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(Mark One)
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
☑ 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
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
Common units
Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units
Series B Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units
Series C Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units
Securities registered pursuant to 12(g) of the Act: None.
Trading Symbol(s)
NS
NSprA
NSprB
NSprC
Name of each exchange on
which registered
New York Stock Exchange
New York Stock Exchange
New York Stock Exchange
New York Stock Exchange
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
Non-accelerated filer
þ
☐
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.
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.
DOCUMENTS INCORPORATED BY REFERENCE:
Table of Contents
NUSTAR ENERGY L.P.
FORM 10-K
TABLE OF CONTENTS
PART I
Items 1., 1A. & 2. Business, Risk Factors and Properties
Overview
Recent Developments
Organizational Structure
Segments
Employees
Rate Regulation
Environmental, Health, Safety and Security Regulation
Risk Factors
Properties
Unresolved Staff Comments
Legal Proceedings
Mine Safety Disclosures
Market for Registrant’s Common Units, Related Unitholder Matters and Issuer Purchases of
Equity Securities
PART II
Selected Financial Data
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Item 1B.
Item 3.
Item 4.
Item 5.
Item 6.
Item 7.
Item 7A.
Quantitative and Qualitative Disclosures about Market Risk
Item 8.
Item 9.
Item 9A.
Item 9B.
Item 10.
Item 11.
Item 12.
Item 13.
Item 14.
Item 15.
Item 16.
Signatures
Financial Statements and Supplementary Data
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
Controls and Procedures
Other Information
Directors, Executive Officers and Corporate Governance
PART III
Executive Compensation
Security Ownership of Certain Beneficial Owners and Management and Related Unitholder
Matters
Certain Relationships and Related Transactions and Director Independence
Principal Accountant Fees and Services
PART IV
Exhibits and Financial Statement Schedules
Form 10-K Summary
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6
7
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15
18
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33
35
36
58
59
124
124
124
125
125
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135
136
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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:
Pipeline
Storage
Fuels marketing
Year Ended
December 31, 2019
(Thousands of Dollars)
$
$
$
332,480
154,105
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.
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We strive to increase unitholder value by:
•
•
•
•
enhancing our existing assets through strategic internal growth projects that expand our business with current and new
customers;
pursuing strategic projects to expand and optimize our existing assets and to construct new assets;
improving our operations, including safety and environmental stewardship, cost control and asset reliability; and
identifying strategic acquisition targets that meet our financial criteria.
Our internet website address is http://www.nustarenergy.com. Information contained on our website is not part of this report.
Our annual reports on Form 10-K, quarterly reports on Form 10-Q and current reports on Form 8-K, 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.
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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.
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ORGANIZATIONAL STRUCTURE
AS OF DECEMBER 31, 2019
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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:
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).
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The following table lists information about our pipeline assets as of December 31, 2019:
Region / Pipeline System
Central West System:
McKee Refined Product System
Three Rivers System
Valley Pipeline System
Other
Central West Refined Products Pipelines
Corpus Christi Crude Pipeline System
McKee Crude System
Ardmore System
Permian Crude System
Central West Crude Oil Pipelines
Total Central West System
Central East System:
East Pipeline
North Pipeline
Ammonia Pipeline
Total Central East System
Throughput
For the year ended December 31,
Length
(Miles)
Tank Capacity
2019
2018
(Barrels)
(Barrels/Day)
2,276
373
271
285
3,205
538
598
119
900
2,155
5,360
2,150
450
2,000
4,600
—
—
—
—
2,157,000
1,039,000
824,000
1,178,000
5,198,000
5,198,000
5,897,000
1,494,000
—
7,391,000
170,433
91,765
46,821
8,834
317,853
414,189
142,263
88,665
553,696
1,198,813
1,516,666
161,323
50,290
28,066
239,679
193,396
81,174
42,530
8,600
325,700
215,227
154,718
70,967
435,743
876,655
1,202,355
150,635
50,180
30,529
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.
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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
Colorado Springs, CO
Denver, CO
Albuquerque, NM
Rosario, NM
Catoosa, OK
Abernathy, TX
Amarillo, TX
Corpus Christi, TX
Corpus Christi, TX (North Beach)
Edinburg, TX
El Paso, TX (a)
Harlingen, TX
Laredo, TX
San Antonio, TX (b)
Southlake, TX
Nuevo Laredo, Mexico
Central West Terminals
11
Tank Capacity
328,000
110,000
251,000
166,000
358,000
160,000
269,000
491,000
3,539,000
346,000
419,000
286,000
215,000
377,000
569,000
35,000
7,919,000
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Facility
Jacksonville, FL
St. James, LA
Houston, TX
Texas City, TX (b)
Gulf Coast Terminals
Blue Island, IL
Andrews AFB, MD (c)
Baltimore, MD
Piney Point, MD
Linden, NJ (b)
Paulsboro, NJ
Virginia Beach, VA (c)
North East Terminals
Los Angeles, CA
Pittsburg, CA
Selby, CA
Stockton, CA
Portland, OR
Tacoma, WA
Vancouver, WA (b)
West Coast Terminals
Benicia, CA
Corpus Christi, TX
Texas City, TX
Refinery Storage Tanks
Point Tupper, Canada
Total
Tank Capacity
2,593,000
9,917,000
86,000
2,964,000
15,560,000
690,000
75,000
813,000
5,402,000
5,134,000
74,000
41,000
12,229,000
608,000
398,000
2,671,000
816,000
1,345,000
391,000
774,000
7,003,000
3,683,000
4,030,000
3,141,000
10,854,000
7,778,000
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.
As of December 31, 2019, we had 1,441 employees.
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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RISKS RELATED TO OUR BUSINESS
RISK FACTORS
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
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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:
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•
•
•
•
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
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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/
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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
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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.
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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
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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:
Year 2019
4th Quarter
3rd Quarter
2nd Quarter
1st Quarter
Year 2018
4th Quarter
3rd Quarter
2nd Quarter
1st Quarter
Cash Distributions
Amount Per
Common Unit
Record Date
Payment Date
$
$
$
$
$
$
$
$
0.60
0.60
0.60
0.60
0.60
0.60
0.60
0.60
February 10, 2020
November 8, 2019
August 7, 2019
May 8, 2019
February 14, 2020
November 14, 2019
August 13, 2019
May 14, 2019
February 8, 2019
November 8, 2018
August 7, 2018
May 8, 2018
February 13, 2019
November 14, 2018
August 13, 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:
Fixed Distribution
Rate Per Annum (as a
Percentage of the
$25.00 Liquidation
Preference Per Unit)
Fixed
Distribution
Rate Per Unit
Per Annum
Units
Optional Redemption
Date/Date at Which
Distribution Rate
Becomes Floating
Floating Annual Rate (as a
Percentage of the
$25.00 Liquidation
Preference Per Unit)
Fixed
Distribution
Per Annum
(Thousands of
Dollars)
Series A Preferred Units
8.50% $
2.125
Series B Preferred Units
7.625% $
1.90625
Series C Preferred Units
9.00% $
2.25
$
$
$
19,252 December 15, 2021
29,357
June 15, 2022
15,525 December 15, 2022
Three-month LIBOR
plus 6.766%
Three-month LIBOR
plus 5.643%
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.
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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.
COMPARISON OF FIVE-YEAR CUMULATIVE TOTAL RETURN*
Among NuStar Energy L.P., the S&P 500 Index
and Alerian MLP Index
$200
$180
$160
$140
$120
$100
$80
$60
$40
12/14
12/15
12/16
12/17
12/18
12/19
NuStar Energy L.P.
S&P 500 Index
Alerian MLP Index
*$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.
S&P 500 Index
Alerian MLP Index
100.00
100.00
100.00
75.13
101.38
67.41
103.4
113.51
79.75
68.99
138.29
74.55
53.72
132.23
65.29
72.54
173.86
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.
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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.”
Statement of Income Data:
Revenues
Operating income
Income from continuing operations (a)
Income (loss) from continuing operations per
common unit (a)
Cash distributions per unit applicable
to common limited partners (b)
Balance Sheet Data:
Property, plant and equipment, net
Total assets (d)
Current portion of long-term debt
Long-term debt and finance leases, less
current portion
Series D Cumulative Convertible Preferred Units (e)
Total partners’ equity (d)
Year Ended December 31,
2019
2018
2017
2016
2015
(Thousands of Dollars, Except Per Unit Data)
$ 1,498,021
390,916
$
206,834
$
$ 1,520,262
335,728
$
146,375
$
$ 1,444,772
290,510
$
110,895
$
$ 1,395,846
319,697
$
111,213
$
$ 1,644,287
348,422
$
268,951
$
$
$
0.60
2.40
$
$
(3.34) $
2.40
$
0.23
4.38
$
$
0.78
4.38
$
$
2.83
4.38
December 31,
2019
2018
2017 (c)
2016
2015
(Thousands of Dollars)
$ 4,118,979
$ 6,185,992
452,637
$
$ 3,774,802
$ 6,349,140
$
— $
$ 3,603,095
$ 6,535,233
349,990
$ 3,159,918
$ 5,030,545
$
— $
$ 3,122,647
$ 5,125,525
—
$ 2,934,918
$
581,935
$ 1,776,210
$ 3,111,996
$
563,992
$ 2,257,731
$ 3,263,069
$
$ 2,480,089
— $
$ 3,014,364
$ 1,611,617
— $
$ 3,055,612
—
$ 1,609,844
(a)
(b)
(c)
(d)
(e)
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.
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.
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.
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.
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.
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ITEM 7.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
The following review of our results of operations and financial condition should be read in conjunction with “Cautionary
Statement Regarding Forward-Looking Information,” Items 1., 1A. and 2. “Business, Risk Factors and Properties” and Item 8.
“Financial Statements and Supplementary Data” included in this report.
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.
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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
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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.
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RESULTS OF OPERATIONS
Year Ended December 31, 2019 Compared to Year Ended December 31, 2018
Financial Highlights
(Thousands of Dollars, Except Per Unit Data)
Statement of Income Data:
Revenues:
Service revenues
Product sales
Total revenues
Costs and expenses:
Costs associated with service revenues
Cost of product sales
General and administrative expenses
Other depreciation and amortization expense
Total costs and expenses
Operating income
Interest expense, net
Other income, net
Income from continuing operations before income tax expense
Income tax expense
Income from continuing operations
(Loss) income from discontinued operations, net of tax
Net (loss) income
Basic and diluted net income (loss) per common unit:
Continuing operations
Discontinued operations
Total
Year Ended December 31,
2019
2018
Change
$ 1,148,167
349,854
$ 1,045,130
475,132
$
1,498,021
1,520,262
103,037
(125,278)
(22,241)
669,246
321,644
107,855
8,360
626,250
449,613
100,067
8,604
1,107,105
1,184,534
390,916
(183,070)
3,742
211,588
4,754
206,834
(312,527)
(105,693) $
335,728
(184,398)
5,202
156,532
10,157
146,375
59,419
205,794
$
42,996
(127,969)
7,788
(244)
(77,429)
55,188
1,328
(1,460)
55,056
(5,403)
60,459
(371,946)
(311,487)
$
0.60
(2.90)
(2.30) $
(3.34) $
0.57
(2.77) $
3.94
(3.47)
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.
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Segment Operating Highlights
(Thousands of Dollars, Except Barrel/Day Information)
Year Ended December 31,
2019
2018
Change
1,198,813
557,532
1,756,345
701,830
202,359
166,991
332,480
464,571
114,243
339,758
454,001
202,323
97,573
154,105
342,215
318,869
23,346
2,768
20,578
$
$
$
$
$
$
876,655
557,044
1,433,699
611,065
184,427
153,943
272,695
341,396
83,157
360,431
443,588
194,535
93,345
155,708
$
$
$
$
322,158
488
322,646
90,765
17,932
13,048
59,785
123,175
31,086
(20,673)
10,413
7,788
4,228
(1,603)
465,651
446,707
18,944
2,980
15,964
$ (123,436)
(127,838)
4,402
(212)
4,614
$
(25) $
7
(32) $
(42) $
(74)
32
$
17
81
(64)
$
$
$
$
$
$
$
$
$ 1,498,021
$ 1,520,262
$
(22,241)
404,682
264,564
669,246
321,644
507,131
107,855
8,360
390,916
$
378,962
247,288
626,250
449,613
444,399
100,067
8,604
335,728
25,720
17,276
42,996
(127,969)
62,732
7,788
(244)
55,188
$
$
Pipeline:
Crude oil pipelines throughput (barrels/day)
Refined products and ammonia pipelines throughput (barrels/day)
Total throughput (barrels/day)
Throughput and other revenues
Operating expenses
Depreciation and amortization expense
Segment operating income
Storage:
Throughput (barrels/day)
Throughput terminal revenues
Storage terminal revenues
Total revenues
Operating expenses
Depreciation and amortization expense
Segment operating income
Fuels Marketing:
Product sales
Cost of goods
Gross margin
Operating expenses
Segment operating income
Consolidation and Intersegment Eliminations:
Revenues
Cost of goods
Total
Consolidated Information:
Revenues
Costs associated with service revenues:
Operating expenses
Depreciation and amortization expense
Total costs associated with service revenues
Cost of product sales
Segment operating income
General and administrative expenses
Other depreciation and amortization expense
Consolidated operating income
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Pipeline
Total revenues increased $90.8 million and total throughputs increased 322,646 barrels per day for the year ended
December 31, 2019, compared to the year ended December 31, 2018, primarily due to:
•
•
•
•
•
•
•
an increase in revenues of $53.8 million and an increase in throughputs of 117,953 barrels per day resulting from
increased customer production supplying our Permian Crude System and the completion of new pipeline connections
with higher tariffs and expansion projects;
an increase in revenues of $14.5 million and an increase in throughputs of 17,698 barrels per day on our Ardmore
System, due to a customer’s refinery turnaround in the third quarter of 2018, an increase in long-haul deliveries
resulting in higher average tariffs in 2019 and the completion of new pipeline connections that began delivering
Permian crude oil in the second quarter of 2019;
an increase in revenues of $8.5 million on our Houston pipeline, as a customer began leasing a portion of the pipeline
on January 1, 2019;
an increase in revenues of $7.0 million and an increase in throughputs of 4,291 barrels per day on our Valley Pipeline
System, mainly due to new customer contracts related to the completion of an expansion project in the third quarter of
2019 and a new connection that began in the fourth quarter of 2018;
an increase in revenues of $5.2 million and an increase in throughputs of 10,688 barrels per day on our East Pipeline,
mainly due to owning and operating the assets associated with the Council Bluffs Acquisition for the full year in 2019;
an increase in revenues of $4.2 million and an increase in throughputs of 10,591 barrels per day on our Three Rivers
System, due to increased demand in markets served by the system and the reactivation of our refined products pipeline
to transport diesel to our Nuevo Laredo terminal in Mexico in 2019;
an increase in revenues of $1.3 million and an increase in throughputs of 198,962 barrels per day on our Corpus
Christi Crude Pipeline System. Throughputs increased due to the completion of the 30-inch crude oil pipeline from
Taft, Texas to our Corpus Christi North Beach terminal, as well as the re-contracting of certain customer contracts.
Lower rates on certain customer contracts partially offset the increase in revenues from increased throughputs.
These increases were partially offset by a decrease in revenues of $3.1 million and a decrease in throughputs of 35,418 barrels
per day due to operational issues at the refinery served by our McKee System pipelines in 2019.
Operating expenses increased $17.9 million for the year ended December 31, 2019, compared to the year ended December 31,
2018, mainly due to:
•
•
•
an increase of $6.9 million in power costs, mainly as the result of higher throughputs on our Permian Crude System
and Corpus Christi Crude Pipeline System;
an increase of $6.1 million in compensation expense; and
an increase of $1.9 million due to owning the assets associated with the Council Bluffs Acquisition for the entire
period in 2019.
Depreciation and amortization expense increased $13.0 million for the year ended December 31, 2019, compared to the year
ended December 31, 2018, mainly due to completed projects associated with the Permian Crude System and the Valley Pipeline
System and owning the assets associated with the Council Bluffs Acquisition for the entire year in 2019.
Storage
Throughput terminal revenues increased $31.1 million, while throughputs increased 123,175 barrels per day for the year ended
December 31, 2019, compared to the year ended December 31, 2018 mainly due to an increase in throughput terminal revenues
of $29.9 million and an increase in throughputs of 124,562 barrels per day at our Corpus Christi North Beach terminal,
consistent with higher volumes on our Corpus Christi Crude Pipeline System.
Storage terminal revenues decreased $20.7 million for the year ended December 31, 2019, compared to the year ended
December 31, 2018, primarily due to:
•
•
a decrease in revenues of $24.1 million at our North East terminals, mainly due to a decrease in customer base and the
re-contracting of certain customer contracts in a backwardated market, as well as an adjustment that increased
revenues in 2018 resulting from a change in the term of a contract at our Linden, New Jersey terminal. Please refer to
Note 7 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data”
for further discussion of the revenue adjustment; and
a decrease in revenues of $5.8 million at our Point Tupper terminal, mainly due to a decrease in customer base.
These decreases in storage terminal revenues were partially offset by an increase in revenues of $9.3 million at our West Coast
terminals, mainly due to completed projects and higher throughput and handling fees.
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Operating expenses increased $7.8 million for the year ended December 31, 2019, compared to the year ended December 31,
2018, primarily due to an increase in reimbursable expenses of $7.4 million, mostly resulting from higher reimbursable
wharfage activity at our Corpus Christi North Beach terminal, and higher compensation expense of $3.8 million. These
increases were partially offset by a decrease in maintenance and regulatory expense of $4.5 million, mainly due to tank
cleanings in 2018.
Depreciation and amortization expense increased $4.2 million for the year ended December 31, 2019, compared to the year
ended December 31, 2018, mainly due to amortization expense associated with a finance lease for a dock that was completed in
September 2018 and projects completed in 2019.
Fuels Marketing
Segment operating income increased $4.6 million for the year ended December 31, 2019, compared to the year ended
December 31, 2018, primarily due to an increase in gross margins from our bunkering operations.
General
General and administrative expenses increased $7.8 million for the year ended December 31, 2019, compared to the year ended
December 31, 2018, mainly due to higher compensation costs in 2019 and lower legal expenses in 2018.
Income tax expense decreased $5.4 million for the year ended December 31, 2019, compared to the year ended December 31,
2018, primarily due to lower income in our taxable entities.
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Year Ended December 31, 2018 Compared to Year Ended December 31, 2017
Financial Highlights
(Thousands of Dollars, Except Per Unit Data)
Statement of Income Data:
Revenues:
Service revenues
Product sales
Total revenues
Costs and expenses:
Costs associated with service revenues
Cost of product sales
General and administrative expenses
Other depreciation and amortization expense
Total costs and expenses
Operating income
Interest expense, net
Other income (expense), net
Income from continuing operations before income tax expense
Income tax expense
Income from continuing operations
Income from discontinued operations, net of tax
Net income
Basic and diluted net (loss) income per common unit:
Continuing operations
Discontinued operations
Total
Year Ended December 31,
2018
2017
Change
$ 1,045,130
475,132
$
955,446
$
489,326
1,520,262
1,444,772
89,684
(14,194)
75,490
626,250
449,613
100,067
8,604
552,480
485,791
107,556
8,435
1,184,534
1,154,262
335,728
(184,398)
5,202
156,532
10,157
146,375
59,419
290,510
(171,774)
(68)
118,668
7,773
110,895
37,069
205,794
$
147,964
$
73,770
(36,178)
(7,489)
169
30,272
45,218
(12,624)
5,270
37,864
2,384
35,480
22,350
57,830
(3.34) $
0.57
(2.77) $
0.23
0.41
0.64
$
$
(3.57)
0.16
(3.41)
$
$
$
Annual Overview
Income from continuing operations increased $35.5 million for the year ended December 31, 2018, compared to the year ended
December 31, 2017, primarily due to higher operating income from the pipeline and fuels marketing segments, partially offset
by lower operating income from the storage segment. Income from discontinued operations, net of tax increased $22.4 million
for the year ended December 31, 2018, compared to the year ended December 31, 2017, primarily due to the $78.8 million gain
recognized in the first quarter of 2018 from insurance proceeds related to hurricane damage at the St. Eustatius terminal in the
third quarter of 2017, partially offset by a $43.4 million loss from the sale of our European Operations in the fourth quarter of
2018.
Despite income from continuing operations, 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.
43
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Segment Operating Highlights
(Thousands of Dollars, Except Barrel/Day Information)
Year Ended December 31,
2018
2017
Change
876,655
557,044
1,433,699
611,065
184,427
153,943
272,695
341,396
83,157
360,431
443,588
194,535
93,345
155,708
465,651
446,707
18,944
2,980
15,964
583,323
516,736
1,100,059
516,288
156,432
128,061
231,795
325,194
85,927
357,089
443,016
178,600
91,696
172,720
489,807
474,188
15,619
13,632
1,987
$
$
$
$
$
$
$
$
$
$
$
$
293,332
40,308
333,640
94,777
27,995
25,882
40,900
16,202
(2,770)
3,342
572
15,935
1,649
(17,012)
(24,156)
(27,481)
3,325
(10,652)
13,977
(42) $
(74)
—
32
$
(4,339) $
(2,029)
(2,309)
(1) $
4,297
1,955
2,309
33
$
$
$
$
$
$
$
$
$ 1,520,262
$ 1,444,772
$
75,490
378,962
247,288
626,250
449,613
444,399
100,067
8,604
335,728
$
332,723
219,757
552,480
485,791
406,501
107,556
8,435
290,510
$
46,239
27,531
73,770
(36,178)
37,898
(7,489)
169
45,218
$
Pipeline:
Crude oil pipelines throughput (barrels/day)
Refined products and ammonia pipelines throughput (barrels/day)
Total throughput (barrels/day)
Throughput revenues
Operating expenses
Depreciation and amortization expense
Segment operating income
Storage:
Throughput (barrels/day)
Throughput terminal revenues
Storage terminal revenues
Total revenues
Operating expenses
Depreciation and amortization expense
Segment operating income
Fuels Marketing:
Product sales and other revenue
Cost of goods
Gross margin
Operating expenses
Segment operating income
Consolidation and Intersegment Eliminations:
Revenues
Cost of goods
Operating expenses
Total
Consolidated Information:
Revenues
Costs associated with service revenues:
Operating expenses
Depreciation and amortization expense
Total costs associated with service revenues
Cost of product sales
Segment operating income
General and administrative expenses
Other depreciation and amortization expense
Consolidated operating income
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Pipeline
Total revenues increased $94.8 million and total throughputs increased 333,640 barrels per day for the year ended
December 31, 2018, compared to the year ended December 31, 2017, primarily due to:
•
•
•
•
an increase in revenues of $68.4 million and an increase in throughputs of 242,785 barrels per day resulting from
increased customer production supplying our Permian Crude System, completion of pipeline expansion projects and
owning and operating the system for the entire period in 2018;
an increase in revenues of $16.0 million and an increase in throughputs of 38,624 barrels per day due to a turnaround
in the fourth quarter of 2017 at the refinery served by our McKee System pipelines;
an increase in revenues of $13.0 million and an increase in throughputs of 11,318 barrels per day on our East Pipeline
due to higher diesel throughputs, an increase in long-haul deliveries resulting in higher average tariffs and the Council
Bluffs Acquisition; and
an increase in revenues of $10.8 million and an increase in throughputs of 8,742 barrels per day, mainly due to a
turnaround at the refinery served by our North Pipeline in the second quarter of 2017, as well as turnaround activity at
a neighboring refinery in 2018, resulting in higher demand on the North Pipeline.
These increases were partially offset by:
•
•
a decrease in revenues of $10.8 million on our Corpus Christi Crude Pipeline System, mainly due to contract renewals
at lower rates, which more than offset an increase in throughputs of 47,338 barrels per day; and
a decrease in revenues of $3.4 million and a decrease in throughputs of 13,834 barrels per day on our Ardmore
System, mainly due to a customer’s refinery turnaround in 2018, as well as an increase in short-haul deliveries, which
result in lower average tariffs.
Operating expenses increased $28.0 million for the year ended December 31, 2018, compared to the year ended December 31,
2017, mainly due to:
•
•
•
•
increased operating expenses of $16.5 million as a result of owning the Permian Crude System for the entire period in
2018 and consistent with the increase in throughputs;
an increase of $3.1 million resulting from the Council Bluffs Acquisition;
an increase of $2.7 million in salaries and wages; and
an increase in power expenses of $2.6 million, mainly due to increased throughputs.
Depreciation and amortization expense increased $25.9 million for the year ended December 31, 2018, compared to the year
ended December 31, 2017, mainly due to owning the Permian Crude System for the entire period in 2018.
Storage
Throughput terminal revenues decreased $2.8 million, while throughputs increased 16,202 barrels per day for the year ended
December 31, 2018, compared to the year ended December 31, 2017. Corpus Christi North Beach terminal revenues decreased
by $6.3 million, despite increased throughputs of 10,581 barrels per day mainly driven by higher Corpus Christi Crude System
volumes, due to lower storage rates and lower dock revenues as additional volumes were delivered to our customer’s refineries
instead of over our docks. Revenues increased $3.8 million and throughputs increased 7,343 barrels per day at our Central West
Terminals, mainly due to increased demand in markets served by those terminals.
Storage terminal revenues increased $3.3 million for the year ended December 31, 2018, compared to the year ended
December 31, 2017, primarily due to:
•
•
•
an increase of $9.4 million at our West Coast Terminals, mainly due to project completions, rate escalations and higher
throughput and associated handling fees;
an increase of $8.1 million at our North East Terminals, mainly due to an adjustment to revenues resulting from a
change in the term of a contract and the completion of a tank expansion project at our Linden terminal, partially offset
by a decrease in revenues at our Piney Point terminal due to the non-renewal at expiration of certain customer
contracts. Please refer to Note 7 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements
and Supplementary Data” for further discussion of the revenue adjustment; and
an increase of $1.9 million due to higher reimbursable revenues at our Point Tupper terminal.
These increases were partially offset by the following:
•
•
a decrease of $15.5 million at our Gulf Coast Terminals, mainly due to a backwardated market resulting in the non-
renewal at expiration of certain customer contracts and lower throughput and associated handling fees; and
a decrease of $1.9 million due to lower throughput and handling fees at our Point Tupper terminal.
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Operating expenses increased $15.9 million for the year ended December 31, 2018, compared to the year ended December 31,
2017, primarily due to:
•
•
•
an increase in salaries and wages of $4.8 million, and an increase in maintenance and regulatory expenses of $1.8
million, both spread across various regions;
an increase in reimbursable expenses of $4.8 million at various terminals, primarily due to tank cleanings at our Point
Tupper and Corpus Christi North Beach terminals, which was offset by a corresponding increase in reimbursable
revenues; and
an increase in insurance expense of $1.5 million across all terminals due to premium increases.
Depreciation and amortization expense increased $1.6 million for the year ended December 31, 2018, compared to the year
ended December 31, 2017, mainly as the result of the completion of various storage projects.
Fuels Marketing
Segment operating income increased $14.0 million for the year ended December 31, 2018, compared to the year ended
December 31, 2017, primarily due to an increase of $9.2 million in operating income from our blending operations and other
product sales, and a reduction in operating losses of $5.6 million incurred by our heavy fuels trading operations.
Consolidation and Intersegment Eliminations
Revenue and operating expense eliminations primarily relate to storage fees charged to the fuels marketing segment by the
storage segment. Cost of product sales eliminations represent expenses charged to the fuels marketing segment for costs
associated with inventory that are expensed once the inventory is sold.
General
General and administrative expenses decreased $7.5 million for the year ended December 31, 2018, compared to the year ended
December 31, 2017, primarily due to transaction costs related to the Navigator Acquisition in 2017, partially offset by higher
compensation costs.
Interest expense, net increased $12.6 million for the year ended December 31, 2018, compared to the year ended December 31,
2017, mainly due to the issuance of $550.0 million of 5.625% senior notes on April 28, 2017 to partially fund the Navigator
Acquisition and higher interest rates.
Income tax expense increased $2.4 million for the year ended December 31, 2018, compared to the year ended December 31,
2017, primarily due to an increase in taxes associated with the Permian Crude System.
TRENDS AND OUTLOOK
For 2020, we expect to continue to benefit from several significant expansion projects completed in 2019. These projects
mainly relate to continued growth in Permian Basin production, which led to an expansion of our Permian Crude System and
other assets experiencing a “spillover” effect from Permian Basin growth. Additionally, during 2019, we completed projects to
handle bio-fuels demand on the West Coast and to expand pipelines to facilitate the export of refined products to Northern
Mexico. Although we expect a significant reduction in our capital spending in 2020, our focus will continue to be on projects to
accommodate production growth in the Permian Basin (on our Permian and Corpus Christi crude systems), to handle bio-fuels
demand on the West Coast and to increase flexibility at our St. James terminal.
Our outlook for the partnership, both overall and for any of our segments, may change, as we base our expectations on our
continuing evaluation of a number of factors, many of which are outside our control. These factors include, but are not limited
to, the state of the economy and the capital markets, changes to our customers’ refinery maintenance schedules and unplanned
refinery downtime, crude oil prices, the supply of and demand for crude oil, refined products and anhydrous ammonia, demand
for our transportation and storage services and changes in laws or regulations affecting our assets.
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LIQUIDITY AND CAPITAL RESOURCES
Overview
Our primary cash requirements are for distributions to our partners, debt service, capital expenditures, acquisitions and
operating expenses.
Our partnership agreement requires that we distribute all “Available Cash” to our common limited partners and, prior to the
Merger, to our general partner each quarter. “Available Cash” is defined in the partnership agreement generally as cash on hand
at the end of the quarter, plus certain permitted borrowings made subsequent to the end of the quarter, less cash reserves
determined by our board of directors, subject to requirements for distributions for our preferred units. The board of directors of
NuStar GP, LLC reset our quarterly distribution per common unit to $0.60 ($2.40 on an annualized basis), starting with the
2018 first-quarter distribution, which was paid on May 14, 2018. As a result of the Merger, our general partner no longer
receives incentive distributions or quarterly cash distributions from us, and we issued approximately 13.4 million incremental
NuStar Energy common units in exchange for previously outstanding Holdings units. Please refer to Note 4 of the Notes to
Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for further discussion regarding
the Merger.
Each year, our objective is to fund our reliability capital expenditures and distribution requirements with our net cash provided
by operating activities during that year. If we do not generate sufficient cash from operations to meet that objective, we utilize
cash on hand or other sources of cash flow, which in the past have primarily included borrowings under our revolving credit
agreement, sales of non-strategic assets and, to the extent necessary, funds raised through equity or debt offerings. We have
typically funded our strategic capital expenditures and acquisitions from external sources, primarily borrowings under our
revolving credit agreement or funds raised through equity or debt offerings. However, our ability to raise funds by issuing debt
or equity depends on many factors beyond our control. Our risk factors in Item 1A. “Risk Factors” describe the risks inherent to
these sources of funding and the availability thereof.
During periods when our cash flow from operations is less than our distribution and reliability capital requirements, we may
maintain our distribution level because we can use other sources of Available Cash, as provided in our partnership agreement,
including borrowings under our revolving credit agreement and proceeds from the sales of assets. Our risk factors in Item 1A.
“Risk Factors” describe the risks inherent in our ability to maintain or grow our distribution.
For 2020, we expect to generate sufficient cash from operations to fund our distribution requirements, reliability capital
expenditures, and a portion of our strategic capital expenditures.
Cash Flows for the Years Ended December 31, 2019, 2018 and 2017
The following table summarizes our cash flows from operating, investing and financing activities (please refer to our
Consolidated Statements of Cash Flows in Item 8. “Financial Statements and Supplementary Data”). The consolidated
statements of cash flows have not been adjusted to separately disclose cash flows related to discontinued operations.
Net cash provided by (used in):
Operating activities
Investing activities
Financing activities
Effect of foreign exchange rate changes on cash
Net increase (decrease) in cash, cash equivalents and restricted cash
Year Ended December 31,
2019
2018
2017
(Thousands of Dollars)
$
$
508,757
(319,247)
(177,650)
(524)
11,336
$
$
$
544,207
(153,778)
(399,867)
(1,210)
(10,648) $
406,799
(1,696,441)
1,276,272
1,720
(11,650)
Net cash provided by operating activities for the year ended December 31, 2019 was $508.8 million, compared to $544.2
million for the year ended December 31, 2018, primarily due to changes in working capital. Our working capital increased by
$44.8 million for the year ended December 31, 2019, compared to a decrease of $78.3 million for the year ended December 31,
2018. Please refer to the “Working Capital Requirements” section below for a discussion of the changes in working capital.
For the year ended December 31, 2019, the net cash provided by operating activities was used to fund our distributions to
unitholders of $380.0 million, reliability capital expenditures of $66.6 million and a portion of our strategic capital
expenditures. Proceeds from the sale of the St. Eustatius Operations along with net proceeds from debt borrowings were used to
fund the remainder of our strategic capital expenditures, which are described in the Capital Requirements section below.
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For the year ended December 31, 2018, net cash provided by operating activities was used to fund our distributions to
unitholders and our general partner in the aggregate amount of $391.4 million and the cash consideration for the Merger of
$67.8 million. Net cash provided by operating activities and a portion of the insurance proceeds we received in the first quarter
of 2018 in settlement of our property damage claim for our St. Eustatius terminal were used to fund reliability capital
expenditures of $77.2 million. The remainder of cash provided by operating activities and proceeds from debt borrowings were
used to fund our strategic capital expenditures, including acquisitions, of $417.8 million. The proceeds from the issuance of
units and the sale of our European operations along with a portion of the insurance proceeds were used to repay outstanding
borrowings under our revolving credit agreement.
For the year ended December 31, 2017, net cash provided by operating activities, the proceeds from the termination of the
Axeon Term Loan of $110.0 million and cash on hand were used to fund our distributions to unitholders and our general partner
in the aggregate amount of $485.1 million and reliability capital expenditures of $57.5 million. Proceeds from our debt and
equity issuances of approximately $1.5 billion were used to fund the purchase price of the Navigator Acquisition. The proceeds
from debt borrowings, net of repayments, remaining proceeds from our equity issuances and cash on hand were used to fund
our other strategic capital expenditures.
Asset Sales
Proceeds from the St. Eustatius Disposition in 2019 and the European Disposition in 2018 were initially used to repay
outstanding borrowings under our revolving credit agreement, increasing the amount available for borrowing. These sales were
part of our plan to improve our debt metrics and partially fund capital projects to grow our core business in North America.
Debt Sources of Liquidity
Revolving Credit Agreement. On September 12, 2019, NuStar Logistics amended its revolving credit agreement (the Revolving
Credit Agreement) primarily to extend the maturity date to October 29, 2021 and reduce the total amount available for
borrowing from $1.4 billion to $1.2 billion.
On June 29, 2018, NuStar Logistics amended the Revolving Credit Agreement to exclude the Series D Preferred Units from the
definition of “Indebtedness.” Additionally, the amendment reduced the total amount available for borrowing from $1.75 billion
to $1.575 billion, effective June 29, 2018, with a further reduction to $1.4 billion, effective December 28, 2018. The Revolving
Credit Agreement was also amended to, among other things, add a minimum consolidated interest coverage ratio (as defined in
the Revolving Credit Agreement), which must not be less than 1.75-to-1.00 for each rolling period of four quarters, beginning
with the rolling period ending June 30, 2018. As of December 31, 2019, our consolidated interest coverage ratio was 2.49x.
The maximum consolidated debt coverage ratio and minimum consolidated interest coverage ratio requirements may limit the
amount we can borrow under the Revolving Credit Agreement to an amount less than the total amount available for borrowing.
The Revolving Credit Agreement also contains customary restrictive covenants, such as limitations on indebtedness, liens,
mergers, asset transfers and certain investing activities. As of December 31, 2019, our consolidated debt coverage ratio was
3.88x and we had $721.0 million available for borrowing. Obligations under the Revolving Credit Agreement are guaranteed
by NuStar Energy and NuPOP.
Letters of credit issued under the Revolving Credit Agreement totaled $4.0 million as of December 31, 2019. Letters of credit
are limited to $400.0 million and also may restrict the amount we can borrow under the Revolving Credit Agreement.
Receivables Financing Agreement. NuStar Energy and NuStar Finance LLC (NuStar Finance), a special purpose entity and
wholly owned subsidiary of NuStar Energy, are parties to a $125.0 million receivables financing agreement with third-party
lenders (the Receivables Financing Agreement) and agreements with certain of NuStar Energy’s wholly owned subsidiaries
(together with the Receivables Financing Agreement, the Securitization Program). On April 29, 2019, we amended the
Receivables Financing Agreement to extend the scheduled termination date from September 20, 2020 to September 20, 2021,
with the option to renew for additional 364-day periods thereafter, and to amend certain provisions with respect to receivables
related to certain customers. The amount available for borrowing under the Receivables Financing Agreement is limited to
$125.0 million and is based on the availability of eligible receivables and other customary factors and conditions. The
Securitization Program contains various customary affirmative and negative covenants and default, indemnification and
termination provisions, and the Receivables Financing Agreement provides for acceleration of amounts owed upon the
occurrence of certain specified events.
Note Issuances. 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 initially used to repay outstanding borrowings under our Revolving Credit
Agreement. The interest on the 6.0% senior notes is payable semi-annually in arrears on June 1 and December 1 of each year,
beginning on December 1, 2019. On April 28, 2017, NuStar Logistics issued $550.0 million of 5.625% senior notes due
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April 28, 2027. We used the net proceeds of $543.3 million from the offering to fund a portion of the purchase price for the
Navigator Acquisition and to pay related fees and expenses. Interest on the 5.625% senior notes is payable semi-annually in
arrears on April 28 and October 28 of each year, beginning on October 28, 2017. The 6.0% and 5.625% senior notes do not
have sinking fund requirements. These senior notes rank equally with existing senior unsecured indebtedness and senior to
existing subordinated indebtedness of NuStar Logistics. These senior notes contain restrictions on NuStar Logistics’ ability to
incur secured indebtedness unless the same security is also provided for the benefit of holders of the senior notes. In addition,
these senior notes limit NuStar Logistics’ ability to incur indebtedness secured by certain liens, engage in certain sale-leaseback
transactions and engage in certain consolidations, mergers or asset sales.
Short-Term Line of Credit Agreement. As of December 31, 2019, we were a party to a line of credit agreement with an
uncommitted borrowing capacity of up to $35.0 million, with $5.5 million of borrowings outstanding.
Please refer to Note 14 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary
Data” for a discussion of our debt agreements.
LOC Agreement
NuStar Logistics is a party to a $100.0 million uncommitted letter of credit agreement, which provides for standby letters of
credit or guarantees with a term of up to one year (LOC Agreement). Any letters of credit issued under the LOC Agreement do
not reduce availability under the Revolving Credit Agreement. As of December 31, 2019, we had no letters of credit issued
under the LOC Agreement.
Repatriation
We may repatriate a portion of undistributed foreign earnings in order to provide greater flexibility to meet cash flow needs.
During the year ended December 31, 2017, we repatriated $9.5 million of cash from our foreign subsidiaries. We will continue
to evaluate our cash flow needs and may repatriate funds from our foreign subsidiaries as a source of liquidity.
Issuances of Units
Common Units. In the fourth quarter of 2019, we issued 527,426 common units to William E. Greehey, Chairman of the Board
of Directors of NuStar GP, LLC, at a price of $28.44 per unit for total proceeds of $15.0 million. In the second quarter of 2018,
we issued 413,736 common units to William E. Greehey at a price of $24.17 per unit for total proceeds of $10.2 million,
including a contribution of $0.2 million from our general partner to maintain the 2% general partner economic interest it owned
at that time. Proceeds were used for general partnership purposes.
As a result of the Merger, in the third quarter of 2018, we issued approximately 13.4 million incremental NuStar Energy
common units in exchange for the previously outstanding Holdings units.
In the second quarter of 2017, we issued 14,375,000 common units at a price of $46.35 per unit. We used the net proceeds from
this offering of $657.5 million, including a contribution of $13.6 million from our general partner to maintain the 2% general
partner economic interest it owned at that time, to fund a portion of the purchase price for the Navigator Acquisition. Beginning
with the distribution earned for the second quarter of 2017, our general partner did not receive incentive distributions with
respect to these common units.
Preferred Units. In June and July of 2018, we issued a total of 23,246,650 Series D Preferred Units at a price of $25.38 per unit
in private placements for net proceeds of $555.8 million. The Series D Preferred Units contain various conversion and
redemption features. We used the net proceeds from the issuance of the Series D Preferred Units for general partnership
purposes, including repayment of outstanding borrowings under our Revolving Credit Agreement.
In the fourth quarter of 2017, we issued 6,900,000 of our 9.00% Series C Fixed-to-Floating Rate Cumulative Redeemable
Perpetual Preferred Units (Series C Preferred Units) representing limited partner interests at a price of $25.00 per unit. We used
the net proceeds of $166.7 million from the issuance of the Series C Preferred Units for general partnership purposes, including
the funding of capital expenditures and repayments of outstanding borrowings under the Revolving Credit Agreement.
In the second quarter of 2017, we issued 15,400,000 of our 7.625% Series B Fixed-to-Floating Rate Cumulative Redeemable
Perpetual Preferred Units (Series B Preferred Units) representing limited partner interests at a price of $25.00 per unit. We used
the net proceeds of $371.8 million from the issuance of the Series B Preferred Units to fund a portion of the purchase price for
the Navigator Acquisition and to pay related fees and expenses.
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 these issuances.
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Capital Requirements
Our operations require significant investments to maintain, upgrade or enhance the operating capacity of our existing assets.
Our capital expenditures consist of:
•
•
strategic capital expenditures, such as those to expand or upgrade the operating capacity, increase efficiency or
increase the earnings potential of existing assets, whether through construction or acquisition, as well as certain capital
expenditures related to support functions; and
reliability capital expenditures, such as those required to maintain the current operating capacity of existing assets or
extend their useful lives, as well as those required to maintain equipment reliability and safety.
The following table summarizes our capital expenditures for the past three years, and the amount we expect to spend in 2020:
Strategic
Acquisitions
Capital Expenditures
Reliability Capital
Expenditures
Total
(Thousands of Dollars)
For the year ended December 31:
2019
2018
2017
$
$
$
— $
$
37,502
1,461,719
$
466,996
380,298
327,141
$
$
$
66,572
77,154
57,497
$
$
$
533,568
494,954
1,846,357
Expected for the year ended
December 31, 2020
$ 300,000 - 350,000
$ 40,000 - 50,000
Strategic capital expenditures for the year ended December 31, 2019 mainly consisted of pipeline expansions on our Permian
Crude System, Northern Mexico refined products supply projects and an export project to connect our Corpus Christi North
Beach terminal to long-haul pipelines transporting crude oil from the Permian Basin. Strategic capital expenditures for the year
ended December 31, 2018 consisted of pipeline expansions on our Permian Crude System and projects at the St. Eustatius and
Linden terminals. Reliability capital expenditures primarily related to maintenance upgrade projects at our terminals, including
costs to repair the property damage at the St. Eustatius terminal.
For the year ended December 31, 2020, we expect a significant portion of our strategic capital spending to relate to our
expansion projects to accommodate production growth in the Permian Basin (on our Permian Crude System and Corpus Christi
Crude System), projects to handle bio-fuels demand on the West Coast and projects to increase flexibility at our St. James
terminal. We continue to evaluate our capital budget and make changes as economic conditions warrant, and our actual capital
expenditures for 2020 may increase or decrease from the expected amounts noted above. In addition, we are currently
evaluating reconstruction efforts related to a fire at our terminal facility in Selby, California, which could cause capital
expenditures to be higher than the expected amounts noted above; however, we expect to receive insurance proceeds that will
cover these capital expenditures. We believe cash on hand, combined with the sources of liquidity previously described, will be
sufficient to fund our capital expenditures in 2020, and our internal growth projects can be accelerated or scaled back
depending on market conditions or customer demand.
Working Capital Requirements
Working capital requirements are mainly affected by our accounts receivable and accounts payable balances, which vary
depending on the timing of payments.
During the year ended December 31, 2019, accounts receivable increased $23.5 million, mainly due to an insurance receivable
of $20.5 million associated with estimated insurance recoveries related to a fire at our terminal facility in Selby, California.
Please refer to Note 1 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary
Data” for additional information. Additionally, accrued liabilities decreased $19.6 million, mainly due to revenue recognized
during the period that was included in a contract liability at the beginning of the year, as discussed in Note 7 of the Notes to
Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data.”
During the year ended December 31, 2018, accrued liabilities increased $39.6 million, mainly due to the recognition of a
contract liability associated with a non-refundable one-time payment of storage fees from a customer. Please refer to Note 7 of
the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for additional
information. Additionally, accounts receivable decreased $22.5 million, mainly due to the sale of our European Operations in
the fourth quarter of 2018.
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During the year ended December 31, 2017, accounts payable decreased $30.4 million and inventories decreased $11.9 million,
primarily due to our exit from our heavy fuels trading and crude oil marketing operations in 2017.
Axeon Term Loan and Credit Support
On February 22, 2017, we settled and terminated the $190.0 million 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. We
received $110.0 million in settlement of the Axeon Term Loan, and our obligation to provide ongoing credit support to Axeon
ceased.
Defined Benefit Plans Funding
During 2019, we contributed $11.3 million to our pension and postretirement benefit plans. We expect to contribute
approximately $11.7 million to our pension and postretirement benefit plans in 2020, which principally represents contributions
either required by regulations or laws or, with respect to unfunded plans, necessary to fund current benefits. Pension and
postretirement benefit plans funding beyond 2020 is uncertain as the funding varies from year to year based upon changes in
the fair value of the plan assets and actuarial assumptions.
Distributions
General Partner and Common Limited Partners. Distribution payments are made to our common limited partners within
45 days after the end of each quarter as of a record date that is set after the end of each quarter. The following table summarizes
information about quarterly cash distributions to our common limited partners.
Quarter Ended
December 31, 2019
September 30, 2019
June 30, 2019
March 31, 2019
Cash
Distributions
Per Unit
Total Cash
Distributions
(Thousands of Dollars)
Record Date
Payment Date
$
$
$
$
0.60
0.60
0.60
0.60
$
$
$
$
65,128
February 10, 2020
February 14, 2020
64,660 November 8, 2019 November 14, 2019
64,658
64,690
August 7, 2019
August 13, 2019
May 8, 2019
May 14, 2019
Pursuant to the terms of our partnership agreement, prior to the Merger, the general partner received a 2% distribution with
respect to its general partner economic interest it owned at that time. The general partner was also entitled to incentive
distributions if the amount we distributed with respect to any quarter exceeded $0.60 per unit. For the first quarter of 2018, the
general partner did not receive incentive distributions because the distribution declared was $0.60 per common unit, which was
below the amount necessary to receive incentive distributions. Because the Merger was effective prior to the record date for the
distribution for the second quarter of 2018, the general partner received no distributions after the first quarter of 2018
distribution. Beginning with the second quarter of 2018, the common limited partners’ distribution includes the additional
common units issued in exchange for previously outstanding Holdings units because the Merger closed prior to the common
unit distribution record date for the second quarter of 2018. 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. For a discussion of
the incentive distribution targets prior to the Merger, please read Note 20 of the Notes to Consolidated Financial Statements in
Item 8. “Financial Statements and Supplementary Data.”
The following table reflects the allocation of total cash distributions to the general partner and common limited partners
applicable to the period in which the distributions were earned:
General partner interest
General partner incentive distribution
Total general partner distribution
Common limited partners’ distribution
Total cash distributions
Cash distributions per unit applicable to common limited partners
51
Year Ended December 31,
2019
2018
2017
(Thousands of Dollars, Except Per Unit Data)
$
$
$
— $
—
—
259,136
259,136
2.40
$
$
1,141
$
—
1,141
248,705
249,846
2.40
$
$
9,252
45,669
54,921
407,681
462,602
4.38
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Preferred Units. 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:
Fixed Distribution
Rate Per Annum (as a
Percentage of the
$25.00 Liquidation
Preference Per Unit)
Fixed
Distribution
Rate Per Unit
Per Annum
Units
Optional Redemption
Date/Date at Which
Distribution Rate
Becomes Floating
Floating Annual Rate (as a
Percentage of the
$25.00 Liquidation
Preference Per Unit)
Fixed
Distribution
Per Annum
(Thousands of
Dollars)
Series A Preferred Units
8.50% $
2.125
Series B Preferred Units
7.625% $
1.90625
Series C Preferred Units
9.00% $
2.25
$
$
$
19,252 December 15, 2021
29,357
June 15, 2022
15,525 December 15, 2022
Three-month LIBOR
plus 6.766%
Three-month LIBOR
plus 5.643%
Three-month LIBOR
plus 6.88%
As discussed above, in June and July of 2018, we issued an aggregate of 23,246,650 Series D Preferred Units. The distribution
rate on the 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. While the Series D
Preferred Units are outstanding, the Partnership will be prohibited from paying distributions on any junior securities, including
the common units, unless full cumulative distributions on the Series D Preferred Units (and any parity securities) have been, or
contemporaneously are being, paid or set aside for payment through the most recent Series D Preferred Unit distribution
payment date. Any Series D Preferred Unit distributions in excess of $0.635 may be paid, in the Partnership’s sole discretion, in
additional Series D Preferred Units, with the remainder paid in cash. If we fail to pay in full any Series D Preferred Unit
distribution amount, then, until we pay such distributions in full, the applicable distribution rate for those distribution periods
shall be increased by $0.048 per Series D Preferred Unit. We would also be subject to other requirements.
Distributions on our 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 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. Please see Notes 19 and 20 of the Notes to
Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for additional information.
In January 2020, our board of directors declared quarterly distributions with respect to the Series A, B and C Preferred Units
and the Series D Preferred Units to be paid on March 16, 2020.
Debt Obligations
As of December 31, 2019, we were a party to the following debt agreements:
•
•
•
•
•
Revolving Credit Agreement due October 29, 2021, with $475.0 million of borrowings outstanding as of
December 31, 2019;
4.80% senior notes due September 1, 2020 with a face value of $450.0 million; 6.75% senior notes due February 1,
2021 with a face value of $300.0 million; 4.75% senior notes due February 1, 2022 with a face value of $250.0
million; 6.0% senior notes due June 1, 2026 with a face value of $500.0 million; 5.625% senior notes due April 28,
2027 with a face value of $550.0 million; and subordinated notes due January 15, 2043 with a face value of $402.5
million and a floating interest rate;
$365.4 million in GoZone Bonds due from 2038 to 2041;
Line of credit agreement with $5.5 million of borrowings outstanding as of December 31, 2019; and
Receivables Financing Agreement due September 20, 2021, with $62.2 million of borrowings outstanding as of
December 31, 2019.
We expect to refinance senior note maturities in 2020 and 2021 by utilizing the capital markets, pursuing other sources of debt
financing or with funds available under our revolving credit agreement.
Effective January 15, 2018, the interest rate on NuStar Logistics’ $402.5 million of fixed-to-floating rate subordinated notes
due January 15, 2043 switched from a fixed annual rate of 7.625%, payable quarterly in arrears, to an annual rate equal to the
sum of the three-month LIBOR for the related quarterly interest period, plus 6.734% payable quarterly, commencing with the
interest payment due April 15, 2018. As of December 31, 2019, the interest rate was 8.7%.
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Management believes that, as of December 31, 2019, we are in compliance with the ratios and covenants contained in our debt
instruments. A default under certain of our debt agreements would be considered an event of default under other of our debt
instruments. Please refer to Note 14 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and
Supplementary Data” for a discussion of our debt agreements.
Credit Ratings
In the second quarter of 2019, our credit rating was downgraded by S&P Global Ratings from BB to BB-, and our outlook was
changed from negative to stable by the three credit rating agencies identified in the table below. Per the terms of the Revolving
Credit Agreement, these changes did not impact the interest rate on our Revolving Credit Agreement, which is the only debt
arrangement with an interest rate that is subject to adjustment if our debt rating is downgraded (or upgraded) by certain credit
rating agencies. The following table reflects the current outlook and ratings that have been assigned to our debt:
Ratings
Outlook
Fitch, Inc.
BB
Stable
Moody’s Investor
Service Inc.
Ba2
Stable
S&P Global Ratings
BB-
Stable
Interest Rate Swaps
As of December 31, 2019 and 2018, we were a party to forward-starting interest rate swap agreements that terminate in
September 2020, for the purpose of hedging interest rate risk. As of December 31, 2019 and 2018, the aggregate notional
amount of these forward-starting interest rate swaps was $250.0 million. In connection with the April 2018 maturity of the
7.65% senior notes, we terminated forward-starting interest rate swap agreements with an aggregate notional amount of $350.0
million and received $8.0 million. Please refer to Notes 2 and 18 of the Notes to Consolidated Financial Statements in Item 8.
“Financial Statements and Supplementary Data” and Item 7A. “Quantitative and Qualitative Disclosures about Market Risk”
for a more detailed discussion of our interest rate swaps.
The following table presents the aggregate notional amounts and fair values of the forward-starting interest rate swaps:
Notional amount
Fair value
December 31,
2019
2018
(Thousands of Dollars)
$
$
250,000
$
(19,169) $
250,000
(124)
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Long-Term Contractual Obligations
The following table presents our long-term contractual obligations and commitments and the related payments due, in total and
by period, as of December 31, 2019:
Payments Due by Period
2020
2021
2022
2023
2024
Thereafter
Total
(Thousands of Dollars)
Long-term debt maturities
Interest payments (a)
Operating leases (b)
Finance leases (b)
Purchase obligations (c)
Total
$ 450,000
183,704
$ 837,200
145,517
$ 250,000
111,559
12,647
6,702
9,419
5,252
8,717
4,582
$
— $
106,395
7,605
4,480
— $ 1,817,940
979,970
107,040
$ 3,355,140
1,634,185
6,739
4,067
60,354
59,681
105,481
84,764
8,935
$ 661,988
7,643
$1,005,031
6,202
$ 381,060
1,485
$ 119,965
812
$ 118,658
5,157
$ 2,923,102
30,234
$ 5,209,804
(a) The interest payments calculated for our variable-rate, long-term debt are based on interest rates and the outstanding borrowings as
of December 31, 2019. The interest payments on our fixed-rate debt are based on the stated interest rates and the outstanding
borrowings as of December 31, 2019.
(b) Our operating leases consist primarily of land and dock leases at various terminal facilities. Our finance leases consist primarily of
a dock lease at a terminal facility with an initial term of five years and four additional five-year renewal periods that also includes a
commitment for minimum dockage and wharfage throughput volumes. Please see Note 17 of the Notes to Consolidated Financial
Statements in Item 8. “Financial Statements and Supplementary Data” for additional information.
(c) A purchase obligation is an enforceable and legally binding agreement to purchase goods or services that specifies significant
terms, including (i) fixed or minimum quantities to be purchased, (ii) fixed, minimum or variable price provisions and (iii) the
approximate timing of the transaction.
We also have pension and other postretirement benefit obligations recorded in “Other long-term liabilities” on our consolidated
balance sheets which have been excluded from the contractual obligations table above due to the uncertainty in timing as to the
future cash flows related to these obligations. For additional information on our pension and other postretirement benefit
obligations see Note 23 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary
Data.”
Environmental, Health and Safety
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. Because more stringent environmental and safety
laws and regulations are continuously being enacted or proposed, the level of expenditures required for environmental, health
and safety matters is expected to increase in the future.
The balance of and changes in our accruals for environmental matters as of and for the years ended December 31, 2019 and
2018 are included in Note 15 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and
Supplementary Data.” We believe that we have adequately accrued for our environmental exposures.
Contingencies
We are subject to certain loss contingencies, and we believe that the resolution of any particular claim or proceeding, or all
matters in the aggregate, would not have a material adverse effect on our results of operations, financial position or liquidity, as
further disclosed in Note 16 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and
Supplementary Data.”
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CRITICAL ACCOUNTING POLICIES
The preparation of financial statements in accordance with U.S. generally accepted accounting principles requires management
to select accounting policies and to make estimates and assumptions related thereto that affect the amounts reported in the
consolidated financial statements and accompanying notes. Actual results could differ from those estimates. The accounting
policies below are considered critical due to judgments made by management and the sensitivity of these estimates to
deviations of actual results from management’s assumptions. The critical accounting policies should be read in conjunction
with Note 2 of the Notes to the Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data,”
which summarizes our significant accounting policies.
Impairment of Long-Lived Assets
We test long-lived assets for recoverability whenever events or changes in circumstances indicate that the carrying amount of
the asset may not be recoverable. We evaluate recoverability using undiscounted estimated net cash flows generated by the
related asset or asset group. If the results of that evaluation indicate that the undiscounted cash flows are less than the carrying
amount of the asset (i.e., the asset is not recoverable) we perform an impairment analysis. If our intent is to hold the asset for
continued use, we determine the amount of impairment as the amount by which the net carrying value exceeds its fair value. If
our intent is to sell the asset, and the criteria required to classify an asset as held for sale are met, we determine the amount of
impairment as the amount by which the net carrying amount exceeds its fair value less costs to sell.
In determining the existence of an impairment of the carrying value of an asset, we make a number of subjective assumptions
as to:
•
whether there is an event or circumstance that may indicate that the carrying amount of an asset may not be
recoverable;
the grouping of assets;
the intention of holding, abandoning or selling an asset;
the forecast of undiscounted expected future cash flows with respect to an asset or asset group; and
if an impairment exists, the fair value of the asset or asset group.
•
•
•
•
Our estimates of undiscounted future cash flows include: (i) discrete financial forecasts, which rely on management’s estimates
of revenue and operating expenses; (ii) long-term growth rates; and (iii) estimates of useful lives of the assets. The
identification of impairment indicators and the estimates of future undiscounted cash flows are highly subjective and are based
on numerous assumptions about future operations and market conditions, which we believe to be reasonable but are inherently
uncertain. The uncertainties underlying our assumptions and estimates could differ significantly from actual results and could
cause a different conclusion about the recoverability of our assets. If that were to occur, and we determined an asset was
impaired, the amount of impairment could be material to our results of operations.
We recorded long-lived asset impairment charges of $305.7 million in 2019. Please refer to Note 5 of the Notes to Consolidated
Financial Statements in Item 8. “Financial Statements and Supplementary Data,” for discussion of the impairment charges.
Impairment of Goodwill
We perform an assessment of goodwill annually or more frequently if events or changes in circumstances warrant. We have the
option to first perform a qualitative annual assessment to determine whether it is necessary to perform a quantitative goodwill
impairment test. A qualitative assessment includes, among other things, industry and market considerations, overall financial
performance, other entity-specific events and events affecting individual reporting units. If after assessing the totality of events
or circumstances for each reporting unit, we determine that it is more likely than not that the carrying value exceeds its fair
value, then we would perform an impairment test for that reporting unit. We performed a qualitative assessment as of
October 1, 2019, and determined it was not more likely than not that the estimated fair value of each reporting unit exceeded its
carrying value; thus, goodwill was not impaired.
We recognize an impairment of goodwill if the carrying value of goodwill exceeds its estimated fair value. In order to estimate
the fair value of goodwill, management must make certain estimates and assumptions that affect the total fair value of the
reporting unit including, among other things, an assessment of market conditions, projected cash flows, discount rates and
growth rates. Management’s estimates of projected cash flows related to the reporting unit include, but are not limited to, future
earnings of the reporting unit, assumptions about the use or disposition of the asset, estimated remaining life of the asset, and
future expenditures necessary to maintain the asset’s existing service potential.
We calculate the estimated fair value of each of our reporting units using a weighted-average of values calculated using an
income approach and a market approach. The income approach involves estimating the fair value of each reporting unit by
discounting its estimated future cash flows using a discount rate, consistent with a market participant’s assumption. The market
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approach bases the fair value measurement on information obtained from observed stock prices of public companies and recent
merger and acquisition transaction data of comparable entities.
Our reporting units to which goodwill has been allocated consist of the following as of October 1, 2019:
•
•
•
crude oil pipelines;
refined product pipelines; and
terminals, excluding our Point Tupper facility and our refinery crude storage tanks.
We recognized a goodwill impairment charge of $31.1 million in the first quarter of 2019. Please refer to Note 5 of the Notes to
Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data,” for discussion of the impairment
charges.
Derivative Financial Instruments
We utilize various derivative instruments to manage our exposure to interest rate risk and commodity price risk. We record
derivative instruments in the consolidated balance sheets at fair value, and apply hedge accounting when appropriate. We
record changes to the fair values of derivative instruments in earnings for fair value hedges or as part of accumulated other
comprehensive income (AOCI) for the effective portion of cash flow hedges. We reclassify the effective portion of cash flow
hedges from AOCI to earnings when the underlying forecasted transaction occurs or becomes probable not to occur. We
recognize ineffectiveness resulting from our derivatives immediately in earnings. With respect to cash flow hedges, we must
exercise judgment to assess the probability of the forecasted transaction, which, among other things, depends upon market
factors and our ability to reliably operate our assets.
Defined Benefit Plans
We estimate pension and other postretirement benefit obligations and costs based on actuarial valuations. The annual
measurement date for our pension and other postretirement benefit plans is December 31. The actuarial valuations require the
use of certain assumptions including discount rates, expected long-term rates of return on plan assets and expected rates of
compensation increase. Changes in these assumptions are primarily influenced by factors outside our control. The discount rate
is based on a hypothetical yield curve represented by a series of annualized individual discount rates. Each bond issue
underlying the hypothetical yield curve required an average rating of double-A, when averaging all available ratings by
Moody’s Investor Service Inc., S&P Global Ratings and Fitch, Inc. The expected long-term rate of return on plan assets is
based on the weighted averages of the expected long-term rates of return for each asset class of investments held in our plans as
determined using historical data and the assumption that capital markets are informationally efficient. The expected rate of
compensation increase represents average long-term salary increases.
These assumptions can have an effect on the amounts reported in our consolidated financial statements. A 0.25% change in the
specified assumptions would have the following effects (thousands of dollars):
Increase in benefit obligation as of December 31, 2019 from:
Discount rate decrease
Compensation rate increase
Increase in net periodic benefit cost for the year ending
December 31, 2020 resulting from:
Discount rate decrease
Expected long-term rate of returns on plan assets decrease
Compensation rate increase
Pension
Benefits
Other
Postretirement
Benefits
$
$
$
$
$
5,800
$
1,500
$
300
400
400
500
n/a
100
n/a
n/a
Please refer to Note 23 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary
Data” for further discussion of our pension and other postretirement benefit obligations.
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Environmental Liabilities
Environmental remediation costs are expensed and an associated accrual is established when site restoration and environmental
remediation and cleanup obligations are either known or considered probable and can be reasonably estimated. These
environmental obligations are based on estimates of probable undiscounted future costs using currently available technology
and applying current regulations, as well as our own internal environmental policies. The environmental liabilities have not
been reduced by possible recoveries from third parties. Environmental costs include initial site surveys, costs for remediation
and restoration and ongoing monitoring costs, as well as fines, damages and other costs, when estimable. Adjustments to initial
estimates are recorded, from time to time, to reflect changing circumstances and estimates based upon additional information
developed in subsequent periods. Environmental liabilities are difficult to assess and estimate due to unknown factors, such as
the timing and extent of remediation, the determination of our liability in proportion to other parties, improvements in cleanup
technologies and the extent to which environmental laws and regulations may change in the future. We believe that we have
adequately accrued for our environmental exposures.
Contingencies
We accrue for costs relating to litigation, claims and other contingent matters when such liabilities become probable and
reasonably estimable. Such estimates may be based on advice from third parties or on management’s judgment, as appropriate.
Due to the inherent uncertainty of litigation, actual amounts paid may differ from amounts estimated, and such differences will
be charged to income in the period when final determination is made.
NEW ACCOUNTING PRONOUNCEMENTS
Please refer to Note 3 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary
Data” for a discussion of new accounting pronouncements.
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ITEM 7A.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
We manage our exposure to changing interest rates principally through the use of a combination of fixed-rate debt and variable-
rate debt. In addition, we utilize forward-starting interest rate swap agreements to lock in the rate on the interest payments
related to forecasted debt issuances. Borrowings under our variable-rate debt expose us to increases in interest rates. Since the
operations of our fuels marketing segment expose us to commodity price risk, we use derivative instruments to attempt to
mitigate the effects of commodity price fluctuations. Derivative financial instruments associated with commodity price risk
were not material for any period presented.
Please refer to Notes 2 and 18 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and
Supplementary Data” for a more detailed discussion of our interest rate swaps. The following tables present principal cash
flows and related weighted-average interest rates by expected maturity dates for our long-term debt, excluding finance leases:
December 31, 2019
Expected Maturity Dates
2020
2021
2022
2023
2024
There-
after
Total
Fair
Value
(Thousands of Dollars, Except Interest Rates)
Long-term Debt:
Fixed-rate
Weighted-average
rate
Variable-rate
Weighted-average
rate
$ 450,000
$ 300,000
$ 250,000
$
— $
— $ 1,050,000
$ 2,050,000
$ 2,123,964
4.8%
6.8%
4.8%
—
—
5.8%
5.6%
—
$
— $ 537,200
$
— $
— $
— $ 767,940
$ 1,305,140
$ 1,318,037
—
3.7%
—
—
—
5.3%
4.7%
—
December 31, 2018
Expected Maturity Dates
2019
2020
2021
2022
2023
There-
after
Total
Fair
Value
(Thousands of Dollars, Except Interest Rates)
Long-term Debt:
Fixed-rate
Weighted-average
rate
Variable-rate
Weighted-average
rate
$
$
— $ 450,000
$ 300,000
$ 250,000
$
— $ 550,000
$ 1,550,000
$ 1,499,920
—
4.8%
6.8%
4.8%
—
5.6%
5.5%
—
— $ 806,800
$
— $
— $
— $ 767,940
$ 1,574,740
$ 1,556,784
—
4.4%
—
—
—
5.6%
5.0%
—
The following table presents information regarding our forward-starting interest rate swap agreements:
Notional Amount as of December 31,
2019
2018
Period of Hedge
Weighted-Average
Fixed Rate
(Thousands of Dollars)
Fair Value as of December 31,
2019
2018
(Thousands of Dollars)
$
250,000
$
250,000
09/2020 - 09/2030
2.8% $
(19,169) $
(124)
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ITEM 8.
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Management’s Report on Internal Control over Financial Reporting
Our management is responsible for establishing and maintaining effective internal control over financial reporting as defined in
Rule 13a-15(f) under the Securities Exchange Act of 1934. Our management assessed the effectiveness of NuStar Energy L.P.’s
internal control over financial reporting as of December 31, 2019. In its evaluation, management used the criteria set forth by
the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control-Integrated Framework
(2013). Based on this assessment, management believes that, as of December 31, 2019, our internal control over financial
reporting was effective based on those criteria.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Therefore,
even those systems determined to be effective can provide only reasonable assurance with respect to financial statement
preparation and presentation.
The effectiveness of internal control over financial reporting as of December 31, 2019 has been audited by KPMG LLP, the
independent registered public accounting firm who audited our consolidated financial statements included in this Form 10-K.
KPMG LLP’s attestation on the effectiveness of our internal control over financial reporting appears on page 62.
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Report of Independent Registered Public Accounting Firm
The Board of Directors of NuStar GP, LLC
and Unitholders of NuStar Energy L.P.:
Opinion on the Consolidated Financial Statements
We have audited the accompanying consolidated balance sheets of NuStar Energy L.P. and subsidiaries (the Partnership) as of
December 31, 2019 and 2018, the related consolidated statements of (loss) income, comprehensive (loss) income, partners’
equity and mezzanine equity, and cash flows for each of the years in the three‑year period ended December 31, 2019, and the
related notes (collectively, the consolidated financial statements). In our opinion, the consolidated financial statements present
fairly, in all material respects, the financial position of the Partnership as of December 31, 2019 and 2018, and the results of its
operations and its cash flows for each of the years in the three‑year period ended December 31, 2019, in conformity with
U.S. generally accepted accounting principles.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States)
(PCAOB), the Partnership’s internal control over financial reporting as of December 31, 2019, based on criteria established in
Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway
Commission, and our report dated February 27, 2020 expressed an unqualified opinion on the effectiveness of the Partnership’s
internal control over financial reporting.
Basis for Opinion
These consolidated financial statements are the responsibility of the Partnership’s management. Our responsibility is to express
an opinion on these consolidated financial statements based on our audits. We are a public accounting firm registered with the
PCAOB and are required to be independent with respect to the Partnership in accordance with the U.S. federal securities laws
and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the
audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement,
whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the
consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such
procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial
statements. Our audits also included evaluating the accounting principles used and significant estimates made by management,
as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a
reasonable basis for our opinion.
Critical Audit Matter
The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial
statements that was communicated or required to be communicated to the audit committee and that: (1) relates to accounts or
disclosures that are material to the consolidated financial statements and (2) involved our especially challenging, subjective, or
complex judgment. The communication of a critical audit matter does not alter in any way our opinion on the consolidated
financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing separate
opinions on the critical audit matter or on the accounts or disclosures to which it relates.
Assessment of the Identification of Triggering Events Related to the Recoverability of Certain Long-Lived Assets or
Asset Groups
As discussed in Note 2, the Partnership tests long-lived assets, including property, plant and equipment, for
impairment whenever triggering events indicate that the carrying amount may not be recoverable. The Partnership
evaluates recoverability using undiscounted estimated net cash flows generated by the related asset or asset group
considering the intended use of the asset. The carrying value of the Partnership’s long-lived assets or asset groups are
generally supported by revenue generating contracts or historically consistent revenue generating activities, making
the triggering event assessment not complex. The balance of property, plant and equipment, net as of December 31,
2019 was $4,119 million, or 66.6% of total assets.
We identified the assessment of the identification of triggering events related to the recoverability of certain long-lived
assets or asset groups as a critical audit matter. There were certain long-lived assets or asset groups that were not
supported by existing revenue-generating contracts or activities resulting in negative cash flows. Assessment of the
identification of triggering events for these assets or asset groups required challenging auditor judgment as the
assessment included subjective qualitative considerations, such as evaluating alternative customers, alternative uses
for the asset or asset group or the Partnership’s intent for the asset or asset group.
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The primary procedures we performed to address this critical audit matter included the following. We tested certain
internal controls over the Partnership’s triggering event assessment, including controls over the identification of long-
lived asset groups that would be at greater risk for a triggering event and evaluation of the qualitative considerations in
assessing the identification of a triggering event. We examined the Partnership’s analysis of the long-lived assets and
asset groups identified to be evaluated for a potential triggering event and assessed the factors considered in
determining the identification of a triggering event. We evaluated the Partnership’s responses to the factors considered,
including alternate customers, alternative uses for the assets or asset group, and the Partnership’s intent for the assets
or asset group by evaluating internal and external documentation. Documentation evaluated included internal
presentations, draft customer contracts, publicly available market data, and communications between the Partnership
and potential customers.
/s/ KPMG LLP
We have served as the Partnership’s auditor since 2004.
San Antonio, Texas
February 27, 2020
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Report of Independent Registered Public Accounting Firm
The Board of Directors of NuStar GP, LLC
and Unitholders of NuStar Energy L.P.:
Opinion on Internal Control Over Financial Reporting
We have audited NuStar Energy L.P. and subsidiaries’ (the Partnership) internal control over financial reporting as of
December 31, 2019, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee
of Sponsoring Organizations of the Treadway Commission. In our opinion, the Partnership maintained, in all material respects,
effective internal control over financial reporting as of December 31, 2019, based on criteria established in Internal Control -
Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States)
(PCAOB), the consolidated balance sheets of the Partnership as of December 31, 2019 and 2018, the related consolidated
statements of (loss) income, comprehensive (loss) income, partners’ equity and mezzanine equity, and cash flows for each of
the years in the three-year period ended December 31, 2019, and the related notes (collectively, the consolidated financial
statements), and our report dated February 27, 2020 expressed an unqualified opinion on those consolidated financial
statements.
Basis for Opinion
The Partnership’s management is responsible for maintaining effective internal control over financial reporting and for its
assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s
Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Partnership’s internal
control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are
required to be independent with respect to the Partnership in accordance with the U.S. federal securities laws and the applicable
rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the
audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all
material respects. Our audit of internal control over financial reporting included obtaining an understanding of internal control
over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating
effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we
considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
Definition and Limitations of Internal Control Over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the
reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally
accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures
that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and
dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit
preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and
expenditures of the company are being made only in accordance with authorizations of management and directors of the
company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or
disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also,
projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate
because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
San Antonio, Texas
February 27, 2020
/s/ KPMG LLP
62
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NUSTAR ENERGY L.P. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Thousands of Dollars, Except Unit Data)
Current assets:
Assets
Cash and cash equivalents
Accounts receivable, net of allowance for doubtful accounts of $72 and $9,412
as of December 31, 2019 and 2018, respectively
Inventories
Prepaid and other current assets
Assets held for sale
Total current assets
Property, plant and equipment, at cost
Accumulated depreciation and amortization
Property, plant and equipment, net
Intangible assets, net
Goodwill
Other long-term assets, net
Total assets
Liabilities, Mezzanine Equity and Partners’ Equity
Current liabilities:
Accounts payable
Short-term debt and current portion of finance leases
Current portion of long-term debt
Accrued interest payable
Accrued liabilities
Taxes other than income tax
Income tax payable
Liabilities held for sale
Total current liabilities
Long-term debt, less current portion
Deferred income tax liability
Other long-term liabilities
Total liabilities
Commitments and contingencies (Note 16)
December 31,
2019
2018
$
16,192
$
11,529
$
$
152,530
12,393
21,933
—
203,048
6,187,144
(2,068,165)
4,118,979
681,632
1,005,853
176,480
6,185,992
109,834
10,046
452,367
37,925
104,285
12,781
4,325
—
731,563
2,934,918
12,427
148,939
3,827,847
$
$
110,417
8,434
17,374
599,347
747,101
5,627,805
(1,853,003)
3,774,802
733,056
1,005,853
88,328
6,349,140
103,122
18,500
—
36,293
74,418
16,823
4,445
69,834
323,435
3,111,996
12,428
79,558
3,527,417
Series D preferred limited partners (23,246,650 preferred units outstanding as of
December 31, 2019 and 2018) (Note 19)
581,935
563,992
Partners’ equity (Note 20):
Series A (9,060,000 units outstanding as of December 31, 2019 and 2018)
Series B (15,400,000 units outstanding as of December 31, 2019 and 2018)
Series C (6,900,000 units outstanding as of December 31, 2019 and 2018)
Common limited partners (108,527,806 and 107,225,156 common units outstanding
as of December 31, 2019 and 2018, respectively)
Accumulated other comprehensive loss
Total partners’ equity
Total liabilities, mezzanine equity and partners’ equity
218,307
371,476
166,518
218,307
371,476
166,518
1,087,805
(67,896)
1,776,210
6,185,992
$
1,556,308
(54,878)
2,257,731
6,349,140
$
See Notes to Consolidated Financial Statements.
63
NUSTAR ENERGY L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF (LOSS) INCOME
(Thousands of Dollars, Except Unit and Per Unit Data)
Table of Contents
Revenues:
Service revenues
Product sales
Total revenues
Costs and expenses:
Costs associated with service revenues:
Operating expenses (excluding depreciation and amortization expense)
Depreciation and amortization expense
Total costs associated with service revenues
Cost of product sales
General and administrative expenses (excluding depreciation and
amortization expense)
Other depreciation and amortization expense
Total costs and expenses
Operating income
Interest expense, net
Other income (expense), net
Income from continuing operations before income tax expense
Income tax expense
Income from continuing operations
(Loss) income from discontinued operations, net of tax
Net (loss) income
Basic and diluted net income (loss) per common unit:
Continuing operations
Discontinued operations
Total (Note 21)
Year Ended December 31,
2019
2018
2017
$ 1,148,167
349,854
1,498,021
$ 1,045,130
475,132
1,520,262
$
955,446
489,326
1,444,772
404,682
264,564
669,246
321,644
107,855
8,360
1,107,105
390,916
(183,070)
3,742
211,588
4,754
206,834
(312,527)
(105,693) $
378,962
247,288
626,250
449,613
100,067
8,604
1,184,534
335,728
(184,398)
5,202
156,532
10,157
146,375
59,419
205,794
$
332,723
219,757
552,480
485,791
107,556
8,435
1,154,262
290,510
(171,774)
(68)
118,668
7,773
110,895
37,069
147,964
$
0.60
(2.90)
(2.30) $
(3.34) $
0.57
(2.77) $
0.23
0.41
0.64
$
$
$
Basic weighted-average common units outstanding
Diluted weighted-average common units outstanding
107,789,030
99,490,495
88,825,964
107,854,699
99,531,172
88,825,964
See Notes to Consolidated Financial Statements.
64
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NUSTAR ENERGY L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE (LOSS) INCOME
(Thousands of Dollars)
Net (loss) income
Other comprehensive income (loss):
Foreign currency translation adjustment
Net (loss) gain on pension and other postretirement benefit adjustments, net
of income tax benefit (expense) of $14, ($94) and $184
Net (loss) gain on cash flow hedges
Total other comprehensive (loss) income
Year Ended December 31,
2019
(105,693) $
2018
205,794
$
2017
147,964
$
3,527
4,304
17,466
(1,314)
(15,231)
(13,018)
2,334
23,411
30,049
(6,170)
(2,046)
9,250
Comprehensive (loss) income
$
(118,711) $
235,843
$
157,214
See Notes to Consolidated Financial Statements.
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NUSTAR ENERGY L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Thousands of Dollars)
Cash Flows from Operating Activities:
Net (loss) income
Adjustments to reconcile net (loss) income to net cash provided by
operating activities:
Depreciation and amortization expense
Amortization of unit-based compensation
Amortization of debt related items
Loss from sale or disposition of assets
Gain from insurance recoveries
Asset and goodwill impairment losses
Deferred income tax (benefit) expense
Changes in current assets and current liabilities (Note 22)
Decrease (increase) in other long-term assets
(Decrease) increase in other long-term liabilities
Other, net
Net cash provided by operating activities
Cash Flows from Investing Activities:
Capital expenditures
Change in accounts payable related to capital expenditures
Acquisitions
Proceeds from Axeon term loan
Proceeds from insurance recoveries
Proceeds from sale or disposition of assets
Other, net
Net cash used in investing activities
Cash Flows from Financing Activities:
Proceeds from long-term debt borrowings
Proceeds from short-term debt borrowings
Proceeds from note offering, net of issuance costs
Long-term debt repayments
Short-term debt repayments
Proceeds from issuance of Series D preferred units
Payment of issuance costs for Series D preferred units
Proceeds from issuance of other preferred units, net of issuance costs
Proceeds from issuance of common units, net of issuance costs
Contributions from general partner
Distributions to preferred unitholders
Distributions to common unitholders and general partner
Cash consideration for Merger (Note 4)
Proceeds from termination of interest rate swaps
Payment of tax withholding for unit-based compensation
(Decrease) increase in cash book overdrafts
Other, net
Net cash (used in) provided by financing activities
Effect of foreign exchange rate changes on cash
Net increase (decrease) in cash, cash equivalents and restricted cash
Cash, cash equivalents and restricted cash as of the beginning of the period
Cash, cash equivalents and restricted cash as of the end of the period
$
See Notes to Consolidated Financial Statements.
66
Year Ended December 31,
2019
2018
2017
$
(105,693) $
205,794
$
147,964
281,460
14,386
5,209
3,499
—
336,838
(476)
(44,765)
22,020
(1,407)
(2,314)
508,757
(533,568)
(12,731)
—
—
—
228,152
(1,100)
(319,247)
659,300
307,500
491,580
(928,900)
(320,500)
—
—
—
15,000
—
(121,693)
(258,354)
—
—
(8,771)
(3,752)
(9,060)
(177,650)
(524)
11,336
13,644
24,980
297,874
12,004
7,388
41,272
(78,756)
—
2,043
78,262
(3,029)
(17,832)
(813)
544,207
(457,452)
(7,683)
(37,502)
—
78,419
270,440
—
(153,778)
1,254,153
618,500
—
(1,746,776)
(635,000)
590,000
(34,203)
—
10,000
204
(90,670)
(300,777)
(67,795)
8,048
(2,083)
2,935
(6,403)
(399,867)
(1,210)
(10,648)
24,292
13,644
264,232
8,132
6,147
4,984
—
—
6
(26,493)
943
2,414
(1,530)
406,799
(384,638)
36,903
(1,461,719)
110,000
977
2,036
—
(1,696,441)
1,465,767
1,051,000
543,333
(1,417,539)
(1,070,000)
—
—
538,560
643,878
13,737
(38,833)
(446,306)
—
—
(2,838)
1,736
(6,223)
1,276,272
1,720
(11,650)
35,942
24,292
$
$
Table of Contents
NUSTAR ENERGY L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF PARTNERS’ EQUITY AND MEZZANINE EQUITY
(Thousands of Dollars, Except Per Unit Data)
Limited Partners
Preferred
Common
General
Partner
Accumulated
Other
Comprehensive
Loss
Total
Partners’
Equity
(Note 20)
Mezzanine
Equity
Series D
Preferred
Limited
Partners
(Note 19)
Total
Balance as of January 1, 2017
$ 218,400
$ 1,455,642
$
31,752
$
(94,177) $ 1,611,617
$
— $ 1,611,617
40,448
60,610
46,906
—
147,964
Balance as of December 31, 2017
756,603
1,770,587
Net income
Other comprehensive income
Distributions to partners:
Series A, B and C preferred
Common ($4.38 per unit)
and general partner
Issuance of common units,
including contribution
from general partner
Issuance of preferred units
Unit-based compensation
Other
Net income
Other comprehensive income
Distributions to partners:
Series A, B and C preferred
Common ($2.895 per unit)
and general partner
Series D preferred
Issuance of common units,
including contribution
from general partner
Issuance of Series D preferred
units
Unit-based compensation
Adjustments related to the Merger
(refer to Note 4 for discussion)
Series D Preferred Unit accretion
Other
—
140
—
37,826
2,466
—
—
—
(40,448)
—
—
538,560
—
(357)
—
—
—
—
(391,737)
(54,569)
643,878
13,597
—
2,516
(322)
64,091
110,788
—
(64,091)
—
—
—
—
—
—
—
—
—
(302)
(286,398)
—
(14,379)
—
10,000
—
7,925
204
—
—
(41,973)
(25,999)
(8,195)
(6,426)
—
(118)
9,250
9,250
—
—
—
—
—
—
(40,448)
(446,306)
657,475
538,560
2,656
(679)
(84,927)
2,480,089
—
—
—
—
—
—
—
—
—
—
—
147,964
9,250
(40,448)
(446,306)
657,475
538,560
2,656
(679)
2,480,089
205,794
30,049
(64,091)
—
177,345
28,449
30,049
30,049
—
—
—
—
—
—
—
—
—
(64,091)
(300,777)
—
—
(28,449)
(300,777)
(28,449)
10,204
—
10,204
—
555,797
555,797
7,925
(67,972)
(8,195)
(6,846)
—
—
8,195
—
7,925
(67,972)
—
(6,846)
Balance as of December 31, 2018
756,301
1,556,308
Net income (loss)
Other comprehensive loss
Distributions to partners:
Series A, B and C preferred
Common ($2.40 per unit)
Series D preferred
Issuance of common units
Unit-based compensation
Series D Preferred Unit accretion
Other
64,134
(227,386)
—
—
(64,134)
—
—
—
—
—
—
—
(258,354)
—
15,000
20,766
(18,085)
(444)
—
—
—
—
—
—
—
—
—
—
(54,878)
2,257,731
563,992
2,821,723
—
(163,252)
57,559
(105,693)
(13,018)
(13,018)
—
(13,018)
—
—
—
—
—
—
—
(64,134)
(258,354)
—
15,000
20,766
—
—
(57,559)
—
(64,134)
(258,354)
(57,559)
15,000
—
20,766
(18,085)
18,085
(444)
(142)
—
(586)
Balance as of December 31, 2019
$ 756,301
$ 1,087,805
$
— $
(67,896) $ 1,776,210
$ 581,935
$ 2,358,145
See Notes to Consolidated Financial Statements.
67
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NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Years Ended December 31, 2019, 2018 and 2017
1. ORGANIZATION AND OPERATIONS
Organization
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 business is managed under the direction of the board of directors of NuStar
GP, LLC, the general partner of our general partner, Riverwalk Logistics, L.P., both of which are wholly owned subsidiaries of
NuStar GP Holdings, LLC (Holdings), which became a wholly owned subsidiary of ours on July 20, 2018.
Recent Developments
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). In 2019, we recorded
long-lived asset and goodwill impairment charges totaling $336.8 million related to the St. Eustatius Operations in “(Loss)
income from discontinued operations, net of tax” on our consolidated statement of loss. In the second quarter of 2019, we
determined the St. Eustatius Operations and the European operations, as discussed below, 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 for additional
discussion.
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.
Other Events
Sale of European Operations. On November 30, 2018, we sold our European operations for approximately $270.0 million (the
European Disposition). The operations sold included six liquids storage terminals in the United Kingdom and one facility in
Amsterdam with total storage capacity of approximately 9.5 million barrels (the European Operations). 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 for further discussion.
Merger. On July 20, 2018, we completed the merger of Holdings with a subsidiary of NS. Under the terms of the merger
agreement, Holdings unitholders received 0.55 of a common unit representing a limited partner interest in NS in exchange for
each Holdings unit owned at the effective time of the merger. Please refer to Note 4 for further discussion of the merger.
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 recorded a $5.0 million loss for property damage at the terminal, which represents the amount of our property
deductible under our insurance policy, and we received insurance proceeds of $12.5 million, 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 statement 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 and the gain are included in
“(Loss) income from discontinued operations, net of tax” in the consolidated statements of (loss) income.
Navigator Acquisition and Financing Transactions. On May 4, 2017, we acquired Navigator Energy Services, LLC for
approximately $1.5 billion (the Navigator Acquisition). In order to fund the purchase price, we issued 14,375,000 common
units for net proceeds of $657.5 million, issued $550.0 million of 5.625% senior notes for net proceeds of $543.3 million and
issued 15,400,000 of our 7.625% Series B Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units (Series B
Preferred Units) for net proceeds of $371.8 million. Please refer to Notes 6, 14 and 20 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
68
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NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
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, L.P. (NuStar Logistics) and NuStar Pipeline
Operating Partnership L.P. (NuPOP). We have three business segments: pipeline, storage and fuels marketing.
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
product pipelines, consisting of the East and North Pipelines, and a 2,000-mile ammonia pipeline, which comprise our Central
East System. The East and North Pipelines have storage capacity of approximately 7.4 million barrels. 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.
Storage. We own terminal and storage facilities in the United States, Canada and Mexico, with approximately 61.3 million
barrels of storage capacity. Our terminal and storage facilities provide storage, handling and other services on a fee basis for
petroleum products, crude oil, specialty chemicals and other liquids.
Fuels Marketing. Prior to the third quarter of 2017, our fuels marketing operations involved the purchase of crude oil, fuel oil,
bunker fuel, fuel oil blending components and other refined products for resale. We ceased marketing crude oil in the second
quarter of 2017 and exited our heavy fuels trading operations in the third quarter of 2017. These actions were in line with our
goal of reducing our exposure to commodity margins, and instead focusing on our core, fee-based pipeline and storage
segments. The remaining operations in our fuels marketing segment include our bunkering operations in the Gulf Coast, as well
as certain of our blending operations associated with our Central East System.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Consolidation
The accompanying consolidated financial statements represent the consolidated operations of the Partnership and our
subsidiaries. Inter-partnership balances and transactions have been eliminated in consolidation. The operations of certain
pipelines and terminals in which we own an undivided interest are proportionately consolidated in the accompanying
consolidated financial statements.
Use of Estimates
The preparation of consolidated financial statements in conformity with U.S. generally accepted accounting principles (GAAP)
requires management to make estimates and assumptions that affect the amounts reported in the consolidated financial
statements and accompanying notes. Actual results could differ from those estimates. On an ongoing basis, management
reviews its estimates based on currently available information. Management may revise estimates due to changes in facts and
circumstances.
Cash and Cash Equivalents
Cash equivalents are all highly liquid investments with an original maturity of three months or less when acquired.
Accounts Receivable
Trade receivables are carried at original invoice amount. We extend credit terms to certain customers after review of various
credit indicators, including the customer’s credit rating. Outstanding customer receivable balances are regularly reviewed for
possible non-payment indicators and allowances for doubtful accounts are recorded based upon management’s estimate of
collectability at the time of its review.
Inventories
Inventories consist of petroleum products, materials and supplies. Inventories, except those associated with a qualifying fair
value hedge, are valued at the lower of cost or net realizable value. Cost is determined using the weighted-average cost method.
Our inventory, other than materials and supplies, consists of one end-product category, petroleum products, which we include
in the fuels marketing segment. Accordingly, we determine lower of cost or net realizable value adjustments on an aggregate
basis. Inventories associated with qualifying fair value hedges are valued at current market prices. Materials and supplies are
valued at the lower of average cost or net realizable value.
69
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NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Restricted Cash
As of December 31, 2019, we have restricted cash representing legally restricted funds that are unavailable for general use
totaling $8.8 million, which is included in “Other long-term assets, net” on the consolidated balance sheet.
Property, Plant and Equipment
We record additions to property, plant and equipment, including reliability and strategic capital expenditures, at cost. Repair
and maintenance costs associated with existing assets that are minor in nature and do not extend the useful life of existing
assets are charged to operating expenses as incurred. Depreciation of property, plant and equipment is recorded on a straight-
line basis over the estimated useful lives of the related assets. When property or equipment is retired, sold or otherwise
disposed of, the difference between the carrying value and the net proceeds is recognized in “Other income (expense), net” or
“(Loss) income from discontinued operations, net of tax” in the consolidated statements of (loss) income in the year of
disposition.
We capitalize overhead costs and interest costs incurred on funds used to construct property, plant and equipment while the
asset is under construction. The overhead costs and capitalized interest are recorded as part of the asset to which they relate and
are amortized over the asset’s estimated useful life as a component of depreciation expense.
Goodwill
We assess goodwill for impairment annually on October 1, or more frequently if events or changes in circumstances indicate it
might be impaired. We have the option to first assess qualitative factors to determine whether it is necessary to perform a
quantitative goodwill impairment test. We performed a qualitative assessment as of October 1, 2019. Our qualitative assessment
included, among other things, industry and market considerations, overall financial performance, other entity-specific events
and events affecting individual reporting units. After assessing the totality of events or circumstances for each reporting unit,
we determined that the carrying value did not exceed its fair value and that goodwill was not impaired.
Our reporting units to which goodwill has been allocated consist of the following as of October 1, 2019:
•
•
•
crude oil pipelines;
refined product pipelines; and
terminals, excluding our Point Tupper facility and our refinery crude storage tanks.
As discussed in Note 5, we recognized a goodwill impairment charge in the first quarter of 2019 for the goodwill associated
with the Statia Bunkering reporting unit, which consisted of our bunkering operations at the St. Eustatius terminal facility. We
adopted amended accounting guidance in the first quarter of 2019 to measure goodwill impairment as the excess of each
reporting unit’s carrying value over its fair value, not to exceed the carrying amount of goodwill for that reporting unit. See
Note 3 for a discussion of new accounting pronouncements. The carrying value of each reporting unit equals the total identified
assets (including goodwill) less the sum of each reporting unit’s identified liabilities. We used reasonable and supportable
methods to assign the assets and liabilities to the appropriate reporting units in a consistent manner.
We recognize an impairment of goodwill if the carrying value of goodwill exceeds its estimated fair value. In order to estimate
the fair value of goodwill, management must make certain estimates and assumptions that affect the total fair value of the
reporting unit including, among other things, an assessment of market conditions, projected cash flows, discount rates and
growth rates. Management’s estimates of projected cash flows related to the reporting unit include, but are not limited to, future
earnings of the reporting unit, assumptions about the use or disposition of the asset, estimated remaining life of the asset, and
future expenditures necessary to maintain the asset’s existing service potential. We calculate the estimated fair value of each of
our reporting units using a weighted-average of values calculated using an income approach and a market approach. The
income approach involves estimating the fair value of each reporting unit by discounting its estimated future cash flows using a
discount rate that would be consistent with a market participant’s assumption. The market approach bases the fair value
measurement on information obtained from observed stock prices of public companies and recent merger and acquisition
transaction data of comparable entities. We performed a quantitative goodwill impairment test as of October 1, 2018 and
determined that no impairment charges existed on that date.
Impairment of Long-Lived Assets
We review long-lived assets, including property, plant and equipment, for impairment whenever events or changes in
circumstances indicate that the carrying amount may not be recoverable. We evaluate recoverability using undiscounted
estimated net cash flows generated by the related asset or asset group. If the results of that evaluation indicate that the
undiscounted cash flows are less than the carrying amount of the asset (i.e., the asset is not recoverable) we perform an
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impairment analysis. If our intent is to hold the asset for continued use, we determine the amount of impairment as the amount
by which the net carrying value exceeds its fair value. If our intent is to sell the asset, and the criteria required to classify an
asset as held for sale are met, we determine the amount of impairment as the amount by which the net carrying amount exceeds
its fair value less costs to sell. As discussed in Note 5, we recognized long-lived asset impairment charges of $305.7 million in
2019 related to the St. Eustatius terminal facility. We believe that the carrying amounts of our long-lived assets as of
December 31, 2019 are recoverable.
Income Taxes
We are a limited partnership and generally are not subject to federal or state income taxes. Accordingly, our taxable income or
loss, which may vary substantially from income or loss reported for financial reporting purposes, is generally included in the
federal and state income tax returns of our partners. For transfers of publicly held common units subsequent to our initial public
offering, we have made an election permitted by Section 754 of the Internal Revenue Code (the Code) to adjust the common
unit purchaser’s tax basis in our underlying assets to reflect the purchase price of the units. This results in an allocation of
taxable income and expenses to the purchaser of the common units, including depreciation deductions and gains and losses on
sales of assets, based upon the new unitholder’s purchase price for the common units.
We conduct certain of our operations through taxable wholly owned corporate subsidiaries. We account for income taxes
related to our taxable subsidiaries using the asset and liability method. Under this method, we recognize deferred tax assets and
liabilities for the future tax consequences attributable to differences between the financial statement carrying amounts of
existing assets and liabilities and their respective tax bases. We measure deferred taxes using enacted tax rates expected to
apply to taxable income in the year those temporary differences are expected to be recovered or settled.
We recognize a tax position if it is more likely than not that the tax position will be sustained, based on the technical merits of
the position, upon examination. We record uncertain tax positions in the financial statements at the largest amount of benefit
that is more likely than not to be realized. We had no unrecognized tax benefits as of December 31, 2019 and 2018.
NuStar Energy and certain of its subsidiaries file income tax returns in the U.S. federal jurisdiction and various state and
foreign jurisdictions. For U.S. federal and state purposes, as well as for our major non-U.S. jurisdictions, tax years subject to
examination are 2016 through 2018, according to standard statute of limitations.
Asset Retirement Obligations
We record a liability for asset retirement obligations at the fair value of the estimated costs to retire a tangible long-lived asset
at the time we incur that liability, which is generally when the asset is purchased, constructed or leased, when we have a legal
obligation to incur costs to retire the asset and when a reasonable estimate of the fair value of the obligation can be made. If a
reasonable estimate cannot be made at the time the liability is incurred, we record the liability when sufficient information is
available to estimate the fair value.
We have asset retirement obligations with respect to certain of our assets due to various legal obligations to clean and/or
dispose of those assets at the time they are retired. However, these assets can be used for an extended and indeterminate period
of time as long as they are properly maintained and/or upgraded. It is our practice and current intent to maintain our assets and
continue making improvements to those assets based on technological advances. As a result, we believe that our assets have
indeterminate lives for purposes of estimating asset retirement obligations because dates or ranges of dates upon which we
would retire these assets cannot reasonably be estimated at this time. When a date or range of dates can reasonably be estimated
for the retirement of any asset, we estimate the costs of performing the retirement activities and record a liability for the fair
value of these costs.
We also have legal obligations in the form of leases and right-of-way agreements, which require us to remove certain of our
assets upon termination of the agreement. However, these lease or right-of-way agreements generally contain automatic
renewal provisions that extend our rights indefinitely or we have other legal means available to extend our rights. We have
recorded liabilities of $0.2 million as of December 31, 2019 and 2018, which are included in “Other long-term liabilities” in the
consolidated balance sheets, for conditional asset retirement obligations related to the retirement of terminal assets with lease
and right-of-way agreements.
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Environmental Remediation Costs
Environmental remediation costs are expensed and an associated accrual established when site restoration and environmental
remediation and cleanup obligations are either known or considered probable and can be reasonably estimated. These
environmental obligations are based on estimates of probable undiscounted future costs using currently available technology
and applying current regulations, as well as our own internal environmental policies. The environmental liabilities have not
been reduced by possible recoveries from third parties. Environmental costs include initial site surveys, costs for remediation
and restoration and ongoing monitoring costs, as well as fines, damages and other costs, when estimable. Adjustments to initial
estimates are recorded, from time to time, to reflect changing circumstances and estimates based upon additional information
developed in subsequent periods.
Revenue Recognition
Revenue-Generating Activities. Revenues for the pipeline segment are derived from interstate and intrastate pipeline
transportation of refined products, crude oil and anhydrous ammonia and the applicable pipeline tariff.
Revenues for the storage segment include fees for tank storage agreements, whereby a customer agrees to pay for a certain
amount of storage in a tank over a period of time (storage terminal revenues), and throughput agreements, whereby a customer
pays a fee per barrel for volumes moving through our terminals (throughput terminal revenues). Our terminals also provide
blending, additive injections, handling and filtering services for which we charge additional fees, and 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 (all of which are considered optional services).
Revenues for the fuels marketing segment are derived from the sale of petroleum products.
Within our pipeline and storage segments, we provide services on uninterruptible and interruptible bases. Uninterruptible
services within our pipeline segment typically result from contracts that contain take-or-pay minimum volume commitments
(MVCs) from the customer. Contracts with MVCs obligate the customer to pay for that minimum amount. If a customer fails to
meet its MVC for the applicable service period, the customer is obligated to pay a deficiency fee based upon the shortfall
between the actual volumes transported or stored and the MVC for that service period (deficiency payments). In exchange,
those contracts with MVCs obligate us to stand ready to transport volumes up to the customer’s MVC.
Within our storage segment, uninterruptible services arise from contracts containing a fixed monthly fee for the portion of
storage capacity reserved by the customer. These contracts require that the customer pay the fixed monthly fee, regardless of
whether or not it uses our storage facility (i.e., take-or-pay obligation), and that we stand ready to store that volume.
Interruptible services within our pipeline and storage segments are generally provided when and to the extent we determine the
requested capacity is available. The customer typically pays a per-unit rate for the actual quantities of services it receives.
Adoption of ASC Topic 606. On January 1, 2018, we adopted Accounting Standards Codification Topic 606, “Revenue from
Contracts with Customers” (ASC Topic 606) using the modified retrospective method and applied ASC Topic 606 to all
revenue contracts with customers. After identifying a contract with a customer, ASC Topic 606 requires us to (i) identify the
performance obligations in the contract; (ii) determine the transaction price; (iii) allocate the transaction price to the
performance obligations; and (iv) recognize revenue when or as we satisfy a performance obligation. For the majority of our
contracts, we recognize revenue in the amount to which we have a right to invoice. Generally, payment terms do not exceed 30
days.
Performance Obligations. The majority of our contracts contain a single performance obligation. For our pipeline segment, the
single performance obligation encompasses multiple activities necessary to deliver our customers’ products to their
destinations. Typically, we satisfy this performance obligation over time as the product volume is delivered in or out of the
pipelines. Similarly, the performance obligation for our storage segment consists of multiple activities necessary to receive,
store and deliver our customers’ products. We typically satisfy this performance obligation over time as the product volume is
delivered in or out of the tanks (for throughput terminal revenues) or with the passage of time (for storage terminal revenues).
Certain of our pipeline segment customer contracts include an incentive pricing structure, which provides a discounted rate for
the remainder of the contract once the customer exceeds a cumulative volume. The ability to receive discounted future services
represents a material right to the customer, which results in a second performance obligation in those contracts.
Product sales contracts associated with our fuels marketing segment generally include a single performance obligation to
deliver specified volumes of a commodity, which we satisfy at a point in time, when the product is delivered and the customer
obtains control of the commodity.
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Optional services do not provide a material right to the customer, and are not considered a separate performance obligation in
the contract. If and when a customer elects an optional service, it becomes part of the existing performance obligation.
Transaction Price. For uninterruptible services, we determine the transaction price at contract inception based on the
guaranteed minimum amount of revenue over the term of the contract. For interruptible services and optional services, we
determine the transaction price based on our right to invoice the customer for the value of services provided to the customer for
the applicable period.
In certain instances, our customers reimburse us for capital projects, in arrangements referred to as contributions in aid of
construction, or CIAC. Typically, in these instances, we receive upfront payments for future services, which are included in the
transaction price of the underlying service contract.
We collect taxes on certain revenue transactions to be remitted to governmental authorities, which may include sales, use,
value-added and some excise taxes. These taxes are not included in the transaction price and are, therefore, excluded from
revenues.
Allocation of Transaction Price. We allocate the transaction price to the single performance obligation that exists in the vast
majority of our contracts with customers. For the few contracts that have a second performance obligation, such as those that
include an incentive pricing structure, we calculate an average rate based on the estimated total volumes to be delivered over
the term of the contract and the resulting estimated total revenue to be billed using the applicable rates in the contract. We
allocate the transaction price to the two performance obligations by applying the average rate to product volumes as they are
delivered to the customer over the term of the contract. Determining the timing and amount of volumes subject to these
incentive pricing contracts requires judgment that can impact the amount of revenue allocated to the two separate performance
obligations. We base our estimates on our analysis of expected future production information available from our customers or
other sources, which we update at least quarterly.
Some of our MVC contracts include provisions that allow the customer to apply deficiency payments to future service periods
(the carryforward period). In those instances, we have not satisfied our performance obligation as we still have the obligation to
perform those services, subject to contractual and/or capacity constraints, at the customer’s request. At least quarterly, we
assess the customer’s ability to utilize any deficiency payments during the carryforward period. If we receive a deficiency
payment from a customer that we expect the customer to utilize during the carryforward period, we defer that amount as a
contract liability. We will consider the performance obligation satisfied and allocate any deferred deficiency payments to our
performance obligation when the customer utilizes the deficiency payment, the carryforward period ends or we determine the
customer cannot or will not utilize the deficiency payment (i.e. breakage). If our contract does not allow the customer to apply
deficiency payments to future service periods, we allocate the deficiency payment to the already satisfied portion of the
performance obligation.
Income Allocation
Our partnership agreement contains provisions for the allocation of net income to the unitholders and, prior to the merger with
our general partner, to the general partner. Our net income for each quarterly reporting period is first allocated to the preferred
limited partner unitholders in an amount equal to the earned distributions for the respective reporting period and, prior to the
merger, then to the general partner in an amount equal to the general partner’s incentive distribution calculated based upon the
declared distribution for the respective reporting period. We allocate the remaining net income or loss among the common
unitholders. Prior to the merger, we allocated the remaining net income or loss among the common unitholders (98%) and
general partner (2%). See Note 4 for further discussion of the merger and Note 20 for the calculation of net income applicable
to the general partner prior to the merger.
Basic and Diluted Net (Loss) Income Per Common Unit
Basic and diluted net (loss) income per common unit are determined pursuant to the two-class method. Under this method, all
earnings are allocated to our limited partners and participating securities based on their respective rights to receive distributions
earned during the period. Participating securities include restricted units awarded under our long-term incentive plans and, prior
to the merger with our general partner, included our general partner’s interest.
We compute basic net (loss) income per common unit by dividing net (loss) income attributable to our common limited
partners by the weighted-average number of common units outstanding during the period. We compute diluted net (loss)
income per common unit by dividing net (loss) income attributable to our common limited partners by the sum of (i) the
weighted-average number of common units outstanding during the period and (ii) the effect of dilutive potential common units
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outstanding during the period. Dilutive potential common units include contingently issuable performance units awarded and
the Series D Preferred Units. See Note 24 for additional information on our performance units, Note 19 for additional
information on our Series D Preferred Units and Note 21 for the calculation of basic and diluted net (loss) income per common
unit.
Derivative Financial Instruments
When we apply hedge accounting, we formally document all relationships between hedging instruments and hedged items. This
process includes identification of the hedging instrument and the hedged transaction, the nature of the risk being hedged and
how the hedging instrument’s effectiveness will be assessed. To qualify for hedge accounting, at inception of the hedge we
assess whether the derivative instruments that are used in our hedging transactions are expected to be highly effective in
offsetting changes in cash flows. Throughout the designated hedge period and at least quarterly, we assess whether the
derivative instruments are highly effective and continue to qualify for hedge accounting.
Under the terms of our forward-starting interest rate swap agreements, we pay a fixed rate and receive a variable rate. We
entered into the forward-starting swaps in order to hedge the risk of changes in the interest payments attributable to changes in
the benchmark interest rate during the period from the effective date of the swap to the issuance of the forecasted debt. For
forward-starting interest rate swaps designated and qualifying as cash flow hedges, we recognize the fair value of each interest
rate swap in the consolidated balance sheets. We record the effective portion of mark-to-market adjustments as a component of
accumulated other comprehensive income (loss) (AOCI), and any hedge ineffectiveness is recognized immediately in “Interest
expense, net.” The amount accumulated in AOCI is amortized into “Interest expense, net” as the forecasted interest payments
occur or if the interest payments are probable not to occur.
We classify cash flows associated with our derivative instruments as operating cash flows in the consolidated statements of
cash flows, except for receipts or payments associated with terminated forward-starting interest rate swap agreements, which
are included in cash flows from financing activities. See Note 18 for additional information regarding our derivative financial
instruments.
Unit-based Compensation
Unit-based compensation for our long-term incentive plans is recorded in our consolidated balance sheets based on the fair
value of the awards granted and recognized as compensation expense primarily on a straight-line basis over the requisite
service period. Forfeitures of our unit-based compensation awards are recognized as an adjustment to compensation expense
when they occur. Unit-based compensation expense is included in “General and administrative expenses” on our consolidated
statements of (loss) income. Most of our currently outstanding awards are classified as equity awards as we intend to settle
these awards through the issuance of our common units. See Note 24 for additional information regarding our unit-based
compensation.
Foreign Currency Translation
The functional currencies of our foreign subsidiaries are the local currencies of the countries in which the subsidiaries are
located. The assets and liabilities of our foreign subsidiaries with local functional currencies are translated to U.S. dollars at
period-end exchange rates, and income and expense items are translated to U.S. dollars at weighted-average exchange rates in
effect during the period. These translation adjustments are included in “Accumulated other comprehensive loss” in the equity
section of the consolidated balance sheets. Gains and losses on foreign currency transactions are included in “Other income
(expense), net” or “(Loss) income from discontinued operations, net of tax” in the consolidated statements of (loss) income.
Reclassifications
We have reclassified certain previously reported amounts in the consolidated financial statements and notes to conform to
current-period presentation. As further discussed in Note 5, we reclassified certain balances to assets and liabilities held for sale
and certain revenues and expenses to discontinued operations.
3. NEW ACCOUNTING PRONOUNCEMENTS
Simplifying the Accounting for Income Taxes
In December 2019, the Financial Accounting Standards Board (FASB) issued amended guidance that simplifies the accounting
for income taxes, including enacted changes in tax laws in interim periods. The guidance is effective for annual and interim
periods beginning after December 15, 2020, with early adoption permitted. These provisions should be applied retrospectively,
prospectively, or on a modified retrospective basis depending on the area affected by the amended guidance. We are currently
evaluating the impact of this amended guidance on our financial position, results of operations or disclosures and whether we
will adopt these provisions early.
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Securities and Exchange Commission Disclosure Update and Simplification
In August 2018, the Securities and Exchange Commission (SEC) issued final rules regarding disclosure requirements that were
redundant, duplicative, overlapping or superseded by other SEC requirements or GAAP. The final rules primarily eliminated or
reduced certain disclosure requirements, although they also required some additional disclosures. The rules became effective on
November 5, 2018, with an exception for the new disclosure requirement to present changes in partners’ equity in interim
periods, which permits entities to begin disclosing this information in the quarter that begins after the effective date of the final
rules. We elected to utilize this exception, and began presenting statements of partners’ equity on an interim basis beginning
with the quarter ending March 31, 2019. These final rules did not have an impact on our financial position or results of
operations.
Cloud Computing Arrangements
In August 2018, the FASB issued guidance addressing a customer’s accounting for implementation costs incurred in a cloud
computing arrangement (CCA) that is considered a service contract. Under the new guidance, implementation costs for a CCA
should be evaluated for capitalization using the same approach as implementation costs associated with internal-use software
and expensed over the term of the hosting arrangement. The guidance is effective for annual and interim periods beginning after
December 15, 2019, with early adoption permitted. Prospective adoption for eligible costs incurred on or after the date of
adoption or retrospective adoption is permitted. We adopted the guidance on January 1, 2020 on a prospective basis and it did
not have a material impact on our financial position or results of operations, and we do not expect it to have a material impact
on our disclosures.
Disclosures for Defined Benefit Plans
In August 2018, the FASB issued amended guidance that makes minor changes to the disclosure requirements for employers
that sponsor defined benefit pension and/or other postretirement benefit plans. The guidance is effective for annual periods
beginning after December 15, 2020, with early adoption permitted, using a retrospective approach. We are currently evaluating
whether we will adopt these provisions early, but we do not expect the guidance to have a material impact on our financial
position, results of operations or disclosures.
Unit-Based Payments to Nonemployees
In June 2018, the FASB issued amended guidance which aligns the measurement and classification guidance for unit-based
payments to nonemployees with the guidance for unit-based payments to employees, with certain exceptions. Under the
amended guidance, unit-based payment awards to nonemployees will be measured at their grant date fair value. The guidance is
effective for annual and interim periods beginning after December 15, 2018, with early adoption permitted. The amended
guidance should be applied by means of a cumulative-effect adjustment to the balance sheet as of the beginning of the fiscal
year of adoption. We adopted these provisions on January 1, 2019, and the guidance did not have a material impact on our
financial position, results of operations or disclosures.
Goodwill
In January 2017, the FASB issued amended guidance that simplifies the accounting for goodwill impairment. Under the
amended guidance, goodwill impairment is measured as the excess of the reporting unit’s carrying value over its fair value, not
to exceed the carrying amount of goodwill for that reporting unit. The changes are effective for annual and interim periods
beginning after December 15, 2019, and amendments should be applied prospectively. Early adoption is permitted for any
impairment tests performed after January 1, 2017. We adopted the amended guidance during the first quarter of 2019 and
applied the guidance to the goodwill impairment discussed in Note 5.
Credit Losses
In June 2016, the FASB issued amended guidance that requires the use of a “current expected loss” model for financial assets
measured at amortized cost and certain off-balance sheet credit exposures. Under this model, entities will be required to
estimate the lifetime expected credit losses on such instruments based on historical experience, current conditions, and
reasonable and supportable forecasts. This amended guidance also expands the disclosure requirements to enable users of
financial statements to understand an entity’s assumptions, models and methods for estimating expected credit losses. The
changes are effective for annual and interim periods beginning after December 15, 2019, and amendments should be applied
using a modified retrospective approach. We adopted the amended guidance on January 1, 2020 and it did not have a material
impact on our financial position or results of operations, and we do not expect it to have a material impact on our disclosures.
Leases
In February 2016, the FASB issued amended guidance that requires lessees to recognize the assets and liabilities that arise from
most leases on the balance sheet. For lessors, this amended guidance modifies the classification criteria and the accounting for
sales-type and direct financing leases. The changes are effective for annual and interim periods beginning after December 15,
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2018, and amendments should be applied using one of two modified retrospective transition methods. We adopted these
provisions on January 1, 2019 through a cumulative-effect adjustment to the opening balance of retained earnings in the period
of adoption. The transition adjustment related to the adoption was immaterial, and the adoption of this guidance did not
materially impact the results of our operations. Please refer to Note 17 for further discussion.
4. MERGER AND RELATED PARTY AGREEMENTS
On July 20, 2018, we completed the merger of Holdings with a subsidiary of NuStar Energy (the Merger). Pursuant to the
Merger agreement and at the effective time of the Merger, NuStar Energy’s 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.
At the effective time of the Merger, each outstanding Holdings common unit was converted into the right to receive 0.55 of a
NuStar Energy common unit and all Holdings common units ceased to be outstanding. As a result of the Merger, we issued
approximately 23.6 million NuStar Energy common units and cancelled the 10.2 million NuStar Energy common units owned
by subsidiaries of Holdings, resulting in approximately 13.4 million incremental NuStar Energy common units outstanding after
the Merger. In addition, we repaid Holdings’ debt with borrowings under our revolving credit agreement and incurred
transaction costs for aggregate cash consideration of approximately $68.0 million.
Also at the effective time of the Merger, each outstanding award of Holdings restricted units was converted, on the same terms
and conditions as were applicable to the awards immediately prior to the Merger, into an award of NuStar Energy restricted
units. The number of NuStar Energy restricted units subject to the converted awards was determined pursuant to the 0.55
exchange ratio provided in the Merger Agreement.
Following the completion of the Merger, the NuStar GP, LLC board of directors consists of nine members, currently composed
of the six members of the NuStar GP, LLC board of directors prior to the Merger and the three independent directors who
served prior to the Merger on Holdings’ board of directors.
We accounted for the Merger as an equity transaction similar to a redemption or induced conversion of preferred stock. The
excess of (x) the fair value of the consideration transferred in exchange for the outstanding Holdings units over (y) the carrying
value of the general partner interest in the Partnership was subtracted from net income available to common unitholders in the
calculation of net loss per common unit attributable to the Merger as follows (in thousands of dollars, except unit and per unit
data):
Consideration transferred:
Fair value of incremental NS common units issued
Holdings debt and assumed net current liabilities
Transaction costs
Total consideration
Carrying value of general partner interest
Loss to common unitholders attributable to the Merger
For the year ended December 31, 2018:
Basic weighted-average common units outstanding
Loss per common unit attributable to the Merger
$
$
$
335,106
52,075
15,897
403,078
25,999
(377,079)
99,490,495
(3.79)
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Related Party Agreements with Holdings
GP Services Agreement. Prior to the Merger, we were a party to an Amended and Restated Services Agreement with NuStar GP,
LLC, effective March 1, 2016 (the Amended GP Services Agreement), which provided that we furnish administrative services
necessary to conduct the business of Holdings, and Holdings compensated us for these services for an annual fee of $1.0
million, subject to adjustment based on the annual merit increase percentage applicable to our employees for the most recently
completed fiscal year and for changes in level of service. We terminated the Amended GP Services Agreement in conjunction
with the Merger.
Non-Compete Agreement. On July 19, 2006, we entered into a non-compete agreement with Holdings, Riverwalk Logistics, L.P.
and NuStar GP, LLC (the Non-Compete Agreement). The Non-Compete Agreement became effective on December 22, 2006.
Under the Non-Compete Agreement, we had the right of first refusal with respect to the potential acquisition of assets related to
the transportation, storage or terminalling of crude oil, feedstocks or refined products (including petrochemicals) in the United
States and internationally. Holdings had a right of first refusal with respect to the potential acquisition of general partner and
other equity interests in publicly traded partnerships under common ownership with the general partner interest. As a result of
the Merger, the Non-Compete Agreement was terminated, effective July 20, 2018.
5. DISCONTINUED OPERATIONS AND IMPAIRMENTS
On November 30, 2018, we sold our European Operations for approximately $270.0 million. The European Operations were
previously reported in our storage segment. In association with the European Disposition, we recognized a non-cash loss of
$43.4 million related to the sale in “(Loss) income from discontinued operations, net of tax” on the consolidated statement of
income for the year ended December 31, 2018.
On January 28, 2019, the U.S. Department of the Treasury’s Office of Foreign Assets Control added Petroleos de Venezuela,
S.A. (PDVSA), at the time a customer at the St. Eustatius facility, to its List of Specially Designated Nationals and Blocked
Persons (the SDN List). The inclusion of PDVSA on the SDN List required us to wind down our contracts with PDVSA. Prior
to winding down such contracts, PDVSA was the St. Eustatius terminal’s largest customer.
The effect of the sanctions issued against PDVSA, combined with the progression in the sale negotiations that occurred during
March 2019, resulted in triggering events that caused us to evaluate the long-lived assets and goodwill associated with the St.
Eustatius terminal and bunkering operations for potential impairment.
With respect to the terminal operations long-lived assets, our estimates of future expected cash flows included the possibility of
a near-term sale, as well as continuing to operate the terminal. The carrying value of the terminal’s long-lived assets exceeded
our estimate of the total expected cash flows, indicating the long-lived assets were potentially impaired. To determine an
impairment amount, we estimated the fair value of the long-lived assets for comparison to the carrying amount of those assets.
Our estimate of the fair value considered the expected sales price as well as estimates generated from income and market
approaches using a market participant’s assumptions. The estimated fair values resulting from the market and income
approaches were consistent with the expected sales price. Therefore, we concluded that the estimated sales price, which was
less than the carrying amount of the long-lived assets, represented the best estimate of fair value at March 31, 2019, and we
recorded a long-lived asset impairment charge of $297.3 million in the first quarter of 2019 to reduce the carrying value of the
assets to their estimated fair value. We recorded an additional impairment charge of $8.4 million in the second quarter of 2019,
mainly due to additional capital expenditures incurred in the second quarter.
With respect to the goodwill in the Statia Bunkering reporting unit, which consisted of our bunkering operations at the St.
Eustatius terminal facility, we estimated the fair value based on the expected sales price discussed above, which is inclusive of
the bunkering operations. As a result, we concluded the goodwill was impaired. Consistent with FASB’s amended goodwill
impairment guidance discussed in Note 3, which we adopted in the first quarter of 2019, we measured the goodwill impairment
as the difference between the reporting unit’s carrying value and its fair value. Therefore, we recognized a goodwill impairment
charge of $31.1 million in the first quarter of 2019 to reduce the goodwill to $0 for the Statia Bunkering reporting unit.
The impairment charges are included in “(Loss) income from discontinued operations, net of tax” on the consolidated statement
of loss.
During the second quarter of 2019, we determined the assets and liabilities associated with the St. Eustatius Operations met the
criteria to be classified as held for sale. We determined the St. Eustatius Operations and the European Operations met the
requirements to be reported as discontinued operations since the St. Eustatius Disposition and the European Disposition
together represented a strategic shift that will have a major impact on our operations and financial results. These sales were part
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NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
of our plan to improve our debt metrics and partially fund capital projects to grow our core business in North America.
Accordingly, the consolidated balance sheet reflects the assets and liabilities associated with the St. Eustatius Operations as held
for sale as of December 31, 2018, and the consolidated statements of (loss) income reflect the St. Eustatius Operations and the
European Operations as discontinued operations for all applicable periods presented.
On July 29, 2019, we sold the St. Eustatius Operations for net proceeds of approximately $230.0 million. 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 recognized a non-cash loss on the sale of $3.9 million in “(Loss) income from discontinued
operations, net of tax” on the consolidated statement of loss in 2019.
Discontinued Operations
The following is a reconciliation of the major classes of line items included in “(Loss) income from discontinued operations,
net of tax” on the consolidated statements of (loss) income:
Revenues
Costs and expenses:
Cost of revenues
Impairment losses
General and administrative expenses (excluding depreciation and
amortization expense)
Other depreciation and amortization expense
Total costs and expenses
Operating (loss) income
Interest income (expense), net
Other (expense) income, net
Year Ended December 31,
2019
2018
2017
(Thousands of Dollars)
$
248,981
$
441,495
$
369,247
220,595
336,838
1,231
—
558,664
(309,683)
32
(2,775)
407,256
318,532
—
6,133
271
—
4,684
263
413,660
323,479
27,835
(1,839)
34,674
60,670
1,251
59,419
$
45,768
(1,309)
(5,226)
39,233
2,164
37,069
(Loss) income from discontinued operations before income
tax expense
Income tax expense
(Loss) income from discontinued operations, net of tax
(312,426)
101
(312,527) $
$
The consolidated statements of cash flows have not been adjusted to separately disclose cash flows related to discontinued
operations. The following table presents selected cash flow information associated with our discontinued operations:
Capital expenditures
Significant noncash operating activities and other adjustments:
Depreciation and amortization expense
Asset impairment losses
Goodwill impairment loss
Loss from sale of the St. Eustatius Operations
Loss from sale of the European Operations
Gain from insurance recoveries
$
$
$
$
$
$
$
Year Ended December 31,
2019
2018
2017
(Thousands of Dollars)
(27,954) $
(114,811) $
(153,785)
8,536
305,715
31,123
$
$
$
3,942
$
— $
— $
41,982
$
— $
— $
— $
43,366
$
(78,756) $
36,040
—
—
—
—
—
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NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Assets and Liabilities Held for Sale
The following is a reconciliation of the carrying amounts of the major classes of assets and liabilities included in “Assets held
for sale” and “Liabilities held for sale” on the consolidated balance sheet:
Total current assets
Property, plant and equipment, net
Goodwill
Assets held for sale
Current liabilities
6. ACQUISITIONS
December 31, 2018
(Thousands of Dollars)
$
$
$
54,404
513,820
31,123
599,347
69,834
Council Bluffs Acquisition. On April 16, 2018, we acquired CHS Inc.’s Council Bluffs pipeline system, comprised of a 227-
mile pipeline and 18 storage tanks, for approximately $37.5 million. The assets acquired and the results of operations are
included in our pipeline segment from the date of acquisition. We accounted for this acquisition as an asset purchase.
Navigator Acquisition. On May 4, 2017, we acquired Navigator Energy Services, LLC (Navigator) for approximately $1.5
billion (the Navigator Acquisition). We acquired crude oil transportation, pipeline connection and storage assets located in the
Midland Basin in West Texas that, together with the assets we have constructed through various expansion projects since the
date of the Navigator Acquisition, we collectively refer to as our Permian Crude System. The assets acquired are included in
our pipeline segment. The consolidated statements of (loss) income include the results of operations for Navigator commencing
on May 4, 2017.
We accounted for the Navigator Acquisition using the acquisition method. The following table reflects the final purchase price
allocation:
Accounts receivable
Other current assets
Property, plant and equipment, net
Intangible assets (a)
Goodwill (b)
Other long-term assets, net
Current liabilities
Purchase price allocation, net of cash acquired
Purchase Price Allocation
(Thousands of Dollars)
$
$
4,747
2,359
376,690
700,000
398,024
2,199
(22,300)
1,461,719
(a)
Intangible assets, which consist of customer contracts and relationships, are amortized on a straight-line basis over a period of 20
years.
(b) The goodwill acquired represents the expected benefit from entering new geographic areas and the anticipated opportunities to
generate future cash flows from the assets acquired and potential future projects.
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NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
The unaudited pro forma information for the year ended December 31, 2017 below presents the combined historical financial
information for Navigator and the Partnership for those periods. This information assumes:
•
•
•
•
•
•
•
we completed the Navigator Acquisition on January 1, 2017;
we issued approximately 14.4 million common units;
we received a contribution from our general partner of $13.6 million to maintain the 2% general partner economic
interest it owned at that time;
we issued 15.4 million Series B Preferred Units;
we issued $550.0 million of 5.625% senior notes;
additional depreciation and amortization that would have been incurred assuming the fair value adjustments to
property, plant and equipment and intangible assets reflected in the purchase price allocation above; and
we satisfied Navigator’s outstanding obligations under its revolving credit agreement.
Revenues
Net income
Basic and diluted net income per common unit
Year Ended December 31, 2017
(Thousands of Dollars, Except Per Unit Data)
$
$
$
1,828,418
127,433
0.31
The pro forma information for the year ended December 31, 2017 includes transaction costs of $14.1 million, which were
directly attributable to the Navigator Acquisition. The pro forma information is unaudited and is not necessarily indicative of
the results of operations that would have resulted had the Navigator Acquisition occurred on January 1, 2017 or that may result
in the future.
7. REVENUE FROM CONTRACTS WITH CUSTOMERS
Transition
On January 1, 2018, we adopted ASC Topic 606 using the modified retrospective method and applied ASC Topic 606 to all
revenue contracts with customers. Results for reporting periods beginning January 1, 2018 are presented under ASC Topic 606.
In accordance with the modified retrospective approach, prior period amounts were not adjusted and are reported under ASC
Topic 605, “Revenue Recognition.”
The adoption of ASC Topic 606 affected our consolidated statements of (loss) income as follows:
For the year ended December 31, 2018:
Revenues
Operating income
Income from continuing operations
Basic net loss per common unit from continuing operations
As Reported
Without Adoption
of ASC Topic 606
Effect of Change
Higher/(Lower)
(Thousands of Dollars, Except Per Unit Data)
$
$
$
$
1,520,262
335,728
$
$
146,375
$
(3.34) $
1,526,447
341,913
$
$
152,560
$
(3.27) $
(6,185)
(6,185)
(6,185)
(0.07)
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NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Contract Assets and Contract Liabilities
The following table provides information about contract assets and contract liabilities from contracts with customers:
2019
2018
Contract Assets
Contract Liabilities
Contract Assets
Contract Liabilities
(Thousands of Dollars)
(Thousands of Dollars)
Balances as of January 1:
Current portion
Noncurrent portion
Held for sale
Total
Activity:
Additions
Transfer to accounts receivable
Transfer to revenues, including amounts
reported in discontinued operations
Total
Balances as of December 31:
Current portion
Noncurrent portion
Held for sale
Total
$
2,066
$
539
—
2,605
4,890
(4,352)
—
538
2,140
1,003
—
$
3,143
$
(21,579) $
(38,945)
(25,357)
(85,881)
(52,957)
—
77,466
24,509
(21,083)
(40,289)
—
(61,372) $
1,956
$
171
—
2,127
3,281
(2,803)
—
478
2,066
539
—
2,605
$
(13,801)
(46,361)
(302)
(60,464)
(83,243)
—
57,826
(25,417)
(21,579)
(38,945)
(25,357)
(85,881)
Contract assets relate to performance obligations satisfied in advance of scheduled billings. Current contract assets are included
in “Other current assets” and noncurrent contract assets are included in “Other long-term assets, net” on the consolidated
balance sheets. Contract liabilities relate to payments received in advance of satisfying performance obligations under a
contract, which mainly result from contracts with an incentive pricing structure, CIAC payments and contracts with MVCs.
Current contract liabilities are included in “Accrued liabilities” or “Liabilities held for sale” and noncurrent contract liabilities
are included in “Other long-term liabilities” on the consolidated balance sheets.
In the third quarter of 2018, we entered into an agreement whereby our customer transferred ownership of crude oil to us, and
we agreed to sell the crude oil and apply the proceeds as a non-refundable, one-time payment of storage fees. At the time of the
agreement, we recognized a contract liability of $37.5 million. We recognized all the revenue associated with this contract
liability by the end of 2019.
In the second quarter of 2018, one customer for whom we had recorded a contract liability to perform future services elected
not to extend the term of its terminal storage contract, thus reducing our future performance obligation. As a result, we adjusted
the related contract liability and recognized $9.0 million in revenue.
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NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Remaining Performance Obligations
The following table presents our estimated revenue from contracts with customers for remaining performance obligations that
has not yet been recognized, representing our contractually committed revenue as of December 31, 2019 (in thousands of
dollars):
2020
2021
2022
2023
2024
Thereafter
Total
$
$
529,830
376,500
310,632
236,853
175,358
255,808
1,884,981
Our contractually committed revenue, for purposes of the tabular presentation above, is generally limited to customer contracts
that have fixed pricing and fixed volume terms and conditions, generally including contracts with MVC payment obligations.
Disaggregation of Revenues
The following table disaggregates our revenues:
Year Ended December 31,
2019
2018
2017
(Thousands of Dollars)
Pipeline segment:
Crude oil pipelines
Refined products and ammonia pipelines (excluding lessor revenues)
Total pipeline segment revenues from contracts with customers
Lessor revenues
Total pipeline segment revenues
Storage segment:
Throughput terminals
Storage terminals (excluding lessor revenues)
Total storage segment revenues from contracts with customers
Lessor revenues
Total storage segment revenues
Fuels marketing segment:
Revenues from contracts with customers
$
316,417
$
248,261
$
376,588
693,005
8,825
701,830
114,243
298,984
413,227
40,774
454,001
362,750
611,011
54
187,874
328,414
516,288
—
611,065
516,288
83,157
320,582
403,739
39,849
443,588
85,927
317,963
403,890
39,126
443,016
342,215
465,651
489,807
Consolidation and intersegment eliminations
(25)
(42)
(4,339)
Total revenues
$
1,498,021
$
1,520,262
$
1,444,772
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NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
8. ALLOWANCE FOR DOUBTFUL ACCOUNTS
The changes in the allowance for doubtful accounts consisted of the following:
Balance as of beginning of year
Increase in allowance, net
Accounts charged against the allowance
Balance as of end of year
9. INVENTORIES
Inventories consisted of the following:
Petroleum products
Materials and supplies
Total
Year Ended December 31,
2019
2018
2017
(Thousands of Dollars)
$
$
9,412
2,322
(11,662)
72
$
$
9,380
233
(201)
9,412
$
$
7,700
1,705
(25)
9,380
December 31,
2019
2018
(Thousands of Dollars)
$
$
8,646
3,747
12,393
$
$
4,853
3,581
8,434
We purchase petroleum products for resale. Our petroleum products consist of intermediates, gasoline, distillates and other
petroleum products. Materials and supplies mainly consist of blending and additive chemicals and maintenance materials used
in our pipeline and storage segments.
10. PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment consisted of the following:
Estimated Useful
Lives
December 31,
2019
2018
Land
Land and leasehold improvements
Buildings
Pipelines, storage and terminals
Rights-of-way
Construction in progress
Total
Less accumulated depreciation and amortization
Property, plant and equipment, net
(Years)
-
-
-
-
-
-
5
15
15
20
40
40
40
40
$
$
$
(Thousands of Dollars)
144,409
223,220
166,878
5,038,468
350,026
264,143
6,187,144
(2,068,165)
4,118,979
138,487
181,578
146,517
4,702,421
301,738
157,064
5,627,805
(1,853,003)
3,774,802
$
Capitalized interest costs added to property, plant and equipment, including amounts related to discontinued operations, totaled
$8.9 million, $7.8 million and $5.5 million for the years ended December 31, 2019, 2018 and 2017, respectively. Depreciation
and amortization expense for property, plant and equipment totaled $226.0 million, $243.5 million and $222.5 million for the
years ended December 31, 2019, 2018 and 2017, respectively, including depreciation and amortization expense reported in
“(Loss) income from discontinued operations, net of tax” on the consolidated statements of (loss) income.
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NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
11. INTANGIBLE ASSETS
Intangible assets consisted of the following:
Customer contracts and relationships
Other
Total
Weighted-
Average
Amortization
Period
(Years)
18
47
December 31, 2019
December 31, 2018
Cost
Accumulated
Amortization
Cost
Accumulated
Amortization
(Thousands of Dollars)
$
$
863,900
2,359
866,259
$
$
(183,832) $
(795)
(184,627) $
863,950
2,359
866,309
$
$
(132,509)
(744)
(133,253)
Intangible assets are recorded at fair value as of the date acquired. All of our intangible assets are amortized on a straight-line
basis. Amortization expense for intangible assets was $51.4 million, $51.4 million and $39.6 million for the years ended
December 31, 2019, 2018 and 2017, respectively. The estimated aggregate amortization expense is approximately $51.0 million
for each of the years 2020 through 2022, and approximately $45.0 million for 2023 and 2024.
12. GOODWILL
Changes in the carrying amount of goodwill by segment were as follows:
Balances as of January 1, 2018
Activity for the year ended December 31, 2018:
Pipeline
Storage
Total
(Thousands of Dollars)
$
707,045
$
301,622
$ 1,008,667
Navigator Acquisition purchase price allocation adjustments (Note 6)
(2,814)
—
(2,814)
Balances as of December 31, 2018 and 2019
$
704,231
$
301,622
$ 1,005,853
As discussed in Note 5, the assets and liabilities associated with the European Operations and the St. Eustatius Operations,
including goodwill, were reclassified to assets and liabilities held for sale for all periods presented and are not included in the
table above. In connection with the European Disposition in 2018, we allocated goodwill of $57.7 million to the European
Operations. In 2019, goodwill of $31.1 million associated with the bunkering operations at the St. Eustatius terminal facility,
which represented all goodwill in the fuels marketing segment, was reduced to $0. Please see Note 5 for additional information.
As a result of the St. Eustatius Disposition, there are no accumulated impairment losses associated with continuing operations
as of December 31, 2019.
13. ACCRUED LIABILITIES
Accrued liabilities consisted of the following:
Employee wages and benefit costs
Revenue contract liabilities
Interest rate swaps
Operating lease liabilities
Other
Accrued liabilities
$
$
84
December 31,
2019
2018
$
(Thousands of Dollars)
36,704
21,083
19,169
10,416
16,913
104,285
$
29,518
21,579
—
—
23,321
74,418
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14. DEBT
NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Short-term debt consisted of the following:
Short-term line of credit
Current portion of finance leases (refer to Note 17)
Short-term debt and current portion of finance leases
December 31,
2019
2018
(Thousands of Dollars)
$
$
5,500
4,546
10,046
$
$
18,500
—
18,500
NuStar Logistics is party to a short-term line of credit agreement with an uncommitted borrowing capacity of up to $35.0
million, which allows us to better manage fluctuations in our daily cash requirements and minimize our excess cash balances.
The interest rates and maturities vary and are determined at the time of borrowing. Obligations under this short-term line of
credit agreement are guaranteed by NuStar Energy. As of December 31, 2019 and 2018, the weighted-average interest rates
related to outstanding borrowings under our short-term line of credit were 3.6% and 4.4%, respectively.
Long-term debt consisted of the following:
Revolving Credit Agreement
4.80% senior notes
6.75% senior notes
4.75% senior notes
6.00% senior notes
5.625% senior notes
Subordinated Notes
GoZone Bonds
Receivables Financing Agreement
Net fair value adjustments, unamortized discounts and unamortized
debt issuance costs
Total long-term debt (excluding finance leases)
Finance leases (refer to Note 17)
Less current portion
Long-term debt, less current portion
December 31,
Maturity
2019
2018
(Thousands of Dollars)
2021
2020
2021
2022
2026
2027
2043
2038 thru 2041
2021
N/A
$
475,000
$
450,000
300,000
250,000
500,000
550,000
402,500
365,440
62,200
745,000
450,000
300,000
250,000
—
550,000
402,500
365,440
61,800
(23,301)
3,331,839
55,446
452,367
2,934,918
$
(12,744)
3,111,996
—
—
3,111,996
$
The long-term debt repayments (excluding finance leases) are due as follows (in thousands of dollars):
2020
2021
2022
2023
2024
Thereafter
Total repayments
Net fair value adjustments, unamortized discounts and unamortized debt issuance costs
Total long-term debt (excluding finance leases)
$
$
450,000
837,200
250,000
—
—
1,817,940
3,355,140
(23,301)
3,331,839
We expect to refinance senior note maturities in 2020 and 2021 by utilizing the capital markets, pursuing other sources of debt
financing or with funds available under our revolving credit agreement.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Interest payments totaled $183.8 million, $190.9 million and $163.6 million for the years ended December 31, 2019, 2018 and
2017, respectively, related to debt obligations. We amortized an aggregate of $6.5 million, $7.1 million and $5.0 million of debt
issuance costs and debt discount combined for the years ended December 31, 2019, 2018 and 2017, respectively.
Revolving Credit Agreement
On September 12, 2019, NuStar Logistics amended its revolving credit agreement (the Revolving Credit Agreement) primarily
to extend the maturity date to October 29, 2021 and reduce the total amount available for borrowing from $1.4 billion to $1.2
billion.
For the rolling period ending December 31, 2019, the maximum allowed consolidated debt coverage ratio (as defined in the
Revolving Credit Agreement) may not exceed 5.00-to-1.00 and the minimum consolidated interest coverage ratio (as defined in
the Revolving Credit Agreement), must not be less than 1.75-to-1.00. If we complete one or more acquisitions for aggregate net
consideration of at least $50.0 million, our maximum consolidated debt coverage ratio will increase to 5.50-to-1.00 for two
rolling periods. The maximum consolidated debt coverage ratio and minimum consolidated interest coverage ratio requirements
may limit the amount we can borrow under the Revolving Credit Agreement to an amount less than the total amount available
for borrowing. The Revolving Credit Agreement also contains customary restrictive covenants, such as limitations on
indebtedness, liens, mergers, asset transfers and certain investing activities. As of December 31, 2019, we believe that we are in
compliance with the covenants in the Revolving Credit Agreement.
As of December 31, 2019, we had $721.0 million available for borrowing. Obligations under the Revolving Credit Agreement
are guaranteed by NuStar Energy and NuPOP. Letters of credit issued under the Revolving Credit Agreement totaled $4.0
million as of December 31, 2019. Letters of credit are limited to $400.0 million and also may restrict the amount we can
borrow under the Revolving Credit Agreement.
The Revolving Credit Agreement bears interest, at our option, based on an alternative base rate, a LIBOR-based rate or a
EURIBOR-based rate. The interest rate on the Revolving Credit Agreement is subject to adjustment if our debt rating is
downgraded (or upgraded) by certain credit rating agencies. As of December 31, 2019, our weighted-average interest rate was
3.9%, and we had $475.0 million outstanding. During the year ended December 31, 2019, the weighted-average interest rate
related to borrowings under the Revolving Credit Agreement was 4.4%.
Notes
NuStar Logistics Senior Notes. 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. The interest on the 6.0% senior notes is payable semi-annually in arrears on June 1 and December 1 of each year,
beginning on December 1, 2019.
On April 28, 2017, NuStar Logistics issued $550.0 million of 5.625% senior notes due April 28, 2027. We used the net
proceeds of $543.3 million from the offering to fund a portion of the purchase price for the Navigator Acquisition and to pay
related fees and expenses. The interest on the 5.625% senior notes is payable semi-annually in arrears on April 28 and October
28 of each year, beginning on October 28, 2017.
Interest is payable semi-annually in arrears for the $450.0 million of 4.80% senior notes, $300.0 million of 6.75% senior notes,
$250.0 million of 4.75% senior notes, $500.0 million of 6.0% senior notes and $550.0 million of 5.625% senior notes
(collectively, the NuStar Logistics Senior Notes). We repaid the $350.0 million of 7.65% senior notes on April 15, 2018 with
borrowings under our Revolving Credit Agreement.
The NuStar Logistics Senior Notes do not have sinking fund requirements. These notes rank equally with existing senior
unsecured indebtedness and senior to existing subordinated indebtedness of NuStar Logistics and contain restrictions on NuStar
Logistics’ ability to incur additional secured indebtedness unless the same security is also provided for the benefit of holders of
the NuStar Logistics Senior Notes. In addition, the NuStar Logistics Senior Notes limit NuStar Logistics’ ability to incur
indebtedness secured by certain liens and to engage in certain sale-leaseback transactions and engage in certain consolidations,
mergers or asset sales. At the option of NuStar Logistics, the NuStar Logistics Senior Notes may be redeemed in whole or in
part at any time at a redemption price, plus accrued and unpaid interest to the redemption date. 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. The NuStar Logistics Senior Notes are fully and unconditionally guaranteed by NuStar
Energy and NuPOP.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
NuStar Logistics Subordinated Notes. NuStar Logistics’ $402.5 million of fixed-to-floating rate subordinated notes are due
January 15, 2043 (the Subordinated Notes). The Subordinated Notes are fully and unconditionally guaranteed on an unsecured
and subordinated basis by NuStar Energy and NuPOP. Effective January 15, 2018, the interest rate on the Subordinated Notes
switched from a fixed annual rate of 7.625%, payable quarterly in arrears, to an annual rate equal to the sum of the three-month
LIBOR for the related quarterly interest period, plus 6.734% payable quarterly, commencing April 15, 2018, unless payment is
deferred in accordance with the terms of the notes. NuStar Logistics may elect to defer interest payments on the Subordinated
Notes on one or more occasions for up to five consecutive years. Deferred interest will accumulate additional interest at a rate
equal to the interest rate then applicable to the Subordinated Notes until paid. If NuStar Logistics elects to defer interest
payments, NuStar Energy cannot declare or make cash distributions to its unitholders during the period that interest payments
are deferred. As of December 31, 2019, the interest rate was 8.7%.
The Subordinated Notes do not have sinking fund requirements and are subordinated to existing senior unsecured indebtedness
of NuStar Logistics and NuPOP. The Subordinated Notes do not contain restrictions on NuStar Logistics’ ability to incur
additional indebtedness, including debt that ranks senior in priority of payment to the notes. In addition, the Subordinated Notes
do not limit NuStar Logistics’ ability to incur indebtedness secured by liens or to engage in certain sale-leaseback transactions.
Effective January 15, 2018, we may redeem the Subordinated Notes in whole or in part at a redemption price equal to 100% of
the principal amount plus accrued and unpaid interest to the redemption date.
Gulf Opportunity Zone Revenue Bonds
In 2008, 2010 and 2011, the Parish of St. James, Louisiana issued Revenue Bonds Series 2008, Series 2010, Series 2010A,
Series 2010B and Series 2011 associated with our St. James terminal expansions pursuant to the Gulf Opportunity Zone Act of
2005 for an aggregate $365.4 million (collectively, the GoZone Bonds). The interest rates on these bonds are based on a weekly
tax-exempt bond market interest rate, and interest is paid monthly. Following the issuances, the proceeds were deposited with a
trustee and were disbursed to us upon our request for reimbursement of expenditures related to our St. James terminal
expansions. We include the amount remaining in the trust in “Other long-term assets, net,” and we include the amount of bonds
issued in “Long-term debt” in our consolidated balance sheets. We did not receive any proceeds from the trustee for the years
ended December 31, 2019 and 2018.
NuStar Logistics is solely obligated to service the principal and interest payments associated with the GoZone Bonds. Letters of
credit were issued by various individual banks on our behalf to guarantee the payment of interest and principal on the bonds.
All letters of credit rank equally with existing senior unsecured indebtedness of NuStar Logistics and generally contain the
same restrictive covenants, maximum consolidated debt coverage ratio and minimum consolidated interest coverage ratio
requirements as the Revolving Credit Agreement. Obligations under the letters of credit issued are guaranteed by NuStar
Energy and NuPOP. The letters of credit issued by individual banks do not restrict the amount we can borrow under the
Revolving Credit Agreement. At the option of NuStar Logistics, during any period when the bonds bear interest at a daily or
weekly rate, the GoZone Bonds may be redeemed in whole or in part on any interest payment date for 100% of the outstanding
principal amount plus accrued interest to the redemption date. On January 27, 2020, NuStar Logistics provided the trustee with
notice to call the $43.3 million principal amount of the GoZone Bonds remaining in trust for redemption on March 4, 2020.
The following table summarizes the GoZone Bonds outstanding as of December 31, 2019:
Date Issued
Maturity Date
Amount
Outstanding
Amount of
Letter of
Credit
Amount
Received from
Trustee
Amount
Remaining in
Trust (a)
Interest Rate (b)
(Thousands of Dollars)
June 26, 2008
July 15, 2010
June 1, 2038
July 1, 2040
$
55,440
$
56,169
$
55,440
$
100,000
101,315
100,000
October 7, 2010
October 1, 2040
December 29, 2010
December 1, 2040
August 9, 2011
August 1, 2041
50,000
85,000
75,000
50,658
86,118
75,986
43,741
49,782
75,000
—
—
6,652
36,580
—
Total
$
365,440
$
370,246
$
323,963
$
43,232
(a) Amount remaining in trust includes accrued interest.
(b) For the year ended December 31, 2019, our weighted-average interest rate on borrowings was 1.5%.
1.6%
1.5%
1.5%
1.5%
1.6%
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Receivables Financing Agreement
NuStar Energy and NuStar Finance LLC (NuStar Finance), a special purpose entity and wholly owned subsidiary of NuStar
Energy, are parties to a $125.0 million receivables financing agreement with third-party lenders (the Receivables Financing
Agreement) and agreements with certain of NuStar Energy’s wholly owned subsidiaries (together with the Receivables
Financing Agreement, the Securitization Program). Under the Securitization Program, certain of NuStar Energy’s wholly
owned subsidiaries (collectively, the Originators), sell their accounts receivable to NuStar Finance on an ongoing basis, and
NuStar Finance provides the newly acquired accounts receivable as collateral for its revolving borrowings under the
Receivables Financing Agreement. NuStar Energy provides a performance guarantee in connection with the Securitization
Program. The amount available for borrowing is limited to $125.0 million and is based on the availability of eligible
receivables and other customary factors and conditions. The Securitization Program contains various customary affirmative and
negative covenants and default, indemnification and termination provisions, and the Receivables Financing Agreement
provides for acceleration of amounts owed upon the occurrence of certain specified events. NuStar Finance’s sole activity
consists of purchasing such receivables and providing them as collateral under the Securitization Program. NuStar Finance is a
separate legal entity and the assets of NuStar Finance, including these accounts receivable, are not available to satisfy the
claims of creditors of NuStar Energy, the Originators or their affiliates.
On April 29, 2019, we amended the Receivables Financing Agreement to extend the scheduled termination date from
September 20, 2020 to September 20, 2021, with the option to renew for additional 364-day periods thereafter, and to amend
certain provisions with respect to receivables related to certain customers. Borrowings by NuStar Finance under the
Receivables Financing Agreement bear interest at the applicable bank rate, as defined under the Receivables Financing
Agreement. As of December 31, 2019 and 2018, accounts receivable totaling $112.8 million and $95.5 million, respectively,
were included in the Securitization Program. The weighted average interest rate related to outstanding borrowings under the
Securitization Program during the year ended December 31, 2019 was 3.2%.
15. HEALTH, SAFETY AND ENVIRONMENTAL MATTERS
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. Future governmental action and regulatory initiatives
could necessitate changes to expected operating permits and procedures, additional remedial actions or increased capital
expenditures and operating costs. Risks of additional costs and liabilities are inherent to government-regulated industries,
including midstream energy, and there can be no assurances that significant costs and liabilities will not be incurred in the
future.
Most of our pipelines are subject to federal regulation by one or more of the following governmental agencies: The Federal
Energy Regulatory Commission (the FERC), the Surface Transportation Board (the STB), the Department of Transportation
(DOT), the Environmental Protection Agency (EPA) and the Department of Homeland Security. Additionally, the operations
and integrity of the pipelines are subject to the respective jurisdictions of the states those lines traverse.
Environmental and safety exposures and liabilities are difficult to assess and estimate due to unknown factors such as the
timing and extent of remediation, the determination of our liability in proportion to other parties, improvements in cleanup
technologies and the extent to which environmental and safety laws and regulations may change in the future. Although
environmental and safety costs may have a significant impact on the results of operations for any single period, we believe that
such costs will not have a material adverse effect on our financial position.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
The balance of and changes in the accruals for environmental matters were as follows:
Balance as of the beginning of year
Additions to accrual
Payments
Balance as of the end of year
Year Ended December 31,
2019
2018
(Thousands of Dollars)
$
$
7,753
$
3,700
(3,515)
7,938
$
5,095
5,708
(3,050)
7,753
Accruals for environmental matters are included in the consolidated balance sheets as follows:
Accrued liabilities
Other long-term liabilities
Accruals for environmental matters
16. COMMITMENTS AND CONTINGENCIES
December 31,
2019
2018
(Thousands of Dollars)
$
$
4,837
3,101
7,938
$
$
4,349
3,404
7,753
Contingencies
We have contingent liabilities resulting from various litigation, claims and commitments. We record accruals for loss
contingencies when losses are considered probable and can be reasonably estimated. Legal fees associated with defending the
Partnership in legal matters are expensed as incurred. We accrued $3.7 million and $2.8 million for contingent losses as of
December 31, 2019 and 2018, respectively. The amount that will ultimately be paid related to such matters may differ from the
recorded accruals, and the timing of such payments is uncertain. We evaluate each contingent loss at least quarterly, and more
frequently as each matter progresses and develops over time, and we do not believe that the resolution of any particular claim
or proceeding, or all matters in the aggregate, would have a material adverse effect on our results of operations, financial
position or liquidity.
Commitments
Future minimum rental payments applicable to all noncancellable purchase obligations as of December 31, 2019 are as follows:
2020
2021
2022
2023
2024
There-
after
Total
Payments Due by Period
(Thousands of Dollars)
Purchase obligations
$
8,935
$
7,643
$
6,202
$
1,485
$
812
$
5,157
$
30,234
Our purchase obligations primarily consist of an eleven-year chemical supply agreement related to our pipelines that terminates
in 2022 and various service agreements with information technology providers.
17. LEASE ASSETS AND LIABILITIES
Transition
On January 1, 2019, we adopted Accounting Standards Codification Topic 842, “Leases” (ASC Topic 842) using the modified
retrospective method. Results for reporting periods beginning after January 1, 2019 are presented under ASC Topic 842. In
accordance with the modified retrospective approach, prior period amounts were not adjusted and are reported under ASC Topic
840, “Leases.” As a result of the adoption of ASC Topic 842, we recorded right-of-use assets and lease liabilities of
approximately $207.0 million and $192.0 million, respectively, as of January 1, 2019. The adoption of ASC Topic 842 had an
immaterial impact on our results of operations and cash flows.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
We elected the following practical expedients permitted under the transition guidance within the new standard:
•
•
•
•
the package of practical expedients, which, among other things, allowed us to carry forward historical lease
classification;
the practical expedient specifically related to land easements, which, among other things, allowed us to carry forward
our historical accounting treatment for existing land easement agreements;
the lessee practical expedient to combine lease and non-lease components for all of our asset classes except the other
pipeline and terminal equipment asset class; and
the lessor practical expedient to combine lease and non-lease components and to account for the transaction based on
the predominant component (i.e., ASC Topic 842 or ASC Topic 606, “Revenue from Contracts with Customers”). We
apply this expedient to certain contracts in which we agree to provide both storage capacity and optional services to
customers.
We record all leases on our consolidated balance sheet except for those leases with an initial term of 12 months or less, which
are expensed on a straight-line basis over the lease term. We use judgment in determining the reasonably certain lease term and
consider factors such as the nature and utility of the leased asset, as well as the importance of the leased asset to our operations.
We calculate the present value of our lease liabilities based upon our incremental borrowing rate unless the rate implicit in the
lease is readily determinable.
Lessee Arrangements
Our operating leases consist primarily of land and dock leases at various terminal facilities. As of December 31, 2019, land and
dock leases have remaining terms generally of up to 6 years and include options to extend, some up to 20 years, which we are
reasonably certain to exercise.
The primary component of our finance lease portfolio is a dock at a terminal facility, which includes a commitment for
minimum dockage and wharfage throughput volumes. The dock lease has a remaining initial term of 1 year and four additional
five-year renewal periods, all of which we are reasonably certain to exercise. We historically accounted for the dock lease under
legacy build-to-suit accounting guidance, which was eliminated by ASC Topic 842.
Certain of our leases are subject to variable payment arrangements, the most notable of which include:
•
•
dockage and wharfage charges, which are based on volumes moved over leased docks and are included in our
calculation of our lease payments based on minimum throughput volume requirements. We recognize charges on
excess throughput volumes in profit or loss in the period in which the obligation for those payments is incurred; and
consumer price index adjustments, which are measured and included in the calculation of our lease payments based on
the consumer price index at the adoption date or, after adoption, at the commencement date. We recognize changes in
lease payments as a result of changes in the consumer price index in profit or loss in the period in which those
payments are made.
Right-of-use assets and lease liabilities included in our consolidated balance sheet were as follows:
Balance Sheet Location
December 31, 2019
(Thousands of Dollars)
Right-of-Use Assets:
Operating
Finance
Lease Liabilities:
Operating:
Current
Noncurrent
Total operating lease liabilities
Finance:
Current
Noncurrent
Total finance lease liabilities
Other long-term assets, net
Property, plant and equipment, net of accumulated
amortization of $3,748
Accrued liabilities
Other long-term liabilities
Short-term debt and current portion of finance leases
Long-term debt, less current portion
90
$
$
$
$
$
$
81,219
74,953
10,416
70,083
80,499
4,546
55,446
59,992
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NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
As of December 31, 2019, maturities of our operating and finance lease liabilities were as follows:
2020
2021
2022
2023
2024
Thereafter
Total lease payments
Less: Interest
Present value of lease liabilities
Operating Leases
Finance Leases
$
$
$
(Thousands of Dollars)
12,647
$
9,419
8,717
7,605
6,739
60,354
105,481
24,982
80,499
$
$
6,702
5,252
4,582
4,480
4,067
59,681
84,764
24,772
59,992
Costs incurred for leases, including costs associated with discontinued operations, were as follows:
Operating lease cost
Finance lease cost:
Amortization of right-of-use assets
Interest expense on lease liability
Short-term lease cost
Variable lease cost
Total lease cost
Year Ended December 31, 2019
(Thousands of Dollars)
$
$
29,167
3,748
2,212
19,140
6,990
61,257
Rental expense for operating leases (pursuant to ASC Topic 840) totaled $42.9 million and $36.2 million for the years ended
December 31, 2018 and 2017, respectively, including rental expense reported in “(Loss) income from discontinued operations,
net of tax” on the consolidated statements of (loss) income.
The table below presents additional information regarding our leases:
Operating Leases
Finance Leases
(Thousands of Dollars, Except Term and Rate Data)
For the year ended December 31, 2019:
Cash outflows from operating activities
Cash outflows from financing activities
Right-of-use assets obtained in exchange for lease liabilities
As of December 31, 2019:
Weighted-average remaining lease term (in years)
Weighted-average discount rate
$
$
$
27,567
$
— $
$
2,153
15
3.6%
2,027
3,700
4,430
20
3.7%
Lessor Arrangements
We have entered into certain revenue arrangements where we are considered to be the lessor. Under the largest of these
arrangements, we lease certain of our storage tanks in exchange for a fixed fee, subject to an annual consumer price index
adjustment. The operating leases commenced on January 1, 2017, and have initial terms of 10 years with successive automatic
renewal terms. We recognized lease revenues from these leases of $40.8 million for the year ended December 31, 2019, which
are included in “Service revenues” in the consolidated statements of (loss) income. As of December 31, 2019, we expect to
receive minimum lease payments totaling $273.7 million, based upon the consumer price index as of the adoption date. We will
recognize these payments ratably over the remaining initial lease term. As of December 31, 2019, the cost and accumulated
depreciation of lease storage assets, which are included in our “Pipeline, storage and terminals” asset class within property,
plant and equipment and have an estimated useful life of 30 years, total $238.2 million and $121.5 million, respectively.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
18. DERIVATIVES AND FAIR VALUE MEASUREMENTS
Derivative Instruments
We utilize various derivative instruments to manage our exposure to interest rate risk and commodity price risk. Our risk
management policies and procedures are designed to monitor interest rates, futures and swap positions and over-the-counter
positions, as well as physical commodity volumes, grades, locations and delivery schedules, to help ensure that our hedging
activities address our market risks.
The results of operations for the fuels marketing segment depend largely on the margin between our cost and the sales prices of
the products we market. Therefore, the results of operations for this segment are more sensitive to changes in commodity prices
compared to the operations of the pipeline and storage segments. Since our fuels marketing operations expose us to commodity
price risk, we enter into derivative instruments to mitigate the effect of commodity price fluctuations on our operations.
Derivative financial instruments associated with commodity price risk with respect to our petroleum product inventories and
related firm commitments to purchase and/or sell such inventories were not material for any period presented.
Interest Rate Risk. We are a party to certain interest rate swap agreements that terminate in September 2020 to manage our
exposure to changes in interest rates, which consist of forward-starting interest rate swap agreements related to a forecasted
debt issuance in 2020. We entered into these swaps in order to hedge the risk of fluctuations in the required interest payments
attributable to changes in the benchmark interest rate during the period from the effective date of the swap to the issuance of the
forecasted debt. Under the terms of the swaps, we pay a fixed rate and receive a rate based on the three-month USD LIBOR.
These swaps qualify as cash flow hedges, and we designate them as such. We record the effective portion of mark-to-market
adjustments as a component of AOCI, and the amount in AOCI will be recognized in “Interest expense, net” as the forecasted
interest payments occur or if the interest payments are probable not to occur. As of December 31, 2019 and 2018, the aggregate
notional amount of forward-starting interest rate swaps totaled $250.0 million. In April 2018, in connection with the maturity of
the 7.65% senior notes due April 15, 2018, we terminated forward-starting interest rate swaps with an aggregate notional
amount of $350.0 million and received $8.0 million. The termination payments are included in cash flows from financing
activities on the consolidated statements of cash flows.
The remaining fair value amounts associated with unwound interest rate swap agreements are presented in the table below.
These amounts are amortized ratably over the remaining life of the related debt instrument into “Interest expense, net” on the
consolidated statements of (loss) income.
Unwound Interest Rate Swap Agreements
Balance Sheet Location
December 31,
2019
2018
(Thousands of Dollars)
Fixed-to-floating
Fixed-to-floating
Forward-starting
Current portion of long-term debt
Long-term debt, less current portion
Accumulated other comprehensive income (loss)
$
$
$
2,755
2,568
3,045
$
$
$
—
10,475
(770)
The fair values of our interest rate swap agreements included in our consolidated balance sheets were as follows:
Balance Sheet Location
Other long-term assets, net
Accrued liabilities
Other long-term liabilities
December 31,
2019
2018
(Thousands of Dollars)
$
$
$
— $
(19,169) $
— $
627
—
(751)
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Our forward-starting interest rate swaps had the following impact on earnings:
Year Ended December 31,
2019
2018
2017
(Thousands of Dollars)
(Loss) gain recognized in other comprehensive income (loss) on derivative
Loss reclassified from AOCI into interest expense, net
$
$
(19,045) $
(3,814) $
17,912
$
(5,499) $
(8,670)
(6,624)
As of December 31, 2019, we expect to reclassify a loss of $2.4 million to “Interest expense, net” within the next twelve
months associated with unwound forward-starting interest rate swap agreements.
Fair Value Measurements
We segregate the inputs used in measuring fair value into three levels: Level 1, defined as observable inputs such as quoted
prices for identical assets or liabilities in active markets; Level 2, defined as inputs other than quoted prices in active markets
that are either directly or indirectly observable, such as quoted prices for similar assets or liabilities in active markets or quoted
prices for identical assets or liabilities in markets that are not active; and Level 3, defined as unobservable inputs for which
little or no market data exists. We consider counterparty credit risk and our own credit risk in the determination of all estimated
fair values.
Recurring Fair Value Measurements. Because we estimate the fair value of our forward-starting interest rate swaps using
discounted cash flows, which use observable inputs such as time to maturity and market interest rates, we include interest rate
swaps in Level 2 of the fair value hierarchy.
Fair Value of Financial Instruments
We recognize cash equivalents, receivables, payables and debt in our consolidated balance sheets at their carrying amounts. The
fair values of these financial instruments, except for long-term debt other than finance leases, approximate their carrying
amounts. The estimated fair values and carrying amounts of the long-term debt, including the current portion and excluding
finance leases, were as follows:
Fair value
Carrying amount
December 31, 2019
December 31, 2018
(Thousands of Dollars)
$
$
3,442,001
3,331,839
$
$
3,056,704
3,111,996
We have estimated the fair value of our publicly traded notes based upon quoted prices in active markets; therefore, we
determined that the fair value of our publicly traded notes falls in Level 1 of the fair value hierarchy. With regard to our other
debt, for which a quoted market price is not available, we have estimated the fair value using a discounted cash flow analysis
using current incremental borrowing rates for similar types of borrowing arrangements and determined that the fair value falls
in Level 2 of the fair value hierarchy.
19. SERIES D CUMULATIVE CONVERTIBLE PREFERRED UNITS
Purchase Agreement and Issuance of Series D Preferred Units
On June 26, 2018, the Partnership entered into a purchase agreement (the Series D Preferred Unit Purchase Agreement) with
investment funds, accounts and entities (collectively, the Purchasers) managed by EIG Management Company, LLC and FS/
EIG Advisors, LLC to issue and sell $590.0 million of Series D Cumulative Convertible Preferred Units (Series D Preferred
Units) in a private placement. The Partnership issued a total of 23,246,650 Series D Preferred Units to the Purchasers at a price
of $25.38 per Series D Preferred Unit (the Series D Preferred Unit Purchase Price). At the initial closing on June 29, 2018 (the
Initial Closing), the Purchasers purchased 15,760,441 Series D Preferred Units for $400.0 million, and we received net
proceeds of $370.7 million. The Purchasers purchased the remaining 7,486,209 Series D Preferred Units for $190.0 million at a
second closing on July 13, 2018. The net proceeds to the Partnership from the sale of the Series D Preferred Units of $555.8
million, including deductions for a 3.5% transaction fee of $20.7 million paid to the Purchasers and other issuance costs of
$13.5 million, were used for general partnership purposes, including repayment of outstanding borrowings under our Revolving
Credit Agreement.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Series D Preferred Units Rights
At the Initial Closing and pursuant to the Series D Preferred Unit Purchase Agreement, the Partnership amended and restated its
partnership agreement to authorize and establish the rights, preferences and privileges of the Series D Preferred Units. The
Series D Preferred Units rank equal to other classes of preferred units and senior to common units in the Partnership with
respect to distribution rights and rights upon liquidation. The Series D Preferred Units generally will vote on an as-converted
basis with the common units and will have certain class voting rights with respect to a limited number of matters as set forth in
the partnership agreement.
Series D Preferred Units Distributions
Distributions on the Series D Preferred Units are payable out of any legally available funds, accrue and are cumulative from the
issuance dates and are payable on the 15th day (or next business day) of each of March, June, September and December,
beginning September 17, 2018, to holders of record on the first business day of each payment month. The distribution rate on
the Series D Preferred Units is: (i) 9.75% per annum ($57.6 million per annum) for the first two years; (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. While the Series D Preferred Units are outstanding, the Partnership will be
prohibited from paying distributions on any junior securities, including the common units, unless full cumulative distributions
on the Series D Preferred Units (and any parity securities) have been, or contemporaneously are being, paid or set aside for
payment through the most recent Series D Preferred Unit distribution payment date. Any Series D Preferred Unit distributions
in excess of $0.635 per unit may be paid, in the Partnership’s sole discretion, in additional Series D Preferred Units, with the
remainder paid in cash.
If we fail to pay in full any Series D Preferred Unit distribution amount, then, until we pay such distributions in full, the
applicable distribution rate for each of those distribution periods shall be increased by $0.048 per Series D Preferred Unit. In
addition, if we fail to pay in full any Series D Preferred Unit distribution amount for three consecutive distribution periods, then
until we pay such distributions in full: (i) each holder of the Series D Preferred Units may elect to convert its Series D Preferred
Units into common units on a one-for-one basis, plus any unpaid Series D distributions, (ii) one person selected by the holders
holding a majority of the outstanding Series D Preferred Units shall become an additional member of our board of directors and
(iii) we will not be permitted to incur any indebtedness (as defined in the Revolving Credit Agreement) or engage in any
acquisitions or asset sales in excess of $50.0 million without the consent of the holders holding a majority of the outstanding
Series D Preferred Units. In addition, we will permanently lose the ability to pay any part of the distributions on the Series D
Preferred Units in the form of additional Series D Preferred Units.
In January 2020, our board of directors declared a distribution of $0.619 per Series D Preferred Unit to be paid on March 16,
2020.
Series D Preferred Units Conversion and Redemption Features
At 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).
The 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.
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NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Series D Preferred Units Change of Control
Upon certain events involving a change of control, each holder of the Series D Preferred Units may elect to: (i) convert its
Series D Preferred Units into common units on a one-for-one basis, plus any unpaid Series D distributions; (ii) require the
Partnership to redeem its Series D Preferred Units for an amount equal to the sum of (a) $29.82 per Series D Preferred Unit plus
(b) any unpaid Series D distributions plus (c) the applicable distribution amount for the distribution periods ending after the
change of control event and prior to (but including) the fourth anniversary of the Initial Closing; (iii) if the Partnership is the
surviving entity and its common units continue to be listed, continue to hold its Series D Preferred Units; or (iv) if the
Partnership will not be the surviving entity, or it will be the surviving entity but its common units will cease to be listed, require
the Partnership to use its commercially reasonable efforts to deliver a security in the surviving entity that has substantially
similar terms as the Series D Preferred Units; however, if the Partnership is unable to deliver a mirror security, each holder is
still entitled to option (i) or (ii) above.
Registration Rights Agreement
On June 29, 2018, in connection with the Initial Closing and pursuant to the Series D Preferred Unit Purchase Agreement, the
Partnership entered into a Registration Rights Agreement (the Registration Rights Agreement) with the Purchasers relating to
the registration of the Series D Preferred Units and common units issuable upon conversion of the Series D Preferred Units (the
Common Unit Registrable Securities, and, collectively with the Series D Preferred Units, the Registrable Securities). Pursuant
to the Registration Rights Agreement, the Partnership is required to use its commercially reasonable efforts to file a registration
statement and to cause such registration statement to become effective: (i) with respect to the Common Unit Registrable
Securities, no later than one year after the Initial Closing; and (ii) with respect to the Series D Preferred Units, after the second
anniversary of the Initial Closing, no later than one year after receipt by the Partnership of a written request from holders
holding a majority of the Series D Preferred Units to register the Series D Preferred Units. In April 2019, the Securities and
Exchange Commission declared effective the registration statement on Form S-3 filed by NuStar Energy to register the
Common Unit Registrable Securities. With respect to the Series D Preferred Units, if the Partnership fails to cause such
registration statement to become effective by the applicable date, the Partnership will be required to pay certain amounts to the
holders of the Registrable Securities as liquidated damages.
Series D Preferred Units Accounting Treatment
The 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. In the calculation of net income per unit, the
accretion is treated in the same manner as a distribution and deducted from net income to arrive at net income attributable to
common units.
20. PARTNERS’ EQUITY
Please refer to Note 4 for a discussion of the Merger.
Partnership Agreement Amendments
In the third quarter of 2018, NuStar Energy’s 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. The partnership agreement was also amended and restated in the second quarter of 2018 in connection with the issuance
of our Series D Preferred Units discussed in Note 19. In 2017, the partnership agreement was amended and restated in
connection with the issuances of our Series B Preferred Units and Series C Preferred Units described below, and in connection
with the Navigator Acquisition to waive certain distributions to our general partner.
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NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Series A, B and C Preferred Units
The following is a summary of our Series A, Series B and Series C Fixed-to-Floating Rate Cumulative Redeemable Perpetual
Preferred Units (collectively the Series A, B and C Preferred Units) issued and outstanding as of December 31, 2019:
Number of
Units Issued
and
Outstanding
Price
per
Unit
Net
Proceeds
(in
millions)
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
(in
thousands)
9,060,000
$ 25.00
$
218.4
8.50% $
2.125
$
19,252
15,400,000
$ 25.00
$
371.8
7.625% $
1.90625
$
29,357
6,900,000
$ 25.00
$
166.7
9.00% $
2.25
$
15,525
Optional
Redemption
Date/Date at
Which
Distribution
Rate Becomes
Floating
December 15,
2021
June 15,
2022
December 15,
2022
Floating
Annual
Rate (as a
Percentage
of the
$25.00
Liquidation
Preference
per Unit)
Three-month
LIBOR plus
6.766%
Three-month
LIBOR plus
5.643%
Three-month
LIBOR plus
6.88%
Original
Issuance
Date
November 25,
2016
April 28,
2017
November 30,
2017
Units
Series A
Preferred
Units
Series B
Preferred
Units
Series C
Preferred
Units
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, those 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.
Distributions on the Series A, B and C 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 Series A, B and C
Preferred Units rank equal to each other and to the Series D Preferred Units, and senior to all of our other classes of equity
securities with respect to distribution rights and rights upon liquidation.
In January 2020, our board of directors declared quarterly distributions with respect to the Series A, B and C Preferred Units to
be paid on March 16, 2020.
Common Units and General Partner
Issuances of Common Units. In the fourth quarter of 2019, we 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. We used the proceeds of $15.0 million from the
sale of these units for general partnership purposes.
As a result of the Merger discussed in Note 4, we issued approximately 13.4 million incremental NuStar Energy common units
in the third quarter of 2018, in exchange for the previously outstanding Holdings units.
In the second quarter of 2018, we issued 413,736 common units at a price of $24.17 per unit to William E. Greehey. We used
the proceeds of $10.2 million from the sale of these units, including a contribution of $0.2 million from our general partner to
maintain the 2% general partner economic interest it owned at that time, for general partnership purposes.
In the second quarter of 2017, we issued 14,375,000 common units at a price of $46.35 per unit. We used the net proceeds from
this offering of $657.5 million, including a contribution of $13.6 million from our general partner to maintain the 2% general
partner economic interest it owned at that time, to fund a portion of the purchase price for the Navigator Acquisition.
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NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
The following table shows the balance of and changes in the number of our common units outstanding:
Balance as of the beginning of year
Issuance of units
Unit-based compensation (refer to Note 24 for discussion)
Merger (refer to Note 4 for discussion)
Balance as of the end of year
Year Ended December 31,
2019
107,225,156
527,426
775,224
—
108,527,806
2018
93,176,683
413,736
225,144
13,409,593
107,225,156
2017
78,616,228
14,375,000
185,455
—
93,176,683
Cash Distributions. We make quarterly distributions to common unitholders, and, prior to the Merger, made quarterly
distributions to the general partner of 100% of our “Available Cash,” generally defined as cash receipts less cash
disbursements, including distributions to our preferred units, and cash reserves established by the general partner, in its sole
discretion. These quarterly distributions are declared and paid within 45 days subsequent to each quarter-end. The common
unitholders receive a distribution each quarter as determined by the board of directors, subject to limitation by the distributions
in arrears, if any, on our preferred units. Prior to the Merger, our Available Cash was distributed based on the percentages
shown below:
Quarterly Distribution Amount Per Common Unit
Up to $0.60
Above $0.60 up to $0.66
Above $0.66
Percentage of Distribution
Common
Unitholders
98%
90%
75%
General Partner
Including Incentive Distributions
2%
10%
25%
Because the Merger was effective prior to the record date for the distribution for the second quarter of 2018, the general partner
received no distributions after the first quarter of 2018 distribution. The following table reflects the allocation of total cash
distributions to the general partner and common limited partners applicable to the period in which the distributions were
earned:
General partner interest
General partner incentive distribution
Total general partner distribution
Common limited partners’ distribution
Total cash distributions
Cash distributions per unit applicable to common limited partners
Year Ended December 31,
2019
2018
2017
(Thousands of Dollars, Except Per Unit Data)
$
$
$
— $
—
—
259,136
259,136
2.40
$
$
1,141
$
—
1,141
248,705
249,846
2.40
$
$
9,252
45,669
54,921
407,681
462,602
4.38
The following table summarizes information about quarterly cash distributions declared for our common limited partners
applicable to the year ended December 31, 2019:
Quarter Ended
December 31, 2019
September 30, 2019
June 30, 2019
March 31, 2019
Cash
Distributions
Per Unit
Total Cash
Distributions
(Thousands of Dollars)
Record Date
Payment Date
65,128
February 10, 2020
February 14, 2020
64,660 November 8, 2019 November 14, 2019
64,658
August 13, 2019
August 7, 2019
64,690
May 8, 2019
May 14, 2019
$
$
$
$
0.60
0.60
0.60
0.60
$
$
$
$
97
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NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Net Income Applicable to the General Partner. For the year ended December 31, 2018, net income applicable to the general
partner totaled $2.5 million and related to the general partner interest allocation prior to the Merger. The following table details
the calculation of net income applicable to the general partner for 2017:
Net income attributable to NuStar Energy L.P.
Less preferred limited partner interest
Less general partner incentive distribution
Net income after general partner incentive distribution and preferred
limited partner interest
General partner interest allocation
General partner interest allocation of net income
General partner incentive distribution
Net income applicable to general partner
Year Ended
December 31, 2017
(Thousands of Dollars)
$
$
147,964
40,448
45,669
61,847
2%
1,237
45,669
46,906
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NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Accumulated Other Comprehensive Income (Loss)
The balance of and changes in the components included in AOCI were as follows:
Balance as of January 1, 2017
$
(69,069) $
(22,258) $
(2,850) $
(94,177)
Foreign
Currency
Translation
Cash Flow
Hedges
Pension and
Other
Postretirement
Benefits
Total
(Thousands of Dollars)
Other comprehensive income (loss) before
reclassification adjustments
Net gain on pension costs reclassified into operating
expense
Net gain on pension costs reclassified into general and
administrative expense
Net loss on cash flow hedges reclassified into interest
expense, net
Other comprehensive income (loss)
17,466
(8,670)
(4,641)
4,155
—
—
—
17,466
—
—
6,624
(2,046)
(1,143)
(1,143)
(386)
(386)
—
(6,170)
(9,020)
6,624
9,250
(84,927)
Balance as of December 31, 2017
(51,603)
(24,304)
Other comprehensive (loss) income before
reclassification adjustments
Sale of European Operations reclassified into other
income, net
Net gain on pension costs reclassified into other income,
net
Net loss on cash flow hedges reclassified into interest
expense, net
Other
Other comprehensive income
(13,880)
17,912
3,282
7,314
18,124
—
—
60
4,304
—
—
5,499
—
23,411
—
18,124
(814)
—
(134)
2,334
(814)
5,499
(74)
30,049
Balance as of December 31, 2018
(47,299)
(893)
(6,686)
(54,878)
Other comprehensive income (loss) before
reclassification adjustments
Net gain on pension costs reclassified into other income,
net
Net loss on cash flow hedges reclassified into interest
expense, net
Other comprehensive income (loss)
3,527
(19,045)
1,000
(14,518)
—
—
3,527
—
(2,314)
(2,314)
3,814
(15,231)
—
(1,314)
3,814
(13,018)
Balance as of December 31, 2019
$
(43,772) $
(16,124) $
(8,000) $
(67,896)
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NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
21. NET (LOSS) INCOME PER COMMON UNIT
As discussed in Note 19, the Series D Preferred Units are convertible into common units at the option of the holder at any time
on or after June 29, 2028. As such, we calculated the dilutive effect of the Series D Preferred Units using the if-converted
method. The effect of the assumed conversion of the Series D Preferred Units outstanding was antidilutive for each of the years
ended December 31, 2019 and 2018; therefore, we did not include such conversion in the computation of diluted net (loss)
income per common unit.
Contingently issuable performance units are included as dilutive potential common units if it is probable that the performance
measures will be achieved. Refer to Note 24 for additional discussion.
The following table details the calculation of net (loss) income per common unit:
Year Ended December 31,
2019
2018
2017
(Thousands of Dollars, Except Unit and Per Unit Data)
Net (loss) income
Distributions to preferred limited partners
Distributions to general partner (including incentive distribution rights)
Distributions to common limited partners
Distribution equivalent rights to restricted units
Distributions in excess of (loss) income
Distributions to common limited partners
Allocation of distributions in excess of (loss) income
Series D Preferred Unit accretion (refer to Note 19)
Loss to common unitholders attributable to the Merger (refer to Note 4)
$
$
$
(105,693) $
(121,693)
—
(259,136)
(2,659)
(489,181) $
$
259,136
(489,181)
(18,085)
—
Net (loss) income attributable to common units
$
(248,130) $
$
205,794
(92,540)
(1,141)
(248,705)
(2,045)
(138,637) $
$
248,705
(138,659)
(8,195)
(377,079)
(275,228) $
147,964
(40,448)
(54,921)
(407,681)
(2,965)
(358,051)
407,681
(350,890)
—
—
56,791
Basic weighted-average common units outstanding
107,789,030
99,490,495
88,825,964
Diluted common units outstanding:
Basic weighted-average common units outstanding
Effect of dilutive potential common units
Diluted weighted-average common units outstanding
107,789,030
99,490,495
88,825,964
65,669
40,677
—
107,854,699
99,531,172
88,825,964
Basic and diluted net (loss) income per common unit
$
(2.30) $
(2.77) $
0.64
100
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NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
22. STATEMENTS OF CASH FLOWS
Changes in current assets and current liabilities were as follows:
Decrease (increase) in current assets:
Accounts receivable
Receivable from related party
Inventories
Prepaid and other current assets
Increase (decrease) in current liabilities:
Accounts payable
Accrued interest payable
Accrued liabilities
Taxes other than income tax
Income tax payable
Changes in current assets and current liabilities
Year Ended December 31,
2019
2018
2017
(Thousands of Dollars)
$
$
(23,480) $
—
(866)
(5,103)
8,068
1,632
(19,614)
(5,276)
(126)
(44,765) $
22,482
$
160
3,819
3,694
8,003
(4,279)
39,577
4,521
285
78,262
$
(865)
112
11,936
3,393
(30,409)
6,489
(11,157)
(3,529)
(2,463)
(26,493)
The above changes in current assets and current liabilities differ from changes between amounts reflected in the applicable
consolidated balance sheets due to:
•
•
•
•
•
•
the change in the amount accrued for capital expenditures;
the effect of foreign currency translation;
changes in the fair values of our interest rate swap agreements;
the recognition of lease liabilities upon the adoption of ASC Topic 842;
the reclassification of certain assets and liabilities to “Assets held for sale” and “Liabilities held for sale” on the
consolidated balance sheets (please refer to Note 5 for additional discussion); and
current assets and current liabilities acquired and disposed of during the period.
Cash flows related to interest and income taxes were as follows:
Year Ended December 31,
2019
2018
2017
(Thousands of Dollars)
Cash paid for interest, net of amount capitalized
Cash paid for income taxes, net of tax refunds received
$
$
176,859
6,817
$
$
183,078
8,535
$
$
158,089
11,338
As of December 31, 2019, restricted cash is included in "Other long-term assets, net" on the consolidated balance sheet. “Cash,
cash equivalents and restricted cash” on the consolidated statements of cash flows was included in the consolidated balance
sheets as follows:
Cash and cash equivalents
Other long-term assets, net
Assets held for sale
Cash, cash equivalents and restricted cash
December 31,
2019
December 31,
2018
(Thousands of Dollars)
16,192
$
11,529
8,788
—
24,980
$
—
2,115
13,644
$
$
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NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
23. EMPLOYEE BENEFIT PLANS
Thrift Plans
The NuStar Thrift Plan (the Thrift Plan) is a qualified defined contribution plan that became effective June 26, 2006.
Participation in the Thrift Plan is voluntary and open to substantially all our domestic employees upon their dates of hire. Thrift
Plan participants can contribute from 1% up to 30% of their total annual compensation to the Thrift Plan in the form of pre-tax
and/or after tax employee contributions. We make matching contributions in an amount equal to 100% of each participant’s
employee contributions up to a maximum of 6% of the participant’s total annual compensation. The matching contributions to
the Thrift Plan for the years ended December 31, 2019, 2018 and 2017 totaled $7.6 million, $7.4 million and $6.9 million,
respectively.
The NuStar Excess Thrift Plan (the Excess Thrift Plan) is a nonqualified deferred compensation plan that became effective
July 1, 2006. The Excess Thrift Plan provides benefits to those employees whose compensation and/or annual contributions
under the Thrift Plan are subject to the limitations applicable to qualified retirement plans under the Code.
We also maintain other defined contribution plans for certain international employees located in Canada. We maintained plans
for international employees in the Caribbean Netherlands, United Kingdom and Netherlands prior to the St. Eustatius
Disposition and the European Disposition on July 29, 2019 and November 30, 2018, respectively. For the years
ended December 31, 2019, 2018 and 2017, our costs for these plans totaled $0.9 million, $2.5 million and $2.5 million,
respectively.
Pension and Other Postretirement Benefits
The NuStar Pension Plan (the Pension Plan) is a qualified non-contributory defined benefit pension plan that provides eligible
U.S. employees with retirement income as calculated under a cash balance formula. Under the cash balance formula, benefits
are determined based on age, years of vesting service and interest credits, and employees become fully vested in their benefits
upon attaining three years of vesting service. Prior to January 1, 2014, eligible employees were covered under either a cash
balance formula or a final average pay formula (FAP). Effective January 1, 2014, the Pension Plan was amended to freeze the
FAP benefits as of December 31, 2013, and going forward, all eligible employees are covered under the cash balance formula
discussed above.
We also maintain an excess pension plan (the Excess Pension Plan), which is a nonqualified deferred compensation plan that
provides benefits to a select group of management or other highly compensated employees. Neither the Excess Thrift Plan nor
the Excess Pension Plan is intended to constitute either a qualified plan under the provisions of Section 401 of the Code or a
funded plan subject to the Employee Retirement Income Security Act.
The Pension Plan and Excess Pension Plan are collectively referred to as the Pension Plans in the tables and discussion below.
Our other postretirement benefit plans include a contributory medical benefits plan for U.S. employees who retired prior to
April 1, 2014 and, for employees who retire on or after April 1, 2014, a partial reimbursement for eligible third-party health
care premiums. We use December 31 as the measurement date for our pension and other postretirement plans.
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NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
The changes in the benefit obligation, the changes in fair value of plan assets, the funded status and the amounts recognized in
the consolidated balance sheets for our Pension Plans and other postretirement benefit plans as of and for the years ended
December 31, 2019 and 2018 were as follows:
Change in benefit obligation:
Benefit obligation, January 1
Service cost
Interest cost
Benefits paid
Participant contributions
Actuarial loss (gain)
Benefit obligation, December 31
Change in plan assets:
Plan assets at fair value, January 1
Actual return on plan assets
Employer contributions
Benefits paid
Participant contributions
Plan assets at fair value, December 31
Reconciliation of funded status:
Fair value of plan assets at December 31
Less: Benefit obligation at December 31
Funded status at December 31
Amounts recognized in the consolidated balance sheets (a):
Accrued liabilities
Other long-term liabilities
Net pension liability
Pension Plans
Other Postretirement
Benefit Plans
2019
2018
2019
2018
(Thousands of Dollars)
$
141,833
$
149,817
$
10,908
$
12,410
9,549
5,480
(7,109)
—
17,504
167,257
$
126,949
$
28,064
11,132
(7,109)
—
9,621
4,824
(7,929)
—
(14,500)
141,833
129,878
(6,034)
11,034
(7,929)
—
$
$
159,036
$
126,949
$
431
453
(217)
62
1,559
13,196
$
— $
—
155
(217)
62
— $
504
429
(255)
87
(2,267)
10,908
—
—
168
(255)
87
—
159,036
$
126,949
$
— $
—
167,257
(8,221) $
141,833
(14,884) $
13,196
(13,196) $
10,908
(10,908)
(303) $
(7,918)
(8,221) $
(267) $
(368) $
(14,617)
(14,884) $
(12,828)
(13,196) $
(362)
(10,546)
(10,908)
$
$
$
$
$
$
$
(a) For the Pension Plan, since assets exceed the present value of expected benefit payments for the next 12 months, all of the liability
is noncurrent. For the Excess Pension Plan and the other postretirement benefit plans, since there are no assets, the current liability
is the present value of expected benefit payments for the next 12 months; the remainder is noncurrent.
The accumulated benefit obligation is the present value of benefits earned to date, assuming no future salary increases. The
aggregate accumulated benefit obligation for our Pension Plans as of December 31, 2019 and 2018 was $164.2 million and
$139.7 million, respectively. As of December 31, 2019 and 2018, the aggregate accumulated benefit obligation for the Pension
Plans exceeded plan assets.
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NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
The components of net periodic benefit cost (income) related to our Pension Plans and other postretirement benefit plans were
as follows:
Pension Plans
Year Ended December 31,
Other Postretirement
Benefit Plans
Year Ended December 31,
2019
2018
2017
2019
2018
2017
(Thousands of Dollars)
Service cost
Interest cost
Expected return on plan assets
Amortization of prior service credit
Amortization of net actuarial loss
$
9,549
$
9,621
$
8,955
$
5,480
(8,015)
(2,057)
846
4,824
(7,417)
(2,057)
2,174
4,507
(6,411)
(2,059)
1,484
Net periodic benefit cost (income) $
5,803
$
7,145
$
6,476
$
$
431
453
—
(1,145)
42
(219) $
$
504
429
—
(1,145)
214
2
$
456
430
—
(1,145)
191
(68)
We amortize prior service costs and credits on a straight-line basis over the average remaining service period of employees
expected to receive benefits under our Pension Plans and other postretirement benefit plans (“Amortization of prior service
credit” in table above). We amortize the actuarial gains and losses that exceed 10% of the greater of the projected benefit
obligation or market-related value of plan assets (smoothed asset value) over the average remaining service period of active
employees expected to receive benefits under our Pension Plans and other postretirement benefit plans (“Amortization of net
actuarial loss” in table above).
The service cost component of net periodic benefit cost (income) is reported in “General and administrative expenses” and
“Operating expenses” on the consolidated statements of (loss) income, and the remaining components of net periodic benefit
cost (income) are reported in “Other income (expense), net.”
Adjustments to other comprehensive (loss) income related to our Pension Plans and other postretirement benefit plans were as
follows:
Pension Plans
Year Ended December 31,
Other Postretirement
Benefit Plans
Year Ended December 31,
2019
2018
2017
2019
2018
2017
(Thousands of Dollars)
Net unrecognized gain (loss) arising
during the year:
Net actuarial gain (loss)
$
2,545
$
1,049
$
(4,235) $
(1,559) $
2,267
$
(590)
Net (gain) loss reclassified into
income:
Amortization of prior service credit
Amortization of net actuarial loss
Net (gain) loss reclassified into
income
Reclassification of stranded tax effects
Income tax benefit (expense)
Total changes to other
comprehensive income (loss)
(2,057)
846
(2,057)
2,174
(2,059)
1,484
(1,145)
42
(1,145)
214
(1,145)
191
(1,211)
117
(575)
(1,103)
(931)
(954)
—
14
(74)
(69)
—
162
—
—
—
(25)
—
22
$
1,348
$
1,023
$
(4,648) $
(2,662) $
1,311
$
(1,522)
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
The amounts recorded as a component of “Accumulated other comprehensive loss” on the consolidated balance sheets related
to our Pension Plans and other postretirement benefit plans were as follows:
Unrecognized actuarial loss
Prior service credit
Deferred tax asset
Accumulated other comprehensive (loss) income,
net of tax
Pension Plans
December 31,
Other Postretirement
Benefit Plans
December 31,
2019
2018
2019
2018
(Thousands of Dollars)
(24,564) $
12,490
90
(27,955) $
14,547
76
(3,190) $
7,174
—
(1,673)
8,319
—
(11,984) $
(13,332) $
3,984
$
6,646
$
$
The following pre-tax amounts in AOCI as of December 31, 2019 are expected to be recognized as components of net periodic
benefit cost (income) in 2020:
Actuarial loss
Prior service credit
Pension Plans
Other Postretirement
Benefit Plans
$
$
(Thousands of Dollars)
1,845
$
(2,057) $
137
(1,145)
Investment Policies and Strategies
The investment policies and strategies for the assets of our qualified Pension Plan incorporate a well-diversified approach that
is expected to earn long-term returns from capital appreciation and a growing stream of current income. This approach
recognizes that assets are exposed to risk, and the market value of the Pension Plan’s assets may fluctuate from year to year.
Risk tolerance is determined based on our financial ability to withstand risk within the investment program and the willingness
to accept return volatility. In line with the investment return objective and risk parameters, the Pension Plan’s mix of assets
includes a diversified portfolio of equity and fixed-income instruments. The aggregate asset allocation is reviewed on an annual
basis. As of December 31, 2019, the target allocations for plan assets were 65% equity securities and 35% fixed income
investments, with certain fluctuations permitted.
The overall expected long-term rate of return on plan assets for the Pension Plan is estimated using various models of asset
returns. Model assumptions are derived using historical data with the assumption that capital markets are informationally
efficient. Three models are used to derive the long-term expected returns for each asset class. Since each method has distinct
advantages and disadvantages and differing results, an equal weighted average of the methods’ results is used.
Fair Value of Plan Assets
We disclose the fair value for each major class of plan assets in the Pension Plan into three levels: Level 1, defined as
observable inputs such as quoted prices for identical assets or liabilities in active markets; Level 2, defined as inputs other than
quoted prices in active markets that are either directly or indirectly observable, such as quoted prices for similar assets or
liabilities in active markets or quoted prices for identical assets or liabilities in markets that are not active; and Level 3, defined
as unobservable inputs for which little or no market data exists.
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The major classes of plan assets measured at fair value for the Pension Plan were as follows:
Cash equivalent securities
Equity securities:
U.S. large cap equity fund (a)
International stock index fund (b)
Fixed income securities:
Bond market index fund (c)
Total
Cash equivalent securities
Equity securities:
U.S. large cap equity fund (a)
International stock index fund (b)
Fixed income securities:
Bond market index fund (c)
Total
December 31, 2019
Level 1
Level 2
Level 3
Total
160
$
(Thousands of Dollars)
— $
— $
160
—
17,473
92,737
—
—
—
92,737
17,473
48,666
66,299
$
—
92,737
$
—
— $
48,666
159,036
December 31, 2018
Level 1
Level 2
Level 3
Total
(Thousands of Dollars)
608
$
— $
— $
608
$
$
$
—
13,391
42,425
70,525
—
—
$
56,424
$
70,525
$
—
—
70,525
13,391
—
— $
42,425
126,949
(a) This fund is a low-cost equity index fund not actively managed that tracks the S&P 500. Fair values were estimated using pricing
models, quoted prices of securities with similar characteristics or discounted cash flows.
(b) This fund tracks the performance of the Total International Composite Index.
(c) This fund tracks the performance of the Barclays Capital U.S. Aggregate Bond Index.
Contributions to the Pension Plans
For the year ended December 31, 2019, we contributed $11.1 million and $0.2 million to the Pension Plans and other
postretirement benefit plans, respectively. During 2020, we expect to contribute approximately $11.3 million and $0.4 million
to the Pension Plans and other postretirement benefit plans, respectively, which principally represent contributions either
required by regulations or laws, or with respect to unfunded plans, necessary to fund current benefits.
Estimated Future Benefit Payments
The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid for the years
ending December 31:
2020
2021
2022
2023
2024
Years 2025-2029
Pension Plans
Other Postretirement
Benefit Plans
(Thousands of Dollars)
$
$
$
$
$
$
9,058
9,859
9,987
10,461
10,825
59,680
$
$
$
$
$
$
368
393
428
481
507
3,232
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Assumptions
The weighted-average assumptions used to determine the benefit obligations were as follows:
Discount rate
Rate of compensation increase
Pension Plans
December 31,
Other Postretirement
Benefit Plans
December 31,
2019
2018
2019
2018
3.34%
3.51%
4.40%
3.51%
3.43%
n/a
4.53%
n/a
The weighted-average assumptions used to determine the net periodic benefit cost (income) were as follows:
Discount rate
Expected long-term rate of
return on plan assets
Rate of compensation increase
Pension Plans
Year Ended December 31,
Other Postretirement
Benefit Plans
Year Ended December 31,
2019
2018
2017
2019
2018
2017
4.40%
3.72%
4.33%
4.53%
3.82%
4.49%
6.50%
3.51%
6.50%
3.51%
6.00%
3.51%
n/a
n/a
n/a
n/a
n/a
n/a
The assumed health care cost trend rates were as follows:
Health care cost trend rate assumed for next year
Rate to which the cost trend rate was assumed to decrease (the ultimate trend rate)
Year that the rate reaches the ultimate trend rate
December 31,
2019
2018
6.84%
5.00%
2028
6.84%
5.00%
2028
We sponsor a contributory postretirement health care plan for employees who retired prior to April 1, 2014. The plan has an
annual limitation (a cap) on the increase of the employer’s share of the cost of covered benefits. The cap on the increase in
employer’s cost is 2.5% per year. The assumed increase in total health care cost exceeds the 2.5% indexed cap, so increasing or
decreasing the health care cost trend rate by 1% does not materially change our obligation or expense for the postretirement
health care plan.
24. UNIT-BASED COMPENSATION
Overview
2019 LTIP. In April 2019, our common unitholders approved the 2019 Long-Term Incentive Plan (2019 LTIP) for eligible
employees, consultants and directors of NuStar Energy L.P., and of NuStar GP, LLC, and their respective affiliates who perform
services for us and our subsidiaries. The 2019 LTIP allows for the awarding of (i) options; (ii) restricted units; (iii) distribution
equivalent rights (DERs); (iv) performance cash; (v) performance units; and (vi) unit awards. DERs entitle the participant to
receive cash equal to cash distributions made on any award prior to its vesting. The 2019 LTIP permits the granting of awards
totaling an aggregate of 2,500,000 common units, subject to adjustment as provided in the 2019 LTIP. The 2019 LTIP generally
will be administered by the compensation committee of our board of directors. As of December 31, 2019, a total of 2,230,392
common units remained available to be awarded under the 2019 LTIP.
2000 LTIP. We sponsor the 2000 Long-Term Incentive Plan, as amended (2000 LTIP), which terminated with respect to new
grants when the unitholders approved the 2019 LTIP. However, unvested restricted unit and performance unit awards granted
under the 2000 LTIP remain outstanding.
2006 LTIP. Effective July 20, 2018 and in conjunction with the Merger, we assumed the 2006 Long-Term Incentive Plan, as
amended (the 2006 LTIP). Prior to the Merger, Holdings sponsored the 2006 LTIP. At the effective time of the Merger, each
outstanding award of Holdings restricted units was converted, on the same terms and conditions as were applicable to the
awards immediately prior to the Merger, into an award of NuStar Energy restricted units. The number of NuStar Energy
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
restricted units subject to the converted awards was determined pursuant to the 0.55 exchange ratio provided in the Merger
agreement. The Holdings units remaining available to be awarded under the 2006 LTIP were also converted pursuant to the
exchange ratio provided in the Merger agreement. Effective with the approval of the 2019 LTIP, the 2006 LTIP terminated with
respect to new grants; however, unvested restricted unit awards granted under the 2006 LTIP remain outstanding.
The following table summarizes information pertaining to all of our long-term incentive plans:
Restricted Units:
Domestic employees
Non-employee directors (NEDs)
International employees
Performance Units
Unit Awards
Total
Units Outstanding
December 31,
Compensation Expense
Year Ended December 31,
2019
2018
2017
2019
2018
2017
(Thousands of Dollars)
1,223,143
1,028,484
736,746
$
9,437
$
8,233
$
7,881
61,349
10,243
59,752
30,918
161,561
158,326
—
—
27,097
58,107
80,961
—
1,456,296
1,277,480
902,911
774
711
4,172
524
1,158
1,889
22,846
$ 37,940
18,895
$ 30,699
251
595
—
—
$
8,727
Restricted Units
Our restricted unit awards are considered phantom units, as they represent the right to receive our common units upon vesting.
We account for restricted units as either equity-classified awards or liability-classified awards, depending on expected method
of settlement. Awards we settle with the issuance of common units upon vesting are equity-classified. Awards we settle in cash
upon vesting are liability-classified. We record compensation expense ratably over the vesting period based on the fair value of
the common units at the grant date (for domestic employees and NEDs) or the fair value of the common units measured at each
reporting period (for international employees). DERs paid with respect to outstanding equity-classified unvested restricted units
reduce equity, similar to cash distributions to unitholders, whereas DERs paid with respect to outstanding liability-classified
unvested restricted units are expensed. In connection with the DERs for equity awards, we paid $2.7 million, $2.0 million and
$3.0 million respectively, in cash, for the years ended December 31, 2019, 2018 and December 31, 2017.
Domestic Employees. The outstanding restricted units granted to domestic employees are equity-classified awards and generally
vest over five years, beginning one year after the grant date. The fair value of these awards is measured at the grant date.
Non-Employee Directors. The outstanding restricted units granted to NEDs are equity-classified awards that vest over three
years. As discussed in Note 3, on January 1, 2019 we adopted amended guidance that will allow for the fair value of these
awards to be measured at the grant date. The unvested restricted units granted to NEDs as of January 1, 2019 were measured at
the fair value as of that date. Previously, the fair value of these awards was equal to the market price of our common units at
each reporting period.
International Employees. The outstanding restricted units granted to international employees are cash-settled and accounted for
as liability-classified awards. These awards vest over three years and the fair value is equal to the market price of our common
units at each reporting period. For the year ended December 31, 2019, we granted 5,378 restricted units and 26,053 restricted
units vested.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
A summary of our restricted unit activity for domestic employees and, beginning January 1, 2019, NEDs is as follows:
Number of
Restricted Units
Weighted-Average
Grant-Date Fair Value
Per Unit
Nonvested units as of January 1, 2017
647,340
$
Granted
Vested
Forfeited
Nonvested units as of December 31, 2017
Converted on July 20, 2018
Granted
Vested
Forfeited
Nonvested units as of December 31, 2018
NEDs
Granted
Vested
Forfeited
Nonvested units as of December 31, 2019
307,009
(201,466)
(16,137)
736,746
53,447
518,282
(235,746)
(44,245)
1,028,484
59,752
596,881
(328,386)
(72,239)
1,284,492
39.72
29.56
38.74
40.00
35.95
24.99
24.07
35.12
36.05
29.47
20.93
26.46
30.11
28.05
27.48
The total fair value of our equity-classified restricted unit awards vested for the years ended December 31, 2019, 2018 and 2017
was $9.3 million, $6.2 million and $6.5 million, respectively. We issued 242,199, 189,399 and 152,017 common units in
connection with these award vestings, net of employee tax withholding requirements, for the years ended December 31, 2019,
2018 and 2017, respectively. Unrecognized compensation cost related to our equity-classified employee awards totaled $32.5
million as of December 31, 2019, which we expect to recognize over a weighted-average period of 3.8 years.
Performance Units
Performance units are issued to certain of our key employees and represent rights to receive our common units upon achieving
performance measures for the performance period established by the NuStar GP, LLC Compensation Committee for the
following year. Achievement of the performance measures determines the rate at which the performance units convert into our
common units, which ranges from zero to 200% for certain awards.
Performance units awarded vest in three annual increments (tranches), based upon our achievement of the performance
measures set by the Compensation Committee during the one-year performance periods that end on December 31 of each
applicable year. Therefore, the performance units are not considered granted for accounting purposes until the Compensation
Committee has set the performance measures for each tranche of awards. Performance units are equity-classified awards
measured at the grant date fair value. In addition, since the performance units granted do not receive DERs, the grant date fair
value of these awards is reduced by the per unit distributions expected to be paid to common unitholders during the vesting
period. We record compensation expense ratably for each vesting tranche over its requisite service period (one year) if it is
probable that the specified performance measures will be achieved. Additionally, changes in the actual or estimated outcomes
that affect the quantity of performance units expected to be converted are recognized as a cumulative adjustment.
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A summary of our performance units is shown below:
Granted for Accounting Purposes
Outstanding as of January 1, 2017
Granted
Performance adjustments (a)
Vested
Outstanding as of December 31, 2017
Granted
Forfeitures
Outstanding as of December 31, 2018
Granted
Vested
Forfeitures
Outstanding as of December 31, 2019
Total Performance
Units Awarded
Performance Units
77,014
39,320
17,690
(53,063)
80,961
116,230
(38,865)
158,326
95,969
(80,690)
(12,044)
161,561
35,373
38,865
17,690
(53,063)
38,865
80,690
(38,865)
80,690
74,439
(80,690)
—
74,439
Weighted-Average Grant
Date Fair Value per Unit
31.75
$
50.04
31.75
31.75
50.04
23.43
50.04
23.43
28.01
23.43
—
28.01
(a) Represents the additional units issued to employees resulting from performance that exceeded the specified targets for the
performance measures.
For the year ended December 31, 2017, we issued 33,438 common units in connection with the performance award vestings
related to 2016 performance, net of employee tax withholding requirements, and the total fair value of performance awards
vested was $2.9 million. For the year ended December 31, 2018, no performance units vested with respect to 2017
performance. For the year ended December 31, 2019, we issued 50,054 common units in connection with the performance
award vestings related to 2018 performance, net of employee tax withholding requirements, and the total fair value of
performance awards vested was $2.1 million.
Unit Awards
Unit awards are equity-classified awards of fully vested common units. We accrued compensation expense in 2019 and 2018
that was paid in unit awards in February of the subsequent years. We base the number of unit awards granted on the fair value
of the common units at the grant date. A summary of our unit awards is shown below:
Date of Grant
Grant Date Fair Value
Unit Awards Granted
Common Units Issued, Net of
Employee Withholding Tax
February 11, 2020
February 11, 2019
July 23, 2018
(Thousands of Dollars)
$
$
$
22,846
17,537
1,358
822,979
704,886
55,133
563,806
482,971
35,745
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25. INCOME TAXES
NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Components of income tax expense related to certain of our continuing operations conducted through separate taxable wholly
owned corporate subsidiaries were as follows:
Current:
U.S.
Foreign
Foreign withholding tax
Total current
Deferred:
U.S.
Foreign
Foreign withholding tax
Total deferred
Less: amounts reported in discontinued operations
Year Ended December 31,
2019
2018
2017
(Thousands of Dollars)
$
$
3,741
1,489
101
5,331
(490)
(168)
182
(476)
101
$
4,515
4,658
192
9,365
1,403
394
246
2,043
1,251
3,117
6,335
479
9,931
1,468
(1,065)
(397)
6
2,164
Income tax expense
$
4,754
$
10,157
$
7,773
The difference between income tax expense recorded in our consolidated statements of (loss) income and income taxes
computed by applying the statutory federal income tax rate (21% for 2019 and 2018 and 35% for 2017) to income before
income tax expense is due to the fact that the majority of our income is not subject to federal income tax due to our status as a
limited partnership. We record a tax provision related to the amount of undistributed earnings of our foreign subsidiaries
expected to be repatriated.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
The tax effects of significant temporary differences representing deferred income tax assets and liabilities were as follows:
Deferred income tax assets:
Net operating losses
Employee benefits
Environmental and legal reserves
Allowance for bad debt
Capital loss
Other
Total deferred income tax assets
Less: Valuation allowance
Net deferred income tax assets
Deferred income tax liabilities:
Property, plant and equipment
Foreign withholding tax
Total deferred income tax liabilities
Net deferred income tax liability
Reported on the consolidated balance sheets as:
Deferred income tax liability
December 31,
2019
2018
(Thousands of Dollars)
$
26,081
372
267
—
3,870
328
30,918
(17,743)
13,175
(25,169)
(433)
(25,602)
21,009
362
239
1,970
—
1,796
25,376
(12,442)
12,934
(25,128)
(234)
(25,362)
(12,427) $
(12,428)
(12,427) $
(12,428)
$
$
$
As of December 31, 2019, our U.S. and foreign corporate operations have net operating loss carryforwards for tax purposes
totaling $96.8 million and $19.1 million, respectively, which are subject to various limitations on use and expire in years 2025
through 2037 for U.S. losses and in years 2019 through 2029 for foreign losses. However, U.S. losses generated after
December 31, 2017 can be carried forward indefinitely. As of December 31, 2019, our U.S. corporate operations have a capital
loss carryforward for tax purposes totaling $18.4 million, which is subject to limitations on use and expires in 2024.
As of December 31, 2019 and 2018, we recorded a valuation allowance of $17.7 million and $12.4 million, respectively, related
to our deferred tax assets. We estimate the amount of valuation allowance based upon our expectations of taxable income in the
various jurisdictions in which we operate and the period over which we can utilize those future deductions. The valuation
allowance reflects uncertainties related to our ability to utilize certain net operating loss carryforwards before they expire. In
2019, there was a $3.7 million increase in the valuation allowance for the U.S. net operating loss and a $1.6 million increase in
the foreign net operating loss valuation allowance due to changes in our estimates of the amount of those loss carryforwards
that will be realized, based upon future taxable income.
The realization of net deferred income tax assets recorded as of December 31, 2019 is dependent upon our ability to generate
future taxable income in the United States. We believe it is more likely than not that the net deferred income tax assets as of
December 31, 2019 will be realized, based on expected future taxable income.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
26. SEGMENT INFORMATION
Our reportable business segments consist of the pipeline, storage and fuels marketing segments. Our segments represent
strategic business units that offer different services and products. We evaluate the performance of each segment based on its
respective operating income, before general and administrative expenses and certain non-segmental depreciation and
amortization expense. General and administrative expenses are not allocated to the operating segments since those expenses
relate primarily to the overall management at the entity level. Our principal operations include the transportation of petroleum
products and anhydrous ammonia, and the terminalling, storage and marketing of petroleum products. Intersegment revenues
result from storage agreements with wholly owned subsidiaries of NuStar Energy at rates consistent with the rates charged to
third parties for storage.
Results of operations for the reportable segments were as follows:
Revenues:
Pipeline
Storage:
Third parties
Intersegment
Total storage
Fuels marketing
Consolidation and intersegment eliminations
Total revenues
Depreciation and amortization expense:
Pipeline
Storage
Total segment depreciation and amortization expense
Other depreciation and amortization expense
Total depreciation and amortization expense
Operating income:
Pipeline
Storage
Fuels marketing
Consolidation and intersegment eliminations
Total segment operating income
General and administrative expenses
Other depreciation and amortization expense
Total operating income
Year Ended December 31,
2019
2018
2017
(Thousands of Dollars)
$
701,830
$
611,065
$
516,288
$
$
$
$
453,976
25
454,001
342,215
(25)
1,498,021
$
443,546
42
443,588
465,651
(42)
1,520,262
$
438,677
4,339
443,016
489,807
(4,339)
1,444,772
166,991
$
153,943
$
97,573
264,564
8,360
93,345
247,288
8,604
128,061
91,696
219,757
8,435
272,924
$
255,892
$
228,192
332,480
$
272,695
$
154,105
20,578
(32)
507,131
107,855
8,360
155,708
15,964
32
444,399
100,067
8,604
231,795
172,720
1,987
(1)
406,501
107,556
8,435
$
390,916
$
335,728
$
290,510
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Revenues by geographic area are shown in the table below:
United States
Foreign
Consolidated revenues
Year Ended December 31,
2019
2018
2017
(Thousands of Dollars)
$
$
1,465,135
32,886
1,498,021
$
$
1,481,844
38,418
1,520,262
$
$
1,406,776
37,996
1,444,772
For the years ended December 31, 2019, 2018 and 2017, Valero Energy Corporation accounted for approximately 21%, or
$307.2 million, 20%, or $303.7 million, and 20%, or $294.5 million, of our revenues, respectively. These revenues were
included in all of our reportable business segments. No other single customer accounted for 10% or more of our consolidated
revenues.
Total amounts of property, plant and equipment, net by geographic area were as follows:
United States
Foreign
Consolidated property, plant and equipment, net
Total assets by reportable segment were as follows:
Pipeline
Storage
Fuels marketing
Total segment assets
Assets held for sale
Other partnership assets
Total consolidated assets
December 31,
2019
2018
(Thousands of Dollars)
$
$
4,000,647
118,332
4,118,979
$
$
3,688,631
86,171
3,774,802
December 31,
2019
2018
(Thousands of Dollars)
$
3,884,819
$
3,637,226
2,082,832
31,064
5,998,715
—
187,277
1,902,764
37,252
5,577,242
599,347
172,551
$
6,185,992
$
6,349,140
Capital expenditures, including acquisitions, by reportable segment were as follows:
Pipeline
Storage
Other partnership assets
Total capital expenditures
Year Ended December 31,
2019
2018
2017
(Thousands of Dollars)
$
$
387,702
$
288,035
$
1,596,311
141,972
3,894
202,782
4,137
244,398
5,648
533,568
$
494,954
$
1,846,357
Capital expenditures have not been adjusted to separately disclose those capital expenditures related to discontinued operations,
which are included in the storage segment totaling $28.0 million, $114.8 million, and $153.8 million for the years ended
December 31, 2019, 2018 and 2017, respectively.
114
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NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
27. CONDENSED CONSOLIDATING FINANCIAL STATEMENTS
NuStar Energy has no operations, and its assets consist mainly of its 100% indirectly owned subsidiaries, NuStar Logistics and
NuPOP. The senior and subordinated notes issued by NuStar Logistics are fully and unconditionally guaranteed by NuStar
Energy and NuPOP. As a result, the following condensed consolidating financial statements are presented as an alternative to
providing separate financial statements for NuStar Logistics and NuPOP.
Assets
Cash and cash equivalents
Receivables, net
Inventories
Prepaid and other current assets
Intercompany receivable
Total current assets
Property, plant and equipment, net
Intangible assets, net
Goodwill
Investment in wholly owned
subsidiaries
Other long-term assets, net
Total assets
Liabilities, Mezzanine Equity and
Partners’ Equity
Accounts payable
Short-term debt and current portion
of finance leases
Current portion of long-term debt
Accrued interest payable
Accrued liabilities
Taxes other than income tax
Income tax payable
Intercompany payable
Total current liabilities
Long-term debt, less current portion
Deferred income tax liability
Other long-term liabilities
Series D preferred units
Total partners’ equity
Total liabilities, mezzanine
equity and partners’ equity
Condensed Consolidating Balance Sheets
December 31, 2019
(Thousands of Dollars)
NuStar
Energy
NuStar
Logistics
NuPOP
Non-Guarantor
Subsidiaries
Eliminations
Consolidated
$
$
$
24
176
317
—
1,953
—
61
16,325
— 1,276,839
1,295,458
237
— 2,058,530
39,683
—
149,453
—
— $
4
4,821
600
—
5,425
612,128
—
170,652
15,992
152,209
5,619
4,947
610,298
789,065
1,448,321
641,949
685,748
$
— $
—
—
—
(1,887,137)
(1,887,137)
16,192
152,530
12,393
21,933
—
203,048
— 4,118,979
—
681,632
— 1,005,853
2,871,540
98
$ 2,871,875
1,743,066
111,362
$ 5,397,552
1,155,855
32,121
$ 1,976,181
490,826
32,899
$ 4,088,808
(6,261,287)
—
—
176,480
$(8,148,424) $ 6,185,992
$
5,427
$
42,064
$
8,379
$
53,964
$
— $
109,834
—
—
—
1,425
125
—
438,857
445,834
299
9,722
—
452,367
4
37,888
8,461
40,514
5,160
7,311
492
2
— 1,448,280
1,470,585
1,127
10
13,774
—
490,685
590,358
— 2,871,786
1,499
—
65,577
—
581,935
—
1,868,332
1,844,106
25
—
33
53,885
185
3,831
—
—
—
—
—
—
— (1,887,137)
(1,887,137)
10,046
452,367
37,925
104,285
12,781
4,325
—
731,563
— 2,934,918
12,427
—
148,939
—
581,935
—
1,776,210
(6,261,287)
111,923
62,005
10,918
69,588
—
3,834,374
$ 2,871,875
$ 5,397,552
$ 1,976,181
$ 4,088,808
$(8,148,424) $ 6,185,992
115
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NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Condensed Consolidating Balance Sheets
December 31, 2018
(Thousands of Dollars)
NuStar
Energy
NuStar
Logistics
NuPOP
Non-Guarantor
Subsidiaries
Eliminations
Consolidated
Assets
Cash and cash equivalents
Receivables, net
Inventories
Prepaid and other current assets
Assets held for sale
Intercompany receivable
Total current assets
Property, plant and equipment, net
Intangible assets, net
Goodwill
Investment in wholly owned
subsidiaries
Other long-term assets, net
Total assets
Liabilities, Mezzanine Equity and
Partners’ Equity
Accounts payable
Short-term debt
Accrued interest payable
Accrued liabilities
Taxes other than income tax
Income tax payable
Liabilities held for sale
Intercompany payable
Total current liabilities
Long-term debt
Deferred income tax liability
Other long-term liabilities
Series D preferred units
Total partners’ equity
Total liabilities, mezzanine
equity and partners’ equity
$
$
51
1,255
2,212
—
1,741
—
14,422
61
—
—
— 1,327,833
1,346,259
— 1,858,264
49,107
—
149,453
—
1,316
$
— $
—
5,237
908
—
—
6,145
615,549
—
170,652
10,223
108,205
1,456
1,983
599,347
500,583
1,221,797
1,300,989
683,949
685,748
$
— $
—
—
—
—
(1,828,416)
(1,828,416)
11,529
110,417
8,434
17,374
599,347
—
747,101
— 3,774,802
—
733,056
— 1,005,853
3,355,636
304
$ 3,357,256
1,750,256
54,429
$ 5,207,768
1,425,283
26,716
$ 2,244,345
857,485
6,879
$ 4,756,847
(7,388,660)
—
—
88,328
$(9,217,076) $ 6,349,140
$
$
6,460
—
—
1,280
125
—
—
472,790
480,655
127,033
— 3,050,531
1,675
—
28,392
—
—
563,992
2,000,137
2,312,609
$
6,331
39,680
—
18,500
—
36,253
8,082
24,858
4,718
7,285
2
457
—
—
— 1,355,626
1,374,759
—
9
12,348
—
857,229
$
50,651
—
40
40,198
4,695
3,986
69,834
$
— $
—
—
—
—
—
—
— (1,828,416)
(1,828,416)
103,122
18,500
36,293
74,418
16,823
4,445
69,834
—
323,435
— 3,111,996
12,428
—
79,558
—
563,992
—
2,257,731
(7,388,660)
169,404
61,465
10,744
38,818
—
4,476,416
$ 3,357,256
$ 5,207,768
$ 2,244,345
$ 4,756,847
$(9,217,076) $ 6,349,140
116
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NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Condensed Consolidating Statements of (Loss) Income
For the Year Ended December 31, 2019
(Thousands of Dollars)
Revenues
Costs and expenses
Operating (loss) income
Equity in earnings of subsidiaries
Interest income (expense), net
Other income (expense), net
Income from continuing
operations before income tax
expense (benefit)
Income tax expense (benefit)
Income from continuing
operations, net of tax
(Loss) income from discontinued
operations, net of tax (a)
Net (loss) income
NuStar
Energy
NuStar
Logistics
$
— $
545,863
$
2,574
(2,574)
208,995
415
—
338,291
207,572
42,139
(187,337)
3,002
NuPOP
258,420
159,376
99,044
51,537
(6,961)
744
Non-Guarantor
Subsidiaries
$
694,485
607,611
86,874
144,366
10,813
(4)
Eliminations
$
Consolidated
(747) $ 1,498,021
(747)
1,107,105
—
(447,037)
—
390,916
—
(183,070)
3,742
—
206,836
2
65,376
(230)
144,364
3
242,049
4,979
(447,037)
—
211,588
4,754
206,834
65,606
144,361
237,070
(447,037)
206,834
(312,527)
$ (105,693) $
7,912
73,518
(320,439)
$ (176,078) $
(640,877)
(403,807) $
953,404
506,367
(312,527)
$ (105,693)
(a) Includes equity in earnings (loss) of subsidiaries related to discontinued operations.
Condensed Consolidating Statements of Income (Loss)
For the Year Ended December 31, 2018
(Thousands of Dollars)
Revenues
Costs and expenses
Operating (loss) income
Equity in earnings of subsidiaries
Interest income (expense), net
Other income, net
Income (loss) from continuing
operations before income tax
expense (benefit)
Income tax expense (benefit)
Income (loss) from continuing
operations, net of tax
Income from discontinued
operations, net of tax (a)
Net income (loss)
NuStar
Energy
NuStar
Logistics
$
— $
485,603
$
2,407
(2,407)
148,554
228
—
317,286
168,317
17,167
(191,835)
3,876
NuPOP
260,679
163,667
97,012
62,494
(7,127)
446
Non-Guarantor
Subsidiaries
$
774,685
701,879
72,806
152,830
14,336
880
Eliminations
$
Consolidated
(705) $ 1,520,262
(705)
1,184,534
—
(381,045)
—
335,728
—
(184,398)
5,202
—
146,375
—
(2,475)
588
152,825
(3)
240,852
9,572
(381,045)
—
156,532
10,157
146,375
(3,063)
152,828
231,280
(381,045)
146,375
59,419
$
205,794
$
—
(3,063) $
59,419
118,838
212,247
$
350,118
(178,257)
$ (559,302) $
59,419
205,794
(a) Includes equity in earnings (loss) of subsidiaries related to discontinued operations.
117
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NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Condensed Consolidating Statements of Income (Loss)
For the Year Ended December 31, 2017
(Thousands of Dollars)
Revenues
Costs and expenses
Operating (loss) income
Equity in earnings (loss)
of subsidiaries
Interest income (expense), net
Other income (expense), net
Income (loss) from continuing
operations before income tax
(benefit) expense
Income tax (benefit) expense
Income (loss) from continuing
operations, net of tax
Income from discontinued
operations, net of tax (a)
Net income (loss)
NuStar
Energy
NuStar
Logistics
$
— $
496,454
$
1,868
(1,868)
317,871
178,583
NuPOP
221,125
146,243
74,882
(10,616)
(176,897)
145
52,336
(5,587)
3
Non-Guarantor
Subsidiaries
$
728,211
689,298
38,913
121,631
10,653
(216)
Eliminations
$
Consolidated
(1,018) $ 1,444,772
(1,018)
1,154,262
—
290,510
(276,057)
—
—
—
(171,774)
(68)
(8,785)
(820)
121,634
2
170,981
8,591
(276,057)
—
118,668
7,773
110,895
(7,965)
121,632
162,390
(276,057)
110,895
37,069
$
147,964
$
—
(7,965) $
37,069
74,138
158,701
$
236,528
(111,207)
$ (387,264) $
37,069
147,964
112,706
57
—
110,895
—
(a) Includes equity in earnings (loss) of subsidiaries related to discontinued operations.
118
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NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Condensed Consolidating Statements of Comprehensive (Loss) Income
For the Year Ended December 31, 2019
(Thousands of Dollars)
Net (loss) income
$ (105,693) $
73,518
$ (176,078) $
(403,807) $
NuStar
Energy
NuStar
Logistics
NuPOP
Non-Guarantor
Subsidiaries
Eliminations
506,367
Consolidated
$ (105,693)
Other comprehensive income (loss):
Foreign currency translation
adjustment
Net loss on pension and other
postretirement benefit
adjustments, net of tax benefit
Net loss on cash flow hedges
Total other comprehensive (loss)
income
—
—
—
—
Comprehensive (loss) income
$ (105,693) $
—
—
(15,231)
(15,231)
58,287
—
—
—
—
$ (176,078) $
3,527
(1,314)
—
2,213
(401,594) $
—
—
—
—
506,367
3,527
(1,314)
(15,231)
(13,018)
$ (118,711)
Condensed Consolidating Statements of Comprehensive Income
For the Year Ended December 31, 2018
(Thousands of Dollars)
Net income (loss)
Other comprehensive income:
Foreign currency translation
adjustment
Net gain on pension and other
postretirement benefit
adjustments, net of tax expense
Net gain on cash flow hedges
Total other comprehensive income
NuStar
Energy
205,794
$
NuStar
Logistics
$
(3,063) $
NuPOP
212,247
Non-Guarantor
Subsidiaries
$
350,118
Eliminations
$ (559,302) $
Consolidated
205,794
—
—
—
—
—
—
23,411
23,411
—
—
—
—
4,304
2,334
—
6,638
—
—
—
—
4,304
2,334
23,411
30,049
Comprehensive income
$
205,794
$
20,348
$
212,247
$
356,756
$ (559,302) $
235,843
Condensed Consolidating Statements of Comprehensive Income (Loss)
For the Year Ended December 31, 2017
(Thousands of Dollars)
NuStar
Energy
147,964
$
NuStar
Logistics
$
(7,965) $
NuPOP
158,701
Non-Guarantor
Subsidiaries
$
236,528
Eliminations
$ (387,264) $
Consolidated
147,964
Net income (loss)
Other comprehensive income (loss):
Foreign currency translation
adjustment
Net loss on pension and other
postretirement benefit
adjustments, net of tax benefit
Net loss on cash flow hedges
Total other comprehensive (loss)
income
Comprehensive income (loss)
$
147,964
$
—
—
—
—
—
—
—
—
17,466
(6,170)
—
11,296
—
—
—
—
17,466
(6,170)
(2,046)
9,250
158,701
$
247,824
$ (387,264) $
157,214
—
—
(2,046)
(2,046)
(10,011) $
119
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NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Condensed Consolidating Statements of Cash Flows
For the Year Ended December 31, 2019
(Thousands of Dollars)
Net cash provided by operating
activities
Cash flows from investing activities:
Capital expenditures
Change in accounts payable
related to capital expenditures
Proceeds from sale or disposition
of assets
Investment in subsidiaries
Other, net
Net cash used in investing activities
Cash flows from financing activities:
Debt borrowings
Debt repayments
Issuance of common units, net of
issuance costs
Distributions to preferred
unitholders
Distributions to common unitholders
Contributions from affiliates
Net intercompany activity
Other, net
Net cash (used in) provided by
financing activities
Effect of foreign exchange rate
changes on cash
Net (decrease) increase in cash, cash
equivalents and restricted cash
Cash, cash equivalents and restricted
cash as of the beginning of the
period
Cash, cash equivalents and restricted
cash as of the end of the period
NuStar
Energy
NuStar
Logistics
NuPOP
Non-Guarantor
Subsidiaries
Eliminations
Consolidated
$ 376,999
$
166,005
$
126,728
$
409,115
$ (570,090) $
508,757
—
—
—
—
—
—
(257,117)
(28,592)
(247,859)
1,369
1,212
(15,312)
247
(11,999)
—
(267,500)
90
—
—
(27,290)
—
—
—
11,999
—
11,999
(533,568)
(12,731)
228,152
—
(1,100)
(319,247)
— 1,458,380
— (1,249,400)
227,815
—
(1,100)
(36,456)
42,800
(42,400)
—
—
15,000
— 1,415,580
— (1,207,000)
15,000
—
—
—
—
(121,693)
(258,354)
—
(2,010)
(11,021)
(60,846)
(129,177)
—
101,980
(10,281)
(60,847)
(129,177)
—
90,734
(148)
(60,853)
(129,190)
11,999
(190,704)
(133)
182,546
387,544
(11,999)
—
—
(121,693)
(258,354)
—
—
(21,583)
(378,078)
110,256
(99,438)
(368,481)
558,091
(177,650)
—
—
(1,079)
8,761
1,255
51
—
—
—
(524)
3,654
12,338
—
—
—
(524)
11,336
13,644
$
176
$
8,812
$
— $
15,992
$
— $
24,980
120
Table of Contents
NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Condensed Consolidating Statements of Cash Flows
For the Year Ended December 31, 2018
(Thousands of Dollars)
Net cash provided by operating
activities
Cash flows from investing activities:
Capital expenditures
Change in accounts payable
related to capital expenditures
Acquisitions
Proceeds from insurance recoveries
Proceeds from sale or disposition
of assets
Investment in subsidiaries
Net cash used in investing activities
Cash flows from financing activities:
Debt borrowings
Debt repayments
Issuance of Series D preferred units
Payment of issuance costs for
Series D preferred units
Issuance of common units, net of
issuance costs
General partner contribution
Distributions to preferred
unitholders
Distributions to common unitholders
and general partner
Cash consideration for Merger
(Note 4)
Proceeds from termination of
interest rate swaps
Contributions from affiliates
Net intercompany activity
Other, net
Net cash provided by (used in)
financing activities
Effect of foreign exchange rate
changes on cash
Net increase (decrease) in cash and
cash equivalents
Cash and cash equivalents as of the
beginning of the period
Cash and cash equivalents as of the
end of the period
NuStar
Energy
NuStar
Logistics
NuPOP
Non-Guarantor
Subsidiaries
Eliminations
Consolidated
$ 444,233
$
100,385
$
179,512
$
514,936
$ (694,859) $
544,207
(71,044)
(19,152)
(367,256)
—
—
—
—
11,101
—
—
—
(708,600)
(708,600)
2,674
(1,711,975)
(1,769,244)
— 1,840,853
— (2,349,476)
—
590,000
(34,203)
10,000
204
—
—
—
(5,161)
(37,502)
—
31
(54,600)
(116,384)
—
—
—
—
—
—
(13,623)
—
78,419
267,735
(54,665)
(89,390)
31,800
(32,300)
—
—
—
—
—
—
—
—
—
2,529,840
2,529,840
(457,452)
(7,683)
(37,502)
78,419
270,440
—
(153,778)
— 1,872,653
— (2,381,776)
590,000
—
—
—
—
(34,203)
10,000
204
(90,670)
(45,336)
(45,336)
(45,335)
136,007
(90,670)
(300,777)
(150,388)
(150,388)
(150,408)
451,184
(300,777)
(67,936)
—
—
8,048
—
162,498
(4,379)
599,400
1,766,881
(1,101)
—
—
54,600
77,996
—
141
—
1,768,172
(2,007,375)
(71)
—
(67,795)
—
(2,422,172)
—
—
8,048
—
—
(5,551)
264,737
1,668,881
(63,128)
(435,376)
(1,834,981)
(399,867)
—
370
885
—
22
29
—
—
—
(1,210)
(11,040)
23,378
—
—
—
(1,210)
(10,648)
24,292
$
1,255
$
51
$
— $
12,338
$
— $
13,644
121
Table of Contents
NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Condensed Consolidating Statements of Cash Flows
For the Year Ended December 31, 2017
(Thousands of Dollars)
Net cash provided by operating
activities
Cash flows from investing activities:
Capital expenditures
Change in accounts payable
related to capital expenditures
Acquisitions
Proceeds from Axeon term loan
Proceeds from insurance recoveries
Proceeds from sale or disposition
of assets
Investment in subsidiaries
Net cash (used in) provided by
investing activities
Cash flows from financing activities:
Debt borrowings
Debt repayments
Issuance of preferred units, net of
issuance costs
Issuance of common units, net of
issuance costs
General partner contribution
Distributions to preferred
unitholders
Distributions to common unitholders
and general partner
Contributions from
(distributions to) affiliates
Net intercompany activity
Other, net
Net cash provided by (used in)
financing activities
Effect of foreign exchange rate
changes on cash
Net increase (decrease) in cash and
cash equivalents
Cash and cash equivalents as of the
beginning of the period
Cash and cash equivalents as of the
end of the period
NuStar
Energy
NuStar
Logistics
NuPOP
Non-Guarantor
Subsidiaries
Eliminations
Consolidated
$ 483,481
$
152,101
$
102,405
$
405,950
$ (737,138) $
406,799
(47,600)
(35,041)
(301,997)
—
(384,638)
—
—
—
—
—
(1,988)
—
110,000
—
—
(1,262,000)
1,955
—
5,964
—
—
—
18
—
32,927
(1,461,719)
—
—
36,903
— (1,461,719)
110,000
—
977
63
(126)
—
—
1,262,126
977
2,036
—
(1,262,000)
62,367
(29,059)
(1,729,875)
1,262,126
(1,696,441)
— 2,969,400
— (2,400,739)
538,560
643,878
13,737
—
—
—
—
—
—
—
—
90,700
(86,800)
— 3,060,100
— (2,487,539)
—
—
—
—
—
—
538,560
643,878
13,737
(38,833)
(19,417)
(19,416)
(19,418)
58,251
(38,833)
(446,306)
(223,153)
(223,153)
(223,176)
669,482
(446,306)
— 1,262,000
(1,801,218)
(1,317)
73,206
(5,708)
—
169,223
—
(9,279)
1,558,789
(300)
(1,252,721)
—
—
—
—
(7,325)
778,534
(214,444)
(73,346)
1,310,516
(524,988)
1,276,272
—
15
870
—
24
5
—
—
—
1,720
(11,689)
35,067
—
—
—
1,720
(11,650)
35,942
$
885
$
29
$
— $
23,378
$
— $
24,292
122
Table of Contents
NUSTAR ENERGY L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
28. QUARTERLY FINANCIAL DATA (UNAUDITED)
The following table summarizes quarterly financial data for the years ended December 31, 2019 and 2018:
2019:
Revenues
Operating income
Income from continuing operations, net of tax
Loss from discontinued operations, net of tax
Net (loss) income
Basic and diluted net (loss) income per common unit:
Continuing operations
Discontinued operations
Total
Cash distributions per unit applicable to common
limited partners
2018:
Revenues
Operating income
$
$
$
First
Quarter
Second
Quarter
Third
Quarter
Fourth
Quarter
Total
(Thousands of Dollars, Except Per Unit Data)
$ 347,826
73,605
$
$ 372,445
93,283
$
$ 378,056
99,972
$
$ 399,694
$ 124,056
$ 1,498,021
390,916
$
$
$
28,923
(306,786)
$ (277,863) $
46,915
(964)
45,951
(0.06) $
(2.85)
(2.91) $
0.11
(0.01)
0.10
$
$
$
$
52,588
(4,777)
47,811
0.15
(0.04)
0.11
$
$
$
$
78,408
—
78,408
$
206,834
(312,527)
$ (105,693)
0.40
—
0.40
$
$
0.60
(2.90)
(2.30)
0.60
$
0.60
$
0.60
$
0.60
$
2.40
$ 376,727
83,493
$
$ 389,256
76,387
$
$ 380,142
89,165
$
$ 374,137
86,683
$
$ 1,520,262
335,728
$
Income from continuing operations, net of tax
Income (loss) from discontinued operations, net of tax
Net income
$
33,233
92,900
$ 126,133
Basic and diluted net income (loss) per common unit:
Continuing operations
Discontinued operations
Total
Cash distributions per unit applicable to common
limited partners
$
$
$
$
$
$
$
26,909
2,490
29,399
0.12
0.03
0.15
$
$
$
$
43,663
4,473
48,136
$
$
42,570
(40,444)
2,126
$
$
146,375
59,419
205,794
(3.53) $
0.04
(3.49) $
$
0.07
(0.38)
(0.31) $
(3.34)
0.57
(2.77)
0.18
0.97
1.15
0.60
$
0.60
$
0.60
$
0.60
$
2.40
The quarterly financial data in the table above includes the following:
•
•
•
impairment and goodwill losses of $297.3 million and $31.1 million, respectively, in the first quarter of 2019 (please
refer to Note 5 for further discussion);
the $43.4 million non-cash loss associated with the sale of our European Operations in the fourth quarter of 2018
(please refer to Note 5 for further discussion); and
the $78.8 million gain from hurricane insurance proceeds received in the first quarter of 2018 (please refer to Note 1
for further discussion).
Basic and diluted net income (loss) per common unit also includes the impact of the $377.1 million loss as a result of the
Merger in 2018. Please refer to Notes 4 and 21 for further discussion.
123
Table of Contents
ITEM 9.
None.
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
ITEM 9A.
CONTROLS AND PROCEDURES
DISCLOSURE CONTROLS AND PROCEDURES
Our management has evaluated, with the participation of the principal executive officer and principal financial officer of
NuStar GP, LLC, the effectiveness of our disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities
Exchange Act of 1934) as of the end of the period covered by this report, and has concluded that our disclosure controls and
procedures were effective as of December 31, 2019.
INTERNAL CONTROL OVER FINANCIAL REPORTING
(a)
Management’s Report on Internal Control over Financial Reporting.
Management’s report on NuStar Energy L.P.’s internal control over financial reporting appears in Item 8. of this Form 10-K,
and is incorporated herein by reference.
(b)
Attestation Report of the Registered Public Accounting Firm.
The report of KPMG LLP on NuStar Energy L.P.’s internal control over financial reporting appears in Item 8. of this Form 10-
K, and is incorporated herein by reference.
(c)
Changes in Internal Control over Financial Reporting.
There has been no change in our internal control over financial reporting that occurred during our last fiscal quarter that has
materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.
ITEM 9B.
OTHER INFORMATION
None.
124
Table of Contents
PART III
ITEM 10.
DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
Information required to be disclosed under this Item 10 is incorporated by reference to the following sections of our Proxy
Statement for the 2020 annual meeting of unitholders, which is expected to be filed within 120 days after the end of the fiscal
year covered by this Form 10-K (Proxy Statement): “Corporate Governance-Leadership and Governance,” “Corporate
Governance-Committees of the Board,” “Corporate Governance-Governance Documents and Codes of Ethics,” “Corporate
Governance-Communications with the Board of Directors,” “Proposal No. 1 Election of Directors” and “Information About
Our Executive Officers.”
ITEM 11.
EXECUTIVE COMPENSATION
Information required to be disclosed under this Item 11 is incorporated by reference to the following sections of our Proxy
Statement: “Corporate Governance-Compensation Committee Interlocks and Insider Participation,” “Compensation Committee
Report,” “Compensation Discussion and Analysis,” “Evaluation of Compensation Risk,” “Summary Compensation Table,”
“Pay Ratio,” “Grants of Plan-Based Awards During the Year Ended December 31, 2019,” “Outstanding Equity Awards at
December 31, 2019,” “Option Exercises and Units Vested During the Year Ended December 31, 2019,” “Pension Benefits for
the Year Ended December 31, 2019,” “Nonqualified Deferred Compensation for the Year Ended December 31, 2019,”
“Potential Payments Upon Termination or Change of Control” and “Director Compensation.”
ITEM 12.
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND
RELATED UNITHOLDER MATTERS
Information required to be disclosed under this Item 12 is incorporated by reference to the following sections of our Proxy
Statement: “Security Ownership-Security Ownership of Management and Directors,” “Security Ownership-Security Ownership
of Certain Beneficial Owners” and “Security Ownership-Equity Compensation Plan Information.”
ITEM 13.
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR
INDEPENDENCE
Information required to be disclosed under this Item 13 is incorporated by reference to the following sections of our Proxy
Statement: “Corporate Governance-Director Independence,” “Corporate Governance-Board Leadership and Governance” and
“Certain Relationships and Related Party Transactions.”
ITEM 14.
PRINCIPAL ACCOUNTANT FEES AND SERVICES
Information required to be disclosed under this Item 14 is incorporated by reference to the following sections of our Proxy
Statement: “KPMG Fees” and “Audit Committee Pre-Approval Policy.”
125
Table of Contents
PART IV
ITEM 15.
EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
(a)
(1) Financial Statements. The following consolidated financial statements of NuStar Energy L.P. and its subsidiaries are
included in Part II, Item 8 of this Form 10-K:
Management’s Report on Internal Control over Financial Reporting
Reports of Independent Registered Public Accounting Firm (KPMG LLP)
Consolidated Balance Sheets as of December 31, 2019 and 2018
Consolidated Statements of (Loss) Income for the Years Ended December 31, 2019, 2018 and 2017
Consolidated Statements of Comprehensive (Loss) Income for the Years Ended December 31, 2019, 2018 and 2017
Consolidated Statements of Cash Flows for the Years Ended December 31, 2019, 2018 and 2017
Consolidated Statements of Partners’ Equity and Mezzanine Equity for the Years Ended December 31, 2019, 2018 and
2017
Notes to Consolidated Financial Statements
(2) Financial Statement Schedules and Other Financial Information. No financial statement schedules are submitted
because either they are inapplicable or because the required information is included in the consolidated financial
statements or notes thereto.
(3) Exhibits.
The following are filed or furnished, as applicable, as part of this Form 10-K:
Exhibit
Number
Description
Incorporated by Reference
to the Following Document
3.01
3.02
3.03
3.04
3.05
3.06
3.07
3.08
3.09
Amended and Restated Certificate of Limited
Partnership of Shamrock Logistics, L.P., effective
January 1, 2002
NuStar Energy L.P.’s Annual Report on Form 10-K
for year ended December 31, 2001 (File No.
001-16417), Exhibit 3.3
Amendment to Certificate of Limited Partnership
of Valero L.P., dated March 21, 2007 and effective
April 1, 2007
NuStar Energy L.P.’s Current Report on Form 8-K
filed March 27, 2007 (File No. 001-16417), Exhibit
3.01
Eighth Amended and Restated Agreement of
Limited Partnership of NuStar Energy L.P., dated
as of July 20, 2018
NuStar Energy L.P.’s Current Report on Form 8-K
filed July 20, 2018 (File No. 001-16417),
Exhibit 3.1
Amended and Restated Certificate of Limited
Partnership of Shamrock Logistics Operations,
L.P., dated as of January 7, 2002 and effective
January 8, 2002
NuStar Energy L.P.’s Annual Report on Form 10-K
for year ended December 31, 2001 (File No.
001-16417), Exhibit 3.8
Certificate of Amendment to Certificate of Limited
Partnership of Valero Logistics Operations, L.P.,
dated March 21, 2007 and effective April 1, 2007
NuStar Energy L.P.’s Quarterly Report on Form 10-
Q for quarter ended March 31, 2007 (File No.
001-16417), Exhibit 3.03
Certificate of Amendment to Certificate of Limited
Partnership of NuStar Logistics, L.P., dated and
effective as of March 18, 2014
NuStar Energy L.P.’s Annual Report on Form 10-K
for year ended December 31, 2014 (File No.
001-16417), Exhibit 3.09
Second Amended and Restated Agreement of
Limited Partnership of Shamrock Logistics
Operations, L.P., dated as of April 16, 2001
NuStar Energy L.P.’s Annual Report on Form 10-K
for year ended December 31, 2001 (File No.
001-16417), Exhibit 3.9
First Amendment to Second Amended and Restated
Agreement of Limited Partnership of Shamrock
Logistics Operations, L.P., effective as of April 16,
2001
Second Amendment to Second Amended and
Restated Agreement of Limited Partnership of
Shamrock Logistics Operations, L.P., dated as of
January 7, 2002
NuStar Energy L.P.’s Quarterly Report on Form 10-
Q for quarter ended June 30, 2001 (File No.
001-16417), Exhibit 4.1
NuStar Energy L.P.’s Annual Report on Form 10-K
for year ended December 31, 2001 (File No.
001-16417), Exhibit 3.10
126
Table of Contents
Exhibit
Number
3.10
3.11
3.12
3.13
3.14
3.15
4.01
4.02
4.03
4.04
4.05
4.06
Description
Certificate of Limited Partnership of Riverwalk
Logistics, L.P., dated as of June 5, 2000
Incorporated by Reference
to the Following Document
NuStar Energy L.P.’s Registration Statement on
Form S-1 filed August 14, 2000 (File No.
333-43668), Exhibit 3.7
First Amended and Restated Limited Partnership
Agreement of Riverwalk Logistics, L.P., dated as of
April 16, 2001
NuStar Energy L.P.’s Annual Report on Form 10-K
for year ended December 31, 2001 (File No.
001-16417), Exhibit 3.16
Certificate of Formation of Shamrock Logistics GP,
LLC, dated as of December 7, 1999
NuStar Energy L.P.’s Registration Statement on
Form S-1 filed August 14, 2000 (File No.
333-43668), Exhibit 3.9
Certificate of Amendment to Certificate of
Formation of Shamrock Logistics GP, LLC, dated
as of December 31, 2001
NuStar Energy L.P.’s Annual Report on Form 10-K
for year ended December 31, 2001 (File No.
001-16417), Exhibit 3.14
Certificate of Amendment to Certificate of
Formation of Valero GP, LLC, dated March 21,
2007 and effective April 1, 2007
NuStar Energy L.P.’s Quarterly Report on Form 10-
Q for quarter ended March 31, 2007 (File No.
001-16417), Exhibit 3.02
Second Amended and Restated Limited Liability
Company Agreement of NuStar GP, LLC, dated as
of July 20, 2018
NuStar Energy L.P.’s Current Report on Form 8-K
filed July 20, 2018 (File No. 001-16417),
Exhibit 3.2
Description of Securities
*
Indenture, dated as of July 15, 2002, among Valero
Logistics Operations, L.P., as Issuer, Valero L.P., as
Guarantor, and The Bank of New York, as Trustee,
relating to Senior Debt Securities
Third Supplemental Indenture, dated as of July 1,
2005, to Indenture dated as of July 15, 2002, as
amended and supplemented, among Valero
Logistics Operations, L.P., Valero L.P., Kaneb Pipe
Line Operating Partnership, L.P., and The Bank of
New York Trust Company, N.A.
Instrument of Resignation, Appointment and
Acceptance, dated March 31, 2008, among NuStar
Logistics, L.P., NuStar Energy L.P., Kaneb Pipeline
Operating Partnership, L.P., The Bank of New York
Trust Company N.A., and Wells Fargo Bank,
National Association
Fifth Supplemental Indenture, dated as of August
12, 2010, to Indenture dated as of July 15, 2002,
among NuStar Logistics, L.P., as Issuer, NuStar
Energy L.P., as Guarantor, NuStar Pipeline
Operating Partnership L.P., as Affiliate Guarantor,
and Wells Fargo Bank, National Association, as
Successor Trustee
Sixth Supplemental Indenture, dated as of February
2, 2012, to Indenture dated as of July 15, 2002,
among NuStar Logistics, L.P., as Issuer, NuStar
Energy L.P., as Guarantor, NuStar Pipeline
Operating Partnership L.P., as Affiliate Guarantor,
and Wells Fargo Bank, National Association, as
Successor Trustee
NuStar Energy L.P.’s Current Report on Form 8-K
filed July 15, 2002 (File No. 001-16417),
Exhibit 4.1
NuStar Energy L.P.’s Quarterly Report on Form 10-
Q for quarter ended June 30, 2005 (File No.
001-16417), Exhibit 4.02
NuStar Energy L.P.’s Annual Report on Form 10-K
for year ended December 31, 2008 (File No.
001-16417), Exhibit 4.05
NuStar Energy L.P.’s Current Report on Form 8-K
filed August 16, 2010 (File No. 001-16417),
Exhibit 4.3
NuStar Energy L.P.’s Current Report on Form 8-K
filed February 7, 2012 (File No. 001-16417),
Exhibit 4.3
127
Table of Contents
Exhibit
Number
4.07
4.08
4.09
4.10
4.11
4.12
10.01
10.02
Description
Seventh Supplemental Indenture, dated as of
August 19, 2013, among NuStar Logistics, L.P., as
Issuer, NuStar Energy L.P., as Guarantor, NuStar
Pipeline Operating Partnership L.P., as Affiliate
Guarantor, and Wells Fargo Bank, National
Association, as Successor Trustee
Eighth Supplemental Indenture, dated as of April
28, 2017, among NuStar Logistics, L.P., as Issuer,
NuStar Energy L.P., as Guarantor, NuStar Pipeline
Operating Partnership L.P., as Affiliate Guarantor,
and Wells Fargo Bank, National Association, as
Successor Trustee
Ninth Supplemental Indenture, dated as of May 22,
2019, among NuStar Logistics, L.P., as Issuer,
NuStar Energy L.P., as Guarantor, NuStar Pipeline
Operating Partnership L.P., as Affiliate Guarantor,
and Wells Fargo Bank, National Association, as
Successor Trustee
Indenture, dated as of January 22, 2013, among
NuStar Logistics, L.P., as Issuer, NuStar Energy
L.P., as Guarantor, and Wells Fargo Bank, National
Association, as Trustee, relating to Subordinated
Debt Securities
First Supplemental Indenture, dated as of January
22, 2013, among NuStar Logistics, L.P., as Issuer,
NuStar Energy L.P., as Parent Guarantor, NuStar
Pipeline Operating Partnership L.P., as Affiliate
Guarantor, and Wells Fargo Bank, National
Association, as Trustee
Incorporated by Reference
to the Following Document
NuStar Energy L.P.’s Current Report on Form 8-K
filed August 23, 2013 (File No. 001-16417),
Exhibit 4.3
NuStar Energy L.P.’s Current Report on Form 8-K
filed April 28, 2017 (File No. 001-16417), Exhibit
4.4
NuStar Energy L.P.’s Current Report on Form 8-K
filed May 22, 2019 (File No. 001-16417), Exhibit
4.3
NuStar Energy L.P.’s Current Report on Form 8-K
filed January 22, 2013 (File No. 001-16417),
Exhibit 4.1
NuStar Energy L.P.’s Current Report on Form 8-K
filed January 22, 2013 (File No. 001-16417),
Exhibit 4.2
Registration Rights Agreement, dated as of June
29, 2018, by and among NuStar Energy L.P. and
the Purchasers party thereto
NuStar Energy L.P.’s Current Report on Form 8-K
filed June 29, 2018 (File No. 001-16417), Exhibit
4.2
Amended and Restated 5-Year Revolving Credit
Agreement, dated as of October 29, 2014, among
NuStar Logistics, L.P., NuStar Energy L.P., the
Lenders party thereto and JPMorgan Chase Bank,
N.A., as Administrative Agent, SunTrust Bank and
Mizuho Bank, Ltd., as Co-Syndication Agents,
Wells Fargo Bank, National Association and PNC
Bank, National Association, as Co-Documentation
Agents, and J.P. Morgan Securities LLC, SunTrust
Robinson Humphrey, Inc., Mizuho Bank, Ltd.,
Wells Fargo Securities, LLC and PNC Capital
Markets LLC, as Joint Bookrunners and Joint Lead
Arrangers
First Amendment to Amended and Restated 5-Year
Revolving Credit Agreement, dated as of March 19,
2015, among NuStar Logistics, L.P., NuStar Energy
L.P., JPMorgan Chase Bank, N.A., as
Administrative Agent, and the Lenders party
thereto
NuStar Energy L.P.’s Current Report on Form 8-K
filed October 31, 2014 (File No. 001-16417),
Exhibit 10.1
NuStar Energy L.P.’s Quarterly Report on Form 10-
Q for quarter ended June 30, 2015 (File No.
001-16417), Exhibit 10.01
128
Table of Contents
Exhibit
Number
10.03
10.04
10.05
10.06
10.07
10.08
10.09
10.10
10.11
10.12
10.13
Description
Second Amendment to Amended and Restated 5-
Year Revolving Credit Agreement, dated as of
August 22, 2017, among NuStar Logistics, L.P.,
NuStar Energy L.P., JPMorgan Chase Bank, N.A.,
as Administrative Agent, and the Lenders party
thereto
Third Amendment to Amended and Restated 5-Year
Revolving Credit Agreement, dated as of
November 22, 2017, among NuStar Logistics, L.P.,
NuStar Energy L.P., JPMorgan Chase Bank, N.A.,
as Administrative Agent, and the Lenders party
thereto
Fourth Amendment to Amended and Restated 5-
Year Revolving Credit Agreement, dated as of
March 28, 2018, among NuStar Logistics, L.P.,
NuStar Energy L.P., JPMorgan Chase Bank, N.A.,
as Administrative Agent, and the Lenders party
thereto
Fifth Amendment to Amended and Restated 5-Year
Revolving Credit Agreement, dated as of June 29,
2018, among NuStar Logistics, L.P., NuStar Energy
L.P., JPMorgan Chase Bank, N.A., as
Administrative Agent, and the Lenders party
thereto
Sixth Amendment to Amended and Restated 5-Year
Revolving Credit Agreement, dated as of
September 12, 2019, among NuStar Logistics, L.P.,
NuStar Energy L.P., JPMorgan Chase Bank, N.A.,
as Administrative Agent, and the Lenders party
thereto
Incorporated by Reference
to the Following Document
NuStar Energy L.P.’s Current Report on Form 8-K
filed August 22, 2017 (File No. 001-16417),
Exhibit 10.01
NuStar Energy L.P.’s Current Report on Form 8-K
filed November 22, 2017 (File No. 001-16417),
Exhibit 10.01
NuStar Energy L.P.’s Current Report on Form 8-K
filed March 28, 2018 (File No. 001-16417), Exhibit
10.02
NuStar Energy L.P.’s Current Report on Form 8-K
filed June 29, 2018 (File No. 001-16417), Exhibit
10.3
NuStar Energy L.P.’s Current Report on Form 8-K
filed September 12, 2019 (File No. 001-16417),
Exhibit 10.01
Lease Agreement Between Parish of St. James,
State of Louisiana and NuStar Logistics, L.P. dated
as of July 1, 2010
NuStar Energy L.P.’s Current Report on Form 8-K
filed July 21, 2010 (File No. 001-16417), Exhibit
10.01
Letter of Credit Agreement dated June 5, 2012
among NuStar Logistics, L.P., NuStar Energy L.P.,
the Lenders party thereto and Mizuho Corporate
Bank, Ltd., as Issuing Bank and Administrative
Agent
First Amendment to Letter of Credit Agreement,
dated as of June 29, 2012, among NuStar Logistics,
L.P., NuStar Energy L.P., the Lenders party thereto
and Mizuho Corporate Bank, Ltd., as Issuing Bank
and Administrative Agent
Second Amendment to Letter of Credit Agreement,
dated as of January 17, 2013, among NuStar
Logistics, L.P., NuStar Energy L.P., the Lenders
party thereto and Mizuho Corporate Bank, Ltd., as
Issuing Bank and Administrative Agent
Third Amendment to Letter of Credit Agreement,
dated as of March 8, 2013, among NuStar
Logistics, L.P., NuStar Energy L.P., the Lenders
party thereto and Mizuho Corporate Bank, Ltd., as
Issuing Bank and Administrative Agent
Fourth Amendment to Letter of Credit Agreement,
dated as of April 19, 2013, among NuStar
Logistics, L.P., NuStar Energy L.P., the Lenders
party thereto and Mizuho Corporate Bank, Ltd., as
Issuing Bank and Administrative Agent
129
NuStar Energy L.P.’s Current Report on Form 8-K
filed June 12, 2012 (File No. 001-16417), Exhibit
10.01
NuStar Energy L.P.’s Current Report on Form 8-K
filed July 6, 2012 (File No. 001-16417), Exhibit
10.2
NuStar Energy L.P.’s Annual Report on Form 10-K
for year ended December 31, 2014 (File No.
001-16417), Exhibit 10.10
NuStar Energy L.P.’s Annual Report on Form 10-K
for year ended December 31, 2014 (File No.
001-16417), Exhibit 10.11
NuStar Energy L.P.’s Annual Report on Form 10-K
for year ended December 31, 2014 (File No.
001-16417), Exhibit 10.12
Table of Contents
Exhibit
Number
10.14
10.15
10.16
10.17
10.18
10.19
10.20
10.21
10.22
10.23
Description
Fifth Amendment to Letter of Credit Agreement,
dated as of April 23, 2014, among NuStar
Logistics, L.P., NuStar Energy L.P., the Lenders
party thereto and Mizuho Bank, Ltd., as Issuing
Bank and Administrative Agent
Sixth Amendment to Letter of Credit Agreement,
dated as of November 3, 2014, among NuStar
Logistics, L.P., NuStar Energy L.P., the Lenders
party thereto and Mizuho Bank, Ltd., as Issuing
Bank and Administrative Agent
Seventh Amendment to Letter of Credit Agreement,
dated as of April 30, 2015, among NuStar
Logistics, L.P., NuStar Energy L.P., the Lenders
party thereto and Mizuho Bank, Ltd., as Issuing
Bank and Administrative Agent
Eighth Amendment to Letter of Credit Agreement,
dated as of May 6, 2016, among NuStar Logistics,
L.P., NuStar Energy L.P., the Lenders party thereto
and Mizuho Bank, Ltd., as Issuing Bank and
Administrative Agent
Ninth Amendment to Letter of Credit Agreement,
dated as of April 17, 2017, among NuStar
Logistics, L.P., NuStar Energy L.P., the Lenders
party thereto and Mizuho Bank, Ltd., as Issuing
Bank and Administrative Agent
Tenth Amendment to Letter of Credit Agreement,
dated as of April 10, 2018, among NuStar
Logistics, L.P., NuStar Energy L.P., the Lenders
party thereto and Mizuho Bank, Ltd., as Issuing
Bank and Administrative Agent
Eleventh Amendment to Letter of Credit
Agreement, dated as of April 10, 2019, among
NuStar Logistics, L.P., NuStar Energy L.P., the
Lenders party thereto and Mizuho Bank, Ltd., as
Issuing Bank and Administrative Agent
Incorporated by Reference
to the Following Document
NuStar Energy L.P.’s Annual Report on Form 10-K
for year ended December 31, 2014 (File No.
001-16417), Exhibit 10.13
NuStar Energy L.P.’s Current Report on Form 8-K
filed November 6, 2014 (File No. 001-16417),
Exhibit 10.1
NuStar Energy L.P.’s Quarterly Report on Form 10-
Q for quarter ended June 30, 2015 (File No.
001-16417), Exhibit 10.02
NuStar Energy L.P.’s Quarterly Report on Form 10-
Q for quarter ended June 30, 2016 (File No.
001-16417), Exhibit 10.01
NuStar Energy L.P.’s Quarterly Report on Form 10-
Q for quarter ended March 31, 2017 (File No.
001-16417), Exhibit 10.03
NuStar Energy L.P.’s Quarterly Report on Form 10-
Q for quarter ended March 31, 2018 (File No.
001-16417), Exhibit 10.07
NuStar Energy L.P.’s Quarterly Report on Form 10-
Q for quarter ended March 31, 2019 (File No.
001-16417), Exhibit 10.01
Lease Agreement between Parish of St. James,
State of Louisiana and NuStar Logistics, L.P. dated
as of December 1, 2010
NuStar Energy L.P.’s Current Report on Form 8-K
filed December 30, 2010 (File No. 001-16417),
Exhibit 10.01
Letter of Credit Agreement dated as of September
3, 2014 among NuStar Logistics, L.P., NuStar
Energy L.P., the Lenders party thereto and The
Bank of Tokyo-Mitsubishi UFJ, Ltd., as Issuing
Bank and Administrative Agent
Amendment No. 1 to Letter of Credit Agreement
and Subsidiary Guaranty Agreement dated as of
November 3, 2014 among NuStar Logistics, L.P.,
NuStar Energy L.P., the Lenders party thereto and
The Bank of Tokyo-Mitsubishi UFJ, Ltd., as
Issuing Bank and Administrative Agent
NuStar Energy L.P.’s Current Report on Form 8-K
filed September 9, 2014 (File No. 001-16417),
Exhibit 10.1
NuStar Energy L.P.’s Current Report on Form 8-K
filed November 6, 2014 (File No. 001-16417),
Exhibit 10.3
130
Table of Contents
Exhibit
Number
10.24
10.25
10.26
10.27
10.28
10.29
10.30
10.31
10.32
Description
Maturity Extension Letter (Amendment No. 2) to
Letter of Credit Agreement and Subsidiary
Guaranty Agreement dated as of August 19, 2015
among NuStar Logistics, L.P., NuStar Energy L.P.,
the Lenders party thereto and The Bank of Tokyo-
Mitsubishi UFJ, Ltd., as Issuing Bank and
Administrative Agent
Maturity Extension Letter (Amendment No. 3) to
Letter of Credit Agreement and Subsidiary
Guaranty Agreement dated as of July 15, 2016
among NuStar Logistics, L.P., NuStar Energy L.P.,
the Lenders party thereto and The Bank of Tokyo-
Mitsubishi UFJ, Ltd., as Issuing Bank and
Administrative Agent
Maturity Extension Letter (Amendment No. 4) to
Letter of Credit Agreement and Subsidiary
Guaranty Agreement dated as of July 13, 2017
among NuStar Logistics, L.P., NuStar Energy L.P.,
the Lenders party thereto and The Bank of Tokyo-
Mitsubishi UFJ, Ltd., as Issuing Bank and
Administrative Agent
Maturity Extension Letter (Amendment No. 5) to
Letter of Credit Agreement and Subsidiary
Guaranty Agreement dated as of July 12, 2018
among NuStar Logistics, L.P., NuStar Energy L.P.,
the Lenders party thereto and MUFG Bank, Ltd.
(formerly known as The Bank of Tokyo Mitsubishi
UFJ, Ltd.), as Issuing Bank and Administrative
Agent
Maturity Extension Letter (Amendment No.6) to
Letter of Credit Agreement and Subsidiary
Guaranty Agreement dated as of July 15, 2019
among NuStar Logistics, L.P., NuStar Energy L.P.,
the Lenders party thereto and MUFG Bank, Ltd., as
Issuing Bank and Administrative Agent
Incorporated by Reference
to the Following Document
NuStar Energy L.P.’s Quarterly Report on Form 10-
Q for quarter ended September 30, 2015 (File No.
001-16417), Exhibit 10.01
NuStar Energy L.P.’s Quarterly Report on Form 10-
Q for quarter ended June 30, 2016 (File No.
001-16417), Exhibit 10.02
NuStar Energy L.P.’s Quarterly Report on Form 10-
Q for quarter ended June 30, 2017 (File No.
001-16417), Exhibit 10.02
NuStar Energy L.P.’s Quarterly Report on Form 10-
Q for quarter ended June 30, 2018 (File No.
001-16417), Exhibit 10.05
NuStar Energy L.P.’s Quarterly Report on Form 10-
Q for quarter ended June 30, 2019 (File No.
001-16417), Exhibit 10.06
Lease Agreement between Parish of St. James,
State of Louisiana and NuStar Logistics, L.P. dated
as of August 1, 2011
NuStar Energy L.P.’s Current Report on Form 8-K
filed August 10, 2011 (File No. 001-16417),
Exhibit 10.01
Letter of Credit Agreement dated as of June 5, 2013
among NuStar Logistics, L.P., NuStar Energy L.P.,
the Lenders party thereto and The Bank of Nova
Scotia, as Issuing Bank and Administrative Agent
Amendment No. 1 to Letter of Credit Agreement
and Subsidiary Guaranty Agreement dated as of
November 3, 2014 among NuStar Logistics, L.P.,
NuStar Energy L.P., the Lenders party thereto and
The Bank of Nova Scotia, as Issuing Bank and
Administrative Agent
Purchase and Sale Agreement, dated as of June 15,
2015, among NuStar Energy Services, Inc., NuStar
Logistics, L.P., NuStar Pipeline Operating
Partnership L.P. and NuStar Supply & Trading
LLC, as Originators, NuStar Energy L.P., as
Servicer, and NuStar Finance LLC, as Buyer
NuStar Energy L.P.’s Current Report on Form 8-K
filed June 11, 2013 (File No. 001-16417), Exhibit
10.01
NuStar Energy L.P.’s Current Report on Form 8-K
filed November 6, 2014 (File No. 001-16417),
Exhibit 10.2
NuStar Energy L.P.'s Current Report on Form 8-K
filed June 19, 2015 (File No. 001-16417), Exhibit
10.1
131
Table of Contents
Exhibit
Number
10.33
10.34
10.35
10.36
10.37
10.38
+10.39
+10.40
+10.41
+10.42
+10.43
+10.44
Description
Receivables Financing Agreement, dated as of June
15, 2015, by and among NuStar Finance LLC, as
Borrower, the persons from time to time party
thereto as Lenders and Group Agents, PNC Bank,
National Association, as Administrative Agent, and
NuStar Energy L.P., as initial Servicer
Omnibus Amendment, dated as of January 15,
2016, which is the First Amendment to the
Purchase and Sale Agreement referenced above and
the First Amendment to the Receivables Financing
Agreement referenced above among the respective
parties thereto
Second Amendment to Purchase and Sale
Agreement, dated as of September 20, 2017, by and
among the Originators listed therein, NuStar
Energy L.P., NuStar Finance LLC, Mizuho Bank,
Ltd. and PNC Bank, National Association
Second Amendment to Receivables Financing
Agreement, dated as of September 20, 2017, by and
among NuStar Finance, LLC, as Borrower, NuStar
Energy L.P., as initial Servicer, Mizuho Bank, Ltd.
and PNC Bank, National Association
Third Amendment to Receivables Financing
Agreement, dated as of March 28, 2018, by and
among NuStar Finance, LLC, as Borrower, NuStar
Energy L.P., as initial Servicer, Mizuho Bank, Ltd.
and PNC Bank, National Association
Fourth Amendment to Receivables Financing
Agreement, dated as of April 29, 2019, by and
among NuStar Finance, LLC, as Borrower, NuStar
Energy L.P., as initial Servicer, Mizuho Bank, Ltd.
and PNC Bank, National Association
Incorporated by Reference
to the Following Document
NuStar Energy L.P.'s Current Report on Form 8-K
filed June 19, 2015 (File No. 001-16417), Exhibit
10.2
NuStar Energy L.P.’s Annual Report on Form 10-K
for year ended December 31, 2015 (File No.
001-16417), Exhibit 10.26
NuStar Energy L.P.’s Current Report on Form 8-K
filed September 20, 2017 (File No. 001-16417),
Exhibit 10.01
NuStar Energy L.P.’s Current Report on Form 8-K
filed September 20, 2017 (File No. 001-16417),
Exhibit 10.02
NuStar Energy L.P.’s Current Report on Form 8-K
filed March 28, 2018 (File No. 001-16417),
Exhibit 10.01
NuStar Energy L.P.’s Current Report on Form 8-K
filed April 29, 2019 (File No. 001-16417),
Exhibit 10.1
NuStar GP, LLC Fifth Amended and Restated 2000
Long-Term Incentive Plan, amended and restated as
of January 28, 2016
NuStar Energy L.P.’s Annual Report on Form 10-K
for year ended December 31, 2017 (File No.
001-16417), Exhibit 10.30
First Amendment to the NuStar GP, LLC Fifth
Amended and Restated 2000 Long-Term Incentive
Plan, dated as of February 7, 2018
NuStar Energy L.P.’s Annual Report on Form 10-K
for year ended December 31, 2017 (File No.
001-16417), Exhibit 10.31
Form of Restricted Unit Award Agreement under
the NuStar GP, LLC Fifth Amended and Restated
2000 Long-Term Incentive Plan
NuStar Energy L.P.’s Annual Report on Form 10-K
for year ended December 31, 2016 (File No.
001-16417), Exhibit 10.28
Form of 2017 Performance Unit Award Agreement
under the NuStar GP, LLC Fifth Amended and
Restated 2000 Long-Term Incentive Plan
NuStar Energy L.P.’s Quarterly Report on Form 10-
Q for quarter ended March 31, 2017 (File No.
001-16417), Exhibit 10.01
Form of 2018 Performance Unit Award Agreement
under the NuStar GP, LLC Fifth Amended and
Restated 2000 Long-Term Incentive Plan
NuStar Energy L.P.’s Current Report on Form 8-K
filed July 25, 2018 (File No. 001-16417),
Exhibit 10.1
Form of Non-employee Director Restricted Unit
Award Agreement under the NuStar GP, LLC Fifth
Amended and Restated 2000 Long-Term Incentive
Plan
NuStar Energy L.P.’s Annual Report on Form 10-K
for year ended December 31, 2016 (File No.
001-16417), Exhibit 10.31
132
Table of Contents
Exhibit
Number
+10.45
+10.46
+10.47
+10.48
+10.49
+10.50
Description
Form of 2018 Non-employee Director Restricted
Unit Award Agreement under the NuStar GP, LLC
Fifth Amended and Restated 2000 Long-Term
Incentive Plan
NuStar GP Holdings, LLC Long-Term Incentive
Plan, amended and restated as of April 1, 2007
Incorporated by Reference
to the Following Document
NuStar Energy L.P.’s Quarterly Report on Form 10-
Q for quarter ended September 30, 2018 (File No.
001-16417), Exhibit 10.08
NuStar GP Holdings, LLC’s Quarterly Report on
Form 10-Q for quarter ended June 30, 2007 (File
No. 001-32040), Exhibit 10.04
First Amendment to the NuStar GP Holdings, LLC
Long-Term Incentive Plan, dated as of February 7,
2018
NuStar GP Holdings, LLC’s Annual Report on
Form 10-K for year ended December 31, 2017 (File
No. 001-32040), Exhibit 10.46
Form of Converted Award Agreement under the
NuStar GP Holdings, LLC Amended and Restated
Long-Term Incentive Plan
NuStar Energy L.P.’s Current Report on Form 8-K
filed July 20, 2018 (File No. 001-16417),
Exhibit 10.1
Form of Restricted Unit Award Agreement under
the NuStar GP Holdings, LLC Amended and
Restated Long-Term Incentive Plan
NuStar Energy L.P.’s Quarterly Report on Form 10-
Q for quarter ended September 30, 2018 (File No.
001-16417), Exhibit 10.06
Form of Non-employee Director Restricted Unit
Award Agreement under the NuStar GP Holdings,
LLC Amended and Restated Long-Term Incentive
Plan
NuStar Energy L.P.’s Quarterly Report on Form 10-
Q for quarter ended September 30, 2018 (File No.
001-16417), Exhibit 10.07
+10.51
NuStar Energy L.P. 2019 Long-Term Incentive Plan
NuStar Energy L.P.’s Current Report on Form 8-K
filed April 23, 2019 (File No. 001-16417),
Exhibit 10.1
+10.52
+10.53
+10.54
Form of Restricted Unit Award Agreement under
the NuStar Energy L.P. 2019 Long-Term Incentive
Plan
NuStar Energy L.P.’s Current Report on Form 8-K
filed April 23, 2019 (File No. 001-16417),
Exhibit 10.2
Form of Non-employee Director Restricted Unit
Award Agreement under the NuStar Energy L.P.
2019 Long-Term Incentive Plan
NuStar Energy L.P.’s Current Report on Form 8-K
filed April 23, 2019 (File No. 001-16417),
Exhibit 10.3
Form of 2019 Performance Unit Award Agreement
under the NuStar Energy L.P. 2019 Long-Term
Incentive Plan
NuStar Energy L.P.’s Quarterly Report on Form 10-
Q for quarter ended June 30, 2019 (File No.
001-16417), Exhibit 10.07
+10.55
NuStar Energy L.P. Annual Bonus Plan
+10.56
+10.57
+10.58
+10.59
+10.60
+10.61
Form of NuStar Energy L.P. Amended and Restated
Change of Control Severance Agreement
NuStar Excess Pension Plan, amended and restated
effective as of January 1, 2014
Amendment to NuStar Excess Pension Plan,
effective October 9, 2018
NuStar Excess Thrift Plan, amended and restated
effective as of January 1, 2008
Amendment to NuStar Excess Thrift Plan, effective
as of January 1, 2017
Amendment No. 2 to NuStar Excess Thrift Plan,
effective October 9, 2018
NuStar Energy L.P.’s Annual Report on Form 10-K
for year ended December 31, 2006 (File No.
001-16417), Exhibit 10.18
NuStar Energy L.P.’s Current Report on Form 8-K
filed August 4, 2016 (File No. 001-16417),
Exhibit 10.1
NuStar Energy L.P.’s Annual Report on Form 10-K
for year ended December 31, 2015 (File No.
001-16417), Exhibit 10.45
NuStar Energy L.P.’s Quarterly Report on Form 10-
Q for quarter ended September 30, 2018 (File No.
001-16417), Exhibit 10.04
NuStar Energy L.P.’s Annual Report on Form 10-K
for year ended December 31, 2008 (File No.
001-16417), Exhibit 10.30
NuStar Energy L.P.’s Quarterly Report on Form 10-
Q for quarter ended March 31, 2017 (File No.
001-16417), Exhibit 10.02
NuStar Energy L.P.’s Quarterly Report on Form 10-
Q for quarter ended September 30, 2018 (File No.
001-16417), Exhibit 10.05
133
Table of Contents
Exhibit
Number
10.62
10.63
10.64
21.01
23.01
24.01
31.01
31.02
32.01
32.02
101.INS
101.SCH
101.CAL
101.DEF
101.LAB
101.PRE
*
**
+
Description
Incorporated by Reference
to the Following Document
Assignment and Assumption Agreement dated
March 1, 2016 between NuStar GP, LLC and
NuStar Services Company LLC
NuStar Energy L.P.’s Current Report on Form 8-K
filed March 1, 2016 (File No. 001-16417), Exhibit
10.1
Amended and Restated Aircraft Time Sharing
Agreement, dated as of September 4, 2009,
between NuStar Logistics, L.P. and William E.
Greehey
First Amendment to Amended and Restated
Aircraft Time Sharing Agreement, dated as of
August 18, 2017, between NuStar Logistics, L.P.
and William E. Greehey
List of subsidiaries of NuStar Energy L.P.
Consent of KPMG LLP dated February 27, 2020
Powers of Attorney (included in signature page of
this Form 10-K)
Rule 13a-14(a) Certification (under Section 302 of
the Sarbanes-Oxley Act of 2002) of principal
executive officer
Rule 13a-14(a) Certification (under Section 302 of
the Sarbanes-Oxley Act of 2002) of principal
financial officer
Section 1350 Certification (under Section 906 of
the Sarbanes-Oxley Act of 2002) of principal
executive officer
Section 1350 Certification (under Section 906 of
the Sarbanes-Oxley Act of 2002) of principal
financial officer
Inline XBRL Instance Document - The instance
document does not appear in the Interactive Data
File because its XBRL tags are embedded within
the Inline XBRL document.
Inline XBRL Taxonomy Extension Schema
Document
Inline XBRL Taxonomy Extension Calculation
Linkbase Document
Inline XBRL Taxonomy Extension Definition
Linkbase Document
Inline XBRL Taxonomy Extension Label Linkbase
Document
Inline XBRL Taxonomy Extension Presentation
Linkbase Document
NuStar Energy L.P.’s Annual Report on Form 10-K
for year ended December 31, 2009 (File No.
001-16417), Exhibit 10.24
NuStar Energy L.P.’s Quarterly Report on Form 10-
Q for quarter ended September 30, 2017 (File No.
001-16417), Exhibit 10.02
*
*
*
*
*
**
**
*
*
*
*
*
*
*
104
Cover page Interactive Data File - Formatted in
Inline XBRL and contained in Exhibit 101
Filed herewith.
Furnished herewith.
Identifies management contracts or compensatory plans or arrangements required to be filed as an exhibit hereto
pursuant to Item 15(c) of Form 10-K.
134
Table of Contents
An electronic copy of this Form 10-K is available on our website, free of charge, at http://www.nustarenergy.com
(select the “Investors” link, then the “SEC Filings” link). A paper copy of the Form 10-K also is available without
charge to unitholders upon written request at the address below. Copies of exhibits filed as a part of this Form 10-K
may be obtained by unitholders of record at a charge of $0.15 per page, minimum $5.00 each request. Direct inquiries to
Corporate Secretary, NuStar Energy L.P., 19003 IH-10 West, San Antonio, Texas 78257 or
corporatesecretary@nustarenergy.com.
ITEM 16.
FORM 10-K SUMMARY
Not applicable.
135
Table of Contents
Pursuant to the requirements of Section 13 or 15(d) of the Exchange Act, the registrant has duly caused this report to be signed
on its behalf by the undersigned, thereunto duly authorized.
SIGNATURES
NUSTAR ENERGY L.P.
(Registrant)
By:
By:
By:
By:
Riverwalk Logistics, L.P., its general partner
By: NuStar GP, LLC, its general partner
/s/ Bradley C. Barron
Bradley C. Barron
President and Chief Executive Officer
February 27, 2020
/s/ Thomas R. Shoaf
Thomas R. Shoaf
Executive Vice President and Chief Financial Officer
February 27, 2020
/s/ Jorge A. del Alamo
Jorge A. del Alamo
Senior Vice President and Controller
February 27, 2020
136
Table of Contents
POWER OF ATTORNEY
KNOW ALL MEN BY THESE PRESENTS, that each person whose signature appears below hereby constitutes and appoints
Bradley C. Barron, Thomas R. Shoaf and Amy L. Perry, or any of them, each with power to act without the other, his or her true
and lawful attorney-in-fact and agent, with full power of substitution and resubstitution, for him or her and in his or her name,
place and stead, in any and all capacities, to sign any or all subsequent amendments and supplements to this Annual Report on
Form 10-K, and to file the same, or cause to be filed the same, with all exhibits thereto, and other documents in connection
therewith, with the Securities and Exchange Commission, granting unto each said attorney-in-fact and agent full power to do
and perform each and every act and thing requisite and necessary to be done in and about the premises, as fully to all intents
and purposes as he or she might or could do in person, hereby qualifying and confirming all that said attorney-in-fact and agent
or his or her substitute or substitutes may lawfully do or cause to be done by virtue hereof.
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following
persons on behalf of the registrant and in the capacities and on the dates indicated.
Signature
Title
Date
/s/ William E. Greehey
William E. Greehey
/s/ Bradley C. Barron
Bradley C. Barron
/s/ Thomas R. Shoaf
Thomas R. Shoaf
/s/ Jorge A. del Alamo
Jorge A. del Alamo
/s/ J. Dan Bates
J. Dan Bates
/s/ William B. Burnett
William B. Burnett
/s/ James F. Clingman, Jr.
James F. Clingman, Jr.
/s/ Dan J. Hill
Dan J. Hill
/s/ Jelynne LeBlanc-Burley
Jelynne LeBlanc-Burley
/s/ Robert J. Munch
Robert J. Munch
/s/ W. Grady Rosier
W. Grady Rosier
Chairman of the Board
February 27, 2020
President, Chief Executive
Officer and Director
(Principal Executive Officer)
Executive Vice President
and Chief Financial Officer
(Principal Financial Officer)
February 27, 2020
February 27, 2020
Senior Vice President and Controller
(Principal Accounting Officer)
February 27, 2020
Director
February 27, 2020
Director
February 27, 2020
Director
February 27, 2020
Director
February 27, 2020
Director
February 27, 2020
Director
February 27, 2020
Director
February 27, 2020
137