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 and minority interests 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 of $26.1 million, or $0.61 per common unit. Non-cash depreciation and amortization totaling $71.4 million reduced net income 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.

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                                                       $     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.

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.

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 CO2 supply 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.

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;

· 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.

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 . . .