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GENESIS ENERGY LP - Quarter Report: 2011 March (Form 10-Q)

form10-q.htm


UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C.  20549
 
Form 10-Q
 
x QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
For the quarterly period ended March 31, 2011
 
OR
 
o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934
 
Commission file number 1-12295
 
GENESIS ENERGY, L.P.
(Exact name of registrant as specified in its charter)
 
Delaware
(State or other jurisdiction of  incorporation or organization)
 
76-0513049
(I.R.S. Employer Identification No.)
     
919 Milam, Suite 2100, Houston, TX
(Address of principal executive offices)
 
77002
(Zip code)
 
Registrant’s telephone number, including area code:
 
(713) 860-2500
 
Securities registered pursuant to Section 12(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.  Class A Common Units outstanding as of May 9, 2011:  64,575,065
 


 
 

 
 
GENESIS ENERGY, L.P.
 
Form 10-Q
 
INDEX
     
   
Page
     
 
PART I.  FINANCIAL INFORMATION
 
     
3
     
 
3
     
 
4
     
 
5
     
 
6
     
 
7
     
 
8
     
19
     
31
     
31
     
 
PART II.  OTHER INFORMATION
 
     
31
     
31
     
31
     
31
     
31
     
31
     
31
     
 33

 
-2-


PART I.  FINANCIAL INFORMATION
 
 
GENESIS ENERGY, L.P.
(In thousands)
 
   
March 31,
   
December 31,
 
   
2011
   
2010
 
             
ASSETS
           
CURRENT ASSETS:
           
Cash and cash equivalents
  $ 4,155     $ 5,762  
Accounts receivable - trade, net
    268,090       171,550  
Inventories
    35,559       55,428  
Other
    20,991       19,798  
Total current assets
    328,795       252,538  
                 
FIXED ASSETS, at cost
    374,479       373,339  
Less:  Accumulated depreciation
    (114,120 )     (108,283 )
Net fixed assets
    260,359       265,056  
                 
NET INVESTMENT IN DIRECT FINANCING LEASES, net of unearned income
    167,225       168,438  
EQUITY INVESTEES
    340,325       343,434  
INTANGIBLE ASSETS, net of amortization
    115,394       120,175  
GOODWILL
    325,046       325,046  
OTHER ASSETS, net of amortization
    30,506       32,048  
TOTAL ASSETS
  $ 1,567,650     $ 1,506,735  
                 
LIABILITIES AND PARTNERS CAPITAL
               
CURRENT LIABILITIES:
               
Accounts payable - trade
  $ 217,336     $ 165,978  
Accrued liabilities
    39,869       40,736  
Total current liabilities
    257,205       206,714  
                 
SENIOR SECURED CREDIT FACILITIES
    389,500       360,000  
SENIOR UNSECURED NOTES
    250,000       250,000  
DEFERRED TAX LIABILITIES
    14,854       15,193  
OTHER LONG-TERM LIABILITIES
    5,643       5,564  
COMMITMENTS AND CONTINGENCIES (Note 12)
               
                 
PARTNERS CAPITAL:
               
Common unitholders, 64,615 units issued and outstanding at March 31, 2011 and December 31, 2010, respectively
    650,448       669,264  
TOTAL LIABILITIES AND PARTNERS CAPITAL
  $ 1,567,650     $ 1,506,735  
 
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

 
-3-


GENESIS ENERGY, L.P.
(In thousands, except per unit amounts)
 
   
Three Months Ended
March 31,
 
   
2011
   
2010
 
REVENUES:
           
Supply and logistics
  $ 627,797     $ 423,371  
Refinery services
    47,546       29,502  
Pipeline transportation services
    14,455       13,658  
Total revenues
    689,798       466,531  
                 
COSTS AND EXPENSES:
               
Supply and logistics costs:
               
Product costs
    597,139       392,191  
Operating costs
    24,225       23,866  
Refinery services operating costs
    29,586       16,227  
Pipeline transportation operating costs
    4,070       4,429  
General and administrative
    8,054       6,294  
Depreciation and amortization
    13,903       13,406  
Net (gain) loss on disposal of surplus assets
    (11 )     80  
Total costs and expenses
    676,966       456,493  
                 
OPERATING INCOME
    12,832       10,038  
Equity in earnings of equity investees
    3,197       182  
Interest expense
    (8,699 )     (3,204 )
Income before income taxes
    7,330       7,016  
Income tax expense
    (300 )     (691 )
                 
NET INCOME
    7,030       6,325  
                 
Net loss attributable to noncontrolling interests
          560  
NET INCOME ATTRIBUTABLE TO GENESIS ENERGY, L.P.
  $ 7,030     $ 6,885  
                 
NET INCOME ATTRIBUTABLE TO GENESIS ENERGY, L.P. PER COMMON UNIT:
               
Basic and Diluted
  $ 0.11     $ 0.06  
                 
WEIGHTED AVERAGE OUTSTANDING COMMON UNITS:
               
Basic and Diluted
    64,615       39,548  
 
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

 
-4-

 
GENESIS ENERGY, L.P.
OF COMPREHENSIVE INCOME
(In thousands)
 
   
Three Months Ended March 31,
 
   
2011
   
2010
 
             
Net income
  $ 7,030     $ 6,325  
Change in fair value of derivatives:
               
Current period reclassification to earnings
          280  
Changes in derivative financial instruments - interest rate swaps
          (204 )
Comprehensive income
    7,030       6,401  
Comprehensive loss attributable to noncontrolling interests
          522  
Comprehensive income attributable to Genesis Energy, L.P.
  $ 7,030     $ 6,923  
 
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

 
-5-

 
GENESIS ENERGY, L.P.
(In thousands)
 
   
Partners’ Capital
 
     Number of
Common
Units
   
Common
Unitholders
 
                 
Partners’ capital, January 1, 2011
    64,615     $ 669,264  
Net income
          7,030  
Cash distributions
          (25,846 )
Partners’ capital, March 31, 2011
    64,615     $ 650,448  

   
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
          2,814       4,071             (560 )     6,325  
Interest rate swap loss reclassified to interest expense
                      138       142       280  
Interest rate swap loss
                      (100 )     (104 )     (204 )
Cash contributions
                37                   37  
Cash distributions
          (14,251 )     (2,328 )           (2 )     (16,581 )
Contribution for executive compensation
                (1,977 )                 (1,977 )
Unit based compensation expense
    98       20                         20  
Partners’ capital, March 31, 2010
    39,586     $ 574,137     $ 10,955     $ (791 )   $ 22,532     $ 606,833  
 
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.
 
 
-6-

 
GENESIS ENERGY, L.P.
(In thousands)
             
   
Three Months Ended March 31,
 
   
2011
   
2010
 
CASH FLOWS FROM OPERATING ACTIVITIES:
           
Net income
  $ 7,030     $ 6,325  
Adjustments to reconcile net income to net cash provided by operating activities -
               
Depreciation and amortization
    13,903       13,406  
Amortization and write-off of credit facility issuance costs
    655       455  
Amortization of unearned income and initial direct costs on direct financing leases
    (4,349 )     (4,449 )
Payments received under direct financing leases
    5,462       5,464  
Equity in earnings of investments in equity investees
    (3,197 )     (182 )
Cash distributions of earnings of equity investees
    4,217       702  
Non-cash effect of equity-based compensation plans
    (135 )     243  
Non-cash compensation credit
          (1,977 )
Deferred and other tax liabilities
    145       186  
Unrealized losses on derivative transactions
    6,460       1,113  
Other, net
    426       164  
Net changes in components of operating assets and liabilities (See Note 9)
    (32,722 )     (8,160 )
Net cash (used in) provided by operating activities
    (2,105 )     13,290  
                 
CASH FLOWS FROM INVESTING ACTIVITIES:
               
Payments to acquire fixed and intangible assets
    (5,489 )     (2,299 )
Cash distributions received from equity investees - return of investment
    2,283        
Investments in equity investees
    (194 )      
Other, net
    (20 )     268  
Net cash used in investing activities
    (3,420 )     (2,031 )
                 
CASH FLOWS FROM FINANCING ACTIVITIES:
               
Bank borrowings
    127,600       130,400  
Bank repayments
    (98,100 )     (118,900 )
General partner contributions
          37  
Noncontrolling interests contributions, net of distributions
          (2 )
Distributions to common unitholders
    (25,846 )     (14,251 )
Distributions to general partner interest
          (2,328 )
Other, net
    264       847  
Net cash provided by (used in) financing activities
    3,918       (4,197 )
Net (decrease) increase in cash and cash equivalents
    (1,607 )     7,062  
Cash and cash equivalents at beginning of period
    5,762       4,148  
Cash and cash equivalents at end of period
  $ 4,155     $ 11,210  
 
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.
 
 
-7-

 
GENESIS ENERGY, L.P.
 
1.  Organization and Basis of Presentation and Consolidation
 
Organization
 
We are a growth-oriented master 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 three divisions:
 
 
Pipeline transportation of crude oil and carbon dioxide (or CO2);
 
 
Refinery services involving processing of high sulfur (or “sour”) gas streams for refineries to remove the sulfur, and sale of the related by-product, sodium hydrosulfide (or NaHS, commonly pronounced nash);
 
 
Supply and logistics services, which includes terminaling, blending, storing, marketing, and transporting crude oil, petroleum products and CO2.
 
In February 2010, new investors, together with members of our executive management team, acquired our general partner.  At that time, our general partner owned all our 2% general partner interest and all of our incentive distribution rights, or IDRs.  In respect of its general partner interest and IDRs, our general partner was entitled to over 50% of any increased distributions we would pay in respect of our outstanding equity.
 
On December 28, 2010, we permanently eliminated our IDRs and converted our 2% general partner interest into a non-economic interest, which we refer to as our IDR Restructuring.   We issued Class A Units, Class B Units and Waiver Units to the former stakeholders of our general partner in exchange for the elimination of our IDRs.  See additional information on our outstanding equity in Note 6.
 
Basis of Presentation and Consolidation
 
The accompanying Unaudited Condensed Consolidated Financial Statements include Genesis Energy, L.P. and its operating subsidiaries, Genesis Crude Oil, L.P. and Genesis NEJD Holdings, LLC, and their subsidiaries, and Genesis Energy, LLC, our general partner.  The inclusion of Genesis Energy, LLC in our Consolidated Financial Statements was effective December 28, 2010 due to our IDR Restructuring.
 
 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, 2010.
 
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.
 
 
-8-

 
GENESIS ENERGY, L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
 
2.  Inventories
 
The major components of inventories were as follows:
 
   
March 31, 2011
   
December 31, 2010
 
Crude oil
  $ 6,609     $ 6,128  
Petroleum products
    16,831       38,588  
Caustic soda
    6,792       6,309  
NaHS
    5,323       4,387  
Other
    4       16  
Total inventories
  $ 35,559     $ 55,428  
 
At March 31, 2011 and December 31, 2010 market values of our inventories exceeded recorded costs.
 
3. Equity Investees
 
We are accounting for our 50% ownership in Cameron Highway Oil Pipeline Company (“Cameron Highway”) under the equity method of accounting.
 
The following table reflects summarized income statement information for Cameron Highway for only one period as we did not acquire our 50% equity interest in Cameron Highway until November 23, 2010.
 
   
Three Months
 
   
Ended
 
   
March 31, 2011
 
Revenues
  $ 15,009  
Operating Income
  $ 8,409  
Net Income
  $ 8,419  

4. Intangible Assets and Goodwill
 
Intangible Assets
 
The following table reflects the components of intangible assets being amortized as of:
 
   
March 31, 2011
   
December 31, 2010
 
   
Gross Carrying Amount
   
Accumulated Amortization
   
Carrying Value
   
Gross Carrying Amount
   
Accumulated Amortization
   
Carrying Value
 
                                     
Refinery services customer relationships
  $ 94,654     $ 55,382     $ 39,272     $ 94,654     $ 53,139     $ 41,515  
Supply and logistics customer relationships
    35,430       20,882       14,548       35,430       19,981       15,449  
Refinery services supplier relationships
    36,469       32,133       4,336       36,469       31,476       4,993  
Refinery services licensing agreements
    38,678       16,709       21,969       38,678       15,786       22,892  
Supply and logistics trade names - Davison and Grifco
    18,888       9,442       9,446       18,888       7,530       11,358  
Intangibles associated with supply and logistics lease
    13,260       1,736       11,524       13,260       1,618       11,642  
Other
    16,169       1,870       14,299       13,776       1,450       12,326  
Total
  $ 253,548     $ 138,154     $ 115,394     $ 251,155     $ 130,980     $ 120,175  
 
 
-9-

 
GENESIS ENERGY, L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
 
The following table reflects our estimated amortization expense for each of the five subsequent fiscal years:
 
   
Amortization
 
   
Expense to
 
Year Ended December 31,
 
be Recorded
 
Remainder of 2011
  $ 21,746  
2012
  $ 21,881  
2013
  $ 14,280  
2014
  $ 12,015  
2015
  $ 10,216  
 
In the first quarter of 2011, we adjusted the useful lives of our supply and logistics trade names. As a result of this change in the amortization period of our assets, operating income and net income attributable to us for the first quarter of 2011 decreased $1.4 million, or $0.02 per common unit. The impact of this change on net income for the remainder of 2011 and 2012 is expected to total $4.2 million and $2.3 million, respectively, and not be material in future periods. The table of estimated future amortization expense above reflects this change.
 
Goodwill
 
The carrying amount of goodwill by business segment at both March 31, 2011 and December 31, 2010 was $301.9 million to refinery services and $23.1 million to supply and logistics.
 
5. Debt
 
As of March 31, 2011, we had $389.5 million borrowed under our senior secured credit facility, with $46 million of that amount designated as a loan under the inventory sublimit. Additionally, we had $5 million in letters of credit outstanding. Due to the revolving nature of loans under our credit facility, additional borrowings and periodic repayments and re-borrowings may be made until the maturity date of June 30, 2015. The total amount available for borrowings at March 31, 2011 was $130.5 million under our credit facility.
 
We believe the amounts included in our balance sheet for debt outstanding under our senior secured credit facility approximate fair value as interest rates reflect current market rates. At March 31, 2011, $250 million of senior unsecured notes were outstanding, which had a fair value of approximately $251.9 million.
 
We were in compliance with the financial covenants contained in our credit facility and indenture as of March 31, 2011.
 
6. Partners’ Capital, Distributions and Net Income Per Common Unit
 
Partners’ Capital
 
At March 31, 2011 and December 31, 2010, our outstanding equity consisted of 64,575,065 Class A Units and 39,997 Class B Units. Additionally 6,949,004 Waiver Units were outstanding.
 
 
-10-

 
GENESIS ENERGY, L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
 
Distributions
 
We paid or will pay the following distributions in 2010 and 2011:
 
                             
General
       
                 
Limited
   
General
   
Partner
       
                 
Partner
   
Partner
   
Incentive
       
           
Per Unit
   
Interests
   
Interest
   
Distribution
   
Total
 
Distribution For
   
Date Paid
   
Amount
   
Amount
   
Amount
   
Amount
   
Amount
 
                     
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
    $ 0.3875     $ 15,339     $ 313     $ 3,147     $ 18,799  
Fourth quarter 2010
   
February 2011
    $ 0.4000     $ 25,846     $     $     $ 25,846  
First quarter 2011
   
May 2011 (1)
    $ 0.4075     $ 26,331     $     $     $ 26,331  

(1) This distribution will be paid on May 13, 2011 to unitholders of record as of May 3, 2011.
 
Net Income Per Common Unit
 
 The following table sets forth the computation of basic and diluted net income per common unit.
 
   
Three Months Ended
 
   
March 31,
 
   
2011
   
2010
 
Numerators for basic and diluted net income per common unit:
           
Income attributable to Genesis Energy, L.P.
  $ 7,030     $ 6,885  
Less: General partner’s incentive distribution to be paid for the period
          (2,339 )
Less: Credit for Class B Awards
          (1,977 )
Subtotal
    7,030       2,569  
Less: General partner 2% ownership
          (51 )
Income available for common unitholders
  $ 7,030     $ 2,518  
                 
Denominator for basic and diluted per common unit:
    64,615       39,548  
                 
Basic and diluted net income per common unit
  $ 0.11     $ 0.06  
 
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 equity investees. Our segment margin definition also excludes the non-cash effects of our stock appreciation rights compensation plan, 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.
 
 
-11-

 
GENESIS ENERGY, L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
 
In the first quarter of 2011, we reorganized our operating segments as a result of a change in the way our Chief Executive Officer evaluates the performance of operations, develops strategy and allocates capital resources. The results of our CO2 marketing activities and processing of syngas through a joint venture, formerly reported in the Industrial Gases Segment, are now included in our Supply and Logistics Segment. The change in operating segments had no impact on our reportable units for goodwill purposes. The historical segment disclosures have been recast to be consistent with the current presentation. This recast also included combining revenues and costs and expenses for our industrial gases activities shown separately in our Unaudited Condensed Consolidated Statements of Operations in the 2010 period with revenues and costs and expenses for our supply and logistics activities.

   
Pipeline
   
Refinery
   
Supply &
       
   
Transportation
   
Services
   
Logistics
   
Total
 
Three Months Ended March 31, 2011
                       
Segment margin (a)
  $ 17,682     $ 17,948     $ 13,525     $ 49,155  
                                 
Maintenance capital expenditures
  $ 187     $ 207     $ 385     $ 779  
                                 
Revenues:
                               
External customers
  $ 12,593     $ 49,583     $ 627,622     $ 689,798  
Intersegment (b)
    1,862       (2,037 )     175        
Total revenues of reportable segments
  $ 14,455     $ 47,546     $ 627,797     $ 689,798  
                                 
Three Months Ended March 31, 2010
                               
Segment margin (a)
  $ 10,399     $ 13,260     $ 7,006     $ 30,665  
                                 
Maintenance capital expenditures
  $ 56     $ 459     $ 110     $ 625  
                                 
Revenues:
                               
External customers
  $ 11,412     $ 31,370     $ 423,749     $ 466,531  
Intersegment (b)
    2,246       (1,868 )     (378 )      
Total revenues of reportable segments
  $ 13,658     $ 29,502     $ 423,371     $ 466,531  
 
 
a)
A reconciliation of Segment Margin to income before income taxes for the periods presented is as follows:
 
 
-12-

GENESIS ENERGY, L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
 
   
Three Months Ended
 
   
March 31,
 
   
2011
   
2010
 
             
Segment margin
  $ 49,155     $ 30,665  
Corporate general and administrative expenses
    (7,384 )     (5,430 )
Depreciation and amortization
    (13,903 )     (13,406 )
Net gain (loss) on disposal of surplus assets
    11       (80 )
Interest expense
    (8,699 )     (3,204 )
Non-cash expenses not included in segment margin
    (7,435 )     (224 )
Other items excluded from income affecting segment margin
    (4,415 )     (1,305 )
Income before income taxes
  $ 7,330     $ 7,016  
 
 
b)
Intersegment sales were conducted on an arm’s length basis.
 
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. Affiliates of Denbury Resources, Inc. sold its interests in our general partner on February 5, 2010. Transactions with Denbury are included in the table below as related party transactions through February 5, 2010.
 
The transactions with related parties were as follows:
 
   
Three Months Ended
 
   
March 31,
 
   
2011
   
2010
 
             
Petroleum products sales to an affiliate of the Robertson Group
  $ 9,721     $  
Marine operating fuel and expenses provided by an affiliate of the Robertson Group
    1,040        
Sales of CO2 to Sandhill
    543       536  
Petroleum products sales to Davison family businesses
    242       215  
Operations, general and administrative services provided by our general partner (1)
          11,305  
Truck transportation services provided to Denbury
          182  
Pipeline transportation services provided to Denbury
          1,364  
Payments received under direct financing leases from Denbury
          5,464  
Pipeline transportation income portion of direct financing lease fees from Denbury
          1,502  
Pipeline monitoring services provided to Denbury
          10  
CO2 transportation services provided by Denbury
          373  
 
 
-13-

 
GENESIS ENERGY, L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
 
 
(1)
Our general partner became a wholly-owned subsidiary in December 2010.
 
Amounts due to and from Related Parties
 
At March 31, 2011 and December 31, 2010, an affiliate of the Robertson Group owed us $2.9 million and $1.4 million, respectively, for petroleum products purchases, and we owed the affiliate $0.4 million and $0.2 million, respectively, for marine-related costs. Sandhill owed us $0.2 million for purchases of CO2 at March 31, 2011 and December 31, 2010.
 
9. Supplemental Cash Flow Information
 
The following table provides information regarding the net changes in components of operating assets and liabilities.
 
   
Three Months Ended
 
   
March 31,
 
   
2011
   
2010
 
Decrease (increase) in:
           
Accounts receivable
  $ (96,899 )   $ 5,521  
Inventories
    20,211       (9,502 )
Other current assets
    (7,890 )     (2,609 )
Increase (decrease) in:
               
Accounts payable
    51,249       1,462  
Accrued liabilities
    607       (3,032 )
Net changes in components of operating assets and liabilities
  $ (32,722 )   $ (8,160 )
 
 
Payments of interest and commitment fees were $3.1 million and $2.7 million for the three months ended March 31, 2011 and 2010, respectively.
 
At March 31, 2011, we had incurred liabilities for fixed asset and intangible asset additions totaling $0.6 million that had not been paid at the end of the first quarter, and, therefore, are not included in the caption “Payments to acquire fixed and intangible assets” under investing activities on the Unaudited Consolidated Statements of Cash Flows. At March 31, 2010, we had incurred $1.3 million of such liabilities that had not been paid at that date and are not included in “Payments to acquire fixed and intangible assets” and “Other, net” under investing activities.
 
 
-14-

 
GENESIS ENERGY, L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
 
10. Derivatives
 
 Commodity Derivatives
 
At March 31, 2011, we had the following outstanding derivative commodity futures, forwards and options contracts that were entered into to hedge inventory or fixed price purchase commitments:
             
   
Sell (Short)
   
Buy (Long)
 
   
Contracts
   
Contracts
 
Designated as hedges under accounting rules:
           
Crude oil futures:
           
Contract volumes (1,000 bbls)
    19        
Weighted average contract price per bbl
  $ 91.96     $  
                 
Not qualifying or not designated as hedges under accounting rules:
               
Crude oil futures:
               
Contract volumes (1,000 bbls)
    116       99  
Weighted average contract price per bbl
  $ 99.23     $ 105.38  
                 
Heating oil futures:
               
Contract volumes (1,000 bbls)
    181        
Weighted average contract price per gal
  $ 2.92     $  
                 
RBOB gasoline futures:
               
Contract volumes (1,000 bbls)
    8        
Weighted average contract price per gal
  $ 3.05     $  
                 
    #6 Fuel oil futures:
               
        Contract volumes (1,000 bbls)
    394       45  
       Weighted average contract price per bbl
  $ 86.97     $ 96.07  
                 
Crude oil forwards:
               
Contract volumes (1,000 bbls)
    122       122  
Weighted average contract price per bbl
  $ 110.37     $ 118.79  
                 
Crude oil written calls:
               
Contract volumes (1,000 bbls)
    235        
Weighted average premium received
  $ 3.69     $  
 
Financial Statement Impacts
 
The following tables reflected the estimated fair value gain (loss) position of our hedge derivatives and related inventory impact for qualifying hedges at March 31, 2011 and December 31, 2010:
 
 
-15-

 
GENESIS ENERGY, L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
 
Fair Value of Derivative Assets and Liabilities
 
   
Asset Derivatives
 
   
Unaudited
           
   
Consolidated
 
Fair Value
 
   
Balance Sheets
Location
 
March 31, 2011
   
December 31, 2010
 
Commodity derivatives - futures and call options:
               
Hedges designated under accounting guidance as fair value hedges
 
 Other Current Assets
  $ 4     $ 14  
Undesignated hedges
 
 Other Current Assets
    214       493  
Total asset derivatives
      $ 218     $ 507  
                     
   
Liability Derivatives
 
   
Unaudited
               
   
Consolidated
 
Fair Value
 
   
Balance Sheets
Location
 
March 31, 2011
   
December 31, 2010
 
Commodity derivatives - forwards futures and call options:
                   
Hedges designated under accounting guidance as fair value hedges
 
 Other Current Assets
  $ (309 ) (1)   $ (191 ) (1)
Undesignated hedges
 
 Other Current Assets
    (8,678 ) (1)     (2,283 ) (1)
Total liability derivatives
        (8,987 )     (2,474 )
 
 
(1)
 These derivative liabilities have been funded with margin deposits recorded in our Unaudited Consolidated Balance Sheets in Other Current Assets.
 
 
-16-

 
GENESIS ENERGY, L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
 
   
Effect on Unaudited Consolidated Statements of Operations
 
   
and Other Comprehensive Income
 
   
Amount of Gain (Loss) Recognized in Income
 
                           
Other Comprehensive
 
   
Supply & Logistics
   
Interest Expense
   
Loss
 
   
Product Costs
   
Reclassified from AOCL
   
Effective Portion
 
   
Three Months
   
Three Months
   
Three Months
 
   
Ended March 31,
   
Ended March 31,
   
Ended March 31,
 
   
2011
   
2010
   
2011
   
2010
   
2011
   
2010
 
Commodity derivatives - forwards futures and call options:
                                   
Contracts designated as hedges under accounting guidance
  $ (261 ) (1)   $ 274   (1)   $     $     $     $  
Contracts not considered hedges under accounting guidance
    (18,253 )     (552 )                        
Total commodity derivatives
    (18,514 )     (278 )                        
                                                 
Interest rate swaps designated as cash flow hedges under accounting guidance
                      (280 )           (204 )
                                                 
Total derivatives
  $ (18,514 )   $ (278 )   $     $ (280 )   $     $ (204 )
 
 
(1)  Represents the amount of loss recognized in income for derivatives related to the fair value hedge of inventory. The amount excludes the gain on the hedged inventory under the fair value hedge of $0.6 million and $0.1 million for March 31, 2011 and March 31, 2010, respectively.
 
11. 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 March 31, 2011. 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 March 31, 2011
   
Fair Value at December 31, 2010
 
Recurring Fair Value Measures
 
Level 1
   
Level 2
   
Level 3
   
Level 1
   
Level 2
   
Level 3
 
                                     
Commodity derivatives:
                                   
Assets
  $ 218     $     $     $ 507     $     $  
Liabilities
  $ (7,960 )   $ (1,027 )   $     $ (2,474 )   $     $  
 
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.
 
 
-17-

 
GENESIS ENERGY, L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Level 2
 
Level 2 fair values are based on pricing inputs other than quoted prices in active markets (as reflected in Level 1 fair values) and are either directly or indirectly observable as of the measurement date. Level 2 fair values include instruments that are valued using financial models or other appropriate valuation methodologies. Such financial models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, the time value of money, volatility factors, current market and contractual prices for the underlying instruments and other relevant economic measures. Substantially all of these assumptions are: (i) observable in the marketplace throughout the full term of the instrument; (ii) can be derived from observable data; or (iii) are validated by inputs other than quoted prices (e.g., interest rate and yield curves at commonly quoted intervals). Our Level 2 fair values consist of forward commodity derivative instruments. The fair values of these derivative instruments are based on observable price quotes for similar products and locations.
 
Level 3
 
At March 31, 2011, we had no Level 3 fair value measurements. Included within Level 3 of the fair value hierarchy at March 31, 2010 were our interest rate swaps. These swaps were settled 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
 
   
March 31,
 
   
2010
 
Balance at beginning of period
  (1,688 )
Realized and unrealized gains (losses)-
       
Reclassified into interest expense for settled contracts
    280  
Included in other comprehensive income
    (204 )
Balance at end of period
  $ (1,612 )
         
Total amount of losses for the three months ended included in earnings attributable to the change in unrealized losses relating to liabilities still held at March 31, 2010
  $ (21 )
 
See Note 10 for additional information on our derivative instruments.
 
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.
 
12. 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 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.
 
 
-18-

 
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
 
 
Segment Reporting Change
 
 
Available Cash before Reserves
 
 
Results of Operations
 
 
Liquidity and Capital Resources
 
 
Non-GAAP Reconciliation
 
 
Commitments and Off-Balance Sheet Arrangements
 
 
Forward Looking Statements
 
In the discussions that follow, we will focus on two measures that we use to manage the business and to review the results of our operations. Those two measures are Segment Margin and Available Cash before Reserves. 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 equity investees. In addition, our segment margin definition excludes the non-cash effects of our stock appreciation rights plan, 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 distributable cash generated by our equity investees in lieu of our equity income attributable to our equity investees, the elimination of gains and losses on asset sales (except those from the sale of surplus assets) and unrealized gains and losses on derivative transactions not designated as hedges for accounting purposes, the elimination of expenses related to acquiring 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 first quarter of 2011, we reported net income attributable to the partnership of $7 million, or $0.11 per common unit. We generated $31.9 million of Available Cash before Reserves, and we will distribute $26.3 million to holders of our common units for the first quarter. During the first quarter of 2011, cash utilized in operating activities was $2.1 million.
 
Segment margin increased by $18.5 million, or 60.3%, in the first quarter of 2011, as compared to the first quarter of 2010. This increase resulted from improvements in segment margin of approximately 70%, 35% and 93% in our pipeline transportation, refinery services and supply and logistics segments, respectively. The contribution to segment margin from our investment in Cameron Highway, combined with increased throughput on our onshore pipelines, were the primary factors increasing pipeline segment margin. In our refinery services segment, NaHS sales volumes increased by approximately 12% over the first quarter of 2010 as demand from mining companies and pulp and paper companies increased. Our supply and logistics segment, which now includes the results of our CO2 marketing and other industrial gases activities, benefited from market conditions that increased the differentials between grades of crude oil and increased demand for heavy-end petroleum products.
 
 
-19-

 
On April 11, 2011, we increased our quarterly distribution rate to our common unitholders for the twenty-third consecutive quarter.  In May of 2011, we will pay a distribution of $0.4075 per unit attributable to our first quarter of 2011, which represents an approximate 10.9% increase from our distribution of $0.3675 per unit for the first quarter of 2010.  During the first quarter of 2011, we paid a distribution of $0.40 per unit related to the fourth quarter of 2010.
 
Segment Reporting Change
 
In the first quarter of 2011, we reorganized our operating segments as a result of a change in the way our Chief Executive Officer, who is our chief operating decision maker, evaluates the performance of operations, develops strategy and allocates capital resources. The results of our CO2 marketing activities and processing of syngas through a joint venture, formerly reported in the Industrial Gases Segment, are now included in our Supply and Logistics Segment.  Our disclosures related to prior periods have been recast to reflect our reorganized segments.
 
Available Cash before Reserves
 
Available Cash before Reserves was as follows:
 
   
Three Months Ended
 
   
March 31,
 
   
2011
   
2010
 
   
(in thousands)
 
Net income attributable to Genesis Energy, L.P.
  $ 7,030     $ 6,885  
Depreciation and amortization
    13,903       13,406  
Cash received from direct financing leases not included in income
    1,113       1,015  
Cash effects of sales of certain assets
          304  
Effects of available cash generated by equity method investees not included in income
    3,303       291  
Cash effects of equity-based compensation plans
    (1,178 )     (551 )
Non-cash tax expense
    145       186  
Loss of DG Marine in excess of distributable cash
          (1,053 )
Non-cash equity-based compensation expense (benefit)
    513       (695 )
Expenses related to acquiring or constructing assets that provide new sources of cash flow
    1,055        
Unrealized losses (gains) on derivative transactions excluding fair value hedges
    6,674       (549 )
Other items, net
    87       (523 )
Maintenance capital expenditures
    (779 )     (625 )
Available Cash before Reserves
  $ 31,866     $ 18,091  
 
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 March 31, 2011 and 2010 in “Liquidity and Capital Resources – Non-GAAP Reconciliation” below.  For the three months ended March 31, 2011, cash flows utilized in operating activities were $2.1 million and for the three months ended March 31, 2010, cash flows provided by operating activities were $13.3 million.
 
 
-20-

 
Results of Operations
 
Revenues, Costs and Expenses and Net Income
 
Our revenues for the three months ended March 31, 2011 increased $223 million, or 47.9% from the first quarter of 2010.  Additionally, our costs and expenses increased $220 million, or 48.3% 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 significant increase in our revenues and costs between the two first quarter periods is primarily attributable to the fluctuations in the market prices for crude oil and petroleum products.  In the first quarter of 2011, closing prices for West Texas Intermediate crude oil on the New York Mercantile Exchange averaged $94.10 per barrel, as compared to $78.71 per barrel in the first quarter of 2010 – an increase of 19.6%.
 
Net income (attributable to us) increased $0.1 million, or 2.1%, between the first quarter of 2010 and the same period in 2011.  The significant factors affecting net income were improved operating results by our business segments as compared to the first quarter of 2010 including our equity method investees, offset partially by an increase in interest costs and general and administrative expenses.  A more detailed discussion of our segment results and other costs is included below.
 
Segment Margin
 
The contribution of each of our segments to total Segment Margin in the three months ended March 31, 2011 and 2010 was as follows:
 
   
Three Months Ended March 31,
 
   
2011
   
2010
 
   
(in thousands)
 
Pipeline transportation
  $ 17,682     $ 10,399  
Refinery services
    17,948       13,260  
Supply and logistics
    13,525       7,006  
Total Segment Margin
  $ 49,155     $ 30,665  
 
Pipeline Transportation Segment
 
Operating results and volumetric data for our pipeline transportation segment were as follows:

   
Three Months Ended March 31,
 
   
2011
   
2010
 
   
(in thousands)
 
             
Crude oil tariffs and revenues from direct financing leases - onshore crude oil pipelines
  $ 5,333     $ 4,516  
CO2 tariffs and revenues from direct financing leases of CO2 pipelines
    6,646       6,688  
Sales of crude oil pipeline loss allowance volumes
    1,519       1,339  
Available cash generated by Cameron Highway
    6,000        
Pipeline operating costs, excluding non-cash charges for equity-based compensation and other non-cash expenses
    (3,071 )     (3,409 )
Payments received under direct financing leases not included in income
    1,113       1,015  
Other
    142       250  
Segment margin
  $ 17,682     $ 10,399  
 
 
-21-

 
   
Three Months Ended March 31,
 
Pipeline System
 
2011
   
2010
 
             
Mississippi - Bbls/day
    20,631       23,626  
Jay - Bbls/day
    14,940       14,098  
Texas - Bbls/day
    46,849       19,355  
Cameron Highway - Bbls/day
    170,709        
Free State - Mcf/day
    174,995       175,251  
 
Three Months Ended March 31, 2011 Compared with Three Months Ended March 31, 2010
 
Pipeline Segment Margin for the first quarter of 2011 increased $7.3 million.   The significant components of this change were as follows:
 
 
Our share of the available cash before reserves generated by Cameron Highway of $6.0 million for the three months ended March 31, 2011.  We acquired our 50% interest in Cameron Highway in November 2010.  Revenue generating volumes on Cameron Highway were approximately 170,709 barrels per day, a 14% increase from the average daily rate for the period in the fourth quarter of 2010 during which we owned our interest in the pipeline.  Planned improvements to offshore field facilities by producers with fields connected to Cameron Highway are expected to be performed in the second and third quarters of 2011.  While these field improvements by the producers are expected to increase volumes on Cameron Highway in the future, reductions in volumes while the improvements are made will likely reduce our share of available cash before reserves from the joint venture during those quarters.
 
 
Crude oil tariffs and revenues from direct financing leases increased $0.8 million.  Volumes transported on our crude oil pipelines increased 25,341 barrels per day, with the increase in volumes attributable primarily to the Texas System where demand by the refiners connected to our system increased.  Volumes on the Jay System increased 842 barrels per day, while volumes on the Mississippi System, where the incremental tariff rate is only $0.25 per barrel, decreased by approximately 2,995 barrels a day, primarily a result of fluctuations in tertiary recovery activities by producers.
 
 
Pipeline integrity testing and other operating costs and maintenance repairs decreased by $0.3 million.  Pipeline integrity tests on a segment of our Texas System in the first quarter of 2010 cost approximately $0.6 million.  This test, which allowed us to increase the operating pressure of the segment, will not be required to be performed again until 2015.
 
 
-22-

 
Refinery Services Segment
 
Operating results for our refinery services segment were as follows:
 
   
Three Months Ended March 31,
 
   
2011
   
2010
 
Volumes sold:
           
NaHS volumes (Dry short tons “DST”)
    37,233       33,107  
NaOH (caustic soda) volumes (DST)
    24,640       21,367  
Total
    61,873       54,474  
                 
Revenues (in thousands):
               
NaHS revenues
  $ 36,799     $ 24,254  
NaOH (caustic soda) revenues
    10,239       4,802  
Other revenues
    2,545       2,314  
Total external segment revenues
  $ 49,583     $ 31,370  
                 
Segment margin
  $ 17,948     $ 13,260  
                 
Average index price for NaOH per DST (1)
  $ 440     $ 268  
                 
Raw material and processing costs as % of segment revenues
    42 %     29 %
 
 
(1)
 Source:  Harriman Chemsult Ltd.
 
Three Months Ended March 31, 2011 Compared with Three Months Ended March 31, 2010
 
Refinery services Segment Margin for the first quarter of 2011 was $17.9 million, an increase of $4.7 million, or 35%, from the comparative period in 2010.  The significant components of this fluctuation were as follows:
 
 
An increase in NaHS sales volumes of 12.5%.  The demand for base metals such as copper and molybdenum has increased over the prior period as the world economies, particularly outside of the United States and European Union, have improved over the prior period.  Additionally the return of industrialization and urbanization in the world’s emerging economies has increased the demand for paper products and packaging materials.  These trends have led to a noticeable increase in NaHS demand from some copper and molybdenum miners and from our pulp/paper customers primarily in North America.  The pricing in the majority of our sales contracts for NaHS include adjustments for fluctuations in commodity benchmarks, freight, labor, energy costs and government indexes.  The frequency at which these adjustments are applied varies by contract, geographic region and supply point.
 
 
An increase in caustic soda sales volumes of 15.3%.  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 not affected by the demand we have in our operations that consume caustic soda.
 
 
Index prices for caustic soda averaged approximately $268 per DST in the first quarter of 2010.  Market prices of caustic soda increased to an average of approximately $440 per DST during the first quarter of 2011.  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 do not materially affect Segment Margin attributable to our sulfur processing services because we generally pass those costs through to our NaHS sales customers.
 
 
-23-

 
 
Somewhat mitigating the increase in segment margin was a slight increase (less than 8%) in total delivery logistics costs. The majority of this increase was attributable to the increase in NaHS and caustic volumes sold, as average delivery costs per DST remained relatively constant with the 2010 period.  Aggressive management of these delivery costs, despite increases in fuel costs, allowed us to maintain this average.
 
Supply and Logistics Segment
 
Operating results from our supply and logistics segment were as follows:
 
   
Three Months Ended March 31,
 
   
2011
   
2010
 
   
(in thousands)
 
Supply and logistics revenue
  $ 627,797     $ 423,371  
Crude oil and products costs, excluding unrealized gains and losses from derivative transactions
    (590,465 )     (392,191 )
Operating and segment general and administrative costs, excluding non-cash charges for equity-based compensation and other non-cash expenses
    (24,307 )     (24,646 )
Other
    500       472  
Segment margin
  $ 13,525     $ 7,006  
                 
Volumes of crude oil and petroleum products (barrels per day)
    66,863       57,253  
 
Three Months Ended March 31, 2011 as Compared to Three Months Ended March 31, 2010
 
The average market prices of crude oil and petroleum products increased by more than $15 per barrel, or approximately 20%, between the two quarterly periods; however that price volatility had a limited impact on our Segment Margin.  Segment Margin for our Supply and Logistics segment increased by $6.5 million.
 
The increase in segment margin resulted primarily from increased opportunities to handle additional volumes of the heavy-end petroleum products as activity increased in the 2011 period at refineries in our operating area.  The volumes we handled during the period increased by 17% as compared to the first quarter of 2010.  Greater demand for fuel oil and other heavy-end petroleum products in countries outside the United States has helped to sustain the price environment for the products that we sold.  Additionally the increased refinery activity created higher demand for inland marine transportation services for heavy-end products, resulting in an increase in the average charter rates for our inland marine transportation services in the first quarter of 2011 as compared to the prior year period.  We also made changes in some of our existing crude oil and petroleum products commercial arrangements to maximize value.
 
 
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  Other Costs, Interest, and Income Taxes
 
General and administrative expenses.  General and administrative expenses consisted of the following:
 
   
Three Months Ended March 31,
 
   
2011
   
2010
 
   
(in thousands)
 
             
General and administrative expenses not separately identified below
  $ 5,141     $ 5,229  
Bonus plan expense
    1,450       1,000  
Equity-based compensation plan expense
    408       280  
Third party costs related to business development activities and growth projects
    1,055        
Expenses related to change in owner of our general partner
          1,762  
Reduction in non-cash compensation expense related to management team
          (1,977 )
Total general and administrative expenses
  $ 8,054     $ 6,294  
 
Routine general and administrative expenses, including bonus expense, increased by $0.4 million to $6.6 million in the first quarter of 2011 as compared to the first quarter of 2010.   The increase was primarily related to a higher level of bonus accrual related to the improvements in our operating results.  An increase in activities related to evaluating potential business and growth opportunities resulted in approximately $1.1 million more of costs paid to third parties for their assistance in these activities.
 
In the first quarter of 2010, we incurred $1.8 million of costs related to the change in our general partner.  The settlement of compensation arrangements with our management team that vested at the time of that change reduced previously recorded accruals for those arrangements, more than offsetting the effects of those costs on general and administrative expenses in the first quarter of 2010.
 
Depreciation and amortization expense. Depreciation and amortization expense increased by $0.5 million between the quarterly periods, primarily as a result of an adjustment in the useful lives of certain of our intangible assets in the first quarter of 2011.  See Note 4 to our Unaudited Condensed Consolidated Financial Statements for additional information regarding this change.
 
Interest expense, net.
 
Interest expense, net was as follows:
 
   
Three Months Ended March 31,
 
   
2011
   
2010
 
   
(in thousands)
 
Genesis Facility and Notes:
           
Interest expense, credit facility, including commitment fees
  $ 3,126     $ 1,924  
Interest expense, senior unsecured notes
    4,922        
Amortization of credit facility and notes issuance fees
    655       163  
DG Marine Facility:
               
Interest expense and commitment fees
          1,131  
Interest income
    (4 )     (14 )
Net interest expense
  $ 8,699     $ 3,204  

Interest expense on our credit facility increased as the average debt balance quarter to quarter increased $48.2 million and the average interest rate for borrowed funds increased approximately 1% over the same periods.  The increase in the outstanding balance under our credit facility is attributable primarily to acquisitions in the second half of 2010, including the 51% ownership interest in DG Marine we did not own and the elimination of the DG Marine credit facility with borrowings under our credit facility.  Additionally, when we amended and extended our credit facility in June 2010, our average interest rate increased to reflect market conditions.
 
 
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We also incurred interest expense, including amortization of notes issuance fees, of $5.1 million during the quarter in connection with the $250 million of senior unsecured notes issued in November 2010 to partially finance our acquisition of a 50% equity interest in Cameron Highway.
 
Interest expense in the 2010 first quarter period was also affected by interest on the DG Marine credit facility.  As discussed above, in the second half of 2010, we eliminated this facility with borrowings under our credit facility.
 
Income tax expense. A portion of our operations are owned by wholly-owned corporate subsidiaries that are taxable as corporations.  As a result, a substantial portion of the income tax expense we record relates to the operations of those corporations, and will vary from period to period as a percentage of our income before taxes based on the percentage of our income or loss that is derived from those corporations.  The balance of the income tax expense we record relates to state taxes imposed on our operations that are treated as income taxes under generally accepted accounting principles.
 
Liquidity and Capital Resources
 
General
 
As of March 31, 2011, we believe our balance sheet and liquidity position remained strong.  We had $130.5 million of borrowing capacity available under our $525 million senior secured bank revolving credit facility.  We anticipate that our future internally-generated funds and the funds available under our credit facility will allow us to meet our short-term capital needs.
 
We continue to pursue a growth strategy that requires significant capital.  On April 11, 2011, we announced plans to expand our crude oil infrastructure in Texas through the acquisition and refurbishment of three crude oil tanks with barge dock access, and to increase our refinery services operating footprint to provide services to a refinery in Tulsa, Oklahoma.
 
Capital Resources
 
While the projects we announced in April can be financed with capacity available under our credit facility and cash from operations, our ability to satisfy future capital needs will depend on our ability to raise substantial amounts of additional capital, including through equity and debt offerings (public and private) from time to time and other financing transactions, 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.
 
Our 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.  Twelve lenders participate in our credit facility, and we do not anticipate any of them being unable to satisfy their obligations under the credit facility.
 
Our unaudited condensed consolidated balance sheet at March 31, 2011 includes total long-term debt of $639.5 million, consisting of $389.5 million outstanding under our credit facility and $250 million of senior unsecured notes due in 2018.  Included in the $389.5 million outstanding under our credit facility is $46 million borrowed under the inventory sublimit tranche.
 
Cash Flows from Operations
 
We generally utilize the cash flows we generate from our operations to fund our working capital needs.  Excess funds that are generated are used to repay borrowings from our credit facilities and to fund capital expenditures.  Our operating cash flows can be impacted by changes in items of working capital, primarily variances in the timing of payment of accounts payable and accrued liabilities related to capital expenditures.
 
 
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We typically sell our crude oil in the same month in which we purchase it, and we do not rely on borrowings under our credit facility to pay for the crude oil.  During such periods, our accounts receivable and accounts payable generally move in tandem as we make payments and receive payments for the purchase and sale of oil.  In our petroleum products activities, we buy products and typically either move the products to one of our storage facilities for further blending or we sell the product within days of our purchase.  The cash requirements for these activities can result in short term increases and decreases in our borrowings under our credit facility.
 
Net cash flows utilized in our operating activities for the three months ended March 31, 2011 were approximately $2.1 million.  As discussed above, changes in the cash requirements related to payment for petroleum products or collection of receivables from the sale of inventory impact the cash utilized in operating activities.  Additionally, changes in the market prices for crude oil and petroleum products can result in fluctuations in our operating cash flows between periods as the cost to acquire a barrel of oil or products will require more cash. At March 31, 2011, the cost of the inventory on our balance sheet decreased by $19.9 million from December 31, 2010.  Sales of inventory in late March that were collected in April 2011, combined with higher market prices, increased net accounts receivable at March 31, 2011 as compared to December 31, 2010.
 
Capital Expenditures and Distributions Paid to our Unitholders
 
We use cash primarily for our acquisition activities, internal growth projects and distributions we pay to our unitholders.  We finance internal growth projects and distributions primarily with cash generated by our operations.  Acquisition activities have historically been funded with borrowings under our credit facility, equity issuances and the issuance of senior unsecured notes.
 
Capital Expenditures, and Business and Asset Acquisitions
 
A summary of our expenditures for fixed assets and other asset acquisitions in the first quarter of 2011 and 2010 is as follows:
 
   
Three Months Ended
 
   
March 31,
 
   
2011
   
2010
 
   
(in thousands)
 
Capital expenditures for property, plant and equipment:
           
Maintenance capital expenditures:
           
Pipeline transportation assets
  $ 187     $ 56  
Supply and logistics assets
    280       102  
Refinery services assets
    207       459  
Other assets
    105       8  
Total maintenance capital expenditures
    779       625  
                 
Growth capital expenditures:
               
Pipeline transportation assets
    261       20  
Supply and logistics assets
          104  
Refinery services assets
    101        
Information technology systems upgrade project
    2,393       2,373  
Total growth capital expenditures
    2,755       2,497  
Total capital expenditures
    3,534       3,122  
 
During 2011, we expect to expend approximately $3.0 million to $4.0 million for maintenance capital projects in progress or planned.  Those expenditures are expected to include improvements in all of our businesses.  In future years we expect to spend $4 million to $5 million per year on maintenance capital projects.  We also expect to expend approximately $3 million in 2011 for the completion of the remaining phases of our information systems project.
 
 
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On April 11, 2011, we announced two projects to increase the services we provide to producers and refiners.  We acquired three above-ground storage tanks, located in Texas City, Texas, representing aggregate capacity of approximately 230,000 barrels that we will refurbish and convert into crude-oil-capable tanks.  We also acquired an existing barge dock at the same location, all approximately 1.5 miles from our existing Texas pipeline system.  We also intend to construct a truck station, tankage and possible pipeline interconnections at West Columbia, Texas, to be able to provide incremental transportation service for Eagle Ford and other Texas production through our pipeline system to refining markets in the greater Houston/Texas City area as well as markets accessible via barge from the new Texas City terminal.  Once the refurbishment, tie-in and all interconnecting pipe is completed, estimated to be in the fourth quarter of 2011, we will be able to handle approximately 40,000 barrels per day of crude oil through the Texas City terminal.  In connection with our activities in Texas, we are also constructing interconnecting pipeline and other required facilities to provide transportation services for all of the crude oil production from the Hastings field, near Alvin, Texas, that is in the very early stages of a CO2 tertiary recovery program
 
We also entered into an agreement to install a new sour gas processing facility at Holly Refining and Marketing’s refinery complex located in Tulsa, Oklahoma.  The new facility, expected to be completed no later than the fourth quarter of 2012, will remove a portion of the sulfur from the crude oil refined at Holly’s complex and result in additional capacity of 24,000 DST per year of NaHS.
 
We anticipate the total costs of these projects to be less than $30 million in total, which will be incurred primarily in the third and fourth quarters of 2011.
 
Expenditures for capital assets to grow the partnership distribution will depend on our access to debt and equity capital.  We will look for opportunities to acquire assets from other parties that meet our criteria for stable cash flows.
 
Distributions to Unitholders
 
On May 13, 2011, we will pay a distribution of $0.4075 per common unit with respect to the first quarter of 2011 to unitholders of record on May 3, 2011.  This is the twenty-third consecutive quarter in which we have increased our quarterly distribution.  Information on our recent distribution history is included in Note 6 to our Unaudited Condensed Consolidated Financial Statements.
 
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.
 
Available Cash before Reserves, also referred to as distributable cash flow, is commonly used as a supplemental financial measure by management and by external users of financial statements, such as investors, commercial banks, research analysts and rating agencies, to assess: (1) the financial performance of our assets without regard to financing methods, capital structures, or historical cost basis; (2) the ability of our assets to generate cash sufficient to pay interest cost and support our indebtedness; (3) our operating performance and return on capital as compared to those of other companies in the midstream energy industry, without regard to financing and capital structure; and (4) the viability of projects and the overall rates of return on alternative investment opportunities.  Because Available Cash before Reserves excludes some, but not all, items that affect net income or loss and because these measures may vary among other companies, the Available Cash before Reserves data presented in this 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 common unitholders.  This is an important financial measure to our public unitholders since it is an indicator of our ability to provide a cash return on their investment.  Specifically, this financial measure aids investors in determining whether or not we are generating cash flows at a level that can support a quarterly cash distribution to the partners.  Lastly, Available Cash before Reserves (also referred to as distributable cash flow) is the quantitative standard used throughout the investment community with respect to publicly-traded partnerships.
 
 
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The reconciliation of Available Cash before Reserves (a non-GAAP liquidity measure) to cash flow from operating activities (the GAAP measure) for the three months ended March 31, 2011 is as follows:
 
   
Three Months Ended
 
   
March 31,
 
   
2011
   
2010
 
   
(in thousands)
 
                 
Net cash flows (used in ) provided by operating activities (GAAP measure)
  $ (2,105 )   $ 13,290  
Adjustments to reconcile operating cash flows to Available Cash before Reserves:
               
Maintenance capital expenditures
    (779 )     (625 )
Proceeds from sales of certain assets
    11       224  
Amortization of credit facility issuance fees
    (655 )     (455 )
Effects of available cash generated by equity method investees not included in cash flows from operating activities
    2,283       (230 )
Earnings of DG Marine in excess of distributable cash
          (1,053 )
Expenses related to acquiring or constructing assets that provide new sources of cash flow
    1,055        
Other items affecting available cash
    (666 )     (1,220 )
Net effect of changes in operating accounts not included in calculation of Available Cash (See Note 9)
    32,722       8,160  
Available Cash before Reserves
  $ 31,866     $ 18,091  
 
Commitments and Off-Balance Sheet Arrangements
 
Contractual Obligations and Commercial Commitments
 
 There have been no material changes to the commitments and obligations reflected in our Annual Report on Form 10-K for the year ended December 31, 2010.
 
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, 2010, 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” as defined under federal law.  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 and 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;
 
 
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;
 
 
changes in laws and regulations to which we are subject, including tax withholding issues, safety, environmental and employment laws and regulations;
 
 
the effects of production declines resulting from the suspension of drilling in the Gulf of Mexico and the effects of future laws and government regulation resulting from the Macondo accident and oil spill in the Gulf;
 
 
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 of our credit agreement and the indenture governing our notes, which contain various affirmative and negative covenants;
 
 
loss of key personnel;
 
 
an increase in the competition that our operations encounter;
 
 
cost and availability of insurance;
 
 
hazards and operating risks that may not be covered fully by insurance;
 
 
our financial and commodity hedging arrangements;
 
 
capital and credit markets conditions, inflation and interest rates;
 
 
natural disasters, accidents or terrorism;
 
 
changes in the financial condition of customers;
 
 
the treatment of us as a corporation for federal income tax purposes or if we become subject to entity-level taxation for state tax purposes; and
 
 
the potential that our internal controls may not be adequate, weaknesses may be discovered or remediation of any identified weaknesses may not be successful and the impact these could have on our unit price.
 
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, 2010 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 2010 Annual Report on Form 10-K.  There have been no material changes that would affect the quantitative and qualitative disclosures provided therein.  Also, see Note 10 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.
 
In January 2011, we began processing our transactions on a newly-implemented Enterprise Resource Planning (“ERP”) system.  We changed systems in order to (i) establish a platform that accommodates future acquisitions and growth opportunities (ii) integrate and automate more of our functions, which will allow us to have more information in one integrated database, (iii) to provide operating efficiencies, (iv) to enable us to close our books in a more timely manner without sacrificing quality, (v) to review and improve our processes and (vi) to improve the internal control surrounding our computer systems.  As a result of moving to a new system in January 2011, many business processes and internal control procedures were required to be changed in order to conform to our new system.
 
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, 2010.  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, 2010. There have been no material changes to the risk factors since the filing of such Form 10-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.
 
 
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)
 
 
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3.2
 
Fifth Amended and Restated Agreement of Limited Partnership of Genesis (incorporated by reference to Exhibit 3.1 to Form 8-K dated January 3, 2011, File No. 001-12295)
       
 
3.4
 
Fourth Amended and Restated Agreement of Limited Partnership of the Operating Partnership (incorporated by reference to Exhibit 4.2 to Form 8-K dated June 15, 2005, 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 3.1 to Form 8-K dated January 7, 2009, File No. 001-12295)
       
 
3.7
 
Second Amended and Restated Limited Liability Company Agreement of Genesis Energy, LLC dated December 28, 2010 (incorporated by reference to Exhibit 3.2 to Form 8-K dated January 3, 2011, 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)
       
 
4.2
 
Indenture dated November 18, 2010 among Genesis Energy, L.P., Genesis Energy Finance Corporation, certain subsidiary guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to Form 8-K dated November 23, 2010, File No. 001-12295)
       
 
4.3
 
Registration Rights Agreement dated November 18, 2010 among Genesis Energy, L.P., Genesis Energy Finance Corporation, certain subsidiary guarantors named therein and, as representative of the several initial purchasers named therein, Merrill Lynch, Pierce, Fenner & Smith Incorporated (incorporated by reference to Exhibit 4.2 to Form 8-K dated November 23, 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
 
*Filed herewith
 
 
-32-

 
 
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:  May 10, 2011
By:
/s/
Robert V. Deere  
   
 
Robert V. Deere
Chief Financial Officer
 
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