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 June 30, 2011
OR
¨ | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934 |
Commission file number 1-12295
GENESIS ENERGY, L.P.
(Exact name of registrant as specified in its charter)
Delaware | 76-0513049 | |
(State or other jurisdiction of incorporation or organization) |
(I.R.S. Employer Identification No.) |
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919 Milam, Suite 2100, Houston, TX | 77002 | |
(Address of principal executive offices) | (Zip code) |
Registrant's telephone number, including area code: (713) 860-2500
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No ¨
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 x No ¨
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of large accelerated filer, accelerated filer and smaller reporting company in Rule 12b-2 of the Exchange Act.
Large accelerated filer | ¨ | Accelerated filer | x | |||
Non-accelerated filer | ¨ | Smaller reporting company | ¨ |
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2) of the Exchange Act). Yes ¨ No x
Indicate the number of shares outstanding of each of the issuers classes of common stock, as of the latest practicable date. Class A Common Units outstanding as of August 2, 2011: 71,925,065
Form 10-Q
INDEX
Page | ||||||
PART I. FINANCIAL INFORMATION | ||||||
Item 1. | ||||||
Unaudited Condensed Consolidated Balance Sheets June 30, 2011 and December 31, 2010 |
3 | |||||
4 | ||||||
5 | ||||||
6 | ||||||
7 | ||||||
Notes to Unaudited Condensed Consolidated Financial Statements |
8 | |||||
Item 2. |
Managements Discussion and Analysis of Financial Condition and Results of Operations |
22 | ||||
Item 3. | 36 | |||||
Item 4. | 36 | |||||
PART II. OTHER INFORMATION | ||||||
Item 1. | 36 | |||||
Item 1A. | 36 | |||||
Item 2. | 36 | |||||
Item 3. | 36 | |||||
Item 4. | 36 | |||||
Item 5. | 36 | |||||
Item 6. | 37 | |||||
SIGNATURES | 38 |
-2-
PART I. FINANCIAL INFORMATION
UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS
(In thousands)
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.
-3-
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except per unit amounts)
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.
-4-
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS
OF COMPREHENSIVE INCOME
(In thousands)
Three Months Ended
June 30, |
Six Months Ended
June 30, |
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2011 | 2010 | 2011 | 2010 | |||||||||||||
Net income |
$ | 17,358 | $ | 13,921 | $ | 24,388 | $ | 20,246 | ||||||||
Change in fair value of derivatives: |
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Current period reclassification to earnings |
| 279 | | 559 | ||||||||||||
Changes in derivative financial instruments - interest rate swaps |
| 4 | | (200 | ) | |||||||||||
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Comprehensive income |
17,358 | 14,204 | 24,388 | 20,605 | ||||||||||||
Comprehensive loss attributable to noncontrolling interests |
| 172 | | 694 | ||||||||||||
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Comprehensive income attributable to Genesis Energy, L.P. |
$ | 17,358 | $ | 14,376 | $ | 24,388 | $ | 21,299 | ||||||||
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The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.
-5-
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF PARTNERS CAPITAL
(In thousands)
Partners Capital | ||||||||
Number of
Common Units |
Common
Unitholders |
|||||||
Partners capital, December 31, 2010 |
64,615 | $ | 669,264 | |||||
Net income |
| 24,388 | ||||||
Cash distributions |
| (52,189 | ) | |||||
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Partners capital, June 30, 2011 |
64,615 | $ | 641,463 | |||||
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Partners Capital | ||||||||||||||||||||||||
Number of
Common Units |
Common
Unitholders |
General
Partner |
Accumulated
Other Comprehensive Loss |
Non-
Controlling Interests |
Total
Capital |
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Partners capital, December 31, 2009 |
39,488 | $ | 585,554 | $ | 11,152 | $ | (829 | ) | $ | 23,056 | $ | 618,933 | ||||||||||||
Comprehensive income: |
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Net income |
| 14,770 | 6,353 | | (877 | ) | 20,246 | |||||||||||||||||
Interest rate swap loss reclassified to interest expense |
| | | 274 | 285 | 559 | ||||||||||||||||||
Interest rate swap loss |
| | | (98 | ) | (102 | ) | (200 | ) | |||||||||||||||
Cash contributions |
| | 37 | | | 37 | ||||||||||||||||||
Cash distributions |
| (28,799 | ) | (4,964 | ) | | (3 | ) | (33,766 | ) | ||||||||||||||
Contribution for executive compensation |
| | (1,676 | ) | | | (1,676 | ) | ||||||||||||||||
Unit based compensation expense |
98 | 20 | | | | 20 | ||||||||||||||||||
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Partners capital, June 30, 2010 |
39,586 | $ | 571,545 | $ | 10,902 | $ | (653 | ) | $ | 22,359 | $ | 604,153 | ||||||||||||
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The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.
-6-
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
Six Months Ended June 30, | ||||||||
2011 | 2010 | |||||||
CASH FLOWS FROM OPERATING ACTIVITIES: |
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Net income |
$ | 24,388 | $ | 20,246 | ||||
Adjustments to reconcile net income to net cash provided by operating activities - |
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Depreciation and amortization |
28,156 | 27,012 | ||||||
Amortization and write-off of credit facility issuance costs |
1,310 | 1,269 | ||||||
Amortization of unearned income and initial direct costs on direct financing leases |
(8,672 | ) | (8,873 | ) | ||||
Payments received under direct financing leases |
10,926 | 10,926 | ||||||
Equity in earnings of investments in equity investees |
(3,789 | ) | (545 | ) | ||||
Cash distributions of earnings of equity investees |
5,917 | 1,122 | ||||||
Non-cash effect of equity-based compensation plans |
(757 | ) | 72 | |||||
Non-cash compensation credit |
| (1,676 | ) | |||||
Deferred and other tax liabilities |
21 | 414 | ||||||
Unrealized gain on derivative transactions |
(15 | ) | (1,105 | ) | ||||
Other, net |
972 | 303 | ||||||
Net changes in components of operating assets and liabilities (See Note 9) |
(49,035 | ) | (38,452 | ) | ||||
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Net cash provided by operating activities |
9,422 | 10,713 | ||||||
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CASH FLOWS FROM INVESTING ACTIVITIES: |
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Payments to acquire fixed and intangible assets |
(9,328 | ) | (5,980 | ) | ||||
Cash distributions received from equity investees - return of investment |
6,096 | 180 | ||||||
Investments in equity investees |
(194 | ) | | |||||
Other, net |
1,041 | 640 | ||||||
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Net cash used in investing activities |
(2,385 | ) | (5,160 | ) | ||||
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CASH FLOWS FROM FINANCING ACTIVITIES: |
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Bank borrowings |
267,900 | 345,029 | ||||||
Bank repayments |
(221,900 | ) | (307,029 | ) | ||||
Credit facility issuance fees |
| (7,428 | ) | |||||
General partner contributions |
| 37 | ||||||
Noncontrolling interests contributions, net of distributions |
| (3 | ) | |||||
Distributions to common unitholders |
(52,189 | ) | (28,799 | ) | ||||
Distributions to general partner interest |
| (4,964 | ) | |||||
Other, net |
(1,176 | ) | (511 | ) | ||||
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Net cash used in financing activities |
(7,365 | ) | (3,668 | ) | ||||
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Net (decrease) increase in cash and cash equivalents |
(328 | ) | 1,885 | |||||
Cash and cash equivalents at beginning of period |
5,762 | 4,148 | ||||||
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Cash and cash equivalents at end of period |
$ | 5,434 | $ | 6,033 | ||||
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The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.
-7-
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
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:
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Pipeline transportation of crude oil and carbon dioxide (or CO 2 ); |
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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); |
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Supply and logistics services, which includes terminaling, blending, storing, marketing, and transporting crude oil, petroleum products and CO 2 . |
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:
June 30, 2011 | December 31, 2010 | |||||||
Crude oil |
$ | 15,219 | $ | 6,128 | ||||
Petroleum products |
59,460 | 38,588 | ||||||
Caustic soda |
6,869 | 6,309 | ||||||
NaHS |
7,245 | 4,387 | ||||||
Other |
27 | 16 | ||||||
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Total inventories |
$ | 88,820 | $ | 55,428 | ||||
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Inventories are valued at the lower of cost or market. The costs of inventories exceeded market values by approximately $0.4 million at June 30, 2011, and we reduced the value of inventory in our unaudited condensed consolidated financial statements for this difference. At 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 the three and six months ended June 30, 2011 as we did not acquire our 50% equity interest in Cameron Highway until November 23, 2010.
Three Months
Ended June 30, 2011 |
Six Months
Ended June 30, 2011 |
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Revenues |
$ | 9,835 | $ | 24,844 | ||||
Operating Income |
$ | 2,783 | $ | 11,192 | ||||
Net Income |
$ | 2,783 | $ | 11,202 |
-9-
GENESIS ENERGY, L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
4. Intangible Assets and Goodwill
Intangible Assets
The following table reflects the components of intangible assets being amortized as of:
June 30, 2011 | December 31, 2010 | |||||||||||||||||||||||
Gross
Carrying Amount |
Accumulated
Amortization |
Carrying
Value |
Gross
Carrying Amount |
Accumulated
Amortization |
Carrying
Value |
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Refinery services customer relationships |
$ | 94,654 | $ | 57,625 | $ | 37,029 | $ | 94,654 | $ | 53,139 | $ | 41,515 | ||||||||||||
Supply and logistics customer relationships |
35,430 | 21,783 | 13,647 | 35,430 | 19,981 | 15,449 | ||||||||||||||||||
Refinery services supplier relationships |
36,469 | 32,791 | 3,678 | 36,469 | 31,476 | 4,993 | ||||||||||||||||||
Refinery services licensing agreements |
38,678 | 17,631 | 21,047 | 38,678 | 15,786 | 22,892 | ||||||||||||||||||
Supply and logistics trade names - Davison and Grifco |
18,888 | 11,353 | 7,535 | 18,888 | 7,530 | 11,358 | ||||||||||||||||||
Intangibles associated with supply and logistics lease |
13,260 | 1,855 | 11,405 | 13,260 | 1,618 | 11,642 | ||||||||||||||||||
Other |
16,911 | 2,589 | 14,322 | 13,776 | 1,450 | 12,326 | ||||||||||||||||||
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Total |
$ | 254,290 | $ | 145,627 | $ | 108,663 | $ | 251,155 | $ | 130,980 | $ | 120,175 | ||||||||||||
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The following table reflects our estimated amortization expense for each of the five subsequent fiscal years:
Year Ended December 31, |
Amortization Expense to be Recorded | |
Remainder of 2011 |
$14,498 | |
2012 |
$21,914 | |
2013 |
$14,312 | |
2014 |
$12,049 | |
2015 |
$10,247 |
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 three and six months ended June 30, 2011 decreased $1.4 million, or $0.02 per common unit and $2.9 million, or $0.04 per common unit, respectively. The impact of this change on net income for the remainder of 2011 and 2012 is expected to total $2.8 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 June 30, 2011 and December 31, 2010 was $301.9 million to refinery services and $23.1 million to supply and logistics.
5. Debt
As of June 30, 2011, we had $406 million borrowed under our senior secured credit facility, with $70.4 million of that amount designated as a loan under the inventory sublimit. Additionally, we had $5.9 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 June 30, 2011 was $113.1 million under our credit facility.
-10-
GENESIS ENERGY, L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
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 June 30, 2011, $250 million of senior unsecured notes were outstanding, which had a fair value of approximately $248.8 million.
We believe we were in compliance with the financial covenants contained in our credit facility and indenture as of June 30, 2011.
6. Partners Capital, Distributions and Net Income Per Common Unit
Partners Capital
At June 30, 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. On July 20, 2011, we issued 7,350,000 Class A Units in a public offering. We received proceeds, net of underwriting discount, of $185 million from the offering.
Distributions
We paid or will pay the following distributions in 2010 and 2011:
Distribution For |
Date Paid |
Per Unit
Amount |
Limited
Partner Interests Amount |
General
Partner Interest Amount |
General
Partner Incentive Distribution Amount |
Total
Amount |
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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 | $ | 0.4075 | $ | 26,343 | $ | | $ | | $ | 26,343 | |||||||||||
Second quarter 2011 |
August 2011 (1) | $ | 0.4150 | $ | 29,866 | $ | | $ | | $ | 29,866 |
(1) | This distribution will be paid on August 12, 2011 to unitholders of record as of August 5, 2011. It includes $3.1 million of distributions on the 7,350,000 Class A Common Units issued in July 2011. |
-11-
GENESIS ENERGY, L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Net Income Per Common Unit
The following table sets forth the computation of basic and diluted net income per common unit.
Three Months Ended | Six Months Ended | |||||||||||||||
June 30, | June 30, | |||||||||||||||
2011 | 2010 | 2011 | 2010 | |||||||||||||
Numerators for basic and diluted net income per common unit: |
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Income attributable to Genesis Energy, L.P. |
$ | 17,358 | $ | 14,238 | $ | 24,388 | $ | 21,123 | ||||||||
Less: General partners incentive distribution to be paid for the period |
| (2,642 | ) | | (4,981 | ) | ||||||||||
Add: Expense (Credit) for Class B Awards |
| 301 | | (1,676 | ) | |||||||||||
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Subtotal |
17,358 | 11,897 | 24,388 | 14,466 | ||||||||||||
Less: General partner 2% ownership |
| (238 | ) | | (289 | ) | ||||||||||
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Income available for common unitholders |
$ | 17,358 | $ | 11,659 | $ | 24,388 | $ | 14,177 | ||||||||
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Denominator for basic and diluted per common unit: |
64,615 | 39,586 | 64,615 | 39,567 | ||||||||||||
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Basic and diluted net income per common unit |
$ | 0.27 | $ | 0.29 | $ | 0.38 | $ | 0.36 | ||||||||
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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.
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 CO 2 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.
-12-
GENESIS ENERGY, L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Pipeline
Transportation |
Refinery
Services |
Supply &
Logistics |
Total | |||||||||||||
Three Months Ended June 30, 2011 |
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Segment margin (a) |
$ | 16,927 | $ | 18,947 | $ | 11,799 | $ | 47,673 | ||||||||
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Maintenance capital expenditures |
$ | 39 | $ | 160 | $ | 411 | $ | 610 | ||||||||
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Revenues: |
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External customers |
$ | 12,051 | $ | 51,334 | $ | 699,405 | $ | 762,790 | ||||||||
Intersegment (b) |
3,033 | (1,971 | ) | (1,062 | ) | | ||||||||||
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Total revenues of reportable segments |
$ | 15,084 | $ | 49,363 | $ | 698,343 | $ | 762,790 | ||||||||
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Three Months Ended June 30, 2010 |
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Segment margin (a) |
$ | 11,437 | $ | 16,190 | $ | 10,222 | $ | 37,849 | ||||||||
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Maintenance capital expenditures |
$ | 78 | $ | 356 | $ | 484 | $ | 918 | ||||||||
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Revenues: |
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External customers |
$ | 11,498 | $ | 40,348 | $ | 404,692 | $ | 456,538 | ||||||||
Intersegment (b) |
1,927 | (2,127 | ) | 200 | | |||||||||||
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Total revenues of reportable segments |
$ | 13,425 | $ | 38,221 | $ | 404,892 | $ | 456,538 | ||||||||
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-13-
GENESIS ENERGY, L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Pipeline
Transportation |
Refinery
Services |
Supply &
Logistics |
Total | |||||||||||||
Six Months Ended June 30, 2011 |
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Segment margin (a) |
$ | 34,609 | $ | 36,895 | $ | 25,324 | $ | 96,828 | ||||||||
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Maintenance capital expenditures |
$ | 226 | $ | 367 | $ | 796 | $ | 1,389 | ||||||||
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Revenues: |
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External customers |
$ | 24,644 | $ | 100,917 | $ | 1,327,027 | $ | 1,452,588 | ||||||||
Intersegment (b) |
4,895 | (4,008 | ) | (887 | ) | | ||||||||||
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Total revenues of reportable segments |
$ | 29,539 | $ | 96,909 | $ | 1,326,140 | $ | 1,452,588 | ||||||||
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Six Months Ended June 30, 2010 |
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Segment margin (a) |
$ | 21,836 | $ | 29,450 | $ | 17,228 | $ | 68,514 | ||||||||
|
|
|
|
|
|
|
|
|||||||||
Maintenance capital expenditures |
$ | 134 | $ | 815 | $ | 594 | $ | 1,543 | ||||||||
|
|
|
|
|
|
|
|
|||||||||
Revenues: |
||||||||||||||||
External customers |
$ | 22,910 | $ | 71,718 | $ | 828,441 | $ | 923,069 | ||||||||
Intersegment (b) |
4,173 | (3,995 | ) | (178 | ) | | ||||||||||
|
|
|
|
|
|
|
|
|||||||||
Total revenues of reportable segments |
$ | 27,083 | $ | 67,723 | $ | 828,263 | $ | 923,069 | ||||||||
|
|
|
|
|
|
|
|
a) | A reconciliation of Segment Margin to income before income taxes for the periods presented is as follows: |
Three Months Ended | Six Months Ended | |||||||||||||||
June 30, | June 30, | |||||||||||||||
2011 | 2010 | 2011 | 2010 | |||||||||||||
Segment margin |
$ | 47,673 | $ | 37,849 | $ | 96,828 | $ | 68,514 | ||||||||
Corporate general and administrative expenses |
(7,689 | ) | (5,975 | ) | (15,073 | ) | (11,405 | ) | ||||||||
Depreciation and amortization |
(14,253 | ) | (13,606 | ) | (28,156 | ) | (27,012 | ) | ||||||||
Net (loss) gain on disposal of surplus assets |
(249 | ) | 62 | (238 | ) | (18 | ) | |||||||||
Interest expense |
(9,011 | ) | (3,760 | ) | (17,710 | ) | (6,964 | ) | ||||||||
Non-cash expenses not included in segment margin |
7,102 | 1,559 | (333 | ) | 1,335 | |||||||||||
Other items excluded from income affecting segment margin |
(6,061 | ) | (1,227 | ) | (10,476 | ) | (2,532 | ) | ||||||||
|
|
|
|
|
|
|
|
|||||||||
Income before income taxes |
$ | 17,512 | $ | 14,902 | $ | 24,842 | $ | 21,918 | ||||||||
|
|
|
|
|
|
|
|
b) | Intersegment sales were conducted on an arms length basis. |
-14-
GENESIS ENERGY, L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
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:
Six Months Ended
June 30, |
||||||||
2011 | 2010 | |||||||
Petroleum products sales to an affiliate of the Robertson Group |
$ | 21,254 | $ | | ||||
Marine operating fuel and expenses provided by an affiliate of the Robertson Group |
1,820 | 1,333 | ||||||
Sales of CO 2 to Sandhill |
975 | 1,308 | ||||||
Petroleum products sales to Davison family businesses |
487 | 464 | ||||||
Operations, general and administrative services provided by our general partner (1) |
| 23,131 | ||||||
Truck transportation services provided to Denbury |
| 182 | ||||||
Pipeline transportation services provided to Denbury |
| 1,365 | ||||||
Payments received under direct financing leases from Denbury |
| 99 | ||||||
Pipeline transportation income portion of direct financing lease fees from Denbury |
| 1,502 | ||||||
Pipeline monitoring services provided to Denbury |
| 10 | ||||||
CO 2 transportation services provided by Denbury |
| 373 |
(1) | Our general partner became a wholly-owned subsidiary in December 2010. |
Amounts due to and from Related Parties
At June 30, 2011 and December 31, 2010, an affiliate of the Robertson Group owed us $0.7 million and $1.4 million, respectively, for petroleum products purchases, and we owed the affiliate $0.1 million and $0.2 million, respectively, for marine-related costs. Sandhill owed us $0.2 million for purchases of CO 2 at June 30, 2011 and December 31, 2010.
-15-
GENESIS ENERGY, L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
9. Supplemental Cash Flow Information
The following table provides information regarding the net changes in components of operating assets and liabilities.
Six Months Ended
June 30, |
||||||||
2011 | 2010 | |||||||
Decrease (increase) in: |
||||||||
Accounts receivable |
$ | (54,810 | ) | $ | 4,870 | |||
Inventories |
(33,847 | ) | (45,008 | ) | ||||
Other current assets |
(1,727 | ) | (1,042 | ) | ||||
Increase (decrease) in: |
||||||||
Accounts payable |
37,167 | 5,302 | ||||||
Accrued liabilities |
4,182 | (2,574 | ) | |||||
|
|
|
|
|||||
Net changes in components of operating assets and liabilities |
$ | (49,035 | ) | $ | (38,452 | ) | ||
|
|
|
|
Payments of interest and commitment fees were $17.6 million and $6.1 million for the six months ended June 30, 2011 and 2010, respectively.
At June 30, 2011, we had incurred liabilities for fixed asset and intangible asset additions totaling $0.9 million that had not been paid at the end of the second 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 June 30, 2010, we had incurred $1.1 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.
10. Derivatives
Commodity Derivatives
At June 30, 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. We had no outstanding derivative contracts that were designated as hedges under accounting rules.
-16-
GENESIS ENERGY, L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Sell (Short)
Contracts |
Buy (Long)
Contracts |
|||||||
Not qualifying or not designated as hedges under accounting rules: |
||||||||
Crude oil futures: |
||||||||
Contract volumes (1,000 bbls) |
193 | 101 | ||||||
Weighted average contract price per bbl |
$ | 95.37 | $ | 97.06 | ||||
Heating oil futures: |
||||||||
Contract volumes (1,000 bbls) |
305 | 56 | ||||||
Weighted average contract price per gal |
$ | 2.97 | $ | 2.91 | ||||
RBOB gasoline futures: |
||||||||
Contract volumes (1,000 bbls) |
60 | | ||||||
Weighted average contract price per gal |
$ | 2.81 | $ | | ||||
#6 Fuel oil futures: |
||||||||
Contract volumes (1,000 bbls) |
436 | 18 | ||||||
Weighted average contract price per bbl |
$ | 96.26 | $ | 97.77 | ||||
Crude oil forwards: |
||||||||
Contract volumes (1,000 bbls) |
31 | 31 | ||||||
Weighted average contract price per bbl |
$ | 96.34 | $ | 109.55 | ||||
Crude oil written calls: |
||||||||
Contract volumes (1,000 bbls) |
110 | | ||||||
Weighted average premium received |
$ | 4.50 | $ | |
-17-
GENESIS ENERGY, L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
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 June 30, 2011 and December 31, 2010:
Fair Value of Derivative Assets and Liabilities
Asset Derivatives |
||||||||||
Unaudited Condensed Consolidated Balance Sheets Location |
Fair Value |
|||||||||
June 30, 2011 | December 31, 2010 | |||||||||
Commodity derivatives - futures and call options: |
||||||||||
Hedges designated under accounting guidance as fair value hedges |
Other Current Assets | $ | | $ | 14 | |||||
Undesignated hedges |
Other Current Assets | 1,104 | 493 | |||||||
|
|
|
|
|||||||
Total asset derivatives |
$ | 1,104 | $ | 507 | ||||||
|
|
|
|
|||||||
Liability Derivatives |
||||||||||
Unaudited Condensed Consolidated Balance Sheets Location |
Fair Value |
|||||||||
June 30, 2011 | December 31, 2010 | |||||||||
Commodity derivatives - forwards futures and call options: |
||||||||||
Hedges designated under accounting guidance as fair value hedges |
Other Current Assets | $ | | $ | (191 | ) (1) | ||||
Undesignated hedges |
Other Current Assets | (2,600 | ) (1) | (2,283 | ) (1) | |||||
|
|
|
|
|||||||
Total liability derivatives |
(2,600 | ) | (2,474 | ) | ||||||
|
|
|
|
(1) | These derivative liabilities have been funded with margin deposits recorded in our Unaudited Condensed Consolidated Balance Sheets in Other Current Assets. |
-18-
GENESIS ENERGY, L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(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 $0.2 million and $0.8 million for the three and six months ended June 30, 2011 and excludes the loss recorded on the hedged inventory of $0.4 million and $0.3 million for the three and six months ended June 30, 2010. |
-19-
GENESIS ENERGY, L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
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 June 30, 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 June 30, 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 |
$ | 1,104 | $ | | $ | | $ | 507 | $ | | $ | | ||||||||||||
Liabilities |
$ | (2,225 | ) | $ | (375 | ) | $ | | $ | (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.
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 June 30, 2011 and December 31, 2010, we had no Level 3 fair value measurements.
At June 30, 2010, our interest rate swaps were included within Level 3 of the fair value hierarchy. 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 Marines 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:
-20-
GENESIS ENERGY, L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
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 effect on our financial position, results of operations, or cash flows.
13. Subsequent Event Acquisition of Barges and Pushboats from Florida Marine
In the third quarter of 2011, we expect to complete a transaction to acquire, for $141 million, the black oil transportation fleet of Florida Marine Transporters, Inc. and its affiliates (FMT). The fleet consists of 30 barges (7 of which will be sub-leased under similar terms of an existing FMT lease) and 14 push/tow boats which transport heavy refined products, principally serving refineries and storage terminals along the Gulf Coast, Intracoastal Canal and western river systems of the United States. We expect to fund that acquisition with the proceeds of a public offering of our common units. On July 20, 2011, we issued 7,350,000 Class A Common Units, and received $185 million in proceeds, net of underwriting discounts. The remaining net proceeds of the offering were used for other purposes, including the repayment of borrowings outstanding under our credit facility.
-21-
Item 2. Managements Discussion and Analysis of Financial Condition and Results of Operations
Included in Managements 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 Marines 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 its most directly comparable GAAP measure of cash provided by operating activities, see Liquidity and Capital Resources - Non-GAAP Reconciliation below.
Overview
In the second quarter of 2011, we reported net income attributable to the partnership of $17.4 million, or $0.27 per common unit. We generated $31.9 million of Available Cash before Reserves. In August 2011, we will distribute $0.415 per common unit to our unitholders with respect to the second quarter. During the second quarter of 2011, cash provided by operating activities was $11.5 million.
Segment margin increased by $9.8 million, or 26%, in the second quarter of 2011, as compared to the second quarter of 2010. This increase resulted from improvements in segment margin of approximately 48%, 17% and 15% 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. Our refinery services segment margin increased as a result of several factors, including operating efficiencies realized at several of our sour gas processing facilities as well as our favorable management of the acquisition and utilization of caustic soda in our operations. Our supply and logistics segment, which now includes the results of our CO 2 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.
-22-
In the third quarter of 2011 we expect to complete the previously announced transaction to acquire, for $141 million, the black oil barge transportation fleet of Florida Marine Transporters, Inc. and its affiliates (FMT). That fleet is primarily comprised of 30 barges (7 of which will be sub-leased under similar terms of an existing FMT lease) and 14 push/tow boats which transport heavy refined petroleum products, principally serving refineries and storage terminals along the Gulf Coast, Intracoastal Canal and western river systems of the United States, including the Red, Ouachita and Mississippi Rivers. The barges, which have an average age of approximately three years, are double-hulled and fully compliant with the requirements of the Oil Pollution Act. The boats are modern and efficient, 13 of which have been in service three years or less.
This acquisition will complement and further integrate certain of our existing operations, including our DG Marine inland barge business (comprised of 20 barges and 10 push/tow boats), our storage and blending terminals and our crude oil pipeline systems. All of the expanded fleet of 50 barges are capable of transporting heavy refined products, including asphalt, and with minor modifications, half of the barges will be capable of transporting crude oil as well. We funded this transaction with funds raised from a sale of 7.4 million Class A Common Units that closed on July 20, 2011. See additional discussion under Liquidity and Capital Resources Capital Resources/Sources of Cash below.
On July 13, 2011, we increased our quarterly distribution rate to our common unitholders for the twenty-fourth consecutive quarter. In August of 2011, we will pay a distribution of $0.4150 per unit attributable to our second quarter of 2011, which represents an approximate 10.7% increase from our distribution of $0.375 per unit for the second quarter of 2010. During the second quarter of 2011, we paid a distribution of $0.4075 per unit related to the first quarter of 2011.
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 CO 2 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.
-23-
Available Cash before Reserves
Available Cash before Reserves was as follows:
Three Months Ended
June 30, |
||||||||
2011 | 2010 | |||||||
(in thousands) | ||||||||
Net income attributable to Genesis Energy, L.P. |
$ | 17,358 | $ | 14,238 | ||||
Depreciation and amortization |
14,253 | 13,606 | ||||||
Cash received from direct financing leases not included in income |
1,141 | 1,038 | ||||||
Cash effects of sales of certain assets |
1,413 | 795 | ||||||
Effects of available cash generated by equity method investees not included in income |
4,921 | 188 | ||||||
Cash effects of equity-based compensation plans |
(716 | ) | (117 | ) | ||||
Non-cash tax expense |
(124 | ) | 228 | |||||
Loss of DG Marine in excess of distributable cash |
| (1,481 | ) | |||||
Non-cash equity-based compensation (benefit) expense |
(270 | ) | 246 | |||||
Expenses related to acquiring or constructing assets that provide new sources of cash flow |
1,466 | 81 | ||||||
Unrealized gains on derivative transactions excluding fair value hedges |
(6,968 | ) | (1,591 | ) | ||||
Other items, net |
80 | (238 | ) | |||||
Maintenance capital expenditures |
(610 | ) | (918 | ) | ||||
|
|
|
|
|||||
Available Cash before Reserves |
$ | 31,944 | $ | 26,075 | ||||
|
|
|
|
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 June 30, 2011 and 2010 in Liquidity and Capital Resources Non-GAAP Reconciliation below. For the three months ended June 30, 2011, cash flows provided by operating activities were $11.5 million and for the three months ended June 30, 2010, cash flows utilized in operating activities were $2.6 million.
Results of Operations
Revenues, Costs and Expenses and Net Income
Our revenues for the three months ended June 30, 2011 increased $306 million, or 67% from the second quarter of 2010. Additionally, our costs and expenses increased $299 million, or 68% 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 second quarter periods is primarily attributable to the fluctuations in the market prices for crude oil and petroleum products. In the second quarter of 2011, closing prices for West Texas Intermediate crude oil on the New York Mercantile Exchange averaged $102.56 per barrel, as compared to $78.04 per barrel in the second quarter of 2010 an increase of 31.4%.
Net income (attributable to us) increased $3.1 million, or 22%, between the second 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 second 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.
-24-
Our revenues for the six months ended June 30, 2011 increased $530 million, or 57% from the six months ended June 30, 2010. Additionally, our costs and expenses increased $519 million, or 58% 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. In the first half of 2011, average closing prices for West Texas Intermediate crude oil on the New York Mercantile Exchange averaged $98.33 per barrel, as compared to $78.37 per barrel in the first half of 2010 an increase of 25.5%. Net income (attributable to us) increased $3.3, or 15%, between the first half of 2010 and the same period in 2011, with the majority of the increase attributable to improved segment results, partially offset by increased general and administrative expenses and increases 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 six months ended June 30, 2011 and 2010 was as follows:
Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||
2011 | 2010 | 2011 | 2010 | |||||||||||||
(in thousands) | (in thousands) | |||||||||||||||
Pipeline transportation |
$ | 16,927 | $ | 11,437 | $ | 34,609 | $ | 21,836 | ||||||||
Refinery services |
18,947 | 16,190 | 36,895 | 29,450 | ||||||||||||
Supply and logistics |
11,799 | 10,222 | 25,324 | 17,228 | ||||||||||||
|
|
|
|
|
|
|
|
|||||||||
Total Segment Margin |
$ | 47,673 | $ | 37,849 | $ | 96,828 | $ | 68,514 | ||||||||
|
|
|
|
|
|
|
|
Pipeline Transportation Segment
Operating results and volumetric data for our pipeline transportation segment were as follows:
Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||
2011 | 2010 | 2011 | 2010 | |||||||||||||
(in thousands) | (in thousands) | |||||||||||||||
Crude oil tariffs and revenues from direct financing leases - onshore crude oil pipelines |
$ | 5,867 | $ | 4,896 | $ | 11,200 | $ | 9,412 | ||||||||
CO 2 tariffs and revenues from direct financing leases of CO 2 pipelines |
6,212 | 6,263 | 12,858 | 12,951 | ||||||||||||
Sales of crude oil pipeline loss allowance volumes |
2,109 | 1,533 | 3,628 | 2,872 | ||||||||||||
Available cash generated by Cameron Highway |
5,000 | | 11,000 | | ||||||||||||
Pipeline operating costs, excluding non-cash charges for equity-based compensation and other non-cash expenses |
(3,662 | ) | (2,534 | ) | (6,733 | ) | (5,943 | ) | ||||||||
Payments received under direct financing leases not included in income |
1,141 | 1,038 | 2,254 | 2,053 | ||||||||||||
Other |
260 | 241 | 402 | 491 | ||||||||||||
|
|
|
|
|
|
|
|
|||||||||
Segment margin |
$ | 16,927 | $ | 11,437 | $ | 34,609 | $ | 21,836 | ||||||||
|
|
|
|
|
|
|
|
-25-
Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||
Pipeline System |
2011 | 2010 | 2011 | 2010 | ||||||||||||
Mississippi - Bbls/day |
21,133 | 23,493 | 20,883 | 23,789 | ||||||||||||
Jay - Bbls/day |
16,655 | 14,400 | 15,803 | 14,493 | ||||||||||||
Texas - Bbls/day |
47,091 | 27,902 | 46,971 | 23,602 | ||||||||||||
Cameron Highway - Bbls/day |
108,964 | | 139,666 | | ||||||||||||
Free State - Mcf/day |
131,683 | 133,009 | 153,220 | 154,013 |
Three Months Ended June 30, 2011 Compared with Three Months Ended June 30, 2010
Pipeline Segment Margin for the second quarter of 2011 increased $5.5 million. The significant components of this change were as follows:
|
Our share of the available cash before reserves generated by Cameron Highway was $5.0 million for the three months ended June 30, 2011. We acquired our 50% interest in Cameron Highway in November 2010. Revenue generating volumes on Cameron Highway were approximately 108,964 barrels per day, a 36% decrease from the average daily rate for the first quarter of 2011. Planned improvements to offshore field facilities by producers with fields connected to Cameron Highway were performed in the second quarter of 2011 and are expected to continue in the third quarter of 2011. Although 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 the third quarter. |
|
Crude oil tariffs and revenues from direct financing leases increased $1.0 million. Volumes transported on our crude oil pipelines increased 19,084 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 2,255 barrels per day, while volumes on the Mississippi System, where the incremental tariff rate is only $0.25 per barrel, decreased by 2,360 barrels a day, primarily as a result of fluctuations in tertiary recovery activities by producers. |
|
Pipeline operating costs, excluding non-cash charges increased approximately $1.1 million primarily due to increased insurance costs (related to our investment in Cameron Highway) and maintenance expenditures. |
Six Months Ended June 30, 2011 Compared with Six Months Ended June 30, 2010
For the six month periods, Pipeline Segment Margin increased $12.8 million. The primary factors in this increase were as follows:
|
Our share of the available cash before reserves generated by Cameron Highway was $11.0 million for the six months ended June 30, 2011. |
|
Crude oil tariffs and revenues from direct financing leases increased $1.8 million. Volumes transported on our crude oil pipelines increased 21,773 barrels per day, with the increase in volumes attributable primarily to the Texas System. Volumes on the Jay system increased 1,310 barrels per day, while volumes on the Mississippi System decreased 2,906 barrels per day. The fluctuations in volumes on our pipeline systems for the six months ended 2011 as compared to the six months ended 2010 are due to similar explanations as provided in the quarter to quarter discussion. |
-26-
Refinery Services Segment
Operating results for our refinery services segment were as follows:
Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||
2011 | 2010 | 2011 | 2010 | |||||||||||||
Volumes sold: |
||||||||||||||||
NaHS volumes (Dry short tons DST) |
36,080 | 38,307 | 73,313 | 71,414 | ||||||||||||
NaOH (caustic soda) volumes (DST) |
26,209 | 23,969 | 50,849 | 45,336 | ||||||||||||
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Total |
62,289 | 62,276 | 124,162 | 116,750 | ||||||||||||
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Revenues (in thousands): |
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NaHS revenues |
$ | 36,459 | $ | 30,517 | $ | 73,258 | $ | 54,771 | ||||||||
NaOH (caustic soda) revenues |
12,004 | 6,810 | 22,243 | 11,612 | ||||||||||||
Other revenues |
2,871 | 3,021 | 5,416 | 5,335 | ||||||||||||
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Total external segment revenues |
$ | 51,334 | $ | 40,348 | $ | 100,917 | $ | 71,718 | ||||||||
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Segment margin |
$ | 18,947 | $ | 16,190 | $ | 36,895 | $ | 29,450 | ||||||||
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Average index price for NaOH per DST (1) |
$ | 495 | $ | 340 | $ | 468 | $ | 304 | ||||||||
Raw material and processing costs as % of segment revenues |
41 | % | 35 | % | 42 | % | 32 | % |
(1) | Source: Harriman Chemsult Ltd. |
Three Months Ended June 30, 2011 Compared with Three Months Ended June 30, 2010
Refinery services Segment Margin for the second quarter of 2011 was $18.9 million, an increase of $2.8 million, or 17%, from the comparative period in 2010. The significant components of this fluctuation were as follows:
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NaHS sales volumes decreased 5.8% between the second quarter periods. Difficulties in mining companies negotiations with their workforces led to a slowdown in mine activity and a decrease in our sales volumes to mining companies in the export market. |
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Revenues increased primarily as a function of the increase in the average index price for caustic soda. The pricing in our sales contracts for NaHS includes 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. Our raw material costs related to NaHS increased correspondingly to the rise in the average index price for caustic soda, although operating efficiencies at several of our sour gas processing facilities as well as our favorable management of the acquisition and utilization of caustic soda in our operations and our logistics management, as discussed below, helped offset these costs. |
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Caustic soda sales volumes increased 9.3%. Caustic soda is a key component in the provision of our sulfur-removal service, from which we receive the by-product NaHS. Consequently, we are a very large consumer of caustic soda. In addition, our economies of scale and logistics capabilities allow us to effectively purchase additional caustic soda for re-sale to third parties. Our ability to purchase caustic soda volumes is currently sufficient to meet the demands of our refinery services operations and third-party sales. |
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Index prices for caustic soda averaged approximately $340 per DST in the second quarter of 2010. Market prices of caustic soda increased to an average of approximately $495 per DST during the second 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 |
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generally pass those costs through to our NaHS sales customers. Additionally, our bulk purchase and storage capabilities related to caustic soda allow us to mitigate the effects of changes in index prices for caustic on our operating costs. |
Six Months Ended June 30, 2011 Compared with Six Months Ended June 30, 2010
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An increase in NaHS sales volumes of 2.7% increased Segment Margin. 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 worlds 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. |
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An increase in caustic soda sales volumes of 12.2%. Caustic soda is a key component in the provision of our sulfur-removal service, from which we receive the by-product NaHS. Consequently, we are a very large consumer of caustic soda. In addition, our economies of scale and logistics capabilities allow us to effectively purchase caustic soda for re-sale to third parties. Our ability to purchase caustic soda volumes is currently sufficient to meet the demands of our refinery services operations and third-party sales. |
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Market prices of caustic soda increased to an average of $468 per DST during the first half of 2011 as compared to market prices of caustic soda of $304 per DST in the first half of 2010. The pricing in 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. However, as discussed above, these changes in caustic soda prices do not materially affect Segment Margin. Our raw material costs related to NaHS increased correspondingly to the rise in the average index price for caustic soda, although efficiencies gained from our bulk purchases, logistic and storage capabilities helped offset these costs. |
Supply and Logistics Segment
Operating results from our supply and logistics segment were as follows:
Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||
2011 | 2010 | 2011 | 2010 | |||||||||||||
(in thousands) | (in thousands) | |||||||||||||||
Supply and logistics revenue |
$ | 698,343 | $ | 404,892 | $ | 1,326,140 | $ | 828,263 | ||||||||
Crude oil and products costs, excluding unrealized gains and losses from derivative transactions |
(660,512 | ) | (369,228 | ) | (1,250,977 | ) | (761,419 | ) | ||||||||
Operating and segment general and administrative costs, excluding non-cash charges for equity-based compensation and other non-cash expenses |
(26,544 | ) | (25,994 | ) | (50,851 | ) | (50,640 | ) | ||||||||
Other |
512 | 552 | 1,012 | 1,024 | ||||||||||||
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Segment margin |
$ | 11,799 | $ | 10,222 | $ | 25,324 | $ | 17,228 | ||||||||
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Volumes of crude oil and petroleum products (barrels per day) |
67,469 | 50,383 | 67,167 | 53,799 |
Three Months Ended June 30, 2011 as Compared to Three Months Ended June 30, 2010
The average market prices of crude oil and petroleum products increased by more than $24 per barrel, or approximately 31.4%, 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 $1.6 million.
The increase in segment margin resulted primarily from increased opportunities to acquire and re-sell additional volumes of heavy-end petroleum products as refining activity increased in the 2011 period in our operating area. The volumes we handled during the period increased by 34% as compared to the second quarter of 2010. Greater demand for fuel oil and other heavy-end petroleum products in countries outside the United States has helped sustain the price environment for the products we sell.
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In addition, favorable differentials between different grades of crude oil and petroleum products as well as changes we made in some of our existing crude oil and petroleum products commercial arrangements increased Segment Margin.
The increase in Segment Margin in the second quarter was partially offset by the effects of the Mississippi River flooding, which impaired our petroleum products marketing and marine transportation activities and resulted in some increased costs for idle time.
Six Months Ended June 30, 2011 Compared with Six Months Ended June 30, 2010
Segment margin for our Supply and Logistics segment increased $8.1 million between the six month periods. Average market prices of crude oil and petroleum products increased by approximately $20 per barrel, or approximately 25.5%, however, as previously discussed, price volatility has a limited impact on our Segment Margin.
Favorable quality differentials, primarily between grades of crude oil, as well as modifications to our existing crude oil and petroleum products commercial arrangements, were key factors resulting in increased Segment Margin.
Similar to the quarter-to-quarter comparison, Segment Margin for the six month period also increased due to greater availability of volumes of heavy-end petroleum products resulting from increased refinery utilization in our operating area. The volumes we handled during the first half of 2011 increased approximately 25% as compared to the first half of 2010 as higher foreign demand for fuel oil and other heavy-end petroleum products helped sustain the price environment for the products we sell.
As indicated above in the three-month 2011 period, the Mississippi River flooding during the second quarter impaired our petroleum products marketing and marine transportation activities and increased some of our costs.
Other Costs, Interest, and Income Taxes
General and administrative expenses . General and administrative expenses consisted of the following:
Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||
2011 | 2010 | 2011 | 2010 | |||||||||||||
(in thousands) | (in thousands) | |||||||||||||||
General and administrative expenses not separately identified below |
$ | 5,165 | $ | 5,175 | $ | 10,306 | $ | 10,037 | ||||||||
Bonus plan expense |
1,513 | 1,306 | 2,963 | 2,306 | ||||||||||||
Equity-based compensation plan expense |
236 | 19 | 644 | 666 | ||||||||||||
Third party costs related to business development activities and growth projects |
1,466 | | 2,521 | | ||||||||||||
Expenses related to change in owner of our general partner |
| | | 1,762 | ||||||||||||
Non-cash compensation expense (credit) related to management team |
| 301 | | (1,676 | ) | |||||||||||
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Total general and administrative expenses |
$ | 8,380 | $ | 6,801 | $ | 16,434 | $ | 13,095 | ||||||||
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Routine general and administrative expenses were relatively consistent between the three and six month periods. Our bonus plan expenses increased $0.2 million and $0.7 million for the three and six months ended June 30, 2011, respectively, related to a higher level of bonus accrual as a result of improvements in our operating results. An increase in activities evaluating potential business and growth opportunities resulted in an increase of approximately $1.5 million and $2.5 million, for the three and six month periods, respectively, for costs paid to third parties for their assistance in these activities.
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Depreciation and amortization expense . Depreciation and amortization expense increased $0.6 million and $1.1 million between the three and six month periods, respectively 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 June 30, | Six Months Ended June 30, | |||||||||||||||
2011 | 2010 | 2011 | 2010 | |||||||||||||
(in thousands) | (in thousands) | |||||||||||||||
Genesis Facility and Notes: |
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Interest expense, credit facility, including commitment fees |
$ | 3,383 | $ | 2,065 | $ | 6,509 | $ | 3,989 | ||||||||
Interest expense, senior unsecured notes |
4,976 | | 9,898 | | ||||||||||||
Amortization of credit facility and notes issuance fees |
655 | 165 | 1,310 | 328 | ||||||||||||
Write-off of facility fees |
| 402 | | 402 | ||||||||||||
DG Marine Facility: |
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Interest expense and commitment fees |
| 1,143 | | 2,274 | ||||||||||||
Interest income |
(3 | ) | (15 | ) | (7 | ) | (29 | ) | ||||||||
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Net interest expense |
$ | 9,011 | $ | 3,760 | $ | 17,710 | $ | 6,964 | ||||||||
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Interest expense on our credit facility increased as our average debt balance increased $52.5 million between the quarterly periods and $50.4 million between the six-month periods. The average interest rate for borrowed funds increased approximately 1% over the same periods, from 2.2% to 3.2%. The increase in the outstanding balance under our credit facility is attributable primarily to acquisitions in the second half of 2010. Additionally, when we amended and extended our credit facility in June 2010, our average interest rate increased to reflect market conditions.
We also incurred interest expense, including amortization of notes issuance fees, of $5.2 million and $10.3 million during the quarter and first six months of 2011, respectively 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 first half of 2010 was also affected by interest on the DG Marine credit facility. 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 and foreign income taxes.
Liquidity and Capital Resources
General
As of June 30, 2011, we believe our balance sheet and liquidity position remained strong. We had $113.1 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.
In the third quarter of 2011, we expect to complete the previously-announced acquisition of the black oil barge transportation fleet of Florida Marine Transporters, Inc. and its affiliates for $141 million. That fleet is
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primarily comprised of 30 barges and 14 push boats which transport heavy refined petroleum products, principally serving refineries and storage terminals along the Gulf Coast, Intracoastal Canal and western river systems of the United States, including the Red, Ouachita and Mississippi Rivers.
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
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.
In July 2011, we issued 7,350,000 Class A common units at $26.30, providing total net proceeds, after deducting underwriting discounts and commissions and estimated offering expenses, of approximately $184.9 million. We will use $141 million of the proceeds from this offering to fund the purchase price and related transaction costs for our acquisition of the black oil barge transportation business of Florida Marine Transporters, Inc. and its affiliates. The remaining net proceeds of the offering were used for other purposes, including the repayment of borrowings outstanding under our credit facility.
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 June 30, 2011 includes total long-term debt of $656 million, consisting of $406 million outstanding under our credit facility and $250 million of senior unsecured notes due in 2018. Included in the $406 million outstanding under our credit facility is $70.4 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 provided by our operating activities for the six months ended June 30, 2011 were approximately $9.4 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 June 30, 2011, the cost of the inventory on our balance sheet increased by $33.4 million from December 31, 2010. Sales of inventory in late June that were collected in July 2011, combined with higher market prices, increased net accounts receivable at June 30, 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 half of 2011 and 2010 is as follows:
Six Months Ended
June 30, |
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2011 | 2010 | |||||||
(in thousands) | ||||||||
Capital expenditures for property, plant and equipment: |
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Maintenance capital expenditures: |
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Pipeline transportation assets |
$ | 226 | $ | 134 | ||||
Supply and logistics assets |
552 | 574 | ||||||
Refinery services assets |
367 | 815 | ||||||
Other assets |
244 | 20 | ||||||
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|
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Total maintenance capital expenditures |
1,389 | 1,543 | ||||||
Growth capital expenditures: |
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Pipeline transportation assets |
1,456 | 123 | ||||||
Supply and logistics assets |
1,575 | 433 | ||||||
Refinery services assets |
102 | | ||||||
Information technology systems upgrade project |
3,135 | 4,492 | ||||||
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|
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Total growth capital expenditures |
6,268 | 5,048 | ||||||
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|
|||||
Total capital expenditures |
7,657 | 6,591 | ||||||
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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.
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 are constructing a truck station, tankage and possible pipeline interconnections at West Columbia,
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Texas, to be able to provide incremental transportation service for the Eagle Ford Shale 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, which is in the very early stages of a CO 2 tertiary recovery program.
We also entered into an agreement to install a new sour gas processing facility at Holly Refining and Marketings 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 Hollys complex and result in additional capacity of 24,000 tons 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.
As discussed above, in the third quarter of 2011, we expect to complete the acquisition of the black oil fleet of Florida Marine consisting of 30 barges (7 of which will be sub-leased under similar terms of an existing FMT lease) and 14 pushboats for $141 million.
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 August 12, 2011, we will pay a distribution of $0.4150 per common unit with respect to the second quarter of 2011 to common unitholders of record on August 5, 2011. This is the twenty-fourth 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 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 June 30, 2011 is as follows:
Three Months Ended
June 30, |
||||||||
2011 | 2010 | |||||||
(in thousands) | ||||||||
Net cash flows (used in ) provided by operating activities (GAAP measure) |
$ | 11,527 | $ | (2,577 | ) | |||
Adjustments to reconcile operating cash flows to Available Cash before Reserves: |
||||||||
Maintenance capital expenditures |
(610 | ) | (918 | ) | ||||
Proceeds from sales of certain assets |
1,164 | 857 | ||||||
Amortization and write-off of credit facility issuance fees |
(655 | ) | (814 | ) | ||||
Effects of available cash generated by equity method investees not included in cash flows from operating activities |
3,813 | 132 | ||||||
Earnings of DG Marine in excess of distributable cash |
| (1,481 | ) | |||||
Expenses related to acquiring or constructing assets that provide new sources of cash flow |
1,466 | 81 | ||||||
Other items affecting available cash |
(1,074 | ) | 503 | |||||
Net effect of changes in operating accounts not included in calculation of Available Cash |
16,313 | 30,292 | ||||||
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|
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Available Cash before Reserves |
$ | 31,944 | $ | 26,075 | ||||
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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
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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, NaHS and caustic soda and CO 2 , all of which may be affected by economic activity, capital expenditures by energy producers, weather, alternative energy sources, international events, conservation and technological advances; |
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throughput levels and rates; |
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changes in, or challenges to, our tariff rates; |
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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; |
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service interruptions in our liquids transportation systems, natural gas transportation systems or natural gas gathering and processing operations; |
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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; |
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risks inherent in marine transportation and vessel operation, including accidents and discharge of pollutants; |
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changes in laws and regulations to which we are subject, including tax withholding issues, safety, environmental and employment laws and regulations; |
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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; |
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planned capital expenditures and availability of capital resources to fund capital expenditures; |
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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; |
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loss of key personnel; |
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an increase in the competition that our operations encounter; |
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cost and availability of insurance; |
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hazards and operating risks that may not be covered fully by insurance; |
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our financial and commodity hedging arrangements; |
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capital and credit markets conditions, inflation and interest rates; |
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natural disasters, accidents or terrorism; |
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changes in the financial condition of customers; |
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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 |
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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 Commissions 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.
During the first and second quarters of 2011, we substantially completed a staged implementation of a Enterprise Resource Planning 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 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
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.
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.
None.
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(a) | Exhibits. |
2.1 | Purchase and Sale Agreement (the Purchase Agreement), dated June [24], 2011, by and among by and among Florida Marine Transporters, Inc., FMT Heavy Oil Transportation, LLC, FMT Industries, L.L.C., JAR Assets Inc., Pasentine Family Enterprises, LLC, PBC Management, Inc. and GEL Marine, LLC (incorporated by reference to Exhibit 2.1 to Form 8-K dated June 30, 2011, file No. 001-12295) | |||
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 | * | Amendment to the Certificate of Limited Partnership of Genesis | ||
3.3 | 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 | 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) | |||
3.5 | 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) | |||
3.6 | 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) | |||
10.1 | * | Genesis Energy, LLC 2010 Long-Term Incentive Plan Form of Executive Phantom Unit with DERs Award - Officers | ||
31.1 | * | Certification by Chief Executive Officer Pursuant to Rule 13a-14(a) of the Securities Exchange Act of 1934 | ||
31.2 | * | Certification by Chief Financial Officer Pursuant to Rule 13a-14(a) of the Securities Exchange Act of 1934 | ||
32 | * | Certification by Chief Executive Officer and Chief Financial Officer Pursuant to Rule 13a-14(b) of the Securities Exchange Act of 1934 | ||
101.INS | * | XBRL Instance Document | ||
101.SCH | * | XBRL Schema Document | ||
101.CAL | * | XBRL Calculation Linkbase Document | ||
101.LAB | * | XBRL Label Linkbase Document | ||
101.PRE | * | XBRL Presentation Linkbase Document | ||
101.DEF | * | XBRL Definition Linkbase Document |
* | Filed herewith |
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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: August 8, 2011 | By: |
/s/ R OBERT V. D EERE |
||
Robert V. Deere Chief Financial Officer |
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Exhibit 3.2
STATE OF DELAWARE
AMENDMENT TO THE CERTIFICATE OF
LIMITED PARTNERSHIP
The undersigned, desiring to amend the Certificate of Limited Partnership pursuant to the provisions of Section 17-202 of the Revised Uniform Limited Partnership Act of the State of Delaware, does hereby certify as follows:
FIRST: The name of the Limited Partnership is Genesis Energy, L.P.
SECOND: Article 3 of the Certificate of Limited Partnership shall be amended as follows:
The name and address of the sole general partner is Genesis Energy, LLC, a Delaware limited liability company, 919 Milam, Suite 2100, Houston, TX 77002
IN WITNESS WHEREOF, the undersigned executed this Amendment to the Certificate of Limited Partnership on this 24th day of June, A.D. 2009.
By: |
/s/ Karen Pape |
|
General Partner(s) |
||
Name: |
Karen N. Pape, SVP and Controller Genesis Energy, LLC |
Exhibit 10.1
Genesis Energy, LLC
2010 Long-Term Incentive Plan
Phantom Units with DERs Award
GRANT made as of between Genesis Energy, LLC, a Delaware limited liability company (the Company), and (Employee).
To carry out the purposes of the Genesis Energy, LLC 2010 Long-Term Incentive Plan (the 2010 Plan), by affording Participant the opportunity to receive cash payments based on the Fair Market Value of the Common Units (Units) of Genesis Energy, L.P. (the Partnership), the Company grants you Phantom Units with DERs as follows:
1. | Grant of Phantom Units with Distribution Equivalent Rights. |
(a) | General. The Company hereby grants to Employee 6,447 Phantom Units pursuant to the 2010 Plan. Each Phantom Unit represents the right to receive the Fair Market Value of the underlying common unit in the Partnership upon vesting. In addition each Phantom Unit includes a tandem right to receive Distribution Equivalent Rights (DERs). A DER is a contingent right to receive an amount in cash equal to the distribution made by the Partnership with respect to a Partnership common unit during the period each Phantom Unit is outstanding. If the Partnership makes cash distributions to its partners, a corresponding amount per Phantom Unit will be credited to your DER account. Schedule A, attached hereto, governs the vesting of your Phantom Units and tandem DERs and the timing of payments attributable to such interests. Your right to the payments described in Schedule A is contingent upon your continued employment through the vesting dates specified therein. This grant is subject to the terms and conditions of the 2010 Plan, which is incorporated herein by reference as a part of this Agreement. A copy of the 2010 Plan is attached hereto. In the event of any conflict between the terms of this Agreement and the 2010 Plan, the 2010 Plan shall control. Capitalized terms used in this Agreement but not defined herein shall have the meanings ascribed to such terms in the 2010 Plan, unless the context requires otherwise. |
(b) | Vesting. Except as otherwise provided in Paragraph 2 hereof, all Phantom Units and DERs granted hereunder shall vest and become payable in accordance with Schedule A hereto. |
2. | Events Occurring Prior to Vesting. |
(a) | Death or Disability. If, prior to vesting, Employee ceases to be an employee of the Company and its Affiliates or a member of the Compan y acting in an employee role as a result of death or disability (within the Companys policy or determination thereof), all unvested Phantom Units and DERs granted hereunder then held by Employee will automatically become fully vested upon such termination. |
(b) | Other Termination. If Employee terminates from the Company and its Affiliates or ceases to be a member acting in an employee role for any reason other than death or disability as provided in (a) above, all unvested Phantom Units and DERs granted hereunder then held by Employee shall be automatically forfeited upon such termination, unless the Committee, in its discretion, waives, in whole or in part, such forfeiture. |
1
(c) | Change in Control. Notwithstanding any other provision hereof, immediately prior to the occurrence of a Change in Control, all Phantom Units and DERs granted hereunder then held by Employee shall become fully vested. |
3. | Payment. Schedule A describes the timing of payment attributable to Phantom Units and tandem DERs. Except as specifically provided for in Schedule A, such amounts will be payable as soon as administratively practicable and not later than 30 days after the vesting of a Phantom Unit and/or its tandem DER. At the end of the Restricted Period, Employee shall receive from the Company, in cancellation of such Phantom Unit and DER, a cash payment equal to the sum of (i) the Fair Market Value, as defined in the 2010 Plan, of each Phantom Unit on the vesting date and (ii) the remaining amount of cash then credited to the DER Account with respect to each Phantom Unit. |
4. | Limitations Upon Transfer. All rights under this Grant shall belong to Employee and may not be transferred, assigned, pledged, or hypothecated in any way (whether by operation of law or otherwise), other than by will or the laws of descent and distribution or pursuant to a qualified domestic relations order (as defined by the Internal Revenue Code of 1986, as amended), and shall not be subject to execution, attachment, or similar process. Upon any attempt to transfer, assign, pledge, hypothecate, or otherwise dispose of such rights contrary to the provision in this Grant, or the 2010 Plan, or upon the levy of any attachment or similar process upon such rights, such rights shall immediately become null and void. |
5. | Withholding of Tax. To the extent that the grant, vesting or payment of a vested Phantom Unit or DER results in the receipt of compensation by Employee with respect to which the Company or Affiliate has a withholding obligation, the Company or Affiliate shall withhold such amount from any payment otherwise due under this Grant. |
6. | Binding Effect. This Grant shall be binding upon and inure to the benefit of any successor or successors of the Company or upon any person lawfully claiming under Employee. |
7. | Modification. The Company has the right to amend this agreement at any time, provided however, that any amendment of the 2010 Plan or this award agreement that would otherwise constitute an impairment of the Employees rights under this award agreement, will not be effective unless the Company requests the Employees consent and the Employee consents in writing. For the avoidance of doubt, the cancellation of a vested award where the Employee receives a payment equal in value to the Fair Market Value of the vested Phantom Units and the vested DER account balance will not be an impairment of the Employees rights that requires the Employees consent. |
8. | Governing Law. This Agreement shall be governed by, and construed in accordance with, the laws of the State of Delaware, without regard to conflicts of laws principles thereof. |
GENESIS ENERGY, LLC | ||
By: |
|
|
Name: | ||
Title: |
2
SCHEDULE A
Units Granted |
Vesting Date |
|
Performance Vested Units:
100% of Grant or Units |
, subject to performance levels achieved below:
Award will vest as follows: (a) if the quarterly distribution on the common units is less than $ per unit for the quarter of (which would be paid in the quarter of ), all of the phantom units granted will be forfeited; (b) if the quarterly distribution on the common units for the quarter of is $ per unit, % of the phantom units granted will vest and the remainder will be forfeited; (c) if the distribution on the common units for the quarter of is $ per unit, % of the phantom units granted will vest; and (d) if the distribution on the common units for the quarter of is $ per unit or greater, % of the phantom units granted will vest. Should the quarterly distribution on the common units for the quarter of be between the range of $ per unit and $ per unit, the phantom units will vest between % and % of the number granted on a pro rata basis. |
|
Performance Vested Units DERS | Paid quarterly on the number of units corresponding to the number of initial units granted, subject to your continued employment through the payment date. If your employment terminates for any reason prior to the payment date, no DER payment will be made and your DERs will be forfeited. |
3
Exhibit 31.1
CERTIFICATION
I, Grant E. Sims, certify that:
1. | I have reviewed this quarterly report on Form 10-Q of Genesis Energy, L.P.; |
2. | Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; |
3. | Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; |
4. | The registrants other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and we have: |
a) | designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; |
b) | designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; |
c) | evaluated the effectiveness of the registrants disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation, and |
d) | disclosed in this report any change in the registrants internal control over financial reporting that occurred during the registrants most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrants internal control over financial reporting; and |
5. | The registrants other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrants auditors and the audit committee of registrants board of directors: |
a) | all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrants ability to record, process, summarize and report financial information; and |
b) | any fraud, whether or not material, that involves management or other employees who have a significant role in the registrants internal control over financial reporting. |
Date: August 8, 2011
/s/ Grant E. Sims |
Grant E. Sims |
Chief Executive Officer |
Exhibit 31.2
CERTIFICATION
I, Robert V. Deere, certify that:
1. | I have reviewed this quarterly report on Form 10-Q of Genesis Energy, L.P.; |
2. | Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; |
3. | Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; |
4. | The registrants other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and we have: |
a) | designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; |
b) | designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; |
c) | evaluated the effectiveness of the registrants disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation, and |
d) | disclosed in this report any change in the registrants internal control over financial reporting that occurred during the registrants most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrants internal control over financial reporting; and |
5. | The registrants other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrants auditors and the audit committee of registrants board of directors: |
a) | all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrants ability to record, process, summarize and report financial information; and |
b) | any fraud, whether or not material, that involves management or other employees who have a significant role in the registrants internal control over financial reporting. |
Date: August 8, 2011
/s/ Robert V. Deere |
Robert V. Deere |
Chief Financial Officer |
Exhibit 32
CERTIFICATION BY CHIEF EXECUTIVE OFFICER
PURSUANT TO 18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
In connection with the Quarterly Report on Form 10-Q of Genesis Energy, L.P. (the Partnership) for the period ended June 30, 2011 (the Report) filed with the Securities and Exchange Commission on the date hereof, the undersigned, Grant E. Sims, Chief Executive Officer and Robert V. Deere, Chief Financial Officer of Genesis Energy, LLC, the general partner of the Partnership, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:
(1) | the Partnerships Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934 as amended; and |
(2) | the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Partnership. |
August 8, 2011 |
/s/ Grant E. Sims |
|
Grant E. Sims | ||
Chief Executive Officer, | ||
Genesis Energy, LLC | ||
/s/ Robert V. Deere |
||
Robert V. Deere | ||
Chief Financial Officer, | ||
Genesis Energy, LLC |