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, 2018
OR
[    ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from                                          to                                         
Commission File Number 1-16417
NS2018LOGO.JPG
NUSTAR ENERGY L.P.
(Exact name of registrant as specified in its charter)
Delaware
 
74-2956831
(State or other jurisdiction of incorporation or organization)
 
(I.R.S. Employer Identification No.)
 
 
 
19003 IH-10 West
 
78257
San Antonio, Texas
 
(Zip Code)
(Address of principal executive offices)
 
 
Registrant’s telephone number, including area code (210) 918-2000
Securities registered pursuant to Section 12(b) of the Act: Common units representing limited partner interests listed on the New York Stock Exchange. 8.50% Series A, 7.625% Series B and 9.00% Series C Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units representing limited partner interests listed on the New York Stock Exchange.
Securities registered pursuant to 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 [  ]
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 [  ] 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 [  ]
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes [X] No [ ]
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) 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. [X]
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act: 
Large accelerated filer
 
[X]
  
Accelerated filer
 
[    ]
 
 
 
 
Non-accelerated filer
 
[    ] 
  
Smaller reporting company
 
[    ]
 
 
 
 
 
 
 
 
 
 
 
Emerging growth company
 
[    ]
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.  [ ]    
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes [    ] No [X]
The aggregate market value of the common units held by non-affiliates was approximately $1.8 billion based on the last sales price quoted as of June 29, 2018 , the last business day of the registrant’s most recently completed second quarter.
The number of common units outstanding as of January 31, 2019 was 107,278,252 .
DOCUMENTS INCORPORATED BY REFERENCE:
Portions of the Proxy Statement for the registrant’s 2019 annual meeting of unitholders, expected to be filed within 120 days after the end of the fiscal year covered by this Form 10-K, are incorporated by reference into Part III to the extent described therein.


Table of Contents

NUSTAR ENERGY L.P.
FORM 10-K

TABLE OF CONTENTS
 
PART I
Items 1., 1A. & 2.
 
 
 
 
 
 
 
 
 
 
 
 
Item 1B.
 
 
 
Item 3.
 
 
 
Item 4.
 
PART II
Item 5.
 
 
 
Item 6.
 
 
 
Item 7.
 
 
 
Item 7A.
 
 
 
Item 8.
 
 
 
Item 9.
 
 
 
Item 9A.
 
 
 
Item 9B.
 
PART III
Item 10.
 
 
 
Item 11.
 
 
 
Item 12.
 
 
 
Item 13.
 
 
 
Item 14.
 
PART IV
Item 15.
 
 
Item 16.
 
 



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Table of Contents

PART I

Unless otherwise indicated, the terms “NuStar Energy,” “the Partnership,” “we,” “our” and “us” are used in this report to refer to NuStar Energy L.P., to one or more of our consolidated subsidiaries or to all of them taken as a whole.

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION
In this Form 10-K, we make certain forward-looking statements, including statements regarding our plans, strategies, objectives, expectations, estimates, predictions, projections, assumptions, intentions and resources. While these forward-looking statements, and any assumptions upon which they are based, are made in good faith and reflect our current judgment regarding the direction of our business, actual results will almost always vary, sometimes materially, from any estimates, predictions, projections, assumptions or other future performance suggested in this report. These forward-looking statements can generally be identified by the words “anticipates,” “believes,” “expects,” “plans,” “intends,” “estimates,” “forecasts,” “budgets,” “projects,” “will,” “could,” “should,” “may” and similar expressions. These statements reflect our current views with regard to future events and are subject to various risks, uncertainties and assumptions, which may cause actual results to differ materially. Please read Item 1A. “Risk Factors” for a discussion of certain of those risks, uncertainties and assumptions.

If one or more of these risks or uncertainties materialize, or if the underlying assumptions prove incorrect, our actual results may vary materially from those described in any forward-looking statement. Other unknown or unpredictable factors could also have material adverse effects on our future results. Readers are cautioned not to place undue reliance on this forward-looking information, which is as of the date of this Form 10-K. We do not intend to update these statements unless we are required by the securities laws to do so, and we undertake no obligation to publicly release the result of any revisions to any such forward-looking statements that may be made to reflect events or circumstances after the date of this report or to reflect the occurrence of unanticipated events.

ITEMS 1., 1A. and 2.
BUSINESS, RISK FACTORS AND PROPERTIES

OVERVIEW
NuStar Energy L.P. (NuStar Energy), a Delaware limited partnership, was formed in 1999 and completed its initial public offering of common units on April 16, 2001. Our common units trade on the New York Stock Exchange (NYSE) under the symbol “NS,” and our fixed-to-floating rate cumulative redeemable perpetual preferred units trade on the NYSE under the symbol “NSprA” for our 8.50% Series A Preferred Units, “NSprB” for our 7.625% Series B Preferred Units and “NSprC” for our 9.00% Series C Preferred Units. Our principal executive offices are located at 19003 IH-10 West, San Antonio, Texas 78257 and our telephone number is (210) 918-2000.
We are engaged in the transportation of petroleum products and anhydrous ammonia, and the terminalling, storage and marketing of petroleum products. The term “throughput” as used in this document generally refers to barrels of crude oil or refined product or tons of ammonia, as applicable, that pass through our pipelines, terminals or storage tanks.
We divide our operations into the following three reportable business segments: pipeline, storage and fuels marketing. As of December 31, 2018 , our assets included approximately 9,800 miles of pipeline and 75 terminal and storage facilities, which provide approximately 88 million barrels of storage capacity. The following table summarizes operating income for each of our business segments:
 
Year Ended
December 31, 2018
 
(Thousands of Dollars)
Pipeline
$
272,695

Storage
$
181,471

Fuels marketing
$
24,440

We conduct our operations through our wholly owned subsidiaries, primarily NuStar Logistics, L.P. (NuStar Logistics) and NuStar Pipeline Operating Partnership L.P. (NuPOP). Our revenues include:
tariffs for transporting crude oil, refined products and anhydrous ammonia through our pipelines;
fees for the use of our terminal and storage facilities and related ancillary services; and
sales of petroleum products.

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We strive to increase unitholder value by:
enhancing our existing assets through strategic internal growth projects that expand our business with current and new customers;
pursuing strategic projects to expand and optimize our existing assets and to construct new assets;
improving our operations, including safety and environmental stewardship, cost control and asset reliability; and
identifying strategic acquisition targets that meet our financial criteria.

Our internet website address is http://www.nustarenergy.com . Information contained on our website is not part of this report. Our annual reports on Form 10-K, quarterly reports on Form 10-Q and current reports on Form 8-K filed with (or furnished to) the Securities and Exchange Commission (SEC) are available on our website, free of charge, as soon as reasonably practicable after we file or furnish such material (select the “Investors” link, then the “SEC Filings” link). We also post our corporate governance guidelines, code of business conduct and ethics, code of ethics for senior financial officers and the charters of our board’s committees on our website free of charge (select the “Investors” link, then the “Corporate Governance” link).

Our governance documents are available in print to any unitholder that makes a written request to Corporate Secretary, NuStar Energy L.P., 19003 IH-10 West, San Antonio, Texas 78257 or corporatesecretary@nustarenergy.com.


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RECENT DEVELOPMENTS

In early 2018, we launched a comprehensive plan to achieve the characteristics now demanded by the master limited partnership market: simplified corporate governance with no incentive distribution rights, minimal equity capital needs, lower leverage and strong distribution coverage. Over the course of the year, we executed our plan, by, among other things, selling our European operations, completing the Merger and issuing the Series D Preferred Units, all discussed in more detail below. We accomplished our objectives and believe we now have the financial flexibility to allow for strong, stable growth.

Sale of European Operations. On November 30, 2018, we sold our European operations to Inter Terminals, Ltd. for approximately $270.0 million . The operations sold include six liquids storage terminals in the United Kingdom and one facility in Amsterdam . Please refer to Note 5 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for further discussion of the sale.

Merger. On February 7, 2018, NuStar Energy, Riverwalk Logistics, L.P., NuStar GP, LLC, Marshall Merger Sub LLC, a wholly owned subsidiary of NuStar Energy (Merger Sub), Riverwalk Holdings, LLC and NuStar GP Holdings, LLC (NuStar GP Holdings) entered into an Agreement and Plan of Merger (the Merger Agreement). Pursuant to the Merger Agreement, Merger Sub merged with and into NuStar GP Holdings, with NuStar GP Holdings being the surviving entity (the Merger), such that NuStar Energy became the sole member of NuStar GP Holdings following the Merger on July 20, 2018. Pursuant to the Merger Agreement and at the effective time of the Merger, our partnership agreement was amended and restated to, among other things, (i) cancel the incentive distribution rights held by our general partner, (ii) convert the 2% general partner interest in NuStar Energy held by our general partner into a non-economic management interest and (iii) provide the holders of our common units with voting rights in the election of the members of the board of directors of NuStar GP, LLC, beginning at the annual meeting in 2019. We issued approximately 13.4 million incremental NuStar Energy common units as a result of the Merger. Please refer to the following two pages for organizational charts at December 31, 2018 and before the Merger and Note 4 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for further discussion.

Issuances of Units. In June and July of 2018, we issued 23,246,650 Series D Cumulative Convertible Preferred Units at a price of $25.38 per unit in a private placement for net proceeds of $555.8 million . Please refer to Note 19 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for further discussion. On June 29, 2018, we also issued 413,736 common units at a price of $24.17 per unit to William E. Greehey, Chairman of the Board of Directors of NuStar GP, LLC.

Council Bluffs Acquisition. On April 16, 2018, we acquired CHS Inc.’s Council Bluffs pipeline system, comprised of a 227-mile pipeline and 18 storage tanks, for approximately $37.5 million . The assets acquired and the results of operations are included in our pipeline segment, within the East Pipeline, from the date of acquisition. We accounted for this acquisition as an asset purchase.

Hurricane Activity. In the third quarter of 2017, several of our facilities were affected by the hurricanes in the Caribbean and Gulf of Mexico, including our St. Eustatius terminal, which experienced the most damage and was temporarily shut down. The damage caused by the Caribbean hurricane resulted in lower revenues for our bunker fuel operations in our fuels marketing segment and lower throughput and associated handling fees in our storage segment in 2017 and in the first quarter of 2018. In 2017, we recorded a $5.0 million loss in “Other income (expense), net” in the consolidated statements of income for property damage at the terminal, which represents the amount of our property deductible under our insurance policy, and we received $12.5 million of insurance proceeds, of which $3.8 million was for business interruption. In January 2018, we received $87.5 million of insurance proceeds in settlement of our property damage claim for our St. Eustatius terminal, of which $9.1 million related to business interruption. Although the repairs are not complete, we expect that the costs to repair the property damage at the terminal will not exceed the amount of insurance proceeds received. Please refer to Note 1 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for further discussion.

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ORGANIZATIONAL STRUCTURE

As a result of the Merger, NuStar GP Holdings, which indirectly owns our general partner, became a wholly owned subsidiary of ours on July 20, 2018. The following chart depicts a summary of our organizational structure at December 31, 2018 :

A123118ORGCHART.JPG









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The following chart depicts a summary of our organizational structure prior to the Merger on July 20, 2018, which is further described in Note 4 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data”:
A63018ORGCHART.JPG










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SEGMENTS
Detailed financial information about our segments is included in Note 26 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data.” The following map depicts our assets at December 31, 2018 :

A10KMAP2.JPG
PIPELINE
Our pipeline operations consist of the transportation of refined products, crude oil and anhydrous ammonia. As of December 31, 2018 , we owned and operated:
refined product pipelines with an aggregate length of 3,130 miles and crude oil pipelines with an aggregate length of 2,070 miles in Texas, Oklahoma, Kansas, Colorado and New Mexico (collectively, the Central West System);
a 2,150 -mile refined product pipeline originating in southern Kansas and terminating at Jamestown, North Dakota, with a western extension to North Platte, Nebraska and an eastern extension into Iowa (the East Pipeline);
a 450 -mile refined product pipeline originating at Marathon Petroleum Corporation’s (Marathon) Mandan, North Dakota refinery and terminating in Minneapolis, Minnesota (the North Pipeline); and
a 2,000 -mile anhydrous ammonia pipeline originating in the Louisiana delta area that travels north through the Midwestern United States to Missouri before forking east and west to terminate in Indiana and Nebraska (the Ammonia Pipeline).

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The following table lists information about our pipeline assets as of December 31, 2018 :
 
 
 
 
 
Throughput
For the year ended December 31,
Region / Pipeline System
Length
 
Tank Capacity
 
2018
 
2017
 
(Miles)
 
(Barrels)
 
(Barrels/Day)
Central West System:
 
 
 
 
 
 
 
McKee System
2,276

 

 
193,396

 
171,815

Three Rivers System
373

 

 
81,174

 
78,165

Other
481

 

 
51,130

 
53,829

Central West Refined Products Pipelines
3,130

 

 
325,700

 
303,809

South Texas Crude System
328

 
2,157,000

 
144,976

 
114,920

Other
200

 

 
70,251

 
52,969

Eagle Ford System
528

 
2,157,000

 
215,227

 
167,889

McKee System
598

 
1,039,000

 
154,718

 
137,675

Ardmore System
119

 
824,000

 
70,967

 
84,801

Permian Crude System
825

 
1,000,000

 
435,743

 
192,958

Central West Crude Oil Pipelines
2,070

 
5,020,000

 
876,655

 
583,323

Total Central West System
5,200

 
5,020,000

 
1,202,355

 
887,132

 
 
 
 
 
 
 
 
Central East System:
 
 
 
 
 
 
 
East Pipeline
2,150

 
5,851,000

 
150,635

 
139,317

North Pipeline
450

 
1,494,000

 
50,180

 
41,438

Ammonia Pipeline
2,000

 

 
30,529

 
32,172

Total Central East System
4,600

 
7,345,000

 
231,344

 
212,927

 
 
 
 
 
 
 
 
Total
9,800

 
12,365,000

 
1,433,699

 
1,100,059

Description of Pipelines
Central West System. The Central West System covers a total of 5,200 miles, including refined product and crude oil pipelines. The refined product pipelines have an aggregate length of 3,130 miles (Central West Refined Products Pipelines) and transport gasoline, distillates (including diesel and jet fuel), natural gas liquids and other products produced at the refineries to which they are connected, including Valero Energy Corporation’s (Valero Energy) McKee and Three Rivers refineries.
The crude oil pipelines have an aggregate length of 2,070 miles (Central West Crude Oil Pipelines). Our crude oil pipelines transport crude oil and other feedstocks to the refineries to which they are connected, including Valero Energy’s McKee, Three Rivers and Ardmore refineries, or from the Eagle Ford Shale region to our North Beach marine export terminal and to third-party refineries in Corpus Christi, Texas.
Our Permian Crude System, which is comprised of the assets we acquired in May 2017, together with the assets we have constructed through various expansion projects since the date of the acquisition, consists of crude oil transportation, pipeline connection and storage assets located in the Midland Basin of West Texas. The Permian Crude System is an interconnected system that aggregates receipts from wellhead connection lines into intra-basin trunk lines for delivery to regional hubs and to connections with third-party mainline takeaway pipelines. The system consists of 825 miles of pipelines and covers over 500,000 dedicated acres owned by producers, with approximately 200 well-connection sites. The Permian Crude System also includes two terminals, at Big Spring and Colorado City, as well as several truck stations and other operational storage facilities, with an aggregate storage capacity of 1.0 million barrels.

Central East System. The Central East System covers a total of 4,600 miles and consists of the East Pipeline, North Pipeline and Ammonia Pipeline.

The East Pipeline covers 2,150 miles and transports refined products and natural gas liquids north via pipelines to our terminals and third-party terminals along the system and to receiving pipeline connections in Kansas. Shippers on the East Pipeline

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obtain refined products from refineries in Kansas, Oklahoma and Texas. The East Pipeline system includes 18 truck-loading terminals, with storage capacity of approximately 4.4 million barrels and two tank farms with storage capacity of approximately 1.4 million barrels at McPherson and El Dorado, Kansas.

The North Pipeline originates at Marathon’s Mandan, North Dakota refinery and runs from west to east for approximately 450 miles to its termination in the Minneapolis, Minnesota area. The North Pipeline system includes four truck-loading terminals with storage capacity of approximately 1.5 million barrels.
The 2,000 -mile Ammonia Pipeline originates in the Louisiana delta area, where it connects to three third-party marine terminals and three anhydrous ammonia plants on the Mississippi River. The line runs north through Louisiana and Arkansas into Missouri, where at Hermann, Missouri it splits and one branch goes east into Illinois and Indiana, while the other branch continues north into Iowa and then turns west into Nebraska. The Ammonia Pipeline is connected to multiple third-party-owned terminals, which include industrial facility delivery locations. Product is supplied to the pipeline from anhydrous ammonia plants in Louisiana and imported product delivered through the marine terminals. Anhydrous ammonia is primarily used as agricultural fertilizer. It is also used as a feedstock to produce other nitrogen derivative fertilizers and explosives.
Pipeline Operations
We charge tariffs on a per barrel basis for transporting refined products, crude oil and other feedstocks in our refined product and crude oil pipelines and on a per ton basis for transporting anhydrous ammonia in the Ammonia Pipeline. Revenues earned at storage facilities included with these pipeline systems predominately relate to the volumes transported on the pipelines through fees included in the respective pipeline tariff. As a result, these storage facilities are included in this segment instead of the storage segment.
In general, shippers on our crude oil and refined product pipelines deliver petroleum products to our pipelines for transport to/from: (i) refineries that connect to our pipelines, (ii) third-party pipelines or terminals and (iii) our terminals for further delivery to marine vessels or pipelines. We charge our shippers tariff rates based on transportation from the origination point on the pipeline to the point of delivery.
Our pipelines are subject to federal regulation by one or more of the following governmental agencies: the Federal Energy Regulatory Commission (the FERC), the Surface Transportation Board (the STB), the Department of Transportation (the DOT), the Environmental Protection Agency (the EPA) and the Department of Homeland Security. Additionally, our pipelines are subject to the respective state jurisdictions. See “Rate Regulation” and “Environmental, Health, Safety and Security Regulation” below for additional discussion.
The majority of our pipelines are common carrier. Common carrier activities are those for which transportation through our pipelines is available to any shipper who requests such services and satisfies the conditions and specifications for transportation. Published tariffs are (i) filed with the FERC for interstate petroleum product shipments, (ii) filed with the relevant state authority for intrastate petroleum product shipments or (iii) regulated by the STB for our Ammonia Pipeline.
We operate our pipelines remotely through an operational technology system called the Supervisory Control and Data Acquisition, or SCADA, system.
Demand for and Sources of Refined Products and Crude Oil
Throughputs on our Central West Refined Product Pipelines and the East and North Pipelines depend on the level of demand for refined products in the markets served by those pipelines, as well as the ability and willingness of the refiners and marketers with access to the pipelines to supply that demand through our pipelines.
The majority of the refined products delivered through the Central West Refined Product Pipelines and the North Pipeline are gasoline and diesel fuel that originate at refineries connected to our pipelines. Demand for motor fuels fluctuates as prices for these products fluctuate. Prices fluctuate for a variety of reasons, including the overall balance in supply and demand, which is affected by general economic conditions, among other factors. Prices for gasoline and diesel fuel tend to increase in the warm weather months when people tend to drive automobiles more often and for longer distances.
Much of the refined products and natural gas liquids delivered through the East Pipeline and a portion of volumes on the North Pipeline are ultimately used as fuel for railroads, ethanol denaturant or in agricultural operations, including fuel for farm equipment, irrigation systems, trucks used for transporting crops and crop-drying facilities. Demand for refined products for agricultural use, and the relative mix of products required, is affected by weather conditions in the markets served by the East and North Pipelines. The agricultural sector is also affected by government agricultural policies and crop prices. Although periods of drought suppress agricultural demand for some refined products, particularly those used for fueling farm equipment, the demand for fuel for irrigation systems often increases during such times. The mix of refined products delivered for

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agricultural use varies seasonally, with gasoline demand peaking in early summer, diesel fuel demand peaking in late summer and propane demand higher in the fall.
Our refined product pipelines are also dependent upon adequate levels of production of refined products by refineries connected to the pipelines, directly or through connecting pipelines. The refineries are, in turn, dependent upon adequate supplies of suitable grades of crude oil. Certain of our Central West Refined Products Pipelines are subject to long-term throughput agreements with Valero Energy. Valero Energy refineries connected directly to our pipelines obtain crude oil from a variety of foreign and domestic sources. If operations at one of these refineries were discontinued or significantly reduced, it could have a material adverse effect on our operations, although we would endeavor to minimize the impact by seeking alternative customers for those pipelines.
The North Pipeline is heavily dependent on Marathon’s Mandan, North Dakota refinery, which primarily runs North Dakota crude oil (although it has the ability to process other crude oils), and an interruption in operations at the Marathon refinery could have a material adverse effect on our operations. The majority of the refined products transported through the East Pipeline are produced at three refineries located at McPherson and El Dorado, Kansas and Ponca City, Oklahoma, which are operated by CHS Inc., HollyFrontier Corporation and Phillips 66, respectively. The East Pipeline also has access to Gulf Coast supplies of products through third-party connecting pipelines that receive products originating from Gulf Coast refineries.
Other than the Valero Energy refineries and the Marathon refinery described above, if operations at any one refinery were discontinued, we believe (assuming stable demand for refined products in markets served by the refined product pipelines) that the effects thereof would be short-term in nature and our business would not be materially adversely affected over the long-term because such discontinued production could be replaced by other refineries or other sources.
Our crude oil pipelines are dependent on our customers’ continued access to sufficient crude oil and sufficient demand for refined products for our customers to operate their refineries. The supply of crude oil production (domestic and foreign) could fluctuate with the price of crude oil. Changes in crude oil prices could also affect the exploration and production of shale plays, which could affect demand for crude oil pipelines serving those regions, such as our Eagle Ford System and Permian Crude System. However, certain of our crude oil pipelines, including the McKee System, are the primary source of crude oil for our customers’ refineries. Therefore, these “demand-pull” pipelines are less affected by changes in crude oil prices.
Demand for and Sources of Anhydrous Ammonia
The Ammonia Pipeline currently is one of two major anhydrous ammonia pipelines in the United States transporting anhydrous ammonia into the nation’s corn belt and the only one with the connectivity to receive products from outside the United States directly into the system.
Throughputs on our Ammonia Pipeline depend on overall demand for nitrogen fertilizer use, the price of natural gas, which is the primary component of anhydrous ammonia, and the level of demand for direct application of anhydrous ammonia as a fertilizer for crop production (Direct Application). Demand for Direct Application is dependent on the weather, as Direct Application is not effective if the ground is too wet or too dry.
Corn producers have fertilizer alternatives to anhydrous ammonia, such as liquid or dry nitrogen fertilizers. Liquid and dry nitrogen fertilizers are both less sensitive to weather conditions during application but are generally more costly than anhydrous ammonia. In addition, anhydrous ammonia has the highest nitrogen content of any nitrogen-derivative fertilizer.
Customers
Valero Energy, the largest customer of our pipeline segment, accounted for approximately 30% of the total segment revenues for the year ended December 31, 2018 . In addition to Valero Energy, our customers include integrated oil companies, refining companies, farm cooperatives, railroads and others. No other customer accounted for more than 10% of the total revenues of the pipeline segment for the year ended December 31, 2018 .
Competition and Other Business Considerations
Because pipelines are generally the lowest-cost method for intermediate and long-haul movement of crude oil and refined products, our more significant competitors are common carrier and proprietary pipelines owned and operated by major integrated and large independent oil companies and other pipeline companies in the areas where we deliver products. Competition between common carrier pipelines is based primarily on transportation charges, quality of customer service and proximity to end users. Trucks may competitively deliver products in some of the areas served by our pipelines; however, trucking costs render that mode of transportation uncompetitive for longer hauls or larger volumes.
Most of our refined product pipelines and certain of our crude oil pipelines within the Central West System are physically integrated with and principally serve refineries owned by Valero Energy. As a result, we do not believe that we will face significant competition for transportation services provided to the Valero Energy refineries we serve.

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Certain of our crude oil pipelines serve areas and/or refineries that are affected by domestic shale oil production in the Eagle Ford, Permian Basin and Granite Wash regions. Our pipelines also face competition from other crude oil pipelines and truck transportation in these regions. However, some of that exposure is mitigated through our long-term contracts and minimum volume commitments with creditworthy customers.
The East and North Pipelines compete with an independent common carrier pipeline system owned by Magellan Midstream Partners, L.P. (Magellan) that operates approximately 100 miles east of and parallel to the East Pipeline and in close proximity to the North Pipeline. Certain of the East Pipeline’s and the North Pipeline’s delivery terminals are in direct competition with Magellan’s terminals. Competition with Magellan is based primarily on transportation charges, quality of customer service and proximity to end users.
Competitors of the Ammonia Pipeline include the other major anhydrous ammonia pipeline, also owned by Magellan, which originates in Oklahoma and Texas and terminates in Minnesota. The competing pipeline has the same Direct Application demand and weather issues as the Ammonia Pipeline but is restricted to domestically produced anhydrous ammonia. On January 31, 2019, Magellan announced its plans to discontinue commercial operations of its ammonia pipeline in late 2019. Midwest production facilities, nitrogen fertilizer substitutes and barge and railroad transportation also compete with the Ammonia Pipeline under certain market conditions.
STORAGE
Our storage segment consists of facilities that provide storage, handling and other services for petroleum products, crude oil, specialty chemicals and other liquids. On November 30, 2018, we sold our European operations, including six liquids storage terminals in the United Kingdom and one facility in Amsterdam, with total storage capacity of approximately 9.5 million barrels. Please refer to Note 5 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for further discussion of the sale.
As of December 31, 2018 , we owned and operated:
40 terminal and storage facilities in the United States and one terminal in Nuevo Laredo, Mexico, with total storage capacity of 53.8 million barrels;
A terminal on the island of St. Eustatius with tank capacity of 14.3 million barrels and a transshipment facility; and
A terminal located in Point Tupper, Canada with tank capacity of 7.8 million barrels and a transshipment facility.

The following table sets forth information about our terminal and storage facilities as of December 31, 2018 :
Facility
Tank Capacity
 
(Barrels)
Colorado Springs, CO
328,000

Denver, CO
110,000

Albuquerque, NM
251,000

Rosario, NM
166,000

Catoosa, OK
358,000

Abernathy, TX
160,000

Amarillo, TX
269,000

Corpus Christi, TX
491,000

Corpus Christi, TX (North Beach)
3,339,000

Edinburg, TX
340,000

El Paso, TX (a)
419,000

Harlingen, TX
286,000

Laredo, TX
215,000

San Antonio, TX (b)
375,000

Southlake, TX
569,000

Nuevo Laredo, Mexico
35,000

Central West Terminals
7,711,000

 
 
 
 

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Facility
Tank Capacity
 
(Barrels)
Jacksonville, FL
2,593,000

St. James, LA
9,917,000

Houston, TX
86,000

Texas City, TX (b)
2,964,000

Gulf Coast Terminals
15,560,000

 
 
Blue Island, IL
690,000

Andrews AFB, MD (c)
75,000

Baltimore, MD
813,000

Piney Point, MD
5,402,000

Linden, NJ (b)
5,134,000

Paulsboro, NJ
74,000

Virginia Beach, VA (c)
41,000

North East Terminals
12,229,000

 
 
Los Angeles, CA
608,000

Pittsburg, CA
398,000

Selby, CA
3,074,000

Stockton, CA
816,000

Portland, OR
1,345,000

Tacoma, WA
391,000

Vancouver, WA (b)
774,000

West Coast Terminals
7,406,000

 
 
Benicia, CA
3,683,000

Corpus Christi, TX
4,030,000

Texas City, TX
3,141,000

Refinery Storage Tanks
10,854,000

 
 
St. Eustatius, the Netherlands
14,256,000

Point Tupper, Canada
7,778,000

International Terminals
22,034,000

 
 
Total
75,794,000

 
(a)
We own a 67% undivided interest in the El Paso refined product terminal. The tank capacity represents the proportionate share of capacity attributable to our ownership interest.
(b)
Location includes two terminal facilities.
(c)
Terminal facility also includes pipelines to U.S. government military base locations.
Description of Major Terminal Facilities
St. Eustatius. We own and operate a 14.3 million barrel petroleum storage and terminalling facility located on the island of St. Eustatius in the Caribbean Netherlands, which is located at a point of minimal deviation from major shipping routes. This facility is capable of handling a wide range of petroleum products, including crude oil and refined products, and it has the capability to load or unload up to three vessels at a time, including heavily laden ultra large crude carriers, or ULCCs. The facility has a two-berth jetty, a two-berth monopile with platform and buoy systems, a floating hose station and an offshore single point mooring (SPM) buoy with the ability to load and unload two different products at the SPM and segregate various grades of crude and fuel oil to and from the SPM. The fuel oil and petroleum product facilities have in-tank and in-line

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blending capabilities, while the crude tanks have tank-to-tank blending capability and in-tank mixers. In addition to the storage and blending services at St. Eustatius, this facility has the flexibility to utilize certain storage capacity for both feedstock and refined products to support our atmospheric distillation unit, which is capable of handling up to 25,000 barrels per day of feedstock, ranging from condensates to heavy crude oil. We own and operate all of the berthing facilities at the St. Eustatius terminal. Separate fees apply for use of the berthing facilities, as well as associated services, including pilotage, tug assistance, line handling, launch service, emergency response services and other ship services.

Refinery Storage Tanks. We own and operate crude oil storage tanks with an aggregate storage capacity of 10.9 million barrels that are physically integrated with and serve refineries owned by Valero Energy at Corpus Christi and Texas City, TX and Benicia, CA. Effective January 1, 2017, we lease our refinery storage tanks to Valero Energy in exchange for a fixed fee, whereas we previously earned fees based upon throughput.
St. James, Louisiana. Our St. James terminal, which is located on the Mississippi River near St. James, Louisiana, has a total storage capacity of 9.9 million barrels. The facility is located on almost 900 acres of land, some of which is undeveloped. The majority of the storage tanks and infrastructure are suited for light crude oil, with certain of the tanks capable of fuel oil or heated crude oil storage. Additionally, the facility has one barge dock and two ship docks. Our St. James terminal is connected to (i) offshore pipelines in the Gulf of Mexico, (ii) long-haul pipelines that can receive crude oil from the Eagle Ford, Permian and other domestic shale plays, and (iii) pipelines to refineries in the Gulf Coast and Midwest. The St. James terminal also has two unit train rail facilities and a manifest rail facility that are served by the Union Pacific Railroad and have a combined capacity of approximately 200,000 barrels per day.
Point Tupper. We own and operate a 7.8 million barrel terminalling and storage facility located at Point Tupper on the Strait of Canso, near Port Hawkesbury, Nova Scotia. This facility is the deepest independent, ice-free marine terminal on the North American Atlantic coast, with access to the East Coast, Canada and the Midwestern United States via the St. Lawrence Seaway and the Great Lakes system. With one of the premier jetty facilities in North America, the Point Tupper facility can accommodate heavily laden ULCCs for loading and discharging crude oil, petroleum products and petrochemicals. Crude oil and petroleum product movements at the terminal are fully automated. Separate fees apply for use of the jetty facility, as well as associated services, including pilotage, tug assistance, line handling, launch service, emergency response services and other ship services (all of which are considered optional services).
Linden, New Jersey. Our Linden terminal facility includes two terminals that provide deep-water terminalling capabilities in the New York Harbor and primarily stores petroleum products, including gasoline, jet fuel and fuel oils. The two terminals have a total storage capacity of 5.1 million barrels and can receive and deliver products via ship, barge and pipeline. The terminal facility also has two docks.

Corpus Christi North Beach. We own and operate a 3.3 million barrel crude oil storage and terminalling facility located at the Port of Corpus Christi in Texas. The facility supports our South Texas Crude System and is also connected to a third-party pipeline system, providing our customers with the flexibility to segregate and deliver crude oil and processed condensate. This facility has access to four docks, including two private docks, and can load crude oil onto ships simultaneously on all four docks. This includes exclusive-use access to the Port of Corpus Christi’s newest crude oil dock, which was completed in September 2018 and is able to accommodate Aframax-class vessels.

Storage Operations
We generate storage segment revenues through fees for tank storage agreements, whereby a customer agrees to pay for a certain amount of storage in a tank over a period of time (storage terminal revenues), and throughput agreements, whereby a customer pays a fee per barrel for volumes moving through our terminals (throughput terminal revenues). Our terminals also provide blending, additive injections, handling and filtering services for which we charge additional fees. We lease our Refinery Storage Tanks to Valero Energy in exchange for a fixed fee. Certain of our facilities charge fees to provide marine services, such as pilotage, tug assistance, line handling, launch service, emergency response services and other ship services.
Demand for Refined Products and Crude Oil
The operations of our refined product terminals depend in large part on the level of demand for products stored in our terminals in the markets served by those assets. The majority of products stored in our terminals are refined products. Demand for our terminalling services will generally increase or decrease with demand for refined products, and demand for refined products tends to increase or decrease with the relative strength of the economy. In addition, the forward pricing curve can have an impact on demand. For example, in a contango market (when the price of a commodity is expected to exceed current prices), demand for storage services will generally increase.

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Crude oil delivered to our St. James and Corpus Christi North Beach terminals will generally increase or decrease with crude oil production rates in the Bakken, Permian and Eagle Ford shale plays. In addition, the market price relationship between various grades of crude oil impacts the demand for our unit train facilities at our St. James terminal.
Customers
We provide storage and terminalling services for crude oil and refined products to many of the world’s largest producers of crude oil, integrated oil companies, chemical companies, oil traders and refiners. In addition, our blending capabilities in our storage assets have attracted customers who have leased capacity primarily for blending purposes. Valero Energy, the largest customer of our storage segment, accounted for approximately 20% of the total revenues of the segment for the year ended December 31, 2018 . No other customer accounted for more than 10% of the total revenues of the storage segment for the year ended December 31, 2018 .
Competition and Other Business Considerations
Many major energy and chemical companies own extensive terminal storage facilities. Although such terminals often have the same capabilities as terminals owned by independent operators, they generally do not provide terminalling services to third parties. In many instances, major energy and chemical companies that own storage and terminalling facilities are also significant customers of independent terminal operators. Such companies typically have strong demand for terminals owned by independent operators when independent terminals have more cost-effective locations near key transportation links, such as deep-water ports. Major energy and chemical companies also need independent terminal storage when their owned storage facilities are inadequate, either because of size constraints, the nature of the stored material or specialized handling requirements.
Independent terminal owners generally compete on the basis of the location and versatility of terminals, service and price. A favorably located terminal will have access to various cost-effective transportation modes both to and from the terminal. Transportation modes typically include waterways, railroads, roadways and pipelines.
Terminal versatility is a function of the operator’s ability to offer complex handling requirements for diverse products. The services typically provided by the terminal include, among other things, the safe storage of the product at specified temperature, moisture and other conditions, as well as receipt at and delivery from the terminal, all of which must comply with applicable environmental regulations. A terminal operator’s ability to obtain attractive pricing is often dependent on the quality, versatility and reputation of the facilities owned by the operator. Although many products require modest terminal modification, operators with versatile storage capabilities typically require less modification prior to usage, ultimately making the storage cost to the customer more attractive.
Our St. Eustatius and Point Tupper terminals have historically functioned as “break bulk” facilities, which handled imports of light crude from foreign sources into the U.S. to satisfy U.S. East Coast and Gulf Coast refinery demand for light crude. Light crude suppliers brought the crude from the Middle East and other foreign regions on very large ships, which are efficient for long routes. These large ships, due to draft constraints, are unable to navigate far enough inland to deliver directly to most U.S. ports, which necessitates unloading these ships to storage and subsequent loading onto smaller ships that can bring the crude to the refiners, a process referred to as “break bulk.” Both terminals are well-located to provide this service.
As the supply of light crude from various U.S. shale formations has increased, U.S. demand for foreign light crude oil, particularly on the U.S. Gulf Coast, has dropped. This reduced demand for imported light crude has, in turn, changed oil trade flow patterns around the world, thereby depressing the demand for break-bulk services. Our St. Eustatius terminal’s location is well-suited to consolidate heavy oil cargos from the small ships used to move heavy crude, from Latin America and other origins, off shore to a large vessel for more efficient transport for long routes, a process referred to as “build bulk,” primarily to Asia. However, recently, the combination of oversupply of storage capacity, decreased demand from backwardated markets, reduced North American crude imports and lower than expected growth in production in Latin America has depressed storage rates in the region.
We may face increased competition from new and/or expanding terminals near our locations, if those facilities offer either break-bulk or build-bulk services, as demanded by the applicable oil trade flows, now and in the future.
Our crude oil refinery storage tanks are physically integrated with and serve refineries owned by Valero Energy. Additionally, we have entered into various agreements with Valero Energy governing the usage of these tanks. As a result, we believe that we will not face significant competition for our services provided to those refineries.

FUELS MARKETING
The fuels marketing segment includes our bunkering operations at our St. Eustatius and Texas City terminals, as well as certain of our blending operations. The results of operations for the fuels marketing segment depend largely on the margin between our

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cost and the sales prices of the products we market. Therefore, the results of operations for this segment are more sensitive to changes in commodity prices compared to the operations of the pipeline and storage segments.

Customers for our bunker fuel sales are mainly ship owners, including cruise line companies. In the sale of bunker fuel, we compete with ports offering bunker fuels that are along the route of travel of the vessel. No customer accounted for a significant portion of the total revenues of the fuels marketing segment for the year ended December 31, 2018 .

EMPLOYEES

As of December 31, 2018 , we had 1,517 employees.

RATE REGULATION

Several of our pipelines are interstate common carrier pipelines, which are subject to regulation by the FERC under the Interstate Commerce Act (ICA) and the Energy Policy Act of 1992 (the EP Act). The ICA and its implementing regulations give the FERC authority to regulate the rates charged for service on interstate common carrier pipelines and generally require the rates and practices of interstate liquids pipelines to be just, reasonable, not unduly discriminatory and not unduly preferential. The ICA also requires tariffs that set forth the rates a common carrier pipeline charges for providing transportation services on its interstate common carrier liquids pipelines, as well as the rules and regulations governing these services, to be maintained on file with the FERC and posted publicly. The EP Act deemed certain rates in effect prior to its passage to be just and reasonable and limited the circumstances under which a complaint can be made against such “grandfathered” rates. The EP Act and its implementing regulations also allow interstate common carrier liquids pipelines to annually index their rates up to a prescribed ceiling level and require that such pipelines index their rates down to the prescribed ceiling level if the index is negative. In addition, the FERC retains cost-of-service ratemaking, market-based rates and settlement rates as alternatives to the indexing approach.

The Ammonia Pipeline is subject to regulation by the STB pursuant to the Interstate Commerce Act applicable to such pipelines (which differs from the ICA applicable to interstate liquids pipelines). Under that regulation, the Ammonia Pipeline’s rates, classifications, rules and practices related to the interstate transportation of anhydrous ammonia must be reasonable and, in providing interstate transportation, the Ammonia Pipeline may not subject a person, place, port or type of traffic to unreasonable discrimination.

In addition to federal regulatory body oversight, various states, including Colorado, Kansas, Louisiana, North Dakota and Texas, maintain commissions focused on the rates and practices of common carrier pipelines offering services within their borders. Although the applicable state statutes and regulations vary, they generally require that intrastate pipelines publish tariffs setting forth all rates, rules and regulations applying to intrastate service, and generally require that pipeline rates and practices be just, reasonable and nondiscriminatory.

Shippers may challenge tariff rates, rules and regulations on our pipelines. In most instances, state commissions have not initiated investigations of the rates or practices of pipelines in the absence of shipper complaints. There are no pending challenges or complaints regarding our tariffs.

ENVIRONMENTAL, HEALTH, SAFETY AND SECURITY REGULATION

Our operations are subject to extensive international, federal, state and local environmental laws and regulations, in the U.S. and in the other countries in which we operate, including those relating to the discharge of materials into the environment, waste management, remediation, the characteristics and composition of fuels, climate change and greenhouse gases. Our operations are also subject to extensive health, safety and security laws and regulations, including those relating to worker and pipeline safety, pipeline and storage tank integrity and operations security. The principal environmental, health, safety and security risks associated with our operations relate to unauthorized emissions into the air, releases into soil, surface water or groundwater, personal injury and property damage. We have adopted policies, practices, systems and procedures to comply with the laws and regulations, mitigate these risks, limit the liability that could result from such events, prevent material environmental or other damage, ensure the safety of our employees and the public and secure our pipelines, terminals and operations. Compliance with environmental, health, safety and security laws, regulations and related permits increases our capital expenditures and operating expenses, and violation of these laws, regulations or permits could result in significant civil and criminal liabilities, injunctions or other penalties.

In 2018 , our capital expenditures attributable to compliance with environmental regulations were $12.2 million, and we currently project spending to be approximately $14.1 million in this regard in 2019 . However, future governmental actions

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could result in these laws and regulations becoming more restrictive, necessitating additional capital expenditures and operating expenses. At this time, we are unable to estimate the effect on our financial condition or results of operations, or the amount and timing of such possible future expenditures or expenses. In addition, while we believe that we are in substantial compliance with the environmental, health, safety and security laws and regulations applicable to our operations, risks of additional compliance expenditures, expenses and liabilities are inherent within the industry. As a result, there can be no assurances that significant expenditures, expenses and liabilities will not be incurred in the future. However, while compliance may affect our capital expenditures and operating expenses, we believe that the cost of such compliance will not have a material impact on our competitive position, financial condition or results of operations. Further, we do not believe that our cost of compliance is proportionately greater than the cost to other companies operating in our industry.

Discussed below are the primary U.S. environmental, health, safety and security laws applicable to our operations. Compliance with or violations of any of these laws and related regulations could result in significant expenditures, expenses and liabilities.

OCCUPATIONAL SAFETY AND HEALTH

We are subject to the Occupational Safety and Health Act, as amended, and analogous or more stringent international, state and local laws and regulations for the protection of worker safety and health. In addition, we have operations subject to the Occupational Safety and Health Administration’s Process Safety Management regulations. These regulations apply to processes which involve certain chemicals at or above specified thresholds.

FUEL STANDARDS AND RENEWABLE ENERGY

International, federal, state and local laws and regulations regulate the fuels we transport and store for our customers. Changes in these laws or regulations could affect our earnings, including by reducing our throughput volumes, or require capital expenditures and expenses to segregate and separately store fuels. In addition, several federal and state programs require, subsidize or encourage the purchase and use of renewable energy, electric battery-powered motor vehicle engines and alternative fuels, such as biodiesel. These programs may over time offset projected increases or reduce the demand for refined products, particularly gasoline, in certain markets. However, the increased production and use of biofuels may also create opportunities for pipeline transportation and fuel blending. Other legislative changes in the future may similarly alter the expected demand and supply projections for refined products in ways that cannot be predicted.

HAZARDOUS SUBSTANCES & HAZARDOUS WASTE

The Federal Comprehensive Environmental Response, Compensation and Liability Act, referred to as CERCLA or “Superfund,” and analogous or more stringent international, state and local laws and regulations, impose restrictions and liability related to the release, threatened release, disposal and remediation of hazardous substances. This liability can be joint and several strict liability, without regard to fault or the legality of the original release or disposal. Current operators of a
facility, past owners or operators of a facility and parties who arranged for the disposal of a hazardous substance can be held liable under these laws and regulations.

We currently own, lease, and operate on, and have in the past owned, leased and operated on, properties and at facilities that handled, transported and stored hazardous substances. Our current operating and disposal practices comply with applicable laws, regulations and industry standards, and we believe our past practices complied at the time. Despite our compliance, hazardous substances may have been released on or under our facilities and properties, or on or under locations where these substances were taken for disposal. We are currently remediating subsurface contamination at several facilities and, based on currently available information, we believe the costs related to these remedial activities should not materially affect our financial condition or results of operations. However, the aggregate total cost of remediation projects can be difficult to estimate and there are no assurances that the cost of future remedial activities will not become material. Further, applicable laws or regulation, including regarding clean up levels, may be revised to be more restrictive in the future. As a result, we are unable to estimate the effect of future regulation on our financial condition or results of operations or the amount and timing of future expenditures.

The Federal Resource Conservation and Recovery Act, as amended, and analogous or more stringent international, state and local laws and regulations impose restrictions and strict controls regarding the handling and disposal of wastes, including hazardous wastes. We generate hazardous wastes and it is possible that additional wastes, which could include wastes currently generated during operations, will be designated as hazardous wastes in the future. Hazardous wastes are subject to more rigorous requirements than are non-hazardous wastes.

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AIR

The Federal Clean Air Act, as amended, and various applicable international, state and local laws and regulations impose restrictions and strict controls regarding emission into the air. These laws and regulations generally require permits issued by applicable federal or state authorities for emissions, and impose monitoring and reporting requirements. Such laws and regulations can also require pre-approval for the construction or modification of certain operations or facilities expected to produce or increase air emissions.

WATER

The Federal Water Pollution Control Act, as amended, also known as the Clean Water Act, and analogous or more stringent international, state and local laws and regulations impose restrictions and strict controls regarding the discharge of pollutants into state waters or waters of the United States. The discharge of pollutants into waters is generally prohibited, except in accordance with a permit issued by applicable federal or state authorities. The Oil Pollution Act further regulates the discharge of oil, and the response to and liability for oil spills, and the Rivers and Harbors Act regulates pipelines crossing navigable waters.

PIPELINE AND OTHER ASSET INTEGRITY, SAFETY AND SECURITY

Our pipeline, storage tank and other operations are subject to extensive international, federal, state and local laws and regulations governing integrity and safety, including those in Title 49 of the U.S. Code and its implementing regulations. These laws and regulations include the Pipeline and Hazardous Materials Safety Administration’s requirements for safe pipeline design, construction, operation, maintenance, inspection, testing and corrosion control, control rooms and qualification programs for operating personnel. In addition, we have marine terminal operations subject to Coast Guard safety, integrity and security regulations and standards. We also have operations subject to the Department of Homeland Security Chemical Facility Anti-Terrorism Standards and Transportation Security Administration’s Pipeline Security Guidelines. We believe that we are in material compliance with all applicable laws and regulations regarding the security of our facilities.

While we are not currently required to implement specific governmental regulatory protocols for the protection of our computer-based systems and technology from cyber threats and attacks, proposals to do so are being considered by a number of U.S. governmental departments and agencies, including the Department of Homeland Security. We currently have our own cybersecurity programs and protocols in place; however, we cannot guarantee their effectiveness, and successful penetration of our critical systems could have a material effect on our operations and those of our customers and vendors.



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RISK FACTORS

RISKS RELATED TO OUR BUSINESS

We may not be able to generate sufficient cash from operations to enable us to pay quarterly distributions to our unitholders.
The amount of cash that we can distribute to our unitholders each quarter principally depends upon the amount of cash we generate from our operations, based on, among other things:
throughput volumes transported in our pipelines;
storage contract renewals or throughput volumes in our terminals and storage facilities;
tariff rates and fees we charge and the revenue we realize for our services;
demand for and supply of crude oil, refined products and anhydrous ammonia;
the effect of worldwide energy conservation measures;
our operating costs;
the costs to comply with environmental, health, safety and security laws and regulations;
weather conditions;
domestic and foreign governmental laws, regulations, sanctions, embargoes and taxes;
prevailing economic conditions; and
the results of our marketing, trading and hedging activities, which fluctuate depending upon the relationship between refined product prices and prices of crude oil and other feedstocks.

Furthermore, the amount of cash that we will have available for distribution depends on a number of other factors, including:
our debt service requirements and restrictions on distributions contained in our current or future financing agreements;
our capital expenditures;
issuances of debt and equity securities and ability to access the capital markets;
fluctuations in our working capital needs;
adjustments in cash reserves made by our board of directors, in its discretion; and
the sources of cash used to fund our acquisitions, if any.

Moreover, the total amount of cash that we have available for distribution to common unitholders is further reduced by the required distributions with respect to the preferred units.

It is possible that one or more of the factors listed above may serve to reduce our available cash to such an extent that we could be rendered unable to pay distributions at the current level or at all in a given quarter. Furthermore, cash distributions to our unitholders depend primarily upon our cash flows, including cash flows from reserves and working capital borrowings, and not solely on profitability, which is affected by non-cash items; as a result, we may be able to make cash distributions during periods in which we record net losses and may not be able to make cash distributions during periods in which we record net income.

Our future financial and operating flexibility may be adversely affected by our significant leverage, any future downgrades of our credit ratings, restrictions in our debt agreements and conditions in the financial markets.
As of December 31, 2018, our consolidated debt was $3.1 billion, and we have the ability to incur more debt. In addition to any potential direct financial impact of our debt, it is possible that any material increase to our debt or other negative financial factors may be viewed negatively by credit rating agencies, which could result in ratings downgrades and increased costs for us to access the capital markets. In February 2018, Moody’s Investors Service, Inc. downgraded our credit rating from Ba1 to Ba2, which increased the interest rate on amounts borrowed under our credit facilities. Any additional downgrades in our credit ratings in the future could result in further increases to the interest rate on our revolving credit agreement, significantly increase our capital costs, reduce our liquidity and adversely affect our ability to raise capital in the future.

Our revolving credit agreement contains restrictive covenants, such as limitations on indebtedness, liens, mergers, asset transfers and certain investing activities. In addition, the revolving credit agreement generally requires us to maintain, as of the end of each rolling period of four quarters, a consolidated debt coverage ratio (consolidated debt to consolidated EBITDA, each as defined in the revolving credit agreement) not to exceed 5.00-to-1.00, except in specific circumstances, including acquisitions for aggregate net consideration of at least $50 million, when we are permitted to maintain a consolidated debt coverage ratio of up to 5.50-to-1.00 for two rolling periods, as provided in the revolving credit agreement. Our revolving credit agreement also requires us to maintain a minimum consolidated interest coverage ratio (as defined in the revolving credit agreement) of at least 1.75-to-1.00 for each rolling period of four quarters. Failure to comply with any of the revolving credit agreement restrictive covenants or the maximum consolidated debt coverage ratio or minimum consolidated interest coverage

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ratio requirements would constitute an event of default and could result in acceleration of our obligations under the revolving credit agreement and possibly other agreements. Future financing agreements we may enter into may contain similar or more restrictive covenants than those we have negotiated for our current financing agreements.

Our accounts receivable securitization program contains various customary affirmative and negative covenants and default, indemnification and termination provisions, and the related receivables financing agreement (pursuant to which we are the initial servicer and performance guarantor) provides for acceleration of amounts owed upon the occurrence of certain specified events.

Our debt service obligations, restrictive covenants and maturities resulting from our leverage may adversely affect our ability to finance future operations, pursue acquisitions, fund our capital needs and pay cash distributions to our unitholders. In addition, this leverage may make our results of operations more susceptible to adverse economic or operating conditions, limit our flexibility in planning for, or reacting to, changes in our business and industry and place us at a competitive disadvantage compared to competitors with proportionately less indebtedness. For example, during an event of default under certain of our debt agreements, we would be prohibited from making cash distributions to our unitholders. Also, if any of our lenders file for bankruptcy or experience severe financial hardship, they may not honor their pro rata share of our borrowing requests under the revolving credit agreement, which may significantly reduce our available borrowing capacity and, as a result, materially adversely affect our financial condition and ability to pay distributions to our unitholders.

Our ability to service our debt will depend on, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond our control. If our operating results are not sufficient to service our indebtedness, we may be required to reduce our distributions, reduce or delay our business activities, investments or capital expenditures, sell assets or issue equity, which could materially and adversely affect our financial condition, results of operations, cash flows and ability to make distributions to unitholders, as well as the trading price of our units.

Depending on conditions in the credit and capital markets at a given time, we may not be able to obtain funding on acceptable terms or at all, which may hinder or prevent us from meeting our future capital needs.
From time to time, the domestic and global financial markets and economic conditions are volatile and disrupted by a variety of factors, including low consumer confidence, high unemployment, geoeconomic and geopolitical issues, weak economic conditions and uncertainty in the market. In addition, there are fewer investors and lenders for master limited partnership debt and equity capital market issuances than there are for corporate issuances. As a result, the cost of raising capital in the debt and equity capital markets could increase substantially, possibly at a time when the availability of funds from these markets has diminished. The cost of obtaining funds from the credit markets may increase as interest rates increase and tighter lending standards are enacted, and lenders may refuse to refinance existing debt on similar terms or at all and reduce, or in some cases cease to provide, funding to borrowers.

In addition, lending counterparties under our existing revolving credit facility and other debt instruments may be unwilling or unable to meet their funding obligations. Due to these factors, we cannot be certain that new financing or funding will be available on acceptable terms. If funding is not available when needed, or is available only on unfavorable terms, we may be unable to execute our growth strategy, complete future acquisitions or construction projects or take advantage of other business opportunities, any of which could have a material adverse effect on our revenues and results of operations.

A significant portion of our debt matures over the next five years and will need to be paid or refinanced, and changes to the debt and equity markets could limit our refinancing options.
A significant portion of our debt is set to mature within the next five years, including our revolving credit facility. We may not be able to refinance our maturing debt on commercially reasonable terms, or at all, depending on numerous factors, including our financial condition and prospects at the time and the then-current state of the banking and capital markets in the United States.

Increases in interest rates could adversely affect our business and the trading price of our units.
We have significant exposure to increases in interest rates through variable rate provisions in certain of our debt instruments. At December 31, 2018, we had approximately $3.1 billion of consolidated debt, of which $1.5 billion was at fixed interest rates and $1.6 billion was at variable interest rates. Additionally, at December 31, 2018, the aggregate notional amount of our interest rate swap arrangements was $250.0 million, which may expose us to risk of financial loss. Prior ratings downgrades on our existing indebtedness caused interest rates under certain of our debt instruments to increase, and any future downgrades may further increase the interest rate on our revolving credit agreement. Our results of operations, cash flows and financial position could be materially adversely affected by significant changes in interest rates.


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The majority of our variable-rate indebtedness uses LIBOR as a benchmark for establishing the rate. LIBOR is the subject of recent national, international and other regulatory guidance and proposals for reform. These reforms and other pressures may cause LIBOR to disappear entirely or to perform differently than in the past. The consequences of these developments cannot be entirely predicted but could include an increase in the cost of our variable-rate indebtedness.

Furthermore, we have historically funded our strategic capital expenditures and acquisitions from external sources, primarily borrowings under our revolving credit agreement or funds raised through debt or equity offerings. An increase in interest rates may also have a negative impact on our ability to access the capital markets at economically attractive rates.

Moreover, the market price of master limited partnership units, like other yield-oriented securities, may be affected by, among other factors, implied distribution yield. The distribution yield is often used by investors to compare and rank yield-oriented securities for investment decision-making purposes. Therefore, increases or decreases in interest rates may affect whether or not certain investors decide to invest in master limited partnership units, including ours, and a rising interest rate environment could have an adverse impact on our unit price and impair our ability to issue additional equity or incur debt to fund growth or for other purposes, including distributions.

Continued low crude oil prices could have an adverse impact on our results of operations, cash flows and ability to make distributions to our unitholders.
In late 2014, the price of crude oil fell precipitously and did not begin to recover until 2018, and then only to approximately three-quarters of 2014 highs. During fourth quarter 2018 and since, prices again fell into the $40s and $50s per barrel. During periods of sustained low prices, producers tend to reduce their capital spending and drilling activity and narrow their focus to assets in the most cost-advantaged regions. On the other hand, refiners tend to benefit from lower crude prices, to the extent that they are able to take advantage of lower feedstock prices, especially those positioned for healthy regional demand for their refined products. However, as inventories increase, refiners typically reduce their production rate, which may reduce the degree to which they are able to benefit from low crude oil prices.

While only a portion of our total business is directly affected by the price of crude, low crude oil prices can slow economic growth overall, and an economic downturn could have a negative impact on our results of operations and cash flow and, by extension, our ability to make cash distributions to our unitholders.

An extended period of reduced demand for or supply of crude oil and refined products could affect our results of operations and ability to make distributions to our unitholders.
Although we enter into throughput and deficiency agreements to protect against near-term fluctuations whenever possible, our business is ultimately dependent upon the long-term demand for and supply of the crude oil and refined products we transport in our pipelines and store in our terminals. Market prices for crude oil and refined products, including fuel oil, are subject to wide fluctuation in response to changes in global and regional supply that are beyond our control, and increases in the price of crude oil may result in a lower demand for refined products that we transport, store and market, including fuel oil. Any sustained decrease in demand for refined products in the markets our pipelines and terminals serve that extends beyond the expiration of our existing throughput and deficiency agreements could result in a significant reduction in throughputs in our pipelines and storage in our terminals, which would reduce our cash flows and impair our ability to make distributions to our unitholders. Factors that tend to decrease market demand include:
a recession or other adverse economic condition that results in lower spending by consumers on gasoline, diesel and travel;
higher fuel taxes or other governmental or regulatory actions that increase, directly or indirectly, the cost of gasoline;
an increase in aggregate automotive engine fuel economy;
new regulations or court decisions requiring the phase out or reduced use of gasoline-fueled vehicles;
the increased use of alternative fuel sources;
an increase in the market price of crude oil that increases refined product prices, which may reduce demand for refined products and drive demand for alternative products; and
a decrease in corn acres planted for ethanol, which may reduce demand for anhydrous ammonia.

Similarly, any sustained decrease in the supply of crude oil and refined products in markets we serve could result in a significant reduction in throughputs in our pipelines and storage in our terminals, which would reduce our cash flows and undermine our ability to make distributions to our unitholders. Factors that tend to decrease supply and, by extension, utilization of our pipelines and terminals include:
prolonged periods of low prices for crude oil and refined products, which could lead to a decrease in exploration and development activity and reduced production in markets served by our pipelines and storage terminals;
a lack of drilling services or equipment available to producers to accommodate production needs;

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changes in laws, regulations, sanctions or taxation that directly or indirectly delay supply or production or increase the cost of production of refined products; and
macroeconomic forces affecting, or actions taken by, foreign oil and gas producing nations that impact supply of and prices for crude oil and refined products.

Our inability to develop, fund and execute growth projects and acquire new assets could limit our ability to maintain and grow quarterly distributions to our unitholders.
Our ability to maintain and grow our distributions to unitholders depends on the growth of our existing businesses and strategic acquisitions. Decisions regarding new growth projects rely on numerous estimates, including, among other factors, the ability to secure a commitment from a customer that sufficiently exceeds our cost of capital to justify the project cost, predictions of future demand for our services, future supply shifts, crude oil production estimates, commodity price environments, economic conditions, both domestic and foreign, and potential changes in the financial condition of our customers. Our predictions of such factors could cause us to forego certain investments and to lose opportunities to competitors who make investments based on different predictions. If we are unable to acquire new assets, due either to high prices or a lack of attractive synergistic targets, our future growth could be limited. In addition, our future growth will be limited if we are unable to develop additional expansion projects, implement business development opportunities and finance such activities on economically acceptable terms, which could adversely impact our results of operations and cash flows and, accordingly, result in reduced distributions over time.

Failure to complete capital projects as planned could adversely affect our financial condition, results of operations and cash flows.
Delays or cost increases related to capital spending programs involving construction of new facilities (or improvements and repairs to our existing facilities) could adversely affect our ability to achieve forecasted operating results. Although we evaluate and monitor each capital spending project and try to anticipate difficulties that may arise, such delays or cost increases may arise as a result of factors that are beyond our control, including:
non-performance or delay by, or disputes with, counterparties, vendors, suppliers, contractors or sub-contractors involved with a project;
denial or delay in issuing requisite regulatory approvals and/or permits;
protests and other activist interference with planned or in-process projects;
unplanned increases in the cost of construction materials or labor;
disruptions in transportation of modular components and/or construction materials;
severe adverse weather conditions, natural disasters or other events (such as hurricanes, equipment malfunctions, explosions, fires or spills) affecting our facilities, or those of vendors and suppliers;
shortages of sufficiently skilled labor, or labor disagreements resulting in unplanned work stoppages; or
market-related increases in a project’s debt or equity financing costs.

While we incur financing costs during the planning and construction phases of our projects, a project does not generate expected operating cash flows until it is completed, if at all. Additionally, our forecasted operating results from capital spending projects are based on future market fundamentals that are not within our control, including changes in general economic conditions, the supply and demand of crude oil and refined products, availability to our customers of attractively priced alternative solutions for storage, transportation or supplies of crude oil and refined products and overall customer demand.

As a result of these uncertainties, the anticipated benefits associated with our capital projects may not be achieved or could be delayed. In turn, this could have a negative impact on our results of operations and cash flow and our ability to make cash distributions to our unitholders.

If we are unable to retain or replace current customers and existing contracts to maintain utilization of our pipeline and storage assets at current or more favorable rates, our revenue and cash flows could be reduced to levels that could adversely affect our ability to make quarterly distributions to our unitholders.
Our revenue and cash flows are generated primarily from our customers’ payments of fees under throughput contracts and storage agreements. Failure to renew or enter into new contracts or our storage customers’ material reduction of utilization under existing contracts could result from many factors, including:
continued low crude oil prices;
a material decrease in the supply or price of crude oil;
a material decrease in demand for refined products in the markets served by our pipelines and terminals;
political, social or economic instability in another country impacting a customer based there;
competition for customers from companies with comparable assets and capabilities;
scheduled turnarounds or unscheduled maintenance at refineries we serve;
operational problems or catastrophic events affecting our assets or a refinery we serve;

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environmental proceedings or other litigation that compel the cessation of all or a portion of the operations of our assets or a refinery we serve;
increasingly stringent environmental, health, safety and security regulations;
a decision by our current customers to redirect refined products transported in our pipelines to markets not served by our pipelines or to transport crude oil or refined products by means other than our pipelines; or
a decision by our current customers to sell one or more of the refineries we serve to a purchaser that elects not to use our pipelines and terminals.

Competing midstream service providers, including certain major energy and chemical companies, possess, or have greater financial resources to acquire, assets better suited to meet customer demand, which could undermine our ability to obtain and retain customers or reduce utilization of our assets, which could reduce our revenues and cash flows, thereby reducing our ability to make our quarterly distributions to unitholders.
We face competition in all aspects of our business and can give no assurances that we will be able to compete effectively against our competitors. Our competitors include major energy and chemical companies, some of which have greater financial resources, more pipelines or storage terminals, greater capacity pipelines or storage terminals and greater access to supply than we do. Certain of our competitors also may have advantages in competing for acquisitions or other new business opportunities because of their financial resources and synergies in operations. As a consequence of increased competition in the industry, some of our customers may be reluctant to renew or enter into long-term contracts or contracts that provide for minimum throughput amounts in the future. Our inability to renew or replace our current contracts as they expire, to enter into contracts for newly acquired, constructed or expanded assets and to respond appropriately to changing market conditions could have a negative effect on our revenue, cash flows and ability to make quarterly distributions to our unitholders.

Our operations are subject to operational hazards and interruptions, and we cannot insure against and/or predict all potential losses and liabilities that might result therefrom.
Our operations and those of our customers and suppliers are subject to operational hazards and unforeseen interruptions due to natural disasters, adverse weather conditions (such as hurricanes, tornadoes, storms and floods), accidents, fires, explosions, hazardous materials releases, mechanical failures and other events beyond our control. In addition, many scientists hypothesize that global climatic changes are occurring that are likely to increase the number and severity of hurricanes and other damaging weather conditions. These events might result in a loss of life or equipment, injury or extensive property damage, as well as an interruption in our operations or those of our customers or suppliers. In the event any of our facilities, or those of our customers or suppliers, suffer significant damage or are forced to shut down for a significant period of time, it may have a material adverse effect on our earnings, our other results of operations and our financial condition as a whole.
    
As a result of market conditions, premiums and deductibles for certain of our insurance policies could increase substantially; therefore, we may not be able to maintain or obtain insurance of the type and amount we desire at reasonable rates. Certain insurance coverage could become subject to broad exclusions, become unavailable altogether or become available only for reduced amounts of coverage and at higher rates. If we were to incur a significant liability for which we are insufficiently insured, such a liability could have a material adverse effect on our financial position.

We are exposed to counterparty credit risk. Nonpayment and nonperformance by our customers, vendors or derivative counterparties could reduce our revenues, increase our expenses and otherwise have a negative impact on our ability to conduct our business, operating results, cash flows and ability to make distributions to our unitholders.
Weak economic conditions and widespread financial stress could reduce the liquidity of our customers, vendors or counterparties, making it more difficult for them to meet their obligations to us. We are therefore subject to risks of loss resulting from nonpayment or nonperformance by our customers to whom we extend credit. Financial problems encountered by our customers could limit our ability to collect amounts owed to us, or to enforce the performance of obligations owed to us under contractual arrangements.

In addition, nonperformance by vendors who have committed to provide us with critical products or services could raise our costs or interfere with our ability to successfully conduct our business. Furthermore, nonpayment by the counterparties to any of our outstanding derivatives could expose us to additional interest rate or commodity price risk. Although we attempt to mitigate our risk through warehouseman’s liens and other security protections, we may not always be able to enforce such liens and protections due to competing claims from other parties. Any substantial increase in the nonpayment and nonperformance by our customers, vendors or counterparties or our inability to enforce our warehouseman’s liens and other security protections could have a material adverse effect on our results of operations, cash flows and ability to make distributions to unitholders.


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We could be subject to damages or lose customers due to failure to maintain certain quality specifications or other claims related to the operation of our assets and the services we provide to our customers.
Certain of the products we store and transport are produced to precise customer specifications. If we fail to maintain the quality and purity of the products we receive and/or a product fails to perform in a manner consistent with the quality specifications required by the customer, the customer could seek replacement of the product or damages for costs incurred as a result of the product failing to perform as guaranteed. We also could face other claims by our customers if our assets do not operate as expected by our customers or our services otherwise do not meet our customers’ expectations. A successful claim or series of claims against us could result in unforeseen expenditures and a loss of one or more customers.

Our policies and practices to manage risk exposures cannot eliminate all risk, and noncompliance with our policies could result in significant financial losses.
We have implemented policies and practices that are designed to minimize risk, including credit risk, commodity price risk and operational risk. These policies and practices cannot, however, eliminate all such risks, and any policy only reduces risk to the extent affected parties comply thereunder. We cannot make any assurances that we will detect and prevent all violations of our policies and practices, particularly if deception, collusion or other intentional misconduct is involved. Any violations of these policies or practices by our employees or agents could result in significant financial losses.

An impairment of goodwill or long-lived assets could reduce our earnings.
We have recorded $1.0 billion of goodwill and $5.0 billion of long-lived assets, including property, plant and equipment, net and intangible assets, net, as of December 31, 2018. U.S. generally accepted accounting principles requires us to test both goodwill and long-lived assets for impairment when events or circumstances occur indicating that either goodwill or long-lived assets might be impaired and, in the case of goodwill, at least annually. Any event that causes a reduction in demand for our services could result in a reduction of our estimates of future cash flows and growth rates in our business, which could cause us to record an impairment charge to reduce the value of goodwill. Similarly, any event or change in circumstances that causes the carrying value of our long-lived assets to no longer be recoverable may require us to record an impairment charge to reduce the value of our long-lived assets. If we determine that either our goodwill or our long-lived assets are impaired, the resulting charge will reduce earnings and partners’ capital. There was no impairment recorded for goodwill or other long-lived assets for the years ended December 31, 2018 or 2017.

Cybersecurity breaches and other disruptions could compromise our information and operations, and expose us to liability, which would cause our business and reputation to suffer.
We rely on our information technology infrastructure to process, transmit and store electronic information. Additionally, we rely on our operational technology systems, as well as our information technology systems, to safely operate our assets. The security of our information networks and systems is critical to our operations and business strategy. Despite our security measures, we may suffer a cybersecurity incident due to attacks from a variety of external threat actors, internal employee error or malfeasance, or even cybersecurity incidents suffered by our managed service providers or other vendors. This may lead to the compromise of confidential business information, personal information or other data assets, as well as operational system disruptions. In recent years, there has been a rise in the number of cyberattacks on network and information systems generally, by both state-sponsored and criminal organizations and, as a result, the risks associated with such an event continue to increase. A significant failure, compromise, breach or interruption in our systems could result in a disruption of our operations, damage to our reputation, loss of customers or revenues and potential regulatory fines. If any such failure, interruption or similar event results in improper disclosure of information maintained in our information systems and networks or those of our vendors, including personnel, customer and vendor information, we could also be subject to liability under relevant contractual obligations and laws and regulations protecting personal data and privacy. Our financial results could also be adversely affected if operational systems are breached or an employee causes our operational systems to fail, either as a result of inadvertent error or by deliberately tampering with or manipulating our operational systems.

Although we believe that we have robust cybersecurity procedures and other safeguards in place, as threats continue to evolve and cybersecurity, data protection laws and regulations continue to develop, we may be required to expend additional resources to continue to enhance our information security, data protection and business continuity measures and/or to investigate and remediate information security vulnerabilities.

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Acquisitions and expansions, if any, may increase substantially the level of our indebtedness and contingent liabilities or otherwise change our capital structure, and we may be unable to integrate acquisitions and expansions effectively into our existing operations.
From time to time, we evaluate and acquire assets and businesses that we believe complement or diversify our existing assets and operations. Acquisitions may require us to raise a substantial amount of equity or incur a substantial amount of indebtedness. If we consummate any future material acquisitions, our capitalization and results of operations may change significantly, and unitholders will not have the opportunity to evaluate the economic, financial and other relevant information that we will consider in connection with any future acquisitions.

Part of our overall business strategy includes acquiring additional assets that complement our existing asset base and distribution capabilities or provide entry into new markets. We may not be able to identify suitable acquisitions, or we may not be able to purchase or finance any acquisitions on terms that we find acceptable. Additionally, we compete against other companies for acquisitions, and we may not be successful in the acquisition of any assets or businesses appropriate for our growth strategy.

Even if we do consummate acquisitions that we believe will increase distributable cash flow, these acquisitions may nevertheless result in a decrease in distributable cash flow. Any acquisition involves potential risks, including, among other things:
we may not be able to obtain the cost savings and financial improvements we anticipate or acquired assets may not perform as we expect;
we may not be able to successfully integrate the assets, management teams or employees of the businesses we acquire with our assets and management team, or such integration may be significantly delayed;
we may fail or be unable to discover some of the liabilities of businesses that we acquire, including liabilities resulting from a prior owner’s noncompliance with applicable federal, state or local laws;
we may have assumed prior known or unknown liabilities for which we may not be indemnified or have adequate insurance;
acquisitions may divert the attention of our senior management from focusing on our core business;
we may experience a decrease in our liquidity by using a significant portion of our available cash or borrowing capacity to finance acquisitions; and
we may face the risk that our existing financial controls, information systems, management resources and human resources will need to grow to support future growth.

We operate assets outside of the United States, which exposes us to different legal and regulatory requirements and additional risk.
A portion of our revenues are generated from our assets located outside of the United States. Our operations are subject to various risks unique to each country in which we operate that could have a material adverse effect on our business, results of operations and financial condition. With respect to any particular country, these risks may include political and economic instability, including: civil unrest, war and other armed conflict; inflation; and currency fluctuations, devaluation and conversion restrictions. We are also exposed to the risk of governmental actions that may: limit or disrupt markets for our operations, restrict payments or limit the movement of funds; impose sanctions on our ability to conduct business with certain customers or persons; or result in the deprivation of contract rights. Our operations outside the United States may also be affected by changes in trade protection laws, policies and measures, and other regulatory requirements affecting trade and investment, including the Foreign Corrupt Practices Act, and other foreign laws prohibiting corrupt payments, as well as import and export regulations.

We also have assets in, or have had customers based in, certain developing markets, such as Mexico, and in challenged markets, such as Venezuela, and the nature of these markets presents a number of risks. In addition, due to the unsettled political conditions in many oil-producing countries, our operations may be subject to the adverse consequences of war, civil unrest, strikes, currency controls and governmental actions. Deterioration of social, political, labor or economic conditions, including the increasing threat of terrorist organizations and drug cartels, in a country or region in which we do business, or affecting a customer with whom we do business, as well as difficulties in staffing and managing foreign operations, may adversely affect our operations or financial results. For example, PDVSA, which was a significant customer of our terminal facility in St. Eustatius, has been affected by the political, social and economic instability in Venezuela in recent years, as well as the negative effects from sanctions implemented by the United States and others, which has undermined PDVSA’s ability to operate and to pay its creditors timely.


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We are subject to laws and sanctions implemented by the United States and foreign jurisdictions where we do business that may restrict the type of business we are permitted to conduct with certain entities, including PDVSA, restrict our activities in certain countries, or even restrict the services we may provide with respect to crude oil or other products produced in certain countries or by certain entities. In 2017, the United States and the European Union imposed sanctions restricting certain types of activities involving Venezuela and PDVSA. On January 28, 2019, the U.S. Department of the Treasury’s Office of Foreign Assets Control (OFAC) added PDVSA to its List of Specially Designated Nationals and Blocked Persons (the SDN List), which, in effect, prohibits U.S. persons from engaging in most activities involving PDVSA, its property, and its interest in property, after a short wind down period. The inclusion of PDVSA on the SDN List prevents us from continuing our existing business with PDVSA. Consequently, we completed a wind down of all operations and agreements involving PDVSA on February 26, 2019, consistent with applicable laws.

We do not own all of the land on which our pipelines and facilities have been constructed, and we are therefore subject to the possibility of increased costs or the inability to retain necessary land use.
Like other pipeline and storage logistics services providers, certain of our pipelines, storage terminals and other facilities are located on land owned by third parties and governmental agencies that we have obtained the right to utilize for these purposes through contract (rather than through outright purchase). Many of our rights-of-way or other property rights are perpetual in duration, but others are for a specific period of time. In addition, some of our facilities are located on leased premises. Our loss of property rights, through our inability to renew right-of-way contracts or leases or otherwise, could adversely affect our operations and cash flows available for distribution to unitholders.

In addition, the construction of expansions or other changes to our existing assets may require us to obtain new rights-of-way or property rights prior to construction. We may be unable to obtain such rights-of-way or other property rights to connect new supplies to our existing pipelines, storage terminals or other facilities or to capitalize on other attractive expansion opportunities. Additionally, it may become more expensive for us to obtain new rights-of-way or other property rights or to renew existing rights-of-way or property rights. If the cost of obtaining new or renewing existing rights-of-way or other property rights increases, it may adversely affect our operations and cash flows available for distribution to unitholders.

We may be unable to obtain or renew permits necessary for our operations, which could inhibit our ability to do business.
Our facilities operate under a number of federal, state and local permits, licenses and approvals with terms and conditions containing a significant number of prescriptive limits and performance standards in order to operate. These limits and standards require a significant amount of monitoring, recordkeeping and reporting in order to demonstrate compliance with the underlying permit, license or approval. Noncompliance or incomplete documentation of our compliance status may result in the imposition of fines, penalties and injunctive relief. In addition, public protest and responsive government intervention have recently made it more difficult for some energy companies to acquire the permits required to complete planned infrastructure projects. A decision by a government agency to deny or delay issuing a new or renewed permit, license or approval, or to revoke or substantially modify an existing permit, license or approval, could have a material adverse effect on our ability to continue operations and on our financial condition, results of operations, cash flows and ability to make distributions to our unitholders.

Our ability to manage and grow our business effectively may be adversely affected if we lose management or operational personnel.
We depend on the continuing efforts of our executive officers. The departure of one or more key executive officers could have a significant negative effect on our business, operating results, financial condition and on our ability to compete effectively in the marketplace. 

Additionally, our ability to hire, train and retain qualified personnel continues to be important and could become more challenging in competitive energy industry market conditions. In regions experiencing rapid growth, such as the Permian Basin, and at times when general industry conditions are good, the competition for experienced operational and field technicians increases as other energy and midstream companies’ needs for the same personnel increases. Our ability to continue our current level of service to our customers could be adversely impacted if we are unable to successfully hire, train and retain these important personnel.

We may have liabilities from our assets that preexist our acquisition of those assets, but that may not be covered by indemnification rights we may have against the sellers of the assets.
Assets we acquired may have associated liabilities that precede our ownership but for which we are not indemnified by the seller responsible. In some cases, we have indemnified the previous owners and operators of acquired assets. Some of our assets have been used for many years to transport and store crude oil and refined products, and releases may have occurred in the past that could require costly future remediation. If a significant release or event occurred in the past, the liability for which was not retained by the seller, or for which indemnification by the seller is not available, it could adversely affect our financial

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position and results of operations. Conversely, if future releases or other liabilities arise from assets we have sold, we could incur costs related to those liabilities if the buyer possesses valid indemnification rights against us with respect to those assets.

Climate change and fuels legislation and other regulatory initiatives may decrease demand for the products we store, transport and sell and increase our operating costs.
In response to scientific studies asserting that emissions of certain “greenhouse gases” such as carbon dioxide and methane may be contributing to warming of the Earth’s atmosphere, the U.S. Congress, European Union and other political bodies have considered legislation or regulation to reduce emissions of greenhouse gases. To the extent the United States and other countries impose climate change regulations on the oil industry, it could have an adverse direct or indirect effect on our business.

Passage of climate change or fuels legislation or other regulatory initiatives in fuel efficiency, fuel additives, renewable fuels and other areas in which we conduct business could result in changes to the demand for the products we store, transport and sell, and could increase the costs of our operations, including costs to operate and maintain our facilities, install new emission controls on our facilities, acquire allowances to authorize our greenhouse gas or other emissions, pay any taxes related to our greenhouse gas or other emissions or administer and manage emissions programs.

In addition, certain of our blending operations can result in requirements to purchase renewable energy credits. Even though we attempt to mitigate such lost revenues or increased costs through the contracts we sign with our customers, we may be unable to recover those revenues or mitigate the increased costs, and any such recovery may depend on events beyond our control, including the outcome of future rate proceedings before the FERC, the STB or other regulators and the provisions of any final legislation or regulations. Reductions in our revenues or increases in our expenses as a result of climate change legislation or other regulatory initiatives could have adverse effects on our business, financial position, results of operations and prospects.

Finally, increasing concentrations of greenhouse gases in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods and other climatic events. If any such effects were to occur, they could have an adverse effect on our assets and operations.

Our operations are subject to federal, state and local laws and regulations, in the U.S. and in the other countries in which we operate, relating to environmental, health, safety and security that could require us to make substantial expenditures.
Our operations are subject to increasingly stringent international, federal, state and local environmental, health, safety and security laws and regulations. Transporting, storing and distributing hazardous materials, including petroleum products, entails the risk that these products may be released into the environment, potentially causing substantial expenditures for a response action, significant government penalties, liability to government agencies including for damages to natural resources, personal injury or property damages to private parties and significant business interruption. Further, certain of our pipeline facilities may be subject to the pipeline integrity and safety regulations of various federal and state regulatory agencies. In recent years, increased regulatory focus on pipeline integrity and safety has resulted in various proposed or adopted regulations. The implementation of these regulations, and the adoption of future regulations, could require us to make additional capital expenditures, including to install new or modified safety measures, or to conduct new or more extensive maintenance programs.

Current and future legislative action and regulatory initiatives could also result in changes to operating permits, material changes in operations, increased capital expenditures and operating costs, increased costs of the goods we transport and decreased demand for products we handle that cannot be assessed with certainty at this time. We may be required to make expenditures to modify operations or install pollution control equipment or release prevention and containment systems that could materially and adversely affect our business, financial condition, results of operations and liquidity if these expenditures, as with all costs, are not ultimately reflected in the tariffs and other fees we receive for our services.

We own or lease a number of properties that were used to transport, store or distribute products for many years before we acquired them; therefore, such properties were operated by third parties whose handling, disposal or release of products and wastes was not under our control. Environmental laws and regulations could impose obligations to conduct assessment or remediation efforts at our facilities, third-party sites where we take wastes for disposal, or where wastes have migrated. Environmental laws and regulations also may impose joint and several liability on us for the conduct of third parties or for actions that complied with applicable requirements when taken, regardless of negligence or fault. If we were to incur a significant liability pursuant to environmental, health, safety or security laws or regulations, such a liability could have a material adverse effect on our financial position.


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Our interstate common carrier pipelines are subject to regulation by the FERC.
The FERC regulates the tariff rates and terms and conditions of service for interstate oil movements on our common carrier pipelines. FERC regulations require that these rates must be just and reasonable and that the pipeline not engage in undue discrimination or undue preference with respect to any shipper. Under the ICA, the FERC or shippers may challenge our pipeline tariff filings, including rates and terms and conditions of service. Further, other than for rates set under market-based rate authority, if a new rate is challenged by protest and investigated by the FERC, the FERC may suspend collection of such new rate for up to seven months. If such new rate is found to be unjust and unreasonable, the FERC may order refunds of amounts collected in excess of amounts generated by the just and reasonable rate determined by the FERC. A successful rate challenge could result in a common carrier paying refunds together with interest for the period that the rate was in effect. In addition, shippers may challenge by complaint tariff rates and terms and conditions of service even after the rates and terms and conditions of service are in effect. If the FERC, in response to such a complaint or on its own initiative, initiates an investigation of rates that are already in effect, the FERC may order a carrier to change its rates prospectively. If existing rates are challenged and are determined by the FERC to be in excess of a just and reasonable level, any complaining shipper may obtain reparations for damages sustained during the two years prior to the date the shipper filed a complaint.

We are able to use various FERC-authorized rate change methodologies for our interstate pipelines, including indexed rates, cost-of-service rates, market-based rates and settlement rates. Typically, we adjust our rates annually in accordance with the FERC indexing methodology, which currently allows a pipeline to change its rates within prescribed ceiling levels that are tied to an inflation index. For the five-year period beginning July 1, 2011, the index was measured by the year-over-year change in the Bureau of Labor’s producer price index for finished goods, plus 2.65%. For the five-year period beginning July 1, 2016, which will end on June 30, 2021, the current index is measured by the year-over-year change in the Bureau of Labor’s producer price index for finished goods, plus 1.23%. It is possible that the index may result in a negative adjustment in some years, in which case we are required to reduce any rates that exceed the new maximum allowable rate. It is also possible that changes in the index might not be large enough to fully reflect actual increases in our costs. Some of our newer projects that have involved an open season include negotiated indexation rate caps that restrict the index rate increases that can be made during the term of the applicable transportation service agreements.

In October 2016, the FERC initiated an Advance Notice of Proposed Rulemaking (ANOPR) to determine whether to require oil pipeline companies to file cost and revenue data for each of the company’s pipeline systems, with the definition of such systems also part of the ANOPR. Among other things, the ANOPR also proposed that index rate adjustments be capped or prohibited under certain circumstances and that ceiling rates be capped under certain circumstances. In particular, the FERC has proposed denying index increases to a pipeline if its FERC Form No. 6 reflects revenues in excess of total cost of service by 15% for both of the prior two years or the proposed index increase would exceed by 5% the pipeline’s annual cost changes. The FERC also has proposed requiring pipelines to file additional information for crude and product pipelines, non-contiguous systems and major pipeline systems. The ANOPR remains pending and FERC has taken no action with regard to the ANOPR since receiving initial comments. The methodologies proposed in the ANOPR, if adopted, could result in changes in our revenue that do not fully reflect changes in costs we incur to operate and maintain our pipelines. They also could lead to an increase in rate litigation at the FERC.

In March 2018, the FERC, in its Revised Policy Statement on the Treatment of Income Taxes (Revised Policy), reversed its long-standing policy that allowed master limited partnership (MLP) pipelines to include in their cost of service an income tax allowance (ITA) if they could demonstrate that the ultimate pipeline owners have an actual or potential income tax liability on such income. The FERC stated that the reversal was required by a July 2016 D.C. Circuit Court of Appeals decision that found the FERC had failed to demonstrate that there is no double recovery of taxes for partnerships that receive an income tax allowance in addition to the return they receive through the rate of return on equity. In July 2018, in an order on rehearing, the FERC modified the Revised Policy by providing MLP pipelines with the opportunity to argue for inclusion of an ITA on a case-by-case basis, as opposed to having no opportunity to recover an ITA. The order on rehearing also allowed pipelines that will no longer recover an ITA to eliminate previously Accumulated Deferred Income Tax from cost of service, instead of flowing those amounts back to ratepayers, which has the effect of increasing a pipeline’s cost of service. Petitions for review of the Revised Policy and order on rehearing have been filed and are currently pending in the D.C. Circuit Court of Appeals.

The Revised Policy and order on rehearing do not impact market-based rates or settlement rates, and have no immediate impact on indexed rates, based on the fact that the current index will remain in effect through June 30, 2021. However, following issuance of the Revised Policy, the FERC now requires liquids pipelines organized as MLPs to eliminate the MLP ITA in their Form No. 6, page 700 reporting. The FERC has stated that it will incorporate the effects of this change to the page 700 data when it commences its next five-year review of the oil pipeline index level in 2020, for rates that will take effect on July 1, 2021. The FERC has not yet commenced this proceeding.


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Changes to FERC rate-making principles or pronouncements could have an adverse impact on our ability to recover the full cost of operating our pipeline facilities and our ability to make distributions to our unitholders.
If the FERC’s ratemaking methodologies change, such change or new methodologies could result in rates that generate lower revenues and cash flow and could adversely affect our ability to make distributions to our unitholders and to meet our debt service requirements. We believe our rates are consistent with FERC statutory and regulatory requirements, but challenges to our rates could be filed with the FERC and FERC decisions resulting from those challenges could reduce our rates and adversely affect our cash flows. Additionally, because competition constrains our rates in various markets, we may from time to time be forced to reduce some of our rates to remain competitive.

The rates that we may charge on our interstate ammonia pipeline are subject to regulation by the STB.
The Ammonia Pipeline is subject to regulation by the STB, which is part of the DOT. The Ammonia Pipeline’s rates, rules and practices related to the interstate transportation of anhydrous ammonia must be reasonable and, in providing interstate transportation, our Ammonia Pipeline may not subject a shipper to unreasonable discrimination.

Increases in natural gas and power prices could adversely affect our operating expenses and our ability to make distributions to our unitholders.
Power costs constitute a significant portion of our operating expenses. For the year ended December 31, 2018, our power costs equaled approximately $56.4 million, or 11.6% of our operating expenses for the year. We use mainly electric power at our pipeline pump stations and terminals, and such electric power is furnished by various utility companies that primarily use natural gas to generate electricity. Accordingly, our power costs typically fluctuate with natural gas prices, and increases in natural gas prices may cause our power costs to increase further. If natural gas prices increase, our cash flows may be adversely affected, which could adversely affect our ability to make distributions to our unitholders.

Terrorist attacks and the threat of future attacks worldwide, as well as continued hostilities in the Middle East or other sustained military campaigns, may adversely impact our results of operations.
The United States Department of Homeland Security has identified pipelines and other energy infrastructure assets as ones that might be specific targets of terrorist organizations. These potential targets might include our pipeline systems, storage facilities or operating systems and may affect our ability to operate or control our pipeline and storage assets. Increased security measures we have taken as a precaution against possible terrorist attacks have resulted in increased costs to our business. Uncertainty surrounding continued hostilities in the Middle East or other sustained military campaigns may affect our operations in unpredictable ways, including disruptions of crude oil supplies and markets for refined products, instability in the financial markets that could restrict our ability to raise capital and the possibility that infrastructure facilities could be direct targets of, or indirect casualties of, an attack.

Hedging transactions may limit our potential gains or result in significant financial losses.
While intended to reduce the effects of volatile commodity prices, hedging transactions, depending on the hedging instrument used, may limit our potential gains if petroleum product prices were to rise substantially over the price established by the hedge. In addition, such transactions may expose us to the risk of financial loss in certain circumstances, including instances in which there is a change in the expected differential between the underlying price in the hedging agreement and the actual prices received.

The accounting standards regarding hedge accounting are complex and, even when we engage in hedging transactions that are effective economically, these transactions may not be considered effective for accounting purposes. Accordingly, our financial statements will reflect increased volatility due to these hedges, even when there is no underlying economic impact at that point. It is not possible for us to engage in a hedging transaction that completely mitigates our exposure to commodity prices, and our financial statements may reflect a gain or loss arising from an exposure to commodity prices for which we are unable to enter into an effective hedge.

Our purchase and sale of petroleum products may expose us to trading losses and hedging losses, and non-compliance with our risk management policies could result in significant financial losses.
Although our marketing and trading of petroleum products represent a small percentage of our overall business, these activities expose us to some commodity price volatility risk for the purchase and sale of petroleum products, including distillates and fuel oil. We attempt to mitigate this volatility risk through hedging, but we are still exposed to basis risk and may be required to post cash collateral under our hedging arrangements. We also may be exposed to inventory and financial liquidity risk due to the inability to trade certain products or rising costs of carrying some inventories. Further, our marketing and trading activities, including any hedging activities, may cause volatility in our earnings. In addition, we will be exposed to credit risk in the event of non-performance by counterparties.


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Our risk management policies may not eliminate all price risk since open trading positions will expose us to price volatility, and there is a risk that our risk management policies will not be complied with. Although we have designed procedures to anticipate and detect non-compliance, we cannot assure you that these steps will detect and prevent all violations of our trading policies and procedures, particularly if deception and other intentional misconduct are involved.

If we fail to maintain an effective system of internal controls, we may not be able to report our financial results accurately or prevent fraud, which could have a material and adverse impact on our financial condition, results of operations, cash flows and ability to make distributions to our unitholders.
Under Section 404 of the Sarbanes-Oxley Act of 2002, we are required to disclose material changes made in our internal controls over financial reporting on a quarterly basis and we are required to assess the effectiveness of our controls annually. Effective internal controls are necessary for us to provide reliable and timely financial reports. Given the difficulties inherent in the design and operation of internal controls over financial reporting, we may be unable to maintain effective controls over our financial processes and reporting in the future or to comply with our obligations under Section 404.

For the foregoing reasons, we can provide no assurance as to our, or our independent registered public accounting firm’s, future conclusions about the effectiveness of our internal controls, and we may incur significant costs in our efforts to comply with Section 404. Any failure to maintain effective internal controls over financial reporting will subject us to regulatory scrutiny and a loss of confidence in our reported financial information, which could have a material adverse effect on our financial condition, results of operations and cash flows and our ability to make distributions to our unitholders.

RISKS INHERENT IN AN INVESTMENT IN US

As a master limited partnership, we do not have the same flexibility as corporations and other types of organizations may have to accumulate cash and equity and prevent illiquidity in the future.
Unlike a corporation, our partnership agreement requires us to make quarterly distributions to our common unitholders of all available cash, after taking into account reserves for commitments and contingencies, including capital and operating costs, debt service requirements and payments with respect to our preferred units. As a result, we do not accumulate equity in the form of retained earnings in a manner typical of many other forms of organizations, including most traditional public corporations. We are therefore more likely than those organizations to require issuances of additional debt and equity securities to finance our growth plans, meet unforeseen cash requirements and service our debt and other obligations.

Additionally, the value of our common units and other limited partner interests may decrease in correlation with any reduction in our cash distributions per unit. Accordingly, if we experience a liquidity shortage in the future, we may not be able to issue more equity to recapitalize.

Our cash distribution policy may limit our growth.
In accordance with the terms of our partnership agreement, we distribute our available cash to our common unitholders each quarter. In determining the amount of cash available for distribution, we set aside cash reserves, which we use to fund our growth capital expenditures. Additionally, we historically have relied upon external financing sources, including commercial borrowings and other debt and equity issuances, to fund our strategic capital expenditures and acquisitions. Accordingly, to the extent we do not have sufficient cash reserves or are unable to finance growth externally, our cash distribution policy will significantly impair our ability to grow. In addition, to the extent we issue additional units in connection with any acquisitions or growth capital expenditures, the payment of distributions on those additional units may increase the risk that we will be unable to maintain our current per unit distribution level.

Unitholders have limited voting rights, and our partnership agreement restricts the voting rights of certain unitholders owning 20% or more of any class of our units.
Unlike holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Unitholders’ voting rights are further restricted by a provision in our partnership agreement providing that units held by certain persons that own 20% or more of any class of units then outstanding cannot vote on any matter without the prior approval of our general partner.


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We may issue additional equity securities, including equity securities that are senior to the common units, which would dilute our unitholders’ existing ownership interests.
Our partnership agreement allows us to issue additional equity securities without the approval of other unitholders as long as the newly issued equity securities are not senior to, or pari passu with, our preferred units. There is no limit on the total number of equity securities we may issue. If we issue additional equity securities, the proportionate partnership interest of our existing common unitholders and the relative voting strength of the previously outstanding common units and Series D Preferred Units will decrease. Any additional issuance may increase the risk that we will be unable to maintain or increase our per common unit distribution level.

With the consent of a majority of the Series D Preferred Units, we may issue an unlimited number of units that are senior to the common units and pari passu with our preferred units. However, in certain circumstances, we may be required to obtain the approval of a majority of each class of our preferred units before we could issue equity securities that are pari passu with our preferred units.

Our issuance of additional units or other equity interests 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 ratio of taxable income to distributions may increase;
the relative voting strength of each previously outstanding unit may be diminished; and
the market price of our common units and preferred units may decline.

Holders of our Series D Preferred Units generally have the same voting rights as holders of our common units and generally vote on an as-converted basis with the holders of our common units as a single class. Although holders of our other preferred units also have voting rights, such rights are limited to certain matters and require that such holders vote as a separate class with all other series of our equally ranked securities that may be issued and possess similar voting rights. As a result, the voting rights of holders of our preferred units may be significantly diluted, and the holders of such future securities of equal rank may be able to control or significantly influence the outcome of any vote with respect to which the holders of the preferred units are entitled to vote.

The issuance of additional units of equal or senior rank to the preferred units (including additional preferred units of the same series) would dilute the interests of the holders of the preferred units. Furthermore, any issuance of (a) equity securities of any class or series that ranks equally with the preferred units as to (i) the payment of distributions or (ii) the amounts payable upon a liquidation event (including additional preferred units of the same series) or (b) equity securities with terms expressly made senior to the preferred units as to (i) the payment of distributions or (ii) amounts payable upon a liquidation event or additional indebtedness, could affect our ability to pay distributions on, redeem or pay the liquidation preference on the preferred units.

Our partnership agreement contains limited protections for the holders of our preferred units (other than Series D Preferred Units) in the event of a transaction, including a merger, sale, lease or conveyance of all or substantially all of our assets or business, which might adversely affect the holders of the preferred units.

Future issuances and sales of securities that rank equally with our preferred units, or the perception that such issuances and sales could occur, may cause prevailing market prices for our preferred units and our common units to decline and may adversely affect our ability to raise additional capital in the financial markets at times and prices favorable to us.

Furthermore, the payment of distributions on any additional units may increase the risk that we will not be able to make distributions at our prior per unit distribution levels. To the extent new units are senior to our common units, their issuance will increase the uncertainty of the payment of distributions on our common units.

If we do not pay distributions on our preferred units in any distribution period, we will be unable to declare or pay distributions on our common units until all unpaid preferred unit distributions have been paid, and our common unitholders are not entitled to receive distributions for such prior period.
Our preferred units rank senior to our common units with respect to distribution rights and rights upon liquidation. If we do not pay the required distributions on our preferred units, we will be unable to declare or pay distributions on our common units. Additionally, because distributions to our preferred unitholders are cumulative, we will have to pay all unpaid accumulated preferred distributions before we can declare or pay any distributions to our common unitholders. Also, because distributions to our common unitholders are not cumulative, if we do not pay distributions on our common units with respect to any quarter, our common unitholders will not be entitled to receive distributions covering any prior periods. In addition, if we do not pay the required distributions on our Series D Preferred Units for three consecutive distribution periods, the holders of our Series D Preferred Units have certain additional rights until such distributions are paid, including the right to convert the Series D

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Preferred Units into common units, the right to appoint one director to our board of directors and the right to approve certain indebtedness, acquisitions or asset sales. The preferences and privileges of our preferred units could adversely affect the market price for our common units, or could make it more difficult for us to sell our common units in the future.

Unitholders may not have limited liability if a court finds that unitholder action constitutes control of our business or that we have not complied with applicable statutes, which may have an impact on the cash we have available to make distributions.
Under Delaware law, unitholders could be held liable for our obligations to the same extent as a general partner if a court determined that actions of a unitholder constituted participation in the “control” of our business.

Under Delaware law, the general partner generally has unlimited liability for the obligations of the partnership, such as its debts and environmental liabilities, except for those contractual obligations of the partnership that are expressly made without recourse to the general partner. In addition, Section 17-607 of the Delaware Revised Uniform Limited Partnership Act (the Delaware Act) provides that, under some circumstances, a limited partner may be liable to us for the amount of a distribution for a period of three years from the date of the distribution.

Under certain circumstances, unitholders may have liability to repay distributions wrongfully distributed to them.
Under Section 17-607 of the Delaware Act, we may not make a distribution to our unitholders if the distribution would cause our liabilities to exceed the fair value of our assets. Liabilities to partners on account of their partnership interests and liabilities that are nonrecourse to the partnership are not counted for purposes of determining whether a distribution is permitted. 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 us for the repayment of the distribution amount. Likewise, upon the winding up of our partnership, in the event that (a) we do not distribute assets in the following order: (1) to creditors in satisfaction of our debts; (2) to partners and former partners in satisfaction of liabilities for distributions owed under our partnership agreement; (3) to partners for the return of their contributions; and finally (4) to the partners in the proportions in which the partners share in distributions and (b) a limited partner knows at the time that the distribution violated the Delaware Act, then such limited partner will be liable to repay the distribution for a period of three years from the impermissible distribution under Section 17-804 of the Delaware Act.

A purchaser of our common or preferred units becomes a limited partner and is liable for the obligations of the transferring limited partner to make contributions to us that are known to such purchaser of common or preferred units at the time it became a limited partner and, for unknown obligations, if the liabilities could be determined from our partnership agreement.

Unitholders may be required to sell their units to our general partner at an undesirable time or price.
If at any time less than 20% of the outstanding units of any class (other than our preferred units) are held by persons other than the general partner and its affiliates, the general partner will have the right to acquire all, but not less than all, of those units at a price no less than their then-current market price. As a consequence, a unitholder may be required to sell his common units at an undesirable time or price. The general partner may assign this purchase right to any of its affiliates or to us.

The NYSE does not require a publicly traded limited partnership like us to comply with certain of its corporate governance requirements.
We currently list our common units on the NYSE under the symbol “NS” and certain of our preferred units on the NYSE under the symbols “NSprA,” “NSprB” and “NSprC,” respectively. Although our general partner has maintained a majority of independent directors on its board and all members of its board’s audit committee, compensation committee and nominating/governance & conflicts committee are independent directors, because we are a publicly traded limited partnership, the NYSE does not require us to have a majority of independent directors on our general partner’s board of directors or to have a compensation committee or a nominating committee consisting of independent directors. Additionally, any future issuance of additional common or preferred units or other securities, including to affiliates, will not be subject to the NYSE’s shareholder approval rules that apply to a corporation. Accordingly, the NYSE does not mandate the same protections for our unitholders as are required for certain corporations that are subject to all of the NYSE corporate governance requirements.


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TAX RISKS TO OUR UNITHOLDERS

If we were treated as a corporation for federal or state income tax purposes or we were otherwise subject to a material amount of entity-level taxation, then our cash available for distribution to unitholders would be substantially reduced.
The anticipated after-tax benefit of an investment in our units depends largely on our being treated as a partnership for federal income tax purposes. We have not requested, and do not plan to request, a ruling from the Internal Revenue Service (the IRS) on this matter.

Despite the fact that we are a limited partnership under Delaware law, we will be treated as a corporation for federal income tax purposes unless we satisfy a “qualifying income” requirement. Based upon our current operations, we believe we satisfy the qualifying income requirement. Failing to meet the qualifying income requirement 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 and would likely pay state and local income tax at varying rates. Distributions to unitholders who are treated as holders of corporate stock would generally be taxed again as corporate dividends (to the extent of our current and accumulated earnings and profits), and no income, gains, losses, deductions or credits would flow through to unitholders. Because a tax would be imposed upon us as a corporation, our distributable cash flow would be substantially reduced.

Moreover, changes in current state law may subject us to entity-level taxation by individual states. 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. Imposition of any such taxes or an increase in the existing tax rates would substantially reduce the cash available for distribution to our unitholders. Therefore, if we were treated as a corporation for federal income tax purposes or otherwise subjected to a material amount of entity-level taxation, there would be 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 units.

The tax treatment of publicly traded partnerships or an investment in our units could be subject to potential legislative, judicial or administrative changes or differing interpretations, possibly applied on a retroactive basis.
The present U.S. federal income tax treatment of publicly traded partnerships, including us, or an investment in our units may be modified by administrative, legislative or judicial changes or differing interpretations at any time. From time to time, members of Congress propose and consider such substantive changes to the existing federal income tax laws that affect publicly traded partnerships.

The Tax Cuts and Jobs Act enacted December 22, 2017 made significant changes to the U.S. federal income tax rules applicable to both individuals and entities, including changes to the tax rate on a unitholder’s allocable share of income from the publicly traded partnership. Unitholders should consult their tax advisor regarding the impact of the Tax Cuts and Jobs Act (and any other applicable tax laws, rules and regulations) on us or an investment in our units.

Any changes to the federal income tax laws and interpretations thereof (including administrative guidance relating to the Tax Cuts and Jobs Act) may be applied retroactively and could make it more difficult or impossible for us to meet the exception for certain publicly traded partnerships to be treated as partnerships for federal income tax purposes or otherwise adversely affect our business, financial condition or results of operations. We are unable to predict whether any additional changes or other proposals will ultimately be enacted. Any such changes could negatively impact the value of an investment in our units.

A successful IRS contest of the federal income tax positions we take may adversely impact the market for our units, and the costs of any contest will reduce cash available for distribution to our unitholders.
The IRS may adopt positions that differ from the positions we take, even positions taken with the advice of counsel. 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 all of the positions we take. Any contest with the IRS may affect adversely the taxable income reported to our unitholders and the income taxes they are required to pay. As a result, any such contest with the IRS may materially and adversely impact the market for our units and the prices at which they trade. In addition, the costs of any contest between us and the IRS will be borne indirectly by our unitholders and our general partner because such costs will reduce our cash available for distribution.


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If the IRS makes audit adjustments to our income tax returns for tax years beginning after December 31, 2017, it (and some states) may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustment directly from us, in which case we may elect to either pay the taxes directly to the IRS or to have our unitholders and former unitholders take such audit adjustment into account and pay any resulting taxes. If we bear such payment, our cash available for distribution to our unitholders might be substantially reduced .
Pursuant to the Bipartisan Budget Act of 2015, for tax years beginning after December 31, 2017, if the IRS makes audit adjustments to our income tax returns, it (and some states) may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustment directly from us. To the extent possible under the new rules, our general partner may elect to either pay the taxes (including any applicable penalties and interest) directly to the IRS or, if we are eligible, issue a revised Schedule K-1 to each unitholder with respect to an audited and adjusted return. Although our general partner may elect to have our unitholders and former unitholders take such audit adjustment into account and pay any resulting taxes (including applicable penalties or interest) in accordance with their interests in us during the tax year under audit, there can be no assurance that such election will be practical, permissible or effective in all circumstances. As a result, our current unitholders may bear some or all of the tax liability resulting from such audit adjustment, even if such unitholders did not own common units in us during the tax year under audit. If, as a result of any such audit adjustment, we make payments of taxes, penalties and interest, our cash available for distribution to our unitholders might be substantially reduced.

Even if unitholders do not receive any cash distributions from us, they will be required to pay taxes on their respective share of our taxable income.
Unitholders will be required to pay federal income taxes and, in some cases, state and local income taxes on their respective share of our taxable income, whether or not the unitholders receive cash distributions from us. Unitholders may not receive cash distributions from us equal to their respective share of our taxable income or even equal to the actual tax liability that results from their respective share of our taxable income.

Tax gain or loss on the disposition of our units could be different than expected.
If a unitholder sells units, the selling unitholder will recognize a gain or loss equal to the difference between the amount realized and the unitholder’s tax basis in those units. Prior distributions to the selling unitholder in excess of the total net taxable income the unitholder was allocated for a unit, which decreased the unitholder’s tax basis in that unit, will, in effect, become taxable income to the selling unitholder if the unit is sold at a price greater than the unitholder’s tax basis in that unit, even if the price the unitholder receives is less than the unit’s original cost. A substantial portion of the amount realized, whether or not representing gain, may be ordinary income to the selling unitholder.

Unitholders may be subject to limitations on their ability to deduct interest expense incurred by us.
In general, we are entitled to a deduction for interest paid or accrued on indebtedness properly allocable to our trade or business during our taxable year. However, under the Tax Cuts and Jobs Act, for taxable years beginning after December 31, 2017, a deduction for “business interest” is limited to the sum of our business interest income plus 30% of our “adjusted taxable income.” Recently issued proposed regulations would institute a broad definition of interest, treating certain amounts, including amounts paid as guaranteed payments for the use of capital with respect to our preferred units, as business interest subject to the limitation. This limitation is applied at the entity level for partnerships. For the purposes of this limitation, our adjusted taxable income is computed without regard to any business interest expense or business interest income, and in the case of taxable years beginning before January 1, 2022, any deduction allowable for depreciation, amortization, or depletion. Any interest disallowed at the partnership level may be carried forward and deducted in future years by a unitholder from his share of our “excess taxable income,” which is generally equal to the excess of 30% of our adjusted taxable income over the amount of our deduction for business interest for such future taxable year, subject to certain restrictions.

Tax-exempt entities face unique tax issues from owning our units that may result in adverse tax consequences to them.
Investment in our units by tax-exempt entities, such as employee benefit plans and individual retirement accounts (known as IRAs) raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from U.S. federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. Further, with respect to taxable years beginning after December 31, 2017, a tax-exempt entity with more than one unrelated trade or business (including by attribution from investment in a partnership such as ours) is required to compute the unrelated business taxable income of such tax-exempt entity separately with respect to each such trade or business (including for purposes of determining any net operating loss deduction). As a result, for years beginning after December 31, 2017, it may not be possible for tax-exempt entities to utilize losses from an investment in us to offset unrelated business taxable income from another unrelated trade or business and vice versa. Tax-exempt entities should consult a tax advisor before investing in our units.


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Non-U.S. unitholders will be subject to U.S. taxes and withholding with respect to their income and gain from owning our units.
Non-U.S. unitholders are subject to U.S. federal income tax on income effectively connected with a U.S. trade or business (effectively connected income). A unitholder’s share of our income, gain, loss and deduction, and any gain from the sale or disposition of our units will generally be considered to be “effectively connected” with a U.S. trade or business and subject to U.S. federal income tax. Additionally, distributions to a non-U.S. unitholder will be subject to withholding at the highest applicable effective tax rate.

The Tax Cuts and Jobs Act imposes a withholding obligation of 10% of the amount realized upon a non-U.S. unitholder’s sale or disposition of units. The IRS has temporarily suspended the application of the withholding requirements on sales of publicly traded interests, including our units, pending promulgation of regulations or other guidance. Non-U.S. unitholders should consult a tax advisor before investing in our units.

We will treat each purchaser of our common units as having the same tax benefits without regard to the 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 will adopt depreciation and amortization positions that may not conform with all aspects of existing Treasury regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to unitholders. It also could affect the timing of these tax benefits or the amount of gain from a unitholder’s sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to the unitholder’s tax returns.

Unitholders will likely be subject to state and local taxes and return filing requirements as a result of investing in our units.
In addition to federal income taxes, unitholders will likely be subject to other taxes, such as state and local income 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. Unitholders will likely be required to file state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions. Further, unitholders may be subject to penalties for failure to comply with those requirements. We may own property or conduct business in other states or foreign countries in the future. It is each unitholder’s responsibility to file all federal, state and local tax returns.

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. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our common unitholders.
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. The U.S. Treasury Department and the IRS issued final regulations adopting a similar monthly convention, but such regulations do not specifically authorize all aspects of our proration method. If the IRS were to challenge our proration method, we may be required to change the allocation of items of income, gain, loss and deduction among our common unitholders.

We have adopted certain valuation methodologies in determining a common unitholder’s allocations of income, gain, loss and deduction. The IRS may challenge these methods or the resulting allocations and such a challenge could adversely affect the value of our common units.
In determining the items of income, gain, loss and deduction allocable to our common unitholders, we must routinely determine the fair market value of our respective assets. Although we may from time to time consult with professional appraisers regarding valuation matters, we make fair market value estimates using a methodology based on the market value of our common units as a means to measure the fair market value of our respective assets. The IRS may challenge these valuation methods and the resulting allocations of income, gain, loss and deduction.

A successful IRS challenge to these methods or allocations could adversely affect the amount, character and timing of taxable income or loss being allocated to our common unitholders. It also could affect the amount of gain from our unitholders’ sale of common units and could have a negative impact on the value of the common units or result in audit adjustments to our common unitholders’ tax returns without the benefit of additional deductions.


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A unitholder whose units are the subject of a securities loan (e.g., a loan to a “short seller” to cover a short sale of units) may be considered as having disposed of those units. If so, the 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 there are no specific rules governing the federal income tax consequences of loaning a partnership interest, a unitholder whose units are the subject of a securities loan may be considered as having disposed of the loaned units. In that case, the 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, 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 consult a tax advisor to discuss whether it is advisable to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their units.

Treatment of distributions on our preferred units as guaranteed payments for the use of capital creates a different tax treatment for the holders of preferred units than the holders of our common units and such distributions are not eligible for the 20% deduction for qualified publicly traded partnership income.
The tax treatment of distributions on our preferred units is uncertain. We will treat the holders of preferred units as partners for tax purposes and will treat distributions on the preferred units as guaranteed payments for the use of capital that will generally be taxable to the holders of preferred units as ordinary income. Although a holder of preferred units could recognize taxable income from the accrual of such a guaranteed payment even in the absence of a contemporaneous distribution, we anticipate accruing and making the guaranteed payment distributions quarterly. Otherwise, the holders of preferred units are generally not anticipated to share in our items of income, gain, loss or deduction, nor will we allocate any share of our nonrecourse liabilities to the holders of preferred units. If the preferred units were treated as indebtedness for tax purposes, rather than as guaranteed payments for the use of capital, distributions likely would be treated as payments of interest by us to the holders of preferred units.

The Tax Cuts and Jobs Act allows individuals and other non-corporate owners of interests in a publicly traded partnership to take a deduction equal to 20% of their allocable share of the partnership’s income that is “qualified publicly traded partnership income.” However, under recently issued final Treasury regulations, income attributable to a guaranteed payment for the use of capital is not eligible for the 20% deduction. As a result, distributions on the preferred units will be taxable to holders of preferred units as ordinary income that is not eligible for the 20% deduction for qualified publicly traded partnership income.

A holder of preferred units will be required to recognize gain or loss on a sale of preferred units equal to the difference between the amount realized by such holder and tax basis in the preferred units sold. The amount realized generally will equal the sum of the cash and the fair market value of other property such holder receives in exchange for such preferred units. Subject to general rules requiring a blended basis among multiple partnership interests, the tax basis of a preferred unit will generally be equal to the sum of the cash and the fair market value of other property paid by the holder of preferred units to acquire such preferred unit. Gain or loss recognized by a holder of preferred units on the sale or exchange of a preferred unit held for more than one year generally will be taxable as long-term capital gain or loss. Because holders of preferred units will generally not be allocated a share of our items of depreciation, depletion or amortization, it is not anticipated that such holders would be required to recharacterize any portion of their gain as ordinary income as a result of the recapture rules.

Investment in the preferred units by tax-exempt investors, such as employee benefit plans and IRAs, and non-U.S. persons raises issues unique to them. A non-U.S. holder’s income from guaranteed payments and any gain from the sale or disposition of our units will generally be considered to be effectively connected income and subject to U.S. federal income tax. Distributions to non-U.S. holders of preferred units will be subject to withholding taxes. If the amount of withholding exceeds the amount of U.S. federal income tax actually due, non-U.S. holders of preferred units may be required to file U.S. federal income tax returns in order to seek a refund of such excess. The Tax Cuts and Jobs Act imposes a withholding obligation of 10% of the amount realized upon a non-U.S. unitholder’s sale or disposition of preferred units. The IRS has temporarily suspended the application of the withholding requirements on sales of publicly traded interests, including our preferred units, pending promulgation of regulations or other guidance. Additionally, the treatment of guaranteed payments for the use of capital to tax exempt investors is not certain and such payments may be treated as unrelated business taxable income for federal income tax purposes.

All holders of our preferred units are urged to consult a tax advisor with respect to the financial consequences of owning our preferred units.



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PROPERTIES

Our principal properties are described above under the caption “Segments,” and that information is incorporated herein by reference. We believe that we have satisfactory title to all of our properties. Although title to these properties is subject to encumbrances in some cases, such as customary interests generally retained in connection with the acquisition of real property, liens for current taxes and other burdens and easements, and restrictions or other encumbrances, including those related to environmental liabilities associated with historical operations, to which the underlying properties were subject at the time of acquisition by us or our predecessors, we believe that none of these burdens will materially detract from the value of these properties or from our interest in these properties or will materially interfere with their use in the operation of our business. In addition, we believe that we have obtained sufficient right-of-way grants and permits from public authorities and private parties for us to operate our business in all material respects as described in this report. We perform scheduled maintenance on all of our pipelines, terminals, crude oil tanks and related equipment and make repairs and replacements when necessary or appropriate. We believe that our pipelines, terminals, crude oil tanks and related equipment have been constructed and are maintained in all material respects in accordance with applicable federal, state and local laws and the regulations and standards prescribed by the American Petroleum Institute, the DOT and accepted industry practice.

ITEM 1B. UNRESOLVED STAFF COMMENTS
None.

ITEM 3.    LEGAL PROCEEDINGS

We are named as a defendant in litigation and are a party to other claims and legal proceedings relating to our normal business operations, including regulatory and environmental matters. Due to the inherent uncertainty of litigation, there can be no assurance that the resolution of any particular claim or proceeding would not have a material adverse effect on our results of operations, financial position or liquidity.

We are insured against various business risks to the extent we believe is prudent; however, we cannot assure you that the nature and amount of such insurance will be adequate, in every case, to protect us against liabilities arising from future legal proceedings as a result of our ordinary business activity.

ITEM 4.    MINE SAFETY DISCLOSURES
Not applicable.

37


PART II

ITEM 5.
MARKET FOR REGISTRANT’S COMMON UNITS, RELATED UNITHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
Common Unit Distributions
Our common units are listed and traded on the New York Stock Exchange under the symbol “NS.” At the close of business on February 15, 2019, we had 427 holders of record of our common units. During 2018, the board of directors of NuStar GP, LLC reset our quarterly distribution per common unit to $0.60 ( $2.40 on an annualized basis), starting with the first-quarter distribution, which was paid on May 14, 2018. The following table presents the amount, record date and payment date of the quarterly cash distributions on our common units with respect to 2018 and 2017 :
 
Cash Distributions
 
Amount Per
Common Unit
 
Record Date
 
Payment Date
Year 2018
 
 
 
 
 
4th Quarter
$
0.60

 
February 8, 2019
 
February 13, 2019
3rd Quarter
$
0.60

 
November 8, 2018
 
November 14, 2018
2nd Quarter
$
0.60

 
August 7, 2018
 
August 13, 2018
1st Quarter
$
0.60

 
May 8, 2018
 
May 14, 2018
Year 2017
 
 
 
 
 
4th Quarter
$
1.095

 
February 8, 2018
 
February 13, 2018
3rd Quarter
$
1.095

 
November 9, 2017
 
November 14, 2017
2nd Quarter
$
1.095

 
August 7, 2017
 
August 11, 2017
1st Quarter
$
1.095

 
May 8, 2017
 
May 12, 2017

Our partnership agreement requires that we distribute all “Available Cash” to our common limited partners and, prior to the merger with our general partner, to our general partner each quarter. This term is defined in the partnership agreement generally as cash on hand at the end of the quarter, plus certain permitted borrowings made subsequent to the end of the quarter, less cash reserves determined by our board of directors, subject to requirements for distributions for our preferred units. See Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” for further information regarding our distributions.

General Partner Distributions
Prior to the merger with our general partner, our Available Cash was distributed based on the percentages shown below:
 
 
Percentage of Distribution
Quarterly Distribution Amount Per Common Unit
 
Common
Unitholders
 
General 
Partner Including Incentive Distributions
Up to $0.60
 
98%
 
2%
Above $0.60 up to $0.66
 
90%
 
10%
Above $0.66
 
75%
 
25%
Our general partner’s incentive distributions totaled $45.7 million for the year ended 2017 . The general partner did not receive incentive distributions for 2018 because the distribution declared for the first quarter was $0.60 per common unit, which was below the amount necessary to receive incentive distributions. Furthermore, because the merger was effective prior to the record date for the second quarter distribution, the general partner received no distributions after the first quarter distribution. Pursuant to the merger agreement discussed in Note 4 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data,” and at the effective time of the merger, our partnership agreement was amended and restated to, among other things, cancel the incentive distribution rights held by our general partner and convert the 2% general partner interest in NuStar Energy held by our general partner into a non-economic management interest.
Due to the impact of the incentive distributions, the general partner’s share of our aggregate distributions for the year ended December 31, 2017 was 11.9% . In the second quarter of 2017, our general partner amended and restated our partnership agreement in connection with the issuance of the Series B Preferred Units described below and our acquisition of Navigator

38


Energy Services, LLC to waive up to an aggregate $22.0 million of the quarterly incentive distributions to our general partner for any NS common units issued from the date of the acquisition agreement, starting with the distributions for the second quarter of 2017.

Preferred Unit Distributions
The following table provides the terms related to distributions for our Series A, Series B and Series C Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units:
Units
 
Fixed Distribution Rate Per Annum (as a Percentage of the $25.00 Liquidation Preference Per Unit)
 
Fixed Distribution Rate Per Unit Per Annum
 
Fixed Distribution Per Annum
 
Optional Redemption Date/Date at Which Distribution Rate Becomes Floating
 
Floating Annual Rate (as a Percentage of the
$25.00 Liquidation
Preference Per Unit)
 
 
 
 
 
 
(Thousands of Dollars)
 
 
 
 
Series A Preferred Units
 
8.50%
 
$
2.125

 
$
19,253

 
December 15, 2021
 
Three-month LIBOR plus 6.766%
Series B Preferred Units
 
7.625%
 
$
1.90625

 
$
29,357

 
June 15, 2022
 
Three-month LIBOR plus 5.643%
Series C Preferred Units
 
9.00%
 
$
2.25

 
$
15,525

 
December 15, 2022
 
Three-month LIBOR plus 6.88%

The distribution rate on our Series D Cumulative Convertible Preferred Units (Series D Preferred Units) is (i) 9.75% per annum ($57.6 million) for the first two years; (ii) 10.75% per annum ($63.4 million) for years three through five; and (iii) the greater of 13.75% per annum ($81.1 million) or the distribution per common unit thereafter.

Distributions on the preferred units are payable out of any legally available funds, accrue and are cumulative from the original issuance dates, and are payable on the 15th day (or the next business day) of each of March, June, September and December of each year to holders of record on the first business day of each payment month. The preferred units rank equal to each other and senior to all of our other classes of equity securities with respect to distribution rights and rights upon liquidation. Please see Notes 19 and 20 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for additional information on distributions to our preferred unitholders.
















39


Performance Graph
The following Performance Graph is not “soliciting material,” is not deemed filed with the SEC and is not to be incorporated by reference into any of NuStar Energy’s filings under the Securities Act of 1933 or the Securities Exchange Act of 1934, as amended, respectively. The stock or unit price performance included in this graph is not necessarily indicative of future stock or unit price performance.

The following graph compares the cumulative five-year total return provided to holders of NuStar Energy’s common units relative to the cumulative total returns of the S&P 500 index and the Alerian MLP index. An investment of $100 (with reinvestment of all dividends) is assumed to have been made in our common units and in each of the indexes on December 31, 2013, and its relative performance is tracked through December 31, 2018.

FIVEYEARRETURN.JPG
 
12/13
12/14
12/15
12/16
12/17
12/18
NuStar Energy L.P.
100.00

122.10

91.73

126.25

84.24

65.60

S&P 500 Index
100.00

113.69

115.26

129.05

157.22

150.33

Alerian MLP Index
100.00

104.80

70.65

83.58

78.13

68.43


Sales of Unregistered Securities
During the fourth quarter of 2018, NuStar Energy issued an aggregate of 18,234 common units in reliance upon an exemption from the registration requirements of the Securities Act of 1933, as amended, pursuant to Section 4(a)(2) thereof, upon the vesting of outstanding awards under a long-term incentive plan.

40


ITEM 6.    SELECTED FINANCIAL DATA
The following table contains selected financial data derived from our audited financial statements:
 
Year Ended December 31,
 
2018
 
2017
 
2016
 
2015
 
2014
 
(Thousands of Dollars, Except Per Unit Data)
Statement of Income Data:
 
 
 
 
 
 
 
 
 
Revenues (a)
$
1,961,757

 
$
1,814,019

 
$
1,756,682

 
$
2,084,040

 
$
3,075,118

Operating income
$
363,563

 
$
336,278

 
$
359,109

 
$
390,704

 
$
346,901

Income from continuing operations (b)
$
205,794

 
$
147,964

 
$
150,003

 
$
305,946

 
$
214,169

(Loss) income from continuing operations per
common unit (b)
$
(2.77
)
 
$
0.64

 
$
1.27

 
$
3.29

 
$
2.14

Cash distributions per unit applicable
to common limited partners (c)
$
2.40

 
$
4.38

 
$
4.38

 
$
4.38

 
$
4.38

 
 
 
 
 
 
 
 
 
 
 
December 31,
 
2018
 
2017 (d)
 
2016
 
2015
 
2014
 
(Thousands of Dollars)
Balance Sheet Data:
 
 
 
 
 
 
 
 
 
Property, plant and equipment, net
$
4,288,622

 
$
4,300,933

 
$
3,722,283

 
$
3,683,571

 
$
3,460,732

Total assets
$
6,349,140

 
$
6,535,233

 
$
5,030,545

 
$
5,125,525

 
$
4,918,796

Long-term debt, less current portion
$
3,111,996

 
$
3,263,069

 
$
3,014,364

 
$
3,055,612

 
$
2,749,452

Total partners’ equity
$
2,257,731

 
$
2,480,089

 
$
1,611,617

 
$
1,609,844

 
$
1,716,210

(a)
On January 1, 2018, we adopted Accounting Standards Codification Topic 606, “Revenue from Contracts with Customers” (ASC Topic 606) using the modified retrospective method and applying ASC Topic 606 to all revenue contracts with customers. Results for reporting periods beginning after January 1, 2018 are presented under ASC Topic 606. In accordance with the modified retrospective approach, prior period amounts were not adjusted and are reported under ASC Topic 605, “Revenue Recognition.”
Declines in revenues from 2014 through 2017 are mainly from a reduction in marketing activity and lower commodity prices. We ceased marketing crude oil in the second quarter of 2017 and exited our heavy fuels trading operations in the third quarter of 2017.
(b)
Includes the impact of a $78.8 million gain from hurricane insurance proceeds received in 2018, a $43.4 million non-cash loss associated with the sale of our European operations in 2018, a $58.7 million non-cash impairment charge on the term loan to Axeon Specialty Products, LLC in 2016 and a $56.3 million non-cash gain associated with the Linden terminal acquisition in 2015. (Loss) income from continuing operations per common unit also includes the impact of a $377.1 million loss as a result of the July 2018 merger with our general partner. Please refer to Notes 4 and 21 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for further discussion.
(c)
The board of directors of NuStar GP, LLC reset our quarterly distribution per common unit to $0.60 ( $2.40 on an annualized basis), starting with the distribution for the first quarter of 2018.
(d)
The significant increases in balance sheet data and income statement data are primarily due to our acquisition of Navigator Energy Services, LLC for approximately $1.5 billion in May 2017.

41


ITEM 7.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following review of our results of operations and financial condition should be read in conjunction with “Cautionary Statement Regarding Forward-Looking Information,” Items 1., 1A. and 2. “Business, Risk Factors and Properties” and Item 8. “Financial Statements and Supplementary Data” included in this report.

NuStar Energy L.P. (NYSE: NS) is engaged in the transportation of petroleum products and anhydrous ammonia, and the terminalling, storage and marketing of petroleum products. Unless otherwise indicated, the terms “NuStar Energy,” “NS,” “the Partnership,” “we,” “our” and “us” are used in this report to refer to NuStar Energy L.P., to one or more of our consolidated subsidiaries or to all of them taken as a whole. Our Management’s Discussion and Analysis of Financial Condition and Results of Operations is presented below in seven sections:
Overview
Results of Operations
Trends and Outlook
Liquidity and Capital Resources
Related Party Transactions
Critical Accounting Policies
New Accounting Pronouncements

OVERVIEW
Recent Developments
Sale of European Operations. On November 30, 2018, we sold our European operations to Inter Terminals, Ltd. for approximately $270.0 million . The operations sold include six liquids storage terminals in the United Kingdom and one facility in Amsterdam . Prior to the sale, the assets disposed of and the results of operations were included in our storage segment. We recognized a non-cash loss of $43.4 million related to the sale in “Other income (expense), net” on our consolidated statement of income for the year ended December 31, 2018. Please refer to Note 5 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for further discussion of the sale.

Merger. On February 7, 2018, NuStar Energy, Riverwalk Logistics, L.P., NuStar GP, LLC, Marshall Merger Sub LLC, a wholly owned subsidiary of NuStar Energy (Merger Sub), Riverwalk Holdings, LLC and NuStar GP Holdings, LLC (NuStar GP Holdings or NSH) entered into an Agreement and Plan of Merger (the Merger Agreement). Pursuant to the Merger Agreement, Merger Sub merged with and into NuStar GP Holdings, with NuStar GP Holdings being the surviving entity (the Merger), such that NuStar Energy became the sole member of NuStar GP Holdings following the Merger on July 20, 2018. Pursuant to the Merger Agreement and at the effective time of the Merger, our partnership agreement was amended and restated to, among other things, (i) cancel the incentive distribution rights held by our general partner, (ii) convert the 2% general partner interest in NuStar Energy held by our general partner into a non-economic management interest and (iii) provide the holders of our common units with voting rights in the election of the members of the board of directors of NuStar GP, LLC, beginning at the annual meeting in 2019. We issued approximately 13.4 million incremental NuStar Energy common units as a result of the Merger. Please refer to Note 4 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for further discussion of the Merger.

Issuances of Units. In June and July of 2018, we issued 23,246,650 Series D Cumulative Convertible Preferred Units (Series D Preferred Units) at a price of $25.38 per unit in a private placement for net proceeds of $555.8 million . Please refer to Note 19 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for further discussion. On June 29, 2018, we also issued 413,736 common units at a price of $24.17 per unit to William E. Greehey, Chairman of the Board of Directors of NuStar GP, LLC.

Council Bluffs Acquisition. On April 16, 2018, we acquired CHS Inc.’s Council Bluffs pipeline system, comprised of a 227-mile pipeline and 18 storage tanks, for approximately $37.5 million (the Council Bluffs Acquisition). The assets acquired and the results of operations are included in our pipeline segment, within the East Pipeline, from the date of acquisition. We accounted for this acquisition as an asset purchase.

Hurricane Activity. In the third quarter of 2017, several of our facilities were affected by the hurricanes in the Caribbean and Gulf of Mexico, including our St. Eustatius terminal, which experienced the most damage and was temporarily shut down. The damage caused by the Caribbean hurricane resulted in lower revenues for our bunker fuel operations in our fuels marketing segment and lower throughput and associated handling fees in our storage segment in 2017 and in the first quarter of 2018. In

42


2017, we received insurance proceeds of $12.5 million for damages at our St. Eustatius terminal, of which $3.8 million was for business interruption ($2.4 million recognized in the fuels marketing segment and $1.4 million in the storage segment). In January 2018, we received $87.5 million of insurance proceeds in settlement of our property damage claim for our St. Eustatius terminal, of which $9.1 million related to business interruption ( $5.6 million recognized in the storage segment and $3.5 million in the fuels marketing segment). Proceeds from business interruption insurance are included in “Operating expenses” in the consolidated statements of income and in “Cash flows from operating activities” in the consolidated statements of cash flows. We recorded a $78.8 million gain in “Other income (expense), net” in the consolidated statements of income in the first quarter of 2018 for the amount by which the insurance proceeds exceeded our expenses incurred during the period. Although the repairs are not complete, we expect that the costs to repair the property damage at the terminal will not exceed the amount of insurance proceeds received.

Other Events
Navigator Acquisition. On May 4, 2017 , we acquired Navigator Energy Services, LLC for approximately $1.5 billion (the Navigator Acquisition). We collectively refer to the acquired assets, together with the assets we have constructed through various expansion projects since the date of the Navigator Acquisition, as our Permian Crude System. The assets acquired are included in our pipeline segment within the Central West System, commencing on May 4, 2017. Please refer to Note 5 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for further discussion.

Axeon Term Loan. On February 22, 2017, we settled and terminated the $190.0 million term loan to Axeon Specialty Products, LLC (the Axeon Term Loan), pursuant to which we also provided credit support, such as guarantees, letters of credit and cash collateral, as applicable, of up to $125.0 million to Axeon Specialty Products, LLC (Axeon). We received $110.0 million in settlement of the Axeon Term Loan, and our obligation to provide ongoing credit support to Axeon ceased. In 2016, we recognized an impairment charge on the Axeon Term Loan of $58.7 million which is included in “Other income (expense), net” in the consolidated statements of income. Please refer to Note 18 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for additional information on the Axeon Term Loan and related credit support.

Martin Terminal Acquisition. On December 21, 2016, we acquired crude oil and refined product storage assets in Corpus Christi, TX for $95.7 million , including $2.1 million of capital expenditure reimbursements, from Martin Operating Partnership L.P. (the Martin Terminal Acquisition). The assets acquired are in our storage segment and include 900,000 barrels of crude oil storage capacity, 250,000 barrels of refined product storage capacity and exclusive use of the Port of Corpus Christi’s new crude oil dock. The acquired assets, which are adjacent to our existing Corpus Christi North Beach terminal, increased our storage capacity in the Corpus Christi region and have direct connectivity to Eagle Ford crude oil production.

Employee Transfer from NuStar GP, LLC. On March 1, 2016, NuStar GP, LLC, the general partner of our general partner and a wholly owned subsidiary of NuStar GP Holdings, transferred and assigned to NuStar Services Company LLC (NuStar Services Co), a wholly owned subsidiary of NuStar Energy, all of NuStar GP, LLC’s employees and related benefit plans, programs, contracts and policies (the Employee Transfer). As a result of the Employee Transfer, we pay employee costs directly and sponsor the Fifth Amended and Restated 2000 Long-Term Incentive Plan and other employee benefit plans. Please refer to the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for the following: Note 4 for further discussion of the Employee Transfer and our related party agreements, Note 23 for a discussion of our employee benefit plans and Note 24 for a discussion of our long-term incentive plans.

Operations
We conduct our operations through our subsidiaries, primarily NuStar Logistics, L.P. (NuStar Logistics) and NuStar Pipeline Operating Partnership L.P. (NuPOP). Our operations are divided into three reportable business segments: pipeline, storage and fuels marketing. For a more detailed description of our segments, please refer to “Segments” under Item 1. “Business.”

Pipeline. We own 3,130 miles of refined product pipelines and 2,070 miles of crude oil pipelines, as well as approximately 5.0 million barrels of storage capacity, which comprise our Central West System. In addition, we own 2,600 miles of refined product pipelines, consisting of the East and North Pipelines, and a 2,000 -mile ammonia pipeline (the Ammonia Pipeline), which comprise our Central East System. The East and North Pipelines have storage capacity of approximately 7.3 million barrels.

Storage. We own terminals and storage facilities in the United States, Canada, Mexico and St. Eustatius in the Caribbean Netherlands, with approximately 75.8 million barrels of storage capacity.

Fuels Marketing. Prior to the third quarter of 2017, our fuels marketing operations involved the purchase of crude oil, fuel oil, bunker fuel, fuel oil blending components and other refined products for resale. We ceased marketing crude oil in the second quarter of 2017 and exited our heavy fuels trading operations in the third quarter of 2017. These actions were in line with our

43


goal of reducing our exposure to commodity margins, and instead focusing on our core, fee-based pipeline and storage segments. The remaining operations in our fuels marketing segment are our bunkering operations at our St. Eustatius and Texas City terminals, as well as certain of our blending operations.

The results of operations for the fuels marketing segment depend largely on the margin between our costs and the sales prices of the products we market. Therefore, the results of operations for this segment are more sensitive to changes in commodity prices compared to the operations of the pipeline and storage segments. Since our fuels marketing operations expose us to commodity price risk, we enter into derivative contracts to attempt to mitigate the effects of commodity price fluctuations on our operations. The derivative instruments we use consist primarily of commodity futures and swap contracts. Not all of our derivative instruments qualify for hedge accounting treatment under U.S. generally accepted accounting principles. In such cases, our earnings for a period may include the gain or loss related to derivative instruments without including the offsetting effect of the hedged item, which could result in greater earnings volatility.

Factors That Affect Results of Operations
The following factors affect the results of our operations:
company-specific factors, such as facility integrity issues and maintenance requirements that impact the throughput rates of our assets;
seasonal factors that affect the demand for products transported by and/or stored in our assets and the demand for products we sell;
industry factors, such as changes in the prices of petroleum products that affect demand and the operations of our competitors;
economic factors, such as commodity price volatility, that impact our fuels marketing segment; and
factors that impact the operations served by our pipeline and storage assets, such as utilization rates and maintenance turnaround schedules of our refining company customers and drilling activity by our crude oil production customers.

Increases or decreases in the price of crude oil affect sectors across the energy industry, including our customers in crude oil production, refining and trading, in different ways at different points in any given price cycle. For example, during periods of sustained low prices, producers tend to reduce their capital spending and drilling activity and narrow their focus to assets in the most cost-advantaged regions. Refiners, on the other hand, tend to benefit from lower crude oil prices, to the extent they are able to take advantage of lower feedstock prices, especially those positioned for healthy regional demand for their refined products; however, as refined product inventories increase, refiners typically reduce their production rate, which may reduce the degree to which they are able to benefit from low crude prices. Crude oil traders focus less on the current market commodity price than on whether that price is higher or lower than expected future market prices: if the future price for a product is believed to be higher than the current market price, or a “contango market,” traders are more likely to purchase and store products to sell in the future at the higher price. On the other hand, when the current price of crude oil nears or exceeds the expected future market price, or “backwardation,” as is currently the case for certain markets that we serve, traders are no longer incentivized to purchase and store product for future sale.

Current Market Conditions
The price of crude oil began to recover in 2018, as global supply and demand reached a balance. Crude oil prices continued to recover up until the fourth quarter when, after hitting a three-year high in October, prices fell sharply and remained there through year-end. As a result, by year-end 2018, many energy industry experts lowered their crude price expectations for 2019. While crude oil prices have made a modest recovery so far in 2019, they have not returned to the levels previously forecasted. Despite the fact that crude prices are somewhat below many experts’ forecasts, we believe that the lower projected crude prices remain at or above levels that should support healthy crude production growth in the Permian Basin. However, crude oil prices are difficult to predict because they are determined by global supply and demand, which, in turn, are dependent on many variables, such as trade relationships, geopolitical challenges, economic health and relative currency strength.


44


RESULTS OF OPERATIONS
Year Ended December 31, 2018 Compared to Year Ended December 31, 2017
Financial Highlights
(Thousands of Dollars, Except Per Unit Data)
 
Year Ended December 31,
 
 
 
2018
 
2017
 
Change
Statement of Income Data:
 
 
 
Revenues:
 
 
 
 
 
Service revenues
$
1,206,981

 
$
1,128,726

 
$
78,255

Product sales
754,776

 
685,293

 
69,483

Total revenues
1,961,757

 
1,814,019

 
147,738

 
 
 
 
 
 
Costs and expenses:
 
 
 
 
 
Costs associated with service revenues
777,173

 
705,204

 
71,969

Cost of product sales
705,946

 
651,599

 
54,347

General and administrative expenses
106,200

 
112,240

 
(6,040
)
Other depreciation and amortization expense
8,875

 
8,698

 
177

Total costs and expenses
1,598,194


1,477,741


120,453

 
 
 
 
 
 
Operating income
363,563

 
336,278

 
27,285

Interest expense, net
(186,237
)
 
(173,083
)
 
(13,154
)
Other income (expense), net
39,876

 
(5,294
)
 
45,170

Income before income tax expense
217,202

 
157,901

 
59,301

Income tax expense
11,408

 
9,937

 
1,471

Net income
$
205,794

 
$
147,964

 
$
57,830

Basic and diluted net (loss) income per common unit
$
(2.77
)
 
$
0.64

 
$
(3.41
)
Annual Overview
Net income increased $57.8 million for the year ended December 31, 2018 , compared to the year ended December 31, 2017 , primarily due to higher other income, which includes the $78.8 million gain recognized in the first quarter of 2018 from insurance proceeds related to hurricane damage at our St. Eustatius terminal in the third quarter of 2017, partially offset by a $43.4 million loss from the sale of our European operations in the fourth quarter of 2018. Additionally, net income increased from a $21.4 million increase in segment operating income.

Despite positive net income, we incurred a net loss per common unit because we accounted for the Merger as an equity transaction similar to a redemption or induced conversion of preferred stock, which resulted in a loss of $377.1 million that was subtracted from net income attributable to common unitholders in the calculation of net loss per common unit for the year ended December 31, 2018. Please refer to Notes 4 and 21 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for further discussion.


45


Segment Operating Highlights
(Thousands of Dollars, Except Barrel/Day Information)
 
 
Year Ended December 31,
 
 
 
2018
 
2017
 
Change
Pipeline:
 
 
 
 
 
Refined products and ammonia pipelines throughput (barrels/day)
557,044

 
516,736

 
40,308

Crude oil pipelines throughput (barrels/day)
876,655

 
583,323

 
293,332

Total throughput (barrels/day)
1,433,699

 
1,100,059

 
333,640

Throughput and other revenues
$
611,065

 
$
516,288

 
$
94,777

Operating expenses
184,427

 
156,432

 
27,995

Depreciation and amortization expense
153,943

 
128,061

 
25,882

Segment operating income
$
272,695

 
$
231,795

 
$
40,900

 
 
 
 
 
 
Storage:
 
 
 
 
 
Throughput (barrels/day)
341,396

 
325,194

 
16,202

Throughput terminal revenues
$
83,157

 
$
85,927

 
$
(2,770
)
Storage terminal revenues
522,793

 
531,026

 
(8,233
)
Total revenues
605,950

 
616,953

 
(11,003
)
Operating expenses
289,423

 
270,041

 
19,382

Depreciation and amortization expense
135,056

 
127,473

 
7,583

Segment operating income
$
181,471

 
$
219,439

 
$
(37,968
)
 
 
 
 
 
 
Fuels Marketing:
 
 
 
 
 
Product sales and other revenue
$
752,312

 
$
692,884

 
$
59,428

Cost of product sales
713,031

 
660,844

 
52,187

Gross margin
39,281

 
32,040

 
7,241

Operating expenses
14,841

 
26,057

 
(11,216
)
Segment operating income
$
24,440

 
$
5,983

 
$
18,457

 
 
 
 
 
 
Consolidation and Intersegment Eliminations:
 
 
 
 
 
Revenues
$
(7,570
)
 
$
(12,106
)
 
$
4,536

Cost of product sales
(7,085
)
 
(9,245
)
 
2,160

Operating expenses
(517
)
 
(2,860
)
 
2,343

Total
$
32

 
$
(1
)
 
$
33

 
 
 
 
 
 
Consolidated Information:
 
 
 
 
 
Revenues
$
1,961,757

 
$
1,814,019

 
$
147,738

Costs associated with service revenues:
 
 
 
 
 
Operating expenses
488,174

 
449,670

 
38,504

Depreciation and amortization expense
288,999

 
255,534

 
33,465

Total costs associated with service revenues
777,173

 
705,204

 
71,969

Cost of product sales
705,946

 
651,599

 
54,347

Segment operating income
478,638


457,216


21,422

General and administrative expenses
106,200

 
112,240

 
(6,040
)
Other depreciation and amortization expense
8,875

 
8,698

 
177

Consolidated operating income
$
363,563

 
$
336,278

 
$
27,285



46


Pipeline
Total revenues increased $94.8 million and total throughputs increased 333,640 barrels per day for the year ended December 31, 2018 , compared to the year ended December 31, 2017 , primarily due to:
an increase in revenues of $68.4 million and an increase in throughputs of 242,785 barrels per day resulting from increased customer production supplying our Permian Crude System, completion of pipeline expansion projects and owning and operating the system for the entire period in 2018;
an increase in revenues of $16.0 million and an increase in throughputs of 38,624 barrels per day due to a turnaround in the fourth quarter of 2017 at the refinery served by our McKee System pipelines;
an increase in revenues of $13.0 million and an increase in throughputs of 11,318 barrels per day on our East Pipeline due to higher diesel throughputs, an increase in long-haul deliveries resulting in higher average tariffs and the Council Bluffs Acquisition; and
an increase in revenues of $10.8 million and an increase in throughputs of 8,742 barrels per day, mainly due to a turnaround at the refinery served by our North Pipeline in the second quarter of 2017, as well as turnaround activity at a neighboring refinery in 2018, resulting in higher demand on the North Pipeline.

These increases were partially offset by:
a decrease in revenues of $10.8 million on our Eagle Ford System, mainly due to contract renewals at lower rates, which more than offset an increase in throughputs of 47,338 barrels per day; and
a decrease in revenues of $3.4 million and a decrease in throughputs of 13,834 barrels per day on our Ardmore System, mainly due to a customer’s refinery turnaround in 2018, as well as an increase in short-haul deliveries, which result in lower average tariffs.

Operating expenses increased $28.0 million for the year ended December 31, 2018 , compared to the year ended December 31, 2017 , mainly due to:
increased operating expenses of $16.5 million as a result of owning the Permian Crude System for the entire period in 2018 and consistent with the increase in throughputs;
an increase of $3.1 million resulting from the Council Bluffs Acquisition;
an increase of $2.7 million in salaries and wages; and
an increase in power expenses of $2.6 million, mainly due to increased throughputs.
Depreciation and amortization expense increased $25.9 million for the year ended December 31, 2018 , compared to the year ended December 31, 2017 , mainly due to owning the Permian Crude System for the entire period in 2018.

Storage
Throughput terminal revenues decreased $2.8 million , while throughputs increased 16,202 barrels per day for the year ended December 31, 2018 , compared to the year ended December 31, 2017 . Corpus Christi North Beach terminal revenues decreased by $6.3 million, despite increased throughputs of 10,581 barrels per day mainly driven by higher South Texas Crude System volumes, due to lower storage rates and lower dock revenues as additional volumes were delivered to our customer’s refineries instead of over our docks. Revenues increased $3.8 million and throughputs increased 7,343 barrels per day at our Central West Terminals, mainly due to increased demand in markets served by those terminals.

Storage terminal revenues decreased $8.2 million for the year ended December 31, 2018 , compared to the year ended December 31, 2017 , primarily due to:
a decrease of $15.5 million at our Gulf Coast Terminals, mainly due to a backwardated market resulting in the non-renewal at expiration of certain customer contracts and lower throughput and associated handling fees;
a decrease of $7.1 million at our St. Eustatius terminal, primarily due to renewal of contracts at lower rates, tanks out of service and lower throughput and handling fees;
a decrease of $4.4 million due to the sale of our European terminals in the fourth quarter of 2018; and
a decrease of $1.9 million due to lower throughput and handling fees at our Point Tupper terminal.

These decreases were partially offset by the following:
an increase of $9.4 million at our West Coast Terminals, mainly due to project completions, rate escalations and higher throughput and associated handling fees;
an increase of $8.1 million at our North East Terminals, mainly due to an adjustment to revenues resulting from a change in the term of a contract and the completion of a tank expansion project at our Linden terminal, partially offset by a decrease in revenues at our Piney Point terminal due to the non-renewal at expiration of certain customer contracts. Please refer to Note 6 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for further discussion of the revenue adjustment; and
an increase of $1.9 million due to higher reimbursable revenues at our Point Tupper terminal.

47


Operating expenses increased $19.4 million for the year ended December 31, 2018 , compared to the year ended December 31, 2017 , primarily due to:
an increase in salaries and wages of $6.0 million, and an increase in maintenance and regulatory expenses of $2.0 million, both spread across various regions;
an increase in reimbursable expenses of $4.9 million at various terminals, primarily due to tank cleanings at our Point Tupper and Corpus Christi North Beach terminals, which was offset by a corresponding increase in reimbursable revenues;
an increase in rent expense of $4.4 million, mainly due to additional marine vessel costs at our St. Eustatius terminal;
an increase of $1.9 million for contractor services and an increase of $1.8 million in power costs, mainly due to increased dive inspection costs and higher gas consumption, respectively, at our St. Eustatius terminal; and
an increase in insurance expense of $1.7 million across all terminals due to premium increases.

These increases were partially offset by a decrease in operating expense of $4.2 million at St. Eustatius due to the business interruption insurance recovery in 2018 versus 2017 related to the hurricane damage.

Depreciation and amortization expense increased $7.6 million for the year ended December 31, 2018 , compared to the year ended December 31, 2017 , mainly as the result of the completion of various storage projects, primarily at our St. Eustatius terminal.

Fuels Marketing
Segment operating income increased $18.5 million for the year ended December 31, 2018 , compared to the year ended December 31, 2017 , primarily due to an increase of $11.2 million in operating income from our blending operations and other product sales, and a reduction in operating losses of $5.6 million incurred by our heavy fuels trading operations.

Consolidation and Intersegment Eliminations
Revenue and operating expense eliminations primarily relate to storage fees charged to the fuels marketing segment by the storage segment. Cost of product sales eliminations represent expenses charged to the fuels marketing segment for costs associated with inventory that are expensed once the inventory is sold.

General
General and administrative expenses decreased $6.0 million for the year ended December 31, 2018 , compared to the year ended December 31, 2017 , primarily due to transaction costs related to the Navigator Acquisition in 2017, partially offset by higher compensation costs.
Interest expense, net increased $13.2 million for the year ended December 31, 2018 , compared to the year ended December 31, 2017 , mainly due to the issuance of $550.0 million of 5.625% senior notes on April 28, 2017 to partially fund the Navigator Acquisition and higher interest rates.
For the year ended December 31, 2018 , we recorded other income, net of $39.9 million , primarily due to a $78.8 million gain recognized in the first quarter from insurance proceeds related to hurricane damage at our St. Eustatius terminal in the third quarter of 2017, partially offset by a $43.4 million loss on the sale of our European operations in the fourth quarter of 2018. For the year ended December 31, 2017 , we recorded other expense, net of $5.3 million , mainly due to a $5.0 million loss for property damage at our St. Eustatius terminal resulting from the hurricane activity in the third quarter of 2017.
Income tax expense increased $1.5 million for the year ended December 31, 2018 , compared to the year ended December 31, 2017 , primarily due to an increase in taxes associated with the Permian Crude System and higher foreign withholding taxes.



48


Year Ended December 31, 2017 Compared to Year Ended December 31, 2016
Financial Highlights
(Thousands of Dollars, Except Per Unit Data)
 
Year Ended December 31,
 
 
 
2017
 
2016
 
Change
Statement of Income Data:
 
Revenues:
 
 
 
 
 
Service revenues
$
1,128,726

 
$
1,083,165

 
$
45,561

Product sales
685,293

 
673,517

 
11,776

Total revenues
1,814,019

 
1,756,682

 
57,337

 
 
 
 
 
 
Costs and expenses:
 
 
 
 
 
Costs associated with service revenues
705,204

 
656,584

 
48,620

Cost of product sales
651,599

 
633,653

 
17,946

General and administrative expenses
112,240

 
98,817

 
13,423

Other depreciation and amortization expense
8,698

 
8,519

 
179

Total costs and expenses
1,477,741

 
1,397,573

 
80,168

 
 
 
 
 
 
Operating income
336,278

 
359,109

 
(22,831
)
Interest expense, net
(173,083
)
 
(138,350
)
 
(34,733
)
Other expense, net
(5,294
)
 
(58,783
)
 
53,489

Income before income tax expense
157,901

 
161,976

 
(4,075
)
Income tax expense
9,937

 
11,973

 
(2,036
)
Net income
$
147,964

 
$
150,003

 
$
(2,039
)
Basic and diluted net income per common unit:
$
0.64

 
$
1.27

 
$
(0.63
)

Annual Overview
Net income slightly decreased for the year ended December 31, 2017, compared to the year ended December 31, 2016. The decrease in other expense, net, mainly resulting from a $58.7 million impairment charge on the Axeon Term Loan in 2016, was offset by increased interest expense, increased general and administrative expenses and decreased segment operating income.


49


Segment Operating Highlights
(Thousands of Dollars, Except Barrel/Day Information)
 
Year Ended December 31,
 
 
 
2017
 
2016
 
Change
Pipeline:
 
 
 
 
 
Refined products and ammonia pipelines throughput (barrels/day)
516,736

 
535,946

 
(19,210
)
Crude oil pipelines throughput (barrels/day)
583,323

 
392,181

 
191,142

Total throughput (barrels/day)
1,100,059

 
928,127

 
171,932

Throughput revenues
$
516,288

 
$
485,650

 
$
30,638

Operating expenses
156,432

 
147,858

 
8,574

Depreciation and amortization expense
128,061

 
89,554

 
38,507

Segment operating income
$
231,795

 
$
248,238

 
$
(16,443
)
 
 
 
 
 
 
Storage:
 
 
 
 
 
Throughput (barrels/day)
325,194

 
789,065

 
(463,871
)
Throughput terminal revenues
$
85,927

 
$
117,586

 
$
(31,659
)
Storage terminal revenues
531,026

 
492,456

 
38,570

Total revenues
616,953

 
610,042

 
6,911

Operating expenses
270,041

 
276,578

 
(6,537
)
Depreciation and amortization expense
127,473

 
118,663

 
8,810

Segment operating income
$
219,439

 
$
214,801

 
$
4,638

 
 
 
 
 
 
Fuels Marketing:
 
 
 
 
 
Product sales and other revenue
$
692,884

 
$
681,934

 
$
10,950

Cost of product sales
660,844

 
645,355

 
15,489

Gross margin
32,040

 
36,579

 
(4,539
)
Operating expenses
26,057

 
33,173

 
(7,116
)
Segment operating income
$
5,983

 
$
3,406

 
$
2,577

 
 
 
 
 
 
Consolidation and Intersegment Eliminations:
 
 
 
 
 
Revenues
$
(12,106
)
 
$
(20,944
)
 
$
8,838

Cost of product sales
(9,245
)
 
(11,702
)
 
2,457

Operating expenses
(2,860
)
 
(9,242
)
 
6,382

Total
$
(1
)
 
$

 
$
(1
)
 
 
 
 
 
 
Consolidated Information:
 
 
 
 
 
Revenues
$
1,814,019

 
$
1,756,682

 
$
57,337

Costs associated with service revenues:
 
 
 
 
 
Operating expenses
449,670


448,367

 
1,303

Depreciation and amortization expense
255,534


208,217

 
47,317

Total costs associated with service revenues
705,204


656,584


48,620

Cost of product sales
651,599

 
633,653

 
17,946

Segment operating income
457,216


466,445


(9,229
)
General and administrative expenses
112,240

 
98,817

 
13,423

Other depreciation and amortization expense
8,698

 
8,519

 
179

Consolidated operating income
$
336,278

 
$
359,109

 
$
(22,831
)


50


Pipeline
Total revenues increased $30.6 million and total throughputs increased 171,932 barrels per day for the year ended December 31, 2017, compared to the year ended December 31, 2016, primarily due to:
an increase in revenues of $42.6 million and an increase in throughputs of 192,958 barrels per day from our Permian Crude System acquired in May 2017;
an increase in revenues of $5.5 million and an increase in throughputs of 2,929 barrels per day due to maintenance downtime in 2016 on a portion of the Ammonia Pipeline, as well as operational issues in 2016 at certain plants served by the pipeline; and
an increase in revenues of $3.4 million, despite a decrease in throughputs of 4,129 barrels per day, on our East Pipeline due to the completion of various storage projects along the pipeline, as well as an increase in long-haul deliveries resulting in higher average tariffs. A turnaround and operational issues at the refineries served by the East Pipeline in 2017 contributed to the decrease in throughputs.

These increases in revenues and throughputs were partially offset by:
a decrease in revenues of $10.4 million and a decrease in throughputs of 16,839 barrels per day due to a turnaround in the fourth quarter of 2017 at the refinery served by our McKee System pipelines;
a decrease in revenues of $6.8 million and a decrease in throughputs of 15,561 barrels per day on our Eagle Ford System, mainly due to reduced production in a sustained low crude oil price environment; and
a decrease in revenues of $4.8 million and a decrease in throughputs of 6,905 barrels per day due to a turnaround in the second quarter of 2017 at the refinery served by the North Pipeline.
Operating expenses increased $8.6 million for the year ended December 31, 2017, compared to the year ended December 31, 2016. Operating expenses increased $9.9 million as a result of our acquisition of the Permian Crude System, which was partially offset by a decrease of $2.1 million from product imbalances on the East Pipeline.
Depreciation and amortization expense increased $38.5 million for the year ended December 31, 2017, compared to the year ended December 31, 2016, due to our acquisition of the Permian Crude System and the completion of various pipeline projects.

Storage
Effective January 1, 2017, our agreements for our refinery crude storage tanks at Corpus Christi, TX, Texas City, TX and Benicia, CA were amended to change our fees from throughput-based to storage-based. Excluding the effect of the change to these agreements, throughput terminal revenues would have increased $9.5 million and throughputs would have increased 14,360 barrels per day for the year ended December 31, 2017, compared to the year ended December 31, 2016. Throughput terminal revenues increased at our Corpus Christi North Beach terminal by $15.1 million due to an increase in throughputs of 26,359 barrels per day, mainly resulting from the Martin Terminal Acquisition. The benefit of the Martin Terminal Acquisition was partially offset by lower revenues and throughputs resulting from a decrease in Eagle Ford Shale crude oil being shipped to Corpus Christi due to reduced production in a sustained low crude oil price environment. Throughputs increased 16,309 barrels per day, despite only a slight increase in revenues of $0.3 million, at our Central West Terminals, mainly due to a new customer contract and increased marine activity, mostly offset by decreased revenues from ancillary services. These increases in revenues and throughputs were partially offset by decreased revenues of $5.8 million and decreased throughputs of 28,308 barrels per day at our Paulsboro, NJ terminal as a customer diverted barrels to other terminals.

Storage terminal revenues would have decreased $0.6 million for the year ended December 31, 2017, compared to the year ended December 31, 2016, excluding the effect of the change to the refinery storage tank agreements described above. Revenues at our Gulf Coast Terminals decreased $19.2 million, mainly at our St. James, LA terminal due to reduced unit train activity and at our Texas City, TX terminal as a result of the exit from our heavy fuels trading operations. These decreases were partially offset by increases in revenues of $8.2 million at our North East Terminals and $4.5 million at our West Coast Terminals, mainly due to new customer contracts and rate escalations.

Storage terminal revenues also increased $5.5 million for the year ended December 31, 2017, compared to the year ended December 31, 2016, at our international terminals. Revenues increased $10.2 million at our St. Eustatius terminal, mainly due to new customer contracts and rate escalations, partially offset by lower throughput and associated handling fees as a result of the temporary shutdown of the terminal and damage caused by hurricane activity in the third quarter of 2017. This increase was partially offset by a decrease in revenues of $4.2 million at our Point Tupper terminal, mainly resulting from a decrease in customer base, tanks out of service and lower reimbursable revenues.


51


Operating expenses decreased $6.5 million for the year ended December 31, 2017, compared to the year ended December 31, 2016, primarily due to:
a decrease of $8.7 million in maintenance and regulatory expenses, primarily at our St. Eustatius, North East and Point Tupper terminals; and
a decrease of $6.1 million in reimbursable expenses, mainly at our Texas City, TX and Point Tupper terminals, consistent with the decrease in reimbursable revenues.

These decreases were partially offset by increased operating expenses of $8.5 million as a result of the Martin Terminal Acquisition.

Depreciation and amortization expense increased $8.8 million for the year ended December 31, 2017, compared to the year ended December 31, 2016, due to the Martin Terminal Acquisition and other various projects.

Fuels Marketing
Segment operating income increased $2.6 million for the year ended December 31, 2017, compared to the year ended December 31, 2016, primarily due to a reduction in losses of $9.1 million from exiting our heavy fuels trading operations in 2017. Segment operating income from our bunker fuel operations at our St. Eustatius terminal decreased $6.4 million, due to lower gross margins and the temporary shutdown of the terminal caused by hurricane activity in the third quarter of 2017.

Consolidation and Intersegment Eliminations
Revenue and operating expense eliminations primarily relate to storage fees charged to the fuels marketing segment by the storage segment. Cost of product sales eliminations represent expenses charged to the fuels marketing segment for costs associated with inventory that are expensed once the inventory is sold.

General
General and administrative expenses increased $13.4 million for the year ended December 31, 2017, compared to the year ended December 31, 2016, primarily due to transaction costs related to the Navigator Acquisition.
Interest expense, net increased $34.7 million for the year ended December 31, 2017, compared to the year ended December 31, 2016, mainly due to the issuance of $550.0 million of 5.625% senior notes in April 2017 and as a result of fees for a bridge loan commitment to potentially assist with the financing of the Navigator Acquisition. We did not enter into or borrow under the bridge loan. Interest expense, net also increased as a result of lower interest income due to the termination of the Axeon Term Loan in February 2017. Please refer to Note 18 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for a discussion of the Axeon Term Loan and related credit support.
For the year ended December 31, 2017, we recorded other expense, net of $5.3 million, mainly due to property damage of $5.0 million at our St. Eustatius terminal resulting from hurricane activity in the third quarter of 2017. For the year ended December 31, 2016, we recorded other expense, net of $58.8 million, mainly due to an impairment charge of $58.7 million recognized on the Axeon Term Loan.
Income tax expense decreased $2.0 million for the year ended December 31, 2017, compared to the year ended December 31, 2016, primarily due to reductions in withholding taxes related to certain of our foreign subsidiaries. This decrease was partially offset by increased tax expense resulting from the enactment of the Tax Cuts and Jobs Act in December 2017 (the Act), pursuant to which we recorded a one-time mandatory tax on previously deferred earnings of certain foreign subsidiaries. Please refer to Note 25 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for a discussion on income taxes, including the impact of the Act.


52


TRENDS AND OUTLOOK
In early 2018, we launched a comprehensive plan to achieve the characteristics now demanded by the master limited partnership market: simplified corporate governance with no incentive distribution rights, minimal equity capital needs, lower leverage and strong distribution coverage. Over the course of the year, we executed our plan by, among other things, selling our European operations, which reduced our debt; completing the merger with our general partner, which both simplified our structure and resulted in the cancellation of the incentive distribution rights previously held by our general partner; resetting our quarterly distribution; and issuing our Series D Preferred Units. With lower leverage metrics and higher distribution coverage, we have positioned ourselves to fund a larger proportion of our capital projects with the cash generated by our operations, thus reducing our need to access common equity markets to finance future growth opportunities.

The majority of significant growth opportunities for midstream crude oil pipeline companies today emanate from the growth in Permian Basin production, and we expect to benefit from that growth within our Permian System and at other assets experiencing a “spillover” effect from Permian Basin growth. In 2019, we expect to continue to expand our Permian System to capture higher throughputs and revenues. Outside the Permian Basin, but related to its growth, we expect our existing crude oil pipelines, including our Wichita Falls, Ardmore and South Texas crude systems, to benefit in 2019 from our customers’ long-haul opportunities to transport Permian crude. Our Wichita Falls and Ardmore pipelines should benefit from higher revenues as we complete connections of those pipelines to Permian production sources. Also, revenues on our South Texas Crude System should increase as we complete the construction of a project to connect a portion of that system with new pipelines carrying Permian production bound for export. That project is backed by a customer commitment and is expected to be in service in the second half of 2019. We also expect our storage facilities in Corpus Christi, Texas and St. James, Louisiana to benefit in 2019 as pipeline projects to move Permian production come online. Longer term, as Permian Basin production continues to grow and exceeds the demand from domestic refiners, we expect those incremental volumes to be exported, most likely from Gulf Coast facilities. We believe our Gulf Coast storage facilities are well positioned to benefit from those export opportunities.

In addition to the Permian-related growth, we also expect 2019 results to benefit from a pipeline expansion project to facilitate the export of refined products to Northern Mexico and the completion of a number of bio-fuel projects at our West Coast terminals in 2018 and 2019.

While backwardated crude prices in 2019 could have a detrimental impact on some of our storage facilities, we believe we are insulated to some extent by our long-term contracts at certain of our facilities where backwardation is a driving factor, and due to the fact that we have storage assets in markets in which forward pricing has little impact on rates or renewals.

The severe political, social and economic instability in Venezuela in recent years, as well as the sanctions implemented in 2017 by the United States and others, have had a negative impact on the ability of Petroleos de Venezuela, S.A. (PDVSA), a customer at our St. Eustatius facility, to conduct its operations and to pay its creditors timely. On January 28, 2019, the U.S. Department of the Treasury’s Office of Foreign Assets Control (OFAC) added PDVSA to its List of Specially Designated Nationals and Blocked Persons (the SDN List). The inclusion of PDVSA on the SDN List prevents us from providing services to PDVSA until such time as these sanctions are lifted or otherwise modified. Since January 28, we have taken all necessary steps to wind down our contracts with PDVSA, in accordance with the requirements of applicable laws, and we are now in the process of marketing the storage capacity no longer leased to PDVSA to other customers. We expect to replace their full position over the next 18 months.

Our outlook for the partnership, both overall and for any of our segments, may change, as we base our expectations on our continuing evaluation of a number of factors, many of which are outside our control. These factors include, but are not limited to, the state of the economy and the capital markets, changes to our customers’ refinery maintenance schedules and unplanned refinery downtime, crude oil prices, the supply of and demand for crude oil, refined products and anhydrous ammonia, demand for our transportation and storage services and changes in laws or regulations affecting our assets.





53


LIQUIDITY AND CAPITAL RESOURCES
Overview
Our primary cash requirements are for distributions to our partners, debt service, capital expenditures, acquisitions and operating expenses.

Our partnership agreement requires that we distribute all “Available Cash” to our common limited partners and, prior to the Merger, to our general partner each quarter. “Available Cash” is defined in the partnership agreement generally as cash on hand at the end of the quarter, plus certain permitted borrowings made subsequent to the end of the quarter, less cash reserves determined by our board of directors, subject to requirements for distributions for our preferred units. The board of directors of NuStar GP, LLC reset our quarterly distribution per common unit to $0.60 ( $2.40 on an annualized basis), starting with the 2018 first-quarter distribution, which was paid on May 14, 2018. As a result of the Merger, our general partner no longer receives incentive distributions or quarterly cash distributions from us, and we issued approximately 13.4 million incremental NuStar Energy common units in exchange for previously outstanding NSH units. Please refer to Note 4 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for further discussion regarding the Merger.

Each year, our objective is to fund our reliability capital expenditures and distribution requirements with our net cash provided by operating activities during that year. If we do not generate sufficient cash from operations to meet that objective, we utilize cash on hand or other sources of cash flow, which in the past have primarily included borrowings under our revolving credit agreement, sales of non-strategic assets and, to the extent necessary, funds raised through equity or debt offerings. We have typically funded our strategic capital expenditures and acquisitions from external sources, primarily borrowings under our revolving credit agreement or funds raised through equity or debt offerings. However, our ability to raise funds by issuing debt or equity depends on many factors beyond our control. Our risk factors in Item 1A. “Risk Factors” describe the risks inherent to these sources of funding and the availability thereof.

During periods when our cash flow from operations is less than our distribution and reliability capital requirements, we may maintain our distribution level because we can use other sources of Available Cash, as provided in our partnership agreement, including borrowings under our revolving credit agreement and proceeds from the sales of assets. Our risk factors in Item 1A. “Risk Factors” describe the risks inherent in our ability to maintain or grow our distribution.

For 2019, we expect to generate sufficient cash from operations to exceed our distribution and reliability capital requirements.

Cash Flows for the Years Ended December 31, 2018 , 2017 and 2016
The following table summarizes our cash flows from operating, investing and financing activities (please refer to our Consolidated Statements of Cash Flows in Item 8. “Financial Statements and Supplementary Data”):
 
Year Ended December 31,
 
2018
 
2017
 
2016
 
(Thousands of Dollars)
Net cash provided by (used in):
 
 
 
 
 
Operating activities
$
544,207

 
$
406,799

 
$
436,761

Investing activities
(153,778
)
 
(1,696,441
)
 
(311,078
)
Financing activities
(399,867
)
 
1,276,272

 
(211,324
)
Effect of foreign exchange rate changes on cash
(1,210
)
 
1,720

 
2,721

Net decrease in cash and cash equivalents
$
(10,648
)
 
$
(11,650
)
 
$
(82,920
)
Net cash provided by operating activities for the year ended December 31, 2018 was $544.2 million , compared to $406.8 million for the year ended December 31, 2017 , primarily due to changes in working capital. Our working capital decreased by $78.3 million for the year ended December 31, 2018 , compared to an increase of $26.5 million for the year ended December 31, 2017 . Please refer to the “Working Capital Requirements” section below for a discussion of the changes in working capital.
For the year ended December 31, 2018 , net cash provided by operating activities was used to fund our distributions to unitholders and our general partner in the aggregate amount of $391.4 million and the cash consideration for the Merger of $67.8 million . Net cash provided by operating activities and a portion of the insurance proceeds we received in the first quarter of 2018 in settlement of our property damage claim for our St. Eustatius terminal were used to fund reliability capital expenditures of $77.2 million . The remainder of cash provided by operating activities and proceeds from debt borrowings were used to fund our strategic capital expenditures, including acquisitions, of $417.8 million. The proceeds from the issuance of

54


units and the sale of our European operations and a portion of the insurance proceeds were used to repay outstanding borrowings under our revolving credit agreement.

For the year ended December 31, 2017, net cash provided by operating activities, the proceeds from the termination of the Axeon Term Loan of $110.0 million and cash on hand were used to fund our distributions to unitholders and our general partner in the aggregate amount of $485.1 million and reliability capital expenditures of $57.5 million. Proceeds from our debt and equity issuances of approximately $1.5 billion were used to fund the purchase price of the Navigator Acquisition. The proceeds from debt borrowings, net of repayments, remaining proceeds from our equity issuances and cash on hand were used to fund our other strategic capital expenditures.

For the year ended December 31, 2016, net cash provided by operating activities primarily was used to fund our distributions to unitholders and our general partner in the aggregate amount of $393.0 million and reliability capital expenditures of $38.2 million. Proceeds from the issuance of common and preferred units and cash on hand were used to fund our strategic capital expenditures, including the Martin Terminal Acquisition.

Debt Sources of Liquidity
Revolving Credit Agreement. On June 29, 2018, NuStar Logistics amended its revolving credit agreement (the Revolving Credit Agreement) to exclude the Series D Preferred Units from the definition of “Indebtedness.” Additionally, the amendment reduced the total amount available for borrowing from $1.75 billion to $1.575 billion , effective June 29, 2018, with a further reduction to $1.4 billion , effective December 28, 2018. The Revolving Credit Agreement was also amended to, among other things, add a minimum consolidated interest coverage ratio (as defined in the Revolving Credit Agreement), which must not be less than 1.75-to-1.00 for each rolling period of four quarters, beginning with the rolling period ending June 30, 2018. As of December 31, 2018 , our consolidated interest coverage ratio was 2.2x.

On March 28, 2018, NuStar Logistics amended the Revolving Credit Agreement to increase the maximum allowed consolidated debt coverage ratio (as defined in the Revolving Credit Agreement) to 5.25-to-1.00 for the rolling periods ending June 30, 2018 through December 31, 2018. For any rolling periods ending on or after March 31, 2019, the maximum allowed consolidated debt coverage ratio may not exceed 5.00-to-1.00. The Revolving Credit Agreement was also amended to, among other things, provide that the definition of “Change in Control” in the Revolving Credit Agreement excludes the Merger.

The maximum consolidated debt coverage ratio and minimum consolidated interest coverage ratio requirements may limit the amount we can borrow under the Revolving Credit Agreement to an amount less than the total amount available for borrowing. The Revolving Credit Agreement also contains customary restrictive covenants, such as limitations on indebtedness, liens, mergers, asset transfers and certain investing activities. As of December 31, 2018 , our consolidated debt coverage ratio was 4.05x and we had $651.3 million available for borrowing. The Revolving Credit Agreement includes the ability to borrow up to the equivalent of $250.0 million in Euros and up to the equivalent of $250.0 million in British Pounds Sterling. Obligations under the Revolving Credit Agreement are guaranteed by NuStar Energy and NuPOP.

Letters of credit issued under the Revolving Credit Agreement totaled $3.7 million as of December 31, 2018 . Letters of credit are limited to $400.0 million (including up to the equivalent of $25.0 million in Euros and up to the equivalent of $25.0 million in British Pounds Sterling) and also may restrict the amount we can borrow under the Revolving Credit Agreement.

Receivables Financing Agreement. NuStar Energy and NuStar Finance LLC (NuStar Finance), a special purpose entity and wholly owned subsidiary of NuStar Energy, are parties to a $125.0 million receivables financing agreement with third-party lenders (the Receivables Financing Agreement) and agreements with certain of NuStar Energy’s wholly owned subsidiaries (collectively with the Receivables Financing Agreement, the Securitization Program). On September 20, 2017, the Securitization Program was amended to add certain of NuStar Energy’s wholly owned subsidiaries resulting from the Navigator Acquisition and to extend the Securitization Program’s scheduled termination date from June 15, 2018 to September 20, 2020, with the option to renew for additional 364-day periods thereafter. On March 28, 2018, the Receivables Financing Agreement was amended to change the definition of Change in Control in the Receivables Financing Agreement such that the Merger would not be a Change in Control for purposes of the Receivables Financing Agreement. The amount of borrowings under the Receivables Financing Agreement is limited to $125.0 million . The amount available for borrowing under the Receivables Financing Agreement is based on the availability of eligible receivables and other customary factors and conditions. The Securitization Program contains various customary affirmative and negative covenants and default, indemnification and termination provisions, and the Receivables Financing Agreement provides for acceleration of amounts owed upon the occurrence of certain specified events.

Issuance of 5.625% Senior Notes. On April 28, 2017, NuStar Logistics issued $550.0 million of 5.625% senior notes due April 28, 2027 . We used the net proceeds of $543.3 million from the offering to fund a portion of the purchase price for the

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Navigator Acquisition and to pay related fees and expenses. Interest on the 5.625% senior notes is payable semi-annually in arrears on April 28 and October 28 of each year beginning on October 28, 2017. The 5.625% senior notes do not have sinking fund requirements. These notes rank equally with existing senior unsecured indebtedness and senior to existing subordinated indebtedness of NuStar Logistics. The 5.625% senior notes contain restrictions on NuStar Logistics’ ability to incur secured indebtedness unless the same security is also provided for the benefit of holders of the senior notes. In addition, the senior notes limit NuStar Logistics’ ability to incur indebtedness secured by certain liens, engage in certain sale-leaseback transactions and engage in certain consolidations, mergers or asset sales.

Other Debt Sources of Liquidity. Other sources of liquidity as of December 31, 2018 consist of the following:
$365.4 million in revenue bonds pursuant to the Gulf Opportunity Zone Act of 2005 (the GoZone Bonds), with $42.9 million remaining in trust as of December 31, 2018 , supported by $370.2 million in letters of credit; and