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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, onshore and offshore pipeline systems, marine transportation 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.

•

We have limited commodity price risk exposure. The volumes of crude oil, refined products or intermediate feedstocks 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, although we cannot completely eliminate commodity price exposure. 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 the rates we charge for processing to maintain a balance between NaHS supply and demand.

•

Our businesses encompass a balanced, diversified portfolio of customers, operations and assets. We operate five business segments and own and operate assets that enable us to provide a number of services to oil 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. Our businesses are primarily focused on providing services around and within refinery complexes. We are not dependent upon any one customer or principal location for our revenues.

•	Our onshore and offshore pipeline transportation and related assets are strategically located. Our pipelines are critical to the ongoing operations of our producer and refiner customers. 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 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.

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Our marine transportation assets provide waterborne transportation throughout North America. Our fleet of barges and boats provide service to both inland and offshore customers within a large North American geographic footprint. There are a limited number of Jones Act qualified vessels participating in United States coastwise trade. All of our vessels operate under the United States flag and are qualified for United States coastwise trade under the Jones Act.

•

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-eight consecutive quarters as of our most recent distribution declaration. During this period, thirty-three of those quarterly increases have been 10% or greater as compared to the same quarter in the preceding year.

•	We are financially flexible and have significant liquidity. As of December 31, 2014, we had $438.8 million available under our $1 billion credit agreement, including up to $105.0 million available under the $150 million petroleum products inventory loan sublimit, and $89.2 million available for letters of credit. Our inventory borrowing base was $45.0 million at December 31, 2014.

•	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 crude oil refining can provide us with an advantage when evaluating new opportunities and/or markets.

•

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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(1)	Our Louisiana pipeline system only had throughput for partial year during 2014, as it was placed into service in March 2014.

•	Texas System. Our Texas System transports crude oil from West Columbia to several delivery points near Houston, Texas. 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. That system also includes gathering connections to approximately 43 wells, additional oil storage capacity of 20,000 barrels in the field, an interconnect with our Walnut Hill rail facility, a delivery connection to a refinery in Alabama and an interconnection to another common carrier pipeline that delivers crude oil into Mississippi.

•

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. That 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.

•

Louisiana System. Our Louisiana System transports crude oil from Port Hudson to the Baton Rouge Scenic Station and continues downstream to the Anchorage Tank Farm servicing Exxon Mobil Corporation's Baton Rouge refinery. This refinery is one of the largest refinery complexes in North America, with more than 500,000 barrels per day of refining capacity. This pipeline system was completed in the first quarter of 2014 and Scenic Station became fully operational in July 2014.

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(1)	Capacity figures represent gross system capacity except Eugene Island, which represents our net capacity in the undivided interest (34%) in that system. Ultimate capacities can vary primarily as a result of pressure requirements, installed pumps, related facilities and the viscosity of the oil actually moved.

(2)	Crude throughput volumes on the SEKCO pipeline commenced in the first quarter of 2015. We began earning certain minimum fees upon completion of the SEKCO pipeline in 2014.

•

CHOPS. CHOPS is comprised of 24- to 30-inch diameter pipelines designed to deliver crude oil from fields 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.

•	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.

•

SEKCO Pipeline. SEKCO, our 50/50 joint venture with Enterprise Products, is a deepwater pipeline serving the Lucius oil and gas field located in the southern Keathley Canyon area of the Gulf of Mexico. That pipeline was completed in June 2014. SEKCO has crude oil transportation agreements with six Gulf of Mexico producers, including Anadarko U.S. Offshore Corporation, Apache Deepwater Development LLC, Exxon Mobil Corporation, Eni Petroleum US LLC, Petrobras America and Plains Offshore Operations, Inc. Those producers have dedicated their production from Lucius to the pipeline for the life of the reserves. We expect the SEKCO pipeline to also provide capacity for additional projects in the deepwater Gulf of Mexico in the future. Enterprise Products served as construction manager and is the operator of the SEKCO pipeline. SEKCO’s customers commenced paying fees to SEKCO upon completion of its pipeline and commenced crude oil deliveries to the SEKCO pipeline in the first quarter of 2015.

•	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.

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(1)	Represents capacity per barge ranges on our inland and offshore barges, as well as the overall capacity of the M/T American Phoenix.

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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 services;

•	the level of competition;

•	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;

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•	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;

•	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

•	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 its affiliates, retention of counsel, accountants and service providers and cash reserves, each of which can also affect the amount of cash that is distributed to our unitholders; 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

•	unitholders 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. For additional information regarding our acquisitions and divestitures during 2014, 2013 and 2012, see Note 3 to our Consolidated Financial Statements included in Item 8.

(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.

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

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•	Overview of 2014 Results

•	Segment Reporting Change

•	Acquisitions, Divestitures and Growth Initiatives

•	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

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(1)	Represents volumes per day from the period the pipeline began operations in the first quarter of 2014.

•	Onshore crude oil pipeline loss allowance volumes, collected and sold, decreased Segment Margin by $2.5 million. Due to the nature of our tariffs on the Louisiana system, we do not collect or sell pipeline loss allowance volumes on this system.

•

With respect to our onshore crude oil pipelines, tariff revenues increased $2.7 million, or 7%, primarily due to a net increase in throughput volumes of 12,199 barrels per day, primarily from the addition of our Louisiana pipeline system and increases in volumes on our Texas pipeline system. Our Louisiana pipeline system is a new 17-mile 24-inch diameter crude oil pipeline connecting Port Hudson to the Baton Rouge Scenic Station and continuing downstream to the Anchorage Tank Farm. This system was placed into service during the first quarter of 2014. These increases were partially offset by volume variances on our other onshore pipeline systems. Due to a mix of tariff rates on our onshore pipelines, the impact on onshore crude oil tariffs and revenues from these volume variances largely offset each other.

•	Onshore pipeline operating costs, excluding non-cash charges, increased $2.7 million due to pipeline integrity maintenance expenditures on our onshore pipelines, employee compensation and related benefit costs and general increases in operating costs inclusive of safety program costs.

•

Volumes on our Free State CO2 pipeline system decreased 16,504 Mcf per day, or 9%. We provide transportation services on our Free State CO2 pipeline system through an "incentive" tariff, which provides that the average rate per Mcf that we charge during any month decreases as our aggregate throughput for that month increases above specific thresholds. As a result of this "incentive" tariff, fluctuations in volumes above a certain base level on our Free State CO2 pipeline system have a limited impact on Segment Margin.

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(1)	Offshore Pipeline Transportation segment margin includes approximately $71 million and $44 million of distributions received from our offshore pipeline joint ventures accounted for under the equity method of accounting in 2014 and 2013, respectively.

(2)	Volumes for our equity method investees are presented on a 100% basis.

(3)	Our SEKCO pipeline was completed in June of 2014. Under the terms of SEKCO’s transportation arrangements, its shippers commenced making minimum monthly payments at that time, even though they did not commence throughput of crude until January 2015.

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(1)	Source: IHS Chemical

•	NaHS revenues increased 2% primarily due to a slight increase in volumes. 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 decreased correspondingly to the decrease in the average index price for caustic soda. We were able to realize benefits from operating efficiencies at several of our sour gas processing facilities, our favorable management of the acquisition (including economies of scale) and utilization of caustic soda in our (and our customers') operations, and our logistics management capabilities.

•

Caustic soda revenues decreased 4%, primarily due to a decrease in our sales price for caustic soda, which was partially offset by an increase in sales volumes. 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.

•

Average index prices for caustic soda decreased to $589 per DST during 2014 compared to $604 per DST during 2013. 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 index 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.

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•	An increase in segment margin in 2014 due to a full year of operating results from our offshore marine transportation business, which we acquired in August 2013.

•	The expansion of our inland marine fleet in 2014, with "new builds" including the addition of 8 inland barges and 2 inland pushboat in 2014.

•	The acquisition of the M/T American Phoenix in late 2014, which became immediately accretive to Segment Margin at that time.

•	utilizing the fleet of trucks, trailers and railcars owned or leased by our supply and logistics segment to transport products (primarily crude oil and petroleum products) for customers;

•	utilizing various modes of transportation owned by third parties and us to transport products (primarily crude oil and petroleum products) for our own account to take advantage of logistical opportunities primarily in the Gulf Coast states and waterways;

•	purchasing/selling 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;

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•	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 and selling those products;

•	railcar loading and unloading activities at our crude-by-rail terminals; and

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

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Crude oil tariff revenues of onshore crude oil pipelines increased $7.7 million, or 24%, primarily due to (1) upward tariff indexing of approximately 4.6% for our FERC-regulated pipelines effective in July 2013 and (2) a net increase in throughput volumes of 12,627 barrels per day primarily from our Jay pipeline system primarily from additional barrels received at our crude-by-rail unloading terminal at Walnut Hill, Florida.

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•	Onshore crude oil pipeline loss allowance volumes, collected and sold, improved Segment Margin by $2.4 million due to an increase in barrels transported in 2013 compared to 2012.

•	Pipeline operating costs, excluding non-cash charges, increased $3.6 million, due to pipeline integrity maintenance expenditures on the pipelines, employee compensation and related benefit costs and general increases in operating costs inclusive of safety program costs.

(1)	Offshore Pipeline Transportation segment margin includes approximately $44 million and $37 million of distributions received from our offshore pipeline joint ventures accounted for under the equity method of accounting in 2013 and 2012, respectively.

(2)	Volumes for our equity method investees are presented on a 100% basis.

(3)	Acquired in January 2012.

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(1)	Source: IHS Chemical

•

NaHS revenues increased primarily as a function of increased sales volumes and an increase in the average index price for caustic soda (which is a component of our sales price), partially offset by other components referenced below. In 2013, NaHS sales volumes increased 3% primarily due to increased demand from customers in the pulp and paper industry, however this increase was partially offset by a decrease in sales to South American customers (due to timing of bulk deliveries). 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. The mix of NaHS sales volumes to which these adjustments applied reduced NaHS revenues in 2013.

•

Our raw material costs related to NaHS increased correspondingly to the rise in the average index price for caustic soda, although we were able to partially offset our increased raw materials costs with operating efficiencies at several of our sour gas processing facilities, our favorable management of the acquisition (including economies of scale) and utilization of caustic soda in our (and our customers') operations, and our logistics management capabilities.

•

Caustic soda sales volumes increased 13%. 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.

•

Average index prices for caustic soda increased to $604 per DST during 2013 compared to $575 per DST during 2012. 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.

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(1)	the financial performance of our assets;

(2)	our operating performance;

(3)	the viability of potential projects, including our cash and overall return on alternative capital investments as compared to those of other companies in the midstream energy industry;

(4)	the ability of our assets to generate cash sufficient to satisfy certain non-discretionary cash requirements, including interest payments and certain maintenance capital requirements; and

(5)	our ability to make certain discretionary payments, such as distributions on our units, growth capital expenditures, certain maintenance capital expenditures and early payments of indebtedness.

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(1)	In the first quarter of 2014, we changed our method of including maintenance capital in our calculation of Available Cash before Reserves to "maintenance capital utilized" rather than "maintenance capital expenditures". For a description of the term "maintenance capital utilized," please see the definition of the term "Available Cash Before Reserves" previously discussed.

•	Working capital, primarily inventories;

•	Routine operating expenses;

•	Capital growth 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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(1)	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 13, 2015 to unitholders of record as of February 2, 2015.

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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, 2019. We have $350 million in aggregate principal amount of senior unsecured notes that mature on December 15, 2018 (the "2018 Notes"), $350 million in aggregate principal amount of senior unsecured notes that mature on February 15, 2021 (the "2021 Notes") and $350 million in aggregate principal amount of senior unsecured notes that mature on June 15, 2024 (the "2024 Notes").

(2)

Interest on our long-term debt under our credit facility is at market-based rates. The interest rates on our 2018, 2021 and 2024 Notes are 7.875%, 5.75% and 5.625%, respectively. The amount shown for interest payments represents the amount that would be paid if the debt outstanding at December 31, 2014 under our credit facility remained outstanding through the final maturity date of July 25, 2019 and interest rates remained at the December 31, 2014 market levels through the final maturity date. Also included is the interest on our senior unsecured notes through their respective maturity dates.

(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, 2014 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 recorded asset retirement obligation on our balance sheet at December 31, 2014 was $14.8 million and is further discussed in Note 6 to our Consolidated Financial Statements.

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(1)	Prices and volumes as 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;

•	Robert V. Deere, Chief Financial Officer;

•	Paul A. Davis, Senior Vice President;

•	Stephen M. Smith, Vice President; and

•	Richard R. Alexander, 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 growing cash distributions and growing 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 compensation 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;

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•	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.

(1)	For 2014, Mr. Davis received a retention bonus of $125,000 and a bonus of $225,000.

(2)

The amounts shown in this column represent the aggregate grant date fair value for each NEO’s phantom units granted under our 2010 Long-Term Incentive Plan, excluding the amount shown for Mr. Davis. The 2012 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. 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)	Mr. Alexander became an executive officer of our general partner in November 2014.

(5)	The following table presents the components of "All Other Compensation" for each NEO for the year ended December 31, 2014.

(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 9, 2014, if the company meets certain performance conditions (threshold, target and maximum) during the fourth quarter of 2016. See additional discussion in "Long-Term Incentive Compensation" above.

(2)	Represents the closing market price of our common units on the date of the phantom unit award on April 9, 2014.

(3)	The amounts in this column for each NEO represent the fair value of the award on the date of the grant (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 ($54.16).

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(1)	The number of performance units reflected in the table assumes a maximum performance payout based upon past achievement levels from the previous vesting period. For the service based units reflected in the table above, as only held by Mr. Alexander, the threshold, target, and maximum payouts are identical.

(2)	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.

(3)	Phantom units outstanding for Mr. Alexander include 2,222, 2,126 and 3,395 service based units for 2014, 2013 and 2012, respectively. The remainder of the outstanding units held by Mr. Alexander and represented above are performance based units.

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•	“Good cause” means, in general, if the executive commits willful theft, embezzlement, forgery; conviction of similar criminal activity; willful violation of our material policies; or substantial non-performance of duties.

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“Change of control” means, in general, any sale or other transfer of substantially all of the assets of us or our general partner, other than to our affiliates, or any merger, consolidation, or other transaction pursuant to which more than 50% of our publicly-traded common units or more than 50% of our Class B Common Units ceases to be beneficially owned by the persons who owned such interests as of the date of the employment agreement.

•	“Good reason” means, in general, the diminution of the executive’s duties, title, reporting relationships, compensation, or benefits, or the relocation of our principal offices or the requirement that the executive be based anywhere other than the Houston, Texas area without his consent.

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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.

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“Good Reason” means, in general, following a change of control which results in a substantial diminution of the executive’s duties, compensation, or benefits; executive’s removal from position as Vice President (other than for cause, death or disability, or being offered an equivalent position); or our failure to make any payment to the executive required under the terms of his employment agreement.

•

“Change of control” means, in general, any sale of equity in us or our general partner or sale of substantially all of our assets; any merger, conversion or consolidation of us or our general partner; or any other event that, in each of the foregoing cases, results in any persons or entities having the ability to elect a majority of the members of our board of directors (other than one or more of our executive officers or affiliates).

•	“Renewal term” means, in general, each one-year term of employment beginning on July 18 of each year, absent either the Company or the executive giving the other party at least 90 days advance written notice of its intent not to renew the employment agreement between them.

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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, 2014 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 6,111 outstanding phantom units and 1,000 stock appreciation rights. Messrs. Jastrow, Robertson, Albert, Taylor and Ms. Gasaway hold 6,746, 6,159, 2,779, 2,779 and 6,915 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.

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*	Less than 1%

(1)

The Class B Common Units, which also are included in the Class A Common Unit total, are identical in most respects to the Class A Common Units and have voting and distribution rights equivalent to those of the Class A Common Units. 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. In addition to his direct ownership interests, Mr. Davison is the sole stockholder of Davison Terminal Service, Inc., which owns 1,010,835 Class A Common Units.

(3)	Mr. Davison, Jr. pledged 1,164,370 of these Class A Common Units as collateral for a loan from a bank. 1,339,383 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)	Mr. Robertson pledged 1,512,555 of these Class A Common Units as collateral for margin accounts. Includes 198,785 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

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

(6)	Mr. Smith pledged 275,000 Class A Common Units as collateral for margin brokerage accounts.

(7)	Includes 147,941 Class A Common units held by the Steven Davison Family Trust.

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(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 reviewing our documentation of controls and process for conversion related to our project to upgrade our information technology systems

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

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

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•	Offshore pipeline transportation of crude oil in the Gulf of Mexico;

•	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");

•	Marine transportation to provide waterborne transportation of petroleum products and crude oil throughout North America; 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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(1)	See discussion of deferred charges on marine transportation assets in the Summary of Accounting Policies (Note 2)

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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 1.50% to 2.50% on Eurodollar borrowings and from 0.50% to 1.50% 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, 2014, the applicable margins on our borrowings were 1.25% for alternate base rate borrowings and 2.25% for Eurodollar rate borrowings.

•	Letter of credit fees range from 1.50% to 2.50% based on our leverage ratio as computed under the credit facility. The rate can fluctuate quarterly. At December 31, 2014, our letter of credit rate was 2.25%.

•	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 0.250% to 0.375% per annum depending on our leverage ratio (0.375% at December 31, 2014).

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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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•	Onshore Pipeline Transportation –transportation of crude oil, and to a lesser extent, CO2;

•	Offshore Pipeline Transportation – offshore transportation of crude oil in the Gulf of Mexico;

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•	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;

•	Marine Transportation – marine transportation to provide waterborne transportation of petroleum products and crude oil throughout North America 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)	Discontinued operations are included in Segment Margin but excluded from revenues for all periods presented.

(b)	A reconciliation of Segment Margin to income from continuing operations before income taxes for each year is presented below.

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(1)	We own a 50% interest in Sandhill Group, LLC (or "Sandhill).

(2)	Amounts included in discontinued operations for all periods presented.

(3)	The Quintana Group monetized all of its remaining investment in our common units on October 5, 2012. Transactions with the Quintana Group are included in the above table as related party transactions through October 5, 2012.

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(1)	These derivative liabilities have been funded with margin deposits recorded in our Consolidated Balance Sheets under Current Assets - Other in 2013.

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(1)	Our discontinued operations had no income tax benefit or expense in any period presented.

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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, the effective tax rate as a percentage of our total income from continuing operations before income taxes is not meaningful for those periods.

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

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