form10q.htm


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

Form 10-Q

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

For the quarterly period ended March 31, 2008

OR

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

Commission file number 1-12295

GENESIS ENERGY, L.P.
(Exact name of registrant as specified in its charter)
 
Delaware
(State or other jurisdictions 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(g) of the Act:
 
NONE

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Yes x   No o
 
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company.  See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
 
Large accelerated filer o
Accelerated filer x
Non-accelerated filer o
Smaller reporting company o

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

Yes o   No x

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date.  Common Units outstanding as of May 9, 2008:  38,253,264
 


 
 

 

GENESIS ENERGY, L.P.

Form 10-Q

INDEX
 

PART I.  FINANCIAL INFORMATION
     
Item 1.
Financial Statements
Page
     
 
3
     
 
4
     
 
5
     
 
6
     
 
7
     
     
Item 2.
26
     
Item 3.
38
     
Item 4.
40
     
     
PART II.  OTHER INFORMATION
   
 
Item 1.
41
     
Item 1A.
41
     
Item 2.
41
     
Item 3.
41
     
Item 4.
41
     
Item 5.
41
     
Item 6.
41
   
 
     
42

-2-


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


   
March 31,
   
December 31,
 
   
2008
   
2007
 
             
ASSETS
           
CURRENT ASSETS:
           
Cash and cash equivalents
  $ 11,431     $ 11,851  
Accounts receivable - trade
    195,998       178,658  
Accounts receivable - related party
    3,694       1,441  
Inventories
    17,915       15,988  
Net investment in direct financing leases, net of unearned income - current portion - related party
    594       609  
Other
    6,168       5,693  
Total current assets
    235,800       214,240  
                 
FIXED ASSETS, at cost
    157,472       150,413  
Less:  Accumulated depreciation
    (52,445 )     (48,413 )
Net fixed assets
    105,027       102,000  
                 
NET INVESTMENT IN DIRECT FINANCING LEASES, net of unearned income - related party
    4,632       4,764  
CO2 ASSETS, net of amortization
    27,855       28,916  
JOINT VENTURES AND OTHER INVESTMENTS
    20,205       18,448  
INTANGIBLE ASSETS, net of amortization
    199,399       211,050  
GOODWILL
    319,918       320,708  
OTHER ASSETS, net of amortization
    10,197       8,397  
                 
TOTAL ASSETS
  $ 923,033     $ 908,523  
                 
LIABILITIES AND PARTNERS' CAPITAL CURRENT LIABILITIES
               
Accounts payable - trade
  $ 181,812     $ 154,614  
Accounts payable - related party
    2,567       2,647  
Accrued liabilities
    14,266       17,537  
Total current liabilities
    198,645       174,798  
                 
LONG-TERM DEBT
    82,000       80,000  
DEFERRED TAX LIABILITIES
    18,461       20,087  
OTHER LONG-TERM LIABILITIES
    1,279       1,264  
MINORITY INTERESTS
    569       570  
COMMITMENTS AND CONTINGENCIES (Note 15)
               
                 
PARTNERS' CAPITAL:
               
Common unitholders, 38,253 units issued and outstanding
    605,974       615,265  
General partner
    16,105       16,539  
Total partners' capital
    622,079       631,804  
                 
TOTAL LIABILITIES AND PARTNERS' CAPITAL
  $ 923,033     $ 908,523  

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

-3-


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


   
Three Months Ended March 31,
 
   
2008
   
2007
 
REVENUES:
           
Supply and logistics:
           
Unrelated parties
  $ 429,393     $ 172,843  
Related parties
    725       436  
Refinery services
    43,912       -  
Pipeline transportation, including natural gas sales:
               
Transportation services - unrelated parties
    5,909       4,155  
Transportation services - related parties
    1,052       1,341  
Natural gas sales revenues
    1,324       1,292  
CO2 marketing revenues:
               
Unrelated parties
    3,163       2,867  
Related parties
    707       630  
Total revenues
    486,185       183,564  
COSTS AND EXPENSES:
               
Supply and logistics costs:
               
Product costs - unrelated parties
    407,275       167,711  
Product costs - related parties
    -       11  
Operating costs
    16,582       3,958  
Refinery services operating costs
    30,324       -  
Pipeline transportation costs:
               
Pipeline transportation operating costs
    2,356       2,685  
Natural gas purchases
    1,286       1,235  
CO2 marketing costs:
               
Transportation costs - related party
    1,257       1,098  
Other costs
    15       46  
General and administrative
    8,524       3,328  
Depreciation and amortization
    16,789       1,928  
Net loss (gain) on disposal of surplus assets
    18       (16 )
Total costs and expenses
    484,426       181,984  
OPERATING INCOME
    1,759       1,580  
Equity in earnings of joint ventures
    178       261  
Interest income
    117       44  
Interest expense
    (1,786 )     (270 )
INCOME BEFORE INCOME TAXES
    268       1,615  
Income tax benefit (expense)
    1,377       (30 )
NET INCOME
  $ 1,645     $ 1,585  
                 
NET INCOME PER COMMON UNIT - BASIC AND DILUTED
  $ 0.04     $ 0.11  
                 
WEIGHTED AVERAGE COMMON UNITS OUTSTANDING
               
BASIC
    38,253       13,784  
DILUTED
    38,297       13,784  
 
The accompanying notes are an integral part of these consolidated financial statements.
 
-4-

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


   
Partners' Capital
 
   
Number of
                   
   
Common
   
Common
   
General
       
   
Units
   
Unitholders
   
Partner
   
Total
 
                         
Partners' capital, January 1, 2008
    38,253     $ 615,265     $ 16,539     $ 631,804  
Net income
    -       1,612       33       1,645  
Cash distributions
    -       (10,903 )     (467 )     (11,370 )
Partners' capital, March 31, 2008
    38,253     $ 605,974     $ 16,105     $ 622,079  

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

-5-


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


   
Three Months Ended March 31,
 
   
2008
   
2007
 
CASH FLOWS FROM OPERATING ACTIVITIES:
           
Net income
  $ 1,645     $ 1,585  
Adjustments to reconcile net income to net cash provided by operating activities -
               
Depreciation and amortization
    16,789       1,928  
Amortization of credit facility issuance costs
    268       136  
Amortization of unearned income on direct financing leases
    (148 )     (159 )
Payments received under direct financing leases
    295       297  
Equity in earnings of investments in joint ventures
    (178 )     (261 )
Distributions from joint ventures - return on investment
    517       424  
Loss (gain) on disposal of assets
    18       (16 )
Non-cash effects of unit-based compensation plans
    (912 )     632  
Deferred tax benefit
    (1,626 )     -  
Other non-cash items
    (166 )     (245 )
Changes in components of operating assets and liabilities -
               
Accounts receivable
    (21,194 )     1,102  
Inventories
    (1,928 )     (3,562 )
Other current assets
    (371 )     808  
Accounts payable
    26,699       878  
Accrued liabilities and taxes payable
    (2,325 )     (1,810 )
Net cash provided by operating activities
    17,383       1,737  
                 
CASH FLOWS FROM INVESTING ACTIVITIES:
               
Payments to acquire fixed assets
    (6,439 )     (365 )
Distributions from joint ventures - return of investment
    161       227  
Investment in joint ventures and other investments
    (2,210 )     -  
Proceeds from disposal of assets
    245       16  
Other, net
    (463 )     (90 )
Net cash used in investing activities
    (8,706 )     (212 )
                 
CASH FLOWS FROM FINANCING ACTIVITIES:
               
Bank borrowings
    71,700       27,300  
Bank repayments
    (69,700 )     (25,100 )
Other, net
    274       (169 )
Distributions to common unitholders
    (10,903 )     (2,895 )
Distributions to general partner interest and minority interest owner
    (468 )     (59 )
Net cash used in financing activities
    (9,097 )     (923 )
                 
Net (decrease) increase in cash and cash equivalents
    (420 )     602  
Cash and cash equivalents at beginning of period
    11,851       2,318  
Cash and cash equivalents at end of period
  $ 11,431     $ 2,920  

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

-6-


GENESIS ENERGY, L.P.
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
 
1.  Organization and Basis of Presentation
 
Organization
 
We are a growth-oriented limited partnership focused on the midstream segment of the oil and gas industry in the Gulf Coast area of the United States.  We conduct our operations through our operating subsidiaries and joint ventures.  We manage our businesses through four divisions:
 
 
·
Pipeline transportation of crude oil, and, to a lesser degree, natural gas and carbon dioxide (or CO2);
 
 
·
Refinery services involving processing of high sulfur (or “sour”) gas streams for refineries to remove the sulfur, and sale of the related by-product, sodium hydrosulfide (or NaHS, commonly pronounced nash);
 
 
·
Industrial gas activities, including wholesale marketing of CO2 and processing of syngas through a joint venture; and
 
 
·
Supply and logistics services, which includes terminaling, blending, storing, marketing, and transporting by trucks of crude oil and petroleum products as well as dry goods.
 
Our 2% general partner interest is held by Genesis Energy, Inc., a Delaware corporation and an indirect, wholly-owned subsidiary of Denbury Resources Inc.  Denbury and its subsidiaries are hereafter referred to as Denbury.  Our general partner also owns 7.4% of our outstanding common units.
 
Our general partner manages our operations and activities and employs our officers and personnel, who devote 100% of their efforts to our management.
 
Basis of Consolidation and Presentation
 
The accompanying unaudited consolidated financial statements and related notes present our consolidated financial position as of March 31, 2008 and December 31, 2007 and our results of operations for the three months ended March 31, 2008 and 2007, our cash flows for the three months ended March 31, 2008 and 2007 and changes in partners’ capital for the three months ended March 31, 2008.  All intercompany transactions have been eliminated.  The accompanying unaudited consolidated financial statements include Genesis Energy, L.P., its operating subsidiary, Genesis Crude Oil, L.P., and its subsidiaries.  Our general partner owns a 0.01% general partner interest in Genesis Crude Oil, L.P., which is reflected in our financial statements as a minority interest.
 
In July 2007, we acquired the energy-related businesses of the Davison family.  The results of the operations of these businesses have been included in our consolidated financial statements since August 1, 2007.
 
We own a 50% interest in T&P Syngas Supply Company and a 50% interest in Sandhill Group, LLC.  These investments are accounted for by the equity method, as we exercise significant influence over their operating and financial policies.  See Note 7.
 
Accounting measurements at interim dates inherently involve greater reliance on estimates than at year end and the results of operations for the interim periods shown in this report are not necessarily indicative of results to be expected for the fiscal year.  The consolidated financial statements included herein have been prepared by us without audit pursuant to the rules and regulations of the Securities and Exchange Commission (SEC).  Accordingly, they reflect all adjustments (which consist solely of normal recurring adjustments) that are, in the opinion of management, necessary for a fair presentation of the financial results for interim periods.  Certain information and notes normally included in financial statements prepared in accordance with generally accepted accounting principles have been condensed or omitted pursuant to such rules and regulations.  However, we believe that the disclosures are adequate to make the information presented not misleading when read in conjunction with the information contained in the periodic reports we file with the SEC pursuant to the Securities Exchange Act of 1934, including the consolidated financial statements and notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2007.
 
Except per Unit amounts, or as noted within the context of each footnote disclosure, the dollar amounts presented in the tabular data within these footnote disclosures are stated in thousands of dollars.
 

GENESIS ENERGY, L.P.
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
 
2.  Recent Accounting Developments
 
Implemented
 
SFAS 157
 
We adopted Statement of Financial Accounting Standards (SFAS) No. 157, “Fair Value Measurements” (SFAS 157), with respect to financial assets and financial liabilities that are regularly adjusted to fair value, as of January 1, 2008.  SFAS 157 provides a common fair value hierarchy to follow in determining fair value measurements in the preparation of financial statements and expands disclosure requirements relating to how such measurements were developed. SFAS 157 does not require any new fair value measurements, but rather applies to all other accounting pronouncements that require or permit fair value measurements.  On February 12, 2008 the Financial Accounting Standards Board (FASB) issued Staff Position No. 157-2, “Effective Date of FASB Statement No. 157” (FSP 157-2) which amends SFAS 157 to delay the effective date for all non-financial assets and non-financial liabilities, except for those that are recognized at fair value in the financial statements on a recurring basis.  The partial adoption of SFAS 157 as described above had no material impact on us.  We have not yet determined the impact, if any, that the second phase of the adoption of SFAS 157 in 2009 will have relating to its fair value measurements of non-financial assets and non-financial liabilities.  See Note 17 for further information regarding fair-value measurements.
 
SFAS 159
 
In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities” (SFAS 159).  This statement became effective for us as of January 1, 2008. SFAS 159 permits entities to choose to measure many financial instruments and certain other items at fair value that are not currently required to be measured at fair value. We did not elect to utilize voluntary fair value measurements as permitted by the standard.
 
Pending
 
SFAS 141(R)
 
In December 2007, the FASB issued SFAS No. 141(R) “Business Combinations” (SFAS 141(R)).  SFAS 141(R) replaces FASB Statement No. 141, “Business Combinations.”  This statement retains the purchase method of accounting used in business combinations but replaces SFAS 141 by establishing principles and requirements for the recognition and measurement of assets, liabilities and goodwill, including the requirement that most transaction costs and restructuring costs be charged to expense as incurred.  In addition, the statement requires disclosures to enable users of the financial statements to evaluate the nature and financial effects of the business combination.  SFAS 141(R) is effective for business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008.  We will adopt SFAS 141(R) on January 1, 2009 for acquisitions on or after that date.
 
SFAS 160
 
In December 2007, the FASB issued SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements - an amendment of ARB No. 51” (SFAS 160). This statement establishes accounting and reporting standards for noncontrolling interests, which have been referred to as minority interests in prior literature.  A noncontrolling interest is the portion of equity in a subsidiary not attributable, directly or indirectly, to a parent company.  This new standard requires, among other things, that (i) ownership interests of noncontrolling interests be presented as a component of equity on the balance sheet (i.e. elimination of the mezzanine “minority interest” category); (ii) elimination of minority interest expense as a line item on the statement of operations and, as a result, that net income be allocated between the parent and the noncontrolling interests on the face of the statement of operations; and (iii) enhanced disclosures regarding noncontrolling interests.  SFAS 160 is effective for fiscal years beginning after December 15, 2008.  We will adopt SFAS 160 on January 1, 2009.  We are assessing the impact of this statement on our financial statements and expect it to impact the presentation of the minority interest in our operating partnership.
 

GENESIS ENERGY, L.P.
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
 
SFAS 161
 
 In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities-an amendment of FASB Statement No.133” (SFAS 161). This Statement requires enhanced disclosures about our derivative and hedging activities. This statement is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008. We will adopt SFAS No. 161 beginning January 1, 2009. We are currently evaluating the impact, if any, that the standard will have on our consolidated financial statements.
 
EITF 07-4
 
In March 2008, the FASB ratified the consensus reached by the Emerging Issues Task Force (or EITF) of the FASB in issue EITF 07-4, “Application of the Two-Class Method under FASB Statement No. 128, Earnings per Share, to Master Limited Partnerships.”  Under this consensus, the computation of earnings per unit will be affected by the incentive distribution rights (“IDRs”) we are contractually obligated to distribute at the end of the current reporting period.  In periods when earnings are in excess of cash distributions, we will reduce net income or loss for the current reporting period by the amount of available cash that will be distributed to our limited partners and general partner for its general partner interest and incentive distribution rights for the reporting period, and the remainder will be allocated to the limited partner and general partner in accordance with their ownership interests.  When cash distributions exceed current-period earnings, net income or loss will be reduced (or increased) by cash distributions, and the resulting excess of distributions over earnings will be allocated to the general partner and limited partner based on their respective sharing of losses.  EITF 07-4 is effective for fiscal years beginning after December 15, 2008, and interim periods within those fiscal years.  We are currently evaluating the impact of EITF 07-4; however we expect it to have an impact on our presentation of earnings per unit beginning in 2009.  For additional information on our incentive distribution rights, see Note 9.
 
3.  Acquisitions
 
2007 Davison Businesses Acquisition
 
On July 25, 2007, we acquired five energy-related businesses from several entities owned and controlled by the Davison family of Ruston, Louisiana (the “Davison Acquisition”) for total consideration of $623 million (including cash and common units), net of cash acquired and direct transaction costs totaling $8.9 million.  The businesses include the operations that comprise our refinery services division, and other operations included in our supply and logistics division, which transport, store, procure, and market petroleum products and other bulk commodities.  The assets acquired in this transaction provide us with opportunities to expand our services to energy companies in the areas in which we operate.
 
The purchase price was allocated to the assets acquired and liabilities assumed based on estimated fair values. The purchase price allocation was adjusted during the first quarter of 2008 for differences in working capital and property and equipment acquired.   These adjustments reduced the amount of the purchase price allocated to goodwill.  See additional information on intangible assets and goodwill in Note 6.
 
2007 Port Hudson Assets Acquisition
 
Effective July 1, 2007, we paid $8.1 million for BP Pipelines (North America) Inc.’s Port Hudson crude oil truck terminal, marine terminal, and marine dock on the Mississippi River, which includes 215,000 barrels of tankage, a pipeline and other related assets in East Baton Rouge Parish, Louisiana.  The purchase price was allocated to the assets acquired based on estimated fair values.  See additional information on goodwill in Note 6.
 
4.  Inventories
 
Inventories are valued at the lower of cost or market.  The costs of inventories did not exceed market values at March 31, 2008 and December 31, 2007.  The major components of inventories were as follows:

GENESIS ENERGY, L.P.
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
 
   
March 31, 2008
   
December 31, 2007
 
             
Crude oil
  $ 4,475     $ 3,710  
Petroleum products
    6,277       6,527  
Caustic soda
    3,432       1,998  
NaHS
    3,601       3,557  
Other
    130       196  
Total inventories
  $ 17,915     $ 15,988  

 
5.  Fixed Assets and Asset Retirement Obligations
 
Fixed assets consisted of the following:
 
   
March 31, 2008
   
December 31, 2007
 
             
Land, buildings and improvements
  $ 12,417     $ 11,978  
Pipelines and related assets
    64,268       63,169  
Machinery and equipment
    26,314       25,097  
Transportation equipment
    32,818       32,906  
Office equipment, furniture and fixtures
    3,313       2,759  
Construction in progress
    6,688       7,102  
Other
    11,654       7,402  
Subtotal
    157,472       150,413  
Accumulated depreciation
    (52,445 )     (48,413 )
Total
  $ 105,027     $ 102,000  
 
Asset Retirement Obligations
 
In general, our future asset retirement obligations relate to future costs associated with the removal of our oil, natural gas and CO2 pipelines, removal of equipment and facilities from leased acreage and land restoration. The fair value of a liability for an asset retirement obligation is recorded in the period in which it is incurred, discounted to its present value using our credit adjusted risk-free interest rate, and a corresponding amount capitalized by increasing the carrying amount of the related long-lived asset. The capitalized cost is depreciated over the useful life of the related asset.  Accretion of the discount increases the liability and is recorded to expense.

The following table summarizes the changes in our asset retirement obligations for the three months ended March 31, 2008.
 
Asset retirement obligations as of December 31, 2007
  $ 1,173  
Accretion expense
    18  
Asset retirement obligations as of March 31, 2008
  $ 1,191  
 
At March 31, 2008, $0.1 million of our asset retirement obligation was classified in “Accrued liabilities” under current liabilities in our Unaudited Consolidated Balance Sheets.  Certain of our unconsolidated affiliates have asset retirement obligations recorded at March 31, 2008 and December 31, 2007 relating to contractual agreements.  These amounts are immaterial to our financial statements.

-10-


GENESIS ENERGY, L.P.
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
 
6.  Intangible Assets and Goodwill
 
Intangible Assets
 
In connection with the Davison acquisition (See Note 3), we allocated a portion of the purchase price to intangible assets based on their fair values.  The following table reflects the components of intangible assets being amortized at the dates indicated:
 
         
March 31, 2008
   
December 31, 2007
 
   
Weighted Amortization Period in Years
   
Gross Carrying Amount
   
Accumulated Amortization
   
Carrying Value
   
Gross Carrying Amount
   
Accumulated Amortization
   
Carrying Value
 
                                           
Refinery services customer relationships
 
3
    $ 94,654     $ 13,539     $ 81,115     $ 94,654     $ 9,380     $ 85,274  
Supply and logistics customer relationships
 
5
      34,630       4,992       29,638       34,630       3,287       31,343  
Refinery services supplier relationships
 
2
      36,469       13,079       23,390       36,469       9,241       27,228  
Refinery services licensing agreements
 
6
 
    38,678       3,458       35,220       38,678       2,218       36,460  
Supply and logistics trade name
 
7
 
    17,988       1,463       16,525       17,988       930       17,058  
Supply and logistics favorable lease
 
15
      13,260       316       12,944       13,260       197       13,063  
Other
 
3
      722       155       567       721       97       624  
Total
 
5
    $ 236,401     $ 37,002     $ 199,399     $ 236,400     $ 25,350     $ 211,050  
 
The licensing agreements referred to in the table above relate to the agreements we have with refiners to provide services.  The trade name is the Davison name, which we retained the right to use in our operations.  The favorable lease relates to a lease of a terminal facility in Shreveport, Louisiana.
 
We are recording amortization of our intangible assets based on the period over which the asset is expected to contribute to our future cash flows.  Generally, the contribution to our cash flows of the customer and supplier relationships, licensing agreements and trade name intangible assets is expected to decline over time, such that greater value is attributable to the periods shortly after the acquisition was made.  The favorable lease and other intangible assets are being amortized on a straight-line basis.  Amortization expense on intangible assets was $11.7 million for the three months ended March 31, 2008.
 
Estimated amortization expense for each of the five subsequent fiscal years is expected to be as follows:
 
   
Amortization
 
   
Expense to
 
Year Ended December 31
 
be Recorded
 
Remainder of 2008
  $ 34,715  
2009
  $ 32,176  
2010
  $ 25,575  
2011
  $ 20,943  
2012
  $ 17,511  
2013
  $ 14,107  

-11-


GENESIS ENERGY, L.P.
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
 
Goodwill
 
In connection with the Davison and Port Hudson acquisitions, the residual of the purchase price over the fair values of the net tangible and identifiable intangible assets acquired was allocated to goodwill.  The carrying amount of goodwill by business segment at March 31, 2008 was $296.8 million to refinery services and $23.1 million to supply and logistics.
 
7.  Joint Ventures and Other Investments
 
T&P Syngas Supply Company
 
We own a 50% interest in T&P Syngas Supply Company (“T&P Syngas”), a Delaware general partnership.  Praxair Hydrogen Supply Inc. (“Praxair”) owns the remaining 50% partnership interest in T&P Syngas.  T&P Syngas is a partnership that owns a syngas manufacturing facility located in Texas City, Texas.  That facility processes natural gas to produce syngas (a combination of carbon monoxide and hydrogen) and high pressure steam.  Praxair provides the raw materials to be processed and receives the syngas and steam produced by the facility under a long-term processing agreement.  T&P Syngas receives a processing fee for its services.  Praxair operates the facility.
 
We are accounting for our 50% ownership in T&P Syngas under the equity method of accounting.  We reflect in our Unaudited Consolidated Statements of Operations our equity in T&P Syngas’ net income, net of the amortization of the excess of our investment over our share of partners’ capital of T&P Syngas.  We paid $4.0 million more for our interest in T&P Syngas than our share of partners’ capital on the balance sheet of T&P Syngas at the date of the acquisition.  This excess amount of the purchase price over the equity in T&P Syngas is being amortized using the straight-line method over the remaining useful life of the assets of T&P Syngas of eleven years.  Our Unaudited Consolidated Statements of Operations for the three months ended March 31, 2008 and 2007 included $0.3 million and $0.4 million, respectively, as our share of the operating earnings of T&P Syngas, reduced by amortization of the excess purchase price of $0.1 million in each period.  We received distributions from T&P Syngas of $0.6 million for both the three months ended March 31, 2008 and 2007.
 
The tables below reflect summarized financial information for T&P Syngas:
 
 
   
Three Months Ended
   
Three Months Ended
 
   
March 31, 2008
   
March 31, 2007
 
             
Revenues
  $ 1,209     $ 1,308  
Operating expenses and depreciation
    (367 )     (438 )
Other (expense) income
    (7 )     5  
Net income
  $ 835     $ 875  
 
 
   
March 31, 2008
   
December 31, 2007
 
             
Current assets
  $ 2,628     $ 2,562  
Non-current assets
    19,932       20,243  
Total assets
  $ 22,560     $ 22,805  
                 
Current liabilities
  $ 365     $ 341  
Non-current liabilities
    185       180  
Partners' capital
    22,010       22,284  
Total liabilities and partners' capital
  $ 22,560     $ 22,805  

-12-


GENESIS ENERGY, L.P.
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
 
Sandhill Group, LLC
 
We own a 50% interest in Sandhill Group, LLC (“Sandhill”).  At March 31, 2008, Reliant Processing Ltd. held the other 50% interest in Sandhill.  Sandhill 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, beverage, chemical and oil industries. The facility acquires CO2 from us under a long-term supply contract that we acquired in 2005 from Denbury.
 
We are accounting for our 50% ownership in Sandhill under the equity method of accounting.  We reflect in our Unaudited Consolidated Statements of Operations our equity in Sandhill’s net income, net of the amortization of the excess of our investment over our share of partners’ capital of Sandhill that is not considered goodwill.
 
Our Unaudited Consolidated Statements of Operations for the three months ended March 31, 2008 and 2007 included $36,000 and $9,000, respectively, as our share of the operating earnings of Sandhill, reduced by amortization of the excess purchase price of $69,000 in each period.  We received distributions from Sandhill of $124,000 and $60,000 during the three months ended March 31, 2008 and 2007, respectively.
 
Other Projects
 
We have invested $4.5 million in the Faustina Project, a petroleum coke to ammonia project that is in the development stage.  All of our investment may later be redeemed, with a return, or converted to equity after the project has obtained construction financing.  The funds we have invested are being used for project development activities, which include the negotiation of off-take agreements for the products and by-products of the plant to be constructed, securing permits and securing financing for the construction phase of the plant.  We have recorded our investment in this debt security at cost and classified it as held-to-maturity, since we have the intent and ability to hold it until it is redeemed.
 
No events or changes in circumstances have occurred that indicate a significant adverse effect on the fair value of our investment at March 31, 2008, therefore our investment is included in our Unaudited Consolidated Balance Sheet at cost.
 
8.  Debt
 
Our credit facility, with a maximum facility amount of $500 million, of which $100 million can be used for letters of credit, is with a group of banks led by Fortis Capital Corp. and Deutsche Bank Securities Inc.  The maximum facility amount represents the amount the banks have committed to fund pursuant to the terms of the credit agreement.  The borrowing base is recalculated quarterly and at the time of material acquisitions.  The borrowing base represents the amount that can be borrowed or utilized for letters of credit from a credit standpoint based on our EBITDA (earnings before interest, taxes, depreciation and amortization), computed in accordance with the provisions of our credit facility.
 
The borrowing base may be increased to the extent of pro forma additional EBITDA, (as defined in the credit agreement), attributable to acquisitions or internal growth projects with approval of the lenders.  Our borrowing base as of March 31, 2008 was $361 million.
 
At March 31, 2008, we had $82 million borrowed under our credit facility and we had $7 million in letters of credit outstanding.  Due to the revolving nature of loans under our credit facility, additional borrowings and periodic repayments and re-borrowings may be made until the maturity date of November 15, 2011.  The total amount available for borrowings at March 31, 2008 was $272 million under our credit facility.
 
The key terms for rates under our credit facility are as follows:
 
 
·
The interest rate on borrowings may be based on the prime rate or the LIBOR rate, at our option.  The interest rate on prime rate loans can range from the prime rate plus 0.50% to the prime rate plus 1.875%.  The interest rate for LIBOR-based loans can range from the LIBOR rate plus 1.50% to the LIBOR rate plus 2.875%.  The rate is based on our leverage ratio as computed under the credit facility.  Our leverage ratio is recalculated quarterly and in connection with each material acquisition.   At March 31, 2008, our borrowing rates were the prime rate plus 1.25% or the LIBOR rate plus 2.25%.  On April 1, 2008, the additional margin for prime rate borrowings and LIBOR rate borrowings declined to 0.50% and 1.50%, respectively.

 
GENESIS ENERGY, L.P.
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
 
 
·
Letter of credit fees will range from 1.50% to 2.875% based on our leverage ratio as computed under the credit facility.  The rate can fluctuate quarterly.  At March 31, 2008, our letter of credit rate was 2.25%.  On April 1, 2008, this rate declined to 1.50%.
 
 
·
We pay a commitment fee on the unused portion of the $500 million maximum facility amount.  The commitment fee will range from 0.30% to 0.50% based on our leverage ratio as computed under the credit facility.  The rate can fluctuate quarterly.  At March 31, 2008, the commitment fee rate was 0.50%.  On April 1, 2008, this rate declined to 0.30%.
 
Collateral under the credit facility consists of substantially all our assets. While our general partner is jointly and severally liable for all of our obligations unless and except to the extent those obligations provide that they are non-recourse to our general partner, our credit facility expressly provides that it is non-recourse to our general partner (except to the extent of its pledge of its general partner interest in certain of our subsidiaries), as well as to Denbury and its other subsidiaries.
 
Our credit facility contains customary covenants (affirmative, negative and financial) that limit the manner in which we may conduct our business.  Our credit facility contains three primary financial covenants - a debt service coverage ratio, leverage ratio and funded indebtedness to capitalization ratio – that require us to achieve specific minimum financial metrics.  In general, our debt service coverage ratio calculation compares EBITDA (as defined and adjusted in accordance with the credit facility) to interest expense.  Our leverage ratio calculation compares our consolidated funded debt (as calculated in accordance with our credit facility) to EBITDA (as adjusted).  Our funded indebtedness ratio compares outstanding debt to the sum of our consolidated total funded debt plus our consolidated net worth.
 
       
Required
 
Actual
       
Ratio
 
Ratio as of
       
through
 
March 31,
Financial Covenant
 
Requirement
 
June 30, 2008
 
2008
             
Debt Service Coverage Ratio
 
Minimum
 
2.75 to 1.0
 
4.1 to 1.0
Leverage Ratio
 
Maximum
 
6.0 to 1.0
 
1.2 to 1.0
Funded Indebtedness Ratio
 
Maximum
 
0.8 to 1.0
 
0.1 to 1.0
 
Our credit facility includes provisions for the temporary adjustment of the required ratios following material acquisitions and with lender approval.  The ratios in the table above are the required ratios for the period following a material acquisition.  If we meet these financial metrics and are not otherwise in default under our credit facility, we may make quarterly distributions; however, the amount of such distributions may not exceed the sum of the distributable cash generated by us for the eight most recent quarters, less the sum of the distributions made with respect to those quarters.  At March 31, 2008, the excess of distributable cash over distributions under this provision of the credit facility was $42.6 million.
 
The carrying value of our debt under our credit facility approximates fair value primarily because interest rates fluctuate with prevailing market rates, and the applicable margin on outstanding borrowings reflect what we believe is market.
 
9.  Partners’ Capital and Distributions
 
Partners’ Capital
 
Partner’s capital at March 31, 2008 consists of 38,253,264 common units, including 2,829,055 units owned by our general partner, representing a 98% aggregate ownership interest in the Partnership and its subsidiaries (after giving affect to the general partner interest), and a 2% general partner interest.

 

GENESIS ENERGY, L.P.
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
 
Our general partner owns all of our general partner interest, including incentive distribution rights, all of the 0.01% general partner interest in our operating partnership (which is reflected as a minority interest in the Unaudited Consolidated Balance Sheet at March 31, 2008) and operates our business.
 
Our partnership agreement authorizes our general partner to cause us to issue additional limited partner interests and other equity securities, the proceeds from which could be used to provide additional funds for acquisitions or other needs.
 
Distributions
 
Generally, we will distribute 100% of our available cash (as defined by our partnership agreement) within 45 days after the end of each quarter to unitholders of record and to our general partner.  Available cash consists generally of all of our cash receipts less cash disbursements adjusted for net changes to reserves.  As discussed in Note 8, our credit facility limits the amount of distributions we may pay in any quarter.
 
Pursuant to our partnership agreement, our general partner receives incremental incentive cash distributions when unitholders’ cash distributions exceed certain target thresholds, in addition to its 2% general partner interest.  The allocations of distributions between our common unitholders and our general partner, including the incentive distribution rights is as follows:
 
         
General
 
   
Unitholders
   
Partner
 
Quarterly Cash Distribution per Common Unit:
           
Up to and including $0.25 per Unit
    98.00 %     2.00 %
First Target - $0.251 per Unit up to and including $0.28 per Unit
    84.74 %     15.26 %
Second Target - $0.281 per Unit up to and including $0.33 per Unit
    74.26 %     25.74 %
Over Second Target - Cash distributions greater than $0.33 per Unit
    49.02 %     50.98 %
 
We paid or will pay the following distributions in 2007 and 2008:
 
                       
General
       
           
Limited
   
General
   
Partner
       
           
Partner
   
Partner
   
Incentive
       
     
Per Unit
   
Interests
   
Interest
   
Distribution
   
Total
 
Distribution For
Date Paid
 
Amount
   
Amount
   
Amount
   
Amount
   
Amount
 
                                 
Fourth quarter 2006
February 2007
  $ 0.210     $ 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  
Fourth quarter 2007
February 2008
  $ 0.285     $ 10,903     $ 222     $ 245     $ 11,370  
First quarter 2008
May 2008 (2)
  $ 0.300     $ 11,476     $ 234     $ 429     $ 12,139  

(1)  The distribution paid on August 14, 2007 to holders of our common units is net of the amounts payable with respect to the common units issued in connection with the Davison transaction.  The Davison unitholders and our general partner waived their rights to receive such distributions, instead receiving purchase price adjustments with us.
 
(2)  This distribution will be paid on May 15, 2008 to the general partner and unitholders of record as of May 9, 2008.
 
Net (Loss) Income Per Common Unit
 
Subject to the applicability of Emerging Issues Task Force Issue No. 03-6 (“EITF 03-6”), Participating Securities and the Two-Class Method under Financial Accounting Standards Board Statement No. 128,” as discussed below, our net income is first allocated to the general partner based on the amount of incentive distributions.  The remainder is then allocated 98% to the limited partners and 2% to the general partner.  Basic net income per limited partner unit is determined by dividing net income attributable to limited partners by the weighted average number of outstanding limited partner units during the period.  Diluted net income per common unit is calculated in the same manner, but also considers the impact to common units for the potential dilution from phantom units outstanding.

-15-


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

In a period of net operating losses, incremental phantom units are excluded from the calculation of diluted earnings per unit due to their anti-dilutive effect.

EITF 03-6 addresses the computation of earnings per share by entities that have issued securities other than common stock that contractually entitle the holder to participate in dividends and earnings of the entity when, and if, it declares dividends on its common stock (or partnership distributions to unitholders).  EITF 03-06 applies to any accounting period where our aggregate net income exceeds our aggregate distribution.  In such periods, we are required to present earnings per unit as if all of the earnings for the periods were distributed, regardless of the pro forma nature of this allocation and whether those earnings would actually be distributed from an economic or practical perspective.  EITF 03-6 does not impact our overall net income or other financial results; however, for periods in which aggregate net income exceeds our aggregate distributions for such period, it will have the impact of reducing the earnings per limited partner units.  This result occurs as a larger portion of our aggregate earnings is allocated (as if distributed) to our general partner, even though we make cash distributions on the basis of cash available for distributions, not earnings, in any given period.  Our aggregate net earnings have not exceeded our aggregate distributions; therefore EITF 03-6 has not had an impact on our calculation of earnings per unit.  EITF 07-4, which will be effective for us beginning in 2009, will change the allocation of net income among our general partner and limited partners as described in Note 2.
 
The following table sets forth the computation of basic net income per common unit.
 
   
Three Months Ended March 31,
 
   
2008
   
2007
 
Numerators for basic and diluted net income per common unit:
           
Net income
  $ 1,645     $ 1,585  
Less general partner 2% ownership
    33       32  
Net income available for common unitholders
  $ 1,612     $ 1,553  
                 
Denominator for basic per common unit:
               
Common Units
    38,253       13,784  
                 
Denominator for diluted per common unit:
               
Common Units
    38,253       13,784  
    Phantom Units
    44       -  
      38,297       13,784  
                 
Basic and diluted net income per common unit
  $ 0.04     $ 0.11  
 
10.  Business Segment Information
 
Our operations consist of four operating segments:  (1) Pipeline Transportation – interstate and intrastate crude oil, and to a lesser extent, natural gas and CO2 pipeline transportation; (2) Refinery Services – processing high sulfur (or “sour”) gas streams as part of refining operations to remove the sulfur and sale of the related by-product; (3) Industrial Gases – the sale of CO2 acquired under volumetric production payments to industrial customers and our investment in a syngas processing facility, and (4) Supply and Logistics – terminaling, blending, storing, marketing, gathering, and transporting by truck crude oil and petroleum products and other dry goods.  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. 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.  The tables below reflect our segment information as though the current segment designations had existed in all periods presented.

GENESIS ENERGY, L.P.
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
 
We evaluate segment performance based on segment margin.  We calculate segment margin as revenues less costs of sales and operating expenses, and we include income from investments in joint ventures. We do not deduct depreciation and amortization.  All of our revenues are derived from, and all of our assets are located in, the United States.  The pipeline transportation segment information includes the revenue, segment margin and assets of our direct financing leases.
 
 
   
Pipeline
   
Refinery
   
Industrial
   
Supply &
       
   
Transportation
   
Services
   
Gases (a)
   
Logistics
   
Total
 
       
Three Months Ended March 31, 2008
                             
Segment margin excluding depreciation and amortization (b)
  $ 4,643     $ 13,588     $ 2,776     $ 6,261     $ 27,268  
                                         
Capital expenditures
  $ 1,278     $ 1,151     $ 2,210     $ 4,603     $ 9,242  
Maintenance capital expenditures
  $ 165     $ 281     $ -     $ 330     $ 776  
Net fixed and other long-term assets (c)
  $ 33,223     $ 458,083     $ 48,060     $ 147,867     $ 687,233  
                                         
Revenues:
                                       
External customers
  $ 6,788     $ 43,912     $ 3,870     $ 430,118     $ 484,688  
Intersegment (d)
    1,497       -       -       -       1,497  
Total revenues of reportable segments
  $ 8,285     $ 43,912     $ 3,870     $ 430,118     $ 486,185  
                                         
Three Months Ended March 31, 2007
                                       
Segment margin excluding depreciation and amortization (b)
  $ 2,868       -     $ 2,614     $ 1,599     $ 7,081  
                                         
Capital expenditures
  $ 293       -     $ -     $ 93     $ 386  
Maintenance capital expenditures
  $ 222       -     $ -     $ 93     $ 315  
Net fixed and other long-term assets (c)
  $ 31,478       -     $ 50,287     $ 7,683     $ 89,448  
                                         
Revenues:
                                       
External customers
  $ 5,660       -     $ 3,497     $ 173,279     $ 182,436  
Intersegment (d)
    1,128       -       -       -       1,128  
Total revenues of reportable segments
  $ 6,788       -     $ 3,497     $ 173,279     $ 183,564  

-17-


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

 
a)
Industrial gases includes our CO2 marketing operations and our equity income from our investments in T&P Syngas and Sandhill.
 
b)
Segment margin was calculated as revenues less cost of sales and operating expenses, excluding depreciation and amortization.  It includes our share of the operating income of equity joint ventures.  A reconciliation of segment margin to income before income taxes for the periods presented is as follows:


   
Three Months Ended March 31,
 
   
2008
   
2007
 
       
Segment margin excluding depreciation and amortization
  $ 27,268     $ 7,081  
General and administrative expenses
    (8,524 )     (3,328 )
Depreciation and amortization expense
    (16,789 )     (1,928 )
                 
Net (loss) gain on disposal of surplus assets
    (18 )     16  
Interest expense, net
    (1,669 )     (226 )
Income before income taxes
  $ 268     $ 1,615  

 
c)
Net fixed and other long-term assets are the measure used by management in evaluating the results of its operations on a segment basis.  Current assets are not allocated to segments as the amounts are shared by the segments or are not meaningful in evaluating the success of the segment’s operations.
 
d)
Intersegment sales were conducted on an arm’s length basis.

11.  Transactions with Related Parties
 
Sales, purchases and other transactions with affiliated companies, in the opinion of management, are conducted under terms no more or less favorable than then-existing market conditions.  The transactions with related parties were as follows:
 
   
Three Months Ended March 31,
 
   
2008
   
2007
 
             
Truck transportation services provided to Denbury
  $ 458     $ 436  
Pipeline transportation services provided to Denbury
  $ 1,295     $ 1,224  
Payments received under direct financing leases from Denbury
  $ 295     $ 297  
Pipeline transportation income portion of direct financing lease fees with Denbury
  $ 162     $ 158  
Pipeline monitoring services provided to Denbury
  $ 30     $ 30  
Directors' fees paid to Denbury
  $ 30     $ 30  
CO2 transportation services provided by Denbury
  $ 1,257     $ 1,128  
Crude oil purchases from Denbury
  $ -     $ 11  
Operations, general and administrative services provided by our general partner
  $ 14,328     $ 6,071  
Distributions to our general partner on its limited partner units and general partner interest
  $ 1,274     $ 273  
Sales of CO2 to Sandhill
  $ 707     $ 630  
Petroleum products sales to Davison family businesses
  $ 266     $ -  

-18-


GENESIS ENERGY, L.P.
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
 
Transportation Services
 
We provide truck transportation services to Denbury to move their crude oil from the wellhead to our Mississippi pipeline.  Denbury pays us a fee for this trucking service that varies with the distance the crude oil is trucked.  These fees are reflected in the statement of operations as supply and logistics revenues.
 
Denbury is the only shipper on our Mississippi pipeline other than us, and we earn tariffs for transporting their oil.  We also earned fees from Denbury under the direct financing lease arrangements for the Olive and Brookhaven crude oil pipelines and the Brookhaven CO2 pipeline and recorded pipeline transportation income from these arrangements.
 
We also provide pipeline monitoring services to Denbury.  This revenue is included in pipeline revenues in the unaudited statements of operations.
 
Directors’ Fees
 
We paid Denbury for the services of each of four of Denbury’s officers who serve as directors of our general partner, at an annual rate that is $10,000 per person less than the rate at which our independent directors were paid.
 
CO2 Operations and Transportation
 
Denbury charges us a transportation fee of $0.16 per Mcf (adjusted for inflation) to deliver CO2 for us to our customers.   In the first three months of 2008, the inflation-adjusted transportation fee averaged $0.1895 per Mcf.
 
Operations, General and Administrative Services
 
We do not directly employ any persons to manage or operate our business.  Those functions are provided by our general partner.  We reimburse the general partner for all direct and indirect costs of these services.
 
Amounts due to and from Related Parties
 
At March 31, 2008 and December 31, 2007, we owed Denbury $1.0 million, respectively, for purchases of crude oil and CO2 transportation charges.  Denbury owed us $0.9 million for transportation services at March 31, 2008 and December 31, 2007, respectively.  We owed our general partner $1.5 million and $0.7 million for administrative services at March 31, 2008 and December 31, 2007, respectively.  At March 31, 2008 and December 31, 2007, Sandhill owed us $0.7 and $0.5 million for purchases of CO2, respectively.  At December 31, 2007, we owed the Davison family entities $0.8 million for reimbursement of costs paid primarily related to employee transition services.
 
Financing
 
Our general partner, a wholly owned subsidiary of Denbury, guarantees our obligations under our credit facility.  Our general partner’s principal assets are its general and limited partnership interests in us.  Our credit agreement obligations are not guaranteed by Denbury or any of its other subsidiaries.  Our credit facility is non-recourse to our general partner, except to the extent of its pledge of its 0.01% general partner interest in our operating partnership.
 
We guarantee 50% of the obligation of Sandhill to a bank.  At March 31, 2008, the total amount of Sandhill’s obligation to the bank was $3.6 million; therefore, our guarantee was for $1.8 million.
 
12.  Major Customers and Credit Risk
 
Due to the nature of our supply and logistics operations, a disproportionate percentage of our trade receivables consists of obligations of oil companies.  This industry concentration has the potential to impact our overall exposure to credit risk, either positively or negatively, in that our customers could be affected by similar changes in economic, industry or other conditions.  However, we believe that the credit risk posed by this industry concentration is offset by the creditworthiness of our customer base.  Our portfolio of accounts receivable is comprised in large part of integrated and large independent energy companies with stable payment experience.  The credit risk related to contracts which are traded on the NYMEX is limited due to the daily cash settlement procedures and other NYMEX requirements.

GENESIS ENERGY, L.P.
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
 
We have established various procedures to manage our credit exposure, including initial credit approvals, credit limits, collateral requirements and rights of offset.  Letters of credit, prepayments and guarantees are also utilized to limit credit risk to ensure that our established credit criteria are met.
 
Shell Oil Company accounted for 18% of total revenues in the first quarter of 2008.  Shell Oil Company, Occidental Energy Marketing, Inc., and Calumet Specialty Products Partners, L.P. accounted for 23%, 20% and 12% of total revenues in the first quarter of 2007, respectively.  The majority of the revenues from these customers in both periods relate to our crude oil supply and logistics operations.
 
13.  Supplemental Cash Flow Information
 
Cash received by us for interest for the three months ended March 31, 2008 and 2007 was $78,000 and $27,000, respectively.  Payments of interest and commitment fees were $2,398,000 and $20,000 for the three months ended March 31, 2008 and 2007, respectively.
 
Cash paid for income taxes during the three months ended March 31, 2008 was $62,000.
 
At March 31, 2008, we had incurred liabilities for fixed asset and other asset additions totaling $1.3 million that had not been paid at the end of the first quarter, and, therefore, are not included in the caption “Payments to acquire fixed assets” and “Other, net” under investing activities on the Unaudited Consolidated Statements of Cash Flows.
 
14.  Derivatives
 
Our market risk in the purchase and sale of crude oil and petroleum products contracts is the potential loss that can be caused by a change in the market value of the asset or commitment.  In order to hedge our exposure to such market fluctuations, we may enter into various financial contracts, including futures, options and swaps.  Historically, any contracts we have used to hedge market risk were less than one year in duration, although we have the flexibility to enter into arrangements with a longer term.
 
We may utilize crude oil futures contracts and other financial derivatives to reduce our exposure to unfavorable changes in crude oil, fuel oil and petroleum products prices.  Every derivative instrument (including certain derivative instruments embedded in other contracts) must be recorded in the balance sheet as either an asset or liability measured at its fair value.  Changes in the derivative’s fair value must be recognized currently in earnings unless specific hedge accounting criteria are met.  Special accounting for qualifying hedges allows a derivative’s gains and losses to offset related results on the hedged item in the income statement.  Companies must formally document, designate, and assess the effectiveness of transactions that receive hedge accounting.
 
We mark to fair value our derivative instruments at each period end, with changes in the fair value of derivatives that are not designated as hedges being recorded as unrealized gains or losses.  Such unrealized gains or losses will change, based on prevailing market prices, at each balance sheet date prior to the period in which the transaction actually occurs.  The effective portion of unrealized gains or losses on derivative transactions qualifying as cash flow hedges are reflected in other comprehensive income.  Derivative transactions qualifying as fair value hedges are evaluated for hedge effectiveness and the resulting hedge ineffectiveness is recorded as a gain or loss in the consolidated statements of operations.
 
We review our contracts to determine if the contracts meet the definition of derivatives pursuant to SFAS 133, “Accounting for Derivative Instruments and Hedging Activities.”  At March 31, 2008, we had futures contracts that were considered free-standing derivatives that are accounted for at fair value.  The fair value of these contracts was determined based on the closing price for such contracts on March 31, 2008.  We marked these contracts to fair value at March 31, 2008.  During the three months ended March 31, 2008, we recorded losses of $1.0 million related to derivative transactions, which are included in the Unaudited Consolidated Statements of Operations under the caption “Supply and logistics costs.”  We did not utilize any derivatives that were accounted for as hedges during the three months ended March 31, 2008.
 
The consolidated balance sheet at March 31, 2008 includes a decrease in other current assets of $0.3 million as a result of these derivative transactions.  The consolidated balance sheet at December 31, 2007 included a decrease in other current assets of $0.7 million as a result of derivative transactions.

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GENESIS ENERGY, L.P.
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
 
We determined that the remainder of our derivative contracts qualified for the normal purchase and sale exemption and were designated and documented as such at March 31, 2008 and December 31, 2007.
 
15.  Contingencies
 
Guarantees
 
We guaranteed $1.2 million of residual value related to the leases of trailers from a lessor.  We believe the likelihood that we would be required to perform or otherwise incur any significant losses associated with this guarantee is remote.
 
We guaranteed 50% of the obligations of Sandhill under a credit facility with a bank.  At March 31, 2008, Sandhill owed $3.6 million; therefore our guaranty was $1.8 million.  Sandhill makes principal payments for this obligation totaling $0.6 million per year.
 
Pennzoil Litigation
 
We were named a defendant in a complaint filed on January 11, 2001, in the 125th District Court of Harris County, Texas, Cause No. 2001-01176.  Pennzoil-Quaker State Company, or PQS, was seeking from us property damages, loss of use and business interruption suffered as a result of a fire and explosion that occurred at the Pennzoil Quaker State refinery in Shreveport, Louisiana, on January 18, 2000.  PQS claimed the fire and explosion were caused, in part, by crude oil we sold to PQS that was contaminated with organic chlorides.  In December 2003, our insurance carriers settled this litigation for $12.8 million.
 
PQS is also a defendant in five consolidated class action/mass tort actions brought by neighbors living in the vicinity of the PQS Shreveport, Louisiana refinery in the First Judicial District Court, Caddo Parish, Louisiana, Cause Nos. 455,647-A, 455,658-B, 455,655-A, 456,574-A, and 458,379-C.  PQS has brought third party claims against us for indemnity with respect to the fire and explosion of January 18, 2000.  We believe that the demand against us is without merit and intend to vigorously defend ourselves in this matter.  We currently believe that this matter will not have a material financial effect on our financial position, results of operations, or cash flows.
 
Environmental
 
In 1992, Howell Crude Oil Company (“Howell”) entered into a sublease with Koch Industries, Inc. (“Koch”), covering a one acre tract of land located in Santa Rosa County, Florida to operate a crude oil trucking station, known as Jay Station.  The sublease provided that Howell would indemnify Koch for environmental contamination on the property under certain circumstances.  Howell operated the Jay Station from 1992 until December of 1996 when this operation was sold to us by Howell.  We operated the Jay Station as a crude oil trucking station until 2003.   Koch has indicated that it has incurred certain investigative and/or other costs, for which Koch alleges some or all should be reimbursed by us, under the indemnification provisions of the sublease for environmental contamination on the site and surrounding areas.  Koch has also alleged that we are responsible for future environmental obligations relating to the Jay Station.
 
Howell was acquired by Anadarko Petroleum Corporation (“Anadarko”) in 2002.  In 2005, we entered into a joint defense and cost allocation agreement with Anadarko.  Under the terms of the joint allocation agreement, we agreed to reasonably cooperate with each other to address any liabilities or defense costs with respect to the Jay Station.  Additionally under the joint allocation agreement, Anadarko will be responsible for sixty percent of the costs related to any liabilities or defense costs incurred with respect to contamination at the Jay Station.
 
We were formed in 1996 by the sale and contribution of assets from Howell and Basis Petroleum, Inc. (“Basis”).  Anadarko's liability with respect to the Jay Station is derived largely from contractual obligations entered into upon our formation.  We believe that Basis has contractual obligations under the same formation agreements.  We intend to seek recovery of Basis' share of potential liabilities and defense costs with respect to Jay Station.
 
We have developed a plan of remediation for affected soil and groundwater at Jay Station which has been approved by appropriate state regulatory agencies.  We have accrued an estimate of our share of liability for this matter in the amount of $0.8 million.  The time period over which our liability would be paid is uncertain and could be several years.  This liability may decrease if indemnification and/or cost reimbursement is obtained by us for Basis' potential liabilities with respect to this matter.  At this time, our estimate of potential obligations does not assume any specific amount contributed on behalf of the Basis obligations, although we believe that Basis is responsible for a significant part of these potential obligations.

GENESIS ENERGY, L.P.
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
 
We are subject to various environmental laws and regulations.  Policies and procedures are in place to monitor compliance and to detect and address any releases of crude oil from our pipelines or other facilities; however, no assurance can be made that such environmental releases may not substantially affect our business.
 
In connection with the sale of pipeline assets in Texas in the fourth quarter of 2003, we retained responsibility for environmental matters related to the operations of those pipelines in the periods prior to the date of the sales, subject to certain conditions.  On the majority of the pipelines sold, our responsibility for any environmental claim will not exceed an aggregate total of $2 million.  Our responsibility for indemnification related to these sales will cease in 2013.
 
Other Matters
 
Our facilities and operations may experience damage as a result of an accident or natural disaster.  These hazards can cause personal injury or loss of life, severe damage to and destruction of property and equipment, pollution or environmental damage and suspension of operations.  We maintain insurance that we consider adequate to cover our operations and properties, in amounts we consider reasonable.  Our insurance does not cover every potential risk associated with operating our facilities, including the potential loss of significant revenues.  The occurrence of a significant event that is not fully-insured could materially and adversely affect our results of operations.  We believe we are adequately insured for public liability and property damage to others and that our coverage is similar to other companies with operations similar to ours.  No assurance can be made that we will be able to maintain adequate insurance in the future at premium rates that we consider reasonable.
 
We are subject to lawsuits in the normal course of business and examination by tax and other regulatory authorities.  We do not expect such matters presently pending to have a material adverse effect on our financial position, results of operations, or cash flows.
 
16.  Unit-Based Compensation Plans
 
Stock Appreciation Rights Plan
 
The adjustment of the liability for our stock appreciation rights plan to its fair value at March 31, 2008 resulted in a credit to expense for the three months ended March 31, 2008 of $0.9 million, with $0.6 million, $0.2 million and $0.1 million included in general and administrative expenses, pipeline operating costs, and supply and logistics operating costs, respectively. An immaterial amount of expense was recorded to refinery services operating costs related to grants awarded in the first quarter of 2008.  The decrease in our common unit market price from December 31, 2007 to March 31, 2008 of $4.66 reduced the accrual for the plan, providing a credit to the expense we recorded under our plan during the three months ended March 31, 2008.  The adjustment of the liability to its fair value at March 31, 2007, resulted in expense for the three months ended March 31, 2007 of $0.6 million, with $0.3 million, $0.2 million and $0.1 million included in general and administrative expenses, supply and logistics operating costs, and pipeline operating costs, respectively.
 
The following table reflects rights activity under our plan during the three months ended March 31, 2008:

GENESIS ENERGY, L.P.
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
 
Stock Appreciation Rights
 
Rights
   
Weighted Average Exercise Price
   
Weighted Average Contractual Remaining Term (Yrs)
   
Aggregate Intrinsic Value
 
                         
Outstanding at January 1, 2008
    593,458     $ 15.45              
Granted
    508,228     $ 20.90              
Exercised
    (10,958 )   $ 21.71              
Forfeited or expired
    (18,699 )   $ 18.49              
Outstanding at March 31, 2008
    1,072,029     $ 18.04       8.7     $ 2,822  
Exercisable at March 31, 2008
    315,264     $ 14.06       7.1     $ 1,781  
 
The weighted-average fair value at March 31, 2008 of rights granted during the first quarter of 2008 was $3.02 per right, determined using the following assumptions:
 
Assumptions for Computation of Fair Value of Rights Granted in First Quarter 2008
Expected life of rights (in years)
6.25 - 7.00
Risk-free interest rate
2.76% - 2.93%
Expected unit price volatility
33.99%
Expected future distribution yield
6.00%
 
The total intrinsic value of rights exercised during the first quarter of 2008 was $0.1 million, which was paid in cash to the participants.
 
At March 31, 2008, there was $1.7 million of total unrecognized compensation cost related to rights that we expect will vest under the plan.  This amount was calculated as the fair value at March 31, 2008 multiplied by those rights for which compensation cost has not been recognized, adjusted for estimated forfeitures.  This unrecognized cost will be recalculated at each balance sheet until the rights are exercised, forfeited, or expire.  For the awards outstanding at March 31, 2008, the remaining cost will be recognized over a weighted average period of 0.7 years.
 
2007 Long Term Incentive Plan
 
Subject to adjustment as provided in the 2007 LTIP, awards with respect to up to an aggregate of 1,000,000 units may be granted under the 2007 LTIP, of which 951,472 remain authorized for issuance at March 31, 2008.  In February 2008, 9,166 Phantom Units were granted with vesting at the end of three years.  The aggregate grant date fair value of these Phantom Unit awards was $0.2 million based on the grant date market price of our common units of $17.89 per unit, adjusted for distributions that holders of phantom units will not receive during the vesting period.
 
As of March 31, 2008, there was $0.9 million of unrecognized compensation expense related to these units.  This unrecognized compensation cost is expected to be recognized over a weighted-average period of 1.7 years.
 
The following table summarizes information regarding our non-vested Phantom Unit grants as of March 31, 2008:
 
         
Weighted
Average
 
   
Number of
   
Grant-Date
 
Non-vested Phantom Unit Grants
 
Units
   
Fair Value
 
             
Non-vested at January 1, 2008
    39,362     $ 21.92  
Granted
    9,166     $ 17.89  
Non-vested at March 31, 2008
    48,528     $ 21.16  

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GENESIS ENERGY, L.P.
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
 
17.  Fair-Value Measurements
 
As discussed in Note 2, we partially adopted SFAS 157 effective January 1, 2008 which defines fair value as the exchange price that would be received for an asset or paid to transfer a liability (an exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants at the measurement date.  SFAS 157 establishes a three-level fair value hierarchy that prioritizes the inputs used to measure fair value.  This hierarchy requires entities to maximize the use of observable inputs and minimize the use of unobservable inputs.  The three levels of inputs used to measure fair value are as follows:
 
 
Level 1:
Quoted prices in active markets for identical, unrestricted assets or liabilities.
 
 
Level 2:
Observable market-based inputs or unobservable inputs that are corroborated by market data.
 
Level 3:
Unobservable inputs that are not corroborated by market data, which require us to develop our own assumptions.  These inputs include certain pricing models, discounted cash flow methodologies and similar techniques that use significant unobservable inputs.
 
Our derivative contracts are exchange-traded futures and exchange-traded option contracts.  The fair value of these exchange-traded derivative contracts is based on unadjusted quoted prices in active markets and is, therefore, included in Level 1.  See Note 14 for additional information on our derivative instruments.
 
We generally apply fair value techniques on a non-recurring basis associated with (1) valuing the potential impairment loss related to goodwill pursuant to SFAS 142, and (2) valuing potential impairment loss related to long-lived assets accounted for pursuant to SFAS 144.
 
Assets and liabilities measured at fair value on a recurring basis are summarized below (in thousands):
 
    Carrying Amount    
Quoted Prices in Active Markets for Identical Assets
(Level 1)
   
Significant Other Observable Inputs
(Level 2)
   
Significant Unobservable Inputs
(Level 3)
 
                 
                 
                 
Crude oil and petroleum products derivative instruments (based on quoted market prices on NYMEX)
  $ (1,038 )   $ (1,038 )   $ -     $ -  
 
18.  Income Taxes
 
We are not a taxable entity for federal income tax purposes.  As such, we do not directly pay federal income taxes.  Our taxable income or loss is includible in the federal income tax returns of each of our partners.
 
A portion of the operations we acquired in the Davison transaction are owned by wholly-owned corporate subsidiaries that are taxable as corporations.  We pay federal and state income taxes on these operations.  The income taxes associated with these operations are accounted for in accordance with SFAS 109 “Accounting for Income Taxes.”
 
In May 2006, the State of Texas enacted a law which will require us to pay a tax of 0.5% on our “margin,” as defined in the law, beginning in 2008 based on our 2007 results.  The “margin” to which the tax rate will be applied generally will be calculated as our revenues (for federal income tax purposes) less the cost of the products sold (for federal income tax purposes), in the State of Texas.
 
-24-


GENESIS ENERGY, L.P.
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
 
For the three months ended March 31, 2008, we have provided current tax expense in the amount of $0.2 million as the estimate of the taxes that will be owed on our income for the period, and a deferred tax benefit of $1.6 million related to temporary differences, related primarily to differences between amortization of intangible assets for financial reporting and tax purposes.  We recorded a decrease of $0.5 million in the liability for uncertain tax benefits during the three months ended March 31, 2008.  This decrease was attributable to uncertain tax positions associated with deferred tax liabilities and goodwill.

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Item 2.  Management’s Discussion and Analysis of Financial Condition and Results of Operations
 
Included in Management’s Discussion and Analysis are the following sections:
 
 
·
Overview
 
 
·
Pending Drop-down Transactions
 
 
·
Liquidity and Capital Resources
 
 
·
Commitments and Off-Balance Sheet Arrangements
 
 
·
Results of Operations
 
 
·
New Accounting Pronouncements
 
In the discussions that follow, we will focus on two measures that we use to manage our 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.  A reconciliation of segment margin to income from continuing operations is included in our segment disclosures in Note 10 to the consolidated financial statements.
 
Available Cash before Reserves (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
 
The first quarter of 2008 was the second full quarter that included the operations acquired from the Davison family in July 2007.  The increases in Available Cash before Reserves resulting from this acquisition enabled us to announce our eleventh consecutive increase in our quarterly distribution.  On April 28, 2008, we announced that our distribution to our common unitholders relative to the first quarter of 2008 will be $0.30 per unit (to be paid in May 2008), which is an increase of 5% relative to the distribution for the fourth quarter of 2007.   This distribution amount represents a 36% increase from our distribution of $0.22 per unit for the first quarter of 2007.  During the first quarter of 2008, we paid a distribution of $0.285 per unit related to the fourth quarter of 2007.
 
During the first quarter of 2008, we generated $15.8 million of Available Cash before Reserves, and we will distribute $12.1 million to holders of our common units and general partner for the first quarter.  During the first quarter of 2008, cash provided by operating activities was $17.4 million.
 
In the first quarter of 2008, we reported net income of $1.6 million, or $0.04 per common unit, with $0.9 million of that income attributable to a reduction in the accrual we recorded for our stock appreciation rights plan.  The decrease in our common unit market price from December 31, 2007 to March 31, 2008 of $4.66 reduced the accrual for the plan, providing a credit to the expense we recorded under our plan during the three months ended March 31, 2008.  Non-cash depreciation and amortization totaling $16.8 million reduced net income during the first quarter.
 
Pending Drop-down Transactions
 
As a result of our acquisition from the Davisons, Denbury will enter into “drop-down” transactions with us involving two of their existing CO2 pipelines - the NEJD and Free State CO2 pipelines. 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 five trading days surrounding 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 are dependent on the volumes of CO2 transported therein. The business terms of the transactions have been completed and the associated documentation, requisite approvals and closing should be completed in the near future.

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Liquidity and Capital Resources
 
Capital Resources/Sources of Cash
 
In the last two years, 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. 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. While we anticipate that we will fund our distributions and our internal growth and maintenance capital expenditures, as well as the drop-downs from Denbury with borrowings under our existing credit facility, we will need to access the debt or equity markets to make any significant acquisitions.  No assurance can be made that we will be able to raise the necessary funds on satisfactory terms.  Current market conditions may make the terms of cost of credit or equity cost prohibitive in relation to the economics of an acquisition.  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. A maximum of $100 million may be used for letters of credit.  The borrowing base under the facility at March 31, 2008 was approximately $361 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 8 of the Notes to the Unaudited Consolidated Financial Statements.
 
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.  The timing of capital expenditures and the related effect on our recorded liabilities affects operating cash flows.
 
The majority of the accounts receivable reflected 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 80% of the $199.7 million aggregate receivables on our consolidated balance sheet at March 31, 2008 relate to our crude oil and fuel procurement businesses.
 
Investing.  We utilized some of our cash flow for capital expenditures.  We paid $6.4 million for capital expenditures and received $0.2 million from the sale of surplus assets.  We received distributions of $0.2 million from our T&P Syngas joint venture that exceeded our share of the earnings of T&P Syngas during the first quarter of 2008.
 
Financing.  Net cash of $9.1 million was utilized in financing activities.  Our net borrowings under our credit facility were $2.0 million. We paid distributions totaling $11.4 million to our limited partners and our general partner during the quarter, and received $0.3 million from other financing activities.
 
Capital Expenditures.  A summary of our capital expenditures, in the three months ended March 31, 2008 and 2007 is as follows:

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Three Months Ended March 31,
 
   
2008
   
2007
 
   
(in thousands)
 
Capital expenditures for property, plant and equipment:
           
Maintenance capital expenditures:
           
Pipeline transportation assets
    165       222  
Supply and logistics assets
    304       91  
Refinery services assets
    281       -  
Administrative and other assets
    26       2  
Total maintenance capital expenditures
    776       315  
                 
Growth capital expenditures:
               
Pipeline transportation assets
    1,113       71  
Supply and logistics assets
    4,273       -  
Refinery services assets
    870       -  
Total growth capital expenditures
    6,256       71  
Total
    7,032       386  
                 
Capital expenditures attributable to unconsolidated affiliates:
               
Faustina project
    2,210       -  
Total
    2,210       -  
Total capital expenditures
  $ 9,242     $ 386  
 
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.
 
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 35 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 $7.5 million on projects currently in progress to expand its operations in 2008 to two additional refineries.  We also increased our base level of crude oil inventory by $4.3 million related to our Port Hudson facility, which is included in fixed assets.  This is the level of inventory needed to ensure efficient and uninterrupted operations of the facility.
 
As discussed above in “Pending Drop-down Transactions”, we are currently in the process of finalizing drop-down transactions with Denbury related to two of its CO2 pipelines.
 
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 senior executive management team provides incentives to them to make such acquisitions.
 
Distributions
 
We are required by our partnership agreement to distribute 100% of our available cash (as defined therein) within 45 days after the end of each quarter to unitholders of record and to our general partner.  Available cash consists generally of all of our cash receipts less cash disbursements adjusted for net changes to reserves.  We have increased our distribution for each of the last six quarters, including the distribution to be paid for the first quarter of 2008, as shown in the table below (in thousands, except per unit amounts).

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General
       
           
Limited
   
General
   
Partner
       
           
Partner
   
Partner
   
Incentive
       
     
Per Unit
   
Interests
   
Interest
   
Distribution
   
Total
 
Distribution For
Date Paid
 
Amount
   
Amount
   
Amount
   
Amount
   
Amount
 
               
Fourth quarter 2006
February 2007
  $ 0.210     $ 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  
Fourth quarter 2007
February 2008
  $ 0.285     $ 10,903     $ 222     $ 245     $ 11,370  
First quarter 2008
May 2008 (2)
  $ 0.300     $ 11,476     $ 234     $ 429     $ 12,139  

(1)  The distribution paid on August 14, 2007 to holders of our common units is net of the amounts payable with respect to the common units issued in connection with the Davison transaction.  The Davison unitholders and our general partner waived their rights to receive such distributions, instead receiving purchase price adjustments with us.
 
(2)  This distribution will be paid on May 15, 2008 to the general partner and unitholders of record as of May 9, 2008.
 
See Notes 8 and 9 of the Notes to the Unaudited Consolidated Financial Statements.
 
Available Cash before Reserves for the three months ended March 31, 2008 is as follows (in thousands):
 
   
Three Months
 
   
Ended
 
   
3/31/2008
 
Net income
  $ 1,645  
Depreciation and amortization
    16,789  
Cash received from direct financing leases not included in income
    147  
Cash effects of sales of certain assets
    245  
Effects of available cash generated by investments in joint ventures not included in income
    423  
Cash effects of stock appreciation rights plan
    (158 )
Other non-cash credits
    (2,528 )
Maintenance capital expenditures
    (776 )
Available Cash before Reserves
  $ 15,787  

We have reconciled Available Cash before Reserves (a non-GAAP measure) to cash flow from operating activities (the GAAP measure) for the three months ended March 31, 2008 below.  For the three months ended March 31, 2008, cash flows provided by operating activities were $17.4 million.
 
Non-GAAP Financial Measure
 
This quarterly 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.

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Available Cash before Reserves, also referred to as discretionary cash flow, is commonly used as a supplemental financial measure by management and by external users of financial statements, such as investors, commercial banks, research analysts and rating agencies, to assess: (1) the financial performance of our assets without regard to financing methods, capital structures, or historical cost basis; (2) the ability of our assets to generate cash sufficient to pay interest cost and support our indebtedness; (3) our operating performance and return on capital as compared to those of other companies in the midstream energy industry, without regard to financing and capital structure; and (4) the viability of projects and the overall rates of return on alternative investment opportunities.  Because Available Cash 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 Quarterly Report on Form 10-Q may not be comparable to similarly titled measures of other companies.  The GAAP measure most directly comparable to Available Cash before Reserves is net cash provided by operating activities.
 
Available Cash before Reserves is a liquidity measure used by our management to compare cash flows generated by us to the cash distribution paid to our limited partners and general partner.  This is an important financial measure to our public unitholders since it is an indicator of our ability to provide a cash return on their investment.  Specifically, this financial measure aids investors in determining whether or not we are generating cash flows at a level that can support a quarterly cash distribution to the partners.  Lastly, Available Cash before Reserves (also referred to as distributable cash flow) is the quantitative standard used throughout the investment community with respect to publicly-traded partnerships.
 
The reconciliation of Available Cash before Reserves (a non-GAAP liquidity measure) to cash flow from operating activities (the GAAP measure) for the three months ended March 31, 2008, is as follows (in thousands):
 
   
Three Months
 
   
Ended
 
   
March 31,2008
 
Cash flows from operating activities
  $ 17,383  
Adjustments to reconcile operating cash flows to Available Cash:
       
Maintenance capital expenditures
    (776 )
Proceeds from sales of certain assets
    245  
Amortization of credit facility issuance fees
    (268 )
Effects of available cash generated by investments in joint ventures not included in cash flows from operating activities
    84  
Net effect of changes in operating accounts not included in calculation of Available Cash
    (881 )
Available Cash before Reserves
  $ 15,787  

 
Commitments and Off-Balance-Sheet Arrangements
 
Contractual Obligations and Commercial Commitments
 
Our obligations that are not currently recorded on our balance sheet consist of our operating leases and crude oil purchase commitments.  Neither the amounts nor the terms of these commitments or contingent obligations have changed significantly from the year-end 2007 amounts reflected in our Annual Report on Form 10-K. Please refer to Management’s Discussion and Analysis of Financial Condition and Results of Operations — “Commitments and Off-Balance Sheet Arrangements” contained in our 2007 Annual Report on Form 10-K for further information regarding our commitments and obligations.
 
Off-Balance Sheet Arrangements
 
We have no off-balance sheet arrangements, special purpose entities, or financing partnerships, other than as disclosed under “Contractual Obligations and Commercial Commitments” above, nor do we have any debt or equity triggers based upon our unit or commodity prices.

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Results of Operations
 
The contribution of each of our segments to total segment margin in the first quarters of 2008 and 2007 was as follows:
 
   
Three Months Ended March 31,
 
   
2008
   
2007
 
   
(in thousands)
 
Pipeline transportation
  $ 4,643     $ 2,868  
Refinery services
    13,588       -  
Industrial gases
    2,776       2,614  
Supply and logistics
    6,261       1,599  
Total segment margin
  $ 27,268     $ 7,081  
 
Pipeline Transportation Segment
 
We operate three crude oil common carrier pipeline systems in a four-state area.  We refer to these pipelines as our Mississippi System, Jay System, and Texas System.  Additionally, 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. We also have several small natural gas gathering systems.
 
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, we expect Denbury to add crude oil gathering and CO2 supply infrastructure to those fields, which could create opportunities for us.
 
The Jay System in Florida/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 or re-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.  In August 2007, we announced that we will construct an expansion of our existing Jay System that will extend to producers operating in southern Alabama.  This extension will consist of approximately 33 miles of pipeline and gathering connections to approximately 35 wells and storage capacity of 20,000 barrels.  We expect to place these facilities in service in the first quarter of 2009.  The production from these wells is currently being transported to our existing Jay System by our trucks.  This expansion will allow us to re-deploy the trucks to other operations.
 
Our Texas System is dependent on connecting carriers for supply, and on two refineries for demand for our services.  Volumes on the Texas System fluctuate as a result of changes in the supply available for the two refineries to acquire and ship on our pipeline.  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.
 
Operating results for our pipeline transportation segment were as follows:

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Three Months Ended March 31,
 
   
2008
   
2007
 
   
(in thousands)
 
Crude oil tariffs and revenues from direct financing leases of crude oil pipelines
  $ 4,126     $ 3,536  
Sales of crude oil pipeline loss allowance volumes
    2,459       1,699  
                 
Revenues from direct financing leases of CO2 pipelines
    78       82  
Tank rental reimbursements and other miscellaneous revenues
    267       163  
Total revenues from crude oil and CO2 tariffs, including revenues from direct financing leases
    6,930       5,480  
Revenues from natural gas tariffs and sales
    1,355       1,308  
Natural gas purchases
    (1,286 )     (1,235 )
Pipeline operating costs
    (2,356 )     (2,685 )
Segment margin
  $ 4,643     $ 2,868  
                 
Barrels per day on crude oil pipelines:
               
Total
    66,032       57,874  
Mississippi System
    22,854       19,355  
Jay System
    14,616       12,812  
Texas System
    28,562       25,707  


Three Months Ended March 31, 2008 Compared with Three Months Ended March 31, 2007
 
Pipeline segment margin for the first quarter of 2008 increased $1.8 million as compared to the first quarter of 2007.  Revenues from crude oil tariffs and related sources and sales of pipeline loss allowance volumes increased a total of $1.5 million.  Pipeline operating costs decreased $0.3 million between the two periods, and the contribution to segment margin from natural gas activities was consistent.
 
Crude oil tariff and direct financing lease revenues increased $0.6 million primarily due to volume increases on all of our pipeline systems totaling 8,158 barrels per day. The tariff on the Mississippi System is an incentive tariff, such that the average tariff per barrel decreases as the volumes increase, however the overall impact of an annual tariff increase on July 1, 2007 with the volume increase still resulted in improved revenues from this system by $0.2 million.  As a result of the annual tariff increase on July 1, 2007, average tariffs on the Jay System increased by approximately $0.03 per barrel between the two periods, which, when combined with the 1,804 barrels per day increase in volumes, improved tariff revenues from this system by $0.2 million.  The volume increase is due in part to the renewed interest by oil producers in the fields in the area and additional volumes we are bringing to the system from other locations.  Volumes on the Texas System increased by 2,855 barrels per day, although the impact on revenues was not very significant due to the relatively low tariffs on that system.  Approximately 78% of the volume on that system is shipped on a tariff of $0.31 per barrel.
 
Higher market prices for crude oil added $0.8 million to pipeline loss allowance revenues.  Crude oil market prices have increased approximately $40 per barrel between the two quarters.
 
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 power cost increases.  We perform regular maintenance on our assets in an effort to keep them in good operational condition and to minimize cost increases.  Operations and maintenance costs, excluding the effects of our stock appreciation rights plan were flat when compared to the prior period.  A decrease in the costs related to our stock appreciation right plan expense that relates to our pipeline operations personnel resulted in the decline in pipeline operating costs between the quarters.

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Refinery Services Segment
 
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 100% of the NaHS as compensation and by selling the NaHS, the by-product of our process, to approximately 100 customers.  Some of the largest customers for the NaHS are copper mining companies in the United States and South America and paper mills.
 
The largest cost component of providing the 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 involves 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.  We estimate that approximately 65% of our NaHS sales are indexed, in one form or another, to our cost of caustic soda.  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.
 
Segment margin from our refinery services for the first quarter of 2008 was $13.6 million.  On a pro forma basis, refinery services segment margin would have been $12.8 million for the first quarter of 2007.
 
We believe the most meaningful measure of our success in this segment is the revenue generated from sales of NaHS after deducting delivery expenses, from both the volumes received as payment for rendering service as well as volumes obtained from third party producers.
 
 
   
Three Months Ended
   
Three Months Ended
 
   
March 31,
   
March 31,
 
   
2008
   
2007
 
             
NaHS Sales
           
Dry Short Tons (DST)
    41,742       38,781  
Net Sales per DST
  $ 660     $ 560  
Contribution Margin per DST
  $ 260     $ 260  
 
During the first quarter of 2008, sales of NaHS, measured in dry short tons (DST) were 41,742 DST, or an average of 458 DST per day.  The average sales price of the NaHS, net of delivery expenses, for the period was $660 per DST.  Comparing the historical results of the predecessor for the first quarter of 2007 with our results for the first quarter of 2008 indicates that the average sales price per DST of NaHS, net of delivery expenses, increased between the two periods by 18%.  The total difference in DST sold between the periods was 2,961 DST more in the first quarter of 2008 than the same period in 2007.  As we expand our sour gas processing services to additional refineries, we expect these NaHS sales volumes to continue to increase.  The increased worldwide demand for copper has contributed to the increased demand for NaHS.
 
The largest input to processing of the sour gas streams that result in NaHS is caustic soda.  We also market caustic soda and sulfidic caustic not used for our processing.  During the first quarter of 2008, the average market price for caustic soda was $476 per DST, an increase of 41% over the market price in the first quarter of 2007.  We have generally been successful in increasing the sales price of NaHS to compensate for increases in caustic soda prices and maintaining or expanding the contribution of NaHS sales to our segment margin.
 
Industrial Gases Segment
 
Our industrial gases segment includes the results of our CO2 sales to industrial customers and our share of the operating income of our 50% joint venture interests in T&P Syngas and Sandhill.

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CO2  - Industrial Customers - We supply CO2 to industrial customers under seven long-term CO2 sales contracts.  The sales contracts contain provisions for adjustments for inflation to sales prices based on the Producer Price Index, with a minimum price.
 
Our industrial customers treat the CO2 and transport it to their own customers.  The primary industrial applications of CO2 by these customers include beverage carbonation and food chilling and freezing.  Based on historical data for 2004 through the first quarter of 2008, we can 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.  Volumes sold each quarter in 2007 and in the first quarter of 2008 were as follows:
 
   
Sales
 
   
Mcf per Day
 
       
First Quarter 2007
    67,158  
Second Quarter 2007
    75,039  
Third Quarter 2007
    85,705  
Fourth Quarter 2007
    80,667  
First Quarter 2008
    73,062  

Operating Results - Operating results from our industrial gases segment were as follows:
 
   
Three Months Ended March 31,
 
   
2008
   
2007
 
   
(in thousands)
 
Revenues from CO2 sales
  $ 3,870     $ 3,497  
CO2 transportation and other costs
    (1,272 )     (1,144 )
Equity in earnings of joint ventures
    178       261  
Segment margin
  $ 2,776     $ 2,614  
                 
Volumes per day:
               
CO2 sales - Mcf
    73,062       67,158  
 
Three Months Ended March 31, 2008 Compared with Three Months Ended March 31, 2007
 
The increase in margin from the industrial gases between the two periods was the result of an increase in  CO2 sales volumes of 8.8%.   Variations in the volumes sold among contracts with different pricing terms resulted in the average sales price of the CO2 remaining consistent between the periods despite inflation adjustment factors in the sales contracts.
 
The increased volumes and the inflation adjustment to the rate we pay Denbury to transport the CO2 in its pipeline to our customers resulted in greater CO2 transportation costs in the first quarter of 2008 when compared to the 2007 quarter.  The transportation rate increase between the two quarters was 5.6%.