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 September 30, 2010

OR

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

Commission file number 001-12295

GENESIS ENERGY, L.P.
(Exact name of registrant as specified in its charter)
 
Delaware
 
76-0513049
(State or other jurisdiction of  incorporation or organization)
 
(I.R.S. Employer Identification No.)
     
919 Milam, Suite 2100, Houston, TX
 
77002
(Address of principal executive offices)
 
(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 þ   No o
 
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or such shorter period that the registrant was required to submit and post such files).

Yes o  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 þ
 
Non-accelerated filer o
 
Smaller reporting company o

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

Yes o  No þ

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 November 2, 2010:  39,585,692
 


 
 

 

GENESIS ENERGY, L.P.

Form 10-Q

INDEX


PART I.  FINANCIAL INFORMATION

Item 1.
 
Financial Statements
 
Page
         
     
3
         
     
4
         
     
5
         
     
6
         
     
7
         
     
8
         
Item 2.
   
23
         
Item 3.
   
39
         
Item 4.
   
39
         
PART II.  OTHER INFORMATION
         
Item 1.
   
39
         
Item 1A.
   
39
         
Item 2.
   
39
         
Item 3.
   
39
         
Item 4.
   
39
         
Item 5.
   
39
         
Item 6.
   
39
         
 
41

 
-2-

 
PART I.  FINANCIAL INFORMATION
Item 1.  Financial Statements
GENESIS ENERGY, L.P.
UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS
(In thousands)

   
September 30, 2010
   
December 31, 2009
 
             
ASSETS
           
CURRENT ASSETS:
           
Cash and cash equivalents
  $ 3,058     $ 4,148  
Accounts receivable - trade, net of allowance for doubtful accounts of $1,303 and $1,372 at September 30, 2010 and December 31, 2009, respectively
    169,370       127,248  
Accounts receivable - related parties
    315       2,617  
Inventories
    64,581       40,204  
Investment in direct financing leases, net of unearned income -current portion
    4,509       4,202  
Other
    8,904       10,825  
Total current assets
    250,737       189,244  
                 
FIXED ASSETS, at cost
    373,636       373,927  
Less:  Accumulated depreciation
    (103,834 )     (89,040 )
Net fixed assets
    269,802       284,887  
                 
INVESTMENT IN DIRECT FINANCING LEASES, net of unearned income
    169,626       173,027  
CO2 ASSETS, net of accumulated amortization
    16,869       20,105  
EQUITY INVESTEES AND OTHER INVESTMENTS
    14,255       15,128  
INTANGIBLE ASSETS, net of accumulated amortization
    123,315       136,330  
GOODWILL
    325,046       325,046  
OTHER ASSETS, net of accumulated amortization
    9,847       4,360  
                 
TOTAL ASSETS
  $ 1,179,497     $ 1,148,127  
                 
LIABILITIES AND PARTNERS' CAPITAL
               
CURRENT LIABILITIES:
               
Accounts payable - trade
  $ 137,390     $ 114,428  
Accounts payable - related parties
    2,213       3,197  
Accrued liabilities
    25,733       23,803  
Total current liabilities
    165,336       141,428  
                 
LONG-TERM DEBT
    426,000       366,900  
DEFERRED TAX LIABILITIES
    14,391       15,167  
OTHER LONG-TERM LIABILITIES
    5,523       5,699  
COMMITMENTS AND CONTINGENCIES (Note 13)
               
                 
PARTNERS' CAPITAL:
               
Common unitholders, 39,586 and 39,488 units issued and outstanding,at September 30, 2010 and December 31, 2009, respectively
    557,079       585,554  
General partner
    10,608       11,152  
Accumulated other comprehensive loss
    -       (829 )
Total Genesis Energy, L.P. partners' capital
    567,687       595,877  
Noncontrolling interests
    560       23,056  
Total partners' capital
    568,247       618,933  
                 
TOTAL LIABILITIES AND PARTNERS' CAPITAL
  $ 1,179,497     $ 1,148,127  

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

 
-3-

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

   
Three Months Ended
   
Nine Months Ended
 
   
September 30,
   
September 30,
 
   
2010
   
2009
   
2010
   
2009
 
REVENUES:
                       
Supply and logistics:
                       
Unrelated parties
  $ 518,441     $ 355,604     $ 1,338,755     $ 833,658  
Related parties
    368       846       1,014       3,218  
Refinery services
    38,437       30,006       106,160       112,894  
Pipeline transportation, including natural gas sales:
                               
Transportation services - unrelated parties
    13,565       4,009       36,342       11,442  
Transportation services - related parties
    -       7,977       2,861       24,175  
Natural gas sales revenues
    522       435       1,967       1,667  
CO2 marketing:
                               
Unrelated parties
    3,886       3,712       9,881       9,821  
Related parties
    793       800       2,101       2,211  
Total revenues
    576,012       403,389       1,499,081       999,086  
                                 
COSTS AND EXPENSES:
                               
Supply and logistics costs:
                               
Product costs - unrelated parties
    490,358       324,162       1,251,777       751,524  
Product costs - related parties
    -       -       -       1,754  
Operating costs
    23,300       22,894       66,764       60,766  
Operating costs - related parties
    599       -       1,932       -  
Refinery services operating costs
    22,251       17,160       60,268       73,711  
Pipeline transportation costs:
                               
Pipeline transportation operating costs
    3,007       2,852       9,192       7,984  
Natural gas purchases
    490       395       1,847       1,519  
CO2 marketing costs:
                               
Transportation costs
    1,741       1,603       4,542       4,251  
Other costs
    16       16       47       47  
General and administrative
    10,583       10,128       23,678       27,188  
Depreciation and amortization
    13,477       15,806       40,489       47,358  
Net loss (gain) on disposal of surplus assets
    7       17       25       (141 )
Total costs and expenses
    565,829       395,033       1,460,561       975,961  
OPERATING INCOME
    10,183       8,356       38,520       23,125  
                                 
Equity in earnings of joint ventures
    377       (788 )     922       1,382  
Interest expense
    (6,542 )     (3,418 )     (13,506 )     (9,826 )
Income before income taxes
    4,018       4,150       25,936       14,681  
Income tax expense
    (155 )     (253 )     (1,827 )     (1,661 )
NET INCOME
    3,863       3,897       24,109       13,020  
                                 
Net loss attributable to noncontrolling interests
    1,205       402       2,082       1,025  
                                 
NET INCOME ATTRIBUTABLE TO GENESIS ENERGY, L.P.
  $ 5,068     $ 4,299     $ 26,191     $ 14,045  

 
-4-


GENESIS ENERGY, L.P.
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS
OF OPERATIONS - CONTINUED
(In thousands, except per unit amounts)
 
   
Three Months Ended
   
Nine Months Ended
 
   
September 30,
   
September 30,
 
   
2010
   
2009
   
2010
   
2009
 
                         
Net Income Attributable to Genesis Energy, L.P.
                               
Per Common Unit:
                               
Basic and Diluted
  $ 0.12     $ 0.14     $ 0.48     $ 0.43  

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

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

   
Three Months Ended
   
Nine Months Ended
 
   
September 30,
   
September 30,
 
   
2010
   
2009
   
2010
   
2009
 
                         
Net income
  $ 3,863     $ 3,897     $ 24,109     $ 13,020  
Change in fair value of derivatives:
                               
Current period reclassification to earnings
    1,553       224       2,112       514  
Changes in derivative financial instruments - interest rate swaps
    (224 )     (315 )     (424 )     (400 )
Comprehensive income
    5,192       3,806       25,797       13,134  
Comprehensive loss (income) attributable to noncontrolling interests
    529       46       1,223       (60 )
Comprehensive income attributable to Genesis Energy, L.P.
  $ 5,721     $ 3,852     $ 27,020     $ 13,074  

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

 
-5-


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

   
Partners' Capital
 
   
Number of Common Units
   
Common Unitholders
   
General Partner
   
Accumulated Other Comprehensive Loss
   
Non-Controlling Interests
   
Total Capital
 
                                     
Partners' capital, January 1, 2010
    39,488     $ 585,554     $ 11,152     $ (829 )   $ 23,056     $ 618,933  
Comprehensive income:
                                               
Net income (loss)
    -       20,052       6,139       -       (2,082 )     24,109  
Interest rate swap losses reclassified to interest expense
    -       -       -       1,035       1,077       2,112  
Interest rate swap loss
    -       -       -       (206 )     (218 )     (424 )
Cash contributions
    -       -       37       -       -       37  
Cash distributions
    -       (43,644 )     (7,909 )     -       (5 )     (51,558 )
Contribution for executive compensation (See Note 9)
    -       -       1,289       -       -       1,289  
Unit based compensation expense
    98       20       -       -       -       20  
Acquisition of non-controlling interest in DG Marine (See Note 2)
    -       (4,903 )     (100 )     -       (21,268 )     (26,271 )
Partners' capital, September 30, 2010
    39,586     $ 557,079     $ 10,608     $ -     $ 560     $ 568,247  

   
Partners' Capital
 
   
Number of Common Units
   
Common Unitholders
   
General Partner
   
Accumulated Other Comprehensive Loss
   
Non-Controlling Interests
   
Total Capital
 
                                     
Partners' capital, January 1, 2009
    39,457     $ 616,971     $ 16,649     $ (962 )   $ 24,804     $ 657,462  
Comprehensive income:
                                               
Net income (loss)
    -       17,892       (3,847 )     -       (1,025 )     13,020  
Interest rate swap loss reclassified to interest expense
    -       -       -       251       263       514  
Interest rate swap loss
    -       -       -       (197 )     (203 )     (400 )
Cash contributions
    -       -       7       -       -       7  
Cash distributions
    -       (39,958 )     (4,191 )     -       (4 )     (44,153 )
Contribution for executive compensation (See Note 9)
    -       -       7,587       -       -       7,587  
Unit based compensation expense
    26       793       -       -       -       793  
Partners' capital, September 30, 2009
    39,483     $ 595,698     $ 16,205     $ (908 )   $ 23,835     $ 634,830  

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

 
-6-


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

   
Nine Months Ended September 30,
 
   
2010
   
2009
 
CASH FLOWS FROM OPERATING ACTIVITIES:
           
Net income
  $ 24,109     $ 13,020  
Adjustments to reconcile net income to net cash provided by operating activities -
               
Depreciation of fixed assets
    17,241       19,378  
Amortization of intangible and CO2 assets
    23,248       27,980  
Amortization and write-off of credit facility issuance costs
    2,498       1,448  
Amortization of unearned income and initial direct costs on direct financing leases
    (13,275 )     (13,606 )
Payments received under direct financing leases
    16,389       16,390  
Equity in earnings of investments in joint ventures
    (922 )     (1,382 )
Distributions from joint ventures - return on investment
    1,494       800  
Non-cash effect of unit-based compensation plans
    1,941       2,758  
Non-cash compensation charge
    1,289       7,587  
Deferred and other tax liabilities
    649       1,084  
Other non-cash items
    2,423       (283 )
Net changes in components of operating assets and liabilities (See Note 10)
    (43,010 )     (19,343 )
Net cash provided by operating activities
    34,074       55,831  
                 
CASH FLOWS FROM INVESTING ACTIVITIES:
               
Payments to acquire fixed and intangible assets
    (8,799 )     (28,656 )
Distributions from joint ventures - return of investment
    308       -  
Other, net
    756       417  
Net cash used in investing activities
    (7,735 )     (28,239 )
                 
CASH FLOWS FROM FINANCING ACTIVITIES:
               
Bank borrowings
    561,429       174,300  
Bank repayments
    (502,329 )     (165,200 )
Credit facility issuance fees
    (7,584 )     -  
General partner contributions
    37       7  
Noncontrolling interests distributions
    (5 )     (4 )
Distributions to common unitholders
    (43,644 )     (39,958 )
Distributions to general partner interest
    (7,909 )     (4,191 )
Acquisition of non-controlling interests in DG Marine (See Note 2)
    (26,271 )     -  
Other, net
    (1,153 )     (2,831 )
Net cash used in financing activities
    (27,429 )     (37,877 )
                 
Net decrease in cash and cash equivalents
    (1,090 )     (10,285 )
Cash and cash equivalents at beginning of period
    4,148       18,985  
                 
Cash and cash equivalents at end of period
  $ 3,058     $ 8,700  

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

 
-7-


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

1. 
Organization and Basis of Presentation and Consolidation
 
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 carbon dioxide;
 
 
·
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);
 
 
·
Supply and logistics services, which includes terminaling, blending, storing, marketing, and transporting crude oil and petroleum products by trucks and barges; and
 
 
·
Industrial gas activities, including wholesale marketing of CO2 and processing of syngas through a joint venture.
 
Our 2% general partner interest is held by Genesis Energy, LLC, a Delaware limited liability company.    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 Presentation and Consolidation
 
Our 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 condensed 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, 2009.
 
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.
 
2. 
DG Marine
 
Today, DG Marine Transportation (“DG Marine”) is one of our wholly-owned consolidated subsidiaries, providing transportation services of petroleum products by barge that complements our other supply and logistics operations.  Originally formed in 2008, DG Marine was a joint venture in which we owned (directly and indirectly) a 49% economic interest.  The remaining 51% economic interest in DG Marine was owned by TD Marine, a related party. (See our Form 10-K for the year ended December 31, 2009 for a description of our related party relationships.)
 
On July 29, 2010, we acquired TD Marine’s effective 51% interest in DG Marine for $25.5 million in cash, resulting in DG Marine becoming wholly-owned by us.  We funded the acquisition with proceeds from our credit agreement, including (i) paying off DG Marine’s stand-alone credit facility, which had an outstanding principal balance of $44.4 million, and (ii) settling DG Marine’s interest rate swaps, which resulted in $1.3 million being reclassified from Accumulated Other Comprehensive Loss (“AOCL”) to interest expense in the third quarter of 2010.
 
As a result of this transaction, we reclassified the acquired noncontrolling interest in DG Marine of $21.3 million to Genesis Energy, L.P. partners’ capital. Additionally, we reduced our partners’ capital by $26.3 million for the costs related to the transaction ($25.5 million paid to TD Marine and $0.8 million in direct transaction costs associated with the acquisition). The net effect on Genesis Energy, L.P. partners’ capital in our Consolidated Balance Sheet for September 30, 2010 was a decrease of $5.0 million.
 
 
-8-


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

Until July 29, 2010, DG Marine was a variable interest entity as certain of our voting rights were not proportional to our 49% economic interest.  Accounting provisions required us to consolidate DG Marine and reflect the interest of TD Marine as a noncontrolling interest.
 
3. 
Inventories
 
The major components of inventories were as follows:
 
   
September 30, 2010
   
December 31, 2009
 
Crude oil
  $ 18,385     $ 13,901  
Petroleum products
    36,421       22,150  
Caustic soda
    5,406       1,985  
NaHS
    4,350       2,154  
Other
    19       14  
Total inventories
  $ 64,581     $ 40,204  

 
Inventories are valued at the lower of cost or market.  The costs of inventories did not exceed market values at September 30, 2010 and December 31, 2009.
 
4. 
Intangible Assets and Goodwill
 
Intangible Assets
 
The following table reflects the components of intangible assets being amortized at the dates indicated:
 
   
September 30, 2010
   
December 31, 2009
 
   
Gross Carrying Amount
   
Accumulated Amortization
   
Carrying Value
   
Gross Carrying Amount
   
Accumulated Amortization
   
Carrying Value
 
                                     
Customer relationships:
                                   
Refinery services
  $ 94,654     $ 50,217     $ 44,437     $ 94,654     $ 41,450     $ 53,204  
Supply and logistics
    35,430       18,859       16,571       35,430       15,493       19,937  
Supplier relationships -
                                               
Refinery services
    36,469       30,745       5,724       36,469       28,551       7,918  
Licensing Agreements -
                                               
Refinery services
    38,678       14,760       23,918       38,678       11,681       26,997  
Trade names -
                                               
Supply and logistics
    18,888       7,009       11,879       18,888       5,444       13,444  
Favorable lease -
                                               
Supply and logistics
    13,260       1,500       11,760       13,260       1,144       12,116  
Other
    10,129       1,103       9,026       3,823       1,109       2,714  
Total
  $ 247,508     $ 124,193     $ 123,315     $ 241,202     $ 104,872     $ 136,330  

 
-9-


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

Estimated amortization expense for each of the five subsequent fiscal years is expected to be as follows (amounts are exclusive of intangible assets not yet in service associated with our information technology systems upgrade project):
 
Year Ended December 31
 
Amortization Expense to be Recorded
 
Remainder of 2010
  $ 7,042  
2011
  $ 21,918  
2012
  $ 18,261  
2013
  $ 14,264  
2014
  $ 11,790  
2015
  $ 9,856  
 
Goodwill
 
The carrying amount of goodwill by business segment at both September 30, 2010 and December 31, 2009 was $301.9 million to refinery services and $23.1 million to supply and logistics.
 
5. 
Debt
 
Our obligations under credit facilities consisted of the following:
 
   
September 30, 2010
   
December 31, 2009
 
             
Genesis Credit Facility, variable rate, due June 2015
  $ 426,000     $ 320,000  
DG Marine Credit Facility, variable rate
    -       46,900  
Total Long-Term Debt
  $ 426,000     $ 366,900  
 
On June 29, 2010, we restructured our senior secured credit agreement with a syndicate of banks led by BNP Paribas.  Among other changes, our credit agreement:
 
 
·
now matures on June 30, 2015;
 
 
·
provides for a $525 million senior secured revolving credit facility, with the ability to increase the size of the facility up to $650 million, with approval of lenders;
 
 
·
includes a $75 million hedged crude oil and petroleum products inventory loan sublimit based on 90% of the hedged value of the inventory; and
 
 
·
no longer includes “borrowing base” limitations except with respect to inventory loans.
 
Our inventory borrowing base is recalculated monthly.  At September 30, 2010, our inventory borrowing base was $50.4 million.
 
At September 30, 2010, we had $426 million borrowed under our credit agreement, with $50.4 million of that amount designated as a loan under the inventory sublimit.  Additionally, we had $4.3 million in letters of credit outstanding.
 
The key terms for rates under our credit agreement are as follows:
 
 
·
The interest rate on borrowings may be based on a eurodollar rate (“LIBOR”) or an Alternate Base Rate (“ABR”), at our option.  The interest rate on LIBOR borrowings is equal to the sum of (a) the LIBOR rate for the applicable interest period multiplied by the statutory reserve rate and (b) a margin that can range from 2.50% to 3.50%.  The interest rate on ABR borrowings is equal to the sum of (a) the greatest of (i) the prime rate established by BNP Paribas, (ii) the federal funds effective rate plus ½ of 1% and (iii) the LIBOR rate for a one-month maturity plus 1%, and (b) a margin that can range from 1.50% to 2.50%.  The applicable margin under either option is based on our leverage ratio as computed under our credit agreement.  Our leverage ratio is recalculated quarterly and in connection with each material acquisition.  At September 30, 2010, our borrowing rate margins were 2.75% and 1.75% for LIBOR and ABR borrowings, respectively.
 
 
-10-


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

 
·
Letter of credit fees will range from 2.50% to 3.50% based on our leverage ratio as computed under our credit agreement.  This rate can fluctuate quarterly.  At September 30, 2010, our letter of credit rate was 2.75%.
 
 
·
We pay a commitment fee on the unused portion of the $525 million facility amount.  The commitment fee is 0.50%.
 
Collateral under the credit facility consists of substantially all of our assets, excluding our security interest in the NEJD pipeline and our ownership interest in the Free State pipeline.  Our credit agreement is recourse to our general partner only with respect to its general partner interest in certain of our subsidiaries.
 
Our credit agreement contains customary covenants (affirmative, negative and financial) that limit the manner in which we may conduct our business.  Our credit agreement contains three primary financial covenants – a maximum leverage ratio, a maximum senior secured leverage ratio and a minimum interest coverage ratio.  In general, our leverage ratio calculations compare our consolidated funded debt (excluding the amounts borrowed under the inventory sublimit in our credit agreement) to EBITDA (as defined and adjusted in accordance with our credit agreement).  Our interest coverage ratio compares EBITDA (as adjusted) to interest expense.  Our credit agreement includes provisions for the temporary adjustment of the required ratios following material acquisitions and with lender approval.  So long as we are in compliance with the terms of our credit agreement, we have no limitations on our ability to distribute all of our available cash (as defined in our partnership agreement).

We were in compliance with all applicable covenants of our credit agreement at September 30, 2010.

In connection with our purchase of TD Marine’s interest in DG Marine on July 29, 2010, the outstanding balance on the DG Marine credit facility was repaid.  See Note 2.
 
We believe the amounts included in our balance sheet for the debt outstanding under our revolving credit agreement approximate fair value due to the recent restructuring of our credit agreement.
 
6. 
Distributions and Net Income Per Common Unit
 
Distributions
 
We paid or will pay the following distributions in 2009 and 2010:
 
Distribution For
 
Date Paid
   
Per Unit
Amount
   
Limited Partner Interests Amount
   
General Partner Interest Amount
   
General Partner Incentive Distribution Amount
   
Total
Amount
 
                   
Fourth quarter 2008
 
February 2009
    $ 0.3300     $ 13,021     $ 266     $ 823     $ 14,110  
First quarter 2009
 
May 2009
    $ 0.3375     $ 13,317     $ 271     $ 1,125     $ 14,713  
Second quarter 2009
 
August 2009
    $ 0.3450     $ 13,621     $ 278     $ 1,427     $ 15,326  
Third quarter 2009
 
November 2009
    $ 0.3525     $ 13,918     $ 284     $ 1,729     $ 15,931  
Fourth quarter 2009
 
February 2010
    $ 0.3600     $ 14,251     $ 291     $ 2,037     $ 16,579  
First quarter 2010
 
May 2010
    $ 0.3675     $ 14,548     $ 297     $ 2,339     $ 17,184  
Second quarter 2010
 
August 2010
    $ 0.3750     $ 14,845     $ 303     $ 2,642     $ 17,790  
Third quarter 2010
 
November 2010 (1)
    $ 0.3875     $ 15,339     $ 313     $ 3,147     $ 18,799  

(1)  This distribution will be paid on November 12, 2010 to our general partner and unitholders of record as of November 2, 2010.
 
 
-11-


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

Net Income Allocation to Partners
 
Net income is allocated to our partners in the Unaudited Condensed Consolidated Statements of Partners’ Capital as follows:
 
 
·
To our general partner – income in the amount of the incentive distributions paid in the period.
 
 
·
To our general partner – expense in the amount of the executive compensation expense to be borne by our general partner (See Note 9).
 
 
·
To our limited partners and general partner – the remainder of net income in the ratio of 98% to the limited partners and 2% to our general partner.
 
Net Income Per Common Unit
 
The following table sets forth the computation of basic and diluted net income per common unit.
 
   
Three Months Ended
   
Nine Months Ended
 
   
September 30,
   
September 30,
 
   
2010
   
2009
   
2010
   
2009
 
Numerators for basic and diluted net income per common unit:
                       
Income attributable to Genesis Energy, L.P.
  $ 5,068     $ 4,299     $ 26,191     $ 14,045  
Less: General partner's incentive distribution to be paid for the period
    (3,147 )     (1,729 )     (8,128 )     (4,281 )
Add:  Expense for Class B and
                               
Series B Awards (Note 9)
    2,965       3,088       1,289       7,587  
Subtotal
    4,886       5,658       19,352       17,351  
Less: General partner 2% ownership
    (98 )     (113 )     (387 )     (347 )
Income available for common unitholders
  $ 4,788     $ 5,545     $ 18,965     $ 17,004  
                                 
Denominator for basic per common unit:
                               
Common Units
    39,586       39,480       39,573       39,467  
                                 
Denominator for diluted per common unit:
                               
Common Units
    39,586       39,480       39,573       39,467  
Phantom Units (1)
    -       134       16       133  
      39,586       39,614       39,589       39,600  
                                 
Basic net income per common unit
  $ 0.12     $ 0.14     $ 0.48     $ 0.43  
Diluted net income per common unit
  $ 0.12     $ 0.14     $ 0.48     $ 0.43  
 
(1)  See Note 9 for description of Phantom Units.
 
7. 
Business Segment Information
 
We define Segment Margin as revenues less product costs, operating expenses (excluding non-cash charges, such as depreciation and amortization), and segment general and administrative expenses, plus our equity in distributable cash generated by our joint ventures.  Our Segment Margin definition also excludes the non-cash effects of our stock-based compensation plans, and includes the non-income portion of payments received under direct financing leases.  Our chief operating decision maker (our Chief Executive Officer) evaluates segment performance based on a variety of measures including Segment Margin, segment volumes where relevant and maintenance capital investment.
 
 
-12-


GENESIS ENERGY, L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
 
   
Pipeline Transportation
   
Refinery Services
   
Supply &Logistics
   
Industrial Gases
   
Total
 
Three Months Ended September 30, 2010
                             
Segment margin (a)
  $ 11,920     $ 16,218     $ 7,740     $ 3,495     $ 39,373  
                                         
Maintenance capital expenditures
  $ 161     $ 354     $ 201     $ -     $ 716  
                                         
Revenues:
                                       
External customers
  $ 11,059     $ 40,246     $ 520,028     $ 4,679     $ 576,012  
Intersegment (b)
    3,028       (1,809 )     (1,219 )     -       -  
Total revenues of reportable segments
  $ 14,087     $ 38,437     $ 518,809     $ 4,679     $ 576,012  
                                         
Three Months Ended September 30, 2009
                                       
Segment margin (a)
  $ 10,269     $ 12,694     $ 9,423     $ 2,893     $ 35,279  
                                         
Maintenance capital expenditures
  $ 451     $ 162     $ 723     $ -     $ 1,336  
                                         
Revenues:
                                       
External customers
  $ 10,729     $ 31,365     $ 356,783     $ 4,512     $ 403,389  
Intersegment (b)
    1,692       (1,359 )     (333 )     -       -  
Total revenues of reportable segments
  $ 12,421     $ 30,006     $ 356,450     $ 4,512     $ 403,389  

   
Pipeline Transportation
   
Refinery Services
   
Supply &Logistics
   
Industrial Gases
   
Total
 
Nine Months Ended September 30, 2010
                             
Segment margin (a)
  $ 33,756     $ 45,668     $ 19,473     $ 8,990     $ 107,887  
                                         
Maintenance capital expenditures
  $ 295     $ 1,169     $ 795     $ -     $ 2,259  
                                         
Revenues:
                                       
External customers
  $ 33,969     $ 111,964     $ 1,341,166     $ 11,982     $ 1,499,081  
Intersegment (b)
    7,201       (5,804 )     (1,397 )     -       -  
Total revenues of reportable segments
  $ 41,170     $ 106,160     $ 1,339,769     $ 11,982     $ 1,499,081  
                                         
Nine Months Ended September 30, 2009
                                       
Segment margin (a)
  $ 30,841     $ 38,643     $ 21,979     $ 8,785     $ 100,248  
                                         
Maintenance capital expenditures
  $ 1,201     $ 704     $ 1,853     $ -     $ 3,758  
                                         
Revenues:
                                       
External customers
  $ 32,927     $ 117,193     $ 836,934     $ 12,032     $ 999,086  
Intersegment (b)
    4,357       (4,299 )     (58 )     -       -  
Total revenues of reportable segments
  $ 37,284     $ 112,894     $ 836,876     $ 12,032     $ 999,086  

 
-13-


GENESIS ENERGY, L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
 
 
 (a)
A reconciliation of Segment Margin to income before income taxes for the periods presented is as follows:

   
Three Months Ended
   
Nine Months Ended
 
   
September 30,
   
September 30,
 
   
2010
   
2009
   
2010
   
2009
 
                         
Segment Margin
  $ 39,373     $ 35,279     $ 107,887     $ 100,248  
Corporate general and administrative expenses
    (9,769 )     (9,141 )     (21,174 )     (24,218 )
Depreciation and amortization
    (13,477 )     (15,806 )     (40,489 )     (47,358 )
Net (loss) gain on disposal of surplus assets
    (7 )     (17 )     (25 )     141  
Interest expense, net
    (6,542 )     (3,418 )     (13,506 )     (9,826 )
Non-cash expenses not included in segment margin
    (4,301 )     (1,008 )     (2,966 )     (1,850 )
Other items excluded from income affecting segment margin
    (1,259 )     (1,739 )     (3,791 )     (2,456 )
Income before income taxes
  $ 4,018     $ 4,150     $ 25,936     $ 14,681  
 
 
(b)
Intersegment sales were conducted on similar terms as sales to third parties.

8. 
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.  An affiliate of Denbury Resources, Inc. sold its interest in our general partner on February 5, 2010.  Transactions with Denbury through February 5, 2010 are included in the table below as related party transactions.
 
The transactions with related parties were as follows:
 
   
Nine Months Ended September 30,
 
   
2010
   
2009
 
             
Operations, general and administrative services provided by our general partner
  $ 34,827     $ 38,999  
Marine operating costs provided by Quintana affiliate
  $ 1,932     $ -  
Sales of CO2 to Sandhill
  $ 2,101     $ 2,211  
Petroleum products sales to Davison family businesses
  $ 832     $ 602  
Truck transportation services provided to Denbury (1)
  $ 182     $ 2,616  
Pipeline transportation services provided to Denbury (1)
  $ 1,365     $ 10,481  
Payments received under direct financing leases from
               
Denbury (1)
  $ 99     $ 16,390  
Pipeline transportation income portion of direct financing lease fees from Denbury (1)
  $ 1,502     $ 13,754  
Pipeline monitoring services provided to Denbury (1)
  $ 10     $ 90  
CO2 transportation services provided by Denbury (1)
  $ 373     $ 4,029  
Crude oil purchases from Denbury (1)
  $ -     $ 1,754  

(1)  Amounts for 2010 only through February 5, 2010.

 
-14-


GENESIS ENERGY, L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
 
Additionally, on July 29, 2010, we acquired the 51% interest of TD Marine in DG Marine.  See Note 3.
 
Amounts due to and from Related Parties
 
At September 30, 2010 and December 31, 2009, we owed our general partner $2.0 million and $2.1 million for administrative services, respectively.  We owed an affiliate of Quintana Capital Group II, L.P.  $0.2 million at September 30, 2010 for fuel and other expenses associated with our inland marine barge operations.  Sandhill owed us $0.3 million and $0.7 million for purchases of CO2 at September 30, 2010 and December 31, 2009, respectively.  Denbury owed us $1.9 million for truck and pipeline transportation services, and we owed Denbury $1.0 million for CO2 transportation charges at December 31, 2009.
 
9. 
Equity-Based Compensation
 
We recorded charges related to our equity-based compensation plans and awards for the three and nine months ended September 30, 2010 and 2009 as follows:
 
Expense Related to Equity-Based Compensation

   
Three Months Ended
   
Nine Months Ended
 
   
September 30,
   
September 30,
 
Statement of Operations
 
2010
   
2009
   
2010
   
2009
 
Pipeline operating costs
  $ 200     $ 124     $ 307     $ 208  
Refinery services operating costs
    234       139       409       289  
Supply and logistics operating costs
    758       481       1,052       910  
General and administrative expenses
    3,829       3,710       2,819       9,041  
Total
  $ 5,021     $ 4,454     $ 4,587     $ 10,448  
 
In connection with the sale of our general partner on February 5, 2010, our general partner redeemed all of its Class B Member Interests and replaced its Class A Member Interest with Series A units and Series B units.
 
Series B Units
 
Our general partner uses the Series B Units, which have no voting rights, as part of its long-term compensation structure for our management team.  A total of 1,000 Series B Units may be issued by our general partner.  Pursuant to restricted unit agreements entered into with Genesis Energy, LLC, our general partner, on February 5, 2010, certain members of our management team received an aggregate of 767 Series B units in our general partner.  Provided the holder of the Series B Units is still employed on the seventh anniversary of the issuance date of the awards, the Series B Units will be converted into Series A Units (unless a conversion occurs at a prior date due to a public offering or a change in control of our general partner).

Subject to the rights of the holders of the Series A units in our general partner to receive distributions up to certain threshold amounts, holders of Series B units, upon vesting, have the right to receive a share of the distributions paid by us to our general partner.  With regard to the right to receive a share of distributions, the Series B Units vest 25% per year on each of the next four anniversary dates of the award.  The four-year vesting requirement would also be applicable to any conversion due to a public offering should that conversion occur in the first four years after issuance of the award.

Although the Series B units represent an equity interest in our general partner and our general partner will not seek reimbursement under our partnership agreement for the value of these compensation arrangements, we will record non-cash expense for the estimated fair value of the awards.  The estimated fair value of the converted Series B units will be recomputed at each quarterly reporting date until conversion, and the expense to be recorded will be adjusted based on that fair value, with an offsetting entry to the capital account of our general partner.

Management’s estimates of the fair value of these awards are based on a number of future events, including estimates of the distributions that would be received by our general partner in the future through the conversion date of February 5, 2017, the fair value of our general partner at February 5, 2017, and assumptions about an appropriate discount rate.  Changes in our assumptions will change the amount of expense we record.
 
 
-15-


GENESIS ENERGY, L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
 
At September 30, 2010, management estimates that the fair value of the Series B Units granted to our management team is approximately $36.4 million.  This estimate of the fair value was determined using a discount rate of 14%.  Due to the limited number of holders of Series B Units, we assumed a forfeiture rate of zero.  For the three and nine months ended September 30, 2010, we recorded non-cash expense of $3.0 million and $3.5 million, respectively for these awards.
 
2007 Long Term Incentive Plan
 
As a result of the sale of our general partner on February 5, 2010, all outstanding phantom units issued pursuant to our 2007 Long Term Incentive Plan vested.   As a result of this acceleration of the vesting period, we recorded non-cash compensation expense of $0.5 million in the first quarter of 2010.  In total, 123,857 phantom units vested.
 
Class B Membership Interests
 
All of the Class B membership interests in our general partner held by the existing management team were either (i) converted into Series A units in our general partner or (ii) redeemed by our general partner on February 5, 2010.  The amounts owed under the deferred compensation plan with the management team were similarly converted or redeemed.  In total, the value of the Series A units issued and cash payments made by our general partner to settle its obligations under the Class B membership interests and deferred compensation totaled $14.9 million. This value, when combined with amounts previously paid to our management team during 2009 related to the Class B membership interests, resulted in total compensation expense of $15.4 million.  The difference between the recorded cumulative compensation expense related to these interests through December 31, 2009 of $17.5 million and the total compensation expense of $15.4 million was recorded as a reduction of expense in the first quarter of 2010.

2010 Long Term Incentive Plan
 
In the second quarter of 2010, our general partner adopted the Genesis Energy, LLC 2010 Long-Term Incentive Plan (the “2010 Plan”).  The 2010 Plan provides for the awards of phantom units and distribution equivalent rights to directors of our general partner, and employees and other representatives of our general partner and its affiliates who provide services to us.  Phantom units are notional units representing unfunded and unsecured promises to pay to the participant a specified amount of cash based on the market value of our common units should specified vesting requirements be met.  Distribution equivalent rights (“DERs”) are tandem rights to receive on a quarterly basis an amount of cash equal to the amount of distributions that would have been paid on the phantom units had they been limited partner units issued by us.  The 2010 Plan is administered by the Governance, Compensation and Business Development Committee (the “GCBD Committee”) of the board of directors of our general partner.

The GCBD Committee (at its discretion) will designate participants in the 2010 Plan, determine the types of awards to grant to participants, determine the number of units to be covered by any award, and determine the conditions and terms of any award including vesting, settlement and forfeiture conditions.  Awards under the 2010 Plan of 54,806 phantom units with tandem DERs were made in the first nine months of 2010.  The phantom units will vest on the third anniversary of the date of issuance.

The compensation cost associated with the phantom units is re-measured each reporting period based on the fair value of the phantom units, and the liability recorded for the estimated amount to be paid to the participants will be adjusted.  Management’s estimates of the fair value of these awards include assumptions about expectation of forfeitures prior to vesting.  Due to the positions of the small group of employees and non-employee directors who received these awards, we have assumed that there will be no forfeitures of these phantom units in our fair value calculation as of September 30, 2010.  At September 30, 2010, we estimate the fair value of these awards to be approximately $1.2 million, and we recorded $0.2 million of compensation expense for the three and nine months ended September 30, 2010.
 
 
-16-


GENESIS ENERGY, L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
 
10. 
Supplemental Cash Flow Information
 
The following table provides information regarding the net changes in components of operating assets and liabilities.
 
   
Nine Months Ended
 
   
September 30,
 
   
2010
   
2009
 
Decrease (increase) in:
           
Accounts receivable
  $ (39,771 )   $ (7,513 )
Inventories
    (25,571 )     (15,048 )
Other current assets
    831       (523 )
Increase (decrease) in:
               
Accounts payable
    22,503       4,071  
Accrued liabilities
    (1,002 )     (330 )
Net changes in components of operating assets and liabilities,net of working capital acquired
  $ (43,010 )   $ (19,343 )
 
Cash received by us for interest for the nine months ended September 30, 2010 and 2009 was less than $0.1 million.  Payments of interest and commitment fees were $10.8 million and $10.9 million for the nine months ended September 30, 2010 and 2009, respectively.
 
Cash paid for income taxes during the nine months ended September 30, 2010 and 2009 was $2.2 million and $1.0 million, respectively.
 
At September 30, 2010, we had incurred liabilities for fixed and intangible assets and other asset additions totaling $2.0 million that had not been paid at the end of the third quarter, and, therefore, are not included in the caption “Payments to acquire fixed and intangible assets” under investing activities on the Unaudited Condensed Consolidated Statements of Cash Flows.  At September 30, 2009, we had incurred $0.3 million of such liabilities that had not been paid at that date and are not included in “Payments to acquire fixed and intangible assets” under investing activities.
 
11. 
Derivatives
 
 Commodity Derivatives
 
At September 30, 2010, we had the following outstanding derivative commodity futures, forwards and options contracts that were entered into to hedge inventory or fixed price purchase commitments:
 
 
-17-


GENESIS ENERGY, L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
 
   
Sell (Short) Contracts
   
Buy (Long) Contracts
 
Designated as hedges under accounting rules:
           
Crude oil futures:
           
Contract volumes (1,000 bbls)
    159       -  
Weighted average contract price per bbl
  $ 78.08     $ -  
                 
Not qualifying or not designated as hedges under accounting rules:
               
Crude oil futures:
               
Contract volumes (1,000 bbls)
    554       417  
Weighted average contract price per bbl
  $ 75.86     $ 75.78  
                 
Heating oil futures:
               
Contract volumes (1,000 bbls)
    115       15  
Weighted average contract price per gal
  $ 2.16     $ 2.32  
                 
RBOB gasoline futures:
               
Contract volumes (1,000 bbls)
    44       -  
Weighted average contract price per gal
  $ 1.93     $ -  
                 
#6 Fuel oil futures:
               
Contract volumes (1,000 bbls)
    325       215  
Weighted average contract price per bbl
  $ 66.92     $ 67.85  
                 
Crude oil written calls and puts:
               
Contract volumes (1,000 bbls)
    252       -  
Weighted average premium received
  $ 1.71     $ -  
 
Interest Rate Derivatives
 
Until July 29, 2010, DG Marine utilized swap contracts with financial institutions to hedge interest payments for a portion of its outstanding debt.  DG Marine expected these interest rate swap contracts to be highly effective in limiting its exposure to fluctuations in market interest rates; therefore, we designated these swap contracts as cash flow hedges under accounting guidance.  The effective portion of the derivative represented the change in fair value of the hedge that offset the change in cash flows of the hedged item.  The effective portion of the gain or loss in the fair value of these swap contracts was reported as a component of AOCL and was reclassified into future earnings contemporaneously as interest expense associated with the underlying debt under the DG Marine credit facility was recorded.    In the third quarter of 2010, we settled the DG Marine interest rate swaps in connection with our acquisition of the 51% of DG Marine that we did not own.  See Note 2.
 
Financial Statement Impacts
 
The following tables reflect the estimated fair value gain (loss) position of our hedge derivatives and related inventory impact for qualifying hedges at September 30, 2010 and December 31, 2009:
 
 
-18-

 
GENESIS ENERGY, L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
 
Fair Value of Derivative Assets and Liabilities

 
Asset Derivatives
 
 
Unaudited Condensed Consolidated Balance Sheets
 
Fair Value
 
 
Location
 
September 30, 2010
   
December 31, 2009
 
Commodity derivatives - futures and call options:
             
Hedges designated under accounting guidance as fair value hedges
 Other Current Assets
  $ 768     $ 53  
Undesignated hedges
 Other Current Assets
    1,516       307  
Total asset derivatives
    $ 2,284     $ 360  

 
Liability Derivatives
 
 
Unaudited Condensed Consolidated Balance Sheets
 
Fair Value
 
 
Location
 
September 30, 2010
   
December 31, 2009
 
Commodity derivatives - futures and call options:
             
Hedges designated under accounting guidance as fair value hedges
 Other Current Assets
  $ (1,250 )(1)   $ (159 )(1)
Undesignated hedges
 Other Current Assets
    (4,040 )(1)     (2,118 )(1)
Total commodity derivatives
      (5,290 )     (2,277 )
                   
Interest rate swaps designated as cash flow hedges under accounting rules:
                 
Portion expected to be reclassified into earnings within one year
 Accrued Liabilities
    -       (1,176 )
Portion expected to be reclassified into earnings after one year
 Other Long-term Liabilities
    -       (512 )
                   
Total liability derivatives
    $ (5,290 )   $ (3,965 )

 
(1)
These derivative liabilities have been funded with margin deposits recorded in our Unaudited Condensed Consolidated Balance Sheets in Other Current Assets.
 
 
-19-


GENESIS ENERGY, L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
 
   
Effect on Unaudited Condensed Consolidated Statements of Operations
and Other Comprehensive Income
 
   
Amount of Gain (Loss) Recognized in Income
 
   
Supply & Logistics
   
Interest Expense
   
Other Comprehensive
Income
 
   
Product Costs
   
Reclassified from AOCL
   
Effective Portion
 
   
Three Months
   
Three Months
   
Three Months
 
   
Ended September 30,
   
Ended September 30,
   
Ended September 30,
 
   
2010
   
2009
   
2010
   
2009
   
2010
   
2009
 
Commodity derivatives - futures and call options:
                                   
Contracts designated as hedges under accounting guidance
  $ (354 )   $ 758     $ -     $ -     $ -     $ -  
Contracts not considered hedges under accounting guidance
    (138 )     1,288       -       -       -       -  
Total commodity derivatives
    (492 )     2,046       -       -       -       -  
                                                 
Interest rate swaps designated as cash flow hedges under accounting guidance
    -       -       (1,553 )     (224 )     (224 )     (315 )
                                                 
Total derivatives
  $ (492 )   $ 2,046     $ (1,553 )   $ (224 )   $ (224 )   $ (315 )

   
Effect on Unaudited Condensed Consolidated Statements of Operations
and Other Comprehensive Income
 
   
Amount of Gain (Loss) Recognized in Income
 
                           
Other Comprehensive
 
   
Supply & Logistics
   
Interest Expense
   
Income
 
   
Product Costs
   
Reclassified from AOCL
   
Effective Portion
 
   
Nine Months
   
Nine Months
   
Nine Months
 
   
Ended September 30,
   
Ended September 30,
   
Ended September 30,
 
   
2010
   
2009
   
2010
   
2009
   
2010
   
2009
 
Commodity derivatives - futures and call options:
                                   
Contracts designated as hedges under accounting guidance
  $ 952 (1)   $ (4,094 )(1)   $ -     $ -     $ -     $ -  
Contracts not considered hedges under accounting guidance
    4,287       (1,075 )     -       -       -       -  
Total commodity derivatives
    5,239       (5,169 )     -       -       -       -  
                                                 
Interest rate swaps designated as cash flow hedges under accounting guidance
    -       -       (2,112 )     (514 )     (424 )     (400 )
                                                 
Total derivatives
  $ 5,239     $ (5,169 )   $ (2,112 )   $ (514 )   $ (424 )   $ (400 )
 
 
(1) 
Represents the amount of gain (loss) recognized in income for derivatives related to the fair value hedge of inventory.  The amount excludes the gain recorded on the hedged inventory under the fair value hedge of $0.5 million for the nine months ended September 30, 2010 and excludes the gain on the hedged inventory under the fair value hedge of $6.4 million for the nine months ended September 30, 2009.
 
 
-20-


GENESIS ENERGY, L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
 
We have no derivative contracts with credit contingent features.
 
12. 
Fair-Value Measurements
 
The following table sets forth by level within the fair value hierarchy our financial assets and liabilities that were accounted for at fair value on a recurring basis as of September 30, 2010.  As required by fair value accounting guidance, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement.  Our assessment of the significance of a particular input to the fair value requires judgment and may affect the placement of assets and liabilities within the fair value hierarchy levels.
 
   
Fair Value at September 30, 2010
   
Fair Value at December 31, 2009
 
Recurring Fair Value Measures
 
Level 1
   
Level 2
   
Level 3
   
Level 1
   
Level 2
   
Level 3
 
                                     
Commodity derivatives:
                                   
Assets
  $ 2,284     $ -     $ -     $ 360     $ -     $ -  
Liabilities
  $ (5,290 )   $ -     $ -     $ (2,277 )   $ -     $ -  
                                                 
Interest rate swaps - Liabilities
  $ -     $ -     $ -     $ -     $ -     $ (1,688 )
 
Level 1
 
Included in Level 1 of the fair value hierarchy as commodity derivative contracts are exchange-traded futures and exchange-traded option contracts.  The fair value of these exchange-traded derivative contracts is based on unadjusted quoted prices in active markets and is, therefore, included in Level 1 of the fair value hierarchy.
 
Level 2
 
At September 30, 2010, we had no Level 2 fair value measurements.
 
Level 3
 
At September 30, 2010, we had no Level 3 fair value measurements.  Included within Level 3 of the fair value hierarchy at December 31, 2009, were our interest rate swaps.  These swaps were closed out in July 2010 in connection with the acquisition of the 51% of DG Marine we did not own and the termination of DG Marine’s credit facility.
 
The following table provides a reconciliation of changes in fair value of the beginning and ending balances for our derivatives measured at fair value using inputs classified as Level 3 in the fair value hierarchy:
 
   
Three Months Ended
   
Nine Months Ended
 
   
September 30,
   
September 30,
 
   
2010
   
2009
   
2010
   
2009
 
Balance at beginning of period
    (1,329 )     (1,759 )     (1,688 )     (1,964 )
Realized and unrealized gains (losses)-
                               
Reclassified into interest expense
    1,553       224       2,112       514  
Included in other comprehensive income
    (224 )     (315 )     (424 )     (400 )
Balance at end of period
  $ -     $ (1,850 )   $ -     $ (1,850 )
                                 
Total amount of losses for the nine months ended included in earnings attributable to the change in unrealized losses relating to contracts still held at September 30, 2010 and 2009, respectively
                  $ -     $ (9 )
 
See Note 11 for additional information on our derivative instruments.
 
 
-21-


GENESIS ENERGY, L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
 
We generally apply fair value techniques on a non-recurring basis associated with (1) valuing potential impairment loss related to goodwill, (2) valuing asset retirement obligations, and (3) valuing potential impairment loss related to long-lived assets.
 
13. 
Contingencies
 
We are subject to various environmental laws and regulations.  Policies and procedures are in place to monitor compliance and to detect and address any material releases of crude oil, petroleum products or chemicals from our pipelines or other facilities; however, no assurance can be made that such environmental releases may not substantially affect our business.
 
We are subject to lawsuits in the normal course of business, as well as examinations 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.
 
14. 
Subsequent Event – Cameron Highway Oil Pipeline Company Acquisition
 
On October 22, 2010, we executed a definitive agreement to purchase Valero Energy Corporation’s ("Valero") 50% equity interest in Cameron Highway Oil Pipeline Company (“Cameron Highway”), a partnership, for $330 million in cash.  Enterprise Products Partners, L.P. also owns a 50% interest in and operates Cameron Highway.  The transaction is expected to close before year end, subject to usual and customary conditions, including receipt of all regulatory approvals.  The purchase price is subject to customary adjustments, including for working capital.
 
We intend to permanently fund the acquisition with some combination of equity and debt.  However, to protect against the possibility of a rapid deterioration in the capital markets, we entered into an agreement with a group of banks to provide up to $300 million of unsecured financing.  This unsecured facility allows for borrowings through December 31, 2011.
 
 
-22-


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
 
 
·
Available Cash before Reserves
 
 
·
Results of Operations
 
 
·
Liquidity and Capital Resources
 
 
·
Commitments and Off-Balance Sheet Arrangements
 
In the discussions that follow, we will focus on our revenues, expenses and net income, as well as two measures that we use to manage our business and to review our results of our operations.  Those two measures are Segment Margin and Available Cash before Reserves.  We define Segment Margin as revenues less product costs, operating expenses (excluding non-cash charges, such as depreciation and amortization), and segment general and administrative expenses, plus our equity in distributable cash generated by our joint ventures.  In addition, our Segment Margin definition excludes the non-cash effects of our equity-based compensation plans, and includes the non-income portion of payments received under direct financing leases.  Our chief operating decision maker (our Chief Executive Officer) evaluates segment performance based on a variety of measures including Segment Margin, segment volumes where relevant, and maintenance capital investment.  A reconciliation of Segment Margin to income before income taxes is included in our segment disclosures in Note 7 to our Unaudited Condensed Consolidated Financial Statements.
 
Available Cash before Reserves (a non-GAAP measure) is net income as adjusted for specific items, the most significant of which are the addition of non-cash expenses (such as depreciation), the substitution of cash generated by our equity investees in lieu of our equity income attributable to such equity investees, the elimination of gains and losses on asset sales (except those from the sale of surplus assets), the elimination of expenses related to acquiring or constructing assets that provide new sources of cash flows, the elimination of earnings of DG Marine in excess of distributable cash until July 29, 2010 when DG Marine’s credit facility was repaid, 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 Reconciliation below.
 
Overview
 
In the third quarter of 2010, we reported net income attributable to the partnership of $5.1 million, or $0.12 per common unit. We generated $28.1 million of Available Cash before Reserves, and we will distribute $18.8 million to holders of our common units and general partner for the third quarter.  During the third quarter of 2010, cash provided by operating activities was $23.4 million, which we believe is the most directly comparable GAAP financial measure to Available Cash before Reserves.
 
On October 13, 2010, we increased our quarterly distribution rate to our common unitholders for the twenty-first consecutive quarter.  We will pay a distribution in November 2010 attributable to the third quarter of 2010 of $0.3875 per unit, which represents an approximate 9.9% increase from our distribution of $0.3525 per unit for the third quarter of 2009.  We paid a distribution in August 2010 attributable to the second quarter of 2010 of $0.375 per unit.
 
On July 29, 2010, we acquired the 51% interest in DG Marine held by a related party for $25.5 million, resulting in DG Marine becoming a wholly-owned subsidiary.   Additionally, we paid off DG Marine’s stand-alone credit facility with proceeds from our credit agreement.
 
On June 29, 2010, we restructured our senior secured credit facility.  Our credit facility now provides for a $525 million senior secured revolving credit facility, includes an accordion feature whereby the total credit available can be increased up to $650 million under certain circumstances, and matures on June 30, 2015.  Among other modifications, our credit facility now includes a $75 million sublimit tranche designed for more efficient financing of crude oil and petroleum products inventory.  See additional discussion under Liquidity and Capital Resources – Capital Resources/Sources of Cash below and in Note 5 to our Unaudited Condensed Consolidated Financial Statements.
 
 
-23-


On October 22, 2010, we entered into an agreement to acquire a 50% interest in Cameron Highway for approximately $330 million in cash.  Cameron Highway, constructed in 2004, is a 380-mile 24-and 30-inch diameter pipeline, with capacity to deliver up to 500,000 barrels per day of crude oil from developments in the Gulf of Mexico to major refining markets along the Texas Gulf Coast located in Port Arthur and Texas City and includes approximately $50 million of linefill and $9 million in pumping equipment (in each case, net to Valero's interest). Valero's share of annualized distributions from the joint venture was approximately $27 million and $33 million at December 31, 2009 and June 30, 2010, respectively.   During the twelve-month period ended June 30, 2010, Cameron Highway’s owners received distributions totaling approximately $65 million.  In the future, we expect the annualized distributions to be higher following resumed development of the fields (following the end to the moratorium on offshore drilling activities in the deepwater Gulf of Mexico as of October 12, 2010) currently dedicated to the pipeline as well as Cameron Highway’s ability to provide services to future developments.  We expect to fund this transaction with some combination of equity and debt.  See additional discussion under Liquidity and Capital Resources – Capital Resources/Sources of Cash below.
 
We believe our current cash balances, internally-generated funds and funds available under our credit facility will provide sufficient resources to meet our current working capital needs.  The financial performance of our existing businesses and the absence of any need to access the capital markets (other than opportunistically) may allow us to take advantage of other acquisition and/or growth opportunities that may develop.
 
Our ability to fund large new projects or make other large acquisitions in the near term may be limited by the current conditions in the credit and equity markets due to limitations in our ability to consummate future debt or equity financings.  We also will consider other arrangements to fund large growth projects and acquisitions such as private equity and joint venture arrangements.
 
Available Cash before Reserves
 
Available Cash before Reserves was as follows:
 
   
Three Months
 
   
Ended September 30,
 
   
2010
   
2009
 
   
(in thousands)
 
Net income attributable to Genesis Energy, L.P.
  $ 5,068     $ 4,299  
Depreciation and amortization
    13,477       15,806  
Cash received from direct financing leases not included in income
    1,063       951  
Unrealized loss on inventory accounting hedges and derivative transactions
    2,934       211  
Effects of available cash generated by equity method investees not included in income
    196       787  
Cash effects of equity-based compensation plans
    (165 )     (77 )
Non-cash tax expense
    235       (3 )
Loss (earnings) of DG Marine in excess of distributable cash
    1,686       (1,108 )
Non-cash equity-based compensation benefit
    4,999       4,454  
Other non-cash items, net
    (651 )     (269 )
Maintenance capital expenditures
    (716 )     (1,336 )
Available Cash before Reserves
  $ 28,126     $ 23,715  
 
 
-24-

 
We have reconciled Available Cash before Reserves (a non-GAAP measure) to cash flow from operating activities (the most comparable GAAP measure) for the three months ended September 30, 2010 and 2009 in Liquidity and Capital Resources – Non-GAAP Reconciliation below.  For the three months ended September 30, 2010 and 2009, cash flows provided by operating activities were $23.4 million and $36.8 million, respectively.
 
Results of Operations
 
Revenues, Costs and Expenses and Net Income
 
Our revenues for the three months ended September 30, 2010 increased $173 million, or 43% from the third quarter of 2009.  Additionally, our costs and expenses increased $171 million, or 43% between the two periods.  The majority of our revenues and costs are derived from the purchase and sale of crude oil and petroleum products.  The increase in our revenues and costs between the two third quarter periods is primarily attributable to fluctuations in the volumes of crude oil and petroleum products purchased and sold by our supply and logistics segment.  Such volumes increased by 25,704 barrels per day, or 50%, as we increased our activities for petroleum products in response to additional opportunities to acquire volumes.
 
Net income (attributable to us) increased $0.8 million, or 18%, between the third quarter of 2009 and the same period in 2010.  The significant factors affecting net income were improved operating results by most of our business segments as compared to the third quarter of 2009 and a net reduction in our non-cash general and administrative expenses for 2010 resulting from the sale of our general partner (comprised of a decrease in the amount of our non-cash executive compensation and equity-based compensation resulting from our general partner’s redemption of certain equity interests, partially offset by other transaction related costs).  A more detailed discussion of our segment results and other costs is included below.
 
Our revenues for the nine months ended September 30, 2010 increased $500 million, or 50% from the nine months ended September 30, 2009.  Additionally, our costs and expenses increased $485 million, or 50% between the two periods.  This increase in our revenues and costs between the two periods is primarily due to fluctuations in the market prices for crude oil and petroleum products, combined with an increase of 30% in the volumes of these products.  In the first nine months of 2010, average closing prices for West Texas Intermediate crude oil on the New York Mercantile Exchange averaged $77.65 per barrel, as compared to $57.00 per barrel in the first nine months of 2009 – an increase of 36%.  Net income (attributable to us) increased $12.1 million, or 86%, between the first nine months of 2009 and the same period in 2010, with the majority of this increase attributable to the improved segment results, decreased general and administrative expenses and a decrease in depreciation and amortization expense as discussed below.
 
Segment Margin
 
The contribution of each of our segments to total Segment Margin in the three and nine months ended September 30, 2010 and 2009 was as follows:
 
   
Three Months Ended September 30,
   
Nine Months Ended September 30,
 
   
2010
   
2009
   
2010
   
2009
 
   
(in thousands)
   
(in thousands)
 
Pipeline transportation
  $ 11,920     $ 10,269     $ 33,756     $ 30,841  
Refinery services
    16,218       12,694       45,668       38,643  
Supply and logistics
    7,740       9,423       19,473       21,979  
Industrial gases
    3,495       2,893       8,990       8,785  
Total Segment Margin
  $ 39,373     $ 35,279     $ 107,887     $ 100,248  
 
Pipeline Transportation Segment
 
Operating results for our pipeline transportation segment were as follows:

 
-25-


   
Three Months Ended September 30,
   
Nine Months Ended September 30,
 
   
2010
   
2009
   
2010
   
2009
 
   
(in thousands)
   
(in thousands)
 
                         
Crude oil tariffs and revenues from direct financing leases of crude oil pipelines
  $ 5,473     $ 4,511     $ 14,885     $ 12,461  
CO2 tariffs and revenues from direct financing leases of CO2 pipelines
    6,519       6,361       19,470       19,481  
Sales of crude oil pipeline loss allowance volumes
    1,372       922       4,244       3,127  
Non-income payments under direct financing leases
    1,063       951       3,116       2,787  
Other miscellaneous revenues
    175       171       526       488  
Revenues from natural gas tariffs and sales
    547       456       2,044       1,727  
Natural gas purchases
    (490 )     (395 )     (1,847 )     (1,519 )
Pipeline operating costs, excluding non-cash charges for our equity-based compensation plans and other non-cash charges
    (2,739 )     (2,708 )     (8,682 )     (7,711 )
Segment margin
  $ 11,920     $ 10,269     $ 33,756     $ 30,841  

Throughput Volumes:
 
Three Months Ended September 30,
   
Nine Months Ended September 30,
 
Pipeline System
 
2010
   
2009
   
2010
   
2009
 
                         
Mississippi-Bbls/day
    23,672       22,643       23,750       24,046  
Jay - Bbls/day
    16,555       10,550       15,188       9,767  
Texas - Bbls/day
    31,549       24,593       26,280       26,477  
Free State - Mcf/day
    158,546       133,038       155,541       146,160  
 
Three Months Ended September 30, 2010 Compared with Three Months Ended September 30, 2009
 
Pipeline Segment Margin for the third quarter of 2010 increased $1.7 million.   The significant components of this change were as follows:
 
 
·
Crude oil tariffs and revenues from direct financing leases increased $1.0 million.  This increase in revenues was a function of volume increases on all three of our pipelines.
 
 
-
Volumes transported on our Jay crude oil pipeline system increased 6,005 barrels per day.  At the end of 2009, a producer connected to our Jay System restarted production from wells that were shut in during the majority of 2009 due to the decline in crude oil prices.  Additionally, the Castleberry extension of our Jay System allowed us to access additional production in the area, increasing volumes on the Jay System between the periods.
 
 
-
Volumes on the Texas System increased 6,956 barrels per day; however, approximately 80% of the volume on that system in the third quarter was shipped on a tariff of $0.31 per barrel.
 
 
-
Volume fluctuations on the Mississippi System, where the incremental tariff rate is only $0.25 per barrel, are primarily a result of activities of crude oil producers. Volumes on this system increased by 1,029 barrels per day.
 
 
·
CO2 tariffs and revenues from direct financing leases of CO2 pipelines increased $0.2 million primarily due to increased volumes on the Free State pipeline of 25.5 MMcf per day.
 
 
·
An increase in revenues from sales of pipeline loss allowance volumes increased Segment Margin by $0.5 million.  Pipeline allowance volumes increased 1,589 barrels.  Higher market prices for crude oil increased the value of our pipeline loss allowance volumes and, accordingly, our loss allowance revenues.  Average crude oil prices increased approximately $7.90, or 12%, between the two quarterly periods.
 
 
-26-


Nine Months Ended September 30, 2010 Compared with Nine Months Ended September 30, 2009
 
Pipeline Segment Margin increased $2.9 million between the nine month periods, with $2.4 million of the change due to increased crude oil tariff revenues.  Sales of pipeline loss allowance volumes added to Segment Margin, but were largely offset by an increase in operating costs.  The significant components of this change were as follows:

 
·
Volumes on the Jay System increased 5,421 barrels per day due to restarted production from wells that had been shut in for most of 2009 as well as the addition of volumes we are able to access with the Castleberry extension to the Jay System.  Volumes on the Texas and Mississippi Systems declined between the periods in large part to maintenance in the first quarter of 2010 on the Texas System.

 
·
Tariff rate increases of approximately 7.6% on our Jay and Mississippi pipelines went into effect July 1, 2009. Tariff rate decreases of approximately 1.3% on our Jay and Mississippi pipelines went into effect July 1, 2010.  Segment Margin increased by a net of approximately $0.5 million between the two periods as a result of these rate changes.
 
 
·
An increase in revenues from sales of pipeline loss allowance volumes increased Segment Margin by $1.1 million related to the significant increase (an average of $21 per barrel) in crude oil prices which more than offset the decrease in pipeline loss allowance volumes of approximately 3,615 barrels.
 
 
·
Pipeline operating costs increased $1.0 million largely due to an increase in pipeline integrity tests and other maintenance costs.  In the first quarter of 2010 pipeline integrity tests on a segment of our Texas System cost approximately $0.6 million.
 
Refinery Services Segment
 
Operating results for our refinery services segment were as follows:
 
 
-27-


   
Three Months Ended September 30,
   
Nine Months Ended September 30,
 
   
2010
   
2009
   
2010
   
2009
 
Volumes sold:
                       
NaHS volumes (Dry short tons "DST")
    35,415       28,207       106,829       75,344  
NaOH (caustic soda) volumes (DST)
    21,442       26,898       66,778       63,561  
Total
    56,857       55,105       173,607       138,905  
                                 
Revenues (in thousands):
                               
NaHS revenues
  $ 30,498     $ 22,654     $ 85,270     $ 74,754  
NaOH (caustic soda) revenues
    7,586       6,455       19,198       33,534  
Other revenues
    2,162       2,256       7,496       8,905  
Total external segment revenues
  $ 40,246     $ 31,365     $ 111,964     $ 117,193  
                                 
Segment margin
  $ 16,218     $ 12,694     $ 45,668     $ 38,643  
                                 
Average index price for caustic soda per DST (1)
  $ 378     $ 198     $ 329     $ 493  
                                 
Raw material and processing costs as % of segment revenues
    38 %     33 %     34 %     47 %
Delivery costs as a % of segment revenues
    14 %     14 %     16 %     11 %
 
 
(1)
 Source:  Harriman Chemsult Ltd.
 
Three Months Ended September 30, 2010 Compared with Three Months Ended September 30, 2009
 
Refinery services Segment Margin for the third quarter of 2010 was $16.2 million, an increase of $3.5 million, or 28%, from the comparative period in 2009.  The significant components of this fluctuation were as follows:
 
 
·
An increase in NaHS sales volumes of 26%.  As the world economies, particularly outside of the United States and European Union, are recovering from the depths of the greatest recession in the last 70 years, the demand for base metals such as copper and molybdenum has increased dramatically over the prior period.  As a result, we have experienced a noticeable increase in the demand for NaHS from our mining customers in North and South America.  Additionally, with the return of industrialization and urbanization in the world’s more underdeveloped economies, the demand for paper products and packaging materials has increased dramatically.  This trend has led to an increase in demand for NaHS from our pulp/paper customers primarily in North America.  The pricing in the majority of our sales contracts for NaHS includes an adjustment for fluctuations in commodity benchmarks, freight, labor, energy costs and government indexes.  The frequency at which these adjustments can be applied varies by geographic region and supply point.
 
 
·
A decrease in caustic soda sales volumes of 20%.  Caustic soda is a key component in the provision of our sulfur-removal service, from which we receive the by-product NaHS.  We are a very large consumer of caustic soda.  In addition, our economies of scale and logistics capabilities allow us to effectively market caustic soda to third parties.  Fluctuations in volumes sold are affected by the demand we have in our operations that consume caustic soda.
 
 
·
Index prices for caustic soda averaged approximately $198 per DST in the third quarter of 2009.  Market prices of caustic soda increased to an average of approximately $378 per DST during the third quarter of 2010.  Those price movements affect the revenues and costs related to our sulfur removal services as well as our caustic soda sales activities.  However, changes in caustic soda prices generally do not materially affect Segment Margin attributable to our sulfur processing services because we generally pass those costs through to our NaHS sales customers. The increase in caustic soda prices did, however, increase our revenues from sales of caustic soda by 18% despite the decrease in caustic soda sales volumes.
 
 
-28-

 
Nine Months Ended September 30, 2010 Compared with Nine Months Ended September 30, 2009
 
Segment margin for our refinery services increased $7.0 million for similar reasons to the quarterly comparison.
 
 
·
NaHS volumes increased 42% as a result of increased demand from mining companies and other industrial customers.  As discussed above, increases in demand for base metals and paper products in the global economy have positively impacted demand for NaHS in North and South America.  The average sales price of NaHS declined by 20% even though we experienced increases in some commodity components and contractual price inflators, which were more than offset by the declines in other costs. The related revenue increase was only 14% due to the effects of the pass-through of fluctuations in commodity benchmarks and transportation.
 
 
·
Caustic soda sales volumes increased 5%, although revenues decreased 43% because the market prices for caustic soda decreased from an average of $493 per DST in the first nine months of 2009 to an average of $329 per DST in the first nine months of 2010.
 
 
·
Delivery logistics costs were higher. Although our logistics costs per unit increased only modestly, our logistics costs expressed as a percentage of revenues increased by 5% (to 16%) primarily because our sales price per unit, along with our cost per unit, dropped precipitously.  Quantities delivered to customers also increased.  Freight demand and fuel prices increased modestly in the 2010 period as economic conditions improved, increasing demand for transportation services  and the increase in crude oil prices increased the cost of fuel used in transporting these products.

Supply and Logistics Segment
 
Operating results from our supply and logistics segment were as follows:
 
   
Three Months Ended September 30,
   
Nine Months Ended September 30,
 
   
2010
   
2009
   
2010
   
2009
 
   
(in thousands)
   
(in thousands)
 
Supply and logistics revenue
  $ 518,809     $ 356,450     $ 1,339,769     $ 836,876  
Crude oil and products costs, excluding unrealized gains and losses from derivative transactions
    (490,358 )     (323,951 )     (1,251,777 )     (753,217 )
Operating and segment general and administrative costs, excluding non-cash charges for stock-based compensation and other non-cash expenses
    (20,711 )     (23,076 )     (68,519 )     (61,680 )
Segment margin
  $ 7,740     $ 9,423     $ 19,473     $ 21,979  
                                 
Volumes of crude oil and petroleum products-average barrels per day
    76,964       51,260       61,605       47,280  
 
Three Months Ended September 30, 2010 Compared with Three Months Ended September 30, 2009
 
The average market prices of crude oil and petroleum products increased by approximately $8 per barrel, or 12%, between the two quarterly periods; however, that price variance  had a limited impact on our supply and logistics Segment Margin.  More significant factors for us are discussed below.
 
 
-29-

 
The key factors affecting the two quarters were as follows:
 
 
·
Fluctuations in the effects of quality differentials on pricing of petroleum products limited the contribution to Segment Margin while the effects on pricing of quality differentials for different grades of crude oil improved Segment Margin.
 
 
·
We acquired, stored and sold-forward fewer barrels of crude oil as the effects of the contango market on crude oil prices narrowed in the third quarter of 2010 as compared to the prior year period.
 
 
·
Increased opportunities to handle the heavy-end petroleum products due to increased access to transportation services (including DG Marine) and storage facilities partially offset the impact of fluctuations in differentials.
 
Our petroleum products activities involve handling volumes from the heavy end of the refined barrel.  Despite increased volumes from our petroleum products activities, fluctuations in quality differentials resulted in a decrease of approximately $2.1 million in the contribution of petroleum products activities to Segment Margin.
 
Beginning late in 2008 and throughout most of 2009, the crude oil market was in wide contango.  When crude oil markets are in contango, oil prices for future deliveries are higher than for current deliveries, providing an opportunity for us to purchase crude oil at current market prices, re-sell it through futures contracts at future prices, and store it as inventory until delivery.  In the third quarter of 2009, we took advantage of contango conditions, holding an average of 220,000 barrels of crude oil in storage throughout the quarter.  In 2010, contango market conditions had narrowed and we reduced the volumes of crude oil stored to take advantage of the contango conditions to an average of 170,000 barrels of crude oil throughout the quarter.  Offsetting the reduced contribution from contango conditions was increased margins in our gathering activities.  Fluctuations in price differentials between different grades of crude oil, which we refer to as quality differentials, increased margins on our gathering activities.  As a result, margins from crude oil gathering and marketing activities increased approximately $0.5 million.
 
 Nine Months Ended September 30, 2010 Compared with Nine Months Ended September 30, 2009

 For the nine month periods, the improvements in our heavy end petroleum products opportunities only partially offset the impacts of the narrowing in contango pricing and differentials in the crude oil markets.  Segment Margin between the two periods declined $2.5 million. The key factors affecting the two nine-month periods were as follows:
 
 
·
The effects on crude oil prices of quality differentials and the contango price market narrowed beginning late in the fourth quarter of 2009 and extended through most of the third quarter of 2010 decreasing the effects on contribution to Segment Margin of our crude oil activities by $2.2 million.
 
 
·
Many of DG Marine’s inland marine tows were under term charter agreements during part of the first six months of 2009.  As those agreements expired in the late spring and summer of 2009, tows have been operated under spot arrangements at lower average charter rates.  Charter rates have improved in the first nine months of 2010; however, the differences as compared to the first nine months of 2009 resulted in a decline in Segment Margin of $0.5 million.
 
 
·
Increased opportunities to handle the heavy end petroleum products due to increased access to transportation services (including those of DG Marine) and storage facilities in 2010 increased segment margin $0.2 million, partially offsetting the affects of the two factors above.
 
Industrial Gases Segment
 
Operating results from our industrial gases segment were as follows:
 
 
-30-


   
Three Months Ended September 30,
   
Nine Months Ended September 30,
 
   
2010
   
2009
   
2010
   
2009
 
   
(in thousands)
   
(in thousands)
 
Revenues from CO2 marketing
  $ 4,679     $ 4,512     $ 11,982     $ 12,032  
CO2 transportation and other costs
    (1,757 )     (1,619 )     (4,589 )     (4,298 )
Available cash generated by equity investees
    573       -       1,597       1,051  
Segment margin
  $ 3,495     $ 2,893     $ 8,990     $ 8,785  
                                 
Volumes per day:
                               
CO2 marketing - Mcf
    86,534       80,520       74,341       73,697  
 
Three Months Ended September 30, 2010 Compared with Three Months Ended September 30, 2009
 
Segment Margin from the industrial gases segment increased between the quarterly periods primarily due to an increase in volumes delivered to our customers.  Volumes increased 7% between the two quarterly periods as customers increased purchases in response to improving economic conditions.  The average sales price of CO2 per Mcf decreased $0.02, or 4% between the quarters.
 
Our industrial gases segment experienced increased costs due to inflationary adjustments to the rates we are charged to transport CO2 to our customers.  Average transportation rates increased by 2.0% over the average rates in the 2009 third quarter.
 
Nine Months Ended September 30, 2010 Compared with Nine Months Ended September 30, 2009
 
The increase in Segment Margin between the two nine-month periods was the result of increased available cash generated by equity investees offset by an increase in average CO2 transportation rates of 6%.
 
Other Costs, Interest, and Income Taxes
General and administrative expenses.
 
General and administrative expenses consisted of the following:
 
   
Three Months Ended September 30,
   
Nine Months Ended September 30,
 
   
2010
   
2009
   
2010
   
2009
 
   
(in thousands)
   
(in thousands)
 
                         
General and administrative expenses not separately identified below
  $ 5,355     $ 4,901     $ 15,391     $ 14,996  
Expenses related to change in owner of our general partner
    -       -       1,762       -  
Bonus plan expense
    1,400       1,517       3,706       3,151  
Equity-based compensation plan expense
    863       622       1,530       1,454  
Non-cash compensation expense related to management team
    2,965       3,088       1,289       7,587  
Total general and administrative expenses
  $ 10,583     $ 10,128     $ 23,678     $ 27,188  
 
Comparing the three-month and nine-month periods, the primary factor driving the decrease in general and administrative expenses was the change in non-cash compensation expense related to our management team.  On December 31, 2008, our general partner and members of our management team entered into an equity-based compensation arrangement whereby our management team could earn an interest in distributions attributable to our incentive distribution rights owned by our general partner.  While the former owner of our general partner was responsible for the cash cost of this compensation with our management team, we recorded the expense of those arrangements with an offsetting non-cash capital contribution by our general partner.  On February 5, 2010, as a result of the sale of our general partner, that equity-based compensation arrangement was settled.  In the first quarter of 2010, we recorded a credit of $2.0 million to general and administrative expense related to the difference in the ultimate settlement value of $14.9 million and the amounts that were previously charged to expense related to this arrangement.  In the three and nine month periods of 2009, we recorded expenses of $3.1 million and $7.6 million, respectively, related to these non-cash compensation arrangements with our management team.  See Note 9 to our Unaudited Condensed Consolidated Financial Statements.
 
 
-31-

 
Partially offsetting the reduction from those compensation arrangements between the nine-month periods were $1.8 million of expenses we incurred related to the sale of our general partner, including costs related to a public offering of the common units initially retained by the former owner of our general partner and severance  arrangements for an executive officer. Additionally, affecting Available Cash before Reserves, but not net income, was an increase of approximately $0.7 million in exercises of stock appreciation rights.
 
Depreciation and amortization expense. Depreciation and amortization expense decreased $2.3 million and $6.9 million between the three and nine month periods, respectively, as a result of the lower amortization expense recognized on intangible assets.  We amortize our intangible assets over the period during which we expect them to contribute to our future cash flows.   The amortization we record on those assets is greater in the initial years following their acquisition because the value of our intangible assets such as customer relationships and trade names are generally more valuable in the first years after an acquisition.  Accordingly, the amount of amortization we have recorded has declined since we acquired those assets in 2007.
 
Interest expense, net.
 
Interest expense, net was as follows:
 
   
Three Months Ended September 30,
   
Nine Months Ended September 30,
 
   
2010
   
2009
   
2010
   
2009
 
   
(in thousands)
   
(in thousands)
 
Interest expense, including commitment fees, excluding DG Marine
  $ 3,563     $ 2,018     $ 7,561     $ 5,799  
Amortization of facility fees, excluding DG Marine facility
    435       167       763       495  
Write-off of facility fees, excluding DG Marine
    -       -       402       -  
Interest expense and commitment fees-DG Marine
    238       1,254       2,512       3,699  
Interest rate swaps settlement - DG Marine
    1,553       -       1,553       -  
Write-off of facility fees - DG Marine
    794       -       794       -  
Capitalized interest
    (30 )     (3 )     (39 )     (112 )
Interest income
    (11 )     (18 )     (40 )     (55 )
Net interest expense
  $ 6,542     $ 3,418     $ 13,506     $ 9,826  

Our interest expense (excluding interest on DG Marine’s stand-alone facility) increased as the average debt balance quarter to quarter increased $64.1 million and the average interest rate for borrowed funds increased approximately 1.2% over the same periods.  For the nine-month periods, our average outstanding debt balance was $22.7 million higher in 2010 than 2009.    The increase in the debt balance is attributable primarily to the acquisition of the 51% of DG Marine we did not own and the elimination of the DG Marine credit facility with borrowings under our credit facility.
 
Consolidated net interest expense was also affected by costs to settle the DG Marine interest rate swaps and the write-off of facility fees related to the DG Marine credit facility due to its repayment.
 
Income tax expense. Income tax expense relates to corporate-level income tax accruals (accrued by the Partnership) and Texas Margin Tax on our operations in Texas.  As the majority of our operations are not conducted by corporations, income tax expense is not expected to be significant.
 
 
-32-


Liquidity and Capital Resources
 
Capital Resources/Sources of Cash
 
Recent market trends have indicated improvements in bank lending capacity and long-term interest rates from the situation in early 2009.  We anticipate that our short-term working capital needs will be met through our current cash balances, future internally-generated funds and funds available under our credit facility.  Existing capacity in our credit facility and cash on hand, may allow us to take advantage of other attractive acquisition and/or growth opportunities that develop.
 
We continue to pursue a growth strategy that requires significant capital.  As discussed above in the Overview, we have entered into an agreement to acquire a 50% interest in Cameron Highway for $330 million.  We expect to fund this acquisition with some combination of equity and debt; however, to protect against the possibility of a rapid deterioration in the capital markets, we entered into an agreement with a group of banks to provide up to $300 million of unsecured financing.  This unsecured facility allows for borrowings through December 31, 2011.
 
We expect our short-term and long-term capital resources to include equity and debt offerings (public and private), revolving and term credit facilities and other financing transactions, in addition to cash generated from our operations. Accordingly, we expect to access the capital markets (equity and debt) from time to time to partially refinance our capital structure and to fund other needs including acquisitions and ongoing working capital needs.
 
In 2010 alone, we have entered into two acquisition agreements (DG Marine and Cameron Highway), amended and extended our credit facility and completed a secondary equity offering of our common units for the former owner of our general partner and a significant unitholder.
 
On June 29, 2010, we restructured our credit facility – which we entered into in November 2006 and which was to mature in November 2011 – to reflect and better accommodate our larger and more diversified operations and resulting credit metrics.  Our restructured credit facility is a $525 million senior secured revolving credit facility maturing on June 30, 2015.  It includes an accordion feature whereby the total credit available can be increased up to $650 million for acquisitions or internal growth projects, with lender approval.  Among other modifications, our credit facility also includes a $75 million inventory sublimit tranche.  This inventory tranche is designed to allow us to more efficiently finance crude oil and petroleum products inventory in the normal course of our operations, by allowing us to exclude the amount of inventory loans from our total outstanding indebtedness for purposes of determining our applicable interest rate.  Additionally, our restructured credit facility does not include a “borrowing base” limitation except with respect to our inventory loans.  Eleven lenders participate in our credit facility, and we do not anticipate any of them being unable to satisfy their obligations under the credit facility.  Additional information on our restructured credit facility is included in Note 5 to the Unaudited Condensed Consolidated Financial Statements.
 
While our new credit facility provides additional flexibility and committed borrowing capacity, our ability to satisfy future capital needs will depend on our ability to raise substantial amounts of additional capital, to utilize our credit facility and to implement our growth strategy successfully. No assurance can be made that we will be able to raise the necessary funds on satisfactory terms.  If we are unable to raise the necessary funds, we may be required to defer our growth plans until such time as funds become available.
 
We continue to monitor the credit markets and the economic outlook to determine the extent of the impact on our business environment.  While we have experienced increases in demand for NaHS in 2010 resulting primarily from increased mining activities associated with increases in commodity prices for copper and molybdenum, we continue to experience lower demand for crude oil and petroleum products, primarily due to low utilization rates at refineries.  We continue to adjust to the effects of these macroeconomic factors in our operating levels and financial decisions.
 
On July 29, 2010, in connection with our acquisition of the 51% interest of DG Marine that we did not own, we paid off DG Marine’s stand-alone credit facility, which had an outstanding principal balance of $44.4 million, with proceeds from our credit agreement.  See Note 2 to our Unaudited Condensed Consolidated Financial Statements and our Current Report on Form 8-K filed August 3, 2010.
 
Uses of Cash
 
Our cash requirements include funding day-to-day operations, maintenance and expansion capital projects, debt service, and distributions on our common units and other equity interests.  We expect to use cash flows from operating activities to fund cash distributions and maintenance capital expenditures needed to sustain existing operations.  Future expansion capital – acquisitions or capital projects – will require funding through various financing arrangements, as more particularly described under Liquidity and Capital Resources – Capital Resources/Sources of Cash above.
 
 
-33-

 
Cash Flows from Operations. We utilize the cash flows we generate from our operations to fund our working capital needs.  Excess funds that are generated are used to repay borrowings from our credit facilities and to fund capital expenditures.  Our operating cash flows can be impacted by changes in items of working capital.
 
Debt and Other Financing Activities.  Our sources of cash are primarily from funds from operations and our credit facilities.  Our net borrowings under our credit facility and the DG Marine credit facility totaled $59.1 million during the first nine months of 2010, which related partially to the acquisition of the 51% interest of DG Marine that we did not own.  The remainder of these borrowings related primarily to increases in petroleum products inventory levels to take advantage of blending and storage opportunities, the investment in fixed and intangible assets, and the payment of liabilities accrued at the 2009 year end for such items as annual bonus payments and property tax obligations.  We paid distributions totaling $51.6 million to our limited partners and our general partner during the first nine months of 2010.  For a more detailed analysis of our recent distributions, see Note 6 to our Unaudited Condensed Consolidated Financial Statements.
 
Investing.  We utilized cash flows for capital expenditures.  The most significant investing activities in the first nine months of 2010 were expenditures related to our project to upgrade our information technology systems discussed below.
 
Capital Expenditures, and Business and Asset Acquisitions
 
A summary of our expenditures for fixed assets and other asset acquisitions for the nine months ended September 30, 2010 and 2009 is as follows:
 
   
Nine Months Ended
 
   
September 30,
 
   
2010
   
2009
 
   
(in thousands)
 
Capital expenditures for fixed and intangible assets:
           
Maintenance capital expenditures:
           
Pipeline transportation assets
    295       1,201  
Supply and logistics assets
    766       1,269  
Refinery services assets
    1,169       704  
Administrative and other assets
    29       584  
Total maintenance capital expenditures
    2,259       3,758  
                 
Growth capital expenditures:
               
Pipeline transportation assets
    263       1,762  
Supply and logistics assets
    421       17,920  
Refinery services assets
    -       1,326  
Information technology systems upgrade project
    7,362       -  
Total growth capital expenditures
    8,046       21,008  
Total
    10,305       24,766  
                 
Capital expenditures for asset purchases:
               
Acquisition of intangible assets
    -       2,500  
Total asset purchases
    -       2,500  
                 
                 
Capital expenditures attributable to unconsolidated affiliates
    -       83  
Total
    -       83  
Total capital expenditures
  $ 10,305     $ 27,349  

 
-34-


During the remainder of 2010, we expect to expend approximately $0.5 million for maintenance capital projects in progress or planned.  We also plan to spend approximately an additional $3.0 million in capital costs to integrate and upgrade our information technology systems to be positioned for further growth, which we will fund with borrowings under our credit facility.
 
Expenditures for capital assets to grow the partnership distribution will depend on our access to debt and equity capital discussed above in Liquidity and Capital Resources – Capital Resources/Sources of Cash. As discussed above, we expect to close a transaction before the end of the year to acquire a 50% interest in Cameron Highway for $330 million.
 
Possible Partnership Simplification or IDR Restructuring Transaction
 
Our senior management has continuously evaluated strategic alternatives in an effort to enhance unitholder value. Among other things, senior management has focused on improving our competitive position and enhancing our long-term growth prospects by reducing our equity cost of capital, the impact of which it believes would benefit the holders of the Partnership’s common units. Senior management believes that our cost of capital potentially has (and will continue to) become high in comparison to a number of publicly-traded limited partnerships, or MLPs, in our peer group.  Our cost of issuing new units to facilitate the continuing growth of the Partnership includes not only the distributions payable to such new unitholders, but also the percent of our aggregate quarterly distributions we pay to our general partner in respect of our general partner interest (2%) and incentive distribution rights (currently, approximately 49%), or IDRs.
 
 Senior management’s focus on reducing our cost of equity capital became more acute after several other midstream MLPs, including Penn Virginia Resource Partners, L.P., Enterprise Product Partners, L.P., Inergy, L.P., Buckeye Partners, L.P., Sunoco Logistics Partners L.P., NuStar Energy L.P., Magellan Midstream Partners, L.P., Eagle Rock Energy Partners, L.P. and MarkWest Energy Partners, L.P., acted or proposed to reduce their cost of equity capital through restructuring their general partners and their attendant IDRs by, generally speaking, resetting, capping, repurchasing or eliminating them. Senior management believes, if we could economically restructure or eliminate our IDRs, we would be more competitive when pursuing acquisitions and able to finance organic growth projects less expensively, which would enhance our long-term distribution growth prospects to the holders of the Partnership’s common units. Senior management also believes such a transaction would further align the interests of our general partner with those of our limited partners.  Thus, senior management suggested to our general partner’s Board that it should consider a partnership simplification or other restructuring transaction.
 
Our general partner’s Board of Directors has authorized us to analyze alternative restructuring transactions, and it granted our Conflicts Committee the authority to analyze, negotiate, and consider for “Special Approval” (as defined in our partnership agreement) and recommendation to the Board such a restructuring.  In September, we engaged a financial advisor to assist us, and in October our Conflicts Committee engaged legal and financial advisors to assist it in its Special Approval process.
 
Senior management believes that, under the right circumstances, the most desirable restructuring transaction would be to alleviate the burden to our equity cost of capital through the complete elimination (in one form or another) of our IDRs.  It is impossible, at this time, to determine (i) whether or not we will consummate any form of a restructuring transaction, or (ii) if we were to consummate a restructuring transaction, when such transaction would be consummated and what terms such a transaction would include, such as (a) whether we would reset, cap, repurchase or eliminate our IDRs; (b) whether the consideration therefore would be in the form of common units, other equity, debt, cash, other consideration or any combination thereof; and (c) what other terms might be required.
 
Non-GAAP Reconciliation
 
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.
 
 
-35-


Available Cash before Reserves, also referred to as distributable cash flow, is commonly used as a supplemental financial measure by management and by external users of financial statements, such as investors, commercial banks, research analysts and rating agencies, to assess: (1) the financial performance of our assets without regard to financing methods, capital structures, or historical cost basis; (2) the ability of our assets to generate cash sufficient to pay interest costs 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 is the quantitative metric used by many in 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) is as follows:
 
   
Three Months
 
   
Ended September 30,
 
   
2010
   
2009
 
   
(in thousands)
 
Cash flows from operating activities
  $ 23,361     $ 36,765  
Adjustments to reconcile operating cash flows to
               
Available Cash:
               
Maintenance capital expenditures
    (716 )     (1,336 )
Amortization and write-off of credit facility issuance fees
    (1,229 )     (487 )
Effects of available cash generated by equity method investees not included in cash flows from operating activities
    201       -  
Loss (earnings) of DG Marine in excess of distributable cash
    1,686       (1,108 )
Other items affecting available cash
    264       (622 )
Net effect of changes in operating accounts not included in calculation of Available Cash
    4,559       (9,497 )
Available Cash before Reserves
  $ 28,126     $ 23,715  
 
Commitments and Off-Balance Sheet Arrangements
 
Contractual Obligations and Commercial Commitments
 
The following table reflects our obligations and commitments at September 30, 2010:
 
 
-36-


   
Payments Due by Period
 
Commercial Cash Obligations and Commitments
 
Less than one year
   
1 - 3 years
   
3 - 5 Years
   
More than 5 years
   
Total
 
                               
Contractual Obligations:
                             
Long-term debt (1)
  $ -     $ -     $ 426,000     $ -     $ 426,000  
Estimated interest payable on long-term debt (2)
    12,780       25,560       22,365       -       60,705  
Operating lease obligations
    8,014       11,503       6,623       23,791       49,931  
Unconditional purchase obligations (3)
    92,112       -       -       -       92,112  
                                         
Other Cash Commitments:
                                       
Asset retirement obligations (4)
    -       -       -       13,777       13,777  
Liabilities associated with unrecognized tax benefits and associated interest  (5)
    5,757       -       -       -       5,757  
Total
  $ 118,663     $ 37,063     $ 454,988     $ 37,568     $ 648,282  
 
 
(1)
Our credit facility allows us to repay and re-borrow funds at any time through the maturity date of June 30, 2015.
 
(2)
Interest on our long-term debt is at market-based rates. The amount shown for interest payments represents the amount that would be paid if the debt outstanding at September 30, 2010 remained outstanding through the final maturity dates of June 30, 2015 and interest rates remained at the September 30, 2010 market levels through the final maturity dates.
 
(3)
Unconditional purchase obligations include agreements to purchase goods and services that are enforceable and legally binding and specify all significant terms.  Contracts to purchase crude oil and petroleum products are generally at market-based prices.  For purposes of this table, estimated volumes and market prices at September 30, 2010, were used to value those obligations.  The actual physical volumes and settlement prices may vary from the assumptions used in the table.  Uncertainties involved in these estimates include levels of production at the wellhead, changes in market prices and other conditions beyond our control.
 
(4)
Represents the estimated future asset retirement obligations on an undiscounted basis.  The present discounted asset retirement obligation is $5.8 million.
 
(5)
The estimated liabilities associated with unrecognized tax benefits and related interest will be settled as a result of expiring statutes or audit activity. The timing of any particular settlement will depend on the length of the tax audit and related appeals process, if any, or an expiration of statute. If a liability is settled due to a statute expiring or a favorable audit result, the settlement of the FIN 48 tax liability would not result in a cash payment.

We have guaranteed 50% of the $2.3 million debt obligation to a bank of Sandhill; however, we believe we are not likely to be required to perform under this guarantee as Sandhill is expected to make all required payments under the debt obligation.
 
Off-Balance Sheet Arrangements
 
We have no off-balance sheet arrangements, special purpose entities, or financing partnerships, other than as disclosed under “Contractual Obligations and Commercial Commitments” in our Annual Report on Form 10-K for the year ended December 31, 2009, nor do we have any debt or equity triggers based upon our unit or commodity prices.
 
Forward Looking Statements
 
The statements in this Quarterly Report on Form 10-Q that are not historical information may be “forward looking statements” within the meaning of the various provisions of the Securities Act of 1933 and the Securities Exchange Act of 1934.  All statements, other than historical facts, included in this document that address activities, events or developments that we expect or anticipate will or may occur in the future, including things such as plans for growth of the business, future capital expenditures, competitive strengths, goals, references to future goals or intentions, and other such references are forward-looking statements.  These forward-looking statements are identified as any statement that does not relate strictly to historical or current facts.  They use words such as “anticipate,” “believe,” “continue,” “estimate,” “expect,” “forecast,””goal”,  “intend,” “may,” “could,” “plan,” “position,” “projection,” “strategy,” “should” or “will,” or the negative of those terms or other variations of them or by comparable terminology.  In particular, statements, expressed or implied, concerning future actions, conditions or events or future operating results or the ability to generate sales, income or cash flow are forward-looking statements.  Forward-looking statements are not guarantees of performance.  They involve risks, uncertainties and assumptions.  Future actions, conditions or events and future results of operations may differ materially from those expressed in these forward-looking statements.  Many of the factors that will determine these results are beyond our ability or the ability of our affiliates to control or predict.  Specific factors that could cause actual results to differ from those in the forward-looking statements include, among others:
 
 
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·
demand for, the supply of, our assumptions about, changes in forecast data for, and price trends related to crude oil, liquid petroleum, natural gas and natural gas liquids or “NGLs”, NaHS,  caustic soda and CO2 all of which may be affected by economic activity, capital expenditures by energy producers, weather, alternative energy sources, international events, conservation and technological advances;
 
 
·
throughput levels and rates;
 
 
·
changes in, or challenges to, our tariff rates;
 
 
·
our ability to successfully identify and consummate strategic acquisitions on acceptable terms, develop or construct energy infrastructure assets, make cost saving changes in operations and integrate acquired assets or businesses into our existing operations;
 
 
·
our ability to make cash distributions on our units;
 
 
·
service interruptions in our liquids transportation systems, natural gas transportation systems or natural gas gathering and processing operations;
 
 
·
shut downs or cutbacks at refineries, petrochemical plants, utilities or other businesses for which we transport crude oil, natural gas or other products or to whom we sell such products;
 
 
·
risks inherent in marine transportation and vessel operation, including accidents and discharge of pollutants;
 
 
·
legislative or regulatory changes, such as changes in the Jones Act or changes in environmental regulation, environmental risks, regulations by FERC and liability under federal and state environmental laws and regulations;
 
 
·
planned capital expenditures and availability of capital resources to fund capital expenditures;
 
 
·
our inability to borrow or otherwise access funds needed for operations, expansions or capital expenditures as a result our credit agreement which contains various affirmative and negative covenants;
 
 
·
loss of key personnel;
 
 
·
the impact of new pipelines and other effects of competition from gatherers, transporters, marketers, brokers and other aggregators;
 
 
·
cost and availability of insurance coverage;
 
 
·
hazards and operating risks that may not be covered fully by insurance;
 
 
·
our financial and commodity hedging arrangements;
 
 
·
the volatility or disruption in the capital or financial markets in the United States;
 
 
·
natural disasters, accidents or terrorism;
 
 
·
loss, bankruptcy, credit risk or concentration of key customers;
 
 
·
the political and economic stability of the oil producing nations of the world; and
 
 
·
general economic conditions, including rates of inflation and fluctuations in interest rates.
 
You should not put undue reliance on any forward-looking statements.  When considering forward-looking statements, please review the risk factors described under “Risk Factors” discussed in Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2009 and any other risk factors contained in our Current Reports on Form 8-K that we may file from time to time with the SEC.  Except as required by applicable securities laws, we do not intend to update these forward-looking statements and information.
 
 
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Item 3.  Quantitative and Qualitative Disclosures about Market Risk
 
The following should be read in conjunction with Quantitative and Qualitative Disclosures About Market Risk included under Item 7A in our 2009 Annual Report on Form 10-K.  There has been no material changes in market risk exposures that would affect the quantitative and qualitative disclosures provided therein.  Also, see Note 11 to our Unaudited Condensed Consolidated Financial Statements for additional discussion related to derivative instruments and hedging activities.

Item 4. Controls and Procedures
 
We maintain disclosure controls and procedures and internal controls designed to ensure that information required to be disclosed in our filings under the Securities Exchange Act of 1934 is recorded, processed, summarized, and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms.  Our chief executive officer and chief financial officer, with the participation of our management, have evaluated our disclosure controls and procedures as of the end of the period covered by this Quarterly Report on Form 10-Q and have determined that such disclosure controls and procedures are effective in ensuring that material information required to be disclosed in this quarterly report is accumulated and communicated to them and our management to allow timely decisions regarding required disclosures.
 
There were no changes during our last fiscal quarter that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
 
PART II. OTHER INFORMATION
 
Item 1.  Legal Proceedings.
 
Information with respect to this item has been incorporated by reference from our Annual Report on Form 10-K for the year ended December 31, 2009.  There have been no material developments in legal proceedings since the filing of such Form 10-K.
 
Item 1A.  Risk Factors.
 
For additional information about our risk factors, see Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2009. On August 3, 2010, we filed a Current Report on Form 8-K that covered several items, including our acquisition of the remaining interest in DG Marine.  That Current Report on Form 8-K included some additional risk factors. There have been no material changes to the risk factors since the filing of such Form 10-K and/or that Current Report on Form 8-K.
 
Item 2.  Unregistered Sales of Equity Securities and Use of Proceeds.
 
None.
 
Item 3.  Defaults Upon Senior Securities.
 
None.
 
Item 4.  [Removed and Reserved]
 
Item 5.  Other Information.
 
None.
 
Item 6.  Exhibits
 
(a)
Exhibits.
   
       
 
2.1
 
Contribution and Sale Agreement, dated July 28, 2010, by and between TD Marine, LLC and Genesis (incorporated by reference to Exhibit 2.1 to Form 8-K dated August 3, 2010, File No. 001-12295)
       
 
*
Purchase and Sale Agreement (the “Purchase Agreement”) by and between Valero Energy Corporation, Valero Services, Inc., Valero Unit Investments, L.L.C., Genesis Energy, L.P., Genesis CHOPS I, LLC, and Genesis CHOPS II, LLC

 
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3.1
 
Certificate of Limited Partnership of Genesis Energy, L.P. (“Genesis”) (incorporated by reference to Exhibit 3.1 to Amendment No. 2 to Registration Statement on Form S-1, File No. 333-11545)
       
 
3.2
 
Fourth Amended and Restated Agreement of Limited Partnership of Genesis (incorporated by reference to Exhibit 4.1 to Form 8-K dated June 15, 2005, File No. 001-12295)
       
 
3.3
 
Amendment No. 1 to Fourth Amended and Restated Agreement of Limited Partnership of Genesis (incorporated by reference to Exhibit 3.3 to Form 10-K for the year ended December 31, 2007, File No. 001-12295)
       
 
3.4
 
Amendment No. 2 to Fourth Amended and Restated Agreement of Limited Partnership of Genesis (incorporated by reference to Exhibit 10.2 to Form 8-K dated March 5, 2010, File No. 001-12295)
       
 
3.5
 
Certificate of Conversion of Genesis Energy, Inc., a Delaware corporation, into Genesis Energy, LLC, a Delaware limited liability company (incorporated by reference to Exhibit 3.1 to Form 8-K dated January 7, 2009, File No. 001-12295)
       
 
3.6
 
Certificate of Formation of Genesis Energy, LLC (formerly Genesis Energy, Inc.) (incorporated by reference to Exhibit 3.2 to Form 8-K dated January 7, 2009, File No. 001-12295)
       
 
3.7
 
Amended and Restated  Limited Liability Company Agreement of Genesis Energy, LLC dated February 5, 2010 (incorporated by reference to Exhibit 3.1 to Form 8-K dated February 11, 2010, File No. 001-12295)
       
 
3.8
 
Amendment No. 1 to Amended and Restated Limited Liability Company Agreement of Genesis Energy, LLC dated June 11, 2010 (incorporated by reference to Exhibit 3.10 to Form 10-Q for the quarterly period ended June 30, 2010, File No. 001-12295)
       
 
3.91
 
Amendment No. 2 to Amended and Restated Limited Liability Company Agreement of Genesis Energy, LLC dated July 28, 2010 (incorporated by reference to Exhibit 3.10 to Form 10-Q for the quarterly period ended June 30, 2010, File No. 001-12295)
       
 
4.1
 
Form of Unit Certificate of Genesis Energy, L.P. (incorporated by reference to Exhibit 4.1 to Form 10-K for the year ended December 31, 2007, File No. 001-12295)
       
 
10.1
 
Second Amended and Restated Credit Agreement, dated as of June 29, 2010, among Genesis as borrower, BNP Paribas as administrative agent, Bank of America, N.A. and Bank of Montreal as co-syndication agents, U.S. Bank National Association as documentation agent, and the lenders party thereto (incorporated by reference to Exhibit 10.1 to Form 8-K dated July 2, 2010, File No. 001-12295)
       
 
*
Certification by Chief Executive Officer Pursuant to Rule 13a-14(a) of the Securities Exchange Act of 1934
       
 
*
Certification by Chief Financial Officer Pursuant to Rule 13a-14(a) of the Securities Exchange Act of 1934
       
 
*
Certification by Chief Executive Officer and Chief Financial Officer Pursuant to Rule 13a-14(b) of the Securities Exchange Act of 1934
       
 
**
List of exhibits and schedules to the Purchase Agreement.
 
*Filed herewith
 
** A list of all exhibits and schedules are included under Exhibit 99.1.  Pursuant to Item 601(b)(2) of Regulation S-K, the registrant agrees to furnish supplementally a copy of such omitted exhibit or schedule to the SEC upon request.
 
 
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SIGNATURES
 
 
Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
 
 
   
GENESIS ENERGY, L.P.
(A Delaware Limited Partnership)
 
By:
GENESIS ENERGY, LLC, as General Partner
Date:  November 3, 2010
By:
  /s/  Robert V. Deere
 
   
        Robert V. Deere
        Chief Financial Officer
 
 
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