GEL 12.31.2013 10-K

Table of Contents


UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-K
x ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2013
OR
¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission file number 1-12295
GENESIS ENERGY, L.P.
(Exact name of registrant as specified in its charter)
Delaware
 
76-0513049
(State or other jurisdiction of
incorporation or organization)
 
(I.R.S. Employer
Identification No.)
919 Milam, Suite 2100, Houston, TX 77002
(Address of principal executive offices) (Zip code)
(713) 860-2500
Registrant’s telephone number, including area code:
Securities registered pursuant to Section 12(b) of the Act:
Title of Each Class
 
Name of Each Exchange on Which Registered
Common Units
 
NYSE
Securities registered pursuant to Section 12(g) of the Act:
NONE
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.    Yes  x    No  o
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.    Yes  o    No  x
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  x    No  o
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  x    No  o
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.    o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer”, “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. 
Large accelerated filer
x
Accelerated filer
¨
Non-accelerated filer
o
Smaller reporting company
¨
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2) of the Act).    Yes  o    No  x
The aggregate market value of the Class A common units held by non-affiliates of the Registrant on June 30, 2013 (the last business day of Registrant’s most recently completed second fiscal quarter) was approximately $3.3 billion based on $51.83 per unit, the closing price of the common units as reported on the NYSE. For purposes of this computation, all executive officers, directors and 10% owners of the registrant are deemed to be affiliates. Such a determination should not be deemed an admission that such executive officers, directors and 10% beneficial owners are affiliates. On February 24, 2014, the Registrant had 88,650,988 Class A Common Units and 39,997 Class B Common Units outstanding.




Table of Contents

GENESIS ENERGY, L.P.
2013 FORM 10-K ANNUAL REPORT
Table of Contents
 
 
 
Page
Item 1
Item 1A.
Item 1B.
Item 2.
Item 3.
Item 4.
Item 5.
Item 6.
Item 7.
Item 7A.
Item 8.
Item 9.
Item 9A.
Item 9B.
Item 10.
Item 11.
Item 12.
Item 13.
Item 14.
Item 15.


2


Table of Contents

Definitions
Unless the context otherwise requires, references in this annual report to “Genesis Energy, L.P.,” “Genesis,” “we,” “our,” “us” or like terms refer to Genesis Energy, L.P. and its operating subsidiaries. As generally used within the energy industry and in this annual report, the identified terms have the following meanings:
Bbl or Barrel: One stock tank barrel, or 42 U.S. gallons liquid volume, used in reference to oil or other liquid hydrocarbons.
Bbls/day: Barrels per day.
Bcf: Billion cubic feet of gas.
CO2: Carbon dioxide.
DST: Dry short tons (2,000 pounds), a unit of weight measurement.
FERC: Federal Energy Regulatory Commission.
Gal: Gallon.
MBbls: Thousand Bbls.
MBbls/d: Thousand Bbls per day.
Mcf: Thousand cubic feet of gas.
mmBtu: One million British thermal units, an energy measurement.
MMcf: Thousand Mcf.
NaHS: (commonly pronounced as “nash”) Sodium hydrosulfide.
NaOH or Caustic Soda: Sodium hydroxide.
Natural gas liquid(s) or NGL(s): The combination of ethane, propane, normal butane, isobutane and natural gasolines that, when removed from natural gas, become liquid under various levels of higher pressure and lower temperature.
Sour gas: Natural gas containing more than four parts per million of hydrogen sulfide.
Wellhead: The point at which the hydrocarbons and water exit the ground.
FORWARD-LOOKING INFORMATION
The statements in this Annual Report on Form 10-K that are not historical information may be “forward looking statements” as defined under federal law. All statements, other than historical facts, included in this document that address activities, events or developments that we expect or anticipate will or may occur in the future, including things such as plans for growth of the business, future capital expenditures, competitive strengths, goals, references to future goals or intentions and other such references are forward-looking statements. These forward-looking statements are identified as any statement that does not relate strictly to historical or current facts. They use words such as “anticipate,” “believe,” “continue,” “estimate,” “expect,” “forecast,” “goal,” “intend,” “may,” “could,” “plan,” “position,” “projection,” “strategy,” “should” or “will,” or the negative of those terms or other variations of them or by comparable terminology. In particular, statements, expressed or implied, concerning future actions, conditions or events or future operating results or the ability to generate sales, income or cash flow are forward-looking statements. Forward-looking statements are not guarantees of performance. They involve risks, uncertainties and assumptions. Future actions, conditions or events and future results of operations may differ materially from those expressed in these forward-looking statements. Many of the factors that will determine these results are beyond our ability or the ability of our affiliates to control or predict. Specific factors that could cause actual results to differ from those in the forward-looking statements include, among others:
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;

3


Table of Contents

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.
You should not put undue reliance on any forward-looking statements. When considering forward-looking statements, please review the risk factors described under “Risk Factors” discussed in Item 1A. These risks may also be specifically described in our Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and Form 8-K/A and other documents that we may file from time to time with the SEC. Except as required by applicable securities laws, we do not intend to update these forward-looking statements and information.



4


Table of Contents

PART I
Item 1. Business
General
We are a growth-oriented master limited partnership formed in Delaware in 1996 and focused on the midstream segment of the oil and gas industry in the Gulf Coast region of the United States, primarily Texas, Louisiana, Arkansas, Mississippi, Alabama, Florida, Wyoming and in the Gulf of Mexico. Our common units are traded on the New York Stock Exchange under the ticker symbol “GEL.” Our principal executive offices are located at 919 Milam, Suite 2100, Houston, Texas 77002 and our telephone number is (713) 860-2500. Except to the extent otherwise provided, the information contained in this annual report is as of December 31, 2013.
We provide an integrated suite of services to oil producers, refineries, and industrial and commercial enterprises. Our business activities are primarily focused on providing services around and within refinery complexes. Upstream of the refineries, we provide gathering and transportation of crude oil. Within the refineries, we provide services to assist in their sulfur balancing requirements. Downstream of refineries, we provide transportation services as well as market outlets for their finished refined products. We have a diverse portfolio of customers, operations and assets, including pipelines, refinery-related plants, storage tanks and terminals, railcars, rail loading and unloading facilities, barges and trucks. Substantially all of our revenues are derived from providing services to integrated oil companies, large independent oil and gas or refinery companies, and large industrial and commercial enterprises.
We conduct our operations and own our operating assets through our subsidiaries and joint ventures. Our general partner, Genesis Energy, LLC, a wholly-owned subsidiary that owns a non-economic general partner interest in us, has sole responsibility for conducting our business and managing our operations.
We manage our businesses through three divisions that constitute our reportable segments – Pipeline Transportation, Refinery Services, and Supply and Logistics.
Pipeline Transportation Segment
Overview
We own interests in approximately 1,530 miles of crude oil pipelines located in the Gulf Coast region of the United States. We also own two CO2 pipelines. Our pipelines generate cash flows from fees charged to customers or substantially similar arrangements that otherwise limit our exposure to changes in commodity prices.
Crude Oil Pipelines
We own interests in three onshore crude oil pipeline systems, with approximately 480 miles of pipe located primarily in Alabama, Florida, Mississippi and Texas. The Federal Energy Regulatory Commission, or FERC, regulates the rates charged by two of our onshore systems to their customers. The rates for the other onshore pipeline are regulated by the Railroad Commission of Texas. We also own interests in various offshore crude oil pipeline systems, with approximately 1,050 miles of pipe and an aggregate design capacity of approximately 1,090 MBbls per day, located offshore in the Gulf of Mexico, a producing region representing approximately 20% of the crude oil production in the United States in 2013. For example, we own a 28% interest in the Poseidon pipeline system and a 50% interest in the Cameron Highway pipeline system, or CHOPS, which is one of the largest crude oil pipelines (in terms of both length and design capacity) located in the Gulf of Mexico.
CO2 Pipelines
We own interests in two CO2 pipelines with approximately 270 miles of pipe. We have leased our NEJD System, comprised of 183 miles of pipe in North East Jackson Dome, Mississippi, to an affiliate of a large, independent oil company through 2028. That company also has the exclusive right to use our Free State pipeline, comprised of 86 miles of pipe, pursuant to a transportation agreement that expires in 2028. We receive a fixed quarterly payment under the NEJD arrangement. Payments on the Free State pipeline are dependent on throughput.
Refinery Services Segment
We primarily (i) provide services to ten refining operations located primarily in Texas, Louisiana, Arkansas, Oklahoma and Utah; (ii) operate significant storage and transportation assets in relation to those services; and (iii) sell NaHS and caustic soda to large industrial and commercial companies. Our refinery services primarily involve processing refiners’ high sulfur (or “sour”) gas streams to remove the sulfur. Our refinery services footprint also includes terminals, and we utilize railcars, ships, barges and trucks to transport product. Our refinery services contracts are typically long-term in nature and have an average remaining term of four years. NaHS is a by-product derived from our refinery services process, and it constitutes the sole

5


Table of Contents

consideration we receive for these services. A majority of the NaHS we receive is sourced from refineries owned and operated by large companies, including Phillips 66, CITGO, HollyFrontier and Ergon. We sell our NaHS to customers in a variety of industries, with the largest customers involved in mining of base metals, primarily copper and molybdenum, and the production of pulp and paper. We believe we are one of the largest marketers of NaHS in North and South America.
Supply and Logistic Segment
We provide supply and logistics services primarily to Gulf Coast oil and gas producers and refineries through a combination of purchasing, transporting, storing, blending and marketing of crude oil and refined products (primarily fuel oil, asphalt, and other heavy refined products). In connection with these services, we utilize our portfolio of logistical assets consisting of trucks, terminals, pipelines, railcars, rail loading and unloading facilities, and barges. We have access to a suite of more than 300 trucks, 400 trailers, 580 railcars, and terminals and tankage with 2.4 million barrels of storage capacity in multiple locations along the Gulf Coast as well as capacity associated with our three common carrier crude oil pipelines. Our crude-by-rail operations consist of a total of six facilities, either in operation or under construction, designed to load and/or unload crude oil. The two facilities located in Texas and Wyoming were designed primarily to load crude oil produced locally onto railcars for further transportation to refining markets. The four other facilities (two in Louisiana, one in Mississippi and one in Florida) were designed primarily to unload crude oil from railcars into pipelines, or onto barges, for delivery to refinery customers. Our marine operations include access to 63 barges (54 inland and 9 offshore) with a combined transportation capacity of 2.4 million barrels of heavy refined petroleum products, including asphalt, and 32 push/tow boats (23 inland and 9 offshore). Usually, our supply and logistics segment experiences limited commodity price risk because it utilizes back-to-back purchases and sales, matching sale and purchase volumes on a monthly basis. Unsold volumes are hedged with NYMEX derivatives to offset the remaining price risk.
Our Objectives and Strategies
Our primary business objectives are to generate stable cash flows that allow us to make quarterly cash distributions to our unitholders and to increase those distributions over time. We plan to achieve those objectives by executing the following business and financial strategies.
Business Strategy
Our primary business strategy is to provide an integrated suite of services to oil and gas producers, refineries and other customers. Successfully executing this strategy should enable us to generate and grow sustainable cash flows. We intend to develop our business by:
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.
Financial Strategy
We believe that preserving financial flexibility is an important factor in our overall strategy and success. Over the long-term, we intend to:
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.

6


Table of Contents

Competitive Strengths
We believe we are well positioned to execute our strategies and ultimately achieve our objectives due primarily to the following competitive strengths:
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 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 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.
We have limited 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, 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 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-four consecutive quarters as of our most recent distribution declaration. During this period, twenty-nine 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, 2013, we had $405.3 million available under our $1 billion credit agreement, including up to $69.2 million available under the $150 million petroleum products inventory loan sublimit, and $88.1 million available for letters of credit. Our inventory borrowing base was $80.8 million at December 31, 2013.
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.
Recent Developments and Status of Certain Growth Initiatives
The following is a brief listing of developments since December 31, 2012. Additional information regarding most of these items may be found elsewhere in this report.

Acquisition of Additional Barges and Tug Boats

On August 28, 2013, we completed the acquisition of substantially all of the assets of the downstream transportation business of Hornbeck Offshore Services, Inc. for approximately $230.9 million, which we refer to as our offshore marine transportation business and assets. The acquired business was primarily comprised of nine barges and nine tug boats which transport crude oil and refined petroleum products, principally serving refineries and storage terminals along the Gulf Coast, Eastern Seaboard, Great Lakes and Caribbean. That acquisition complements and further integrates our existing operations, including our Genesis Marine inland barge business (comprised of 54 barges and 23 push/tow boats), our crude oil and heavy refined products storage and blending terminals as well as our crude oil pipeline systems.


7


Table of Contents

ExxonMobil Baton Rouge Project

We are improving existing assets and developing 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 24-inch diameter crude oil pipeline connecting Port Hudson to the Baton Rouge Scenic Station and continuing downstream to the Anchorage Tank Farm and building a new crude oil unit train unload facility at Scenic Station. The Port Hudson upgrades and new crude oil pipeline are expected to be completed by the end of the first quarter of 2014, and Scenic Station is expected to be completed in the second quarter of 2014.
Baton Rouge Terminal
We recently announced plans to construct a new crude oil, intermediates and refined products import/export terminal in Baton Rouge. That terminal will be located near the Port of Greater Baton Rouge and will be pipeline-connected to that port's existing deepwater docks on the Mississippi River. We will initially construct approximately 1.1 million barrels of tankage for the storage of crude oil, intermediates and/or refined products with the capability to expand to provide additional terminaling services to our customers. Our Baton Rouge Terminal will also be pipeline-connected to ExxonMobil facilities in the area, as well as to Scenic Station. Shippers to Scenic Station will have access to both the local Baton Rouge refining market, as well as the ability to access other attractive refining markets via our Baton Rouge Terminal. The Baton Rouge Terminal is expected to be completed by the end of the second quarter of 2015.
Deepwater Gulf of Mexico Pipeline Joint Venture
Southeast Keathley Canyon Pipeline Company LLC, or SEKCO, our 50/50 joint venture with Enterprise Products Partners, L.P., expects to place in-service in mid-2014 its deepwater pipeline serving the Lucius oil and gas field in the southern Keathley Canyon area of the Gulf of Mexico. SEKCO has entered into 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 pipeline to provide capacity for additional projects in the deepwater Gulf of Mexico. Enterprise Products serves as construction manager and will be the operator of the new pipeline.
The 149-mile, 18-inch diameter pipeline, designed to have a 115,000 barrel per day capacity, will connect the Lucius-truss spar floating production platform to an existing junction platform at South Marsh Island that is part of the Poseidon pipeline system, in which we own a 28% interest. See additional discussion regarding this project in Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources.”
Texas City Projects
In December 2013, we placed in-service an 18-inch diameter loop of our existing crude oil pipeline into Texas City, supported by a term contract with one of our refining customers, which we expect will allow us to significantly expand our total service capabilities into the Texas City area. Previously, we had acquired three above-ground storage tanks located in Texas City, Texas and an existing barge dock at the same location, all approximately 1.5 miles from our existing Texas pipeline system. We also constructed a truck station and tankage in West Columbia, Texas to provide incremental transportation service for the Eagle Ford Shale and other Texas production through our pipeline system to refining markets in the greater Houston/Texas City area. We are able to handle approximately 40,000 barrels per day of crude oil through the Texas City terminal.
Rail Projects    
Walnut Hill - In the first quarter of 2013, we completed construction on the second phase of our crude-by-rail unloading terminal at Walnut Hill, Florida, which includes a 100,000 barrel storage tank, related equipment and connections to our Jay System. This facility provides the capability of handling unit train shipments for direct deliveries to an existing refinery customer and indirect deliveries (through third-party common carriers) to multiple other markets in the Southeast at the option of the shippers. We have commenced construction on an additional tank at that site with 110,000 barrels of capacity, which will allow us to handle increased rail and pipeline demand. We estimate this tank will be fully operational by the end of the first quarter of 2014.
Wink - In 2012, we completed the initial phase construction of a crude oil rail loading facility in Wink, Texas, which was designed to move crude oil from West Texas to other markets and gives us the capability to load Genesis and third party railcars. Construction on the second phase of that facility, which we estimate will be operational by the end of the first quarter of 2014, will allow us to more efficiently load full unit trains.
Natchez - In the third quarter of 2013, we completed construction on a crude oil rail unloading/loading facility at our existing terminal located in Natchez, Mississippi, which is designed to facilitate the movement of Canadian bitumen/dilbit to Gulf Coast markets. That facility has the capability to unload bitumen/dilbit as well as load diluent for backhauls to Canada.

8


Table of Contents

We have initiated construction on the second phase of the Natchez facility, which will provide an additional 60 railcar spots and additional heated tanks. We expect to complete that rail unloading/loading facility expansion by the end of the first quarter of 2014.
Raceland - In the fourth quarter of 2013, we began construction on a new crude oil unit train unloading facility capable of unloading up to two unit trains per day, which is located in Raceland, Louisiana. The Raceland Rail Facility will be connected to existing midstream infrastructure that will provide direct pipeline access to refineries from the Baton Rouge area to the Gulf of Mexico and is expected to be operational in the fourth quarter of 2014.
Pronghorn - In December of 2013, we placed in-service a new unit train loading facility in the Powder River Basin of the Niobrara Shale Play. That facility is tied-in to our existing gathering system in that region.
Thirty-four Consecutive Distribution Rate Increases
We have increased our quarterly distribution rate for thirty-four consecutive quarters. Twenty-nine of those quarterly increases have been 10% or greater as compared to the same quarter in the preceding year. On February 14, 2014, we paid a quarterly cash distribution of $0.5350 (or $2.14 on an annualized basis) per unit to unitholders of record as of January 31, 2014, an increase of 2.4% from the distribution in the prior quarter, and an increase of 10.3% from the distribution in February 2013. As in the past, future increases (if any) in our quarterly distribution rate will depend on our ability to execute critical components of our business strategy.
Organizational Structure
The following chart depicts our organizational structure at December 31, 2013.
Description of Segments and Related Assets
We conduct our business through three primary segments: Pipeline Transportation, Refinery Services and Supply and Logistics. These segments are strategic business units that provide a variety of energy-related services. Financial information with respect to each of our segments can be found in Note 12 to our Consolidated Financial Statements in Item 8.
Pipeline Transportation
Overview
We own three onshore crude oil common carrier pipelines, interests in several offshore crude oil pipeline systems in the Gulf of Mexico and two CO2 pipelines. Our core pipeline transportation business is the transportation of crude oil for others for a fee.

9


Table of Contents

Crude Oil Pipelines
Onshore Crude Oil Pipelines
Through the onshore pipeline systems we own and operate, we transport crude oil for our gathering and marketing operations and for other shippers pursuant to tariff rates regulated by FERC or the Railroad Commission of Texas (TXRRC). Accordingly, we offer transportation services to any shipper of crude oil, if the products tendered for transportation satisfy the conditions and specifications contained in the applicable tariff. Pipeline revenues are a function of the level of throughput and the particular point where the crude oil is injected into the pipeline and the delivery point. We also may earn revenue from pipeline loss allowance volumes. In exchange for bearing the risk of pipeline volumetric losses, we deduct volumetric pipeline loss allowances and crude oil quality deductions. Such allowances and deductions are offset by measurement gains and losses. When our actual volume losses are less than the related allowances and deductions, we recognize the difference as income and inventory available for sale valued at the market price for the crude oil.
The margins from our onshore crude oil pipeline operations are generated by the difference between the sum of revenues from regulated published tariffs and pipeline loss allowance revenues and the fixed and variable costs of operating and maintaining our pipelines.
We own and operate three onshore common carrier crude oil pipeline systems: the Texas System, the Jay System and the Mississippi System.
 
 
Texas System
 
Jay System
 
Mississippi System
Product
Crude Oil
 
Crude Oil
 
Crude Oil
Interest Owned
100%
 
100%
 
100%
Design Capacity (Bbls/day)
Existing 8" - 60,000
Looped 18" - 275,000
 
150,000
 
45,000
2013 Throughput (Bbls/day)
51,067
 
34,933
 
18,026
System Miles
109
 
135
 
235
Approximate owned tankage storage capacity (Bbls)
220,000
 
230,000
 
247,500
Location
West Columbia, TX to Webster, TX
 
Southern AL/FL to Mobile, AL
 
Soso, MS to Liberty, MS
 
Webster, TX to Texas City, TX
 
 
 
 
 
Webster, TX to Houston, TX
 
 
 
 
Rate Regulated
TXRRC
 
FERC
 
FERC
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. Our 18-inch diameter loop of our existing crude oil pipeline into Texas City began full operations in mid-December 2013, as discussed in more detail above in "Recent Developments and Growth Initiatives."
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 35 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.
Offshore Crude Oil Pipelines
We own interests in several crude oil pipelines located offshore in the Gulf of Mexico, a producing region representing approximately 20% of the crude oil production in the United States in 2013. CHOPS is one of the largest crude oil pipelines (in

10


Table of Contents

terms of both length and design capacity) located in the Gulf of Mexico. The table below reflects our interests in our operating offshore crude oil pipelines.
 
 
CHOPS
 
Poseidon
 
Odyssey
 
Eugene Island
 
SEKCO (3)
Product
Crude Oil
 
Crude Oil
 
Crude Oil
 
Crude Oil
 
Crude Oil
Interest Owned (1)
50%
 
28%
 
29%
 
23%
 
50%
System Miles
380
 
367
 
120
 
183
 
149
Design Capacity (Bbls/day) (2)
500,000
 
350,000
 
200,000
 
39,000
 
115,000
2013 Throughput (Bbls/day)
143,854
 
207,372
 
44,978
 
8,583
 
N/A
Location
Gulf of Mexico (primarily offshore of Texas and Louisiana)
 
Gulf of Mexico (primarily offshore of Louisiana)
 
Gulf of Mexico (primarily offshore of Louisiana)
 
Gulf of Mexico (primarily offshore of Louisiana)
 
Gulf of Mexico (primarily offshore of Louisiana)
Rate Regulated
No
 
No
 
No
 
FERC
 
No
In-Service Date
2004
 
1996
 
1998
 
1983
 
N/A (3)
 
(1)
We acquired our interests in CHOPS in November 2010 and our interests in our other offshore pipelines in January 2012.
(2)
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.
(3)
Expected to be placed in-service in mid-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. 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 and Growth Initiatives” SEKCO, our 50/50 joint venture with Enterprise Products is constructing a deepwater pipeline serving the Lucius oil and gas field located in the southern Keathley Canyon area of the Gulf of Mexico. The new pipeline is expected to begin service by mid-2014.

11


Table of Contents

CO2 Pipelines
We transport CO2 on our Free State pipeline for a fee and we lease our Northeast Jackson Dome Pipeline System, or NEJD System, for a fee.
 
 
Free State Pipeline
 
NEJD System (1)
Product
CO2
 
CO2
Interest owned
100%
 
100%
System miles
86
 
183
Pipeline diameter
20"
 
20"
Location
Jackson Dome near Jackson, MS to East Mississippi
 
Jackson Dome near Jackson, MS to Donaldsonville, LA
Rate Regulated
No
 
No
 
(1)
Subject to a fixed payment agreement.
Our Free State pipeline extends from CO2 source fields near Jackson, Mississippi to oil fields in eastern Mississippi. We have a transportation services agreement through 2028 related to the transportation of CO2 on our Free State pipeline.
Denbury Resources, Inc., or Denbury, has leased the NEJD System from us through 2028. Our NEJD System transports CO2 to tertiary oil recovery operations in southwest Mississippi.
Customers
Our customers on our Mississippi, Jay and Texas systems are primarily large, energy companies. Denbury has exclusive use of the NEJD Pipeline System and is responsible for all operations and maintenance on that system and will bear and assume all obligations and liabilities with respect to that system. Currently, Denbury also has rights to exclusive use of our Free State pipeline.
Due to the cost of finding, developing and producing oil properties in the deepwater regions of the Gulf of Mexico, most of our offshore pipeline customers are integrated oil companies and other large producers, and those producers desire to have longer-term arrangements ensuring that their production can access the markets.
Usually, our offshore pipeline customers enter into buy-sell or other transportation arrangements, pursuant to which the pipeline acquires possession (and, sometimes, title) from its customer of the relevant production at a specified location (often a producer’s platform or at another interconnection) and redelivers possession (and title, if applicable) to such customer of an equivalent volume at one or more specified downstream locations (such as a refinery or an interconnection with another pipeline). Most of the production handled by our offshore pipelines is pursuant to life-of-reserve commitments that include both firm and interruptible capacity arrangements.
Revenues from customers of our pipeline transportation segment did not account for more than ten percent of our consolidated revenues.
Competition
Competition among common carrier pipelines is based primarily on posted tariffs, quality of customer service and proximity to production, refineries and connecting pipelines. We believe that high capital costs, tariff regulation and the cost of acquiring rights-of-way make it unlikely that other competing pipeline systems, comparable in size and scope to our onshore pipelines, will be built in the same geographic areas in the near future.
The principal competition for our offshore pipelines includes other crude oil pipeline systems as well as producers who may elect to build or utilize their own production handling facilities. Our offshore pipelines compete for new production on the basis of geographic proximity to the production, cost of connection, available capacity, transportation rates and access to onshore markets. In addition, the ability of our offshore pipelines to access future reserves will be subject to our ability, or the producers’ ability, to fund the significant capital expenditures required to connect to the new production. In general, our offshore pipelines are not subject to regulatory rate-making authority, and the rates our offshore pipelines charge for services are dependent on the quality of the service required by the customer and the amount and term of the reserve commitment by that customer.

12


Table of Contents

Refinery Services
Our refinery services segment (i) provides sulfur-extraction services to ten refining operations primarily located in Texas, Louisiana, Arkansas, Oklahoma and Utah, (ii) operates significant storage and transportation assets in relation to our business and (iii) sells NaHS and caustic soda (or NaOH) to large industrial and commercial companies. Our refinery services activities involve processing high sulfur (or “sour”) gas streams that the refineries have generated from crude oil processing operations. Our process applies our proprietary technology, which uses large quantities of caustic soda (the primary raw material used in our process) to act as a scrubbing agent under prescribed temperature and pressure to remove sulfur. Sulfur removal in a refinery is a key factor in optimizing production of refined products such as gasoline, diesel and aviation fuel. Our sulfur removal technology returns a clean (sulfur-free) hydrocarbon stream to the refinery for further processing into refined products, and simultaneously produces NaHS. The resultant NaHS constitutes the sole consideration we receive for our refinery services activities. A majority of the NaHS we receive is sourced from refineries owned and operated by large companies, including Phillips 66, CITGO, HollyFrontier, and Ergon. Our ten refinery services contracts have an average remaining life of four years.
Our refinery services footprint includes terminals in the Gulf Coast, the Midwest, Montana, Utah, British Columbia and South America. In conjunction with our supply and logistics segment, we sell and deliver (via railcars, ships, barges and trucks) NaHS and caustic soda to over 150 customers. We believe we are one of the largest marketers of NaHS in North and South America. By minimizing our costs through utilization of our own logistical assets and leased storage sites, we believe we have a competitive advantage over other suppliers of NaHS. NaHS is used in the specialty chemicals business (plastic additives, dyes and personal care products), in pulp and paper business, and in connection with mining operations (nickel, gold and separating copper from molybdenum) as well as bauxite refining (aluminum). NaHS has also gained acceptance in environmental applications, including waste treatment programs requiring stabilization and reduction of heavy and toxic metals and flue gas scrubbing. Additionally, NaHS can be used for removing hair from hides at the beginning of the tannery process.
Caustic soda is used in many of the same industries as NaHS. Many applications require both chemicals for use in the same process – for example, caustic soda can increase the yields in bauxite refining, pulp manufacturing and in the recovery of copper, gold and nickel. Caustic soda is also used as a cleaning agent (when combined with water and heated) for process equipment and storage tanks at refineries.
Customers
We provide on-site services utilizing NaHS units at ten refining locations. Additionally, we have marketing arrangements at four third-party sites. Thus, even though some of our customers have elected to own the sulfur removal facilities located at their refineries, we operate those facilities. Those customer-owned NaHS facilities are located primarily in the southeastern United States.
We sell our NaHS to customers in a variety of industries, with the largest customers involved in mining of base metals, primarily copper and molybdenum and the production of pulp and paper. We sell to customers in the copper mining industry in the western United States, Canada and Mexico. We also export the NaHS to South America for sale to customers for mining in Peru and Chile. No customer of the refinery services segment is responsible for more than ten percent of our consolidated revenues. Many of the industries that our NaHS customers are in (such as copper mining and the pulp and paper industry) participate in global markets for their products. As a result, this creates an indirect exposure for NaHS to global demand for the end products of our customers. Provisions in our service contracts with refiners allow us to adjust our sour gas processing rates (sulfur removal) to maintain a balance between NaHS supply and demand.
We sell caustic soda to many of the same customers who purchase NaHS from us, including pulp and paper manufacturers and customers in the copper mining industry. We also supply caustic soda to some of the refineries in which we operate for use in cleaning processing equipment.
Competition
Our competitors for the supply of NaHS consist primarily of parties who produce NaHS as a by-product of processes involved with agricultural pesticide products, plastic additives and lubricant viscosity. Typically our competitors for the production of NaHS have only one manufacturing location and they do not have the logistical infrastructure that we have to supply customers. Our primary competitor has been AkzoNobel, a chemical manufacturing company that produces NaHS primarily in its pesticide operations.
Our competitors for sales of caustic soda include manufacturers of caustic soda. These competitors supply caustic soda to our refinery services operations and support us in our third-party NaOH sales. By utilizing our storage capabilities and having access to transportation assets, we sell caustic soda to third parties who gain efficiencies from acquiring both NaHS and NaOH from one source.

13


Table of Contents

Supply and Logistics
We provide supply and logistics services to Gulf Coast oil and gas producers and refineries through a combination of purchasing, transporting, storing, blending and marketing of crude oil and refined products (primarily fuel oil, asphalt, and other heavy refined products). In connection with these services, we utilize our portfolio of logistical assets consisting of trucks, terminals, pipelines, railcars and barges. Our crude oil related services include gathering crude oil from producers at the wellhead, transporting crude oil by gathering line, truck, railcar and barge to pipeline injection points and marketing crude oil to refiners. Not unlike our crude oil operations, we also gather refined products from refineries, transport refined products via truck, railcar and barge, and sell refined products to customers in wholesale markets. For these services, we generate fee-based income and profit from the difference between the price at which we re-sell the crude oil and petroleum products less the price at which we purchase the oil and products, minus the associated costs of aggregation and transportation.
Our crude oil supply and logistics operations are concentrated in Texas, Louisiana, Alabama, Florida, Mississippi and Wyoming. These operations help to ensure (among other things) a base supply source for our oil pipeline systems and our refinery customers while providing our producer customers with a market outlet for their production. We attempt to limit our commodity price risk in our supply and logistics segment by utilizing back-to-back purchases and sales, matching sale and purchase volumes on a monthly basis and hedging unsold volumes (primarily with NYMEX derivatives to offset the remaining price risk); however, we cannot completely eliminate commodity price risks. By utilizing our network of gathering lines, trucks, railcars, barges, terminals and pipelines, we are able to provide transportation related services to, and back-to-back gathering and marketing arrangements with, crude oil producers and refiners. Additionally, our crude oil gathering and marketing expertise and knowledge base provide us with an ability to capitalize on opportunities that arise from time to time in our market areas. We gather and transport approximately 70,000 barrels per day of crude oil, much of which is produced from large and growing resource basins throughout Texas and the Gulf Coast. Given our network of terminals, we also have the ability to store crude oil during periods of contango (oil prices for future deliveries are higher than for current deliveries) for delivery in future months. When we purchase and store crude oil during periods of contango, we attempt to limit commodity price risk by simultaneously entering into a contract to sell the inventory in a future period, either with a counterparty or in the crude oil futures market. The most substantial component of the costs we incur while aggregating crude oil and petroleum products relates to operating our fleet of owned and leased trucks.
Our refined products supply and logistics operations are concentrated in the Gulf Coast region, principally Texas and Louisiana, and in Wyoming. Through our footprint of owned and leased trucks, leased railcars, terminals and barges, we are able to provide Gulf Coast area refineries with transportation services as well as market outlets for their refined products. We primarily engage in the transportation and supply of fuel oil, asphalt, and other heavy refined products to our customers in wholesale markets. By utilizing our broad network of relationships and logistics assets, including our terminal accessibility, we have the ability from time to time to obtain various grades of refined products from our refinery customers and blend them to meet the requirements of our other market customers. However, because our refinery customers may choose to manufacture such refined products based on a number of economic and operating factors, we cannot predict the timing of contribution margins related to our blending services.
We own four active crude oil rail loading/unloading facilities located in Walnut Hill, Florida; Wink, Texas; Natchez, Mississippi and Douglas, Wyoming which provide synergies to our existing asset footprint. We generally earn a fee for loading or unloading railcars at these facilities. We are expanding our Walnut Hill, Florida, Wink, Texas and Natchez, Mississippi facilities to increase our railcar capacity in the first quarter of 2014.
    
As discussed in "Recent Development and Growth Initiatives" above, in early 2013, we began construction on a new crude oil unit train unload facility at Scenic Station, connected to Exxon Mobil Corporation's Baton Rouge refinery. This facility is expected to be operational late in the second quarter of 2014.
    
Also, as discussed in "Recent Developments and Growth Initiatives" above, in the fourth quarter of 2013, we began construction on a new crude oil unit train unloading facility in Raceland, Louisiana which is expected to be operational in the third quarter of 2014.
Our industrial gases supply and logistics operations supply CO2 to industrial customers under four long-term contracts. We obtain our CO2 supply pursuant to our volumetric production payments (also known as VPPs). Our existing customer contracts expire between 2015 and 2023. At December 31, 2013, we had approximately 29 Bcf of CO2 remaining under the VPPs. We do not expect to renew or replace our CO2 supply agreements.
Within our supply and logistics business segment, we employ many types of logistically flexible assets. These assets include 300 trucks, 400 trailers, 580 railcars, 63 barges (54 inland and 9 offshore) with approximately 2.4 million barrels of refined products transportation capacity, 32 push/tow boats (23 inland and 9 offshore), and terminals and other tankage with 2.4

14


Table of Contents

million barrels of leased and owned storage capacity in multiple locations along the Gulf Coast, accessible by pipeline, truck, rail or barge. Our leased railcars consist of approximately 90 refined product railcars and 490 crude oil railcars. Our inland marine fleet transports heavy refined petroleum products, including asphalt, principally serving refineries and storage terminals along the Gulf Coast, Intracoastal Canal and western river systems of the United States, including the Red, Ouachita and Mississippi Rivers. Our offshore marine fleet transports crude oil and refined petroleum products, principally serving refineries and storage terminals along the Gulf Coast, Eastern Seaboard, Great Lakes and Caribbean.
Customers
Our supply and logistics business encompasses hundreds of producers and customers, for which we provide transportation related services, as well as gather from and market to crude oil, refined products and CO2. During 2013, more than 10% of our consolidated revenues were generated from Shell, however, we do not believe that the loss of any one customer for crude oil, refined products or CO2 would have a material adverse effect on us as these products are readily marketable commodities.
Competition
In our crude oil supply and logistics operations, we compete with other midstream service providers and regional and local companies who may have significant market share in the respective areas in which they operate. In our refined products supply and logistics operations, we compete primarily with regional companies. Competitive factors in our supply and logistics business include price, relationships with customers, range and quality of services, knowledge of products and markets, availability of trade credit and capabilities of risk management systems.
Geographic Segments
All of our operations are in the United States. Additionally, we transport and sell NaHS to customers in South America and Canada. Revenues from customers in foreign countries totaled approximately $17 million, $19.3 million and $19.7 million in 2013, 2012 and 2011, respectively. The remainder of our revenues was generated from sales to customers in the United States.
Credit Exposure
Due to the nature of our operations, a disproportionate percentage of our trade receivables constitute obligations of oil companies, independent refiners, and mining and other industrial companies that purchase NaHS. This energy industry concentration has the potential to affect our overall exposure to credit risk, either positively or negatively, in that our customers could be affected by similar changes in economic, industry or other conditions. However, we believe that the credit risk posed by this industry concentration is offset by the creditworthiness of our customer base. Our portfolio of accounts receivable is comprised in large part of the obligations of integrated and independent energy companies with stable payment histories. The credit risk related to contracts that are traded on the NYMEX is limited due to the daily cash settlement procedures and other NYMEX requirements.
When we market crude oil and petroleum products and NaHS, we must determine the amount, if any, of the line of credit we will extend to any given customer. We have established procedures to manage our credit exposure, including initial credit approvals, credit limits, collateral requirements and rights of offset. Letters of credit, prepayments and guarantees are also utilized to limit credit risk to ensure that our established credit criteria are met. We use similar procedures to manage our exposure to our customers in the pipeline transportation segment.
Employees
To carry out our business activities, we employed approximately 1,200 employees at December 31, 2013. None of our employees are represented by labor unions, and we believe that relationships with our employees are good.
Regulation
Pipeline Rate and Access Regulation
The rates and the terms and conditions of service of our interstate common carrier pipeline operations are subject to regulation by FERC under the Interstate Commerce Act, or ICA. Under the ICA, rates must be “just and reasonable,” and must not be unduly discriminatory or confer any undue preference on any shipper. FERC regulations require that oil pipeline rates and terms and conditions of service for regulated pipelines be filed with FERC and posted publicly.
Effective January 1, 1995, FERC promulgated rules simplifying and streamlining the ratemaking process. Previously established rates were “grandfathered,” limiting the challenges that could be made to existing tariff rates. Increases from grandfathered rates of interstate oil pipelines are currently regulated by FERC primarily through an index methodology, whereby a pipeline is allowed to change its rates based on the year-to-year change in an index. Under FERC regulations, we are

15


Table of Contents

able to change our rates within prescribed ceiling levels that are tied to the Producer Price Index for Finished Goods. Rate increases made pursuant to the index will be subject to protest, but such protests must show that the portion of the rate increase resulting from application of the index is substantially in excess of the applicable pipeline’s increase in costs.
In addition to the index methodology, FERC allows for rate changes under three other methods—cost-of-service, competitive market showings and agreements between shippers and the oil pipeline company that the rate is acceptable, or Settlement Rates. The pipeline tariff rates on our Mississippi and Jay Systems are either rates that were grandfathered and have been changed under the index methodology or Settlement Rates. None of our tariffs have been subjected to a protest or complaint by any shipper or other interested party.
Our offshore pipelines are neither interstate nor common carrier pipelines. However, these pipelines are subject to federal regulation under the Outer Continental Shelf Lands Act, which requires all pipelines operating on or across the outer continental shelf to provide nondiscriminatory transportation service.
Our intrastate common carrier pipeline operations in Texas are subject to regulation by the Railroad Commission of Texas. The applicable Texas statutes require that pipeline rates and practices be reasonable and non-discriminatory and that pipeline rates provide a fair return on the aggregate value of the property of a common carrier, after providing reasonable allowance for depreciation and other factors and for reasonable operating expenses. Most of the volume on our Texas System is now shipped under joint tariffs with Enterprise Products and Exxon. Although no assurance can be given that the tariffs we charge would ultimately be upheld if challenged, we believe that the tariffs now in effect can be sustained.
Our CO2 pipelines are subject to regulation by the state agencies in the states in which they are located.
Marine Regulations
Maritime Law. The operation of tow boats, barges and marine equipment create maritime obligations involving property, personnel and cargo under General Maritime Law. These obligations can create risks which are varied and include, among other things, the risk of collision and allision, which may precipitate claims for personal injury, cargo, contract, pollution, third-party claims and property damages to vessels and facilities. Routine towage operations can also create risk of personal injury under the Jones Act and General Maritime Law, cargo claims involving the quality of a product and delivery, terminal claims, contractual claims and regulatory issues. Federal regulations also require that all tank barges engaged in the transportation of oil and petroleum in the U.S. be double hulled by 2015. All of our barges are double-hulled.
Jones Act. The Jones Act is a federal law that restricts maritime transportation between locations in the United States to vessels built and registered in the United States and owned and manned by United States citizens. We are responsible for monitoring the ownership of our subsidiary that engages in maritime transportation and for taking any remedial action necessary to insure that no violation of the Jones Act ownership restrictions occurs. Jones Act requirements significantly increase operating costs of United States-flag vessel operations compared to foreign-flag vessel operations. Further, the USCG and American Bureau of Shipping, or ABS, maintain the most stringent regime of vessel inspection in the world, which tends to result in higher regulatory compliance costs for United States-flag operators than for owners of vessels registered under foreign flags of convenience. The Jones Act and General Maritime Law also provide damage remedies for crew members injured in the service of the vessel arising from employer negligence or vessel unseaworthiness.
Merchant Marine Act of 1936. The Merchant Marine Act of 1936 is a federal law providing that, upon proclamation by the president of the United States of a national emergency or a threat to the national security, the United States Secretary of Transportation may requisition or purchase any vessel or other watercraft owned by United States citizens (including us, provided that we are considered a United States citizen for this purpose). If one of our tow boats or barges were purchased or requisitioned by the United States government under this law, we would be entitled to be paid the fair market value of the vessel in the case of a purchase or, in the case of a requisition, the fair market value of charter hire. However, if one of our tow boats is requisitioned or purchased and its associated barge or barges are left idle, we would not be entitled to receive any compensation for the lost revenues resulting from the idled barges. We also would not be entitled to be compensated for any consequential damages we suffer as a result of the requisition or purchase of any of our tow boats or barges.
Railcar Regulation
We operate a number of railcar loading and unloading facilities and lease a significant number of railcars. Our railcar operations are subject to the regulatory jurisdiction of the Federal Railroad Administration of the DOT, the Occupational Safety and Health Administration, as well as other federal and state regulatory agencies. We believe that our railcar operations are in substantial compliance with all existing federal, state and local regulations.

16


Table of Contents

Environmental Regulations
General
We are subject to stringent federal, state and local laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. These laws and regulations may (i) require the acquisition of and compliance with permits for regulated activities, (ii) limit or prohibit operations on environmentally sensitive lands such as wetlands or wilderness areas or areas inhabited by endangered or threatened species, (iii) result in capital expenditures to limit or prevent emissions or discharges, and (iv) place burdensome restrictions on our operations, including the management and disposal of wastes. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, including the assessment of monetary penalties, the imposition of investigatory and remedial obligations, the suspension or revocation of necessary permits, licenses and authorizations, the requirement that additional pollution controls be installed and the issuance of orders enjoining future operations or imposing additional compliance requirements. Changes in environmental laws and regulations occur frequently, typically increasing in stringency through time, and any changes that result in more stringent and costly operating restrictions, emission control, waste handling, disposal, cleanup and other environmental requirements have the potential to have a material adverse effect on our operations. While we believe that we are in substantial compliance with current environmental laws and regulations and that continued compliance with existing requirements would not materially affect us, there is no assurance that this trend will continue in the future. Revised or new additional regulations that result in increased compliance costs or additional operating restrictions, particularly if those costs are not fully recoverable from our customers, could have a material adverse effect on our business, financial position, results of operations and cash flows.
Hazardous Substances and Waste Handling
The Comprehensive Environmental Response, Compensation, and Liability Act, as amended, or CERCLA, also known as the “Superfund” law, and analogous state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons. These persons include current owners and operators of the site where a release of hazardous substances occurred, prior owners or operators that owned or operated the site at the time of the release of hazardous substances, and companies that disposed or arranged for the disposal of the hazardous substances found at the site. We currently own or lease, and have in the past owned or leased, properties that have been in use for many years with the gathering and transportation of hydrocarbons including crude oil and other activities that could cause an environmental impact. Persons deemed “responsible persons” under CERCLA may be subject to strict and joint and several liability for the costs of removing or remediating previously disposed wastes (including wastes disposed of or released by prior owners or operators) or property contamination (including groundwater contamination), for damages to natural resources, and for the costs of certain health studies. CERCLA also authorizes the EPA and, in some instances, third parties to act in response to threats to the public health or the environment and to seek to recover the costs they incur from the responsible classes of persons. It is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances or other pollutants released into the environment.
We also may incur liability under the Resource Conservation and Recovery Act, as amended, or RCRA, and analogous state laws which impose requirements and also liability relating to the management and disposal of solid and hazardous wastes. While RCRA regulates both solid and hazardous wastes, it imposes strict requirements on the generation, storage, treatment, transportation and disposal of hazardous wastes. Certain petroleum production wastes are excluded from RCRA’s hazardous waste regulations. However, it is possible that these wastes, which could include wastes currently generated during our operations, will in the future be designated as “hazardous wastes” and, therefore, be subject to more rigorous and costly disposal requirements. Indeed, legislation has been proposed from time to time in Congress to re-categorize certain oil and gas exploration and production wastes as “hazardous wastes.” Any such changes in the laws and regulations could have a material adverse effect on our capital expenditures and operating expenses.
We believe that we are in substantial compliance with the requirements of CERCLA, RCRA and related state and local laws and regulations, and that we hold all necessary and up-to-date permits, registrations and other authorizations required under such laws and regulations. Although we believe that the current costs of managing our wastes as they are presently classified are reflected in our budget, any legislative or regulatory reclassification of oil and natural gas exploration and production wastes could increase our costs to manage and dispose of such wastes.
Water
The Federal Water Pollution Control Act, as amended, also known as the “Clean Water Act,” and analogous state laws impose restrictions and strict controls regarding the unauthorized discharge of pollutants, including oil, into navigable waters of the United States, as well as state waters. Permits must be obtained to discharge pollutants into these waters. In addition, the Clean Water Act and analogous state laws require individual permits or coverage under general permits for discharges of storm

17


Table of Contents

water runoff from certain types of facilities. These permits may require us to monitor and sample the storm water runoff from certain of our facilities. Some states also maintain groundwater protection programs that require permits for discharges or operations that may impact groundwater conditions. The Oil Pollution Act, or the OPA, is the primary federal law for oil spill liability. The OPA contains numerous requirements relating to the prevention of and response to oil spills into waters of the United States, including the requirement that operators of offshore facilities and certain onshore facilities near or crossing waterways must maintain certain significant levels of financial assurance to cover potential environmental cleanup and restoration costs. Under the OPA, strict, joint and several liability may be imposed on “responsible parties” for all containment and cleanup costs and certain other damages arising from a release, including, but not limited to, the costs of responding to a release of oil to surface waters and natural resource damages, resulting from oil spills into or upon navigable waters, adjoining shorelines or in the exclusive economic zone of the United States. A “responsible party” includes the owner or operator of an onshore facility.
Noncompliance with the Clean Water Act or the OPA may result in substantial civil and criminal penalties. We believe we are in material compliance with each of these requirements.
Air Emissions
The Federal Clean Air Act, or CAA, as amended, and analogous state and local laws and regulations restrict the emission of air pollutants, and impose permit requirements and other obligations. Regulated emissions occur as a result of our operations, including the handling or storage of crude oil and other petroleum products. Both federal and state laws impose substantial penalties for violation of these applicable requirements. Accordingly, our failure to comply with these requirements could subject us to monetary penalties, injunctions, conditions or restrictions on operations, revocation or suspension of necessary permits and, potentially, criminal enforcement actions.
NEPA
Under the National Environmental Policy Act, or NEPA, a federal agency, commonly in conjunction with a current permittee or applicant, may be required to prepare an environmental assessment or a detailed environmental impact statement before taking any major action, including issuing a permit for a pipeline extension or addition that would affect the quality of the environment. Should an environmental impact statement or environmental assessment be required for any proposed pipeline extensions or additions, NEPA may prevent or delay construction or alter the proposed location, design or method of construction.
Climate Change
In December 2009, the EPA published its findings that emissions of carbon dioxide, methane and other greenhouse gases ("GHGs") present an endangerment to human health and the environment because emissions of such gases are, according to the EPA, contributing to the warming of the earth’s atmosphere and other climatic changes. These findings served as a statutory prerequisite for EPA to adopt and implement regulations that would restrict emissions of GHGs under existing provisions of the CAA. The EPA also adopted two sets of related rules, one of which purports to regulate emissions of GHGs from motor vehicles and the other of which regulates emissions of GHGs from certain large stationary sources of emissions such as power plants or industrial facilities. The EPA finalized the motor vehicle rule in April 2010 and it became effective January 2011. The EPA adopted the stationary source rule, also known as the "Tailoring Rule," in May 2010, and it also became effective January 2011. Additionally, in September 2009, the EPA issued a final rule requiring the reporting of GHG emissions from specified large GHG emission sources in the U.S., beginning in 2011 for emissions occurring in 2010. More recently, in November 2010, the EPA expanded its existing GHG reporting rule to include onshore and offshore oil and natural gas production and onshore processing, transmission, storage and distribution facilities, which may include certain or our facilities, beginning in 2012 for emissions occurring in 2011. As a result of this continued regulatory focus, future GHG regulations of the oil and natural gas industry remain a possibility.
    
Further, the U.S. Congress has considered various proposals to reduce GHG emissions that may impose a carbon emissions tax, a cap-and-trade program or other programs aimed at carbon reduction, and almost half of the states, either individually or through multi-state regional initiatives, have already taken legal measures to reduce GHG emissions, primarily through the planned development of GHG emission inventories and/or GHG cap-and-trade programs. The net effect of this legislation is to impose increasing costs on the combustion of carbon-based fuels such as oil, refined petroleum products and natural gas. Our compliance with any future legislation or regulation of GHGs, if it occurs, may result in materially increased compliance and operating costs. It is not possible at this time to predict with any accuracy the structure or outcome of any future legislative or regulatory efforts to address such emissions or the eventual costs to us of compliance.

18


Table of Contents

Safety and Security Regulations
Our crude oil and CO2 pipelines are subject to construction, installation, operation and safety regulation by the U.S. Department of Transportation, or DOT, and various other federal, state and local agencies. Congress has enacted several pipeline safety acts over the years. Currently, the Pipeline and Hazardous Materials Safety Administration under DOT administers pipeline safety requirements for natural gas and hazardous liquid pipelines pursuant to detailed regulations set forth in 49 C.F.R. Parts 190 to 195. These regulations, among other things, address pipeline integrity management and pipeline operator qualification rules. Significant expenses could be incurred in the future if additional safety measures are required or if safety standards are raised and exceed the current pipeline control system capabilities.
We are subject to the DOT Integrity Management, or IM, regulations, which require that we perform baseline assessments of all pipelines that could affect a High Consequence Area, or HCA, including certain populated areas and environmentally sensitive areas. Due to the proximity of all of our pipelines to water crossings and populated areas, we have designated all of our pipelines as affecting HCAs. The integrity of these pipelines must be assessed by internal inspection, pressure test, or equivalent alternative new technology.
The IM regulations required us to prepare an Integrity Management Plan, or IMP, that details the risk assessment factors, the overall risk rating for each segment of pipe, a schedule for completing the integrity assessment, the methods to assess pipeline integrity, and an explanation of the assessment methods selected. The regulations also require periodic review of HCA pipeline segments to ensure that adequate preventative and mitigative measures exist and that companies take prompt action to address pipeline integrity issues. No assurance can be given that the cost of testing and the required rehabilitation identified will not be material costs to us that may not be fully recoverable by tariff increases.
We have developed a Risk Management Plan required by the EPA as part of our IMP. This plan is intended to minimize the offsite consequences of catastrophic spills. As part of this program, we have developed a mapping program. This mapping program identified HCAs and unusually sensitive areas along the pipeline right-of-ways in addition to mapping of shorelines to characterize the potential impact of a spill of crude oil on waterways.
Our crude oil, refined products and refinery services operations are also subject to the requirements of OSHA and comparable state statutes. Various other federal and state regulations require that we train all operations employees in HAZCOM and disclose information about the hazardous materials used in our operations. Certain information must be reported to employees, government agencies and local citizens upon request.

States are responsible for enforcing the federal regulations and more stringent state pipeline regulations and inspection with respect to hazardous liquids pipelines, including crude oil, natural gas and CO2 pipelines. In practice, states vary considerably in their authority and capacity to address pipeline safety. We do not anticipate any significant problems in complying with applicable state laws and regulations in those states in which we operate.

Our trucking operations are licensed to perform both intrastate and interstate motor carrier services. As a motor carrier, we are subject to certain safety regulations issued by the DOT. The trucking regulations cover, among other things, driver operations, log book maintenance, truck manifest preparations, safety placard placement on the trucks and trailer vehicles, drug and alcohol testing, operation and equipment safety and many other aspects of truck operations. We are also subject to OSHA with respect to our trucking operations.
The USCG regulates occupational health standards related to our marine operations. Shore-side operations are subject to the regulations of OSHA and comparable state statutes. The Maritime Transportation Security Act requires, among other things, submission to and approval of the USCG of vessel security plans.
Since the terrorist attacks of September 11, 2001, the United States Government has issued numerous warnings that energy assets could be the subject of future terrorist attacks. We have instituted security measures and procedures in conformity with federal guidance. We will institute, as appropriate, additional security measures or procedures indicated by the federal government. None of these measures or procedures should be construed as a guarantee that our assets are protected in the event of a terrorist attack.
Available Information
The public may read and copy any materials that we file with the SEC at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, DC 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. We make available free of charge on our internet website (www.genesisenergy.com) our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 as soon as reasonably

19


Table of Contents

practicable after we electronically file the material with, or furnish it to, the SEC. These documents are also available at the SEC’s website (www.sec.gov). Additionally, on our internet website we make available our Corporate Governance Guidelines, Code of Business Conduct and Ethics, Audit Committee Charter and Governance, Compensation and Business Development Committee Charter. Information on our website is not incorporated into this Form 10-K or our other securities filings and is not a part of this Form 10-K or our other securities filings.
Item 1A. Risk Factors
Risks Related to Our Business
We may not be able to fully execute our growth strategy if we are unable to raise debt and equity capital at an affordable price.
Our strategy contemplates substantial growth through the development and acquisition of a wide range of midstream and other energy infrastructure assets while maintaining a strong balance sheet. This strategy includes constructing and acquiring additional assets and businesses to enhance our ability to compete effectively, diversify our asset portfolio and, thereby, provide more stable cash flow. We regularly consider and enter into discussions regarding, and are currently contemplating, additional potential joint ventures, stand-alone projects and other transactions that we believe will present opportunities to realize synergies, expand our role in the energy infrastructure business, and increase our market position and, ultimately, increase distributions to unitholders.
We will need new capital to finance the future development and acquisition of assets and businesses. Limitations on our access to capital will impair our ability to execute this strategy. Expensive capital will limit our ability to develop or acquire accretive assets. Although we intend to continue to expand our business, this strategy may require substantial capital, and we may not be able to raise the necessary funds on satisfactory terms, if at all.
The capital and credit markets have previously been, and may in the future be, disrupted and volatile as a result of adverse conditions. The government response to the disruptions in the financial markets may not adequately restore investor or customer confidence, stabilize such markets, or increase liquidity and the availability of credit to businesses. If the credit markets experience volatility and the availability of funds are limited, we may experience difficulties in accessing capital for significant growth projects or acquisitions which could adversely affect our strategic plans.
In addition, we experience competition for the assets we purchase or contemplate purchasing. Increased competition for a limited pool of assets could result in our not being the successful bidder more often or our acquiring assets at a higher relative price than that which we have paid historically. Either occurrence would limit our ability to fully execute our growth strategy. Our ability to execute our growth strategy may impact the market price of our securities.
Fluctuations in interest rates could adversely affect our business.
We have exposure to movements in interest rates. The interest rates on our credit facility ($582.8 million outstanding at December 31, 2013) are variable. Our results of operations and our cash flow, as well as our access to future capital and our ability to fund our growth strategy, could be adversely affected by significant increases in interest rates.
An increase in interest rates may also cause a corresponding decline in demand for equity investments, in general, and in particular, for yield-based equity investments such as our common units. Any such reduction in demand for our common units resulting from other more attractive investment opportunities may cause the trading price of our common units to decline.
We may not have sufficient cash from operations to pay the current level of quarterly distribution following the establishment of cash reserves and payment of fees and expenses.
The amount of cash we distribute on our units principally depends upon margins we generate from our businesses, which fluctuate from quarter to quarter based on, among other things:
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;

20


Table of Contents

the level of our general and administrative costs; and
prevailing economic conditions.
In addition, the actual amount of cash we will have available for distribution will depend on other factors that include:
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.
Our ability to pay distributions each quarter depends primarily on our cash flow, including cash flow from financial reserves and working capital borrowings, and our cash requirements, so it is not solely a function of profitability, which will be affected by non-cash items. As a result, we may make cash distributions during periods when we record losses and we may not make distributions during periods when we record net income.
Our indebtedness could adversely restrict our ability to operate, affect our financial condition, and prevent us from complying with our requirements under our debt instruments and could prevent us from paying cash distributions to our unitholders.
We have outstanding debt and the ability to incur more debt. As of December 31, 2013, we had approximately $582.8 million outstanding of senior secured indebtedness and an additional $700.8 million of senior unsecured indebtedness.
We must comply with various affirmative and negative covenants contained in our credit facilities. Among other things, these covenants limit our ability to:
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.
The restrictions under our indebtedness may prevent us from engaging in certain transactions which might otherwise be considered beneficial to us and could have other important consequences to unitholders. For example, they could:
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.
We may incur additional indebtedness (public or private) in the future under our existing credit facilities, by issuing debt instruments, under new credit agreements, under joint venture credit agreements, under capital leases or synthetic leases, on a project-finance or other basis or a combination of any of these. If we incur additional indebtedness in the future, it likely would be under our existing credit facility or under arrangements that may have terms and conditions at least as restrictive as those contained in our existing credit facility. Failure to comply with the terms and conditions of any existing or future indebtedness would constitute an event of default. If an event of default occurs, the lenders will have the right to accelerate the

21


Table of Contents

maturity of such indebtedness and foreclose upon the collateral, if any, securing that indebtedness. In addition, if there is a change of control as described in our credit facility, that would be an event of default, unless our creditors agreed otherwise, and, under our credit facility, any such event could limit our ability to fulfill our obligations under our debt instruments and to make cash distributions to unitholders which could adversely affect the market price of our securities.
In addition, from time to time, some of our joint ventures may have substantial indebtedness, which will include affirmative and negative covenants and other provisions that limit their freedom to conduct certain operations, events of default, prepayment and other customary terms.
Our profitability and cash flow are dependent on our ability to increase or, at a minimum, maintain our current commodity—oil, refined products, NaHS and caustic soda—volumes, which often depend on actions and commitments by parties beyond our control.
Our profitability and cash flow are dependent on our ability to increase or, at a minimum, maintain our current commodity — oil, refined products, NaHS and caustic soda — volumes. We access commodity volumes through two sources, producers and service providers (including gatherers, shippers, marketers and other aggregators). Depending on the needs of each customer and the market in which it operates, we can either provide a service for a fee (as in the case of our pipeline transportation operations) or we can purchase the commodity from our customer and resell it to another party.
Our source of volumes depends on successful exploration and development of additional oil reserves by others; continued demand for our refinery services, for which we are paid in NaHS; the breadth and depth of our logistics operations; the extent that third parties provide NaHS for resale; and other matters beyond our control.
The oil and refined products available to us are derived from reserves produced from existing wells, and these reserves naturally decline over time. In order to offset this natural decline, our energy infrastructure assets must access additional reserves. Additionally, some of the projects we have planned or recently completed are dependent on reserves that we expect to be produced from newly discovered properties that producers are currently developing.
Finding and developing new reserves is very expensive, requiring large capital expenditures by producers for exploration and development drilling, installing production facilities and constructing pipeline extensions to reach new wells. Many economic and business factors out of our control can adversely affect the decision by any producer to explore for and develop new reserves. These factors include the prevailing market price of the commodity, the capital budgets of producers, the depletion rate of existing reservoirs, the success of new wells drilled, environmental concerns, regulatory initiatives, cost and availability of equipment, capital budget limitations or the lack of available capital and other matters beyond our control. Additional reserves, if discovered, may not be developed in the near future or at all. Thus, oil production in our market area may not rise to sufficient levels to allow us to maintain or increase the commodity volumes we have historically realized.
Our ability to access NaHS depends primarily on the demand for our proprietary refinery services process. Demand for our services could be adversely affected by many factors, including lower refinery utilization rates, U.S. refineries accessing more “sweet” (instead of sour) crude, and the development of alternative sulfur removal processes that might be more economically beneficial to refiners.
We are dependent on third parties for NaOH for use in our refinery services process as well as volume to market to third parties. Should regulatory requirements or operational difficulties disrupt the manufacture of caustic soda by these producers, we could be affected.
Our refinery services operations are dependent upon the supply of caustic soda and the demand for NaHS, as well as the operations of the refiners for whom we process sour gas.
Caustic soda is a major component of the proprietary sour gas removal process we provide to our refinery customers. Because we are a large consumer of caustic soda, we can leverage our economies of scale and logistics capabilities to effectively market caustic soda to third parties. NaHS, the resulting by-product from our refinery services operations, is a vital ingredient in a number of industrial and consumer products and processes. Any decrease in the supply of caustic soda could affect our ability to provide sour gas treatment services to refiners and any decrease in the demand for NaHS by the parties to whom we sell the NaHS could adversely affect our business. The refineries’ need for our sour gas services is also dependent on the competition from other refineries, the impact of future economic conditions, fuel conservation measures, alternative fuel requirements, government regulation or technological advances in fuel economy and energy generation devices, all of which could reduce demand for our services.

22


Table of Contents

Our crude oil transportation operations are dependent upon demand for crude oil by refiners, primarily in the Midwest and Gulf Coast.
Any decrease in this demand for crude oil by those refineries or connecting carriers to which we deliver could adversely affect our cash flows. Those refineries’ demand for crude oil also is dependent on the competition from other refineries, the impact of future economic conditions, fuel conservation measures, alternative fuel requirements, government regulation or technological advances in fuel economy and energy generation devices, all of which could reduce demand for our services.
We face intense competition to obtain oil and refined products volumes.
Our competitors — gatherers, transporters, marketers, brokers and other aggregators — include independents and major integrated energy companies, as well as their marketing affiliates, who vary widely in size, financial resources and experience. Some of these competitors have capital resources many times greater than ours and control substantially greater supplies of crude oil and other refined products.
Even if reserves exist or refined products are produced in the areas accessed by our facilities, we may not be chosen by the producers or refiners to gather, refine, market, transport, store or otherwise handle any of these crude oil reserves, NaHS, caustic soda or other refined products. We compete with others for any such volumes on the basis of many factors, including:
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.
Additionally, on our onshore pipelines most of our third-party shippers do not have long-term contractual commitments to ship crude oil on our pipelines. A decision by a shipper to substantially reduce or cease to ship volumes of crude oil on our pipelines could cause a significant decline in our revenues. In Mississippi, we are dependent on interconnections with other pipelines to provide shippers with a market for their crude oil, and in Texas, we are dependent on interconnections with other pipelines to provide shippers with transportation to our pipeline. Any reduction of throughput available to our shippers on these interconnecting pipelines as a result of testing, pipeline repair, reduced operating pressures or other causes could result in reduced throughput on our pipelines that would adversely affect our cash flows and results of operations.
Fluctuations in demand for crude oil or availability of refined products or NaHS, such as those caused by refinery downtime or shutdowns, can negatively affect our operating results. Reduced demand in areas we service with our pipelines and trucks can result in less demand for our transportation services.
Non-utilization of certain assets, such as our leased railcars, could significantly reduce our profitability due to the fixed costs incurred with respect to such assets.
From time to time in connection with our business, we may lease or otherwise secure the right to use certain third party assets (such as railcars, trucks, barges, pipeline capacity, storage capacity and other similar assets) with the expectation that the revenues we generate through the use of such assets will be greater than the fixed costs we incur pursuant to the applicable leases or other arrangements. However, when such assets are not utilized or are under-utilized, our profitability is negatively affected because the revenues we earn are either non-existent or reduced (in the event of under-utilization), but we remain obligated to continue paying any applicable fixed charges, in addition to incurring any other costs attributable to the non-utilization of such assets. For example, in connection with our rail operations, we lease all of our railcars that obligate us to pay the applicable lease rate without regard to utilization. If business conditions are such that we do not utilize a portion of our rail fleet for any period of time, we will still be obligated to pay the applicable fixed lease rate for such railcars. In addition, during the period of time that we are not utilizing such railcars, we will incur incremental costs associated with the cost of storing such railcars, and we will continue to incur costs for maintenance and upkeep. Our failure to utilize a significant portion of our leased railcars and other similar assets could have a significant negative impact on our profitability and cash flows.

23


Table of Contents

In addition, certain of our field and pipeline operating costs and expenses are fixed and do not vary with the volumes we gather and transport. These costs and expenses may not decrease ratably or at all should we experience a reduction in our volumes transported by truck or rail or transported by our pipelines. As a result, we may experience declines in our margin and profitability if our volumes decrease.
Fluctuations in commodity prices could adversely affect our business.
Oil, natural gas, other petroleum products, NaHS and caustic soda prices are volatile and could have an adverse effect on our profits and cash flow. Prices for commodities can fluctuate in response to changes in supply, market uncertainty and a variety of additional factors that are beyond our control. Price reductions in those commodities can cause material long and short term reductions in the level of production, throughput, volumes and, in some cases, margins. We attempt to limit commodity price risk exposure through back-to-back sales and hedges; however, we cannot completely eliminate commodity price risk exposure.
We are exposed to the credit risk of our customers in the ordinary course of our business activities.
When we (or our joint ventures) market our products or services, we (or our joint ventures) must determine the amount, if any, of the line of credit. Since certain transactions can involve very large payments, the risk of nonpayment and nonperformance by customers, industry participants and others is an important consideration in our business.
For example, in those cases where we provide division order services for crude oil purchased at the wellhead, we may be responsible for distribution of proceeds to all of the interest owners. In other cases, we pay all of or a portion of the production proceeds to an operator who distributes these proceeds to the various interest owners. These arrangements expose us to operator credit risk. As a result, we must determine that operators have sufficient financial resources to make such payments and distributions and to indemnify and defend us in case of a protest, action or complaint.
Additionally, we sell NaHS and caustic soda to customers in a variety of industries. Many of these customers are in industries that have been impacted by a decline in demand for their products and services. Even if our credit review and analytical procedures work properly, we have experienced, and we could continue to experience losses in dealings with other parties.
Additionally, many of our customers were impacted by the weakened economic conditions experienced in recent years in a manner that influenced the need for our products and services and their ability to pay us for those products and services.
Our refinery services division is dependent on contracts with less than fifteen refineries and much of its revenue is attributable to a few refineries.
If one or more of our refinery customers that, individually or in the aggregate, generate a material portion of our refinery services revenue experience financial difficulties or changes in their strategy for sulfur removal such that they do not need our services, our cash flows could be adversely affected. For example, in 2013, approximately 70% of our refinery services’ division NaHS by-product volumes was attributable to Phillips 66’s refinery located in Westlake, Louisiana. That contract requires Phillips 66 to make available minimum volumes of sour gas to us (except during periods of force majeure). Although the primary term of that contract extends until 2018, if, for any reason, Phillips 66 does not meet its obligations under that contract for an extended period of time, such non-performance could have a material adverse effect on our profitability and cash flow.
Our operations are subject to federal and state environmental protection and safety laws and regulations.
Our operations are subject to the risk of incurring substantial environmental and safety related costs and liabilities. In particular, our operations are subject to increasingly stringent environmental protection and safety laws and regulations that restrict our operations, impose consequences of varying degrees for noncompliance, and require us to expend resources in an effort to maintain compliance. Moreover, our operations, including the transportation and storage of crude oil and other commodities, involves a risk that crude oil and related hydrocarbons or other substances may be released into the environment, which may result in substantial expenditures for a response action, significant government penalties, liability to government agencies for natural resources damages, liability to private parties for personal injury or property damages, and significant business interruption. These costs and liabilities could rise under increasingly strict environmental and safety laws, including regulations and enforcement policies, or claims for damages to property or persons resulting from our operations. If we are unable to recover such resulting costs through increased rates or insurance reimbursements, our cash flows and distributions to our unitholders could be materially affected.

24


Table of Contents

Climate change legislation and regulatory initiatives may decrease demand for the products we store, transport and sell and increase our operating costs.
In December 2009, the EPA published its findings that emissions of carbon dioxide, methane and other GHGs present an endangerment to human health and the environment because emissions of such gases are, according to the EPA, contributing to the warming of the earth's atmosphere and other climatic changes. These findings served as a statutory prerequisite for EPA to adopt and implement regulations that would restrict emissions of GHGs under existing provisions of the CAA. The EPA has adopted two sets of related rules, one which purports to regulate emissions of GHGs from motor vehicles and the other of which regulates emissions of GHGs from certain large stationary sources of emissions such as power plants or industrial facilities. The EPA finalized the motor vehicle rule in April 2010 and it became effective January 2011. The EPA adopted the stationary source rule, also known as the "Tailoring Rule," in May 2010, and it also became effective in January 2011. Additionally, in September 2009, the EPA issued a final rule requiring the reporting of GHG emissions from specified large GHG emission sources in the U.S. beginning in 2011 for emissions occurring in 2010. More recently, in November 2010, the EPA expanded its existing GHG reporting rule to include onshore and offshore oil and natural gas production and onshore processing, transmission, storage and distribution facilities, which may include certain of our facilities, beginning in 2012 for emissions occurring in 2011. As a result of this continued regulatory focus, future GHG regulations of the oil and natural gas industry remain a possibility.
Further, the U.S. Congress has considered various proposals to reduce GHG emissions that may impose a carbon emissions tax, a cap-and-trade program or other programs aimed at carbon reduction, and almost half of the states, either individually or through multi-state regional initiatives, have already taken legal measures to reduce emissions of GHGs, primarily through the planned development of GHG emission inventories and/or GHG gas cap-and-trade programs. The net effect of this legislation is to impose increasing costs on the combustion of carbon-based fuels such as oil, refined petroleum products and natural gas. Our compliance with any future legislation or regulation of GHGs, if it occurs, may result in materially increased compliance and operating costs. It is not possible at this time to predict with any accuracy the structure or outcome of any future legislative or regulatory efforts to address such emissions or the eventual costs to us of compliance.
The effect on our operations of CAA regulations, legislative efforts or related implementation regulations that regulate or restrict emissions of GHGs in areas that we conduct business could adversely affect the demand for the products that we transport, store and distribute and, depending on the particular program adopted, could increase our costs to operate and maintain our facilities by requiring that we, among other things, measure and report our emissions, install new emission controls on our facilities, acquire allowances to authorize our GHG emissions, pay any taxes related to our GHG emissions and administer and manage a GHG emissions program. We may be unable to include some or all of such increased costs in the rates charged by our pipelines or other facilities, and any such recovery may depend on events beyond our control, including the outcome of future rate proceedings before the FERC or state regulatory agencies and the provisions of any final legislation or implementing regulations.
Regulation of the rates, terms and conditions of services and a changing regulatory environment could affect our financial position, results of operations or cash flow.
FERC regulates certain of our energy infrastructure assets engaged in interstate operations. Our intrastate pipeline operations are regulated by state agencies. Our railcar operations are subject to the regulatory jurisdiction of the Federal Railroad Administration of the DOT, the Occupational Safety and Health Administration, as well as other federal and state regulatory agencies. This regulation extends to such matters as:
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.
In addition, some of our pipelines and other infrastructure are subject to laws providing for open and/or non-discriminatory access.
Given the extent of this regulation, the evolving nature of federal and state regulation and the possibility for additional changes, the current regulatory regime may change and affect our financial position, results of operations or cash flow.

25


Table of Contents

Our growth strategy may adversely affect our results of operations if we do not successfully integrate the businesses that we acquire or if we substantially increase our indebtedness and contingent liabilities to make acquisitions.
We may be unable to integrate successfully businesses we acquire. We may incur substantial expenses, delays or other problems in connection with our growth strategy that could negatively impact our results of operations. Moreover, acquisitions and business expansions involve numerous risks, including:
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.
If consummated, any acquisition or investment also likely would result in the incurrence of indebtedness and contingent liabilities and an increase in interest expense and depreciation and amortization expenses. A substantial increase in our indebtedness and contingent liabilities could have a material adverse effect on our business, as discussed above.
Our actual construction, development and acquisition costs could exceed our forecast, and our cash flow from construction and development projects may not be immediate.
Our forecast contemplates significant expenditures for the development, construction or other acquisition of energy infrastructure assets, including some construction and development projects with technological challenges. We (or our joint ventures) may not be able to complete our projects at the costs currently estimated. If we (or our joint ventures) experience material cost overruns, we will have to finance these overruns using one or more of the following methods:
using cash from operations;
delaying other planned projects;
incurring additional indebtedness; or
issuing additional debt or equity.
Any or all of these methods may not be available when needed or may adversely affect our future results of operations.
In addition, some construction projects require substantial investments over a long period of time before they begin generating any meaningful cash flow.
Our use of derivative financial instruments could result in financial losses.
We use derivative financial instruments and other hedging mechanisms from time to time to limit a portion of the effects resulting from changes in commodity prices. To the extent we hedge our commodity price exposure, we forego the benefits we would otherwise experience if commodity prices were to increase. In addition, we could experience losses resulting from our hedging and other derivative positions. Such losses could occur under various circumstances, including if our counterparty does not perform its obligations under the hedge arrangement, our hedge is imperfect, or our hedging policies and procedures are not followed.
A natural disaster, accident, terrorist attack or other interruption event involving us could result in severe personal injury, property damage and/or environmental damage, which could curtail our operations and otherwise adversely affect our assets and cash flow.
Some of our operations involve significant risks of severe personal injury, property damage and environmental damage, any of which could curtail our operations and otherwise expose us to liability and adversely affect our cash flow. Virtually all of our operations are exposed to the elements, including hurricanes, tornadoes, storms, floods and earthquakes. A significant portion of our operations are located along the U.S. Gulf Coast, and our offshore pipelines are located in the Gulf of Mexico. These areas can be subject to hurricanes.
If one or more facilities that are owned by us or that connect to us is damaged or otherwise affected by severe weather or any other disaster, accident, catastrophe or event, our operations could be significantly interrupted. Similar interruptions could result from damage to production or other facilities that supply our facilities or other stoppages arising from factors beyond our control. These interruptions might involve significant damage to people, property or the environment, and repairs might take from a week or less for a minor incident to six months or more for a major interruption. Any event that interrupts the

26


Table of Contents

fees generated by our energy infrastructure assets, or which causes us to make significant expenditures not covered by insurance, could reduce our cash available for paying our interest obligations as well as unitholder distributions and, accordingly, adversely impact the market price of our securities. Additionally, the proceeds of any property insurance maintained by us may not be paid in a timely manner or be in an amount sufficient to meet our needs if such an event were to occur, and we may not be able to renew it or obtain other desirable insurance on commercially reasonable terms, if at all.
On September 11, 2001, the United States was the target of terrorist attacks of unprecedented scale. Since the September 11 attacks, the U.S. government has issued warnings that energy assets, specifically the nation’s pipeline infrastructure, may be the future targets of terrorist organizations. These developments have subjected our operations to increased risks. Any future terrorist attack at our facilities, those of our customers and, in some cases, those of other pipelines, could have a material adverse effect on our business.
Our business could be negatively impacted by security threats, including cybersecurity threats, and related disruptions.
We rely on our information technology infrastructure to process, transmit and store electronic information, including information we use to safely operate our assets. While we believe that we maintain appropriate information security policies and protocols, we face cybersecurity and other security threats to our information technology infrastructure, which could include threats to our operational and safety systems that operate our pipelines, facilities and other assets. We could face unlawful attempts to gain access to our information technology infrastructure, including coordinated attacks from hackers, whether state-sponsored groups, “hacktivists,” or private individuals. The age, operating systems or condition of our current information technology infrastructure and software assets and our ability to maintain and upgrade such assets could affect our ability to resist cybersecurity threats.
Our information technology infrastructure is critical to the efficient operation of our business and essential to our ability to perform day-to-day operations. Breaches in our information technology infrastructure or physical facilities, or other disruptions, could result in damage to our assets, loss of intellectual property, impairment of our ability to conduct our operations, disruption of our customers’ operations, loss or damage to our customer data delivery systems, safety incidents, damage to the environment and could have a material adverse effect on our operations, financial position and results of operations. It is also possible that breaches to our systems could go unnoticed for some period of time.
We cannot cause our joint ventures to take or not to take certain actions unless some or all of the joint venture participants agree.
Due to the nature of joint ventures, each participant (including us) in our material joint ventures has made substantial investments (including contributions and other commitments) in that joint venture and, accordingly, has required that the relevant charter documents contain certain features designed to provide each participant with the opportunity to participate in the management of the joint venture and to protect its investment in that joint venture, as well as any other assets which may be substantially dependent on or otherwise affected by the activities of that joint venture. These participation and protective features include a corporate governance structure that consists of a management committee composed of members, only some of which are appointed by us. In addition, many of our joint ventures are operated by our “partners” and have “stand-alone” credit agreements that limit their freedom to take certain actions. Thus, without the concurrence of the other joint venture participants and/or the lenders of our joint venture participants, we cannot cause our joint ventures to take or not to take certain actions, even though those actions may be in the best interest of the joint ventures or us.
Our business would be adversely affected if we failed to comply with the Jones Act foreign ownership provisions.
We are subject to the Jones Act and other federal laws that restrict maritime cargo transportation between points in the United States only to vessels operating under the U.S. flag, built in the United States, at least 75% owned and operated by U.S. citizens (or owned and operated by other entities meeting U.S. citizenship requirements to own vessels operating in the U.S. coastwise trade and, in the case of limited partnerships, where the general partner meets U.S. citizenship requirements) and manned by U.S. crews. To maintain our privilege of operating vessels in the Jones Act trade, we must maintain U.S. citizen status for Jones Act purposes. To ensure compliance with the Jones Act, we must be U.S. citizens qualified to document vessels for coastwise trade. We could cease being a U.S. citizen if certain events were to occur, including if non-U.S. citizens were to own 25% or more of our equity interest or were otherwise deemed to control us or our general partner. We are responsible for monitoring ownership to ensure compliance with the Jones Act. The consequences of our failure to comply with the Jones Act provisions on coastwise trade, including failing to qualify as a U.S. citizen, would have an adverse effect on us as we may be prohibited from operating our vessels in the U.S. coastwise trade or, under certain circumstances, permanently lose U.S. coastwise trading rights or be subject to fines or forfeiture of our vessels.

27


Table of Contents

Our business would be adversely affected if the Jones Act provisions on coastwise trade or international trade agreements were modified or repealed or as a result of modifications to existing legislation or regulations governing the oil and gas industry in response to the Deepwater Horizon drilling rig incident in the U.S. Gulf of Mexico and subsequent oil spill.
If the restrictions contained in the Jones Act were repealed or altered or certain international trade agreements were changed, the maritime transportation of cargo between U.S. ports could be opened to foreign flag or foreign-built vessels. The Secretary of the Department of Homeland Security, or the Secretary, is vested with the authority and discretion to waive the coastwise laws if the Secretary deems that such action is necessary in the interest of national defense. Any waiver of the coastwise laws, whether in response to natural disasters or otherwise, could result in increased competition from foreign product carrier and barge operators, which could reduce our revenues and cash available for distribution. In the past several years, interest groups have lobbied Congress to repeal or modify the Jones Act to facilitate foreign-flag competition for trades and cargoes currently reserved for U.S. flag vessels under the Jones Act. Foreign-flag vessels generally have lower construction costs and generally operate at significantly lower costs than we do in U.S. markets, which would likely result in reduced charter rates. We believe that continued efforts will be made to modify or repeal the Jones Act. If these efforts are successful, foreign-flag vessels could be permitted to trade in the United States coastwise trade and significantly increase competition with our fleet, which could have an adverse effect on our business. Events within the oil and gas industry, such as the April 2010 fire and explosion on the Deepwater Horizon drilling rig in the U.S. Gulf of Mexico and the resulting oil spill and moratorium on certain drilling activities in the U.S. Gulf of Mexico implemented by the Bureau of Ocean Energy Management, Regulation and Enforcement (formerly, the Minerals Management Service), may adversely affect our customers’ operations and, consequently, our operations. Such events may also subject companies operating in the oil and gas industry, including us, to additional regulatory scrutiny and result in additional regulations and restrictions adversely affecting the U.S. oil and gas industry.
A decrease in the cost of importing refined petroleum products could cause demand for U.S. flag product carrier and barge capacity and charter rates to decline, which would decrease our revenues and our ability to pay cash distributions on our units.
The demand for U.S. flag product carriers and barges is influenced by the cost of importing refined petroleum products. Historically, charter rates for vessels qualified to participate in the U.S. coastwise trade under the Jones Act have been higher than charter rates for foreign flag vessels. This is due to the higher construction and operating costs of U.S. flag vessels under the Jones Act requirements that such vessels be built in the United States and manned by U.S. crews. This has made it less expensive for certain areas of the United States that are underserved by pipelines or which lack local refining capacity, such as in the Northeast, to import refined petroleum products carried aboard foreign flag vessels than to obtain them from U.S. refineries. If the cost of importing refined petroleum products decreases to the extent that it becomes less expensive to import refined petroleum products to other regions of the East Coast and the West Coast than producing such products in the United States and transporting them on U.S. flag vessels, demand for our vessels and the charter rates for them could decrease.
Risks Related to Our Partnership Structure
Our significant unitholders may sell units or other limited partner interests in the trading market, which could reduce the market price of common units.
As of December 31, 2013, we have a number of significant unitholders. For example, certain members of the Davison family (including their affiliates) and management owned approximately 17.7 million or 20% of our common units. From time to time, we also may have other unitholders that have large positions in our common units. In the future, any such parties may acquire additional interest or dispose of some or all of their interest. If they dispose of a substantial portion of their interest in the trading markets, such sales could reduce the market price of common units. In connection with certain transactions, we have put in place resale shelf registration statements, which allow unit holders thereunder to sell their common units at any time (subject to certain restrictions) and to include those securities in any equity offering we consummate for our own account.
Individual members of the Davison family can exert significant influence over us and may have conflicts of interest with us and may be permitted to favor their interests to the detriment of our other unitholders.
James E. Davison and James E. Davison, Jr., each of whom is a director of our general partner, each own a significant portion of our common units, including our Class B Common Units, holders of which elect our directors. Other members of the Davison family also own a significant portion of our common units. Collectively, members of the Davison family and their affiliates own approximately 14.4% of our Class A Common Units and 76.9% of our Class B Common Units and are able to exert significant influence over us, including the ability to elect at least a majority of the members of our board of directors and the ability to control most matters requiring board approval, such as material business strategies, mergers, business combinations, acquisitions or dispositions of assets, issuances of additional partnership securities, incurrences of debt or other

28


Table of Contents

financings and payments of distributions. In addition, the existence of a controlling group (if one were to form) may have the effect of making it difficult for, or may discourage or delay, a third party from seeking to acquire us, which may adversely affect the market price of our common units. Further, conflicts of interest may arise between us and other entities for which members of the Davison family serve as officers or directors. In resolving any conflicts that may arise, such members of the Davison family may favor the interests of another entity over our interests.
Members of the Davison family own, control and have interests in diverse companies, some of which may (or could in the future) compete directly or indirectly with us. As a result, the interests of the members of the Davison family may not always be consistent with our interests or the interests of our other unitholders. Members of the Davison family could also pursue acquisitions or business opportunities that may be complementary to our business. Our organizational documents allow the holders of our units (including affiliates, like the Davisons) to take advantage of such corporate opportunities without first presenting such opportunities to us. As a result, corporate opportunities that may benefit us may not be available to us in a timely manner, or at all. To the extent that conflicts of interest may arise among us and any member of the Davison family, those conflicts may be resolved in a manner adverse to us or you. Other potential conflicts may involve, among others, the following situations:
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
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 Class B Common Units may be transferred to a third party without unitholder consent, which could affect our strategic direction.
Unlike the holders of common stock in a corporation, our unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Only holders of our Class B Common Units have the right to elect our board of directors. Holders of our Class B Common Units may transfer such units to a third party without the consent of the unitholders. The new holders of our Class B Common Units may then be in a position to replace our board of directors and officers of our general partner with its own choices and to control the strategic decisions made by our board of directors and officers.
Unitholders with registration rights have rights to require underwritten offerings that could limit our ability to raise capital in the public equity market.
Unitholders with registration rights have rights to require us to conduct underwritten offerings of our common units. If we want to access the capital markets, those unitholders’ ability to sell a portion of their common units could satisfy investor’s demand for our common units or may reduce the market price for our common units, thereby reducing the net proceeds we would receive from a sale of newly issued units.
We may issue additional common units without unitholder’s approval, which would dilute their ownership interests.
We may issue an unlimited number of limited partner interests of any type without the approval of our unitholders.
The issuance of additional common units or other equity securities of equal or senior rank will have the following effects:
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.

29


Table of Contents

Our general partner has a limited call right that may require unitholders to sell their units at an undesirable time or price.
If at any time our general partner and its affiliates own more than 80% of any class of our units, our general partner will have the right, but not the obligation, which it may assign to any of its affiliates, including any controlling unitholder, or to us, to acquire all, but not less than all, of the units held by unaffiliated persons at a price not less than their then-current market price. As a result, unitholders may be required to sell their units at an undesirable time or price and may not receive any return on their investment. Unitholders may also incur a tax liability upon a sale of their units.
The interruption of distributions to us from our subsidiaries and joint ventures could affect our ability to make payments on indebtedness or cash distributions to our unitholders.
We are a holding company. As such, our primary assets are the equity interests in our subsidiaries and joint ventures. Consequently, our ability to fund our commitments (including payments on our indebtedness) and to make cash distributions depends upon the earnings and cash flow of our subsidiaries and joint ventures and the distribution of that cash to us. Distributions from our joint ventures, other than CHOPS are subject to the discretion of their respective management committees. Further, each joint venture’s charter documents typically vest in its management committee sole discretion regarding distributions. Accordingly, our joint ventures may not continue to make distributions to us at current levels or at all.
We do not have the same flexibility as other types of organizations to accumulate cash and equity to protect against illiquidity in the future.
Unlike a corporation, our partnership agreement requires us to make quarterly distributions to our unitholders of all available cash reduced by any amounts reserved for commitments and contingencies, including capital and operating costs and debt service requirements. The value of our units and other limited partner interests may decrease in direct correlation with decreases in the amount we distribute per unit. Accordingly, if we experience a liquidity problem in the future, we may not be able to issue more equity to recapitalize.
Unitholders may have liability to repay distributions that were wrongfully distributed to them.
Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, we may not make a distribution to you if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that for a period of three years from the date of an impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. Substituted limited partners are liable both for the obligations of the assignor to make contributions to the partnership that were known to the substituted limited partner at the time it became a limited partner and for those obligations that were unknown if the liabilities could have been determined from the partnership agreement. Neither liabilities to partners on account of their partnership interest nor liabilities that are non-recourse to the partnership are counted for purposes of determining whether a distribution is permitted.
Your liability may not be limited if a court finds that unitholder action constitutes control of our business.
A general partner of a partnership generally has unlimited liability for the obligations of the partnership, except for those contractual obligations of the partnership that are expressly made without recourse to the general partner. Our partnership is organized under Delaware law, and we conduct business in other states. The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some states in which we do business or may do business in from time to time in the future. You could be liable for any and all of our obligations as if you were a general partner if a court or government agency were to determine that:
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.
Tax Risks to Common Unitholders
Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as our not being subject to a material amount of entity-level taxation by individual states. A publicly-traded partnership can lose its status as a partnership for a number of reasons, including not having enough “qualifying income.” If the Internal Revenue Service, or IRS, were to treat us as a corporation or if we were to become subject to a material amount of entity-level taxation for state tax purposes, then our cash available for distribution to unitholders would be substantially reduced.

30


Table of Contents

The anticipated after-tax economic benefit of an investment in our common units depends largely on our being treated as a partnership for federal income tax purposes. Section 7704 of the Internal Revenue Code provides that publicly traded partnerships will, as a general rule, be taxed as corporations. However, an exception, referred to in this discussion as the “Qualifying Income Exception,” exists with respect to publicly traded partnerships 90% or more of the gross income of which for every taxable year consists of “qualifying income.” If less than 90% of our gross income for any taxable year is “qualifying income” from transportation or processing of natural resources including crude oil, natural gas or products thereof, interest, dividends or similar sources, we will be taxable as a corporation under Section 7704 of the Internal Revenue Code for federal income tax purposes for that taxable year and all subsequent years. We have not requested, and do not plan to request, a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes.
Although we do not believe based upon our current operations that we are treated as a corporation for federal income tax purposes, a change in our business (or a change in current law) could cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to taxation as an entity. If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate, which is currently a maximum of 35% and would pay state income tax at varying rates. Distributions to our unitholders would generally be taxable to them again as corporate distributions and no income, gains, losses, or deductions would flow through to them. Because a tax would be imposed upon us as a corporation, our cash available for distribution to unitholders would be substantially reduced. Therefore, treatment of us as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to our unitholders, likely causing a substantial reduction in the value of our common units.
Current law may change so as to cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to entity-level taxation. Moreover, any modification to the federal income tax laws and interpretations thereof may or may not be applied retroactively. Any such changes could negatively impact the value of an investment in our common units. At the state level, because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. For example, we are required to pay Texas franchise tax on our gross income apportioned to Texas. Imposition of any such taxes on us by any other state would reduce the cash available for distribution to our unitholders.
The tax treatment of publicly traded partnerships could be subject to potential legislative, judicial or administrative changes and differing interpretations, possibly on a retroactive basis.
The present U.S. federal income tax treatment of publicly traded partnerships, including us, may be modified by administrative, legislative or judicial interpretation at any time. Any modification to the U.S. federal income tax laws and interpretations thereof may or may not be applied retroactively and could make it more difficult or impossible to meet the exception for us to be treated as a partnership for U.S. federal income tax purposes that is not taxable as a corporation, affect or cause us to change our business activities, affect the tax considerations of an investment in us and change the character or treatment of portions of our income. From time to time, members of Congress propose and consider substantive changes to the existing U.S. federal income tax laws that would adversely affect the tax treatment of certain publicly traded partnerships. We are unable to predict whether any of these changes, or other proposals, will ultimately be enacted. Any such changes could cause a material reduction in our anticipated cash flow.
A successful IRS contest of the federal income tax positions we take may adversely affect the market for our common units, and the cost of any IRS contest will reduce our cash available for distribution to our unitholders and our general partner.
We have not requested, and do not plan to request, a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes or any other matter affecting us. The IRS may adopt positions that differ from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take. A court may not agree with some or all of the positions we take. Any contest with the IRS may materially and adversely impact the market for our common units and the price at which they trade. In addition, our costs of any contest with the IRS will be borne indirectly by our unitholders and our general partner because these costs will reduce our cash available for distribution.
Unitholders will be required to pay taxes on income (as well as deemed distributions, if any) from us even if they do not receive any cash distributions from us.
Unitholders will be required to pay any federal income taxes and, in some cases, state and local income taxes on their share of our taxable income (as well as deemed distributions, if any) even if unitholders receive no cash distributions from us. Unitholders may not receive cash distributions from us equal to their share of our taxable income (or deemed distributions, if any) or even the tax liability that results from that income (or deemed distribution).

31


Table of Contents

Tax gain or loss on the disposition of our common units could be more or less than expected.
If unitholders sell their common units, they will recognize a gain or loss equal to the difference between the amount realized and their tax basis in those common units. Prior distributions to unitholders in excess of the total net taxable income unitholders were allocated for a common unit, which decreased their tax basis in that common unit, will, in effect, become taxable income to unitholders if the common unit is sold at a price greater than their tax basis in that common unit, even if the price they receive is less than their original cost. A substantial portion of the amount realized, whether or not representing gain, may be ordinary income due to potential recapture items, including depreciation recapture. In addition, because the amount realized includes a unitholder’s share of our non-recourse liabilities, if unitholders sell their units, they may incur a tax liability in excess of the amount of cash they receive from the sale.
Tax-exempt entities and non-U.S. persons face unique tax issues from owning our common units that may result in adverse tax consequences to them.
Investment in common units by tax-exempt entities, such as individual retirement accounts (known as IRAs), other retirement plans, and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. Distributions to non-U.S. persons will be reduced by withholding taxes at the highest applicable effective tax rate and non-U.S. persons will be required to file U.S. federal income tax returns and pay tax on their share of our taxable income. Tax-exempt entities and non-U.S. persons should consult their tax advisors before investing in our common units.
We will treat each purchaser of our common units as having the same tax benefits without regard to the actual common units purchased. The IRS may challenge this treatment, which could adversely affect the value of our common units.
Because we cannot match transferors and transferees of our common units, we adopt depreciation and amortization conventions that may not conform to all aspects of existing Treasury Regulations and may result in audit adjustments to our unitholders’ tax returns without the benefit of additional deductions. A successful IRS challenge to those conventions could adversely affect the amount of tax benefits available to a common unitholder. It also could affect the timing of these tax benefits or the amount of gain from a sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to the common unitholder’s tax returns.
Unitholders will likely be subject to state and local taxes in states where they do not live as a result of an investment in the common units.
In addition to federal income taxes, unitholders will likely be subject to other taxes, including foreign, state and local taxes, unincorporated business taxes and estate inheritance or intangible taxes that are imposed by the various jurisdictions in which we do business or own property, even if unitholders do not live in any of those jurisdictions. Unitholders will likely be required to file foreign, state, and local income tax returns and pay state and local income taxes in some or all of these jurisdictions. Further, unitholders may be subject to penalties for failure to comply with those requirements. We own assets and do business in more than 20 states including Texas, Louisiana, Mississippi, Alabama, Florida, Arkansas and Oklahoma. Many of the states we currently do business in impose a personal income tax. It is our unitholders’ responsibility to file all applicable United States federal, foreign, state and local tax returns.
We have subsidiaries that are treated as corporations for federal income tax purposes and subject to corporate-level income taxes.
We conduct a portion of our operations through subsidiaries that are, or are treated as, corporations for federal income tax purposes. We may elect to conduct additional operations in corporate form in the future. These corporate subsidiaries will be subject to corporate-level tax, which will reduce the cash available for distribution to us and, in turn, to our unitholders. If the IRS were to successfully assert that these corporate subsidiaries have more tax liability than we anticipate or legislation was enacted that increased the corporate tax rate, our cash available for distribution to our unitholders would be further reduced.
We prorate our items of income, gain, loss and deduction between transferors and transferees of our common units each month based upon the ownership of our common units on the first day of each month, instead of on the basis of the date a particular common unit is transferred.
We prorate our items of income, gain, loss, and deduction between transferors and transferees of our common units each month based upon the ownership of our common units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The use of this proration method may not be permitted under existing Treasury Regulations. If the IRS were to successfully challenge this method or new Treasury Regulations were issued, we may be required to change the allocation of items of income, gain, loss, and deduction among our unitholders.

32


Table of Contents

A unitholder whose units are loaned to a “short seller” to cover a short sale of units may be considered as having disposed of those units. If so, such unitholder would no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and may recognize gain or loss from the disposition.
Because a unitholder whose units are loaned to a “short seller” to cover a short sale of units may be considered as having disposed of the loaned units, such unitholder may no longer be treated for tax purposes as a partner with respect to those units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan to the short seller, any of our income, gain, loss or deduction with respect to those units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those units could be fully taxable as ordinary income. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their units.
The sale or exchange of 50% or more of our capital and profits interests during any twelve-month period will result in the termination of our partnership for federal income tax purposes.
We will be considered to have terminated our partnership for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. Our termination would, among other things, result in the closing of our taxable year for all unitholders, which would result in us filing two tax returns (and unitholders receiving two Schedule K-1s) for one fiscal year. Our termination could also result in a deferral of depreciation deductions allowable in computing our taxable income. In the case of a common unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of our taxable year may result in more than twelve months of our taxable income or loss being includable in his taxable income for the year of termination. Our termination currently would not affect our classification as a partnership for federal income tax purposes, but instead, we would be treated as a new partnership for tax purposes. If treated as a new partnership, we must make new tax elections and could be subject to penalties if we are unable to determine that a termination occurred.
Item 1B. Unresolved Staff Comments
None.
Item 2. Properties
See Item 1. “Business.” We also have various operating leases for rental of office space, office and field equipment and vehicles. See “Commitments and Off-Balance Sheet Arrangements” in Management’s Discussion and Analysis of Financial Condition and Results of Operations, and Note 19 to our Consolidated Financial Statements in Item 8 for the future minimum rental payments. Such information is incorporated herein by reference.
Item 3. Legal Proceedings
We are involved from time to time in various claims, lawsuits and administrative proceedings incidental to our business. In our opinion, the ultimate outcome, if any, of such proceedings is not expected to have a material adverse effect on our financial condition, results of operations or cash flows. See Note 19 to our Consolidated Financial Statements in Item 8.
Item 4. Mine Safety Disclosures
Not applicable.

33


Table of Contents

PART II
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Our Class A common units are listed on the New York Stock Exchange (“NYSE”) under the symbol “GEL.” The following table sets forth, for the periods indicated, the high and low sale prices per common unit and the amount of cash distributions declared and paid per common unit.
 
 
Price Range
 
Cash
Distributions (1)
 
High
 
Low
 
2012
 
 
 
 
 
1st Quarter
$
33.81

 
$
27.62

 
$
0.4400

2nd Quarter
$
31.40

 
$
26.70

 
$
0.4500

3rd Quarter
$
34.12

 
$
28.80

 
$
0.4600

4th Quarter
$
36.38

 
$
30.86

 
$
0.4725

2013
 
 
 
 
 
1st Quarter
$
49.34

 
$
36.00

 
$
0.4850

2nd Quarter
$
54.91

 
$
44.04

 
$
0.4975

3rd Quarter
$
55.99

 
$
45.81

 
$
0.5100

4th Quarter
$
53.94

 
$
48.00

 
$
0.5225

 
(1)
Cash distributions are shown in the quarter paid and are based on the prior quarter’s activities.
At February 24, 2014, we had 88,650,988 Class A common units outstanding. As of December 31, 2013, the closing price of our common units was $52.57 and we had approximately 47,200 record holders of our Class A common units, which include holders who own units through their brokers “in street name.”
After holders of our Waiver Units receive a minimal preferential quarterly distribution, we distribute all of our available cash, as defined in our partnership agreement, within 45 days after the end of each quarter to holders of record of our common units. Available cash consists generally of all of our cash receipts less cash disbursements, adjusted for net changes to cash reserves. Cash reserves are the amounts deemed necessary or appropriate, in the reasonable discretion of our general partner, to provide for the proper conduct of our business or to comply with applicable law, any of our debt instruments or other agreements. The full definition of available cash is set forth in our partnership agreement and amendments thereto, which are incorporated by reference as an exhibit to this Form 10-K.
See Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources – Capital Expenditures and Distributions Paid to our Unitholders” and Note 11 to our Consolidated Financial Statements in Item 8 for further information regarding restrictions on our distributions. See Item 12. “Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters” for information regarding securities authorized for issuance under equity compensation plans.

34


Table of Contents

Item 6. Selected Financial Data
The table below includes selected financial and other data for the Partnership for the years ended December 31, 2013, 2012, 2011, 2010 and 2009 (in thousands, except per unit and volume data). The selected financial data should be read in conjunction with our Consolidated Financial Statements and Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”
 
 
Year Ended December 31,
 
 2013 (1)
 
2012 (1)
 
2011 (1)
 
2010 (1)
 
2009 (1)
Income Statement Data:
 
 
 
 
 
 
 
 
 
Revenues:
 
 
 
 
 
 
 
 
 
Supply and logistics
$
3,842,337

 
$
3,095,054

 
$
2,173,896

 
$
1,516,071

 
$
956,151

Refinery services
205,985

 
196,017

 
201,711

 
151,060

 
141,365

Pipeline transportation
86,508

 
76,290

 
62,190

 
55,652

 
50,951

Total revenues
$
4,134,830

 
$
3,367,361

 
$
2,437,797

 
$
1,722,783

 
$
1,148,467

Income (loss) from continuing operations before income taxes (2)
$
84,004

 
$
97,337

 
$
51,371

 
$
(50,307
)
 
$
6,938

Income (loss) from continuing operations before income taxes attributable to Genesis Energy, L.P. (2)
$
84,004

 
$
97,337

 
$
51,371

 
$
(48,225
)
 
$
8,823

Income from continuing operations before income taxes available to Common Unitholders
$
84,004

 
$
97,337

 
$
51,371

 
$
20,163

 
$
20,946

Income (loss) from continuing operations attributable to Genesis Energy, L.P. per Common Unit: Basic and Diluted
$
1.00

 
$
1.24

 
$
0.76

 
$
0.50

 
$
0.53

Cash distributions declared per Common Unit
$
2.0150

 
$
1.8225

 
$
1.6500

 
$
1.4900

 
$
1.3650

Balance Sheet Data (at end of period):
 
 
 
 
 
 
 
 
 
Current assets
$
535,223

 
$
404,034

 
$
376,104

 
$
252,538

 
$
189,244

Total assets
$
2,862,202

 
$
2,109,664

 
$
1,730,844

 
$
1,506,735

 
$
1,148,127

Long-term liabilities
$
1,317,912

 
$
880,518

 
$
688,778

 
$
630,757

 
$
387,766

Partners’ capital:
 
 
 
 
 
 
 
 
 
Genesis Energy, L.P.
$
1,097,737

 
$
916,495

 
$
792,638

 
$
669,264

 
$
595,877

Noncontrolling interests

 

 

 

 
23,056

Total partners’ capital
$
1,097,737

 
$
916,495

 
$
792,638

 
$
669,264

 
$
618,933

Other Data:
 
 
 
 
 
 
 
 
 
Volumes—continuing operations:
 
 
 
 
 
 
 
 
 
Onshore crude oil pipeline (barrels per day)
104,026

 
92,897

 
82,712

 
67,931

 
60,262

Offshore crude oil pipeline (barrels per day) (3)
404,787

 
359,387

 
120,723

 
149,270

 

CO2 pipeline (Mcf per day)
190,274

 
186,479

 
169,962

 
167,619

 
154,271

NaHS sales (DST)
147,297

 
142,712

 
147,670

 
145,213

 
107,311

NaOH sales (DST)
87,463

 
77,492

 
99,702

 
93,283

 
88,959

Crude oil and petroleum products sales (barrels per day)
99,651

 
79,174

 
56,903

 
49,992

 
37,642

 
(1)
Our operating results and financial position have been affected by acquisitions, most notably (1) the acquisition of our offshore marine transportation business in August 2013, (2) 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, (3) the acquisition of the black oil barge business of Florida Marine Transporters, Inc. in August 2011, (4) the

35


Table of Contents

50% equity interest acquisition in CHOPS in November 2010 and (5) the acquisition of the remaining 51% ownership interest in DG Marine in July 2010. The results of these operations are included in our financial results prospectively from the acquisition date. On December 31, 2013 we completed the sale of our vehicle fuel procurement and delivery logistics management services business. That business, previously reported in our supply and logistics revenues and costs and expenses, was reclassified as discontinued operations for the periods in the table above. For additional information regarding our acquisitions and divestitures during 2013, 2012 and 2011, 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 and $14.1 million for 2009.
(3)
Includes barrels per day for CHOPS for the period we owned the pipeline in 2010.

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
Introduction
We are a growth-oriented master limited partnership formed in Delaware in 1996 and focused on the midstream segment of the oil and gas industry in the Gulf Coast region of the United States, primarily Texas, Louisiana, Arkansas, Mississippi, Alabama, Florida, Wyoming and in the Gulf of Mexico. We have a diverse portfolio of assets, including pipelines, refinery-related plants, storage tanks and terminals, railcars, rail loading and unloading facilities, barges and trucks. We provide an integrated suite of services to oil producers, refineries, and industrial and commercial enterprises that use NaHS and caustic soda. Our business activities are primarily focused on providing services around and within refinery complexes. We conduct our operations and own our operating assets through our subsidiaries and joint ventures.
Included in Management’s Discussion and Analysis are the following sections:
Overview of 2013 Results
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
Overview of 2013 Results
We reported net income from continuing operations of $84 million, or $1.00 per common unit, in 2013 compared to net income from continuing operations of $97.3 million, or $1.24 per common unit, in 2012. The decline in net income in 2013 was primarily due to the reversal in 2012 of a provision for uncertain tax positions of $8.2 million combined with a $7.7 million increase in interest expense, a $4.1 million increase in general and administrative expenses related to growth capital expenditures and a $3.6 million increase in depreciation and amortization expense. Those decreases were partially offset by the overall increase in Segment Margin as discussed below.
Available Cash before Reserves increased $6.9 million in 2013 to $186.1 million as compared to 2012 Available Cash before Reserves of $179.2 million. See "Financial Measures" below for additional information on Available Cash before Reserves.
Segment Margin (as defined below in "Financial Measures") was $280.4 million in 2013, an increase of $18 million, or 7%, as compared to 2012. This increase primarily resulted from improvement in Segment Margin in our pipeline transportation segment of 13% and increases of 3% in both our refinery services and supply and logistics segments. Our Segment Margin attributable to our pipeline transportation and refinery services segments increased primarily due to increased pipeline throughput volumes and increased NaHS sales volumes, respectively. Our supply and logistics segment benefited from our acquisition of our offshore marine transportation business in August 2013, our recently completed crude-by-rail terminals and higher crude oil and petroleum products volumes handled by our expanded marine, trucking and rail fleets.

36


Table of Contents

Distribution Increase
In January 2014, we declared our thirty-fourth consecutive increase in our quarterly distribution to our common unitholders relative to the fourth quarter of 2013. Twenty-nine of those quarterly increases have been 10% or greater as compared to the same quarter in the preceding year. In February 2014, we paid a distribution of $0.5350 per unit related to the fourth quarter of 2013, representing a 10.3% increase from our distribution of $0.4850 per unit related to the fourth quarter of 2012.
Acquisitions, Divestitures and Growth Initiatives
Acquisition of Additional Barges and Tug Boats
On August 28, 2013, we completed the acquisition of substantially all of the assets of the downstream transportation business of Hornbeck Offshore Services, Inc. for approximately $230.9 million, which we refer to as our offshore marine transportation business and assets. The acquired business was primarily comprised of nine barges and nine tug boats that transport crude oil and refined petroleum products, principally serving refineries and storage terminals along the Gulf Coast, Eastern Seaboard, Great Lakes and Caribbean. That acquisition complements and further integrates certain of our existing operations, including our Genesis Marine inland barge business (comprised of 54 barges and 23 push/tow boats), our crude oil and heavy refined products storage and blending terminals as well as our crude oil pipeline systems.

Divestiture of Fuel Procurement Business

On December 31, 2013 we completed the sale of our vehicle fuel procurement and delivery logistics management services business for $1 million. The operating results of that business, previously reported within our supply and logistics segment, was reclassified as discontinued operations in our Consolidated Statements of Operations for the years ended December 31, 2013, 2012 and 2011.

ExxonMobil Baton Rouge Project
We are improving existing assets and developing 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 24-inch diameter crude oil pipeline connecting Port Hudson to the Baton Rouge Scenic Station and continuing downstream to the Anchorage Tank Farm and building a new crude oil unit train unload facility at Scenic Station. The Port Hudson upgrades and new crude oil pipeline are expected to be completed by the end of the first quarter of 2014, and Scenic Station is expected to be completed in the second quarter of 2014.
Baton Rouge Terminal
We recently announced plans to construct a new crude oil, intermediates and refined products import/export terminal in Baton Rouge. That terminal will be located near the Port of Greater Baton Rouge and will be pipeline-connected to that port's existing deepwater docks on the Mississippi River. We will initially construct approximately 1.1 million barrels of tankage for the storage of crude oil, intermediates and/or refined products with the capability to expand to provide additional terminaling services to our customers. Our Baton Rouge Terminal will also be pipeline-connected to ExxonMobil facilities in the area, as well as to Scenic Station. Shippers to Scenic Station will have access to both the local Baton Rouge refining market, as well as the ability to access other attractive refining markets via our Baton Rouge Terminal. The Baton Rouge Terminal is expected to be completed by the end of the second quarter of 2015.
Deepwater Gulf of Mexico Pipeline Joint Venture
Southeast Keathley Canyon Pipeline Company LLC, or SEKCO, our 50/50 joint venture with Enterprise Products Partners, L.P., expects to place in-service in mid-2014 its deepwater pipeline serving the Lucius oil and gas field in the southern Keathley Canyon area of the Gulf of Mexico. SEKCO has entered into 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 pipeline to provide capacity for additional projects in the deepwater Gulf of Mexico. Enterprise Products serves as construction manager and will be the operator of the new pipeline.
The 149-mile, 18-inch diameter pipeline, designed to have a 115,000 barrel per day capacity, will connect the Lucius-truss spar floating production platform to an existing junction platform at South Marsh Island that is part of the Poseidon pipeline system, in which we own a 28% interest. See additional discussion regarding this project in Item 7.

37


Table of Contents

“Management’s Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources.”
Texas City Projects
In December 2013, we placed in-service an 18-inch diameter loop of our existing crude oil pipeline into Texas City, supported by a term contract with one of our refining customers, which we expect will allow us to significantly expand our total service capabilities into the Texas City area. Previously, we had acquired three above-ground storage tanks located in Texas City, Texas and an existing barge dock at the same location, all approximately 1.5 miles from our existing Texas pipeline system. We also constructed a truck station and tankage in West Columbia, Texas to provide incremental transportation service for the Eagle Ford Shale and other Texas production through our pipeline system to refining markets in the greater Houston/Texas City area. We are able to handle approximately 40,000 barrels per day of crude oil through the Texas City terminal.
Rail Projects    
Walnut Hill - In the first quarter of 2013, we completed construction on the second phase of our crude-by-rail unloading terminal at Walnut Hill, Florida, which includes a 100,000 barrel storage tank and related equipment and connections to our Jay System. This facility provides the capability of handling unit train shipments for direct deliveries to an existing refinery customer and indirect deliveries (through third-party common carriers) to multiple other markets in the Southeast at the option of the shippers. We have commenced construction on an additional tank at that site with 110,000 barrels of capacity, which will allow us to handle increased rail and pipeline demand. We estimate this tank will be fully operational by the end of the first quarter of 2014.
Wink - In 2012, we completed the initial phase construction of a crude oil rail loading facility in Wink, Texas, which was designed to move crude oil from West Texas to other markets and to give us the capability to load Genesis and third party railcars. Construction on the second phase of that facility, which we estimate will be operational by the end of the first quarter of 2014, will allow us to more efficiently load full unit trains.
Natchez - In the third quarter of 2013, we completed construction on a crude oil rail unloading/loading facility at our existing terminal located in Natchez, Mississippi, which is designed to facilitate the movement of Canadian bitumen/dilbit to Gulf Coast markets. That facility has the capability to unload bitumen/dilbit as well as load diluent for backhauls to Canada. We have initiated construction on the second phase of the Natchez facility, which will provide an additional 60 railcar spots and additional heated tanks. We expect to complete that rail unloading/loading facility expansion by the end of the first quarter of 2014.
Raceland - In the fourth quarter of 2013, we began construction on a new crude oil unit train unloading facility capable of unloading up to two unit trains per day, which is located in Raceland, Louisiana. The Raceland Rail Facility will be connected to existing midstream infrastructure that will provide direct pipeline access to refineries from the Baton Rouge area to the Gulf of Mexico and is expected to be operational in the fourth quarter of 2014.
Pronghorn - In December of 2013, we placed in-service a new unit train loading facility in the Powder River Basin of the Niobrara Shale Play. That facility is tied-in to our existing gathering system in that region.
Results of Operations
In the discussions that follow, we will focus on our revenues, expenses and net income, as well as two measures that we use to manage the business and to review the results of our operations--Segment Margin and Available Cash before Reserves. Segment Margin and Available Cash before Reserves are defined in the "Financial Measures" section below.
Revenues, Costs and Expenses and Net Income
Our revenues from continuing operations for the year ended December 31, 2013 increased $767.5 million, or 23% from 2012. Additionally, our costs and expenses from continuing operations increased $771.4 million or 24% between the two periods. The majority of our revenues and our costs are derived from the purchase and sale of crude oil and petroleum products. The significant increase in our revenues and costs between 2013 and 2012 is primarily attributable to increased volumes from our continuing operations, our recently completed acquisitions and internal growth projects and slight increases in the market prices for crude oil and petroleum products as described below.
Volumes from our continuing operations in 2013 increased in our supply and logistics segment by 26% from 2012, as explained in our supply and logistics Segment Margin discussion below. The average closing prices for West Texas Intermediate ("WTI") crude oil on the New York Mercantile Exchange ("NYMEX") increased 4% to $97.97 per barrel in 2013, as compared to $94.21 per barrel in 2012.
Net income from continuing operations decreased $13.3 million in 2013 from 2012. See "Overview of 2013 Results" above for additional discussion.

38


Table of Contents

Revenues from continuing operations in 2012 increased $929.6 million, or 38% from 2011. Additionally, our costs and expenses from continuing operations increased $897.4 million or 38% between the two periods. The significant increase in our revenues and costs between 2012 and 2011 is primarily attributable to increased volumes from our continuing operations and our acquisitions, partially offset by slight decreases in the market prices for crude oil and petroleum products. Volumes from continuing operations increased in our supply and logistics segment in 2012 by 39% from 2012, as explained in our supply and logistics Segment Margin discussion below. The average closing prices for WTI crude oil on the NYMEX were consistent, decreasing 1% to $94.21 per barrel in 2012, as compared to $95.12 per barrel in 2011. Net income from continuing operations increased $46 million in 2012 to $97.3 million from $51.4 million in 2011. The increase in net income during 2012 primarily reflects improved Segment Margin results primarily due to our acquisitions and increased volumes. Our income tax expense decreased due to the reversal of uncertain tax positions as a result of tax audit settlements and the expiration of statutes of limitations. These increases to net income were partially offset by increases in general and administrative expenses and interest costs.
Included below is additional detailed discussion of the results of our operations focusing on Segment Margin and other costs including general and administrative expenses, depreciation and amortization, interest and income taxes.
Segment Margin
The contribution of each of our segments to total Segment Margin in each of the last three years was as follows:
 
Year Ended December 31,
 
2013
 
2012
 
2011
 
(in thousands)
Pipeline transportation
$
108,879

 
$
96,539

 
$
67,908

Refinery services
75,361

 
72,883

 
74,618

Supply and logistics
96,120

 
92,911

 
59,975

Total Segment Margin
$
280,360

 
$
262,333

 
$
202,501


39


Table of Contents


Year Ended December 31, 2013 Compared with Year Ended December 31, 2012
Pipeline Transportation Segment
Operating results and volumetric data for our pipeline transportation segment are presented below: 
 
Year Ended December 31,
 
2013
 
2012
 
(in thousands)
Crude oil tariffs and revenues from direct financing leases—onshore crude oil pipelines
$
39,627

 
$
31,931

Segment Margin from offshore crude oil pipelines, including pro-rata share of distributable cash from equity investees
44,530

 
38,500

CO2 tariffs and revenues from direct financing leases of CO2 pipelines
26,342

 
26,603

Sales of onshore crude oil pipeline loss allowance volumes
11,526

 
9,165

Onshore pipeline operating costs, excluding non-cash charges for equity-based compensation and other non-cash expenses
(19,217
)
 
(15,607
)
Payments received under direct financing leases not included in income
5,110

 
5,016

Other
961

 
931

Segment Margin
$
108,879

 
$
96,539

 
 
 
 
Volumetric Data (average barrels/day unless otherwise noted):
 
 
 
Onshore crude oil pipelines:
 
 
 
Texas
51,067

 
51,880

Jay
34,933

 
22,306

Mississippi
18,026

 
18,711

Onshore crude oil pipelines total
104,026

 
92,897

 
 
 
 
Offshore crude oil pipelines:
 
 
 
CHOPS (1)
143,854

 
96,664

Poseidon (1)
207,372

 
211,375

Odyssey (1)
44,978

 
36,157

GOPL
8,583

 
15,191

Offshore crude oil pipelines total
404,787

 
359,387

 
 
 
 
CO2 pipeline (average Mcf/day):
 
 
 
Free State
190,274

 
186,479

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

Pipeline transportation Segment Margin for 2013 increased $12.3 million, or 13%, from 2012. The significant components of this change were as follows:
With respect to our onshore crude oil pipelines, tariff revenues 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 11,129 barrels per day (12%), primarily from our Jay pipeline system. Our Jay pipeline system volumes increased primarily from additional barrels received at our crude-by-rail unloading terminal at Walnut Hill, Florida.
Segment Margin from our offshore crude oil pipelines increased $6 million, or 16%, primarily reflecting an increased contribution from CHOPS. The completion of improvement facility work by producers at the connected production fields in 2012 resulted in higher volumes transported on CHOPS in 2013.
Onshore crude oil pipeline loss allowance volumes, collected and sold, increased Segment Margin by $2.4 million due to an increase in barrels transported in 2013 as compared to 2012.

40


Table of Contents

Onshore pipeline operating costs, excluding non-cash charges, increased $3.6 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 increased 3,795 Mcf per day, or 2%. 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 on our Free State CO2 pipeline system have a limited impact on Segment Margin.     
Refinery Services Segment
Operating results for our refinery services segment were as follows: 
 
Year Ended December 31,
 
2013
 
2012
Volumes sold (in Dry short tons "DST"):
 
 
 
NaHS volumes
147,297

 
142,712

NaOH (caustic soda) volumes
87,463

 
77,492

Total
234,760

 
220,204

 
 
 
 
Revenues (in thousands):
 
 
 
NaHS revenues
$
159,125

 
$
153,689

NaOH (caustic soda) revenues
50,748

 
44,322

Other revenues
6,987

 
7,099

Total external segment revenues
$
216,860

 
$
205,110

 
 
 
 
Segment Margin (in thousands)
$
75,361

 
$
72,883

 
 
 
 
Average index price for NaOH per DST (1)
$
604

 
$
575

Raw material and processing costs as % of segment revenues
49
%
 
48
%
 
(1)
Source: IHS Chemical

Refinery services Segment Margin for 2013 increased $2.5 million, or 3%, from 2012. The significant components of this fluctuation were as follows:
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

41


Table of Contents

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.
Supply and Logistics Segment
Our supply and logistics segment is focused on utilizing our knowledge of the crude oil and petroleum markets and our logistics capabilities from our terminals, railcars, rail loading and unloading facilities, trucks and barges to provide oil and gas producers, refineries and other customers with a full suite of services. These services include:
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;
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;
utilizing our fleet of trucks and trailers, railcars, and barges to take advantage of logistical opportunities primarily in the Gulf Coast states and waterways;
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.
We also use our terminal facilities to take advantage of contango market conditions for crude oil gathering and marketing and to capitalize on regional opportunities which arise from time to time for both crude oil and petroleum products.
Despite crude oil being considered a somewhat homogeneous commodity, many refiners are very particular about the quality of crude oil feedstock they process. Many U.S. refineries have distinct configurations and product slates that require crude oil with specific characteristics, such as gravity, sulfur content and metals content. The refineries evaluate the costs to obtain, transport and process their preferred feedstocks. That particularity provides us with opportunities to help the refineries in our areas of operation identify crude oil sources meeting their requirements and to purchase the crude oil and transport it to the refineries for sale. The imbalances and inefficiencies relative to meeting the refiners’ requirements can provide opportunities for us to utilize our purchasing and logistical skills to meet their demands. The pricing in the majority of our purchase contracts contains a market price component and a deduction to cover the cost of transporting the crude oil and to provide us with a margin. Contracts sometimes contain a grade differential which considers the chemical composition of the crude oil and its appeal to different customers. Typically, the pricing in a contract to sell crude oil will consist of the market price components and the grade differentials. The margin on individual transactions is then dependent on our ability to manage our transportation costs and to capitalize on grade differentials.
In our petroleum products marketing operations, we supply primarily fuel oil, asphalt and other heavy refined products to wholesale markets and some end-users such as paper mills and utilities. We also provide a service to refineries by purchasing “heavier” petroleum products that are the residual fuels from gasoline production, transporting them to one of our terminals and blending them to a quality that meets the requirements of our customers.
We utilize our fleet of 300 trucks, 400 trailers, 580 railcars, 63 barges (54 inland and 9 offshore), 32 push/tow boats (23 inland and 9 offshore) and 2.4 million barrels of leased and owned storage capacity to service our crude oil and refining customers and to store and blend the intermediate and finished refined products.

42


Table of Contents

Operating results for our supply and logistics segment were as follows:
 
Year Ended December 31,
 
2013
 
2012
 
(in thousands)
Supply and logistics revenue
$
3,842,337

 
$
3,095,054

Crude oil and products costs, excluding unrealized gains and losses from derivative transactions
(3,545,830
)
 
(2,840,883
)
Operating costs, excluding non-cash charges for equity-based compensation and other non-cash expenses
(203,915
)
 
(161,189
)
Segment Margin attributable to discontinued operations
2,378

 
(846
)
Other
1,150

 
775

Segment Margin
$
96,120

 
$
92,911

 
 
 
 
Volumetric Data (average barrels per day):
 
 
 
Crude oil and petroleum products sales:
 
 
 
Continuing operations
99,651

 
79,174

Discontinued operations
13,110

 
14,869

Total crude oil and petroleum products sales
112,761

 
94,043

As discussed above in “Revenues, Costs and Expenses and Net Income,” the average market prices of crude oil and petroleum products increased 4% between 2013 and 2012. Fluctuations in these prices, however, have a limited impact on our Segment Margin.
Segment Margin for our supply and logistics segment increased $3.2 million, or 3%, in 2013 as compared to 2012.
Crude and petroleum products volumes from continuing operations increased 26% in 2013. Somewhat offsetting this increase, operating costs, excluding non-cash charges, increased 27% between 2013 and 2012 primarily due to employee compensation and related benefit costs. Increases in those costs are the result of a higher number of employees from our expanded marine and trucking fleets and the recent growth in our crude oil rail loading and unloading operations. Segment Margin in 2013 was also adversely impacted by railcar rental and storage costs incurred in advance of completion dates on certain of our rail projects, ineffectiveness of hedging certain crude oil volumes and volumetric measurement losses.
    
Additionally, in the second half of 2013, fluctuations in commodity margins for some of our refined products resulted in a decision by us to postpone sales and carry products in inventory for longer periods. Our decisions, from time to time, to carry more or less product inventory than usual are often driven by dislocations in the prices/margins for the underlying commodities. While certain conditions that gave rise to challenges beginning in the third quarter of 2013 have somewhat ameliorated, the level of activity, relative to our past years of experience, has not fully recovered, resulting in lower volumes handled at reduced margins. We continue to monitor developments in the market for these products and will endeavor to transition our business accordingly. However, given these changing fundamentals, our operations are having to transition from a level and structure designed to operate within historical market conditions in terms of costs, size and type of activity. As a result of this changing operating environment, our Segment Margin has been negatively impacted for the last two quarters. We expect this negative impact to continue at least through the first quarter of 2014, during which either market fundamentals return to more historical norms, or we transition our scale, cost structure and type of activity to adapt to newly defined market fundamentals.
Segment Margin also increased due to the recent acquisition of our offshore marine transportation business and the contribution from our crude oil rail loading and unloading operations completed in the second half of 2012 and early 2013.

43


Table of Contents

Other Costs and Interest
General and administrative expenses 
 
Year Ended December 31,
 
2013
 
2012
 
(in thousands)
General and administrative expenses not separately identified below:
 
 
 
Corporate
$
28,517

 
$
30,753

Segment
3,302

 
3,291

Equity-based compensation plan expense
9,180

 
6,114

Third party costs related to business development activities and growth projects
5,791

 
1,679

Total general and administrative expenses
$
46,790

 
$
41,837

Total general and administrative expenses increased $5 million between 2013 and 2012, primarily due to increases in third party costs related to business and growth transactions. Third party costs related to business development activities and growth projects increased $4.1 million due to the acquisition of our offshore marine transportation assets and recently completed internal growth projects. General and administrative expenses also increased due to an increase in equity-based compensation plan expenses not included in Segment Margin. Increases in the market price of our common units resulted in increased expenses related to our equity-based compensation plans. The market price of our common units at December 31, 2013 was $52.57 compared to $35.72 at December 31, 2012, representing a 47% increase.
Depreciation and amortization expense  
 
Year Ended December 31,
 
2013
 
2012
 
(in thousands)
Depreciation on fixed assets
$
46,325

 
$
37,382

Amortization of intangible assets
14,560

 
19,930

Amortization of CO2 volumetric production payments
3,899

 
3,838

Total depreciation and amortization expense
$
64,784

 
$
61,150

Total depreciation and amortization expense increased $3.6 million between 2013 and 2012 primarily as a result of an increasing asset base, partially offset by decreases in amortization of intangible assets. Depreciation expense increased $8.9 million primarily as a result of the acquisition of our offshore marine transportation assets and recently completed internal growth projects. Amortization of intangible assets decreased $5.4 million. A significant portion of our intangible assets were acquired in 2007 and are being amortized in relation to the benefit they provide to future cash flows, which is typically greater in the years closer to the period of acquisition.

Interest expense, net 
 
Year Ended December 31,
 
2013
 
2012
 
(in thousands)
Interest expense, senior secured credit facility (including commitment fees)
$
11,949

 
$
14,199

Interest expense, senior unsecured notes
45,619

 
26,578

Amortization and write-off of debt issuance costs and premium
4,339

 
4,037

Capitalized interest
(13,324
)
 
(3,891
)
Net interest expense
$
48,583

 
$
40,923

Net interest expense increased $7.7 million during 2013. In February 2013, we issued an additional $350 million of aggregate principal amount of 5.75% senior unsecured notes to repay borrowings under our senior secured credit facility. Capitalized interest costs, which increased due to our capital expenditures and investments in the SEKCO pipeline joint venture (see below for more information), partially offset the increase in interest expense.    

44


Table of Contents

Year Ended December 31, 2012 Compared with Year Ended December 31, 2011
Pipeline Transportation Segment

In January 2012, we acquired from Marathon Oil Company interests in several Gulf of Mexico crude oil pipeline systems. The acquired pipeline interests include a 28% interest in Poseidon Oil Pipeline Company, L.L.C., a 100% interest in Marathon Offshore Pipeline, LLC (subsequently re-named GEL Offshore Pipeline, LLC, or “GOPL”) and a 29% interest in Odyssey Pipeline L.L.C. GOPL owns a 23% interest in the Eugene Island crude oil pipeline system and a 100% interest in two smaller offshore pipelines. The purchase price, net of post-closing adjustments, was $205.6 million. We funded the purchase price with cash available under our credit facility.    
Operating results and volumetric data for our pipeline transportation segment are presented below: 
 
Year Ended December 31,
 
2012
 
2011
 
(in thousands)
Crude oil tariffs and revenues from direct financing leases—onshore crude oil pipelines
$
31,931

 
$
24,870

Segment Margin from offshore crude oil pipelines, including pro-rata share of distributable cash from equity investees
38,500

 
15,772

CO2 tariffs and revenues from direct financing leases of CO2 pipelines
26,603

 
26,334

Sales of crude oil pipeline loss allowance volumes
9,165

 
7,756

Onshore pipeline operating costs, excluding non-cash charges for equity-based compensation and other non-cash expenses
(15,607
)
 
(12,222
)
Payments received under direct financing leases not included in income
5,016

 
4,615

Other
931

 
783

Segment Margin
$
96,539

 
$
67,908

 
 
 
 
Volumetric Data (average barrels/day unless otherwise noted):
 
 
 
Onshore crude oil pipelines:
 
 
 
Texas
51,880

 
45,183

Jay
22,306

 
16,900

Mississippi
18,711

 
20,629

Onshore crude oil pipelines total
92,897

 
82,712

 
 
 
 
Offshore crude oil pipelines:
 
 
 
CHOPS (1) (2)
96,664

 
120,723

Poseidon (1) (2)
211,375

 

Odyssey (1) (2)
36,157

 

GOPL (2)
15,191

 

Offshore crude oil pipelines total
359,387

 
120,723

 
 
 
 
CO2 pipeline (average Mcf/day):
 
 
 
Free State
186,479

 
169,962

(1) Volumes for our equity method investees are presented on a 100% basis.
(2) Acquired in January 2012.
During 2012, crude oil volumes shipped on our Texas System and Jay System increased 6,697 barrels per day (or 15%) and 5,406 barrels per day (or 32%), respectively. Volumes on our Texas System increased primarily as a result of increased demand by one of the refiners connected to our system with capabilities for processing light crude oil such as that being produced in the Eagle Ford Shale area. Additional barrels received at our new crude-by-rail unloading terminal at Walnut Hill, Florida, increased volumes on the Jay System. On CHOPS, crude oil volumes declined 24,059 barrels per day (or 20%) during 2012 due to ongoing improvements being made by producers at several connected fields. Improvements at

45


Table of Contents

those fields were substantially completed late in the third quarter of 2012, and total throughput levels on the pipeline have returned to levels last seen in the first quarter of 2011.
    
Segment Margin for our pipeline transportation segment increased $28.6 million, or 42%, in 2012 as compared to 2011. The significant components of this change were as follows:

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.

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.

Onshore crude oil pipeline loss allowance volumes, collected and sold, 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.
Refinery Services Segment
Operating results for our refinery services segment were as follows: 
 
Year Ended December 31,
 
2012
 
2011
Volumes sold (in DST):
 
 
 
NaHS volumes
142,712

 
147,670

NaOH (caustic soda) volumes
77,492

 
99,702

Total
220,204

 
247,372

 
 
 
 
Revenues (in thousands):
 
 
 
NaHS revenues
$
153,689

 
$
152,422

NaOH (caustic soda) revenues
44,322

 
47,339

Other revenues
7,099

 
10,633

Total external segment revenues
$
205,110

 
$
210,394

 
 
 
 
Segment Margin (in thousands)
$
72,883

 
$
74,618

 
 
 
 
Average index price for NaOH per DST (1)
$
575

 
$
513

Raw material and processing costs as % of segment revenues
48
%
 
48
%
 
(1)
Source: IHS Chemical

Refinery services Segment Margin for 2012 decreased $1.7 million, or 2%, from 2011. The significant components of this fluctuation were as follows:

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.

46


Table of Contents


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.

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.

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.
Supply and Logistics Segment
Operating results for our supply and logistics segment were as follows:
 
Year Ended December 31,
 
2012
 
2011
 
(in thousands)
Supply and logistics revenue
$
3,095,054

 
$
2,173,896

Crude oil and products costs, excluding unrealized gains and losses from derivative transactions
(2,840,883
)
 
(1,993,459
)
Operating costs, excluding non-cash charges for equity-based compensation and other non-cash expenses
(161,189
)
 
(121,012
)
Segment Margin attributable to discontinued operations
(846
)
 
(156
)
Other
775

 
706

Segment Margin
$
92,911

 
$
59,975

 
 
 
 
Volumetric Data (average barrels per day):
 
 
 
Crude oil and petroleum products:
 
 
 
Continuing operations
79,174

 
56,903

Discontinued operations
14,869

 
14,140

Total crude oil and petroleum products
94,043

 
71,043


As discussed above in “Revenues, Costs and Expenses and Net Income,” the average market prices of crude oil and petroleum products were consistent between 2012 and 2011. Fluctuations in these prices, however, have a limited impact on our Segment Margin.
    
Segment Margin for our supply and logistics segment increased $32.9 million, or 55%, in 2012 as compared to 2011. The increase in Segment Margin resulted primarily from the contribution of the black oil barge transportation assets that we acquired in August 2011 and February 2012 and increased volumes handled by our expanded trucking, rail and barge fleets. Our volumes of crude oil and petroleum products from continuing operations increased by 39% primarily as a result of these expansions. Our operating costs from continuing, excluding non-cash charges, increased 33% between the two periods due to our expanded trucking, rail and barge fleets and increased utilization of such fleets.


47


Table of Contents

Other Costs and Interest
General and administrative expenses 
 
Year Ended December 31,
 
2012
 
2011
 
(in thousands)
General and administrative expenses not separately identified below:
 
 
 
Corporate
$
30,753

 
$
25,660

Segment
3,291

 
2,064

Equity-based compensation plan expense
6,114

 
1,758

Third party costs related to business development activities and growth projects
1,679

 
4,376

Total general and administrative expenses
$
41,837

 
$
33,858


Routine corporate and segment general and administrative expenses increased between 2012 and 2011 as a result of salary and benefits expenses associated with increases in personnel to support our growth. Additionally, increases in the market price of our common units and an increase in the number of awards outstanding due to increases in personnel affected expense related to our equity-based compensation plans. A decrease in third party costs related to business and growth transactions resulted in a decrease of approximately $2.7 million between the periods.
Depreciation and amortization expense  
    
 
Year Ended December 31,
 
2012
 
2011
 
(in thousands)
Depreciation on fixed assets
$
37,382

 
$
27,515

Amortization of intangible assets
19,930

 
30,952

Amortization of CO2 volumetric production payments
3,838

 
3,694

Total depreciation and amortization expense
$
61,150

 
$
62,161

    
Depreciation and amortization expense decreased $1 million between 2012 and 2011 primarily as a result of decreases in amortization of intangible assets, offset by an increase in depreciation expense. Amortization of intangible assets decreased $11 million as we amortize our intangible assets over the period in which we expect them to contribute to our future cash flows. Generally, the amortization we record on those assets is greater in the initial years following their acquisition because our intangible assets are generally more valuable in the first years after an acquisition. Depreciation expense increased $9.9 million primarily as a result of our recent acquisitions, including the black oil barge transportation assets in August 2011 and February 2012.

Interest expense, net 
 
Year Ended December 31,
 
2012
 
2011
 
(in thousands)
Interest expense, senior secured credit facility (including commitment fees)
$
14,199

 
$
12,976

Interest expense, senior unsecured notes
26,578

 
19,961

Amortization and write-off of debt issuance costs and premium
4,037

 
2,940

Capitalized interest
(3,891
)
 
(106
)
Net interest expense
$
40,923

 
$
35,771

    
Net interest expense increased $5.2 million during 2012, primarily as a result of increased borrowings associated with acquisitions. Interest expense on our senior unsecured notes increased $6.6 million over the same period as a result of issuing an additional $100 million of senior unsecured notes under the indenture in February 2012 to repay borrowings under our credit facility. An increase in capitalized interest costs of $3.8 million attributable to our growth capital expenditures and

48


Table of Contents

investments in the SEKCO pipeline joint venture (see below for more information) partially offset the increase in interest expense.

Other Consolidated Results
Income Taxes
A portion of our operations are owned by wholly-owned corporate subsidiaries that are taxable as corporations. As a result, a substantial portion of the income tax expense we record relates to the operations of those corporations, and will vary from period to period based on the percentage of our income or loss that is derived from those corporations. The balance of the income tax expense we record relates to state taxes imposed on our operations that are treated as income taxes under generally accepted accounting principles and foreign income taxes. During 2013 and 2012, we recorded income tax expense of $0.8 million and income tax benefit of $9.2 million, respectively. In 2011, we recorded income tax benefit of $1.2 million. The benefit during 2012 is primarily due to the reversal of $8.2 million in uncertain tax positions as a result of tax audit settlements and the expiration of statutes of limitation. The benefit during 2011 reflects a net loss for those wholly-owned corporate subsidiaries that are taxable as corporations.
Financial Measures
Segment Margin
We define Segment Margin as revenues less product costs, operating expenses (excluding non-cash charges, such as depreciation and amortization) and segment general and administrative expenses, plus our equity in distributable cash generated by our equity investees. In addition, our Segment Margin definition excludes the non-cash effects of our legacy stock appreciation rights plan and includes the non-income portion of payments received under direct financing leases. Our chief operating decision maker (our Chief Executive Officer) evaluates segment performance based on a variety of measures including Segment Margin, segment volumes where relevant and capital investment
A reconciliation of Segment Margin to income from continuing operations before income taxes is included in our segment disclosures in Note 12 to our Consolidated Financial Statements in Item 8. Our non-GAAP financial measure should not be considered as an alternative to GAAP measures such as net income, operating income, cash flow from operating activities or any other GAAP measure of liquidity or financial performance. We believe that investors benefit from having access to the same financial measures being utilized by management, lenders, analysts and other market participants.
Available Cash before Reserves
This Annual Report on Form 10-K includes the financial measure of Available Cash before Reserves, which is a “non-GAAP” measure because it is not contemplated by or referenced in accounting principles generally accepted in the U.S., also referred to as GAAP. The accompanying schedule below provides a reconciliation of this non-GAAP financial measure to its most directly comparable GAAP financial measure – net income. Our non-GAAP financial measure should not be considered as an alternative to GAAP measures such as net income, operating income, cash flow from operating activities or any other GAAP measure of liquidity or financial performance. We believe that investors benefit from having access to the same financial measures being utilized by management, lenders, analysts and other market participants.
Available Cash before Reserves, also referred to as distributable cash flow, is commonly used as a supplemental financial measure by management and by external users of financial statements, such as investors, commercial banks, research analysts and rating agencies, to assess: (1) the financial performance of our assets without regard to financing methods, capital structures, or historical cost basis; (2) the ability of our assets to generate cash sufficient to pay interest costs and support our indebtedness; (3) our operating performance and return on capital as compared to those of other companies in the midstream energy industry, without regard to financing and capital structure and (4) the viability of projects and the overall rates of return on alternative investment opportunities.
    Because Available Cash before Reserves excludes some items that affect net income or loss and because these measures may vary among other companies, the Available Cash before Reserves data presented in this Annual Report on Form 10-K may not be comparable to similarly titled measures of other companies.
Available Cash before Reserves, including applicable pro forma presentations, is a performance measure used by our management to compare cash flows generated by us to the cash distribution paid to our common unitholders. This is an important financial measure to our public unitholders since it is an indicator of our ability to provide a cash return on their investments. Among other things, this financial measure aids investors in determining whether or not we are generating cash

49


Table of Contents

flows at a level that can support a quarterly cash distribution to the partners. Lastly, Available Cash before Reserves is the quantitative standard used throughout the investment community with respect to publicly-traded partnerships.

Available Cash before Reserves is net income as adjusted for specific items, the most significant of which are the addition of certain non-cash expenses (such as depreciation and amortization), the substitution of distributable cash generated by our equity investees in lieu of our equity income attributable to our equity investees, the elimination of gains and losses on asset sales (except those from the sale of surplus assets), unrealized gains and losses on derivative transactions not designated as hedges for accounting purposes, the elimination of expenses related to acquiring or constructing assets that provide new sources of cash flows, and the subtraction of maintenance capital expenditures, which are expenditures that are necessary to sustain existing (but not to provide new sources of) cash flows.

Available Cash before Reserves for the years ended December 31, 2013, 2012 and 2011 was as follows: 
 
Year Ended December 31,
 
2013
 
2012
 
2011
 
(in thousands)
Net income
$
86,109

 
$
96,319

 
$
51,249

Depreciation and amortization
64,784

 
61,150

 
62,161

Cash received from direct financing leases not included in income
5,110

 
5,016

 
4,615

Cash effects of sales of certain assets and discontinued operations
1,910

 
773

 
6,424

Effects of distributable cash generated by equity method investees not included in income
23,889

 
24,464

 
16,681

Cash effects of legacy stock appreciation rights plan
(5,498
)
 
(3,280
)
 
(2,394
)
Non-cash legacy stock appreciation rights plan expense
5,704

 
4,478

 
311

Non-cash executive equity award expense

 
500

 

Expenses related to acquiring or constructing growth capital assets
5,791

 
1,679

 
4,376

Unrealized loss on derivative transactions excluding fair value hedges
1,313

 
86

 
724

Maintenance capital expenditures
(3,569
)
 
(4,430
)
 
(4,237
)
Non-cash tax benefit
(152
)
 
(9,222
)
 
(2,075
)
Other items, net
674

 
1,625

 
364

Available Cash before Reserves
$
186,065

 
$
179,158

 
$
138,199

Liquidity and Capital Resources
General
As of December 31, 2013, we believe our balance sheet and liquidity position remained strong. We had $405.3 million of borrowing capacity available under our $1 billion senior secured revolving credit facility. We anticipate that our future internally-generated funds and the funds available under our credit facility will allow us to meet our ordinary course capital needs. Our primary sources of liquidity have been cash flows from operations, borrowing availability under our credit facility and the proceeds from issuances of equity and senior unsecured notes.
Our primary cash requirements consist of:
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.

50


Table of Contents

Capital Resources
Our ability to satisfy future capital needs will depend on our ability to raise substantial amounts of additional capital from time to time — including through equity and debt offerings (public and private), borrowings under our credit facility and other financing transactions—and to implement our growth strategy successfully. No assurance can be made that we will be able to raise the necessary funds on satisfactory terms.
In September 2013, we issued 5,750,000 Class A common units in a public offering at a price of $47.51 per unit. We received proceeds, net of underwriting discounts and offering costs, of approximately $263.6 million from that offering. We used those net proceeds for general corporate purposes, including the repayment of borrowings under our revolving credit facility. See Note 11 to our Consolidated Financial Statements for more information.
    
Our $1 billion senior secured credit facility matures on July 25, 2017 and includes an accordion feature of $300 million, giving us the ability to expand the size of the facility up to an aggregate of $1.3 billion for acquisitions or internal growth projects, subject to lender consent. The inventory financing sublimit tranche under our senior secured credit facility is $150 million, which is designed to allow us to more efficiently finance crude oil and petroleum products inventory in the normal course of our operations, by allowing us to exclude the amount of inventory loans from our total outstanding indebtedness for purposes of determining our applicable interest rate. Our credit facility does not include a “borrowing base” limitation except with respect to our inventory loans. At any one time, we can have up to $100 million in letters of credit outstanding under our facility. We had $11.9 million in letters of credit outstanding at December 31, 2013. Due to the revolving nature of loans under our credit facility, we may make additional borrowings and periodic repayments and re-borrowings until the maturity date. At December 31, 2013, we had $582.8 million borrowed under our credit facility, with $80.8 million of the borrowed amount designated as a loan under the inventory sublimit. Thus, the total amount available for borrowings under our credit facility at December 31, 2013 was $405.3 million.
    
On February 8, 2013, we issued an additional $350 million of aggregate principal amount of 5.75% senior unsecured notes. Those notes were sold at face value. Interest payments are due on February 15 and August 15 of each year, beginning August 15, 2013. Those notes mature on February 15, 2021. The net proceeds were used to repay borrowings under our credit facility and for general partnership purposes.
    
Those notes were co-issued by Genesis Energy Finance Corporation (which has no independent assets or operations) and are fully and unconditionally guaranteed, jointly and severally, by certain of our 100%-owned subsidiaries. We have the right to redeem those notes at any time after February 15, 2017, at a premium to the face amount of the notes that varies based on the time remaining to maturity on the notes. Prior to February 15, 2016, we may also redeem up to 35% of the principal amount for 105.750% of the face amount with the proceeds from an equity offering of our common units.

At December 31, 2013, long-term debt totaled $1.3 billion, consisting of $582.8 million outstanding under our credit facility (including $80.8 million borrowed under the inventory sublimit tranche) a $350.8 million carrying amount of senior unsecured notes due on December 15, 2018 and a $350 million carrying amount of senior unsecured notes due on February 15, 2021.
For additional information on our long-term debt and covenants see Note 10 to our Consolidated Financial Statements in Item 8.
Cash Flows from Operations
We generally utilize the cash flows we generate from our operations to fund our working capital needs. Excess funds that are generated are used to repay borrowings from our credit facility and to fund capital expenditures. Our operating cash flows can be impacted by changes in items of working capital, primarily variances in the carrying amount of inventory and the timing of payment of accounts payable and accrued liabilities related to capital expenditures.
We typically sell our crude oil in the same month in which we purchase it, and we do not rely on borrowings under our credit facility to pay for such crude oil purchases, other than inventory. During such periods, our accounts receivable and accounts payable generally move in tandem as we make payments and receive payments for the purchase and sale of crude oil.
In our petroleum products activities, we buy products and typically either move the products to one of our storage facilities for further blending or we sell the product within days of our purchase. The cash requirements for these activities can result in short term increases and decreases in our borrowings under our credit facility.

51


Table of Contents

The storage of crude oil and petroleum products can have a material impact on our cash flows from operating activities. In the month we pay for the stored oil or petroleum products, we borrow under our credit facility (or use cash on hand) to pay for the oil or petroleum products, utilizing a portion of our operating cash flows. Conversely, cash flow from operating activities increases during the period in which we collect the cash from the sale of the stored crude oil or petroleum products. Additionally, we may be required to deposit margin funds with the NYMEX when prices increase as the value of the derivatives utilized to hedge the price risk in our inventory fluctuates. These deposits also impact our operating cash flows as we borrow under our credit facility or use cash on hand to fund the deposits.
Net cash flows provided by our operating activities were $138.4 million and $189.3 million for 2013 and 2012, respectively. As discussed above, changes in the cash requirements related to payment for petroleum products or collection of receivables from the sale of inventory impact the cash provided by operating activities. Additionally, changes in the market prices for crude oil and petroleum products can result in fluctuations in our working capital and therefore, our operating cash flows between periods as the cost to acquire a barrel of oil or products will require more or less cash. The decrease in operating cash flow for 2013 compared to 2012 was primarily due to an increase in working capital needs, which was partially offset by higher cash earnings.
Capital Expenditures and Distributions Paid to Our Unitholders
We use cash primarily for our operating expenses, working capital needs, debt service, acquisition activities, internal growth projects and distributions we pay to our unitholders. We finance maintenance capital expenditures and smaller internal growth projects and distributions primarily with cash generated by our operations. We have historically funded material growth capital projects (including acquisitions and internal growth projects) with borrowings under our credit facility, equity issuances and/or the issuance of senior unsecured notes.
Capital Expenditures and Business and Asset Acquisitions
The following table summarizes our expenditures for fixed assets, business and other asset acquisitions in the periods indicated:
 
Years Ended December 31,
 
2013
 
2012
 
2011
 
 
 
(in thousands)
 
 
Capital expenditures for fixed and intangible assets:
 
 
 
 
 
Pipeline transportation assets
$
130,787

 
$
59,385

 
$
7,629

Refinery services assets
3,258

 
2,692

 
1,846

Supply and logistics assets
244,994

 
94,896

 
13,846

Information technology systems
2,424

 
1,631

 
4,128

Total capital expenditures for fixed and intangible assets
381,463

 
158,604

 
27,449

Capital expenditures for business combinations, net of liabilities assumed:
 
 
 
 
 
Acquisition of offshore marine transportation assets
230,880

 

 

Offshore pipelines

 
205,576

 
194

Acquisition of FMT assets

 

 
143,479

Wyoming refinery and related pipeline

 

 
20,000

Total business combinations capital expenditures
230,880

 
205,576

 
163,673

Capital expenditures related to equity investees (1)
94,286

 
63,749

 

Total capital expenditures
$
706,629

 
$
427,929

 
$
191,122

(1)
Amount represents our investment in the SEKCO pipeline joint venture (see below for more information).
Expenditures for capital assets to grow the partnership distribution will depend on our access to debt and equity capital. We will look for opportunities to acquire assets from other parties that meet our criteria for stable cash flows.
Capital Expenditures for Acquisitions
We continue to pursue a growth strategy that requires significant capital. On August 28, 2013, we completed the acquisition of our offshore marine transportation assets, consisting of nine barges and nine tug boats for approximately $230.9 million.

52


Table of Contents

See Note 3 to our Consolidated Financial Statements in Item 8 for further information related to that acquisition.
Growth Capital Expenditures
Total capital expenditures on projects currently under construction, and disclosed in the following discussion, are estimated to be approximately $500 million, inclusive of capital expenditures incurred in prior quarters. We anticipate that approximately $260 million of that total will be spent in 2014.
ExxonMobil Baton Rouge Project
We are improving existing assets and developing 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 24-inch diameter crude oil pipeline connecting Port Hudson to the Baton Rouge Scenic Station and continuing downstream to the Anchorage Tank Farm and building a new crude oil unit train unload facility at Scenic Station. The Port Hudson upgrades and new crude oil pipeline are expected to be completed by the end of the first quarter of 2014, and Scenic Station is expected to be completed in the second quarter of 2014.
Baton Rouge Terminal
We recently announced plans to construct a new crude oil, intermediates and refined products import/export terminal in Baton Rouge. The terminal will be located near the Port of Greater Baton Rouge and will be pipeline-connected to that port's existing deepwater docks on the Mississippi River. We will initially construct approximately 1.1 million barrels of tankage for the storage of crude oil, intermediates and/or refined products with the capability to expand to provide additional terminaling services to our customers. Our Baton Rouge Terminal will also be pipeline-connected to ExxonMobil facilities in the area, as well as to Scenic Station. Shippers to Scenic Station will have access to both the local Baton Rouge refining market, as well as the ability to access other attractive refining markets via our Baton Rouge Terminal. The Baton Rouge Terminal is expected to be completed by the end of the second quarter of 2015.
Rail Projects    
Walnut Hill - In the first quarter of 2013, we completed construction on the second phase of our crude-by-rail unloading terminal at Walnut Hill, Florida, which includes a 100,000 barrel storage tank and related equipment and connections to our Jay System. This facility provides the capability of handling unit train shipments for direct deliveries to an existing refinery customer and indirect deliveries (through third-party common carriers) to multiple other markets in the Southeast at the option of the shippers. We have commenced construction on an additional tank at that site with 110,000 barrels of capacity, which will allow us to handle increased rail and pipeline demand. We estimate this tank will be fully operational by the end of the first quarter of 2014.
Wink - In 2012, we completed the initial phase construction of a crude oil rail loading facility in Wink, Texas, which was designed to move crude oil from West Texas to other markets and giving us the capability to load Genesis and third party railcars. Construction on the second phase of that facility, which we estimate will be operational by the end of the first quarter of 2014, will allow us to more efficiently load full unit trains.
Natchez - In the third quarter of 2013, we completed construction on a crude oil rail unloading/loading facility at our existing terminal located in Natchez, Mississippi, which is designed to facilitate the movement of Canadian bitumen/dilbit to Gulf Coast markets. That facility has the capability to unload bitumen/dilbit as well as load diluent for backhauls to Canada. We have initiated construction on the second phase of the Natchez facility, which will provide an additional 60 railcar spots and additional heated tanks. We expect to complete that rail unloading/loading facility expansion by the end of the first quarter of 2014.
Raceland - In the fourth quarter of 2013, we began construction on a new crude oil unit train unloading facility capable of unloading up to two unit trains per day, which is located in Raceland, Louisiana. The Raceland Rail Facility will be connected to existing midstream infrastructure that will provide direct pipeline access to refineries from the Baton Rouge area to the Gulf of Mexico and is expected to be operational in the fourth quarter of 2014.

Capital Expenditures Related to Equity Investees
    
SEKCO, our 50/50 joint venture with Enterprise Products expects to place in-service in mid-2014 its deepwater pipeline serving the Lucius oil and gas field in the southern Keathley Canyon area of the Gulf of Mexico. We have budgeted approximately $200 million for our cumulative share of the pipeline construction through 2014. In 2013 and 2012, we contributed $94.3 million and $63.7 million, respectively, to SEKCO that was used to fund our share of the construction costs incurred during those years. Most cost overruns and other costs incurred associated with weather-related delays will be the responsibility of the producers that have entered into transportation agreements with us.

53


Table of Contents


Maintenance Capital Expenditures
Maintenance capital expenditures have annually ranged between $3 million and $5 million. As we place more assets into service, our maintenance capital expenditures may increase in future years.
Distributions to Unitholders
Our partnership agreement requires us to distribute 100% of our available cash (as defined therein) within 45 days after the end of each quarter to unitholders of record. Available cash consists generally of all of our cash receipts less cash disbursements adjusted for net changes to reserves. We have increased our distribution for each of the last thirty-four quarters, including the distribution paid for the fourth quarter of 2013, as shown in the table below (in thousands, except per unit amounts). Each quarter, our board of directors determines the distribution amount, or available cash, per unit based upon various factors such as our operating performance, cash on hand, future cash requirements and the economic environment. As a result, the historical trend of distribution increases may not be a good indicator of future increases. 
Distribution For
 
Date Paid
 
Per Unit
Amount
 
Total
Amount
2011
 
 
 
 
 
 
4th Quarter
 
February 14, 2012
 
$
0.4400

 
$
31,677

2012
 
 
 
 
 
 
1st Quarter
 
May 15, 2012
 
$
0.4500

 
$
35,768

2nd Quarter
 
August 14, 2012
 
$
0.4600

 
$
36,563

3rd Quarter
 
November 14, 2012
 
$
0.4725

 
$
38,375

4th Quarter
 
February 14, 2013
 
$
0.4850

 
$
39,390

2013
 
 
 
 
 
 
1st Quarter
 
May 15, 2013
 
$
0.4975

 
$
40,405

2nd Quarter
 
August 14, 2013
 
$
0.5100

 
$
42,302

3rd Quarter
 
November 14, 2013
 
$
0.5225

 
$
46,344

4th Quarter
 
February 14, 2014
(1) 
$
0.5350

 
$
47,453


(1)
This distribution was paid on February 14, 2014 to unitholders of record as of January 31, 2014.

Commitments and Off-Balance Sheet Arrangements
Contractual Obligations and Commercial Commitments
In addition to our credit facility discussed above, we have contractual obligations under operating leases as well as commitments to purchase crude oil and petroleum products. The table below summarizes our obligations and commitments at December 31, 2013.
 
 
Payments Due by Period
Commercial Cash Obligations and
Commitments
Less than
one year
 
1 - 3 years
 
3 - 5 Years
 
More than
5 years
 
Total
 
(in thousands)
Contractual Obligations:
 
 
 
 
 
 
 
 
 
Long-term debt (1)
$

 
$

 
$
582,800

 
$
700,772

 
$
1,283,572

Estimated interest payable on long-term debt (2)
72,457

 
144,981

 
108,206

 
42,766

 
368,410

Operating lease obligations
30,501

 
42,259

 
28,596

 
48,824

 
150,180

Unconditional purchase obligations (3)
484,163

 
132,528

 

 

 
616,691

Other Cash Commitments:
 
 
 
 
 
 
 
 
 
Asset retirement obligations (4)

 

 

 
32,515

 
32,515

Total
$
587,121

 
$
319,768

 
$
719,602
</