GENESIS ENERGY LP - FORM 8-K - EX-99.3 - EXHIBIT 99.3

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EX-23.2 - EXHIBIT 23.2 - GENESIS ENERGY LP	ex23_2.htm
EX-99.2 - EXHIBIT 99.2 - GENESIS ENERGY LP	ex99_2.htm
EX-99.1 - EXHIBIT 99.1 - GENESIS ENERGY LP	ex99_1.htm
8-K - GENESIS ENERGY LP 8-K 9-26-2011 - GENESIS ENERGY LP	form8k.htm
EX-99.4 - EXHIBIT 99.4 - GENESIS ENERGY LP	ex99_4.htm
EX-23.1 - EXHIBIT 23.1 - GENESIS ENERGY LP	ex23_1.htm

EXHIBIT 99.3

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:

Significant Events

Overview of 2010

Available Cash before Reserves

Results of Operations

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 our revenues, expenses and net income, as well as two measures that we use to manage the business and to review the results of our operations. Those two measures are segment margin and Available Cash before Reserves.

We define segment margin as revenues less 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 equity-based compensation plans and the unrealized gains and losses on derivative transactions not designated as hedges for accounting purposes. Segment margin includes the non-income portion of payments received under direct financing leases. Our chief operating decision maker (our Chief Executive Officer) evaluates segment performance based on a variety of measures including segment margin, segment volumes where relevant, and maintenance capital investment. A reconciliation of segment margin to income before income taxes is included in our segment disclosures in Note 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 distributable 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 unrealized gains and losses on derivative transactions not designated as hedges for accounting purposes, the elimination of expenses related to acquiring assets that provide new sources of cash flows, the elimination of earnings of DG Marine in excess of distributable cash until July 29, 2010 when DG Marine’s credit facility was repaid, and the subtraction of maintenance capital expenditures, which are expenditures that are necessary to sustain existing (but not to provide new sources of) cash flows. For additional information on Available Cash before Reserves and a reconciliation of this measure to cash flows from operations, see “Liquidity and Capital Resources - Non-GAAP Financial Measure” below.

Significant Events

Permanent Elimination of IDRs

In February 2010, new investors, together with members of our executive management team, acquired our general partner. At that time, our general partner owned all our 2% general partner interest and all of our incentive distribution rights, or IDRs. At that time, in respect of its general partner interest and IDRs, our general partner was entitled to over 50% of any increased distributions we would pay in respect of our outstanding equity.

On December 28, 2010, we permanently eliminated our IDRs and converted our two percent general partner interest into a non-economic interest. In exchange for our IDRs and the 2% economic interest attributable to our general partner interest, we issued approximately 20 million common units and 7 million “Waiver” units to the stakeholders of our general partner, less approximately 145,000 common units and 50,000 Waiver Units that have been reserved for a new deferred equity compensation plan for employees.

Our Waiver Units have the right to convert into Genesis common units in four equal installments in the calendar quarter during which each of our common units receives a quarterly distribution of at least $0.43, $0.46, $0.49 and $0.52, if our distribution coverage ratio (after giving effect to the then convertible Waiver Units) would be at least 1.1 times.

As a result of the IDR Restructuring, (i) we now have approximately 64.6 million common units outstanding (with the former stakeholders of the general partner owning approximately 45% of such units, including common units owned prior to the IDR Restructuring), (ii) our general partner has become (by way of merger) one of our wholly-owned subsidiaries, (iii) there has been no change in the composition of our board of directors and (iv) the former stakeholders of our general partner will continue to elect our board of directors in the future. See additional discussion under “Liquidity and Capital Resources – Capital Expenditures and Distributions paid to our Common Unitholders and General Partner” below and in Note 11 to our Consolidated Financial Statements.

Cameron Highway Acquisition, Notes Issuance and Equity Issuance

On November 23, 2010, we acquired a 50% interest in Cameron Highway for approximately $330 million. Cameron Highway, a joint venture with Enterprise Products Partners, L.P., owns and operates the largest (measured by both length and capacity) crude oil pipeline system in the Gulf of Mexico. We financed the purchase price for the acquisition primarily with the net proceeds of approximately $119 million from an underwritten public offering of 5.2 million of our common units (including the overallotment option that the underwriters exercised in full and including our general partner’s proportionate capital contribution to maintain its 2% general partner interest) at $23.58 per common unit and net proceeds of approximately $243 million from a private placement of $250 million in aggregate principal amount of 7.875% senior unsecured notes due 2018. We used $23.8 million in excess net proceeds to temporarily reduce the balance outstanding under our revolving credit agreement. See additional discussion under “Liquidity and Capital Resources” below and in Notes 3, 10 and 11 to our Consolidated Financial Statements.

Acquisition of Remaining 51% Interest in DG Marine Acquisition

On July 29, 2010, we acquired the 51% interest in DG Marine held by a related party for $25.5 million, resulting in DG Marine becoming a wholly-owned subsidiary. Additionally, we paid off DG Marine’s stand-alone credit facility with proceeds from our credit agreement.

Credit Facility Restructuring

On June 29, 2010, we restructured our credit agreement. Our credit agreement now provides for a $525 million senior secured revolving credit facility, includes an accordion feature whereby the total credit available can be increased up to $650 million under certain circumstances, and matures on June 30, 2015. Among other modifications, our credit agreement now includes a $75 million sublimit tranche designed for more efficient financing of crude oil and petroleum products inventory. See additional discussion under “Liquidity and Capital Resources – Debt and Equity Financing Activities” below and in Note 10 to our Consolidated Financial Statements.

Distribution Increase

On January 12, 2011, we declared our twenty-second consecutive increase in our quarterly distribution to our common unitholders relative to the fourth quarter of 2010. This distribution of $0.40 per unit (paid in February 2011) represents an 11% increase from our distribution of $0.36 per unit for the fourth quarter of 2009.

Overview of 2010

In 2010, we reported a net loss attributable to Genesis Energy, L.P. of $48.5 million, which included $76.9 million of non-cash compensation charges borne entirely by our general partner. As a result, net income attributable to our common units for 2010 was $19.9 million, or $0.49 per common unit. See additional discussion of the charge related to executive compensation in “Results of Operations – Other Costs and Interest” below.

Segment margin increased by $15.1 million, or 11.2%, in 2010 as compared to 2009. The majority of this increase was attributable to our pipeline transportation and refinery services segments. Onshore crude oil pipeline transportation volumes increased by 13% and CO2 pipeline transportation volumes increased by almost 9%. Our NaHS sales volumes in our refinery services segment increased by 35%. Partially offsetting the increased contribution from these segments was a 5% decline in segment margin from our supply and logistics operations as market conditions reduced the profitability of storing crude oil and products for future delivery and differentials between grades of petroleum products narrowed as discussed in more detail below.

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, until December 28, 2010, our general partner. During 2010, we generated $101.5 million of Available Cash before Reserves, and we distributed $70.4 million to holders of our common units and general partner. Cash provided by operating activities in 2010 was $90.5 million. Our total distributions attributable to 2010 increased 17% over the total distributions attributable to 2009.

Available Cash before Reserves

Available Cash before Reserves for the years ended December 31, 2010, 2009 and 2008 is as follows:

	Year Ended December 31,
	2010			2009			2008
	(in thousands)
Net (loss) income attributable to Genesis Energy, L.P.	$	(48,459	)	$	8,063		$	26,089
Depreciation, amortization and impairment		53,557			67,586			71,370
Cash received from direct financing leases not included in income		4,203			3,758			2,349
Cash effects of sales of certain assets		1,158			873			760
Effects of available cash generated by equity method investees not included in income		2,285			(495	)		1,830
Cash effects of equity-based compensation plans		(1,350	)		(121	)		(385	)
Non-cash tax expense (benefit)		1,337			1,914			(2,782	)
Earnings of DG Marine in excess of distributable cash		(848	)		(4,475	)		(2,821	)
Non-cash equity-based compensation expense		82,979			18,512			-
Expenses related to acquiring or constructing assets that provide new sources of cash flow		11,260			-			-
Other items, net		(1,767	)		(203	)		(2,172	)
Maintenance capital expenditures		(2,856	)		(4,426	)		(4,454	)
Available Cash before Reserves	$	101,499		$	90,986		$	89,784

We have reconciled Available Cash before Reserves (a non-GAAP measure) to cash flows from operating activities (the most comparable GAAP measure) for the each of the periods in the table above in “Capital Resources and Liquidity – Non-GAAP Reconciliation” below. For the years ended December 31, 2010, 2009 and 2008, net cash provided by operating activities was $90.5 million, $90.1 million and $94.8 million, respectively.

Results of Operations

Revenues, Costs and Expenses and Net Income

Our revenues for the year ended December 31, 2010 increased $666 million, or 46% from 2009. Excluding non-cash charges for executive compensation borne by our general partner, our costs and expenses increased $652 million, or 47%, between the two periods. The majority of our revenues and our costs are derived from the purchase and sale of crude oil and petroleum products. The significant increase in our revenues and costs between 2009 and 2010 is primarily attributable to the fluctuations in the market prices for crude oil and petroleum products. In 2010, prices for West Texas Intermediate crude oil on the New York Mercantile Exchange averaged $79.53, as compared to $61.80 in 2009 - a 29% increase. Also contributing to the increase in our revenues and costs was an increase in volumes in all of our segments; although the impact of the increase in our supply and logistics segment was the most significant to revenues and costs. Supply and logistics sales volumes increased by almost 30% between 2010 and 2009.

Net income attributable to Genesis Energy, L.P. declined $56.5 million to a net loss in 2010 of $48.5 million from net income of $8.1 million in 2009. An increase in non-cash charges included in general and administrative expenses related to executive compensation and equity-based compensation borne by our general partner totaling $62.8 million provided the decline in net income. Also reducing net income for 2010 was $7.0 million of one-time costs related to the acquisition of our interest in Cameron Highway and to the IDR Restructuring. A $15.1 million increase in our segment margin somewhat offset these increased costs. See additional discussion of the one-time charges in “Other Costs and Interest” below.

Revenues and costs and expenses in 2009 decreased as compared to 2008 primarily as a result of a 38% decline in market prices for crude oil. Revenues decreased $706 million, or 33%, while costs decreased $690 million, or 33%, between the two periods. Net income attributable to Genesis Energy, L.P. declined from income of $26.1 million in 2008 to $8.1 million in 2009. An increase in non-cash charges included in general and administrative expenses related to executive compensation and equity-based compensation totaling $16.6 million provided most of the decline in net income.

Included below is additional detailed discussion of the results of our operations focusing on segment margin and other costs including general and administrative expense, depreciation, amortization and impairment, interest and income taxes.

Segment Margin

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,
	2010		2009		2008
	(in thousands)
Pipeline transportation	$	48,305	$	42,162	$	33,149
Refinery services		62,923		51,844		55,784
Supply and logistics		38,336		40,484		45,952
Total segment margin	$	149,564	$	134,490	$	134,885

Year Ended December 31, 2010 Compared with Year Ended December 31, 2009

Pipeline Transportation Segment

Operating results and volumetric data for our pipeline transportation segment were as follows.

	Year Ended December 31,
	2010			2009
	(in thousands)
Crude oil tariffs and revenues from direct financing leases - onshore crude oil pipelines	$	20,351		$	17,202
CO2 tariffs and revenues from direct financing leases of CO2 pipelines		26,413			26,279
Sales of crude oil pipeline loss allowance volumes		5,519			4,462
Available cash generated by Cameron Highway		2,384			-
Pipeline operating costs, excluding non-cash charges for equity-based compensation		(11,522	)		(10,477	)
Payments received under direct financing leases not included in income		4,202			3,758
Other		958			938
Segment margin	$	48,305		$	42,162

We operate three onshore 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. Additionally, we own a 50% interest in Cameron Highway. Volumes shipped on these systems for the last two years are as follows (barrels or Mcf per day):

Pipeline System	2010			2009

Mississippi-Bbls/day		23,537			24,092
Jay - Bbls/day		15,646			10,523
Texas - Bbls/day		28,748			25,647
Cameron Highway - Bbls/day		149,270	(1)		-
Free State - Mcf/day		167,619			154,271

(1) Daily average for the period from November 23, 2010 to December 31, 2020 when we owned an interest in Cameron Highway.

Crude Oil Volumes

Volumes on our Mississippi pipeline fluctuate primarily as a result of the operations of Denbury and other producers. The tariff on the Mississippi System is an incentive tariff, such that the average tariff per barrel decreases as the volumes increase; therefore the effect of the decline in the volumes of 555 barrels per day between 2009 and 2010 on that system was mitigated by the relatively low incremental tariff rate. Additional development of surrounding fields using CO2 based operations could offset a portion of any future declines from existing fields.

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. A producer connected to our Jay System shut in production at the end of 2008 due to the decline in crude oil prices in the latter half of 2008. As crude oil market prices increased in late 2009 and 2010, the producer restored production capabilities to his fields resulting in a volumetric increase on the Jay system of approximately 49% as compared to 2009. New production in the area also contributed to the volumetric increase with a greater impact on tariff revenue for us due to the greater distance that the crude oil is transported on the pipeline.

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 connecting carriers for supply, and on the two refineries for demand for our services. Volumes on the Texas System may continue to fluctuate as refiners on the Texas Gulf Coast compete for crude oil with other markets.

During the five weeks we owned an interest in Cameron Highway, the average daily revenue volume of that joint venture was 149,270 barrels per day.

CO2 Volumes

Under the terms of a transportation services agreement extending through 2028, we deliver CO2 on the Free State pipeline for use in tertiary recovery operations in east Mississippi. We are responsible for owning, operating, maintaining and making improvements to the pipeline. Denbury currently 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. Variations in Denbury’s CO2 tertiary recovery activities create the fluctuations in the volumes transported on the Free State pipeline. 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 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.

We also have a twenty-year financing lease (through 2028) with Denbury initially valued at $175 million related to Denbury’s North East Jackson Dome (NEJD) Pipeline System. Denbury makes fixed quarterly base rent payments to us of $5.2 million per quarter or approximately $20.7 million per year.

Segment Margin

Pipeline segment margin increased $6.1 million in 2010 as compared to 2009. This increase is primarily attributable to the following factors:

Our share of the available cash before reserves generated by Cameron Highway beginning in the latter part of November 2010 added $2.4 million to Segment Margin,

An increase in volumes transported on our crude oil pipelines between the two periods increased segment margin by $2.1 million,

Tariff rate changes in July 2009 and July 2010 resulted in an increase of approximately $0.4 million between the two periods.

An increase in revenues from sales of pipeline loss allowance volumes increased Segment Margin by $1.1 million. This revenue increase is due primarily to increased crude oil market prices, although the increase in volumes transported in our onshore pipelines also contributed to the additional revenue.

Pipeline operating costs increased approximately $1.0 million due to an increase in pipeline integrity tests and other maintenance costs. In the first quarter of 2010 pipeline integrity tests on a segment of our Texas System cost approximately $0.6 million.

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. The increase in market prices for crude oil increased the value of our pipeline loss allowance volumes and, accordingly, our loss allowance revenues. Average crude oil market prices increased approximately $18 per barrel between the two periods. Pipeline loss allowance volumes decreased by approximately 8,300 barrels between the annual periods. 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.

Refinery Services Segment

Operating results from our refinery services segment were as follows (in thousands, except average index price):

	Year Ended December 31,
	2010			2009
Volumes sold:
NaHS volumes (Dry short tons "DST")		145,213			107,311
NaOH volumes (DST)		93,283			88,959
Total		238,496			196,270

NaHS revenues	$	119,688		$	97,962
NaOH revenues		29,578			38,773
Other revenues		9,190			10,505
Total external segment revenues	$	158,456		$	147,240

Segment margin	$	62,923		$	51,844

Average index price for NaOH per DST (1)	$	353		$	424

Raw material and processing costs as % of segment revenues		37	%		44	%
Delivery costs as a % of segment revenues		15	%		12	%

(1)

Source: Harriman Chemsult Ltd.

Refinery services Segment Margin for the year ended 2010 was $62.9 million, an increase of $11.1 million, or 21% from the year ended 2009. The significant components of this change were as follows:

An increase in NaHS volumes of 35%. As the world economies, particularly outside of the United States and European Union, are recovering from the depths of the greatest recession in the last 70 years, the demand for base metals such as copper and molybdenum has increased over the prior period. As a result, we have experienced a noticeable increase in the demand for NaHS from our mining customers in North and South America. Additionally, with the return of industrialization and urbanization in the world’s more underdeveloped economies, the demand for paper products and packaging materials has increased. This trend has led to an increase in demand for NaHS from our pulp/paper customers primarily in North America. The pricing in the majority of our sales contracts for NaHS includes an adjustment for fluctuations in commodity benchmarks, freight, labor, energy costs and government indexes. The frequency at which these adjustments can be applied varies by geographic region and supply point.

An increase in NaOH (or caustic soda) sales volumes of 5%. Caustic soda is a key component in the provision of our sulfur-removal service, from which we receive the by-product NaHS. We are a very large consumer of caustic soda. In addition, our economies of scale and logistics capabilities allow us to effectively market caustic soda to third parties. Fluctuations in volumes sold are affected by the demand we have in our operations that consume caustic soda.

Index prices for caustic soda averaged approximately $424 per DST in 2009. Market index prices of caustic soda decreased to an average of approximately $353 per DST during 2010. Those price movements affect the revenues and costs related to our sulfur removal services as well as our caustic soda sales activities. However, changes in caustic soda prices do not materially affect Segment Margin attributable to our sulfur processing services because we generally pass those costs through to our NaHS sales customers.

Somewhat mitigating the increase in segment margin was an increase in delivery logistics costs. Although our logistics costs per unit increased only modestly, our logistics costs expressed as a percentage of revenues increased by 3% (to 15%) primarily because our sales price per unit, along with our cost per unit declined. Quantities delivered to customers also increased. Freight demand and fuel prices increased modestly in the 2010 period as economic conditions improved, increasing demand for transportation services and the increase in crude oil prices increased the cost of fuel used in transporting these products.

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, transporting the products to one of our terminals and blending the products to a quality that meets the requirements of our customers;

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

industrial gas activities, including wholesale marketing of CO2 and processing of syngas through a joint venture.

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 feedstocks. Despite crude oil being considered a somewhat homogenous commodity, many refiners are very particular about the quality of crude oil feedstock they 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 under the accounting guidance. See Notes 17 and 18 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 “heavier” petroleum products that are the residual fuels from gasoline production, 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 250 trucks and 280 trailers and DG Marine’s twenty “hot-oil” barges in combination with our 1.5 million barrels of existing leased and owned storage to service our refining customers and to store and blend the intermediate and finished refined products.

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

	Year Ended December 31,
	2010			2009
	(in thousands)
Supply and logistics revenue	$	1,894,612		$	1,243,044
Crude oil and products costs, excluding unrealized gains and losses from derivative transactions		(1,761,161	)		(1,115,809	)
Operating and segment general and administrative costs,excluding non-cash charges for stock-based compensation and other non-cash expenses		(97,371	)		(87,802	)
Other		2,256			1,051
Segment margin	$	38,336		$	40,484

Volumes of crude oil and petroleum products (mbbls)		22,823			17,563

As discussed above in “Revenues, Costs and Expenses and Net Income,” the average market prices of crude oil increased by approximately $18 per barrel, or approximately 29% between the two periods. Similarly, market prices for petroleum products increased significantly between 2009 and 2010. Fluctuations in these prices, however, have a limited impact on our segment margin.

The key factors affecting the change in segment margin between 2010 and 2009 were as follows:

The contango price market narrowed beginning late in the fourth quarter of 2009 and extended through most of 2010 decreasing the effects on contribution to Segment Margin of our crude oil activities.

Fluctuations in differentials related to heavy end petroleum products decreased segment margin from our petroleum products marketing activities.

Beginning late in 2008 and throughout most of 2009, the crude oil market was in wide contango. When crude oil markets are in contango, oil prices for future deliveries are higher than for current deliveries, providing an opportunity for us to purchase crude oil at current market prices, re-sell it through futures contracts at future prices, and store it as inventory until delivery. In 2009, we took advantage of contango conditions, holding an average of 174,000 barrels of crude oil in storage throughout the year. In 2010, contango market conditions had narrowed and we reduced the volumes of crude oil stored to take advantage of the contango conditions to an average of 101,000 barrels of crude oil throughout the year. This change in contango market conditions was the primary factor in the $1.1 million decrease in the contribution to segment margin of our crude oil gathering and marketing activities.

Our petroleum products activities involve handling volumes from the heavy end of the refined barrel. Our access to logistical assets (owned and leased trucks, leased railcars and barges) as well as our access to terminals (owned and leased), provided us with greater opportunities in 2010 to acquire increased volumes of petroleum products for sale or for blending. However, fluctuations in the differentials between crude oil and fuel oils combined with variances in the values of other products we sell or utilize in our blending activities reduced the margins between the costs at which we obtained the heavy end products from refiners and the sales prices for those products. The contribution to Segment Margin in 2010 decreased by $2.2 million, as compared to 2009, as a result of these activities.

An increase of $0.5 million in the contribution to segment margin by our barge operations in 2010 as compared to 2009 partially offset these decreases. In 2010, we were successful in increasing the average day rates for utilization of our barges and overall utilization rate of our fleet improved as market conditions for refiners increased the volumes of heavy end products to be transported throughout the U.S. inland waterways and along the Gulf Coast.

Our share of available cash before reserves generated by our equity investment in T&P Syngas increased from $0.9 million in 2009 to $2.3 million in 2010, partially offsetting the decrease in segment margin from changes in contango market conditions. In the third quarter of 2009, T&P Syngas performed a scheduled turnaround at its facility that decreased its revenues and increased maintenance expenses. Additionally T&P incurred expenses related to improving its treatment of waster water.

Other Costs and Interest

General and administrative expenses were as follows.

	Year Ended December 31,
	2010		2009
	(in thousands)
General and administrative expenses not separately identified below	$	20,469	$	20,277
Expenses related to change in owner of our general partner		1,762		-
Transaction costs related to IDR restructuring and growth projects including acquisition of interest in Cameron Highway		7,290		-
Bonus plan expense		5,007		3,900
Equity-based compensation plan expense		1,955		2,132
Non-cash compensation expense related to management team		76,923		14,104
Total general and administrative expenses	$	113,406	$	40,413

Although our general and administrative expenses increased substantially, 86% of the increase was due to non-cash compensation expense related to our management team and borne by the former owners of our general partner, as described in more detail below. Routine general and administrative expense increased by $0.2 million to $20.7 million in 2010 as compared to 2009, primarily as a result of additions to personnel consistent with our growth during 2010.

Transaction costs related to the restructuring of our IDRs and growth projects including the acquisition of our 50% interest in Cameron Highway totaled $7.3 million in 2010, or 10% of the remaining increase in general and administrative expenses. These transaction costs consisted primarily of fees paid to legal and financial advisors for their assistance in the evaluation and completion of these transactions.

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. As a result of our performance in 2010, the pool available for bonuses was determined to be $1.1 million more than 2009. The bonus plan for employees is described in Item 11, “Executive Compensation” below.

Due to fluctuations in the market price for our common units, expense for outstanding and exercised SARs and phantom units issued under our 2010 Long-Term Incentive Plan has varied significantly between the periods. In 2009 and the first quarter of 2010, we also had phantom units issued and outstanding under our 2007 Long-Term Incentive Plan. The fair value of phantom units issued under this long-term incentive plan are calculated at the grant date and charged to expense over the vesting period of the phantom units. Unlike the accounting for the SAR plan and 2010 LTIP, the total expense to be recorded was determined at the time of the award and did not change. The change in control of our general partner in February 2010 resulted in the vesting of the outstanding phantom units under our 2007 LTIP and the recognition of the remaining grant date fair value as an expense in 2010.

We finalized a compensation structure in December 2008 for members of our management team. The terms of these compensation arrangements provided that our management team would vest in the package and receive certain payments upon a change in control of our general partner. During 2009, we recorded compensation expense of $14.1 million related to these arrangements, and we recorded a reduction in compensation expense of $2.1 million in 2010 upon vesting of the package when the change in control occurred in February 2010 in which a group of investors acquired all of the equity interest in our general partner.

In February 2010, certain members of our management received new equity interests in our general partner (Series B units) that would increase in value as the net cash distributions to the owners of our general partner increased, with a conversion to Series A units in our general partner at the end of seven years or under certain other conditions. As a result of the IDR Restructuring, the Series B units were exchanged for units issued by us, which is characterized as compensation expense. The management team members received Class A Common Units and Waiver Units in the restructuring, with a total fair value of approximately $79.1 million attributable to the Series B units, which was recorded as expense in 2010.

Although the compensation under both of these arrangements ultimately came from our general partner, we recorded the fair value of the compensation expense in our Consolidated Statements of Operations in general and administrative expenses due to the rules for accounting for transactions where the beneficiary of a transaction is not the same as the parties to the transaction. See additional discussion of the compensation arrangements with our senior management team in Item 11, “Executive Compensation.”

Depreciation, amortization and impairment expense was as follows:

	Year Ended December 31,
	2010		2009
	(in thousands)
Depreciation on fixed assets	$	22,498	$	25,208
Amortization of intangible assets		26,805		33,099
Amortization of CO2 volumetric production payments		4,254		4,274
Impairment expense		-		5,005
Total depreciation, amortization and impairment expense	$	53,557	$	67,586

Depreciation and amortization expense decreased $9 million between 2010 and 2009 primarily as a result of the lower amortization expense recognized on intangible assets. We amortize our intangible assets over the period which we expect them to contribute to our future cash flows. The amortization we record on those assets is greater in the initial years following their acquisition because the value of our intangible assets such as customer relationships and trade names are generally more valuable in the first years after an acquisition. Accordingly, the amount of amortization we have recorded has declined since we acquired those assets in 2007. See Note 9 of the Notes 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. Amortization of CO2 volumetric payments fluctuate as a result of increases or decreases in the volume of CO2 sold..

In 2009, we recorded a $5.0 million impairment charge related to our investment in the Faustina Project. The Faustina Project is a petroleum coke to ammonia project in which we first made an investment in 2006. As a result of a review of the financing alternatives available for the project to use as construction financing and a determination not to continue making investments in the project beginning in 2010, we determined that the likelihood of a recovery of our investment was remote and the fair value of the investment was zero. For additional information related to this charge, see Note 8 of the Notes to the Consolidated Financial Statements.

Interest expense, net was as follows:

	Year Ended December 31,
	2010			2009
	(in thousands)
Genesis Facilities and Notes:
Interest expense, credit facility, including commitment fees	$	10,624		$	8,148
Interest expense, senior unsecured notes		2,406			-
Bridge financing fees		3,219			-
Amortization and write-off of facility and notes issuance fees		1,953			662
DG Marine Facility:
Interest expense and commitment fees		2,512			4,446
Interest rate swaps settlement		1,553			-
Write-off of facility fees		794			586
Capitalized interest		(84	)		(112	)
Interest income		(53	)		(70	)
Net interest expense	$	22,924		$	13,660

Our average outstanding credit facility balance (excluding interest on DG Marine’s stand-alone facility), was $31.4 million higher in 2010 than 2009. The increase in the credit facility balance is attributable primarily to the acquisition of the 51% ownership interest in DG Marine we did not own and the elimination of the DG Marine credit facility with borrowings under our credit facility.

We also incurred interest expense of $2.4 million in connection with the issuance of $250 million of senior unsecured notes in November 2010 to partially finance our acquisition of a 50% equity interest in Cameron Highway. At the time we agreed to acquire the interest in Cameron Highway, we had not yet issued the senior unsecured notes, nor had we issued the equity that was used to finance the acquisition. In order to ensure that we would have funds available at the time of the closing of the Cameron Highway transaction, we entered into a bridge arrangement that would have provided financing for the acquisition for a period of time until we could secure longer term financing. These fees totaled $3.2 million.

Consolidated net interest expense was also affected by interest on the DG Marine credit facility during the seven months it was outstanding and costs to settle the DG Marine interest rate swaps and the write-off of facility fees related to the DG Marine credit facility due to its repayment.

Income taxes. A portion of our operations are owned by wholly-owned corporate subsidiaries that are taxable as corporations. As a result, a substantial portion of the income tax expense we record relates to the operations of those corporations, and will vary from period to period as a percentage of our income before taxes based on the percentage of our income or loss that is derived from those corporations. The balance of the income tax expense we record relates to state taxes imposed on our operations that are treated as income taxes under generally accepted accounting principles. In 2010 and 2009, we recorded income tax expense of $2.6 million and $3.1 million, respectively.

Year Ended December 31, 2009 Compared with Year Ended December 31, 2008

Pipeline Transportation Segment

Operating results and volumetric data for our pipeline transportation segment were as follows.

	Year Ended December 31,
	2009			2008
	(in thousands)
Crude oil tariffs and revenues from direct financing leases - onshore crude oil pipelines	$	17,202		$	16,280
CO2 tariffs and revenues from direct financing leases of CO2 pipelines		26,279			15,733
Sales of crude oil pipeline loss allowance volumes		4,462			8,542
Pipeline operating costs, excluding non-cash charges for equity-based compensation		(10,477	)		(10,529	)
Payments received under direct financing leases not included in income		3,758			2,349
Other		938			774
Segment margin	$	42,162		$	33,149

Volumes shipped on our pipeline systems in 2009 and 2008 are as follows (barrels or Mcf per day):

Pipeline System	2009		2008

Mississippi-Bbls/day		24,092		25,288
Jay - Bbls/day		10,523		13,428
Texas - Bbls/day		25,647		25,395
Free State - Mcf/day		154,271		160,220	(1)

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

Pipeline segment margin increased $9.0 million in 2009 as compared to 2008. This increase is primarily attributable to the following factors:

An increase in revenues from CO2 financing leases and tariffs of $10.5 million and a related increase in payments from the same financing leases of $1.4 million not included as income (non-income payments under direct financing leases).

Tariff rate increases of approximately 7.6% on our Jay and Mississippi pipelines that went into effect July 1, 2009. The rate increases increased segment margin between the two periods by approximately $1.9 million.

Partially offsetting the increase in segment margin was a decrease in revenues from sales of pipeline loss allowance volumes of $4.1 million,

A decline in volumes transported on our crude oil pipelines between the two periods decreased segment margin by $1.0 million.

Revenues for 2008 only included results from the NEJD and Free State CO2 pipelines for a seven-month period while 2009 included results for a twelve-month period. The average volume transported on the Free State pipeline for 2009 was 154 MMcf per day, with the transportation fees and the minimum payments totaling $7.3 million and $1.2 million, respectively. Transportation fees and the minimum payments for the seven months in 2008 were $4.4 million and $0.7 million, respectively, with an average transportation volume of 160 MMcf per day.

The decline in market prices for crude oil reduced the value of our pipeline loss allowance volumes and, accordingly, our loss allowance revenues. Average crude oil market prices decreased approximately $38 per barrel between the two periods. In addition, pipeline loss allowance volumes decreased by approximately 10,000 barrels between the annual periods.

Refinery Services Segment

Operating results from our refinery services segment were as follows (in thousands, except average index price):

	Year Ended December 31,
	2009			2008
Volumes sold:
NaHS volumes (Dry short tons "DST")		107,311			162,210
NaOH volumes (DST)		88,959			68,647
Total		196,270			230,857

NaHS revenues	$	97,962		$	167,715
NaOH revenues		38,773			53,673
Other revenues		10,505			12,483
Total external segment revenues	$	147,240		$	233,871

Segment margin	$	51,844		$	55,784

Average index price for NaOH per DST (1)	$	424		$	702

Raw material and processing costs as % of segment revenues		44	%		41	%
Delivery costs as a % of segment revenues		12	%		8	%

(1)

Source: Harriman Chemsult Ltd.

Segment margin for our refinery services segment decreased $3.9 million between 2009 and 2008. The significant components of this change were as follows:

NaHS volumes declined 34%. Macroeconomic conditions negatively impacted the demand for NaHS, primarily in mining and industrial activities. A significant decline in the market prices and demand for copper and molybdenum in the last quarter of 2008 continued through most of 2009. Copper and molybdenum prices improved and demand for NaHS increased in the fourth quarter of 2009; however the increases in NaHS sales in that quarter did not offset the declines in the first three quarters of 2009.

NaOH (or caustic soda) sales volumes increased 30%. With the decline in NaHS production during 2009, we focused on expanding our activities as a NaOH supplier.

Average index prices for caustic soda were somewhat volatile in 2008, ranging from an average index price of approximately $450 per dry short ton (DST) during the first quarter of 2008 to a high of $950 per DST in the fourth quarter of 2008. During 2009 market prices of caustic soda decreased to approximately $230 per DST by the end of the year. This volatility affected both the cost of caustic soda used to provide our services as well as the price at which we sold NaHS and caustic soda.

Raw material and processing costs related to providing our refinery services and supplying caustic soda as a percentage of our segment margin increased 3% between periods. As the market price of caustic soda fluctuated in 2008 and 2009, we had to aggressively manage our acquisition costs to minimize purchasing caustic soda for use in our operations in a period of falling market prices. We were generally successful in this management, as reflected by the relatively small percentage increase in costs despite the significant decline in caustic prices. We also took steps to reduce processing costs and to manage our logistics costs related to our caustic soda purchases.

Supply and Logistics Segment

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

	Year Ended December 31,
	2009			2008
	(in thousands)
Supply and logistics revenue	$	1,243,044		$	1,870,063
Crude oil and products costs, excluding unrealized gains and losses from derivative transactions		(1,115,809	)		(1,736,637	)
Operating and segment general and administrative costs,excluding non-cash charges for stock-based compensation and other non-cash expenses		(87,802	)		(89,813	)
Other		1,051			2,339
Segment margin	$	40,484		$	45,952

Volumes of crude oil and petroleum products (mbbls)		17,563			17,410

As discussed above in “Revenues, Costs and Expenses and Net Income,” the average market prices of crude oil declined by approximately $38 per barrel, or approximately 38% between the two periods. Similarly, market prices for petroleum products declined significantly between 2008 and 2009. Fluctuations in these prices, however, have a limited impact on our segment margin.

The key factors affecting the change in segment margin between 2009 and 2008 were as follows:

Segment margin generated by DG Marine’s inland marine barge operations, which increased segment margin by $5.6 million;

Crude oil contango market conditions, which increased segment margin by $2.2 million; and

Reduction in opportunities to purchase and blend crude oil and products, which reduced segment margin by $11.1 million.

The inland marine transportation operations of Grifco Transportation, acquired by DG Marine in mid-July of 2008, contributed $5.6 million more to segment margin in 2009 as compared to 2008, primarily as a result of owning these operations for twelve months in 2009 as compared to approximately six months in 2008. These operations provided us with an additional capability to provide transportation services of petroleum products by barge. As part of the acquisition, DG Marine acquired six tows (a tow consists of a push boat and two barges.) A total of four additional tows added in the fourth quarter of 2008 and first half of 2009 generated the segment margin increase despite declines in average charter rates for the tows over the same period.

During 2009, crude oil markets were in contango, providing an opportunity for us to purchase and store crude oil as inventory for delivery in future months. The crude oil markets were not in contango during most of 2008. During 2009, we held an average of approximately 174,000 barrels of crude oil per month in our storage tanks and hedged this volume with futures contracts on the NYMEX. The effect on segment margin of storing this inventory was a $2.2 million gain in 2009.

Offsetting these improvements in segment margin was a decrease in the margins from our crude oil gathering and petroleum products marketing operations. In 2009, we experienced some reductions in volumes as a result of crude oil producers’ choices to reduce operating expenses or postpone development expenditures that could have maintained or enhanced their existing production levels. As a consequence of the reductions in volumes, our segment margin from crude oil gathering declined between the annual periods by $2.7 million. Volatile price changes in the petroleum products markets and robust refinery utilization in 2008 created blending and sales opportunities with expanded margins in comparison to historical rates. Relatively flat petroleum prices and reduced refinery utilization in 2009 narrowed the economics of our blending opportunities and reduced sales margins to more historical rates. The net result of these factors was a reduction of our segment margin of $8.5 million from petroleum products and related activities.

Transportation costs for the CO2 remained consistent as a percentage of revenues at approximately 36% to 37%. The transportation rate we pay Denbury is adjusted annually for inflation in a manner similar to the sales prices for the CO2. We also recorded a charge for approximately $0.3 million in 2009 and $0.9 million in 2008 related to a commission on one of the industrial gas sales contracts.

Due to a scheduled turnaround at T&P Syngas in 2009, available cash generated by our equity investees decreased in 2009 as compared to 2008.

Other Costs and Interest

General and administrative expenses were as follows:

	Year Ended December 31,
	2009		2008
	(in thousands)
General and administrative expenses not separately identified below	$	20,277	$	25,131
Bonus plan expense		3,900		4,763
Equity-based compensation plan expense (credit)		2,132		(394	)
Non-cash compensation expense related to management team		14,104		-
Total general and administrative expenses	$	40,413	$	29,500

The primary reason for the $10.9 million increase in general and administrative expenses between 2008 and 2009 was $14.1 million of non-cash compensation we recorded related to the arrangements between our executive management team and our general partner. Partially offsetting that increase was a decline in routine general and administrative expenses of approximately $4.9 million, resulting primarily from a reduction in professional fees and services. Between 2009 and 2008, our bonus pool decreased by $0.9 million as a function of our operating results.

Depreciation, amortization and impairment expense was as follows:

	Year Ended December 31,
	2009		2008
	(in thousands)
Depreciation on fixed assets	$	25,208	$	20,415
Amortization of intangible assets		33,099		46,418
Amortization of CO2 volumetric production payments		4,274		4,537
Impairment expense		5,005		-
Total depreciation, amortization and impairment expense	$	67,586	$	71,370

Depreciation and amortization expense decreased $8.5 million between 2009 and 2008 primarily as a result of the lower amortization expense recognized on intangible assets. As discussed above, we amortize our intangible assets over the period which we expect them to contribute to our future cash flows, and that amortization has declined since we acquired the assets. We recorded an impairment charge in 2009 that partially offset the decline in intangible amortization.

Interest expense, net was as follows:

	Year Ended December 31,
	2009			2008
	(in thousands)
Genesis Facilities and Notes:
Interest expense, credit facility, including commitment fees	$	8,148		$	10,738
Amortization and write-off of facility and notes issuance fees		662			664
DG Marine Facility:
Interest expense and commitment fees		4,446			2,269
Write-off of facility fees		586			-
Capitalized interest		(112	)		(276	)
Interest income		(70	)		(458	)
Net interest expense	$	13,660		$	12,937

Net interest expense (excluding interest on DG Marine’s credit facility) increased from 2008 to 2009 as the average outstanding debt balance increased $114 million primarily due to the CO2 pipeline dropdown transactions in May 2008 and the DG Marine acquisition in July 2008. The increase in outstanding debt during 2009 partially offset the effect of the lower interest rates, with the result of an overall decrease in 2009 for interest and commitment fees of $2.6 million.

DG Marine incurred interest expense in 2009 of $4.4 million under its credit facility. Interest expense for DG Marine in 2008 included only five months of activity subsequent to the acquisition of the Grifco assets in July 2008, resulting in an increase in net interest expense between 2009 and 2008.

Liquidity and Capital Resources

General

As of December 31, 2010, we believe our balance sheet and liquidity position remained strong. We had $160.4 million of borrowing capacity available under our $525 million senior secured bank revolving credit facility. We anticipate that our future internally-generated funds and the funds available under our credit facility will allow us to meet our short-term capital needs.

Our primary cash requirements consist of:

Routine operating expenses;

Capital expansion and maintenance projects;

Acquisitions of assets or businesses;

Interest payments on our debt obligations; and

Quarterly cash distributions to our unitholders.

We continue to pursue a growth strategy that requires significant capital. As discussed above in the Overview, we acquired a 50% interest in Cameron Highway for $330 million in November 2010. We funded this acquisition with a combination of equity and debt. Additionally, in 2010, we acquired the portion of DG Marine we did not already own utilizing funds from our revolving credit facility.

During 2010, we amended and expanded our credit facility to provide additional financial flexibility, issued senior unsecured notes for the first time in a private placement, permanently eliminated our IDRs, and issued new equity for cash in a public offering. See additional discussion below in “Debt and Equity Financing Activities”.

While our credit facility provides additional flexibility and committed borrowing capacity, our ability to satisfy future capital needs will depend on our ability to raise substantial amounts of additional capital, including through equity and debt offerings (public and private) from time to time and other financing transactions, to utilize our credit facility and to implement our growth strategy successfully. No assurance can be made that we will be able to raise the necessary funds on satisfactory terms. If we are unable to raise the necessary funds, we may be required to defer our growth plans until such time as funds become available.

Debt and Equity Financing Activities

On June 29, 2010, we restructured our credit facility – which we entered into in November 2006 and which was to mature in November 2011 – to reflect and better accommodate our larger and more diversified operations and resulting credit metrics. Our restructured credit facility is a $525 million senior secured revolving credit facility maturing on June 30, 2015. It includes an accordion feature whereby the total credit available can be increased up to $650 million for acquisitions or internal growth projects, with lender approval. Among other modifications, our credit facility also includes a $75 million inventory sublimit tranche. This inventory tranche is designed to allow us to more efficiently finance crude oil and petroleum products inventory in the normal course of our operations, by allowing us to exclude the amount of inventory loans from our total outstanding indebtedness for purposes of determining our applicable interest rate. Additionally, our restructured credit facility does not include a “borrowing base” limitation except with respect to our inventory loans. Twelve lenders participate in our credit facility, and we do not anticipate any of them being unable to satisfy their obligations under the credit facility. Additional information on our restructured credit facility is included in Note 10 to the Consolidated Financial Statements.

In November 2010, we raised approximately $362 million with a combination of an equity and debt issuance. We issued 5,175,000 common units at $23.58, providing total net proceeds, after deducting underwriting discounts and commissions and estimated offering expenses and including our general partner’s proportionate capital contribution to maintain its 2% general partner interest, of approximately $119 million. We also issued $250 million of senior unsecured notes in a private placement. The notes bear interest at 7.875% and will mature on December 15, 2018. We have agreed to register these notes with the SEC within one year of the date of issuance. We have the option to redeem the notes, in whole or in part, at any time after December 15, 2014, at varying redemption prices. These funds were primarily utilized for the acquisition of our interest in Cameron Highway, and the excess funds were utilized to temporarily reduce the balance under our revolving credit facility. See Note 10 to the Consolidated Financial Statements for additional information about the notes we issued.

In December 2010, we permanently eliminated our IDRs and converted our two percent general partner interest into a non-economic interest. In exchange for the IDRs and the 2% economic interest attributable to our general partner interest, we issued approximately 20 million common units and 7 million “Waiver” units to the stakeholders of our general partner, less approximately 145,000 common units and 50,000 Waiver Units that have been reserved for a new deferred equity compensation plan for employees. The Waiver Units have the right to convert into Genesis common units in four equal installments in the calendar quarter during which each of our common units receives a quarterly distribution of at least $0.43, $0.46, $0.49 and $0.52, if our distribution coverage ratio (after giving effect to the then convertible Waiver Units) would be at least 1.1 times. Prior to the elimination of our IDRs, our general partner was entitled to over 50% of any increased distributions we would pay in respect of our outstanding equity. We believe the elimination of our IDRs will lower our cost of capital and enhance our ability to grow the partnership.

On July 29, 2010, in connection with our acquisition of the 51% interest of DG Marine that we did not own, we paid off DG Marine’s stand-alone credit facility, which had an outstanding principal balance of $44.4 million, with proceeds from our credit agreement. See Note 3 to our Consolidated Financial Statements.

Cash Flows from Operations

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

We typically sell our crude oil in the same month in which we purchase it and we do not rely on borrowings under our credit facility to pay for the crude oil. During such periods, our accounts receivable and accounts payable generally move in tandem as we make payments and receive payments for the purchase and sale of oil. However, when the crude oil markets are in contango, we may store crude for future delivery utilizing futures contracts to hedge our risk to fluctuations in prices.

In our petroleum products activities, we buy products and typically either move the products to one of our storage facilities for further blending or we sell the product within days of our purchase. The cash requirements for these activities can result in short term increases and decreases in our borrowings under our credit facility.

The storage of crude oil and petroleum products can have a material impact on our cash flows from operating activities. In the month we pay for the stored oil or products, we borrow under our credit facility (or pay from cash on hand) to pay for the oil or products, which negatively impacts our operating cash flows. Conversely, cash flow from operating activities increases during the period in which we collect the cash from the sale of the stored oil or products. Additionally, we may be required to deposit margin funds with the NYMEX when prices increase as the value of the derivatives utilized the hedge the price risk in our inventory fluctuates. These deposits also impact our operating cash flows as we borrow under our credit facility or use cash on hand to fund the deposits.

Net cash flows provided from our operating activities for the twelve months ended December 31, 2010 were approximately $90.5 million. As discussed above, changes in our inventory levels due to storage impact the cash provided from operating activities. Additionally, changes in the market prices for crude oil and petroleum products can result in fluctuations in our operating cash flows between periods as the cost to acquire a barrel of oil or products will require more cash. At December 31, 2010, the cost of the inventory on our balance sheet increased by $15.2 million over the cost at December 31, 2009. Prepayments by customers for crude oil at December 31, 2010 increased, however, partially offsetting the increased use of cash for inventory.

Capital Expenditures and Distributions Paid to our Unitholders and General Partner

We use cash primarily for our acquisition activities, internal growth projects and distributions paid to our unitholders and general partner. We finance internal growth projects and distributions primarily with cash generated by our operations. Acquisition activities have historically been funded with borrowings under our credit facility and equity issuances and, beginning in 2010, the issuance of senior unsecured notes.

Capital Expenditures, and Business and Asset Acquisitions

The most significant investing activities in 2010 were expenditures related to the acquisition of a 50% equity interest in Cameron Highway and our project to upgrade our information technology systems discussed below. Additionally we utilized funds to acquire the 51% interest in DG Marine that we did not already own for approximately $26.3 million, including transaction costs.

A summary of our expenditures for fixed assets, businesses and other asset acquisitions in the three years ended December 31, 2010, 2009, and 2008 is as follows:

	Years Ended December 31,
	2010		2009		2008
	(in thousands)
Capital expenditures for fixed and intangible assets:
Maintenance capital expenditures:
Pipeline transportation assets	$	522	$	1,281	$	719
Supply and logistics assets		901		1,667		729
Refinery services assets		1,433		1,246		1,881
Administrative and other assets		-		232		1,125
Total maintenance capital expenditures		2,856		4,426		4,454

Growth capital expenditures:
Pipeline transportation assets		573		1,762		7,589
Supply and logistics assets		839		19,099		22,659
Refinery services assets		-		1,326		3,609
Information technology systems upgrade project		10,613		-		-
Total growth capital expenditures		12,025		22,187		33,857
Total		14,881		26,613		38,311

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
Acquisition of intangible assets		-		2,500		-
Total		-		2,500		347,964

Capital expenditures related to equity investees and other investments		332,462		83		2,397
Total		332,462		83		2,397
Total capital expenditures	$	347,343	$	29,196	$	388,672

In 2010, we acquired our 50% interest in Cameron Highway for $330 million, plus an additional $2.5 million purchase price adjustment related to the working capital of Cameron Highway and its operating activities for November. We also substantially completed a project to upgrade and integrate our existing information technology systems in order to be positioned for further growth.

In 2010, we acquired TD Marine’s effective 51% interest in DG Marine for $25.5 million in cash plus $0.8 million in direct transaction costs associated with the acquisition, resulting in DG Marine becoming wholly-owned by us. We funded the acquisition with proceeds from our credit agreement, including (i) paying off DG Marine’s stand-alone credit facility, which had an outstanding principal balance of $44.4 million, and (ii) settling DG Marine’s interest rate swaps, which resulted in $1.3 million being reclassified from Accumulated Other Comprehensive Loss (“AOCL”) to interest expense in the third quarter of 2010.

During 2011, we expect to expend approximately $3.0 million to $4.0 million for maintenance capital projects in progress or planned. Those expenditures are expected to include improvements in all of our businesses. In future years we expect to spend $4 million to $5 million per year on maintenance capital projects. We also expect to expend approximately $2 million for the completion of the remaining phases of our information systems project.

Expenditures for capital assets to grow the partnership distribution will depend on our access to debt and equity capital. We will look for opportunities to acquire assets from other parties that meet our criteria for stable cash flows.

Distributions to Unitholders and our General Partner

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. 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 twenty-two quarters, including the distribution paid for the fourth quarter of 2010, as shown in the table below (in thousands, except per unit amounts). Each quarter, our board of directors 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 2008	February 2009	$	0.3300	$	13,021	$	266	$	823	$	14,110
First quarter 2009	May 2009	$	0.3375	$	13,317	$	271	$	1,125	$	14,713
Second quarter 2009	August 2009	$	0.3450	$	13,621	$	278	$	1,427	$	15,326
Third quarter 2009	November 2009	$	0.3525	$	13,918	$	284	$	1,729	$	15,931
Fourth quarter 2009	February 2010	$	0.3600	$	14,251	$	291	$	2,037	$	16,579
First quarter 2010	May 2010	$	0.3675	$	14,548	$	297	$	2,339	$	17,184
Second quarter 2010	August 2010	$	0.3750	$	14,845	$	303	$	2,642	$	17,790
Third quarter 2010	November 2010	$	0.3875	$	15,339	$	313	$	3,147	$	18,799
Fourth quarter 2010	February 2011 (1)	$	0.4000	$	25,846	$	-	$	-	$	25,846

(1) This distribution was paid on February 14, 2011 to unitholders of record as of February 2, 2011.

On December 28, 2010, we permanently eliminated our IDRs and converted our general partner interest into a non-economic interest. In connection with this transaction, we issued approximately 20 million common units. These common units and the new units sold to the public in November 2010 participated in the distribution for the fourth quarter of 2010 included in the table above.

We also issued approximately 7 million Waiver Units in connection with the elimination of our IDRs. The Waiver Units, which are entitled to a minimal preferential distribution, have the right to convert into Genesis common units, on a one-for-one basis, in four equal installments in the calendar quarter during which each of our common units receives a quarterly distribution of at least $0.43, $0.46, $0.49 and $0.52, if our distribution coverage ratio (after giving effect to the then convertible Waiver Units) would be at least 1.1 times.

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) is as follows (in thousands):

	Year Ended December 31,
	2010			2009			2008
	(in thousands)
Cash flows from operating activities	$	90,463		$	90,079		$	94,808
Adjustments to reconcile operating cash flows to Available Cash:
Maintenance capital expenditures		(2,856	)		(4,426	)		(4,454	)
Proceeds from sales of certain assets		1,146			873			760
Amortization of credit facility issuance fees		(3,082	)		(2,503	)		(1,437	)
Effects of available cash generated by equity method investees not included in cash flows from operating activities		1,017			101			1,067
Earnings of DG Marine in excess of distributable cash		(848	)		(4,475	)		(2,821	)
Other items affecting available cash		(1,088	)		1,768			(2,561	)
Expenses related to acquiring or constructing assets that provide new sources of cash flow		11,260			-			-
Net effect of changes in operating accounts not included in calculation of Available Cash		5,487			9,569			1,262
Available Cash before Reserves	$	101,499		$	90,986		$	86,624

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, 2010.

	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 and notes payable (1)	$	-	$	-	$	360,000	$	250,000	$	610,000
Estimated interest payable on long-term debt and notes payable (2)		37,688		75,478		66,301		56,797		236,264
Operating lease obligations		11,055		11,570		5,501		21,410		49,536
Unconditional purchase obligations (3)		229,162		8,970		-		-		238,132

Other Cash Commitments:
Asset retirement obligations (4)		-		-		-		13,777		13,777
Liabilities associated with unrecognized tax benefits and associated interest (5)		6,241		-		-		-		6,241
Total	$	284,146	$	96,018	$	431,802	$	341,984	$	1,153,950

(1)	Our credit facility allows us to repay and re-borrow funds at any time through the maturity date of June 30, 2015. Our senior unsecured notes are due November 18, 2018.

(2)

Interest on our long-term debt under our credit facility is at market-based rates. The interest rate on our senior unsecured notes is 7.875%. The amount shown for interest payments represents the amount that would be paid if the debt outstanding at December 31, 2010 under our credit facility remained outstanding through the final maturity dates of June 30, 2015 and interest rates remained at the December 31, 2010 market levels through the final maturity dates. Also included is the interest on our senior unsecured notes through the maturity date.

(3)

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, 2010, 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.

(4)	Represents the estimated future asset retirement obligations on an undiscounted basis. The present discounted asset retirement obligation is $5.2 million and is further discussed in Note 5 to the Consolidated Financial Statements.

(5)

The estimated liabilities associated with unrecognized tax benefits and related interest 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 tax liability would not result in a cash payment.

We have guaranteed 50% of the $2.2 million debt obligation to a bank of Sandhill; however, we believe we are not likely to be required to perform under this guarantee as Sandhill is expected to make all required payments under the debt obligation.

Off-Balance Sheet Arrangements

We have no off-balance sheet arrangements, special purpose entities, or financing partnerships, other than as disclosed under Contractual Obligation and Commercial Commitments above.

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-compete agreements 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, 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. 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.

Goodwill represents the excess of the purchase prices we paid for certain businesses over their respective fair values. We do not amortize goodwill; however, we test our goodwill (at the reporting unit level) for impairment on October 1 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 impairment test 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 may be required to reduce the carrying value of goodwill to its implied fair value.

We monitor the markets for our products and services, in addition to the overall 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. One of our monitoring procedures is the comparison of our market capitalization to our book equity on a quarterly basis to determine if there is an indicator of impairment. As of December 31, 2010, our market capitalization exceeded the book value of our equity; therefore, since there were no events or changes in circumstances indicating impairment issues, we determined that it was not necessary to perform an interim goodwill impairment test as of December 31, 2010. We did not have any goodwill impairments in 2010, 2009 or 2008.

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

Asset Retirement Obligations

With regards to some of our assets, primarily related to our pipeline operations segment, we 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 of the Notes 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 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.

We recognize the equity-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, 2010, there was $0.8 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 approximately 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.

Our 2010 Long-Term Incentive Plan provides for grantees, which may include key employees and directors, to receive cash at the vesting of the phantom units equal to the average of the closing market price of our common units for the twenty trading days prior to the vesting date. Until the vesting date, we calculate estimates of the fair value of the awards and record that value as compensation expense during the vesting period. These estimates are based on the current trading price of our common units and an estimate of the forfeiture rate we expect may occur. At December 31, 2010, 62,927 phantom units had been granted and $0.4 million of expense had been recorded. The liability recorded for phantom units expected to vest fluctuates with the market price of our common units. At the date of vesting, any difference between the estimates recorded and the actual cash paid to the grantee will be charged to expense.

For phantom unit awards granted under our 2007 Long-Term Incentive Plan, the total compensation expense recognized over the service period was 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. As a result of the change in control of our general partner in February 2010 when Denbury sold its interest in our general partner to The Robertson Group, the outstanding phantom units at December 31, 2009 vested. We recorded $0.5 million of compensation expense in the first quarter of 2010 related to this accelerated vesting. No awards are outstanding at December 31, 2010 under the 2007 LTIP.

In connection with the settlement of the Series B awards to members of management, we made estimates of the fair value of the awards on the settlement date and recorded compensation expense for the awards totaling $79.1 million in 2010. This estimate included a value for the Class A Units received by the holders of the Series B units in our general partner based on the number of units received and the market price of our common units on the date of the transaction. Compensation expense also included an estimate of the fair value of the Waiver Units issued to the holders of the Series B units based estimates by management of the likelihood and timing of conversion of the Waiver Units into Class A Units and an estimate of the value of those Class A Units. No expense is required to be recorded related to the awards in any future period.

See Note 15 of the Notes to our Consolidated Financial Statements for further discussion regarding our equity compensation plans.

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, 2010, 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.

Allowance for Doubtful Accounts

We perform credit evaluations of our customers and grant credit based on past payment history, financial conditions and anticipated industry conditions. Customer payments are regularly monitored and a provision for doubtful accounts is established based on specific situations and overall industry conditions. Our history of bad debt losses has been minimal and generally limited to specific customer circumstances; however, credit risks can change suddenly and without notice. See Note 4 to our Consolidated Financial Statements for additional information on our allowance for doubtful accounts.

Recent Accounting Pronouncements.

Future Implementation

In December 2010, the FASB issued updated accounting guidance related to the calculation of the carrying amount of a reporting unit when performing the first step of a goodwill impairment test. More specifically, this update will require an entity to use an equity premise when performing the first step of a goodwill impairment test, and if a reporting unit has a zero or negative carrying amount, the entity must assess and consider qualitative factors to determine whether it is more likely than not that a goodwill impairment exists. The new accounting guidance is effective for public entities, for impairment tests performed during entities’ fiscal years (and interim periods within those years) that begin after December 15, 2010. Early application is not permitted. We will adopt the new guidance in the first quarter of 2011; however, as we currently do not have any reporting units with a zero or negative carrying amount, we do not expect the adoption of this guidance to have an impact on our financial position, results of operations or cash flows.

In December 2010, the FASB issued updated accounting guidance to clarify that pro forma disclosures should be presented as if a business combination that is determined to be material on an individual or aggregate basis occurred at the beginning of the prior annual period for purposes of preparing both the current reporting period and the prior reporting period pro forma financial information. These disclosures should be accompanied by a narrative description about the nature and amount of material, nonrecurring pro forma adjustments. The new accounting guidance is effective for business combinations consummated in periods beginning after December 15, 2010 and should be applied prospectively as of the date of adoption. Early adoption is permitted. We will adopt the new disclosures in the first quarter of 2011. We do not believe that the adoption of this guidance will have a material impact to our financial position, results of operations or cash flows.

Implemented in 2010

In January 2010, the FASB issued guidance to enhance disclosures related to the existing fair value hierarchy disclosure requirements. A fair value measurement is designated as level 1, 2 or 3 within the hierarchy based on the nature of the inputs used in the valuation process. Level 1 measurements generally reflect quoted market prices in active markets for identical assets or liabilities, level 2 measurements generally reflect the use of significant observable inputs and level 3 measurements typically utilize significant unobservable inputs. This new guidance requires additional disclosures regarding transfers into and out of level 1 and level 2 measurements and requires a gross presentation of activities within the level 3 roll forward. This guidance was effective for the first interim or annual reporting period beginning after December 15, 2009, except for the gross presentation of the level 3 roll forward, which is required for annual reporting periods beginning after December 15, 2010 and for interim reporting periods within those years. We adopted the guidance relating to level 1 and level 2 transfers as of January 1, 2010, and we adopted the guidance relating to level 3 measurements on January 1, 2011. Our adoption did not have any material impact on our financial position, results of operations or cash flows.

In June 2009, the FASB issued authoritative guidance to amend the manner in which entities evaluate whether consolidation is required for VIEs. The model for determining which enterprise has a controlling financial interest and is the primary beneficiary of a VIE has changed significantly under the new guidance. Previously, variable interest holders had to determine whether they had a controlling interest in a VIE based on a quantitative analysis of the expected gains and/or losses of the entity. In contrast, the new guidance requires an enterprise with a variable interest in a VIE to qualitatively assess whether it has a controlling interest in the entity, and if so, whether it is the primary beneficiary. Furthermore, this guidance requires that companies continually evaluate VIEs for consolidation, rather than assessing based upon the occurrence of triggering events. This revised guidance also requires enhanced disclosures about how a company’s involvement with a VIE affects its financial statements and exposure to risks. This guidance was effective for us beginning January 1, 2010, and had no impact on our conclusions regarding consolidation of our VIEs.

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