0001110805-20-000024.txt : 20200227 0001110805-20-000024.hdr.sgml : 20200227 20200227154644 ACCESSION NUMBER: 0001110805-20-000024 CONFORMED SUBMISSION TYPE: 10-K PUBLIC DOCUMENT COUNT: 200 CONFORMED PERIOD OF REPORT: 20191231 FILED AS OF DATE: 20200227 DATE AS OF CHANGE: 20200227 FILER: COMPANY DATA: COMPANY CONFORMED NAME: NuStar Energy L.P. CENTRAL INDEX KEY: 0001110805 STANDARD INDUSTRIAL CLASSIFICATION: PIPE LINES (NO NATURAL GAS) [4610] IRS NUMBER: 742956831 STATE OF INCORPORATION: DE FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K SEC ACT: 1934 Act SEC FILE NUMBER: 001-16417 FILM NUMBER: 20661723 BUSINESS ADDRESS: STREET 1: 19003 IH-10 WEST CITY: SAN ANTONIO STATE: TX ZIP: 78257 BUSINESS PHONE: (210) 918-2000 MAIL ADDRESS: STREET 1: 19003 IH-10 WEST CITY: SAN ANTONIO STATE: TX ZIP: 78257 FORMER COMPANY: FORMER CONFORMED NAME: VALERO L P DATE OF NAME CHANGE: 20020110 FORMER COMPANY: FORMER CONFORMED NAME: SHAMROCK LOGISTICS LP DATE OF NAME CHANGE: 20000331 10-K 1 ns201910-k.htm 10-K Document
false--12-31FY201900011108053748000The Partnership may redeem all or any portion of the Series D Preferred Units, in an amount not less than $50.0 million for cash at a redemption price equal to, as applicable: (i) $31.73 per Series D Preferred Unit at any time on or after June 29, 2023 but prior to June 29, 2024; (ii) $30.46 per Series D Preferred Unit at any time on or after June 29, 2024 but prior to June 29, 2025; (iii) $29.19 per Series D Preferred Unit at any time on or after June 29, 2025; plus, in each case, the sum of any unpaid distributions on the applicable Series D Preferred Unit plus the distributions prorated for the number of days elapsed (not to exceed 90) in the period of redemption (Series D Partial Period Distributions). The holders have the option to convert the units prior to such redemption as discussed above. Additionally, at any time on or after June 29, 2028, each holder of Series D Preferred Units will have the right to require the Partnership to redeem all of the Series D Preferred Units held by such holder at a redemption price equal to $29.19 per Series D Preferred Unit plus any unpaid Series D distributions plus the Series D Partial Period Distributions. If a holder of Series D Preferred Units exercises its redemption right, the Partnership may elect to pay up to 50% of such amount in common units (which shall be valued at 93% of a volume-weighted average trading price of the common units); provided, that the common units to be issued do not, in the aggregate, exceed 15% of NuStar Energy’s common equity market capitalization at the time.81100000$31.73 per Series D Preferred Unit plus any unpaid Series D distributions plus the Series D Partial Period Distributions$30.46 per Series D Preferred Unit plus any unpaid Series D distributions plus the Series D Partial Period Distributions $29.19 per Series D Preferred Unit plus any unpaid Series D distributions plus the Series D Partial Period Distributions 2000000.3137500000At any time on or after June 29, 2020, each holder of Series D Preferred Units may convert all or any portion of its Series D Preferred Units into common units on a one-for-one basis (plus any unpaid Series D distributions), subject to anti-dilution adjustments, at any time, but not more than once per quarter, so long as any conversion is for at least $50.0 million based on the Series D Preferred Unit Purchase Price (or such lesser amount representing all of a holder’s Series D Preferred Units). If we undergo a change of control, as defined in the supplemental indentures for the 6.75% senior notes, the 6.0% senior notes or the 5.625% senior notes, each holder of the 6.75% senior notes, the 6.0% senior notes or the 5.625% senior notes may require us to repurchase all or a portion of its notes at a price equal to 101% of the principal amount of the notes repurchased, plus any accrued and unpaid interest to the date of repurchase.If we undergo a change of control, as defined in the supplemental indentures for the 6.75% senior notes, the 6.0% senior notes or the 5.625% senior notes, each holder of the 6.75% senior notes, the 6.0% senior notes or the 5.625% senior notes may require us to repurchase all or a portion of its notes at a price equal to 101% of the principal amount of the notes repurchased, plus any accrued and unpaid interest to the date of repurchase.If we undergo a change of control, as defined in the supplemental indentures for the 6.75% senior notes, the 6.0% senior notes or the 5.625% senior notes, each holder of the 6.75% senior notes, the 6.0% senior notes or the 5.625% senior notes may require us to repurchase all or a portion of its notes at a price equal to 101% of the principal amount of the notes repurchased, plus any accrued and unpaid interest to the date of repurchase.2500000004.382.8952.400.214500000051000000510000007042310003016220000.230.180.123.530.073.340.060.110.150.400.600.410.970.030.040.380.572.850.010.040.002.90P5Y1072251561085278060.641.150.153.490.312.772.910.100.110.402.3018400094000140000.137525.0025.0025.00We may redeem any of our outstanding Series A, B and C Preferred Units at any time on or after the optional redemption date set forth above for each series of the Series A, B and C Preferred Units, in whole or in part, at a redemption price of $25.00 per unit plus an amount equal to all accumulated and unpaid distributions to, but not including, the date of redemption, whether or not declared. We may also redeem the Series A, B and C Preferred Units upon the occurrence of certain rating events or a change of control as defined in our partnership agreement. In the case of the latter instance, if we choose not to redeem the Series A, B and C Preferred Units, the preferred unitholders may have the ability to convert their Series A, B and C Preferred Units to common units at the then applicable conversion rate. Holders of the Series A, B and C Preferred Units have no voting rights except for certain exceptions set forth in our partnership agreement.We may redeem any of our outstanding Series A, B and C Preferred Units at any time on or after the optional redemption date set forth above for each series of the Series A, B and C Preferred Units, in whole or in part, at a redemption price of $25.00 per unit plus an amount equal to all accumulated and unpaid distributions to, but not including, the date of redemption, whether or not declared. We may also redeem the Series A, B and C Preferred Units upon the occurrence of certain rating events or a change of control as defined in our partnership agreement. In the case of the latter instance, if we choose not to redeem the Series A, B and C Preferred Units, the preferred unitholders may have the ability to convert their Series A, B and C Preferred Units to common units at the then applicable conversion rate. Holders of the Series A, B and C Preferred Units have no voting rights except for certain exceptions set forth in our partnership agreement.9060000154000006900000906000015400000690000000P1YP1YP1YP1YP1Y25.381The Series D Preferred Units include redemption provisions at the option of the holders of the Series D Preferred Units and upon a Series D Change of Control (as defined in the partnership agreement), which are outside the Partnership’s control. Therefore, the Series D Preferred Units are presented in the mezzanine section of the consolidated balance sheets. The Series D Preferred Units have been recorded at their issuance date fair value, net of issuance costs. We reassess the presentation of the Series D Preferred Units in our consolidated balance sheets on a quarterly basis. The Series D Preferred Units are subject to accretion from their carrying value at the issuance date to the redemption value, which is based on the redemption right of the Series D Preferred Unit holders that may be exercised at any time on or after June 29, 2028, using the effective interest method over a period of ten years. 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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark One)
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2019
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
nustarlogoa02.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
San Antonio, Texas
(Address of principal executive offices)
78257
(Zip Code)
Registrant’s telephone number, including area code (210) 918-2000
Securities registered pursuant to Section 12(b) of the Act:
Title of each class
 
Trading Symbol(s)
 
Name of each exchange on which registered
Common units
 
NS
 
New York Stock Exchange
Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units
 
NSprA
 
New York Stock Exchange
Series B Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units
 
NSprB
 
New York Stock Exchange
Series C Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units
 
NSprC
 
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 þ No o
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o No þ
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 þ No o
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes þ No o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act: 
Large accelerated filer
 
þ
  
Accelerated filer
 
 
 
 
 
Non-accelerated filer
 
  
Smaller reporting company
 
 
 
 
 
 
 
 
 
 
 
 
Emerging growth company
 
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes No þ
The aggregate market value of the common units held by non-affiliates was approximately $2.7 billion based on the last sales price quoted as of June 28, 2019, the last business day of the registrant’s most recently completed second quarter.
The number of common units outstanding as of January 31, 2020 was 108,527,939.
DOCUMENTS INCORPORATED BY REFERENCE:
Portions of the Proxy Statement for the registrant’s 2020 annual meeting of unitholders, expected to be filed within 120 days after the end of the fiscal year covered by this Form 10-K, are incorporated by reference into Part III to the extent described therein.



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.
 
 



2


PART I

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

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

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

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

OVERVIEW
NuStar Energy L.P. (NuStar Energy), a Delaware limited partnership, was formed in 1999 and completed its initial public offering of common units on April 16, 2001. Our common units trade on the New York Stock Exchange (NYSE) under the symbol “NS,” and our fixed-to-floating rate cumulative redeemable perpetual preferred units trade on the NYSE under the symbol “NSprA” for our 8.50% Series A Preferred Units, “NSprB” for our 7.625% Series B Preferred Units and “NSprC” for our 9.00% Series C Preferred Units. Our principal executive offices are located at 19003 IH-10 West, San Antonio, Texas 78257, and our telephone number is (210) 918-2000.
We are engaged in the transportation of petroleum products and anhydrous ammonia, and the terminalling, storage and marketing of petroleum products. The term “throughput” as used in this document generally refers to barrels of crude oil or refined product or tons of ammonia, as applicable, that pass through our pipelines, terminals or storage tanks.
We divide our operations into the following three reportable business segments: pipeline, storage and fuels marketing. As of December 31, 2019, our assets included 9,960 miles of pipeline and 74 terminal and storage facilities, which provide approximately 74 million barrels of storage capacity. The following table summarizes operating income for each of our business segments:
 
Year Ended
December 31, 2019
 
(Thousands of Dollars)
Pipeline
$
332,480

Storage
$
154,105

Fuels marketing
$
20,578

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.

3


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

Our internet website address is http://www.nustarenergy.com. Information contained on our website is not part of this report. Our annual reports on Form 10-K, quarterly reports on Form 10-Q and current reports on Form 8-K, and any amendments thereto, 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.


4


RECENT DEVELOPMENTS

In 2019, we continued to execute on the comprehensive plan that we began in 2018, which included simplifying our corporate structure and eliminating the incentive distribution rights, reducing our leverage metrics and improving our distribution coverage ratio. Those actions, combined with our sale of the European operations in the fourth quarter of 2018 and the St. Eustatius operations in the third quarter of 2019, reduced our need to access the equity markets to finance future growth opportunities. During 2019, we continued to enhance our position by accomplishing our three core operational goals for 2019: executing our capital projects; exercising financial discipline; and maintaining safe, reliable operations. We believe we have enhanced our financial flexibility to allow for strong, stable growth. Furthermore, since we completed several major pipeline projects in 2019, we expect significantly lower capital expenditures in 2020.

Completed Projects. In the third quarter of 2019, we completed construction of a 30-inch crude oil pipeline from Taft, Texas to our Corpus Christi North Beach terminal to transport volumes from the Permian Basin to Corpus Christi, Texas for export. We also completed an expansion project on our Valley Pipeline System, which originates in Corpus Christi and runs south to the Rio Grande Valley, and reactivated our refined products pipeline in South Texas to transport diesel to our Nuevo Laredo terminal in Mexico.

Sale of St. Eustatius Operations and Impairments. On July 29, 2019, we sold our St. Eustatius terminal and bunkering operations (the St. Eustatius Operations) for net proceeds of approximately $230.0 million (the St. Eustatius Disposition). The St. Eustatius Disposition included a 14.3 million barrel storage and terminalling facility and related assets on the island of St. Eustatius in the Caribbean Netherlands. We previously reported the terminal operations in our storage segment and the bunkering operations in our fuels marketing segment. We sold these non-core assets, which were not synergistic with our other operations, as part of our plan to significantly improve our debt metrics and partially fund capital projects to grow our core business. We also recorded long-lived asset and goodwill impairment charges totaling $336.8 million related to the St. Eustatius Operations. The impairment charges are recorded in discontinued operations. Please refer to Note 5 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for further discussion of the sale and impairment charges.

Issuance of Debt. On May 22, 2019, NuStar Logistics issued $500.0 million of 6.0% senior notes due June 1, 2026. We received net proceeds of $491.6 million, which we used to repay outstanding borrowings under our revolving credit agreement. Please refer to Note 14 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for further information.



5


ORGANIZATIONAL STRUCTURE
AS OF DECEMBER 31, 2019

orgchartfinal.jpg

6


SEGMENTS
Detailed financial information about our segments is included in the Results of Operations section of Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and Note 26 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data.” The following map depicts our assets at December 31, 2019:
a10kmap2a01.jpg

PIPELINE
Our pipeline operations consist of the transportation of refined products, crude oil and anhydrous ammonia. As of December 31, 2019, we owned and operated:
refined product pipelines with an aggregate length of 3,205 miles and crude oil pipelines with an aggregate length of 2,155 miles in Texas, Oklahoma, Kansas, Colorado and New Mexico (collectively, the Central West System);
a 2,150-mile refined product pipeline originating in southern Kansas and terminating at Jamestown, North Dakota, with a western extension to North Platte, Nebraska and an eastern extension into Iowa (the East Pipeline);
a 450-mile refined product pipeline originating at Marathon Petroleum Corporation’s (Marathon) Mandan, North Dakota refinery and terminating in Minneapolis, Minnesota (the North Pipeline); and
a 2,000-mile anhydrous ammonia pipeline originating from the Louisiana delta area and then running north through the Midwestern United States to Missouri before forking east and west to terminate in Indiana and Nebraska (the Ammonia Pipeline).

7


The following table lists information about our pipeline assets as of December 31, 2019:
 
 
 
 
 
Throughput
For the year ended December 31,
Region / Pipeline System
Length
 
Tank Capacity
 
2019
 
2018
 
(Miles)
 
(Barrels)
 
(Barrels/Day)
Central West System:
 
 
 
 
 
 
 
McKee Refined Product System
2,276

 

 
170,433

 
193,396

Three Rivers System
373

 

 
91,765

 
81,174

Valley Pipeline System
271

 
 
 
46,821

 
42,530

Other
285

 

 
8,834

 
8,600

Central West Refined Products Pipelines
3,205

 

 
317,853

 
325,700

Corpus Christi Crude Pipeline System
538

 
2,157,000

 
414,189

 
215,227

McKee Crude System
598

 
1,039,000

 
142,263

 
154,718

Ardmore System
119

 
824,000

 
88,665

 
70,967

Permian Crude System
900

 
1,178,000

 
553,696

 
435,743

Central West Crude Oil Pipelines
2,155

 
5,198,000

 
1,198,813

 
876,655

Total Central West System
5,360

 
5,198,000

 
1,516,666

 
1,202,355

 
 
 
 
 
 
 
 
Central East System:
 
 
 
 
 
 
 
East Pipeline
2,150

 
5,897,000

 
161,323

 
150,635

North Pipeline
450

 
1,494,000

 
50,290

 
50,180

Ammonia Pipeline
2,000

 

 
28,066

 
30,529

Total Central East System
4,600

 
7,391,000

 
239,679

 
231,344

 
 
 
 
 
 
 
 
Total
9,960

 
12,589,000

 
1,756,345

 
1,433,699

Description of Pipelines
Central West System. The Central West System covers a total of 5,360 miles, including refined product and crude oil pipelines. The refined product pipelines have an aggregate length of 3,205 miles (Central West Refined Products Pipelines) and transport gasoline, distillates (including diesel and jet fuel), natural gas liquids and other products produced at the refineries to which they are connected, including Valero Energy Corporation’s (Valero Energy) McKee and Three Rivers refineries.
The crude oil pipelines have an aggregate length of 2,155 miles (Central West Crude Oil Pipelines) and 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 Permian Basin and Eagle Ford Shale regions to our North Beach marine export terminal or to third-party refineries in Corpus Christi, Texas. In the third quarter of 2019, we completed construction of a 30-inch crude oil pipeline from Taft, Texas to our Corpus Christi North Beach terminal to transport volumes from the Permian Basin to Corpus Christi, Texas for export. We refer to our legacy pipelines that transport crude oil from the Eagle Ford and Permian Basin regions to Corpus Christi, together with our new 30-inch pipeline, as the Corpus Christi Crude Pipeline System.
Our Permian Crude System consists of crude oil transportation, pipeline connection and storage assets located in the Midland Basin of West Texas. The Permian Crude System is an interconnected system that aggregates receipts from wellhead connection lines into intra-basin trunk lines for delivery to regional hubs and to connections with third-party mainline takeaway pipelines. The system consists of 900 miles of pipelines and covers over 500,000 dedicated acres owned by producers, with approximately 275 receipt points. The Permian Crude System also includes two terminals in Texas, at Big Spring and Colorado City, as well as several truck stations and other operational storage facilities, with an aggregate storage capacity of approximately 1.2 million barrels.





8


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

The East Pipeline covers 2,150 miles and transports refined products and natural gas liquids north via pipelines to our terminals and third-party terminals along the system and to receiving pipeline connections in Kansas. Shippers on the East Pipeline obtain refined products from refineries in Kansas, Oklahoma and Texas. The East Pipeline includes 18 truck-loading terminals, with storage capacity of approximately 4.5 million barrels and two tank farms with storage capacity of approximately 1.4 million barrels at McPherson and El Dorado, Kansas.

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

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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 commodity prices. Although periods of drought suppress agricultural demand for some refined products, particularly those used for fueling farm equipment, the demand for fuel to power 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 connected directly to Valero Energy refineries and are subject to long-term throughput agreements with Valero Energy. If operations at one of these refineries were discontinued or significantly reduced, it could have a material adverse effect on our operations, although we would endeavor to minimize the impact by seeking alternative customers for those pipelines.
The North Pipeline is heavily dependent on Marathon’s Mandan, North Dakota refinery, which primarily runs North Dakota crude oil (although it has the ability to process other crude oils), and an interruption in operations at the Marathon refinery could have a material adverse effect on our operations. The majority of the refined products transported through the East Pipeline are produced at three refineries located at McPherson and El Dorado, Kansas and Ponca City, Oklahoma, which are operated by CHS Inc., HollyFrontier Corporation and Phillips 66, respectively. The East Pipeline also has access to Gulf Coast supplies of products through third-party connecting pipelines that receive products originating from Gulf Coast refineries.
Other than the Valero Energy refineries and the Marathon refinery described above, if operations at any one refinery were discontinued, we believe (assuming stable demand for refined products in markets served by the refined product pipelines) that the effects thereof would be short-term in nature, and our business would not be materially adversely affected over the long-term because such discontinued production could be replaced by other refineries or other sources.
Our crude oil pipelines are dependent on our customers’ continued access to sufficient crude oil and sufficient demand for refined products for our customers to operate their refineries. The supply of crude oil production (domestic and foreign) could fluctuate with the price of crude oil. Changes in crude oil prices could also affect the exploration and production of shale plays, which could affect demand for crude oil pipelines serving those regions, such as our Corpus Christi Crude Pipeline System and Permian Crude System. However, certain of our crude oil pipelines, including the McKee System, are the primary source of crude oil for our customers’ refineries. Therefore, these “demand-pull” pipelines are less affected by changes in crude oil prices.
Demand for and Sources of Anhydrous Ammonia
The Ammonia Pipeline currently is the only major pipeline in the United States transporting anhydrous ammonia into the nation’s corn belt. The pipeline is connected to domestic production facilities and also has the capability to receive products from outside the United States directly into the system.
Throughputs on our Ammonia Pipeline depend on overall demand for nitrogen fertilizer use, the price of natural gas, which is the primary component of anhydrous ammonia, and the level of demand for direct application of anhydrous ammonia as a fertilizer for crop production (Direct Application). Demand for Direct Application is dependent on the weather, as Direct Application is not effective if the ground is too wet or too dry.
Corn producers have fertilizer alternatives to anhydrous ammonia, such as liquid or dry nitrogen fertilizers. Liquid and dry nitrogen fertilizers are both less sensitive to weather conditions during application but are generally more costly than anhydrous ammonia. In addition, anhydrous ammonia has the highest nitrogen content of any nitrogen-derivative fertilizer.
Customers
Valero Energy, the largest customer of our pipeline segment, accounted for approximately 28% of the total segment revenues for the year ended December 31, 2019. In addition to Valero Energy, our customers include integrated oil companies, refining companies and others. No other customer accounted for more than 10% of the total revenues of the pipeline segment for the year ended December 31, 2019.

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Competition and Other Business Considerations
Because pipelines are generally the lowest-cost method for intermediate and long-haul movement of crude oil and refined products, our more significant competitors are common carrier and proprietary pipelines owned and operated by major integrated and large independent oil companies and other pipeline companies in our service areas. Competition between common carrier pipelines is based primarily on transportation charges, quality of customer service and proximity to end users. Trucks may deliver products competitively for short-hauls; however, trucking costs render that mode of transportation uncompetitive with pipeline options 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 and/or refineries that are affected by domestic shale oil production in the Eagle Ford, Permian Basin and Granite Wash regions. Our pipelines also face competition from other crude oil pipelines and truck transportation in these regions. However, some of that exposure is mitigated through our long-term contracts and minimum volume commitments with creditworthy customers.
The East and North Pipelines compete with an independent common carrier pipeline system owned by Magellan Midstream Partners, L.P. (Magellan) that operates approximately 100 miles east of and parallel to the East Pipeline and in close proximity to the North Pipeline. Certain of the East Pipeline’s and the North Pipeline’s delivery terminals are in direct competition with Magellan’s terminals. Competition with Magellan is based primarily on transportation charges, quality of customer service and proximity to end users.
Competitors of the Ammonia Pipeline include midwest production facilities, nitrogen fertilizer substitutes and barge and railroad transportation 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, 2019, we owned and operated 40 terminal and storage facilities in the United States, one terminal in Nuevo Laredo, Mexico and one terminal located in Point Tupper, Canada with an aggregate storage capacity of 61.3 million barrels. The following table sets forth information about our terminal and storage facilities as of December 31, 2019:
Facility
Tank Capacity
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)
3,539,000

Edinburg, TX
346,000

El Paso, TX (a)
419,000

Harlingen, TX
286,000

Laredo, TX
215,000

San Antonio, TX (b)
377,000

Southlake, TX
569,000

Nuevo Laredo, Mexico
35,000

Central West Terminals
7,919,000

 
 
 
 
 
 

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Facility
Tank Capacity
Jacksonville, FL
2,593,000

St. James, LA
9,917,000

Houston, TX
86,000

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

Gulf Coast Terminals
15,560,000

 
 
Blue Island, IL
690,000

Andrews AFB, MD (c)
75,000

Baltimore, MD
813,000

Piney Point, MD
5,402,000

Linden, NJ (b)
5,134,000

Paulsboro, NJ
74,000

Virginia Beach, VA (c)
41,000

North East Terminals
12,229,000

 
 
Los Angeles, CA
608,000

Pittsburg, CA
398,000

Selby, CA
2,671,000

Stockton, CA
816,000

Portland, OR
1,345,000

Tacoma, WA
391,000

Vancouver, WA (b)
774,000

West Coast Terminals
7,003,000

 
 
Benicia, CA
3,683,000

Corpus Christi, TX
4,030,000

Texas City, TX
3,141,000

Refinery Storage Tanks
10,854,000

 
 
Point Tupper, Canada
7,778,000

 
 
Total
61,343,000

 
(a)
We own a 67% undivided interest in the El Paso refined product terminal. The tank capacity represents the proportionate share of capacity attributable to our ownership interest.
(b)
Location includes two terminal facilities.
(c)
Terminal facility also includes pipelines to U.S. government military base locations.
Description of Major Terminal Facilities
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, Texas and Benicia, California. We lease our refinery storage tanks to Valero Energy in exchange for a fixed fee.
St. James, Louisiana. Our St. James terminal, which is located on the Mississippi River near St. James, Louisiana, has a total storage capacity of 9.9 million barrels. The facility is located on almost 900 acres of land, some of which is undeveloped. The majority of the storage tanks and infrastructure are suited for light crude oil, with certain of the tanks capable of fuel oil or heated crude oil storage. Additionally, the facility has one barge dock and two ship docks. Our St. James terminal is connected to (i) offshore pipelines in the Gulf of Mexico, (ii) long-haul pipelines that can receive crude oil from the Eagle Ford, Permian Basin and other domestic shale plays, and (iii) pipelines to refineries in the Gulf Coast and Midwest. The St. James terminal

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also has two unit train rail facilities that are served by the Union Pacific Railroad. Each facility has the capacity to simultaneously off-load 120 railcars, at a minimum, in a 24-hour period.
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 ice-free marine terminal on the North American Atlantic coast, with access to the East Coast, Canada and the Midwestern United States markets 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 ultra large crude carriers (ULCCs) for loading and discharging crude oil, petroleum products and petrochemicals. Crude oil and petroleum product movements at the terminal are fully automated. Separate fees apply for use of the jetty facility, as well as associated services, including pilotage, tug assistance, line handling, launch service, emergency response services and other ship services (all of which are considered optional services).
Linden, New Jersey. Our Linden terminal facility includes two terminals that provide deep-water terminalling capabilities in the New York Harbor and primarily stores petroleum products, including gasoline, jet fuel and fuel oils. The two terminals have a total storage capacity of 5.1 million barrels and can receive and deliver products via ship, barge and pipeline. The terminal facility also has two docks.

Corpus Christi North Beach. We own and operate a 3.5 million barrel crude oil storage and terminalling facility located at the Port of Corpus Christi in Texas. The facility supports our pipelines that transport crude oil from the Eagle Ford and Permian Basin regions to Corpus Christi and is also connected to a third-party pipeline systems, providing our customers with the flexibility to segregate and deliver crude oil and processed condensate. This facility has access to four docks, including one dock for which we have exclusive-use that is able to accommodate Aframax-class vessels and two private docks. We can load crude oil onto ships simultaneously on all four docks. The completion of the 30-inch crude oil pipeline from Taft, Texas to our Corpus Christi North Beach terminal in 2019 provides our customers the ability to transport volumes from the Permian Basin to Corpus Christi, Texas for export.

We refer to our pipelines that transport crude oil from the Eagle Ford and Permian Basin regions to Corpus Christi, including our new 30-inch pipeline, together with our Corpus Christi North Beach terminal, as the Corpus Christi Crude System.

Storage Operations
We generate storage segment revenues through fees for tank storage agreements, under which 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, under which a customer pays a fee per barrel for volumes moved through our terminals (throughput terminal revenues). Our terminals also provide blending, additive injections, handling and filtering services for which we charge additional fees. We lease our Refinery Storage Tanks to Valero Energy in exchange for a fixed fee. Certain of our facilities charge fees to provide marine services, such as pilotage, tug assistance, line handling, launch service, emergency response services and other ship services.
Demand for Refined Products and Crude Oil
The operations of our refined product terminals depend in large part on the level of demand for products stored in our terminals in the markets served by those assets. Demand for our terminalling services will generally increase or decrease with demand for refined products, and demand for refined products tends to increase or decrease with the relative strength of the economy. In addition, the forward pricing curve can have an impact on demand. For example, in a contango market (when the price of a commodity is expected to exceed current prices), demand for storage services will generally increase.
Crude oil delivered to our St. James and Corpus Christi North Beach terminals will generally increase or decrease with crude oil production rates in the Bakken, Permian and Eagle Ford shale plays. In addition, the market price relationship between various grades of crude oil impacts the demand for our unit train facilities at our St. James terminal.
The dramatic increase in North American shale play production has increased exports of crude oil from U.S. ports, including our Corpus Christi North Beach facility, to destinations as close as the U.S. East Coast, to as far away as Europe and Asia.
Customers
We provide storage and terminalling services for crude oil and refined products to many of the world’s largest producers of crude oil, integrated oil companies, chemical companies, oil traders and refiners. In addition, our blending capabilities in our storage assets have attracted customers who have leased capacity primarily for blending purposes. Valero Energy, the largest customer of our storage segment, accounted for approximately 25% of the total revenues of the segment for the year ended December 31, 2019. No other customer accounted for a significant portion of the total revenues of the storage segment for the year ended December 31, 2019.

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Competition and Other Business Considerations
Many major energy and chemical companies own extensive terminal storage facilities. Although such terminals often have the same capabilities as terminals owned by independent operators, they generally do not provide terminalling services to third parties. In many instances, major energy and chemical companies that own storage and terminalling facilities are also significant customers of independent terminal operators. Such companies typically have strong demand for terminals owned by independent operators when independent terminals have more cost-effective locations near key transportation links, such as deep-water ports. Major energy and chemical companies also need independent terminal storage when their owned storage facilities are inadequate, either because of size constraints, the nature of the stored material or specialized handling requirements.
Independent terminal owners generally compete on the basis of the location and versatility of terminals, service and price. A favorably located terminal will have access to various cost-effective transportation modes both to and from the terminal. Transportation modes typically include waterways, railroads, roadways and pipelines.
Terminal versatility is a function of the operator’s ability to offer complex handling requirements for diverse products. The services typically provided by the terminal include, among other things, the safe storage of the product at specified temperature, moisture and other conditions, as well as receipt at and delivery from the terminal, all of which must comply with applicable environmental regulations. A terminal operator’s ability to obtain attractive pricing is often dependent on the quality, versatility and reputation of the facilities owned by the operator. Although many products require modest terminal modification, operators with versatile storage capabilities typically require less modification prior to usage, ultimately making the storage cost to the customer more attractive.
Our crude oil refinery storage tanks are physically integrated with and serve refineries owned by Valero Energy, and we have entered into various agreements with Valero Energy governing the use of these tanks. As a result, we believe that we will not face significant competition for our services provided to those refineries.

FUELS MARKETING
The fuels marketing segment includes our bunkering operations in the Gulf Coast, as well as certain of our blending operations associated with our Central East System. 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.

Customers for our bunker fuel sales are mainly ship owners, including cruise line companies, which collectively accounted for approximately 25% of the total revenues of the segment for the year ended December 31, 2019. In the sale of bunker fuel, we compete with ports offering bunker fuels that are along the route of travel of the vessel.

EMPLOYEES

As of December 31, 2019, we had 1,441 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

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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 designed to comply with the laws and regulations, and to help 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 2019, our capital expenditures attributable to compliance with environmental regulations were $11.6 million, and we currently project regulatory compliance spending of approximately $5.6 million in 2020. However, future governmental actions could result in more restrictive laws and regulations, which could increase required capital expenditures and operating expenses. At this time, we are unable to estimate either the impact, if any, of potential future regulation and/or legislation on our financial condition or results of operations, or the amount and timing of such possible future expenditures or expenses. We believe that we are in substantial compliance with the environmental, health, safety and security laws and regulations applicable to our operations, but risk of additional compliance expenditures, expenses and liabilities are inherent to government-regulated industries, including midstream energy. As a result, there can be no assurances that significant expenditures, expenses and liabilities will not be incurred in the future. However, while compliance may affect our capital expenditures and operating expenses, we believe that the cost of such compliance will not have a material impact on our competitive position, financial condition or results of operations. Further, we do not believe that our cost of compliance is proportionately greater than the cost to other companies operating in our industry.

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

OCCUPATIONAL SAFETY AND HEALTH

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

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FUEL STANDARDS AND RENEWABLE ENERGY

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

HAZARDOUS SUBSTANCES & HAZARDOUS WASTE

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

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

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.

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.



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PIPELINE AND OTHER ASSET INTEGRITY, SAFETY AND SECURITY

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

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



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RISK FACTORS

RISKS RELATED TO OUR BUSINESS

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

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

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

It is possible that one or more of the factors listed above may 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. 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; in other words, we may be able to make cash distributions during periods in which we record net losses and may not be able to make cash distributions during periods in which we record net income.

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

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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 that result in decreased 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
macroeconomic forces affecting, or actions taken by, oil and gas producing nations that impact supply of and prices for crude oil and refined products.

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

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, uncertainty in the market and negative sentiment toward energy-related companies generally, or master limited partnerships specifically. 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.

As of December 31, 2019, we had $3.4 billion of consolidated debt, of which $1.5 billion (including our revolving credit facility) matures within the next five years. Due to these factors, we cannot be certain that we will be able to refinance our maturing debt or 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.

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, 2019, our consolidated debt was $3.4 billion, and we have the ability to incur more debt. In addition to any potential direct financial impact of our debt, it is possible that any material increase to our debt or other adverse financial

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factors may be viewed negatively by credit rating agencies, which could result in ratings downgrades, increased costs for us to access the capital markets and an increase in interest rates on amounts borrowed under our revolving credit agreement.

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 limits us to 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 and requires us to maintain a minimum consolidated interest coverage ratio (as defined in the revolving credit agreement) of at least 1.75-to-1.00. Failure to comply with any of the revolving credit agreement restrictive covenants or the maximum consolidated debt coverage ratio or minimum consolidated interest coverage ratio requirements would constitute an event of default and could result in acceleration of our obligations under the revolving credit agreement and possibly other agreements. The letter of credit agreements supporting our Gulf Opportunity Zone bonds contain comparable covenants and ratios, and future financing agreements we may enter into may contain similar or more restrictive covenants and ratio requirements 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 provides for acceleration of amounts owed upon the occurrence of certain specified events.

Our debt service obligations, restrictive covenants, ratio requirements and maturities 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.

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.

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 and our Series A, B and C preferred units. At December 31, 2019, we had approximately $3.4 billion of consolidated debt, of which $2.1 billion was at fixed interest rates and $1.3 billion was at variable interest rates. Additionally, at December 31, 2019, the aggregate notional amount of our interest rate swap arrangements was $250.0 million, which expire in September 2020 and may expose us to risk of financial loss. In addition, the distribution rates on our Series A, B and C preferred units convert from fixed rates to floating rates, beginning in December 2021, June 2022 and December 2022, respectively. Our results of operations, cash flows and financial position could be materially adversely affected by significant changes in interest rates.

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

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

We may be adversely affected by changes in the method of determining the London Interbank Offering Rate (LIBOR) or the replacement of LIBOR with an alternative reference rate.
As of December 31, 2019, we had approximately $1.3 billion of variable-rate indebtedness, $0.9 billion of which uses LIBOR as a benchmark for establishing the interest rate. In addition, the distribution rates on our Series A, B and C preferred units convert from fixed rates to floating rates based on LIBOR, beginning in December 2021, June 2022 and December 2022, respectively. The U.K. Financial Conduct Authority announced in 2017 that it would no longer compel banks to submit rates for the calculation of LIBOR after 2021, and it is expected that a transition away from the widespread use of LIBOR to

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alternative rates will occur over the next couple of years. The consequences of these developments cannot be entirely predicted but could include an increase in the cost of our variable-rate indebtedness, our Series A, B and C preferred units and other commercial arrangements tied to LIBOR. In addition, we have incurred and expect to incur further expenses during the next couple of years to renegotiate or clarify the rate provisions in certain of our variable-rate arrangements to affect the transition away from LIBOR-based rates and implement replacement indices, as necessary, but may not be able to do so on terms favorable to us. Furthermore, uncertainty regarding the continued use and reliability of LIBOR as a benchmark rate and uncertainty regarding its replacement could disrupt the financial markets or adversely affect the value of our arrangements tied to LIBOR.

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

Failure to complete capital projects as planned could adversely affect our financial condition, results of operations and cash flows.
Delays or cost increases related to capital spending programs involving construction of new facilities (or improvements and repairs to our existing facilities) could adversely affect our ability to achieve forecasted operating results. Although we evaluate and monitor each capital spending project and try to anticipate difficulties that may arise, delays or cost increases 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;
delay or increased costs to obtain right-of-way or other property rights;
delays or failures by third parties to complete related projects;
protests and other activist interference with planned or in-process projects;
unplanned increases in the cost of construction materials or labor;
disruptions in transportation of modular components and/or construction materials;
severe adverse weather conditions, natural disasters or other events (such as hurricanes, equipment malfunctions, explosions, fires or spills) affecting our facilities, or those of vendors and suppliers;
shortages of sufficiently skilled labor, or labor disagreements resulting in unplanned work stoppages; or
market-related increases in a project’s debt or equity financing costs.

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

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


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Any future acquisitions could increase substantially the level of our indebtedness and contingent liabilities or otherwise change our capital structure.
From time to time, we evaluate and acquire assets and businesses that we believe complement or diversify our existing assets and operations. Any future 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.

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

Our operations are subject to operational hazards and interruptions, and we cannot insure against and/or predict all potential losses and liabilities that might result therefrom.
Our operations and those of our customers and suppliers are subject to operational hazards and unforeseen interruptions due to natural disasters, adverse weather conditions (such as hurricanes, tornadoes, storms, floods and earthquakes), accidents, fires, explosions, hazardous materials releases, mechanical failures, cyberattacks, acts of terrorism and other events beyond our control. In addition, findings show global climatic changes are occurring that are likely to increase the number and severity of hurricanes and other damaging weather conditions. These events might result in a loss of life or equipment, injury or extensive property or environmental 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, losses experienced by us and other companies, premiums and deductibles for certain of our insurance policies have increased and could continue to increase substantially; therefore, we may not be able to maintain or obtain insurance of the type and amount we desire at reasonable rates. In addition, certain insurance coverage is subject to broad exclusions, and may become subject to further exclusions, become unavailable altogether or become available only for reduced amounts of coverage and at higher rates. We are not fully insured against all hazards and risks to our business, and the insurance we carry requires us to meet certain deductibles before we collect for any losses we sustain. If we incur a significant liability for which we are uninsured or not fully insured, or if there is a significant delay in payment of a major insurance claim, such a liability could have a material adverse effect on our financial position.

We are exposed to counterparty credit risk. Nonpayment and nonperformance by our customers, vendors or derivative counterparties could reduce our revenues, increase our expenses and otherwise have a negative impact on our ability to conduct our business, operating results, cash flows and ability to make distributions to our unitholders.
Weak economic conditions and widespread financial stress could reduce the liquidity of our customers, vendors or counterparties, making it more difficult for them to meet their obligations to us. We are therefore subject to risks of loss resulting from nonpayment or nonperformance by our customers to whom we extend credit. Financial problems encountered by our customers could limit our ability to collect amounts owed to us, or to enforce the performance of obligations owed to us under contractual arrangements. In addition, nonperformance by vendors or their subcontractors, who have committed to provide us with critical products or services, could result in significant disruptions, raise our costs or interfere with our ability to successfully conduct our business. Furthermore, nonpayment by the counterparties to any of our outstanding derivatives could expose us to additional interest rate or commodity price risk. Although we attempt to mitigate our risk through warehouseman’s liens and other security protections, we may not always be able to enforce such liens and protections due to competing claims from other parties. Any substantial increase in the nonpayment and nonperformance by our customers, vendors or counterparties or our inability to enforce our warehouseman’s liens and other security protections could have a material adverse effect on our results of operations, cash flows and ability to make distributions to our unitholders.


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We could be subject to damages or lose customers due to failure to maintain certain quality specifications or other claims related to the operation of our assets and the services we provide to our customers.
Certain of the products we store and transport are produced to precise customer specifications. If the quality and purity of the products we receive are not maintained and/or a product fails to perform in a manner consistent with the quality specifications required by our customers, customers have sought, and could in the future seek replacement of the product or damages for costs incurred as a result of the product failing to perform as guaranteed. We also have faced, and could in the future 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. Successful claims or a series of claims against us result in unforeseen expenditures and could result in the loss of one or more customers.

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 and increase our costs and could adversely affect our ability to make distributions to our unitholders.
We rely on our information technology systems and our operational technology systems to process, transmit and store information, such as employee, customer and vendor data, and to conduct almost all aspects of our business, including safely operating our pipelines and storage facilities, recording and reporting commercial and financial transactions and receiving and making payments. We also rely on systems hosted by third parties, with respect to which we have limited visibility and control. The security of these networks and systems is critical to our operations and business strategy.

Despite our security measures, we could suffer a serious cybersecurity incident due to attacks from a variety of external threat actors, internal employee error or malfeasance, or even cybersecurity incidents suffered by our service providers or other vendors. In addition, certain cybersecurity incidents, such as surveillance, may remain undetected for an extended period of time. A significant failure, compromise, breach or interruption in our systems could result in a disruption of our operations, damage to our assets or the environment, safety incidents, damage to our reputation, loss of customers or revenues, increased costs for remedial actions and potential litigation or regulatory fines. If any such failure, interruption or similar event results in the loss or improper disclosure of information maintained in our 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 our systems are breached or an employee or vendor causes our systems to fail, either as a result of inadvertent error or by deliberately tampering with or manipulating our systems.

In recent years, there has been a rise in the number of cyberattacks generally, by both state-sponsored and criminal organizations and, as a result, the risks associated with such an event continue to increase. In addition, new laws and regulations governing data privacy and protection pose increasingly complex compliance challenges. Although we believe that we have robust cybersecurity procedures and other safeguards in place, we cannot guarantee their effectiveness, and a significant failure, compromise, breach or interruption in our systems could have a material effect on our operations and those of our customers and vendors. As threats continue to evolve and cybersecurity, data protection laws and regulations continue to develop, we expect to spend additional resources to continue to enhance our cybersecurity, data protection, business continuity and incident response measures and to investigate and remediate any vulnerabilities to or consequences of cyber incidents.

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.

We operate assets outside of the United States, which exposes us to different legal and regulatory requirements and additional risk.
A portion of our revenues are generated from our assets located in Canada and northern Mexico. Our operations in both locations are subject to various risks unique to each country in which we operate that could have a material adverse effect on our business, results of operations and financial condition. With respect to any particular country, these risks may include political and economic instability, including: civil unrest, war and other armed conflict; inflation; and currency fluctuations, devaluation and conversion restrictions. We are also exposed to the risk of foreign and domestic governmental actions that may: impose additional costs on us; limit or disrupt markets for our operations, restrict payments or limit the movement of funds;

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impose sanctions on or otherwise restrict our ability to conduct business with certain customers or persons or in certain countries; or result in the deprivation of contract rights. Our operations outside the United States may also be affected by changes in trade protection laws, policies and measures, and other regulatory requirements affecting trade and investment, including the Foreign Corrupt Practices Act, and other foreign laws prohibiting corrupt payments, as well as import and export regulations.

We also have assets in, or have customers based in, certain developing markets, such as Mexico, and the nature of these markets presents a number of risks. In addition, due to the unsettled political conditions in many oil-producing countries, our operations may be subject to the adverse consequences of war, civil unrest, strikes, currency controls and governmental actions. Deterioration of social, political, labor or economic conditions, including the increasing threat of terrorist organizations and drug cartels, in a country or region in which we do business, or affecting a customer with whom we do business, as well as difficulties in staffing and managing foreign operations, may adversely affect our operations or financial results.

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

We may be unable to obtain or renew permits necessary for our current or proposed operations, which could inhibit our ability to conduct or expand our 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 or expand our operations and on our financial condition, results of operations, cash flows and ability to make distributions to our unitholders.

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

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

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

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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 findings that emissions of certain “greenhouse gases” such as carbon dioxide and methane present a danger to public health and the environment, including contributing to warming of the Earth’s atmosphere, the U.S. Congress, European Union and other political bodies have considered legislation or regulation to reduce emissions of greenhouse gases. To the extent the United States and other political bodies enact climate change regulations that increase costs or reduce demand, it could have an adverse direct or indirect effect on our business.

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

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

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

Our operations are subject to federal, state and local laws and regulations, in the U.S. and in the other countries in which we operate, relating to environmental, health, safety and security that could require us to make substantial expenditures.
Our operations are subject to increasingly stringent international, federal, state and local environmental, health, safety and security laws and regulations. Transporting, storing and distributing hazardous materials, including petroleum products, entails the risk of releasing these products 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, our pipeline facilities are 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 has required, 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, which could have an adverse impact on our ability to recover the full cost of operating our pipelines and the revenue we are able to receive from those operations.
The FERC regulates the tariff rates and terms and conditions of service for interstate oil movements on common carrier pipelines. FERC requires that these rates be just and reasonable and that the pipeline not engage in undue discrimination with respect to any shipper. The FERC or shippers may challenge required 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

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and investigated by the FERC, the FERC may require the pipeline owner to refund amounts collected in excess of the deemed just and reasonable rate. In addition, shippers may challenge by complaint tariff rates and terms and conditions of service even after they take effect, and the FERC may order a carrier to change its rates prospectively to a just and reasonable level. A complaining shipper also may obtain reparations for damages sustained during the two years prior to the date of the 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 negotiated 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, 2016, which will end on June 30, 2021, the index allows for annual changes in rates equal to the change in the Bureau of Labor’s producer price index for finished goods plus 1.23%. It is possible that the index may result in negative rate adjustments in some years, or that changes in the index might not be large enough to fully reflect actual increases in our costs. The FERC’s indexing methodology is subject to review and revision every five years, with the next five-year review commencing in 2020.

In March 2018, the FERC issued a Revised Policy Statement on the Treatment of Income Taxes (Revised Policy) in which the FERC reversed its previous policy and found that an impermissible double recovery results from granting a master limited partnership (MLP) pipeline both an income tax allowance (ITA) and a return on equity in determining cost-of-service rates. Pursuant to the Revised Policy, the FERC now requires liquids pipelines organized as MLPs to eliminate the MLP ITA in their Form No. 6, page 700 reporting. The FERC stated that it would incorporate the effects of the Revised Policy and the Tax Cuts and Jobs Act of 2017 on industry-wide pipeline costs in its 2020 five-year review of the indexing methodology. Depending on the outcome of that five-year review, the Revised Policy and the Tax Cuts and Jobs Act of 2017 may impact revenues received from transportation services provided pursuant to cost-of-service or index based rates in the future.

FERC has granted us authority to charge market-based rates on some of our pipelines, which are not subject to cost-of-service or indexing constraints. If we were to lose market-based rate authority, however, we could be required to establish rates on some other basis, such as cost-of-service, which could reduce our revenues and cash flows. Additionally, because competition constrains our rates in various markets, we may from time to time be forced to reduce some of our rates to remain competitive.

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

Increases in natural gas and power prices could adversely affect our operating expenses and our ability to make distributions to our unitholders.
Power costs constitute a significant portion of our operating expenses. For the year ended December 31, 2019, our power costs equaled approximately $53.0 million, or 13.0% 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.

An impairment of goodwill or long-lived assets could reduce our earnings.
We have recorded $1.0 billion of goodwill and $4.8 billion of long-lived assets, including property, plant and equipment, net and intangible assets, net, as of December 31, 2019. U.S. generally accepted accounting principles requires us to test both goodwill and long-lived assets for impairment when events or circumstances occur indicating that either goodwill or long-lived assets might be impaired and, in the case of goodwill, at least annually. Any event that causes a reduction in demand for our services could result in a reduction of our estimates of future cash flows and growth rates in our business, which could cause us to record an impairment charge to reduce the value of goodwill. Similarly, any event or change in circumstances that causes the carrying value of our long-lived assets to no longer be recoverable may require us to record an impairment charge to reduce the value of our long-lived assets. If we determine that either our goodwill or our long-lived assets are impaired, the resulting charge will reduce earnings and partners’ capital. For example, during 2019, we recorded $305.7 million of long-lived asset impairment charges and $31.1 million of goodwill impairment charges related to our St. Eustatius operations, which we sold in July 2019.

Our purchase and sale of petroleum products may expose us to trading losses and hedging losses, and non-compliance with our risk management policies could result in significant financial losses.
Our marketing and trading of petroleum products exposes us to commodity price volatility risk for the purchase and sale of petroleum products, including distillates and fuel oil. We attempt to mitigate this volatility risk through hedging, which may

26


limit our potential gains or result in potential losses, 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.

RISKS INHERENT IN AN INVESTMENT IN US

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

In addition, to the extent we issue additional units in connection with any acquisitions or growth capital expenditures, the payment of distributions on those additional units may increase the risk that we will be unable to maintain our current per unit distribution level and 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.

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

We may issue additional equity securities, including equity securities that are senior to our common units, which would dilute our unitholders’ existing ownership interests.
Our partnership agreement allows us to issue an unlimited number of additional equity securities without the approval of other unitholders as long as the newly issued equity securities are not senior to, or pari passu with, our preferred units. With the consent of a majority of the Series D Preferred Units, we may issue an unlimited number of units that are senior to our common units and pari passu with our preferred units. However, in certain circumstances, we may be required to obtain the approval of a majority of each class of our preferred units before we could issue equity securities that are pari passu with our preferred units.

Our issuance of additional units or other equity interests of equal or senior rank will have the following effects:
our unitholders’ proportionate ownership interest in us will decrease;
the amount of cash available for distribution on each unit may decrease;
the amount of cash available for redemption of, or payment of the liquidation preference on, each preferred unit may decrease;
the ratio of taxable income to distributions may increase;
the relative voting strength of each previously outstanding unit may be diminished; and
the market price of our common units and preferred units may decline.

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

27


D Preferred Units) in the event of a transaction, including a merger, sale, lease or conveyance of all or substantially all of our assets or business, which might adversely affect the holders of our preferred units.

Future issuances and sales of securities that rank equally with our preferred units, or the perception that such issuances and sales could occur, may cause prevailing market prices for our preferred units and our common units to decline and may adversely affect our ability to raise additional capital in the financial markets at times and prices favorable to us. Furthermore, the payment of distributions on any additional units may increase the risk that we will not be able to make distributions at our prior per unit distribution levels. To the extent new units are senior to our common units, their issuance will increase the uncertainty of the payment of distributions on our common units.

If we do not pay distributions on our preferred units in any distribution period, we would be unable to declare or pay distributions on our common units until all unpaid preferred unit distributions have been paid, and our common unitholders are not entitled to receive distributions for such prior period.
Our preferred units rank senior to our common units with respect to distribution rights and rights upon liquidation. If we do not pay the required distributions on our preferred units, we will be unable to declare or pay distributions on our common units. Additionally, because distributions to our preferred unitholders are cumulative, we will have to pay all unpaid accumulated preferred distributions before we can declare or pay any distributions to our common unitholders. Also, because distributions to our common unitholders are not cumulative, if we do not pay distributions on our common units with respect to any quarter, our common unitholders will not be entitled to receive distributions covering any prior periods. In addition, if we do not pay the required distributions on our Series D Preferred Units for three consecutive distribution periods, the holders of our Series D Preferred Units have certain additional rights until such distributions are paid, including the right to convert the Series D Preferred Units into common units, the right to appoint one director to our board of directors and the right to approve certain indebtedness, acquisitions or asset sales. The preferences and privileges of our preferred units could adversely affect the market price for our common units, or could make it more difficult for us to sell our common units in the future.

Unitholders would not have limited liability if a court were to determine 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, if a court were to determine that actions of a unitholder constituted participation in the “control” of our business, unitholders would be held liable for our obligations to the same extent as a general partner.

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

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

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

The NYSE does not require a publicly traded limited partnership like us to comply with certain of its corporate governance requirements.
We currently list our common units on the NYSE under the symbol “NS” and certain of our preferred units on the NYSE under the symbols “NSprA,” “NSprB” and “NSprC,” respectively. Although our general partner has maintained a majority of independent directors on its board and all members of its board’s audit committee, compensation committee and nominating/

28


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.

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. 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.

If we were treated as a corporation, we would pay federal income tax at the corporate tax rate and would likely pay state and local income tax at varying rates. Distributions to unitholders would generally be taxed again as corporate distributions, 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. Additionally, at the state level, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. If we were treated as a corporation for federal income tax purposes or otherwise subjected to a material amount of entity-level taxation, then our cash available for distribution to unitholders would be substantially reduced and there would be a material reduction in the after-tax return to our unitholders, likely causing a substantial reduction in the value of our units.

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

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

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

A successful IRS contest of the federal income tax positions we take may adversely impact the market for our units, and the costs of any contest will reduce cash available for distribution to our unitholders.
The IRS may adopt positions that differ from the positions we take, even positions taken with the advice of counsel. 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, penalties and interest directly from us. If we bear such payment, our cash available for distribution to our unitholders might be substantially reduced.
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, penalties and interest resulting from such audit adjustment directly from us. To the extent possible under applicable rules, our general partner may pay such amounts directly to the IRS or, if we are eligible, elect

29


to issue a revised Schedule K-1 to each unitholder with respect to an audited and adjusted return. No assurances can be made 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 could be substantially reduced.

Unitholders will be required to pay taxes on their share of our taxable income even if they do not receive cash distributions from us.
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 share of our taxable income.

Tax gain or loss on the disposition of our units could be different than expected.
A unitholder who sells units 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 unitholder in excess of the total net taxable income with respect to a unit will reduce the unitholder’s tax basis in that unit. As a result, the selling unitholder can recognize gain if such 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, even if there is a net taxable loss realized on the sale, may be ordinary income to the selling unitholder.

Unitholders may be subject to limitations on their ability to deduct interest expense incurred by us.
The deduction for “business interest” paid or accrued on indebtedness properly allocable to our trade or business is limited to the sum of our business interest income plus 30% of our “adjusted taxable income.” Proposed regulations would institute a broad definition of interest, treating certain amounts, including amounts paid as guaranteed payments for the use of capital with respect to our preferred units, as business interest subject to the limitation. 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, subject to certain restrictions.

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

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 an interest, such as our units, in a partnership that is engaged in a U.S. trade or business. The IRS has temporarily suspended the application of the withholding requirements on sales of publicly traded interests, including our units, until 60 days after proposed regulations are finalized. 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.

30


Because we cannot match transferors and transferees of our common units, we have adopted 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. Treasury regulations allow a similar monthly simplifying convention, but such regulations do not specifically authorize all aspects of our proration method. If the IRS were to challenge our proration method, we may be required to change the allocation of items of income, gain, loss and deduction among our common unitholders.

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

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

A unitholder whose units are the subject of a securities loan (e.g., a loan to a “short seller”) 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 and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan, any of our income, gain, loss or deduction with respect to those units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those units could be fully taxable as ordinary income. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to consult a tax advisor to discuss whether it is advisable to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their units.

Treatment of distributions on our preferred units as guaranteed payments for the use of capital creates a different tax treatment for the holders of preferred units than the holders of our common units and such distributions are not eligible for the 20% deduction for qualified publicly traded partnership income.
The tax treatment of distributions on our preferred units is uncertain. We will treat the holders of preferred units as partners for tax purposes and will treat distributions on the preferred units as guaranteed payments for the use of capital that will generally be taxable to the holders of preferred units as ordinary income. Although a holder of preferred units could recognize taxable income from the accrual of such a guaranteed payment even in the absence of a contemporaneous distribution, we anticipate accruing and making the guaranteed payment distributions quarterly. Otherwise, the holders of preferred units are generally not

31


anticipated to share in our items of income, gain, loss or deduction, nor will we allocate any share of our nonrecourse liabilities to the holders of preferred units. If the preferred units were treated as indebtedness for tax purposes, rather than as guaranteed payments for the use of capital, distributions likely would be treated as payments of interest by us to the holders of preferred units.

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

Investment in the preferred units by tax-exempt investors, such as employee benefit plans and IRAs, and non-U.S. persons raises issues unique to them. A non-U.S. holder’s income from guaranteed payments and any gain from the sale or disposition of our units may 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, to the extent gain on the sale or disposition is effectively connected income. The IRS has temporarily suspended the application of the withholding requirements on sales of publicly traded interests, including our preferred units, until 60 days after proposed regulations are finalized. 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 and selling 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 10, 2020, we had 407 holders of record of our common units. The following table presents the amount, record date and payment date of the quarterly cash distributions on our common units with respect to 2019 and 2018:
 
Cash Distributions
 
Amount Per
Common Unit
 
Record Date
 
Payment Date
Year 2019
 
 
 
 
 
4th Quarter
$
0.60

 
February 10, 2020
 
February 14, 2020
3rd Quarter
$
0.60

 
November 8, 2019
 
November 14, 2019
2nd Quarter
$
0.60

 
August 7, 2019
 
August 13, 2019
1st Quarter
$
0.60

 
May 8, 2019
 
May 14, 2019
Year 2018
 
 
 
 
 
4th Quarter
$
0.60

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

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

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

 
May 8, 2018
 
May 14, 2018

Our partnership agreement requires that we distribute all “Available Cash” to our common limited partners each quarter. This term is defined in the partnership agreement generally as cash receipts less cash disbursements, including distributions to our preferred units, and cash reserves established by the general partner, in its sole discretion. See Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” for further information regarding our distributions.

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

 
$
19,252

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

 
$
29,357

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

 
$
15,525

 
December 15, 2022
 
Three-month LIBOR plus 6.88%

The distribution rate on our Series D Cumulative Convertible Preferred Units (Series D Preferred Units) is (i) 9.75% per annum ($57.6 million per annum) for the first two years (beginning with the September 17, 2018 distribution); (ii) 10.75% per annum ($63.4 million per annum) for years three through five; and (iii) the greater of 13.75% per annum ($81.1 million per annum) or the distribution per common unit thereafter.

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

33


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

The following graph compares the cumulative five-year total return provided to holders of NuStar Energy’s common units relative to the cumulative total returns of the S&P 500 index and the Alerian MLP index. An investment of $100 (with reinvestment of all dividends) is assumed to have been made in our common units and in each of the indexes on December 31, 2014, and its relative performance is tracked through December 31, 2019.
chart-c1f01db32313fbb72c8.jpg
*$100 invested on 12/31/14 in stock or index, including reinvestment of dividends. Fiscal year ending December 31.
 
12/14
12/15
12/16
12/17
12/18
12/19
NuStar Energy L.P.
100.00

75.13

103.4

68.99

53.72

72.54

S&P 500 Index
100.00

101.38

113.51

138.29

132.23

173.86

Alerian MLP Index
100.00

67.41

79.75

74.55

65.29

69.57


Sales of Unregistered Securities
During the fourth quarter of 2018 and the fourth quarter of 2019, NuStar Energy issued an aggregate of 18,234 common units and 14,896 common units, respectively, in reliance upon an exemption from the registration requirements of the Securities Act of 1933, as amended, pursuant to Section 4(a)(2) thereof, upon the vesting of outstanding awards under a long-term incentive plan.

During the fourth quarter of 2019, NuStar Energy issued 527,426 common units at a price of $28.44 per unit to William E. Greehey, Chairman of the Board of Directors of NuStar GP, LLC, in reliance upon an exemption from the registration requirements of the Securities Act of 1933, as amended, pursuant to Section 4(a)(2) thereof. We used the proceeds of $15.0 million from the sale of these units for general partnership purposes.

34


ITEM 6.    SELECTED FINANCIAL DATA

On July 29, 2019, we sold our St. Eustatius terminal and bunkering operations and, on November 30, 2018, we sold our European operations. In the second quarter of 2019, we determined the St. Eustatius terminal and bunkering operations and the European operations met the requirements to be reported as discontinued operations and, as a result, we reclassified certain balances to assets and liabilities held for sale and certain revenues and expenses to discontinued operations for all applicable periods presented. Please refer to Note 5 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for further information.
The following table contains selected financial data derived from our audited financial statements and should be read in conjunction with Item 8. “Financial Statements and Supplementary Data.”
 
Year Ended December 31,
 
2019
 
2018
 
2017
 
2016
 
2015
 
(Thousands of Dollars, Except Per Unit Data)
Statement of Income Data:
 
 
 
 
 
 
 
 
 
Revenues
$
1,498,021

 
$
1,520,262

 
$
1,444,772

 
$
1,395,846

 
$
1,644,287

Operating income
$
390,916

 
$
335,728

 
$
290,510

 
$
319,697

 
$
348,422

Income from continuing operations (a)
$
206,834

 
$
146,375

 
$
110,895

 
$
111,213

 
$
268,951

Income (loss) from continuing operations per
common unit (a)
$
0.60

 
$
(3.34
)
 
$
0.23

 
$
0.78

 
$
2.83

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

 
$
2.40

 
$
4.38

 
$
4.38

 
$
4.38

 
 
 
 
 
 
 
 
 
 
 
December 31,
 
2019
 
2018
 
2017 (c)
 
2016
 
2015
 
(Thousands of Dollars)
Balance Sheet Data:
 
 
 
 
 
 
 
 
 
Property, plant and equipment, net
$
4,118,979

 
$
3,774,802

 
$
3,603,095

 
$
3,159,918

 
$
3,122,647

Total assets (d)
$
6,185,992

 
$
6,349,140

 
$
6,535,233

 
$
5,030,545

 
$
5,125,525

Current portion of long-term debt
$
452,637

 
$

 
$
349,990

 
$

 
$

Long-term debt and finance leases, less
current portion
$
2,934,918

 
$
3,111,996

 
$
3,263,069

 
$
3,014,364

 
$
3,055,612

Series D Cumulative Convertible Preferred Units (e)
$
581,935

 
$
563,992

 
$

 
$

 
$

Total partners’ equity (d)
$
1,776,210

 
$
2,257,731

 
$
2,480,089

 
$
1,611,617

 
$
1,609,844

(a)
Includes a $58.7 million non-cash impairment charge on the term loan to Axeon Specialty Products, LLC in 2016 and a $56.3 million non-cash gain associated with the Linden terminal acquisition in 2015. (Loss) income from continuing operations per common unit also includes the impact of a $377.1 million loss as a result of the July 2018 merger with our general partner. Please refer to Notes 4 and 21 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for further discussion.
(b)
The board of directors of NuStar GP, LLC reset our quarterly distribution per common unit to $0.60 ($2.40 on an annualized basis), starting with the distribution for the first quarter of 2018.
(c)
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.
(d)
In 2019, we incurred impairment charges totaling $336.8 million related to the St. Eustatius operations. Please refer to Note 5 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for further discussion.
(e)
In 2018, we issued 23,246,650 Series D Cumulative Convertible Preferred Units, which are presented in the mezzanine section of the consolidated balance sheets. Please refer to Note 19 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for further discussion.

35


ITEM 7.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following review of our results of operations and financial condition should be read in conjunction with “Cautionary Statement Regarding Forward-Looking Information,” Items 1., 1A. and 2. “Business, Risk Factors and Properties” and Item 8. “Financial Statements and Supplementary Data” included in this report.

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

OVERVIEW
Recent Developments
Completed Projects. In the third quarter of 2019, we completed construction of a 30-inch crude oil pipeline from Taft, Texas to our Corpus Christi North Beach terminal to transport volumes from the Permian Basin to Corpus Christi, Texas for export. We also completed an expansion project on our Valley Pipeline System, which originates in Corpus Christi and runs south to the Rio Grande Valley, and reactivated our refined products pipeline in South Texas to transport diesel to our Nuevo Laredo terminal in Mexico.

Our legacy pipelines that transport crude oil from the Eagle Ford and Permian Basin regions to Corpus Christi, together with our Corpus Christi North Beach terminal and new 30-inch pipeline, comprise the Corpus Christi Crude System.

Sale of St. Eustatius Operations. On July 29, 2019, we sold our St. Eustatius terminal and bunkering operations (the St. Eustatius Operations) for net proceeds of approximately $230.0 million (the St. Eustatius Disposition). The St. Eustatius Disposition included a 14.3 million barrel storage and terminalling facility and related assets on the island of St. Eustatius in the Caribbean Netherlands. We previously reported the terminal operations in our storage segment and the bunkering operations in our fuels marketing segment.

The consolidated statements of (loss) income reflect the St. Eustatius Operations and the European Operations, which were sold on November 30, 2018 and defined below, as discontinued operations for all applicable periods presented. In 2019, we recorded long-lived asset and goodwill impairment charges totaling $336.8 million related to the St. Eustatius Operations. Please refer to Note 5 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for further discussion of the sale and impairment charges.

Issuance of Debt. On May 22, 2019, NuStar Logistics L.P. (NuStar Logistics) issued $500.0 million of 6.0% senior notes due June 1, 2026. We received net proceeds of $491.6 million, which we used to repay outstanding borrowings under our revolving credit agreement. Please refer to Note 14 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for further information.

Selby Terminal Fire. On October 15, 2019, our terminal facility in Selby, California experienced a fire that destroyed two storage tanks and temporarily shut down the terminal. The property damage was isolated, and in the fourth quarter, we incurred losses of $5.4 million, which represent the aggregate amount of our deductibles under various insurance policies. We believe we have adequate insurance to offset additional costs in excess of the insurance deductibles.


36


Other Events
Sale of European Operations. On November 30, 2018, we sold our European operations, which consisted of six liquids storage terminals in the United Kingdom and one facility in Amsterdam and related assets (the European Operations), for approximately $270.0 million (the European Disposition). We previously reported the European Operations in our storage segment. We recognized a non-cash loss of $43.4 million related to the sale in “(Loss) income from discontinued operations, net of tax” on our consolidated statement of income for the year ended December 31, 2018. Please refer to Note 5 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for further discussion of the sale.

Merger. On July 20, 2018, we completed the merger of NuStar GP Holdings, LLC (Holdings) with a subsidiary of NuStar Energy (the Merger). Pursuant to the Merger agreement and at the effective time of the Merger, our partnership agreement was amended and restated to, among other things, (i) cancel the incentive distribution rights held by our general partner, (ii) convert the 2% general partner interest in NuStar Energy held by our general partner into a non-economic management interest and (iii) provide the holders of our common units with voting rights in the election of the members of the board of directors of NuStar GP, LLC, beginning at the annual meeting in 2019. We issued approximately 13.4 million incremental NuStar Energy common units as a result of the Merger. Please refer to Note 4 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for further discussion of the Merger.

Issuances of Units. In June and July of 2018, we issued 23,246,650 Series D Cumulative Convertible Preferred Units (Series D Preferred Units) at a price of $25.38 per unit in a private placement for net proceeds of $555.8 million. Please refer to Note 19 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for further discussion.

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

Hurricane Activity. In the third quarter of 2017, several of our facilities were affected by the hurricanes in the Caribbean and Gulf of Mexico, including the St. Eustatius terminal, which experienced the most damage and was temporarily shut down. In 2017, we received insurance proceeds of $12.5 million for damages at the St. Eustatius terminal, of which $3.8 million was for business interruption. In 2018, we received $87.5 million of insurance proceeds in settlement of our property damage claim for the St. Eustatius terminal, of which $9.1 million related to business interruption. Proceeds from business interruption insurance are included in “Cash flows from operating activities” in the consolidated statements of cash flows. We recorded a $78.8 million gain in the consolidated statements of income in 2018 for the amount by which the insurance proceeds exceeded our expenses incurred during the period. The insurance proceeds related to business interruption, the gain in 2018 and the loss in 2017 are all included in “(Loss) income from discontinued operations, net of tax” in the consolidated statements of (loss) income.

Navigator Acquisition. On May 4, 2017, we acquired Navigator Energy Services, LLC for approximately $1.5 billion (the Navigator Acquisition). We collectively refer to the acquired assets, together with the assets we have constructed through various expansion projects since the date of the Navigator Acquisition, as our Permian Crude System. The assets acquired are included in our pipeline segment within the Central West System, commencing on May 4, 2017. Please refer to Note 6 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.

Operations
We conduct our operations through our subsidiaries, primarily 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 and more detailed financial information about our segments, please refer to “Segments” under Item 1. “Business” and Note 26 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data.”

Pipeline. We own 3,205 miles of refined product pipelines and 2,155 miles of crude oil pipelines, as well as approximately 5.2 million barrels of storage capacity, which comprise our Central West System. In addition, we own 2,600 miles of refined

37


product pipelines, consisting of the East and North Pipelines, and a 2,000-mile ammonia pipeline (the Ammonia Pipeline), which comprise our Central East System. The East and North Pipelines have storage capacity of approximately 7.4 million barrels.

Storage. We own terminals and storage facilities in the United States, Canada and Mexico, with approximately 61.3 million barrels of storage capacity.

Fuels Marketing. Within our fuels marketing segment, which primarily includes our bunkering operations in the Gulf Coast and blending operations associated with our Central East System, we purchase petroleum products for resale. Prior to the third quarter of 2017, our fuels marketing operations involved the purchase of crude oil, fuel oil, bunker fuel, fuel oil blending components and other refined products for resale. We ceased marketing crude oil in the second quarter of 2017 and exited our heavy fuels trading operations in the third quarter of 2017. These actions were in line with our goal of reducing our exposure to commodity margins, and instead focusing on our core, fee-based pipeline and storage segments.

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 financial impacts of the derivative financial instruments associated with commodity price risk were not material for any period presented.

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

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



38


RESULTS OF OPERATIONS
Year Ended December 31, 2019 Compared to Year Ended December 31, 2018
Financial Highlights
(Thousands of Dollars, Except Per Unit Data)
 
Year Ended December 31,
 
 
 
2019
 
2018
 
Change
Statement of Income Data:
 
 
 
Revenues:
 
 
 
 
 
Service revenues
$
1,148,167

 
$
1,045,130

 
$
103,037

Product sales
349,854

 
475,132

 
(125,278
)
Total revenues
1,498,021

 
1,520,262

 
(22,241
)
 
 
 
 
 
 
Costs and expenses:
 
 
 
 
 
Costs associated with service revenues
669,246

 
626,250

 
42,996

Cost of product sales
321,644

 
449,613

 
(127,969
)
General and administrative expenses
107,855

 
100,067

 
7,788

Other depreciation and amortization expense
8,360

 
8,604

 
(244
)
Total costs and expenses
1,107,105


1,184,534


(77,429
)
 
 
 
 
 
 
Operating income
390,916

 
335,728

 
55,188

Interest expense, net
(183,070
)
 
(184,398
)
 
1,328

Other income, net
3,742

 
5,202

 
(1,460
)
Income from continuing operations before income tax expense
211,588

 
156,532

 
55,056

Income tax expense
4,754

 
10,157

 
(5,403
)
Income from continuing operations
206,834

 
146,375

 
60,459

(Loss) income from discontinued operations, net of tax
(312,527
)
 
59,419

 
(371,946
)
Net (loss) income
$
(105,693
)
 
$
205,794

 
$
(311,487
)
Basic and diluted net income (loss) per common unit:
 
 
 
 
 
Continuing operations
$
0.60

 
$
(3.34
)
 
$
3.94

Discontinued operations
(2.90
)
 
0.57

 
(3.47
)
Total
$
(2.30
)
 
$
(2.77
)
 
$
0.47

Annual Overview
Income from continuing operations increased $60.5 million for the year ended December 31, 2019 compared to the year ended December 31, 2018, mainly due to higher operating income from the pipeline segment.

For the year ended December 31, 2019, loss from discontinued operations, net of tax, includes impairment charges totaling $336.8 million related to the St. Eustatius Operations. For the year ended December 31, 2018, income from discontinued operations, net of tax, includes a gain of $78.8 million resulting from insurance proceeds received for hurricane damages incurred at the St. Eustatius terminal, partially offset by a loss of $43.4 million related to the sale of our European Operations. Please refer to Note 5 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for further discussion.

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

39


Segment Operating Highlights
(Thousands of Dollars, Except Barrel/Day Information)
 
Year Ended December 31,
 
 
 
2019
 
2018
 
Change
Pipeline:
 
 
 
 
 
Crude oil pipelines throughput (barrels/day)
1,198,813

 
876,655