Genesis Energy (GEL) 8-K Other Events

Exhibit 99.2

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

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

• Overview of 2008

• Available Cash before Reserves

• Acquisitions in 2008

• Results of Operations

• Significant Events

• Capital Resources and Liquidity

• Commitments and Off-Balance Sheet Arrangements

• Critical Accounting Policies and Estimates

• Recent Accounting Pronouncements

In the discussions that follow, we will focus on two measures that we use to manage the business and to review the results of our operations. Those two measures are segment margin and Available Cash before Reserves. During the fourth quarter of 2008, we revised the manner in which we internally evaluate our segment performance. As a result, we changed our definition of segment margin to include within segment margin all costs that are directly associated with a business segment. Segment margin now includes costs such as general and administrative expenses that are directly incurred by a business segment. Segment margin also includes all payments received under direct financing leases. In order to improve comparability between periods, we exclude from segment margin the non-cash effects of our stock-based compensation plans which are impacted by changes in the market price for our common units. Previous periods have been restated to conform to this segment presentation. We now define segment margin as revenues less cost of sales, operating expenses (excluding depreciation and amortization), and segment general and administrative expenses, plus our equity in distributable cash generated by our joint ventures. In addition, our segment margin definition excludes the non-cash effects of our stock-based compensation plans, and includes the non-income portion of payments received under direct financing leases. Our chief operating decision maker (our Chief Executive Officer) evaluates segment performance based on a variety of measures including segment margin, segment volumes where relevant, and maintenance capital investment. A reconciliation of segment margin to income from before income taxes is included in our segment disclosures in Note 12 to the consolidated financial statements.

Available Cash before Reserves (a non-GAAP measure) is net income as adjusted for specific items, the most significant of which are the addition of non-cash expenses (such as depreciation), the substitution of cash generated by our joint ventures in lieu of our equity income attributable to our joint ventures, the elimination of gains and losses on asset sales (except those from the sale of surplus assets) and the subtraction of maintenance capital expenditures, which are expenditures that are necessary to sustain existing (but not to provide new sources of) cash flows. For additional information on Available Cash before Reserves and a reconciliation of this measure to cash flows from operations, see “Liquidity and Capital Resources - Non-GAAP Financial Measure” below.

Overview of 2008

In 2008, we reported net income attributable to Genesis Energy, L.P. of $26.1 million, or $0.59 per common unit. Non-cash depreciation and amortization totaling $71.4 million reduced net income attributable to Genesis Energy, L.P. during the year. See additional discussion of our depreciation and amortization expense in “Results of Operations – Other Costs and Interest” below.

Segment margin for all of our operating segments increased in 2008. The acquisitions of the Davison family business in July 2007, the two drop down transactions with Denbury in May 2008 and the acquisition in July 2008 of our interest in DG Marine which owns the inland marine transportation business of Grifco were the primary factors contributing to this improvement. During 2008, we continued to integrate these acquisitions with our existing operations.

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Increases in cash flow generally result in increases in Available Cash before Reserves, from which we pay distributions quarterly to holders of our common units and our general partner. During 2008, we generated $89.8 million of Available Cash before Reserves, and we distributed $50.5 million to holders of our common units and general partner. Cash provided by operating activities in 2008 was $94.8 million. Our total distributions attributable to 2008 increased 109% over the total distributions attributable to 2007.

Additionally, on January 8, 2009, we declared our fourteenth consecutive increase in our quarterly distribution to our common unitholders relative to the fourth quarter of 2008. This distribution of $0.33 per unit (paid in February 2009) represents a 16% increase from our distribution of $0.285 per unit for the fourth quarter of 2007. During the fourth quarter of 2008, we paid a distribution of $0.3225 per unit related to the third quarter of 2008.

The current economic crisis has restricted the availability of credit and access to capital in our business environment. Despite efforts by treasury and banking regulators to provide liquidity to the financial sector, capital markets continue to remain constrained. While we anticipate that the challenging economic environment will continue for the foreseeable future, we believe that our current cash balances, future internally-generated funds and funds available under our credit facility will provide sufficient resources to meet our current working capital liquidity needs. The financial performance of our existing businesses, $195.5 million in cash and existing debt commitments and no need, other than opportunistically, to access the capital markets, may allow us to take advantage of acquisition and/or growth opportunities that may develop.

Our ability to fund large new projects or make large acquisitions in the near term may be limited by the current conditions in the credit and equity markets due to limitations in our ability to issue new debt or equity financing. We will consider other arrangements to fund large growth projects and acquisitions such as private equity and joint venture arrangements.

Available Cash before Reserves

Available Cash before Reserves for the year ended December 31, 2008 is as follows (in thousands):

	Year Ended December 31, 2008
Net income attributable to Genesis Energy, L.P.	$	26,089
Depreciation and amortization		71,370
Cash received from direct financing leases not included in income		2,349
Cash effects of sales of certain assets		760
Effects of available cash generated by equity method investees not included in income		1,830
Cash effects of stock appreciation rights plan		(385	)
Non-cash tax benefits		(2,782	)
Earnings of DG Marine in excess of distributable cash		(2,821	)
Other non-cash items, net		(2,172	)
Maintenance capital expenditures		(4,454	)
Available Cash before Reserves	$	89,784

We have reconciled Available Cash before Reserves (a non-GAAP measure) to cash flow from operating activities (the most comparable GAAP measure) for the year ended December 31, 2008 in“Capital Resources and Liquidity – Non-GAAP Reconciliation” below. For the year ended December 31, 2008, cash flows provided by operating activities were $94.8 million.

Acquisitions in 2008

Investment in DG Marine Transportation, LLC

On July 18, 2008, we completed the acquisition of an effective 49% economic interest in DG Marine, which acquired the inland marine transportation business of Grifco Transportation, Ltd. (“Grifco”) and two of Grifco’s affiliates. TD Marine, LLC, an entity formed by members of the Davison family (See discussion below on the acquisition of the Davison family businesses in 2007) owns (indirectly) a 51% economic interest in the joint venture. This acquisition gives us the capability to provide transportation services of petroleum products by barge and complements our other supply and logistics operations.

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Grifco received initial purchase consideration of approximately $80 million, comprised of $63.3 million in cash and $16.7 million, or 837,690 of our common units. DG Marine acquired substantially all of Grifco’s assets, including twelve barges, seven push boats, certain commercial agreements, offices and the rights and obligations to acquire a total of eight new barges. Through December 31, 2008, DG Marine had taken delivery of four new barges and acquired two new push boats at a total cost of approximately $16 million. DG Marine expects to take delivery of the remaining new barges and one additional push boat in first half of 2009 (at a total cost of approximately $14.6 million). Upon delivery of the first four new barges and two new push boats in the latter half of 2008, DG Marine paid additional purchase consideration to Grifco of $6 million. After delivery of the remaining four barges and push boat, and after placing the barges and push boats into commercial operations, DG Marine will be obligated to pay additional purchase consideration of up to $6 million. The estimated discounted present value of that $6 million obligation is included in current liabilities in our consolidated balance sheets.

The Grifco acquisition and related closing costs were funded with $50 million of aggregate equity contributions from us and TD Marine, in proportion to our ownership percentages, and with borrowings of $32.4 million under a $90 million revolving credit facility which is non-recourse to us and TD Marine (other than with respect to our investments in DG Marine). Although DG Marine’s debt is non-recourse to us, our ownership interest in DG Marine is pledged to secure its indebtedness and we have guaranteed $7.5 million of its indebtedness. The guarantee will expire on May 31, 2009 if DG marine’s leverage ratio under its revolving credit agreement is less than 4.0 to 1.0. We funded our $24.5 million equity contribution with $7.8 million of cash and 837,690 of our common units, valued at $19.896 per unit, for a total value of $16.7 million. At closing, we also redeemed 837,690 of our common units from the Davison family. The total number of our outstanding common units did not change as a result of that investment.

We consolidate DG Marine’s financial results even though we do not own a majority interest in it. We also do not control the key operational decisions of DG Marine. See Note 3 of the Notes to the Consolidated Financial Statements for more information on DG Marine.

Drop-down Transactions

We completed two “drop-down” transactions with Denbury in 2008 involving two of their existing CO₂ pipelines - the NEJD and Free State CO₂ pipelines. We paid for these pipeline assets with $225 million in cash and 1,199,041 common units valued at $25 million based on the average closing price of our units for the five trading days surrounding the closing date of the transaction. We expect to receive approximately $30 million per annum, in the aggregate, under the lease agreement for the NEJD pipeline and the Free State pipeline transportation services agreement. Future payments for the NEJD pipeline are fixed at $20.7 million per year during the term of the financing lease, and the payments related to the Free State pipeline are dependent on the volumes of CO₂ transported therein, with a minimum monthly payment of $0.1 million.

The NEJD Pipeline System is a 183-mile, 20” pipeline extending from the Jackson Dome, near Jackson, Mississippi, to near Donaldson, Louisiana, and is currently being used by Denbury for its Phase I area of tertiary operations in southwest Mississippi. Denbury has the rights to exclusive use of the NEJD Pipeline System and is responsible for all operations and maintenance on the system, and will bear and assume all obligations and liabilities with respect to the pipeline.

On August 5, 2008, Denbury announced that the economic impact of an approved tax accounting method change providing for an acceleration of tax deductions will likely affect certain types of future asset “drop-downs” to us. Transactions which are not sales for tax purposes for Denbury, such as the lease arrangement for the NEJD pipeline, would not be affected provided the transactions meet other tax structuring criteria for Denbury and us. There can be no assurances as to the amount, or timing, of any potential future asset “drop-downs” from Denbury to us.

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Results of Operations

The contribution of each of our segments to total segment margin in each of the last three years was as follows:

	Year Ended December 31,
	2008		2007		2006
	(in thousands)
Pipeline transportation	$	33,149	$	14,170	$	13,280
Refinery services		55,784		19,713		—
Industrial gases		13,504		13,038		12,844
Supply and logistics		32,448		10,646		5,017
Total segment margin	$	134,885	$	57,567	$	31,141

Pipeline Transportation Segment

We operate three common carrier crude oil pipeline systems and a CO₂ pipeline in a four state area. We refer to these pipelines as our Mississippi System, Jay System, Texas System and Free State Pipeline. Volumes shipped on these systems for the last three years are as follows (barrels per day):

Pipeline System	2008		2007	2006
Mississippi-Bbls/day	25,288		21,680	16,931
Jay - Bbls/day	13,428		13,309	13,351
Texas - Bbls/day	25,395		24,346	31,303
Free State - Mcf/day	160,220	(1)	—	—

(1) Daily average for the period we owned the pipeline in 2008.

The Mississippi System begins in Soso, Mississippi and extends to Liberty, Mississippi. At Liberty, shippers can transfer the crude oil to a connection to Capline, a pipeline system that moves crude oil from the Gulf Coast to refineries in the Midwest. The system has been improved to handle the increased volumes produced by Denbury and transported on the pipeline. In order to handle future increases in production volumes in the area that are expected, we have made capital expenditures for tank, station and pipeline improvements over the last three years and we will continue to make further improvements.

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, Denbury may need crude oil gathering and CO₂supply infrastructure to those fields, which could create some opportunities for us.

Two segments of crude oil pipeline connect producing fields operated by Denbury to our Mississippi System. Denbury pays us a minimum payment each month for the right to use these pipeline segments. We account for these arrangements as direct financing leases.

The Jay Pipeline system in Florida and Alabama ships crude oil from mature producing fields in the area as well as production from new wells drilled in the area. The increase in crude oil prices in 2007 and 2008 led to interest in further development of the mature fields. We do not know what long-term impact the decline in crude oil prices in the fourth quarter of 2008 may have on the continued production from the mature fields, and the volumes transported on our pipeline.

The new production in the area produces greater tariff revenue for us due to the greater distance that the crude oil is transported on the pipeline. This increased revenue, increases in tariff rates each year on the remaining segments of the pipeline, sales of pipeline loss allowance volumes, and operating efficiencies that have decreased operating costs have contributed to increases in our cash flows from the Jay System. The recent decline in crude oil market prices will also impact our sales of pipeline loss allowance volumes.

As we have consistently been able to increase our pipeline tariffs as needed and due to the new production in the area surrounding our Jay System, we do not believe that a decline in volumes or revenues from sales of pipeline loss allowance volumes will affect the recoverability of the net investment that remains for the Jay System.

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Volumes on our Texas System averaged 25,395 barrels per day during 2008. The crude oil that enters our system comes to us at West Columbia where we have a connection to TEPPCO’s South Texas System and at Webster where we have connections to two other pipelines. One of these connections at Webster is with ExxonMobil Pipeline and is used to receive volumes that originate from TEPPCO’s pipelines. We have a joint tariff with TEPPCO under which we earn $0.31 per barrel on the majority of the barrels we deliver to the shipper’s facilities. Substantially all of the volume being shipped on our Texas System goes to two refineries on the Texas Gulf Coast.

Our Texas System is dependent on the connecting carriers for supply, and on the two refineries for demand for our services. We lease tankage in Webster on the Texas System of approximately 165,000 barrels. We have a tank rental reimbursement agreement with the primary shipper on our Texas System to reimburse us for the expense of leasing of that storage capacity. 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.

We entered into a twenty-year transportation services agreement to deliver CO₂ on the Free State pipeline for Denbury’s use in its tertiary recovery operations. Under the terms of the transportation services agreement, we are responsible for owning, operating, maintaining and making improvements to the pipeline. Denbury has rights to exclusive use of the pipeline and is required to use the pipeline to supply CO₂ to its current and certain of its other tertiary operations in east Mississippi. The transportation services agreement provides for a $0.1 million per month minimum payment plus a tariff based on throughput. Denbury has two renewal options, each for five years on similar terms.

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. This arrangement has been accounted for as a direct financing lease.

In May 2008, we entered into a twenty-year financing lease transaction with Denbury valued at $175 million related to Denbury’s North East Jackson Dome (NEJD) Pipeline System. Denbury Onshore makes fixed quarterly base rent payments to us of $5.2 million per quarter or approximately $20.7 million per year.

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 are not within our control, like power cost increases. We perform regular maintenance on our assets to keep them in good operational condition and to minimize cost increases.

Operating results from operations for our pipeline transportation segment were as follows.

	Year Ended December 31,
	2008			2007			2006
	(in thousands)
Pipeline transportation revenues, excluding natural gas	$	41,097		$	22,755		$	21,742
Natural gas tariffs and sales, net of gas purchases		232			334			612
Pipeline operating costs, excluding non-cash charges for stock-based compensation		(10,529	)		(9,488	)		(9,605	)
Non-income payments under direct financing leases		2,349			569			531
Segment margin	$	33,149		$	14,170		$	13,280

Year Ended December 31, 2008 Compared with Year Ended December 31, 2007

Pipeline segment margin increased $19.0 million in 2008 as compared to 2007. This increase is primarily attributable to the following factors:

• An increase in revenues from the lease of the NEJD pipeline to Denbury beginning in May 2008 added $12.1 million to segment margin;

• an increase in revenues from the Free State pipeline beginning in May 2008 added a total of $5.1 million to CO₂ tariff revenues, with the transportation fee related to 34.3 MMcf totaling $4.4 million and the minimum monthly payments totaling $0.7 million;

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• an increase in revenues from crude oil tariffs and direct financing leases of $1.4 million; and

• an increase in revenues from sales of pipeline loss allowance volumes of $1.7 million, resulting from an increase in the average annual crude oil market prices of $26.73 per barrel, offset by a decline in allowance volumes of approximately 15,000 barrels.

• Partially offsetting the increase in segment margin was an increase of $1.0 million in pipeline operating costs.

Tariff and direct financing lease revenues from our crude oil pipelines increased primarily due to volume increases on all three pipeline systems totaling 4,776 barrels per day. These volume increases occurred despite the brief disruptions in operations caused by Hurricanes Gustav and Ike which affected power supplies on the Gulf Coast.

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, 2008 with the volume increase still resulted in improved tariff revenues from this system of $0.6 million. As a result of the annual tariff increase on July 1, 2008, average tariffs on the Jay System increased by approximately $0.06 per barrel between the two periods. Combined with the 119 barrels per day increase in average daily volumes, the Jay System tariff revenues increased $0.4 million. The impact of volume increases on the Texas System on revenues is not very significant due to the relatively low tariffs on that system. Approximately 75% of the 2008 volume on that system was shipped on a tariff of $0.31 per barrel.

As is common in the industry, our crude oil tariffs incorporate a loss allowance factor that is intended to, among other things, offset losses due to evaporation, measurement and other losses in transit. We value the variance of allowance volumes to actual losses at the average market value at the time the variance occurred and the result is recorded as either an increase or decrease to tariff revenues. As compared to 2007, volumes from loss allowance were 15,000 barrels less, however the average price of crude oil was significantly higher during 2008 as compared to 2007. Based on historic volumes, a change in crude oil market prices of $10 per barrel has the effect of decreasing or increasing our pipeline loss allowance revenues by approximately $0.1 million per month.

Pipeline operating costs increased $1.0 million, with approximately $0.4 million of that amount due to an increase in IMP testing and repairs, $0.2 million related to the Free State pipeline acquired in May 2008 and $0.1 million related to increased electricity costs. Fluctuations in the cost of our IMP program are a function of the length and age of the segments of the pipeline being tested each year and the type of test being performed. Electricity costs in 2008 were higher due to market increases in the cost of power. The remaining $0.3 million of increased pipeline operating costs were related to various operational and maintenance items.

Year Ended December 31, 2007 Compared with Year Ended December 31, 2006

Pipeline segment margin increased $0.9 million, or 7%, for 2007, as compared to 2006. Revenues from crude oil and CO₂ tariffs and related sources were responsible for the increase for the period. Net profit from natural gas transportation and sales decreased slightly and pipeline operating costs increased, slightly offsetting the increase from tariffs and other sources.

Tariff revenues from transportation of crude oil and CO₂ increased $0.6 million in 2007 compared to the prior year period due primarily to increased volumes on the Mississippi System of 4,749 barrels per day and tariff increases on the Jay System. The volumes on the Jay System were almost identical to the prior year period. As a result of the annual tariff increase on July 1, 2007, average tariffs on the Jay System increased by approximately $0.04 per barrel between the two periods. The effect on revenues of a decline in volumes on the Texas System was not significant due to the relatively low tariffs on that system.

Higher market prices for crude oil added $0.4 million to pipeline loss allowance revenues. During 2007, average crude oil market prices, as referenced by the prices posted by Shell Trading (US) Company for West Texas/New Mexico Intermediate grade crude oil, were $6.20 higher than in 2006.

Net profit from natural gas pipeline activities decreased in total $0.3 million from 2006 amounts. The natural gas pipeline activities were negatively impacted by production difficulties of a producer attached to the system. Due to the declines we have experienced in the results from our natural gas pipelines, we reviewed these assets to determine if the fair market value of the assets exceeded the net book value of the assets. As a result of this review, we recorded an impairment loss in 2007 related to these assets. See “Other Costs and Interest – Depreciation, Amortization and Impairment” below.

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Operating costs decreased $0.1 million. The decrease in 2007 was due primarily to a decline in pipeline lease fees and insurance related to our pipeline operations.

Refinery Services Segment

Segment margin from our refinery services for 2008 was $55.8 million. Segment margin from our refinery services for the five months we owned this business in 2007 was $19.7 million. Annualizing the 2007 results and comparing those results to the 2008 segment margin would indicate that segment margin increased by approximately $8.5 million between the periods.

We provide a service to refiners – processing the refiner’s sour gas streams to reduce the sulfur content. The key cost components of the provision of this service are the purchase and transportation of caustic soda for use in the processing of the gas streams. Market prices for caustic soda were somewhat volatile in 2008, ranging from an average monthly low spot price of approximately $400 per dry short ton (DST) during the first quarter of 2008 as published by the Chemical Market Associates, Inc. (CMAI) to a high of $850 per DST in the fourth quarter of 2008. Our freight costs during 2008 fluctuated with freight demand and fuel prices. The price of diesel fuel ranged from a low of approximately $2.26 per gallon to a high of approximately $4.73 per gallon. In 2008, we believe that we were successful in mitigating some of the impact on segment margin of the volatility of these costs through our management of caustic acquisition and freight costs and by indexing our sales prices for NaHS to CMAI caustic market prices and adjusting sales prices for fluctuations in fuel surcharges. Additionally, 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 receive NaHS as consideration for provision of our services to the refiners. We sell the NaHS for use in applications including, but not limited to, agriculture, dyes and other chemical processing; waste treatment programs requiring stabilization and reduction of heavy and toxic metals; sulfidizing oxide ores (most commonly to separate copper from molybdenum; and certain applications in paper production and tannery processes. The table below reflects information about NaHS sales for 2008 and similar information for 2007 and 2006 volumes and sales prices on a pro forma basis based on historic data related to the refinery services operations.

	Year Ended December 31,		Pro Forma Year Ended December 31,
	2008		2007		2006
NaHS Sales
Dry Short Tons (DST)		162,210		164,059		159,952
Average sales price per DST, net of delivery costs	$	888	$	591	$	561

NaHS sales prices per DST increased as we adjusted these prices throughout 2008 for fluctuations in the cost components of our services. As discussed above, market prices for caustic were volatile in 2008. Additionally, freight costs for delivering NaHS to our customers fluctuated in 2008 in a manner similar to the freight costs associated with our caustic supply as discussed above. We were generally successful in increasing our sales prices for NaHS to compensate for these cost fluctuations by indexing approximately 60% of our NaHS sales volumes to market prices for caustic soda and by adjusting sales prices for NaHS as fuel surcharges billed to us increased.

Our NaHS sales volumes declined slightly in 2008, with almost all of the decline occurring in the fourth quarter resulting primarily from the slowdown in worldwide economic activity.

Industrial Gases Segment

Our industrial gases segment includes the results of our CO₂ sales to industrial customers and our share of the available cash generated by our 50% joint ventures, T&P Syngas and Sandhill.

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Operating Results

Operating results for our industrial gases segment were as follows.

	Year Ended December 31,
	2008			2007			2006
	(in thousands)
Revenues from CO2 marketing	$	17,649		$	16,158		$	15,154
CO2 transportation and other costs		(6,484	)		(5,365	)		(4,842	)
Available cash generated by equity investees		2,339			2,245			2,532
Segment margin	$	13,504		$	13,038		$	12,844
Volumes per day:
CO2 marketing - Mcf		78,058			77,309			72,841

CO₂ – Industrial Customers

We supply CO₂ to industrial customers under seven long-term CO₂ sales contracts. The terms of our contracts with the industrial CO₂customers include minimum take-or-pay and maximum delivery volumes. The maximum daily contract quantity per year in the contracts totals 97,625 Mcf. Under the minimum take-or-pay volumes, the customers must purchase a total of 51,048 Mcf per day whether received or not. Any volume purchased under the take-or-pay provision in any year can then be recovered in a future year as long as the minimum requirement is met in that year. At December 31, 2008, we have no liabilities to customers for gas paid for but not taken.

Our seven industrial contracts expire at various dates beginning in 2010 and extending through 2023. The sales contracts contain provisions for adjustments for inflation to sales prices based on the Producer Price Index, with a minimum price.

Based on historical data for 2004 through 2008, we 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. The table below depicts these seasonal fluctuations. The average daily sales (in Mcfs) of CO₂ for each quarter in 2008 and 2007 under these contracts were as follows:

Quarter	2008	2007
First	73,062	67,158
Second	79,968	75,039
Third	83,816	85,705
Fourth	75,164	80,667

The increasing margins from the industrial gases segment between the periods were the result of an increase in volumes and increases in the average revenue per Mcf sold of 8% from 2007 to 2008 and 1% from 2006 to 2007. Inflation adjustments in the contracts and variations in the volumes sold under each contract cause the changes in average revenue per Mcf.

Transportation costs for the CO₂ on Denbury’s pipeline have increased due to the increased volume and the effect of the annual inflation factor in the rate paid to Denbury. The average rate in 2008 increased 4% over the 2007 rate. The average rate per Mcf in 2007 increased 6% over the 2006 rate. In 2008, we also recorded a charge for approximately $0.9 million related to a commission on one of the industrial gas sales contracts. We expect this commission to continue in future years at a cost of approximately $0.3 million annually.

Equity Method Joint Ventures

Our share of the available cash before reserves generated by equity investments in each year primarily resulted from our investment in T&P Syngas. Our share of the available cash before reserves generated by T&P Syngas for 2008, 2007, and 2006 was $2.2 million, $1.9 million and $2.3 million, respectively.

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Supply and Logistics Segment

Our supply and logistics segment is focused on utilizing our knowledge of the crude oil and petroleum markets and our logistics capabilities from our terminals, trucks and barges to provide suppliers and customers with a full suite of services. These services include:

• purchasing and/or transporting crude oil from the wellhead to markets for ultimate use in refining;

• supplying petroleum products (primarily fuel oil, asphalt, diesel and gasoline) to wholesale markets and some end-users such as paper mills and utilities;

• purchasing products from refiners that do not meet the specifications they desire, transporting the products to one of our terminals and blending the products to a quality that meets the requirements of our customers; and

• utilizing our fleet of trucks and trailers and barges to take advantage of logistical opportunities primarily in the Gulf Coast states and inland waterways.

We also use our terminal facilities to take advantage of contango market conditions for crude oil gathering and marketing, and to capitalize on regional opportunities which arise from time to time for both crude oil and petroleum products.

Many U.S. refineries have distinct configurations and product slates that require crude oil with specific characteristics, such as gravity, sulfur content and metals content. The refineries evaluate the costs to obtain, transport and process their preferred choice of feedstock. Despite crude oil being considered a somewhat homogenous commodity, many refiners are very particular about the quality of crude oil feedstock they will process. That particularity provides us with opportunities to help the refineries in our areas of operation identify crude oil sources meeting their requirements, and to purchase the crude oil and transport it to the refineries for sale. The imbalances and inefficiencies relative to meeting the refiners’ requirements can provide opportunities for us to utilize our purchasing and logistical skills to meet their demands and take advantage of regional differences. The pricing in the majority of our purchase contracts contain a market price component, unfixed bonuses that are based on several other market factors and a deduction to cover the cost of transporting the crude oil and to provide us with a margin. Contracts sometimes 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.

When crude oil markets are in contango (oil prices for future deliveries are higher than for current deliveries), we may purchase and store crude oil as inventory for delivery in future months. When we purchase this inventory, we simultaneously enter into a contract to sell the inventory in the future period for a higher price, either with a counterparty or in the crude oil futures market. The storage capacity we own for use in this strategy is approximately 420,000 barrels, although maintenance activities on our pipelines can impact the availability of a portion of this storage capacity. We generally 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 17 of the Notes to the Consolidated Financial Statements.

In our petroleum products marketing operations, we supply primarily 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 them to one of our terminals and blending them to a quality that meets the requirements of our customers. The opportunities to provide this service cannot be predicted, but their contribution to margin as a percentage of their revenues tend to be higher than the same percentage attributable to our recurring operations. We utilize our fleet of 280 trucks and 550 trailers and DG Marine’s sixteen “hot-oil” barges in combination with our 1.1 million barrels of existing leased and owned storage to service our refining customers and store and blend the intermediate and finished refined products.

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Operating results from continuing operations for our supply and logistics segment were as follows.

	Year Ended December 31,
	2008			2007			2006
	(in thousands)
Supply and logistics revenue	$	1,852,414		$	1,094,189		$	873,268
Crude oil and products costs		(1,736,637	)		(1,041,738	)		(851,671	)
Operating and segment general and administrative costs, excluding non-cash charges for stock-based compensation		(83,329	)		(41,805	)		(16,580	)
Segment margin	$	32,448		$	10,646		$	5,017
Volumes of crude oil and petroleum products (mbbls)		17,410			14,246			13,571

Year Ended December 31, 2008 Compared with Year Ended December 31, 2007

In 2008, our supply and logistics segment margin included a full year of contribution from the assets acquired in July 2007 from the Davison family, as compared to only five months in 2007. This additional seven months of activity in 2008 was the primary factor in the increase in segment margin.

The dramatic rise in commodity prices in the first nine months of 2008 provided significant opportunities to us to take advantage of purchasing and blending of “off-spec” products. The average NYMEX price for crude oil rose from $95.98 per barrel at December 31, 2007 to a high of $145.29 per barrel in July 2008, and then declined to $44.60 per barrel at December 31, 2008. Grade differentials for crude oil widened significantly during this period as refiners sought to meet consumer demand for gasoline and diesel. This widening of grade differentials provided us with opportunities to acquire crude oil with a higher specific gravity and sulfur content (heavy or sour crude oil) at significant discounts to market prices for light sweet crude oil and sell it to refiners at prices providing significantly greater margin to us than sales of light sweet crude oil.

The absolute market price for crude oil also impacts the price at which we recognize volumetric gains and losses that are inherent in the handling and transportation of any liquid product. In 2008 our average monthly volumetric gains were approximately 2,000 barrels.

In the first half of 2007, crude oil markets were in contango, providing an opportunity for us to increase segment margin. This opportunity did not exist in most of 2008. Late in 2008, crude oil price markets were again in contango, so we anticipate that opportunities will exist to profit from this strategy in 2009.

The demand for gasoline by consumers during most of 2008 also led refiners to focus on producing the “light” end of the refined barrel. Some refiners were willing to sell the heavy end of the refined barrel, in the form of fuel oil or asphalt, as well as product not meeting their specifications for use in making gasoline, at discounts to market prices in order to free up capacity at their refineries to meet gasoline demand. Our ability to utilize our logistics equipment to transport product from the refiner’s facilities to one of our terminals increased the opportunity to acquire the product at a discount.

As a result of the actions we took in light of the opportunities presented to us in the market, our average margin per barrel increased to $6.65 in 2008 from $3.68 per barrel in 2007. Before consideration of the costs of providing our services, we generated $63.3 million of additional margin from our supply and logistics activities,

Our operating and segment general and administrative (G&A) costs increased by $41.5 million in 2008 as compared to 2007. The costs of operating the logistical equipment and terminals acquired in the Davison acquisition for an additional seven months in 2008 accounted for approximately $30.2 million of this difference. Our inland marine transportation operations acquired in July 2008 added approximately $8.4 million to our costs in 2008. The remaining increase in costs of $2.9 million is attributable to the crude oil portion of our supply and logistics operations. The most significant components of our operating and segment G&A costs consist of fuel for our fleet of trucks, maintenance of our trucks, terminals and barges, and personnel costs to operate our equipment. In 2008, fuel costs for our trucks increased significantly as result of market prices for diesel fuel.

Year Ended December 31, 2007 Compared with Year Ended December 31, 2006

The portions of our supply and logistics operations acquired in the Davison transaction added approximately $8.6 million to our supply and logistics segment margin for the five months we owned these operations in 2007. Our existing crude oil gathering and marketing operations contribution for 2007 was $0.6 million less than the contribution for 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 of crude oil volumes that we did not purchase by truck for a fee, 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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An increase in the operating and segment general and administrative costs related to our crude oil activities of $4.1 million was the largest contributor to the decrease in segment margin from crude oil operations. Compensation and related costs accounted for $1.8 million of the increased costs. In order to remain competitive in retaining drivers for our crude oil trucking, we increased compensation rates. We also had increased costs for fuel and repairs to our trucks and related equipment that combined to increase our operating costs in the crude oil area by $1.2 million. We increased the accrual for the remediation of a former trucking station by $0.3 million. Additionally we incurred costs of $0.7 million related to the operation of the Port Hudson facility which we acquired in 2007.

Partially offsetting these increased operating costs was an increase of 1,429 barrels per day in crude oil volumes that we transported for a fee. Most of this increase in volume was attributable to transportation of Denbury’s production from its wellheads to our pipeline. The increase in the fees for these services was $2.7 million between 2006 and 2007. On a like-kind basis, volumes purchased and sold decreased by 2,531 barrels per day. We focused on volumes in 2007 that met 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 a decrease of $0.6 million. The margins generated from the storage of crude oil inventory in the contango market were $0.2 million greater in 2007 than 2006.

Other Costs and Interest

General and administrative expenses were as follows.

	Year Ended December 31,
	2008			2007		2006
	(in thousands)
General and administrative expenses not separately identified below	$	25,131		$	16,760	$	9,007
Bonus plan expense		4,763			2,033		1,747
Stock-based compensation plans (credit) expense		(394	)		1,593		1,279
Compensation expense related to management team		—			3,434		—
Management team transition costs		—			2,100		1,540
Total general and administrative expenses	$	29,500		$	25,920	$	13,573

As a result of the substantial growth we have experienced beginning in 2006 and continuing through 2008, our general and administrative expenses have increased each year. We added a new senior management team in August 2006 and additional personnel in our financial, human resources and other functions to support the operations we acquired in 2008 and 2007 in the Davison and Grifco transactions. As we have grown, we have incurred increased legal, audit, tax and other consulting and professional fees, and additional director fees and expenses. Late in 2008, we moved to larger headquarters offices, incurring costs for moving as well as increased rent and related costs.

The expense we have recorded under our bonus plan increased substantially as a result of the improvement in our Available Cash before Reserves in each year and the tripling of our personnel count in mid 2007. The amounts paid under our bonus plan are a function of both the Available Cash before Reserves that we generate in a year and the improvement in our safety record, and are approved by our Compensation Committee of our Board of Directors. The bonus plan for employees is described in Item 11, “Executive Compensation” below.

We record stock-based compensation expense for phantom units issued under our long-term incentive plan and for our stock appreciation rights (SAR) plan. (See additional discussion in Item 11, “Executive Compensation” below and Note 15 to the Consolidated Financial Statements.) The fair value of phantom units issued under our long-term incentive plan is calculated at the grant date and charged to expense over the vesting period of the phantom units. Unlike the accounting for the SAR plan, the total expense to be recorded is determined at the time of the award and does not change except to the extent that phantom unit awards do not vest due to employee terminations. The SAR plan for employees and directors is a long-term incentive plan whereby rights are granted for the grantee to receive cash equal to the difference between the grant price and common unit price at date of exercise. The rights vest over several years. We determine the fair value of the SARs at the end of each reporting period and the fair value is charged to expense over the period during which the employee vests in the SARs. Changes in our common unit market price affect the computation of the fair value of the outstanding SARs. The change in fair value combined with the elapse of time and its effect on the vesting of SARs create the expense we record. Additionally any difference between the expected value for accounting purposes that an employee will receive upon exercise of his rights and the actual value received when the employee exercise the SARs creates additional expense. Due to fluctuations in the market price for our common units, expense for outstanding and exercised SARs has varied significantly between the periods.

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Our senior management team was hired in August 2006. Throughout 2006, 2007 and until December 2008, Denbury negotiated with that team to finalize a compensation package. Although the terms of these arrangements were not agreed to and completed at December 31, 2007, we recorded expense of $3.4 million in 2007, representing an estimated value of compensation attributable to our Chief Executive Officer and Chief Operating Officer for services performed during 2007. Although this compensation is to ultimately come from our general partner, we have recorded the expense in our Consolidated Statements of Operations in G&A expense due to the “push-down” rules for accounting for transactions where the beneficiary of a transaction is not the same as the parties to the transaction. On December 31, 2008, we finalized the arrangements with our senior management team. See additional discussion of the compensation arrangements with our senior management team in Item 11, “Executive Compensation.”

Additionally, we recorded transition costs primarily in the form of severance costs when members of our management team changed in December 2007 and August 2006. Our general partner made a cash contribution to us of $1.4 million in 2007 to partially offset the $2.1 million cash cost of the severance payment to a former member of our management team.

Depreciation, amortization and impairment expense was as follows:

	Year Ended December 31,
	2008		2007		2006
Depreciation on Genesis assets	$	17,331	$	8,909	$	3,719
Depreciation of acquired DG Marine property and equipment		3,084		—		—
Amortization on acquired Davison intangible assets		46,326		25,350		—
Amortization on acquired DG Marine intangible assets		92		—		—
Amortization of CO2 volumetric production payments		4,537		4,488		4,244
Impairment expense on natural gas pipeline assets		—		1,498		—
Total depreciation, amortization and impairment expense	$	71,370	$	40,245	$	7,963

Depreciation, amortization and impairment increased in 2007 and 2008 due primarily to the depreciation and amortization expense recognized on the fixed assets and intangible assets acquired from the Davison family in July 2007 and the DG Marine acquisition in July 2008.

Our intangible assets are being amortized over the period during which the intangible asset is expected to contribute to our future cash flows. As intangible assets such as customer relationships and trade names are generally most valuable in the first years after an acquisition, the amortization we will record on these assets will be greater in the initial years after the acquisition. As a result, we expect to record significantly more amortization expense related to our intangible assets in 2008 through 2010 than in years subsequent to that time. See Note 9 to the Consolidated Financial Statements for information on the amount of amortization we expect to record in each of the next five years.

Amortization of our CO₂ volumetric payments is based on the units-of-production method. We acquired three volumetric production payments totaling 280 Mcf of CO₂ from Denbury between 2003 and 2005. Amortization is based on volumes sold in relation to the volumes acquired. In each annual period, the volume of CO₂ sold has increased.

In 2007 and 2006, our natural gas pipeline activities were impacted by production difficulties of a producer attached to the system. Due to declines we experienced in the results from our natural gas pipelines, we reviewed these assets in 2007 to determine if the fair market value of the assets exceeded the net book value of the assets. As a result of this review, we recorded an impairment loss of $1.5 million related to these assets.

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Interest expense, net was as follows:

	Year Ended December 31,
	2008			2007			2006
	(in thousands)
Interest expense, including commitment fees, excluding DG Marine	$	10,738		$	10,103		$	781
Amortization of facility fees, excluding DG Marine facility		664			441			300
Interest expense and commitment fees - DG Marine		2,269			—			—
Capitalized interest		(276	)		(59	)		(9	)
Write-off of facility fees and other fees		—			—			500
Interest income		(458	)		(385	)		(198	)
Net interest expense	$	12,937		$	10,100		$	1,374

Our average outstanding debt balance, excluding the DG Marine credit facility, increased $107.0 million to $225 million in 2008 over the average outstanding debt balance in 2007, primarily due to the Davison acquisition in July 2007 and the CO₂ pipeline dropdown transactions in May 2008. The average interest rate on our debt, however, was 3.52% lower during 2008, partially offsetting the effects of the higher debt balance, resulting in an overall increase for the year for interest and commitment fees on our credit facility of $0.6 million, and an average interest rate of 4.26%.

DG Marine incurred interest expense in 2008 of $2.3 million under its credit facility. Additionally DG Marine recorded accretion of the discount on the payments to Grifco related upon successful launch of the barges under construction. (See Note 3 to the Consolidated Financial Statements.) The net effect of these changes was an increase in net interest expense between the 2008 and 2007 of $2.8 million.

Net interest expense increased $8.7 million from 2006 to 2007. This increase in interest resulted form the borrowings in July 2007 to fund the Davison acquisition, with a reduction in debt in December 2007 from the proceeds from an equity offering. Our average outstanding balance of debt was $118.5 million during 2007, an increase of $115.1 million over 2006. Our average interest rate during 2007 was 7.78%, a decrease of 0.64% from 2006. As a result of the termination of our prior credit facility to enter into the new facility we obtained in November 2006, we wrote-off $0.5 million of deferred facility fees related to the prior credit facility in 2006.

Income taxes. A portion of the operations we acquired in the Davison transaction are owned by wholly-owned corporate subsidiaries that are taxable as corporations. As a result, a substantial portion of the income tax expense we record relates to the operations of those corporations, and will vary from period to period as a percentage of our income before taxes based on the percentage of our income or loss that is derived from those corporations. The balance of the income taxes expense we record relates to state taxes imposed on our operations that are treated as income taxes under generally accepted accounting principles. In 2008 and 2007, we recorded an income tax benefit totaling $0.4 million and $0.7 million, respectively. The current income taxes we expect to pay for 2008 are approximately $2.4 million, and we provided a deferred tax benefit of $4.2 million related to temporary differences between the relevant basis of our assets and liabilities for financial reporting and tax purposes.

Liquidity and Capital Resources

Capital Resources/Sources of Cash

The current economic crisis has restricted the availability of credit and access to capital in our business environment. Despite efforts by treasury and banking regulators to provide liquidity to the financial sector, capital markets continue to remain constrained. While we anticipate that the challenging economic environment will continue for the foreseeable future, we believe that our current cash balances, future internally-generated funds and funds available under our credit facility will provide sufficient resources to meet our current working capital liquidity needs. The cash flow generated by our existing businesses, the $19.0 million in cash on hand, our existing debt commitments, and the absence of any need to access the capital markets, may allow us to take advantage of acquisition and/or growth opportunities that may develop.

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Long-term, we continue to pursue a growth strategy that requires significant capital. We expect our long-term capital resources to include equity and debt offerings (public and private) and other financing transactions, in addition to cash generated from our operations. Accordingly, we expect to access the capital markets (equity and debt) from time to time to partially refinance our capital structure and to fund other needs including acquisitions and ongoing working capital needs. 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.

As of December 31, 2008, we had $320 million of loans and $3.5 million in letters of credit outstanding under our $500 million credit facility, resulting in $176.5 million of remaining credit, all of which was available under our borrowing base. Our borrowing base fluctuates each quarter based on our earnings before interest, taxes, depreciation and amortization, or EBITDA. Our borrowing base may be increased to the extent of EBITDA attributable to acquisitions, with approval of the lenders.

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 10 of the Notes to the Consolidated Financial Statements for additional information on our credit facility.

As of December 31, 2008, DG Marine had $55.3 million of loans outstanding under its $90 million credit facility. DG Marine will utilize this facility to fund its acquisition of additional barges and a push boat in the first half of 2009.

Uses of Cash

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

Cash Flows from Operations. We utilize the cash flows we generate from our operations to fund our working capital needs. Excess funds that are generated are used to repay borrowings from our credit facilities and to fund capital expenditures. Our operating cash flows can be impacted by changes in items of working capital, primarily variances in the timing of payment of accounts payable and accrued liabilities related to capital expenditures.

Debt and Other Financing Activities.Our sources of cash are primarily from operations and our credit facilities. Our net borrowings under our credit facility and the DG Marine credit facility totaled $295.3 million. These borrowings related to the CO₂ pipeline drop-down transactions in May 2008 and the acquisition by DG Marine of the Grifco assets in July 2008. Our joint venture partner in DG Marine (members of the Davison family) also contributed $25.5 million for its 51% interest and we redeemed $16.7 million of common units from those members of the Davison family at the time of the Grifco acquisition. In connection with our issuance of 1,199,041 common units to Denbury for a portion of the consideration in the drop-down transactions, our general partner contributed $0.5 million as required under our partnership agreement to maintain its two percent general partner capital account balance.

We paid distributions totaling $50.5 million to our limited partners and our general partner during 2008. See the details of distributions paid in “Distributions” below. DG Marine paid credit facility fees of $2.3 million in 2008.

Investing. We utilized cash flows to make acquisitions and for capital expenditures. The most significant investing activities in 2008 were the CO₂ pipeline drop-down transactions in May 2008 for which we expended $225 million in cash as consideration (along with the issuance of $25 million of our common units) and the acquisition of the inland marine transportation assets of Grifco in July 2008. We paid Grifco $66.0 million in cash consideration at closing of the transaction (along with the issuance of $16.7 million of our common units and an agreement to pay an additional $12.0 million consideration, with one-half payable in December 2008 and the remainder in December 2009). On December 31, 2008 we expended $6.0 million for the first payment of the deferred consideration. We also expended approximately $16.0 million for additional barges and push boats. Additional information on our capital expenditures and business acquisitions is provided below.

14

Capital Expenditures, and Business and Asset Acquisitions

A summary of our expenditures for fixed assets, businesses and other asset acquisitions in the three years ended December 31, 2008, 2007, and 2006 is as follows:

	Years Ended December 31,
	2008		2007		2006
	(in thousands)
Capital expenditures for business combinations and asset purchases:
DG Marine acquisition	$	94,072	$	—	$	—
Free State Pipeline acquisition, including transaction costs		76,193		—		—
NEJD Pipeline transaction, including transaction costs		177,699		—		—
Davison acquisition		—		631,476		—
Port Hudson acquisition		—		8,103		—
Total		347,964		639,579		—
Capital expenditures for property, plant and equipment:
Maintenance capital expenditures:
Pipeline transportation assets		719		2,880		611
Supply and logistics assets		729		440		175
Refinery services assets		1,881		469		—
Administrative and other assets		1,125		51		181
Total maintenance capital expenditures		4,454		3,840		967
Growth capital expenditures:
Pipeline transportation assets		7,589		3,712		360
Supply and logistics assets		22,659		650		—
Refinery services assets		3,609		979		—
Total growth capital expenditures		33,857		5,341		360
Total		38,311		9,181		1,327
Capital expenditures attributable to unconsolidated affiliates:
Sandhill investment		—		—		5,042
Faustina project		2,397		1,104		1,016
Total		2,397		1,104		6,058
Total capital expenditures	$	388,672	$	649,864	$	7,385

During 2009, we expect to expend approximately $12.7 million for maintenance capital projects in progress or planned. Those expenditures are expected to include approximately $1.9 million of improvements in our refinery services business, $2.6 million in our crude oil pipeline operations, including $2.0 million for rehabilitation of a segment of the Mississippi System as a result of IMP testing, $3.6 million related to integration and upgrades of our information technology systems, $2.7 related to improvements at our terminals and the remainder on projects related to our truck transportation operations, including $1.7 for replacement vehicles. In future years we expect to spend $4 million to $5 million per year on vehicle replacements.

We will also complete construction of an expansion of our existing Jay System that will extend the pipeline to producers operating in southern Alabama. That expansion will consist of approximately 33 miles of pipeline and gathering connections to approximately 35 wells and will include storage capacity of 20,000 barrels. We expect to spend a total of approximately $4.1 million in 2009 to complete this project, including the acquisitions of crude oil linefill.

15

DG Marine is expected to expend approximately $14.6 million in 2009 for four new barges and one additional push boat. Upon receipt of these vessels, DG Marine will have twenty barges and ten push boats. DG Marine’s capital expenditures are funded through its credit facility.

Expenditures for capital assets to grow the partnership distribution will depend on our access to debt and equity capital discussed above in “Capital Resources — Sources of Cash.” We will look for opportunities to acquire assets from other parties that meet our criteria for stable cash flows. The arrangement that Denbury has made with our new senior executive management team provide incentives to them to increase the available cash for our common unitholders. See “Item 11. Executive Compensation” for a description of these arrangements.

Distributions

Our partnership agreement requires us 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 fourteen quarters, including the distribution paid for the fourth quarter of 2008, as shown in the table below (in thousands, except per unit amounts). Each quarter, the Board of Directors of our general partner determines the distribution amount per unit based upon various factors such as our operating performance, available cash, future cash requirements and the economic environment. As a result, the historical trend of distribution increases may not be a good indicator of future increases.

Distribution For	Date Paid	Per Unit Amount		Limited Partner Interests Amount			General Partner Interest Amount		General Partner Incentive Distribution Amount		Total Amount
Fourth quarter 2006	February 2007	$	0.2100	$	2,895		$	59	$	—	$	2,954
First quarter 2007	May 2007	$	0.2200	$	3,032		$	62	$	—	$	3,094
Second quarter 2007	August 2007	$	0.2300	$	3,170	(1)	$	65	$	—	$	3,235	(1)
Third quarter 2007	November 2007	$	0.2700	$	7,646		$	156	$	90	$	7,892
Fourth quarter 2007	February 2008	$	0.2850	$	10,902		$	222	$	245	$	11,369
First quarter 2008	May 2008	$	0.3000	$	11,476		$	234	$	429	$	12,139
Second quarter 2008	August 2008	$	0.3150	$	12,427		$	254	$	633	$	13,314
Third quarter 2008	November 2008	$	0.3225	$	12,723		$	260	$	728	$	13,711
Fourth quarter 2008	February 2009(2)	$	0.3300	$	13,021		$	266	$	823	$	14,110

(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 was paid on February 13, 2009 to our general partner and unitholders of record as of February 3, 2009.

Our credit facility also includes a restriction on the amount of distributions we can pay in any quarter. At December 31, 2008, our restricted net assets (as defined in Rule 4-03 (e)(3) of Regulation S-X) were $573.6 million.

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. Under the quarterly incentive distribution provisions, our general partner is entitled to receive 13.3% of any distributions to our common unitholders in excess of $0.25 per unit, 23.5% of any distributions to our common unitholders in excess of $0.28 per unit, and 49% of any distributions to our common unitholders in excess of $0.33 per unit, without duplication. The likelihood and timing of the payment of any incentive distributions will depend on our ability to increase the cash flow from our existing operations and to make accretive acquisitions. In addition, our partnership agreement authorizes us to issue additional equity interests in our partnership with such rights, powers and preferences (which may be senior to our common units) as our general partner may determine in its sole discretion, including with respect to the right to share in distributions and profits and losses of the partnership.

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Non-GAAP Reconciliation

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

Available Cash before Reserves, also referred to as distributable cash flow, is commonly used as a supplemental financial measure by management and by external users of financial statements, such as investors, commercial banks, research analysts and rating agencies, to assess: (1) the financial performance of our assets without regard to financing methods, capital structures, or historical cost basis; (2) the ability of our assets to generate cash sufficient to pay interest cost and support our indebtedness; (3) our operating performance and return on capital as compared to those of other companies in the midstream energy industry, without regard to financing and capital structure; and (4) the viability of projects and the overall rates of return on alternative investment opportunities. Because Available Cash before Reserves excludes some, but not all, items that affect net income or loss and because these measures may vary among other companies, the Available Cash before Reserves data presented in this Annual Report on Form 10-K 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 year ended December 31, 2008, is as follows (in thousands):

	Year Ended December 31, 2008
Cash flows from operating activities	$	94,808
Adjustments to reconcile operating cash flows to Available Cash:
Maintenance capital expenditures		(4,454	)
Proceeds from sales of certain assets		760
Amortization of credit facility issuance fees		(1,437	)
Effects of available cash generated by equity method investees not included in cash flows from operating activities		1,067
Available cash from NEJD pipeline not yet received and included in cash flows from operating activities		1,723
Earnings of DG Marine in excess of distributable cash		(2,821	)
Other items affecting available cash		(1,124	)
Net effect of changes in operating accounts not included in calculation of Available Cash		1,262
Available Cash before Reserves	$	89,784

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Commitments and Off-Balance Sheet Arrangements

Contractual Obligation and Commercial Commitments

In addition to our credit facility discussed above, we have contractual obligations under operating leases as well as commitments to purchase crude oil and petroleum products. The table below summarizes our obligations and commitments at December 31, 2008.

	Payments Due by Period
Commercial Cash Obligations and Commitments	Less than one year		1 - 3 years		3 - 5 Years		More than 5 years		Total
Contractual Obligations:
Long-term debt(1)	$	—	$	375,300	$	—	$	—	$	375,300
Estimated interest payable on long-term debt(2)		14,428		27,487		—		—		41,915
Operating lease obligations		5,324		7,961		4,417		11,067		28,769
Capital expansion projects(3)		14,713		—		—		—		14,713
Unconditional purchase obligations(4)		57,975		—		—		—		57,975
Remaining purchase obligation to Grifco(5)		6,000		—		—		—		6,000
Other Cash Commitments:
Asset retirement obligations(6)		150		—		—		4,438		4,588
FIN 48 tax liabilities(7)		—		—		2,599		—		2,599
Total	$	98,590	$	410,748	$	7,016	$	15,505	$	531,859

⁽¹⁾ Our credit facility allows us to repay and re-borrow funds at any time through the maturity date of November 15, 2011. The DG Marine credit facility allows it to repay and re-borrow funds at any time through the maturity date of July 18, 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 December 31, 2008 remained outstanding through the final maturity dates of July 18, 2011 and November 15, 2011 and interest rates remained at the December 31, 2008 market levels through the final maturity dates.

⁽³⁾ We expect to complete the expansion of our Jay System in the first quarter of 2009. We also have signed commitments to purchase four newly-constructed barges. See “Capital Expenditures and Business Acquisitions” under “Liquidity and Capital Resources – Uses of Cash” above.

⁽⁴⁾ Unconditional purchase obligations include agreements to purchase goods and services that are enforceable and legally binding and specify all significant terms. Contracts to purchase crude oil and petroleum products are generally at market-based prices. For purposes of this table, estimated volumes and market prices at December 31, 2008, were used to value those obligations. The actual physical volumes and settlement prices may vary from the assumptions used in the table. Uncertainties involved in these estimates include levels of production at the wellhead, changes in market prices and other conditions beyond our control.

⁽⁵⁾ DG Marine will pay Grifco $6 million after delivery of four new barges and boats. See Note 3 to the Consolidated Financial Statements.

⁽⁶⁾ Represents the estimated future asset retirement obligations on an undiscounted basis. The present discounted asset retirement obligation is $1.4 million, as determined under FIN 47 and SFAS 143, and is further discussed in Note 5 to the Consolidated Financial Statements.

⁽⁷⁾ The estimated FIN 48 tax liabilities will be settled as a result of expiring statutes or audit activity. The timing of any particular settlement will depend on the length of the tax audit and related appeals process, if any, or an expiration of statute. If a liability is settled due to a statute expiring or a favorable audit result, the settlement of the FIN 48 tax liability would not result in a cash payment.

We have guaranteed 50% of the $3.0 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 underContractual Obligation and Commercial Commitments above.

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Critical Accounting Policies and Estimates

The preparation of consolidated financial statements in conformity with accounting principles generally accepted in the United States requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities, if any, at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. We base these estimates and assumptions on historical experience and other information that are believed to be reasonable under the circumstances. Estimates and assumptions about future events and their effects cannot be perceived with certainty, and, accordingly, these estimates may change as new events occur, as more experience is acquired, as additional information is obtained and as the business environment in which we operate changes. Significant accounting policies that we employ are presented in the notes to the consolidated financial statements (See Note 2 Summary of Significant Accounting Policies.)

We have defined critical accounting policies and estimates as those that are most important to the portrayal of our financial results and positions. These policies require management’s judgment and often employ the use of information that is inherently uncertain. Our most critical accounting policies pertain to measurement of the fair value of assets and liabilities in business acquisitions, depreciation, amortization and impairment of long-lived assets, asset retirement obligations, equity plan compensation accruals and contingent and environmental liabilities. We discuss these policies below.

Fair Value of Assets and Liabilities Acquired and Identification of Associated Goodwill and Intangible Assets.

In conjunction with each acquisition we make, we must allocate the cost of the acquired entity to the assets and liabilities assumed based on their estimated fair values at the date of acquisition. As additional information becomes available, we may adjust the original estimates within a short time period subsequent to the acquisition. In addition, we are required to recognize intangible assets separately from goodwill. Determining the fair value of assets and liabilities acquired, as well as intangible assets that relate to such items as customer relationships, contracts, trade names, and non-competes involves professional judgment and is ultimately based on acquisition models and management’s assessment of the value of the assets acquired, and to the extent available, third party assessments. Uncertainties associated with these estimates include fluctuations in economic obsolescence factors in the area and potential future sources of cash flow. We cannot provide assurance that actual amounts will not vary significantly from estimated amounts. In connection with the Grifco acquisition in 2008 and the Davison and Port Hudson acquisitions in 2007, we performed allocations of the purchase price. See Note 3 of the Notes to the Consolidated Financial Statements.

Depreciation and Amortization of Long-Lived Assets and Intangibles

In order to calculate depreciation and amortization we must estimate the useful lives of our fixed assets at the time the assets are placed in service. We compute depreciation using the straight-line method based on these estimated useful lives. The actual period over which we will use the asset may differ from the assumptions we have made about the estimated useful life. We adjust the remaining useful life as we become aware of such circumstances.

Intangible assets with finite useful lives are required to 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 customer and supplier relationships, licensing agreements and trade names based on the period over which the asset is expected to contribute to our future cash flows. Generally, the contribution of these assets to our cash flows is expected to decline over time, such that greater value is attributable to the periods shortly after the acquisition was made. Our favorable lease and other intangible assets are being amortized on a straight-line basis over their expected useful lives.

Impairment of Long-Lived Assets including Intangibles and Goodwill

When events or changes in circumstances indicate that the carrying amount of a fixed asset or intangible asset may not be recoverable, we review our assets for impairment in accordance with SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets. We compare the carrying value of the fixed asset to the estimated undiscounted future cash flows expected to be generated from that asset. Estimates of future net cash flows include estimating future volumes, future margins or tariff rates, future operating costs and other estimates and assumptions consistent with our business plans. If we determine that an asset’s unamortized cost may not be recoverable due to impairment; we may be required to reduce the carrying value and the subsequent useful life of the asset. Any such write-down of the value and unfavorable change in the useful life of an intangible asset would increase costs and expenses at that time.

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Goodwill represents the excess of the purchase prices we paid for certain businesses over their respective fair values and is primarily associated with the Davison acquisition in 2007. We do not amortize goodwill; however, we test our goodwill (at the reporting unit level) for impairment during the fourth quarter of each fiscal year, and more frequently, if circumstances indicate it is more likely than not that the fair value of goodwill is below its carrying amount. Our goodwill testing involves the determination of a reporting unit’s fair value, which is predicated on our assumptions regarding the future economic prospects of the reporting unit. Such assumptions include (i) discrete financial forecasts for the assets contained within the reporting unit, which rely on management’s estimates of operating margins, (ii) long-term growth rates for cash flows beyond the discrete forecast period, (iii) appropriate discount rates and (iv) estimates of the cash flow multiples to apply in estimating the market value of our reporting units. If the fair value of the reporting unit (including its inherent goodwill) is less than its carrying value, a charge to earnings is required to reduce the carrying value of goodwill to its implied fair value. At December 31, 2008, the carrying value of our goodwill was $325.0 million. We did not record any goodwill impairment charges during 2008.

Due to the recent disruptions in the credit markets and macroeconomic conditions, we will continue to monitor the market to determine if a triggering event occurs that would indicate that the fair value of a reporting unit is less than its carrying value. If we determine that a triggering event has occurred, we will perform an interim goodwill impairment analysis.

For additional information regarding our goodwill, see Notes 3 and 9 of the Notes to Consolidated Financial Statements.

Asset Retirement Obligations

Some of our assets, primarily related to our pipeline operations segment, have obligations regarding removal and restoration activities when the asset is abandoned. Additionally, we generally have obligations to remove crude oil injection stations located on leased sites and to decommission barges when we take them out of service. We estimate the future costs of these obligations, discount those costs to their present values, and record a corresponding asset and liability in our Consolidated Balance Sheets. The values ultimately derived are based on many significant estimates, including the ultimate expected cost of the obligation, the expected future date of the required cash payment, and interest and inflation rates. Revisions to these estimates may be required based on changes to cost estimates, the timing of settlement, and changes in legal requirements. Any such changes that result in upward or downward revisions in the estimated obligation will result in an adjustment to the related capitalized asset and corresponding liability on a prospective basis and an adjustment in our depreciation expense in future periods. See Note 5 to our Consolidated Financial Statements for further discussion regarding our asset retirement obligations.

Equity Compensation Plan Accruals

We accrue for the fair value of our liability for the stock appreciation rights (“SAR”) awards we have issued to our employees and directors under the provisions of SFAS No. 123(R),Share-Based Payments,as amended and interpreted. Under our SAR plan, grantees receive cash for the difference between the market value of our common units and the strike price of the award at the time of exercise. We estimate the fair value of SAR awards at each balance sheet date using the Black-Scholes option pricing model. The Black-Scholes valuation model requires the input of somewhat subjective assumptions, including expected stock price volatility and expected term. Other assumptions required for estimating fair value with the Black-Scholes model are the expected risk-free interest rate and our expected distribution yield. The risk-free interest rates used are the U.S. Treasury yield for bonds matching the expected term of the option on the date of grant. Our SAR plan was instituted December 31, 2003, so we have very limited experience from which to determine the expected term of the awards. As a result, we use the simplified method allowed by the Securities and Exchange Commission to determine the expected life, which results in an expected life of 6 to 7 years at the time an award it granted.

We recognize the stock-based compensation expense on a straight-line basis over the requisite service period for the awards. The expense we recognize is net of estimated forfeitures. We estimate our forfeiture rate at each balance sheet date based on prior experience. As of December 31, 2008, there was $0.2 million of total compensation cost to be recognized in future periods related to non-vested SARs. The cost is expected to be recognized over a weighted-average period of less than one year. We also record compensation cost for changes in the estimated liability for vested SARs. The liability recorded for vested SARs fluctuates with the market price of our common units. See Note 15 to our Consolidated Financial Statements for further discussion regarding our SAR plan.

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For phantom unit awards granted under our 2007 Long-Term Incentive Plan, the total compensation expense recognized over the service period is determined by the grant date fair value of our common units that become earned. Uncertainties involved in the estimate of the compensation cost we record for our phantom units relate to the assumptions regarding the continued employment of personnel who have been awarded phantom units.

On December 31, 2008, our general partner completed compensation arrangements with our senior executive team. See Item 11 – Executive Compensation - The Class B Membership Interest in our General Partner. The Class B Membership Interests awarded to our senior executives will be accounted for as liability awards under the provisions of SFAS 123(R). As such, the fair value of the compensation cost we record for these awards will be recomputed at each measurement date and the expense to be recorded will be adjusted based on that fair value. Management’s estimates of the fair value of these awards are based on assumptions regarding a number of future events, including estimates of the Available Cash before Reserves we will generate each quarter through the final vesting date of December 31, 2012, estimates of the future amount of incentive distributions we will pay to our general partner, and assumptions about appropriate discount rates. Additionally the determination of fair value will be affected by the distribution yield of ten publicly-traded entities that are the general partners in publicly-traded master limited partnerships, a factor over which we have no control. Included within the assumptions used to prepare these estimates are projections of available cash and distributions to our common unitholders and general partner, including an assumed level of growth and the effects of future new growth projects during the four-year vesting period. At December 31, 2008, management estimates that the fair value of the Class B Membership Awards and the related deferred compensation awards granted to our Senior Executives on that date is approximately $12 million. The fair value of these incentive awards will be recomputed each quarter beginning with the quarter ending March 31, 2009 through the final settlement of the awards. Compensation expense of $3.4 million was recorded in the fourth quarter of 2007 related to the previous arrangements between our general partner and our Senior Executives. The fair value to be recorded by us as compensation expense will be the excess of the recomputed estimated fair value over the previously recorded compensation expense of $3.4 million. Due to the vesting conditions for the awards, the amounts to which the Senior Executives were entitled on December 31, 2008 for the Class B Membership Awards and the related deferred compensation was zero. Management’s estimates of fair value are made in order to record non-cash compensation expense over the vesting period, and do not necessarily represent the contractual amounts payable under these awards at December 31, 2008. This expense will be recorded on an accelerated basis to align with the requisite service period of the award. Changes in our assumptions will change the amount of compensation cost we record. Changes in these assumptions would not, however, affect our Available Cash before Reserves, as the cash cost of the Class B Membership Interests will be borne by Denbury.

Liability and Contingency Accruals

We accrue reserves for contingent liabilities including environmental remediation and potential legal claims. When our assessment indicates that it is probable that a liability has occurred and the amount of the liability can be reasonably estimated, we make accruals. We base our estimates on all known facts at the time and our assessment of the ultimate outcome, including consultation with external experts and counsel. We revise these estimates as additional information is obtained or resolution is achieved.

We also make estimates related to future payments for environmental costs to remediate existing conditions attributable to past operations. Environmental costs include costs for studies and testing as well as remediation and restoration. We sometimes make these estimates with the assistance of third parties involved in monitoring the remediation effort.

At December 31, 2008, we are not aware of any contingencies or liabilities that will have a material effect on our financial position, results of operations, or cash flows.

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Recent Accounting Pronouncements.

SFAS 141(R)

In December 2007, the FASB issued SFAS No. 141(R) “Business Combinations” (SFAS 141(R)). SFAS 141(R) replaces FASB Statement No. 141, “Business Combinations.” This statement retains the purchase method of accounting used in business combinations but replaces SFAS 141 by establishing principles and requirements for the recognition and measurement of assets, liabilities and goodwill, including the requirement that most transaction costs and restructuring costs be charged to expense as incurred. In addition, the statement requires disclosures to enable users of the financial statements to evaluate the nature and financial effects of the business combination. SFAS 141(R) is effective for business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008. We adopted SFAS 141(R) on January 1, 2009. Adoption will impact our accounting for acquisitions we complete subsequent to that date.

SFAS 160

In December 2007, the FASB issued SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements - an amendment of ARB No. 51” (SFAS 160). This statement establishes accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary in an effort to improve the relevance, comparability and transparency of the financial information that a reporting entity provides in its consolidated financial statements. SFAS 160 is effective for fiscal years beginning after December 15, 2008. We adopted SFAS 160 on January 1, 2009. SFAS 160 changed the presentation of the interests in Genesis Crude Oil, L.P. held by our general partner and the interests in DG Marine held by our joint venture partner in our consolidated financial statements. The presentation and disclosure requirements of SFAS 160 have been applied retrospectively to the Consolidated Financial Statements and Notes included in this Current Report on Form 8-K.

SFAS 161

In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities-an amendment of FASB Statement No. 133” (SFAS 161). This Statement requires enhanced disclosures about (i) how and why an entity uses derivative instruments, (ii) how derivative instruments and related hedged items are accounted for under SFAS 133, and its related interpretations, and (iii) how derivative instruments and related hedged items affect an entity’s financial position, financial performance and cash flows. This statement is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008. We adopted SFAS No. 161 on January 1, 2009. Adoption did not have any material impact on our financial position, results of operations or cash flows.

EITF 07-4

In March 2008, 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” (EITF 07-4). EITF 07-4 addresses the application of the two-class method under SFAS No. 128 “Earnings Per Share” in determining income per unit for master limited partnerships having multiple classes of securities that may participate in partnership distributions. To the extent the partnership agreement does not explicitly limit distributions to the general partner, any earnings in excess of distributions are to be allocated to the general partner and limited partners utilizing the distribution formula for available cash specified in the partnership agreement. When current period distributions are in excess of earnings, the excess distributions are to be allocated to the general partner and limited partners based on their respective sharing of losses specified in the partnership agreement for the period. EITF 07-4 is to be applied retrospectively for all financial statements presented and is effective for financial statements issued for fiscal years beginning after December 15, 2008, and interim periods within those fiscal years. Earlier application is not permitted. We adopted EITF 07-04 on January 1, 2009. The requirements of EITF 07-4 have been applied retrospectively to the Consolidated Financial Statements and Notes included in this Current Report on Form 8-K. For additional information on our incentive distribution rights, see Note 11 to the Consolidated Financial Statements.

FASB Staff Position No. 142-3

In April 2008, the FASB issued FASB Staff Position No. 142-3, “Determination of the Useful Life of Intangible Assets” (FSP 142-3). This FSP amends the factors that should be considered in developing renewal or extension assumptions used to determine the useful life of an intangible asset under Statement of Financial Accounting Standards No. 142, “Goodwill and other Intangible Assets.” The purpose of this FSP is to develop consistency between the useful life assigned to intangible assets and the cash flows from those assets. FSP 142-3 is effective for fiscal years beginning after December 31, 2008. We are currently evaluating the impact, if any, that the standard will have on our consolidated financial statements.

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Item 7a. Quantitative and Qualitative Disclosures About Market Risk

We are exposed to various market risks, primarily related to volatility in crude oil and petroleum products prices, NaHS and NaOH prices, and interest rates. Our policy is to purchase only commodity products for which we have a market, and to structure our sales contracts so that price fluctuations for those products do not materially affect the segment margin we receive. We do not acquire and hold futures contracts or other derivative products for the purpose of speculating on price changes.

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 grade and location differentials and their effect on future contractual commitments. Our risk management policies are designed to monitor our physical volumes, grades, and delivery schedules to ensure our hedging activities address the market risks that are inherent in our gathering and marketing activities.

We utilize NYMEX commodity based futures contracts and option contracts to hedge our exposure to these market price fluctuations as needed. All of our open commodity price risk derivatives at December 31, 2008 were categorized as non-trading. On December 31, 2008, we had entered into NYMEX future contracts that will settle between February 2009 and August 2009 and NYMEX options contracts that will settle during February and March 2009. Although the intent of our risk-management activities is to hedge our margin, none of our derivative positions at December 31, 2008 qualified for hedge accounting. This accounting treatment is discussed further under Note 17 to our Consolidated Financial Statements.

The table below presents information about our open derivative contracts at December 31, 2008. Notional amounts in barrels, the weighted average contract price, total contract amount and total fair value amount in U.S. dollars of our open positions are presented below. Fair values were determined by using the notional amount in barrels multiplied by the December 31, 2008 quoted market prices on the NYMEX. All of the hedge positions offset physical exposures to the cash market; none of these offsetting physical exposures are included in the table below.

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	Sell (Short) Contracts			Buy (Long) Contracts
Futures Contracts:
Crude Oil:
Contract volumes (1,000 bbls)		146			107
Weighted average price per bbl	$	53.25		$	47.94
Contract value (in thousands)	$	7,774			5,129
Mark-to-market change (in thousands)		(169	)		(357	)
Market settlement value (in thousands)	$	7,605		$	4,772
Heating Oil:
Contract volumes (1,000 bbls)		35			—
Weighted average price per gal	$	1.43		$	—
Contract value (in thousands)	$	2,099			—
Mark-to-market change (in thousands)		21			—
Market settlement value (in thousands)	$	2,120		$	—
Natural Gas:
Contract volumes (10,000 mmBtus)					5
Weighted average price per mmBtu	$	—		$	6.09
Contract value (in thousands)	$	—			304
Mark-to-market change (in thousands)		—			(23	)
Market settlement value (in thousands)	$	—		$	281
NYMEX Option Contracts:
Crude Oil- Written/Purchased Calls
Contract volumes (1,000 bbls)		90			6
Weighted average premium received/paid	$	2.23		$	0.10
Contract value (in thousands)	$	200		$	1
Mark-to-market change (in thousands)		11			1
Market settlement value (in thousands)	$	211		$	2
Natural Gas- Written Calls
Contract volumes (10,000 mmBtus)		10
Weighted average premium received	$	0.33
Contract value (in thousands)	$	33
Mark-to-market change (in thousands)		(10	)
Market settlement value (in thousands)	$	23

We manage our risks of volatility in NaOH prices by indexing prices for the sale of NaHS to the market price of NaOH in most of our contracts.

We are also exposed to market risks due to the floating interest rates on our credit facility and the DG Marine credit facility. Our debt bears interest at the LIBOR Rate or Prime Rate, at our option, plus the applicable margin. We have not, historically hedged our interest rates. On December 31, 2008, we had $320.0 million of debt outstanding under our credit facility and $55.3 million outstanding under the DG Marine credit facility. DG Marine hedged a portion of its debt through July 2011.

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