taxes and estate inheritance or intangible taxes that are imposed by the various jurisdictions in which we do business or own property, even if unitholders do not live in any of those jurisdictions. Unitholders will likely be required to file foreign, state and local income tax returns and pay state and local income taxes in some or all of these jurisdictions. Further, unitholders may be subject to penalties for failure to comply with those requirements. We own assets and do business in more than 25 states including Texas, Louisiana, Mississippi, Alabama, Florida, Arkansas and Oklahoma.  Many of the states we currently do business in currently impose a personal income tax. It is unitholders’ responsibility to file all United States federal, foreign, state and local tax returns. Our counsel has not rendered an opinion on the state or local tax consequences of an investment in our common units.
 
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.

32


 We prorate our items of income, gain, loss and deduction between transferors and transferees of our common units each month based upon the ownership of our common units on the first day of each month, instead of on the basis of the date a particular common unit is transferred.
 
We prorate our items of income, gain, loss and deduction between transferors and transferees of our common units each month based upon the ownership of our common units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The use of this proration method may not be permitted under existing Treasury regulations. If the IRS were to successfully challenge this method or new Treasury regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders.
 
We have adopted certain valuation methodologies that may result in a shift of income, gain, loss and deduction between our general partner and our unitholders. The IRS may challenge this treatment, which could adversely affect the value of the common units.
 
When we issue additional common units or engage in certain other transactions, we determine the fair market value of our assets and allocate any unrealized gain or loss attributable to our assets to the capital accounts of our unitholders and our general partner.  Our methodology may be viewed as understating the value of our assets.  In that case, there may be a shift of income, gain, loss and deduction between certain unitholders and our general partner, which may be unfavorable to such unitholders.  Moreover, subsequent purchasers of common units may have a greater portion of their Internal Revenue Code Section 743(b) adjustment allocated to our tangible assets and a lesser portion allocated to our intangible assets.  The IRS may challenge our methods, or our allocation of the Section 743(b) adjustment attributable to our tangible and intangible assets, and allocations of income, gain, loss and deduction between our general partner and certain of our unitholders.
 
A successful IRS challenge to these methods or allocations could adversely affect the amount of taxable income or loss being allocated to our unitholders.  It also could affect the amount of gain from a unitholder’s sale of common units and could have a negative impact on the value of the common units or result in audit adjustments to the unitholder’s tax returns.
 
The sale or exchange of 50% or more of our capital and profits interests during any twelve-month period will result in the termination of our partnership for federal income tax purposes.
 
We will be considered to have terminated for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period.  Our termination would, among other things, result in the closing of our taxable year for all unitholders, which would result in us filing two tax returns (and unitholders receiving two Schedule K-1’s) for one fiscal year.  Our termination could also result in a deferral of depreciation deductions allowable in computing our taxable income.  In the case of a common unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of our taxable year may result in more than twelve months of our taxable income or loss being includable in his taxable income for the year of termination.  Our termination currently would not affect our classification as a partnership for federal income tax purposes, but instead, we would be treated as a new partnership for tax purposes.  If treated as a new partnership, we must make new tax elections and could be subject to penalties if we are unable to determine that a termination occurred.
 
Item 1B.  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 18 of the Notes to Consolidated Financial Statements for the future minimum rental payments.  Such information is incorporated herein by reference.

33


Item 3.  Legal Proceedings
 
We are involved from time to time in various claims, lawsuits and administrative proceedings incidental to our business.  In our opinion, the ultimate outcome, if any, of such proceedings is not expected to have a material adverse effect on our financial condition, results of operations or cash flows.  (See Note 18 of the Notes to Consolidated Financial Statements.)
 
Item 4.  Submission of Matters to a Vote of Security Holders
 
The board of directors of our general partner (which we refer to as our board of directors), called a special meeting for December 18, 2007.  At that meeting, unitholders were asked to consider and vote upon:
 
 
·
a proposal to amend certain provisions of our partnership agreement which we refer to as the “Amendment Proposal,” to allow any affiliated persons or group who hold more than 20% of our outstanding voting units to vote on all matters on which holders of our voting units have the right to vote, other than matters relating to the succession, election, removal, withdrawal, replacement or substitution of our general partner and to clarify and expand the concept of “group”; and
 
 
·
a proposal to approve the terms of the Genesis Energy, Inc. 2007 Long Term Incentive Plan, which provides for awards of our units and other rights to our employees and, possibly, our directors (the “Incentive Plan Proposal”).
 
Of the unitholders entitled to vote at this special meeting, over 60% voted in favor of these proposals.  The voting results were as follows:
 

 
   
Votes Cast
   
Broker
 
Matter
 
For
   
Against
   
Abstain
   
Non-Votes
 
Approve Amendment Proposal
    8,121,986       889,239       100,104       n/a  
Approve Incentive Plan Proposal
    8,607,575       438,332       65,419       n/a  
 
PART II
 

Item 5.  Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
 
Our common units are listed on the American Stock Exchange under the symbol “GEL”.  The following table sets forth, for the periods indicated, the high and low sale prices per common unit and the amount of cash distributions paid per common unit.
 
   
Price Range
   
Cash
 
   
High
   
Low
   
Distributions (1)
 
                   
2008
                 
First Quarter (through February 29, 2008)
  $ 25.00     $ 15.07     $ 0.285  
                         
2007
                       
Fourth Quarter
  $ 28.62     $ 20.01     $ 0.270  
Third Quarter
  $ 37.50     $ 27.07     $ 0.230  
Second Quarter
  $ 35.98     $ 20.01     $ 0.220  
First Quarter
  $ 22.01     $ 18.76     $ 0.210  
                         
2006
                       
Fourth Quarter
  $ 20.65     $ 14.48     $ 0.200  
Third Quarter
  $ 19.18     $ 11.20     $ 0.190  
Second Quarter
  $ 14.14     $ 10.25     $ 0.180  
First Quarter
  $ 12.85     $ 11.25     $ 0.170  

_____________________
(1)  Cash distributions are shown in the quarter paid and are based on the prior quarter’s activities.
 
34


At February 29, 2008, we had 38,253,264 common units outstanding, including 2,829,055 common units held by our general partner.  As of December 31, 2007, we had approximately 10,200 record holders of our common units, which include holders who own units through their brokers “in street name.”
 
We distribute all of our available cash, as defined in our partnership agreement, within 45 days after the end of each quarter to Unitholders of record and to our general partner.  Available cash consists generally of all of our cash receipts less cash disbursements, adjusted for net changes to cash reserves.  Cash reserves are the amounts deemed necessary or appropriate, in the reasonable discretion of our general partner, to provide for the proper conduct of our business or to comply with applicable law, any of our debt instruments or other agreements.  The full definition of available cash is set forth in our partnership agreement and amendments thereto, which is filed as an exhibit to this Form 10-K.
 
In addition to its 2% general partner interest, our general partner is entitled to receive incentive distributions if the amount we distribute with respect to any quarter exceeds levels specified in our partnership agreement.  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, 2007.
 
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)
    39,362       (1 )     960,638  
 
(1)  Awards issued under our 2007 LTIP are phantom units for which the grantee will receive one common unit for each phantom unit.  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
 
On December 10, 2007, we sold 734,732 common units to our general partner for $15.5 million in a private transaction that was exempt from the registration requirements of the Securities Act of 1933, pursuant to Section 4(2) thereof. This sale, made concurrently with a public offering, was made pursuant to our general partner's preemptive rights to maintain its pro rata interest in our common units under Section 5.6 of our partnership agreement.

35


Item 6.  Selected Financial Data
 
The table below includes selected financial and other data for the Partnership for the years ended December 31, 2007, 2006, 2005, 2004, and 2003 (in thousands, except per unit and volume data).
 
   
Year Ended December 31,
 
   
2007 (1)
   
2006
   
2005
   
2004
   
2003
 
Income Statement Data:
                             
Revenues:
                             
Supply and logistics (2)
  $ 1,094,189     $ 873,268     $ 1,038,549     $ 901,902     $ 641,684  
Refinery services
    62,095       -       -       -       -  
Pipeline transportation, including natural gas sales
    27,211       29,947       28,888       16,680       15,134  
CO2 marketing
    16,158       15,154       11,302       8,561       1,079  
Total revenues
    1,199,653       918,369       1,078,739       927,143       657,897  
Costs and expenses:
                                       
Supply and logistics costs (2)
    1,078,859       865,902       1,034,888       897,868       633,776  
Refinery services operating costs
    40,197       -       -       -       -  
Pipeline transportation, including natural gas purchases
    14,176       17,521       19,084       8,137       10,026  
CO2 marketing transportation costs
    5,365       4,842       3,649       2,799       355  
General and administrative expenses
    25,920       13,573       9,656       11,031       8,768  
Depreciation and amortization
    38,747       7,963       6,721       7,298       4,641  
Loss (gain) from sales of surplus assets
    266       (16 )     (479 )     33       (236 )
Impairment Expense (3)
    1,498       -       -       -       -  
Total costs and expenses
    1,205,028       909,785       1,073,519       927,166       657,330  
                                         
Operating (loss) income from continuing operations
    (5,375 )     8,584       5,220       (23 )     567  
Earnings from equity in joint ventures
    1,270       1,131       501       -       -  
Interest expense, net
    (10,100 )     (1,374 )     (2,032 )     (926 )     (986 )
                                         
(Loss) income from continuing operations before cumulative effect of change in accounting principle, income taxes and minority interest
    (14,205 )     8,341       3,689       (949 )     (419 )
Income tax benefit
    654       11       -       -       -  
Minority interest
    1       (1 )     -       -       -  
                                         
(Loss) income from continuing operations before cumulative effect of change in accounting principle
    (13,550 )     8,351       3,689       (949 )     (419 )
(Loss) income from discontinued operations
    -       -       312       (463 )     13,741  
Cumulative effect of changes in accounting principle
    -       30       (586 )     -       -  
Net (loss) income
  $ (13,550 )   $ 8,381     $ 3,415     $ (1,412 )   $ 13,322  
Net (loss) income per common unit - basic and diluted:
                                       
Continuing operations
  $ (0.64 )   $ 0.59     $ 0.38     $ (0.10 )   $ (0.05 )
Discontinued operations
    -       -       0.03       (0.05 )     1.55  
Cumulative effect of change in accounting principle
    -       -       (0.06 )     -       -  
Net (loss) income
  $ (0.64 )   $ 0.59     $ 0.35     $ (0.15 )   $ 1.50  
                                         
Cash distributions per common unit
  $ 0.93     $ 0.74     $ 0.61     $ 0.60     $ 0.15  

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Year Ended December 31,
 
   
2007 (1)
   
2006
   
2005
   
2004
   
2003
 
Balance Sheet Data (at end of period):
                             
Current assets
  $ 214,240     $ 99,992     $ 90,449     $ 77,396     $ 88,211  
Total assets
    908,523       191,087       181,777       143,154       147,115  
Long-term liabilities
    101,351       8,991       955       15,460       7,000  
Minority interests
    570       522       522       517       517  
Partners' capital
    631,804       85,662       87,689       45,239       52,354  
                                         
                                         
Other Data:
                                       
Maintenance capital expenditures (4)
    3,840       967       1,543       939       4,178  
Volumes - continuing operations:
                                       
Crude oil pipeline (bpd)
    59,335       61,585       61,296       63,441       66,959  
Crude oil wellhead (bpd)
    30,363       33,853       39,194       45,919       45,015  
CO2 sales (Mcf per day)
    77,309       72,841       56,823       45,312       36,332  
 
 
(1)
Our operating results and financial position have been affected by acquisitions in 2007, most notably the Davison acquisition, which was completed on July 25, 2007. The aggregate value of the total consideration we paid or issued to complete the Davison acquisition was approximately $623 million.   The operating results of the acquired Davison entities are included in our financial results prospectively from the acquisition date. For additional information regarding the Davison acquisition, 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)  
Represents average daily volume for the two month period in 2003 that we owned the assets.

The table below summarizes our unaudited quarterly financial data for 2007 and 2006 (in thousands, except per unit data).
 
   
2007 Quarters
 
   
First
   
Second
   
Third
   
Fourth
 
Revenues
  $ 183,564     $ 201,016     $ 354,270     $ 460,803  
Operating income (loss)
  $ 1,580     $ (1,319 )   $ 7,043     $ (12,679 )
Income (loss) from continuing operations
  $ 1,585     $ (1,372 )   $ 1,699     $ (15,462 )
Net income (loss)
  $ 1,585     $ (1,372 )   $ 1,699     $ (15,462 )
Income (loss) from continuing operations per common unit - basic and diluted
  $ 0.11     $ (0.09 )   $ 0.07     $ (0.49 )
Net income (loss) per common unit - basic and diluted
  $ 0.11     $ (0.09 )   $ 0.07     $ (0.49 )
                                 
   
2006 Quarters
 
   
First
   
Second
   
Third
   
Fourth
 
Revenues
  $ 263,602     $ 233,343     $ 229,551     $ 191,873  
Operating income
  $ 2,370     $ 3,357     $ 1,688     $ 1,169  
Income from continuing operations
  $ 2,561     $ 3,444     $ 1,695     $ 651  
Cumulative effect adjustment
  $ 30     $ -     $ -     $ -  
Net income
  $ 2,591     $ 3,444     $ 1,695     $ 651  
Income from continuing operations per common unit - basic and diluted
  $ 0.18     $ 0.24     $ 0.12     $ 0.05  

37


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 2007
 
 
·
Significant Events
 
 
·
Capital Resources and Liquidity
 
 
·
Commitments and Off-Balance Sheet Arrangements
 
 
·
Results of Operations
 
 
·
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.  Our profitability depends to a significant extent upon our ability to maximize segment margin.  Segment margin is revenues less cost of sales and operating expenses (excluding depreciation and amortization) plus our equity in the operating income of joint ventures.  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 continuing operations is included in our segment disclosures in Note 12 to the consolidated financial statements.
 
Available Cash before Reserves is a non-GAAP measure is net income as adjusted for specific items, the most significant of which are the elimination of gains and losses on asset sales (except those from the sale of surplus assets) the addition of non-cash expenses (such as depreciation), the substitution of cash generated by our joint ventures in lieu of our equity income attributable to our joint ventures, 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 2007
 
 The year 2007 was a significant year for us.  We acquired five energy-related businesses from the Davison family of Ruston, Louisiana and a crude oil terminal on the Mississippi River from BP Pipelines North America Inc.  To finance our acquisitions and other activities, we increased the size of our revolving credit facility to $500 million (from $125 million) and issued 24,468,823 common units, including 13,459,209 units to the Davisons and 9,200,000 units in a public offering.  We used the proceeds from our public offering to temporarily reduce the balance on our revolving credit facility, which had $80 million outstanding as of December 31, 2007.
 
We also are negotiating with Denbury several potential “drop-down” transactions involving midstream assets with an aggregate value of approximately $250 million.
 
Increases in cash flow generally result in increases in Available Cash before Reserves, which we distribute quarterly to holders of our common units and our general partner.  During 2007, we generated $28.2 million of Available Cash before Reserves, and we distributed $17.2 million to holders of our common units and general partner.  Cash provided by operating activities in 2007 was $33.9 million.
 
In 2007, we reported a net loss of $13.6 million, or $0.64 per common unit, resulting primarily from non-cash depreciation and amortization of the assets acquired in the Davison transaction totaling $30.1 million.  See additional discussion of our depreciation and amortization expense in “Results of Operations – Other Costs and Interest” below.
 
Additionally, on January 28, 2008, we declared that our distribution to our common unitholders relative to the fourth quarter of 2007 would be $0.285 per unit (paid in February 2008), which is an increase of 5.6% relative to the distribution for the third quarter of 2007.   That distribution amount represents a 36% increase from our distribution of $0.21 per unit for the fourth quarter of 2006.  During the fourth quarter of 2007 we paid a distribution of $0.27 per unit related to the third quarter of 2007.  Our total distributions attributable to 2007 increased 29% over the total distributions attributable to 2006.

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We manage our business through four divisions, which constitute our reportable segments – pipeline transportation (primarily of crude oil), refinery services, industrial gases and supply and logistics (crude oil, petroleum products, terminaling, and truck transportation).
 
Significant Events
 
Davison Businesses Acquisition
 
On July 25, 2007, we acquired substantially all of the operating assets of five energy- related businesses from entities owned and controlled by the Davison family of Ruston, Louisiana.  The businesses that we acquired from the Davison family include refinery services, petroleum products marketing, terminaling, trucking, and fuel procurement.  Additional information on those operations is included in “Item 1.  Business” above.
 
For financial reporting purposes, the total consideration for the transaction was $623 million, comprised of common units and cash.  In that transaction, we issued 13,459,209 of our common units, which were contractually valued at $20.8036 per unit.  The units issued are reflected in our consolidated balance sheet at a total value of $330 million.  In accordance with EITF No. 99-12, “Determination of the Measurement Date for the Market Price of Acquirer Securities Issued in a Purchase Business Combination,” the fair value of Genesis common units issued was determined using an average price of $24.52, which was the average closing price of Genesis common units for the two days before and after the terms of the acquisition were agreed to and announced. The remainder of the net purchase price of $293 million (adjusted for purchase price adjustments), along with working capital of an additional $32.5 million (excluding cash acquired), was paid with cash borrowed under our credit facility.
 
Additionally, our general partner exercised its right to maintain its proportionate share of our outstanding common units by purchasing 1,074,882 common units from us for $22.4 million cash, or $20.8036 per common unit.  As a result of that purchase, our general partner continued to hold 7.4% of our outstanding common units.  As required under our partnership agreement, our general partner also contributed approximately $6.2 million to maintain its two percent general partner capital account balance.
 
Pursuant to a unitholder agreement executed on July 25, 2007, the Davison unitholders have the right to designate up to two directors to our board of directors, depending on their continued level of ownership in us.  Until July 25, 2010, the Davison unitholders have the right to designate two directors to our board of directors.  Thereafter, the Davison unitholders will have the right to designate (i) one director if they beneficially own at least 10% but less than 35% of our outstanding common units, or (ii) two directors if they beneficially own 35% or more of our outstanding common units.  If their percentage ownership in our common units drops below 10% after July 25, 2010, the Davison unitholders would have no rights to designate directors.  At December 31, 2007, the Davison unitholders held approximately 33% of our outstanding common units.
 
On July 25, 2007, the Davison unitholders designated James E. Davison and James E. Davison, Jr. as directors to the Board of Directors of our general partner.
 
Our operational results for the year ended December 31, 2007, include five months of activity from the Davison acquisition.  We have included pro forma information in Note 3 of the Notes to the Consolidated Financial Statements for the year ended December 31, 2007 as if this transaction had occurred January 1, 2007.
 
Credit Agreement Amendment
 
In connection with our acquisition from the Davison family, we also amended our credit facility.  That amendment increased the committed amount under our facility from $125 million to $500 million, of which a maximum of $100 million may be used for letters of credit.  The committed amount represents the amount the banks have committed to fund pursuant to the terms of the credit agreement.
 
December 2007 Equity Offering
 
On December 10, 2007, we received $194 million in proceeds (net to us after expenses) from a public offering of 9,200,000 common units.  We also received $15.5 million from our general partner for its purchase of 734,732 common units to maintain its 7.4% proportionate share of our outstanding common units and $4.4 million to maintain its two percent general partner capital account balance.  We used the net proceeds from the offering to repay outstanding borrowings under our credit facility.
 
Port Hudson Assets Acquisition
 
Effective July 1, 2007, we acquired the Port Hudson Crude Oil truck terminal, marine terminal, and marine dock of BP Pipelines (North America) Inc. for $8.1 million.  The assets acquired in that transaction include docking facilities on the Mississippi River, 215,000 barrels of tankage, a pipeline and other related assets in East Baton Rouge Parish, Louisiana.   That acquisition was funded with borrowings under our credit facility.  We allocated $4.1 million of the purchase price to the tangible assets we acquired and $4.0 million to goodwill.  The assets we acquired in that transaction should provide us with the increased ability to gather, blend and store crude oil from south Louisiana for delivery to markets that can be reached by barge from the Mississippi River.

39


Drop-down Transactions
 
As a result of our acquisition from the Davisons, we anticipate that during the first quarter of 2008, Denbury will enter into “drop-down” transactions with us involving two of their existing CO2 pipelines - the NEJD and Free State CO2 pipelines. We have reached substantial agreement and are in the process of finalizing the business issues with Denbury and the lenders in our credit facility as to the terms of such drop-downs by Denbury and the terms of a long-term transportation service arrangement for the Free State line and a 20-year financing lease for the NEJD system. We expect to pay for these pipeline assets with $225 million in cash and $25 million of our common units based on the average closing price of our units for the thirty trading days prior to the closing of the transaction. We expect to receive approximately $30 million per annum, in the aggregate, under the lease and the transportation services agreement (and a lesser pro-rated amount for 2008), with future payments for the NEJD pipeline fixed at $20.7 million per year during the term of the financing lease, and the payments relating to the Free State pipeline dependant on the volumes of CO2 transported therein. While the business terms of the transactions and associated documentation have been substantially completed, closing remains subject to completion of closing documentation, receipt of a fairness opinion and approval by the audit committee and the board of directors of our general partner.
 
Liquidity and Capital Resources
 
Capital Resources/Sources of Cash
 
In the last eighteen months, we have adopted a growth strategy that has dramatically increased our cash requirements.  We now expect our 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.
 
In November 2006, we entered into a credit facility with a maximum facility amount of $500 million (replacing our $100 million facility). A maximum of $100 million may be used for letters of credit.  The borrowing base under the facility at December 31, 2007 was approximately $356 million, and is recalculated quarterly and at the time of acquisitions.  The borrowing base represents the amount that can be borrowed or utilized for letters of credit based on our EBITDA, computed in accordance with the provisions of our credit facility.
 
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.
 
Uses of Cash
 
Our cash requirements include funding day-to-day operations, maintenance and expansion capital projects, debt service, refinancings 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.
 
Operating.  Our operating cash flows are affected significantly by changes in items of working capital.  We have had situations where other parties have prepaid for purchases or paid more than was due, resulting in fluctuations in one period as compared to the next until the party recovers the excess payment.  The timing of capital expenditures and the related effect on our recorded liabilities also affects operating cash flows.

40


The majority of the accounts receivable amount on our consolidated balance sheets relate to our crude oil operations.  These accounts receivable settle monthly and collection delays generally relate only to discrepancies or disputes as to the appropriate price, volume or quality of crude oil delivered.  Accounts receivable in our fuel procurement business also settle within 30 days of delivery.  Over 75% of our $180.1 million aggregate receivables on our consolidated balance sheet at December 31, 2007 relate to our crude oil and fuel procurement businesses.
 
Investing.  We utilized cash flows to make acquisitions and for capital expenditures.  The most significant investing activities in 2007 have been the Davison acquisition for which we expended $301.6 million in cash as consideration and for related acquisition costs.  We also paid $8.1 million for our acquisition of the Port Hudson assets.  We paid $8.2 million for capital expenditures.  We received distributions from our T&P Syngas joint venture that exceeded our share of the earnings of T&P Syngas of $0.4 million during 2007.
 
During 2006, we utilized cash flows in investing activities by acquiring a 50% interest in Sandhill for $5.0 million.  We expended $2.3 million for other investments and capital improvements.  Offsetting those expenditures was the receipt of returns of our investment in T&P Syngas in the form of distributions totaling $0.5 million.
 
We utilized cash flows in investing activities in 2005 by making a $13.4 million investment in T&P Syngas, acquiring a CO2 contract for $14.4 million and making investments in property and equipment of $6.1 million, including $3.1 million for the natural gas gathering assets acquired from Multifuels.  Offsetting these expenditures was the receipt of $1.6 million for the sale of idle assets.  We also received returns of our investment in T&P Syngas in the form of distributions totaling $0.4 million.
 
Financing.  Our financing activities provided net cash of $297.0 million.  Our net borrowings under our credit facility were $72.0 million. In an offering in December 2007, we sold 9,200,000 common units to the public and received $193.6 million, net of offering costs.  We received $37.9 million from our general partner for 1,809,614 common units it acquired as part of the Davison acquisition and the common unit offering in December 2007 in order to maintain its 7.4% limited partner interest.  Our general partner also contributed $10.6 million during 2007 as required under our partnership agreement to maintain its two percent general partner capital account balance and $1.4 million to offset the costs of a portion of the severance payment to an executive.  In connection with the increase in the committed amount of our credit facility, we incurred credit facility fees of $2.3 million.  We paid distributions totaling $17.2 million to our limited partners and our general partner during 2007, and received $0.9 million on other financing activities.
 
In 2006, we utilized net cash of $5.2 million in financing activities.  We paid distributions totaling $10.4 million to our limited partners and our general partner during the year.  We borrowed $8.0 million under our credit facility, and paid $2.7 million in legal and bank fees in November 2006 to obtain our new credit facility.
 
In 2005, financing activities provided net cash of $23.3 million.  We issued 4,140,000 new limited partner units to the public and 330,630 new limited partner units to our general partner.  Additionally, our general partner contributed funds to maintain its 2% general partner interest.  In total these activities provided $44.8 million to us.  A portion of these funds were utilized to eliminate our bank debt, and we also paid distributions totaling $5.8 million to our partners.

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Capital Expenditures and Business Acquisitions
 
A summary of our expenditures for fixed assets and businesses in the three years ended December 31, 2007, 2006, and 2005 is as follows:
 
   
Years Ended December 31,
 
   
2007
   
2006
   
2005
 
   
(in thousands)
 
Capital expenditures for business combinations and asset purchases:
                 
Davison acquisition:
                 
Cash payments to Davison
  $ 314,227       -       -  
Transaction fees and other direct costs
    8,915       -       -  
Cash received from Davison
    (21,686 )     -       -  
Net cash payments
    301,456       -       -  
Value of non-cash consideration issued or granted
    330,020       -       -  
Total Davison acquisition consideration
    631,476       -       -  
Port Hudson acquisition
    8,103       -       -  
CO2 contracts
    -       -       14,446  
Natural gas gathering assets
    -       -       3,110  
Total
    639,579       -       17,556  
                         
Capital expenditures for property, plant and equipment:
                       
Maintenance capital expenditures:
                       
Pipeline transportation assets
    2,880       611       1,256  
Supply and logistics assets
    440       175       34  
Refinery services assets
    469       -       -  
Administrative and other assets
    51       181       253  
Total maintenance capital expenditures
    3,840       967       1,543  
                         
Growth capital expenditures:
                       
Pipeline transportation assets
    3,712       360       1,059  
Supply and logistics assets
    650       -       260  
Refinery services assets
    979       -       -  
Total growth capital expenditures
    5,341       360       1,319  
Total
    9,181       1,327       2,862  
                         
Capital expenditures attributable to unconsolidated affiliates:
                       
T&P Syngas investment
    -       -       13,418  
Sandhill investment
    -       5,042       -  
Faustina project
    1,104       1,016       -  
Total
    1,104       6,058       13,418  
Total capital expenditures
  $ 649,864     $ 7,385     $ 33,836  
 
During 2008, we expect to expend approximately $6.1 million for maintenance capital projects in progress or planned.  Those expenditures are expected to include approximately $3.3 million of improvements in our refinery services business, $0.6 million in our crude oil pipeline operations, $1.5 million related to the relocation of our headquarters office when our existing lease ends in October 2008 and the remainder on projects related to our truck transportation and information technology areas.  Most of our truck fleet is less than two years old, so we do not anticipate making any significant expenditures for vehicles in 2008; however, in future years we expect to spend $4 million to $5 million per year on vehicle replacements.  Based on the information available to us at this time, we do not anticipate that future capital expenditures for compliance with regulatory requirements will be material.

42


We have started construction of an expansion of our existing Jay System that will extend the pipeline to producers operating in southern Alabama.  That expansion will consist of approximately 33 miles of pipeline and gathering connections to approximately 30 wells and will include storage capacity of 20,000 barrels.  We expect to spend a total of approximately $9.9 million on this project in 2008.  Our refinery services segment expects to expend approximately $3.9 million on projects currently in progress to expand its operations in 2008 to two additional refineries.
 
As discussed above in “Significant Events”, we are currently in the process of finalizing drop down transactions with Denbury related to two of its CO2 pipelines that are expected to occur in the first quarter of 2008.
 
Expenditures for capital assets to grow the partnership distribution will depend on our access to debt and equity capital discussed above in “Capital Resources -- Sources of Cash.”  We will look for opportunities to acquire assets from other parties that meet our criteria for stable cash flows.  The arrangement that Denbury has made with our new senior executive management team provide incentives to them to make such acquisitions.  See “Item 11. Executive Compensation” for a description of these arrangements.
 
Distributions
 
Our partnership agreement requires us to distribute 100% of our available cash (as defined therein) within 45 days after the end of each quarter to unitholders of record and to our general partner.  Available cash consists generally of all of our cash receipts less cash disbursements adjusted for net changes to reserves.  We have increased our distribution for each of the last nine quarters, including the distribution paid for the fourth quarter of 2007, as shown in the table below (in thousands, except per unit amounts)
 
                         
General
       
             
Limited
   
General
   
Partner
       
             
Partner
   
Partner
   
Incentive
       
       
Per Unit
   
Interests
   
Interest
   
Distribution
   
Total
 
Distribution For
 
Date Paid
 
Amount
   
Amount
   
Amount
   
Amount
   
Amount
 
                 
Fourth quarter 2005
 
February 2006
  $ 0.170     $ 2,343     $ 48     $ -     $ 2,391  
First quarter 2006
 
May 2006
  $ 0.180     $ 2,481     $ 51     $ -     $ 2,532  
Second quarter 2006
 
August 2006
  $ 0.190     $ 2,619     $ 53     $ -     $ 2,672  
Third quarter 2006
 
November 2006
  $ 0.200     $ 2,757     $ 56     $ -     $ 2,813  
Fourth quarter 2006
 
February 2007
  $ 0.210     $ 2,895     $ 59     $ -     $ 2,954  
First quarter 2007
 
May 2007
  $ 0.220     $ 3,032     $ 62     $ -     $ 3,094  
Second quarter 2007
 
August 2007
  $ 0.230     $ 3,170 (1)   $ 65     $ -     $ 3,235 (1)
Third quarter 2007
 
November 2007
  $ 0.270     $ 7,646     $ 156     $ 90     $ 7,892 (2)
Fourth quarter 2007
 
February 2008
  $ 0.285     $ 10,902     $ 222     $ 245     $ 11,369 (3)
 
(1)  The distribution paid on August 14, 2007 to holders of our common units is net of the amounts payable with respect to the common units issued in connection with the Davison transaction.  The Davison unitholders and our general partner waived their rights to receive such distributions, instead receiving purchase price adjustments with us.
 
(2)  The increased amount of distributions that were paid is primarily a result of the additional units issued in connection with the Davison acquisition in July 2007 and the offering of common units in December 2007 as discussed above.
 
(3)  This distribution was paid on February 14, 2008 to our general partner and unitholders of record as of February 7, 2008.
 
Our credit facility also includes a restriction on the amount of distributions we can pay in any quarter.  At December 31, 2007, our restricted net assets (as defined in Rule 4-03 (e)(3) of Regulation S-X) were $593.7 million.
 
Our general partner is entitled to receive incentive distributions if the amount we distribute with respect to any quarter exceeds levels specified in our partnership agreement.  Under the quarterly incentive distribution provisions, our general partner is entitled to receive 13.3% of any distributions to our common unitholders in excess of $0.25 per unit, 23.5% of any distributions to our common unitholders in excess of $0.28 per unit, and 49% of any distributions to our common unitholders in excess of $0.33 per unit, without duplication.  The likelihood and timing of the payment of any incentive distributions will depend on our ability to increase the cash flow from our existing operations and to make accretive acquisitions.  In addition, our partnership agreement authorizes us to issue additional equity interests in our partnership with such rights, powers and preferences (which may be senior to our common units) as our general partner may determine in its sole discretion, including with respect to the right to share in distributions and profits and losses of the partnership.

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Available Cash before Reserves for the year ended December 31, 2007 is as follows (in thousands):
 
Net loss
  $ (13,550 )
Depreciation, amortization, and impairment expense
    40,245  
Cash received from direct financing leases not included in income
    568  
Cash effects of sales of certain assets
    195  
Effects of available cash generated by investments in joint ventures not included in income
    975  
Denbury contribution toward executive severance
    1,412  
Cash effects of stock appreciation rights plan
    (1,614 )
Non-cash charges
    3,788  
Maintenance capital expenditures
    (3,840 )
Available Cash before Reserves
  $ 28,179  

We have reconciled Available Cash before Reserves (a non-GAAP measure) to cash flow from operating activities (the GAAP measure) for the year ended December 31, 2007 below.  For the year ended December 31, 2007, cash flow provided by operating activities was $33.9 million.
 
Non-GAAP Financial Measure
 
This annual report includes the financial measure of Available Cash before Reserves, which is a “non-GAAP” measure because it is not contemplated by or referenced in accounting principles generally accepted in the U.S., also referred to as GAAP.  The accompanying schedule provides a reconciliation of this non-GAAP financial measure to its most directly comparable GAAP financial measure.  Our non-GAAP financial measure should not be considered as an alternative to GAAP measures such as net income, operating income, cash flow from operating activities or any other GAAP measure of liquidity or financial performance.  We believe that investors benefit from having access to the same financial measures being utilized by management, lenders, analysts and other market participants.
 
Available Cash before Reserves, also referred to as distributable cash flow, is commonly used as a supplemental financial measure by management and by external users of financial statements, such as investors, commercial banks, research analysts and rating agencies, to assess: (1) the financial performance of our assets without regard to financing methods, capital structures or historical cost basis; (2) the ability of our assets to generate cash sufficient to pay interest cost and support our indebtedness; (3) our operating performance and return on capital as compared to those of other companies in the midstream energy industry, without regard to financing and capital structure; and (4) the viability of projects and the overall rates of return on alternative investment opportunities.  Because Available Cash before Reserves excludes some, but not all, items that affect net income or loss and because these measures may vary among other companies, the Available Cash before Reserves data presented in this Annual Report on Form 10-K may not be comparable to similarly titled measures of other companies.  The GAAP measure most directly comparable to Available Cash before Reserves is net cash provided by operating activities.
 
Available Cash before Reserves is a liquidity measure used by our management to compare cash flows generated by us to the cash distribution paid to our limited partners and general partner.  This is an important financial measure to our public unitholders since it is an indicator of our ability to provide a cash return on their investment.  Specifically, this financial measure aids investors in determining whether or not we are generating cash flows at a level that can support a quarterly cash distribution to the partners.  Lastly, Available Cash before Reserves (also referred to as distributable cash flow) is the quantitative standard used throughout the investment community with respect to publicly-traded partnerships.

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The reconciliation of Available Cash before Reserves (a non-GAAP measure) to cash flow from operating activities (the GAAP measure) for the year ended December 31, 2007, is as follows (in thousands):
 
Cash flows from operating activities
  $ 33,929  
Adjustments to reconcile operating cash flows to Available Cash:
       
Maintenance capital expenditures
    (3,840 )
Proceeds from sales of certain assets
    195  
Amortization and write-off of credit facility issuance fees
    (779 )
Effects of available cash generated by investments in joint ventures not included in cash flows from operating activities
    400  
Denbury contribution toward executive severance
    1,412  
Other items affecting Available Cash
    142  
Net effect of changes in operating accounts not included in calculation of Available Cash
    (3,280 )
Available Cash before Reserves
  $ 28,179  
 
Commitments and Off-Balance Sheet Arrangements
 
Contractual Obligation and Commercial Commitments
 
In addition to our credit facility discussed above, we have contractual obligations under operating leases as well as commitments to purchase crude oil.  The table below summarizes our obligations and commitments at December 31, 2007.
 
   
Payments Due by Period
 
Commercial Cash Obligations and Commitments
 
Less than one year
   
1 - 3 years
   
3 - 5 Years
   
More than 5 years
   
Total
 
                               
Contractual Obligations:
                             
Long-term debt (1)
  $ -     $ -     $ 80,000     $ -     $ 80,000  
Estimated interest payable on long-term debt (2)
    6,819       13,600       5,924       -       26,343  
Operating lease obligations
    6,885       7,166       3,563       10,779       28,393  
Capital expansion projects (3)
    6,751       -       -       -       6,751  
Additional investment in the Faustina Project (4)
    763       -       -       -       763  
Unconditional purchase obligations (5)
    183,927       29,072       4,097       -       217,096  
                                         
Other Cash Commitments:
                                       
Asset retirement obligations (6)
    100                       3,771       3,871  
FIN 48 tax liabilities (7)
                            1,168       1,168  
Total
  $ 205,245     $ 49,838     $ 93,584     $ 15,718     $ 364,385  
 
(1)
Our credit facility allows us to repay and re-borrow funds at any time through the maturity date of November 15, 2011.
(2)
Interest on our long-term debt is at market-based rates. The amount shown for interest payments represents the amount that would be paid if the debt outstanding at December 31, 2007 remained outstanding through the final maturity date of November 15, 2011 and interest rates remained at the December 31, 2007 market levels through November 15, 2011.
(3)
We have signed commitments to expand our Jay System and to construct sour gas processing facilities at an additional refinery in Utah.  See “Capital Expenditures and Business Acquisitions” under “Liquidity and Capital Resources – Uses of Cash” above.
(4)
We made an additional investment in the Faustina Project in January 2008 in the amount of $0.8 million.
(5)
Unconditional purchase obligations includes agreements to purchase goods and services that are enforceable and legally binding and specify all significant terms.  Contracts to purchase crude oil and petroleum products are generally at market-based prices.  For purposes of this table, estimated volumes and market prices at December 31, 2007, were used to value those obligations.  The actual physical volumes and settlement prices may vary from the assumptions used in the table.  Uncertainties involved in these estimates include levels of production at the wellhead, changes in market prices and other conditions beyond our control.

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(6)
Represents the estimated future asset retirement obligations on an undiscounted basis.  The present discounted asset retirement obligation is $1.2 million, as determined under FIN 47 and SFAS 143, and is further discussed in Note 5 to the Consolidated Financial Statements.
(7)
The estimated FIN 48 tax liabilities will be settled as a result of expiring statutes or audit activity. The timing of any particular settlement will depend on the length of the tax audit and related appeals process, if any, or an expiration of statute. If a liability is settled due to a statute expiring or a favorable audit result, the settlement of the FIN 48 tax liability would not result in a cash payment.

In additional to the contractual cash obligations included above, we also have a contingent obligation related to our acquisition of a 50% interest in Sandhill, which could require us to pay an additional $2 million for our interest.  See additional discussion in the section on Sandhill in Note 8 to the consolidated financial statements.
 
We have guaranteed 50% of the $3.9 million debt obligation to a bank of Sandhill; however, we believe we are not likely to be required to perform under this guarantee as Sandhill is expected to make all required payments under the debt obligation.  See additional discussion in the section on Sandhill in Note 8 to the consolidated financial statements.
 
Off-Balance Sheet Arrangements
 
We have no off-balance sheet arrangements, special purpose entities, or financing partnerships, other than as disclosed under Contractual Obligation and Commercial Commitments above, nor do we have any debt or equity triggers based upon our unit or commodity prices.
 
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,
 
   
2007
   
2006
   
2005
 
   
(in thousands)
 
Pipeline transportation
  $ 13,035     $ 12,426     $ 9,804  
Refinery services
    21,898       -       -  
Industrial gases
    12,063       11,443       8,154  
Supply and logistics
    15,330       7,366       3,661  
Total segment margin
  $ 62,326     $ 31,235     $ 21,619  
 
Pipeline Transportation Segment
 
We operate three common carrier crude oil pipeline systems in a four state area.  We refer to these pipelines as our Mississippi System, Jay System and Texas System.  Volumes shipped on these systems for the last three years are as follows (barrels per day):
 
Pipeline System
 
2007
   
2006
   
2005
 
                   
Mississippi
    21,680       16,931       16,021  
Jay
    13,309       13,351       13,725  
Texas
    24,346       31,303       31,550  
 
The Mississippi System begins in Soso, Mississippi and extends to Liberty, Mississippi.  At Liberty, shippers can transfer the crude oil to a connection to Capline, a pipeline system that moves crude oil from the Gulf Coast to refineries in the Midwest.  The system has been improved to handle the increased volumes produced by Denbury and transported on the pipeline.  In order to handle future increases in production volumes in the area that are expected, we have made capital expenditures for tank, station and pipeline improvements and we intend to make further improvements. See “Capital Expenditures and Business Acquisitions” under “Liquidity and Capital Resources – Uses of Cash” above.
 
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 expects to add crude oil gathering and CO2 supply infrastructure to those fields, which could create some opportunities for us.

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Beginning in September 2004, Denbury became a shipper on the Mississippi System, under an incentive tariff designed to encourage shippers to increase volumes shipped on the pipeline.  Prior to this point, Denbury sold its production to us before it entered the pipeline.
 
In the fourth quarter of 2004, we constructed two segments of crude oil pipeline to connect producing fields operated by Denbury to our Mississippi System.  One of these segments was placed in service in 2004 and the other began operations in the first quarter of 2005.  Denbury pays us a minimum payment each month for the right to use these pipeline segments.  We account for these arrangements as direct financing leases.
 
The Jay Pipeline system in Florida and Alabama ships crude oil from fields with relatively short remaining production lives.  Recent changes in the ownership of the more mature producing fields in the area surrounding our Jay System have led to interest in further development of these fields which may lead to increases in production.  Additionally, new wells have been drilled in the area.  This new production 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 increase our cash flows from the Jay System.
 
Volumes on our Texas System averaged 24,346 barrels per day during 2007.  The crude oil that enters our system comes to us at West Columbia where we have a connection to TEPPCO’s South Texas System and at Webster where we have connections to two other pipelines.  One of these connections at Webster is with ExxonMobil Pipeline and is used to receive volumes that originate from TEPPCO’s pipelines.  We have a joint tariff with TEPPCO under which we earn $0.31 per barrel on the majority of the barrels we deliver to the shipper’s facilities.  Substantially all of the volume being shipped on our Texas System goes to two refineries on the Texas gulf coast.
 
Our Texas System is dependent on the connecting carriers for supply, and on the two refineries for demand for our services.  In 2003, we sold a portion of our Texas System to TEPPCO.  Since such sale, volumes on the Texas System have declined as a result of changes in the supply available for the two refineries to acquire and ship on our pipeline and changes TEPPCO made to the operations of the pipeline segments.  As we have consistently been able to increase our pipeline tariffs as needed and due to the insignificance of the Texas Systems’ net book value at December 31, 2007, we do not believe that the decline in volumes will affect the recoverability of the net investment that remains on the Texas System.  We lease tankage in Webster on the Texas System of approximately 165,000 barrels.  We have a tank rental reimbursement agreement effective January 1, 2005 with the primary shipper on our Texas System to reimburse us for the expense of leasing of that storage capacity.  Volumes on the Texas System may continue to fluctuate as refiners on the Texas Gulf Coast compete for crude oil with other markets connected to TEPPCO’s pipeline systems.
 
We operate a 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.
 
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.

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Operating results from operations for our pipeline transportation segment were as follows.
 
   
Year Ended December 31,
 
   
2007
   
2006
   
2005
 
   
(in thousands)
 
Crude oil tariffs and revenues from direct financing leases of crude oil pipelines
  $ 14,906     $ 14,309     $ 13,490  
Sales of crude oil pipeline loss allowance volumes
    6,875       6,472       4,672  
Revenues from direct financing leases of CO2 pipelines
    319       340       359  
Tank rental reimbursements and other miscellaneous revenues
    655       621