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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, 2017
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
https://cdn.kscope.io/bbc6fc1d8c65ce93f87cbdfd9aa08f0c-nslogoa02a03.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 and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted 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 and post 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, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act: 
Large accelerated filer
 
[X]
  
Accelerated filer
 
[    ]
 
 
 
 
Non-accelerated filer
 
[    ]  (Do not check if a smaller reporting company)
  
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.    o   
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 $3,692 million based on the last sales price quoted as of June 30, 2017, the last business day of the registrant’s most recently completed second quarter.
The number of common units outstanding as of January 31, 2018 was 93,182,018.


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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PART I

Unless otherwise indicated, the terms “NuStar Energy L.P.,” “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, that may cause actual results to differ materially, including the possibility that the proposed merger described under “Recent Developments” below will not be completed prior to the August 8, 2018 outside termination date, the possibility that NuStar GP Holdings, LLC will not obtain the required approvals by its unitholders, the possibility that the anticipated benefits from the proposed merger cannot be fully realized, the possibility that costs or difficulties related to the proposed merger will be greater than expected and other risk factors. 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.

ITEM 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,” 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, 2017, our assets included approximately 9,400 miles of pipeline and 81 terminal and storage facilities that provide approximately 96 million barrels of storage capacity. The following table summarizes operating income for each of our business segments:
 
Year Ended
December 31, 2017
 
(Thousands of Dollars)
Pipeline
$
231,795

Storage
$
219,439

Fuels marketing
$
5,983


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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.
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 expansion projects by constructing new assets;
improving our operations, including safety and environmental stewardship, cost control and asset reliability; and
identifying acquisition targets that meet our financial and strategic 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.

RECENT DEVELOPMENTS

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 which Merger Sub will merge with and into NuStar GP Holdings with NuStar GP Holdings being the surviving entity (the Merger), such that NuStar Energy will be the sole member of NuStar GP Holdings following the Merger. Pursuant to the Merger Agreement and at the effective time of the Merger, our partnership agreement will be 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 at an annual meeting, beginning in 2019. The Merger is subject to the satisfaction or waiver of certain conditions, including approval of the Merger Agreement by NuStar GP Holdings unitholders. Additionally, on February 8, 2018, we announced that our management anticipates recommending to the board of directors of NuStar GP, LLC, and the board of directors expects to adopt, a reset of our quarterly distribution per common unit to $0.60 ($2.40 on an annualized basis), starting with the first-quarter distribution payable in May 2018. Please refer to Note 28 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for further discussion of the Merger.

Hurricane Activity. In the third quarter of 2017, parts of the Caribbean and Gulf of Mexico experienced three major hurricanes. Several of our facilities were affected by the hurricanes, but our St. Eustatius terminal experienced the most damage and was temporarily shut down. We recorded a $5.0 million loss in 2017 for property damage at our St. Eustatius terminal, which represents the amount of our property deductible under our insurance policy. We received insurance proceeds of $12.5 million in 2017 and $87.5 million in January 2018 for property damage at our St. Eustatius terminal. We expect that the costs to repair the property damage at the terminal will not exceed the value 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.

Navigator Acquisition and Financing Transactions. On May 4, 2017, we completed the acquisition of Navigator Energy Services, LLC for approximately $1.5 billion (the Navigator Acquisition). In order to fund the purchase price, we issued 14,375,000 common units for net proceeds of $657.5 million, issued $550.0 million of 5.625% senior notes for net proceeds of $543.3 million and issued 15,400,000 of our 7.625% Series B Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units (Series B Preferred Units) for net proceeds of $371.8 million. Please refer to Notes 4, 12 and 19 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for further discussion.


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ORGANIZATIONAL STRUCTURE
Our operations are managed by NuStar GP, LLC, the general partner of our general partner. NuStar GP, LLC, a Delaware limited liability company, is a consolidated subsidiary of NuStar GP Holdings (NYSE: NSH).

The following chart depicts a summary of our organizational structure at December 31, 2017:

https://cdn.kscope.io/bbc6fc1d8c65ce93f87cbdfd9aa08f0c-nsorgstructure2017.jpg

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SEGMENTS
Detailed financial information about our segments is included in Note 25 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data.” The following map depicts our assets at December 31, 2017:
https://cdn.kscope.io/bbc6fc1d8c65ce93f87cbdfd9aa08f0c-nsmap2.jpg











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PIPELINE
Our pipeline operations consist of the transportation of refined petroleum products, crude oil and anhydrous ammonia. As of December 31, 2017, we owned and operated:
refined product pipelines with an aggregate length of 3,130 miles and crude oil pipelines with an aggregate length of 1,930 miles in Texas, Oklahoma, Kansas, Colorado and New Mexico (collectively, the Central West System);
a 1,920-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 Andeavor’s 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 forking east and west to terminate in Nebraska and Indiana (the Ammonia Pipeline).
The following table lists information about our pipeline assets as of December 31, 2017:
 
 
 
 
 
Throughput
 For the year ended December 31,
Region / Pipeline System
Length
 
Tank Capacity
 
2017
 
2016
 
(Miles)
 
(Barrels)
 
(Barrels/Day)
Central West System:
 
 
 
 
 
 
 
McKee System
2,276

 

 
171,815

 
178,373

Three Rivers System
373

 

 
78,165

 
79,502

Other
481

 

 
53,829

 
57,039

Central West Refined Products Pipelines
3,130

 

 
303,809

 
314,914

South Texas Crude System
330

 
2,157,000

 
114,920

 
124,363

Other
200

 

 
52,969

 
59,087

Eagle Ford System
530

 
2,157,000

 
167,889

 
183,450

McKee System
598

 
1,039,000

 
137,675

 
147,956

Ardmore System
119

 
824,000

 
84,801

 
60,775

Permian Crude System
683

 
1,000,000

 
192,958

 

Central West Crude Oil Pipelines
1,930

 
5,020,000

 
583,323

 
392,181

Total Central West System
5,060

 
5,020,000

 
887,132

 
707,095

 
 
 
 
 
 
 
 
Central East System:
 
 
 
 
 
 
 
East Pipeline
1,920

 
5,261,000

 
139,317

 
143,446

North Pipeline
450

 
1,492,000

 
41,438

 
48,343

Ammonia Pipeline
2,000

 

 
32,172

 
29,243

Total Central East System
4,370

 
6,753,000

 
212,927

 
221,032

 
 
 
 
 
 
 
 
Total
9,430

 
11,773,000

 
1,100,059

 
928,127

Description of Pipelines
Central West System. The Central West System covers a total of 5,060 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 1,930 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 terminal and to our customers’ refineries in Corpus Christi, Texas. Our Permian Crude System, most of which we acquired with the Navigator Acquisition,

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consists of crude oil transportation, pipeline connection and storage assets located in the Midland Basin of West Texas, including a pipeline connection system with more than 200 producer tank batteries covering over 500,000 dedicated acres.

Central East System. The Central East System covers a total of 4,370 miles and consists of the East Pipeline, North Pipeline and Ammonia Pipeline.
The East Pipeline covers 1,920 miles and moves refined products and natural gas liquids north in pipelines ranging in diameter from 6 inches to 16 inches to our terminals and third party terminals along the system and to receiving pipeline connections in Kansas. Shippers on the East Pipeline obtain refined petroleum products from refineries in Kansas, Oklahoma and Texas. The East Pipeline system includes 17 terminals, discussed below, with storage capacity of approximately 3.8 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 Andeavor’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 terminals, discussed below, with storage capacity of approximately 1.5 million barrels.
The East and North Pipelines include 21 truck-loading terminals through which refined petroleum products are delivered to storage tanks and then loaded into petroleum product transport trucks. Revenues earned at these terminals predominately relate to the volumes transported on the pipeline through fees included in the pipeline tariff. As a result, these terminals are included in this segment instead of the storage segment.
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.
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 (DOT), the Environmental Protection Agency (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.
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 a computerized 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 the pipelines and the ability and willingness of the refiners and marketers having 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 these products 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.

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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 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 Andeavor’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 Andeavor 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 on the Gulf Coast.
Other than the Valero Energy refineries and the Andeavor refinery described above, if operations at any one refinery were discontinued, we believe (assuming unchanged 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 increase or decrease with the change in crude oil prices. 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 is one of two major anhydrous ammonia pipelines in the United States and the only one capable of receiving products from outside the United States directly into the system and transporting anhydrous ammonia into the nation’s corn belt.
Throughputs on our Ammonia Pipeline depend on overall 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
The largest customer of our pipeline segment was Valero Energy, which accounted for approximately 33% of the total segment revenues for the year ended December 31, 2017. 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, 2017.

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Competition and Business Considerations
Because pipelines are generally the lowest-cost method for intermediate and long-haul movement of crude oil and refined petroleum products, our more significant competitors are common carrier and proprietary pipelines owned and operated by major integrated and large independent oil companies and other 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.
Certain of our crude oil pipelines serve areas or refineries impacted 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, 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. Midwest production facilities, nitrogen fertilizer substitutes and barge and railroad transportation represent other forms of direct competition to 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. As of December 31, 2017, 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 53.3 million barrels;
A terminal on the island of St. Eustatius with tank capacity of 14.3 million barrels and a transshipment facility;
A terminal located in Point Tupper, Canada with tank capacity of 7.8 million barrels and a transshipment facility; and
Six terminals located in the United Kingdom and one terminal located in Amsterdam, the Netherlands, with total storage capacity of approximately 9.5 million barrels.

The following table sets forth information about our terminal and storage facilities as of December 31, 2017:
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

 
 

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Facility
Tank Capacity
 
(Barrels)
El Paso, TX (b)
419,000

Harlingen, TX
286,000

Laredo, TX
215,000

San Antonio, TX (c)
375,000

Southlake, TX
569,000

Nuevo Laredo, Mexico
35,000

Central West Terminals
7,711,000

 
 
Jacksonville, FL
2,593,000

St. James, LA
9,917,000

Houston, TX
86,000

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

Gulf Coast Terminals
15,560,000

 
 
Blue Island, IL
690,000

Andrews AFB, MD (a)
75,000

Baltimore, MD
813,000

Piney Point, MD
5,402,000

Linden, NJ (c)
4,637,000

Paulsboro, NJ
74,000

Virginia Beach, VA (a)
41,000

North East Terminals
11,732,000

 
 
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 (c)
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

 
 
Eastham, England
2,096,000

Grays, England
1,958,000

Runcorn, England
149,000

Belfast, Northern Ireland
408,000

Glasgow, Scotland
353,000

Grangemouth, Scotland
719,000

United Kingdom (UK) Terminals
5,683,000

 
 

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Facility
Tank Capacity
 
(Barrels)
St. Eustatius, the Netherlands
14,256,000

Amsterdam, the Netherlands
3,834,000

Point Tupper, Canada
7,778,000

International Terminals
31,551,000

 
 
Total
84,814,000

 
(a)
Terminal facility also includes pipelines to U.S. government military base locations.
(b)
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.
(c)
Location includes two terminal facilities.
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, 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 can accommodate heavily laden ultra large crude carriers, or ULCCs, for loading and discharging crude oil and other petroleum products. 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 loading and unloading capabilities serve the terminal’s customers’ vessels. The fuel oil and petroleum product facilities have in-tank and in-line 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.

We are currently working on strategic projects at the St. Eustatius terminal to make it more flexible and marketable. These projects include: (i) replacing the existing SPM with a refurbished SPM and the installation of two additional subsea pipelines from the SPM, which will give us the option to load and unload two different products at the SPM and segregate various grades of crude and fuel oil to and from the SPM, (ii) pipeline improvements and (iii) tank upgrades, repairs and rebuilds. Upon completion of these projects, we will also have the capability to load or unload three crude vessels at a time. In September 2017, St. Eustatius sustained substantial damage during Hurricane Irma and the terminal was temporarily shut down. Although the terminal was fully operational by November, we expect repairs to continue into 2018 and beyond, thereby delaying the completion of certain of these strategic projects.
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 gathering pipelines in the Gulf of Mexico, lines that connect to Eagle Ford, Permian and other domestic shale plays, and 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, which 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

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as associated services, including pilotage, tug assistance, line handling, launch service, emergency response services and other ship 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 4.6 million barrels and can receive and deliver products via ship, barge and pipeline. The terminal facility includes two docks.

Amsterdam. Our Amsterdam terminal has a total storage capacity of 3.8 million barrels. This facility is located at the Port of Amsterdam and primarily stores petroleum products, including gasoline, diesel and fuel oil. This facility has two docks for vessels and five docks for inland barges.

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 connected to a third-party pipeline system. It also provides our customers with the flexibility to segregate and deliver crude oil and processed condensate. This facility has three docks, including one private dock, and can load crude oil onto ships simultaneously on all three docks at a maximum rate of 65,000 barrels per hour. This facility will have exclusive-use access to the Port of Corpus Christi’s new crude oil dock expected to be completed in 2018, which will give the terminal four docks. Once the new dock is complete, the Corpus Christi North Beach terminal will have the capacity to move on average between 650,000 and 700,000 barrels per day and will be able to accommodate Aframax-class vessels.
Storage Operations
Revenues for the storage segment include fees for tank storage agreements, where 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, where 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 previously charged a fee for each barrel of crude oil and certain other feedstocks that we delivered to Valero Energy’s Benicia, Corpus Christi West and Texas City refineries from our crude oil refinery storage tanks. Effective January 1, 2017, we lease these refinery storage tanks 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 Petroleum 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 petroleum products. Demand for our terminalling services will generally increase or decrease with demand for refined petroleum products, and demand for refined petroleum 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.
Crude oil delivered to our St. James terminal through our unit train facilities, and crude oil delivered to our Corpus Christi North Beach terminal will generally increase or decrease with crude oil production rates in the Bakken and Eagle Ford shale plays, respectively. 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 petroleum 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. The largest customer of our storage segment is Valero Energy, which accounted for approximately 21% of the total revenues of the segment for the year ended December 31, 2017. No other customer accounted for more than 10% of the total revenues of the storage segment for the year ended December 31, 2017.
Competition and 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

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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 U.S. shores, 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. At the same time, South American production of heavy crude has ramped up significantly. As demand for export of heavy crude out of South America has risen, so has the demand for “build bulk” services. In order to reduce costs and increase efficiencies for long routes to customers abroad, exporting producers need to consolidate their heavy oil cargos from the small ships used to move the heavy crude off shore to a large vessel that is more efficient for long routes, a process referred to as “build bulk.” Our St. Eustatius terminal’s location is well-suited to build bulk for South American producers headed to customers overseas, primarily in Asia. However, recently, the combination of oversupply of storage capacity, decreased demand from backwardated markets and reduced North American crude imports 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

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 are in line with our goal of reducing our exposure to commodity margins, and instead focusing on our core, fee-based pipeline and storage segments. The only operations remaining 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 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. Since our fuels marketing operations expose us to commodity price risk, we enter into derivative instruments to mitigate the effect of commodity price fluctuations on our operations. The derivative instruments we use consist primarily of commodity futures and swap contracts.

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.


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EMPLOYEES

As of December 31, 2017, we had 1,694 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 2017, our capital expenditures attributable to compliance with environmental regulations were $13.9 million, and we currently project spending to be approximately $17.8 million in this regard in 2018. However, future governmental actions 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

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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

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 petroleum 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 petroleum 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.

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.


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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 THE POTENTIAL MERGER

While the Merger Agreement is in effect, we may be limited in our ability to pursue other attractive business opportunities.
While the Merger Agreement is in effect, we have agreed to refrain from taking certain actions with respect to our business and financial affairs pending the consummation of the Merger or termination of the Merger Agreement. These restrictions could be in effect for an extended period of time if the consummation of the Merger is delayed. These limitations do not preclude us from conducting our business in the ordinary or usual course or from acquiring assets or businesses so long as such activity does not have a “material adverse effect,” as such term is defined in the Merger Agreement, or exceed certain thresholds specifically provided in the Merger Agreement.

In addition to the economic costs associated with pursuing the Merger, the management of our general partner will continue to devote substantial time and other human resources to the proposed Merger, which could limit our ability to pursue other attractive business opportunities, including potential joint ventures, stand-alone projects and other transactions. If we are unable to pursue such other attractive business opportunities, our growth prospects and the long-term strategic position of our business following the Merger could be adversely affected.

Our existing unitholders will be diluted by the Merger.
The Merger will dilute the ownership position of our existing unitholders. Pursuant to the Merger Agreement, NuStar GP Holdings unitholders will receive approximately 23.6 million of our common units as a result of the Merger. Assuming the number of units outstanding as of January 31, 2018, immediately following the Merger, our common units would be owned approximately 78% by our current common unitholders and approximately 22% by former NuStar GP Holdings unitholders.

The Merger is subject to conditions and may not be consummated even if the required NuStar GP Holdings unitholder approvals are obtained.
The Merger is subject to the satisfaction or waiver of certain conditions, some of which are out of the control of NuStar GP Holdings and NuStar Energy, including approval of the Merger Agreement by NuStar GP Holdings unitholders. The Merger Agreement also contains other conditions that, if not satisfied or waived, would result in the Merger not occurring, regardless of whether or not the NuStar GP Holdings unitholders have voted in favor of the Merger-related proposals presented to them. Satisfaction of some of these other conditions to the Merger is not entirely in the control of either NuStar GP Holdings or NuStar Energy. In addition, NuStar GP Holdings and NuStar Energy can agree not to consummate the Merger even if all unitholder approvals have been received. The closing conditions to the Merger may not be satisfied, and NuStar GP Holdings and NuStar Energy may choose not to, or may be unable to, waive an unsatisfied condition, which may cause the Merger not to occur.

The Merger Agreement contains provisions granting both NuStar Energy and NuStar GP Holdings the right to terminate the Merger Agreement for certain reasons, including, among others (1) by mutual consent of NuStar Energy and NuStar GP Holdings; (2) by either party if the Merger has not been consummated on or before August 8, 2018; (3) if certain changes in rules or regulations prohibit the consummation of the Merger; (4) if NuStar GP Holdings fails to obtain NuStar GP Holdings unitholder approval; or (5) if a breach of, or an inaccuracy in, the representations or warranties is not cured within thirty days. Furthermore, NuStar Energy may terminate the Merger Agreement in the event that, prior to NuStar GP Holdings unitholder approval, NuStar GP Holdings has intentionally and materially breached the non-solicitation covenants in the Merger Agreement or the NuStar GP Holdings board issues a change of recommendation pursuant to the terms of the Merger Agreement, and NuStar GP Holdings may terminate the Merger Agreement in order to accept a Superior Proposal (as defined in the Merger Agreement) so long as NuStar GP Holdings (1) has not intentionally and materially breached certain provisions of the Merger Agreement and (2) has paid NuStar Energy a termination fee.

Failure to complete the Merger or delays in completing the Merger could negatively impact our common unit price.
If the Merger is not completed for any reason, we may be subject to a number of material risks, including the following:
we will not realize the benefits expected from the Merger, including a potentially enhanced financial and competitive position;
the price of our common units may decline to the extent that the current market price of these securities reflects a market assumption that the Merger will be completed; and
some costs relating to the Merger, such as certain investment banking fees and legal and accounting fees, must be paid even if the Merger is not completed.


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The costs of the Merger could adversely affect our operations and cash flows available for distribution to our unitholders.
The total costs of the Merger, which could be substantial, primarily consist of investment banking, legal counsel and accounting fees, financial printing and other related costs. These costs could adversely affect our operations and cash flows available for distributions to our unitholders.

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, which fluctuates from quarter to quarter 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.

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

On February 8, 2018, we announced that our management anticipates recommending to our board of directors, and our board of directors expects to adopt, a reset of our quarterly distribution per common unit to $0.60 ($2.40 on an annualized basis), starting with the first-quarter distribution payable in May 2018. In addition, 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, and we may make cash distributions during periods in which we record net losses and may not 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, 2017, our consolidated debt was $3.6 billion, and we have the ability to incur more debt. We also may be required to post cash collateral under certain of our hedging arrangements, which we expect to fund with borrowings under our revolving credit agreement. 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 November 2017, S&P Global Ratings downgraded our credit rating from BB+ Stable to BB Negative outlook, which raised the interest rate on our 7.65% Senior Notes Due 2018 (the 2018 Senior Notes). In February 2018, Moody’s Investors Service, Inc. downgraded our credit rating from Ba1 to Ba2, which increased the interest rate on both the 2018 Senior Notes and 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 the 2018 Senior Notes, 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 (consisting of any period of four consecutive fiscal 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,

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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 maximum permitted ratio was raised to 5.50-to-1.00 through March 31, 2018 due to our acquisition of Navigator Energy Services, LLC. We also amended our revolving credit agreement in November 2017 to exclude NuStar Logistics’ 7.625% Fixed-to-Floating Rate Subordinated Notes due 2043 (the Junior Sub Notes) from our calculation of consolidated debt through December 31, 2018. Failure to comply with any of the revolving credit agreement restrictive covenants or our required coverage ratio will result in a default and could result in acceleration of our obligations under the revolving credit agreement and possibly other indebtedness. 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 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, 2017, we had approximately $3.6 billion of consolidated debt, of which $2.3 billion was at fixed interest rates

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and $1.3 billion was at variable interest rates. Also, in January 2018 the interest rate on our Junior Sub Notes shifted from a fixed rate to a floating annual rate equal to the sum of the three-month LIBOR rate for the related quarterly interest period, plus 6.734%. Additionally, at December 31, 2017, we had $600.0 million aggregate notional amount of interest rate swap arrangements, which may expose us to risk of financial loss. Prior ratings downgrades on our existing indebtedness caused interest rates under our revolving credit agreement and our 2018 Senior Notes to increase, and any future downgrades may further increase the interest rate on our 2018 Senior Notes. Our results of operations, cash flows and financial position could be materially adversely affected by significant changes in interest rates. In addition, we historically have 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.

Furthermore, 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.
Since late 2014, the price of crude oil has been depressed, which has caused most crude oil producers 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 have benefited from lower crude prices, to the extent that lower feedstock price has been coupled with higher demand for certain refined products in some regional markets. While only a portion of our total business is directly affected by the price of crude, continued low crude oil prices and related overall economic downturn could have a negative impact on our cash flows and results of operations.

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. 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 automotive engine fuel economy, whether as a result of a shift by consumers to more fuel-efficient vehicles or technological advances by manufacturers;
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 leads to higher refined product prices, which may reduce demand for refined products and drive demand for alternative products. 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; 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;
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

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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 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, 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 will 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.

We will incur financing costs during the planning and construction phases of our projects; however, the operating cash flows we expect these projects to generate will not materialize until sometime after the projects are completed, if at all. Additionally, our forecasted operating results from capital spending projects are based upon our projections of 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.

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;
environmental proceedings or other litigation that compel the cessation of all or a portion of the operations at 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

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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.
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 such as 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 cause an increase in hurricanes and other severe 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 have increased substantially and could escalate further; 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. For example, our insurance carriers require broad exclusions for losses due to terrorist acts. If we were to incur a significant liability for which we are not fully insured, such a liability could have a material adverse effect on our financial position.

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.

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. Severe 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. For example, a substantial portion of our St. Eustatius facility revenue derives from our storage of petroleum products exported from Venezuela on behalf of Petróleos de Venezuela, S.A. (PDVSA), a state-owned Venezuelan oil company. Significant political, social and economic instability in Venezuela, including constraints on foreign currency transactions by the Venezuelan government, has caused PDVSA to utilize our assets significantly less than we forecasted and late-pay invoices from time to time. Our involvement with products exported from Venezuela also exposes us to the risk of trade restrictions and economic embargoes imposed by the United States and other countries.

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

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of our outstanding derivatives could expose us to additional interest rate or commodity price risk. While we attempt to mitigate our risk through warehouseman’s liens and other security protections, any substantial increase in the nonpayment and nonperformance by our customers, vendors or counterparties could have a material adverse effect on our results of operations, cash flows and ability to make distributions to unitholders.

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, including information we use to safely operate our assets. In recent years, there has been a rise in the number of cyberattacks on other companies’ network and information systems 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, customer dissatisfaction, damage to our reputation, a 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 information security procedures and other safeguards in place, as cyberthreats continue to evolve, we may be required to expend additional resources to continue to enhance our information security measures and/or to investigate and remediate information security vulnerabilities.

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 a global business that exposes us to additional risk.
We operate a global business. A significant portion of our revenues come from our business outside of the United States, and our operations are subject to various risks unique to each country 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

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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, the United Kingdom Bribery Act and other foreign laws prohibiting corrupt payments, as well as import and export regulations. Additionally, negotiations are ongoing regarding the United Kingdom’s exit from the European Union, and any future effects from this are currently unknown.

We also have assets in, or do business with customers based in, certain emerging markets, and the developing 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, a state-owned oil company in Venezuela, is a significant customer of our terminal facility in St. Eustatius, and recent political, social and economic instability in Venezuela seems to have had a negative impact on both PDVSA’s utilization of our facility and its ability to timely pay amounts invoiced.

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.   In 2017, the United States and the European Union imposed sanctions relating to Venezuela and PDVSA.  While these sanctions do not prohibit us from continuing to perform under our existing contracts with PDVSA, the sanctions may increase the likelihood that PDVSA will be unable to perform its obligations to us.  In addition, in the event additional sanctions are imposed in the future relating to Venezuela or PDVSA, such future sanctions may result in further deterioration of PDVSA’s ability to perform its obligations to us and could prevent us from continuing to serve PDVSA in St. Eustatius.

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.
We obtain the rights to construct and operate our pipelines, storage terminals and other facilities on land owned by third parties and governmental agencies. 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 additions 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.

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.
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

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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 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. 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.

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 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.

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

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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, 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%. Further, some of our newer projects that involved an open season include negotiated indexation rate caps.

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. These methodologies, 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. For example, our costs could increase more quickly or by a greater amount than the negotiated or, if adopted, FERC-mandated indexation rate cap.

The reporting of system-based cost and revenue data, if adopted as a result of the ANOPR, could lead to an increase in rate litigation at the FERC. Currently, shippers may protest rate increases made within the ceiling levels, but such protests must show that the portion of the rate increase resulting from application of the index is substantially in excess of the pipeline’s change in costs from the previous year. However, if the index results in a negative adjustment, we are required to reduce any rates that exceed the new maximum allowable rate. In addition, changes in the index might not be large enough to fully reflect actual increases in our costs. If the FERC’s rate-making methodologies change, any 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. 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.

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.
In May 2005, the FERC issued a statement of general policy stating it will permit pipelines to include in their costs of service a tax allowance to reflect actual or potential tax liability on their public utility income attributable to all partnership or limited liability company interests, if the ultimate owner of the interest has an actual or potential income tax liability on such income. Whether a pipeline’s owners have such actual or potential income tax liability will be reviewed by the FERC on a case-by-case basis. Although this policy is generally favorable for pipelines that are organized as pass-through entities, it still entails rate risk due to the case-by-case review requirement. This tax allowance policy and the FERC’s application of that policy were appealed to the D.C. Circuit and, on May 29, 2007, the D.C. Circuit issued an opinion upholding the FERC’s tax allowance policy.

In two proceedings involving SFPP, L.P., a refined products pipeline system, shippers again challenged the FERC’s income tax allowance policy, alleging that it is unlawful for a pipeline organized as a tax-pass-through entity to be afforded an income tax allowance and that the income tax allowance is unnecessary because an allowance for income taxes for such pipelines is recovered indirectly through the rate of return on equity.  The FERC rejected these shipper arguments in multiple orders.  Petitions for review of the FERC’s rulings on the income tax allowance were filed with the D.C. Circuit.

On July 1, 2016, the D.C. Circuit issued an opinion granting the shippers’ petition for review of the FERC’s rulings on the income tax allowance, finding that 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. On this basis, the D.C. Circuit remanded the issue to the FERC, which established a pending industrywide Notice of Inquiry regarding this issue. Certain participants in the Notice of Inquiry made filings claiming that pipeline rates should be reduced based on anticipated income tax reductions related to the Tax Cuts and Jobs Act. Because the extent to which an interstate oil pipeline organized as a partnership is entitled to an income tax allowance is subject to a case-by-case review at the FERC and is a matter that remains under litigation and FERC review, the level of income tax allowance to which we would ultimately be entitled is not certain. The manner in which the FERC’s income tax allowance policy is applied to pipelines owned by publicly traded partnerships could limit our ability to include a full income tax allowance in our cost of service.


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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, 2017, our power costs equaled approximately $46.0 million, or 10.2% 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 crude oil and 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 crude oil and petroleum products represents a small percentage of our overall business, these activities expose us to some commodity price volatility risk for the purchase and sale of crude oil and 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.

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.

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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

We do not have the same flexibility as other types of organizations to accumulate cash and equity and protect against illiquidity in the future.
Unlike a corporation, our partnership agreement requires us to make quarterly distributions to our unitholders of all available cash, after taking into account reserves for commitments and contingencies, including capital and operating costs and debt service requirements. 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 capital to finance our growth plans, meet unforeseen cash requirements and service our debt.

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.
Consistent with the terms of our partnership agreement, we distribute our available cash to our common unitholders and our general partner each quarter. In determining the amount of cash available for distribution, our management sets 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 acquisition capital expenditures. 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 or increase our current per unit distribution level.

NuStar GP Holdings may currently have and, if the Merger is not consummated, may continue to have conflicts of interest and limited fiduciary responsibilities, which may permit it to favor its own interests to the detriment of our unitholders.
NuStar GP Holdings currently indirectly owns our general partner, our incentive distribution rights and, as of December 31, 2017, an aggregate 11.0% of our outstanding common units. Conflicts of interest may arise between NuStar GP Holdings and its affiliates, including our general partner, on the one hand, and us and our limited partners, on the other hand. As a result of these conflicts, the general partner may favor its own interests and the interests of its affiliates over the interests of our unitholders. These conflicts include, among others, the following situations:
our general partner is allowed to take into account the interests of parties other than us, such as NuStar GP Holdings, in resolving conflicts of interest, which has the effect of limiting its fiduciary duty to our unitholders;
our general partner may limit its liability and reduce its fiduciary duties, while also restricting the remedies available to unitholders. As a result of purchasing our units, unitholders have consented to some actions and conflicts of interest that might otherwise constitute a breach of fiduciary or other duties under applicable state law;
our general partner determines the amount and timing of asset purchases and sales, capital expenditures, borrowings and issuances of additional limited partner interests and reserves, each of which can affect the amount of cash that is paid to our unitholders;
our general partner determines in its sole discretion which costs incurred by NuStar GP Holdings and its affiliates are reimbursable by us;
our general partner may cause us to pay the general partner or its affiliates for any services rendered on terms that are fair and reasonable to us or enter into additional contractual arrangements with any of these entities on our behalf;
our general partner decides whether to retain separate counsel, accountants or others to perform services for us; and

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in some instances, our general partner may cause us to borrow funds in order to permit the payment of distributions.

Our partnership agreement gives the general partner broad discretion in establishing financial reserves for the proper conduct of our business, including interest payments. These reserves also affect the amount of cash available for distribution.

If the Merger is not consummated, the general partner interest, the control of our general partner and the incentive distribution rights of our general partner may be transferred to a third party without unitholder consent.
If the merger is not consummated, our general partner may transfer its general partner interest and/or its incentive distribution rights to a third party without the consent of our unitholders. Any new owner of our general partner would be in a position to replace the officers of the general partner with its own choices and to control the decisions made by such officers. If our general partner transfers its incentive distribution rights to a third party but retains its general partner interest, our general partner may not have the same incentive to grow our partnership and increase quarterly distributions to unitholders over time as it would if it had retained ownership of its incentive distribution rights.

Unitholders have limited voting rights, and our partnership agreement further restricts the voting rights of 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, other than our general partner or its affiliates, cannot vote on any matter without the prior approval of our general partner.

We may issue an unlimited number of additional units, including units that are senior to the common units and pari passu with our 8.50% Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units, 7.625% Series B Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units and 9.00% Series C Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units (collectively, the Preferred Units); issuing new units dilutes existing unitholders and may increase the aggregate distribution we are required to pay each quarter under the terms of our partnership agreement.
Our partnership agreement allows us to issue additional units and certain other equity securities on the terms and conditions established by our general partner and without the approval of other unitholders. There is no limit on the total number of units and other equity securities we may issue.  If we issue additional units or other equity securities, the proportionate partnership interest of our existing common unitholders and the relative voting strength of each of the previously outstanding common 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.

In addition, we may issue an unlimited number of units that are senior to the common units in right of distribution, liquidation and voting, including additional Preferred Units and any securities in parity with the Preferred Units without any vote of the holders of the Preferred Units (except where the cumulative distributions on the Preferred Units or any parity securities are in arrears and in certain other circumstances) and without the approval of our common unitholders. 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.

Additionally, although holders of the Preferred Units are entitled to limited voting rights, with respect to certain matters the Preferred Units generally vote separately as a class along with all other series of our parity securities that we may issue upon which like voting rights have been conferred and are exercisable. As a result, the voting rights of holders of Preferred Units may be significantly diluted, and the holders of such other series of parity securities that we may issue 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 on parity with or senior to the Preferred Units (including additional Preferred Units of the same series) would dilute the interests of the holders of the Preferred Units, and any issuance of equity securities of any class or series that ranks on parity with the Preferred Units as to the payment of distributions and amounts payable upon a liquidation event (including additional Preferred Units of the same series) or equity securities with terms expressly made senior to the Preferred Units as to the payment of distributions and 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 the Preferred Units in the event of a highly leveraged or other

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transaction, including a merger or the 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 parity securities, or the perception that such issuances and sales could occur, may cause prevailing market prices for the 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 fiscal quarter, we will be unable to 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.
The 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 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 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. The preferences and privileges of the 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 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 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.


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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 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. See “Director Independence” under Item 13 of this annual report on Form 10-K for additional information regarding the independence of our general partner’s directors and the committees of our general partner’s board.

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. Further, final Treasury regulations under Section 7704(d)(1)(E) of the Code published in the Federal Register interpret the scope of qualifying income requirements for publicly traded partnerships by providing industry-specific guidance. We do not believe the final Treasury regulations affect our ability to be treated as a partnership for U.S. federal income tax purposes.

In addition, the Tax Cuts and Jobs Act enacted December 22, 2017, makes 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. The Tax Cuts and Jobs Act is complex and lacks administrative guidance. Thus, the impact of certain aspects of its provisions on us or an investment in our units is currently unclear. Unitholders should consult their tax advisor regarding the Tax Cuts and Jobs Act and its effect on us or an investment in our units.


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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.

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.” 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.


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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 that is engaged in one or more unrelated trades or businesses) 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.
 
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. It is not clear if or when such regulations or other guidances will be issued. 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 pursuant to which a publicly traded partnership may use a similar monthly simplifying convention to allocate tax items among transferor and transferee unitholders, although such tax items must be prorated on a daily basis and the regulations do not specifically authorize all aspects of the proration method we have currently adopted. 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.


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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.

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 may not be 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 “qualified publicly traded partnership income.” Although we expect that much of the income we earn is generally eligible for the 20% deduction for qualified publicly traded partnership income, it is uncertain whether a guaranteed payment for the use of capital may constitute an allocable or distributive share of such income. As a result, the guaranteed payment for use of capital received by the holders of our Preferred Units may not be 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

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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. It is not clear if or when such regulations or other guidance will be issued. 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 consequences of owning our Preferred Units.

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.

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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 8, 2018, we had 464 holders of record of our common units. The following table presents the high and low sales prices for our common units during the periods presented (composite transactions as reported by the New York Stock Exchange) and the amount, record date and payment date of the quarterly cash distributions on our common units with respect to such periods:
 
Price Range per Common Unit
 
Cash Distributions
 
High
 
Low
 
Amount Per
Common Unit
 
Record Date
 
Payment Date
Year 2017
 
 
 
 
 
 
 
 
 
4th Quarter (a)
$
41.00

 
$
26.21

 
$
1.095

 
February 8, 2018
 
February 13, 2018
3rd Quarter
$
47.99

 
$
37.30

 
$
1.095

 
November 9, 2017
 
November 14, 2017
2nd Quarter
$
52.68

 
$
42.40

 
$
1.095

 
August 7, 2017
 
August 11, 2017
1st Quarter
$
55.64

 
$
49.09

 
$
1.095

 
May 8, 2017
 
May 12, 2017
Year 2016
 
 
 
 
 
 
 
 
 
4th Quarter
$
50.87

 
$
43.41

 
$
1.095

 
February 8, 2017
 
February 13, 2017
3rd Quarter
$
50.72

 
$
43.91

 
$
1.095

 
November 8, 2016
 
November 14, 2016
2nd Quarter
$
53.47

 
$
37.90

 
$
1.095

 
August 9, 2016
 
August 12, 2016
1st Quarter
$
42.87

 
$
25.65

 
$
1.095

 
May 9, 2016
 
May 13, 2016
(a)
The distribution was announced on January 29, 2018.

Our partnership agreement requires that we distribute all “Available Cash” to our common limited partners and general partner each quarter, and 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. See Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” for further information regarding our distributions.

On February 7, 2018, NuStar Energy, Riverwalk Logistics, L.P., NuStar GP, LLC, Merger Sub, Riverwalk Holdings, LLC and NuStar GP Holdings entered into the Merger Agreement pursuant to which Merger Sub will merge with and into NuStar GP Holdings with NuStar GP Holdings being the surviving entity, such that NuStar Energy will be the sole member of NuStar GP Holdings following the Merger. Additionally, on February 8, 2018, we announced that our management anticipates recommending to the board of directors of NuStar GP, LLC, and the board of directors expects to adopt, a reset of our quarterly distribution per common unit to $0.60 ($2.40 on an annualized basis), starting with the first-quarter distribution payable in May 2018. Please refer to Note 28 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for further discussion of the Merger.

General Partner Distributions
Our general partner is entitled to distributions as 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%

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Our general partner’s incentive distributions totaled $45.7 million and $43.4 million for the years ended December 31, 2017 and 2016, respectively. The general partner’s share of our distributions for the years ended December 31, 2017 and 2016 was 11.9% and 13.0%, respectively, due to the impact of the incentive distributions. 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 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 (other than those attributable to NS common units issued under any equity compensation plan) for ten consecutive quarters, starting with the distributions for the second quarter of 2017.

Pursuant to the Merger Agreement and at the effective time of the Merger, our partnership agreement will be 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. As a result, after the Merger, our general partner will no longer receive incentive distributions or quarterly cash distributions related to its ownership interest, from us. Please refer to Note 28 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for further discussion of the Merger.

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 (collectively, the 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
 
Optional Redemption Date/Date at Which Distribution Rate Becomes Floating
 
Floating Annual Rate (as a Percentage of the $25.00 Liquidation Preference per Unit)
Series A Preferred Units
 
8.50%
 
$
2.125

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

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

 
December 15, 2022
 
Three-month LIBOR plus 6.88%

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.


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The following table summarizes information related to our quarterly cash distributions on our Preferred Units:
Period
 
Cash
Distributions
Per Unit
 
Record Date
 
Payment Date
 
 
 
 
 
 
 
Series A Preferred Units:
 
 
 
 
 
 
December 15, 2017 - March 14, 2018 (a)
 
$
0.53125

 
March 1, 2018
 
March 15, 2018
September 15, 2017 - December 14, 2017
 
$
0.53125

 
December 1, 2017
 
December 15, 2017
June 15, 2017 - September 14, 2017
 
$
0.53125

 
September 1, 2017
 
September 15, 2017
March 15, 2017 - June 14, 2017
 
$
0.53125

 
June 1, 2017
 
June 15, 2017
November 25, 2016 - March 14, 2017
 
$
0.64930556

 
March 1, 2017
 
March 15, 2017
 
 
 
 
 
 
 
Series B Preferred Units:
 
 
 
 
 
 
December 15, 2017 - March 14, 2018 (a)
 
$
0.47657

 
March 1, 2018
 
March 15, 2018
September 15, 2017 - December 14, 2017
 
$
0.47657

 
December 1, 2017
 
December 15, 2017
April 28, 2017 - September 14, 2017
 
$
0.725434028

 
September 1, 2017
 
September 15, 2017
 
 
 
 
 
 
 
Series C Preferred Units:
 
 
 
 
 
 
November 30, 2017 - March 14, 2018 (a)
 
$
0.65625

 
March 1, 2018
 
March 15, 2018
(a)
The distribution was announced on January 29, 2018.


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ITEM 6.    SELECTED FINANCIAL DATA
The following table contains selected financial data derived from our audited financial statements:
 
Year Ended December 31,
 
2017
 
2016
 
2015
 
2014
 
2013 (a)
 
(Thousands of Dollars, Except Per Unit Data)
Statement of Income Data:
 
 
 
 
 
 
 
 
 
Revenues (b)
$
1,814,019

 
$
1,756,682

 
$
2,084,040

 
$
3,075,118

 
$
3,463,732

Operating income (loss)
$
336,278

 
$
359,109

 
$
390,704

 
$
346,901

 
$
(19,121
)
Income (loss) from continuing operations (c)
$
147,964

 
$
150,003

 
$
305,946

 
$
214,169

 
$
(185,509
)
Income (loss) from continuing operations per
common unit (c)
$
0.64

 
$
1.27

 
$
3.29

 
$
2.14

 
$
(2.89
)
Cash distributions per unit applicable
to common limited partners
$
4.38

 
$
4.38

 
$
4.38

 
$
4.38

 
$
4.38

 
 
 
 
 
 
 
 
 
 
 
December 31,
 
2017 (d)
 
2016
 
2015
 
2014
 
2013
 
(Thousands of Dollars)
Balance Sheet Data:
 
 
 
 
 
 
 
 
 
Property, plant and equipment, net
$
4,300,933

 
$
3,722,283

 
$
3,683,571

 
$
3,460,732

 
$
3,310,653

Total assets
$
6,535,233

 
$
5,030,545

 
$
5,125,525

 
$
4,918,796

 
$
5,032,186

Long-term debt, less current portion
$
3,263,069

 
$
3,014,364

 
$
3,055,612

 
$
2,749,452

 
$
2,655,553

Total partners’ equity
$
2,480,089

 
$
1,611,617

 
$
1,609,844

 
$
1,716,210

 
$
1,903,794

(a)
The losses for the year ended December 31, 2013 are mainly due to goodwill impairment charges.
(b)
Declines in revenues from 2013 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.
(c)
Includes the impact of a $58.7 million non-cash impairment charge on the Axeon term loan in 2016 and a $56.3 million non-cash gain associated with the Linden terminal acquisition in 2015.
(d)
The significant increases in balance sheet data are primarily due to our acquisition of Navigator Energy Services, LLC for approximately $1.5 billion in May 2017.


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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.
OVERVIEW
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. NuStar GP Holdings, LLC (NuStar GP Holdings or NSH) (NYSE: NSH) owns our general partner, Riverwalk Logistics, L.P., and owns an approximate 11% common limited partner interest in us as of December 31, 2017. Our Management’s Discussion and Analysis of Financial Condition and Results of Operations is presented in seven sections:
Overview
Results of Operations
Trends and Outlook
Liquidity and Capital Resources
Related Party Transactions
Critical Accounting Policies
New Accounting Pronouncements

Recent Developments
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 which Merger Sub will merge with and into NuStar GP Holdings with NuStar GP Holdings being the surviving entity (the Merger), such that NuStar Energy will be the sole member of NuStar GP Holdings following the Merger. Pursuant to the Merger Agreement and at the effective time of the Merger, our partnership agreement will be 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 at an annual meeting, beginning in 2019. The Merger is subject to the satisfaction or waiver of certain conditions, including approval of the Merger Agreement by NuStar GP Holdings unitholders. Please refer to Note 28 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for further discussion of the Merger.

Hurricane Activity. In the third quarter of 2017, parts of the Caribbean and Gulf of Mexico experienced three major hurricanes. Several of our facilities were affected by the hurricanes, but our St. Eustatius terminal experienced the most damage and was temporarily shut down. We incurred approximately $2.6 million of operating expenses to repair minor property damage at several of our domestic terminals. Additionally, we recorded a $5.0 million loss in “Other (expense) income, net” in the consolidated statements of income in the third quarter of 2017 for property damage at our St. Eustatius terminal, which represents the amount of our property deductible under our insurance policy. The hurricane impacts lowered revenues for our bunker fuel operations in our fuels marketing segment and lowered throughput and associated handling fees in our storage segment in the third and fourth quarters of 2017. We received insurance proceeds of $12.5 million in 2017 for damages at our St. Eustatius terminal, of which $3.8 million was for business interruption and the remainder was used for repairs and cleanup. 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. In January 2018, we received $87.5 million of insurance proceeds in settlement of our property damage claim for our St. Eustatius terminal. We expect that the costs to repair the property damage at the terminal will not exceed the value of insurance proceeds received.

Navigator Acquisition and Financing Transactions. On May 4, 2017, we completed the acquisition of Navigator Energy Services, LLC for approximately $1.5 billion (the Navigator Acquisition). In order to fund the purchase price, we issued 14,375,000 common units for net proceeds of $657.5 million, issued $550.0 million of 5.625% senior notes for net proceeds of $543.3 million and issued 15,400,000 of our 7.625% Series B Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units (Series B Preferred Units) for net proceeds of $371.8 million. We collectively refer to the acquired assets as our

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Permian Crude System. Please refer to Notes 4, 12 and 19 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 (expense) income, net” in the consolidated statements of income. Please refer to Notes 7 and 15 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.

Other Events
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 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 17 for further discussion of the Employee Transfer and our related party agreements, Note 22 for a discussion of our employee benefit plans and Note 23 for a discussion of our long-term incentive plan.

Linden Acquisition. On January 2, 2015, we acquired full ownership of ST Linden Terminal, LLC (Linden), which owns a refined products terminal in Linden, NJ with 4.3 million barrels of storage capacity, for $142.5 million (the Linden Acquisition). Prior to the Linden Acquisition, Linden operated as a joint venture between Linden Holding Corp. and us, with each party owning 50%. On the acquisition date, we remeasured our existing 50% equity investment in Linden to its fair value of $128.0 million and we recognized a gain of $56.3 million in “Other (expense) income, net” in the consolidated statements of income for the year ended December 31, 2015. 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 Linden Acquisition.

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 1,930 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 2,370 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 6.8 million barrels.

Storage. We own terminals and storage facilities in the United States, Canada, Mexico, the Netherlands, including St. Eustatius in the Caribbean, and the United Kingdom (UK), with approximately 84.8 million barrels of storage capacity.

Fuels Marketing. Within our fuels marketing operations, we purchase petroleum products for resale. 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. We enter into derivative contracts to attempt to mitigate the effects of commodity price fluctuations. 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.

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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 are in line with our goal of reducing our exposure to commodity margins, and instead focusing on our core, fee-based pipeline and storage segments. The only operations remaining 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.

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 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.

Current Market Conditions
The price of crude oil has recovered somewhat since its sharp initial decline in 2014 and subsequent historic lows during 2015 and 2016. In 2017, global supply and demand moved into balance, which seems to have reduced crude price volatility, but crude prices remain stalled at approximately 50% of their 2014 levels. Most energy industry experts now project a modest price recovery in 2018, but the duration and degree of price improvements will depend on, among other things, changes in global supply and demand.

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, U.S. crude oil producers reduced their capital spending relatively early in this sustained low price cycle, which reduced drilling activity and lowered production, particularly in shale play regions with higher relative drilling costs. As this cycle has continued, producers focused their trimmed-back spending on the most capital-efficient regions, such as, notably, the Permian Basin. Refiners, on the other hand, have benefitted from lower crude oil prices, to the extent they have been 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 are incentivized to reduce their production levels, which in turn may reduce their ability 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, traders are no longer incentivized to purchase and store product for future sale.


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RESULTS OF OPERATIONS
Year Ended December 31, 2017 Compared to Year Ended December 31, 2016
Financial Highlights
(Thousands of Dollars, Except Unit and 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:
 
 
 
 
 
Cost of product sales
651,599

 
633,653

 
17,946

Operating expenses
449,670

 
448,367

 
1,303

General and administrative expenses
112,240

 
98,817

 
13,423

Depreciation and amortization expense
264,232

 
216,736

 
47,496

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
)
Basic weighted-average common units outstanding
88,825,964

 
78,080,484

 
10,745,480

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.


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Table of Contents

Segment Operating Highlights
(Thousands of Dollars, Except Barrel/Day Information)
 
 
Year Ended December 31,
 
 
 
2017
 
2016
 
Change
Pipeline:
 
 
 
 
 
Refined products 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

Cost of product sales
651,599

 
633,653

 
17,946

Operating expenses
449,670

 
448,367

 
1,303

Depreciation and amortization expense
255,534

 
208,217

 
47,317

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
)


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Table of Contents

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 this 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
Beginning January 1, 2017, our agreements for our refinery crude storage tanks at Corpus Christi, TX, Texas City, TX and Benicia, CA changed 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 this 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.


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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 our heavy fuels trading operations following our exit of that business in 2017. Segment operating income from our bunker fuel operations at our St. Eustatius terminal decreased $6.4 million, resulting from 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 7 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 24 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.


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Table of Contents

Year Ended December 31, 2016 Compared to Year Ended December 31, 2015
Financial Highlights
(Thousands of Dollars, Except Unit and Per Unit Data)
 
Year Ended December 31,
 
 
 
2016
 
2015
 
Change
Statement of Income Data:
 
Revenues:
 
 
 
 
 
Service revenues
$
1,083,165

 
$
1,114,153

 
$
(30,988
)
Product sales
673,517

 
969,887

 
(296,370
)
Total revenues
1,756,682

 
2,084,040

 
(327,358
)
 
 
 
 
 
 
Costs and expenses:
 
 
 
 
 
Cost of product sales
633,653

 
907,574

 
(273,921
)
Operating expenses
448,367

 
473,031

 
(24,664
)
General and administrative expenses
98,817

 
102,521

 
(3,704
)
Depreciation and amortization expense
216,736

 
210,210

 
6,526

Total costs and expenses
1,397,573

 
1,693,336

 
(295,763
)
 
 
 
 
 
 
Operating income
359,109

 
390,704

 
(31,595
)
Interest expense, net
(138,350
)
 
(131,868
)
 
(6,482
)
Other (expense) income, net
(58,783
)
 
61,822

 
(120,605
)
Income from continuing operations before income tax expense
161,976

 
320,658

 
(158,682
)
Income tax expense
11,973

 
14,712

 
(2,739
)
Income from continuing operations
150,003

 
305,946

 
(155,943
)
Income from discontinued operations, net of tax

 
774

 
(774
)
Net income
$
150,003

 
$
306,720

 
$
(156,717
)
Basic and diluted net income per common unit:
 
 
 
 


Continuing operations
$
1.27

 
$
3.29

 
$
(2.02
)
Discontinued operations

 
0.01

 
(0.01
)
Total
$
1.27

 
$
3.30

 
$
(2.03
)
Basic weighted-average common units outstanding
78,080,484

 
77,886,078

 
194,406


Annual Overview
Net income decreased $156.7 million for the year ended December 31, 2016, compared to the year ended December 31, 2015, primarily due to a $58.7 million impairment charge on the Axeon Term Loan in 2016 and a $56.3 million gain associated with the Linden Acquisition in 2015. In addition, segment operating income decreased $35.3 million, resulting mainly from reductions in operating income for the pipeline and fuels marketing segments.


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Table of Contents

Segment Operating Highlights
(Thousands of Dollars, Except Barrel/Day Information)
 
Year Ended December 31,
 
 
 
2016
 
2015
 
Change
Pipeline:
 
 
 
 
 
Refined products pipelines throughput (barrels/day)
535,946

 
522,146

 
13,800

Crude oil pipelines throughput (barrels/day)
392,181

 
471,632

 
(79,451
)
Total throughput (barrels/day)
928,127

 
993,778

 
(65,651
)
Throughput revenues
$
485,650

 
$
508,522

 
$
(22,872
)
Operating expenses
147,858

 
153,222

 
(5,364
)
Depreciation and amortization expense
89,554

 
84,951

 
4,603

Segment operating income
$
248,238

 
$
270,349

 
$
(22,111
)
 
 
 
 
 
 
Storage:
 
 
 
 
 
Throughput (barrels/day)
789,065

 
899,606

 
(110,541
)
Throughput terminal revenues
$
117,586

 
$
130,127

 
$
(12,541
)
Storage terminal revenues
492,456

 
494,781

 
(2,325
)
Total revenues
610,042

 
624,908

 
(14,866
)
Operating expenses
276,578

 
290,322

 
(13,744
)
Depreciation and amortization expense
118,663

 
116,768

 
1,895

Segment operating income
$
214,801

 
$
217,818

 
$
(3,017
)
 
 
 
 
 
 
Fuels Marketing:
 
 
 
 
 
Product sales and other revenue
$
681,934

 
$
976,216

 
$
(294,282
)
Cost of product sales
645,355

 
922,906

 
(277,551
)
Gross margin
36,579

 
53,310

 
(16,731
)
Operating expenses
33,173

 
39,803

 
(6,630
)
Segment operating income
$
3,406

 
$
13,507

 
$
(10,101
)
 
 
 
 
 
 
Consolidation and Intersegment Eliminations:
 
 
 
 
 
Revenues
$
(20,944
)
 
$
(25,606
)
 
$
4,662

Cost of product sales
(11,702
)
 
(15,332
)
 
3,630

Operating expenses
(9,242
)
 
(10,316
)
 
1,074

Total
$

 
$
42

 
$
(42
)
 
 
 
 
 
 
Consolidated Information:
 
 
 
 
 
Revenues
$
1,756,682

 
$
2,084,040

 
$
(327,358
)
Cost of product sales
633,653

 
907,574

 
(273,921
)
Operating expenses
448,367

 
473,031

 
(24,664
)
Depreciation and amortization expense
208,217

 
201,719

 
6,498

Segment operating income
466,445

 
501,716

 
(35,271
)
General and administrative expenses
98,817

 
102,521

 
(3,704
)
Other depreciation and amortization expense
8,519

 
8,491

 
28

Consolidated operating income
$
359,109

 
$
390,704

 
$
(31,595
)


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Table of Contents

Pipeline
Total revenues decreased $22.9 million and total throughputs decreased 65,651 barrels per day for the year ended December 31, 2016, compared to the year ended December 31, 2015, primarily due to:
a decrease in revenues of $36.3 million and a decrease in throughputs of 81,779 barrels per day on our Eagle Ford System due to reduced production resulting from a sustained low crude oil price environment;
a decrease in revenues of $7.1 million and a decrease in throughputs of 6,586 barrels per day on our Ammonia Pipeline partly due to a shipper’s facility reconfiguration, resulting in fewer barrels available for transportation, and maintenance downtime on a portion of the pipeline; and
a decrease in revenues of $3.9 million and a decrease in throughputs of 1,551 barrels per day on our Ardmore System due to operational issues and a turnaround at our customer’s Ardmore refinery in 2016, as well as increased short-haul deliveries resulting in lower average tariffs.

Those decreases in pipeline revenues and throughputs were partially offset by:
an increase in revenues of $12.1 million and an increase in throughputs of 14,803 barrels per day on our McKee and Three Rivers System pipelines due to higher demand in those markets, increased production at our customer’s McKee refinery and increased volumes on pipelines with higher average tariffs;
an increase in revenues of $9.6 million and an increase in throughputs of 11,441 barrels per day on our East Pipeline, mainly due to the completion of various expansion projects beginning in the fourth quarter of 2015, unfavorable pricing differentials in 2015 in markets served by the East Pipeline and lower throughputs in 2015 due to maintenance downtime on a portion of the pipeline; and
an increase in revenues of $3.4 million and an increase in throughputs of 1,392 barrels per day on our North Pipeline due to increased refinery production shipped via pipeline and increased long-haul deliveries resulting in higher average tariffs.
Operating expenses decreased $5.4 million for the year ended December 31, 2016, compared to the year ended December 31, 2015, primarily due to lower operating expenses of $8.7 million on our Eagle Ford System, consistent with the decrease in throughputs. The decrease in pipeline operating expenses was partially offset by higher maintenance and regulatory expenses of $3.2 million, mainly on our Central West Refined Products Pipelines.
Depreciation and amortization expense increased $4.6 million for the year ended December 31, 2016, compared to the year ended December 31, 2015, mainly due to the completion of pipeline projects.

Storage
Throughput terminal revenues decreased $12.5 million and throughputs decreased 110,541 barrels per day for the year ended December 31, 2016, compared to the year ended December 31, 2015, primarily due to:
a decrease in revenues of $10.9 million and a decrease in throughputs of 82,177 barrels per day at our Corpus Christi North Beach terminal due to (i) a decrease in Eagle Ford Shale crude oil being shipped to Corpus Christi, consistent with the decrease in pipeline throughputs and (ii) the completion of a pipeline expansion project in the first quarter of 2016, in which we transport volumes from North Beach to our customer’s refineries, thus reducing volumes moved over our docks; and
a decrease in revenues of $3.3 million and a decrease in throughputs of 35,497 barrels per day due to turnarounds at the refineries served by our Benicia and Corpus Christi crude oil storage tank facilities, as well as operational issues at a customer’s Corpus Christi refinery in 2016.

The decreases were partially offset by an increase in revenue of $3.0 million and an increase in throughputs of 9,044 barrels per day at our McKee and Three Rivers System terminals due to higher demand in those markets, as well as increased production at our customer’s McKee refinery.

Storage terminal revenues decreased $2.3 million for the year ended December 31, 2016, compared to the year ended December 31, 2015. Revenues from our International Terminals decreased $17.7 million, primarily due to a decrease in revenues at our St. Eustatius terminal of $8.3 million, resulting mainly from lower throughput and related handling fees, as well as a decrease in revenues of $5.9 million at our UK Terminals, mainly due to fluctuations in foreign exchange rates. These decreases were partially offset by an increase of $15.3 million in domestic revenues. Domestic revenues increased $10.1 million from rate escalations and new customer contracts mainly at our Selby, CA, Linden, NJ, Blue Island, IL and Piney Point, MD terminals. In addition, revenues at our St. James, LA terminal increased $3.1 million due to completed terminal expansion projects.

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Table of Contents

Operating expenses decreased $13.7 million for the year ended December 31, 2016, compared to the year ended December 31, 2015, primarily due to:
a decrease of $11.8 million in operating expenses at our International Terminals, mainly at our St. Eustatius terminal facility due to higher property taxes in 2015, and lower employee related costs and reimbursable expenses in 2016;
a decrease of $3.1 million resulting from an insurance settlement for environmental remediation expenses incurred on a previously sold terminal; and
a decrease of $2.0 million resulting from lower wharfage and dockage costs at our Corpus Christi North Beach terminal.

The decreases in storage operating expenses were partially offset by a $3.9 million increase in regulatory and maintenance expenses mainly at our Central West terminal facilities and $1.6 million in cancelled capital project costs.

Fuels Marketing
Segment operating income decreased $10.1 million for the year ended December 31, 2016, compared to the year ended December 31, 2015, primarily due to a decrease in gross margin of $7.9 million and $6.6 million from our fuel oil trading and bunker fuel operations, respectively. The lower gross margins were partially offset by a reduction in operating expenses of $6.6 million mainly from our bunker fuel operations due to lower bad debt expense and decreased product inspection and marine vessel costs.

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 $3.7 million for the year ended December 31, 2016, compared to the year ended December 31, 2015, primarily due to a decrease in employee benefit costs which was partially offset by increased compensation expense associated with our long-term incentive plan.
Interest expense, net increased $6.5 million for the year ended December 31, 2016, compared to the year ended December 31, 2015, primarily due to increased interest costs associated with higher borrowings under our revolving credit agreement, as well as lower capitalized interest resulting from fewer capital projects.
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. For the year ended December 31, 2015, we recorded other income, net of $61.8 million, mainly due to the $56.3 million gain associated with the Linden Acquisition.
Income tax expense decreased $2.7 million for the year ended December 31, 2016, compared to the year ended December 31, 2015, primarily due to lower margin tax in Texas, a decrease in the UK tax rate and a reduction in our St. Eustatius and Canada withholding tax. Please refer to Note 24 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for a discussion on income taxes.


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Table of Contents

TRENDS AND OUTLOOK
As discussed in more detail in Note 28 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data,” we and NuStar GP Holdings entered into the Merger Agreement to simplify our corporate structure. At the closing of the Merger, which is subject to, among other things, approval of the NSH unitholders: (i) NuStar Energy will issue 0.55 of an NS common unit for each outstanding NSH unit; (ii) NSH’s economic rights in the 2% general partner interest, the incentive distribution rights (the IDRs) in NS and the NS common units held by NSH will be cancelled; and (iii) NS will pay off and cancel NSH’s obligations under its revolving credit agreement.

We believe simplifying our corporate structure and eliminating the IDRs will lower our cost of capital and create a more efficient and transparent structure. In addition, management anticipates recommending, and the NuStar Energy board of directors indicated it intends to approve, resetting NuStar Energy’s quarterly distribution from $1.095 per common unit to $0.60 per common unit, effective with the first quarter 2018 distribution. We expect that resetting our distribution will improve our ability to fund cash requirements immediately, and, in the longer-term, will also serve to improve our leverage metrics and reduce our future need to access the capital markets.

Historically, master limited partnerships (MLPs), like NuStar Energy, have typically funded strategic capital expenditures and acquisitions from external sources, primarily through borrowings under revolving credit agreements and issuance of equity and debt securities. In the past few years, the total number of, and aggregate amount raised by, MLP common equity issuances has dropped dramatically, and MLPs with low coverage and high leverage have found it increasingly difficult to issue common equity. Through the combination of the simplification and distribution reset discussed above, we expect to be able to fund a larger proportion of our capital projects with the cash generated by our operations, which should, over time, reduce our need to access capital markets to finance future growth opportunities.

During 2017, our legacy pipeline systems and storage assets, other than our Permian Crude System, faced several unanticipated challenges, on top of the continuing burden of the third year of sustained low crude prices. In September, hurricanes caused damage in the Gulf of Mexico and significant destruction in the Caribbean. Hurricane Harvey’s heavy rainfall caused only minimal damage to our six affected Gulf Coast facilities, but Hurricane Irma passed almost directly over our facility at St. Eustatius, causing a temporary shutdown and inflicting substantial damage. We received hurricane insurance proceeds of $12.5 million in the fourth quarter of 2017 and $87.5 million in January 2018. We expect to recognize a gain in our first quarter 2018 results equal to the amount by which the insurance proceeds received exceed our actual expense incurred during the period, or approximately $85 million. At this time, we expect that costs incurred, over and above our deductible amount, will be covered by the insurance proceeds we have already received. We expect these repairs to continue through next year and into 2020.

Due to that fact that some of our current committed shippers’ contracts on our South Texas Crude System expire in the second half of 2018, as well as our assessment of the current market conditions in the Eagle Ford, our 2018 forecast reflects our expectation that some of those customers will decline to renew their commitments and demand rates lower than previously contracted rates. As a result, we are projecting lower throughput and rates for the South Texas Crude System in the second half of 2018, which we expect to result in lower revenues for that system during 2018 as compared to 2017.

Since we agree with the many energy experts who currently predict that backwardation, which tends to decrease demand for storage capacity, will continue through 2018, our 2018 forecast reflects lower storage rates and contract renewals at certain of our facilities, which we expect to result in lower revenues for those facilities during 2018 as compared to 2017.

In January 2018, as a result of the widely reported economic strife in Venezuela and the mounting financial and operational challenges facing our St. Eustatius anchor tenant, Petróleos de Venezuela, S.A. (PDVSA), we reduced our expectations for their utilization of the terminal during 2018 to reflect a more conservative outlook. In 2017 and this year so far, news outlets around the world have reported the dramatic deterioration of economic conditions in Venezuela, and during 2017, we saw PDVSA’s activity at the terminal decrease to levels well below their historical levels. In addition, in August 2017, the United States imposed sanctions against Venezuela intended to limit PDVSA’s access to credit, and the Trump Administration has announced it may also ban imports of Venezuelan crude into the U.S. and export of U.S. refined products to Venezuela. If implemented, these additional sanctions, together with the current sanctions, could have a significant negative impact on Venezuela and on PDVSA.

Largely due to the impact we believe those negative factors may have on PDVSA and their utilization of our facility, our current forecast reflects our expectation that our 2018 results of operations of our storage segment will be lower than 2017 and that it properly reflects our conservative assessment of significant uncertainty and risk surrounding PDVSA’s ability to perform this year. That being said, since early January PDVSA’s activity at the terminal has increased, and, if they are able to continue this trend through all or a portion of the year, all other factors remaining constant, we could see improvement in our revenue generated for St. Eustatius, in comparison with our current forecast for 2018, as the year progresses. While we are hopeful that

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PDVSA will maintain its current activity and we continue to work to retain them as an important customer, we also continue to closely monitor PDVSA’s activity and financial well-being and are working to diversify our St. Eustatius facility customer base.

While our outlook for 2018 reflects all the challenges we have described, we believe that the consummation of the Merger and our board of director’s approval of our recommended reset to our distribution will immediately increase our cash available to pay for capital expenditures, and, over time, will improve our leverage metrics. We expect these steps to strengthen our balance sheet in 2018 and beyond. We also project that the Permian Crude System will continue to grow, and we expect its positive contributions to our pipeline segment’s overall results to grow accordingly.

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.









































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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 general partner each quarter, and 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. After the Merger, our general partner will no longer receive incentive distributions or quarterly cash distributions, related to its ownership interest, from us. Additionally, on February 8, 2018, we announced that our management anticipates recommending to the board of directors of NuStar GP, LLC, and the board of directors expects to adopt, a reset of our quarterly distribution per common unit to $0.60 ($2.40 on an annualized basis), starting with the first-quarter distribution payable in May 2018. Please refer to Note 28 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for further discussion of 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 under our shelf registration statements. 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 the year ended December 31, 2017, our cash flow from operations did not exceed our distributions to our partners and our reliability capital expenditures. See below for discussion. For 2018, we expect to generate sufficient cash from operations to exceed our distribution and reliability capital requirements. Although we expect higher interest costs due to our issuances of debt and equity securities in 2017, we expect a decrease in distributions as a result of the distribution reset and the Merger discussed above. See below for additional discussion of our 2017 equity and debt issuances.

Cash Flows for the Years Ended December 31, 2017, 2016 and 2015
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,
 
2017
 
2016
 
2015
 
(Thousands of Dollars)
Net cash provided by (used in):
 
 
 
 
 
Operating activities
$
406,799

 
$
436,761

 
$
524,937

Investing activities
(1,696,441
)
 
(311,078
)
 
(452,029
)
Financing activities
1,276,272

 
(211,324
)
 
(29,229
)
Effect of foreign exchange rate changes on cash
1,720

 
2,721

 
(12,729
)
Net (decrease) increase in cash and cash equivalents
$
(11,650
)
 
$
(82,920
)
 
$
30,950

Net cash provided by operating activities for the year ended December 31, 2017 was $406.8 million, compared to