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•	demand for, the supply of, our assumptions about, changes in forecast data for, and price trends related to crude oil, liquid petroleum, NaHS, caustic soda and CO2, all of which may be affected by economic activity, capital expenditures by energy producers, weather, alternative energy sources, international events, conservation and technological advances;

•	throughput levels and rates;

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•	changes in, or challenges to, our tariff rates;

•	our ability to successfully identify and close strategic acquisitions on acceptable terms (including obtaining third-party consents and waivers of preferential rights), develop or construct energy infrastructure assets, make cost saving changes in operations and integrate acquired assets or businesses into our existing operations;

•	service interruptions in our pipeline transportation systems, and processing operations;

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

•	risks inherent in marine transportation and vessel operation, including accidents and discharge of pollutants;

•	changes in laws and regulations to which we are subject, including tax withholding issues, accounting pronouncements, and safety, environmental and employment laws and regulations;

•	the effects of production declines resulting from the suspension of drilling in the Gulf of Mexico and the effects of future laws and government regulation resulting from the Macondo accident and oil spill in the Gulf;

•	planned capital expenditures and availability of capital resources to fund capital expenditures;

•	our inability to borrow or otherwise access funds needed for operations, expansions or capital expenditures as a result of our credit agreement and the indenture governing our notes, which contain various affirmative and negative covenants;

•	loss of key personnel;

•	an increase in the competition that our operations encounter;

•	cost and availability of insurance;

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

•	our financial and commodity hedging arrangements;

•	changes in global economic conditions, including capital and credit markets conditions, inflation and interest rates;

•	natural disasters, accidents or terrorism;

•	changes in the financial condition of customers or counterparties;

•	adverse rulings, judgments, or settlements in litigation or other legal or tax matters;

•	the treatment of us as a corporation for federal income tax purposes or if we become subject to entity-level taxation for state tax purposes; and

•	the potential that our internal controls may not be adequate, weaknesses may be discovered or remediation of any identified weaknesses may not be successful and the impact these could have on our unit price.

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•	Identifying and exploiting incremental profit opportunities, including cost synergies, across an increasingly integrated footprint;

•	Optimizing our existing assets and creating synergies through additional commercial and operating advancement;

•	Leveraging customer relationships across business segments;

•	Attracting new customers and expanding our scope of services offered to existing customers;

•	Expanding the geographic reach of our refinery services and supply and logistics businesses;

•	Economically expanding our pipeline and terminal operations;

•	Evaluating internal and third party growth opportunities (including asset and business acquisitions) that leverage our core competencies and strengths and further integrate our businesses; and

•	Focusing on health, safety and environmental stewardship.

•	Increase the relative contribution of recurring and throughput-based revenues, emphasizing longer-term contractual arrangements;

•	Prudently manage our limited commodity price risks;

•	Maintain a sound, disciplined capital structure; and

•	Create strategic arrangements and share capital costs and risks through joint ventures and strategic alliances.

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•

Our businesses encompass a balanced, diversified portfolio of customers, operations and assets. We operate three business segments and own and operate assets that enable us to provide a number of services to oil and CO2 producers; refinery owners; and industrial and commercial enterprises that use NaHS and caustic soda. Our business lines complement each other by allowing us to offer an integrated suite of services to common customers across segments.

•	Through our NaHS sales, we have indirect exposure to fast-growing, developing economies outside of the U.S. We sell NaHS to the mining and pulp and paper industries, which sell copper and other mined materials and paper products in the global market.

•

We have lower commodity price risk exposure. The volumes of crude oil, refined products or intermediate feedstocks that we purchase are either subject to back-to-back sales contracts or are hedged with NYMEX derivatives to limit our exposure to movements in the price of the commodity. Our risk management policy requires that we monitor the effectiveness of the hedges to maintain a value at risk of such hedged inventory that does not exceed $2.5 million. In addition, our service contracts with refiners allow us to adjust our processing rates to maintain a balance between NaHS supply and demand.

•	Our businesses provide consistent consolidated financial performance. Our consistent and improving financial performance, combined with our conservative capital structure, has allowed us to increase our distribution for thirty consecutive quarters as of our most recent distribution declaration. During this period, twenty-five of those quarterly increases have been 10% or greater year-over-year.

•	Our pipeline transportation and related assets are strategically located. Our crude oil pipelines are located in the Gulf of Mexico and provide our customers access to multiple delivery points. In addition, a majority of our terminals are located in areas that can be accessed by truck, rail or barge.

•	We believe we are one of the largest marketers of NaHS in North and South America. We believe the scale of our well-established refinery services operations as well as our integrated suite of assets provides us with a unique cost advantage over some of our existing and potential competitors.

•	Our expertise and reputation for high performance standards and quality enable us to provide refiners with economic and proven services. Our extensive understanding of the sulfur removal process and refinery services market can provide us with an advantage when evaluating new opportunities and/or markets.

•	Our supply and logistics business is operationally flexible. Our portfolio of trucks, railcars, barges and terminals affords us flexibility within our existing regional footprint and provides us the capability to enter new markets and expand our customer relationships.

•	We are financially flexible and have significant liquidity. As of December 31, 2012, we had $483.3 million available under our $1 billion credit agreement, including up to $86.1 million available under the $150 million petroleum products inventory loan sublimit, and $83.3 million available for letters of credit. Our inventory borrowing base was $63.9 million at December 31, 2012.

•

We have an experienced, knowledgeable and motivated executive management team with a proven track record. Our executive management team has an average of more than 25 years of experience in the midstream sector. Its members have worked in leadership roles at a number of large, successful public companies, including other publicly-traded partnerships. Through their equity interest in us, our executive management team is incentivized to create value by increasing cash flows.

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•	Texas System. Our Texas System transports crude oil from West Columbia to several delivery points near Houston, Texas. The Texas System receives all of its volume from connections to other pipeline carriers. We earn a tariff for our transportation services, with the tariff rate per barrel of crude oil varying with the distance from injection point to delivery point.

•	Jay System. Our Jay System provides crude oil shippers access to refineries, pipelines and storage near Mobile, Alabama. The system also includes gathering connections to approximately 35 wells, additional oil storage capacity of 20,000 barrels in the field and a delivery connection to a refinery in Alabama.

•

Mississippi System. Our Mississippi System provides shippers of crude oil in Mississippi indirect access to refineries, pipelines, storage, terminals and other crude oil infrastructure located in the Midwest. The system is adjacent to several oil fields that are in various phases of being produced through tertiary recovery strategy, including CO2 injection and flooding. We provide transportation services on our Mississippi pipeline through an “incentive” tariff which provides that the average rate per barrel that we charge during any month decreases as our aggregate throughput for that month increases above specified thresholds.

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(1)	We acquired our interests in CHOPS in November 2010 and our interests in our other offshore pipelines in January 2012.

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CHOPS. CHOPS is comprised of 24- to 30-inch diameter pipelines to deliver crude oil from developments in the Gulf of Mexico to refining markets along the Texas Gulf Coast via interconnections with refineries located in Port Arthur and Texas City, Texas. CHOPS also includes two strategically located multi-purpose offshore platforms. Enterprise Products owns the remaining 50% interest in, and operates, the joint venture. The pipeline has significant available capacity to accommodate future growth in the fields from which the production is dedicated to the pipeline as well as to transport volumes from non-dedicated fields both currently in production and to be developed in the future.

•	Poseidon. The Poseidon system is comprised of 16- to 24-inch diameter pipelines to deliver crude oil from developments in the central and western offshore Gulf of Mexico to other pipelines and terminals onshore and offshore Louisiana. Affiliates of Enterprise Products and Shell each own a 36% interest in Poseidon. An affiliate of Enterprise Products serves as the operator.

•	Odyssey. The Odyssey system is comprised of 12- to 20-inch diameter pipelines to deliver crude oil from developments in the eastern Gulf of Mexico to other pipelines and terminals onshore Louisiana. An affiliate of Shell owns the remaining 71% interest in Odyssey, and an affiliate of Shell serves as the operator.

•

Eugene Island. The Eugene Island system is comprised of a network of crude oil pipelines, the main pipeline of which is 20 inches in diameter, to deliver crude oil from developments in the central Gulf of Mexico to other pipelines and terminals onshore Louisiana. Other owners in Eugene Island include affiliates of Exxon-Mobil, Chevron-Texaco, ConocoPhillips and Shell Oil Company. An affiliate of Shell serves as the operator.

•	SEKCO Pipeline. As described in “Recent Developments” we entered into a joint venture with Enterprise Products to construct a deepwater pipeline serving the Lucius development area in southern Keathley Canyon of the Gulf of Mexico. The pipeline is expected to begin service by mid-2014.

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(1)	Subject to a fixed payment agreement.

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

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

•	the demand for our trucking, barge and pipeline transportation services;

•	the demand for our terminal storage services;

•	the level of our operating costs;

•	the effect of worldwide energy conservation measures;

•	governmental regulations and taxes;

•	the level of our general and administrative costs; and

•	prevailing economic conditions.

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

•	our debt service requirements;

•	fluctuations in our working capital;

•	restrictions on distributions contained in our debt instruments;

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

•	the amount of cash reserves required in the conduct of our business.

•	incur additional indebtedness or liens;

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

•	sell assets;

•	make loans or investments;

•	make guarantees;

•	enter into any hedging agreement for speculative purposes;

•	acquire or be acquired by other companies; and

•	amend some of our contracts.

•	increase our vulnerability to general adverse economic and industry conditions;

•

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

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

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

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•	geographic proximity to the production;

•	costs of connection;

•	available capacity;

•	rates;

•	logistical efficiency in all of our operations;

•	operational efficiency in our refinery services business;

•	customer relationships; and

•	access to markets.

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•	rate structures;

•	rates of return on equity;

•	recovery of costs;

•	the services that our regulated assets are permitted to perform;

•	the acquisition, construction and disposition of assets; and

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

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

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

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

•	using cash from operations;

•	delaying other planned projects;

•	incurring additional indebtedness; or

•	issuing additional debt or equity.

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•	our general partner is allowed to take into account the interest of parties other than us, such as one or more of its affiliates, in resolving conflicts of interest;

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

•	our general partner determines the amount and timing of asset purchases and sales, capital expenditures, borrowings, issuance of additional partnership securities, reimbursements and enforcement of obligations to the general partner and

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

•	our unitholders’ proportionate ownership interest in us will decrease;

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

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

•	the market price of our common units may decline.

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•	we were conducting business in a state but had not complied with that particular state’s partnership statute; or

•	your right to act with other unitholders to remove or replace our general partner, to approve some amendments to our partnership agreement or to take other actions under our partnership agreement constitutes “control” of our business.

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(1)	Cash distributions are shown in the quarter paid and are based on the prior quarter’s activities.

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(1)

Our operating results and financial position have been affected by acquisitions, most notably the acquisition of interests in several Gulf of Mexico crude oil pipeline systems from Marathon Oil Company, including its 28% interest in Poseidon Oil Company, L.L.C., its 29% interest in Odyssey Pipeline, L.L.C. and its 23% interest in the Eugene Island Pipeline System in January 2012, the acquisition of the black oil barge business of Florida Marine Transporters, Inc. in August 2011, the 50% equity interest acquisition in CHOPS in November 2010, the acquisition of the remaining 51% ownership interest in DG Marine in July 2010 and the Grifco acquisition in July 2008. The results of these operations are included in our financial results prospectively from the acquisition date. For additional

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(2)	Includes executive compensation expense related to Series B and Class B awards borne entirely by our general partner in the amounts of $76.9 million for 2010 and $14.1 million for 2009, see Note 15 to our Consolidated Financial Statements in Item 8.

(3)	Maintenance capital expenditures are capital expenditures to replace or enhance partially or fully depreciated assets to sustain the existing operating capacity or efficiency of our assets and extend their useful lives.

(4)	Includes barrels per day for CHOPS for the period we owned the pipeline in 2010.

(5)	Volume per day for the period we owned the Free State CO2 pipeline in 2008.

•	Overview of 2012 Results and Operational Update

•	Results of Operations

•	Other Consolidated Results

•	Financial Measures

•	Liquidity and Capital Resources

•	Commitments and Off-Balance Sheet Arrangements

•	Critical Accounting Policies and Estimates

•	Recent Accounting Pronouncements

•	Cameron Highway Pipeline. Production from several fields dedicated to our Cameron Highway pipeline in the offshore Gulf of Mexico began to ramp back up in August 2012 after an extended period of maintenance on the third-

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Gulf Coast Infrastructure.We plan to invest approximately $125 million to improve existing assets and develop new infrastructure in Louisiana, including connecting to Exxon Mobil Corporation’s Baton Rouge refinery, one of the largest refinery complexes in North America, with more than 500,000 barrels per day of refining capacity. Our investment includes improving our existing terminal at Port Hudson, Louisiana, constructing a new 18-mile 20-inch diameter crude oil pipeline connecting Port Hudson to the Baton Rouge Maryland Terminal and continuing downstream to the Anchorage Tank Farm and building a new crude oil unit train facility at the Maryland Terminal. The Port Hudson upgrades and new crude oil pipeline are expected to be completed by the end of 2013 and the Maryland Terminal completion is scheduled for the second quarter of 2014.

•	Walnut Hill Rail Facility. We continue to receive unit trains of crude oil at Walnut Hill, Florida for further delivery downstream on our Jay Pipeline System, and would anticipate our new tank and related facilities to be fully operational in March of 2013, allowing us to handle more trains, more efficiently.

•	Wink Rail Facility. At our new crude loading facility outside Wink, Texas in the Permian Basin, we have continued to support manifest service of crude oil volumes and in early February 2013 loaded our first full unit train. Construction of our tanks and expanded trucking capabilities remains on track to be fully operational by late third quarter or early fourth quarter of 2013.

•	Natchez Terminal. At our terminal in Natchez, Mississippi, we have steamed and unloaded into tanks the first railcars loaded with bitumen/dilbit originating in Alberta, Canada. As volumes continue to ramp up, we will begin loading barges for further shipment to refineries along the Mississippi River.

•	Texas City Facility. We have commissioned our new crude oil terminal and barge dock in Texas City. We would expect the terminal and barge dock to see increasing levels of throughput in the latter half of 2013 upon the completion of our new 18-inch pipeline from Webster to Texas City in the late second quarter or early third quarter of 2013.

•	Wyoming. We have entered into an agreement with a local refinery in Wyoming which will support our investment to expand and place into service certain segments of our crude oil gathering system in the Niobrara shale development in Wyoming, with start-up operations expected in the second quarter of 2013.

•	SEKCO. Construction has commenced on the SEKCO lateral in the Keathley Canyon area of the deepwater Gulf of Mexico, and we expect significant contribution from this investment beginning mid-2014.

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•	Crude oil tariff revenues of onshore crude oil pipelines increased $7.1 million primarily due to upward tariff indexing of 6.9% and 8.6% for our FERC-regulated pipelines effective in July 2011 and 2012, respectively, and increased volumes of 10,185 barrels per day transported on our onshore crude oil pipelines as described above.

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•	Segment margin from our offshore crude oil pipelines increased $22.7 million reflecting a contribution of $29.1 million from our interests in the Gulf of Mexico pipelines that we acquired in 2012. The contribution to Segment Margin by CHOPS declined by $6.4 million from 2011 due to ongoing improvements being made by producers at several connected fields as discussed above.

•	Revenues from sales of pipeline loss allowance volumes improved Segment Margin by $1.4 million due to an increase of approximately 10,200 barrels sold in 2012 compared to 2011.

•	Pipeline operating costs, excluding non-cash charges, increased $3.4 million, due to pipeline integrity maintenance on the pipelines and employee compensation and related benefit costs.

(1)	Source: IHS Chemical

•	NaHS sales volumes during 2012 decreased 3% from 2011 primarily due to the timing of sales to South American customers. In late 2011, we experienced a high volume of sales to these customers. Sales volumes to customers in South America can fluctuate due to scheduling of shipments.

•	NaHS revenues increased primarily as a function of the increase in the average index price for caustic soda. The pricing in our sales contracts for NaHS includes adjustments for fluctuations in commodity benchmarks, freight, labor, energy costs and government indexes. The frequency at which these adjustments are applied varies by contract, geographic region and supply point.

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Our raw material costs related to NaHS increased correspondingly to the rise in the average index price for caustic soda. In addition, in the first half of 2012, longer than anticipated refinery turnarounds at some of our largest refinery service locations resulted in increased costs as a result of processing at and shipping from less efficient locations to ensure uninterrupted supplies of NaHS to our customers.

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Caustic soda sales volumes decreased 22% primarily due to turnarounds at some of our refinery customers in the first half of 2012. Although caustic sales volumes may fluctuate, the contribution to Segment Margin from these sales is not a significant portion of our refinery services activities. Caustic soda is a key component in the provision of our sulfur-removal service, from which we receive the by-product NaHS. Consequently, we are a very large consumer of caustic soda. In addition, our economies of scale and logistics capabilities allow us to effectively purchase additional caustic soda for re-sale to third parties. Our ability to purchase caustic soda volumes is currently sufficient to meet the demands of our refinery services operations and third-party sales.

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Average index prices for caustic soda increased to $575 per DST during 2012 compared to $513 per DST during 2011. Those price movements affect the revenues and costs related to our sulfur removal services as well as our caustic soda sales activities. However, generally changes in caustic soda prices do not materially affect Segment Margin attributable to our sulfur processing services because we usually pass those costs through to our NaHS sales customers. Additionally, our bulk purchase and storage capabilities related to caustic soda allow us to somewhat mitigate the effects of changes in index prices for caustic on our operating costs.

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

•	supplying petroleum products (primarily fuel oil, asphalt, and other heavy refined products) 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, railcars, 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.

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•	Segment margin from our offshore crude oil pipeline, CHOPS, increased $13.6 million during 2011 as a result of owning our 50% interest for a full year in 2011. Despite the increase, planned improvements by producers of offshore field facilities from the second quarter of 2011 through the fourth quarter of 2011 negatively impacted our revenue generating volumes during the year.

•	Crude oil tariff revenues of onshore crude oil pipelines increased $4.5 million reflecting increased volumes of 14,781 barrels per day transported on our onshore crude oil pipelines as described above.

•	An increase in revenues from sales of pipeline loss allowance volumes increased Segment Margin by $2.2 million related to the significant increase (an average of $16 per barrel) in crude oil prices.

•	Pipeline operating costs, excluding non-cash charges increased $0.9 million, primarily due to increased employee compensation and related benefit costs.

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(1)	Source: IHS Chemical

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Revenues increased primarily as a function of the increase in the average index price for caustic soda. Average index prices of caustic soda increased to an average of $513 per DST during 2011 as compared to $353 per DST in 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. Additionally, our bulk purchase and storage capabilities related to caustic soda allow us to mitigate the effects of changes in index prices for caustic on our operating costs.

•

The pricing in our sales contracts for NaHS includes adjustments for fluctuations in commodity benchmarks, freight, labor, energy costs and government indexes. The frequency at which these adjustments are applied varies by contract, geographic region and supply point. Our raw material costs related to NaHS increased correspondingly to the rise in the average index price for caustic soda, although operating efficiencies at several of our sour gas processing facilities as well as our favorable management of the acquisition and utilization of caustic soda in our operations and our logistics management, as discussed below, helped offset these costs.

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NaHS sales volumes during 2011 increased 2% from 2010. Although there were decreased levels of activity by our pulp and paper customers, the return of industrialization and urbanization in the world’s emerging economies increased the demand for products requiring copper and molybdenum. These trends led to a noticeable increase in NaHS demand from our mining customers primarily in North America in 2011 as compared to 2010.

•	Caustic soda sales volumes increased 7%. Caustic soda is a key component in the provision of our sulfur-removal service, from which we receive the by-product NaHS. Consequently, we are a very large consumer of caustic soda. In addition, our economies of scale and logistics capabilities allow us to effectively purchase caustic soda for re-sale to third parties.

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•	increased volumes of approximately 16% from 2010 primarily due to a greater availability of volumes of crude oil and heavy-end petroleum products resulting from increased refinery utilization in our operating area;

•	increased production from new sources of crude oil, principally shale oil production, increased demand for our services;

•	higher foreign demand for fuel oil and other heavy-end petroleum products helped sustain the price environment for the products we sell;

•	operating efficiencies and modifications to our existing crude oil and petroleum products commercial arrangements; and

•	the contribution from the additional black oil barges we acquired in August 2011.

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•	Working capital, primarily inventories;

•	Routine operating expenses;

•	Capital expansion and maintenance projects;

•	Acquisitions of assets or businesses;

•	Interest payments related to outstanding debt; and

•	Quarterly cash distributions to our unitholders.

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•	The applicable margin varies from 1.75% to 2.75% on eurodollar borrowings and from 0.75% to 1.75% on alternate base rate borrowings.

•	Letter of credit fees range from 1.75% to 2.75%.

•	The commitment fee on the unused committed amount will range from 0.375% to 0.50%.

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(1)	In 2012, amount includes the purchase of barge assets for $30.9 million (see below for more information).

(2)	In 2012, amount represents the investment to acquire from Marathon Oil Company interests in several Gulf of Mexico crude oil pipeline systems. In 2011 and 2010, amounts represent the investment to acquire our interest in CHOPS.

(3)	Amount represents our investment in the SEKCO pipeline joint venture (see below for more information).

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(1)	This distribution was paid on February 14, 2013 to unitholders of record as of February 1, 2013.

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(1)

Our credit facility allows us to repay and re-borrow funds at any time through the maturity date of July 25, 2017. Our senior unsecured notes are due December 15, 2018. In February 2013, we issued an additional $350 million in aggregate principal amount senior unsecured notes that mature in February 2021. The net proceeds were used for general partnership purposes, including to repay borrowings under our credit facility, which will result in extending the repayment of approximately $350 million of our long term debt obligations as of February 2013 from the 3 to 5 year payment period to the more than 5 year payment period.

(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, 2012 under our credit facility remained outstanding through the final maturity date of July 25, 2017 and interest rates remained at the December 31, 2012 market levels through the final maturity date. Also included is the interest on our senior unsecured notes through the maturity date.

(3)	Includes operating lease obligations on approximately 400 rail cars which we expect to receive in 2013.

(4)

Unconditional purchase obligations include agreements to purchase goods and services that are enforceable and legally binding and specify all significant terms. Contracts to purchase crude oil and petroleum products are generally at market-based prices. For purposes of this table, estimated volumes and market prices at December 31, 2012 were used to value those obligations. The actual physical volumes and settlement prices may vary from the assumptions used in the table. Uncertainties involved in these estimates include levels of production at the wellhead, changes in market prices and other conditions beyond our control.

(5)	Represents the estimated future asset retirement obligations on an undiscounted basis. The recorded asset retirement obligation on our balance sheet at December 31, 2012 was $12.7 million and is further discussed in Note 6 to our Consolidated Financial Statements.

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(1)	Prices and volumes are presented as quoted on the NYMEX. To calculate the total contract value the price per unit in gallons should be multiplied by 42 gallons to convert into a price per barrel.

(2)	Weighted average premium received/paid.

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•	Grant E. Sims, Chief Executive Officer;

•	Steven R. Nathanson, President and Chief Operating Officer;

•	Robert V. Deere, Chief Financial Officer;

•	Paul A. Davis, Senior Vice President; and

•	Stephen M. Smith, Vice President

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•	encourage our executives to build and operate the partnership in a way that is aligned with our common unitholders’ interests, focusing on maximizing cash distributions and growth in the asset base with an emphasis on maintaining a focus on the long-term stability of the enterprise so as to not promote inappropriate risk taking;

•	offer near-term and long-term opportunities that are consistent with industry norms; and

•	provide appropriate levels of retention to the executive team to ensure long-term continuity and stability for the successful execution of key growth initiatives and projects.

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•	annual cash base salary

•	discretionary annual cash bonus awards

•	annual grants under long-term incentive arrangements

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•	the company has strong internal financial controls;

•	base salaries are consistent with employees’ responsibilities so that they are not motivated to take excessive risks to achieve a reasonable level of financial security;

•	the determination of incentive awards is based on a review of a variety of indicators of performance as well as a meaningful subjective assessment of personal performance, thus diversifying the risk associated with any single indicator of performance;

•	goals are appropriately set to avoid targets that, if not achieved, result in a large percentage loss of compensation;

•	incentive awards are capped by the G&C Committee;

•	compensation decisions include discretionary authority to adjust annual awards and payments, which further reduces any business risk associated with our plans; and

•	long-term incentive awards are designed to provide appropriate awards for dedication to a corporate strategy that delivers long-term returns to unitholders.

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(1)	Bonuses are paid in March of the following year (e.g., the bonuses with respect to 2012 will be paid in March 2013).

(2)

The amounts shown in this column represent the aggregate grant date fair value for each NEO’s phantom units granted in 2011 and 2012 under our 2010 Long-Term Incentive Plan, excluding the amount shown for Mr. Davis. The amount for Mr. Davis represents the grant date fair value of an award of 12,206 Class A Units and 2,946 Waiver Units issued on the first day of Mr. Davis' employment in March 2012. Amounts in 2010 also include the aggregate grant date fair value for each NEO’s Series B Award. The Series B Awards provided for the conversion into Series A units in our general partner under certain conditions. These awards were ultimately exchanged for our Class A Units and Waiver Units in connection with our IDR Restructuring. For additional information on these awards and our IDR Restructuring see Note 15 to our Consolidated Financial Statements in Item 8. The grant date fair value of each award was determined in accordance with accounting guidance for equity-based compensation and is based on the probable outcome of any underlying performance conditions. Assumptions used in the calculation of these amounts are included in Note 15 to our Consolidated Financial Statements in Item 8.

(3)	Mr. Davis became an executive officer of our general partner in March 2012.

(4)	The following table presents the components of "All Other Compensation" for each NEO for the year ended December 31, 2012.

(a)	Contributions by us to our 401(k) plan on each NEO’s behalf.

(b)	Term life insurance premiums paid by us on each NEO’s behalf.

(c)	This column includes cash distributions paid in connection with granted DERs.

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(1)

Represents the number of phantom units that each NEO can earn of grant awarded on April 10, 2012, if the company meets certain performance conditions (threshold, target and maximum) during the fourth quarter of 2014. Upon achieving either the threshold, target or maximum levels during the fourth quarter of 2014 the NEO earns either 50% of the initial grant, 100% of the initial grant or 150% of the initial grant, respectively. The target level represents the number of phantom units initially issued on the grant date. The performance targets are as follows: (i) at threshold, if the quarterly cash distribution on the common units is $0.49 per unit, 50% of the phantom units granted will vest and the remainder will be forfeited; (ii) at target, if the quarterly cash distribution on the common units is $0.53 per unit, 100% of the phantom units granted will vest; or (iii) at maximum, if the quarterly cash distribution on the common units is $0.57 per unit or greater, 150% of the phantom units granted will vest. Should the quarterly cash distribution on the common units fall between the range of $0.49 per unit and $0.57 per unit, the phantom units will vest between 50% and 150% of the number granted on a proportionately adjusted basis (for example, if the quarterly cash distribution on the common units is $0.51 per unit, 75% of the phantom units granted will vest or if the quarterly cash distribution on the common units is $0.55 per unit, 125% of the phantom units granted will vest). If the quarterly cash distribution is below $0.49 per unit for the fourth quarter of 2014, all of the phantom units granted will be forfeited.

(2)	Represents the closing market price of our common units on the date of the phantom unit award on April 10, 2012.

(3)	The amounts in this column for each NEO represent the fair value of the award on the date of the grant, based on a target performance payout (as calculated in accordance with accounting guidance for equity-based compensation) using the twenty day average closing price of our common units through the date of grant ($31.38).

•	“Cause” means, in general, if an executive commits willful fraud or theft of our assets, is convicted of a felony or crime of moral turpitude, materially violates certain provisions of his employment agreement, substantially fails to perform, is grossly negligent, acts with willful misconduct, acts in a way materially injurious to us, willfully

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•

“Good reason” means, in general, an executive's duties, responsibilities, base salary, or benefits are materially diminished, if either our principal executive office or that executive is based anywhere outside of metropolitan Houston without his consent, if our general partner fails to make a material payment under, or perform a material provision of, his employment agreement, or our general partner amends or changes certain equity interests in a manner that materially and adversely affects the executive's right to distributions or redemptions payable because of such amendment or change, subject to certain exceptions.

•	“Disability” means, in general, if the executive has been absent from his duties with us on a full-time basis for 180 out of any 220 consecutive calendar days as a result of incapacity due to mental or physical illness or injury that is determined to be total and permanent by a selected physician or if the Social Security Administration has determined that executive is totally disabled.

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(1)	All rights in this column were vested at December 31, 2012.

(2)	The phantom unit awards granted in 2010 vest on April 20, 2013.

(3)	The amounts in this column were calculated by multiplying the closing market price of our units using the twenty day average at year-end by the number of applicable units outstanding.

(4)

The number of performance units reflected in the table assumes a threshold performance payout during the fourth quarter of 2013 for units granted on April 29, 2011 and the fourth quarter of 2014 for units granted on April 10, 2012 (at which 50% of the initial phantom units awarded will vest on the third year anniversary from the date of grant). The phantom units will vest at the end of three years between 50% and 150% of the number granted, if certain quarterly cash distribution target levels for the fourth quarter of 2013 and fourth quarter of 2014 are achieved.

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•

“Cause” means, in general, if the executive commits theft, embezzlement, forgery, any other act of dishonesty relating the executive’s employment or violates our policies or any law, rule, or regulation applicable to us, is convicted of a felony or lesser crime having as its predicate element fraud, dishonesty, or misappropriation, fails to perform his duties under the employment agreement or commits an act or intentionally fails to act, which act or failure to act amounts to gross negligence or willful misconduct.

•

“Change of control” means, in general, any sale of equity of us or our general partner or substantially all of the assets of us or our general partner, merger, conversion or consolidation of us or our general partner, or other event that, in each case, results in any person or entity (or other persons or entities acting in concert) having the ability to elect a majority of the members of our board of directors.

•

“Cause” means, in general, if the executive commits theft, embezzlement, forgery, any other act of dishonesty relating the executive’s employment or violates our policies or any law, rule, or regulation applicable to us, is convicted of a felony or lesser crime having as its predicate element fraud, dishonesty, or misappropriation, fails to perform his duties under the employment agreement or commits an act or intentionally fails to act, which act or failure to act amounts to gross negligence or willful misconduct.

•

“Change of control” means, in general, any sale of equity of us or our general partner or substantially all of the assets of us or our general partner, merger, conversion or consolidation of us or our general partner, or other event that, in each case, results in any person or entity (or other persons or entities acting in concert) having the ability to elect a majority of the members of our board of directors.

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(1)	Amounts include annual retainer fees and fees for attending meetings.

(2)	Amounts in this column represent the fair value of the awards of phantom units under our 2010 LTIP on the date of grant, as calculated in accordance with accounting guidance for equity-based compensation.

(3)

Outstanding awards to directors at December 31, 2012 consist of phantom units granted under our 2010 LTIP and stock appreciation rights pursuant to our Stock Appreciation Rights Plan. Messrs. James Davison and James Davison, Jr. each hold 8,057 outstanding phantom units and 1,000 stock appreciation rights. Messrs. Evans, Jastrow, C. Robertson and Ms. Gasaway hold 8,057, 8,612, 8,075, and 9,128 outstanding phantom units, respectively.

(4)	Amounts in this column represent the amounts paid for tandem DERs related to outstanding phantom units granted under our 2010 LTIP.

(5)

In October 2012, certain directors resigned from the board of directors of our general partner. In connection with those directors' resignations, we paid Messrs. Nelson, W. Robertson, Sturdivant and Thomason $268,750, $251,392, $251,392 and $252,129, respectively, related to phantom units granted under our 2010 LTIP that were outstanding as of September 30, 2012. Proceeds from the phantom units held by Messrs. W. Robertson and Sturdivant were paid to an affiliate of Quintana.

(6)	Prior to September 30, 2012, all fees paid and amounts paid for DERs related to phantom unit awards for these directors were paid to an affiliate of Quintana. After September 30, 2012, all fees paid and amounts paid for DERs related to phantom unit awards for Messrs. Evans and C. Robertson, were paid directly to the individuals.

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*	Less than 1%

(1)

The Class B Common Units, which are included in the Class A Common Unit total, are identical to the Class A Common Units and, accordingly, have voting and distribution rights equivalent to those of the Class A Common Units, and, in addition, the Class B Common Units have the right to elect all of our board of directors and are convertible into Class A Common Units under certain circumstances, subject to certain exceptions.

(2)	Mr. Davison pledged 1,049,406 of these Class A Common Units as collateral for a loan from a bank. James E. Davison is the sole stockholder of Davison Terminal Service, Inc., which directly owns 1,010,835 Class A Common Units.

(3)	Mr. Davison, Jr. pledged 2,972,711 of these Class A Common Units as collateral for a loan from a bank. 1,155,737 of these Class A Common Units are held by trusts for Mr. Davison's children. 187,856 of these Class A Common Units are held by the James E. and Margaret A. B. Davison Special Trust.

(4)	91,823 of each class of our outstanding Waiver Units are held by trusts for Mr. Davison's children.

(5)

Mr. Evans is a member of the board of managers of QEP Management Co. GP, LLC, a Delaware limited liability company (“Management Co GP”), a member of the board of directors and senior partner of Quintana Capital Group GP, Ltd., a Cayman Islands company (“QCG GP”), and partner of Quintana Capital Group II, L.P., a Cayman Islands limited partnership (“QCG II”); Each of Quintana Energy Partners II, L.P., a Cayman Islands limited partnership (“QEP II”), and QEP II Genesis TE Holdco, LP, a Delaware limited partnership (“Holdco”), has (i) QCG II as its general partner (with QCG GP as the general partner of QCG II), (ii) management services provided by QEP Management Co., L.P., a Delaware limited partnership (“QEP Management”) (with Management Co GP as the general partner of QEP Management) and (iii) membership interests in Q GEI. Mr. Robertson, III is the chief executive officer, president and a member of the board of managers of Q GEI, a manager of Management Co GP, a member of the board of directors and managing director of QCP GP, a member of Q GEI and a partner in QCG II; The Corbin J. Robertson III 2009 Family Trust is a member of Q GEI. Each such person disclaims beneficial ownership of all the units reported by such entities.

(6)	Mr. C. Robertson pledged 1,300,000 of these Class A Common Units as collateral for a loan from a bank. Includes 172,951 Class A Common Units held by The Corbin J. Robertson III 2009 Family Trust and 5,743 Class A Common Units held by Corby & Brooke Robertson 2006 Family Trust.

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(7)	The Corbin J. Robertson III 2009 Family Trust holds 12,917 of each class of our outstanding Waiver Units and Mr. C. Robertson III holds 97,484 of each class of our outstanding Waiver Units.

(8)	Mr. Sims pledged 866,334 of these Class A Common Units as collateral for a loan from a bank. Includes 1,000 Class A Common Units held by Mr. Sims’ father, of which Mr. Sims disclaims beneficial ownership.

(9)	Includes 291,208 Class A Common Units held in trusts in the names of Mr. Nathanson's children, of which Mr. Nathanson disclaims beneficial ownership.

(10)	Includes 100,000 Class A Common Units that are held in a margin brokerage account.

(11)	Includes 132,245 Class A Common units held by the Steven Davison Family Trust.

(12)	The Steven Davison Family Trust holds 22,848 of each class of our outstanding Waiver Units and Mr. S. Davison holds 68,974 of each class of our outstanding Waiver Units. The mailing address for Mr. S. Davison is 2000 Farmerville Highway, Ruston, Louisiana, 71270.

•	would evaluate and, where appropriate, negotiate certain material terms of the proposed transaction;

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•	may engage an independent legal counsel and, if it deems appropriate, an independent financial adviser to assist with its evaluation of the proposed transaction; and

•	would determine whether to reject or approve and recommend the proposed transaction.

(1)	Includes fees for the annual audit and quarterly reviews (including internal control evaluation and reporting), SEC registration statements and accounting and financial reporting consultations and research work regarding Generally Accepted Accounting Principles.

(2)	Includes fees related to (i) reviewing our documentation of controls and process for conversion related to our project to upgrade our information technology systems and (ii) review of correspondence with the SEC. 2011 also includes fees for the audit of our employee benefit plan.

(3)	Includes fees for tax return preparation and tax consultations.

(4)	Includes fees associated with licenses for accounting research software.

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•	Pipeline transportation of interstate, intrastate and offshore crude oil, and, to a lesser extent, carbon dioxide (or “CO2”);

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

•	Supply and logistics services, which include terminaling, blending, storing, marketing, and transporting crude oil and petroleum products and, on a smaller scale, CO2.

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The interest rate on borrowings may be based on an alternate base rate or a Eurodollar rate, at our option. The alternate base rate is equal to the sum of (a) the greatest of (i) the prime rate as established by the administrative agent for the credit facility, (ii) the federal funds effective rate plus 0.5% of 1% and (iii) the LIBOR rate for a one-month maturity plus 1% and (b) the applicable margin. The Eurodollar rate is equal to the sum of (a) the LIBOR rate for the applicable interest period multiplied by the statutory reserve rate and (b) the applicable margin. The applicable margin varies from 1.75% to 2.75% on Eurodollar borrowings and from 0.75% to 1.75% on alternate base rate borrowings, depending on our leverage ratio. Our leverage ratio is recalculated quarterly and in connection with each material acquisition. At December 31, 2012, the applicable margins on our borrowings were 1.0% for alternate base rate borrowings and 2.0% for Eurodollar rate borrowings.

•	Letter of credit fees range from 1.75% to 2.75% based on our leverage ratio as computed under the credit facility. The rate can fluctuate quarterly. At December 31, 2012, our letter of credit rate was 2.0%.

•	We pay a commitment fee on the unused portion of the $1 billion maximum facility amount. The commitment fee on the unused committed amount will range from 0.375% to 0.50% per annum depending on our leverage ratio (0.375% at December 31, 2012).

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•	incur indebtedness if certain financial ratios are not maintained;

•	grant liens;

•	engage in sale-leaseback transactions; and

•	sell substantially all of our assets or enter into a merger or consolidation.

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•	Pipeline Transportation – interstate, intrastate and offshore crude oil, and to a lesser extent, CO2;

•	Refinery Services – processing high sulfur (or “sour”) gas streams as part of refining operations to remove the sulfur and selling the related by-product, NaHS and;

•	Supply and Logistics – terminaling, blending, storing, marketing, and transporting crude oil and petroleum products (primarily fuel oil, asphalt, and other heavy refined products) and, on a smaller scale, CO2.

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(a)	A reconciliation of Segment Margin to income (loss) before income taxes for each year presented is as follows:

(b)

Capital expenditures include maintenance and growth capital expenditures, such as fixed asset additions (including enhancements to existing facilities and construction of internal growth projects) as well as acquisitions of businesses and interests in equity investees. Capital spending in our pipeline transportation segment included $63.7 million during the year ended December 31, 2012 representing capital contributions to our SEKCO equity investee to fund our share of the construction costs for its pipeline. During the same period, capital spending in our pipeline transportation segment also included $205.6 million for the acquisition of interests in several Gulf of Mexico pipelines. During 2012, capital spending in our supply and logistics segment also included $30.9 million for the purchase of barge assets.

(c)	Intersegment sales were conducted under terms that we believe were no more or less favorable than then-existing market conditions.

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(1)	Affiliates of Denbury Resources, Inc. sold its interests in our general partner in February 2010. Transactions with Denbury are included in the table as a related party through that date.

(2)

The Quintana Group, a private equity fund based in Houston, Texas owned 12% of our Class A common units and 74% of our Class B common units until October 5, 2012 when the Quintana Group monetized all of its remaining investment in us. Substantially in connection with that transaction, certain members of the Davison family, collectively, increased their investment in us to 17.2% of our Class A common units and 76.9% of our Class B common units. At December 31, 2012, certain members of the Davison family, collectively, owned 17% of our Class A common units and 76.9% of our Class B common units. Solely for financial statement purposes, we will continue to treat the Davison family and their affiliates as related parties.

(3)	We own a 50% interest in Sandhill Group, LLC.

(4)	Our general partner became a wholly-owned subsidiary in December 2010.

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(1)	These derivative liabilities have been funded with margin deposits recorded in our Consolidated Balance Sheets under Current Assets - Other.

(1)	Represents the amount of loss recognized in income for derivatives related to the fair value hedge of inventory. The amount excludes the gain on the hedged inventory under the fair value hedge of $0.8 million and $1 million for the years ended 2011 and 2010, respectively.

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(1)	Income tax expense is related to taxable income generated by our corporate subsidiaries and Texas Margin Tax. Due to the income tax benefit in 2012 and 2011 and the loss before income taxes in 2010, the effective tax rate as a percentage of our total income (loss) before income taxes is not meaningful.

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(1)	Represents cash distributions declared and paid in the applicable period.

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(1)	Includes the Pipeline and related assets.

(2)	Platforms and facilities include offshore platforms and related facilities that are an integral part of the Pipeline.

(3)	Crude oil line fill is carried at original cost and is not depreciated, but it is subject to impairment considerations.

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