Edgar Filing: GENESIS ENERGY LP

Form 10-Q for the quarterly period ended September 30, 2007

Index to Financial Statements

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

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

For the quarterly period ended September 30, 2007

¨	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 jurisdictions of incorporation or organization)		(I.R.S. Employer Identification No.)

500 Dallas, Suite 2500, Houston, TX		77002
(Address of principal executive offices)		(Zip code)

Registrant’s telephone number, including area code:		(713) 860-2500

Securities registered pursuant to Section 12(g) of the Act:

NONE

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act.


Large accelerated filer ¨		Accelerated filer x		Non-accelerated filer ¨

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 number of outstanding shares of each of the issuer’s classes of common stock, as of the latest practicable date. Common Units outstanding as of November 6, 2007: 28,318,532

Index to Financial Statements

GENESIS ENERGY, L.P.

Form 10-Q

INDEX


		Page
PART I. FINANCIAL INFORMATION

Item 1.	Financial Statements

	Unaudited Consolidated Balance Sheets - September 30, 2007 and December 31, 2006	3

	Unaudited Consolidated Statements of Operations for the Three and Nine Months Ended September 30, 2007 and 2006	4

	Unaudited Consolidated Statement of Partners’ Capital for the Nine Months Ended September 30, 2007	5

	Unaudited Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2007 and 2006	6

	Notes to Unaudited Consolidated Financial Statements	7

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	28

Item 3.	Quantitative and Qualitative Disclosures about Market Risk	47

Item 4.	Controls and Procedures	48

PART II. OTHER INFORMATION

Item 1.	Legal Proceedings	49

Item 1A.	Risk Factors	49

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	64

Item 3.	Defaults upon Senior Securities	64

Item 4.	Submission of Matters to a Vote of Security Holders	64

Item 5.	Other Information	64

Item 6.	Exhibits	64

SIGNATURES		65

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Index to Financial Statements

GENESIS ENERGY, L.P.

UNAUDITED CONSOLIDATED BALANCE SHEETS

(In thousands)


	September 30, 2007			December 31, 2006
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	7,767		$	2,318
Accounts receivable:
Trade		152,303			88,006
Related Party		2,319			1,100
Inventories		12,034			5,172
Net investment in direct financing leases, net of unearned income - current portion - related party		598			568
Other		3,572			2,828

Total current assets		178,593			99,992

FIXED ASSETS, at cost		160,859			70,382
Less: Accumulated depreciation		(43,996	)		(39,066	)

Net fixed assets		116,863			31,316

NET INVESTMENT IN DIRECT FINANCING LEASES, net of unearned income—related party		4,921			5,373
CO₂ ASSETS, net of amortization		30,101			33,404
JOINT VENTURES AND OTHER INVESTMENTS		18,087			18,226
INTANGIBLE ASSETS, net of amortization		221,138			—
GOODWILL		318,915			—
OTHER ASSETS, net of amortization		6,022			2,776


TOTAL ASSETS	$	894,640		$	191,087


LIABILITIES AND PARTNERS’ CAPITAL
CURRENT LIABILITIES:
Accounts payable:
Trade	$	128,992		$	85,063
Related party		2,622			1,629
Accrued liabilities		16,084			9,220

Total current liabilities		147,698			95,912

LONG-TERM DEBT		285,000			8,000
DEFERRED TAX LIABILITIES		23,305			—
OTHER LONG-TERM LIABILITIES		1,292			991
MINORITY INTERESTS		552			522
COMMITMENTS AND CONTINGENCIES (Note 15)

PARTNERS’ CAPITAL:
Common unitholders, 13,784 and 28,319 units issued and outstanding, respectively		428,993			83,884
General partner		7,800			1,778

Total partners’ capital		436,793			85,662

TOTAL LIABILITIES AND PARTNERS’ CAPITAL	$	894,640		$	191,087

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

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Index to Financial Statements

GENESIS ENERGY, L.P.

UNAUDITED CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except per unit amounts)


	Three Months Ended September 30,						Nine Months Ended September 30,
	2007			2006			2007			2006
REVENUES:
Supply and logistics:
Product sales revenues - unrelated parties (including revenues from buy/sell arrangements of $69,772 in the first quarter of 2006)	$	311,226		$	217,755		$	672,520		$	690,334
Service revenues - unrelated parties		6,018			192			7,860			507
Service revenues - related parties		409			194			1,287			573
Refinery services:
Product revenues		24,789			—			24,789			—
Service revenues		560			—			560			—
Pipeline transportation, including natural gas sales:
Transportation services - unrelated parties		4,596			4,485			12,519			13,033
Transporation services - related parties		1,499			1,268			4,225			3,665
Natural gas sales revenues		800			1,395			3,274			6,841
CO₂ marketing revenues:
Unrelated parties		3,610			3,560			9,772			10,186
Related parties		763			702			2,044			1,357

Total revenues		354,270			229,551			738,850			726,496
COSTS AND EXPENSES:
Supply and logistics costs:
Product costs - unrelated parties (including costs from buy/sell arrangements of $68,899 in the first quarter of 2006)		304,089			212,725			656,317			673,374
Product costs - related parties		40			12			69			1,496
Operating costs		8,564			3,405			17,295			10,470
Refinery services operating costs		16,804			—			16,804			—
Pipeline transportation costs:
Pipeline operating costs		2,315			2,349			7,996			7,095
Natural gas purchases		817			1,341			3,164			6,582
CO₂ marketing costs:
Transportation costs - related party		1,462			1,324			3,796			3,498
Other costs		40			50			131			156
General and administrative		4,724			4,539			13,652			10,448
Depreciation and amortization		8,372			2,107			12,346			6,000
Net (gain) loss on disposal of surplus assets		—			11			(24	)		(38	)

Total costs and expenses		347,227			227,863			731,546			719,081

OPERATING INCOME		7,043			1,688			7,304			7,415
OTHER INCOME (EXPENSE):
Equity in earnings of joint ventures		361			267			915			919
Interest income		141			49			219			157
Interest expense		(4,842	)		(309	)		(5,467	)		(802	)

Income before income taxes and cumulative effect adjustment		2,703			1,695			2,971			7,689
Income tax (expense) benefit		(1,004	)		—			(1,059	)		11

Income before cumulative effect adjustment		1,699			1,695			1,912			7,700
Cumulative effect adjustment of adoption of new accounting principle		—			—			—			30

NET INCOME	$	1,699		$	1,695		$	1,912		$	7,730

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Index to Financial Statements

GENESIS ENERGY, L.P.

UNAUDITED CONSOLIDATED STATEMENTS OF OPERATIONS - CONTINUED

(In thousands, except per unit amounts)


	Three Months Ended September 30,				Nine Months Ended September 30,
	2007		2006		2007		2006
NET INCOME PER COMMON UNIT - BASIC AND DILUTED:
Income before cumulative effect adjustment	$	0.07	$	0.12	$	0.11	$	0.55
Cumulative effect adjustment		—		—		—		—

NET INCOME	$	0.07	$	0.12	$	0.11	$	0.55

Weighted average number of common units outstanding		24,527		13,784		17,405		13,784

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

GENESIS ENERGY, L.P.

UNAUDITED CONSOLIDATED STATEMENT OF PARTNERS’ CAPITAL

(In thousands)


	Partners’ Capital
	Number of Common Units	Common Unitholders			General Partner			Total
Partners’ capital, January 1, 2007	13,784	$	83,884		$	1,778		$	85,662
Net income	—		1,875			37			1,912
Cash distributions	—		(9,097	)		(186	)		(9,283	)
Issuance of units	14,535		352,331			6,171			358,502

Partners’ capital, September 30, 2007	28,319	$	428,993		$	7,800		$	436,793

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

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Index to Financial Statements

GENESIS ENERGY, L.P.

UNAUDITED CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)


	Nine Months Ended September 30,
	2007			2006
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	1,912		$	7,730
Adjustments to reconcile net income to net cash provided by operating activities -
Depreciation and amortization		12,346			6,000
Amortization of credit facility issuance costs		509			279
Amortization of unearned income on direct financing leases		(468	)		(495	)
Payments received under direct financing leases		890			889
Equity in earnings of investments in joint ventures		(915	)		(919	)
Distributions from joint ventures - return on investment		1,276			1,151
Gain on disposal of assets		(24	)		(38	)
Cumulative effect adjustment		—			(30	)
Non-cash effect of stock appreciation rights plan		1,696			915
Other non-cash items		667			26
Changes in components of operating assets and liabilities -
Accounts receivable		(9,749	)		(9,068	)
Inventories		3,810			(3,937	)
Other current assets		(515	)		474
Accounts payable		10,819			4,250
Accrued liabilities		3,399			(505	)

Net cash provided by operating activities		25,653			6,722

CASH FLOWS FROM INVESTING ACTIVITIES:
Payments to acquire fixed assets		(3,292	)		(830	)
Distributions from joint ventures - return of investment		389			352
Investment in joint ventures and other investments		(552	)		(5,749	)
Proceeds from disposal of assets		195			67
Acquisition of Davison assets, net of cash acquired		(301,360	)		—
Acquisition of Port Hudson assets		(8,103	)		—
Other, net		(1,300	)		(54	)

Net cash used in investing activities		(314,023	)		(6,214	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Bank borrowings		355,800			6,000
Bank repayments		(78,800	)		—
Credit facility issuance fees		(2,297	)
Issuance of common units for cash		22,361			—
General partner contribution		6,171			—
Minority interest contributions, net of distributions		30			—
Other, net		(163	)		372
Distributions to common unitholders		(9,097	)		(7,442	)
Distributions to general partner and minority interest owner		(186	)		(153	)

Net cash provided by (used in) financing activities		293,819			(1,223	)

Net increase (decrease) in cash and cash equivalents		5,449			(715	)
Cash and cash equivalents at beginning of period		2,318			3,099

Cash and cash equivalents at end of period	$	7,767		$	2,384

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

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Index to Financial Statements

GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

1. Organization and Basis of Presentation

Organization

We are a growth-oriented limited partnership focused on the midstream segment of the oil and gas industry in Gulf Coast area of the United States. We conduct our operations through our operating subsidiaries and joint ventures. We manage our businesses through four divisions:

•

Pipeline transportation of crude oil, and, to a lesser degree, natural gas and carbon dioxide (or CO₂);

•

Refinery services involving processing of high sulfur (or “sour”) gas streams for refineries to remove the sulfur, and sale of the related by-product, sodium hydrosulfide (or NaHS, commonly pronounced nash);

•

Industrial gas activities, including wholesale marketing of CO₂ and processing of syngas through a joint venture; and

•

Supply and logistics services, which includes terminaling, blending, storing, marketing and transporting by trucks of crude oil and petroleum products as well as dry goods.

Our 2% general partner interest is held by Genesis Energy, Inc., a Delaware corporation and an indirect, wholly-owned subsidiary of Denbury Resources Inc. Denbury and its subsidiaries are hereafter referred to as Denbury. Our general partner also owns 7.4% of our outstanding common units and all of our incentive distribution rights. See Note 9.

Our general partner manages our operations and activities and employs our officers, who devote 100% of their efforts to our management.

On July 25, 2007, we acquired certain energy-related businesses of the Davison family of Ruston, Louisiana. For additional information regarding this event, see Note 3.

Basis of Consolidation and Presentation

The accompanying consolidated financial statements and related notes present our consolidated financial position as of September 30, 2007 and December 31, 2006 and our results of operations for the three and nine months ended September 30, 2007 and 2006, our cash flows for the nine months ended September 30, 2007 and 2006 and changes in partners’ capital for the nine months ended September 30, 2007. All intercompany transactions have been eliminated. The accompanying consolidated financial statements include Genesis Energy, L.P., its operating subsidiary and its subsidiaries. Our general partner owns a 0.01% general partner interest in Genesis Crude Oil, L.P., which is reflected in our financial statements as a minority interest.

In 2005, we acquired a 50% interest in T&P Syngas Supply Company. In 2006, we acquired a 50% interest in Sandhill Group, LLC. These investments are accounted for by the equity method, as we exercise significant influence over their operating and financial policies. See Note 7.

In general, we conduct substantially all of our operations through pass-through entities. Accordingly, no provision for federal income taxes related to those operations is included in the accompanying consolidated financial statements; as such income will be taxable directly to the partners holding partnership interests. We do, however, conduct certain of our operations through wholly-owned corporations that will pay us dividends based upon their cash flows after the payment of federal and state income taxes on their operations. See Note 17.

Accounting measurements at interim dates inherently involve greater reliance on estimates than at year end and the results of operations for the interim periods shown in this report are not necessarily indicative of results to be expected for the fiscal year. The consolidated financial statements included herein have been prepared by us without audit pursuant to the rules and regulations of the Securities and Exchange Commission. 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

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Index to Financial Statements

GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

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, 2006.

Except per Unit amounts, or as noted within the context of each footnote disclosure, the dollar amounts presented in the tabular data within these footnote disclosures are stated in thousands of dollars.

2. Recent Accounting Pronouncements

SFAS 157

In September 2006, the FASB issued Statement of Financial Accounting Standards, or SFAS, No. 157, “Fair Value Measurements”, or SFAS 157. SFAS 157 defines fair value, establishes a framework for measuring fair value in accordance with accounting principles generally accepted in the United States, and expands disclosures about fair value measurements. SFAS 157 is effective for fiscal years beginning after November 15, 2007, with earlier adoption encouraged. Any amounts recognized upon adoption as a cumulative effect adjustment will be recorded to the opening balance of retained earnings in the year of adoption. SFAS 157 may impact our balance sheet and statement of operations in many areas including the fair value measurement and allocation of the purchase price in business combinations and the fair value measurements for derivative instruments, impairment of assets, and asset retirement obligations. We have not yet determined the impact of adopting SFAS 157, if any, on our consolidated financial statements.

SFAS 159

In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities”, or SFAS 159. SFAS 159 permits entities to choose to measure many financial assets and financial liabilities at fair value. Unrealized gains and losses on items for which the fair value option has been elected are reported in earnings. SFAS 159 is effective for fiscal years beginning after November 15, 2007. We have not yet determined the impact of adopting SFAS 159, if any, on our consolidated financial statements.

EITF 07-4

In May 2007, the Emerging Issues Task Force (or EITF) of the FASB issued EITF 07-4, “Application of the Two-Class Method under FASB Statement No. 128, Earnings per Share, to Master Limited Partnerships.” This EITF considers the question of whether the incentive distribution rights (“IDRs”) of a master limited partnership represent a participating security and should be considered in the calculation of earnings per unit. Under the “two class” method of computing earnings per unit, earnings are allocated to participating securities as if all of the earnings for the period had been distributed. The EITF also presents alternative methods for inclusion of IDRs in the computation of earnings per unit, depending on whether cash distributions exceed earnings for the period. The EITF has issued a draft abstract on this topic and will address comments it receives before issuing a final consensus. Once a final consensus is issued it is expected to be effective for fiscal years beginning after December 15, 2007, and interim periods within those fiscal years. We will assess the impact of EITF 07-4 once a final consensus is issued; however we would expect it to have an impact on our presentation of earnings per unit in the future. For additional information on our incentive distribution rights, see Note 9.

EITF 04-13

We enter into buy/sell arrangements that were accounted for on a gross basis as revenues and costs of products prior to April 1, 2006. These transactions are contractual arrangements that establish the terms of the purchase of a particular grade of crude oil at a specified location and the sale of a particular grade of crude oil at a different location at the same or at another specified date. These arrangements are detailed either jointly, in a single contract, or separately, in individual contracts that are entered into concurrently or in contemplation of one another with a single counterparty. Both transactions require physical delivery of the crude oil and the risk and reward of ownership are evidenced by title transfer, assumption of environmental risk, transportation scheduling, credit risk and counterparty nonperformance risk. In accordance with the provision of Emerging Issues Task Force Issue No. 04-13, “Accounting for Purchases and Sales of Inventory with the Same Counterparty,” we have started reflecting

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Index to Financial Statements

GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

these amounts of revenues and purchases as a net amount in our consolidated statements of operations beginning in the second quarter of 2006. Had this provision been in effect in the first quarter of 2006, our reported supply and logistics product sales revenues from unrelated parties for the nine months ended September 30, 2006 would have been reduced by $70 million to $621 million. Our reported supply and logistics product costs from unrelated parties for the nine months ended September 30, 2006, would have been reduced by $69 million to $604 million. This change had no effect on operating income, net income or cash flows.

3. Acquisitions

Davison Businesses Acquisition

On July 25, 2007, we acquired five energy-related businesses from several entities owned and controlled by the Davison family of Ruston, Louisiana (the “Davison Acquisition”). The businesses include the operations that comprise our refinery services division, and other operations included in our supply and logistics division, which transport, store, procure and market petroleum products and other bulk commodities. The assets acquired in this transaction provide us with opportunities to expand our services to energy companies in the areas in which we operate.

For financial reporting purposes, the consideration for this acquisition consisted of $623 million of value, net of cash acquired and subject to adjustment for purchase price adjustments. The consideration is comprised of $293 million in cash, (which is net of $21.7 million of cash acquired), and 13,459,209 common units of Genesis valued at $330 million. In accordance with EITF, No. 99-12, “Determination of the Measurement Date for the Market Price of Acquirer Securities Issued in a Purchase Business Combination,” the fair value of Genesis common units issued was determined using an average price of $24.52, which was the average closing price of Genesis common units for the two days before and after the date on which the terms of the acquisition were agreed to and announced. The estimated direct transaction costs totaled $8.8 million and consist primarily of legal and accounting fees and other external costs related directly to the acquisition.

The Davison family is our largest unitholder, with approximately 48% of our outstanding common units. It has designated two of the family members to the board of directors of our general partner, and as long as it maintains a specified minimum percentage of our common units, it will have the continuing right to designate up to two directors. The Davison family has agreed to restrictions that limit its ability to sell specified percentages of its common units through July 26, 2010. Pursuant to an agreement between us and the Davison unitholders, the Davison unitholders have registration rights with respect to their common units. These rights include the right to require us to file a Form S-3 shelf registration statement, if we are eligible.

The purchase price has been allocated to the assets acquired and liabilities assumed based on estimated preliminary fair values. Such preliminary values have been developed by management with the assistance of a third-party valuation firm and are subject to change pending a final valuation report and final determination of working capital acquired and other purchase price adjustments. The preliminary valuation may change due to additional information we have requested on certain tangible assets and the effects on goodwill on any changes to those values, and the effects of the final purchase price adjustments. We expect to finalize the purchase price allocation for this transaction during the fourth quarter of 2007. We do not expect any material adjustments to these preliminary purchase price allocations as a result of the final valuation

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Index to Financial Statements

GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

The preliminary allocation of the purchase price is summarized as follows:


Cash and cash equivalents	$	21,686
Accounts receivable		55,767
Inventories		10,824
Other current assets		962
Other assets		293
Property and equipment		82,607
Goodwill		314,946
Amortizable intangible assets:
Customer relationships		114,646
Supplier agreements		35,937
Licensing agreements		39,504
Trade name		21,115
Covenants not-to-compete		699
Favorable lease agreement		13,260
Accounts payable and accrued expenses		(35,925	)
Deferred tax liabilties assumed		(23,305	)

Total allocation	$	653,016

See additional information on intangible assets and goodwill in Note 6

The following table presents selected unaudited pro forma financial information incorporating the historical operating results of the Davison businesses. The effective closing date of our purchase of the Davison businesses was July 25, 2007. As a result, our Unaudited Consolidated Statements of Operations for the three and nine months ended September 30, 2007, includes two months of results of operations of these acquired businesses. The pro forma financial information has been prepared as if the acquisition had been completed on the first day of each period presented rather than the actual closing date. The pro forma financial information has been prepared based upon assumptions deemed appropriate by us and may not be indicative of actual results.

Because certain of our acquired operations do not generate “qualified income” within the meaning of the Internal Revenue Code, we conduct some of those activities through wholly-owned corporations that pay entity-level taxes. Accordingly, the pro forma income statements include an estimate of the federal and state income tax effects we estimate we are likely to have to be paid by our corporate subsidiaries (which will dividend their after-tax earnings to the partnership entities) in order to insure that at least 90% of our consolidated gross income is “qualified income.” We currently estimate this tax cost to be approximately $0.4 million per month. Although there can be no assurances, we believe as the amount of “qualified income” we generate increases and as certain other activities are restructured, this estimated tax cost will likely decrease in future periods.

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Index to Financial Statements

GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS


	Three Months Ended September 30,					Nine Months Ended September 30,
	2007		2006			2007			2006
Pro Forma Earnings Data:
Revenue	$	406,339	$	369,752		$	1,113,927		$	1,147,100
Costs and expenses	$	398,140	$	363,881		$	1,094,309		$	1,127,134
Operating income	$	8,200	$	5,872		$	19,619		$	19,966
Income (loss) before extraordinary items	$	889	$	(354	)	$	(1,234	)	$	1,584
Net income (loss)	$	889	$	(354	)	$	(1,234	)	$	1,584
Basic and diluted earnings per unit:
As reported units outstanding		24,527		13,784			17,405			13,784
Pro forma units outstanding		28,319		28,319			28,319			28,319
As reported net income per unit	$	0.07	$	0.12		$	0.12		$	0.55
Pro forma net income (loss) per unit	$	0.03	$	(0.01	)	$	(0.04	)	$	0.06

Port Hudson Assets Acquisition

Effective July 1, 2007, we paid $8.1 million for BP Pipelines (North America) Inc.’s Port Hudson crude oil truck terminal, marine terminal, and marine dock on the Mississippi River, which includes 215,000 barrels of tankage, a pipeline and other related assets in East Baton Rouge Parish, Louisiana. The acquisition was funded with borrowings under our credit facility.

The purchase price has been allocated to the assets acquired based on estimated fair values. The allocation of the purchase price is summarized as follows:


Property and equipment	$	4,134
Goodwill		3,969

Total	$	8,103

See additional information on goodwill in Note 6.

4. Inventories

Inventories are valued at the lower of cost or market. The costs of inventories did not exceed market values at September 30, 2007 and December 31, 2006. The major components of inventories were as follows:


	September 30, 2007		December 31, 2006
Crude oil	$	1,903	$	5,081
Petroleum products		6,418		—
Caustic soda		922		—
NaHS		2,645		—
Other		146		91

Total	$	12,034	$	5,172

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Index to Financial Statements

GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

5. Fixed Assets

Fixed assets consisted of the following:


	September 30, 2007			December 31, 2006
Land, buildings and improvements	$	11,962		$	808
Pipelines and related assets		64,672			58,428
Machinery and equipment		36,398			—
Transportation equipment		34,150			1,257
Office equipment, furniture and fixtures		3,122			2,616
Construction in progress		2,810			78
Other		7,745			7,195

Subtotal		160,859			70,382
Accumulated depreciation		(43,996	)		(39,066	)

Total	$	116,863		$	31,316

6. Intangible Assets and Goodwill

Intangible Assets

As explained in Note 3, in connection with the Davison acquisition, we allocated a portion of the purchase price to intangible assets based on their fair values. The purchase price allocation is preliminary and subject to change based upon final determination of working capital acquired and other factors. The following table reflects the components of intangible assets being amortized at September 30, 2007:


	Amortization Period in Years	September 30, 2007
	Amortization Period in Years	Gross Carrying Amount		Accumulated Amortization
Refinery services customer relationships	8	$	80,118	$	1,669
Supply and logistics customer relationships	11		34,528		523
Refinery services supplier relationships	6		35,937		998
Refinery services licensing agreements	12		39,504		549
Supply and logistics trade name	20		21,115		176
Supply and logistics favorable lease	28		13,260		79
Other	3-5		709		39

Total		$	225,171	$	4,033

Statement of Financial Accounting Standards No. 142, “Goodwill and Other Intangible Assets,” (SFAS 142) requires that intangible assets with finite useful lives be amortized over their respective estimated useful lives. If an intangible asset has a finite useful life, but the precise length of that life is not known, that intangible asset shall be amortized over the best estimate of its useful life. At a minimum, we will assess the useful lives and residual values of all intangible assets on an annual basis to determine if adjustments are required. We are recording amortization of our intangible assets on a straight-line basis. Amortization expense on intangible assets was $4.0 million for the three and nine months ended September 30, 2007.

Amortization expense for intangible assets is estimated to be $10.1 million for 2007. Estimated amortization expense for each of the five subsequent fiscal years is expected to be approximately $24 million.

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Index to Financial Statements

GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

Goodwill

Goodwill represents the excess of purchase price over fair value of net assets acquired. We account for goodwill under SFAS 142, which prohibits amortization of goodwill, but instead requires testing for impairment at least annually. We will test goodwill for impairment annually at October 1, and more frequently if indicators of impairment are present. In the event that we determine that the goodwill has become impaired, we will incur a charge for the amount of impairment during the period in which the determination is made.

As explained in Note 3, in connection with the Davison and Port Hudson acquisitions, the residual of the purchase price over the fair values of the net tangible and identifiable intangible assets acquired was allocated to goodwill. The carrying amount of goodwill by business segment at September 30, 2007 was $228 million to refinery services and $91 million to supply and logistics.

7. Joint Ventures and Other Investments

T&P Syngas Supply Company

We own a 50% interest in T&P Syngas Supply Company (“T&P Syngas”), a Delaware general partnership. Praxair Hydrogen Supply Inc. (“Praxair”) owns the remaining 50% partnership interest in T&P Syngas. T&P Syngas is a partnership that owns a syngas manufacturing facility located in Texas City, Texas. That facility processes natural gas to produce syngas (a combination of carbon monoxide and hydrogen) and high pressure steam. Praxair provides the raw materials to be processed and receives the syngas and steam produced by the facility under a long-term processing agreement. T&P Syngas receives a processing fee for its services. Praxair operates the facility.

We are accounting for our 50% ownership in T&P Syngas under the equity method of accounting as both partners have substantive participating rights. We reflect in our consolidated statements of operations our equity in T&P Syngas’ net income, net of the amortization of the excess of our investment over our share of partners’ capital of T&P Syngas. We paid $4.0 million more for our interest in T&P Syngas than our share of partners’ capital on the balance sheet of T&P Syngas at the date of the acquisition. This excess amount of the purchase price over the equity in T&P Syngas is being amortized using the straight-line method over the remaining useful life of the assets of T&P Syngas of eleven years. Our consolidated statements of operations for the three and nine months ended September 30, 2007 included $0.4 million and $1.2 million, respectively, as our share of the operating earnings of T&P Syngas, reduced by amortization of the excess purchase price of $0.1 million and $0.3 million, respectively. Our consolidated statements of operations for the three and nine months ended September 30, 2006 included $0.4 million and $1.2 million, respectively, as our share of the operating earnings of T&P Syngas, reduced by amortization of the excess purchase price of $0.1 million and $0.3 million, respectively. We received distributions from T&P Syngas of $1.6 million during the nine months ended September 30, 2007.

The tables below reflect summarized financial information for T&P Syngas:


	Nine Months Ended September 30, 2007			Nine Months Ended September 30, 2006
Revenues	$	3,705		$	3,702
Operating expenses and depreciation		(1,333	)		(1,345	)
Other income		15			13

Net income	$	2,387		$	2,370

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Index to Financial Statements

GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS


	September 30, 2007		December 31, 2006
Current assets	$	1,417	$	1,355
Non-current assets		15,058		15,387

Total assets	$	16,475	$	16,742

Current liabilities	$	594	$	156
Non-current liabilties		176		165
Partners’ capital		15,705		16,421

Total liabilites and partners’ capital	$	16,475	$	16,742

Sandhill Group, LLC

On April 1, 2006, we acquired a 50% interest in Sandhill Group, LLC (“Sandhill”). At September 30, 2007, Reliant Processing Ltd. held the other 50% interest in Sandhill. Sandhill owns a CO₂ processing facility located in Brandon, Mississippi. Sandhill is engaged in the production and distribution of liquid carbon dioxide for use in the food, beverage, chemical and oil industries. The facility acquires CO₂ from us under a long-term supply contract that we acquired in 2005 from Denbury.

We are accounting for our 50% ownership in Sandhill under the equity method of accounting as both partners have substantive participating rights. We reflect in our consolidated statements of operations our equity in Sandhill’s net income, net of the amortization of the excess of our investment over our share of partners’ capital of Sandhill that is not considered goodwill.

Our consolidated statements of operations for the three and nine months ended September 30, 2007 included $135,000 and $193,000, respectively, as our share of the operating earnings of Sandhill, reduced by amortization of the excess purchase price of $69,000 and $208,000, respectively. Our consolidated statements of operations for the three and nine months ended September 30, 2006 included $46,000 and $136,000, as our share of the operating earnings of Sandhill, reduced by amortization of the excess purchase price of $65,000 and $138,000, respectively. We received distributions from Sandhill of $101,000 during the nine months ended September 30, 2007.

Other Projects

In 2006, we invested $1.0 million in the Faustina Project, a petroleum coke to ammonia project that is in the development stage. We have subsequently invested an additional $0.6 million. All of our investment may later be redeemed, with a return, or converted to equity after the project has obtained construction financing. We have committed to invest an additional $0.6 million in the Faustina Project during the remainder of 2007. The funds we have invested will be used for project development activities, which include the negotiation of off-take agreements for the products and by-products of the plant to be constructed, securing permits and securing financing for the construction phase of the plant.

No events or changes in circumstances have occurred that indicate a significant adverse effect on the fair values of our investments at September 30, 2007, therefore our investments are included in our consolidated balance sheet at their costs adjusted for our share of their earnings and distributions.

8. Debt

Our credit facility, with a maximum facility amount of $500 million, of which $100 million could be used for letters of credit, is with a group of banks led by Fortis Capital Corp. and Deutsche Bank Securities Inc. The maximum facility amount represents the amount the banks have committed to fund pursuant to the terms of the credit agreement. The borrowing base is recalculated quarterly and at the time of material acquisitions. The borrowing base represents the amount that can be borrowed or utilized for letters of credit from a credit standpoint based on our EBITDA (earnings before interest, taxes, depreciation and amortization), computed in accordance with the provisions of our credit facility.

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Index to Financial Statements

GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

The borrowing base may be increased to the extent of pro forma additional EBITDA attributable to acquisitions or internal growth projects with approval of the lenders. Our borrowing base as of September 30, 2007 was $380 million.

At September 30, 2007, we had $285 million borrowed under our credit facility and we had $4.7 million in letters of credit outstanding. Due to the revolving nature of loans under our credit facility, additional borrowings and periodic repayments and re-borrowings may be made until the maturity date of November 15, 2011. The total amount available for borrowings at September 30, 2007 was $90.4 million under our credit facility.

The key terms for rates under our credit facility are as follows:

•

The interest rate on borrowings may be based on the prime rate or the LIBOR rate, at our option. The interest rate on prime rate loans can range from the prime rate plus 0.50% to the prime rate plus 1.875%. The interest rate for LIBOR-based loans can range from the LIBOR rate plus 1.50% to the LIBOR rate plus 2.875%. The rate is based on our leverage ratio as computed under the credit facility. Our leverage ratio is recalculated quarterly and in connection with each material acquisition. At September 30, 2007, our borrowing rates were the prime rate plus 1.25% or the LIBOR rate plus 2.25%.

•

Letter of credit fees will range from 1.50% to 2.875% based on our leverage ratio as computed under the credit facility. The rate can fluctuate quarterly. At September 30, 2007, our letter of credit rate was 2.25%.

•

We pay a commitment fee on the unused portion of the $500 million maximum facility amount. The commitment fee will range from 0.30% to 0.50% based on our leverage ratio as computed under the credit facility. The rate can fluctuate quarterly. At September 30, 2007, the commitment fee rate was 0.50%.

Collateral under the credit facility consists of substantially all our assets. While our general partner is jointly and severally liable for all of our obligations unless and except to the extent those obligations provide that they are non-recourse to our general partner, our credit facility expressly provides that it is non-recourse to our general partner (except to the extent of its pledge of its general partner interest in certain of our subsidiaries) and Denbury and its other subsidiaries.

Our credit facility contains customary covenants (affirmative, negative and financial) that limit the manner in which we may conduct our business. Our credit facility contains three primary financial covenants - a debt service coverage ratio, leverage ratio and funded indebtedness to capitalization ratio – that require us to achieve specific minimum financial metrics. In general, our debt service coverage ratio calculation compares EBITDA (as adjusted in accordance with the credit facility) to interest expense. Our leverage ratio calculation compares our consolidated funded debt (as calculated in accordance with our credit facility) to EBITDA (as adjusted). Our funded indebtedness ratio compares outstanding debt to the sum of our consolidated total funded debt plus our consolidated net worth.


Financial Covenant	Requirement	Required Ratio through June 30, 2008	Actual Ratio as of September 30, 2007
Debt Service Coverage Ratio	Minimum	2.75 to 1.0	4.1 to 1.0
Leverage Ratio	Maximum	6.5 to 1.0	3.9 to 1.0
Funded Indebtedness Ratio	Maximum	0.80 to 1.0	0.40 to 1.0

Our credit facility includes provisions for the temporary adjustment of the required ratios following material acquisitions and with lender approval. The ratios in the table above are the required ratios for the period following a material acquisition. If we meet these financial metrics and are not otherwise in default under our credit facility, we

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Index to Financial Statements

GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

may make quarterly distributions; however the amount of such distributions may not exceed the sum of the distributable cash generated by us for the eight most recent quarters, less the sum of the distributions made with respect to those quarters. At September 30, 2007, the excess of distributable cash over distributions under this provision of the credit facility was $19.7 million. For a summary of our non-financial covenants, please refer to our Annual Report on Form 10-K for the year ended December 31, 2006.

The carrying value of our debt under our credit facility approximates fair value primarily because interest rates fluctuate with prevailing market rates, and the applicable margin on outstanding borrowings reflect what we believe is market.

9. Partners’ Capital and Distributions

Partners’ Capital

Partner’s capital at September 30, 2007 consists of 28,318,532 common units, including 2,094,323 units owned by our general partner, representing a 98% aggregate ownership interest in the Partnership and its subsidiaries (after giving affect to the general partner interest), and a 2% general partner interest. Included in these amounts are the common units issued on July 25, 2007 in connection with the Davison acquisition. We issued 13,459,209 common units to the entities owned and controlled by the Davison family. The issuance of the units was recorded in the financial statements at a value of $330 million. In accordance with EITF No. 99-12, “Determination of the Measurement Date for the Market Price of Acquirer Securities Issued in a Purchase Business Combination,” the fair value of our common units issued was determined using an average price of $24.52, which was the average closing price of our common units for the two days before and after the terms of the acquisition were agreed to and announced. Additionally, our general partner exercised its right to maintain its proportionate share of our outstanding common units by purchasing 1,074,882 common units from us for $22.4 million cash, or $20.8036 per common unit. As required under our partnership agreement, our general partner also contributed approximately $6.2 million to maintain its capital account balance.

Our general partner owns all of our general partner interest, all of the 0.01% general partner interest in our operating partnership (which is reflected as a minority interest in the consolidated balance sheet at September 30, 2007) and operates our business.

Our partnership agreement authorizes our general partner to cause us to issue additional limited partner interests and other equity securities, the proceeds from which could be used to provide additional funds for acquisitions or other needs.

Distributions

Generally, we will distribute 100% of our available cash (as defined by our partnership agreement) within 45 days after the end of each quarter to unitholders of record and to our general partner. Available cash consists generally of all of our cash receipts less cash disbursements adjusted for net changes to reserves. As discussed in Note 8, our credit facility limits the amount of distributions we may pay in any quarter.

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Index to Financial Statements

GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

We paid or will pay the following distributions to the holders of our common units in 2006 and 2007:


Distribution For	Date Paid		Per Unit Amount		Limited Partner Interests Amount			General Partner Interest Amount		General Partner Incentive Distribution Amount		Total Amount
Fourth quarter 2005	February 2006		$	0.17	$	2,343		$	48	$	—	$	2,391
First quarter 2006	May 2006		$	0.18	$	2,481		$	51	$	—	$	2,532
Second quarter 2006	August 2006		$	0.19	$	2,619		$	53	$	—	$	2,672
Third quarter 2006	November 2006		$	0.20	$	2,757		$	56	$	—	$	2,813
Fourth quarter 2006	February 2007		$	0.21	$	2,895		$	59	$	—	$	2,954
First quarter 2007	May 2007		$	0.22	$	3,032		$	62	$	—	$	3,094
Second quarter 2007	August 2007		$	0.23	$	3,170	⁽¹⁾	$	65	$	—	$	3,235	⁽¹⁾
Third quarter 2007	November 2007	⁽²⁾	$	0.27	$	7,646	⁽³⁾	$	156	$	90	$	7,892	⁽³⁾

(1)

The distribution paid on August 14, 2007 to holders of our common units is net of the amounts payable with respect to the common units issued in connection with the Davison transaction. The Davison unitholders and our general partner waived their rights to receive such distributions, instead receiving purchase price adjustments with us.

(2)	This distribution will be paid on November 14, 2007 to the general partner and unitholders of record as of November 6, 2007.

(3)	The increased amount of distributions that will be paid is primarily a result of the additional units issued in connection with the Davison acquisition as discussed above.

Our general partner is entitled to receive incentive distributions if the amount we distribute with respect to any quarter exceeds levels specified in our partnership agreement. Pursuant to our partnership agreement, our general partner receives incremental incentive cash distributions when unitholders’ cash distributions exceed certain target thresholds, in addition to its 2% general partner interest. The allocations of distributions between our common unitholders and our general partner, including the incentive distribution rights is as follows:


	Unitholders		General Partner
Quarterly Cash Distribution per Common Unit:
Up to and including $0.25 per Unit	98.00	%	2.00	%
First Target - $0.251 per Unit up to and including $0.28 per Unit	84.74	%	15.26	%
Second Target - $0.281 per Unit up to and including $0.33 per Unit	74.26	%	25.74	%
Over Second Target - Cash distributions greater than $.033 per Unit	49.02	%	50.98	%

Net Income Per Common Unit

Subject to the applicability of Emerging Issues Task Force Issue No. 03-06 (“EITF 03-06”), Participating Securities and the Two-Class Method under Financial Accounting Standards Board Statement No. 128,” as discussed below, our net income is first allocated to the general partner based on the amount of incentive distributions. The remainder is then allocated 98% to the limited partners and 2% to the general partner. Basic and diluted net income per limited partner unit is determined by dividing net income attributable to limited partners by the weighted average number of outstanding limited partner units during the period.

EITF 03-06 addresses the computation of earnings per share by entities that have issued securities other than common stock that contractually entitle the holder to participate in dividends and earnings of the entity when, and if, it declares dividends on its common stock (or partnership distributions to unitholders). EITF 03-06 applies to any accounting period where our aggregate net income exceeds our aggregate distribution. In such periods, we are required to present earnings per unit as if all of the earnings for the periods were distributed, regardless of the pro forma nature of this allocation and whether those earnings would actually be distributed from an economic or practical perspective. EITF 03-06 does not impact our overall net income or other financial results; however, for periods in which aggregate net income exceeds our aggregate distributions for such period, it will have the impact of

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Index to Financial Statements

GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

reducing the earnings per limited partner units. This result occurs as a larger portion of our aggregate earnings is allocated (as if distributed) to our general partner, even though we make cash distributions on the basis of cash available for distributions, not earnings, in any given period. Our aggregate net earnings have not exceeded our aggregate distributions, therefore EITF 03-06 has not had an impact on our calculation of earnings per unit.

The following table sets forth the computation of basic net income per common unit.


	Three Months Ended September 30,				Nine Months Ended September 30,
	2007		2006		2007		2006
Numerators for basic and diluted net income per common unit:
Income from continuing operations	$	1,699	$	1,695	$	1,912	$	7,700
Less general partner 2% ownership		34		34		38		54

Income from continuing operations available for common unitholders	$	1,665	$	1,661	$	1,874	$	7,646

Income from cumulative effect adjustment	$	—	$	—	$	—	$	30
Less general partner 2% ownership		—		—		—		1

Income from cumulative effect adjustment available for common unitholders	$	—	$	—	$	—	$	29

Denominator for basic and diluted per common unit - weighted average number of common units outstanding		24,527		13,784		17,405		13,784

Basic and diluted net income per common unit:
Income from continuing operations	$	0.07	$	0.12	$	0.11	$	0.55
Income from cumulative effect adjustment		—		—		—		—

Net income	$	0.07	$	0.12	$	0.11	$	0.55

10. Business Segment Information

Our operations consist of four operating segments: (1) Pipeline Transportation - interstate and intrastate crude oil, and to a lesser extent, natural gas and CO₂ pipeline transportation; (2) Refinery Services - processing high sulfur (or “sour”) gas streams as part of refining operations to remove the sulfur and sale of the related by-product; (3) Industrial Gases - the sale of CO₂ acquired under volumetric production payments to industrial customers and our investment in a syngas processing facility, and (4) Supply and Logistics - terminaling, blending, storing, marketing, gathering and transporting by truck crude oil and petroleum products and other dry goods. Our Supply and Logistics segment was previously known as Crude Oil Gathering and Marketing. With the Davison acquisition, we expanded our operations into petroleum products and other transportation services, and combined these operations due to their similarities and our approach to managing these operations. The tables below reflect our segment information as though the current segment designations had existed in all periods presented.

We evaluate segment performance based on segment margin. We calculate segment margin as revenues less costs of sales and operating expenses, and we include income from investments in joint ventures. We do not deduct depreciation and amortization. All of our revenues are derived from, and all of our assets are located in the United States. The pipeline transportation segment information includes the revenue, segment margin and assets of our direct financing leases.

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Index to Financial Statements

GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS


	Pipeline Transportation		Refinery Services		Industrial Gases^(a)		Supply & Logistics		Total
Three Months Ended September 30, 2007
Segment margin excluding depreciation and amortization^(b)	$	3,763	$	8,545	$	3,232	$	4,960	$	20,500
Capital expenditures	$	1,812	$	553	$	552	$	441	$	3,358
Maintenance capital expenditures	$	1,624	$	269	$	—	$	255	$	2,148

Revenues:
External customers	$	5,949	$	25,349	$	4,373	$	317,653	$	353,324
Intersegment^(d)		946		—		—		—		946

Total revenues of reportable segments	$	6,895	$	25,349	$	4,373	$	317,653	$	354,270

Three Months Ended September 30, 2006
Segment margin excluding depreciation and amortization^(b)	$	3,458	$	—	$	3,155	$	1,999	$	8,612
Capital expenditures	$	216	$	—	$	194	$	34	$	444
Maintenance capital expenditures	$	146	$	—	$	—	$	34	$	180

Revenues:
External customers	$	6,232	$	—	$	4,262	$	218,141	$	228,635
Intersegment^(d)		916		—		—		—		916

Total revenues of reportable segments	$	7,148	$	—	$	4,262	$	218,141	$	229,551

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Index to Financial Statements

GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS


	Pipeline Transportation		Refinery Services		Industrial Gases^(a)		Supply & Logistics		Total
Nine Months Ended September 30, 2007
Segment margin excluding depreciation and amortization^(b)	$	8,858	$	8,545	$	8,804	$	7,986	$	34,193
Capital expenditures	$	2,365	$	553	$	552	$	582	$	4,052
Maintenance capital expenditures	$	2,177	$	269	$	—	$	396	$	2,842
Net fixed and other non-current assets^(c)	$	31,558	$	409,510	$	48,188	$	226,791	$	716,047

Revenues:
External customers	$	16,956	$	25,349	$	11,816	$	681,667	$	735,788
Intersegment^(d)		3,062		—		—		—		3,062

Total revenues of reportable segments	$	20,018	$	25,349	$	11,816	$	681,667	$	738,850

Nine Months Ended September 30, 2006
Segment margin excluding depreciation and amortization^(b)	$	9,862	$	—	$	8,808	$	6,074	$	24,744
Capital expenditures	$	639	$	—	$	5,744	$	190	$	6,573
Maintenance capital expenditures	$	370	$	—	$	—	$	190	$	560
Net fixed and other long-term assets^(c)	$	32,516	$	—	$	52,704	$	5,469	$	90,689

Revenues:
External customers	$	20,158	$	—	$	11,543	$	691,414	$	723,115
Intersegment^(d)		3,381		—		—		—		3,381

Total revenues of reportable segments	$	23,539	$	—	$	11,543	$	691,414	$	726,496

a)	Industrial gases includes our CO₂ marketing operations and our equity income from our investments in T&P Syngas Supply Company and Sandhill Group, LLC.

b)	Segment margin was calculated as revenues less cost of sales and operations expense. It includes our share of the operating income of equity joint ventures. A reconciliation of segment margin to income before income taxes and cumulative effect adjustment for the periods presented is as follows:

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Index to Financial Statements

GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS


	Three Months Ended September 30,						Nine Months Ended September 30,
	2007			2006			2007			2006
Segment margin excluding depreciation and amortization	$	20,500		$	8,612		$	34,193		$	24,744
General and administrative expenses		(4,724	)		(4,539	)		(13,652	)		(10,448	)
Depreciation and amortization expense		(8,372	)		(2,107	)		(12,346	)		(6,000	)
Net gain (loss) on disposal of surplus assets		—			(11	)		24			38
Interest expense, net		(4,701	)		(260	)		(5,248	)		(645	)

Income before income taxes and cumulative effect adjustment	$	2,703		$	1,695		$	2,971		$	7,689

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

d)	Intersegment sales, in the opinion of management, were conducted on an arm’s length basis.

11. Transactions with Related Parties

Sales, purchases and other transactions with affiliated companies, in the opinion of management, are conducted under terms no more or less favorable than then-existing market conditions. The transactions with related parties were as follows:


	Nine Months Ended September 30,
	2007		2006
Truck transportation services provided to Denbury	$	1,287	$	573
Pipeline transportation services provided to Denbury	$	3,878	$	3,110
Payments received under direct financing leases from Denbury	$	890	$	889
Pipeline transportation income portion of direct financing lease fees with Denbury	$	479	$	495
Pipeline monitoring services provided to Denbury	$	90	$	45
Directors’ fees paid to Denbury	$	112	$	90
CO₂ transportation services provided by Denbury	$	3,796	$	3,498
Crude oil purchases from Denbury	$	69	$	1,496
Operations, general and administrative services provided by our general partner	$	15,966	$	13,330
Distributions to our general partner on its limited partner units and general partner interest	$	1,111	$	703
Sales of CO₂ to Sandhill	$	2,040	$	1,352
Purchases of parts for vehicle repair and maintenance from Davison Motor Company	$	24	$	—

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Index to Financial Statements

GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

Transportation Services

We provide truck transportation services to Denbury to move their crude oil from the wellhead to our Mississippi pipeline. Denbury pays us a fee for this trucking service that varies with the distance the crude oil is trucked. These fees are reflected in the statement of operations as supply and logistics service revenues.

Denbury is the only shipper on our Mississippi pipeline other than us. We also earned fees from Denbury under the direct financing lease arrangements for the Olive and Brookhaven crude oil pipelines and the Brookhaven CO₂ pipeline and recorded pipeline transportation income from these arrangements.

We also provide pipeline monitoring services to Denbury. This revenue is included in pipeline revenues in the statement of operations.

Directors’ Fees

We paid Denbury for the services of each of four of Denbury’s officers who serve as directors of our general partner, at an annual rate that is $10,000 per director less than the rate at which our independent directors and Davison directors were paid. Additionally we pay Denbury fees for the attendance of the directors at board and committee meetings at the same rates at which our independent directors and Davison directors were paid.

CO₂ Operations and Transportation

Denbury charges us a transportation fee of $0.16 per Mcf (adjusted for inflation) to deliver CO₂ for us to our customers. In the first nine months of 2007, the inflation-adjusted transportation fee averaged $0.183 per Mcf.

Operations, General and Administrative Services

We do not directly employ any persons to manage or operate our business. Those functions are provided by our general partner. We reimburse the general partner for all direct and indirect costs of these services.

Transition Services from Davison

Until the end of 2007, the Davison family is providing certain transition services to us related to the payroll for persons who provide services to us. These persons will become employees of our general partner on January 1, 2008; however, to create the least disruption for employees while we evaluate benefit plan arrangements, the personnel in our Supply and Logistics operations acquired from Davison are paid by entities owned by the Davison family and we reimburse them for all direct costs.

Amounts due to and from Related Parties

At September 30, 2007 and December 31, 2006, we owed Denbury $1.5 million and $0.8 million, respectively, for purchases of crude oil and CO₂ transportation charges. Denbury owed us $0.8 million and $0.6 million for transportation services at September 30, 2007 and December 31, 2006, respectively. We owed our general partner $1.1 million and $0.9 million for administrative services at September 30, 2007 and December 31, 2006, respectively. At both September 30, 2007 and December 31, 2006, Sandhill owed us $0.5 million for purchases of CO₂. At September 30, 2007, the Davison family entities owed us $0.6 million for reimbursement of costs paid by us on their behalf.

Financing

Our general partner is jointly and severally liable for all of our obligations unless and except to the extent those obligations provide that they are non-recourse to our general partner. Our credit facility expressly provides that it is non-recourse to owners of our equity interests, including our general partner (except to the extent of its pledge of its general partner interest in certain of our subsidiaries) and Denbury and its other subsidiaries.

We effectively guarantee our proportionate share (50%) of Sandhill’s outstanding bank debt, which was $3.9 million ($1.95 million net to us) at September 30, 2007.

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Index to Financial Statements

GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

12. Major Customers and Credit Risk

Due to the nature of our operations, a significant percentage of our trade receivables constitute obligations of energy companies. This industry concentration has the potential to impact our overall exposure to credit risk, either positively or negatively, in that our customers could be affected by similar changes in economic, industry or other conditions. However, we believe that the credit risk posed by this industry concentration is offset by the creditworthiness of our customer base. Our portfolio of accounts receivable is comprised in large part of integrated and large independent energy companies with stable payment experience. The credit risk related to contracts which are traded on the NYMEX is limited due to the daily cash settlement procedures and other NYMEX requirements.

We have established various procedures to manage our credit exposure, including initial credit approvals, credit limits, collateral requirements and rights of offset. Letters of credit, prepayments and guarantees are also utilized to limit credit risk to ensure that our established credit criteria are met.

Shell Oil Company, Occidental Energy Marketing, Inc., and Calumet Specialty Products Partners, L.P. accounted for 22%, 14% and 10% of total revenues in the first nine months of 2007, respectively. Occidental Energy Marketing, Inc., Shell Oil Company and Calumet Specialty Products Partners, L.P. accounted for 21%, 18% and 11% of total revenues in the first nine months of 2006, respectively. The majority of the revenues from these three customers in both periods relate to our crude oil supply and logistics operations.

13. Supplemental Cash Flow Information

We received interest payments of $158,000 and $164,000 for the nine months ended September 30, 2007 and 2006, respectively. Payments of interest and commitment fees were $462,000 and $768,000 for the nine months ended September 30, 2007 and 2006, respectively.

At September 30, 2007, we had incurred liabilities for fixed asset additions totaling $0.3 million that had not been paid at the end of the second quarter, and, therefore, are not included in the caption “Additions to property and equipment” on the Consolidated Statements of Cash Flows.

The consideration for a portion of the Davison acquisition was paid with the issuance of Genesis common units. This equity issuance, with a value of $330 million, was a non-cash transaction, and, therefore, is not included in the Consolidated Statements of Cash Flows as a financing activity, and the assets acquired for the equity are not included in the caption “Acquisition of Davison assets, net of cash acquired” in our investing activities. See Note 3 for additional information on this acquisition.

14. Derivatives

Our market risk in the purchase and sale of crude oil and petroleum products contracts is the potential loss that can be caused by a change in the market value of the asset or commitment. In order to hedge our exposure to such market fluctuations, we may enter into various financial contracts, including futures, options and swaps. Historically, any contracts we have used to hedge market risk were less than one year in duration, although we have the flexibility to enter into arrangements with a longer term.

We may utilize crude oil futures contracts and other financial derivatives to reduce our exposure to unfavorable changes in crude oil prices and fuel oil prices. Every derivative instrument (including certain derivative instruments embedded in other contracts) must be recorded in the balance sheet as either an asset or liability measured at its fair value. Changes in the derivative’s fair value must be recognized currently in earnings unless specific hedge accounting criteria are met. Special accounting for qualifying hedges allows a derivative’s gains and losses to offset related results on the hedged item in the income statement. Companies must formally document, designate and assess the effectiveness of transactions that receive hedge accounting.

We mark to fair value our derivative instruments at each period end, with changes in the fair value of derivatives that are not designated as hedges being recorded as unrealized gains or losses. Such unrealized gains or losses will change, based on prevailing market prices, at each balance sheet date prior to the period in which the transaction actually occurs. The effective portion of unrealized gains or losses on derivative transactions qualifying as cash flow hedges are reflected in other comprehensive income. Derivative transactions qualifying as fair value hedges are evaluated for hedge effectiveness and the resulting hedge ineffectiveness is recorded as a gain or loss in the consolidated statements of operations.

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Index to Financial Statements

GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

We review our contracts to determine if the contracts meet the definition of derivatives pursuant to SFAS 133, “Accounting for Derivative Instruments and Hedging Activities.” At September 30, 2007, we had futures contracts that were considered free-standing derivatives that are accounted for at fair value. The fair value of these contracts was determined based on the closing price for such contracts on September 30, 2007. We marked these contracts to fair value at September 30, 2007. During the three and nine months ended September 30, 2007, we recorded losses of $87,000 and $68,000, respectively, related to derivative transactions, which are included in the consolidated statements of operations under the caption “Product costs”.

For a portion of 2007 we had futures contracts that qualified as derivatives and were formally documented and designated as fair value hedges of inventory. During the three and nine months ended September 30, 2007, we recognized gains, due to hedge ineffectiveness, on the fair value hedge of inventory of approximately $337,000 and $119,000, respectively. These gains are included in the caption “Product costs” in the consolidated statements of operations. The time value component of the derivative gain or loss excluded from the assessment of hedge effectiveness was not material. At September 30, 2007, our fair value hedges of inventory were closed.

The consolidated balance sheet at September 30, 2007 includes a decrease in other current assets of $1.3 million as a result of these derivative transactions. The consolidated balance sheet at December 31, 2006 included an increase in other current assets of $165,000 as a result of derivative transactions.

At September 30, 2006, we had futures contracts that were considered free-standing derivatives that are accounted for at fair value. The fair value of these contracts was determined based on the closing price for such contracts on September 30, 2006. We marked these contracts to fair value at September 30, 2006. During the nine months ended September 30, 2006, we recorded gains of $97,000 related to derivative transactions, which is included in the consolidated statements of operations under the caption “Product costs”.

At September 30, 2006, we had futures contracts that qualified as derivatives and were formally documented and designated as fair value hedges of inventory. During the nine months ended September 30, 2006, we recognized losses, due to hedge ineffectiveness, on the fair value hedge of inventory of approximately $53,000. These gains are included in the caption “Product Costs” in the consolidated statements of operations. The time value component of the derivative gain or loss excluded from the assessment of hedge effectiveness was not material.

We determined that the remainder of our derivative contracts qualified for the normal purchase and sale exemption and were designated and documented as such at September 30, 2007 and December 31, 2006.

15. Contingencies

Guarantees

We have guaranteed the payments by our subsidiaries to the banks under the terms of our credit facility related to borrowings and letters of credit. To the extent liabilities exist under the letters of credit, such liabilities are included in the consolidated balance sheet. Borrowings at September 30, 2007 were $285 million and are reflected in the consolidated balance sheet. We have also guaranteed the payments by our operating partnership under the terms of our operating leases of tractors and trailers.

We guaranteed $1.2 million of residual value related to the leases of trailers from a lessor. We believe the likelihood we would be required to perform or otherwise incur any significant losses associated with this guarantee is remote.

We effectively guarantee our proportionate share (50%) of Sandhill’s bank debt, which was $3.9 million ($1.95 million, net to us) at September 30, 2007. Sandhill makes principal payments totaling $0.6 million annually on that debt.

Pennzoil Litigation

We were named a defendant in a complaint filed on January 11, 2001, in the 125^th District Court of Harris County, Texas, Cause No. 2001-01176. Pennzoil-Quaker State Company, or PQS, was seeking from us property

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Index to Financial Statements

GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

damages, loss of use and business interruption suffered as a result of a fire and explosion that occurred at the Pennzoil Quaker State refinery in Shreveport, Louisiana, on January 18, 2000. PQS claimed the fire and explosion were caused, in part, by crude oil we sold to PQS that was contaminated with organic chlorides. In December 2003, our insurance carriers settled this litigation for $12.8 million.

PQS is also a defendant in five consolidated class action/mass tort actions brought by neighbors living in the vicinity of the PQS Shreveport, Louisiana refinery in the First Judicial District Court, Caddo Parish, Louisiana, Cause Nos. 455,647-A, 455,658-B, 455,655-A, 456,574-A, and 458,379-C. PQS has brought third party claims against us for indemnity with respect to the fire and explosion of January 18, 2000. We believe that the demand against us is without merit and intend to vigorously defend ourselves in this matter. We currently believe that this matter will not have a material financial effect on our financial position, results of operations, or cash flows.

Environmental

In 1992, Howell Crude Oil Company (“Howell”) entered into a sublease with Koch Industries, Inc. (“Koch”), covering a one acre tract of land located in Santa Rosa County, Florida to operate a crude oil trucking station, known as Jay Station. The sublease provided that Howell would indemnify Koch for environmental contamination on the property under certain circumstances. Howell operated the Jay Station from 1992 until December of 1996 when this operation was sold to us by Howell. We operated the Jay Station as a crude oil trucking station until 2003. Koch has indicated that it has incurred certain investigative and/or other costs, for which Koch alleges some or all should be reimbursed by us, under the indemnification provisions of the sublease for environmental contamination on the site and surrounding areas. Koch has also alleged that we are responsible for future environmental obligations relating to the Jay Station.

Howell was acquired by Anadarko Petroleum Corporation (“Anadarko”) in 2002. In 2005, we entered into a joint defense and cost allocation agreement with Anadarko. Under the terms of the joint allocation agreement, we agreed to reasonably cooperate with each other to address any liabilities or defense costs with respect to the Jay Station. Additionally under the joint allocation agreement, Anadarko will be responsible for sixty percent of the costs related to any liabilities or defense costs incurred with respect to contamination at the Jay Station.

We were formed in 1996 by the sale and contribution of assets from Howell and Basis Petroleum, Inc. (“Basis”). Anadarko’s liability with respect to the Jay Station is derived largely from contractual obligations entered into upon our formation. We believe that Basis has contractual obligations under the same formation agreements. We intend to seek recovery of Basis’ share of potential liabilities and defense costs with respect to Jay Station.

We have developed a plan of remediation for affected soil and groundwater at Jay Station which has been approved by appropriate state regulatory agencies. We have accrued an estimate of our share of liability for this matter in the amount of $0.5 million. The time period over which our liability would be paid is uncertain and could be several years. This liability may decrease if indemnification and/or cost reimbursement is obtained by us for Basis’ potential liabilities with respect to this matter. At this time, our estimate of potential obligations does not assume any specific amount contributed on behalf of the Basis obligations, although we believe that Basis is responsible for a significant part of these potential obligations.

We are subject to various environmental laws and regulations. Policies and procedures are in place to monitor compliance and to detect and address any releases of crude oil from our pipelines or other facilities, however no assurance can be made that such environmental releases may not substantially affect our business.

Other Matters

Our facilities and operations may experience damage as a result of an accident or natural disaster. These hazards can cause personal injury or loss of life, severe damage to and destruction of property and equipment, pollution or environmental damage and suspension of operations. We maintain insurance that we consider adequate to cover our operations and properties, in amounts we consider reasonable. Our insurance does not cover every potential risk associated with operating our facilities, including the potential loss of significant revenues. The occurrence of a significant event that is not fully-insured could materially and adversely affect our results of operations. We believe we are adequately insured for public liability and property damage to others and that our coverage is similar to other companies with operations similar to ours. No assurance can be made that we will be able to maintain adequate insurance in the future at premium rates that we consider reasonable.

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Index to Financial Statements

GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

As discussed in Note 7, we have committed to invest an additional $0.6 million in a potential petroleum coke to ammonia project.

We are subject to lawsuits in the normal course of business and examination by tax and other regulatory authorities. We do not expect such matters presently pending to have a material adverse effect on our financial position, results of operations or cash flows.

16. Stock Appreciation Rights Plan

At December 31, 2005, we had a recorded liability of $0.8 million for our stock appreciation rights plan, computed under the provisions of FASB Interpretation No. 28, “Accounting for Stock Appreciation Rights and Other Variable Sock Option and Variable Award Plans”. We calculated the effect of adoption of SFAS 123(R), “Share-Based Payments”, at January 1, 2006, and determined that our recorded liability at December 31, 2005 should be reduced by $30,000. This reduction is reflected as income from the cumulative effect of the adoption of a new accounting principle on our statement of operations in 2006. The adjustment of the liability to its fair value of $1.5 million at September 30, 2006, resulted in general and administrative expense of $0.4 million and $0.9 million for the three and nine month periods ended September 30, 2006, respectively. The adjustment of the liability to its fair value at September 30, 2007, resulted in expense for the nine months ended September 30, 2007 of $3.1 million, with $2.0 million, $0.6 million and $0.5 million included in general and administrative expenses, supply and logistics operating costs and pipeline operating costs, respectively. For the three months ended September 30, 2007, we recorded a reduction to our expense of $1.2 million, with $0.8 million, $0.2 million and $0.2 million included in general and administrative expenses, field operating costs and pipeline operating costs, respectively.

The following table reflects rights activity under our plan during the nine months ended September 30, 2007:


Stock Appreciation Rights	Rights		Weighted Average Exercise Price		Weighted Average Contractual Remaining Term (Yrs)	Aggregate Intrinsic Value
Outstanding at January 1, 2007	659,010		$	12.79
Granted during 2007	94,120		$	29.32
Exercised during 2007	(85,331	)	$	9.98
Forfeited or expired during 2007	(61,847	)	$	16.48

Outstanding at September 30, 2007	605,952		$	15.37	8.1	$	5,026

Exercisable at September 30, 2007	178,261		$	11.25	6.9	$	2,979

The weighted-average fair value at September 30, 2007 of rights granted during the first three quarters of 2007 was $5.39 per right. The total intrinsic value of rights exercised during the first nine months of 2007 was $1.5 million, which was paid in cash to the participants.

At September 30, 2007, there was $1.9 million of total unrecognized compensation cost related to rights that we expect will vest under the plan. This amount was calculated as the fair value at September 30, 2007 multiplied by those rights for which compensation cost has not been recognized, adjusted for estimated forfeitures. This unrecognized cost will be recalculated at each balance sheet until the rights are exercised, forfeited or expire. For the awards outstanding at September 30, 2007, the remaining cost will be recognized over a weighted average period of 1.1 years.

17. Income Taxes

We are not a taxable entity for federal income tax purposes. As such, we do not directly pay federal income taxes. Our taxable income or loss is includible in the federal income tax returns of each of our partners.

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Index to Financial Statements

GENESIS ENERGY, L.P.

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

A portion of the operations we acquired in the Davison transactions are owned by wholly-owned corporate subsidiaries that are taxable as corporations. We will pay federal and state income taxes on these operations. The income taxes associated with these operations are accounted for in accordance with SFAS 109 “Accounting for Income Taxes.”

In May 2006, the State of Texas enacted a law which will require us to pay a tax of 0.5% on our “margin,” as defined in the law, beginning in 2008 based on our 2007 results. The “margin” to which the tax rate will be applied generally will be calculated as our revenues (for federal income tax purposes) less the cost of the products sold (for federal income tax purposes), in the State of Texas.

Temporary differences related to our inventory affect the Texas margin tax, so we recorded a deferred tax asset in the amount of $11,000 upon enactment of the law in 2006. We believe that we will be able to utilize this deferred tax asset at September 30, 2007, and therefore have provided no valuation allowance against this deferred tax asset.

For the three and nine months ended September 30, 2007, we have provided current tax expense in the amount of $1.0 million and $1.1 million, respectively, as the estimate of the taxes that will be owed on our income for the period. The current liability we have accrued at September 30, 2007 is $1.1 million.

We have determined that we expect to claim tax benefits on tax returns that are uncertain tax positions with respect to activity during the third quarter. The amount of the tax benefits expected to be claimed with respect to the third quarter is not material. We do not believe the tax benefits we expect to claim will materially affect our effective tax rate in future periods. We do not expect a change to the amount of our unrecognized tax benefits to occur over the next twelve months. We will record interest and penalty associated with the claimed tax benefits as part of our income tax expense.

18. Subsequent Events

Distribution

On October 26, 2007, the Board of Directors of the general partner declared a cash distribution of $0.27 per unit for the quarter ended September 30, 2007. The distribution will be paid November 14, 2007 to our general partner and all common unitholders of record as of the close of business on November 6, 2007.

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Index to Financial Statements

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

Included in Management’s Discussion and Analysis are the following sections:

•

Overview

•

Acquisitions and Related Activities in 2007

•

Description of our Businesses, including who we are, our relationship with Denbury, our objectives and strategies, and our competitive strengths

•

Results of Operations

•

Liquidity and Capital Resources

•

Commitments and Off-Balance Sheet Arrangements

•

Other Matters

•

New Accounting Pronouncements

Overview

The third quarter of 2007 was a significant period for us. We completed a transaction to purchase five energy-related businesses from the Davison family of Ruston, Louisiana and completed an acquisition of a crude oil terminal on the Mississippi River.

In connection with the acquisition from the Davison family, we increased the committed amount of our credit facility to the maximum facility amount of $500 million. We are also negotiating with Denbury for the “drop-down” of certain of their midstream assets to us.

In the discussion below, we will provide information on each of these events, and updated descriptions of our business segments, our relationship with Denbury, and our objectives and strategies and competitive strengths. Additionally we will discuss the results of our operations and other financial data for the three and nine months ended September 30, 2007.

We focus on two measures that we use to manage our business and to review the results of our operations. Those two measures are segment margin and Available Cash before Reserves. Our profitability depends to a significant extent upon our ability to maximize segment margin. Segment margin is calculated as revenues less cost of sales and operating expense, which does not include depreciation and amortization. Segment margin also includes our share of the equity in the operating income of our joint ventures. A reconciliation of segment margin to income from continuing operations is included in our segment disclosures in Note 10 to the consolidated financial statements.

Available Cash before Reserves is a non-GAAP liquidity measure calculated as net income with several adjustments, the most significant of which are the elimination of gains and losses on asset sales (except those from the sale of surplus assets); the addition of non-cash expenses such as depreciation; the replacement with the amount recognized as our equity in the income of joint ventures with the available cash generated from those ventures; and the subtraction of maintenance capital expenditures, which are expenditures to sustain existing cash flows but not to provide new sources of revenues. For additional information on Available Cash before reserves and a reconciliation of this measure to cash flows from operations, see “Liquidity and Capital Resources - Non-GAAP Financial Measure” below.

Increases in cash flow generally result in increases in Available Cash before reserves, which we distribute quarterly to holders of our common units and general partner. During the third quarter of 2007, we generated $7.3 million of Available Cash before reserves, and we will distribute $7.9 million to holders of our common units and general partner for the third quarter. During the third quarter of 2007, cash provided by operating activities was $22.6 million.

In the third quarter of 2007, we reported net income of $1.7 million, or $0.07 per common unit, with $1.2 million of that income attributable to a reduction in the accrual we recorded for our stock appreciation rights plan.

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Index to Financial Statements

The decrease in our common unit market price from June 30, 2007 to September 30, 2007 of $7.03 reduced the accrual for the plan, providing a credit to the expense we recorded under our plan during the three months ended September 30, 2007.

For the nine months ended September 30, 2007, we generated net income of $1.9 million, or $0.11 per common unit. Total expense recorded for our stock appreciation rights plan for the nine month period was $3.1 million.

Additionally, on October 26, 2007, we announced that our distribution to our common unitholders relative to the third quarter of 2007 will be $0.27 per unit (to be paid in November 2007), which is an increase of 17% relative to the distribution for the second quarter of 2007. This distribution amount represents a 35% increase from our distribution of $0.20 per unit for the third quarter of 2006. During the third quarter of 2007 we paid a distribution of $0.23 per unit related to the second quarter of 2007.

Acquisitions and Related Activities in 2007

Davison Businesses Acquisition

On July 25, 2007, we completed the acquisition of certain assets of businesses engaged in five energy- related segments from several entities owned and controlled by the Davison family of Ruston, Louisiana. The Davison family has conducted energy-related transportation businesses in Ruston since 1937. The businesses acquired from the Davison family include a refinery services business, a petroleum products marketing business, a terminaling business, a trucking business, and a fuel procurement business. Additional information on these operations is included in “Description of our Businesses – Who We Are” below.

For financial reporting purposes, the total consideration for the transaction was $623 million, subject to adjustment. A portion of the consideration was paid with 13,459,209 of our common units, contractually valued at $20.8036 per unit. The units issued are reflected in our consolidated balance sheet at a total value of $330 million. In accordance with EITF No. 99-12, “Determination of the Measurement Date for the Market Price of Acquirer Securities Issued in a Purchase Business Combination,” the fair value of Genesis common units issued was determined using an average price of $24.52, which was the average closing price of Genesis common units for the two days before and after the terms of the acquisition were agreed to and announced. The remainder of the base purchase price of $293 million (adjusted for purchase price adjustments), along with estimated working capital of an additional $31.9 million (excluding cash acquired), was paid in cash borrowed under our credit facility.

Additionally, our general partner exercised its right to maintain its proportionate share of our outstanding common units by purchasing 1,074,882 common units from us for $22.4 million cash, or $20.8036 per common unit. As a result of this purchase, our general partner will continue to hold 7.4% of our outstanding common units. As required under our partnership agreement, our general partner also contributed approximately $6.2 million to maintain its capital account balance.

Pursuant to the Unitholder Agreement executed on July 25, 2007, the Davison unitholders have the right to designate up to two directors to the Board of Directors of our general partner, depending on their continued level of ownership in us. Until July 25, 2010, the Davison unitholders have the right to designate two directors to our general partner’s Board of Directors. Thereafter, the Davison unitholders will have the right to designate (i) one director if they beneficially own at least 10% but less than 35% of our outstanding common units, or (ii) two directors if they beneficially own 35% of more of our outstanding common units. If their percentage ownership in our common units drops below 10% after July 25, 2010, the Davison unitholders have no rights to designate directors. On October 31, 2007, the Davison unitholders hold approximately 48% of our outstanding common units.

On July 25, 2007, the Davison unitholders designated James E. Davison and James E. Davison, Jr. as directors to the Board of Directors of our general partner.

In addition, we have agreed to call a special meeting of our unitholders, currently scheduled for December 18, 2007, to propose an amendment to our partnership agreement that would allow any affiliated persons or group (including the Davison unitholders) who hold more than 20% of our outstanding voting units to vote on all matters on which holders of our voting units have the right to vote, other than matters relating to the succession, election, removal, withdrawal, replacement or substitution of our general partner and to clarify and expand the concept of “group” as defined in our partnership agreement. Currently our partnership agreement does not allow any unitholder (including its affiliates) holding more than 20% of our outstanding units to vote on any matters.

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Index to Financial Statements

Our operational results for the three and nine months ended September 30, 2007, include two months of activity from the Davison acquisition. We have included in pro forma information in Note 3 of the Notes to the Consolidated Financial Statements for the three and nine months of 2007 as if this transaction had occurred July 1, 2007 and January 1, 2007, respectively.

Credit Agreement Amendment

As a result of the transaction with the Davison family, we also amended our existing credit facility. The amendment increased the committed amount under our facility from $125 million to $500 million, of which a maximum of $100 million may be used for letters of credit. The committed amount represents the amount the banks have committed to fund pursuant to the terms of the credit agreement.

Port Hudson Assets Acquisition

Effective July 1, 2007, we acquired the Port Hudson Crude Oil truck terminal, marine terminal, and marine dock of BP Pipelines (North America) Inc. for $8.1 million. The assets acquired in this transaction include docking facilities on the Mississippi River, 215,000 barrels of tankage, a pipeline and other related assets in East Baton Rouge Parish, Louisiana. The acquisition was funded with borrowings under our credit facility. We allocated $4.1 million of the purchase price to the tangible assets we acquired and $4.0 million to goodwill. The assets we acquired in this transaction should provide us with the increased ability to gather, blend and store crude oil from south Louisiana for delivery to markets that can be reached by barge from the Mississippi River.

Drop-down Transactions

As Denbury has publicly stated, upon our achievement of certain goals, primarily our acquisition (by construction or purchase) of economic projects that are not related to Denbury’s operations, Denbury will undertake to “drop-down” certain midstream Denbury assets to us in an amount of $1.00 of Denbury assets for every $1.50 of non-Denbury-related acquisitions we complete. These “drop-down” transactions are currently thought most likely to consist of property sales combined with associated transportation or service arrangements, direct financing leases, or a combination of these approaches. As a result of the transaction with the Davisons, we anticipate that during 2007, Denbury will enter into “drop-down” transactions with us involving their existing CO₂ pipelines, with a current estimated value of between $200 million and $250 million. These “drop-down” transactions would be subject to, among other things, negotiation of specific terms, the approval of the board of directors of both entities, and the receipt of fairness opinions by both companies. We would anticipate a similar transaction with Denbury for the new CO₂ pipeline Denbury is constructing from its Jackson Dome to its Tinsley and Delhi Fields, once that pipeline is completed, currently estimated to be in the second half of 2008. If in future periods we are able to consummate with third parties additional acquisitions of sufficient size with acceptable economic returns, and subject to the same types of conditions, Denbury anticipates similar transactions with us for its proposed 280 to 300 mile CO₂ pipeline from South Louisiana to Hastings Field, located near Houston, Texas, probably during 2010. We expect to fund the transactions with Denbury with borrowings under our credit facility as well as other sources of capital such as a public or private offering of debt or equity.

Description of our Businesses, Relationship with Denbury, Our Objectives and Strategies and Our Competitive Strengths

In conjunction with our recent acquisition of the Davison businesses, we have reassessed our operating and reporting structure and expanded our business strategies. Provided below is some updated information related thereto. We have also updated other general information regarding our operations.

Who We Are

We are a growth-oriented limited partnership focused on the midstream segment of the oil and gas industry in the Gulf Coast region of the United States, primarily Texas, Louisiana, Arkansas, Mississippi, Alabama and Florida. We have a diverse portfolio of customers, operations and assets, including refinery-related plants, pipelines, storage tanks and terminals, and trucks and truck terminals. We provide services to refinery owners; oil, natural gas and CO₂ producers; industrial and commercial enterprises that use CO₂ and other industrial gases; and individuals and companies that use our dry-goods trucking services. Substantially all of our revenues are derived from providing services to integrated oil companies, large independent oil and gas or refining companies, and large industrial and commercial enterprises.

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Index to Financial Statements

We manage our businesses through four divisions:

•

Pipeline Transportation: We transport oil and, to a lesser extent, natural gas and CO₂ in the Gulf Coast region of the U.S. through approximately 500 miles of pipeline. We own and operate three crude oil common carrier pipelines, a small CO₂ pipeline and several small natural gas gathering pipelines.

•

Refinery Services: We provide services to 10 refining operations located predominantly in Texas, Louisiana and Arkansas. These refineries are owned and operated by large companies, including ConocoPhillips, Holly Refining and Citgo. Our services primarily involve processing high sulfur (or “sour”) natural gas streams, which are separated from hydrocarbon streams, to remove the sulfur. Our refinery services contracts, which usually have an initial term of two to ten years, have an average remaining term of five years. We provide the caustic soda used in the process and market the by-product of the process, NaHS, or sodium hydrosulfide.

•

Supply and Logistics: We provide terminaling, blending, storing, marketing, gathering and transporting by trucks, and other supply and logistics services to third parties, as well as to support our other businesses. We own approximately 300 trucks, 600 trailers and almost 2.6 million barrels of liquid storage capacity at eleven different locations. Our terminaling, blending, marketing and gathering activities are focused on crude oil and petroleum products, primarily fuel oil.

•

Industrial Gases: We supply CO₂ to industrial customers under long-term back-to-back arrangements. Through our 50% interest in Sandhill Group, LLC, we process raw CO₂ for sale to other customers for uses ranging from completing oil and natural gas producing wells to food processing. Through our 50% interest in T&P Syngas Supply Company, or T&P Syngas, we process syngas (a combination of carbon monoxide and hydrogen), which T&P Syngas sells to Praxair Inc., the other 50% owner.

We conduct our business through subsidiaries and joint ventures. As is customary with master limited partnerships, or MLPs, our general partner is responsible for operating our business, including providing all necessary personnel and other resources.

Our Relationship with Denbury Resources Inc.

We continue to benefit from our strategic affiliation with Denbury Resources Inc. (NYSE:DNR), which indirectly owns 100% of our general partner interest, all of our incentive distribution rights and 7.4% of our outstanding common units. Denbury, which had an equity market capitalization of approximately $6.9 billion as of November 1, 2007, operates primarily in Mississippi, Louisiana and Texas, emphasizing the tertiary recovery of oil using CO₂ flooding. Denbury is the largest producer (based on average barrels produced per day) of oil in Mississippi, and it is one of only a handful of producers in the U.S. that possesses CO₂ tertiary recovery expertise along with large deposits of low-cost CO₂ reserves, approximately 5.5 trillion cubic feet of estimated proved CO₂ reserves as of December 31, 2006. Other than the CO₂ reserves owned by Denbury, there are no known significant natural sources of CO₂ from East Texas to Florida. Denbury is conducting the CO₂ tertiary recovery operations in the Eastern Gulf Coast of the U.S., an area with many mature oil reservoirs that potentially contain substantial volumes of recoverable oil. In addition to the amounts it has already expended on the Free State and North East Jackson Dome, or NEJD, CO₂ pipelines, Denbury has announced that it expects to spend approximately $775 million between December 31, 2007 and the end of 2009 to build CO₂ pipelines to support its tertiary oil recovery expansions.

We believe Denbury’s equity ownership interests in us provide Denbury with strong economic and strategic incentives to furnish business opportunities to us in the form of acquisitions, leases, transportation agreements and other transactions. In fact, Denbury has indicated that it plans to use us as a vehicle to provide its midstream infrastructure needs, particularly with respect to CO₂ pipelines. We believe Denbury is likely to provide us with future growth opportunities due to the following additional factors, among others:

•

Denbury’s stated intent for us to function as a provider of pipelines and gathering systems necessary to support its operations;

•

Denbury’s significant economic and strategic interests in us;

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Index to Financial Statements

•

the close proximity of certain of Denbury’s assets and operations to certain of our assets and operations; and

•

the extent of Denbury’s growth capital requirements.

Denbury has announced its intent to drop down certain midstream assets over time, at its discretion. Denbury intends to consider offering $1.00 of “drop down” transactions to us for each $1.50 of non-Denbury-related capital we economically deploy. For example, because we have consummated the Davison acquisition for approximately $623 million (net of cash acquired at closing and subject to final purchase price adjustments), Denbury is willing to discuss with us drop down transactions of approximately $400 million.

We believe there is a broad array of transactions that we could explore with Denbury which could result in strong growth opportunities for us, including acquiring (through purchase, construction, lease or otherwise) CO_2,oil and/or natural gas gathering and transportation pipelines and related midstream infrastructure; transporting CO₂; transporting, gathering and storing oil and/or natural gas; and enhancing our industrial gases opportunities. In August 2007, both Denbury and we announced our intention to enter into negotiations regarding specific transactions.

Although our relationship with Denbury may provide us with a source of acquisition and other growth opportunities, Denbury is not obligated to enter into any transactions with (or to offer any opportunities to) us or to promote our interest, and none of Denbury or any of its affiliates (including our general partner) has any obligation or commitment to contribute or sell any assets to us or enter into any type of transaction with us, and each of them, other than our general partner, has the right to act in a manner that could be beneficial to its interests and detrimental to ours. Further, Denbury may, at any time, and without notice, alter its business strategy, including determining that it no longer desires to use us as a provider of its midstream infrastructure. Additionally, if Denbury were to make one or more offers to us, we cannot say that we would elect to pursue or consummate any such opportunity. In addition, though our relationship with Denbury is a significant strength, it also is a source of potential conflicts.

Our Objectives and Strategies

Our primary business objectives are to generate stable cash flows to allow us to make quarterly cash distributions to our unitholders and to increase those distributions over time. We plan to achieve those objectives by executing the following strategies:

•

Expanding our asset base through strategic and accretive acquisitions and construction and development projects with third parties and Denbury;

•

Optimizing our CO₂ and other industrial gases expertise and infrastructure;

•

Leveraging our oil handling capabilities with Denbury’s tertiary recovery projects;

•

Attracting new refining customers and expanding the services we provide those customers;

•

Increasing the utilization rates and enhancing the profitability of our existing assets;

•

Increasing stable cash flows generated through fee-based services, longer-term contractual arrangements and managing commodity price risks;

•

Maintaining a balanced and diversified portfolio of midstream energy and industrial gases assets, operations and customers;

•

Creating strategic arrangements and sharing capital costs and risks through joint ventures and strategic alliances; and

•

Maintaining, on average, a conservative capital structure that will allow us to execute our growth strategy while, over the longer term, enhancing our credit ratings.

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Index to Financial Statements

Our Competitive Strengths

We believe we are well positioned to execute our strategies and ultimately achieve our objectives due primarily to the following competitive strengths:

Strategic Relationship with Denbury. We have a strategic relationship with Denbury, the indirect owner of our general partner. Denbury has indicated that it intends to use us as a vehicle to provide its midstream infrastructure needs, particularly with respect to CO₂ pipelines. We believe Denbury has strong economic and strategic incentives to provide business opportunities to us. We also believe that, if we can become an instrumental component of Denbury’s future development projects, we can leverage those operations (and our relationship with Denbury) into oil transportation and storage opportunities with third parties, such as other producers and refinery operators, in the areas into which Denbury expands its operations.

Experienced, Knowledgeable and Motivated Senior Management Team with Proven Track Record. Our senior management team has over 60 years of combined experience in the midstream sector. They have worked together and separately in leadership roles at a number of large, successful public companies, including other publicly-traded partnerships. The incentive compensation arrangements of our senior management team are being structured to help ensure that our senior management team executes our growth strategy in a manner that is accretive on a “distribution per unit” basis.

Unique Platform, Limited Competition and Anticipated Growing Demand in Refinery Services Operations. We provide services to 10 refining operations located predominantly in Texas, Louisiana and Arkansas. Our services primarily involve processing sour natural gas streams, which are separated from hydrocarbon streams, to remove the sulfur. We believe that the U.S. refinery industry’s demand for sulfur extraction services will increase because we believe sour oil will constitute an ever-increasing portion of the total supply of crude oil worldwide. In addition, we have an increasing array of services we can offer to our refinery customers and we believe our proprietary knowledge, scale, logistics capabilities and safety and service record will encourage such customers to continue to outsource their existing refinery services needs to us.

Unique Platform and Limited Competition in Industrial Gases Operations. We have a unique industrial gases platform, which is based on the following factors:

•

our relationship with Denbury and its large CO₂ deposits and extensive CO₂ operations;

•

the anticipated growth in our CO₂ activities from the drop down of CO₂ pipelines from Denbury;

•

our existing industrial gases operations; and

•

our knowledge about CO₂ and certain other industrial gases.

Supply and Logistics Division Supports Full Suite of Services. In addition to the established customers of our supply and logistics division, that division can, from time to time, attract customers to our other divisions and/or create synergies that may not be available to our competitors.

Diversified and Balanced Portfolio of Customers, Operations and Assets. We have a diversified and well-balanced portfolio of customers, operations, and assets throughout the Gulf Coast region of the U.S. Through our diverse assets, we provide stand-alone and integrated gathering, transporting, processing, blending, storing and marketing services, among others, to numerous customer groups. Our operations and assets are characterized by:

•

Strategic Locations. Our crude oil pipelines and related assets are predominately located near areas that are experiencing increasing oil production, in large part because of Denbury’s tertiary recovery operations, and in and around inland refining operations, many of which we believe are contemplating expansion.

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•

Cost-Effective Expansion and Enhancement Opportunities. We own pipelines, terminals and other assets that have available capacity or that have opportunities for expansion of capacity with relatively immaterial expenditures. Our available capacity allows us to increase our revenues with little or no additional cost to us, and our expansion capability allows us to increase our asset base, as needed, in a cost-effective manner.

•

Cash Flow Stability. Our cash flow is relatively stable due to a number of factors, including our longer-term contracts with our refinery services and industrial gases customers, our diversified base of customers, assets and services, and our relatively low exposure to volatile fluctuations in commodity prices.

•

Insulation from Volatile Fluctuations in Commodity Prices. We are relatively insulated from most commodity price risks, particularly those associated with crude oil, natural gas and other energy products with volatile prices. When necessary, we manage our exposure to commodity price risks by (i) emphasizing long-term, fee-based contracts for our services and (ii) using contractual arrangements, including back-to-back contracts and derivatives. We utilize fee-based charges for substantially all of our services except our refinery services. Although we have some exposures to monthly changes in the prices for NaHS and caustic soda, those prices are not as volatile as the prices for crude oil, natural gas and refined petroleum products.

•

Financial Flexibility. As of September 30, 2007, we had $285 million of loans and $4.7 million in letters of credit outstanding, under our $500 million credit facility, resulting in $210.4 million of remaining credit, of which $90.4 was available under our borrowing base. In addition, any new acquisitions that we complete will have the potential to increase our borrowing base, subject to specified limitations.

Results of Operations

The contribution of each of our segments to total segment margin in the third quarters and nine-month periods of 2007 and 2006 was as follows:


	Three Months Ended September 30,				Nine Months Ended September 30,
	2007		2006		2007		2006
	(in thousands)				(in thousands)
Pipeline transportation	$	3,763	$	3,458	$	8,858	$	9,862
Refinery services		8,545		—		8,545		—
Industrial gases		3,232		3,155		8,804		8,808
Supply and logistics		4,960		1,999		7,986		6,074

Total segment margin	$	20,500	$	8,612	$	34,193	$	24,744

Pipeline Transportation Operations

We operate three crude oil common carrier pipeline systems in a four-state area. We refer to these pipelines as our Mississippi System, Jay System and Texas System. Additionally, we operate a CO₂ pipeline in Mississippi to transport CO₂ from Denbury’s main CO₂ pipeline to Brookhaven oil field. Denbury has the exclusive right to use this CO₂ pipeline. We also have several small natural gas gathering systems.

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Index to Financial Statements

Operating results for our pipeline transportation segment were as follows:


	Three Months Ended September 30,						Nine Months Ended September 30,
	2007			2006			2007			2006
	(in thousands)						(in thousands)
Crude oil tariffs and revenues from direct financing leases of crude oil pipelines	$	3,912		$	3,792		$	10,907		$	10,659
Sales of crude oil pipeline loss allowance volumes		1,845			1,669			4,985			5,064

Revenues from direct financing leases of CO₂ pipelines		79			84			241			257
Tank rental reimbursements and other miscellaneous revenues		164			144			491			452

Total revenues from crude oil and CO₂ tariffs, including revenues from direct financing leases		6,000			5,689			16,624			16,432
Revenues from natural gas tariffs and sales		895			1,459			3,394			7,107
Natural gas purchases		(817	)		(1,341	)		(3,164	)		(6,582	)
Pipeline operating costs		(2,315	)		(2,349	)		(7,996	)		(7,095	)

Segment margin	$	3,763		$	3,458		$	8,858		$	9,862

Barrels per day on crude oil pipelines:
Total		60,311			62,610			58,531			62,484
Mississippi System		22,818			17,078			20,938			16,828
Jay System		14,596			14,785			13,027			13,321
Texas System		22,897			30,747			24,566			32,335

Three Months Ended September 30, 2007 Compared with Three Months Ended September 30, 2006

Pipeline segment margin for the third quarter of 2007 increased $0.3 million as compared to the third quarter of 2006. Revenues from crude oil tariffs and related sources and sales of pipeline loss allowance volumes increased a total of $0.3 million. Pipeline operating costs were the same between the two periods, and the contribution to segment margin from natural gas activities was consistent.

Crude oil tariff and direct financing lease revenues increased $0.1 million primarily due to volume increases on the Mississippi System of 5,740 barrels per day and tariff increases on the Jay System. The tariff on the Mississippi System is an incentive tariff, such that the average tariff per barrel decreases as the volumes increase, however the overall impact of an annual tariff increase on July 1, 2007 with the volume increase still resulted in improved revenues. The volumes on the Jay System were almost identical to the prior year period. Average tariffs on the Jay System increased by approximately $0.03 per barrel between the two periods, as a result of the annual tariff increase on July 1, 2007. Although volumes on the Texas System declined by 7,850 barrels per day, the impact on revenues was not very significant due to the relatively low tariffs on that system. Approximately 74% of the volume on that system is shipped on a tariff of $0.31 per barrel. The increased volumes on the Mississippi System, which has a much higher tariff than the Texas System, offset the impact of the volume decrease.

The volume increase on the Mississippi System was due to increased volumes shipped on our pipeline by Denbury for which we receive a tariff. Denbury is the largest producer (based on average barrels produced per day) of crude oil in the State of Mississippi. Our Mississippi System is adjacent to several of Denbury’s existing and prospective oil fields. As Denbury continues to acquire and develop old oil fields using CO₂ based tertiary recovery operations, we expect Denbury to add crude oil gathering and CO₂supply infrastructure to those fields, which could create opportunities for us.

The Jay System in Florida/Alabama ships crude oil from fields with relatively short remaining production lives. Recent changes in the ownership of the more mature producing fields in the area surrounding our Jay System have led to interest in further development or re-development of these fields which may lead to increases in production. Additionally, new wells have been drilled in the area. This new production produces greater tariff

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Index to Financial Statements

revenue for us due to the greater distance that the crude oil is transported on the pipeline. In August 2007, we announced that we will construct an expansion of our existing Jay System that will extend to producers operating in southern Alabama. This extension will consist of approximately 33 miles of pipeline and gathering connections to approximately 30 wells and storage capacity of 20,000 barrels. We expect to place these facilities in service in the first quarter of 2009. The production from these wells is currently being transported to our existing Jay System by our trucks. This expansion will allow us to re-deploy the trucks to other operations.

Our Texas System is dependent on connecting carriers for supply, and on two refineries for demand for our services. Volumes on the Texas System have declined as a result of changes in the supply available for the two refineries to acquire and ship on our pipeline. Volumes on the Texas System may continue to fluctuate as refiners on the Texas Gulf Coast compete for crude oil with other markets connected to TEPPCO’s pipeline systems.

Sales of pipeline loss allowance volumes increased $0.2 million due to an increase in volumetric gain volumes of approximately 1,399 barrels. These volumes are sold at crude oil market prices.

Historically, the largest operating costs in our crude oil pipeline segment have consisted of personnel costs, power costs, maintenance costs and costs of compliance with regulations. Some of these costs are not predictable, such as failures of equipment or power cost increases. We perform regular maintenance on our assets in an effort to keep them in good operational condition and to minimize cost increases. Operations and maintenance costs, excluding the effects of our stock appreciation rights plan increased $0.2 million, with an offsetting decrease in the costs related to our stock appreciation right plan expense that relates to our pipeline operations personnel. The increased operations and maintenance costs related primarily to higher compensation costs in the 2007 quarter and increased property taxes and maintenance costs.

Nine Months Ended September 30, 2007 Compared with Nine Months Ended September 30, 2006

For the nine-month periods, pipeline segment margin decreased by $1.0 million. Higher pipeline operating costs accounted for $0.9 million of the increase, with $0.5 million of that increase due to stock appreciation rights plan expense. The remaining $0.4 million increase in costs related to integrity management testing, costs to tear down a tank on the Texas System to prepare the location for its replacement and other maintenance costs. Revenues from crude oil tariffs and related sources and sales of pipeline loss allowance volumes increased a total of $0.3 million and net segment margin from natural gas pipeline activities decreased by $0.3 million. The natural gas pipeline activities were impacted by production difficulties of a producer attached to the system.

As in the third quarter periods, the decline in crude oil pipeline volumes in the nine month periods of 3,953 barrels per day did not have a significant impact on tariff revenues, as it was attributable to the lower tariff Texas System and was partially offset by volume increases on the higher tariff Mississippi System.

Refinery Services Segment

We acquired our refinery services segment in the Davison transaction. That segment primarily provides a service to refining operations - it processes sour hydrocarbon streams to remove sulfur and returns such hydrocarbon streams for further refining and/or consumption within the refining location. In most instances, we own, maintain and operate the facilities required to perform the services. Typically, we receive 100% of the by-product of our process, sodium hydrosulfide, or NaHS, as compensation for providing the sour gas processing services. The largest cost component of providing the service is acquiring and delivering caustic soda to our operations. Caustic soda, or NaOH, is the scrubbing agent introduced in the sour gas stream to remove the sulfur and generate the by-product, NaHS. Therefore the contribution to segment margin involves the revenues generated from the sales of NaHS less our total cost of providing the services, including the costs of acquiring and delivering caustic soda to our service locations. We estimate that approximately 65% of our NaHS sales are indexed, in one form or another, to our cost of caustic soda. Because the activities of these service arrangements can fluctuate, we do, from time to time engage in other activities such as selling caustic soda, buying NaHS from other producers for re-sale to our customers and buying and selling sulfur, the financial results of which are also reported in our refinery services segment.

We believe the most meaningful measure of our success in this segment is the revenue generated from sales of NaHS after deducting delivery expenses, from both the volumes received as payment for rendering service as well as volumes obtained from third party producers.

During the two months that we owned this operation, sales of NaHS, measured in dry short tons (DST) were 27,925 DST. The average sales price of the NaHS, net of delivery expenses, for the period was $613 per DST.

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Index to Financial Statements

Combining the historical results of this operation for July 2007 with our results and comparing it to the historical results of the predecessor for the third quarter of 2006 indicates that the average sales price per DST of NaHS, net of delivery expenses, increased between the three month periods by 8%. The total DST sold between the periods, including the July 2007 sales of the predecessor, was 437 DST less in the 2007 third quarter than the same period in 2006. In total, for the two month period of our ownership, sales of NaHS produced revenues, net of delivery costs of $3.0 million, was $17.2 million.

Revenues from sales of NaOH, and sulfur, net of delivery costs, for the two months we owned this operation were $4.3 million. Including the sales of NaOH and sulfur by the predecessor for July 2007 with the sales in our two-months of ownership and comparing that to the results for the predecessor for the third quarter of 2006 indicates that this source of revenue would have increased by $0.5 million.

Costs of acquiring and delivering the NaOH used in the processing of the sour gas streams and the other costs of our processing activities, including delivery costs related to NaHS, as well as the cost of the NaOH and NaHS re-sold and the sulfur re-sold totaled $16.8 million for the two months we owned the operations.

Industrial Gases Segment

Our industrial gases segment includes the results of our CO₂ sales to industrial customers and our share of the operating income of our 50% joint venture interests in T&P Syngas and Sandhill. Operating results from our industrial gases segment were as follows:


	Three Months Ended September 30,						Nine Months Ended September 30,
	2007			2006			2007			2006
	(in thousands)						(in thousands)
Revenues from CO₂ sales	$	4,373		$	4,262		$	11,816		$	11,543
CO₂ transportation and other costs		(1,502	)		(1,374	)		(3,927	)		(3,654	)
Equity in earnings of joint ventures		361			267			915			919

Segment margin	$	3,232		$	3,155		$	8,804		$	8,808

Volumes per day:
CO₂ sales - Mcf		85,705			82,244			76,035			74,321

Three Months Ended September 30, 2007 Compared with Three Months Ended September 30, 2006

Segment margin from industrial gases activities was consistent between the two third quarter periods, increasing slightly by $0.1 million. This margin is derived from two sources - sales of CO₂ and our equity in the earnings of joint ventures.

CO₂ Sales

We supply CO₂ to industrial customers under seven long-term CO₂ sales contracts. The sales contracts contain provisions for adjustments for inflation to sales prices based on the Producer Price Index, with a minimum price.

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Index to Financial Statements

Our industrial customers treat the CO₂ and transport it to their own customers. The primary industrial applications of CO₂ by these customers include beverage carbonation and food chilling and freezing. Based on historical data for 2004 through 2007, we can expect some seasonality in our sales of CO₂. The dominant months for beverage carbonation and freezing food are from April to October, when warm weather increases demand for beverages and the approaching holidays increase demand for frozen foods. Volumes sold in the last six quarters were as follows:


		Sales Mcf per Day
Second Quarter 2006		73,980
Third Quarter 2006		82,244
Fourth Quarter 2006		68,452
First Quarter 2007		67,158
Second Quarter 2007		75,039
Third Quarter 2007		85,705

Although CO₂ sales volumes increased 4% between the two periods, the volumes varied among contracts with different pricing terms such that revenues only increased by $111,000. The increased volumes and the inflation adjustment to the rate we pay Denbury to transport the CO₂ in its pipeline to our customers resulted in greater CO₂ transportation costs in the third quarter of 2007 when compared to the 2006 quarter.

Joint Ventures

We own a 50% interest in two joint ventures engaged in industrial gases activities, T&P Syngas and Sandhill. T&P Syngas owns a facility located in Texas City, Texas that manufactures syngas (a combination of carbon monoxide and hydrogen) and high-pressure steam. Under that processing agreement, Praxair provides the raw materials to be processed and receives the syngas and steam produced by the facility. T&P Syngas receives a processing fee for its services. Our share of the operating income of T&P Syngas for the three months ended September 30, 2007 and 2006 was the same. During the third quarters of 2007 and 2006, T&P Syngas paid us distributions totaling $0.4 million and $0.6 million, respectively, attributable to the second quarters of the years.

Sandhill is engaged in the production and distribution of liquid carbon dioxide for use in the food, beverage, chemicals and oil industries. The facility acquires CO₂ from us under a long-term supply contract that we acquired in 2005 from Denbury. Our share of the operating income of Sandhill for the third quarters of 2007 and 2006 was $135,000 and $46,000, respectively, which we reduced by $69,000 and $65,000 for the amortization of excess purchase price, respectively.

Nine Months Ended September 30, 2007 Compared with Nine Months Ended September 30, 2006

As in the three month periods, segment margin from our industrial gases segment for the nine-month periods was consistent, with an increase in revenues from sales of CO₂ offset by an increase in the associated transportation costs. Although CO₂ sales volumes increased by 1,714 Mcf per day, the variance in volumes among the individual contracts with differing pricing terms resulted in no increase in the contribution to segment margin.

Additional discussion of our joint ventures is included in Note 7 of the Notes to the Unaudited Consolidated Financial Statements.

Supply and Logistics Segment

Our supply and logistics segment was previously known as our crude oil gathering and marketing segment. With the acquisition of the Davison businesses, we renamed the segment and we included the petroleum products, fuel logistics, terminaling and truck transportation activities we acquired from the Davisons. Those operations are similar to our crude oil gathering operations, with the focus on buying the petroleum products at an economical price and providing the blending, storage and transportation logistics to make the highest possible margin. We also provide terminaling and trucking services to third parties, and are integrating the capabilities of our acquired operations with our existing operations.

The commodity prices (for purchases and sales) of crude oil and petroleum products do not necessarily bear a relationship to segment margin as those prices normally impact revenues and costs of sales by approximately

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Index to Financial Statements

equivalent amounts. Because period-to-period variations in revenues and costs of sales are not generally meaningful in analyzing the variation in segment margin for our supply and logistics operations, these changes are not addressed in the following discussion.

Generally, as we purchase crude oil and petroleum products, we simultaneously establish a margin by selling crude oil or petroleum products for physical delivery to third party users, such as independent refiners, major oil companies or users of petroleum products. Through these transactions, we seek to maintain a position that is substantially balanced between crude oil and petroleum purchases, on the one hand, and sales or future delivery obligations, on the other hand. We hold no material volumes of crude oil, petroleum products, futures contracts or other derivative products to speculate on commodity price changes. When our positions become unbalanced such that we have inventory, we will use derivative instruments to hedge that inventory until such time as we can sell it into the market.

When the crude oil markets are in contango, (oil prices for future deliveries are higher than for current deliveries), we may store crude oil as inventory in our storage tanks that we have purchased at lower prices in the current month for delivery at higher prices in future months. When we purchase this inventory, we simultaneously enter into a contract to sell the inventory in the future period, either with a counterparty or in the crude oil futures market. We generally will account for this inventory and the related derivative hedge as a fair value hedge in accordance with Statement of Financial Accounting Standards No. 133. See Note 14 of the Notes to the Unaudited Consolidated Financial Statements.

Most of our contracts for the purchase and sale of crude oil have components in the pricing provisions such that the price paid or received is adjusted for changes in the market price for crude oil. The pricing in the majority of our purchase contracts contain the market price component, a bonus that is not fixed, but instead is based on another market factor and a deduction to cover the cost of transporting the crude oil and to provide us with a margin. Contracts will sometimes also contain a grade differential which considers the chemical composition of the crude oil and its appeal to different customers. Typically the pricing in a contract to sell crude oil will consist of the market price components and the grade differentials. The margin on individual transactions is then dependent on our ability to manage our transportation costs and to capitalize on grade differentials.

In our petroleum products marketing operations, we primarily supply fuel oil, asphalt, diesel and gasoline to wholesale markets and some end-users such as paper mills and utilities. We also provide a service to refineries by purchasing their products that do not meet the specifications they desire, transporting it to one of our terminals and blending it to a quality that meets the requirements of our customers. The opportunities to provide this service cannot be predicted, but the contribution to margin tends to be higher than in our recurring operations.

Operating results from our supply and logistics segment were as follows:


	Three Months Ended September 30,						Nine Months Ended September 30,
	2007			2006			2007			2006
	(in thousands)						(in thousands)
Supply and logistics revenues	$	317,653		$	218,141		$	691,220		$	691,414
Crude oil and products costs		(304,129	)		(212,737	)		(665,939	)		(674,870	)
Operating costs		(8,564	)		(3,405	)		(17,295	)		(10,470	)

Segment margin	$	4,960		$	1,999		$	7,986		$	6,074

Three Months Ended September 30, 2007 as Compared to Three Months Ended September 30, 2006

The portions of our supply and logistics operations acquired in the Davison transaction added approximately $3.0 million to our supply and logistics segment margin for the three months ended September 30, 2007. Our existing crude oil gathering and marketing operations contribution for the three months ended September 30, 2007 was only slightly less than the contribution for the three months ended September 30, 2006, however the contribution was actually the result of offsetting fluctuations as discussed below. Contribution by our crude oil operations is derived from sales of crude oil and from the transportation by truck for a fee of crude oil volumes that we did not purchase, with costs for this part of the operation relating to the purchase of the crude oil and the related aggregation and transportation costs.

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Index to Financial Statements

Crude oil volumes that we transported for a fee, but did not purchase, increased by 1,462 barrels per day. Most of this increase in volume was attributable to transportation of Denbury’s production from their wellheads to our pipeline. The increase in the fees for these services was $0.8 million between the two third quarter periods.

Offsetting the increase in revenues from the crude oil transportation was an increase of $0.8 million in field costs between the 2007 and 2006 third quarters. Compensation costs to operate the trucks and manage our crude oil gathering operations increased $0.6 million, as a result of compensation increases and the use of contract personnel. Expense related to our stock appreciation rights plan decreased by $0.2 million between the periods. Increased fuel costs to operate our fleet of trucks and repairs to trucks and equipment accounted for most of the remaining $0.4 million increase in costs.

Nine Months Ended September 30, 2007 as Compared to Nine Months Ended September 30, 2006

For the nine-month periods, the contribution by the operations acquired from the Davison family was $3.0 million. Our existing crude oil gathering and marketing operations contribution to segment margin declined by $1.1 million between the nine-month periods. An increase in the expense we recorded for our stock appreciation rights plan of $0.6 million accounted for much of this decrease. We also had increased costs for fuel and personnel as well as higher costs to maintain our trucks that combined to increase our operating costs in the crude oil area by $2.0 million. Offsetting a portion of these higher costs was an increase in revenues from transporting crude oil between the periods of $1.9 million.

On a like-kind basis, volumes decreased 1,901 barrels per day, or 4%. We eliminated contracts during the first quarter of 2006 that did not meet our targets for profitability and we were impacted by significant volatility between crude quality differentials between the periods, with the overall impact on margin of an increase of $1.1 million. The margins generated from the storage of crude oil inventory in the contango market were $0.6 million greater in the 2007 first nine months than in the prior year.

Other Costs, Interest and Income Taxes

General and administrative expenses. General and administrative expenses consisted of the following:


	Three Months Ended September 30,					Nine Months Ended September 30,
	2007			2006		2007		2006
	(in thousands)					(in thousands)
Expenses excluding effect of stock appreciation rights plan and transition costs	$	5,527		$	2,804	$	11,595	$	8,240
Transition costs related to new management team		—			1,293		—		1,293
Stock appreciation rights plan expense		(803	)		442		2,057		915

Total general and administrative expenses	$	4,724		$	4,539	$	13,652	$	10,448

Between the third quarter periods, general and administrative expenses increased by $0.2 million. This increase results from an increase related to the administrative personnel and costs at the Davison locations totaling $2.0 million, offset partially by a credit to general and administrative expense for our stock appreciation rights plan that resulted in a total reduction in expense between the periods of $1.2 million. Additionally, we incurred transition costs in the 2006 period when we brought in a new management team totaling $1.3 million, which did not recur in the 2007 period. Bonus plan expense decreased $0.2 million between the two periods. The remaining change in general and administrative expenses totals $0.9 million. We have added additional personnel at our headquarters office due to the Davison acquisition and have incurred additional costs for legal and other consulting services.

For the nine-month periods, the $3.2 million increase in general and administrative costs is primarily attributable the costs of the administrative personnel at the Davison locations of $2.0 million, increased stock appreciation rights plan expense of $1.2 million, partially offset by the transition costs of $1.3 million that were incurred in 2006. The remaining increase in expense of $1.3 million is attributable to $0.3 million of personnel costs, $0.5 million of increased legal, audit and other consulting fees, and $0.5 million of other increased costs.

Denbury, the owner of our general partner has been negotiating with our management team that was hired in August 2006 to finalize a compensation package for that team that will involve an ownership interest in our general partner. When the terms of those arrangements are finalized and the agreements and necessary structure are

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Index to Financial Statements

in place, we expect that our management team will have the opportunity to earn up to 20% of our general partner interest and would potentially vest in a portion of our general partner’s interest due to the completion of the Davison transaction. Under the “push-down” rules for accounting for transactions where the beneficiary of a transaction is not the same as the parties to the transaction, we expect to record non-cash general and administrative expense for the fair value of this compensation arrangement. Should the terms and agreements pertaining to the arrangements be finalized in the fourth quarter of 2007, we would expect that some portion of the expense related to the ownership- interest award will be recorded as general and administrative expense in the fourth quarter. At this time we cannot estimate the amount of the expense we will record as the terms of the agreement have not been agreed to and finalized.

Depreciation, amortization and impairment expense increased in the three and nine month periods primarily as a result of the depreciation and amortization on the assets acquired in the Davison and Port Hudson transactions. This additional depreciation and amortization totaled $6.1 million.

Interest expense, net.

Interest expense, net was as follows:


	Three Months Ended September 30,						Nine Months Ended September 30,
	2007			2006			2007			2006
	(in thousands)						(in thousands)
Interest expense, including commitment fees	$	4,728		$	220		$	5,226		$	547
Capitalized interest		(27	)		—			(33	)		—
Amortization of facility fees		141			89			274			255
Interest income		(141	)		(49	)		(219	)		(157	)

Net interest expense	$	4,701		$	260		$	5,248		$	645

As a result of the Davison acquisition which was partially financed with borrowings under our credit facility beginning on July 25, 2007, our interest expense increased $4.5 million in the third quarter. Our average outstanding balance of debt was $225 million, during the third quarter of 2007, an increase of $220 million over the prior year period. Our average interest rate during the 2007 quarter was 7.91%. For the nine month periods, our interest expense was $4.7 million more than the interest expense for the nine months of 2006. Our average outstanding balance of debt was $76 million greater than the prior year period. Our average interest rate for the nine month period in 2007 was 7.95%.

Income taxes.

Because certain of our operations acquired in the Davison transaction do not generate “qualified income” within the meaning of the Internal Revenue Code, a portion of the operations we acquired in the Davison transactions are owned by wholly-owned corporate subsidiaries that are taxable as corporations. We will pay federal and state income taxes on these operations. We recorded an estimate of our current tax expense for the three months and nine months ended September 30, 2007 of $1.0 million and $1.1 million, respectively. These wholly-owned taxable corporations will pay us dividends of their after-tax earnings. Although there can be no assurances, we believe as the amount of “qualified income” we generate increases and as certain other activities are restructured, this estimated tax cost will likely decrease in future periods.

Liquidity and Capital Resources

Capital Resources

Capital Resources/Sources of Cash

In the last 12 months, we have adopted a growth strategy that has dramatically increased our cash requirements. We now expect our capital resources to include equity and debt offerings (public and private) and other financing transactions. Accordingly, we expect to access the capital markets (equity and debt) from time to time to partially refinance our capital structure and to fund other needs including acquisitions and ongoing working capital needs. Our ability to satisfy future capital needs will depend on our ability to raise substantial amounts of additional capital, to utilize our current credit facility and to implement our growth strategy successfully. No assurance can be made that we will be able to raise the necessary funds on satisfactory terms. If we are unable to raise the necessary funds, we may be required to defer our growth plans until such time as funds become available or reduce or suspend our distributions.

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Index to Financial Statements

In November 2006, we entered into a credit facility with a maximum facility amount of $500 million (replacing our $100 million facility). A maximum of $100 million may be used for letters of credit. The borrowing base under the facility at September 30, 2007 was approximately $380 million, and is recalculated quarterly and at the time of acquisitions. The borrowing base represents the amount that can be borrowed or utilized for letters of credit based on our EBITDA, computed in accordance with the provisions of our credit facility.

The terms of our credit facility also effectively limit the amount of distributions that we may pay to our general partner and holders of common units. Such distributions may not exceed the sum of the distributable cash generated for the eight most recent quarters, less the sum of the distributions made with respect to those quarters. See Note 8 of the Notes to the Unaudited Consolidated Financial Statements.

We financed the Davison acquisition with the issuance of 13,459,209 common units and cash, which we funded with borrowings under our credit facility and the issuance of 1,074,882 common units to our general partner. Our general partner exercised its right to maintain its proportionate ownership interest in our common units, by purchasing these units for $22.4 million or $20.8036 per common unit. Additionally, we received $6.2 million from the general partner to maintain its general partner capital account balance as required by our partnership agreement. Other acquisitions may be initially funded primarily with debt or equity or any combination thereof.

Uses of Cash

Our cash requirements include funding day-to-day operations, maintenance and expansion capital projects, debt service, refinancings and distributions on our common units and other equity interests. We expect to use cash flows from operating activities to fund cash distributions and maintenance capital expenditures needed to sustain existing operations. Future expansion capital - acquisitions or capital projects - will require funding through various financing arrangements, as more particularly described under “Liquidity and Capital Resources - Capital Resources/Sources of Cash” above.

Operating. Our operating cash flows are affected significantly by changes in items of working capital. We have had situations where other parties have prepaid for purchases or paid more than was due, resulting in fluctuations in one period as compared to the next until the party recovers the excess payment. The timing of capital expenditures and the related effect on our recorded liabilities also affects operating cash flows.

The majority of our accounts receivable relate to our crude oil operations. These accounts receivable settle monthly and collection delays generally relate only to discrepancies or disputes as to the appropriate price, volume or quality of crude oil delivered. Accounts receivable in our fuel procurement business also settle within 30 days of delivery. Over 75% of the $154.6 million aggregate receivables on our consolidated balance sheet at September 30, 2007 relate to our crude oil and fuel procurement businesses.

Investing. We utilized cash flows to make acquisitions and for capital expenditures. The most significant investing activities in 2007 have been the Davison acquisition for which we expended $301.3 million in cash as consideration and for related acquisition costs. We also paid $8.1 million for our acquisition of the Port Hudson assets. We paid $3.3 million for capital expenditures and received $0.2 million from the sale of surplus assets. We received distributions from our T&P Syngas joint venture that exceeded our share of the earnings of T&P Syngas of $0.4 million during the first nine months of 2007.

Financing. Net cash of $293.8 million was provided by financing activities. Our net borrowings under our credit facility were $277.0 million. We received $22.4 million from our general partner for 1,074,882 common units they acquired as part of the Davison acquisition in order to maintain their 7.4% limited partner interest. Our general partner also contributed $6.2 million as required under our partnership agreement to maintain its general partner capital account balance. In connection with the increase in the committed amount of our credit facility, we incurred credit facility fees of $2.3 million. We paid distributions totaling $9.3 million to our limited partners and our general partner during the nine month period, and expended $0.2 million on other financing activities.

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Index to Financial Statements

Capital Expenditures. A summary of our capital expenditures, excluding acquisitions, in the nine months ended September 30, 2007 and 2006 is as follows:


	Nine Months Ended September 30,
	2007		2006
	(in thousands)
Maintenance capital expenditures:
Mississippi pipeline systems	$	84	$	163
Jay pipeline system		1,238		89
Texas pipeline system		855		118
Supply and logistics assets		348		92
Refinery services assets		269
Administrative and other assets		48		98

Total maintenance capital expenditures		2,842		560
Growth capital expenditures
Mississippi pipeline systems		—		269
Jay pipeline system		188		—
Supply and logistics assets		186		—
Refinery services assets		284
Sandhill Group, LLC investment		—		5,042
Faustina Project		552		702

Total growth capital expenditures		1,210		6,013

Total capital expenditures	$	4,052	$	6,573

During the fourth quarter of 2007, we expect to expend approximately $1.3 million for maintenance capital projects in progress or planned. At this time, we anticipate that our maintenance capital expenditures relating to our existing assets for 2008 will range from $2.0 million to $3.0 million; however we have not finalized our 2008 capital budget. Most of our truck fleet is less than two years old, so we do not anticipate making any significant expenditures for vehicles in 2008; however, in future years we expect to spend $4 million to $5 million per year on vehicle replacements.

We have started construction of an expansion of our existing Jay System that will extend the pipeline to producers operating in southern Alabama. The expansion will consist of approximately 33 miles of pipeline and gathering connections to approximately 30 wells and will include storage capacity of 20,000 barrels. We expect to spend a total of approximately $9.9 million on this project during the fourth quarter of 2007 and in 2008. Our refinery services segment expects to expend approximately $1.3 million on projects currently in progress to expand its operations during the fourth quarter of 2007 and $1.4 million on these projects in 2008. We are also making improvements at our Port Hudson terminal to both increase its capacity, the services we can provide and extend the life of the assets. Based on the information available to us at this time, we do not anticipate that future capital expenditures for compliance with regulatory requirements will be material. We expect to fund these capital improvements with borrowings under our credit agreement.

As discussed under “Acquisitions and Related Activities in 2007” above, we closed on the transaction with the Davison family in the third quarter of 2007 and we are currently negotiating with Denbury regarding the “drop-down” of certain CO₂ pipeline assets before the end of 2007.

Distributions

We are required by our partnership agreement to distribute 100% of our available cash (as defined therein) within 45 days after the end of each quarter to unitholders of record and to our general partner. Available cash consists generally of all of our cash receipts less cash disbursements adjusted for net changes to reserves. We have increased our distribution for each of the last eight quarters, including the distribution to be paid for the third quarter of 2007, as shown in the table below (in thousands, except per unit amounts).

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Index to Financial Statements


Distribution For	Date Paid	Per Unit Amount		Limited Partner Interests Amount			General Partner Interest Amount		General Partner Incentive Distribution Amount		Total Amount
Fourth quarter 2005	February 2006	$	0.17	$	2,343		$	48	$	—	$	2,391
First quarter 2006	May 2006	$	0.18	$	2,481		$	51	$	—	$	2,532
Second quarter 2006	August 2006	$	0.19	$	2,619		$	53	$	—	$	2,672
Third quarter 2006	November 2006	$	0.20	$	2,757		$	56	$	—	$	2,813
Fourth quarter 2006	February 2007	$	0.21	$	2,895		$	59	$	—	$	2,954
First quarter 2007	May 2007	$	0.22	$	3,032		$	62	$	—	$	3,094
Second quarter 2007	August 2007	$	0.23	$	3,170	⁽¹⁾	$	65	$	—	$	3,235	⁽¹⁾
Third quarter 2007	November 2007 ⁽²⁾	$	0.27	$	7,646	⁽³⁾	$	156	$	90	$	7,892	⁽³⁾

(1)

(2)	This distribution will be paid on November 14, 2007 to the general partner and unitholders of record as of November 6, 2007.

(3)	The increased amount of distributions that will be paid is primarily a result of the additional units issued in connection with the Davison acquisition as discussed above.

See Note 9 of the Notes to the Unaudited Consolidated Financial Statements.

Available Cash before Reserves for the three and nine months ended September 30, 2007 is as follows (in thousands):


	Three Months Ended September 30, 2007			Nine Months Ended September 30, 2007
Net income	$	1,699		$	1,912
Depreciation and amortization		8,372			12,346
Cash received from direct financing leases not included in income		143			422
Effects of available cash generated by investments in joint ventures not included in income		179			664
Non-cash (credits) charges		(994	)		2,339
Proceeds from disposals of surplus assets		—			195
Maintenance capital expenditures		(2,148	)		(2,842	)

Available Cash before Reserves	$	7,251		$	15,036

We have reconciled Available Cash before Reserves (a non-GAAP liquidity measure) to cash flow from operating activities (the GAAP measure) for the three and nine months ended September 30, 2007 below. For the three months and nine months ended September 30, 2007, cash flows provided by operating activities were $22.6 million and $25.7 million, respectively.

Non-GAAP Financial Measure

This quarterly report includes the financial measure of Available Cash before Reserves, which is a “non-GAAP” measure because it is not contemplated by or referenced in accounting principles generally accepted in the U.S., also referred to as GAAP. The accompanying schedule provides a reconciliation of this non-GAAP financial measure to its most directly comparable GAAP financial measure. Our non-GAAP financial measure should not be considered as an alternative to GAAP measures such as net income, operating income, cash flow from operating activities or any other GAAP measure of liquidity or financial performance. We believe that investors benefit from having access to the same financial measures being utilized by management, lenders, analysts and other market participants.

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Index to Financial Statements

Available Cash before Reserves, also referred to as discretionary cash flow, is commonly used as a supplemental financial measure by management and by external users of financial statements, such as investors, commercial banks, research analysts and rating agencies, to assess: (1) the financial performance of our assets without regard to financing methods, capital structures or historical cost basis; (2) the ability of our assets to generate cash sufficient to pay interest cost and support our indebtedness; (3) our operating performance and return on capital as compared to those of other companies in the midstream energy industry, without regard to financing and capital structure; and (4) the viability of projects and the overall rates of return on alternative investment opportunities. Because Available Cash before Reserves excludes some, but not all, items that affect net income or loss and because these measures may vary among other companies, the Available Cash before Reserves data presented in this Quarterly Report on Form 10-Q may not be comparable to similarly titled measures of other companies. The GAAP measure most directly comparable to Available Cash before Reserves is net cash provided by operating activities.

Available Cash before Reserves is a liquidity measure used by our management to compare cash flows generated by us to the cash distribution paid to our limited partners and general partner. This is an important financial measure to our public unitholders since it is an indicator of our ability to provide a cash return on their investment. Specifically, this financial measure aids investors in determining whether or not we are generating cash flows at a level that can support a quarterly cash distribution to the partners. Lastly, Available Cash before Reserves (also referred to as distributable cash flow) is the quantitative standard used throughout the investment community with respect to publicly-traded partnerships.

The reconciliation of Available Cash before Reserves (a non-GAAP liquidity measure) to cash flow from operating activities (the GAAP measure) for the three and nine months ended September 30, 2007, is as follows (in thousands):


	Three Months Ended September 30, 2007			Nine Months Ended September 30, 2007
Cash flows from operating activities	$	22,598		$	25,653
Adjustments to reconcile operating cash flows to Available Cash:
Maintenance capital expenditures		(2,148	)		(2,842	)
Proceeds from sales of certain assets		—			195
Amortization of credit facility issuance fees		(236	)		(509	)
Effects of available cash generated by investments in joint ventures not included in cash flows from operating activities		97			303
Cash effects of exercises under SAR Plan		(452	)		(1,447	)
Other items affecting Available Cash		(1,009	)		—
Net effect of changes in operating accounts not included in calculation of Available Cash		(11,599	)		(6,317	)

Available Cash before Reserves	$	7,251		$	15,036

Commitments and Off-Balance-Sheet Arrangements

Contractual Obligation and Commercial Commitments

In addition to the credit facility discussed above, we have contractual obligations under operating leases as well as commitments to purchase crude oil. The table below summarizes our obligations and commitments at September 30, 2007 (in thousands).

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Index to Financial Statements


	Payments Due by Period
Commercial Cash Obligations and Commitments	Less than one year		1 - 3 years		4 - 5 Years		After 5 years		Total
Long-term debt⁽¹⁾	$	—	$	—	$	285,000	$	—	$	285,000
Estimated interest payable on long-term debt⁽²⁾		25,270		51,300		28,812		—		105,382
Operating lease obligations		3,062		4,051		1,517		7,527		16,157
Capital expansion projects⁽³⁾		11,865		—		—		—		11,865
Unconditional purchase obligations⁽⁴⁾		144,473		3,831		—		—		148,304

Total Contractual Cash Obligations	$	184,670	$	59,182	$	315,329	$	7,527	$	566,708

(1)	Our credit facility allows us to repay and re-borrow funds at any time through the maturity date of November 15, 2011.

(2)

Interest on our long-term debt is at market-based rates. The amount shown for interest payments represents the amount that would be paid if the debt outstanding at September 30, 2007 remained outstanding through the final maturity date of November 15, 2011 and interest rates remained at the September 30, 2007 market levels through November 15, 2011.

(3)	We have signed commitments to expand our Jay pipeline system and to construct sour gas processing facilities at a new location. See “Capital Expenditures” above.

(4)

The unconditional purchase obligations included above are contracts to purchase crude oil and petroleum products, generally at market-based prices. For purposes of this table, market prices at September 30, 2007, were used to value the obligations. Actual obligations may differ from the amounts included above.

In addition to the contractual cash obligations included above, we also have a contingent obligation related to our acquisition of a 50% interest in Sandhill. The terms of the acquisition included earnout provisions such that we could pay up to an additional $2.0 million to Magna Carta for our interest in Sandhill, based on the distributable cash generated by Sandhill during the period of January 1, 2006 through no later than December 31, 2012. Should the cumulative distributable cash of Sandhill in the period beginning with 2006 average at least $1.5 million per year, and distributions to the members average at least $1.2 million per year, we will owe Magna Carta $1.0 million at the end of the year when the target is exceeded. If the distributable cash averages $2.0 million per year and distributions average $1.6 million per year in the period beginning with 2006, we will owe Magna Carta an additional $1.0 million.

We have guaranteed 50% of the $3.9 million debt obligation to a bank of Sandhill; however, we believe we are not likely to be required to perform under this guarantee as Sandhill is expected to make all required payments under the debt obligation.

Off-Balance Sheet Arrangements

We have no off-balance sheet arrangements, special purpose entities, or financing partnerships, other than as disclosed under Contractual Obligation and Commercial Commitments above, nor do we have any debt or equity triggers based upon our unit or commodity prices.

New and Proposed Accounting Pronouncements

See discussion of new accounting pronouncements in Note 2, “Recent Accounting Pronouncements” in the accompanying consolidated financial statements.

Forward Looking Statements

The statements in this Quarterly Report on Form 10-Q that are not historical information may be “forward looking statements” within the meaning of the various provisions of the Securities Act of 1933 and the Securities Exchange Act of 1934. All statements, other than historical facts, included in this document that address activities, events or developments that we expect or anticipate will or may occur in the future, including things such as plans for growth of the business, future capital expenditures, competitive strengths, goals, references to future goals or intentions and other such references are forward-looking statements. These forward-looking statements are identified as any statement that does not relate strictly to historical or current facts. They use words such as “anticipate,” “believe,” “continue,” “estimate,” “expect,” “forecast,” “intend,” “may,” “plan,” “position,” “projection,” “strategy” or “will” or the negative of those terms or other variations of them or by comparable

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Index to Financial Statements

terminology. In particular, statements, expressed or implied, concerning future actions, conditions or events or future operating results or the ability to generate sales, income or cash flow are forward-looking statements. Forward-looking statements are not guarantees of performance. They involve risks, uncertainties and assumptions. Future actions, conditions or events and future results of operations may differ materially from those expressed in these forward-looking statements. Many of the factors that will determine these results are beyond our ability or the ability of our affiliates to control or predict. Specific factors that could cause actual results to differ from those in the forward-looking statements include:

•

demand for, the supply of, changes in forecast data for, and price trends related to crude oil, liquid petroleum, refined products, NaHS, caustic soda, CO₂ natural gas and natural gas liquids or “NGLs” in the United States, all of which may be affected by economic activity, capital expenditures by energy producers, weather, alternative energy sources, international events, conservation and technological advances;

•

throughput levels and rates;

•

changes in, or challenges to, our tariff rates;

•

our ability to successfully identify and consummate strategic acquisitions, make cost saving changes in operations and integrate acquired assets or businesses into our existing operations;

•

service interruptions in our liquids transportation systems, natural gas transportation systems or natural gas gathering and processing operations;

•

shutdowns or cutbacks at refineries, petrochemical plants, utilities or other businesses for which we transport crude oil, natural gas or other products or to whom we sell such products;

•

changes in laws or regulations to which we are subject;

•

our inability to borrow or otherwise access funds needed for operations, expansions or capital expenditures as a result of existing debt agreements that contain restrictive financial covenants;

•

loss of key personnel;

•

the effects of competition, in particular, by other pipeline systems;

•

hazards and operating risks that may not be covered fully by insurance;

•

the condition of the capital markets in the United States;

•

loss of key customers;

•

the political and economic stability of the oil producing nations of the world; and

•

general economic conditions, including rates of inflation and interest rates.

You should not put undue reliance on any forward-looking statements. When considering forward-looking statements, please review the risk factors described under “Risk Factors” discussed in Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2006. Except as required by applicable securities laws, we do not intend to update these forward-looking statements and information.

Item 3. Quantitative and Qualitative Disclosures about Market Risk

We are exposed to market risks primarily related to volatility in prices of crude oil, petroleum products, caustic soda, and NaHS and volatility in interest rates.

Our primary price risk relates to the effect of crude oil and petroleum products price fluctuations on our inventories and the fluctuations each month in crude oil grade and location differentials and their effect on future contractual commitments. We utilize NYMEX commodity based futures contracts and forward contracts to hedge our exposure to these market price fluctuations as needed. At September 30, 2007, we had entered into NYMEX future contracts that will settle through November 2007. These contracts either do not qualify for hedge accounting or are fair value hedges, therefore the fair value of these derivatives have received mark-to-market treatment in current earnings. This accounting treatment is discussed further under Note 2 “Summary of Significant Accounting Policies” of our Consolidated Financial Statements in our Annual Report on Form 10-K.

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Index to Financial Statements


	Sell (Short) Contracts		Buy (Long) Contracts
Futures Contracts
Contract volumes (1,000 bbls)		132		54
Weighted average price per bbl	$	80.55	$	80.97

Contract value (in thousands)	$	10,633		4,372
Mark-to-market change (in thousands)		146		76

Market settlement value (in thousands)	$	10,779	$	4,448

The table above presents notional amounts in barrels, the weighted average contract price, total contract amount and total fair value amount in U.S. dollars. Fair values were determined by using the notional amount in barrels multiplied by the September 30, 2007 quoted market prices on the NYMEX.

We are also exposed to market risks due to the floating interest rates on our credit facility. Our debt bears interest at the LIBOR Rate or Prime Rate plus the applicable margin. We do not hedge our interest rates. At September 30, 2007, we had $285 million of debt outstanding under our credit facility.

Item 4. Controls and Procedures

We maintain disclosure controls and procedures and internal controls designed to ensure that information required to be disclosed in our filings under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms. Our chief executive officer and chief financial officer, with the participation of our management, have evaluated our disclosure controls and procedures as of the end of the period covered by this Quarterly Report on Form 10-Q and have determined that such disclosure controls and procedures are effective in ensuring that material information required to be disclosed in this quarterly report is accumulated and communicated to them and our management to allow timely decisions regarding required disclosures.

Other than the events discussed under the Davison Acquisition below, there were no changes during our last fiscal quarter that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Davison Acquisition

On July 25, 2007, we completed the Davison Acquisition, which met the criteria of being a significant acquisition for us. For additional information regarding the acquisition, please read Note 3 to the Consolidated Financial Statements and “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Acquisitions and Related Activities in 2007” included in Item 2 in this Quarterly Report.

On June 22, 2004, the Office of the Chief Accountant of the SEC issued guidance regarding the reporting of internal control over financial reporting in connection with a major acquisition. On October 6, 2004, the SEC revised its guidance to include expectations of quarterly reporting updates of new internal control and the status of the control regarding any exempted businesses. This guidance was reiterated in September 2007 to affirm that management may omit an assessment of an acquired business’s internal control over financial reporting from its assessment of internal control over financial reporting for a period not to exceed one year.

We have recommended to our Audit Committee that we exclude the operations acquired in the Davison Acquisition from the scope of our Sarbanes-Oxley Section 404 report on internal controls over financial reporting for the year ended December 31, 2007 which is due in February 2008. We are in the process of implementing of our internal control structure over the operations we acquired from the Davisons. Due to the magnitude of the businesses, we expect that this effort will be completed in 2008. The assessment and documentation of internal controls requires a complete review of controls operating in a stable and effective environment.

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Index to Financial Statements

PART II. OTHER INFORMATION

Item 1. Legal Proceedings.

See Part I. Item 1. Note 15 to the Consolidated Financial Statements entitled “Contingencies”, which is incorporated herein by reference.

Item 1A. Risk Factors.

Set forth below is a consolidated set of our “risk factors.” It consolidates in one place management’s current perception of our risk profile after taking into consideration changes in our portfolio, markets and organizational structure – as well as changes in the economy in general – that have occurred since we filed our Annual Report on Form 10-K relating to the year ended December 31, 2006 and our Quarterly Reports on Form 10-Q for the prior quarters in 2007 and our Periodic Reports on Form 8-K relating to calendar 2007.

Risks Related to Our Business

We may not be able to fully execute our growth strategy if we are unable to raise debt and equity capital at an affordable price.

Our strategy contemplates substantial growth through the development and acquisition of a wide range of midstream and other energy infrastructure assets while maintaining a strong balance sheet. This strategy includes constructing and acquiring additional assets and businesses to enhance our ability to compete effectively, diversify our asset portfolio and, thereby, provide more stable cash flow. We regularly consider and enter into discussions regarding, and are currently contemplating, additional potential joint ventures, stand-alone projects and other transactions that we believe will present opportunities to realize synergies, expand our role in the energy infrastructure business, and increase our market position and, ultimately, increase distributions to unitholders.

We will need new capital to finance the future development and acquisition of assets and businesses. Limitations on our access to capital will impair our ability to execute this strategy. Expensive capital will limit our ability to develop or acquire accretive assets. Although we intend to continue to expand our business, this strategy may require substantial capital, and we may not be able to raise the necessary funds on satisfactory terms, if at all.

In addition, we are experiencing increased competition for the assets we purchase or contemplate purchasing. Increased competition for a limited pool of assets could result in our not being the successful bidder more often or our acquiring assets at a higher relative price than that which we have paid historically. Either occurrence would limit our ability to fully execute our growth strategy. Our ability to execute our growth strategy may impact the market price of our securities.

We may not have sufficient cash from operations to pay the current level of quarterly distribution following the establishment of cash reserves and payment of fees and expenses, including payments to our general partner.

The amount of cash we distribute on our units principally depends upon margins we generate from our refinery services, pipeline transportation, logistics and supply and industrial gases businesses which will fluctuate from quarter to quarter based on, among other things:

•

the volumes and prices at which we purchase and sell crude oil, refined products, and caustic soda;

•

the volumes of sodium hydrosulfide, or NaHS, that we receive for our refinery services and the prices at which we sell NaHS;

•

the demand for our trucking and pipeline transportation services;

•

the volumes of CO₂ we sell and the prices at which we sell it;

•

the demand for our terminal storage services;

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Index to Financial Statements

•

the level of our operating costs;

•

the level of our general and administrative costs; and

•

prevailing economic conditions.

In addition, the actual amount of cash we will have available for distribution will depend on other factors that include:

•

the level of capital expenditures we make, including the cost of acquisitions (if any);

•

our debt service requirements;

•

fluctuations in our working capital;

•

restrictions on distributions contained in our debt instruments;

•

our ability to borrow under our working capital facility to pay distributions; and

•

the amount of cash reserves established by our general partner in its sole discretion in the conduct of our business.

Our ability to pay distributions each quarter depends primarily on our cash flow, including cash flow from financial reserves and working capital borrowings, and is not solely a function of profitability, which will be affected by non-cash items. As a result, we may make cash distributions during periods when we record losses and we may not make distributions during periods when we record net income.

Our indebtedness could adversely restrict our ability to operate, affect our financial condition, and prevent us from complying with our requirements under our debt instruments and could prevent us from paying cash to our unitholders.

We have outstanding indebtedness and the ability to incur more indebtedness. As of September 30, 2007, we had approximately $285 million outstanding of senior secured indebtedness.

We must comply with various affirmative and negative covenants contained in our credit facilities. Among other things, these covenants limit our ability to:

•

incur additional indebtedness or liens;

•

make payments in respect of or redeem or acquire any debt or equity issued by us;

•

sell assets;

•

make loans or investments;

•

make guarantees;

•

enter into any hedging agreement for speculative purposes;

•

acquire or be acquired by other companies; and

•

amend some of our contracts.

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Index to Financial Statements

The restrictions under our indebtedness may prevent us from engaging in certain transactions which might otherwise be considered beneficial to us and could have other important consequences to unitholders. For example, they could:

•

increase our vulnerability to general adverse economic and industry conditions;

•

limit our ability to make distributions; to fund future working capital, capital expenditures and other general partnership requirements; to engage in future acquisitions, construction or development activities; or to otherwise fully realize the value of our assets and opportunities because of the need to dedicate a substantial portion of our cash flow from operations to payments on our indebtedness or to comply with any restrictive terms of our indebtedness;

•

limit our flexibility in planning for, or reacting to, changes in our businesses and the industries in which we operate; and

•

place us at a competitive disadvantage as compared to our competitors that have less debt.

We may incur additional indebtedness (public or private) in the future, either under our existing credit facilities, by issuing debt instruments, under new credit agreements, under joint venture credit agreements, under capital leases or synthetic leases, on a project-finance or other basis, or a combination of any of these. If we incur additional indebtedness in the future, it likely would be under our existing credit facility or under arrangements which may have terms and conditions at least as restrictive as those contained in our existing credit facilities. Failure to comply with the terms and conditions of any existing or future indebtedness would constitute an event of default. If an event of default occurs, the lenders will have the right to accelerate the maturity of such indebtedness and foreclose upon the collateral, if any, securing that indebtedness. If an event of default occurs under our joint ventures’ credit facilities, we may be required to repay amounts previously distributed to us and our subsidiaries. In addition, if there is a change of control as described in our credit facility, that would be an event of default, unless our creditors agreed otherwise, under our credit facility, any such event could limit our ability to fulfill our obligations under our debt instruments and to make cash distributions to unitholders which could adversely affect the market price of our securities.

Our profitability and cash flow is dependent on our ability to increase or, at a minimum, maintain our current commodity - oil, refined products, NaHS, natural gas and CO₂ - volumes. We access commodity volumes through two sources, producers and service providers (including gatherers, shippers, marketers and other aggregators). Depending on the needs of each customer and the market in which it operates, we can either provide a service for a fee (as in the case of our pipeline transportation operations) or we can purchase the commodity from our customer and resell it to another party (as in the case of oil marketing and CO₂ operations).

Our source of volumes depends on successful exploration and development of additional oil and natural gas reserves by others and other matters beyond our control.

The oil, natural gas and other products available to us are derived from reserves produced from existing wells, which reserves naturally decline over time. In order to offset this natural decline, our energy infrastructure assets must access additional reserves. Additionally, some of the projects we have planned or recently completed are dependent on reserves that we expect to be produced from newly discovered properties that producers are currently developing.

Finding and developing new reserves is very expensive, requiring large capital expenditures by producers for exploration and development drilling, installing production facilities and constructing pipeline extensions to reach new wells. Many economic and business factors out of our control can adversely affect the decision by any producer to explore for and develop new reserves. These factors include the prevailing market price of the commodity, the

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Index to Financial Statements

capital budgets of producers, the depletion rate of existing reservoirs, the success of new wells drilled, environmental concerns, regulatory initiatives, cost and availability of equipment, capital budget limitations or the lack of available capital, and other matters beyond our control. Additional reserves, if discovered, may not be developed in the near future or at all. We cannot assure unitholders that production will rise to sufficient levels to allow us to maintain or increase the commodity volumes we are experiencing.

We face intense competition to obtain commodity volumes.

Our competitors—gatherers, transporters, marketers, brokers and other aggregators—include independents and major integrated energy companies, as well as their marketing affiliates, who vary widely in size, financial resources and experience. Some of these competitors have capital resources many times greater than ours and control substantially greater supplies of crude oil.

Even if reserves exist, or refined products are produced, in the areas accessed by our facilities, we may not be chosen by the producers or refiners to gather, refine, market, transport, store or otherwise handle any of these reserves, NaHS or refined products produced. We compete with others for any such volumes on the basis of many factors, including:

•

geographic proximity to the production;

•

costs of connection;

•

available capacity;

•

rates;

•

logistical efficiency in all of our operations;

•

operational efficiency in our refinery services business;

•

customer relationships; and

•

access to markets.

Additionally, third-party shippers do not have long-term contractual commitments to ship crude oil on our pipelines. A decision by a shipper to substantially reduce or cease to ship volumes of crude oil on our pipelines could cause a significant decline in our revenues. In Mississippi, we are dependent on interconnections with other pipelines to provide shippers with a market for their crude oil, and in Texas, we are dependent on interconnections with other pipelines to provide shippers with transportation to our pipeline. Any reduction of throughput available to our shippers on these interconnecting pipelines as a result of testing, pipeline repair, reduced operating pressures or other causes could result in reduced throughput on our pipelines that would adversely affect our cash flows and results of operations.

Fluctuations in demand for crude oil or availability of refined products or NaHS, such as those caused by refinery downtime or shutdowns, can negatively affect our operating results. Reduced demand in areas we service with our pipelines and trucks can result in less demand for our transportation services. In addition, certain of our field and pipeline operating costs and expenses are fixed and do not vary with the volumes we gather and transport. These costs and expenses may not decrease ratably or at all should we experience a reduction in our volumes transported by truck or transmitted by our pipelines. As a result, we may experience declines in our margin and profitability if our volumes decrease.

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Index to Financial Statements

Fluctuations in commodity prices could adversely affect our business.

Oil, natural gas, other petroleum products, and CO₂ prices are volatile and could have an adverse effect on our profits and cash flow. Our operations are affected by price reductions in those commodities. Price reductions in those commodities can cause material long and short term reductions in the level of throughput, volumes and margins in our logistic and supply businesses. Price changes for NaHS and caustic soda affect the margins we achieve in our refinery services business acquired from the Davison family.

Prices for commodities can fluctuate in response to changes in supply, market uncertainty and a variety of additional factors that are beyond our control.

Our operations are dependent upon demand for crude oil by refiners in the Midwest and on the Gulf Coast.

Any decrease in this demand for crude oil by the refineries or connecting carriers to which we deliver could adversely affect our business. Those refineries’ need for crude oil also is dependent on the competition from other refineries, the impact of future economic conditions, fuel conservation measures, alternative fuel requirements, government regulation or technological advances in fuel economy and energy generation devices, all of which could reduce demand for our services.

We are exposed to the credit risk of our customers in the ordinary course of our crude oil gathering and marketing activities.

When we market any of our products or services, we must determine the amount, if any, of the line of credit we will extend to any given customer. Since typical sales transactions can involve very large volumes, the risk of nonpayment and nonperformance by customers is an important consideration in our business. In those cases where we provide division order services for crude oil purchased at the wellhead, we may be responsible for distribution of proceeds to all parties. In other cases, we pay all of or a portion of the production proceeds to an operator who distributes these proceeds to the various interest owners. These arrangements expose us to operator credit risk. As a result, we must determine that operators have sufficient financial resources to make such payments and distributions and to indemnify and defend us in case of a protest, action or complaint. Even if our credit review and analysis mechanisms work properly, there can be no assurance that we will not experience losses in dealings with other parties.

Our operations are subject to federal and state environmental protection and safety laws and regulations

Our operations are subject to the risk of incurring substantial environmental and safety related costs and liabilities. In particular, our operations are subject to environmental protection and safety laws and regulations that restrict our operations, impose relatively harsh consequences for noncompliance, and require us to expend resources in an effort to maintain compliance. Moreover, the transportation and storage of crude oil and other commodities involves a risk that crude oil and related hydrocarbons or other by-products may be released into the environment, which may result in substantial expenditures for a response action, significant government penalties, liability to government agencies for natural resources damages, liability to private parties for personal injury or property damages, and significant business interruption. These costs and liabilities could rise under increasingly strict environmental and safety laws, including regulations and enforcement policies, or claims for damages to property or persons resulting from our operations. If we are unable to recover such resulting costs through increased rates or insurance reimbursements, our cash flows and distributions to our unitholders could be materially affected.

FERC Regulation and a changing regulatory environment could affect our cash flow.

The FERC extensively regulates certain of our energy infrastructure assets engaged in interstate operations. Our intrastate pipeline operations are regulated by state agencies. This regulation extends to such matters as:

•

rate structures;

•

rates of return on equity;

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Index to Financial Statements

•

recovery of costs;

•

the services that our regulated assets are permitted to perform;

•

the acquisition, construction and disposition of assets; and

•

to an extent, the level of competition in that regulated industry.

Given the extent of this regulation, the extensive changes in FERC policy over the last several years, the evolving nature of federal and state regulation and the possibility for additional changes, the current regulatory regime may change and affect our financial position, results of operations or cash flows.

Our CO₂ operations primarily relate to our volumetric production payment interests, which are a finite resource and projected to deplete around 2016.

The cash flow from our CO₂ operations primarily relates to our volumetric production payments, which are projected to terminate around 2016. Unless we are able to obtain a replacement supply of CO₂ and enter into sales arrangements that generate substantially similar economics, our cash flow could decline significantly around 2016.

Our CO₂ operations are exposed to risks related to Denbury’s operation of their CO₂ fields, equipment and pipeline

Because Denbury Resources produces the CO₂ and transports the CO₂ to our customers, any major failure of its operations could have an impact on our ability to meet our obligations to our CO₂ customers. We have no other supply of CO₂ or method to transport it to our customers. Sandhill relies on us for its supply of CO₂ therefore our share of the earnings of Sandhill would also be impacted by any major failure of Denbury’s operations.

The CO₂ supplied by Denbury Resources to us for our sale to our customers could fail to meet the quality standards in the contracts due to impurities or water vapor content. If the CO₂ were below specifications, we could be contractually obligated to provide compensation to our customers for the costs incurred in raising the CO₂ quality to serviceable levels required by our contracts.

Fluctuations in demand for CO₂ by our industrial customers could materially adversely impact our profitability, results of operations and cash available for distribution.

Our customers are not obligated to purchase volumes in excess of specified minimum amounts in our contracts. As a result, fluctuations in our customers’ demand due to market forces or operational problems could result in a reduction in our revenues from our sales of CO₂.

Our wholesale CO₂ industrial operations are dependent on five customers and our syngas operations are dependent on one customer.

If one or more of those customers experience financial difficulties such that they fail to purchase their required minimum take-or-pay volumes, our cash flows could be adversely affected, and we cannot assure unitholders that an unanticipated deterioration in their ability to meet their obligations to us might not occur.

Our Syngas joint venture has dedicated 100% of its syngas processing capacity to one customer pursuant to a processing contract. The contract term expires in 2016, unless our customer elects to extend the contract for two additional five year terms. If our customer reduces or discontinues its business with us, or if we are not able to successfully negotiate a replacement contract with our sole customer after the expiration of such contract, or if the replacement contract is on less favorable terms, the effect on us will be adverse. In addition, if our sole customer for syngas processing were to experience financial difficulties such that it failed to provide volumes to process, our cash flow from the syngas joint venture could be adversely affected. We believe this customer is creditworthy, but we cannot assure unitholders that unanticipated deterioration of their abilities to meet their obligations to the syngas joint venture might not occur.

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Index to Financial Statements

Our refinery services division is dependent on contracts with less than fifteen refineries and we rely on a few refineries for much of our NaHS supply, with ConocoPhillips representing approximately 65% of the volume of NaHS produced as a by-product of our refinery services business.

If one or more of our refinery customers experience financial difficulties or changes in their strategy for sulfur removal such that they do not need our services, our cash flows could be adversely affected and we cannot assure unitholders that an unanticipated reduction in the need for our services might not occur.

In 2006, approximately 65% of the volume of NaHS that was produced as a byproduct of the refinery service by our predecessor in interest was attributable to Conoco’s refinery located in Westlake, Louisiana. Although the primary term of that contract extends until 2018, if Conoco is excused from performing, or refuses or is unable to perform, its obligations under that contract for an extended period of time, such non-performance could materially adversely affect our profitability and cash flow. That contract requires Conoco to make minimum annual payments to us (whether or not its hydrocarbon stream contains sulfur) except during periods of force majeures or turnarounds. In addition, if Conoco closes that refinery it can pay us a discounted lump sum amount in lieu of making the minimum annual payments.

Our growth strategy may adversely affect our results of operations if we do not successfully integrate the businesses that we acquire or if we substantially increase our indebtedness and contingent liabilities to make acquisitions.

We may be unable to integrate successfully businesses we acquire. We may incur substantial expenses, delays or other problems in connection with our growth strategy that could negatively impact our results of operations. Moreover, acquisitions and business expansions involve numerous risks, including:

•

difficulties in the assimilation of the operations, technologies, services and products of the acquired companies or business segments;

•

inefficiencies and complexities that can arise because of unfamiliarity with new assets and the businesses associated with them, including unfamiliarity with their markets; and

•

diversion of the attention of management and other personnel from day-to-day business to the development or acquisition of new businesses and other business opportunities.

If consummated, any acquisition or investment also likely would result in the incurrence of indebtedness and contingent liabilities and an increase in interest expense and depreciation, depletion and amortization expenses. A substantial increase in our indebtedness and contingent liabilities could have a material adverse effect on our business, as discussed above.

Our actual construction, development and acquisition costs could exceed our forecast, and our cash flow from construction and development projects may not be immediate.

Our forecast contemplates significant expenditures for the development, construction or other acquisition of energy infrastructure assets, including some construction and development projects with technological challenges. We may not be able to complete our projects at the costs currently estimated. If we experience material cost overruns, we will have to finance these overruns using one or more of the following methods:

•

using cash from operations;

•

delaying other planned projects;

•

incurring additional indebtedness; or

•

issuing additional debt or equity.

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Index to Financial Statements

Any or all of these methods may not be available when needed or may adversely affect our future results of operations.

Fluctuations in interest rates could adversely affect our business.

In addition to our exposure to commodity prices, we also have exposure to movements in interest rates. The interest rates on our credit facility are variable. Our results of operations and our cash flow, as well as our access to future capital and our ability to fund our growth strategy, could be adversely affected by significant increases or decreases in interest rates.

Our use of derivative financial instruments could result in financial losses.

We use financial derivative instruments and other hedging mechanisms from time to time to limit a portion of the adverse effects resulting from changes in commodity prices, although there are times when we do not have any hedging mechanisms in place. To the extent we hedge our commodity price exposure, we forego the benefits we would otherwise experience if commodity prices were to increase. In addition, we could experience losses resulting from our hedging and other derivative positions. Such losses could occur under various circumstances, including if our counterparty does not perform its obligations under the hedge arrangement, our hedge is imperfect, or our hedging policies and procedures are not followed.

A natural disaster, catastrophe, terrorist attack or other interruption event involving us could result in severe personal injury, property damage and/or environmental damage, which could curtail our operations and otherwise adversely affect our assets and cash flow.

Some of our operations involve higher risks of severe personal injury, property damage and environmental damage, any of which could curtail our operations and otherwise expose us to liability and adversely affect our cash flow. Virtually all of our operations are exposed to the elements, including hurricanes, tornadoes, storms, floods and earthquakes.

If one or more facilities that are owned by us or that connect to us is damaged or otherwise affected by severe weather or any other disaster, accident, catastrophe or event, our operations could be significantly interrupted. Similar interruptions could result from damage to production or other facilities that supply our facilities or other stoppages arising from factors beyond our control. These interruptions might involve significant damage to people, property or the environment, and repairs might take from a week or less for a minor incident to six months or more for a major interruption. Any event that interrupts the fees generated by our energy infrastructure assets, or which causes us to make significant expenditures not covered by insurance, could reduce our cash available for paying our interest obligations as well as unitholder distributions and, accordingly, adversely impact the market price of our securities. Additionally, the proceeds of any property insurance maintained by us may not be paid in a timely manner or be in an amount sufficient to meet our needs if such an event were to occur, and we may not be able to renew it or obtain other desirable insurance on commercially reasonable terms, if at all.

On September 11, 2001, the United States was the target of terrorist attacks of unprecedented scale. Since the September 11 attacks, the U.S. government has issued warnings that energy assets, specifically the nation’s pipeline infrastructure, may be the future targets of terrorist organizations. These developments have subjected our operations to increased risks. Any future terrorist attack at our facilities, those of our customers and, in some cases, those of other pipelines, could have a material adverse effect on our business.

We cannot cause our joint ventures to take or not to take certain actions unless some or all of the joint venture participants agree.

Due to the nature of joint ventures, each participant (including us) in our joint ventures has made substantial investments (including contributions and other commitments) in that joint venture and, accordingly, has required that the relevant charter documents contain certain features designed to provide each participant with the opportunity to participate in the management of the joint venture and to protect its investment in that joint venture, as well as any other assets which may be substantially dependent on or otherwise affected by the activities of that joint venture.

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Index to Financial Statements

These participation and protective features include a corporate governance structure that consists of a management committee composed of four members, only two of which are appointed by us. In addition, the other 50% owner in each of our joint ventures operates the joint venture facilities. Thus, without the concurrence of the other joint venture participant, we cannot cause our joint ventures to take or not to take certain actions, even though those actions may be in the best interest of the joint ventures or us.

Our refinery services operations are dependent upon the supply of caustic soda and the demand for NaHS, as well as the operations of the refiners for whom we process sour gas.

Caustic soda is a major component used in the provision of sour gas treatment services provided by us to refineries. NaHS, the resulting product from the refinery services we provide, is a vital ingredient in a number of industrial and consumer products and processes. Any decrease in the supply of caustic soda could affect our ability to provide sour gas treatment services to refiners and any decrease in the demand for NaHS by the parties to whom we sell the NaHS could adversely affect our business. The refineries’ need for our sour gas services is also dependent on the competition from other refineries, the impact of future economic conditions, fuel conservation measures, alternative fuel requirements, government regulation or technological advances in fuel economy and energy generation devices, all of which could reduce demand for our services.

Our operating results from trucking operations acquired from the Davison family may fluctuate and may be materially adversely affected by economic conditions and business factors unique to the trucking industry.

Our trucking business is dependent upon factors, many of which are beyond our control. Those factors include excess capacity in the trucking industry, difficulty in attracting and retaining qualified drivers, significant increases or fluctuations in fuel prices, fuel taxes, license and registration fees and insurance and claims costs, to the extent not offset by increases in freight rates. Our results of operations from our trucking operations also are affected by recessionary economic cycles and downturns in customers’ business cycles. Economic and other conditions may adversely affect our trucking customers and their ability to pay for our services.

In the past, there have been shortages of drivers in the trucking industry and such shortages may occur in the future. Periodically, the trucking industry experiences substantial difficulty in attracting and retaining qualified drivers. If we are unable to continue to retain and attract drivers, we could be required to adjust our driver compensation package, let trucks sit idle or otherwise operate at a reduced level, which could adversely affect our operations and profitability.

Significant increases or rapid fluctuations in fuel prices are major issues for the transportation industry. Increases in fuel costs, to the extent not offset by rate per mile increases or fuel surcharges, have an adverse effect on our operations and profitability.

Denbury is the only shipper (other than us) on our Mississippi System.

Denbury Resources is our only customer on the Mississippi System. This relationship may subject our operations to increased risks. Any adverse developments concerning Denbury Resources could have a material adverse effect on our Mississippi System business. Neither our partnership agreement nor any other agreement requires Denbury Resources to pursue a business strategy that favors us or utilizes our Mississippi System. Denbury Resources may compete with us and may manage their assets in a manner that could adversely affect our Mississippi System business.

Risks Related to Our Partnership Structure

Denbury Resources and its affiliates have conflicts of interest with us and limited fiduciary responsibilities, which may permit them to favor their own interests to unitholder detriment.

Denbury Resources indirectly owns and controls our general partner. Conflicts of interest may arise between Denbury Resources and its affiliates, including our general partner, on the one hand, and us and our unitholders, on the other hand. As a result of these conflicts, our general partner may favor its own interest and the interest of its

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Index to Financial Statements

affiliates or others over the interest of our unitholders. These conflicts include, among others, the following situations:

•

neither our partnership agreement nor any other agreement requires Denbury Resources to pursue a business strategy that favors us or utilizes our assets. Denbury Resources’ directors and officers have a fiduciary duty to make these decisions in the best interest of the stockholders of Denbury Resources;

•

Denbury Resources may compete with us. Denbury Resources owns the largest reserves of CO₂ used for tertiary oil recovery east of the Mississippi River and may manage these reserves in a manner that could adversely affect our CO₂ business;

•

our general partner is allowed to take into account the interest of parties other than us, such as Denbury Resources, in resolving conflicts of interest;

•

our general partner may limit its liability and reduce its fiduciary duties, while also restricting the remedies available to our unitholders for actions that, without the limitations, might constitute breaches of fiduciary duty;

•

our general partner determines the amount and timing of asset purchases and sales, capital expenditures, borrowings, including for incentive distributions, issuance of additional partnership securities, reimbursements and enforcement of obligations to the general partner and its affiliates, retention of counsel, accountants and service providers, and cash reserves, each of which can also affect the amount of cash that is distributed to our unitholders;

•

our general partner determines which costs incurred by it and its affiliates are reimbursable by us and the reimbursement of these costs and of any services provided by our general partner could adversely affect our ability to pay cash distributions to our unitholders;

•

our general partner controls the enforcement of obligations owed to us by our general partner and its affiliates;

•

our general partner decides whether to retain separate counsel, accountants or others to perform services for us; and

•

in some instances, our general partner may cause us to borrow funds in order to permit the payment of distributions even if the purpose or effect of the borrowing is to make incentive distributions.

Denbury is not obligated to enter into any transactions with (or to offer any opportunities to) us, although we expect to continue to enter into substantial transactions and other activities with Denbury Resources and its subsidiaries because of the businesses and areas in which we and Denbury Resources currently operate, as well as those in which we plan to operate in the future. Denbury has expressed indications of interest in selling to us (and entering into arrangements under which Denbury would have the exclusive right to utilize) specified CO₂ infrastructure assets, including some that have not yet been placed in-service, subject to the satisfaction of certain conditions. Those conditions include the negotiation of material terms, the execution of definitive agreements, the existence of adequate credit support and our acquisition (by construction and purchase) of assets that are not related to Denbury’s operations in an amount at least equal to 150% of the amount of new acquisitions or financings we complete with Denbury. Some more recent transactions in which we, on the one hand, and Denbury Resources and its subsidiaries, on the other hand, had a conflict of interest include:

•

transportation services

•

pipeline monitoring services; and

•

CO₂ volumetric production payment.

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Index to Financial Statements

In addition, Denbury Resources’ beneficial ownership interest in our outstanding partnership interests could have a substantial effect on the outcome of some actions requiring partner approval. Accordingly, subject to legal requirements, Denbury Resources makes the final determination regarding how any particular conflict of interest is resolved.

Even if unitholders are dissatisfied, they cannot easily remove our general partner.

Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business.

Unitholders did not elect our general partner or its board of directors and will have no right to elect our general partner or its board of directors on an annual or other continuing basis. The board of directors of our general partner is chosen by the stockholders of our general partner. In addition, if the unitholders are dissatisfied with the performance of our general partner, they will have little ability to remove our general partners. As a result of these limitations, the price at which the common units trade could be diminished because of the absence or reduction of a takeover premium in the trading price.

The vote of the holders of at least a majority of all outstanding units (excluding any units held by our general partner and its affiliates) is required to remove the general partner without cause. If our general partner is removed without cause, (i) Denbury Resources will have the option to acquire a substantial portion of our Mississippi pipeline system at 110% of its then fair market value, and (ii) our general partner will have the option to convert its interest in us (other than its common units) into common units or to require our replacement general partner to purchase such interest for cash at its then fair market value. In addition, unitholders’ voting rights are further restricted by our partnership agreement provision providing that any units held by a person that owns 20% or more of any class of units then outstanding, other than the general partner, its affiliates, their transferees, and persons who acquired such units with the prior approval of the board of directors of the general partner, cannot vote on any matter. Our partnership agreement also contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting the unitholders’ ability to influence the manner of direction of management.

As a result of these provisions, the price at which our common units trade may be lower because of the absence or reduction of a takeover premium.

The control of our general partner may be transferred to a third party without unitholder consent, which could affect our strategic direction and liquidity.

Our general partner may transfer its general partner interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of the unitholders. Furthermore, there is no restriction in our partnership agreement on the ability of the owner of our general partner from transferring its ownership interest in the general partner to a third party. The new owner of the general partner would then be in a position to replace the board of directors and officers of the general partner with its own choices and to control the decisions taken by the board of directors and officers.

In addition, unless our creditors agreed otherwise, we would be required to repay the amounts outstanding under our credit facilities upon the occurrence of any change of control described therein. We may not have sufficient funds available or be permitted by our other debt instruments to fulfill these obligations upon such occurrence. A change of control could have other consequences to us depending on the agreements and other arrangements we have in place from time to time, including employment compensation arrangements.

Our general partner and its affiliates may sell units or other limited partner interests in the trading market, which could reduce the market price of common units.

As of September 30, 2007 our general partner and its affiliates own 2,094,323 (approximately 7.4%) of our common units. In the future, they may acquire additional interest or dispose of some or all of their interest. If they dispose of a substantial portion of their interest in the trading markets, the sale could reduce the market price of

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Index to Financial Statements

common units. Our partnership agreement, and other agreements to which we are party, allow our general partner and certain of its subsidiaries to cause us to register for sale the partnership interests held by such persons, including common units. These registration rights allow our general partner and its subsidiaries to request registration of those partnership interests and to include any of those securities in a registration of other capital securities by us.

Our general partner has anti-dilution rights.

Whenever we issue equity securities to any person other than our general partner and its affiliates, our general partner and its affiliates have the right to purchase an additional amount of those equity securities on the same terms as they are issued to the other purchasers. This allows our general partner and its affiliates to maintain their percentage partnership interest in us. No other unitholder has a similar right. Therefore, only our general partner may protect itself against dilution caused by the issuance of additional equity securities.

Due to our significant relationships with Denbury, adverse developments concerning Denbury could adversely affect us, even if we have not suffered any similar developments.

Through its subsidiaries, Denbury Resources owns 100 percent of our general partner and has historically, with its affiliates, employed the personnel who operate our businesses. Denbury Resources is a significant stakeholder in our limited partner interests, and as with many other energy companies, is a significant customer of ours.

We may issue additional common units without unitholder’s approval, which would dilute their ownership interests.

We may issue an unlimited number of limited partner interests of any type without the approval of our unitholders.

The issuance of additional common units or other equity securities of equal or senior rank will have the following effects:

•

our unitholders’ proportionate ownership interest in us will decrease;

•

the amount of cash available for distribution on each unit may decrease;

•

the relative voting strength of each previously outstanding unit may be diminished; and

•

the market price of our common units may decline.

Our general partner has a limited call right that may require unitholders to sell their common units at an undesirable time or price.

If at any time our general partner and its affiliates own more than 80% of the common units, our general partner will have the right, but not the obligation, which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price not less than their then-current market price. As a result, unitholders may be required to sell their common units at an undesirable time or price and may not receive any return on their investment. Unitholders may also incur a tax liability upon a sale of their units.

The interruption of distributions to us from our subsidiaries and joint ventures may affect our ability to make payments on indebtedness or cash distributions to our unitholders.

We are a holding company. As such, our primary assets are the equity interests in our subsidiaries and joint ventures. Consequently, our ability to fund our commitments (including payments on our indebtedness) and to make cash distributions depends upon the earnings and cash flow of our subsidiaries and joint ventures and the distribution of that cash to us. Distributions from our joint ventures are subject to the discretion of their respective management committees. Further, each joint venture’s charter documents typically vest in its management committee sole discretion regarding distributions. Accordingly, our joint ventures may not continue to make distributions to us at current levels or at all.

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Index to Financial Statements

We do not have the same flexibility as other types of organizations to accumulate cash and equity to protect against illiquidity in the future.

Unlike a corporation, our partnership agreement requires us to make quarterly distributions to our unitholders of all available cash reduced by any amounts reserved for commitments and contingencies, including capital and operating costs and debt service requirements. The value of our units and other limited partner interests will decrease in direct correlation with decreases in the amount we distribute per unit. Accordingly, if we experience a liquidity problem in the future, we may not be able to issue more equity to recapitalize.

Tax Risks to Common Unitholders

Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as out not being subject to a material amount of entity-level taxation by individual states. A publicly-traded partnership can lose its status as a partnership for a number of reasons, including not having enough “qualifying income.” If the IRS were to treat us as a corporation or if we were to become subject to a material amount of entity-level taxation for state tax purposes, then our cash available for distribution to unitholders would be substantially reduced.

The anticipated after-tax economic benefit of an investment in us depends largely on our being treated as a partnership for federal income tax purposes. Section 7704 of the Internal Revenue Code provides that publicly traded partnerships will, as a general rule, be taxed as corporations. However, an exception, referred to in this discussion as the “Qualifying Income Exception,” exists with respect to publicly traded partnerships 90% or more of the gross income of which for every taxable year consists of “qualifying income.” If less than 90% of our gross income for any taxable year is “qualifying income” from transportation or processing of natural resources including crude oil, natural gas or products thereof, interest, dividends or similar sources, we will be taxable as a corporation under Section 7704 of the Internal Revenue Code for federal income tax purposes for that taxable year and all subsequent years.

In addition, current law may change so as to cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to entity-level taxation. For example, in response to certain recent developments, members of Congress are considering substantive changes to the definition of qualifying income under Internal Revenue Code section 7704(d). It is possible that these efforts could result in changes to the existing U.S. tax laws that affect publicly-traded partnerships, including us. We are unable to predict whether any of these changes or other proposals will ultimately be enacted. Any such changes could negatively impact the value of an investment in our common units. In addition, because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. Imposition of any such taxes may substantially reduce the cash available for distribution to our unitholders.

A successful IRS contest of the federal income tax positions we take may adversely affect the market for our common units, and the cost of any IRS contest will reduce our cash available for distribution to our unitholders and our general partner.

We have not requested a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes or any other matter affecting us. The IRS may adopt positions that differ from the conclusions of our counsel expressed in this prospectus or from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of our counsel’s conclusions or the positions we take. A court may not agree with some or all of our counsel’s conclusions or positions we take. Any contest with the IRS may materially and adversely impact the market for our common units and the price at which they trade. In addition, our costs of any contest with the IRS will be borne indirectly by our unitholders and our general partner, and these costs will reduce our cash available for distribution.

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Index to Financial Statements

Unitholders will be required to pay taxes on income from us even if they do not receive any cash distributions from us.

Unitholders will be required to pay any federal income taxes and, in some cases, state and local income taxes on their share of our taxable income even if unitholders receive no cash distributions from us. Unitholders may not receive cash distributions from us equal to their share of our taxable income or even the tax liability that results from that income.

Tax gain or loss on disposition of common units could be different than expected.

If unitholders sell their common units, they will recognize a gain or loss equal to the difference between the amount realized and their tax basis in those common units. Prior distributions to unitholders in excess of the total net taxable income unitholders were allocated for a common unit, which decreased their tax basis in that common unit, will, in effect, become taxable income to unitholders if the common unit is sold at a price greater than their tax basis in that common unit, even if the price is less than their original cost. A substantial portion of the amount realized, whether or not representing gain, may be ordinary income. In addition, if unitholders sell their units, they may incur a tax liability in excess of the amount of cash they receive from the sale.

Tax-exempt entities and foreign persons face unique tax issues from owning common units that may result in adverse tax consequences to them.

Investment in common units by tax-exempt entities, such as individual retirement accounts (known as IRAs), and non-U.S. persons raises issues unique to them. For example, a significant amount of our income allocated to organizations exempt from federal income tax, including individual retirement accounts and other retirement plans, may be unrelated business taxable income and will be taxable to such a unitholder. Distributions to non-U.S. persons will be reduced by withholding tax at the highest effective tax rate applicable to individuals, and non-U.S. person will be required to file federal income tax returns and pay tax on their share of our taxable income.

We registered as a tax shelter under prior law. This may increase the risk of an IRS audit of us or a unitholder.

Prior to the enactment of the American Jobs Creation Act of 2004, certain types of entities were required to register with the IRS as “tax shelters,” based on a perception that those entities might claim tax benefits that were unwarranted. We registered as a tax shelter under such prior law. The American Jobs Creation Act of 2004 repealed the tax shelter registration requirement and replaced it with a regime that requires reporting, and will likely require registration, of certain “reportable transactions.” We do not expect to engage in any reportable transactions. Nevertheless, our registration as a tax shelter under prior law, or our future participation in a reportable transaction, might increase the likelihood that we will be audited, and any such audit might lead to tax adjustments.

Should our tax returns be audited, any adjustments to our tax returns may lead to adjustments to our unitholders’ tax returns and may lead to audits of unitholders’ tax returns. Our unitholders’ would be responsible for the consequences of any audits to their tax returns.

We will treat each purchaser of common units as having the same tax benefits without regard to the actual common units purchased. The IRS may challenge this treatment, which could adversely affect the value of our common units.

Because we cannot match transferors and transferees of common units, we adopt depreciation and amortization positions that may not conform with all aspects of applicable Treasury regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to a common unitholder. It also could affect the timing of these tax benefits or the amount of gain from a sale of common units and could have a negative impact on the value of the common units or result in audit adjustments to the common unitholder’s tax returns.

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Index to Financial Statements

Unitholders will likely be subject to state and local taxes in states where they do not live as a result of an investment in the common units.

In addition to federal income taxes, unitholders will likely be subject to other taxes, including foreign, state and local taxes, unincorporated business taxes and estate inheritance or intangible taxes that are imposed by the various jurisdictions in which we do business or own property, even if unitholders do not live in any of those jurisdictions. Unitholders will likely be required to file foreign, state and local income tax returns and pay state and local income taxes in some or all of these jurisdictions. Further, unitholders may be subject to penalties for failure to comply with those requirements. We own assets and do business in more than 25 states including Texas, Louisiana, Mississippi, Alabama, Florida, Arkansas and Oklahoma. Many of the states we currently do business in currently impose a personal income tax. It is unitholders’ responsibility to file all United States federal, foreign, state and local tax returns. Our counsel has not rendered an opinion on the state or local tax consequences of an investment in our common units.

We have subsidiaries that are treated as corporations for federal income tax purposes and subject to corporate-level income taxes.

We conduct a portion of our operations through subsidiaries that are, or are treated as, corporations for federal income tax purposes. We may elect to conduct additional operations in corporate form in the future. These corporate subsidiaries will be subject to corporate-level tax, which will reduce the cash available for distribution to us and, in turn, to our unitholders. If the IRS were to successfully assert that these corporate subsidiaries have more tax liability than we anticipate or legislation was enacted that increased the corporate tax rate, our cash available for distribution to our unitholders would be further reduced.

We have adopted certain valuation methodologies that may result in a shift of income, gain, loss and deduction between the general partner and the unitholders. The IRS may challenge this treatment, which could adversely affect the value of the common units.

When we issue additional common units or engage in certain other transactions, we determine the fair market value of our assets and allocate any unrealized gain or loss attributable to our assets to the capital accounts of our unitholders and our general partner. Our methodology may be viewed as understating the value of our assets. In that case, there may be a shift of income, gain, loss and deduction between certain unitholders and the general partner, which may be unfavorable to such unitholders. Moreover, subsequent purchasers of common units may have a greater portion of their Internal Revenue Code Section 743(b) adjustment allocated to our tangible assets and a lesser portion allocated to out intangible assets. The IRS may challenge our methods, or our allocation of the Section 743(b) adjustment attributable our tangible and intangible assets, and allocations of income, gain, loss and deduction between the general partner and certain of our unitholders.

A successful IRS challenge to these methods or allocations could adversely affect the amount of taxable income or loss being allocated to our unitholders. It also could affect the amount of gain from a unitholder’s sale of common units and could have a negative impact on the value of the common units or result in audit adjustments to the unitholder’s tax returns.

The sale or exchange of 50% or more of our capital and profits interests during any twelve-month period will result in the termination of our partnership for federal income tax purposes.

We will be considered to have terminated for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. Our termination would, among other things, result in the closing of our taxable year for all unitholders, which would result in us filing two tax returns (and unitholders receiving two Schedule K-1’s) for one fiscal year. Our termination could also result in a deferral of depreciation deductions allowable in computing our taxable income. In the case of a common unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of our taxable year may result in more than twelve months of our taxable income or loss being includable in his taxable income for the year of termination. Our termination currently would not affect our classification as a partnership for federal income tax purposes, but instead, we would be treated as a new partnership for tax purposes. If treated as a new partnership, we must make new tax elections and could be subject to penalties if we are unable to determine that a termination occurred.

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Item 2. Unregistered Sales of Equity Securities and Use of Proceeds.

On July 25, 2007, we issued 13,459,209 of our common units to entities owned and controlled by the Davison family. The units were issued at a negotiated value of $20.8036 per unit, for a total value of $280 million as a portion of the consideration for the acquisition of the energy-related business of the Davison family. (For financial reporting purposes, the units are valued at $24.52 per unit. See Note 3 to the Consolidated Financial Statements.) Additionally, our general partner exercised its right to maintain its proportionate share of our outstanding common units by purchasing 1,074,882 common units from us for $22.4 million cash, or $20.8036 per common unit. As a result of this purchase, our general partner will continue to hold 7.4% of our outstanding common units. These sales of common units by us were completed on July 25, 2007 and were exempt from registration under the Securities Act of 1933 by reason of Section 4(2) thereof and Rule 506 of Regulation D promulgated thereunder.

See Note 3, 8 and 9 of the Notes to the Unaudited Consolidated Financial Statements.

Item 3. Defaults Upon Senior Securities.

None.

Item 4. Submission of Matters to a Vote of Security Holders.

None.

Item 5. Other Information.

None.

Item 6. Exhibits.

(a) Exhibits.



		10.1				Contribution and Sale Agreement by and among Davison Petroleum Products, L.L.C., Davison Transport, Inc., Transport Company, Davison Terminal Service, Inc., Sunshine Oil & Storage, Inc., T&T Chemical, Inc. Fuel Masters, LLC, TDC, L.L.C. and Red River Terminals, L.L.C. dated April 25, 2007 (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K of Genesis Energy, L.P. filed on July 31, 2007, File No. 001-12295).

		10.2				Amendment No. 1 to the Contribution and Sale Agreement dated July 25, 2007 (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K of Genesis Energy, L.P. filed on July 31, 2007, File No. 001-12295.

		10.3				Registration Rights Agreement (incorporated by reference to Exhibit 10.3 to the Current Report on Form 8-K of Genesis Energy, L.P. filed on July 31, 2007, File No. 001-12295.

		10.4				Unitholder Rights Agreement (incorporated by reference to Exhibit 10.4 to the Current Report on Form 8-K of Genesis Energy, L.P. filed on July 31, 2007, File No. 001-12295.

		10.5				Pledge and Security Agreement (incorporated by reference to Exhibit 10.5 to the Current Report on Form 8-K of Genesis Energy, L.P. filed on July 31, 2007, File No. 001-12295.

		10.6				First Amendment to Credit Agreement and Guarantee and Collateral Agreement dated as of July 25, 2007 among Genesis Crude Oil, L.P., Genesis Energy, L.P. and the Lenders, Issuing Banks and Guarantors (incorporated by reference to Exhibit 10.6 to the Current Report on Form 8-K of Genesis Energy, L.P. filed on July 31, 2007, File No. 001-12295.

		10.7				Amendment No. 2 to the Contribution and Sale Agreement dated October 15, 2007 (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K of Genesis Energy, L.P. filed on October 19, 2007, File No. 001-12295.

		10.8				Amendment No. 1 to the Unitholder Rights Agreement dated October 15, 2007 (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K of Genesis Energy, L.P. filed on October 19, 2007, File No. 001-12295.

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31.1	*	Certification by Chief Executive Officer Pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934

31.2	*	Certification by Chief Financial Officer Pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934

32.1	*	Certification by Chief Executive Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

32.2	*	Certification by Chief Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

*	Filed herewith

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.


		GENESIS ENERGY, L.P. (A Delaware Limited Partnership)
	By:	GENESIS ENERGY, INC., as General Partner
Date: November 9, 2007	By:	/s/ ROSS A. BENAVIDES
		Ross A. Benavides Chief Financial Officer

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