NuStar Energy L.P. - Annual Report: 2017 (Form 10-K)

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UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2017

[ ] 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		78257
San Antonio, Texas		(Zip Code)
(Address of principal executive offices)

Registrant’s telephone number, including area code (210) 918-2000

Securities registered pursuant to Section 12(b) of the Act: Common units representing limited partner interests listed on the New York Stock Exchange. 8.50% Series A, 7.625% Series B and 9.00% Series C Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units representing limited partner interests listed on the New York Stock Exchange.

Securities registered pursuant to 12(g) of the Act: None.

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes [X] No [ ]

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.

Yes [ ] No [X]

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes [X] No [ ]

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes [X] No [ ]

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [X]

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act:



Large accelerated filer	[X]	Accelerated filer	[ ]

Non-accelerated filer	[ ] (Do not check if a smaller reporting company)	Smaller reporting company	[ ]

		Emerging growth company	[ ]

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes [ ] No [X]

The aggregate market value of the common units held by non-affiliates was approximately $3,692 million based on the last sales price quoted as of June 30, 2017, the last business day of the registrant’s most recently completed second quarter.

The number of common units outstanding as of January 31, 2018 was 93,182,018.

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NUSTAR ENERGY L.P.

FORM 10-K

TABLE OF CONTENTS



PART I
Items 1., 1A. & 2.	Business, Risk Factors and Properties	3
	Overview	3
	Recent Developments	4
	Organizational Structure	5
	Segments	6
	Employees	15
	Rate Regulation	15
	Environmental, Health, Safety and Security Regulation	15
	Risk Factors	18
	Properties	36

Item 1B.	Unresolved Staff Comments	36

Item 3.	Legal Proceedings	36

Item 4.	Mine Safety Disclosures	36

PART II
Item 5.	Market for Registrant’s Common Units, Related Unitholder Matters and Issuer Purchases of Equity Securities	37

Item 6.	Selected Financial Data	40

Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	41

Item 7A.	Quantitative and Qualitative Disclosures about Market Risk	64

Item 8.	Financial Statements and Supplementary Data	67

Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	127

Item 9A.	Controls and Procedures	127

Item 9B.	Other Information	127

PART III
Item 10.	Directors, Executive Officers and Corporate Governance	128

Item 11.	Executive Compensation	132

Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters	168

Item 13.	Certain Relationships and Related Transactions and Director Independence	171

Item 14.	Principal Accountant Fees and Services	175

PART IV
Item 15.	Exhibits and Financial Statement Schedules	176

Item 16.	Form 10-K Summary	183

Signatures		184

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PART I

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

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

In this Form 10-K, we make certain forward-looking statements, including statements regarding our plans, strategies, objectives, expectations, estimates, predictions, projections, assumptions, intentions and resources. While these forward-looking statements, and any assumptions upon which they are based, are made in good faith and reflect our current judgment regarding the direction of our business, actual results will almost always vary, sometimes materially, from any estimates, predictions, projections, assumptions or other future performance suggested in this report. These forward-looking statements can generally be identified by the words “anticipates,” “believes,” “expects,” “plans,” “intends,” “estimates,” “forecasts,” “budgets,” “projects,” “will,” “could,” “should,” “may” and similar expressions. These statements reflect our current views with regard to future events and are subject to various risks, uncertainties and assumptions, that may cause actual results to differ materially, including the possibility that the proposed merger described under “Recent Developments” below will not be completed prior to the August 8, 2018 outside termination date, the possibility that NuStar GP Holdings, LLC will not obtain the required approvals by its unitholders, the possibility that the anticipated benefits from the proposed merger cannot be fully realized, the possibility that costs or difficulties related to the proposed merger will be greater than expected and other risk factors. Please read Item 1A. “Risk Factors” for a discussion of certain of those risks, uncertainties and assumptions.

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


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

OVERVIEW

NuStar Energy L.P. (NuStar Energy), a Delaware limited partnership, was formed in 1999 and completed its initial public offering of common units on April 16, 2001. Our common units trade on the New York Stock Exchange (NYSE) under the symbol “NS,” our fixed-to-floating rate cumulative redeemable perpetual preferred units trade on the NYSE under the symbol “NSprA” for our 8.50% Series A Preferred Units, “NSprB” for our 7.625% Series B Preferred Units and “NSprC” for our 9.00% Series C Preferred Units. Our principal executive offices are located at 19003 IH-10 West, San Antonio, Texas 78257 and our telephone number is (210) 918-2000.

We are engaged in the transportation of petroleum products and anhydrous ammonia, and the terminalling, storage and marketing of petroleum products. The term “throughput” as used in this document generally refers to barrels of crude oil or refined product or tons of ammonia, as applicable, that pass through our pipelines, terminals or storage tanks.

We divide our operations into the following three reportable business segments: pipeline, storage and fuels marketing. As of December 31, 2017, our assets included approximately 9,400 miles of pipeline and 81 terminal and storage facilities that provide approximately 96 million barrels of storage capacity. The following table summarizes operating income for each of our business segments:



	Year Ended December 31, 2017
	(Thousands of Dollars)
Pipeline	$	231,795
Storage	$	219,439
Fuels marketing	$	5,983

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We conduct our operations through our wholly owned subsidiaries, primarily NuStar Logistics, L.P. (NuStar Logistics) and NuStar Pipeline Operating Partnership L.P. (NuPOP). Our revenues include:


•	tariffs for transporting crude oil, refined products and anhydrous ammonia through our pipelines;


•	fees for the use of our terminal and storage facilities and related ancillary services; and


•	sales of petroleum products.

We strive to increase unitholder value by:


•	enhancing our existing assets through strategic internal growth projects that expand our business with current and new customers;


•	pursuing strategic expansion projects by constructing new assets;


•	improving our operations, including safety and environmental stewardship, cost control and asset reliability; and


•	identifying acquisition targets that meet our financial and strategic criteria.

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

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

RECENT DEVELOPMENTS

Merger. On February 7, 2018, NuStar Energy, Riverwalk Logistics, L.P., NuStar GP, LLC, Marshall Merger Sub LLC, a wholly owned subsidiary of NuStar Energy (Merger Sub), Riverwalk Holdings, LLC and NuStar GP Holdings, LLC (NuStar GP Holdings) entered into an Agreement and Plan of Merger (the Merger Agreement) pursuant to which Merger Sub will merge with and into NuStar GP Holdings with NuStar GP Holdings being the surviving entity (the Merger), such that NuStar Energy will be the sole member of NuStar GP Holdings following the Merger. Pursuant to the Merger Agreement and at the effective time of the Merger, our partnership agreement will be amended and restated to, among other things, (i) cancel the incentive distribution rights held by our general partner, (ii) convert the 2% general partner interest in NuStar Energy held by our general partner into a non-economic management interest and (iii) provide the holders of our common units with voting rights in the election of the members of the board of directors of NuStar GP, LLC at an annual meeting, beginning in 2019. The Merger is subject to the satisfaction or waiver of certain conditions, including approval of the Merger Agreement by NuStar GP Holdings unitholders. Additionally, on February 8, 2018, we announced that our management anticipates recommending to the board of directors of NuStar GP, LLC, and the board of directors expects to adopt, a reset of our quarterly distribution per common unit to $0.60 ($2.40 on an annualized basis), starting with the first-quarter distribution payable in May 2018. Please refer to Note 28 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for further discussion of the Merger.

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

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ORGANIZATIONAL STRUCTURE

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

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

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SEGMENTS

Detailed financial information about our segments is included in Note 25 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data.” The following map depicts our assets at December 31, 2017:

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PIPELINE

Our pipeline operations consist of the transportation of refined petroleum products, crude oil and anhydrous ammonia. As of December 31, 2017, we owned and operated:


•	refined product pipelines with an aggregate length of 3,130 miles and crude oil pipelines with an aggregate length of 1,930 miles in Texas, Oklahoma, Kansas, Colorado and New Mexico (collectively, the Central West System);


•	a 1,920-mile refined product pipeline originating in southern Kansas and terminating at Jamestown, North Dakota, with a western extension to North Platte, Nebraska and an eastern extension into Iowa (the East Pipeline);


•	a 450-mile refined product pipeline originating at Andeavor’s Mandan, North Dakota refinery and terminating in Minneapolis, Minnesota (the North Pipeline); and


•	a 2,000-mile anhydrous ammonia pipeline originating in the Louisiana delta area that travels north through the Midwestern United States forking east and west to terminate in Nebraska and Indiana (the Ammonia Pipeline).

The following table lists information about our pipeline assets as of December 31, 2017:



			Throughput For the year ended December 31,
Region / Pipeline System	Length	Tank Capacity	2017	2016
	(Miles)	(Barrels)	(Barrels/Day)
Central West System:
McKee System	2,276	—	171,815	178,373
Three Rivers System	373	—	78,165	79,502
Other	481	—	53,829	57,039
Central West Refined Products Pipelines	3,130	—	303,809	314,914
South Texas Crude System	330	2,157,000	114,920	124,363
Other	200	—	52,969	59,087
Eagle Ford System	530	2,157,000	167,889	183,450
McKee System	598	1,039,000	137,675	147,956
Ardmore System	119	824,000	84,801	60,775
Permian Crude System	683	1,000,000	192,958	—
Central West Crude Oil Pipelines	1,930	5,020,000	583,323	392,181
Total Central West System	5,060	5,020,000	887,132	707,095

Central East System:
East Pipeline	1,920	5,261,000	139,317	143,446
North Pipeline	450	1,492,000	41,438	48,343
Ammonia Pipeline	2,000	—	32,172	29,243
Total Central East System	4,370	6,753,000	212,927	221,032

Total	9,430	11,773,000	1,100,059	928,127

Description of Pipelines

Central West System. The Central West System covers a total of 5,060 miles, including refined product and crude oil pipelines. The refined product pipelines have an aggregate length of 3,130 miles (Central West Refined Products Pipelines) and transport gasoline, distillates (including diesel and jet fuel), natural gas liquids and other products produced at the refineries to which they are connected, including Valero Energy Corporation’s (Valero Energy) McKee and Three Rivers refineries.

The crude oil pipelines have an aggregate length of 1,930 miles (Central West Crude Oil Pipelines). Our crude oil pipelines transport crude oil and other feedstocks to the refineries to which they are connected, including Valero Energy’s McKee, Three Rivers and Ardmore refineries, or from the Eagle Ford Shale region to our North Beach marine terminal and to our customers’ refineries in Corpus Christi, Texas. Our Permian Crude System, most of which we acquired with the Navigator Acquisition,

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

Central East System. The Central East System covers a total of 4,370 miles and consists of the East Pipeline, North Pipeline and Ammonia Pipeline.

The East Pipeline covers 1,920 miles and moves refined products and natural gas liquids north in pipelines ranging in diameter from 6 inches to 16 inches to our terminals and third party terminals along the system and to receiving pipeline connections in Kansas. Shippers on the East Pipeline obtain refined petroleum products from refineries in Kansas, Oklahoma and Texas. The East Pipeline system includes 17 terminals, discussed below, with storage capacity of approximately 3.8 million barrels and two tank farms with storage capacity of approximately 1.4 million barrels at McPherson and El Dorado, Kansas.

The North Pipeline originates at Andeavor’s Mandan, North Dakota refinery and runs from west to east for approximately 450 miles to its termination in the Minneapolis, Minnesota area. The North Pipeline system includes four terminals, discussed below, with storage capacity of approximately 1.5 million barrels.

The East and North Pipelines include 21 truck-loading terminals through which refined petroleum products are delivered to storage tanks and then loaded into petroleum product transport trucks. Revenues earned at these terminals predominately relate to the volumes transported on the pipeline through fees included in the pipeline tariff. As a result, these terminals are included in this segment instead of the storage segment.

The 2,000-mile Ammonia Pipeline originates in the Louisiana delta area, where it connects to three third-party marine terminals and three anhydrous ammonia plants on the Mississippi River. The line runs north through Louisiana and Arkansas into Missouri, where at Hermann, Missouri it splits and one branch goes east into Illinois and Indiana, while the other branch continues north into Iowa and then turns west into Nebraska. The Ammonia Pipeline is connected to multiple third-party-owned terminals, which include industrial facility delivery locations. Product is supplied to the pipeline from anhydrous ammonia plants in Louisiana and imported product delivered through the marine terminals. Anhydrous ammonia is primarily used as agricultural fertilizer. It is also used as a feedstock to produce other nitrogen derivative fertilizers and explosives.

Pipeline Operations

We charge tariffs on a per barrel basis for transporting refined products, crude oil and other feedstocks in our refined product and crude oil pipelines and on a per ton basis for transporting anhydrous ammonia in the Ammonia Pipeline.

In general, shippers on our crude oil and refined product pipelines deliver petroleum products to our pipelines for transport to/from: (i) refineries that connect to our pipelines, (ii) third-party pipelines or terminals and (iii) our terminals for further delivery to marine vessels or pipelines. We charge our shippers tariff rates based on transportation from the origination point on the pipeline to the point of delivery.

Our pipelines are subject to federal regulation by one or more of the following governmental agencies: the Federal Energy Regulatory Commission (the FERC), the Surface Transportation Board (the STB), the Department of Transportation (DOT), the Environmental Protection Agency (EPA) and the Department of Homeland Security. Additionally, our pipelines are subject to the respective state jurisdictions. See “Rate Regulation” and “Environmental, Health, Safety and Security Regulation” below.

The majority of our pipelines are common carrier. Common carrier activities are those for which transportation through our pipelines is available to any shipper who requests such services and satisfies the conditions and specifications for transportation. Published tariffs are (i) filed with the FERC for interstate petroleum product shipments, (ii) filed with the relevant state authority for intrastate petroleum product shipments or (iii) regulated by the STB for our Ammonia Pipeline.

We operate our pipelines remotely through a computerized Supervisory Control and Data Acquisition, or SCADA, system.

Demand for and Sources of Refined Products and Crude Oil

Throughputs on our Central West Refined Product Pipelines and the East and North Pipelines depend on the level of demand for refined products in the markets served by the pipelines and the ability and willingness of the refiners and marketers having access to the pipelines to supply that demand through our pipelines.

The majority of the refined products delivered through the Central West Refined Product Pipelines and the North Pipeline are gasoline and diesel fuel that originate at refineries connected to our pipelines. Demand for these products fluctuates as prices for these products fluctuate. Prices fluctuate for a variety of reasons, including the overall balance in supply and demand, which is affected by general economic conditions, among other factors. Prices for gasoline and diesel fuel tend to increase in the warm weather months when people tend to drive automobiles more often and for longer distances.

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Much of the refined products and natural gas liquids delivered through the East Pipeline and a portion of volumes on the North Pipeline are ultimately used as fuel for railroads, ethanol denaturant or in agricultural operations, including fuel for farm equipment, irrigation systems, trucks used for transporting crops and crop-drying facilities. Demand for refined products for agricultural use, and the relative mix of products required, is affected by weather conditions in the markets served by the East and North Pipelines. The agricultural sector is also affected by government agricultural policies and crop prices. Although periods of drought suppress agricultural demand for some refined products, particularly those used for fueling farm equipment, the demand for fuel for irrigation systems often increases during such times. The mix of refined products delivered for agricultural use varies seasonally, with gasoline demand peaking in early summer, diesel fuel demand peaking in late summer and propane demand higher in the fall.

Our refined product pipelines are also dependent upon adequate levels of production of refined products by refineries connected to the pipelines, directly or through connecting pipelines. The refineries are, in turn, dependent upon adequate supplies of suitable grades of crude oil. Certain of our Central West Refined Products Pipelines are subject to long-term throughput agreements with Valero Energy. Valero Energy refineries connected directly to our pipelines obtain crude oil from a variety of foreign and domestic sources. If operations at one of these refineries were discontinued or significantly reduced, it could have a material adverse effect on our operations, although we would endeavor to minimize the impact by seeking alternative customers for those pipelines.

The North Pipeline is heavily dependent on Andeavor’s Mandan, North Dakota refinery, which primarily runs North Dakota crude oil (although it has the ability to process other crude oils), and an interruption in operations at the Andeavor refinery could have a material adverse effect on our operations. The majority of the refined products transported through the East Pipeline are produced at three refineries located at McPherson and El Dorado, Kansas and Ponca City, Oklahoma, which are operated by CHS Inc., HollyFrontier Corporation and Phillips 66, respectively. The East Pipeline also has access to Gulf Coast supplies of products through third party connecting pipelines that receive products originating on the Gulf Coast.

Other than the Valero Energy refineries and the Andeavor refinery described above, if operations at any one refinery were discontinued, we believe (assuming unchanged demand for refined products in markets served by the refined product pipelines) that the effects thereof would be short-term in nature and our business would not be materially adversely affected over the long-term because such discontinued production could be replaced by other refineries or other sources.

Our crude oil pipelines are dependent on our customers’ continued access to sufficient crude oil and sufficient demand for refined products for our customers to operate their refineries. The supply of crude oil production (domestic and foreign) could increase or decrease with the change in crude oil prices. Changes in crude oil prices could also affect the exploration and production of shale plays, which could affect demand for crude oil pipelines serving those regions, such as our Eagle Ford System and Permian Crude System. However, certain of our crude oil pipelines, including the McKee System, are the primary source of crude oil for our customers’ refineries. Therefore, these “demand-pull” pipelines are less affected by changes in crude oil prices.

Demand for and Sources of Anhydrous Ammonia

The Ammonia Pipeline is one of two major anhydrous ammonia pipelines in the United States and the only one capable of receiving products from outside the United States directly into the system and transporting anhydrous ammonia into the nation’s corn belt.

Throughputs on our Ammonia Pipeline depend on overall nitrogen fertilizer use, the price of natural gas, which is the primary component of anhydrous ammonia, and the level of demand for direct application of anhydrous ammonia as a fertilizer for crop production (Direct Application). Demand for Direct Application is dependent on the weather, as Direct Application is not effective if the ground is too wet or too dry.

Corn producers have fertilizer alternatives to anhydrous ammonia, such as liquid or dry nitrogen fertilizers. Liquid and dry nitrogen fertilizers are both less sensitive to weather conditions during application but are generally more costly than anhydrous ammonia. In addition, anhydrous ammonia has the highest nitrogen content of any nitrogen-derivative fertilizer.

Customers

The largest customer of our pipeline segment was Valero Energy, which accounted for approximately 33% of the total segment revenues for the year ended December 31, 2017. In addition to Valero Energy, our customers include integrated oil companies, refining companies, farm cooperatives, railroads and others. No other customer accounted for more than 10% of the total revenues of the pipeline segment for the year ended December 31, 2017.

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Competition and Business Considerations

Because pipelines are generally the lowest-cost method for intermediate and long-haul movement of crude oil and refined petroleum products, our more significant competitors are common carrier and proprietary pipelines owned and operated by major integrated and large independent oil companies and other companies in the areas where we deliver products. Competition between common carrier pipelines is based primarily on transportation charges, quality of customer service and proximity to end users. Trucks may competitively deliver products in some of the areas served by our pipelines; however, trucking costs render that mode of transportation uncompetitive for longer hauls or larger volumes.

Most of our refined product pipelines and certain of our crude oil pipelines within the Central West System are physically integrated with and principally serve refineries owned by Valero Energy. As a result, we do not believe that we will face significant competition for transportation services provided to the Valero Energy refineries we serve.

Certain of our crude oil pipelines serve areas or refineries impacted by domestic shale oil production in the Eagle Ford, Permian Basin and Granite Wash regions. Our pipelines also face competition from other crude oil pipelines and truck transportation in these regions. However, some of that exposure is mitigated through our long-term contracts and minimum volume commitments with creditworthy customers.

The East and North Pipelines compete with an independent common carrier pipeline system owned by Magellan Midstream Partners, L.P. (Magellan) that operates approximately 100 miles east of and parallel to the East Pipeline and in close proximity to the North Pipeline. Certain of the East Pipeline’s and the North Pipeline’s delivery terminals are in direct competition with Magellan’s terminals. Competition with Magellan is based primarily on transportation charges, quality of customer service and proximity to end users.

Competitors of the Ammonia Pipeline include the other major anhydrous ammonia pipeline, owned by Magellan, which originates in Oklahoma and Texas and terminates in Minnesota. The competing pipeline has the same Direct Application demand and weather issues as the Ammonia Pipeline but is restricted to domestically produced anhydrous ammonia. Midwest production facilities, nitrogen fertilizer substitutes and barge and railroad transportation represent other forms of direct competition to the Ammonia Pipeline under certain market conditions.

STORAGE

Our storage segment consists of facilities that provide storage, handling and other services for petroleum products, crude oil, specialty chemicals and other liquids. As of December 31, 2017, we owned and operated:


•	40 terminal and storage facilities in the United States and one terminal in Nuevo Laredo, Mexico, with total storage capacity of 53.3 million barrels;


•	A terminal on the island of St. Eustatius with tank capacity of 14.3 million barrels and a transshipment facility;


•	A terminal located in Point Tupper, Canada with tank capacity of 7.8 million barrels and a transshipment facility; and


•	Six terminals located in the United Kingdom and one terminal located in Amsterdam, the Netherlands, with total storage capacity of approximately 9.5 million barrels.

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



Facility	Tank Capacity
	(Barrels)
Colorado Springs, CO	328,000
Denver, CO	110,000
Albuquerque, NM	251,000
Rosario, NM	166,000
Catoosa, OK	358,000
Abernathy, TX	160,000
Amarillo, TX	269,000
Corpus Christi, TX	491,000
Corpus Christi, TX (North Beach)	3,339,000
Edinburg, TX	340,000

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Facility	Tank Capacity
	(Barrels)
El Paso, TX (b)	419,000
Harlingen, TX	286,000
Laredo, TX	215,000
San Antonio, TX (c)	375,000
Southlake, TX	569,000
Nuevo Laredo, Mexico	35,000
Central West Terminals	7,711,000

Jacksonville, FL	2,593,000
St. James, LA	9,917,000
Houston, TX	86,000
Texas City, TX (c)	2,964,000
Gulf Coast Terminals	15,560,000

Blue Island, IL	690,000
Andrews AFB, MD (a)	75,000
Baltimore, MD	813,000
Piney Point, MD	5,402,000
Linden, NJ (c)	4,637,000
Paulsboro, NJ	74,000
Virginia Beach, VA (a)	41,000
North East Terminals	11,732,000

Los Angeles, CA	608,000
Pittsburg, CA	398,000
Selby, CA	3,074,000
Stockton, CA	816,000
Portland, OR	1,345,000
Tacoma, WA	391,000
Vancouver, WA (c)	774,000
West Coast Terminals	7,406,000

Benicia, CA	3,683,000
Corpus Christi, TX	4,030,000
Texas City, TX	3,141,000
Refinery Storage Tanks	10,854,000

Eastham, England	2,096,000
Grays, England	1,958,000
Runcorn, England	149,000
Belfast, Northern Ireland	408,000
Glasgow, Scotland	353,000
Grangemouth, Scotland	719,000
United Kingdom (UK) Terminals	5,683,000

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Facility	Tank Capacity
	(Barrels)
St. Eustatius, the Netherlands	14,256,000
Amsterdam, the Netherlands	3,834,000
Point Tupper, Canada	7,778,000
International Terminals	31,551,000

Total	84,814,000


(a)	Terminal facility also includes pipelines to U.S. government military base locations.


(b)	We own a 67% undivided interest in the El Paso refined product terminal. The tank capacity represents the proportionate share of capacity attributable to our ownership interest.


(c)	Location includes two terminal facilities.

Description of Major Terminal Facilities

St. Eustatius. We own and operate a 14.3 million barrel petroleum storage and terminalling facility located on the island of St. Eustatius in the Caribbean, which is located at a point of minimal deviation from major shipping routes. This facility is capable of handling a wide range of petroleum products, including crude oil and refined products, and it can accommodate heavily laden ultra large crude carriers, or ULCCs, for loading and discharging crude oil and other petroleum products. A two-berth jetty, a two-berth monopile with platform and buoy systems, a floating hose station and an offshore single point mooring (SPM) buoy with loading and unloading capabilities serve the terminal’s customers’ vessels. The fuel oil and petroleum product facilities have in-tank and in-line blending capabilities, while the crude tanks have tank-to-tank blending capability and in-tank mixers. In addition to the storage and blending services at St. Eustatius, this facility has the flexibility to utilize certain storage capacity for both feedstock and refined products to support our atmospheric distillation unit, which is capable of handling up to 25,000 barrels per day of feedstock, ranging from condensates to heavy crude oil. We own and operate all of the berthing facilities at the St. Eustatius terminal. Separate fees apply for use of the berthing facilities, as well as associated services, including pilotage, tug assistance, line handling, launch service, emergency response services and other ship services.

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

Refinery Storage Tanks. We own and operate crude oil storage tanks with an aggregate storage capacity of 10.9 million barrels that are physically integrated with and serve refineries owned by Valero Energy at Corpus Christi and Texas City, TX and Benicia, CA. Effective January 1, 2017, we lease our refinery storage tanks to Valero Energy in exchange for a fixed fee, whereas we previously earned fees based upon throughput.

St. James, Louisiana. Our St. James terminal, which is located on the Mississippi River near St. James, Louisiana, has a total storage capacity of 9.9 million barrels. The facility is located on almost 900 acres of land, some of which is undeveloped. The majority of the storage tanks and infrastructure are suited for light crude oil, with certain of the tanks capable of fuel oil or heated crude oil storage. Additionally, the facility has one barge dock and two ship docks. Our St. James terminal is connected to gathering pipelines in the Gulf of Mexico, lines that connect to Eagle Ford, Permian and other domestic shale plays, and pipelines to refineries in the Gulf Coast and Midwest. The St. James terminal also has two unit train rail facilities and a manifest rail facility, which are served by the Union Pacific Railroad and have a combined capacity of approximately 200,000 barrels per day.

Point Tupper. We own and operate a 7.8 million barrel terminalling and storage facility located at Point Tupper on the Strait of Canso, near Port Hawkesbury, Nova Scotia. This facility is the deepest independent, ice-free marine terminal on the North American Atlantic coast, with access to the East Coast, Canada and the Midwestern United States via the St. Lawrence Seaway and the Great Lakes system. With one of the premier jetty facilities in North America, the Point Tupper facility can accommodate heavily laden ULCCs for loading and discharging crude oil, petroleum products and petrochemicals. Crude oil and petroleum product movements at the terminal are fully automated. Separate fees apply for use of the jetty facility, as well

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as associated services, including pilotage, tug assistance, line handling, launch service, emergency response services and other ship services.

Linden, New Jersey. Our Linden terminal facility includes two terminals that provide deep-water terminalling capabilities in the New York Harbor and primarily stores petroleum products, including gasoline, jet fuel and fuel oils. The two terminals have a total storage capacity of 4.6 million barrels and can receive and deliver products via ship, barge and pipeline. The terminal facility includes two docks.

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

Corpus Christi North Beach. We own and operate a 3.3 million barrel crude oil storage and terminalling facility located at the Port of Corpus Christi in Texas. The facility supports our South Texas Crude System and is connected to a third-party pipeline system. It also provides our customers with the flexibility to segregate and deliver crude oil and processed condensate. This facility has three docks, including one private dock, and can load crude oil onto ships simultaneously on all three docks at a maximum rate of 65,000 barrels per hour. This facility will have exclusive-use access to the Port of Corpus Christi’s new crude oil dock expected to be completed in 2018, which will give the terminal four docks. Once the new dock is complete, the Corpus Christi North Beach terminal will have the capacity to move on average between 650,000 and 700,000 barrels per day and will be able to accommodate Aframax-class vessels.

Storage Operations

Revenues for the storage segment include fees for tank storage agreements, where a customer agrees to pay for a certain amount of storage in a tank over a period of time (storage terminal revenues), and throughput agreements, where a customer pays a fee per barrel for volumes moving through our terminals (throughput terminal revenues). Our terminals also provide blending, additive injections, handling and filtering services for which we charge additional fees. We previously charged a fee for each barrel of crude oil and certain other feedstocks that we delivered to Valero Energy’s Benicia, Corpus Christi West and Texas City refineries from our crude oil refinery storage tanks. Effective January 1, 2017, we lease these refinery storage tanks in exchange for a fixed fee. Certain of our facilities charge fees to provide marine services such as pilotage, tug assistance, line handling, launch service, emergency response services and other ship services.

Demand for Refined Petroleum Products and Crude Oil

The operations of our refined product terminals depend in large part on the level of demand for products stored in our terminals in the markets served by those assets. The majority of products stored in our terminals are refined petroleum products. Demand for our terminalling services will generally increase or decrease with demand for refined petroleum products, and demand for refined petroleum products tends to increase or decrease with the relative strength of the economy. In addition, the forward pricing curve can have an impact on demand. For example, in a contango market (when the price of a commodity is expected to exceed current prices), demand for storage services will generally increase.

Crude oil delivered to our St. James terminal through our unit train facilities, and crude oil delivered to our Corpus Christi North Beach terminal will generally increase or decrease with crude oil production rates in the Bakken and Eagle Ford shale plays, respectively. In addition, the market price relationship between various grades of crude oil impacts the demand for our unit train facilities at our St. James terminal.

Customers

We provide storage and terminalling services for crude oil and refined petroleum products to many of the world’s largest producers of crude oil, integrated oil companies, chemical companies, oil traders and refiners. In addition, our blending capabilities in our storage assets have attracted customers who have leased capacity primarily for blending purposes. The largest customer of our storage segment is Valero Energy, which accounted for approximately 21% of the total revenues of the segment for the year ended December 31, 2017. No other customer accounted for more than 10% of the total revenues of the storage segment for the year ended December 31, 2017.

Competition and Business Considerations

Many major energy and chemical companies own extensive terminal storage facilities. Although such terminals often have the same capabilities as terminals owned by independent operators, they generally do not provide terminalling services to third parties. In many instances, major energy and chemical companies that own storage and terminalling facilities are also significant customers of independent terminal operators. Such companies typically have strong demand for terminals owned by independent operators when independent terminals have more cost-effective locations near key transportation links, such as

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deep-water ports. Major energy and chemical companies also need independent terminal storage when their owned storage facilities are inadequate, either because of size constraints, the nature of the stored material or specialized handling requirements.

Independent terminal owners generally compete on the basis of the location and versatility of terminals, service and price. A favorably located terminal will have access to various cost-effective transportation modes both to and from the terminal. Transportation modes typically include waterways, railroads, roadways and pipelines.

Terminal versatility is a function of the operator’s ability to offer complex handling requirements for diverse products. The services typically provided by the terminal include, among other things, the safe storage of the product at specified temperature, moisture and other conditions, as well as receipt at and delivery from the terminal, all of which must comply with applicable environmental regulations. A terminal operator’s ability to obtain attractive pricing is often dependent on the quality, versatility and reputation of the facilities owned by the operator. Although many products require modest terminal modification, operators with versatile storage capabilities typically require less modification prior to usage, ultimately making the storage cost to the customer more attractive.

Our St. Eustatius and Point Tupper terminals have historically functioned as “break bulk” facilities, which handled imports of light crude from foreign sources into the U.S. to satisfy U.S. East Coast and Gulf Coast refinery demand for light crude. Light crude suppliers brought the crude from the Middle East and other foreign regions on very large ships, which are efficient for long routes. These large ships, due to draft constraints, are unable to navigate far enough inland to deliver directly to U.S. shores, which necessitates unloading these ships to storage and subsequent loading onto smaller ships that can bring the crude to the refiners, a process referred to as “break bulk.” Both terminals are well-located to provide this service.

As the supply of light crude from various U.S. shale formations has increased, U.S. demand for foreign light crude oil, particularly on the U.S. Gulf Coast, has dropped. This reduced demand for imported light crude has, in turn, changed oil trade flow patterns around the world, thereby depressing the demand for break bulk services. At the same time, South American production of heavy crude has ramped up significantly. As demand for export of heavy crude out of South America has risen, so has the demand for “build bulk” services. In order to reduce costs and increase efficiencies for long routes to customers abroad, exporting producers need to consolidate their heavy oil cargos from the small ships used to move the heavy crude off shore to a large vessel that is more efficient for long routes, a process referred to as “build bulk.” Our St. Eustatius terminal’s location is well-suited to build bulk for South American producers headed to customers overseas, primarily in Asia. However, recently, the combination of oversupply of storage capacity, decreased demand from backwardated markets and reduced North American crude imports has depressed storage rates in the region.

We may face increased competition from new and/or expanding terminals near our locations, if those facilities offer either break bulk or build bulk services, as demanded by the applicable oil trade flows, now and in the future.

Our crude oil refinery storage tanks are physically integrated with and serve refineries owned by Valero Energy. Additionally, we have entered into various agreements with Valero Energy governing the usage of these tanks. As a result, we believe that we will not face significant competition for our services provided to those refineries.

FUELS MARKETING

Prior to the third quarter of 2017, our fuels marketing operations involved the purchase of crude oil, fuel oil, bunker fuel, fuel oil blending components and other refined products for resale. We ceased marketing crude oil in the second quarter of 2017 and exited our heavy fuels trading operations in the third quarter of 2017. These actions are in line with our goal of reducing our exposure to commodity margins, and instead focusing on our core, fee-based pipeline and storage segments. The only operations remaining in our fuels marketing segment are our bunkering operations at our St. Eustatius and Texas City terminals, as well as certain of our blending operations.

The results of operations for the fuels marketing segment depend largely on the margin between our cost and the sales prices of the products we market. Therefore, the results of operations for this segment are more sensitive to changes in commodity prices compared to the operations of the pipeline and storage segments. Since our fuels marketing operations expose us to commodity price risk, we enter into derivative instruments to mitigate the effect of commodity price fluctuations on our operations. The derivative instruments we use consist primarily of commodity futures and swap contracts.

Customers for our bunker fuel sales are mainly ship owners, including cruise line companies. In the sale of bunker fuel, we compete with ports offering bunker fuels that are along the route of travel of the vessel.

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EMPLOYEES

As of December 31, 2017, we had 1,694 employees.

RATE REGULATION

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

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

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

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

ENVIRONMENTAL, HEALTH, SAFETY AND SECURITY REGULATION

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

In 2017, our capital expenditures attributable to compliance with environmental regulations were $13.9 million, and we currently project spending to be approximately $17.8 million in this regard in 2018. However, future governmental actions could result in these laws and regulations becoming more restrictive, necessitating additional capital expenditures and operating expenses. At this time, we are unable to estimate the effect on our financial condition or results of operations, or the amount and timing of such possible future expenditures or expenses. In addition, while we believe that we are in substantial compliance with the environmental, health, safety and security laws and regulations applicable to our operations, risks of additional compliance expenditures, expenses and liabilities are inherent within the industry. As a result, there can be no assurances that significant expenditures, expenses and liabilities will not be incurred in the future. However, while compliance may affect our capital expenditures and operating expenses, we believe that the cost of such compliance will not have a material impact on our

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competitive position, financial condition or results of operations. Further, we do not believe that our cost of compliance is proportionately greater than the cost to other companies operating in our industry.

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

OCCUPATIONAL SAFETY AND HEALTH

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

FUEL STANDARDS AND RENEWABLE ENERGY

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

HAZARDOUS SUBSTANCES & HAZARDOUS WASTE

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

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

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

AIR

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

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WATER

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

PIPELINE AND OTHER ASSET INTEGRITY, SAFETY AND SECURITY

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

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

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RISK FACTORS

RISKS RELATED TO THE POTENTIAL MERGER

While the Merger Agreement is in effect, we may be limited in our ability to pursue other attractive business opportunities.

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

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

Our existing unitholders will be diluted by the Merger.

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

The Merger is subject to conditions and may not be consummated even if the required NuStar GP Holdings unitholder approvals are obtained.

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

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

Failure to complete the Merger or delays in completing the Merger could negatively impact our common unit price.

If the Merger is not completed for any reason, we may be subject to a number of material risks, including the following:


•	we will not realize the benefits expected from the Merger, including a potentially enhanced financial and competitive position;


•	the price of our common units may decline to the extent that the current market price of these securities reflects a market assumption that the Merger will be completed; and


•	some costs relating to the Merger, such as certain investment banking fees and legal and accounting fees, must be paid even if the Merger is not completed.

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The costs of the Merger could adversely affect our operations and cash flows available for distribution to our unitholders.

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

RISKS RELATED TO OUR BUSINESS

We may not be able to generate sufficient cash from operations to enable us to pay quarterly distributions to our unitholders.

The amount of cash that we can distribute to our unitholders each quarter principally depends upon the amount of cash we generate from our operations, which fluctuates from quarter to quarter based on, among other things:


•	throughput volumes transported in our pipelines;


•	storage contract renewals or throughput volumes in our terminals and storage facilities;


•	tariff rates and fees we charge and the revenue we realize for our services;


•	demand for and supply of crude oil, refined products and anhydrous ammonia;


•	the effect of worldwide energy conservation measures;


•	our operating costs;


•	the costs to comply with environmental, health, safety and security laws and regulations;


•	weather conditions;


•	domestic and foreign governmental laws, regulations, sanctions, embargoes and taxes;


•	prevailing economic conditions; and


•	the results of our marketing, trading and hedging activities, which fluctuate depending upon the relationship between refined product prices and prices of crude oil and other feedstocks.

In addition, the amount of cash that we will have available for distribution depends on other factors, including:


•	our debt service requirements and restrictions on distributions contained in our current or future debt agreements;


•	the sources of cash used to fund our acquisitions;


•	our capital expenditures;


•	fluctuations in our working capital needs;


•	issuances of debt and equity securities and ability to access the capital markets; and


•	adjustments in cash reserves made by our board of directors, in its discretion.

On February 8, 2018, we announced that our management anticipates recommending to our board of directors, and our board of directors expects to adopt, a reset of our quarterly distribution per common unit to $0.60 ($2.40 on an annualized basis), starting with the first-quarter distribution payable in May 2018. In addition, it is possible that one or more of the factors listed above may serve to reduce our available cash to such an extent that we could be rendered unable to pay distributions at the current level or at all in a given quarter. Furthermore, cash distributions to our unitholders depend primarily upon our cash flows, including cash flows from reserves and working capital borrowings, and not solely on profitability, which is affected by non-cash items, and we may make cash distributions during periods in which we record net losses and may not make cash distributions during periods in which we record net income.

Our future financial and operating flexibility may be adversely affected by our significant leverage, any future downgrades of our credit ratings, restrictions in our debt agreements and conditions in the financial markets.

As of December 31, 2017, our consolidated debt was $3.6 billion, and we have the ability to incur more debt. We also may be required to post cash collateral under certain of our hedging arrangements, which we expect to fund with borrowings under our revolving credit agreement. In addition to any potential direct financial impact of our debt, it is possible that any material increase to our debt or other negative financial factors may be viewed negatively by credit rating agencies, which could result in ratings downgrades and increased costs for us to access the capital markets. In November 2017, S&P Global Ratings downgraded our credit rating from BB+ Stable to BB Negative outlook, which raised the interest rate on our 7.65% Senior Notes Due 2018 (the 2018 Senior Notes). In February 2018, Moody’s Investors Service, Inc. downgraded our credit rating from Ba1 to Ba2, which increased the interest rate on both the 2018 Senior Notes and amounts borrowed under our credit facilities. Any additional downgrades in our credit ratings in the future could result in further increases to the interest rate on the 2018 Senior Notes, significantly increase our capital costs, reduce our liquidity and adversely affect our ability to raise capital in the future.

Our revolving credit agreement contains restrictive covenants, such as limitations on indebtedness, liens, mergers, asset transfers and certain investing activities. In addition, the revolving credit agreement generally requires us to maintain, as of the end of each rolling period (consisting of any period of four consecutive fiscal quarters) a consolidated debt coverage ratio (consolidated debt to consolidated EBITDA, each as defined in the revolving credit agreement) not to exceed 5.00-to-1.00,

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except in specific circumstances, including acquisitions for aggregate net consideration of at least $50 million, when we are permitted to maintain a consolidated debt coverage ratio of up to 5.50-to-1.00 for two rolling periods, as provided in the revolving credit agreement. Our maximum permitted ratio was raised to 5.50-to-1.00 through March 31, 2018 due to our acquisition of Navigator Energy Services, LLC. We also amended our revolving credit agreement in November 2017 to exclude NuStar Logistics’ 7.625% Fixed-to-Floating Rate Subordinated Notes due 2043 (the Junior Sub Notes) from our calculation of consolidated debt through December 31, 2018. Failure to comply with any of the revolving credit agreement restrictive covenants or our required coverage ratio will result in a default and could result in acceleration of our obligations under the revolving credit agreement and possibly other indebtedness. Future financing agreements we may enter into may contain similar or more restrictive covenants than those we have negotiated for our current financing agreements.

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

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

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

Depending on conditions in the credit and capital markets at a given time, we may not be able to obtain funding on acceptable terms or at all, which may hinder or prevent us from meeting our future capital needs.

From time to time, the domestic and global financial markets and economic conditions are volatile and disrupted by a variety of factors, including low consumer confidence, high unemployment, geoeconomic and geopolitical issues, weak economic conditions and uncertainty in the market. In addition, there are fewer investors and lenders for master limited partnership debt and equity capital market issuances than there are for corporate issuances. As a result, the cost of raising capital in the debt and equity capital markets could increase substantially, possibly at a time when the availability of funds from these markets has diminished. The cost of obtaining funds from the credit markets may increase as interest rates increase and tighter lending standards are enacted, and lenders may refuse to refinance existing debt on similar terms or at all and reduce, or in some cases cease to provide, funding to borrowers.

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

A significant portion of our debt matures over the next five years and will need to be paid or refinanced, and changes to the debt and equity markets could limit our refinancing options.

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

Increases in interest rates could adversely affect our business and the trading price of our units.

We have significant exposure to increases in interest rates through variable rate provisions in certain of our debt instruments. At December 31, 2017, we had approximately $3.6 billion of consolidated debt, of which $2.3 billion was at fixed interest rates

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and $1.3 billion was at variable interest rates. Also, in January 2018 the interest rate on our Junior Sub Notes shifted from a fixed rate to a floating annual rate equal to the sum of the three-month LIBOR rate for the related quarterly interest period, plus 6.734%. Additionally, at December 31, 2017, we had $600.0 million aggregate notional amount of interest rate swap arrangements, which may expose us to risk of financial loss. Prior ratings downgrades on our existing indebtedness caused interest rates under our revolving credit agreement and our 2018 Senior Notes to increase, and any future downgrades may further increase the interest rate on our 2018 Senior Notes. Our results of operations, cash flows and financial position could be materially adversely affected by significant changes in interest rates. In addition, we historically have funded our strategic capital expenditures and acquisitions from external sources, primarily borrowings under our revolving credit agreement or funds raised through debt or equity offerings. An increase in interest rates may also have a negative impact on our ability to access the capital markets at economically attractive rates.

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

Continued low crude oil prices could have an adverse impact on our results of operations, cash flows and ability to make distributions to our unitholders.

Since late 2014, the price of crude oil has been depressed, which has caused most crude oil producers to reduce their capital spending and drilling activity and narrow their focus to assets in the most cost-advantaged regions. On the other hand, refiners have benefited from lower crude prices, to the extent that lower feedstock price has been coupled with higher demand for certain refined products in some regional markets. While only a portion of our total business is directly affected by the price of crude, continued low crude oil prices and related overall economic downturn could have a negative impact on our cash flows and results of operations.

An extended period of reduced demand for or supply of crude oil and refined products could affect our results of operations and ability to make distributions to our unitholders.

Although we enter into throughput and deficiency agreements to protect against near-term fluctuations whenever possible, our business is ultimately dependent upon the long-term demand for and supply of the crude oil and refined products we transport in our pipelines and store in our terminals. Any sustained decrease in demand for refined products in the markets our pipelines and terminals serve that extends beyond the expiration of our existing throughput and deficiency agreements could result in a significant reduction in throughputs in our pipelines and storage in our terminals, which would reduce our cash flows and impair our ability to make distributions to our unitholders. Factors that tend to decrease market demand include:


•	a recession or other adverse economic condition that results in lower spending by consumers on gasoline, diesel and travel;


•	higher fuel taxes or other governmental or regulatory actions that increase, directly or indirectly, the cost of gasoline;


•	an increase in automotive engine fuel economy, whether as a result of a shift by consumers to more fuel-efficient vehicles or technological advances by manufacturers;


•	new regulations or court decisions requiring the phase out or reduced use of gasoline-fueled vehicles;


•	the increased use of alternative fuel sources;

•

an increase in the market price of crude oil that leads to higher refined product prices, which may reduce demand for refined products and drive demand for alternative products. Market prices for crude oil and refined products, including fuel oil, are subject to wide fluctuation in response to changes in global and regional supply that are beyond our control, and increases in the price of crude oil may result in a lower demand for refined products that we transport, store and market, including fuel oil; and


•	a decrease in corn acres planted for ethanol, which may reduce demand for anhydrous ammonia.

Similarly, any sustained decrease in the supply of crude oil and refined products in markets we serve could result in a significant reduction in throughputs in our pipelines and storage in our terminals, which would reduce our cash flows and undermine our ability to make distributions to our unitholders. Factors that tend to decrease supply and, by extension, utilization of our pipelines and terminals include:


•	prolonged periods of low prices for crude oil and refined products, which could lead to a decrease in exploration and development activity and reduced production in markets served by our pipelines and storage terminals;


•	a lack of drilling services or equipment available to producers to accommodate production needs;


•	changes in laws, regulations, sanctions or taxation that directly or indirectly delay supply or production or increase the cost of production of refined products; and

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

Our inability to develop and execute growth projects and acquire new assets could limit our ability to maintain and grow quarterly distributions to our unitholders.

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

Failure to complete capital projects as planned could adversely affect our financial condition, results of operations and cash flows.

Delays or cost increases related to capital spending programs involving construction of new facilities (or improvements and repairs to our existing facilities) could adversely affect our ability to achieve forecasted operating results. Although we evaluate and monitor each capital spending project and try to anticipate difficulties that may arise, such delays or cost increases may arise as a result of factors that are beyond our control, including:


•	non-performance or delay by, or disputes with, counterparties, vendors, suppliers, contractors or sub-contractors involved with a project;


•	denial or delay in issuing requisite regulatory approvals and/or permits;


•	protests and other activist interference with planned or in-process projects;


•	unplanned increases in the cost of construction materials or labor;


•	disruptions in transportation of modular components and/or construction materials;


•	severe adverse weather conditions, natural disasters or other events (such as hurricanes, equipment malfunctions, explosions, fires or spills) affecting our facilities, or those of vendors and suppliers;


•	shortages of sufficiently skilled labor, or labor disagreements resulting in unplanned work stoppages; or


•	market-related increases in a project’s debt or equity financing costs.

We will incur financing costs during the planning and construction phases of our projects; however, the operating cash flows we expect these projects to generate will not materialize until sometime after the projects are completed, if at all. Additionally, our forecasted operating results from capital spending projects are based upon our projections of future market fundamentals that are not within our control, including changes in general economic conditions, the supply and demand of crude oil and refined products, availability to our customers of attractively priced alternative solutions for storage, transportation or supplies of crude oil and refined products and overall customer demand.

If we are unable to retain or replace current customers and existing contracts to maintain utilization of our pipeline and storage assets at current or more favorable rates, our revenue and cash flows could be reduced to levels that could adversely affect our ability to make quarterly distributions to our unitholders.

Our revenue and cash flows are generated primarily from our customers’ payments of fees under throughput contracts and storage agreements. Failure to renew or enter into new contracts or our storage customers’ material reduction of utilization under existing contracts could result from many factors, including:


•	continued low crude oil prices;


•	a material decrease in the supply or price of crude oil;


•	a material decrease in demand for refined products in the markets served by our pipelines and terminals;


•	political, social or economic instability in another country impacting a customer based there;


•	competition for customers from companies with comparable assets and capabilities;


•	scheduled turnarounds or unscheduled maintenance at refineries we serve;


•	operational problems or catastrophic events affecting our assets or a refinery we serve;


•	environmental proceedings or other litigation that compel the cessation of all or a portion of the operations at our assets or a refinery we serve;


•	increasingly stringent environmental, health, safety and security regulations;


•	a decision by our current customers to redirect refined products transported in our pipelines to markets not served by our pipelines or to transport crude oil or refined products by means other than our pipelines; or

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•	a decision by our current customers to sell one or more of the refineries we serve to a purchaser that elects not to use our pipelines and terminals.

Competing midstream service providers, including certain major energy and chemical companies, possess, or have greater financial resources to acquire, assets better suited to meet customer demand, which could undermine our ability to obtain and retain customers or reduce utilization of our assets, which could reduce our revenues and cash flows, thereby reducing our ability to make our quarterly distributions to unitholders.

Our competitors include major energy and chemical companies, some of which have greater financial resources, more pipelines or storage terminals, greater capacity pipelines or storage terminals and greater access to supply than we do. Certain of our competitors also may have advantages in competing for acquisitions or other new business opportunities because of their financial resources and synergies in operations. As a consequence of increased competition in the industry, some of our customers may be reluctant to renew or enter into long-term contracts or contracts that provide for minimum throughput amounts in the future. Our inability to renew or replace our current contracts as they expire, to enter into contracts for newly acquired, constructed or expanded assets and to respond appropriately to changing market conditions could have a negative effect on our revenue, cash flows and ability to make quarterly distributions to our unitholders.

Our operations are subject to operational hazards and interruptions, and we cannot insure against and/or predict all potential losses and liabilities that might result therefrom.

Our operations and those of our customers and suppliers are subject to operational hazards and unforeseen interruptions such as natural disasters, adverse weather conditions (such as hurricanes, tornadoes, storms and floods), accidents, fires, explosions, hazardous materials releases, mechanical failures and other events beyond our control. In addition, many scientists hypothesize that global climatic changes are occurring that are likely to cause an increase in hurricanes and other severe weather conditions. These events might result in a loss of life or equipment, injury or extensive property damage, as well as an interruption in our operations or those of our customers or suppliers. In the event any of our facilities, or those of our customers or suppliers, suffer significant damage or are forced to shut down for a significant period of time, it may have a material adverse effect on our earnings, our other results of operations and our financial condition as a whole.

As a result of market conditions, premiums and deductibles for certain of our insurance policies have increased substantially and could escalate further; therefore, we may not be able to maintain or obtain insurance of the type and amount we desire at reasonable rates. Certain insurance coverage could become subject to broad exclusions, become unavailable altogether or become available only for reduced amounts of coverage and at higher rates. For example, our insurance carriers require broad exclusions for losses due to terrorist acts. If we were to incur a significant liability for which we are not fully insured, such a liability could have a material adverse effect on our financial position.

We could be subject to damages or lose customers due to failure to maintain certain quality specifications or other claims related to the operation of our assets and the services we provide to our customers.

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

We are exposed to counterparty credit risk. Nonpayment and nonperformance by our customers, vendors or derivative counterparties could reduce our revenues, increase our expenses and otherwise have a negative impact on our ability to conduct our business, operating results, cash flows and ability to make distributions to our unitholders.

Weak economic conditions and widespread financial stress could reduce the liquidity of our customers, vendors or counterparties, making it more difficult for them to meet their obligations to us. We are therefore subject to risks of loss resulting from nonpayment or nonperformance by our customers to whom we extend credit. Severe financial problems encountered by our customers could limit our ability to collect amounts owed to us, or to enforce the performance of obligations owed to us under contractual arrangements. For example, a substantial portion of our St. Eustatius facility revenue derives from our storage of petroleum products exported from Venezuela on behalf of Petróleos de Venezuela, S.A. (PDVSA), a state-owned Venezuelan oil company. Significant political, social and economic instability in Venezuela, including constraints on foreign currency transactions by the Venezuelan government, has caused PDVSA to utilize our assets significantly less than we forecasted and late-pay invoices from time to time. Our involvement with products exported from Venezuela also exposes us to the risk of trade restrictions and economic embargoes imposed by the United States and other countries.

In addition, nonperformance by vendors who have committed to provide us with critical products or services could raise our costs or interfere with our ability to successfully conduct our business. Furthermore, nonpayment by the counterparties to any

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

Cybersecurity breaches and other disruptions could compromise our information and operations, and expose us to liability, which would cause our business and reputation to suffer.

We rely on our information technology infrastructure to process, transmit and store electronic information, including information we use to safely operate our assets. In recent years, there has been a rise in the number of cyberattacks on other companies’ network and information systems by both state-sponsored and criminal organizations, and as a result, the risks associated with such an event continue to increase. A significant failure, compromise, breach or interruption in our systems could result in a disruption of our operations, customer dissatisfaction, damage to our reputation, a loss of customers or revenues and potential regulatory fines. If any such failure, interruption or similar event results in improper disclosure of information maintained in our information systems and networks or those of our vendors, including personnel, customer and vendor information, we could also be subject to liability under relevant contractual obligations and laws and regulations protecting personal data and privacy. Our financial results could also be adversely affected if operational systems are breached or an employee causes our operational systems to fail, either as a result of inadvertent error or by deliberately tampering with or manipulating our operational systems.

Although we believe that we have robust information security procedures and other safeguards in place, as cyberthreats continue to evolve, we may be required to expend additional resources to continue to enhance our information security measures and/or to investigate and remediate information security vulnerabilities.

Acquisitions and expansions, if any, may increase substantially the level of our indebtedness and contingent liabilities or otherwise change our capital structure, and we may be unable to integrate acquisitions and expansions effectively into our existing operations.

From time to time, we evaluate and acquire assets and businesses that we believe complement or diversify our existing assets and operations. Acquisitions may require us to raise a substantial amount of equity or incur a substantial amount of indebtedness. If we consummate any future material acquisitions, our capitalization and results of operations may change significantly, and unitholders will not have the opportunity to evaluate the economic, financial and other relevant information that we will consider in connection with any future acquisitions.

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

Even if we do consummate acquisitions that we believe will increase distributable cash flow, these acquisitions may nevertheless result in a decrease in distributable cash flow. Any acquisition involves potential risks, including, among other things:


•	we may not be able to obtain the cost savings and financial improvements we anticipate or acquired assets may not perform as we expect;


•	we may not be able to successfully integrate the assets, management teams or employees of the businesses we acquire with our assets and management team, or such integration may be significantly delayed;


•	we may fail or be unable to discover some of the liabilities of businesses that we acquire, including liabilities resulting from a prior owner’s noncompliance with applicable federal, state or local laws;


•	we may have assumed prior known or unknown liabilities for which we may not be indemnified or have adequate insurance;


•	acquisitions may divert the attention of our senior management from focusing on our core business;


•	we may experience a decrease in our liquidity by using a significant portion of our available cash or borrowing capacity to finance acquisitions; and


•	we may face the risk that our existing financial controls, information systems, management resources and human resources will need to grow to support future growth.

We operate a global business that exposes us to additional risk.

We operate a global business. A significant portion of our revenues come from our business outside of the United States, and our operations are subject to various risks unique to each country that could have a material adverse effect on our business, results of operations and financial condition. With respect to any particular country, these risks may include political and

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economic instability, including: civil unrest, war and other armed conflict; inflation; and currency fluctuations, devaluation and conversion restrictions. We are also exposed to the risk of governmental actions that may: limit or disrupt markets for our operations, restrict payments or limit the movement of funds; impose sanctions on our ability to conduct business with certain customers or persons; or result in the deprivation of contract rights. Our operations outside the United States may also be affected by changes in trade protection laws, policies and measures, and other regulatory requirements affecting trade and investment, including the Foreign Corrupt Practices Act, the United Kingdom Bribery Act and other foreign laws prohibiting corrupt payments, as well as import and export regulations. Additionally, negotiations are ongoing regarding the United Kingdom’s exit from the European Union, and any future effects from this are currently unknown.

We also have assets in, or do business with customers based in, certain emerging markets, and the developing nature of these markets presents a number of risks. In addition, due to the unsettled political conditions in many oil-producing countries, our operations may be subject to the adverse consequences of war, civil unrest, strikes, currency controls and governmental actions.

Deterioration of social, political, labor or economic conditions, including the increasing threat of terrorist organizations and drug cartels, in a country or region in which we do business, or affecting a customer with whom we do business, as well as difficulties in staffing and managing foreign operations, may adversely affect our operations or financial results. For example, PDVSA, a state-owned oil company in Venezuela, is a significant customer of our terminal facility in St. Eustatius, and recent political, social and economic instability in Venezuela seems to have had a negative impact on both PDVSA’s utilization of our facility and its ability to timely pay amounts invoiced.

We are subject to laws and sanctions implemented by the United States and foreign jurisdictions where we do business that may restrict the type of business we are permitted to conduct with certain entities, including PDVSA, restrict our activities in certain countries, or even restrict the services we may provide with respect to crude oil or other products produced in certain countries. In 2017, the United States and the European Union imposed sanctions relating to Venezuela and PDVSA. While these sanctions do not prohibit us from continuing to perform under our existing contracts with PDVSA, the sanctions may increase the likelihood that PDVSA will be unable to perform its obligations to us. In addition, in the event additional sanctions are imposed in the future relating to Venezuela or PDVSA, such future sanctions may result in further deterioration of PDVSA’s ability to perform its obligations to us and could prevent us from continuing to serve PDVSA in St. Eustatius.

We do not own all of the land on which our pipelines and facilities have been constructed, and we are therefore subject to the possibility of increased costs or the inability to retain necessary land use.

We obtain the rights to construct and operate our pipelines, storage terminals and other facilities on land owned by third parties and governmental agencies. Many of our rights-of-way or other property rights are perpetual in duration, but others are for a specific period of time. In addition, some of our facilities are located on leased premises. Our loss of property rights, through our inability to renew right-of-way contracts or leases or otherwise, could adversely affect our operations and cash flows available for distribution to unitholders.

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

We may be unable to obtain or renew permits necessary for our operations, which could inhibit our ability to do business.

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

We may have liabilities from our assets that preexist our acquisition of those assets, but that may not be covered by indemnification rights we may have against the sellers of the assets.

In some cases, we have indemnified the previous owners and operators of acquired assets. Some of our assets have been used for many years to transport and store crude oil and refined products, and releases may have occurred in the past that could

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require costly future remediation. If a significant release or event occurred in the past, the liability for which was not retained by the seller, or for which indemnification by the seller is not available, it could adversely affect our financial position and results of operations. Conversely, if future releases or other liabilities arise from assets we have sold, we could incur costs related to those liabilities if the buyer possesses valid indemnification rights against us with respect to those assets.

Climate change and fuels legislation and other regulatory initiatives may decrease demand for the products we store, transport and sell and increase our operating costs.

In response to scientific studies asserting that emissions of certain “greenhouse gases” such as carbon dioxide and methane may be contributing to warming of the Earth’s atmosphere, the U.S. Congress, European Union and other political bodies have considered legislation or regulation to reduce emissions of greenhouse gases. Passage of climate change or fuels legislation or other regulatory initiatives in fuel efficiency, fuel additives, renewable fuels and other areas in which we conduct business could result in changes to the demand for the products we store, transport and sell, and could increase the costs of our operations, including costs to operate and maintain our facilities, install new emission controls on our facilities, acquire allowances to authorize our greenhouse gas or other emissions, pay any taxes related to our greenhouse gas or other emissions or administer and manage emissions programs. In addition, certain of our blending operations can result in requirements to purchase renewable energy credits. Even though we attempt to mitigate such lost revenues or increased costs through the contracts we sign with our customers, we may be unable to recover those revenues or mitigate the increased costs, and any such recovery may depend on events beyond our control, including the outcome of future rate proceedings before the FERC, the STB or other regulators and the provisions of any final legislation or regulations. Reductions in our revenues or increases in our expenses as a result of climate change legislation or other regulatory initiatives could have adverse effects on our business, financial position, results of operations and prospects.

Our operations are subject to federal, state and local laws and regulations, in the U.S. and in the other countries in which we operate, relating to environmental, health, safety and security that could require us to make substantial expenditures.

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

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

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

Our interstate common carrier pipelines are subject to regulation by the FERC.

The FERC regulates the tariff rates and terms and conditions of service for interstate oil movements on our common carrier pipelines. FERC regulations require that these rates must be just and reasonable and that the pipeline not engage in undue discrimination or undue preference with respect to any shipper. Under the ICA, the FERC or shippers may challenge our pipeline tariff filings, including rates and terms and conditions of service. Further, other than for rates set under market-based rate authority, if a new rate is challenged by protest and investigated by the FERC, the FERC may suspend collection of such new rate for up to seven months. If such new rate is found to be unjust and unreasonable, the FERC may order refunds of amounts collected in excess of amounts generated by the just and reasonable rate determined by the FERC. A successful rate challenge could result in a common carrier paying refunds together with interest for the period that the rate was in effect. In

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addition, shippers may challenge by complaint tariff rates and terms and conditions of service even after the rates and terms and conditions of service are in effect. If the FERC, in response to such a complaint or on its own initiative, initiates an investigation of rates that are already in effect, the FERC may order a carrier to change its rates prospectively. If existing rates are challenged and are determined by the FERC to be in excess of a just and reasonable level, any complaining shipper may obtain reparations for damages sustained during the two years prior to the date the shipper filed a complaint.

We are able to use various FERC-authorized rate change methodologies for our interstate pipelines, including indexed rates, cost-of-service rates, market-based rates and settlement rates. Typically, we adjust our rates annually in accordance with the FERC indexing methodology, which currently allows a pipeline to change its rates within prescribed ceiling levels that are tied to an inflation index. For the five-year period beginning July 1, 2011, the index was measured by the year-over-year change in the Bureau of Labor’s producer price index for finished goods, plus 2.65%. For the five-year period beginning July 1, 2016, the current index is measured by the year-over-year change in the Bureau of Labor’s producer price index for finished goods, plus 1.23%. Further, some of our newer projects that involved an open season include negotiated indexation rate caps.

In October 2016, the FERC initiated an Advance Notice of Proposed Rulemaking (ANOPR) to determine whether to require oil pipeline companies to file cost and revenue data for each of the company’s pipeline systems, with the definition of such systems also part of the ANOPR. Among other things, the ANOPR also proposed that index rate adjustments be capped or prohibited under certain circumstances and that ceiling rates be capped under certain circumstances. These methodologies, if adopted, could result in changes in our revenue that do not fully reflect changes in costs we incur to operate and maintain our pipelines. For example, our costs could increase more quickly or by a greater amount than the negotiated or, if adopted, FERC-mandated indexation rate cap.

The reporting of system-based cost and revenue data, if adopted as a result of the ANOPR, could lead to an increase in rate litigation at the FERC. Currently, shippers may protest rate increases made within the ceiling levels, but such protests must show that the portion of the rate increase resulting from application of the index is substantially in excess of the pipeline’s change in costs from the previous year. However, if the index results in a negative adjustment, we are required to reduce any rates that exceed the new maximum allowable rate. In addition, changes in the index might not be large enough to fully reflect actual increases in our costs. If the FERC’s rate-making methodologies change, any such change or new methodologies could result in rates that generate lower revenues and cash flow and could adversely affect our ability to make distributions to our unitholders and to meet our debt service requirements. Additionally, because competition constrains our rates in various markets, we may from time to time be forced to reduce some of our rates to remain competitive.

Changes to FERC rate-making principles or pronouncements could have an adverse impact on our ability to recover the full cost of operating our pipeline facilities and our ability to make distributions to our unitholders.

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

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

On July 1, 2016, the D.C. Circuit issued an opinion granting the shippers’ petition for review of the FERC’s rulings on the income tax allowance, finding that the FERC had failed to demonstrate that there is no double recovery of taxes for partnerships that receive an income tax allowance in addition to the return they receive through the rate of return on equity. On this basis, the D.C. Circuit remanded the issue to the FERC, which established a pending industrywide Notice of Inquiry regarding this issue. Certain participants in the Notice of Inquiry made filings claiming that pipeline rates should be reduced based on anticipated income tax reductions related to the Tax Cuts and Jobs Act. Because the extent to which an interstate oil pipeline organized as a partnership is entitled to an income tax allowance is subject to a case-by-case review at the FERC and is a matter that remains under litigation and FERC review, the level of income tax allowance to which we would ultimately be entitled is not certain. The manner in which the FERC’s income tax allowance policy is applied to pipelines owned by publicly traded partnerships could limit our ability to include a full income tax allowance in our cost of service.

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The rates that we may charge on our interstate ammonia pipeline are subject to regulation by the STB.

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

Increases in natural gas and power prices could adversely affect our operating expenses and our ability to make distributions to our unitholders.

Power costs constitute a significant portion of our operating expenses. For the year ended December 31, 2017, our power costs equaled approximately $46.0 million, or 10.2% of our operating expenses for the year. We use mainly electric power at our pipeline pump stations and terminals, and such electric power is furnished by various utility companies that primarily use natural gas to generate electricity. Accordingly, our power costs typically fluctuate with natural gas prices, and increases in natural gas prices may cause our power costs to increase further. If natural gas prices increase, our cash flows may be adversely affected, which could adversely affect our ability to make distributions to our unitholders.

Terrorist attacks and the threat of future attacks worldwide, as well as continued hostilities in the Middle East or other sustained military campaigns, may adversely impact our results of operations.

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

Hedging transactions may limit our potential gains or result in significant financial losses.

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

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

Our purchase and sale of crude oil and petroleum products may expose us to trading losses and hedging losses, and non-compliance with our risk management policies could result in significant financial losses.

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

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

If we fail to maintain an effective system of internal controls, we may not be able to report our financial results accurately or prevent fraud, which could have a material and adverse impact on our financial condition, results of operations, cash flows and ability to make distributions to our unitholders.

Under Section 404 of the Sarbanes-Oxley Act of 2002, we are required to disclose material changes made in our internal controls over financial reporting on a quarterly basis and we are required to assess the effectiveness of our controls annually.

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Effective internal controls are necessary for us to provide reliable and timely financial reports. Given the difficulties inherent in the design and operation of internal controls over financial reporting, we may be unable to maintain effective controls over our financial processes and reporting in the future or to comply with our obligations under Section 404.

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

RISKS INHERENT IN AN INVESTMENT IN US

We do not have the same flexibility as other types of organizations to accumulate cash and equity and protect against illiquidity in the future.

Unlike a corporation, our partnership agreement requires us to make quarterly distributions to our unitholders of all available cash, after taking into account reserves for commitments and contingencies, including capital and operating costs and debt service requirements. As a result, we do not accumulate equity in the form of retained earnings in a manner typical of many other forms of organizations, including most traditional public corporations. We are therefore more likely than those organizations to require issuances of additional capital to finance our growth plans, meet unforeseen cash requirements and service our debt.

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

Our cash distribution policy may limit our growth.

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

NuStar GP Holdings may currently have and, if the Merger is not consummated, may continue to have conflicts of interest and limited fiduciary responsibilities, which may permit it to favor its own interests to the detriment of our unitholders.

NuStar GP Holdings currently indirectly owns our general partner, our incentive distribution rights and, as of December 31, 2017, an aggregate 11.0% of our outstanding common units. Conflicts of interest may arise between NuStar GP Holdings and its affiliates, including our general partner, on the one hand, and us and our limited partners, on the other hand. As a result of these conflicts, the general partner may favor its own interests and the interests of its affiliates over the interests of our unitholders. These conflicts include, among others, the following situations:


•	our general partner is allowed to take into account the interests of parties other than us, such as NuStar GP Holdings, in resolving conflicts of interest, which has the effect of limiting its fiduciary duty to our unitholders;


•	our general partner may limit its liability and reduce its fiduciary duties, while also restricting the remedies available to unitholders. As a result of purchasing our units, unitholders have consented to some actions and conflicts of interest that might otherwise constitute a breach of fiduciary or other duties under applicable state law;


•	our general partner determines the amount and timing of asset purchases and sales, capital expenditures, borrowings and issuances of additional limited partner interests and reserves, each of which can affect the amount of cash that is paid to our unitholders;


•	our general partner determines in its sole discretion which costs incurred by NuStar GP Holdings and its affiliates are reimbursable by us;


•	our general partner may cause us to pay the general partner or its affiliates for any services rendered on terms that are fair and reasonable to us or enter into additional contractual arrangements with any of these entities on our behalf;


•	our general partner decides whether to retain separate counsel, accountants or others to perform services for us; and

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

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

If the Merger is not consummated, the general partner interest, the control of our general partner and the incentive distribution rights of our general partner may be transferred to a third party without unitholder consent.

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

Unitholders have limited voting rights, and our partnership agreement further restricts the voting rights of unitholders owning 20% or more of any class of our units.

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

We may issue an unlimited number of additional units, including units that are senior to the common units and pari passu with our 8.50% Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units, 7.625% Series B Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units and 9.00% Series C Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units (collectively, the Preferred Units); issuing new units dilutes existing unitholders and may increase the aggregate distribution we are required to pay each quarter under the terms of our partnership agreement.

Our partnership agreement allows us to issue additional units and certain other equity securities on the terms and conditions established by our general partner and without the approval of other unitholders. There is no limit on the total number of units and other equity securities we may issue. If we issue additional units or other equity securities, the proportionate partnership interest of our existing common unitholders and the relative voting strength of each of the previously outstanding common units will decrease. Any additional issuance may increase the risk that we will be unable to maintain or increase our per common unit distribution level.

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


•	our unitholders’ proportionate ownership interest in us will decrease;


•	the amount of cash available for distribution on each unit may decrease;


•	the ratio of taxable income to distributions may increase;


•	the relative voting strength of each previously outstanding unit may be diminished; and


•	the market price of our common units and Preferred Units may decline.

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

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

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

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

If we do not pay distributions on our Preferred Units in any fiscal quarter, we will be unable to pay distributions on our common units until all unpaid Preferred Unit distributions have been paid, and our common unitholders are not entitled to receive distributions for such prior period.

The Preferred Units rank senior to our common units with respect to distribution rights and rights upon liquidation. If we do not pay the required distributions on our Preferred Units, we will be unable to pay distributions on our common units. Additionally, because distributions to our Preferred Unitholders are cumulative, we will have to pay all unpaid accumulated preferred distributions before we can pay any distributions to our common unitholders. Also, because distributions to our common unitholders are not cumulative, if we do not pay distributions on our common units with respect to any quarter, our common unitholders will not be entitled to receive distributions covering any prior periods. The preferences and privileges of the Preferred Units could adversely affect the market price for our common units, or could make it more difficult for us to sell our common units in the future.

Unitholders may not have limited liability if a court finds that unitholder action constitutes control of our business or that we have not complied with applicable statutes, which may have an impact on the cash we have available to make distributions.

Under Delaware law, unitholders could be held liable for our obligations to the same extent as a general partner if a court determined that actions of a unitholder constituted participation in the “control” of our business.

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

Under certain circumstances, unitholders may have liability to repay distributions wrongfully distributed to them.

Under Section 17-607 of the Delaware Act, we may not make a distribution to our unitholders if the distribution would cause our liabilities to exceed the fair value of our assets. Liabilities to partners on account of their partnership interests and liabilities that are nonrecourse to the partnership are not counted for purposes of determining whether a distribution is permitted.

Delaware law provides that, for a period of three years from the date of an impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to us for the repayment of the distribution amount. Likewise, upon the winding up of our partnership, in the event that (a) we do not distribute assets in the following order: (1) to creditors in satisfaction of our debts; (2) to partners and former partners in satisfaction of liabilities for distributions owed under our partnership agreement; (3) to partners for the return of their contributions; and finally (4) to the partners in the proportions in which the partners share in distributions and (b) a limited partner knows at the time that the distribution violated the Delaware Act, then such limited partner will be liable to repay the distribution for a period of three years from the impermissible distribution under Section 17-804 of the Delaware Act.

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

Unitholders may be required to sell their units to our general partner at an undesirable time or price.

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

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The NYSE does not require a publicly traded limited partnership like us to comply with certain of its corporate governance requirements.

We currently list our common units on the NYSE under the symbol “NS” and our Preferred Units on the NYSE under the symbols “NSprA,” “NSprB” and “NSprC,” respectively. Although our general partner has maintained a majority of independent directors on its board and all members of its board’s audit committee, compensation committee and nominating/governance & conflicts committee are independent directors, because we are a publicly traded limited partnership, the NYSE does not require us to have a majority of independent directors on our general partner’s board of directors or to have a compensation committee or a nominating committee consisting of independent directors. Additionally, any future issuance of additional common or Preferred Units or other securities, including to affiliates, will not be subject to the NYSE’s shareholder approval rules that apply to a corporation. Accordingly, the NYSE does not mandate the same protections for our unitholders as are required for certain corporations that are subject to all of the NYSE corporate governance requirements. See “Director Independence” under Item 13 of this annual report on Form 10-K for additional information regarding the independence of our general partner’s directors and the committees of our general partner’s board.

TAX RISKS TO OUR UNITHOLDERS

If we were treated as a corporation for federal or state income tax purposes or we were otherwise subject to a material amount of entity-level taxation, then our cash available for distribution to unitholders would be substantially reduced.

The anticipated after-tax benefit of an investment in our units depends largely on our being treated as a partnership for federal income tax purposes. We have not requested, and do not plan to request, a ruling from the Internal Revenue Service (the IRS) on this matter.

Despite the fact that we are a limited partnership under Delaware law, we will be treated as a corporation for federal income tax purposes unless we satisfy a “qualifying income” requirement. Based upon our current operations, we believe we satisfy the qualifying income requirement. Failing to meet the qualifying income requirement or a change in current law could cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to taxation as an entity.

If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate and would likely pay state and local income tax at varying rates. Distributions to unitholders who are treated as holders of corporate stock would generally be taxed again as corporate dividends (to the extent of our current and accumulated earnings and profits), and no income, gains, losses, deductions or credits would flow through to unitholders. Because a tax would be imposed upon us as a corporation, our distributable cash flow would be substantially reduced.

Moreover, changes in current state law may subject us to entity-level taxation by individual states. Because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. Imposition of any such taxes or an increase in the existing tax rates would substantially reduce the cash available for distribution to our unitholders. Therefore, if we were treated as a corporation for federal income tax purposes or otherwise subjected to a material amount of entity-level taxation, there would be a material reduction in the anticipated cash flow and after-tax return to our unitholders, likely causing a substantial reduction in the value of our units.

The tax treatment of publicly traded partnerships or an investment in our units could be subject to potential legislative, judicial or administrative changes or differing interpretations, possibly applied on a retroactive basis.

The present U.S. federal income tax treatment of publicly traded partnerships, including us, or an investment in our units may be modified by administrative, legislative or judicial changes or differing interpretations at any time. From time to time, members of Congress propose and consider such substantive changes to the existing federal income tax laws that affect publicly traded partnerships. Further, final Treasury regulations under Section 7704(d)(1)(E) of the Code published in the Federal Register interpret the scope of qualifying income requirements for publicly traded partnerships by providing industry-specific guidance. We do not believe the final Treasury regulations affect our ability to be treated as a partnership for U.S. federal income tax purposes.

In addition, the Tax Cuts and Jobs Act enacted December 22, 2017, makes significant changes to the U.S. federal income tax rules applicable to both individuals and entities, including changes to the tax rate on a unitholder’s allocable share of income from the publicly traded partnership. The Tax Cuts and Jobs Act is complex and lacks administrative guidance. Thus, the impact of certain aspects of its provisions on us or an investment in our units is currently unclear. Unitholders should consult their tax advisor regarding the Tax Cuts and Jobs Act and its effect on us or an investment in our units.

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

A successful IRS contest of the federal income tax positions we take may adversely impact the market for our units, and the costs of any contest will reduce cash available for distribution to our unitholders.

The IRS may adopt positions that differ from the positions we take, even positions taken with the advice of counsel. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take. A court may not agree with all of the positions we take. Any contest with the IRS may affect adversely the taxable income reported to our unitholders and the income taxes they are required to pay. As a result, any such contest with the IRS may materially and adversely impact the market for our units and the prices at which they trade. In addition, the costs of any contest between us and the IRS will be borne indirectly by our unitholders and our general partner because such costs will reduce our cash available for distribution.

If the IRS makes audit adjustments to our income tax returns for tax years beginning after December 31, 2017, it (and some states) may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustment directly from us, in which case we may elect to either pay the taxes directly to the IRS or to have our unitholders and former unitholders take such audit adjustment into account and pay any resulting taxes. If we bear such payment our cash available for distribution to our unitholders might be substantially reduced.

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

Even if unitholders do not receive any cash distributions from us, they will be required to pay taxes on their respective share of our taxable income.

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

Tax gain or loss on the disposition of our units could be different than expected.

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

Unitholders may be subject to limitations on their ability to deduct interest expense incurred by us.

In general, we are entitled to a deduction for interest paid or accrued on indebtedness properly allocable to our trade or business during our taxable year. However, under the Tax Cuts and Jobs Act, for taxable years beginning after December 31, 2017, a deduction for “business interest” is limited to the sum of our business interest income plus 30% of our “adjusted taxable income.” This limitation is applied at the entity level for partnerships. For the purposes of this limitation, our adjusted taxable income is computed without regard to any business interest expense or business interest income, and in the case of taxable years beginning before January 1, 2022, any deduction allowable for depreciation, amortization, or depletion. Any interest disallowed at the partnership level may be carried forward and deducted in future years by a unitholder from his share of our “excess taxable income,” which is generally equal to the excess of 30% of our adjusted taxable income over the amount of our deduction for business interest for such future taxable year, subject to certain restrictions.

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Tax-exempt entities face unique tax issues from owning our units that may result in adverse tax consequences to them.

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

Non-U.S. unitholders will be subject to U.S. taxes and withholding with respect to their income and gain from owning our units.

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

The Tax Cuts and Jobs Act imposes a withholding obligation of 10% of the amount realized upon a non-U.S. unitholder’s sale or disposition of units. The IRS has temporarily suspended the application of the withholding requirements on sales of publicly traded interests, including our units, pending promulgation of regulations or other guidance. It is not clear if or when such regulations or other guidances will be issued. Non-U.S. unitholders should consult a tax advisor before investing in our units.

We will treat each purchaser of our common units as having the same tax benefits without regard to the units purchased. The IRS may challenge this treatment, which could adversely affect the value of our common units.

Because we cannot match transferors and transferees of our common units, we will adopt depreciation and amortization positions that may not conform with all aspects of existing Treasury regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to unitholders. It also could affect the timing of these tax benefits or the amount of gain from a unitholder’s sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to the unitholder’s tax returns.

Unitholders will likely be subject to state and local taxes and return filing requirements as a result of investing in our units.

In addition to federal income taxes, unitholders will likely be subject to other taxes, such as state and local income taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we do business or own property. Unitholders will likely be required to file state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions. Further, unitholders may be subject to penalties for failure to comply with those requirements. We may own property or conduct business in other states or foreign countries in the future. It is each unitholder’s responsibility to file all federal, state and local tax returns.

We prorate our items of income, gain, loss and deduction between transferors and transferees of our common units each month based upon the ownership of our common units on the first day of each month, instead of on the basis of the date a particular common unit is transferred. The U.S. Treasury Department and the IRS issued final regulations pursuant to which a publicly traded partnership may use a similar monthly simplifying convention to allocate tax items among transferor and transferee unitholders, although such tax items must be prorated on a daily basis and the regulations do not specifically authorize all aspects of the proration method we have currently adopted. If the IRS were to challenge our proration method, we may be required to change the allocation of items of income, gain, loss and deduction among our common unitholders.

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We have adopted certain valuation methodologies in determining a common unitholder’s allocations of income, gain, loss and deduction. The IRS may challenge these methods or the resulting allocations and such a challenge could adversely affect the value of our common units.

In determining the items of income, gain, loss and deduction allocable to our common unitholders, we must routinely determine the fair market value of our respective assets. Although we may from time to time consult with professional appraisers regarding valuation matters, we make fair market value estimates using a methodology based on the market value of our common units as a means to measure the fair market value of our respective assets. The IRS may challenge these valuation methods and the resulting allocations of income, gain, loss and deduction.

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

A unitholder whose units are the subject of a securities loan (e.g., a loan to a “short seller” to cover a short sale of units) may be considered as having disposed of those units. If so, the unitholder would no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and may recognize gain or loss from the disposition.

Because there are no specific rules governing the federal income tax consequences of loaning a partnership interest, a unitholder whose units are the subject of a securities loan may be considered as having disposed of the loaned units. In that case, the unitholder may no longer be treated for tax purposes as a partner with respect to those units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan, any of our income, gain, loss or deduction with respect to those units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those units could be fully taxable as ordinary income. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to consult a tax advisor to discuss whether it is advisable to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their units.

Treatment of distributions on our Preferred Units as guaranteed payments for the use of capital creates a different tax treatment for the holders of Preferred Units than the holders of our common units and such distributions may not be eligible for the 20% deduction for qualified publicly traded partnership income.

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

The Tax Cuts and Jobs Act allows individuals and other non-corporate owners of interests in a publicly traded partnership to take a deduction equal to 20% of their allocable share of “qualified publicly traded partnership income.” Although we expect that much of the income we earn is generally eligible for the 20% deduction for qualified publicly traded partnership income, it is uncertain whether a guaranteed payment for the use of capital may constitute an allocable or distributive share of such income. As a result, the guaranteed payment for use of capital received by the holders of our Preferred Units may not be eligible for the 20% deduction for qualified publicly traded partnership income.

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

Investment in the Preferred Units by tax-exempt investors, such as employee benefit plans and IRAs, and non-U.S. persons raises issues unique to them. A non-U.S. holder’s income from guaranteed payments and any gain from the sale or disposition

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of our units will generally be considered to be effectively connected income and subject to U.S. federal income tax. Distributions to non-U.S. holders of Preferred Units will be subject to withholding taxes. If the amount of withholding exceeds the amount of U.S. federal income tax actually due, non-U.S. holders of Preferred Units may be required to file U.S. federal income tax returns in order to seek a refund of such excess. The Tax Cuts and Jobs Act imposes a withholding obligation of 10% of the amount realized upon a non-U.S. unitholder’s sale or disposition of Preferred Units. The IRS has temporarily suspended the application of the withholding requirements on sales of publicly traded interests, including our Preferred Units, pending promulgation of regulations or other guidance. It is not clear if or when such regulations or other guidance will be issued. Additionally, the treatment of guaranteed payments for the use of capital to tax exempt investors is not certain and such payments may be treated as unrelated business taxable income for federal income tax purposes.

All holders of our Preferred Units are urged to consult a tax advisor with respect to the consequences of owning our Preferred Units.

PROPERTIES

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

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

ITEM 3. LEGAL PROCEEDINGS

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

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

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

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PART II


ITEM 5.	MARKET FOR REGISTRANT’S COMMON UNITS, RELATED UNITHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Common Unit Distributions

Our common units are listed and traded on the New York Stock Exchange under the symbol “NS.” At the close of business on February 8, 2018, we had 464 holders of record of our common units. The following table presents the high and low sales prices for our common units during the periods presented (composite transactions as reported by the New York Stock Exchange) and the amount, record date and payment date of the quarterly cash distributions on our common units with respect to such periods:



	Price Range per Common Unit				Cash Distributions
	High		Low		Amount Per Common Unit		Record Date	Payment Date
Year 2017
4th Quarter (a)	$	41.00	$	26.21	$	1.095	February 8, 2018	February 13, 2018
3rd Quarter	$	47.99	$	37.30	$	1.095	November 9, 2017	November 14, 2017
2nd Quarter	$	52.68	$	42.40	$	1.095	August 7, 2017	August 11, 2017
1st Quarter	$	55.64	$	49.09	$	1.095	May 8, 2017	May 12, 2017
Year 2016
4th Quarter	$	50.87	$	43.41	$	1.095	February 8, 2017	February 13, 2017
3rd Quarter	$	50.72	$	43.91	$	1.095	November 8, 2016	November 14, 2016
2nd Quarter	$	53.47	$	37.90	$	1.095	August 9, 2016	August 12, 2016
1st Quarter	$	42.87	$	25.65	$	1.095	May 9, 2016	May 13, 2016


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

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

General Partner Distributions

Our general partner is entitled to distributions as shown below:



	Percentage of Distribution
Quarterly Distribution Amount per Common Unit	Common Unitholders	General Partner Including Incentive Distributions
Up to $0.60	98%	2%
Above $0.60 up to $0.66	90%	10%
Above $0.66	75%	25%

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Our general partner’s incentive distributions totaled $45.7 million and $43.4 million for the years ended December 31, 2017 and 2016, respectively. The general partner’s share of our distributions for the years ended December 31, 2017 and 2016 was 11.9% and 13.0%, respectively, due to the impact of the incentive distributions. In the second quarter of 2017, our general partner amended and restated our partnership agreement in connection with the issuance of the Series B Preferred Units described below and our acquisition of Navigator Energy Services, LLC to waive up to an aggregate $22.0 million of the quarterly incentive distributions to our general partner for any NS common units issued from the date of the acquisition agreement (other than those attributable to NS common units issued under any equity compensation plan) for ten consecutive quarters, starting with the distributions for the second quarter of 2017.

Pursuant to the Merger Agreement and at the effective time of the Merger, our partnership agreement will be amended and restated to, among other things, cancel the incentive distribution rights held by our general partner and convert the 2% general partner interest in NuStar Energy held by our general partner into a non-economic management interest. As a result, after the Merger, our general partner will no longer receive incentive distributions or quarterly cash distributions related to its ownership interest, from us. Please refer to Note 28 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for further discussion of the Merger.

Preferred Unit Distributions

The following table provides the terms related to distributions for our Series A, Series B and Series C Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units (collectively, the Preferred Units):



Units	Fixed Distribution Rate per Annum (as a Percentage of the $25.00 Liquidation Preference per Unit)	Fixed Distribution Rate per Unit per Annum		Optional Redemption Date/Date at Which Distribution Rate Becomes Floating	Floating Annual Rate (as a Percentage of the $25.00 Liquidation Preference per Unit)
Series A Preferred Units	8.50%	$	2.125	December 15, 2021	Three-month LIBOR plus 6.766%
Series B Preferred Units	7.625%	$	1.90625	June 15, 2022	Three-month LIBOR plus 5.643%
Series C Preferred Units	9.00%	$	2.25	December 15, 2022	Three-month LIBOR plus 6.88%

Distributions on the Preferred Units are payable out of any legally available funds, accrue and are cumulative from the original issuance dates, and are payable on the 15th day (or the next business day) of each of March, June, September and December of each year to holders of record on the first business day of each payment month. The Preferred Units rank equal to each other and senior to all of our other classes of equity securities with respect to distribution rights and rights upon liquidation.

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The following table summarizes information related to our quarterly cash distributions on our Preferred Units:



Period	Cash Distributions Per Unit		Record Date	Payment Date

Series A Preferred Units:
December 15, 2017 - March 14, 2018 (a)	$	0.53125	March 1, 2018	March 15, 2018
September 15, 2017 - December 14, 2017	$	0.53125	December 1, 2017	December 15, 2017
June 15, 2017 - September 14, 2017	$	0.53125	September 1, 2017	September 15, 2017
March 15, 2017 - June 14, 2017	$	0.53125	June 1, 2017	June 15, 2017
November 25, 2016 - March 14, 2017	$	0.64930556	March 1, 2017	March 15, 2017

Series B Preferred Units:
December 15, 2017 - March 14, 2018 (a)	$	0.47657	March 1, 2018	March 15, 2018
September 15, 2017 - December 14, 2017	$	0.47657	December 1, 2017	December 15, 2017
April 28, 2017 - September 14, 2017	$	0.725434028	September 1, 2017	September 15, 2017

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


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

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ITEM 6. SELECTED FINANCIAL DATA

The following table contains selected financial data derived from our audited financial statements:



	Year Ended December 31,
	2017		2016		2015		2014		2013 (a)
	(Thousands of Dollars, Except Per Unit Data)
Statement of Income Data:
Revenues (b)	$	1,814,019	$	1,756,682	$	2,084,040	$	3,075,118	$	3,463,732
Operating income (loss)	$	336,278	$	359,109	$	390,704	$	346,901	$	(19,121	)
Income (loss) from continuing operations (c)	$	147,964	$	150,003	$	305,946	$	214,169	$	(185,509	)
Income (loss) from continuing operations per common unit (c)	$	0.64	$	1.27	$	3.29	$	2.14	$	(2.89	)
Cash distributions per unit applicable to common limited partners	$	4.38	$	4.38	$	4.38	$	4.38	$	4.38

	December 31,
	2017 (d)		2016		2015		2014		2013
	(Thousands of Dollars)
Balance Sheet Data:
Property, plant and equipment, net	$	4,300,933	$	3,722,283	$	3,683,571	$	3,460,732	$	3,310,653
Total assets	$	6,535,233	$	5,030,545	$	5,125,525	$	4,918,796	$	5,032,186
Long-term debt, less current portion	$	3,263,069	$	3,014,364	$	3,055,612	$	2,749,452	$	2,655,553
Total partners’ equity	$	2,480,089	$	1,611,617	$	1,609,844	$	1,716,210	$	1,903,794


(a)	The losses for the year ended December 31, 2013 are mainly due to goodwill impairment charges.


(b)	Declines in revenues from 2013 through 2017 are mainly from a reduction in marketing activity and lower commodity prices. We ceased marketing crude oil in the second quarter of 2017 and exited our heavy fuels trading operations in the third quarter of 2017.


(c)	Includes the impact of a $58.7 million non-cash impairment charge on the Axeon term loan in 2016 and a $56.3 million non-cash gain associated with the Linden terminal acquisition in 2015.


(d)	The significant increases in balance sheet data are primarily due to our acquisition of Navigator Energy Services, LLC for approximately $1.5 billion in May 2017.

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

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

OVERVIEW

NuStar Energy L.P. (NYSE: NS) is engaged in the transportation of petroleum products and anhydrous ammonia, and the terminalling, storage and marketing of petroleum products. Unless otherwise indicated, the terms “NuStar Energy,” “NS,” “the Partnership,” “we,” “our” and “us” are used in this report to refer to NuStar Energy L.P., to one or more of our consolidated subsidiaries or to all of them taken as a whole. NuStar GP Holdings, LLC (NuStar GP Holdings or NSH) (NYSE: NSH) owns our general partner, Riverwalk Logistics, L.P., and owns an approximate 11% common limited partner interest in us as of December 31, 2017. Our Management’s Discussion and Analysis of Financial Condition and Results of Operations is presented in seven sections:


•	Overview


•	Results of Operations


•	Trends and Outlook


•	Liquidity and Capital Resources


•	Related Party Transactions


•	Critical Accounting Policies


•	New Accounting Pronouncements

Recent Developments

Merger. On February 7, 2018, NuStar Energy, Riverwalk Logistics, L.P., NuStar GP, LLC, Marshall Merger Sub LLC, a wholly owned subsidiary of NuStar Energy (Merger Sub), Riverwalk Holdings, LLC and NuStar GP Holdings, LLC (NuStar GP Holdings) entered into an Agreement and Plan of Merger (the Merger Agreement) pursuant to which Merger Sub will merge with and into NuStar GP Holdings with NuStar GP Holdings being the surviving entity (the Merger), such that NuStar Energy will be the sole member of NuStar GP Holdings following the Merger. Pursuant to the Merger Agreement and at the effective time of the Merger, our partnership agreement will be amended and restated to, among other things, (i) cancel the incentive distribution rights held by our general partner, (ii) convert the 2% general partner interest in NuStar Energy held by our general partner into a non-economic management interest and (iii) provide the holders of our common units with voting rights in the election of the members of the board of directors of NuStar GP, LLC at an annual meeting, beginning in 2019. The Merger is subject to the satisfaction or waiver of certain conditions, including approval of the Merger Agreement by NuStar GP Holdings unitholders. Please refer to Note 28 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for further discussion of the Merger.

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

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

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Permian Crude System. Please refer to Notes 4, 12 and 19 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for further discussion.

Axeon Term Loan. On February 22, 2017, we settled and terminated the $190.0 million term loan to Axeon Specialty Products, LLC (the Axeon Term Loan), pursuant to which we also provided credit support, such as guarantees, letters of credit and cash collateral, as applicable, of up to $125.0 million to Axeon Specialty Products, LLC (Axeon). We received $110.0 million in settlement of the Axeon Term Loan, and our obligation to provide ongoing credit support to Axeon ceased. In 2016, we recognized an impairment charge on the Axeon Term Loan of $58.7 million which is included in “Other (expense) income, net” in the consolidated statements of income. Please refer to Notes 7 and 15 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for additional information on the Axeon Term Loan and related credit support.

Other Events

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

Employee Transfer from NuStar GP, LLC. On March 1, 2016, NuStar GP, LLC, the general partner of our general partner and a wholly owned subsidiary of NuStar GP Holdings, transferred and assigned to NuStar Services Company LLC (NuStar Services Co), a wholly owned subsidiary of NuStar Energy, all of NuStar GP, LLC’s employees and related benefit plans, programs, contracts and policies (the Employee Transfer). As a result of the Employee Transfer, we pay employee costs directly and sponsor the long-term incentive plan and other employee benefit plans. Please refer to the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for the following: Note 17 for further discussion of the Employee Transfer and our related party agreements, Note 22 for a discussion of our employee benefit plans and Note 23 for a discussion of our long-term incentive plan.

Linden Acquisition. On January 2, 2015, we acquired full ownership of ST Linden Terminal, LLC (Linden), which owns a refined products terminal in Linden, NJ with 4.3 million barrels of storage capacity, for $142.5 million (the Linden Acquisition). Prior to the Linden Acquisition, Linden operated as a joint venture between Linden Holding Corp. and us, with each party owning 50%. On the acquisition date, we remeasured our existing 50% equity investment in Linden to its fair value of $128.0 million and we recognized a gain of $56.3 million in “Other (expense) income, net” in the consolidated statements of income for the year ended December 31, 2015. Please refer to Note 4 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for further discussion of the Linden Acquisition.

Operations

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

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

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

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We ceased marketing crude oil in the second quarter of 2017 and exited our heavy fuels trading operations in the third quarter of 2017. These actions are in line with our goal of reducing our exposure to commodity margins, and instead focusing on our core, fee-based pipeline and storage segments. The only operations remaining in our fuels marketing segment are our bunkering operations at our St. Eustatius and Texas City terminals, as well as certain of our blending operations.

Factors That Affect Results of Operations

The following factors affect the results of our operations:


•	company-specific factors, such as facility integrity issues and maintenance requirements that impact the throughput rates of our assets;


•	seasonal factors that affect the demand for products transported by and/or stored in our assets and the demand for products we sell;


•	industry factors, such as changes in the prices of petroleum products that affect demand and operations of our competitors;


•	economic factors, such as commodity price volatility that impact our fuels marketing segment; and


•	factors that impact the operations served by our pipeline and storage assets, such as utilization rates and maintenance turnaround schedules of our refining company customers and drilling activity by our crude oil production customers.

Current Market Conditions

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

Increases or decreases in the price of crude oil affect sectors across the energy industry, including our customers in crude oil production, refining and trading, in different ways at different points in any given price cycle. For example, U.S. crude oil producers reduced their capital spending relatively early in this sustained low price cycle, which reduced drilling activity and lowered production, particularly in shale play regions with higher relative drilling costs. As this cycle has continued, producers focused their trimmed-back spending on the most capital-efficient regions, such as, notably, the Permian Basin. Refiners, on the other hand, have benefitted from lower crude oil prices, to the extent they have been able to take advantage of lower feedstock prices, especially those positioned for healthy regional demand for their refined products; however, as refined product inventories increase, refiners are incentivized to reduce their production levels, which in turn may reduce their ability to benefit from low crude prices. Crude oil traders focus less on the current market commodity price than on whether that price is higher or lower than expected future market prices: if the future price for a product is believed to be higher than the current market price, or a “contango market,” traders are more likely to purchase and store products to sell in the future at the higher price. On the other hand, when the current price of crude oil nears or exceeds the expected future market price, or “backwardation,” as is currently the case, traders are no longer incentivized to purchase and store product for future sale.

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RESULTS OF OPERATIONS

Year Ended December 31, 2017 Compared to Year Ended December 31, 2016

Financial Highlights

(Thousands of Dollars, Except Unit and Per Unit Data)



	Year Ended December 31,
	2017			2016			Change
Statement of Income Data:
Revenues:
Service revenues	$	1,128,726		$	1,083,165		$	45,561
Product sales	685,293			673,517			11,776
Total revenues	1,814,019			1,756,682			57,337

Costs and expenses:
Cost of product sales	651,599			633,653			17,946
Operating expenses	449,670			448,367			1,303
General and administrative expenses	112,240			98,817			13,423
Depreciation and amortization expense	264,232			216,736			47,496
Total costs and expenses	1,477,741			1,397,573			80,168

Operating income	336,278			359,109			(22,831		)
Interest expense, net	(173,083		)	(138,350		)	(34,733		)
Other expense, net	(5,294		)	(58,783		)	53,489
Income before income tax expense	157,901			161,976			(4,075		)
Income tax expense	9,937			11,973			(2,036		)
Net income	$	147,964		$	150,003		$	(2,039	)
Basic and diluted net income per common unit	$	0.64		$	1.27		$	(0.63	)
Basic weighted-average common units outstanding	88,825,964			78,080,484			10,745,480

Annual Overview

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

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Segment Operating Highlights

(Thousands of Dollars, Except Barrel/Day Information)



	Year Ended December 31,
	2017			2016			Change
Pipeline:
Refined products pipelines throughput (barrels/day)	516,736			535,946			(19,210		)
Crude oil pipelines throughput (barrels/day)	583,323			392,181			191,142
Total throughput (barrels/day)	1,100,059			928,127			171,932
Throughput revenues	$	516,288		$	485,650		$	30,638
Operating expenses	156,432			147,858			8,574
Depreciation and amortization expense	128,061			89,554			38,507
Segment operating income	$	231,795		$	248,238		$	(16,443	)

Storage:
Throughput (barrels/day)	325,194			789,065			(463,871		)
Throughput terminal revenues	$	85,927		$	117,586		$	(31,659	)
Storage terminal revenues	531,026			492,456			38,570
Total revenues	616,953			610,042			6,911
Operating expenses	270,041			276,578			(6,537		)
Depreciation and amortization expense	127,473			118,663			8,810
Segment operating income	$	219,439		$	214,801		$	4,638

Fuels Marketing:
Product sales and other revenue	$	692,884		$	681,934		$	10,950
Cost of product sales	660,844			645,355			15,489
Gross margin	32,040			36,579			(4,539		)
Operating expenses	26,057			33,173			(7,116		)
Segment operating income	$	5,983		$	3,406		$	2,577

Consolidation and Intersegment Eliminations:
Revenues	$	(12,106	)	$	(20,944	)	$	8,838
Cost of product sales	(9,245		)	(11,702		)	2,457
Operating expenses	(2,860		)	(9,242		)	6,382
Total	$	(1	)	$	—		$	(1	)

Consolidated Information:
Revenues	$	1,814,019		$	1,756,682		$	57,337
Cost of product sales	651,599			633,653			17,946
Operating expenses	449,670			448,367			1,303
Depreciation and amortization expense	255,534			208,217			47,317
Segment operating income	457,216			466,445			(9,229		)
General and administrative expenses	112,240			98,817			13,423
Other depreciation and amortization expense	8,698			8,519			179
Consolidated operating income	$	336,278		$	359,109		$	(22,831	)

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Pipeline

Total revenues increased $30.6 million and total throughputs increased 171,932 barrels per day for the year ended December 31, 2017, compared to the year ended December 31, 2016, primarily due to:


•	an increase in revenues of $42.6 million and an increase in throughputs of 192,958 barrels per day from our Permian Crude System acquired in May 2017;


•	an increase in revenues of $5.5 million and an increase in throughputs of 2,929 barrels per day due to maintenance downtime in 2016 on a portion of the Ammonia Pipeline, as well as operational issues in 2016 at certain plants served by the pipeline; and

•

an increase in revenues of $3.4 million, despite a decrease in throughputs of 4,129 barrels per day, on our East Pipeline due to the completion of various storage projects along the pipeline, as well as an increase in long-haul deliveries resulting in higher average tariffs. A turnaround and operational issues at the refineries served by the East Pipeline in 2017 contributed to the decrease in throughputs.

These increases in revenues and throughputs were partially offset by:


•	a decrease in revenues of $10.4 million and a decrease in throughputs of 16,839 barrels per day due to a turnaround in the fourth quarter of 2017 at the refinery served by our McKee System pipelines;


•	a decrease in revenues of $6.8 million and a decrease in throughputs of 15,561 barrels per day on our Eagle Ford System, mainly due to reduced production in this sustained low crude oil price environment; and


•	a decrease in revenues of $4.8 million and a decrease in throughputs of 6,905 barrels per day due to a turnaround in the second quarter of 2017 at the refinery served by the North Pipeline.

Operating expenses increased $8.6 million for the year ended December 31, 2017, compared to the year ended December 31, 2016. Operating expenses increased $9.9 million as a result of our acquisition of the Permian Crude System, which was partially offset by a decrease of $2.1 million from product imbalances on the East Pipeline.

Depreciation and amortization expense increased $38.5 million for the year ended December 31, 2017, compared to the year ended December 31, 2016, due to our acquisition of the Permian Crude System and the completion of various pipeline projects.

Storage

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

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

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

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Operating expenses decreased $6.5 million for the year ended December 31, 2017, compared to the year ended December 31, 2016, primarily due to:


•	a decrease of $8.7 million in maintenance and regulatory expenses, primarily at our St. Eustatius, North East and Point Tupper terminals; and


•	a decrease of $6.1 million in reimbursable expenses, mainly at our Texas City, TX and Point Tupper terminals, consistent with the decrease in reimbursable revenues;

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

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

Fuels Marketing

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

Consolidation and Intersegment Eliminations

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

General

General and administrative expenses increased $13.4 million for the year ended December 31, 2017, compared to the year ended December 31, 2016, primarily due to transaction costs related to the Navigator Acquisition.

Interest expense, net increased $34.7 million for the year ended December 31, 2017, compared to the year ended December 31, 2016, mainly due to the issuance of $550.0 million of 5.625% senior notes in April 2017 and as a result of fees for a bridge loan commitment to potentially assist with the financing of the Navigator Acquisition. We did not enter into or borrow under the bridge loan. Interest expense, net also increased as a result of lower interest income due to the termination of the Axeon Term Loan in February 2017. Please refer to Note 7 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for a discussion of the Axeon Term Loan and related credit support.

For the year ended December 31, 2017, we recorded other expense, net of $5.3 million, mainly due to property damage of $5.0 million at our St. Eustatius terminal resulting from hurricane activity in the third quarter of 2017. For the year ended December 31, 2016, we recorded other expense, net of $58.8 million, mainly due to an impairment charge of $58.7 million recognized on the Axeon Term Loan.

Income tax expense decreased $2.0 million for the year ended December 31, 2017, compared to the year ended December 31, 2016, primarily due to reductions in withholding taxes related to certain of our foreign subsidiaries. This decrease was partially offset by increased tax expense resulting from the enactment of the Tax Cuts and Jobs Act in December 2017 (the Act), pursuant to which we recorded a one-time mandatory tax on previously deferred earnings of certain foreign subsidiaries. Please refer to Note 24 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for a discussion on income taxes, including the impact of the Act.

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Year Ended December 31, 2016 Compared to Year Ended December 31, 2015

Financial Highlights

(Thousands of Dollars, Except Unit and Per Unit Data)



	Year Ended December 31,
	2016			2015			Change
Statement of Income Data:
Revenues:
Service revenues	$	1,083,165		$	1,114,153		$	(30,988	)
Product sales	673,517			969,887			(296,370		)
Total revenues	1,756,682			2,084,040			(327,358		)

Costs and expenses:
Cost of product sales	633,653			907,574			(273,921		)
Operating expenses	448,367			473,031			(24,664		)
General and administrative expenses	98,817			102,521			(3,704		)
Depreciation and amortization expense	216,736			210,210			6,526
Total costs and expenses	1,397,573			1,693,336			(295,763		)

Operating income	359,109			390,704			(31,595		)
Interest expense, net	(138,350		)	(131,868		)	(6,482		)
Other (expense) income, net	(58,783		)	61,822			(120,605		)
Income from continuing operations before income tax expense	161,976			320,658			(158,682		)
Income tax expense	11,973			14,712			(2,739		)
Income from continuing operations	150,003			305,946			(155,943		)
Income from discontinued operations, net of tax	—			774			(774		)
Net income	$	150,003		$	306,720		$	(156,717	)
Basic and diluted net income per common unit:
Continuing operations	$	1.27		$	3.29		$	(2.02	)
Discontinued operations	—			0.01			(0.01		)
Total	$	1.27		$	3.30		$	(2.03	)
Basic weighted-average common units outstanding	78,080,484			77,886,078			194,406

Annual Overview

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

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Segment Operating Highlights

(Thousands of Dollars, Except Barrel/Day Information)



	Year Ended December 31,
	2016			2015			Change
Pipeline:
Refined products pipelines throughput (barrels/day)	535,946			522,146			13,800
Crude oil pipelines throughput (barrels/day)	392,181			471,632			(79,451		)
Total throughput (barrels/day)	928,127			993,778			(65,651		)
Throughput revenues	$	485,650		$	508,522		$	(22,872	)
Operating expenses	147,858			153,222			(5,364		)
Depreciation and amortization expense	89,554			84,951			4,603
Segment operating income	$	248,238		$	270,349		$	(22,111	)

Storage:
Throughput (barrels/day)	789,065			899,606			(110,541		)
Throughput terminal revenues	$	117,586		$	130,127		$	(12,541	)
Storage terminal revenues	492,456			494,781			(2,325		)
Total revenues	610,042			624,908			(14,866		)
Operating expenses	276,578			290,322			(13,744		)
Depreciation and amortization expense	118,663			116,768			1,895
Segment operating income	$	214,801		$	217,818		$	(3,017	)

Fuels Marketing:
Product sales and other revenue	$	681,934		$	976,216		$	(294,282	)
Cost of product sales	645,355			922,906			(277,551		)
Gross margin	36,579			53,310			(16,731		)
Operating expenses	33,173			39,803			(6,630		)
Segment operating income	$	3,406		$	13,507		$	(10,101	)

Consolidation and Intersegment Eliminations:
Revenues	$	(20,944	)	$	(25,606	)	$	4,662
Cost of product sales	(11,702		)	(15,332		)	3,630
Operating expenses	(9,242		)	(10,316		)	1,074
Total	$	—		$	42		$	(42	)

Consolidated Information:
Revenues	$	1,756,682		$	2,084,040		$	(327,358	)
Cost of product sales	633,653			907,574			(273,921		)
Operating expenses	448,367			473,031			(24,664		)
Depreciation and amortization expense	208,217			201,719			6,498
Segment operating income	466,445			501,716			(35,271		)
General and administrative expenses	98,817			102,521			(3,704		)
Other depreciation and amortization expense	8,519			8,491			28
Consolidated operating income	$	359,109		$	390,704		$	(31,595	)

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Pipeline

Total revenues decreased $22.9 million and total throughputs decreased 65,651 barrels per day for the year ended December 31, 2016, compared to the year ended December 31, 2015, primarily due to:


•	a decrease in revenues of $36.3 million and a decrease in throughputs of 81,779 barrels per day on our Eagle Ford System due to reduced production resulting from a sustained low crude oil price environment;


•	a decrease in revenues of $7.1 million and a decrease in throughputs of 6,586 barrels per day on our Ammonia Pipeline partly due to a shipper’s facility reconfiguration, resulting in fewer barrels available for transportation, and maintenance downtime on a portion of the pipeline; and


•	a decrease in revenues of $3.9 million and a decrease in throughputs of 1,551 barrels per day on our Ardmore System due to operational issues and a turnaround at our customer’s Ardmore refinery in 2016, as well as increased short-haul deliveries resulting in lower average tariffs.

Those decreases in pipeline revenues and throughputs were partially offset by:


•	an increase in revenues of $12.1 million and an increase in throughputs of 14,803 barrels per day on our McKee and Three Rivers System pipelines due to higher demand in those markets, increased production at our customer’s McKee refinery and increased volumes on pipelines with higher average tariffs;


•	an increase in revenues of $9.6 million and an increase in throughputs of 11,441 barrels per day on our East Pipeline, mainly due to the completion of various expansion projects beginning in the fourth quarter of 2015, unfavorable pricing differentials in 2015 in markets served by the East Pipeline and lower throughputs in 2015 due to maintenance downtime on a portion of the pipeline; and


•	an increase in revenues of $3.4 million and an increase in throughputs of 1,392 barrels per day on our North Pipeline due to increased refinery production shipped via pipeline and increased long-haul deliveries resulting in higher average tariffs.

Operating expenses decreased $5.4 million for the year ended December 31, 2016, compared to the year ended December 31, 2015, primarily due to lower operating expenses of $8.7 million on our Eagle Ford System, consistent with the decrease in throughputs. The decrease in pipeline operating expenses was partially offset by higher maintenance and regulatory expenses of $3.2 million, mainly on our Central West Refined Products Pipelines.

Depreciation and amortization expense increased $4.6 million for the year ended December 31, 2016, compared to the year ended December 31, 2015, mainly due to the completion of pipeline projects.

Storage

Throughput terminal revenues decreased $12.5 million and throughputs decreased 110,541 barrels per day for the year ended December 31, 2016, compared to the year ended December 31, 2015, primarily due to:

•

a decrease in revenues of $10.9 million and a decrease in throughputs of 82,177 barrels per day at our Corpus Christi North Beach terminal due to (i) a decrease in Eagle Ford Shale crude oil being shipped to Corpus Christi, consistent with the decrease in pipeline throughputs and (ii) the completion of a pipeline expansion project in the first quarter of 2016, in which we transport volumes from North Beach to our customer’s refineries, thus reducing volumes moved over our docks; and


•	a decrease in revenues of $3.3 million and a decrease in throughputs of 35,497 barrels per day due to turnarounds at the refineries served by our Benicia and Corpus Christi crude oil storage tank facilities, as well as operational issues at a customer’s Corpus Christi refinery in 2016.

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

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

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Operating expenses decreased $13.7 million for the year ended December 31, 2016, compared to the year ended December 31, 2015, primarily due to:


•	a decrease of $11.8 million in operating expenses at our International Terminals, mainly at our St. Eustatius terminal facility due to higher property taxes in 2015, and lower employee related costs and reimbursable expenses in 2016;


•	a decrease of $3.1 million resulting from an insurance settlement for environmental remediation expenses incurred on a previously sold terminal; and


•	a decrease of $2.0 million resulting from lower wharfage and dockage costs at our Corpus Christi North Beach terminal.

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

Fuels Marketing

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

Consolidation and Intersegment Eliminations

General

General and administrative expenses decreased $3.7 million for the year ended December 31, 2016, compared to the year ended December 31, 2015, primarily due to a decrease in employee benefit costs which was partially offset by increased compensation expense associated with our long-term incentive plan.

Interest expense, net increased $6.5 million for the year ended December 31, 2016, compared to the year ended December 31, 2015, primarily due to increased interest costs associated with higher borrowings under our revolving credit agreement, as well as lower capitalized interest resulting from fewer capital projects.

For the year ended December 31, 2016, we recorded other expense, net of $58.8 million, mainly due to an impairment charge of $58.7 million recognized on the Axeon Term Loan. For the year ended December 31, 2015, we recorded other income, net of $61.8 million, mainly due to the $56.3 million gain associated with the Linden Acquisition.

Income tax expense decreased $2.7 million for the year ended December 31, 2016, compared to the year ended December 31, 2015, primarily due to lower margin tax in Texas, a decrease in the UK tax rate and a reduction in our St. Eustatius and Canada withholding tax. Please refer to Note 24 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for a discussion on income taxes.

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TRENDS AND OUTLOOK

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

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

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

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

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

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

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

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

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

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

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

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LIQUIDITY AND CAPITAL RESOURCES

Overview

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

Our partnership agreement requires that we distribute all “Available Cash” to our common limited partners and general partner each quarter, and this term is defined in the partnership agreement generally as cash on hand at the end of the quarter, plus certain permitted borrowings made subsequent to the end of the quarter, less cash reserves determined by our board of directors. After the Merger, our general partner will no longer receive incentive distributions or quarterly cash distributions, related to its ownership interest, from us. Additionally, on February 8, 2018, we announced that our management anticipates recommending to the board of directors of NuStar GP, LLC, and the board of directors expects to adopt, a reset of our quarterly distribution per common unit to $0.60 ($2.40 on an annualized basis), starting with the first-quarter distribution payable in May 2018. Please refer to Note 28 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for further discussion of the Merger.

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

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

For the year ended December 31, 2017, our cash flow from operations did not exceed our distributions to our partners and our reliability capital expenditures. See below for discussion. For 2018, we expect to generate sufficient cash from operations to exceed our distribution and reliability capital requirements. Although we expect higher interest costs due to our issuances of debt and equity securities in 2017, we expect a decrease in distributions as a result of the distribution reset and the Merger discussed above. See below for additional discussion of our 2017 equity and debt issuances.

Cash Flows for the Years Ended December 31, 2017, 2016 and 2015

The following table summarizes our cash flows from operating, investing and financing activities (please refer to our Consolidated Statements of Cash Flows in Item 8. “Financial Statements and Supplementary Data”):



	Year Ended December 31,
	2017			2016			2015
	(Thousands of Dollars)
Net cash provided by (used in):
Operating activities	$	406,799		$	436,761		$	524,937
Investing activities	(1,696,441		)	(311,078		)	(452,029		)
Financing activities	1,276,272			(211,324		)	(29,229		)
Effect of foreign exchange rate changes on cash	1,720			2,721			(12,729		)
Net (decrease) increase in cash and cash equivalents	$	(11,650	)	$	(82,920	)	$	30,950

Net cash provided by operating activities for the year ended December 31, 2017 was $406.8 million, compared to $436.8 million for the year ended December 31, 2016, primarily due to changes in working capital. Our working capital increased by $26.5 million for the year ended December 31, 2017, compared to a decrease of $3.7 million for the year ended December 31, 2016. Please refer to the “Working Capital Requirements” section below for a discussion of the changes in working capital.

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

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equity issuances of approximately $1.5 billion were used to fund the purchase price of the Navigator Acquisition. The proceeds from debt borrowings, net of repayments, remaining proceeds from our equity issuances and cash on hand were used to fund our other strategic capital expenditures.

For the year ended December 31, 2016, net cash provided by operating activities primarily was used to fund our distributions to

unitholders and our general partner in the aggregate amount of $393.0 million and reliability capital expenditures of $38.2

million. Proceeds from the issuance of common and preferred units and cash on hand were used to fund our strategic capital expenditures, including the Martin Terminal Acquisition.

For the year ended December 31, 2015, the majority of net cash provided by operating activities was used to fund our distributions to unitholders and our general partner in the aggregate amount of $392.2 million and to fund $40.0 million of reliability capital expenditures. The proceeds from debt borrowings, net of repayments, combined with a portion of net cash provided by operating activities, were used to fund our strategic capital expenditures, including the Linden Acquisition.

Debt Sources of Liquidity

Revolving Credit Agreement. On August 22, 2017, NuStar Logistics amended its revolving credit agreement (the Revolving Credit Agreement), mainly to extend the maturity date from October 29, 2019 to October 29, 2020, and to increase the borrowing capacity from $1.50 billion to $1.75 billion. The Revolving Credit Agreement includes the ability to borrow up to the equivalent of $250.0 million in Euros and up to the equivalent of $250.0 million in British Pounds Sterling. Obligations under the Revolving Credit Agreement are guaranteed by NuStar Energy and NuPOP.

The Revolving Credit Agreement was also amended to increase the maximum allowed consolidated debt coverage ratio (as defined in the Revolving Credit Agreement) from 5.00-to-1.00 to 5.50-to-1.00 through the rolling period ending March 31, 2018. Subsequently, the maximum allowed consolidated debt coverage ratio may not exceed 5.00-to-1.00 for any rolling period ending on or after June 30, 2018. 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. On November 22, 2017, the Revolving Credit Agreement was amended to continue to exclude our $402.5 million fixed-to-floating rate subordinated notes from the definition of consolidated debt for purposes of calculating our consolidated debt coverage ratio through December 31, 2018. The Revolving Credit Agreement also contains customary restrictive covenants, such as limitations on indebtedness, liens, mergers, asset transfers and certain investing activities.

The requirement not to exceed a maximum consolidated debt coverage ratio may limit the amount we can borrow under the Revolving Credit Agreement to an amount less than the total amount available for borrowing. As of December 31, 2017, our consolidated debt coverage ratio was 4.9x and we had $853.0 million available for borrowing.

Letters of credit issued under the Revolving Credit Agreement totaled $3.7 million as of December 31, 2017. Letters of credit are limited to $400.0 million (including up to the equivalent of $25.0 million in Euros and up to the equivalent of $25.0 million in British Pounds Sterling) and also may restrict the amount we can borrow under the Revolving Credit Agreement.

Receivables Financing Agreement. NuStar Energy and NuStar Finance LLC (NuStar Finance), a special purpose entity and wholly owned subsidiary of NuStar Energy, are parties to a $125.0 million receivables financing agreement with third-party lenders (the Receivables Financing Agreement) and agreements with certain of NuStar Energy’s wholly owned subsidiaries (collectively with the Receivables Financing Agreement, the Securitization Program). On September 20, 2017, the Securitization Program was amended to add certain of NuStar Energy’s wholly owned subsidiaries resulting from the Navigator Acquisition and to extend the Securitization Program’s scheduled termination date from June 15, 2018 to September 20, 2020, with the option to renew for additional 364-day periods thereafter. The amount available for borrowing under the Receivables Financing Agreement is based on the availability of eligible receivables and other customary factors and conditions. The Securitization Program contains various customary affirmative and negative covenants and default, indemnification and termination provisions, and the Receivables Financing Agreement provides for acceleration of amounts owed upon the occurrence of certain specified events.

Issuance of 5.625% Senior Notes. On April 28, 2017, NuStar Logistics issued $550.0 million of 5.625% senior notes due April 28, 2027. We used the net proceeds of $543.3 million from the offering to fund a portion of the purchase price for the Navigator Acquisition and to pay related fees and expenses. Interest on the 5.625% senior notes is payable semi-annually in arrears on April 28 and October 28 of each year beginning on October 28, 2017. The 5.625% senior notes do not have sinking fund requirements. These notes rank equally with existing senior unsecured indebtedness and senior to existing subordinated indebtedness of NuStar Logistics. The 5.625% senior notes contain restrictions on NuStar Logistics’ ability to incur secured indebtedness unless the same security is also provided for the benefit of holders of the senior notes. In addition, the senior notes

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limit NuStar Logistics’ ability to incur indebtedness secured by certain liens, engage in certain sale-leaseback transactions and engage in certain consolidations, mergers or asset sales.

Other Debt Sources of Liquidity. Other sources of liquidity consist of the following:


•	$365.4 million in revenue bonds pursuant to the Gulf Opportunity Zone Act of 2005 (the GoZone Bonds), with $42.5 million remaining in trust as of December 31, 2017, supported by $370.2 million in letters of credit; and


•	two short-term line of credit agreements with an aggregate uncommitted borrowing capacity of up to $85.0 million, with $35.0 million of borrowings outstanding as of December 31, 2017.

Please refer to Note 12 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, 2017, 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 years ended December 31, 2017 and 2016, we repatriated $9.5 million and $110.8 million, respectively, 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

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.

On April 28, 2017, we issued 15,400,000 of our 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.

On April 18, 2017, we issued 14,375,000 common units representing limited partner interests 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 its 2% general partner interest, 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 will not receive incentive distributions with respect to these common units. Our general partner amended and restated our partnership agreement to waive up to an aggregate $22.0 million of the quarterly incentive distributions to our general partner for any NS common units issued from the date of the Navigator Acquisition agreement (other than those attributable to NS common units issued under any equity compensation plan) for ten consecutive quarters.

In the fourth quarter of 2016, we issued 9,060,000 of our 8.50% Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units (Series A Preferred Units) representing limited partner interests at a price of $25.00 per unit. We used the net proceeds of $218.4 million from this issuance for general partnership purposes, including the funding of capital expenditures and repayments of outstanding borrowings under the Revolving Credit Agreement.

During the year ended December 31, 2016, we issued 595,050 common units representing limited partner interests at an average price of $47.39 per unit for proceeds of $28.3 million, net of $0.5 million of issuance costs. We used these proceeds, which include a contribution of $0.6 million from our general partner to maintain its 2% general partner interest, for general partnership purposes, including repayments of outstanding borrowings under the Revolving Credit Agreement.

Please refer to Note 19 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 existing 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, and the amount we expect to spend for 2018:



	Strategic
	Acquisitions and Investments in Other Long-Term Assets		Capital Expenditures (a)		Reliability Capital Expenditures (b)		Total
	(Thousands of Dollars)
For the year ended December 31:
2017	$	1,461,719	$	327,141	$	57,497	$	1,846,357
2016	$	95,657	$	166,203	$	38,155	$	300,015
2015	$	146,064	$	284,806	$	40,002	$	470,872

Expected for the year ended December 31, 2018			$ 360,000 - 390,000		$ 80,000 - 100,000		$ 440,000 - 490,000


(a)	Strategic capital for 2015, 2016 and 2017 mainly consists of terminal expansions. In addition, strategic capital in 2015 includes the reactivation and conversion of our 200-mile pipeline between Mont Belvieu and Corpus Christi, Texas and strategic capital in 2017 includes pipeline expansions on our Permian Crude System.


(b)	Reliability capital expenditures primarily relate to maintenance upgrade projects at our terminals.

For the year ended December 31, 2018, we expect a significant portion of our strategic capital spending to relate to our Permian Crude System and a significant portion of reliability capital spending to relate to hurricane damage repairs at our St. Eustatius facility. We continue to evaluate our capital budget and make changes as economic conditions warrant, and our actual capital expenditures for 2018 may increase or decrease from the budgeted amounts. We believe cash on hand, combined with the sources of liquidity previously described, will be sufficient to fund our capital expenditures in 2018, and our internal growth projects can be accelerated or scaled back depending on market conditions or customer demand.

Working Capital Requirements

Working capital requirements, particularly in our fuels marketing segment, may vary with the seasonality of demand and the volatility of commodity prices for the products we market. This seasonality in demand and the volatility of commodity prices affect our accounts receivable and accounts payable balances, which vary depending on timing of payments.

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.

During the year ended December 31, 2016, accounts receivable increased $23.2 million and accounts payable increased $14.1 million, primarily due to the timing of payments related to our bunker fuel operations and crude oil trading activity.

During the year ended December 31, 2015, inventories decreased $16.8 million, mainly due to the continued decline in crude oil prices. In addition, inventory volumes decreased in 2015 primarily due to decreased bunker fuel operations activity. During the year ended December 31, 2015, accounts receivable decreased $67.3 million and accounts payable decreased $32.2 million, primarily due to decreased bunker fuel operations and crude oil trading activity.

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. In 2016, we recognized an impairment charge on the Axeon Term Loan of $58.7 million which is included in “Other (expense) income, net” in the consolidated statements of income. Please refer to Notes 7 and 15 of the Notes to Consolidated

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Financial Statements in Item 8. “Financial Statements and Supplementary Data” for additional information on the Axeon Term Loan and related credit support.

Defined Benefit Plans Funding

During 2017, we contributed $11.2 million to our pension and postretirement benefit plans. We expect to contribute approximately $11.6 million to our pension and postretirement benefit plans in 2018, 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 2018 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. NuStar Energy’s partnership agreement determines the amount and priority of cash distributions that our unitholders and general partner may receive. The general partner receives a 2% distribution with respect to its general partner interest. The general partner is also entitled to incentive distributions if the amount we distribute with respect to any quarter exceeds $0.60 per unit. For a detailed discussion of the incentive distribution targets, please read Item 5. “Market for Registrant’s Common Units, Related Unitholder Matters and Issuer Purchases of Equity Securities.”

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:



	Year Ended December 31,
	2017		2016		2015
	(Thousands of Dollars, Except Per Unit Data)
General partner interest	$	9,252	$	7,877	$	7,844
General partner incentive distribution	45,669		43,407		43,220
Total general partner distribution	54,921		51,284		51,064
Common limited partners’ distribution	407,681		342,598		341,140
Total cash distributions	$	462,602	$	393,882	$	392,204

Cash distributions per unit applicable to common limited partners	$	4.38	$	4.38	$	4.38

Distribution payments to our general partner and common limited partners are made 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 related to our quarterly cash distributions to our general partner and common limited partners:



Quarter Ended	Cash Distributions Per Unit		Total Cash Distributions		Record Date	Payment Date
			(Thousands of Dollars)
December 31, 2017 (a)	$	1.095	$	115,267	February 8, 2018	February 13, 2018
September 30, 2017	$	1.095	$	115,084	November 9, 2017	November 14, 2017
June 30, 2017	$	1.095	$	115,083	August 7, 2017	August 11, 2017
March 31, 2017	$	1.095	$	117,168	May 8, 2017	May 12, 2017


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

Pursuant to the Merger Agreement and at the effective time of the Merger, our partnership agreement will be amended and restated to, among other things, cancel the incentive distribution rights held by our general partner and convert the 2% general partner interest in NuStar Energy held by our general partner into a non-economic management interest. As a result, after the Merger, our general partner will no longer receive incentive distributions or quarterly cash distributions related to its ownership interest from us. Please refer to Note 28 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for further discussion of the Merger.

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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 (collectively, the Preferred Units):



Units	Fixed Distribution Rate per Annum (as a Percentage of the $25.00 Liquidation Preference per Unit)	Fixed Distribution Rate per Unit per Annum		Optional Redemption Date/Date at Which Distribution Rate Becomes Floating	Floating Annual Rate (as a Percentage of the $25.00 Liquidation Preference per Unit)
Series A Preferred Units	8.50%	$	2.125	December 15, 2021	Three-month LIBOR plus 6.766%
Series B Preferred Units	7.625%	$	1.90625	June 15, 2022	Three-month LIBOR plus 5.643%
Series C Preferred Units	9.00%	$	2.25	December 15, 2022	Three-month LIBOR plus 6.88%

The following table summarizes information related to our quarterly cash distributions on our Preferred Units:



Period	Cash Distributions Per Unit		Total Cash Distributions		Record Date	Payment Date
			(Thousands of Dollars)
Series A Preferred Units:
December 15, 2017 - March 14, 2018 (a)	$	0.53125	$	4,813	March 1, 2018	March 15, 2018
September 15, 2017 - December 14, 2017	$	0.53125	$	4,813	December 1, 2017	December 15, 2017
June 15, 2017 - September 14, 2017	$	0.53125	$	4,813	September 1, 2017	September 15, 2017
March 15, 2017 - June 14, 2017	$	0.53125	$	4,813	June 1, 2017	June 15, 2017
November 25, 2016 - March 14, 2017	$	0.64930556	$	5,883	March 1, 2017	March 15, 2017

Series B Preferred Units:
December 15, 2017 - March 14, 2018 (a)	$	0.47657	$	7,339	March 1, 2018	March 15, 2018
September 15, 2017 - December 14, 2017	$	0.47657	$	7,339	December 1, 2017	December 15, 2017
April 28, 2017 - September 14, 2017	$	0.725434028	$	11,172	September 1, 2017	September 15, 2017

Series C Preferred Units:
November 30, 2017 - March 14, 2018 (a)	$	0.65625	$	4,528	March 1, 2018	March 15, 2018


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

Debt Obligations

As of December 31, 2017, we were a party to the following debt agreements:


•	Revolving Credit Agreement due October 29, 2020, with $893.3 million of borrowings outstanding as of December 31, 2017;

•

7.65% senior notes due April 15, 2018 with a face value of $350.0 million; 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; 5.625% senior notes due April 28, 2027 with a face value of $550.0 million; and 7.625% fixed-to-floating subordinated notes due January 15, 2043 with a face value of $402.5 million;


•	$365.4 million in GoZone Bonds due from 2038 to 2041;


•	Line of credit agreements with $35.0 million of borrowings outstanding as of December 31, 2017; and


•	Receivables Financing Agreement due September 20, 2020, with $62.3 million of borrowings outstanding as of December 31, 2017.

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Management believes that, as of December 31, 2017, 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 12 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for a discussion of our debt agreements.

Credit Ratings

The following table reflects the current outlook and ratings that have been assigned to our debt as of December 31, 2017:



	Standard & Poor’s Ratings Services	Moody’s Investor Service Inc.	Fitch, Inc.

Ratings	BB	Ba1	BB
Outlook	Negative	Negative	Stable

The interest rates payable on the $350.0 million of 7.65% senior notes due 2018 (the 7.65% Senior Notes) and the Revolving Credit Agreement are subject to adjustment if our debt rating is downgraded (or upgraded) by certain credit rating agencies. In November 2017, Standard & Poor’s Rating Services lowered our credit rating from BB+ to BB, and the outlook was changed from stable to negative. The rating downgrade caused the interest rate on the 7.65% Senior Notes to increase from 8.15% to 8.4% and had no impact on the interest rate payable on our Revolving Credit Agreement. In February 2018, Moody’s Investor Service Inc. (Moody’s) lowered our credit rating from Ba1 to Ba2, which caused the interest rate on the 7.65% Senior Notes to also increase by 0.25%, resulting in an interest rate of 8.65% applicable to the interest payment due April 15, 2018. This Moody’s downgrade also caused the interest rate on our Revolving Credit Agreement to increase by 0.25%.

Interest Rate Swaps

As of December 31, 2017 and 2016, we were a party to forward-starting interest rate swap agreements for the purpose of hedging interest rate risk. As of December 31, 2017 and 2016, the aggregate notional amount of these forward-starting interest rate swaps was $600.0 million. Please refer to Notes 2 and 16 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.

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, 2017:



	Payments Due by Period
	2018		2019		2020		2021		2022		Thereafter		Total
	(Thousands of Dollars)
Long-term debt maturities	$	350,000	$	—	$	1,405,611	$	300,000	$	250,000	$	1,317,940	$	3,623,551
Interest payments (a)	174,937		169,162		165,124		102,586		86,715		1,150,198		1,848,722
Operating leases (b)	39,236		34,203		19,541		13,324		7,295		68,386		181,985
Purchase obligations (c)	6,963		6,133		4,686		4,690		4,480		300		27,252
Total	$	571,136	$	209,498	$	1,594,962	$	420,600	$	348,490	$	2,536,824	$	5,681,510


(a)	The interest payments calculated for our variable-rate debt are based on forward LIBOR interest rates and the outstanding borrowings as of December 31, 2017. The interest payments on our fixed-rate debt are based on the stated interest rates and the outstanding borrowings as of December 31, 2017.


(b)	Our operating leases consist primarily of leases for tugs and barges utilized at our St. Eustatius facility and land leases at various terminal facilities.


(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 22 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data.”

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Environmental, Health and Safety

The balance of and changes in our accruals for environmental matters as of and for the years ended December 31, 2017 and 2016 are included in Note 13 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, the outcomes of which could have an adverse effect on our cash flows and results of operations, as further disclosed in Note 14 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data.”

RELATED PARTY TRANSACTIONS

Please refer to Note 17 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for a discussion of our related party transactions.

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.

Depreciation

We calculate depreciation expense using the straight-line method over the estimated useful lives of our property, plant and equipment. Due to the expected long useful lives of our property, plant and equipment, we depreciate our property, plant and equipment over periods ranging from 5 years to 40 years. Changes in the estimated useful lives of our property, plant and equipment could have a material adverse effect on our results of operations.

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.

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. However, we chose to perform a quantitative goodwill impairment test for all reporting units as of October 1, 2017.

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

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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 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 determined that no impairment charges resulted from our October 1, 2017 impairment assessment. Furthermore, our assessment did not reflect any reporting units at risk of failing step one of the goodwill impairment test, which compares the fair value of the reporting unit to its carrying value including goodwill.

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., Standard & Poor’s Ratings Services and Fitch, Inc. The resulting discount rates were 3.72% and 3.82% for our pension and other postretirement benefit plans, respectively, as of December 31, 2017. 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. The effect of a 0.25% change in the specified assumptions would have the following effects (thousands of dollars):



	Pension Benefits		Other Postretirement Benefits
Increase in benefit obligation as of December 31, 2017 from:
Discount rate decrease	$	5,200	$	500
Compensation rate increase	$	1,500	n/a
Increase in net periodic benefit cost for the year ending December 31, 2018 resulting from:
Discount rate decrease	$	400	$	100
Expected long-term rate of returns on plan assets decrease	$	300	n/a
Compensation rate increase	$	400	n/a

Please refer to Note 22 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

Interest Rate 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.

Please refer to Note 2 and Note 16 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:



	December 31, 2017
	Expected Maturity Dates
	2018			2019		2020			2021			2022			There- after			Total			Fair Value
	(Thousands of Dollars, Except Interest Rates)
Long-term Debt:
Fixed-rate	$	350,000		$	—	$	450,000		$	300,000		$	250,000		$	952,500		$	2,302,500		$	2,355,535
Weighted-average interest rate	8.4		%	—		4.8		%	6.8		%	4.8		%	6.5		%	6.3		%
Variable-rate	$	—		$	—	$	955,611		$	—		$	—		$	365,440		$	1,321,051		$	1,322,087
Weighted-average interest rate	—			—		3.1		%	—			—			1.7		%	2.7		%



	December 31, 2016
	Expected Maturity Dates
	2017		2018			2019			2020			2021			There- after			Total			Fair Value
	(Thousands of Dollars, Except Interest Rates)
Long-term Debt:
Fixed-rate	$	—	$	350,000		$	—		$	450,000		$	300,000		$	652,500		$	1,752,500		$	1,821,261
Weighted-average interest rate	—		8.2		%	—			4.8		%	6.8		%	6.5		%	6.4		%
Variable-rate	$	—	$	58,400		$	838,992		$	—		$	—		$	365,440		$	1,262,832		$	1,263,501
Weighted-average interest rate	—		1.6		%	2.5		%	—			—			0.7		%	1.9		%

The following table presents information regarding our forward-starting interest rate swap agreements:



Notional Amount as of December 31,				Period of Hedge	Weighted-Average Fixed Rate		Fair Value as of December 31,
2017		2016		Period of Hedge	Weighted-Average Fixed Rate		2017			2016
(Thousands of Dollars)							(Thousands of Dollars)
$	350,000	$	350,000	04/2018 - 04/2028	2.6	%	$	(5,394	)	$	(1,333	)
250,000		250,000		09/2020 - 09/2030	2.8	%	(4,594		)	15
$	600,000	$	600,000		2.7	%	$	(9,988	)	$	(1,318	)

Commodity Price Risk

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. The derivative instruments we use consist primarily of commodity futures and swap contracts. Please refer to our derivative financial instruments accounting policy in Note 2 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for further information on our various types of derivatives.

We have a risk management committee that oversees our trading policies and procedures and certain aspects of risk management. Our risk management committee also reviews all new risk management strategies in accordance with our risk management policy, as approved by our board of directors.

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The commodity contracts disclosed below represent only those contracts exposed to commodity price risk at the end of the period. Please refer to Note 16 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for the volume and related fair value of all commodity contracts.



	December 31, 2017
	Contract Volumes	Weighted Average				Fair Value of Current Asset (Liability)
	Contract Volumes	Pay Price		Receive Price		Fair Value of Current Asset (Liability)
	(Thousands of Barrels)					(Thousands of Dollars)
Fair Value Hedges:
Futures – long:
(refined products)	2	$	86.88	N/A		$	—
Futures – short:
(refined products)	5	N/A		$	85.59	$	(6	)
Swaps – short:
(refined products)	149	N/A		$	55.79	$	(106	)

Economic Hedges and Other Derivatives:
Futures – long:
(refined products)	10	$	86.13	N/A		$	7
Futures – short:
(refined products)	14	N/A		$	85.76	$	(16	)
Swaps – long:
(refined products)	196	$	55.05	N/A		$	264
Swaps – short:
(refined products)	199	N/A		$	53.76	$	(525	)

Total fair value of open positions exposed to commodity price risk						$	(382	)

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	December 31, 2016
	Contract Volumes	Weighted Average				Fair Value of Current Asset (Liability)
	Contract Volumes	Pay Price		Receive Price		Fair Value of Current Asset (Liability)
	(Thousands of Barrels)					(Thousands of Dollars)
Fair Value Hedges:
Futures – long:
(crude oil and refined products)	47	$	55.53	N/A		$	2
Futures – short:
(crude oil and refined products)	107	N/A		$	58.79	$	(243	)
Swaps – long:
(refined products)	84	$	45.99	N/A		$	141
Swaps – short:
(refined products)	573	N/A		$	41.87	$	(3,322	)

Economic Hedges and Other Derivatives:
Futures – long:
(crude oil and refined products)	18	$	72.06	N/A		$	10
Futures – short:
(crude oil and refined products)	9	N/A		$	71.88	$	(7	)
Swaps – long:
(refined products)	869	$	42.20	N/A		$	4,737
Swaps – short:
(refined products)	874	N/A		$	41.40	$	(5,459	)
Forward purchase contracts:
(crude oil)	310	$	52.78	N/A		$	499
Forward sales contracts:
(crude oil)	310	N/A		$	52.76	$	(507	)

Total fair value of open positions exposed to commodity price risk						$	(4,149	)

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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, 2017. 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, 2017, 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.

Management’s evaluation of and conclusion regarding the effectiveness of our internal control over financial reporting excludes the internal control over Navigator Energy Services, LLC acquired on May 4, 2017 (as described in Note 4), which contributed approximately 2% of our total revenues for the year ended December 31, 2017 and accounted for approximately 23% of our total assets as of December 31, 2017. We plan to fully integrate these assets and operations into our internal control over financial reporting in 2018.

The effectiveness of internal control over financial reporting as of December 31, 2017 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 69.

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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. (a Delaware limited partnership) and subsidiaries (the “Partnership”) as of December 31, 2017 and 2016, the related consolidated statements of income, comprehensive income, partners’ equity, and cash flows for each of the years in the three‑year period ended December 31, 2017, 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, 2017 and 2016, and the results of its operations and its cash flows for each of the years in the three‑year period ended December 31, 2017, 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, 2017, 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 28, 2018 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.

We have served as the Partnership’s auditor since 2004.

/s/ KPMG LLP

San Antonio, Texas

February 28, 2018

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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. (a Delaware limited partnership) and subsidiaries’ (the “Partnership”) internal control over financial reporting as of December 31, 2017, 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, 2017, 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, 2017 and 2016, the related consolidated statements of income, comprehensive income, partners’ equity, and cash flows for each of the years in the three-year period ended December 31, 2017, and the related notes (collectively, the “consolidated financial statements”), and our report dated February 28, 2018 expressed an unqualified opinion on those consolidated financial statements.

The Partnership acquired Navigator Energy Services, LLC during 2017, and management excluded from its assessment of the effectiveness of the Partnership’s internal control over financial reporting as of December 31, 2017, Navigator Energy Services, LLC’s internal control over financial reporting whose financial statements reflect 23 percent of total assets and 2 percent of total revenues of the related consolidated financial statement amounts of NuStar Energy L.P. as of and for the year ended December 31, 2017. Our audit of internal control over financial reporting of the Partnership also excluded an evaluation of the internal control over financial reporting of Navigator Energy Services, LLC.

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.

/s/ KPMG LLP

San Antonio, Texas

February 28, 2018

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NUSTAR ENERGY L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Thousands of Dollars, Except Unit Data)



	December 31,
	2017			2016
Assets
Current assets:
Cash and cash equivalents	$	24,292		$	35,942
Accounts receivable, net of allowance for doubtful accounts of $9,948 and $7,756 as of December 31, 2017 and 2016, respectively	176,570			170,293
Receivable from related party	205			317
Inventories	26,857			37,945
Other current assets	22,508			132,686
Total current assets	250,432			377,183
Property, plant and equipment, at cost	6,243,481			5,435,278
Accumulated depreciation and amortization	(1,942,548		)	(1,712,995		)
Property, plant and equipment, net	4,300,933			3,722,283
Intangible assets, net	784,479			127,083
Goodwill	1,097,475			696,637
Deferred income tax asset	233			2,051
Other long-term assets, net	101,681			105,308
Total assets	$	6,535,233		$	5,030,545
Liabilities and Partners’ Equity
Current liabilities:
Accounts payable	$	145,932		$	118,686
Short-term debt	35,000			54,000
Current portion of long-term debt	349,990			—
Accrued interest payable	40,449			34,030
Accrued liabilities	61,578			60,485
Taxes other than income tax	14,385			15,685
Income tax payable	4,172			6,510
Total current liabilities	651,506			289,396
Long-term debt, less current portion	3,263,069			3,014,364
Deferred income tax liability	22,272			22,204
Other long-term liabilities	118,297			92,964
Commitments and contingencies (Note 14)
Partners’ equity (Note 19):
Preferred limited partners	756,603			218,400
Common limited partners (93,176,683 and 78,616,228 common units outstanding as of December 31, 2017 and 2016, respectively)	1,770,587			1,455,642
General partner	37,826			31,752
Accumulated other comprehensive loss	(84,927		)	(94,177		)
Total partners’ equity	2,480,089			1,611,617
Total liabilities and partners’ equity	$	6,535,233		$	5,030,545

See Notes to Consolidated Financial Statements.

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NUSTAR ENERGY L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

(Thousands of Dollars, Except Unit and Per Unit Data)



	Year Ended December 31,
	2017			2016			2015
Revenues:
Service revenues	$	1,128,726		$	1,083,165		$	1,114,153
Product sales	685,293			673,517			969,887
Total revenues	1,814,019			1,756,682			2,084,040
Costs and expenses:
Cost of product sales	651,599			633,653			907,574
Operating expenses (excluding depreciation and amortization expense):
Third parties	449,670			426,686			337,466
Related party	—			21,681			135,565
Total operating expenses	449,670			448,367			473,031
General and administrative expenses (excluding depreciation and amortization expense):
Third parties	112,240			88,324			35,752
Related party	—			10,493			66,769
Total general and administrative expenses	112,240			98,817			102,521
Depreciation and amortization expense	264,232			216,736			210,210
Total costs and expenses	1,477,741			1,397,573			1,693,336
Operating income	336,278			359,109			390,704
Interest expense, net	(173,083		)	(138,350		)	(131,868		)
Other (expense) income, net	(5,294		)	(58,783		)	61,822
Income from continuing operations before income tax expense	157,901			161,976			320,658
Income tax expense	9,937			11,973			14,712
Income from continuing operations	147,964			150,003			305,946
Income from discontinued operations, net of tax	—			—			774
Net income	$	147,964		$	150,003		$	306,720
Basic and diluted net income per common unit:
Continuing operations	$	0.64		$	1.27		$	3.29
Discontinued operations	—			—			0.01
Total (Note 20)	$	0.64		$	1.27		$	3.30
Basic weighted-average common units outstanding	88,825,964			78,080,484			77,886,078

Diluted weighted-average common units outstanding	88,825,964			78,113,002			77,886,078

See Notes to Consolidated Financial Statements.

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NUSTAR ENERGY L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Thousands of Dollars)



	Year Ended December 31,
	2017			2016			2015
Net income	$	147,964		$	150,003		$	306,720
Other comprehensive income (loss):
Foreign currency translation adjustment	17,466			(8,243		)	(31,987		)
Net loss on pension and other postretirement benefit adjustments, net of income tax benefit of $184, $60 and $0	(6,170		)	(2,850		)	—
Net (loss) gain on cash flow hedges	(2,046		)	5,710			11,105
Total other comprehensive income (loss)	9,250			(5,383		)	(20,882		)
Comprehensive income	$	157,214		$	144,620		$	285,838

See Notes to Consolidated Financial Statements.

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NUSTAR ENERGY L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Thousands of Dollars)



	Year Ended December 31,
	2017			2016			2015
Cash Flows from Operating Activities:
Net income	$	147,964		$	150,003		$	306,720
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization expense	264,232			216,736			210,210
Unit-based compensation expense	8,132			7,579			—
Amortization of debt related items	6,147			7,477			8,840
Loss (gain) from sale or disposition of assets	4,984			64			(1,617		)
Gain associated with the Linden Acquisition	—			—			(56,277		)
Impairment loss	—			58,655			—
Deferred income tax expense (benefit)	6			(469		)	2,058
Distributions of equity in earnings of joint ventures	—			—			2,500
Changes in current assets and current liabilities (Note 21)	(26,493		)	3,716			50,559
Other, net	1,827			(7,000		)	1,944
Net cash provided by operating activities	406,799			436,761			524,937
Cash Flows from Investing Activities:
Capital expenditures	(384,638		)	(204,358		)	(324,808		)
Change in accounts payable related to capital expenditures	36,903			(11,063		)	(3,156		)
Acquisitions	(1,461,719		)	(95,657		)	(142,500		)
Proceeds from Axeon term loan	110,000			—			—
Proceeds from insurance recoveries	977			—			4,867
Proceeds from sale or disposition of assets	2,036			—			17,132
Investment in other long-term assets	—			—			(3,564		)
Net cash used in investing activities	(1,696,441		)	(311,078		)	(452,029		)
Cash Flows from Financing Activities:
Proceeds from long-term debt borrowings	1,465,767			752,729			860,131
Proceeds from short-term debt borrowings	1,051,000			654,000			823,500
Proceeds from note offering, net of issuance costs	543,333			—			—
Long-term debt repayments	(1,417,539		)	(772,152		)	(500,410		)
Short-term debt repayments	(1,070,000		)	(684,000		)	(816,500		)
Proceeds from issuance of preferred units, net of issuance costs	538,560			218,400			—
Proceeds from issuance of common units, net of issuance costs	643,878			27,710			—
Contributions from general partner	13,737			680			—
Distributions to preferred unitholders	(38,833		)	—			—
Distributions to common unitholders and general partner	(446,306		)	(392,962		)	(392,204		)
Increase (decrease) in cash book overdrafts	1,736			(11,237		)	(2,954		)
Other, net	(9,061		)	(4,492		)	(792		)
Net cash provided by (used in) financing activities	1,276,272			(211,324		)	(29,229		)
Effect of foreign exchange rate changes on cash	1,720			2,721			(12,729		)
Net (decrease) increase in cash and cash equivalents	(11,650		)	(82,920		)	30,950
Cash and cash equivalents as of the beginning of the period	35,942			118,862			87,912
Cash and cash equivalents as of the end of the period	$	24,292		$	35,942		$	118,862

See Notes to Consolidated Financial Statements.

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NUSTAR ENERGY L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF PARTNERS’ EQUITY

Years Ended December 31, 2017, 2016 and 2015

(Thousands of Dollars, Except Unit Data)



	Limited Partners
	Preferred (Note 19)				Common				General Partner			Accumulated Other Comprehensive Loss (Note 19)			Total Partners’ Equity
	Units	Amount			Units	Amount			General Partner			Accumulated Other Comprehensive Loss (Note 19)			Total Partners’ Equity
Balance as of January 1, 2015	—	$	—		77,886,078	$	1,744,810		$	39,312		$	(67,912	)	$	1,716,210
Net income	—	—			—	258,230			48,490			—			306,720
Other comprehensive loss	—	—			—	—			—			(20,882		)	(20,882		)
Distributions to partners	—	—			—	(341,140		)	(51,064		)	—			(392,204		)
Balance as of December 31, 2015	—	—			77,886,078	1,661,900			36,738			(88,794		)	1,609,844
Net income	—	1,925			—	102,580			45,498			—			150,003
Other comprehensive loss	—	—			—	—			—			(5,383		)	(5,383		)
Distributions to partners	—	(1,925		)	—	(341,798		)	(51,164		)	—			(394,887		)
Issuance of common units, including contribution from general partner	—	—			595,050	27,710			575			—			28,285
Issuance of preferred units	9,060,000	218,400			—	—			—			—			218,400
Unit-based compensation	—	—			135,100	5,250			105			—			5,355
Balance as of December 31, 2016	9,060,000	218,400			78,616,228	1,455,642			31,752			(94,177		)	1,611,617
Net income	—	40,448			—	60,610			46,906			—			147,964
Other comprehensive income	—	—			—	—			—			9,250			9,250
Distributions to partners	—	(40,448		)	—	(391,737		)	(54,569		)	—			(486,754		)
Issuance of common units, including contribution from general partner	—	—			14,375,000	643,878			13,597			—			657,475
Issuance of preferred units	22,300,000	538,560			—	—			—			—			538,560
Unit-based compensation	—	—			185,455	2,516			140			—			2,656
Other	—	(357		)	—	(322		)	—			—			(679		)
Balance as of December 31, 2017	31,360,000	$	756,603		93,176,683	$	1,770,587		$	37,826		$	(84,927	)	$	2,480,089

See Notes to Consolidated Financial Statements.

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NUSTAR ENERGY L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2017, 2016 and 2015

1. ORGANIZATION AND OPERATIONS

Organization

Employee Transfer from NuStar GP, LLC. On March 1, 2016, NuStar GP, LLC, the general partner of our general partner and a wholly owned subsidiary of NuStar GP Holdings, transferred and assigned to NuStar Services Company LLC (NuStar Services Co), a wholly owned subsidiary of NuStar Energy, all of NuStar GP, LLC’s employees and related benefit plans, programs, contracts and policies (the Employee Transfer). As a result of the Employee Transfer, we pay employee costs directly and sponsor the long-term incentive plan and other employee benefit plans. Please refer to Note 17 for further discussion of the Employee Transfer and our related party agreements, Note 22 for a discussion of our employee benefit plans and Note 23 for a discussion of our long-term incentive plan.

Recent Developments

Merger. On February 7, 2018, NuStar Energy, Riverwalk Logistics, L.P., NuStar GP, LLC, Marshall Merger Sub LLC, a wholly owned subsidiary of NuStar Energy (Merger Sub), Riverwalk Holdings, LLC and NuStar GP Holdings, LLC (NuStar GP Holdings) entered into an Agreement and Plan of Merger (the Merger Agreement) pursuant to which Merger Sub will merge with and into NuStar GP Holdings with NuStar GP Holdings being the surviving entity (the Merger), such that NuStar Energy will be the sole member of NuStar GP Holdings following the Merger. Pursuant to the Merger Agreement and at the effective time of the Merger, our partnership agreement will be amended and restated to, among other things, (i) cancel the incentive distribution rights held by our general partner, (ii) convert the 2% general partner interest in NuStar Energy held by our general partner into a non-economic management interest and (iii) provide the holders of our common units with voting rights in the election of the members of the board of directors of NuStar GP, LLC at an annual meeting, beginning in 2019. The Merger is subject to the satisfaction or waiver of certain conditions, including approval of the Merger Agreement by NuStar GP Holdings unitholders. Please refer to Note 28 for further discussion of the Merger.

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settlement of the Axeon Term Loan, and our obligation to provide ongoing credit support to Axeon ceased. Please refer to Notes 7 and 15 for further discussion of the Axeon Term Loan and related credit support.

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 3,130 miles of refined product pipelines and 1,930 miles of crude oil pipelines, as well as approximately 5.0 million barrels of storage capacity, which comprise our Central West System. In addition, we own 2,370 miles of refined product pipelines, consisting of the East and North Pipelines, and a 2,000-mile ammonia pipeline, which comprise our Central East System. The East and North Pipelines have storage capacity of approximately 6.8 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, Mexico, the Netherlands, including St. Eustatius in the Caribbean, and the United Kingdom, with approximately 84.8 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. Within our fuels marketing operations, we purchase petroleum products for resale. The activities of the fuels marketing segment expose us to the risk of fluctuations in commodity prices, which has a direct impact on the segment’s results of operations. We enter into derivative contracts to attempt to mitigate the effect of commodity price fluctuations.

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

Accounts receivable represent valid claims against non-affiliated customers for products sold or services rendered. 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

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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.

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 (expense) income, net” in the consolidated statements of 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 quantitative goodwill impairment test as of October 1, 2017 and 2016, and determined that no impairment charges occurred.

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.

Our reporting units to which goodwill has been allocated consist of the following:


•	crude oil pipelines;


•	refined product pipelines;


•	terminals, excluding our St. Eustatius and Point Tupper facilities and our refinery crude storage tanks; and


•	bunkering activity at our St. Eustatius and Point Tupper facilities.

The quantitative impairment test for goodwill consists of a two-step process. Step 1 compares the fair value of the reporting unit to its carrying value including goodwill. 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. If the carrying value exceeds fair value, there is a potential impairment and step 2 must be performed to determine the amount of goodwill impairment. Step 2 compares the carrying value of the reporting unit’s goodwill to its implied fair value using a hypothetical allocation of the reporting unit’s fair value. If the goodwill carrying value exceeds its implied fair value, the excess is reported as impairment.

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 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. We believe that the carrying amounts of our long-lived assets as of December 31, 2017 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 units subsequent to our initial public offering,

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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, 2017 and 2016.

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 2013 through 2016, 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 a liability of $0.7 million and $0.6 million as of December 31, 2017 and 2016, respectively, which is 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.

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.

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Product Imbalances

We incur product imbalances as a result of variances in pipeline meter readings and volume fluctuations due to pressure and temperature changes. We use quoted market prices as of the reporting date to value our assets and liabilities related to product imbalances. Product imbalance liabilities are included in “Accrued liabilities” and product imbalance assets are included in “Other current assets” in the consolidated balance sheets.

Revenue Recognition

Revenues for the pipeline segment are derived from interstate and intrastate pipeline transportation of refined products, crude oil and anhydrous ammonia. Transportation revenues (based on pipeline tariffs) are recognized as the refined product, crude oil or anhydrous ammonia is delivered out of the pipelines.

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. 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. Storage terminal revenues are recognized when services are provided to the customer. Throughput revenues are recognized as refined products or crude oil are received in or delivered out of our terminal. Revenues for marine services are recognized as those services are provided.

Revenues from the sale of petroleum products, which are included in our fuels marketing segment, are recognized when product is delivered to the customer and title and risk pass to the customer.

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 revenue.

Income Allocation

Our partnership agreement, as amended, sets forth the calculation to be used to determine the amount and priority of cash distributions that the unitholders and general partner will receive. The partnership agreement also contains provisions for the allocation of net income to the unitholders and the general partner; however, losses are only allocated to the common unitholders and 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 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 (98%) and general partner (2%), as set forth in our partnership agreement.

Basic and Diluted Net Income Per Common Unit

Basic and diluted net income per common unit are determined pursuant to the two-class method. Under this method, all earnings are allocated to our common limited partners and participating securities based on their respective rights to receive distributions earned during the period. Participating securities include our general partner interest and restricted units awarded under our long-term incentive plan.

We compute basic net income per common unit by dividing net income attributable to our common limited partners by the weighted-average number of common units outstanding during the period. We compute diluted net income per common unit by dividing net 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 outstanding during the period. Dilutive potential common units include contingently issuable performance units awarded under our long-term incentive plan. See Note 23 for additional information on our performance units.

Derivative Financial Instruments

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 or the fair value of the hedged items. 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. To assess the effectiveness of the hedging relationship both prospectively and retrospectively, we use regression analysis to calculate the correlation of the changes in the fair values of the derivative instrument and related hedged item.

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We record commodity derivative instruments in the consolidated balance sheets at fair value. We recognize mark-to-market adjustments for derivative instruments designated and qualifying as fair value hedges (Fair Value Hedges) and the related change in the fair value of the associated hedged physical inventory or firm commitment within “Cost of product sales.” For derivative instruments designated and qualifying as cash flow hedges (Cash Flow Hedges), we record the effective portion of mark-to-market adjustments as a component of accumulated other comprehensive income (loss) (AOCI) until the underlying hedged forecasted transactions occur. Any hedge ineffectiveness is recognized immediately in “Cost of product sales.” Once a hedged transaction occurs, we reclassify the effective portion from AOCI to “Cost of product sales.” If it becomes probable that a hedged transaction will not occur, then the associated gains or losses are reclassified from AOCI to “Cost of product sales” immediately. For derivative instruments that have associated underlying physical inventory but do not qualify for hedge accounting (Economic Hedges and Other Derivatives), we record the mark-to-market adjustments in “Cost of product sales.”

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. We account for the forward-starting interest rate swaps as Cash Flow Hedges, and 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 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 16 for additional information regarding our derivative financial instruments.

Operating Leases

We recognize rent expense on a straight-line basis over the lease term, including the impact of both scheduled rent increases and free or reduced rents (commonly referred to as “rent holidays”).

Unit-based Compensation

Unit-based compensation for our long-term incentive plan 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 income. See Note 23 for additional information regarding our unit-based compensation.

Margin Deposits

Margin deposits relate to our exchange-traded derivative contracts and generally vary based on changes in the value of the contracts. Margin deposits are included in “Other current assets” in the consolidated balance sheets.

Foreign Currency Translation

The functional currencies of our foreign subsidiaries are the local currencies of the countries in which the subsidiaries are located, except for our subsidiaries located in St. Eustatius in the Caribbean (formerly the Netherlands Antilles), whose functional currency is the U.S. dollar. 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 (expense) income, net” in the consolidated statements of income.

3. NEW ACCOUNTING PRONOUNCEMENTS

Derivatives and Hedging

In August 2017, the Financial Accounting Standards Board (FASB) issued amended guidance intended to improve the financial reporting of hedging relationships to better portray the economic results of an entity’s risk management activities in its financial statements. The amended guidance also makes certain targeted improvements to simplify the application of current hedge accounting guidance. The guidance is effective for annual and interim periods beginning after December 15, 2018, with early adoption permitted. Certain of the new requirements should be applied prospectively while others should be applied using a modified retrospective transition method. We currently expect to adopt the amended guidance on January 1, 2019. We do not

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expect the guidance to have a material impact on our financial position or results of operations, and we are assessing the impact on our disclosures.

Unit-Based Payments

In May 2017, the FASB issued amended guidance that clarifies when a change to the terms and conditions of a unit-based payment award is accounted for as a modification. Under the amended guidance, an entity will apply modification accounting if the value, vesting or classification of the unit-based payment award changes. The guidance is effective for annual and interim periods beginning after December 15, 2017, and amendments should be applied prospectively. We adopted these provisions January 1, 2018, and the guidance did not have a material impact on our financial position, results of operations or disclosures.

Defined Benefit Plans

In March 2017, the FASB issued amended guidance that changes the presentation of net periodic pension cost related to defined benefit plans. Under the amended guidance, the service cost component of net periodic benefit cost will be presented in the same income statement line items as other current employee compensation costs, but the remaining components of net periodic benefit cost will be presented outside of operating income. The changes are effective for annual and interim periods beginning after December 15, 2017, and amendments should be applied retrospectively. We adopted these provisions January 1, 2018, 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 by eliminating step 2 of the goodwill impairment test. Under the amended guidance, goodwill impairment will be 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, and we are currently evaluating whether we will adopt these provisions early. Regardless of our decision, we do not expect the guidance to have a material impact on our financial position, results of operations or disclosures.

Definition of a Business

In January 2017, the FASB issued amended guidance that clarifies the definition of a business used in evaluating whether a set of transferred assets and activities constitutes a business. Under the amended guidance, if substantially all of the fair value of the gross assets acquired is concentrated in a single identifiable asset or a group of similar identifiable assets, the set of transferred assets and activities would not represent a business. To be considered a business, the set of assets transferred is also required to include at least one substantive process that together significantly contribute to the ability to create outputs. In addition, the amended guidance narrows the definition of outputs to be consistent with how outputs are described in the new revenue recognition standard. The changes are effective for annual and interim periods beginning after December 15, 2017, and amendments should be applied prospectively. We adopted these provisions January 1, 2018, and they did not have an impact on our financial position, results of operations or disclosures.

Statement of Cash Flows

In August 2016, the FASB issued amended guidance that clarifies how entities should present certain cash receipts and cash payments on the statement of cash flows, including, but not limited to, debt prepayment or debt extinguishment costs, contingent consideration payments made after a business combination, proceeds from the settlement of insurance claims and distributions received from equity method investees. The changes are effective for annual and interim periods beginning after December 15, 2017, and amendments should be applied retrospectively. We adopted these provisions January 1, 2018, and they did not have an impact on our statements of cash flows or disclosures.

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 currently expect to adopt the amended guidance on January 1, 2020 and are assessing the impact of this amended guidance on our financial position, results of operations and disclosures. We plan to provide additional information about the expected financial impact at a future date.

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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, 2018, and amendments should be applied using a modified retrospective approach for leases that exist or are entered into after the beginning of the earliest comparative period in the financial statements, with the option to use certain expedients. In January 2018, the FASB issued additional guidance that provides an optional transition practical expedient for land easements. We currently expect to adopt these provisions on January 1, 2019 using the modified retrospective approach of adoption. We are working to identify our lease arrangements and have begun the process of system implementation. We are continuing to evaluate the impact of this amended guidance on our financial position, results of operations, disclosures and internal controls and plan to provide additional information about the expected financial impact at a future date.

Financial Instruments

In January 2016, the FASB issued new guidance that addresses certain aspects of recognition, measurement, presentation and disclosure of financial instruments. The changes are effective for annual and interim periods beginning after December 15, 2017, and amendments 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 January 1, 2018, and they did not have an impact on our financial position, results of operations or disclosures.

Revenue Recognition

In May 2014, the FASB and the International Accounting Standards Board jointly issued a comprehensive new revenue recognition standard that requires an entity to recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration the entity expects to be entitled to in exchange for those goods or services. The standard is effective for public entities for annual and interim periods beginning after December 15, 2017, using one of two retrospective transition methods. We adopted these provisions January 1, 2018 using the modified retrospective approach. The transition adjustment related to the adoption was immaterial (less than 1% of total revenues for the year ended December 31, 2017 and total partners’ equity as of December 31, 2017), and we do not expect the adoption of this standard to materially impact the amount or timing of our revenue going forward. Under the new guidance, we will no longer recognize the fair value of product imbalance assets or liabilities on our consolidated balance sheets. We intend to provide additional disclosures as required by the new standard, which we are currently assessing, in our quarterly report on Form 10-Q for the first quarter of 2018.

4. ACQUISITIONS

Navigator Acquisition

On April 11, 2017, we entered into a Membership Interest Purchase and Sale Agreement (the Acquisition Agreement) with FR Navigator Holdings LLC to acquire all of the issued and outstanding limited liability company interests in Navigator Energy Services, LLC (Navigator) for approximately $1.5 billion. We closed the Navigator Acquisition on May 4, 2017 and funded the purchase price with the net proceeds of the equity and debt issuances described in Notes 12 and 19. We acquired crude oil transportation, pipeline gathering and storage assets located in the Midland Basin of West Texas consisting of: (i) more than 500 miles of crude oil gathering and transportation pipelines with approximately 92,000 barrels per day ship-or-pay volume commitments and deliverability of approximately 412,000 barrels per day; (ii) a pipeline gathering system with more than 200 connected producer tank batteries capable of more than 400,000 barrels per day of pumping capacity covering over 500,000 dedicated acres with fixed fee contracts; and (iii) approximately 1.0 million barrels of crude oil storage capacity with 440,000 barrels contracted to third parties. We collectively refer to the acquired assets as our Permian Crude System. The assets acquired are included in our pipeline segment within the Central West System.

The Navigator Acquisition broadens our geographic footprint by marking our entry into the Permian Basin and complements our existing asset base. We believe the Permian Crude System will provide a strong growth platform that, when coupled with our assets in the Eagle Ford region, serve to solidify our presence in two of the most prolific basins in the United States.

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We accounted for the Navigator Acquisition using the acquisition method. The fair value estimates of the assets acquired and liabilities assumed are based on preliminary assumptions, pending the completion of an independent appraisal and other evaluations as information becomes available to us. The following table reflects the preliminary purchase price allocation as of December 31, 2017:



	Preliminary Purchase Price Allocation
	(Thousands of Dollars)
Accounts receivable	$	4,747
Other current assets	2,359
Property, plant and equipment, net	376,690
Intangible assets (a)	700,000
Goodwill (b)	400,838
Other long-term assets, net	2,199
Current liabilities	(25,114		)
Preliminary purchase price allocation, net of cash acquired	$	1,461,719


(a)	Intangible assets, which consist of customer contracts and relationships, are expected to be 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.

The values used in the purchase price allocation above are preliminary and subject to change after we finalize our review of certain of Navigator’s pre-acquisition liabilities, and pending the completion of an independent appraisal. Although a change in the value used for the assets acquired and liabilities assumed would cause a corresponding increase or decrease in goodwill, we do not expect any change to be significant.

The consolidated statements of income include the results of operations for Navigator commencing on May 4, 2017. The table below presents certain financial information included in the consolidated statements of income related to the Navigator Acquisition:



	Year Ended December 31, 2017
	(Thousands of Dollars)
Permian Crude System:
Revenues	$	42,620
Operating loss	$	(1,724	)

Transaction costs:
General and administrative expenses	$	10,391
Interest expense, net	3,688
Total transaction costs	$	14,079

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The unaudited pro forma information for the years ended December 31, 2017 and 2016 presented below combines the historical financial information for Navigator and the Partnership for those periods. The information assumes we completed the Navigator Acquisition on January 1, 2016 and the following:


•	we issued approximately 14.4 million common units;


•	we received a contribution from our general partner of $13.6 million to maintain its 2% interest;


•	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 preliminary purchase price allocation above; and


•	we satisfied Navigator’s outstanding obligations under its revolving credit agreement.



	Pro Forma Year Ended December 31,
	2017		2016
	(Thousands of Dollars, Except Per Unit Data)
Revenues	$	1,828,418	$	1,782,932
Net income	$	127,433	$	78,664

Basic and diluted net income per common unit	$	0.31	$	0.01

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, 2016 or that may result in the future.

Linden Acquisition. On January 2, 2015, we acquired full ownership of ST Linden Terminal, LLC (Linden), which owns a refined products terminal in Linden, NJ with 4.3 million barrels of storage capacity (the Linden Acquisition). Linden is located on a 44-acre facility that provides deep-water terminalling capabilities in the New York Harbor and primarily stores petroleum products, including gasoline, jet fuel and fuel oils. Prior to the Linden Acquisition, Linden operated as a joint venture between Linden Holding Corp. and us, with each party owning 50%.

In connection with the Linden Acquisition, we ceased applying the equity method of accounting and consolidated Linden, which is included in our storage segment. The consolidated statements of income include the results of operations for Linden commencing on January 2, 2015. On the acquisition date, we remeasured our existing 50% equity investment in Linden to its fair value of $128.0 million and we recognized a gain of $56.3 million in “Other (expense) income, net” in the consolidated statement of income for the year ended December 31, 2015. We estimated the fair value using a market approach and an income approach. The market approach estimates the enterprise value based on an earnings multiple. The income approach calculates fair value by discounting the estimated net cash flows. We funded the acquisition with borrowings under our revolving credit agreement. The acquisition complements our existing storage operations, and having sole ownership of Linden strengthens our presence in the New York Harbor and the East Coast market.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

We accounted for the Linden Acquisition using the acquisition method. The purchase price has been allocated based on the estimated fair values of the individual assets acquired and liabilities assumed at the date of the acquisition.

The final purchase price allocation was as follows (in thousands of dollars):



Cash paid for the Linden Acquisition	$	142,500
Fair value of liabilities assumed	22,865
Consideration	165,365
Acquisition date fair value of previously held equity interest	128,000
Total	$	293,365

Current assets (a)	$	9,513
Property, plant and equipment	134,484
Goodwill	79,208
Intangible assets (b)	70,050
Other long-term assets	110
Purchase price allocation	$	293,365


(a)	Current assets include a receivable of $7.8 million related to a pre-acquisition insurance claim, for which proceeds were received in 2015.


(b)	Intangible assets primarily consist of customer contracts and relationships and are being amortized over 10 years.

5. ALLOWANCE FOR DOUBTFUL ACCOUNTS

The changes in the allowance for doubtful accounts consisted of the following:



	Year Ended December 31,
	2017			2016			2015
	(Thousands of Dollars)
Balance as of beginning of year	$	7,756		$	8,473		$	7,808
Increase in allowance, net	2,217			24			965
Accounts charged against the allowance	(25		)	(741		)	(300		)
Balance as of end of year	$	9,948		$	7,756		$	8,473

6. INVENTORIES

Inventories consisted of the following:



	December 31,
	2017		2016
	(Thousands of Dollars)
Petroleum products	$	17,027	$	28,044
Materials and supplies	9,830		9,901
Total	$	26,857	$	37,945

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.

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7. OTHER CURRENT ASSETS

Other current assets consisted of the following:



	December 31,
	2017		2016
	(Thousands of Dollars)
Axeon Term Loan	$	—	$	110,000
Prepaid expenses	15,982		14,894
Derivative assets	—		155
Other	6,526		7,637
Other current assets	$	22,508	$	132,686

Axeon Term Loan. In December 2016, Lindsay Goldberg LLC, the private investment firm that owned Axeon, informed us that they entered into an agreement to sell Axeon’s retail asphalt sales and distribution business (the Axeon Sale), and we entered into an agreement with Axeon (the Axeon Letter Agreement) to settle and terminate the Axeon Term Loan for a $110.0 million payment to us upon closing of the Axeon Sale. Therefore, we recorded a charge of $58.7 million, included in “Other (expense) income, net” in the consolidated statements of income, to reduce the carrying amount of the Axeon Term Loan to $110.0 million and reclassified the Axeon Term Loan from “Other long-term assets, net” to “Other current assets” on the consolidated balance sheet as of December 31, 2016. The Axeon Sale closed on February 22, 2017, at which time we received the $110.0 million payment in accordance with the Axeon Letter Agreement. Furthermore, the Axeon Term Loan and our obligation to provide ongoing credit support to Axeon all terminated concurrently on February 22, 2017. Please refer to Note 15 for a discussion of the guarantees. In addition, in connection with the closing of the Axeon Sale, the terminal storage agreements that Axeon has with our Jacksonville, FL and Baltimore, MD terminal facilities were amended to increase the storage fees.

Prior to the closing of the Axeon Sale, we reviewed the financial information of Axeon monthly for possible credit loss indicators. We recognized interest income associated with the Axeon Term Loan ratably over the term of the loan in “Interest expense, net” on the consolidated statements of income.

8. PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment, at cost, consisted of the following:



	Estimated Useful Lives			December 31,
	Estimated Useful Lives			2017			2016
	(Years)			(Thousands of Dollars)
Land		-		$	143,527		$	138,224
Land and leasehold improvements	5	-	40	203,085			187,930
Buildings	15	-	40	151,702			144,773
Pipelines, storage and terminals	20	-	40	5,080,795			4,647,718
Rights-of-way	20	-	40	264,170			202,311
Construction in progress		-		400,202			114,322
Total				6,243,481			5,435,278
Less accumulated depreciation and amortization				(1,942,548		)	(1,712,995		)
Property, plant and equipment, net				$	4,300,933		$	3,722,283

Capitalized interest costs added to property, plant and equipment totaled $5.5 million, $3.4 million and $5.5 million for the years ended December 31, 2017, 2016 and 2015, respectively. Depreciation and amortization expense for property, plant and equipment totaled $222.5 million, $200.7 million and $192.3 million for the years ended December 31, 2017, 2016 and 2015, respectively.

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9. INTANGIBLE ASSETS

Intangible assets consisted of the following:



		December 31, 2017					December 31, 2016
	Weighted-Average Amortization Period	Cost		Accumulated Amortization			Cost		Accumulated Amortization
	(Years)	(Thousands of Dollars)
Customer contracts and relationships	18	$	863,950	$	(81,136	)	$	166,950	$	(41,582	)
Other	47	2,359		(694		)	2,359		(644		)
Total		$	866,309	$	(81,830	)	$	169,309	$	(42,226	)

All of our intangible assets are amortized on a straight-line basis. Amortization expense for intangible assets was $39.6 million, $13.9 million and $16.7 million for the years ended December 31, 2017, 2016 and 2015, respectively. The estimated aggregate amortization expense is approximately $51.0 million for each of the years 2018 through 2022.

10. GOODWILL

Changes in the carrying amount of goodwill by segment were as follows:



	Pipeline		Storage			Fuels Marketing			Total
	(Thousands of Dollars)
Balances as of January 1, 2016 and December 31, 2016:
Goodwill	$	306,207	$	691,220		$	53,255		$	1,050,682
Accumulated impairment losses	—		(331,913		)	(22,132		)	(354,045		)
Net goodwill	306,207		359,307			31,123			696,637

Activity for the year ended December 31, 2017:
Navigator Acquisition preliminary purchase price allocation (a)	400,838		—			—			400,838

Balances as of December 31, 2017:
Goodwill	707,045		691,220			53,255			1,451,520
Accumulated impairment losses	—		(331,913		)	(22,132		)	(354,045		)
Net goodwill	$	707,045	$	359,307		$	31,123		$	1,097,475


(a)	See Note 4 for discussion of the Navigator Acquisition.

11. ACCRUED LIABILITIES

Accrued liabilities consisted of the following:



	December 31,
	2017		2016
	(Thousands of Dollars)
Employee wages and benefit costs	$	16,963	$	30,807
Unearned income	18,243		14,355
Other	26,372		15,323
Accrued liabilities	$	61,578	$	60,485

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12. DEBT

Long-term debt consisted of the following:



				December 31,
	Maturity			2017			2016
				(Thousands of Dollars)
Revolving Credit Agreement		2020		$	893,311		$	838,992
7.65% senior notes		2018		350,000			350,000
4.80% senior notes		2020		450,000			450,000
6.75% senior notes		2021		300,000			300,000
4.75% senior notes		2022		250,000			250,000
5.625% senior notes		2027		550,000			—
Subordinated Notes		2043		402,500			402,500
GoZone Bonds	2038	thru	2041	365,440			365,440
Receivables Financing Agreement		2020		62,300			58,400
Net fair value adjustments, unamortized discounts and unamortized debt issuance costs		N/A		(10,492		)	(968		)
Total long-term debt				3,613,059			3,014,364
Less current portion				349,990			—
Long-term debt, less current portion				$	3,263,069		$	3,014,364

The long-term debt repayments are due as follows (in thousands of dollars):



2018	$	350,000
2019	—
2020	1,405,611
2021	300,000
2022	250,000
Thereafter	1,317,940
Total repayments	3,623,551
Net fair value adjustments, unamortized discounts and unamortized debt issuance costs	(10,492		)
Total long-term debt	$	3,613,059

Interest payments totaled $163.6 million, $146.1 million and $138.9 million for the years ended December 31, 2017, 2016 and 2015, respectively. We amortized an aggregate of $5.0 million, $4.4 million and $4.0 million of debt issuance costs and debt discount for the years ended December 31, 2017, 2016 and 2015, respectively.

Revolving Credit Agreement

On August 22, 2017, NuStar Logistics amended its revolving credit agreement (the Revolving Credit Agreement), mainly to extend the maturity date from October 29, 2019 to October 29, 2020, and to increase the borrowing capacity from $1.50 billion to $1.75 billion. The Revolving Credit Agreement includes the ability to borrow up to the equivalent of $250.0 million in Euros and up to the equivalent of $250.0 million in British Pounds Sterling. Obligations under the Revolving Credit Agreement are guaranteed by NuStar Energy and NuPOP. For the year ended December 31, 2017, we recorded deferred issuance costs of $3.1 million associated with the Revolving Credit Agreement to “Other long-term assets, net” on the consolidated balance sheet.

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through December 31, 2018. The Revolving Credit Agreement also contains customary restrictive covenants, such as limitations on indebtedness, liens, mergers, asset transfers and certain investing activities.

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, 2017, our weighted-average interest rate was 3.2%. During the year ended December 31, 2017, the weighted-average interest rate related to borrowings under the Revolving Credit Agreement was 2.8%.

In February 2018, Moody’s Investor Service Inc. (Moody’s) lowered our credit rating from Ba1 to Ba2. This rating downgrade caused the interest rate on our Revolving Credit Agreement to increase by 0.25% effective February 2018.

Notes

NuStar Logistics Senior Notes. On April 28, 2017, NuStar Logistics issued $550.0 million of 5.625% senior notes due April 28, 2027. We used the net proceeds of $543.3 million from the offering to fund a portion of the purchase price for the 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 $350.0 million of 7.65% senior notes, $450.0 million of 4.80% senior notes, $300.0 million of 6.75% senior notes, $250.0 million of 4.75% senior notes and $550.0 million of 5.625% senior notes (collectively, the NuStar Logistics Senior Notes). The interest rate payable on the 7.65% senior notes is subject to adjustment if our debt rating is downgraded (or upgraded) by certain credit rating agencies and was 8.40% as of December 31, 2017. In November 2017, Standard & Poor’s Rating Services lowered our credit rating from BB+ to BB. Additionally, the outlook was changed from stable to negative. The rating downgrade caused the interest rate on the 7.65% senior notes due 2018 to increase from 8.15% to 8.40%. The credit rating downgrade by Moody’s in February 2018 also increased the interest rate by 0.25%, resulting in an interest rate of 8.65% applicable to the interest payment due April 15, 2018.

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. 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, which includes a make-whole premium, 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 or the 5.625% senior notes, each holder of the 6.75% 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, 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.

NuStar Logistics 7.625% Fixed-to-Floating Rate Subordinated Notes. NuStar Logistics’ $402.5 million of 7.625% 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. The Subordinated Notes bore interest at a fixed annual rate of 7.625%, payable quarterly in arrears beginning on April 15, 2013 and ending on January 15, 2018. Thereafter, the Subordinated Notes bear interest at an annual rate equal to the sum of the three-month LIBOR rate 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.

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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 are 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 year ended December 31, 2017, and for the year ended December 31, 2016, we received $12.5 million from the trustee.

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. 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.

The following table summarizes the GoZone Bonds outstanding as of December 31, 2017:



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	June 1, 2038	$	55,440	$	56,169	$	55,440	$	—	1.8	%
July 15, 2010	July 1, 2040	100,000		101,315		100,000		—		1.7	%
October 7, 2010	October 1, 2040	50,000		50,658		43,741		6,546		1.7	%
December 29, 2010	December 1, 2040	85,000		86,118		49,782		35,997		1.7	%
August 29, 2011	August 1, 2041	75,000		75,986		75,000		—		1.8	%
	Total	$	365,440	$	370,246	$	323,963	$	42,543


(a)	Amount remaining in trust includes accrued interest.


(b)	For the year ended December 31, 2017, our weighted-average interest rate on borrowings was 0.9%.

Receivables Financing Agreement

NuStar Energy and NuStar Finance LLC (NuStar Finance), a special purpose entity and wholly owned subsidiary of NuStar Logistics, are parties to a $125.0 million receivables financing agreement with third-party lenders (the Receivables Financing Agreement) and agreements with certain of NuStar Energy’s wholly owned subsidiaries (collectively with the Receivables Financing Agreement, the Securitization Program). 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 maximum amount available for borrowing by NuStar Finance under the Receivables Financing Agreement is $125.0 million, with an option for NuStar Finance to request an increase of up to $75.0 million from the lenders (for aggregate total borrowings not to exceed $200.0 million). The amount available for borrowing 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.

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On September 20, 2017, the Securitization Program was amended to add certain of NuStar Energy’s wholly owned subsidiaries resulting from the Navigator Acquisition and to extend the Securitization Program’s scheduled termination date from June 15, 2018 to September 20, 2020, with the option to renew for additional 364-day periods thereafter. 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, 2017 and 2016, accounts receivable totaling $92.6 million and $104.5 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, 2017 was 2.0%.

Short-Term Lines of Credit

NuStar Logistics is party to two short-term line of credit agreements with an aggregate uncommitted borrowing capacity of up to $85.0 million, which allow us to better manage fluctuations in our daily cash requirements and minimize our excess cash balances. The interest rate and maturity vary and are determined at the time of borrowing. We had $35.0 million outstanding under these lines of credit as of December 31, 2017. Obligations under these short-term line of credit agreements are guaranteed by NuStar Energy. The weighted-average interest rate related to outstanding borrowings under our short-term lines of credit during the years ended December 31, 2017 and 2016, was 2.7% and 2.0%, respectively.

13. HEALTH, SAFETY AND ENVIRONMENTAL MATTERS

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 state jurisdictions along the routes of the systems.

We have adopted policies, practices and procedures to address pollution control, pipeline integrity, operator qualifications, public relations and education, process safety management, risk management planning, hazard communication, emergency response planning, community right-to-know, occupational health and the handling, storage, use and disposal of hazardous materials. Our policies are designed to comply with applicable federal, state and local regulations and to prevent material environmental or other damage, to ensure the safety of our pipelines, our employees, the public and the environment and to limit the financial liability that could result from such events. 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 within the industry, and there can be no assurances that significant costs and liabilities will not be incurred in the future.

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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The balance of and changes in the accruals for environmental matters were as follows:



	Year Ended December 31,
	2017			2016
	(Thousands of Dollars)
Balance as of the beginning of year	$	5,120		$	7,667
Additions to accrual	3,186			870
Payments	(2,675		)	(3,302		)
Foreign currency translation	52			(115		)
Balance as of the end of year	$	5,683		$	5,120

Accruals for environmental matters are included in the consolidated balance sheets as follows:



	December 31,
	2017		2016
	(Thousands of Dollars)
Accrued liabilities	$	3,054	$	3,281
Other long-term liabilities	2,629		1,839
Accruals for environmental matters	$	5,683	$	5,120

14. COMMITMENTS AND CONTINGENCIES

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 $7.3 million for contingent losses as of December 31, 2017, and had no accrual for contingent losses as of December 31, 2016. 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. In addition, 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.

Commitments

Lessee Commitments. Future minimum rental payments applicable to all noncancellable operating leases and purchase obligations as of December 31, 2017 are as follows:



	Payments Due by Period
	2018		2019		2020		2021		2022		There- after		Total
	(Thousands of Dollars)
Operating leases	$	39,236	$	34,203	$	19,541	$	13,324	$	7,295	$	68,386	$	181,985
Purchase obligations	$	6,963	$	6,133	$	4,686	$	4,690	$	4,480	$	300	$	27,252

Rental expense for all operating leases totaled $36.2 million, $37.0 million and $39.7 million for the years ended December 31, 2017, 2016 and 2015, respectively. Our operating leases consist primarily of the following:


•	a ten-year lease for tugs and barges utilized at our St. Eustatius facility for bunker fuel sales, with two five-year renewal options; and


•	land leases at various terminal facilities, with original terms ranging from 10 to 100 years.

Our purchase obligations primarily consist of an eleven-year chemical supply agreement related to our pipelines.

Lessor Revenues. We have entered into certain revenue arrangements where we are considered to be the lessor in accordance with GAAP. Under these arrangements we lease certain of our storage tanks in exchange for a fixed fee, subject to an annual consumer price index adjustment. The arrangements commenced on January 1, 2017, and have initial terms of ten years with successive ten-year automatic renewal terms. We recognized $39.1 million of lease revenues from these leases for the year ended December 31, 2017, which is included in “Service revenues” in the consolidated statements of income. Future minimum

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revenues we expect to receive under these lease arrangements as of December 31, 2017 total $352.2 million, which we will recognize ratably over the following nine years. As of December 31, 2017, the cost and accumulated depreciation of leased storage assets totaled $229.8 million and $104.9 million, respectively.

15. 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

The following assets and liabilities are measured at fair value on a recurring basis:



	December 31, 2017
	Level 1			Level 2			Level 3		Total
	(Thousands of Dollars)
Assets:
Other current assets:
Product imbalances	$	3,890		$	—		$	—	$	3,890
Liabilities:
Accrued liabilities:
Product imbalances	$	(1,534	)	$	—		$	—	$	(1,534	)
Commodity derivatives	(878		)	—			—		(878		)
Interest rate swaps	—			(5,394		)	—		(5,394		)
Other long-term liabilities:
Interest rate swaps	—			(4,594		)	—		(4,594		)
Total	$	(2,412	)	$	(9,988	)	$	—	$	(12,400	)



	December 31, 2016
	Level 1			Level 2			Level 3			Total
	(Thousands of Dollars)
Assets:
Other current assets:
Product imbalances	$	1,551		$	—		$	—		$	1,551
Commodity derivatives	—			155			—			155
Other long-term assets, net:
Interest rate swaps	—			1,314			—			1,314
Total	$	1,551		$	1,469		$	—		$	3,020
Liabilities:
Accrued liabilities:
Product imbalances	$	(1,577	)	$	—		$	—		$	(1,577	)
Commodity derivatives	(4,887		)	(165		)	—			(5,052		)
Other long-term liabilities:
Guarantee liability	—			—			(1,230		)	(1,230		)
Interest rate swaps	—			(2,632		)	—			(2,632		)
Total	$	(6,464	)	$	(2,797	)	$	(1,230	)	$	(10,491	)

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NUSTAR ENERGY L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Product Imbalances. Since we value our assets and liabilities related to product imbalances using quoted market prices in active markets as of the reporting date, we include these product imbalances in Level 1 of the fair value hierarchy.

Commodity Derivatives. We base the fair value of certain of our commodity derivative instruments on quoted prices on an exchange; accordingly, we include these items in Level 1 of the fair value hierarchy. We also had derivative instruments for which we determined fair value using industry pricing services and other observable inputs, such as quoted prices on an exchange for similar derivative instruments, and we included these derivative instruments in Level 2 of the fair value hierarchy. See Note 16 for a discussion of our derivative instruments.

Interest Rate Swaps. 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 these interest rate swaps in Level 2 of the fair value hierarchy.

Guarantees. We previously provided guarantees for commodity purchases, lease obligations and certain utilities for Axeon. As of December 31, 2016, we provided guarantees totaling $54.1 million, and one guarantee that did not specify a maximum amount. We estimated the fair value based on the guarantees outstanding and an estimate of the amount we would be obligated to pay under the guarantees at the time of default and considering the probability of default by Axeon. Our estimate of the fair value was based on significant inputs not observable in the market and thus fell within Level 3 of the fair value hierarchy. In conjunction with the termination of the Axeon Term Loan on February 22, 2017, our obligation to provide credit support to Axeon ceased. See Note 7 for additional information on the Axeon Term Loan.

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, approximate their carrying amounts. The estimated fair values and carrying amounts of the long-term debt, including the current portion, and the Axeon Term Loan were as follows:



	December 31, 2017		December 31, 2016
	Long-term Debt		Long-term Debt		Axeon Term Loan
	(Thousands of Dollars)
Fair value	$	3,677,622	$	3,084,762	$	110,000
Carrying amount	$	3,613,059	$	3,014,364	$	110,000

We estimated the fair value of our publicly traded senior notes based upon quoted prices in active markets; therefore, we determined that the fair value of our publicly traded senior notes falls in Level 1 of the fair value hierarchy. For our other debt, for which a quoted market price is not available, we 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. We determined that the fair value of the Axeon Term Loan approximated its carrying value as of December 31, 2016, which is included in “Other current assets” on the consolidated balance sheet. See Note 7 for additional information on the Axeon Term Loan.

16. DERIVATIVES AND RISK MANAGEMENT ACTIVITIES

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 volumes, grades, locations and delivery schedules, to help ensure that our hedging activities address our market risks.

Interest Rate Risk

We are a party to certain interest rate swap agreements to manage our exposure to changes in interest rates, which include forward-starting interest rate swap agreements related to forecasted debt issuances in 2018 and 2020. We entered into these swaps during the year ended December 31, 2015, 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. 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, 2017 and 2016, the aggregate notional amount of forward-starting interest rate swaps totaled $600.0 million.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

The remaining fair value amount associated with unwound fixed-to-floating interest rate swap agreements totaled a $15.6 million and a $21.1 million gain as of December 31, 2017 and 2016, respectively, and is included in “Long-term debt” on the consolidated balance sheets. The remaining fair value amount associated with unwound forward-starting interest rate swap agreements totaled a $14.3 million and a $20.9 million loss as of December 31, 2017 and 2016, respectively, and is included in AOCI on the consolidated balance sheets. These amounts are amortized ratably over the remaining life of the related debt instrument into “Interest expense, net” on the consolidated statements of income.

Commodity Price Risk

We are exposed to market risks related to the volatility of petroleum product prices. In order to reduce the risk of commodity price fluctuations with respect to our petroleum product inventories and related firm commitments to purchase and/or sell such inventories, we utilize commodity futures and swap contracts, which qualify and we designate as fair value hedges. Derivatives that are intended to hedge our commodity price risk, but fail to qualify as fair value or cash flow hedges, are considered economic hedges, and we record associated gains and losses in net income. Our risk management committee oversees our trading controls and procedures and certain aspects of commodity and trading risk management. Our risk management committee also reviews all new commodity and trading risk management strategies in accordance with our risk management policy, as approved by our board of directors. We ceased marketing crude oil in the second quarter of 2017 and exited our heavy fuels trading operations in the third quarter of 2017, thereby reducing our overall hedging activity.

The volume of commodity contracts is based on open derivative positions and represents the combined volume of our long and short open positions on an absolute basis, which totaled 1.2 million barrels and 4.7 million barrels as of December 31, 2017 and 2016, respectively. We had $0.3 million and $1.8 million of margin deposits as of December 31, 2017 and December 31, 2016, respectively.

The fair values of our derivative instruments included in our consolidated balance sheets were as follows:



		Asset Derivatives				Liability Derivatives
	Balance Sheet Location	December 31,
	Balance Sheet Location	2017		2016		2017			2016
		(Thousands of Dollars)
Derivatives Designated as Hedging Instruments:
Interest rate swaps	Other long-term assets, net	$	—	$	1,314	$	—		$	—
Commodity contracts	Accrued liabilities	—		144		(112		)	(3,566		)
Interest rate swaps	Accrued liabilities	—		—		(5,394		)	—
Interest rate swaps	Other long-term liabilities	—		—		(4,594		)	(2,632		)
Total		—		1,458		(10,100		)	(6,198		)

Derivatives Not Designated as Hedging Instruments:
Commodity contracts	Other current assets	—		265		—			(110		)
Commodity contracts	Accrued liabilities	742		9,128		(1,508		)	(10,758		)
Total		742		9,393		(1,508		)	(10,868		)

Total Derivatives		$	742	$	10,851	$	(11,608	)	$	(17,066	)

Certain of our derivative instruments are eligible for offset in the consolidated balance sheets and subject to master netting arrangements. Under our master netting arrangements, there is a legally enforceable right to offset amounts, and we intend to settle such amounts on a net basis. The following are the net amounts presented on the consolidated balance sheets:



	December 31,
Commodity Contracts	2017			2016
	(Thousands of Dollars)
Net amounts of assets presented in the consolidated balance sheets	$	—		$	155
Net amounts of liabilities presented in the consolidated balance sheets	$	(878	)	$	(5,052	)

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

We recognize the impact of our commodity contracts on earnings in “Cost of product sales” on the consolidated income statements, and that impact was as follows:



	Year Ended December 31,
	2017			2016			2015
	(Thousands of Dollars)
Derivatives Designated as Fair Value Hedging Instruments:
Gain (loss) recognized in income on derivative	$	806		$	(11,254	)	$	21,589
(Loss) gain recognized in income on hedged item	(656		)	15,295			(18,047		)
Gain recognized in income for ineffective portion	$	150		$	4,041		$	3,542

Derivatives Not Designated as Hedging Instruments:
(Loss) gain recognized in income on derivative	$	(668	)	$	225		$	2,208

Our interest rate swaps had the following impact on earnings:



	Year Ended December 31,
	2017			2016			2015
	(Thousands of Dollars)
Derivatives Designated as Cash Flow Hedging Instruments:
(Loss) gain recognized in other comprehensive (loss) income on derivative (effective portion)	$	(8,670	)	$	(2,621	)	$	1,303
Loss reclassified from AOCI into interest expense, net (effective portion)	(6,624		)	(8,331		)	(9,802		)

As of December 31, 2017, we expect to reclassify a loss of $5.1 million to “Interest expense, net” within the next twelve months associated with unwound forward-starting interest rate swaps.

17. RELATED PARTY TRANSACTIONS

Please refer to Note 28 for a discussion of the merger of a subsidiary of ours with and into NuStar GP Holdings, pursuant to which we will become the sole member of NuStar GP Holdings.

GP Services Agreement. Prior to the Employee Transfer discussed in Note 1, our operations were managed by NuStar GP, LLC under a services agreement effective January 1, 2008 pursuant to which employees of NuStar GP, LLC performed services for our U.S. operations. Employees of NuStar GP, LLC provided services to us and NuStar GP Holdings; therefore, we reimbursed NuStar GP, LLC for all employee costs incurred prior to the Employee Transfer, other than the expenses allocated to NuStar GP Holdings. The following table summarizes information pertaining to our related party transactions prior to the Employee Transfer:



	Year Ended December 31,
	2016		2015
	(Thousands of Dollars)
Operating expenses	$	21,681	$	135,565
General and administrative expenses	$	10,493	$	66,769
Expenses included in discontinued operations, net of tax	$	—	$	2

In conjunction with the Employee Transfer, we entered into an Amended and Restated Services Agreement with NuStar GP, LLC, effective March 1, 2016 (the Amended GP Services Agreement). The Amended GP Services Agreement provides that we will furnish administrative services necessary to conduct the business of NuStar GP Holdings. NuStar GP Holdings will compensate us for these services through 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. The Amended GP Services Agreement will terminate on March 1, 2020 and will automatically renew for successive two-year terms, unless terminated by either party.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Assignment and Assumption Agreement. Also on March 1, 2016 and in connection with the Employee Transfer, we entered into an Assignment and Assumption Agreement with NuStar GP, LLC (the Assignment Agreement). Under the Assignment Agreement, NuStar GP, LLC assigned all of its employee benefit plans, programs, contracts, policies, and various of its other agreements and contracts with certain employees, affiliates and third-party service providers (collectively, the Assigned Programs) to NuStar Services Co. In addition, NuStar Services Co agreed to assume the sponsorship of and all obligations relating to the ongoing maintenance and administration of each of the plans and agreements in the Assigned Programs. Certain of our officers are also officers of NuStar GP Holdings and are considered dual employees of ours and NuStar GP Holdings.

The following table summarizes the related party transactions and changes to amounts reported on our consolidated balance sheet as a result of the Employee Transfer on March 1, 2016 (thousands of dollars):



Decrease in related party payable:
Current	$	16,014
Long-term	32,656
Decrease in related party payable	$	48,670

Changes to our consolidated balance sheet:
Current and long-term assets	$	2,154
Current liabilities	5,609
Other long-term liabilities	34,042
Limited partners’ equity	2,664
Accumulated other comprehensive loss	4,201
Changes to our consolidated balance sheet	$	48,670

Non-Compete Agreement. On July 19, 2006, we entered into a non-compete agreement with NuStar GP Holdings, Riverwalk Logistics, L.P. and NuStar GP, LLC (the Non-Compete Agreement). The Non-Compete Agreement became effective on December 22, 2006 when NuStar GP Holdings ceased to be subject to the Amended and Restated Omnibus Agreement, dated March 31, 2006. Under the Non-Compete Agreement, we will have a right of first refusal with respect to the potential acquisition of assets that relate to the transportation, storage or terminalling of crude oil, feedstocks or refined petroleum products (including petrochemicals) in the United States and internationally. NuStar GP Holdings will have 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. With respect to any other business opportunities, neither the Partnership nor NuStar GP Holdings are prohibited from engaging in any business, even if the Partnership and NuStar GP Holdings would have a conflict of interest with respect to such other business opportunity.

18. OTHER (EXPENSE) INCOME

Other (expense) income consisted of the following:



	Year Ended December 31,
	2017			2016			2015
	(Thousands of Dollars)
(Loss) gain from sale or disposition of assets	$	(4,984	)	$	(64	)	$	1,617
Impairment loss on Axeon Term Loan	—			(58,655		)	—
Gain associated with Linden Acquisition	—			—			56,277
Foreign exchange (losses) gains	(344		)	(660		)	3,891
Other, net	34			596			37
Other (expense) income, net	$	(5,294	)	$	(58,783	)	$	61,822

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

19. PARTNERS’ EQUITY

Please refer to Note 28 for a discussion of the merger of a subsidiary of ours with and into NuStar GP Holdings, pursuant to which we will become the sole member of NuStar GP Holdings.

Amendment of Partnership Agreement

In the second quarter of 2017, our general partner amended and restated our partnership agreement in connection with the issuance of the Series B Preferred Units as described below and the Navigator Acquisition to waive up to an aggregate $22.0 million of the quarterly incentive distributions to our general partner for any NS common units issued from the date of the Acquisition Agreement (other than those attributable to NS common units issued under any equity compensation plan) for ten consecutive quarters, starting with the distributions for the second quarter of 2017. The partnership agreement was amended and restated again in connection with the issuance of our Series C Preferred Units described below.

Issuance of Common Units

For the years ended December 31, 2017 and 2016, we issued 185,455 and 135,100 common units, respectively, representing limited partner interests in connection with the vestings of awards issued under our long-term incentive plan.

Preferred Units

The following is a summary of our fixed-to-floating rate cumulative redeemable perpetual preferred units issued and outstanding as of December 31, 2017:



Units	Original Issuance Date	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		Optional Redemption Date/Date at Which Distribution Rate Becomes Floating	Floating Annual Rate (as a Percentage of the $25.00 Liquidation Preference per Unit)
Series A Preferred Units	November 25, 2016	9,060,000	$	25.00	$	218.4	8.50	%	$	2.125	December 15, 2021	Three-month LIBOR plus 6.766%
Series B Preferred Units	April 28, 2017	15,400,000	$	25.00	$	371.8	7.625	%	$	1.90625	June 15, 2022	Three-month LIBOR plus 5.643%
Series C Preferred Units	November 30, 2017	6,900,000	$	25.00	$	166.7	9.00	%	$	2.25	December 15, 2022	Three-month LIBOR plus 6.88%

Distributions on the Series A, Series B and Series C Preferred Units (collectively, 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.

We may redeem any of our outstanding Preferred Units at any time on or after the optional redemption date set forth above for each series of 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 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 Preferred Units, the preferred unitholders may have the ability to convert their Preferred Units to common units at the then applicable conversion rate. Holders of the Preferred Units have no voting rights except for certain exceptions set forth in our partnership agreement.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

The following table summarizes financial information related to our preferred units:



	Preferred Limited Partners
	Series A			Series B			Series C			Total
Balance as of January 1, 2016	$	—		$	—		$	—		$	—
Issuance of units	218,400			—			—			218,400
Net income	1,925			—			—			1,925
Distributions to partners	(1,925		)	—			—			(1,925		)
Balance as of December 31, 2016	218,400			—			—			218,400
Issuance of units	—			371,823			166,737			538,560
Net income	19,253			19,815			1,380			40,448
Distributions to partners	(19,253		)	(19,815		)	(1,380		)	(40,448		)
Other	(93		)	(189		)	(75		)	(357		)
Balance as of December 31, 2017	$	218,307		$	371,634		$	166,662		$	756,603

Net Income Applicable to the General Partner

The following table details the calculation of net income applicable to the general partner:



	Year Ended December 31,
	2017			2016			2015
	(Thousands of Dollars)
Net income attributable to NuStar Energy L.P.	$	147,964		$	150,003		$	306,720
Less preferred limited partner interest	40,448			1,925			—
Less general partner incentive distribution	45,669			43,407			43,220
Net income after general partner incentive distribution and preferred limited partner interest	61,847			104,671			263,500
General partner interest allocation	2		%	2		%	2		%
General partner interest allocation of net income	1,237			2,091			5,270
General partner incentive distribution	45,669			43,407			43,220
Net income applicable to general partner	$	46,906		$	45,498		$	48,490

Cash Distributions

General Partner and Common Limited Partners. We make quarterly distributions to common unitholders and the general partner of 100% of our available cash, generally defined as cash receipts less cash disbursements (including distributions to the 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, to the Preferred Units. Our available cash is distributed based on the percentages shown below:



	Percentage of Distribution
Quarterly Distribution Amount per Common Unit	Common Unitholders	General Partner Including Incentive Distributions
Up to $0.60	98%	2%
Above $0.60 up to $0.66	90%	10%
Above $0.66	75%	25%

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

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:



	Year Ended December 31,
	2017		2016		2015
	(Thousands of Dollars, Except Per Unit Data)
General partner interest	$	9,252	$	7,877	$	7,844
General partner incentive distribution	45,669		43,407		43,220
Total general partner distribution	54,921		51,284		51,064
Common limited partners’ distribution	407,681		342,598		341,140
Total cash distributions	$	462,602	$	393,882	$	392,204

Cash distributions per unit applicable to common limited partners	$	4.38	$	4.38	$	4.38

The following table summarizes information related to our quarterly cash distributions to our general partner and common limited partners:



Quarter Ended	Cash Distributions Per Unit		Total Cash Distributions		Record Date	Payment Date
			(Thousands of Dollars)
December 31, 2017 (a)	$	1.095	$	115,267	February 8, 2018	February 13, 2018
September 30, 2017	$	1.095	$	115,084	November 9, 2017	November 14, 2017
June 30, 2017	$	1.095	$	115,083	August 7, 2017	August 11, 2017
March 31, 2017	$	1.095	$	117,168	May 8, 2017	May 12, 2017


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

Preferred Units. The following table summarizes information related to our quarterly cash distributions on our Preferred Units:



Period	Cash Distributions Per Unit		Total Cash Distributions		Record Date	Payment Date
			(Thousands of Dollars)
Series A Preferred Units:
December 15, 2017 - March 14, 2018 (a)	$	0.53125	$	4,813	March 1, 2018	March 15, 2018
September 15, 2017 - December 14, 2017	$	0.53125	$	4,813	December 1, 2017	December 15, 2017
June 15, 2017 - September 14, 2017	$	0.53125	$	4,813	September 1, 2017	September 15, 2017
March 15, 2017 - June 14, 2017	$	0.53125	$	4,813	June 1, 2017	June 15, 2017
November 25, 2016 - March 14, 2017	$	0.64930556	$	5,883	March 1, 2017	March 15, 2017

Series B Preferred Units:
December 15, 2017 - March 14, 2018 (a)	$	0.47657	$	7,339	March 1, 2018	March 15, 2018
September 15, 2017 - December 14, 2017	$	0.47657	$	7,339	December 1, 2017	December 15, 2017
April 28, 2017 - September 14, 2017	$	0.725434028	$	11,172	September 1, 2017	September 15, 2017

Series C Preferred Units:
November 30, 2017 - March 14, 2018 (a)	$	0.65625	$	4,528	March 1, 2018	March 15, 2018


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

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Accumulated Other Comprehensive Income (Loss)

The balance of and changes in the components included in “Accumulated other comprehensive income (loss)” were as follows:



	Foreign Currency Translation			Cash Flow Hedges			Pension and Other Postretirement Benefits			Total
	(Thousands of Dollars)
Balance as of January 1, 2015	$	(28,839	)	$	(39,073	)	$	—		$	(67,912	)
Other comprehensive (loss) income before reclassification adjustments	(31,987		)	1,303			—			(30,684		)
Net loss on cash flow hedges reclassified into interest expense, net	—			9,802			—			9,802
Other comprehensive (loss) income	(31,987		)	11,105			—			(20,882		)
Balance as of December 31, 2015	(60,826		)	(27,968		)	—			(88,794		)
Employee Transfer	—			—			4,201			4,201
Deferred income tax adjustments	—			—			2,414			2,414
Other comprehensive loss before reclassification adjustments	(8,243		)	(2,621		)	(7,852		)	(18,716		)
Net gain on pension costs reclassified into operating expense	—			—			(1,200		)	(1,200		)
Net gain on pension costs reclassified into general and administrative expense	—			—			(413		)	(413		)
Net loss on cash flow hedges reclassified into interest expense, net	—			8,331			—			8,331
Other comprehensive (loss) income	(8,243		)	5,710			(2,850		)	(5,383		)
Balance as of December 31, 2016	(69,069		)	(22,258		)	(2,850		)	(94,177		)
Other comprehensive income (loss) before reclassification adjustments	17,466			(8,670		)	(4,641		)	4,155
Net gain on pension costs reclassified into operating expense	—			—			(1,143		)	(1,143		)
Net gain on pension costs reclassified into general and administrative expense	—			—			(386		)	(386		)
Net loss on cash flow hedges reclassified into interest expense, net	—			6,624			—			6,624
Other comprehensive income (loss)	17,466			(2,046		)	(6,170		)	9,250
Balance as of December 31, 2017	$	(51,603	)	$	(24,304	)	$	(9,020	)	$	(84,927	)

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20. NET INCOME PER COMMON UNIT

The following table details the calculation of net income per common unit:



	Year Ended December 31,
	2017			2016			2015
	(Thousands of Dollars, Except Per Unit Data)
Net income attributable to NuStar Energy L.P.	$	147,964		$	150,003		$	306,720
Less: Distributions to general partner (including incentive distribution rights)	54,921			51,284			51,064
Less: Distributions to common limited partners	407,681			342,598			341,140
Less: Distributions to preferred limited partners	40,448			1,925			—
Less: Distribution equivalent rights to restricted units	2,965			2,697			—
Distributions in excess of earnings	$	(358,051	)	$	(248,501	)	$	(85,484	)

Net income attributable to common units:
Distributions to common limited partners	$	407,681		$	342,598		$	341,140
Allocation of distributions in excess of earnings	(350,890		)	(243,530		)	(83,774		)
Total	$	56,791		$	99,068		$	257,366

Basic weighted-average common units outstanding	88,825,964			78,080,484			77,886,078

Diluted common units outstanding:
Basic weighted-average common units outstanding	88,825,964			78,080,484			77,886,078
Effect of dilutive potential common units	—			32,518			—
Diluted weighted-average common units outstanding	88,825,964			78,113,002			77,886,078

Basic and diluted net income per common unit	$	0.64		$	1.27		$	3.30

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21. STATEMENTS OF CASH FLOWS

Changes in current assets and current liabilities were as follows:



	Year Ended December 31,
	2017			2016			2015
	(Thousands of Dollars)
Decrease (increase) in current assets:
Accounts receivable	$	(865	)	$	(23,234	)	$	67,257
Receivable from related parties	112			(317		)	—
Inventories	11,936			940			16,776
Other current assets	3,393			8,128			4,414
Increase (decrease) in current liabilities:
Accounts payable	(30,409		)	14,071			(32,152		)
Payable to related party, net	—			894			(872		)
Accrued interest payable	6,489			(256		)	941
Accrued liabilities	(11,157		)	161			(7,834		)
Taxes other than income tax	(3,529		)	2,690			(1,522		)
Income tax payable	(2,463		)	639			3,551
Changes in current assets and current liabilities	$	(26,493	)	$	3,716		$	50,559

The above changes in current assets and current liabilities differ from changes between amounts reflected in the applicable consolidated balance sheets due to:


•	current assets and current liabilities acquired and disposed of during the period;


•	the change in the amount accrued for capital expenditures;


•	the effect of foreign currency translation;


•	reclassification of the Axeon Term Loan to other current assets from other long-term assets, net;


•	changes in the fair values of our interest rate swap agreements;


•	reclassification of our 7.65% senior notes due April 15, 2018 from long-term debt to current portion of long-term debt; and


•	non-cash related party transactions associated with the Employee Transfer (see Note 17 for further information).

Cash flows related to interest and income taxes were as follows:



	Year Ended December 31,
	2017		2016		2015
	(Thousands of Dollars)
Cash paid for interest, net of amount capitalized	$	158,089	$	142,663	$	133,388
Cash paid for income taxes, net of tax refunds received	$	11,338	$	11,847	$	9,971

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22. EMPLOYEE BENEFIT PLANS

Employee Transfer

On March 1, 2016, and in conjunction with the Employee Transfer, we assumed $22.5 million and $10.2 million in benefit obligations associated with the pension plans and other postretirement benefit plans, respectively. Prior to the Employee Transfer, we reimbursed all costs incurred by NuStar GP, LLC related to these employee benefit plans at cost. For comparability purposes this footnote presents information related to these benefit plans on a combined basis for periods prior to the Employee Transfer and after the Employee Transfer, including changes in the benefit obligation and fair value of plan assets, components of net periodic benefit cost (income), and adjustments to other comprehensive income (loss). Consequently, certain amounts presented below will differ from amounts reflected in our consolidated financial statements. See Note 17 for additional discussion on the Employee Transfer.

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, 2017, 2016 and 2015 totaled $6.9 million, $6.6 million and $6.3 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 several other defined contribution plans for certain international employees located in Canada, the Netherlands and the United Kingdom. For the years ended December 31, 2017, 2016 and 2015, our costs for these plans totaled $2.5 million, $2.4 million and $2.6 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, 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 that retired prior to April 1, 2014 and for employees that 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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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, 2017 and 2016 were as follows:



	Pension Plans						Other Postretirement Benefit Plans
	2017			2016			2017			2016
	(Thousands of Dollars)
Change in benefit obligation:
Benefit obligation, January 1	$	127,402		$	109,202		$	11,061		$	10,042
Service cost	8,955			7,703			456			419
Interest cost	4,507			4,023			430			401
Benefits paid	(5,941		)	(2,554		)	(342		)	(422		)
Participant contributions	—			—			215			253
Actuarial loss	14,894			9,028			590			368
Benefit obligation, December 31	$	149,817		$	127,402		$	12,410		$	11,061
Change in plan assets:
Plan assets at fair value, January 1	$	107,644		$	87,706		$	—		$	—
Actual return on plan assets	17,070			6,891			—			—
Employer contributions	11,105			15,601			127			169
Benefits paid	(5,941		)	(2,554		)	(342		)	(422		)
Participant contributions	—			—			215			253
Plan assets at fair value, December 31	$	129,878		$	107,644		$	—		$	—
Reconciliation of funded status:
Fair value of plan assets at December 31	$	129,878		$	107,644		$	—		$	—
Less: Benefit obligation at December 31	149,817			127,402			12,410			11,061
Funded status at December 31	$	(19,939	)	$	(19,758	)	$	(12,410	)	$	(11,061	)
Amounts recognized in the consolidated balance sheets (a):
Accrued liabilities	$	(210	)	$	(162	)	$	(376	)	$	(321	)
Other long-term liabilities	(19,729		)	(19,596		)	(12,034		)	(10,740		)
Net pension liability	$	(19,939	)	$	(19,758	)	$	(12,410	)	$	(11,061	)


(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, 2017 and 2016 was $146.3 million and $125.0 million, respectively. As of December 31, 2017 and 2016, the aggregate accumulated benefit obligation for the Pension Plans exceeded plan assets.

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The components of net periodic benefit cost (income) related to our Pension Plans and other postretirement benefit plans were as follows:



	Pension Plans									Other Postretirement Benefit Plans
	Year Ended December 31,									Year Ended December 31,
	2017			2016			2015			2017			2016			2015
	(Thousands of Dollars)
Service cost	$	8,955		$	7,703		$	7,676		$	456		$	419		$	470
Interest cost	4,507			4,023			4,389			430			401			448
Expected return on plan assets	(6,411		)	(5,407		)	(5,018		)	—			—			—
Amortization of prior service credit	(2,059		)	(2,063		)	(2,063		)	(1,145		)	(1,145		)	(1,145		)
Amortization of net actuarial loss	1,484			1,091			1,845			191			181			269
Net periodic benefit cost (income)	$	6,476		$	5,347		$	6,829		$	(68	)	$	(144	)	$	42

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 percent 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).

Adjustments to other comprehensive (loss) income related to our Pension Plans and other postretirement benefit plans were as follows:



	Pension Plans									Other Postretirement Benefit Plans
	Year Ended December 31,									Year Ended December 31,
	2017			2016			2015			2017			2016			2015
	(Thousands of Dollars)
Net unrecognized (loss) gain arising during the year:
Net actuarial (loss) gain	$	(4,235	)	$	(7,544	)	$	1,000		$	(590	)	$	(368	)	$	1,056
Net (gain) loss reclassified into income:
Amortization of prior service credit	(2,059		)	(2,063		)	(2,063		)	(1,145		)	(1,145		)	(1,145		)
Amortization of net actuarial loss	1,484			1,091			1,845			191			181			269
Net gain reclassified into income	(575		)	(972		)	(218		)	(954		)	(964		)	(876		)

Income tax benefit (expense)	162			57			(362		)	22			3			(382		)
Total changes to other comprehensive (loss) income	$	(4,648	)	$	(8,459	)	$	420		$	(1,522	)	$	(1,329	)	$	(202	)

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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:



	Pension Plans						Other Postretirement Benefit Plans
	December 31,						December 31,
	2017			2016			2017			2016
	(Thousands of Dollars)
Unrecognized actuarial loss	$	(31,178	)	$	(28,427	)	$	(4,154	)	$	(3,755	)
Prior service credit	16,604			18,663			9,464			10,609
Deferred tax asset	219			57			25			3
Accumulated other comprehensive (loss) income, net of tax	$	(14,355	)	$	(9,707	)	$	5,335		$	6,857

The following pre-tax amounts in accumulated other comprehensive loss as of December 31, 2017 are expected to be recognized as components of net periodic benefit cost (income) in 2018:



	Pension Plans			Other Postretirement Benefit Plans
	(Thousands of Dollars)
Actuarial loss	$	2,174		$	214
Prior service credit	$	(2,057	)	$	(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, 2017, the target allocations for plan assets are 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:



	December 31, 2017
	Level 1		Level 2		Level 3		Total
	(Thousands of Dollars)
Cash equivalent securities	$	381	$	—	$	—	$	381
Equity securities:
U.S. large cap equity fund (a)	—		75,353		—		75,353
International stock index fund (b)	14,480		—		—		14,480
Fixed income securities:
Bond market index fund (c)	39,664		—		—		39,664
Total	$	54,525	$	75,353	$	—	$	129,878



	December 31, 2016
	Level 1		Level 2		Level 3		Total
	(Thousands of Dollars)
Cash equivalent securities	$	738	$	—	$	—	$	738
Equity securities:
U.S. large cap equity fund (a)	—		64,813		—		64,813
International stock index fund (b)	10,459		—		—		10,459
Fixed income securities:
Bond market index fund (c)	31,634		—		—		31,634
Total	$	42,831	$	64,813	$	—	$	107,644


(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, 2017, we contributed $11.1 million and $0.1 million to the Pension Plans and other postretirement benefit plans, respectively. During 2018, we expect to contribute approximately $11.2 million and $0.4 million to the Pension Plans and other postretirement benefit plans, respectively, which principally represents 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:



	Pension Plans		Other Postretirement Benefit Plans
	(Thousands of Dollars)
2018	$	8,823	$	376
2019	$	9,699	$	416
2020	$	10,432	$	434
2021	$	11,050	$	464
2022	$	11,650	$	497
Years 2023-2027	$	64,799	$	3,090

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Assumptions

The weighted-average assumptions used to determine the benefit obligations were as follows:



	Pension Plans				Other Postretirement Benefit Plans
	December 31,				December 31,
	2017		2016		2017		2016
Discount rate	3.72	%	4.33	%	3.82	%	4.49	%
Rate of compensation increase	3.51	%	3.51	%	n/a		n/a

The weighted-average assumptions used to determine the net periodic benefit cost (income) were as follows:



	Pension Plans						Other Postretirement Benefit Plans
	Year Ended December 31,						Year Ended December 31,
	2017		2016		2015		2017		2016		2015
Discount rate	4.33	%	4.61	%	4.22	%	4.49	%	4.75	%	4.34	%
Expected long-term rate of return on plan assets	6.00	%	6.25	%	6.50	%	n/a		n/a		n/a
Rate of compensation increase	3.51	%	3.51	%	3.51	%	n/a		n/a		n/a

The assumed health care cost trend rates were as follows:



	December 31,
	2017		2016
Health care cost trend rate assumed for next year	6.84	%	6.84	%
Rate to which the cost trend rate was assumed to decrease (the ultimate trend rate)	5.00	%	5.00	%
Year that the rate reaches the ultimate trend rate	2028		2028

Assumed health care cost trend rates have a significant effect on the amounts reported for health care plans. We sponsor a contributory postretirement health care plan for employees that 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.

23. UNIT-BASED COMPENSATION

Please refer to Note 28 for a discussion of the merger of a subsidiary of ours with and into NuStar GP Holdings, pursuant to which we will become the sole member of NuStar GP Holdings.

Overview

On January 28, 2016, our unitholders approved the Fifth Amended and Restated 2000 Long-Term Incentive Plan (the 2000 LTIP) which, among other items, provides that we may use newly issued common units from NuStar Energy to satisfy unit awards and extends the term of the 2000 LTIP to January 28, 2026. Prior to the Employee Transfer, NuStar GP, LLC sponsored the 2000 LTIP, and we reimbursed NuStar GP, LLC for awards under this plan. Following the approval of the 2000 LTIP and the Employee Transfer in 2016, most of our currently outstanding awards are now classified as equity awards as we intend to settle these awards through the issuance of our common units.

Effective March 1, 2016, we assumed sponsorship of the 2000 LTIP, which provides the Compensation Committee of the Board of Directors of NuStar GP, LLC (the Compensation Committee) with the right to issue and award up to 3,250,000 of our common units to employees and non-employee directors (NEDs). Awards available under the 2000 LTIP include restricted units, performance units, unit options, unit awards and distribution equivalent rights (DERs). The Compensation Committee may also include a tandem grant of a DER that will entitle the participant to receive cash equal to cash distributions made on

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any award prior to its vesting. As of December 31, 2017, common units that remained available to be awarded under the 2000 LTIP totaled 679,045.

On March 1, 2016, we assumed all outstanding awards under the 2000 LTIP. The transfer of the outstanding awards qualifies as a plan modification. Therefore, we measured the fair value of the outstanding awards based on the common unit price on the transfer date.

The following table summarizes information pertaining to our long-term incentive plan compensation expense:



	Units Outstanding December 31,		Transferred Units	Compensation Expense Year Ended December 31,
	2017	2016	March 1, 2016	2017		2016
				(Thousands of Dollars)
Restricted Units:
Domestic employees	736,746	647,340	586,524	$	7,881	$	5,980
Non-employee directors (NEDs)	27,097	18,134	17,629	251		388
International employees	58,107	50,609	49,121	595		715
Performance Units	80,961	77,014	77,014	—		1,211
Total	902,911	793,097	730,288	$	8,727	$	8,294

Prior to the Employee Transfer, we reimbursed NuStar GP, LLC for our long-term incentive plan compensation expense which totaled $6.4 million for the year ended December 31, 2015.

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) or the fair value of the common units measured at each reporting period (for NEDs and 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, we paid or expect to pay $3.0 million and $2.7 million, respectively, in cash, for the years ended December 31, 2017 and 2016. A summary of our restricted unit activity is as follows:



	Domestic Employees
	Number of Restricted Units		Weighted- Average Grant-Date Fair Value Per Unit		Number of Restricted Units to NEDs		Number of Restricted Units to International Employees
Nonvested units as of January 1, 2016	—		$	—	—		—
Transferred	586,524		35.03		17,629		49,121
Granted	246,070		47.70		8,730		20,107
Vested	(180,724	)	35.50		(8,225	)	(14,812	)
Forfeited	(4,530	)	35.03		—		(3,807	)
Nonvested units as of December 31, 2016	647,340		39.72		18,134		50,609
Granted	307,009		29.56		17,110		24,533
Vested	(201,466	)	38.74		(8,147	)	(16,440	)
Forfeited	(16,137	)	40.00		—		(595	)
Nonvested units as of December 31, 2017	736,746		$	35.95	27,097		58,107

The total fair value of our equity-classified awards vested for the years ended December 31, 2017 and 2016 was $6.5 million and $9.0 million, respectively. We issued 152,017 common units in connection with these award vestings, net of employee tax withholding requirements, for the year ended December 31, 2017. Unrecognized compensation cost related to our equity-

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classified employee awards totaled $25.5 million as of December 31, 2017, which we expect to recognize over a weighted-average period of 3.7 years.

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 transfer date (or grant date for issuances subsequent to the Employee Transfer).

Non-Employee Directors. The outstanding restricted units granted to NEDs are equity-classified awards that vest over three years. The fair value of these awards is 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 to five years and the fair value is equal to the market price of our common units at each reporting period.

Performance Units

Performance units are issued to certain of our key employees and represent rights to receive our common units upon achieving an objective performance measure for the performance period. The objective performance measure is determined each year by the NuStar GP, LLC Compensation Committee for the following year. Achievement of the performance measure determines the rate at which the performance units convert into our common units, which can range from zero to 200%.

Performance units vest in three annual increments (tranches), based upon our achievement of the performance measure set by the Compensation Committee during the one-year performance periods that end on December 31 of each year following the date of grant. Therefore, the performance units are not considered granted for accounting purposes until the Compensation Committee has set the performance measure 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 measure 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.

For the period from the Employee Transfer date to December 31, 2016, no performance units were granted or forfeited. 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. For 2017, we did not achieve the performance measure.

A summary of our performance units is shown below:



			Granted for Accounting Purposes
	Total Performance Units Awarded		Performance Units		Weighted-Average Grant Date Fair Value per Unit
Outstanding as of January 1, 2017	77,014		35,373		$	31.75
Granted	39,320		38,865		50.04
Vested	(35,373	)	(35,373	)	31.75
Outstanding as of December 31, 2017	80,961		38,865		$	50.04

Performance units vested during the year ended December 31, 2017 with respect to 2016 performance were as follows:



	Vested Units	Actual Conversion Rate		Gross Number of Units Issued
2014 awards	9,613	150	%	14,420
2015 awards	9,878	150	%	14,818
2016 awards	15,882	150	%	23,825
Total	35,373			53,063

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24. INCOME TAXES

On December 22, 2017, the U.S. enacted the Tax Cuts and Jobs Act (“the Act”). The Act, which is also commonly referred to as “U.S. tax reform,” significantly changes U.S. corporate income tax laws by, among other things, reducing the U.S. corporate tax rate from 35% to 21%, starting in 2018, and creating a territorial tax system with a one-time mandatory tax on previously deferred foreign earnings of U.S. subsidiaries. As a result, we recorded an expense of $0.8 million in the fourth quarter of 2017. This amount, which is included in “Income tax expense” on the consolidated statements of income, consists of two components: (i) $0.7 million relating to the one-time mandatory tax on previously deferred earnings of certain non-U.S. subsidiaries that are wholly owned by one of our U.S. subsidiaries and (ii) $0.1 million resulting from the revaluation of our net deferred tax assets in the U.S. based on the new lower corporate income tax rate.

Although the $0.8 million expense represents what we believe to be a reasonable estimate of the impact of the income tax effects of the Act on our consolidated financial statements as of December 31, 2017, it should be considered provisional. We are continuing to gather additional information to more precisely compute our deferred tax assets balance in the U.S., as well as the income tax expense associated with the one-time mandatory tax. Any adjustments to these provisional amounts will be reported as a component of “Income tax expense” on the consolidated statements of income in the reporting period in which any such adjustments are determined, which will be no later than the fourth quarter of 2018, and are not expected to be significant.

Due to the complexity of the new Global Intangible Low-Tax Income (GILTI) tax rules, we are continuing to evaluate this provision of the Act and the application of FASB’s Accounting Standards Codification 740 (ASC 740). Under U.S. GAAP, we are allowed to make an accounting policy choice of either (i) treating taxes due on future U.S. inclusions in taxable income related to GILTI as a current-period expense when incurred (the “period cost method”) or (ii) factoring such amounts into a company’s measurement of its deferred taxes (the “deferred method”). Our selection of an accounting policy with respect to the new GILTI tax rules will depend, in part, on analyzing our global income to determine whether we expect to have future U.S. inclusions in taxable income related to GILTI and, if so, what the impact is expected to be. Because whether we expect to have future U.S. inclusions in taxable income related to GILTI depends on not only our current structure and estimated future results of global operations, but also our intent and ability to modify our structure and/or our business, we are not yet able to reasonably estimate the effect of this provision of the Tax Act. Therefore, we have not made any adjustments related to potential GILTI tax in our consolidated financial statements as of December 31,2017, and have not made a policy decision regarding whether to record deferred taxes on GILTI.

Due to the complexity of the new Base Erosion Anti-Abuse Tax (BEAT) rules, we are continuing to evaluate this provision of the Act and the application of ASC 740. Under U.S. GAAP, because the BEAT provisions are designed to be an “incremental tax,” BEAT is treated as a current-period expense when incurred (the period cost method). Therefore, we have not made any adjustments related to the potential BEAT in our consolidated financial statements.

Components of income tax expense related to certain of our continuing operations conducted through separate taxable wholly owned corporate subsidiaries were as follows:



	Year Ended December 31,
	2017			2016			2015
	(Thousands of Dollars)
Current:
U.S.	$	3,117		$	2,280		$	908
Foreign	6,335			6,329			9,820
Foreign withholding tax	479			3,833			1,926
Total current	9,931			12,442			12,654

Deferred:
U.S.	1,468			2,680			1,022
Foreign	(1,065		)	(1,122		)	(1,464		)
Foreign withholding tax	(397		)	(2,027		)	2,500
Total deferred	6			(469		)	2,058

Total income tax expense	$	9,937		$	11,973		$	14,712

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The difference between income tax expense recorded in our consolidated statements of income and income taxes computed by applying the statutory federal income tax rate (35% for all years presented) 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.

The tax effects of significant temporary differences representing deferred income tax assets and liabilities were as follows:



	December 31,
	2017			2016
	(Thousands of Dollars)
Deferred income tax assets:
Net operating losses	$	20,688		$	31,539
Employee benefits	483			697
Environmental and legal reserves	185			148
Allowance for bad debt	1,982			2,697
Other	2,050			1,697
Total deferred income tax assets	25,388			36,778
Less: Valuation allowance	(11,251		)	(12,759		)
Net deferred income tax assets	14,137			24,019

Deferred income tax liabilities:
Property, plant and equipment	(36,176		)	(43,788		)
Foreign withholding tax	—			(384		)
Total deferred income tax liabilities	(36,176		)	(44,172		)

Net deferred income tax liability	$	(22,039	)	$	(20,153	)

Reported on the consolidated balance sheets as:
Deferred income tax asset	$	233		$	2,051
Deferred income tax liability	(22,272		)	(22,204		)
Net deferred income tax liability	$	(22,039	)	$	(20,153	)

As of December 31, 2017, our U.S. and foreign corporate operations have net operating loss carryforwards for tax purposes totaling $79.9 million and $13.1 million, respectively, which are subject to various limitations on use and expire in years 2025 through 2036 for U.S. losses and in years 2018 through 2026 for foreign losses.

As of December 31, 2017 and 2016, we recorded a valuation allowance of $11.3 million and $12.8 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 2017, there was a $1.9 million decrease in the valuation allowance for the U.S. net operating loss and a $0.4 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, 2017 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, 2017 will be realized, based on expected future taxable income.

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25. SEGMENT INFORMATION

Our reportable business segments consist of pipeline, storage and fuels marketing. 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, the terminalling and storage of petroleum products and the 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:



	Year Ended December 31,
	2017			2016			2015
	(Thousands of Dollars)
Revenues:
Pipeline	$	516,288		$	485,650		$	508,522
Storage:
Third parties	604,847			589,098			599,302
Intersegment	12,106			20,944			25,606
Total storage	616,953			610,042			624,908
Fuels marketing	692,884			681,934			976,216
Consolidation and intersegment eliminations	(12,106		)	(20,944		)	(25,606		)
Total revenues	$	1,814,019		$	1,756,682		$	2,084,040

Depreciation and amortization expense:
Pipeline	$	128,061		$	89,554		$	84,951
Storage	127,473			118,663			116,768
Total segment depreciation and amortization expense	255,534			208,217			201,719
Other depreciation and amortization expense	8,698			8,519			8,491
Total depreciation and amortization expense	$	264,232		$	216,736		$	210,210

Operating income:
Pipeline	$	231,795		$	248,238		$	270,349
Storage	219,439			214,801			217,818
Fuels marketing	5,983			3,406			13,507
Consolidation and intersegment eliminations	(1		)	—			42
Total segment operating income	457,216			466,445			501,716
General and administrative expenses	112,240			98,817			102,521
Other depreciation and amortization expense	8,698			8,519			8,491
Total operating income	$	336,278		$	359,109		$	390,704

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Revenues by geographic area are shown in the table below:



	Year Ended December 31,
	2017		2016		2015
	(Thousands of Dollars)
United States	$	1,406,626	$	1,352,936	$	1,599,088
Netherlands	322,251		313,395		386,282
Other	85,142		90,351		98,670
Consolidated revenues	$	1,814,019	$	1,756,682	$	2,084,040

For the years ended December 31, 2017, 2016 and 2015, Valero Energy Corporation accounted for approximately 17%, or $300.0 million, 18%, or $310.0 million, and 16%, or $331.7 million, of our consolidated 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:



	December 31,
	2017		2016
	(Thousands of Dollars)
United States	$	3,519,965	$	3,086,337
Netherlands	572,817		469,061
Other	208,151		166,885
Consolidated long-lived assets	$	4,300,933	$	3,722,283

Total assets by reportable segment were as follows:



	December 31,
	2017		2016
	(Thousands of Dollars)
Pipeline	$	3,492,417	$	2,024,633
Storage	2,735,563		2,522,586
Fuels marketing	118,746		168,347
Total segment assets	6,346,726		4,715,566
Other partnership assets	188,507		314,979
Total consolidated assets	$	6,535,233	$	5,030,545

Capital expenditures, including acquisitions and investments in other noncurrent assets, by reportable segment were as follows:



	Year Ended December 31,
	2017		2016		2015
	(Thousands of Dollars)
Pipeline	$	1,596,311	$	88,373	$	175,657
Storage	244,398		206,641		285,258
Other partnership assets	5,648		5,001		9,957
Total capital expenditures	$	1,846,357	$	300,015	$	470,872

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26. 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.

Condensed Consolidating Balance Sheets

December 31, 2017

(Thousands of Dollars)



	NuStar Energy		NuStar Logistics		NuPOP		Non-Guarantor Subsidiaries		Eliminations			Consolidated
Assets
Cash and cash equivalents	$	885	$	29	$	—	$	23,378	$	—		$	24,292
Receivables, net	—		280		—		176,495		—			176,775
Inventories	—		1,686		8,611		16,560		—			26,857
Other current assets	61		11,412		4,191		6,844		—			22,508
Intercompany receivable	—		3,112,164		—		—		(3,112,164		)	—
Total current assets	946		3,125,571		12,802		223,277		(3,112,164		)	250,432
Property, plant and equipment, net	—		1,893,720		591,070		1,816,143		—			4,300,933
Intangible assets, net	—		58,530		—		725,949		—			784,479
Goodwill	—		149,453		170,652		777,370		—			1,097,475
Investment in wholly owned subsidiaries	2,891,371		24,162		1,301,717		790,882		(5,008,132		)	—
Deferred income tax asset	—		—		—		233		—			233
Other long-term assets, net	303		65,684		27,493		8,201		—			101,681
Total assets	$	2,892,620	$	5,317,120	$	2,103,734	$	4,342,055	$	(8,120,296	)	$	6,535,233
Liabilities and Partners’ Equity
Current portion of long-term debt	$	—	$	349,990	$	—	$	—	$	—		$	349,990
Payables	4,078		27,642		13,160		101,052		—			145,932
Short-term debt	—		35,000		—		—		—			35,000
Accrued interest payable	—		40,402		—		47		—			40,449
Accrued liabilities	1,105		17,628		9,450		33,395		—			61,578
Taxes other than income tax	125		7,110		3,794		3,356		—			14,385
Income tax payable	—		732		4		3,436		—			4,172
Intercompany payable	322,296		—		1,277,691		1,512,177		(3,112,164		)	—
Total current liabilities	327,604		478,504		1,304,099		1,653,463		(3,112,164		)	651,506
Long-term debt, less current portion	—		3,201,220		—		61,849		—			3,263,069
Deferred income tax liability	—		1,262		12		20,998		—			22,272
Other long-term liabilities	—		58,806		8,861		50,630		—			118,297
Total partners’ equity	2,565,016		1,577,328		790,762		2,555,115		(5,008,132		)	2,480,089
Total liabilities and partners’ equity	$	2,892,620	$	5,317,120	$	2,103,734	$	4,342,055	$	(8,120,296	)	$	6,535,233

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Condensed Consolidating Balance Sheets

December 31, 2016

(Thousands of Dollars)



	NuStar Energy		NuStar Logistics		NuPOP		Non-Guarantor Subsidiaries		Eliminations			Consolidated
Assets
Cash and cash equivalents	$	870	$	5	$	—	$	35,067	$	—		$	35,942
Receivables, net	—		3,040		—		167,570		—			170,610
Inventories	—		2,216		2,005		33,724		—			37,945
Other current assets	61		120,350		1,829		10,446		—			132,686
Intercompany receivable	—		1,308,415		—		57,785		(1,366,200		)	—
Total current assets	931		1,434,026		3,834		304,592		(1,366,200		)	377,183
Property, plant and equipment, net	—		1,935,172		589,139		1,197,972		—			3,722,283
Intangible assets, net	—		71,033		—		56,050		—			127,083
Goodwill	—		149,453		170,652		376,532		—			696,637
Investment in wholly owned subsidiaries	1,964,736		34,778		1,221,717		874,649		(4,095,880		)	—
Deferred income tax asset	—		—		—		2,051		—			2,051
Other long-term assets, net	1,255		63,586		28,587		11,880		—			105,308
Total assets	$	1,966,922	$	3,688,048	$	2,013,929	$	2,823,726	$	(5,462,080	)	$	5,030,545
Liabilities and Partners’ Equity
Payables	$	2,436	$	24,272	$	7,124	$	84,854	$	—		$	118,686
Short-term debt	—		54,000		—		—		—			54,000
Accrued interest payable	—		34,008		—		22		—			34,030
Accrued liabilities	1,070		7,118		10,766		41,531		—			60,485
Taxes other than income tax	125		6,854		3,253		5,453		—			15,685
Income tax payable	—		1,326		5		5,179		—			6,510
Intercompany payable	257,497		—		1,108,703		—		(1,366,200		)	—
Total current liabilities	261,128		127,578		1,129,851		137,039		(1,366,200		)	289,396
Long-term debt	—		2,956,338		—		58,026		—			3,014,364
Deferred income tax liability	—		1,862		13		20,329		—			22,204
Other long-term liabilities	—		34,358		9,436		49,170		—			92,964
Total partners’ equity	1,705,794		567,912		874,629		2,559,162		(4,095,880		)	1,611,617
Total liabilities and partners’ equity	$	1,966,922	$	3,688,048	$	2,013,929	$	2,823,726	$	(5,462,080	)	$	5,030,545

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Condensed Consolidating Statements of Income (Loss)

For the Year Ended December 31, 2017

(Thousands of Dollars)



	NuStar Energy			NuStar Logistics			NuPOP			Non-Guarantor Subsidiaries			Eliminations			Consolidated
Revenues	$	—		$	496,454		$	221,125		$	1,097,458		$	(1,018	)	$	1,814,019
Costs and expenses	1,868			317,871			146,243			1,012,777			(1,018		)	1,477,741
Operating (loss) income	(1,868		)	178,583			74,882			84,681			—			336,278
Equity in earnings (loss) of subsidiaries	149,775			(10,616		)	89,405			158,700			(387,264		)	—
Interest income (expense), net	57			(176,897		)	(5,587		)	9,344			—			(173,083		)
Other income (expense), net	—			145			3			(5,442		)	—			(5,294		)
Income (loss) before income tax (benefit) expense	147,964			(8,785		)	158,703			247,283			(387,264		)	157,901
Income tax (benefit) expense	—			(820		)	2			10,755			—			9,937
Net income (loss)	$	147,964		$	(7,965	)	$	158,701		$	236,528		$	(387,264	)	$	147,964

Condensed Consolidating Statements of Income (Loss)

For the Year Ended December 31, 2016

(Thousands of Dollars)



	NuStar Energy			NuStar Logistics			NuPOP			Non-Guarantor Subsidiaries			Eliminations			Consolidated
Revenues	$	—		$	511,650		$	224,966		$	1,021,804		$	(1,738	)	$	1,756,682
Costs and expenses	1,806			302,099			150,384			945,022			(1,738		)	1,397,573
Operating (loss) income	(1,806		)	209,551			74,582			76,782			—			359,109
Equity in earnings (loss) of subsidiaries	151,794			(13,769		)	82,202			156,036			(376,263		)	—
Interest (expense) income, net	—			(139,827		)	(744		)	2,221			—			(138,350		)
Other income (expense), net	18			(58,264		)	(26		)	(511		)	—			(58,783		)
Income (loss) before income tax expense (benefit)	150,006			(2,309		)	156,014			234,528			(376,263		)	161,976
Income tax expense (benefit)	3			1,607			(23		)	10,386			—			11,973
Net income (loss)	$	150,003		$	(3,916	)	$	156,037		$	224,142		$	(376,263	)	$	150,003

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Condensed Consolidating Statements of Income

For the Year Ended December 31, 2015

(Thousands of Dollars)



	NuStar Energy			NuStar Logistics			NuPOP		Non-Guarantor Subsidiaries		Eliminations			Consolidated
Revenues	$	—		$	547,959		$	215,469	$	1,322,675	$	(2,063	)	$	2,084,040
Costs and expenses	1,717			293,708			140,081		1,259,935		(2,105		)	1,693,336
Operating (loss) income	(1,717		)	254,251			75,388		62,740		42			390,704
Equity in earnings (loss) of subsidiaries	308,437			(7,257		)	120,768		197,760		(619,708		)	—
Interest (expense) income, net	—			(137,847		)	1,611		4,368		—			(131,868		)
Other income, net	—			1,179			5		60,638		—			61,822
Income from continuing operations before income tax (benefit) expense	306,720			110,326			197,772		325,506		(619,666		)	320,658
Income tax (benefit) expense	—			(392		)	23		15,081		—			14,712
Income from continuing operations	306,720			110,718			197,749		310,425		(619,666		)	305,946
Income from discontinued operations, net of tax	—			—			—		774		—			774
Net income	$	306,720		$	110,718		$	197,749	$	311,199	$	(619,666	)	$	306,720

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Condensed Consolidating Statements of Comprehensive Income (Loss)

For the Year Ended December 31, 2017

(Thousands of Dollars)



	NuStar Energy		NuStar Logistics			NuPOP		Non-Guarantor Subsidiaries			Eliminations			Consolidated
Net income (loss)	$	147,964	$	(7,965	)	$	158,701	$	236,528		$	(387,264	)	$	147,964

Other comprehensive income (loss):
Foreign currency translation adjustment	—		—			—		17,466			—			17,466
Net loss on pension and other postretirement benefit adjustments, net of tax benefit	—		—			—		(6,170		)	—			(6,170		)
Net loss on cash flow hedges	—		(2,046		)	—		—			—			(2,046		)
Total other comprehensive (loss) income	—		(2,046		)	—		11,296			—			9,250
Comprehensive income (loss)	$	147,964	$	(10,011	)	$	158,701	$	247,824		$	(387,264	)	$	157,214

Condensed Consolidating Statements of Comprehensive Income

For the Year Ended December 31, 2016

(Thousands of Dollars)



	NuStar Energy		NuStar Logistics			NuPOP		Non-Guarantor Subsidiaries			Eliminations			Consolidated
Net income (loss)	$	150,003	$	(3,916	)	$	156,037	$	224,142		$	(376,263	)	$	150,003

Other comprehensive income (loss):
Foreign currency translation adjustment	—		—			—		(8,243		)	—			(8,243		)
Net loss on pension and other postretirement benefit adjustments, net of tax benefits	—		—			—		(2,850		)	—			(2,850		)
Net gain on cash flow hedges	—		5,710			—		—			—			5,710
Total other comprehensive income (loss)	—		5,710			—		(11,093		)	—			(5,383		)
Comprehensive income	$	150,003	$	1,794		$	156,037	$	213,049		$	(376,263	)	$	144,620

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Condensed Consolidating Statements of Comprehensive Income

For the Year Ended December 31, 2015

(Thousands of Dollars)



	NuStar Energy		NuStar Logistics		NuPOP		Non-Guarantor Subsidiaries			Eliminations			Consolidated
Net income	$	306,720	$	110,718	$	197,749	$	311,199		$	(619,666	)	$	306,720

Other comprehensive income (loss):
Foreign currency translation adjustment	—		—		—		(31,987		)	—			(31,987		)
Net gain on cash flow hedges	—		11,105		—		—			—			11,105
Total other comprehensive income (loss)	—		11,105		—		(31,987		)	—			(20,882		)
Comprehensive income	$	306,720	$	121,823	$	197,749	$	279,212		$	(619,666	)	$	285,838

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Condensed Consolidating Statements of Cash Flows

For the Year Ended December 31, 2017

(Thousands of Dollars)



	NuStar Energy			NuStar Logistics			NuPOP			Non-Guarantor Subsidiaries			Eliminations			Consolidated
Net cash provided by operating activities	$	483,481		$	152,101		$	102,405		$	405,950		$	(737,138	)	$	406,799
Cash flows from investing activities:
Capital expenditures	—			(47,600		)	(35,041		)	(301,997		)	—			(384,638		)
Change in accounts payable related to capital expenditures	—			(1,988		)	5,964			32,927			—			36,903
Acquisitions	—			—			—			(1,461,719		)	—			(1,461,719		)
Proceeds from Axeon term loan	—			110,000			—			—			—			110,000
Proceeds from insurance recoveries	—			—			—			977			—			977
Proceeds from sale or disposition of assets	—			1,955			18			63			—			2,036
Investment in subsidiaries	(1,262,000		)	—			—			(126		)	1,262,126			—
Net cash (used in) provided by investing activities	(1,262,000		)	62,367			(29,059		)	(1,729,875		)	1,262,126			(1,696,441		)
Cash flows from financing activities:
Debt borrowings	—			2,969,400			—			90,700			—			3,060,100
Debt repayments	—			(2,400,739		)	—			(86,800		)	—			(2,487,539		)
Issuance of preferred units, net of issuance costs	538,560			—			—			—			—			538,560
Issuance of common units, net of issuance costs	643,878			—			—			—			—			643,878
General partner contribution	13,737			—			—			—			—			13,737
Distributions to preferred unitholders	(38,833		)	(19,417		)	(19,416		)	(19,418		)	58,251			(38,833		)
Distributions to common unitholders and general partner	(446,306		)	(223,153		)	(223,153		)	(223,176		)	669,482			(446,306		)
Contributions from (distributions to) affiliates	—			1,262,000			—			(9,279		)	(1,252,721		)	—
Net intercompany activity	73,206			(1,801,218		)	169,223			1,558,789			—			—
Other, net	(5,708		)	(1,317		)	—			(300		)	—			(7,325		)
Net cash provided by (used in) financing activities	778,534			(214,444		)	(73,346		)	1,310,516			(524,988		)	1,276,272
Effect of foreign exchange rate changes on cash	—			—			—			1,720			—			1,720
Net increase (decrease) in cash and cash equivalents	15			24			—			(11,689		)	—			(11,650		)
Cash and cash equivalents as of the beginning of the period	870			5			—			35,067			—			35,942
Cash and cash equivalents as of the end of the period	$	885		$	29		$	—		$	23,378		$	—		$	24,292

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Condensed Consolidating Statements of Cash Flows

For the Year Ended December 31, 2016

(Thousands of Dollars)



	NuStar Energy			NuStar Logistics			NuPOP			Non-Guarantor Subsidiaries			Eliminations			Consolidated
Net cash provided by operating activities	$	391,773		$	167,900		$	211,816		$	359,283		$	(694,011	)	$	436,761
Cash flows from investing activities:
Capital expenditures	—			(64,334		)	(52,637		)	(87,387		)	—			(204,358		)
Change in accounts payable related to capital expenditures	—			(10,076		)	(285		)	(702		)	—			(11,063		)
Acquisitions	—			(95,657		)	—			—			—			(95,657		)
Investment in subsidiaries	—			—			(212,900		)	—			212,900			—
Net cash used in investing activities	—			(170,067		)	(265,822		)	(88,089		)	212,900			(311,078		)
Cash flows from financing activities:
Debt borrowings	—			1,365,529			—			41,200			—			1,406,729
Debt repayments	—			(1,419,852		)	—			(36,300		)	—			(1,456,152		)
Issuance of preferred units, net of issuance costs	218,400			—			—			—			—			218,400
Issuance of common units, net of issuance costs	27,710			—			—			—			—			27,710
General partner contribution	680			—			—			—			—			680
Distributions to common unitholders and general partner	(392,962		)	(196,481		)	(196,481		)	(196,501		)	589,463			(392,962		)
Contributions from affiliates	—			—			—			108,352			(108,352		)	—
Net intercompany activity	(241,131		)	255,326			250,487			(264,682		)	—			—
Other, net	(4,485		)	(2,354		)	—			(8,890		)	—			(15,729		)
Net cash (used in) provided by financing activities	(391,788		)	2,168			54,006			(356,821		)	481,111			(211,324		)
Effect of foreign exchange rate changes on cash	—			—			—			2,721			—			2,721
Net (decrease) increase in cash and cash equivalents	(15		)	1			—			(82,906		)	—			(82,920		)
Cash and cash equivalents as of the beginning of the period	885			4			—			117,973			—			118,862
Cash and cash equivalents as of the end of the period	$	870		$	5		$	—		$	35,067		$	—		$	35,942

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Condensed Consolidating Statements of Cash Flows

For the Year Ended December 31, 2015

(Thousands of Dollars)



	NuStar Energy			NuStar Logistics			NuPOP			Non-Guarantor Subsidiaries			Eliminations			Consolidated
Net cash provided by operating activities	$	389,967		$	237,780		$	119,928		$	365,588		$	(588,326	)	$	524,937
Cash flows from investing activities:
Capital expenditures	—			(201,388		)	(39,533		)	(83,887		)	—			(324,808		)
Change in accounts payable related to capital expenditures	—			(4,950		)	33			1,761			—			(3,156		)
Acquisitions	—			—			—			(142,500		)	—			(142,500		)
Proceeds from insurance recoveries	—			—			—			4,867			—			4,867
Proceeds from sale or disposition of assets	—			10,320			22			6,790			—			17,132
Investment in other long-term assets	—			—			—			(3,564		)	—			(3,564		)
Net cash used in investing activities	—			(196,018		)	(39,478		)	(216,533		)	—			(452,029		)
Cash flows from financing activities:
Debt borrowings	—			1,589,131			—			94,500			—			1,683,631
Debt repayments	—			(1,275,910		)	—			(41,000		)	—			(1,316,910		)
Distributions to common unitholders and general partner	(392,204		)	(196,102		)	(196,102		)	(196,122		)	588,326			(392,204		)
Net intercompany activity	2,199			(155,278		)	115,652			37,427			—			—
Other, net	—			(3,605		)	—			(141		)	—			(3,746		)
Net cash used in financing activities	(390,005		)	(41,764		)	(80,450		)	(105,336		)	588,326			(29,229		)
Effect of foreign exchange rate changes on cash	—			—			—			(12,729		)	—			(12,729		)
Net (decrease) increase in cash and cash equivalents	(38		)	(2		)	—			30,990			—			30,950
Cash and cash equivalents as of the beginning of the period	923			6			—			86,983			—			87,912
Cash and cash equivalents as of the end of the period	$	885		$	4		$	—		$	117,973		$	—		$	118,862

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

27. QUARTERLY FINANCIAL DATA (UNAUDITED)

The following table summarizes quarterly financial data for the years ended December 31, 2017 and 2016:



	First Quarter		Second Quarter		Third Quarter		Fourth Quarter			Total
	(Thousands of Dollars, Except Per Unit Data)
2017:
Revenues	$	487,430	$	435,488	$	440,566	$	450,535		$	1,814,019
Operating income	$	97,139	$	73,404	$	91,717	$	74,018		$	336,278
Net income	$	57,940	$	26,250	$	38,592	$	25,182		$	147,964
Basic and diluted net income per common unit	$	0.49	$	0.05	$	0.15	$	—		$	0.64
Cash distributions per unit applicable to common limited partners	$	1.095	$	1.095	$	1.095	$	1.095		$	4.380

2016:
Revenues	$	405,703	$	437,804	$	441,418	$	471,757		$	1,756,682
Operating income	$	94,565	$	91,217	$	87,954	$	85,373		$	359,109
Net income (loss)	$	57,401	$	52,517	$	51,141	$	(11,056	)	$	150,003
Basic and diluted net income (loss) per common unit	$	0.57	$	0.52	$	0.49	$	(0.31	)	$	1.27
Cash distributions per unit applicable to common limited partners	$	1.095	$	1.095	$	1.095	$	1.095		$	4.380

The quarterly financial data in the table above includes the impact of a $58.7 million non-cash impairment charge on the Axeon Term Loan in the fourth quarter of 2016.

28. SUBSEQUENT EVENTS

On February 7, 2018, NuStar Energy, Riverwalk Logistics, L.P., NuStar GP, LLC, Marshall Merger Sub LLC, a wholly owned subsidiary of NuStar Energy (Merger Sub), Riverwalk Holdings, LLC and NuStar GP Holdings entered into an Agreement and Plan of Merger (the Merger Agreement) pursuant to which Merger Sub will merge with and into NuStar GP Holdings with NuStar GP Holdings being the surviving entity (the Merger), such that NuStar Energy will be the sole member of NuStar GP Holdings following the Merger. Pursuant to the Merger Agreement and at the effective time of the Merger, NuStar Energy’s partnership agreement will be amended and restated to, among other things, (i) cancel the incentive distribution rights held by our general partner, (ii) convert the 2% general partner interest in NuStar Energy held by our general partner into a non-economic management interest and (iii) provide the holders of our common units with voting rights in the election of the members of the board of directors of NuStar GP, LLC at an annual meeting, beginning in 2019.

At the effective time of the Merger, each outstanding NuStar GP Holdings common unit, other than those held by NuStar GP Holdings or its subsidiaries, will be converted into the right to receive 0.55 of a NuStar Energy common unit. All NuStar GP Holdings common units, when converted, will cease to be outstanding and will automatically be cancelled and no longer exist. No fractional NuStar Energy common units will be issued in the Merger; instead, each holder of NuStar GP Holdings’ common units otherwise entitled to receive a fractional NuStar Energy common unit will receive cash in lieu thereof. Furthermore, the 10,214,626 NuStar Energy common units currently owned by NuStar GP Holdings will be cancelled and will cease to exist.

At the effective time of the Merger, each outstanding award of NuStar GP Holdings restricted units will be 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 will be determined as provided in the Merger Agreement. Each of our executive officers and directors has agreed and acknowledged that the Merger will not be deemed to trigger a “change of control” as defined under any NuStar Energy or NuStar GP Holdings plan or award, and has waived any rights to vesting, payment or other benefit thereunder that would arise upon a “change of control,” to which he or she might otherwise have been entitled.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

a Unit Majority, as defined in the Second Amended and Restated Limited Liability Company Agreement of NuStar GP Holdings, as amended; (ii) the effectiveness of a registration statement on Form S-4 with respect to the issuance by NuStar Energy of its common units in connection with the Merger; (iii) the absence of certain legal injunctions or impediments prohibiting the transactions; (iv) the receipt of certain tax opinions from a nationally recognized tax counsel; and (v) the approval for the listing of NuStar Energy’s common units to be issued in the Merger on the New York Stock Exchange.

NuStar Energy entered into a Support Agreement, dated as of February 7, 2018 (the Support Agreement), with Merger Sub, WLG Holdings, LLC, a Texas limited liability company controlled by Mr. Greehey (WLG Holdings), Mr. Greehey (together, WLG Holdings and Mr. Greehey are referred to as the Greehey Unitholders), and, for limited purposes, NuStar GP Holdings, pursuant to which the Greehey Unitholders have agreed to vote in favor of the approval and adoption of the Merger Agreement, the approval of the Merger and any other action required in furtherance thereof submitted for the vote or written consent of NuStar GP Holdings unitholders. The Greehey Unitholders collectively own approximately 21% of the outstanding NuStar GP Holdings units. The Support Agreement will terminate (i) at the effective time of the Merger, (ii) upon the termination of the Merger Agreement as provided therein, or (iii) at such time as NuStar Energy and the Greehey Unitholders agree in writing to terminate the Support Agreement.

After the Merger, the NuStar GP, LLC board of directors is expected to consist of nine members, initially composed of the six members of the NuStar GP, LLC board of directors and the three independent directors of the board of directors of NuStar GP Holdings.

Additionally, on February 8, 2018, we announced that our management anticipates recommending to the board of directors of NuStar GP, LLC, and the board of directors expects to adopt, a reset of our quarterly distribution per common unit to $0.60 ($2.40 on an annualized basis), starting with the first-quarter distribution payable in May 2018.

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ITEM 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.


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 (the Exchange Act)) 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, 2017.

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 required by Item 9A. 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.

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PART III


ITEM 10.	DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

DIRECTORS AND EXECUTIVE OFFICERS OF NUSTAR GP, LLC

We do not have directors or officers. The directors and officers of NuStar GP, LLC, the general partner of our general partner, Riverwalk Logistics, L.P., perform all of our management functions. NuStar GP Holdings, the sole member of NuStar GP, LLC, selects the directors of NuStar GP, LLC (the Board) annually. Officers of NuStar GP, LLC are appointed annually by its directors.

As described below in Item 13, on February 7, 2018, NuStar Energy, Riverwalk Logistics, L.P., NuStar GP, LLC, Marshall Merger Sub LLC, a wholly owned subsidiary of NuStar Energy (Merger Sub), Riverwalk Holdings, LLC and NuStar GP Holdings entered into an Agreement and Plan of Merger (the Merger Agreement) pursuant to which Merger Sub will merge with and into NuStar GP Holdings with NuStar GP Holdings being the surviving entity (the Merger), such that NuStar Energy will be the sole member of NuStar GP Holdings following the Merger. Pursuant to the Merger Agreement and at the effective time of the Merger, NuStar Energy’s partnership agreement will be amended and restated to, among other things, provide the holders of NuStar Energy common units with voting rights in the election of the members of the Board of NuStar GP, LLC at an annual meeting, beginning in 2019. After the Merger, the NuStar GP, LLC Board is expected to consist of nine members, initially composed of the six members of the NuStar GP, LLC Board and the three independent directors of the board of directors of NuStar GP Holdings, LLC. The Merger is subject to the satisfaction or waiver of certain conditions, including approval of the Merger Agreement by NuStar GP Holdings unitholders. Please refer to Item 13 for further discussion of the Merger.

Set forth below is certain information concerning the directors and executive officers of NuStar GP, LLC, effective as of February 20, 2018.



Name	Age	Position Held with NuStar GP, LLC
William E. Greehey	81	Chairman of the Board
Bradley C. Barron	52	President, Chief Executive Officer and Director
J. Dan Bates	73	Director
Dan J. Hill	77	Director
Robert J. Munch	66	Director
W. Grady Rosier	69	Director
Mary Rose Brown	61	Executive Vice President and Chief Administrative Officer
Thomas R. Shoaf	59	Executive Vice President and Chief Financial Officer
Jorge A. del Alamo	48	Senior Vice President and Controller
Daniel S. Oliver	51	Senior Vice President-Marketing and Business Development
Amy L. Perry	49	Senior Vice President, General Counsel-Corporate & Commercial Law and Corporate Secretary
Karen M. Thompson	50	Senior Vice President and General Counsel-Litigation, Regulatory & Environmental
Michael Truby	58	Senior Vice President-Operations

As a limited partnership, we are not required by the NYSE rules to have a nominating committee. However, in 2013, the Board created a Nominating/Governance & Conflicts Committee to identify candidates for membership on the Board. The members of the Nominating/Governance & Conflicts Committee are Mr. Rosier (Chairman), Mr. Bates, Mr. Hill and Mr. Munch. In accordance with our Corporate Governance Guidelines, individuals are considered for membership on the Board based on their character, judgment, integrity, diversity, age, skills (including financial literacy), independence and experience in the context of the overall needs of the Board. Our directors are also selected based on their knowledge about our industry and their respective experience leading or advising large companies. We require that our directors have the ability to work collegially, exercise good judgment and think critically. The Nominating/Governance & Conflicts Committee strives to find the best possible candidates to represent the interests of NuStar Energy and its unitholders. As part of its annual self-assessment process, the Nominating/Governance & Conflicts Committee evaluates the mix of independent and non-independent directors, the selection and functions of the presiding director and whether the Board has the appropriate range of talents, expertise and backgrounds.

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The Board is led by its Chairman, Mr. Greehey. Although the Board believes that separating the roles of Chairman and Chief Executive Officer is appropriate in the current circumstances, our Corporate Governance Guidelines do not establish this approach as a policy. The Board also has appointed Mr. Hill as its presiding director to serve as a point of contact for unitholders wishing to communicate with the Board and to lead executive sessions of the non-management directors.

Mr. Greehey became Chairman of the Board in January 2002. He also has been the Chairman of the board of directors of NuStar GP Holdings since March 2006. Mr. Greehey served as Chairman of the board of directors of Valero Energy Corporation (Valero Energy) from 1979 through January 2007. Mr. Greehey was Chief Executive Officer of Valero Energy from 1979 through December 2005, and President of Valero Energy from 1998 until January 2003.

Mr. Barron became President, Chief Executive Officer and a director of NuStar GP, LLC and NuStar GP Holdings in January 2014. He served as Executive Vice President and General Counsel of NuStar GP, LLC and NuStar GP Holdings from February 2012 until his promotion in January 2014. From April 2007 to February 2012, he served as Senior Vice President and General Counsel of NuStar GP, LLC and NuStar GP Holdings. Mr. Barron also served as Secretary of NuStar GP, LLC and NuStar GP Holdings from April 2007 to February 2009. He served as Vice President, General Counsel and Secretary of NuStar GP, LLC from January 2006 until April 2007 and as Vice President, General Counsel and Secretary of NuStar GP Holdings from March 2006 until his promotion in April 2007. He has been with NuStar GP, LLC since July 2003 and, prior to that, was with Valero Energy from January 2001 to July 2003.

Mr. Bates became a director of NuStar GP, LLC in April 2006. He served as President and CEO of the Southwest Research Institute from 1997 until October 2014 and continues to serve as a director and as President Emeritus of the Southwest Research Institute. Mr. Bates also serves as a director of Signature Science L.L.C., Broadway Bank and Broadway Bankshares, Inc. He served as Chairman or Vice Chairman of the board of directors of the Federal Reserve Bank of Dallas’ San Antonio Branch from January 2005 through December 2009.

Mr. Hill became a director of NuStar GP, LLC in July 2004. From February 2001 through May 2004, he served as a consultant to El Paso Corporation. Prior to that, he served as President and CEO of Coastal Refining and Marketing Company. In 1978, Mr. Hill was named as Senior Vice President of the Coastal Corporation and President of Coastal States Crude Gathering. In 1971, he began managing Coastal’s NGL business. Previously, Mr. Hill worked for Amoco and Mobil.

Mr. Munch became a director of NuStar GP, LLC in January 2016. He served as General Manager and Head of Corporate & Investment Banking of Mizuho Bank, Ltd. from 2006 to 2013 and as Deputy General Manager, Origination, of Mizuho Bank, Ltd. from 2005 to 2006. Prior to his service with Mizuho Bank Ltd., Mr. Munch also served in several senior management positions with Canadian Imperial Bank of Commerce and CIBC World Markets from 1980 to 2001 and Fidelity Union Bancorporation (now Wells Fargo) from 1973 to 1980.

Mr. Rosier became a director of NuStar GP, LLC in March 2013. He has been the President and Chief Executive Officer of McLane Company, Inc., a leading supply chain services company and subsidiary of Berkshire Hathaway, Inc., since February 1995. Mr. Rosier has been with McLane Company, Inc. since 1984, serving in various senior management positions prior to his current position. Mr. Rosier also has served as a director of NVR, Inc. since December 2008. He was formerly a director of Tandy Brands Accessories, Inc. from February 2006 to October 2011, serving as the lead director from October 2009 to October 2010.

Ms. Brown became Executive Vice President and Chief Administrative Officer of NuStar GP, LLC and NuStar GP Holdings in April 2013. She served as Executive Vice President - Administration of NuStar GP, LLC and NuStar GP Holdings from February 2012 until her promotion in April 2013. Ms. Brown served as Senior Vice President - Administration of NuStar GP, LLC from April 2008 through February 2012. She served as Senior Vice President - Corporate Communications of NuStar GP, LLC from April 2007 through April 2008. Prior to her service to NuStar GP, LLC, Ms. Brown served as Senior Vice President - Corporate Communications for Valero Energy from September 1997 to April 2007.

Mr. Shoaf became Executive Vice President and Chief Financial Officer of NuStar GP, LLC and NuStar GP Holdings in January 2014. He served as Senior Vice President and Controller of NuStar GP, LLC and NuStar GP Holdings from February 2012 until his promotion in January 2014. Mr. Shoaf served as Vice President and Controller of NuStar GP, LLC from July 2005 to February 2012 and Vice President and Controller of NuStar GP Holdings from March 2006 until February 2012. He served as Vice President - Structured Finance for Valero Corporate Services Company, a subsidiary of Valero Energy, from 2001 until joining NuStar GP, LLC.

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Mr. del Alamo became Senior Vice President and Controller of NuStar GP, LLC and NuStar GP Holdings in July 2014. Prior thereto, he served as Vice President and Controller of NuStar GP, LLC and NuStar GP Holdings since January 2014. He served as Vice President and Assistant Controller of NuStar GP, LLC from July 2010 until his promotion in January 2014. From April 2008 to July 2010 he served as Assistant Controller of NuStar GP, LLC. Prior to his service at NuStar GP, LLC, Mr. del Alamo served as Director-Sarbanes Oxley Compliance for Valero Energy.

Mr. Oliver became Senior Vice President - Marketing and Business Development of NuStar GP, LLC and NuStar GP Holdings in May 2014. Prior thereto, he served as Senior Vice President - Business and Corporate Development of NuStar GP, LLC and NuStar GP Holdings since March 2011. He served as Senior Vice President - Marketing and Business Development of NuStar GP, LLC and NuStar GP Holdings from May 2010 to March 2011 and as Vice President - Marketing and Business Development of NuStar GP, LLC from October 2008 until May 2010 and of NuStar GP Holdings from December 2009 until May 2010. Prior to that, Mr. Oliver served as Vice President for NuStar Marketing LLC. Previously, Mr. Oliver served as Vice President - Product Supply & Distribution for Valero Energy from May 1997 to July 2007.

Ms. Perry became Senior Vice President, General Counsel-Corporate & Commercial Law and Corporate Secretary of NuStar GP, LLC and NuStar GP Holdings in January 2014. She served as Vice President, Assistant General Counsel and Corporate Secretary of NuStar GP, LLC and as Corporate Secretary of NuStar GP Holdings from February 2010 until her promotion in January 2014. From June 2005 to February 2010 she served as Assistant General Counsel and Assistant Secretary of NuStar GP, LLC and, from March 2006 to February 2010, Assistant Secretary of NuStar GP Holdings. Prior to her service at NuStar GP, LLC, Ms. Perry served as Counsel to Valero Energy.

Ms. Thompson became Senior Vice President, General Counsel-Litigation, Regulatory & Environmental of NuStar GP, LLC and NuStar GP Holdings in January 2014. She served as Vice President, Assistant General Counsel and Assistant Secretary of NuStar GP, LLC from February 2010 until her promotion in January 2014. From May 2007 to February 2010 she served as Assistant General Counsel and Assistant Secretary of NuStar GP, LLC. Prior to her service at NuStar GP, LLC, Ms. Thompson served as Managing Counsel to Valero Energy.

Mr. Truby became Senior Vice President - Operations of NuStar GP, LLC in February 2013 and of NuStar GP Holdings in November 2015. Prior thereto, he served as Vice President - Pipeline Operations of NuStar GP, LLC since April 2012 and as Vice President - Health, Safety and Environmental of NuStar GP, LLC from January 2012 until April 2012. Previously he served as Vice President and General Manager of NuStar GP, LLC’s former San Antonio Refinery from May 2011 until January 2012 and led NuStar GP, LLC’s East Region from November 2009 until May 2011.

SECTION 16(a) BENEFICIAL OWNERSHIP REPORTING COMPLIANCE

Section 16(a) of the Exchange Act requires directors, executive officers and persons who beneficially own more than 10% of NuStar Energy’s equity securities to file certain reports with the Securities and Exchange Commission (SEC) concerning their beneficial ownership of NuStar Energy’s equity securities. We believe that our directors, executive officers and greater than 10% unitholders have filed all Section 16(a) reports by the applicable deadlines with respect to the year ended December 31, 2017.

CODE OF ETHICS OF SENIOR FINANCIAL OFFICERS

NuStar GP, LLC has adopted a Code of Ethics for Senior Financial Officers that applies to NuStar GP, LLC’s principal executive officer, principal financial officer and controller. A copy of the code is available on NuStar Energy’s website at www.nustarenergy.com. This code charges the senior financial officers with responsibilities regarding honest and ethical conduct, the preparation and quality of the disclosures in documents and reports we file with or submit to the SEC, compliance with applicable laws, rules and regulations, adherence to the code and reporting of violations of the code. We also have a Code of Business Conduct and Ethics that applies to all of our employees and directors.

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CORPORATE GOVERNANCE

AUDIT COMMITTEE

The Audit Committee reviews and reports to the Board on various auditing and accounting matters, including the quality, objectivity and performance of NuStar Energy’s internal and external accountants and auditors, the adequacy of its financial controls and the reliability of financial information reported to the public. The Audit Committee also monitors NuStar Energy’s compliance with environmental laws and regulations. The Board has adopted a written charter for the Audit Committee, a copy of which is available on NuStar Energy’s website at www.nustarenergy.com. The members of the Audit Committee are Mr. Bates (Chairman), Mr. Hill, Mr. Munch and Mr. Rosier. The Board has determined that Mr. Bates is an “audit committee financial expert” (as defined by the SEC), and that each member of the Audit Committee is “independent” as that term is used in the NYSE Listing Standards and described below in Item 13. The Audit Committee met eight times during 2017. For further information, see the Audit Committee Report below.

AUDIT COMMITTEE REPORT

Management of NuStar GP, LLC is responsible for NuStar Energy’s internal controls and the financial reporting process. KPMG LLP (KPMG), NuStar Energy’s independent registered public accounting firm for the year ended December 31, 2017, is responsible for performing an independent audit of NuStar Energy’s consolidated financial statements in accordance with the standards of the Public Company Accounting Oversight Board (PCAOB) and generally accepted auditing standards, and an audit of NuStar Energy’s internal control over financial reporting in accordance with the standards of the PCAOB, and issuing a report thereon. The Audit Committee monitors and oversees these processes and approves the selection and appointment of NuStar Energy’s independent registered public accounting firm and recommends the ratification of such selection and appointment to the Board.

The Audit Committee has reviewed and discussed NuStar Energy’s audited consolidated financial statements with management and KPMG. The Audit Committee has discussed with KPMG the matters required to be discussed by Auditing Standard 1301, “Communications with Audit Committees,” issued by the PCAOB. The Audit Committee has received written disclosures and the letter from KPMG required by applicable requirements of the PCAOB concerning independence and has discussed with KPMG its independence.

Based on the foregoing review and discussions and such other matters the Audit Committee deemed relevant and appropriate, the Audit Committee recommended to the Board that the audited consolidated financial statements of NuStar Energy be included in NuStar Energy’s Annual Report on Form 10-K for the year ended December 31, 2017.

Members of the Audit Committee:

J. Dan Bates (Chairman)

Dan J. Hill

Robert J. Munch

W. Grady Rosier

RISK OVERSIGHT

Although it is the job of management to assess and manage our risk, the Board of Directors and its Audit Committee (each where applicable) discuss the guidelines and policies that govern the process by which risk assessment and management is undertaken and evaluate reports from various functions with the management team on risk assessment and management. The Board interfaces regularly with management and receives periodic reports that include updates on operational, financial, legal and risk management matters. The Audit Committee assists the Board in oversight of the integrity of NuStar Energy’s financial statements and NuStar Energy’s compliance with legal and regulatory requirements, including those related to the health, safety and environmental performance of our company. The Audit Committee also reviews and assesses the performance of NuStar Energy’s internal audit function and its independent auditors. The Board receives regular reports from the Audit Committee. For a description of our oversight and evaluation of compensation risk, see “Evaluation of Compensation Risk” in Item 11 below.

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ITEM 11. EXECUTIVE COMPENSATION

COMPENSATION COMMITTEE

The Compensation Committee reviews and reports to the Board on matters related to compensation strategies, policies and programs, including certain personnel policies and policy controls, management development, management succession and benefit programs. The Compensation Committee also conducts periodic reviews of director compensation and makes recommendations to the Board regarding director compensation. The Compensation Committee also approves and administers NuStar Energy’s equity compensation plans and incentive bonus plan. The Board has adopted a written charter for the Compensation Committee, a copy of which is available on NuStar Energy’s website at www.nustarenergy.com. The members of the Compensation Committee are Mr. Hill (Chairman), Mr. Bates, Mr. Munch and Mr. Rosier, none of whom is a current or former employee or officer of NuStar GP, LLC and each of whom has been determined by the Board to be “independent,” as described below in Item 13. The Compensation Committee met four times during 2017.

COMPENSATION COMMITTEE REPORT

The Compensation Committee has reviewed and discussed the Compensation Discussion and Analysis with management. Based on its review and discussion and such other matters the Compensation Committee deemed relevant and appropriate, the Compensation Committee recommended to the Board that the Compensation Discussion and Analysis be included in this Annual Report on Form 10-K.

Members of the Compensation Committee:

Dan J. Hill (Chairman)

J. Dan Bates

Robert J. Munch

W. Grady Rosier

COMPENSATION DISCUSSION AND ANALYSIS

EXECUTIVE COMPENSATION PHILOSOPHY

Our philosophy for compensating our named executive officers (NEOs) is based on the belief that a significant portion of executive compensation should be incentive-based and determined by both the performance of NuStar Energy and the executive’s individual performance objectives. Our executive compensation programs are designed to accomplish the following long-term objectives:


•	increase value to unitholders, while practicing good corporate governance;


•	support our business strategy and business plan by clearly communicating what is expected of executives with respect to goals and results;


•	provide the Compensation Committee with the flexibility to respond to the continually changing environment in which NuStar Energy operates;


•	align executive incentive compensation with NuStar Energy’s short- and long-term performance results; and


•	provide market-competitive compensation and benefits to enable us to recruit, retain and motivate the executive talent necessary to produce sustainable growth for our unitholders.

Compensation for our NEOs primarily consists of base salary, an annual incentive bonus and long-term, equity-based incentives, which we refer to as “Total Direct Compensation.” Our NEOs participate in the same group benefit programs available to our salaried employees in the United States, and each NEO’s incentive bonus is awarded in accordance with the same bonus plan and metric that we use for each of our other employees. In addition, as discussed under “Post-Employment Benefits” below, our NEOs may participate in certain non-qualified, retirement-related programs. Our NEOs do not have employment or severance agreements, other than the change of control severance agreements described under “Potential Payments Upon Termination or Change of Control” in this Item 11. The Compensation Committee targets base salary for our NEOs, as well as annual incentive bonus and long-term incentive opportunities (expressed, in each case, as a percentage of base salary), with reference to prevailing practices of our peer companies and information from survey sources. In determining total compensation, as well as each component thereof, we consider the unique responsibilities of each individual’s position, as well as his or her experience and performance, together with the market information.

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Our NEOs for the year ended December 31, 2017 were:


•	Bradley C. Barron, President and Chief Executive Officer (CEO);


•	Thomas R. Shoaf, Executive Vice President and Chief Financial Officer;


•	Mary Rose Brown, Executive Vice President and Chief Administrative Officer;


•	Daniel S. Oliver, Senior Vice President-Marketing and Business Development; and


•	Michael Truby, Senior Vice President-Operations.

ADMINISTRATION OF EXECUTIVE COMPENSATION PROGRAMS

Our executive compensation programs are administered by our Board’s Compensation Committee. The Compensation Committee is composed of independent directors who are not participants in our executive compensation programs. Policies adopted by the Compensation Committee are implemented by our Human Resources department.

The Compensation Committee considers market trends in compensation, including the practices of identified competitors, and the alignment of the compensation program with NuStar Energy’s strategy. Specifically, for our NEOs, the Compensation Committee:


•	establishes and approves target compensation levels for each NEO;


•	approves company performance measures and goals;


•	determines the mix between cash and equity compensation, short-term and long-term incentives and benefits;


•	verifies the achievement of previously established performance goals; and


•	approves the resulting cash or equity awards to our NEOs.

In making determinations about Total Direct Compensation for our NEOs, the Compensation Committee takes into account a number of factors, including:


•	the competitive market for talent;


•	compensation paid at peer companies;


•	industry-wide trends;


•	NuStar Energy’s performance;


•	the particular NEO’s role, responsibilities, experience and performance; and


•	retention.

The Compensation Committee also considers other equitable factors such as the role, contribution and performance of an individual relative to his or her peers at the company. The Compensation Committee does not assign specific weight to these factors, but rather makes a subjective judgment taking all of these factors into account.

During 2017, the Compensation Committee retained Energy Partners Pay Advisors (EPPA) as its independent compensation consultant for expertise and guidance with respect to executive compensation matters. In its role as advisor to the Compensation Committee, EPPA was retained directly by the Compensation Committee, which has the authority to select, retain and/or terminate its relationship with a consulting firm. The Compensation Committee determined that there are no conflicts of interest between the company, the Compensation Committee and EPPA because: EPPA provides no other services to NuStar Energy; EPPA has policies in place to prevent a conflict of interest, including a policy that no employee of EPPA may own NuStar Energy units; and there is no business or personal relationship between EPPA’s consultant and any of NuStar Energy’s officers or directors.

Selection of Compensation Comparative Data

To establish compensation for each of the NEOs, the Compensation Committee consults with management and EPPA and considers compensation provided by certain peer companies when evaluating competitive levels of compensation. The competitive data regarding the peer companies is derived from their respective publicly filed annual proxy statements or Annual Reports on Form 10-K.

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Following the sale of our remaining 50% interest in the asphalt business during 2014, the Compensation Committee consulted with management and the Compensation Committee’s independent compensation consultant at the time, reevaluated our peer group and removed the independent refining companies that were previously included in our peer group (the 2014 Compensation Comparative Group). Since that time, several of the companies in the peer group have merged, consolidated or otherwise no longer publicly disclose comprehensive executive compensation information. Due to the changes in the midstream and logistics industry since 2014, the Compensation Committee consulted with management and EPPA and updated our peer group again in 2017 to: (1) remove entities that have been acquired or otherwise no longer publicly disclose comprehensive executive compensation information; (2) remove sponsored master limited partnerships (MLPs) for which the executives’ primary responsibility relates to the sponsor’s operations rather than the operations of the MLP; (3) add other comparable midstream and/or logistics entities; and (4) recognize the scope of responsibility of executive teams that manage two public companies, similar to NuStar Energy and NuStar GP Holdings (the Current Compensation Comparative Group).

The tables below list: (1) the companies in the 2014 Compensation Comparative Group after giving effect to all merger or consolidation transactions that closed prior to December 31, 2017 (with the relevant transactions described in the footnote); and (2) the companies in the Current Compensation Comparative Group.

2014 Compensation Comparative Group



Company ⁽¹⁾	Ticker
1. Andeavor Logistics LP (previously known as Tesoro Logistics LP)	ANDX
2. Arc Logistics Partners LP	ARCX
3. Boardwalk Pipeline Partners, LP	BWP
4. Buckeye Partners, L.P.	BPL
5. Enable Midstream Partners, LP	ENBL
6. Enbridge Energy Partners, L.P.	EEP
7. Energy Transfer Partners, L.P.	ETP
8. EnLink Midstream Partners, LP	ENLK
9. Enterprise Products Partners L.P.	EPD
10. Genesis Energy, L.P.	GEL
11. Holly Energy Partners, L.P.	HEP
12. Magellan Midstream Partners, L.P.	MMP
13. MPLX LP	MPLX
14. Phillips 66 Partners LP	PSXP
15. Plains All American Pipeline, L.P.	PAA
16. Valero Energy Partners LP	VLP

(1) The following companies have been removed from the 2014 Compensation Comparative Group originally established in July 2014 as a result of the transactions described in this footnote: Access Midstream Partners, L.P. merged with Williams Partners L.P. in February 2015; Atlas Pipeline Partners, L.P. was acquired by Targa Resources Partners LP in February 2015; Kinder Morgan Energy Partners, L.P. was acquired by Kinder Morgan, Inc. in November 2014; MarkWest Energy Partners, L.P. was acquired by MPLX LP in December 2015; Regency Energy Partners LP was acquired by Energy Transfer Partners, L.P. in April 2015; Targa Resources Partners LP was acquired by Targa Resources Corp. in February 2016; Energy Transfer Partners, L.P. merged with Sunoco Logistics Partners L.P. in April 2017; and Western Refining Logistics, LP was acquired by Andeavor Logistics LP in October 2017.

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Current Compensation Comparative Group



Company	Ticker
1. Boardwalk Pipeline Partners, LP	BWP
2. Buckeye Partners, L.P.	BPL
3. Calumet Specialty Products Partners, L.P.	CLMT
4. Enable Midstream Partners, LP	ENBL
5. Enbridge Energy Partners, L.P./Enbridge Energy Management, L.L.C.	EEP/EEQ
6. Energy Transfer Partners, L.P. /Energy Transfer Equity, L.P. ⁽¹⁾	ETP/ETE
7. EnLink Midstream Partners, LP/EnLink Midstream, LLC	ENLK/ENLC
8. Enterprise Products Partners L.P.	EPD
9. Genesis Energy, L.P.	GEL
10. Holly Energy Partners, L.P.	HEP
11. Magellan Midstream Partners, L.P.	MMP
12. MPLX LP	MPLX
13. ONEOK, Inc. (includes operations of ONEOK Partners, L.P.)	OKE
14. SemGroup Corporation	SEMG
15. Sunoco Logistics Partners L.P. ⁽¹⁾	SXL
16. Targa Resources Corp. (includes operations of Targa Resources Partners LP)	TRGP

(1)

Although Energy Transfer Partners, L.P. and Sunoco Logistics Partners L.P. merged in April 2017, both entities are listed as separate peer companies in the Current Compensation Comparative Group because their executive compensation for the year ended December 31, 2016 was publicly disclosed separately and considered along with the compensation of the other peer companies as part of the evaluation of our 2017 compensation.

At the Compensation Committee’s request, EPPA also reviews survey data reported on a position-by-position basis to obtain additional information regarding compensation of comparable positions. The survey data consists of general industry data for specific executive positions reported in published executive compensation surveys. We refer to the competitive survey data, together with the 2014 Compensation Comparative Group data or the Current Compensation Comparative Group data, as applicable, as the “Compensation Comparative Data.”

Process and Timing of Compensation Decisions

The Compensation Committee reviews and approves all compensation of the NEOs. The CEO develops recommendations for the compensation of the other NEOs in consultation with our Human Resources department and with EPPA. In making these recommendations, the CEO considers the Compensation Comparative Data and evaluates the individual performance of each NEO and their respective contributions to NuStar Energy. The recommendations are then reviewed by the Compensation Committee, which may accept the recommendations or may make adjustments to the recommended compensation based on the Compensation Committee’s assessment of the individual’s performance and contributions to NuStar Energy.

As required by the Compensation Committee’s charter, the CEO’s compensation is reviewed and approved by the Compensation Committee based on the Compensation Comparative Data and the Compensation Committee’s independent evaluation of the CEO’s contributions to NuStar Energy’s performance.

Each July, the Compensation Committee reviews each NEO’s Total Direct Compensation, including base salary and the target levels of annual incentive and long-term incentive compensation. The review includes a comparison with competitive market data provided by EPPA (as described above), an evaluation of the Total Direct Compensation of the NEOs from an internal equity perspective and a review of reports on the compensation history of each NEO. Based on these reviews and evaluations, the Compensation Committee establishes annual salary rates for each NEO for the upcoming 12-month period and sets target levels of annual incentive and long-term incentive compensation. Although the target levels are established in July, the long-term incentives are reviewed again at the time of grant, typically in the fourth quarter for restricted units and in the first quarter for performance units. The Compensation Committee also may review salaries or grant long-term incentive awards at other times during the year because of new appointments, promotions or other extraordinary circumstances.

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The following table summarizes the typical timing of some of our significant compensation events.



Event	Timing
- Establish financial performance objectives for the current year’s annual incentive bonus - Evaluate achievement of the bonus metric for the prior year - Review prior year financial performance for performance units - Grant performance units for the current year	First quarter
- Review NEO base salaries and targets for annual incentive bonus and long-term incentive grants for the current year	Third quarter
- Grant restricted units to employees, including the NEOs - Grant restricted units to non-employee directors pursuant to the director compensation program - Set meeting dates for action by the Compensation Committee for the upcoming year	Fourth quarter

Additional information regarding the timing of the 2017 long-term incentive grants is discussed below under “Restricted Units” and “Performance Units.”

ELEMENTS OF EXECUTIVE COMPENSATION

Compensation for our NEOs primarily consists of the following elements, which we refer to as Total Direct Compensation:



	Element	Form	Purpose
Fixed	Base Salary	Cash	- Foundation of the executive compensation program - Provides a fixed level of competitive pay - Reflects the individual’s primary duties and responsibilities - Foundation for incentive opportunities and benefit levels
At-Risk	Annual Incentive Bonus	Cash	- Focus NEOs on improving performance
At-Risk	Long-Term Equity-Based Incentives:	Units	- Directly tie NEO financial reward opportunities with the rewards to unitholders, as measured by long-term unit price performance and payment of distributions
	- Restricted Units		- Time-vesting award focused on retention and increasing ownership levels
	- Performance Units		- Performance-vesting award focused on attainment of objective performance measure

We also offer group medical and other insurance benefits to provide our employees (including our NEOs) affordable coverage at group rates, as well as pension benefits that reward continued service and a thrift plan that provides a tax-advantaged savings opportunity.

Relative Size of Primary Elements of Compensation

In setting compensation, the Compensation Committee considers the aggregate amount of compensation payable to each NEO and the form of the compensation. The Compensation Committee seeks to achieve the appropriate balance between salary, cash rewards earned for the achievement of company and personal objectives, and long-term incentives that align the interests of our NEOs with those of our unitholders. The size of each element is based on competitive market practices, as well as company and individual performance.

As illustrated by the chart below, the level of at-risk incentive compensation typically increases in relation to an NEO’s responsibilities, with the level of incentive compensation for more senior executive officers being a greater percentage of Total Direct Compensation than for less senior executives. The Compensation Committee believes that tying a significant portion of an NEO’s incentive compensation to NuStar Energy’s performance more closely aligns the NEO’s interests with those of our unitholders.

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Because we place such a large percentage of our Total Direct Compensation at risk in the form of variable pay (i.e., annual and long-term incentives), the Compensation Committee does not adjust current compensation based upon realized gains or losses from prior incentive awards. For example, we will not reduce the size of a target long-term incentive grant in a particular year solely because NuStar Energy’s unit price performed well during the immediately preceding years. We believe that adopting a policy of making such adjustments would penalize management’s current compensation for NuStar Energy’s prior success.

Individual Performance and Personal Objectives

The Compensation Committee evaluates our NEOs’ individual performance and personal objectives with input from our CEO. Our CEO’s performance is evaluated by the Compensation Committee in consultation with other members of the Board.

Assessment of individual performance may include objective criteria, but is a largely subjective process. The criteria used to measure an individual’s performance may include use of quantitative criteria (e.g., execution of projects within budget, improving an operating unit’s profitability, or timely completion of an acquisition or divestiture), as well as more qualitative factors, such as the NEO’s ability to lead, communicate and successfully adhere to NuStar Energy’s core values (i.e., environmental and workplace safety, integrity, work commitment, effective communication and teamwork). There are no specific weights given to any of these various elements of individual performance.

The Compensation Committee uses its evaluation of individual performance to supplement the objective compensation criteria and adjust an NEO’s recommended compensation. For example, although an individual’s indicated bonus may be calculated to be $100,000 based on NuStar Energy’s performance, the individual’s performance evaluation might result in a reduction or increase in that amount.

Base Salaries

The Compensation Committee reviews the base salaries for our NEOs annually based on recommendations by our CEO, with input from EPPA and our Human Resources department. Our CEO’s base salary is reviewed and approved by the Compensation Committee based on its review of recommendations by EPPA, our Chairman and our Human Resources department.

The competitiveness of base salaries for each NEO’s position is determined by an evaluation of the Compensation Comparative Data described above. Base salaries may be adjusted to achieve what is determined to be a reasonably competitive level or to reflect promotions, the assignment of additional responsibilities, individual performance or the performance of NuStar Energy.

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Following a detailed analysis performed in July 2014 by the Compensation Committee’s independent compensation consultant at the time, for 2015 and 2016 base salaries the Compensation Committee considered, among other factors, the Consumer Price Index, the average base salary increase anticipated by nationwide compensation surveys, the increases required by NuStar Energy’s union contracts and the anticipated increases by other local companies and raised the base salaries of each of the NEOs effective on each of July 1, 2015 and July 1, 2016 to remain competitive.

During July 2017, EPPA performed a comprehensive review of our NEOs’ Total Direct Compensation. After consultation with EPPA, the Chairman (in the case of the CEO’s base salary) and the CEO (in the case of the base salaries for each other NEO), the Compensation Committee raised the base salaries of each of the NEOs effective July 1, 2017 to remain competitive. The July 1, 2017 increases and the December 31, 2017 base salaries for each of the NEOs are presented in the table below.



Name	Annualized Base Salary at December 31, 2017 ($)	July 1, 2017 Increase to Prior Annualized Salary ($)
Barron	592,250	17,250
Shoaf	360,200	10,500
Brown	388,000	11,300
Oliver	328,000	9,700
Truby	305,000	24,400

Annual Incentive Bonus

Our NEOs participate in the same annual incentive program in which all of our domestic employees participate. Under our annual bonus plan, participants can earn annual incentive bonuses based on the following three factors:


•	The individual’s position, which is used to determine a targeted percentage of annual base salary that may be awarded as incentive bonus. Generally, the target amount for the NEOs is set following the analysis of market practices in the Compensation Comparative Group with reference to the median bonus target available to comparable executives in those companies;


•	NuStar Energy’s attainment of specific quantitative financial goals, which are established by the Compensation Committee during the first quarter of the year; and


•	A discretionary evaluation by the Compensation Committee of both NuStar Energy’s performance and, in the case of the NEOs, the individual’s performance.

In July 2015, after consultation with the Compensation Committee’s independent compensation consultant at the time and the Chairman, the Compensation Committee raised the annual incentive bonus target for Mr. Barron from 90% to 100%. The Compensation Committee did not make any changes to the annual incentive bonus target for Mr. Barron during 2016 or for any of the other NEOs serving as such during 2015 or 2016. In July 2017, following EPPA’s comprehensive review of our NEOs’ Total Direct Compensation, the Compensation Committee raised the annual incentive bonus target for Mr. Truby from 50% to 55% and retained the existing annual incentive bonus targets for all other NEOs. The following table shows each NEO’s annual incentive bonus target for the fiscal year ended December 31, 2017 (expressed as a percent of base salary paid).



Name	Annual Incentive Bonus Target (% of base salary)
Barron	100
Shoaf	60
Brown	60
Oliver	55
Truby	55

Determination of Annual Incentive Target Opportunities

As illustrated in the table above, each NEO has an annual incentive opportunity generally based on a stated percentage of his or her salary paid that year. The target amount is awarded for achieving a 100% score on our stated financial goal under the annual bonus plan. For example, in a year with a 100% score, an NEO paid $200,000 with a target annual incentive opportunity equal to 60% of his base salary paid would be eligible to receive a bonus of $120,000 based on those financial goals.

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Once the financial goals have been reviewed and measured, the Compensation Committee has the authority to exercise its discretion in evaluating NuStar Energy’s performance. In exercising this discretionary judgment, the Compensation Committee considers such relevant performance factors as growth, attainment of strategic objectives, acquisitions and divestitures, safety and environmental compliance, as well as other considerations. This discretionary judgment may result in an increase or decrease to the aggregate earned award for all employees that is based upon the attainment of NuStar Energy’s financial goals.

The CEO develops individual incentive bonus recommendations for the other NEOs based upon the methodology described above. In addition, both the CEO and the Compensation Committee may make adjustments to the recommended incentive bonus amounts based upon an assessment of an individual’s performance and contributions to NuStar Energy. The CEO and the Compensation Committee also review and discuss each NEO’s bonus on a case-by-case basis, considering such factors as teamwork, leadership, individual accomplishments and initiative, and may adjust the bonus awarded to a specific NEO to reflect these factors.

The bonus target for the CEO is decided solely by the Compensation Committee, and the Compensation Committee may make discretionary adjustments to the calculated level of bonus for the CEO based upon its independent evaluation of the CEO’s performance and contributions.

Company Performance Objectives

As in prior years, our annual incentive bonus for 2017 was designed to focus our NEOs on improving NuStar Energy’s distributable cash flow (DCF). In the MLP investment community, DCF is widely regarded as a significant indicator of operating performance. As such, the Compensation Committee believes the measure appropriately aligns our management’s interest with our unitholders’ interest.

For 2017, the Compensation Committee determined that a bonus pool for all employees would be established based on DCF such that employees would receive a 100% bonus for 2017 if NuStar Energy achieved a target distribution coverage ratio (DCR) of 1.01 times. After achieving a 100% bonus, incremental DCF earned would be shared between the bonus pool and NuStar Energy until employees achieve a 200% bonus. If DCR for 2017 is below 1.00 times, the bonus pool would be reduced dollar-for-dollar until a 1.00 times DCR is achieved or the pool is reduced to $0. The Compensation Committee has discretion to raise or lower the incentive opportunity resulting from this calculation by 25%. In addition, the budgeted DCF may be adjusted during the year in order to account for acquisitions or other significant changes not anticipated at the time the target was determined.

DCF and DCR are non-GAAP measures of performance. We derive DCF from our financial statements by adjusting our net income for depreciation and amortization expense, unrealized gains and losses arising from certain derivative contracts and other non-cash items, including non-cash gains or losses or impairment charges. We further adjust our earnings by (1) subtracting our aggregate annual reliability capital expenditures, (2) adding non-cash unit-based compensation expenses for awards that we intend to satisfy with the issuance of units upon vesting and (3) adding or subtracting, as applicable, certain cash receipts and disbursements not included in net income. DCR is determined by dividing DCF applicable to common limited partners by the distributions applicable to common limited partners.

Determination of Awards

Our executive officers, including our NEOs, did not receive cash bonuses for 2017. For the 2017 annual incentive bonus determination, the Compensation Committee reviewed NuStar Energy’s DCF against the established target of attaining a DCR of 1.01 times and considered NuStar Energy’s overall performance and the performance of each NEO. Based solely on our 2017 DCR results, our NEOs were not eligible to receive a bonus award for 2017 under the annual incentive bonus plan. The Compensation Committee recognized NuStar Energy’s significant accomplishments during 2017, including the successful acquisition of the Permian Crude System and NuStar Energy’s achievement of its best safety record in the history of the company, with only one employee recordable injury and zero lost-time injuries. The Compensation Committee also considered the strain on the business and the MLP sector generally from continued low crude oil prices and the further negative impact on NuStar Energy of several unexpected items, such as losses at seven facilities impacted by five hurricanes, losses resulting from unplanned turnarounds and downtime at customers’ refineries, a decline in results at our St. Eustatius terminal from under-utilization by an important customer there due to deteriorating conditions in Venezuela and the expense of an unanticipated reliability project on our Ammonia Pipeline.

After considering our 2017 DCR results and these additional factors, upon the recommendation of executive management (other than with respect to the CEO) and our Chairman (with respect to the CEO), the Compensation Committee decided not to award cash bonuses under the annual incentive bonus plan for any of our executive officers, including our NEOs, for 2017.

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Long-Term Incentive Awards

We provide unit-based, long-term incentive compensation for employees, including our NEOs, and for our non-employee directors through our 2000 Long-Term Incentive Plan (as amended and restated from time to time, the 2000 LTIP). The 2000 LTIP provides for unit awards and a variety of unit-based awards, including unit options, restricted units and performance units. Long-term incentive awards vest over a period determined by the Compensation Committee, with performance units vesting upon the achievement of an objective performance goal.

Under the design of our long-term incentive awards, a target long-term incentive award opportunity expressed as a percentage of base salary is established for each plan participant, including each NEO. This percentage reflects the fair value of the awards to be granted.

The Compensation Committee did not make any changes to the individual long-term incentive target percentages for our NEOs serving as such during 2015 or 2016. In July 2017, following EPPA’s comprehensive review of our NEOs’ Total Direct Compensation, the Compensation Committee raised the long-term incentive targets for Mr. Barron from 200% to 250%, for Mr. Shoaf and Ms. Brown from 150% to 180% and for Mr. Truby from 100% to 125%, and retained the existing target for Mr. Oliver. The following table shows each NEO’s long-term incentive target for 2017 (expressed as a percent of base salary).



Name	Long-Term Incentive Target (% of base salary)
Barron	250
Shoaf	180
Brown	180
Oliver	125
Truby	125

The Compensation Committee allocates a percentage of long-term incentive award value to performance-based awards and a percentage to awards that focus on retention and increasing ownership levels of executive officers (including our NEOs). Since the fourth quarter of 2011, the target levels of long-term incentive award value have been allocated in the following manner:


•	35% performance units; and


•	65% restricted units.

The Compensation Committee reviews and approves long-term incentive grants for each of the NEOs. The CEO develops individual grant recommendations for the other NEOs based upon the methodology described above, but both the CEO and the Compensation Committee may make adjustments to the recommended grants based upon an assessment of an individual’s performance and contributions to NuStar Energy. Grants to the CEO are decided solely by the Compensation Committee following the methodology described above, and the Compensation Committee may make discretionary adjustments to the calculated level of long-term incentives for the CEO based upon its independent evaluation of the CEO’s performance and contributions.

Restricted Units

Restricted units comprise approximately 65% of each NEO’s total NuStar Energy long-term incentive target. The Compensation Committee expects to grant restricted units on an annual basis. In 2017, the NEOs’ long-term incentive targets included approximately 70% NuStar Energy restricted units to be granted by the Compensation Committee under the 2000 LTIP and 30% NuStar GP Holdings phantom units (which we refer to as “restricted units” in Part III of this Annual Report on Form 10-K) to be granted by NuStar GP Holdings’ compensation committee under its long-term incentive plan. In both cases, no units are issued at the time of grant and the awards represent the right to receive common units upon vesting. The awards are calculated from an assumed unit value based on the average closing price of the common units for the first 10 business days of the month prior to the committee meeting at which the awards are to be approved. The restricted units all vest over five years in equal increments on the anniversary of the grant date, and common unit distribution equivalents are paid in cash quarterly for all unvested NuStar Energy and NuStar GP Holdings restricted units. Restricted units of NuStar GP Holdings were introduced into the compensation program in 2008 to reflect the fact that the performance of NuStar GP Holdings is directly tied to the performance of NuStar Energy since NuStar GP Holdings’ sole asset is its interest in NuStar Energy. As described under “Accounting Treatment” below, effective March 1, 2016, NuStar GP Holdings retains the expense associated with the NuStar GP Holdings restricted unit awards.

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The annual grants of NuStar GP Holdings restricted units, as well as the annual grants of NuStar Energy restricted units, were approved in a joint meeting of the Compensation Committee and the compensation committee of NuStar GP Holdings’ board of directors on October 18, 2017. The committees determined that the grants would be made as soon as administratively practicable and no earlier than the third business day following our third quarter earnings release. Due to the time required to award and implement the grants, the 2017 annual grants were not effective until November 16, 2017. The following table sets forth the restricted units granted to each of our NEOs in 2017.



Name	Restricted Units Granted in 2017
Name	NuStar Energy	NuStar GP Holdings
Barron	16,660	13,315
Shoaf	7,295	5,830
Brown	7,860	6,280
Oliver	4,615	3,690
Truby	4,290	3,430

For more information regarding the 2017 restricted unit grants, see the table entitled “Grants of Plan-Based Awards During the Year Ended December 31, 2017.”

Performance Units

Performance units comprise approximately 35% of each NEO’s total NuStar Energy long-term incentive target and typically have been awarded in the first quarter of each year. The number of performance units awarded is determined by multiplying the annual base salary rate by the NEO’s long-term incentive target percentage, and then multiplying that product by 35%. That product is divided by the assumed value of an individual unit, which is the product of (x) the average common unit price for the period of December 15 through December 31 (using the daily closing prices) and (y) a factor reflecting the risk that the award might be forfeited.

Performance units are earned only upon NuStar Energy’s achievement of an objective performance measure for the performance period. The Compensation Committee believes this type of incentive award strengthens the tie between each NEO’s pay and our financial performance.

Since 2014, the target performance measure for performance unit awards has been NuStar Energy achieving a specific DCR, after taking into account the aggregate expense of the performance units. As described above, the Compensation Committee believes that distribution coverage appropriately aligns our NEOs’ interest with our unitholders’ interest.

Performance units are awarded pursuant to the 2000 LTIP, with each award subject to vesting in three annual increments (or tranches), based upon our DCR during the one-year performance periods that end on December 31 of each year following the date of grant, as illustrated in the table below.



Annual Performance Target	2015 Target= DCR 1.01 : 1	2016 Target= DCR 1.03 : 1	2017 Target= DCR 1.01 : 1
2015 Award Tranche Eligible to Vest	1st	2nd	3rd
2016 Award Tranche Eligible to Vest	N/A	1st	2nd
2017 Award Tranche Eligible to Vest	N/A	N/A	1st
Performance Achieved for One-Year Performance Period	1.11 : 1	1.07 : 1	0.63 : 1
Percent of Eligible Units Vested for One-Year Performance Period	200%	150%	0%

If the DCR falls between the benchmarks established by the Compensation Committee for the performance period, the percentage vesting with respect to performance during that period will be determined through straight-line interpolation. The Compensation Committee retains the full discretion to vest up to 200% of performance units available for vesting, regardless of the DCR that NuStar Energy attains for the applicable performance period. As illustrated in the table above, performance units did not vest with respect to 2017 performance and vested at the 150% and 200% levels with respect to 2016 and 2015 performance, respectively. Additional information is provided below regarding the performance targets established by the Compensation Committee and the performance attained by NuStar Energy for each of the 2015, 2016 and 2017 performance periods.

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•	2015 Performance Period. The target measure established by the Compensation Committee on January 29, 2015 for performance unit vesting with respect to 2015 performance was NuStar Energy achieving a DCR of 1.01:1, with all units eligible for vesting as follows based on the DCR for 2015:



Level	DCR	% Performance Units Earned
Below Threshold	Below 1.00 : 1	0%
Threshold	1.00 : 1	90%
Target	1.01 : 1	100%
Exceeds Target	1.05 : 1	150%
Maximum	1.10 : 1	200%

On January 28, 2016, the Compensation Committee determined that NuStar Energy achieved a DCR of 1.11:1 for 2015 and, in accordance with the award terms, the performance units available to vest under the applicable tranche for each of the 2014 awards and 2015 awards with respect to 2015 performance vested at 200%.


•	2016 Performance Period. The target measure established by the Compensation Committee on February 24, 2016 for performance unit vesting with respect to 2016 performance was NuStar Energy achieving a DCR of 1.03:1, with all units eligible for vesting as follows based on the DCR for 2016:



Level	DCR	% Performance Units Earned
Below Threshold	Below 1.00 : 1	0%
Threshold	1.00 : 1	90%
Target	1.03 : 1	100%
Exceeds Target	1.07 : 1	150%
Maximum	1.12 : 1	200%

On January 26, 2017, the Compensation Committee determined that NuStar Energy achieved a DCR of 1.07:1 for 2016 and, in accordance with the award terms, the performance units available to vest under the applicable tranche for each of the 2014 awards, 2015 awards and 2016 awards with respect to 2016 performance vested at 150%.


•	2017 Performance Period. On February 23, 2017, the Compensation Committee awarded the target number of performance units set forth below to our NEOs:



Name	Performance Units Awarded in 2017
Barron	11,000
Shoaf	4,776
Brown	5,145
Oliver	3,624
Truby	2,556

The target measure established by the Compensation Committee on February 23, 2017 for performance unit vesting with respect to 2017 performance was NuStar Energy achieving a DCR of 1.01:1, with all units eligible for vesting as follows based on the DCR for 2017:



Level	DCR	% Performance Units Earned
Below Threshold	Below 1.00 : 1	0%
Threshold	1.00 : 1	90%
Target	1.01 : 1	100%
Exceeds Target	1.05 : 1	150%
Maximum	1.10 : 1	200%

On January 25, 2018, the Compensation Committee determined that NuStar Energy achieved a DCR of 0.63:1 for 2017 and, in accordance with the award terms, the performance units available to vest under the applicable tranche for each of the 2015 awards, 2016 awards and 2017 awards with respect to 2017 performance did not vest. See the table entitled “Grants of Plan-Based Awards During the Year Ended December 31, 2017” for the performance units that did not vest with respect to the 2017 performance period.

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Perquisites and Other Benefits

Perquisites

We provide only minimal perquisites to our NEOs. Each of our NEOs received federal income tax preparation services and personal liability insurance in 2017. For more information on perquisites, see the Summary Compensation Table and its footnotes.

Other Benefits

We provide other benefits, including medical, life, dental and disability insurance in line with competitive market practices. Our NEOs are eligible for the same benefit plans provided to our other employees, including our pension plans, 401(k) thrift plan (the Thrift Plan), and insurance and supplemental plans chosen and paid for by employees who desire additional coverage. Our NEOs and other employees whose compensation exceeds certain limits are eligible to participate in non-qualified excess benefit programs whereby those individuals can choose to make larger contributions than allowed under the qualified plan rules and receive correspondingly higher benefits. These plans are described below under “Post-Employment Benefits.”

Post-Employment Benefits

Pension Plans

For a discussion of our Pension Plan, as well as the Excess Pension Plan, please see the narrative description accompanying the table entitled “Pension Benefits for the Year Ended December 31, 2017.”

Nonqualified Deferred Compensation Plan (Excess Thrift Plan)

The Excess Thrift Plan provides unfunded benefits to those employees whose annual additions under the Thrift Plan are subject to the limitations under §415 of the Internal Revenue Code of 1986, as amended (the Code), and/or who are constrained from making maximum contributions under the Thrift Plan by §401(a)(17) of the Code, which limits the amount of an employee’s annual compensation that may be taken into account under that plan. The Excess Thrift Plan is comprised of two separate components, consisting of (1) an “excess benefit plan” as defined under §3(36) of The Employee Retirement Income Security Act of 1974, as amended (ERISA), and (2) a plan that is maintained primarily for the purpose of providing deferred compensation for a select group of management or highly compensated employees. Each component of the Excess Thrift Plan consists of a separate plan for purposes of Title I of ERISA. To the extent a participant’s annual total compensation exceeds the compensation limits for the calendar year under §401(a)(17) of the Code ($270,000 for 2017) or a participant’s annual additions under the Thrift Plan are limited by the maximum annual additions permitted under §415 of the Code ($54,000 for 2017), the participant’s Excess Thrift Plan account is credited with that number of hypothetical NuStar Energy units that could have been purchased with the difference between:


•	The total company matching contributions that would have been credited to the participant’s account under the Thrift Plan had the participant’s contributions not been limited pursuant to §401(a)(17) and/or §415; and


•	The actual company matching contributions credited to such participant’s account.

Each of our NEOs participated in the Excess Thrift Plan in 2017.

Change of Control Severance Arrangements

We initially entered into change of control severance agreements with each of our NEOs in, or prior to, 2007. The change of control severance agreements are intended to ensure the continued availability of these executives in the event of certain transactions culminating in a “change of control” as defined in the agreements. The change of control severance agreements have three-year terms and are automatically extended for one year upon each anniversary unless we give notice not to extend. If a “change of control” (as defined in the agreements) occurs during the term of an agreement, then the agreement becomes operative for a fixed three-year period. The agreements provide generally that the NEO’s terms and conditions of employment (including position, location, compensation and benefits) will not be adversely changed during the three-year period after a change of control.

The agreements contain tiers of compensation and benefits based on each NEO’s position. Each tier corresponds to a certain “severance multiple” used to calculate cash severance and other benefits to be provided under the agreements. Compensation and benefits under the agreements are triggered upon the occurrence of any of the following in connection with a change of control:

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•	termination of employment by the employer other than for “cause” (as defined in the agreements), death or disability;


•	termination by the NEO for “good reason” (as defined in the agreements);


•	termination by the NEO other than for “good reason;” and


•	termination of employment because of death or disability.

These triggers were designed to ensure the continued availability of these executives following a change of control, and to compensate them at appropriate levels if their employment is unfairly or prematurely terminated during the applicable term following a change of control.

The following table sets forth the severance multiple applicable to each NEO, based on his or her current officer position.



Name	Applicable Officer Position	Severance Multiple
Barron	Chief Executive Officer	3
Shoaf	Executive Vice President	2.5
Brown	Executive Vice President	2.5
Oliver	Senior Vice President	2
Truby	Senior Vice President	2

When determining the amounts and benefits payable under the agreements, the Compensation Committee sought to secure compensation that is competitive in our market in order to recruit and retain executive officer talent. Consideration was given to the principal economic terms found in written employment and change of control agreements of other publicly traded companies. For more information regarding payments and benefits that may be provided under our change of control severance arrangements, see our disclosures below under the caption “Potential Payments upon Termination or Change of Control.”

Each of our NEOs has agreed and acknowledged that the Merger will not be deemed to trigger a “change of control” as defined under any NuStar Energy or NuStar GP Holdings plan or award, and has waived any rights to vesting, payment or other benefit thereunder that would arise upon a “change of control,” to which he or she might otherwise have been entitled.

Employment Agreements

None of the NEOs have employment agreements, other than the change of control severance agreements described above. As a result, in the event of a termination, retirement, death or disability that is not related to a change of control, an NEO will only receive the compensation or benefits to which he or she would be entitled under the terms of the defined contribution, defined benefit, medical or long-term incentive plans, as applicable.

IMPACT OF ACCOUNTING AND TAX TREATMENTS

Accounting Treatment

Services Agreement

As described in Item 13 below, on March 1, 2016, NuStar GP, LLC transferred and assigned to NuStar Services Co, a wholly owned subsidiary of ours, employment of all of NuStar GP, LLC’s employees. Our executive officers continue to serve as officers of NuStar GP Holdings and NuStar GP, LLC, and also serve as officers of NuStar Services Co and other NuStar Energy subsidiaries. Our NEOs serve as employees of both NuStar GP, LLC and NuStar Services Co. In connection with the transfer and assignment, we amended and restated the Services Agreement such that, beginning March 1, 2016, NuStar GP Holdings and NuStar Energy receive all management and administrative services from NuStar Services Co. NuStar Energy reimburses NuStar Services Co for all services provided to NuStar Energy, including payroll and benefit costs, as well as NuStar Energy unit-based compensation costs. NuStar GP Holdings pays NuStar Services Co an administrative services fee, subject to certain adjustments, but no longer pays 1.0% of our domestic bonus and unit compensation expenses. Instead, NuStar GP Holdings retains the expense associated with any NuStar GP Holdings common unit awards or other compensation that it provides to its officers and directors.

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Unit-Based Compensation

In connection with the employee transfer on March 1, 2016, we assumed all outstanding awards under the 2000 LTIP. Our financial statements include the expense for awards of NuStar Energy restricted units and performance units. The transfer of the outstanding awards qualified as a plan modification. Therefore, we measured the fair value of then-outstanding awards to domestic employees (including our NEOs) based on the common unit price on the transfer date. Restricted units awarded to international employees are liability-classified awards that are cash-settled and measured at fair value based on the common unit price at each reporting period.

NuStar Energy 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 expected to result in the issuance of our common units upon vesting as equity-classified awards. The restricted units granted to our domestic employees (including our NEOs) generally vest over five years and the restricted units granted to non-employee directors generally vest over three years. We record compensation expense ratably over the vesting period based on the fair value of the units at the grant date (for domestic employees, including our NEOs) or the fair value of the units measured at each reporting period (for non-employee directors) using the market price of our common units on the applicable date. Common unit distribution equivalents paid with respect to outstanding, unvested equity-classified restricted units reduce equity, similar to cash distributions to unitholders.

NuStar Energy Performance Units. Performance units are equity-classified awards that vest in three increments (tranches) and represent the right to receive our common units, based upon our achievement of the performance measure set by the Compensation Committee during the one-year performance periods that end on December 31 of each year following the grant date. Under applicable accounting standards, a tranche of performance units is not considered “granted” until the Compensation Committee has set the performance measure for that specific tranche of the award. Therefore, performance units are measured at the grant date fair value once the performance measure is established for a specific tranche. In addition, since the performance units granted do not receive common unit distribution equivalents, the estimated fair value of these awards does not include the per unit distributions expected to be paid to unitholders during the vesting period. We record compensation expense ratably for each vesting tranche over its one-year service period if it is probable that the specified performance measure 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.

NuStar GP Holdings, LLC Restricted Units. NuStar GP Holdings’ restricted units are “phantom” units, as they represent the right to receive NuStar GP Holdings’ common units upon vesting. As described above, pursuant to the amended and restated services agreement, NuStar GP Holdings retains the expense associated with NuStar GP Holdings restricted unit awards. NuStar GP Holdings accounts for restricted units that it awards under its long-term incentive plan to its directors and employees (including our NEOs) at fair value. NuStar GP Holdings uses the market price at the grant date as the fair value of its restricted units. Awards of NuStar GP Holdings’ restricted units to its employees vest over five years, and NuStar GP Holdings recognizes the resulting compensation expense ratably over the vesting period.

Tax Treatment

We are a limited partnership and not a corporation for U.S. federal income tax purposes. Therefore, we are not subject to the executive compensation deduction limitations under Section 162(m) of the Code.

COMPENSATION-RELATED POLICIES

Unit Ownership Guidelines

We believe that ownership of NuStar Energy units aligns the interests of our directors and executives with those of NuStar Energy’s unitholders. We have long emphasized and reinforced the importance of unit ownership among our executives and directors.

During 2006, the Compensation Committee worked with its independent compensation consultant to formalize unit ownership and retention guidelines for our directors and officers to ensure continuation of our successful track record in aligning the interests of our directors and officers with those of our unitholders through unit ownership. During 2015, at the request of the Board and its committees, management undertook a review of the unit ownership and retention guidelines. Management discussed the results of its review with the Compensation Committee’s independent compensation consultant at the time, which agreed with management’s conclusions. The Compensation Committee and the Nominating/Governance and Conflicts Committee of NuStar GP, LLC’s Board, as well as the board of directors of NuStar GP Holdings, have approved the updated unit ownership and retention guidelines described below.

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Non-Employee Director Unit Ownership Guidelines

Non-employee directors are expected to acquire and hold during their service as a Board member NuStar Energy units and/or NuStar GP Holdings units with an aggregate value of at least two times their annual cash retainer. Directors have five years from their initial election to the Board to meet the target unit ownership guidelines, and they are expected to continuously own sufficient units to meet the guidelines, once attained. As of December 31, 2017, each of our directors exceeded the ownership levels set forth in the unit ownership guidelines.

Officer Unit Ownership Guidelines

Unit ownership guidelines for the officers set forth below are as follows:



Officer	Value of NuStar Energy Units and/or NuStar GP Holdings Units Owned
CEO/President	4.0x base salary
EVP serving on CEO’s officer committee	3.0x base salary
SVP serving on CEO’s officer committee	2.0x base salary
VP serving on CEO’s officer committee	1.0x base salary

The officers subject to the unit ownership and retention guidelines, including each of our NEOs, are expected to meet the applicable guidelines within five years of becoming subject to the guidelines and continuously own sufficient units to meet the guidelines, once attained. As of December 31, 2017, each of our NEOs exceeded the ownership levels set forth in the unit ownership guidelines.

Unit Ownership

For purposes of satisfying the unit ownership guidelines, the following units are considered owned:


•	units owned directly;


•	units owned indirectly through possession of the right to sell, transfer and/or vote such units; and


•	unvested restricted or phantom units granted under our long-term incentive plan or NuStar GP Holdings’ long-term incentive plan.

Unexercised unit options and unvested performance units are not considered owned for purposes of satisfying the unit ownership guidelines.

Prohibition on Insider Trading and Speculation in NuStar Energy or NuStar GP Holdings Units

We have established policies prohibiting our officers, directors and employees from purchasing or selling either NuStar Energy or NuStar GP Holdings securities while in possession of material, nonpublic information or otherwise using such information for their personal benefit or in any manner that would violate applicable laws and regulations. Our directors, officers and certain other employees are prohibited from trading in either NuStar Energy or NuStar GP Holdings securities for the period beginning on the last business day of each calendar quarter through the first business day following our disclosure of our quarterly or annual financial results. In addition, our policies prohibit our officers, directors and employees from speculating in either NuStar Energy or NuStar GP Holdings units, such as by short selling (profiting if the market price of our units decreases), buying or selling publicly traded options (including writing covered calls), hedging or any other type of derivative arrangement that has a similar economic effect. Our directors, officers and certain other employees also are required to obtain consent from the CEO (or, in the case of the CEO, from the Chair of the applicable company’s Audit Committee) before they enter into margin loans or other financing arrangements that may lead to the ownership or other rights to their NuStar Energy or NuStar GP Holdings securities being transferred to a third party.

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EVALUATION OF COMPENSATION RISK

The Compensation Committee has focused on aligning our compensation policies with the long-term interests of NuStar Energy and avoiding short-term rewards for management decisions that could pose long-term risks to NuStar Energy. As described above in “Compensation Discussion and Analysis,” the primary elements of our compensation program are base salary, annual incentive bonus and long-term incentives. We believe that our compensation program appropriately balances cash with equity-based compensation and fixed compensation with short- and long-term incentives such that no single pay element would motivate unnecessary risk taking.

NuStar Energy’s compensation program is structured so that base salaries provide a fixed level of competitive pay that reflects the individual’s primary duties and responsibilities, and a considerable amount of our management’s compensation is tied to NuStar Energy’s long-term fiscal health. Bonuses, including executive bonuses, are determined with reference to a well-defined performance measure selected by the Compensation Committee and applicable to all employees, as well as the Compensation Committee’s review of each individual executive’s performance. Historically, our long-term incentives have taken the form of performance units and restricted units that typically vest over three- and five-year periods, respectively, which we believe serves to align our employees’ interests with the long-term goals of NuStar Energy. No business group or unit is compensated differently than any other, regardless of profitability. There also is a maximum number of performance units that may be earned, based on the performance of NuStar Energy relative to a performance measure selected by the Compensation Committee. As such, we believe that our compensation policies encourage employees to operate our business in a fundamentally sound manner, align our executives’ interests with those of our unitholders and do not create incentives to take risks that are reasonably likely to have a material adverse effect on NuStar Energy.

COMPENSATION COMMITTEE INTERLOCKS AND INSIDER PARTICIPATION

There are no compensation committee interlocks. The members of our Compensation Committee are Mr. Hill (Chairman), Mr. Bates, Mr. Munch and Mr. Rosier. None of the members of our Compensation Committee have served as an officer or employee of ours. Furthermore, except for compensation arrangements disclosed in this Annual Report on Form 10-K, NuStar Energy has not participated in any contracts, loans, fees or awards, nor does it have financial interests, direct or indirect, with any Compensation Committee member. In addition, none of NuStar Energy’s management or Board members are aware of any means, directly or indirectly, by which a Compensation Committee member could receive a material benefit from NuStar Energy.

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COMPENSATION OF EXECUTIVE OFFICERS AND DIRECTORS

The following pages of this Item 11 provide information required by the SEC regarding compensation paid to or earned by our NEOs and the members of our Board for the periods indicated. We have used captions and headings in the tables provided below in accordance with the SEC regulations requiring these disclosures. The footnotes to these tables provide important information to explain the values presented in the tables, and are an important part of our disclosures.

SUMMARY COMPENSATION TABLE

The following table provides a summary of compensation paid for the years ended December 31, 2017, December 31, 2016 and December 31, 2015 to our Chief Executive Officer, Chief Financial Officer and our three other most highly compensated executive officers serving during 2017. For each NEO, the table shows amounts earned for services rendered to us in all capacities in which the NEO served during the periods presented for that NEO. Mr. Oliver and Mr. Truby were not considered “executive officers” for SEC reporting purposes prior to 2017 and, accordingly, their compensation is reported only with respect to 2017.



Name and Principal Position	Year	Salary ($)	Unit Awards ($)⁽¹⁾	Non-Equity Incentive Plan Compensation ($)⁽²⁾	Change in Pension Value and Nonqualified Deferred Compensation Earnings ($)⁽³⁾	All Other Compensation ($)⁽⁴⁾	Total ($)
Bradley C. Barron President and Chief Executive Officer	2017	583,625	1,233,907	—	218,342	54,897	2,090,771
	2016	557,500	1,039,456	700,000	184,931	35,698	2,517,585
	2015	515,000	1,077,860	800,000	47,061	35,677	2,475,598
Thomas R. Shoaf Executive Vice President and Chief Financial Officer	2017	354,950	554,372	—	171,513	28,387	1,109,222
	2016	344,600	479,970	260,000	124,479	22,924	1,231,973
	2015	334,550	515,023	311,000	47,692	21,729	1,229,994
Mary Rose Brown Executive Vice President and Chief Administrative Officer	2017	382,350	597,187	—	188,315	60,689	1,228,541
	2016	371,200	516,952	280,000	142,437	24,520	1,335,109
	2015	360,350	554,552	335,000	173,968	23,836	1,447,706
Daniel S. Oliver Senior Vice President-Marketing and Business Development	2017	323,150	382,223	—	142,129	29,973	877,475
Michael Truby Senior Vice President-Operations	2017	293,800	310,868	—	112,573	23,259	740,500

(1)

The amounts reported represent the aggregate grant date fair value of grants of NuStar Energy restricted units, NuStar Energy performance units and NuStar GP Holdings restricted units. Under a services agreement in effect prior to March 1, 2016, we reimbursed NuStar GP, LLC for 99% of the compensation expense associated with NuStar Energy awards. On March 1, 2016, NuStar GP, LLC transferred and assigned to NuStar Services Co, a wholly owned subsidiary of ours, employment of all of NuStar GP, LLC’s employees and we assumed all outstanding NuStar Energy awards. Our NEOs are employees of both NuStar Services Co and NuStar GP, LLC. NuStar GP Holdings retains the expense associated with the NuStar GP Holdings restricted unit awards.

Restricted Units

The grant date fair value for restricted units presented in the table above was determined by multiplying the number of NuStar Energy restricted units or NuStar GP Holdings restricted units that were granted by the NYSE closing unit price of NuStar Energy common units or NuStar GP Holdings common units, as applicable, on the date of grant.

Performance Units

For the 2015 row in the Summary Compensation Table, the grant date fair value of the NuStar Energy performance units was determined by multiplying the target number of performance units that were granted by the NYSE closing unit price of NuStar Energy common units on the date of grant.

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On March 1, 2016, in connection with the employee transfer, we assumed all outstanding NuStar Energy awards, and performance unit awards are now equity-classified awards. The transfer qualified as a plan modification, and we measured the fair value of then-outstanding awards based on our common unit price on the transfer date. Under applicable accounting standards, a tranche of performance units is not considered “granted” until the Compensation Committee has set the performance measure for that specific tranche of the award. Therefore, performance units are measured at the grant date fair value once the performance measure is established for a specific tranche (or, for 2016, the transfer date).

Beginning with the 2016 period, the grant date fair value presented in the Summary Compensation Table includes the fair value of each tranche of performance units for which the Compensation Committee established a performance measure during that year. Accordingly, as illustrated in the table below:


•	the amount reported for 2016 includes the one tranche of each of the 2014, 2015 and 2016 performance unit awards subject to vesting based on the performance criteria established by the Compensation Committee on February 24, 2016 with respect to 2016 performance; and


•	the amount reported for 2017 includes the one tranche of each of the 2015, 2016 and 2017 performance unit awards subject to vesting based on the performance criteria established by the Compensation Committee on February 23, 2017 with respect to 2017 performance.



Award	Tranche Considered “Granted”
Award	In 2017 with respect to 2017 Performance Measure	In 2016 with respect to 2016 Performance Measure
2014 Performance Unit Award	N/A	3rd
2015 Performance Unit Award	3rd	2nd
2016 Performance Unit Award	2nd	1st
2017 Performance Unit Award	1st	N/A

For 2017 and 2016, the grant date fair value of the NuStar Energy performance units was determined by multiplying the probable number of performance units for all tranches eligible to vest with respect to 2017 and 2016 performance (as illustrated in the table above), respectively, by the NYSE closing unit price of NuStar Energy common units on the grant date (or, for 2016, the transfer date as described above), reduced by the per unit value of distributions not paid on performance units prior to vesting.

If the maximum number of NuStar Energy performance units had been used to determine the grant date fair value of performance units for the 2017 and 2016 periods presented, the grant date fair value for performance units for the 2017 and 2016 periods presented in the Summary Compensation Table for each of our NEOs would have been as set forth in the table below:



Name	Grant Date Fair Value Based on Maximum Number of Performance Units
Name	2017 ($)	2016 ($)
Barron	1,077,444	618,393
Shoaf	499,944	305,958
Brown	538,471	329,513
Oliver	379,247	N/A
Truby	263,667	N/A

Please see the “Long-Term Incentive Awards” section and the “Accounting Treatment” section of “Compensation Discussion and Analysis” above in this Item 11 and Note 23 of the Notes to Consolidated Financial Statements in Item 8 for additional information regarding the vesting schedules and the assumptions made in the valuation.

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(2)

Our NEOs did not receive cash annual incentive bonus amounts for 2017. The amounts reported as “non-equity incentive plan compensation” for 2016 and 2015 reflect the cash annual incentive bonus amounts paid to our NEOs pursuant to the annual bonus plan with respect to performance for those years. Any bonus amounts are paid in February of each year with respect to performance during the immediately preceding year. Bonuses are determined taking into consideration NuStar Energy’s performance in the applicable year, each individual NEO’s target and each NEO’s performance, as described above under “Compensation Discussion and Analysis-Elements of Executive Compensation-Annual Incentive Bonus.” For an explanation of the amount of salary and bonus in proportion to total compensation, see “Compensation Discussion and Analysis-Elements of Executive Compensation-Relative Size of Primary Elements of Compensation.”

(3)

The amounts reported reflect the amounts attributable to the aggregate change in the actuarial present value of each NEO’s accumulated benefit under our defined benefit and actuarial pension plans, including supplemental plans (but excluding tax-qualified defined contribution plans and nonqualified defined contribution plans). None of the NEOs received any above-market or preferential earnings on compensation that is deferred on a basis that is not tax-qualified during the periods presented.


(4)	The amounts reported in this column for 2017 consist of the following for each NEO:



Name	Company Contribution to Thrift Plan ($)	Company Contribution to Excess Thrift Plan ($)	Tax Preparation ($)	Personal Liability Insurance ($)	Executive Health Exams ($)^(a)	TOTAL ($)
Barron	16,200	36,316	850	1,531	—	54,897
Shoaf	16,200	7,226	850	1,531	2,580	28,387
Brown	13,185	42,543	850	1,531	2,580	60,689
Oliver	16,200	11,392	850	1,531	—	29,973
Truby	16,200	4,678	850	1,531	—	23,259


(a)	The amount reported is the difference between the value of the respective NEO’s health exams and the value of NuStar Energy’s all-employee wellness assessments.

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PAY RATIO

As required by SEC regulations, we are providing the following information regarding the ratio of the annual total compensation of our President and Chief Executive Officer, Mr. Barron, to the median of the annual total compensation of our employees for our last completed fiscal year.

For 2017:


•	the median of the annual total compensation of all of our employees (other than our President and Chief Executive Officer) was $88,610; and


•	the annual total compensation of our President and Chief Executive Officer, as reported in the Summary Compensation Table above, was $2,090,771.

Accordingly, for 2017, the ratio of the annual total compensation of our President and Chief Executive Officer to the annual total compensation of our median employee was 24 to 1.

To determine our median employee, we identified each individual employed by us on October 1, 2017 (our Determination Date), and, for each individual employed by us on the Determination Date, we examined each of the following elements of compensation (which we refer to as the Total Comparable Compensation) that we paid those employees during the period from October 1, 2016 through September 30, 2017 (the Compensation Review Period):


•	salary, wages and any overtime paid during the Compensation Review Period;


•	any bonus awards paid during the Compensation Review Period; and


•	the grant date fair value of any restricted units awarded during the Compensation Review Period.

As of our Determination Date, we had approximately 1,690 employees located in five countries. We selected our Determination Date and our Compensation Review Period to provide sufficient time for us to gather the necessary information from multiple countries and to enable us to make the identification of the median employee in a reasonably efficient and economical manner. After identifying the median employee based on Total Comparable Compensation, we calculated the annual total compensation for the median employee for 2017 using the same methodology we use to calculate the annual total compensation for our NEOs for 2017, as set forth in the Summary Compensation Table above. We did not make any assumptions, adjustments or estimates to identify the median employee, to determine the Total Comparable Compensation for each employee or to determine the annual total compensation for the median employee.

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GRANTS OF PLAN-BASED AWARDS

DURING THE YEAR ENDED DECEMBER 31, 2017

The following table provides information regarding grants of plan-based awards to the NEOs during 2017.



Name	Grant Date		Date of Approval by Compensation Committee of Equity-Based Awards	Estimated Future Payouts Under Non-Equity Incentive Plan Awards			Estimated Future Payouts Under Equity Incentive Plan Awards			All Other Unit Awards: Number of Units (#)	Grant Date Fair Value of Unit Awards ($)
Name	Grant Date			Threshold ($)	Target ($)	Maximum ($)	Threshold (#)	Target (#)	Maximum (#)	All Other Unit Awards: Number of Units (#)	Grant Date Fair Value of Unit Awards ($)
Barron	N/A	⁽¹⁾	N/A	N/A	583,625	1,167,250	—	—	—	—		—
	2/23/2017	⁽²⁾	2/23/2017	—	—	—	9,665	10,739	21,478	—		538,722
	11/16/2017	⁽³⁾	10/18/2017	—	—	—	—	—	—	16,660	16,660	486,805
	11/16/2017	⁽⁴⁾	10/18/2017	—	—	—	—	—	—	13,315		208,380
Shoaf	N/A	⁽¹⁾	N/A	N/A	212,970	425,940	—	—	—	—		—
	2/23/2017	⁽²⁾	2/23/2017	—	—	—	4,485	4,983	9,966	—	249,972
	11/16/2017	⁽³⁾	10/18/2017	—	—	—	—	—	—	7,295	213,160
	11/16/2017	⁽⁴⁾	10/18/2017	—	—	—	—	—	—	5,830	91,240
Brown	N/A	⁽¹⁾	N/A	N/A	229,410	458,820	—	—	—	—		—
	2/23/2017	⁽²⁾	2/23/2017	—	—	—	4,830	5,367	10,734	—	269,236
	11/16/2017	⁽³⁾	10/18/2017	—	—	—	—	—	—	7,860	229,669
	11/16/2017	⁽⁴⁾	10/18/2017	—	—	—	—	—	—	6,280	98,282
Oliver	N/A	⁽¹⁾	N/A	N/A	177,733	355,465	—	—	—	—		—
	2/23/2017	⁽²⁾	2/23/2017	—	—	—	3,402	3,780	7,560	—		189,624
	11/16/2017	⁽³⁾	10/18/2017	—	—	—	—	—	—	4,615		134,850
	11/16/2017	⁽⁴⁾	10/18/2017	—	—	—	—	—	—	3,690		57,749
Truby	N/A	⁽¹⁾	N/A	N/A	161,590	323,180	—	—	—	—		—
	2/23/2017	⁽²⁾	2/23/2017	—	—	—	2,365	2,628	5,256	—		131,834
	11/16/2017	⁽³⁾	10/18/2017	—	—	—	—	—	—	4,290		125,354
	11/16/2017	⁽⁴⁾	10/18/2017	—	—	—	—	—	—	3,430		53,680

(1)

The amounts reported represent the target and maximum amounts that would potentially have been payable in cash to the NEOs as annual incentive bonus awards under the annual bonus plan with respect to 2017 performance. The annual incentive bonus awards with respect to 2017 performance did not include a threshold amount that would potentially be payable to the NEOs. As reflected in the “Non-Equity Incentive Plan Compensation” column of the Summary Compensation Table and as described above under “Compensation Discussion and Analysis-Elements of Executive Compensation-Annual Incentive Bonus,” the target level of performance with respect to 2017 was not met, and, upon the recommendation of executive management, the Compensation Committee did not award our executives, including our NEOs, annual incentive bonus award payments with respect to 2017 performance.

(2)

Performance units were awarded by the Compensation Committee on February 23, 2017 pursuant to the 2000 LTIP. Performance units vest in three annual increments (tranches), based upon our achievement of the performance measure set by the Compensation Committee during the one-year performance periods that end on December 31 of each year following the date of grant. Under applicable accounting standards, a tranche of performance units is not considered “granted” until the Compensation Committee has set the performance measure for that specific tranche of the award. Therefore, performance units are measured at the grant date fair value once the performance measure is established for a specific tranche. In addition, since the performance units granted do not receive common unit distribution equivalents, the estimated fair value of these awards does not include the per unit distributions expected to be paid to unitholders during the vesting period.

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The estimated future payouts and the grant date fair value presented in the table above with respect to performance units includes each tranche of performance units for which the Compensation Committee established a performance measure during 2017. For 2017, the amounts presented include the one tranche of each of the 2015, 2016 and 2017 performance unit awards that was subject to vesting based on the performance criteria established by the Compensation Committee on February 23, 2017 with respect to 2017 performance, as illustrated in the table below:



Award	Tranche Considered “Granted” in 2017 With Respect to 2017 Performance Measure
2015 Performance Unit Award	3rd
2016 Performance Unit Award	2nd
2017 Performance Unit Award	1st

On January 25, 2018, the Compensation Committee determined that, based on the performance level attained for the performance period ended December 31, 2017, the performance units reported in the table above did not vest. See “Compensation Discussion and Analysis-Elements of Executive Compensation-Long Term Incentive Awards-Performance Units” for a description of the performance measure and the performance level attained with respect to the 2017 performance period. See “Compensation Discussion and Analysis-Impact of Accounting and Tax Treatments-Accounting Treatment” and footnote (1) to the Summary Compensation Table above in this Item 11 for information regarding the assumptions made in valuation.

(3)

Restricted units of NuStar Energy were approved by the Compensation Committee on October 18, 2017, and the grant date for these NuStar Energy restricted units was set at that time for the date that was as soon as administratively practicable after the meeting and no earlier than the third business day following our third quarter earnings release. The NuStar Energy restricted units were awarded pursuant to the 2000 LTIP and vest 1/5 annually over five years beginning on the first anniversary of the grant date. All grantees receiving NuStar Energy restricted units are entitled to receive an amount in cash equal to the product of (a) the number of restricted units granted to the grantee that remain outstanding and unvested as of the record date for such quarter and (b) the quarterly distribution declared by the Board for such quarter with respect to NuStar Energy’s common units. See “Compensation Discussion and Analysis-Impact of Accounting and Tax Treatments-Accounting Treatment” and footnote (1) to the Summary Compensation Table above in this Item 11 for information regarding the assumptions made in valuation.

(4)

Restricted units of NuStar GP Holdings were approved by the compensation committee of NuStar GP Holdings on October 18, 2017, and the grant date for these NuStar GP Holdings restricted units was set at that time for the date that was as soon as administratively practicable after the meeting and no earlier than the third business day following NuStar GP Holdings’ third quarter earnings release. The NuStar GP Holdings restricted units were awarded pursuant to the NuStar GP Holdings Long-Term Incentive Plan, as amended and restated as of April 1, 2007, and vest 1/5 annually over five years beginning on the first anniversary of the grant date. All grantees receiving NuStar GP Holdings restricted units are entitled to receive an amount in cash equal to the product of (a) the number of restricted units granted to the grantee that remain outstanding and unvested as of the record date for such quarter and (b) the quarterly distribution declared by the NuStar GP Holdings Board for such quarter with respect to NuStar GP Holdings’ common units. See “Compensation Discussion and Analysis-Impact of Accounting and Tax Treatments-Accounting Treatment” and footnote (1) to the Summary Compensation Table above in this Item 11 for information regarding the assumptions made in valuation.

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OUTSTANDING EQUITY AWARDS

AT DECEMBER 31, 2017

The following table provides information regarding our NEOs’ unvested restricted units and the target amount of our NEOs’ unvested performance units as of December 31, 2017. The value of NuStar Energy restricted units, NuStar Energy performance units and NuStar GP Holdings restricted units reported below was determined by multiplying (1) the number of units reflected in the table by (2) $29.95 (the closing price of NuStar Energy common units on December 29, 2017, the last trading day of the year) or $15.70 (the closing price of NuStar GP Holdings common units on December 29, 2017, the last trading day of the year), as applicable.

At the effective time of the Merger, each outstanding award of NuStar GP Holdings restricted units will be 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 will be determined as provided in the Merger Agreement. Each of our NEOs has agreed and acknowledged that the Merger will not be deemed to trigger a “change of control” as defined under any NuStar Energy or NuStar GP Holdings plan or award, and has waived any rights to vesting, payment or other benefit thereunder that would arise upon a “change of control,” to which he or she might otherwise have been entitled.



Name	Unit Awards
Name	Type of Award	Number of Units That Have Not Vested (#)	Market Value of Units That Have Not Vested ($)	Equity Incentive Plan Awards: Number of Unearned Units or Other Rights That Have Not Vested (#)	Equity Incentive Plan Awards: Market or Payout Value of Unearned Units or Other Rights That Have Not Vested ($)
Barron	NuStar Energy Performance Unit ⁽¹⁾	—	—	22,480	673,276
	NuStar Energy Restricted Unit ⁽²⁾	35,272	1,056,396	—	—
	NuStar GP Holdings Restricted Unit ⁽³⁾	27,505	431,829	—	—
Shoaf	NuStar Energy Performance Unit ⁽⁴⁾	—	—	10,245	306,838
	NuStar Energy Restricted Unit ⁽⁵⁾	16,102	482,255	—	—
	NuStar GP Holdings Restricted Unit ⁽⁶⁾	12,551	197,051	—	—
Brown	NuStar Energy Performance Unit ⁽⁷⁾	—	—	11,035	330,498
	NuStar Energy Restricted Unit ⁽⁸⁾	17,607	527,330	—	—
	NuStar GP Holdings Restricted Unit ⁽⁹⁾	13,709	215,231	—	—
Oliver	NuStar Energy Performance Unit ⁽¹⁰⁾	—	—	7,772	232,771
	NuStar Energy Restricted Unit ⁽¹¹⁾	11,479	343,796	—	—
	NuStar GP Holdings Restricted Unit ⁽¹²⁾	8,924	140,107	—	—
Truby	NuStar Energy Performance Unit ⁽¹³⁾	—	—	5,444	163,048
	NuStar Energy Restricted Unit ⁽¹⁴⁾	9,650	289,018	—	—
	NuStar GP Holdings Restricted Unit ⁽¹⁵⁾	6,259	98,266	—	—

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(1)	Mr. Barron’s target number of NuStar Energy performance units consist of: 2,666 units awarded January 29, 2015; 8,814 units awarded February 24, 2016; and 11,000 units awarded February 23, 2017.

The performance units awarded in 2015, 2016 and 2017 are eligible to vest in three annual increments and are payable in NuStar Energy’s common units. Upon vesting, the performance units are converted into a number of NuStar Energy common units based upon NuStar Energy’s performance during the one-year performance periods that end on December 31 of each year following the date of grant against an objective performance measure established by the Compensation Committee.

On January 25, 2018, the Compensation Committee determined that, based on the performance level attained for the performance period ended December 31, 2017, the performance units available to vest under the 2015 awards, 2016 awards and 2017 awards with respect to 2017 performance did not vest. See the table entitled “Grants of Plan-Based Awards During the Year Ended December 31, 2017” for the performance units that did not vest with respect to the 2017 performance period. See “Compensation Discussion and Analysis-Elements of Executive Compensation-Long Term Incentive Awards-Performance Units” for a description of the performance measure and the performance level attained with respect to the 2017 performance period.

If the maximum level of performance (200%) had been assumed for all of the target unvested performance units reported in the table, the number of performance units outstanding and the market value thereof as of December 31, 2017 would have been twice the amounts reflected in the table.

(2)

Mr. Barron’s restricted NuStar Energy units consist of: 950 restricted units granted December 16, 2013; 2,862 restricted units granted December 19, 2014; 6,000 restricted units granted November 16, 2015; 8,800 restricted units granted November 16, 2016; and 16,660 restricted units granted November 16, 2017. All of Mr. Barron’s NuStar Energy restricted units vest in 1/5 increments over five years, beginning on the first anniversary of the date of grant.

(3)

Mr. Barron’s restricted NuStar GP Holdings units consist of: 688 restricted units granted December 16, 2013; 1,922 restricted units granted December 19, 2014; 4,380 restricted units granted November 16, 2015; 7,200 restricted units granted November 16, 2016; and 13,315 restricted units granted November 16, 2017. All of Mr. Barron’s NuStar GP Holdings restricted units vest in 1/5 increments over five years, beginning on the first anniversary of the date of grant.


(4)	Mr. Shoaf’s target number of NuStar Energy performance units consist of: 1,313 units awarded January 29, 2015; 4,156 units awarded February 24, 2016; and 4,776 units awarded February 23, 2017. The performance units vest in accordance with the description in footnote (1) above.

(5)

Mr. Shoaf’s restricted NuStar Energy units consist of: 637 restricted units granted December 16, 2013; 1,444 restricted units granted December 19, 2014; 2,790 restricted units granted November 16, 2015; 3,936 restricted units granted November 16, 2016; and 7,295 restricted units granted November 16, 2017. All of Mr. Shoaf’s NuStar Energy restricted units vest in 1/5 increments over five years, beginning on the first anniversary of the date of grant.

(6)

Mr. Shoaf’s restricted NuStar GP Holdings units consist of: 461 restricted units granted December 16, 2013; 970 restricted units granted December 19, 2014; 2,058 restricted units granted November 16, 2015; 3,232 restricted units granted November 16, 2016; and 5,830 restricted units granted November 16, 2017. All of Mr. Shoaf’s NuStar GP Holdings restricted units vest in 1/5 increments over five years, beginning on the first anniversary of the date of grant.


(7)	Ms. Brown’s target number of NuStar Energy performance units consist of: 1,414 units awarded January 29, 2015; 4,476 units awarded February 24, 2016; and 5,145 units awarded February 23, 2017. The performance units vest in accordance with the description in footnote (1) above.

(8)

Ms. Brown’s restricted NuStar Energy units consist of: 950 restricted units granted December 16, 2013; 1,554 restricted units granted December 19, 2014; 3,003 restricted units granted November 16, 2015; 4,240 restricted units granted November 16, 2016; and 7,860 restricted units granted November 16, 2017. All of Ms. Brown’s NuStar Energy restricted units vest in 1/5 increments over five years, beginning on the first anniversary of the date of grant.

(9)

Ms. Brown’s restricted NuStar GP Holdings units consist of: 688 restricted units granted December 16, 2013; 1,044 restricted units granted December 19, 2014; 2,217 restricted units granted November 16, 2015; 3,480 restricted units granted November 16, 2016; and 6,280 restricted units granted November 16, 2017. All of Ms. Brown’s NuStar GP Holdings restricted units vest in 1/5 increments over five years, beginning on the first anniversary of the date of grant.

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(10)	Mr. Oliver’s target number of NuStar Energy performance units consist of: 996 units awarded January 29, 2015; 3,152 units awarded February 24, 2016; and 3,624 units awarded February 23, 2017. The performance units vest in accordance with the description in footnote (1) above.

(11)

Mr. Oliver’s restricted NuStar Energy units consist of: 671 restricted units granted December 16, 2013; 1,094 restricted units granted December 19, 2014; 2,115 restricted units granted November 16, 2015; 2,984 restricted units granted November 16, 2016; and 4,615 restricted units granted November 16, 2017. All of Mr. Oliver’s NuStar Energy restricted units vest in 1/5 increments over five years, beginning on the first anniversary of the date of grant.

(12)

Mr. Oliver’s restricted NuStar GP Holdings units consist of: 486 restricted units granted December 16, 2013; 736 restricted units granted December 19, 2014; 1,560 restricted units granted November 16, 2015; 2,452 restricted units granted November 16, 2016; and 3,690 restricted units granted November 16, 2017. All of Mr. Oliver’s NuStar GP Holdings restricted units vest in 1/5 increments over five years, beginning on the first anniversary of the date of grant.


(13)	Mr. Truby’s target number of NuStar Energy performance units consist of: 664 units awarded July 23, 2015; 2,224 units awarded February 24, 2016; and 2,556 units awarded February 23, 2017. The performance units vest in accordance with the description in footnote (1) above.

(14)

Mr. Truby’s restricted NuStar Energy units consist of: 747 restricted units granted December 16, 2013; 1,018 restricted units granted December 19, 2014; 1,491 restricted units granted November 16, 2015; 2,104 restricted units granted November 16, 2016; and 4,290 restricted units granted November 16, 2017. All of Mr. Truby’s NuStar Energy restricted units vest in 1/5 increments over five years, beginning on the first anniversary of the date of grant.


(15)	Mr. Truby’s restricted NuStar GP Holdings units consist of: 1,101 restricted units granted November 16, 2015; 1,728 restricted units granted November 16, 2016; and 3,430 restricted units granted November 16, 2017. All of Mr. Truby’s NuStar GP Holdings restricted units vest in 1/5 increments over five years, beginning on the first anniversary of the date of grant.

OPTION EXERCISES AND UNITS VESTED

DURING THE YEAR ENDED DECEMBER 31, 2017

The following table provides information regarding the vesting of restricted units and performance units held by our NEOs during 2017. None of our NEOs had outstanding unit option awards during 2017.



	Unit Awards
Name	Number of Units Acquired on Vesting (#)	Value Realized on Vesting ($)⁽¹⁾
Barron	27,269⁽²⁾	1,106,122
Shoaf	13,734⁽³⁾	553,181
Brown	15,654⁽⁴⁾	616,374
Oliver	10,988⁽⁵⁾	430,859
Truby	6,074⁽⁶⁾	237,937

(1)

The value realized on vesting of NuStar Energy restricted units and performance units was calculated by multiplying the closing price of NuStar Energy common units on the NYSE on the date of vesting by the number of NuStar Energy units vested. The value realized on vesting of NuStar GP Holdings restricted units was calculated by multiplying the closing price of NuStar GP Holdings common units on the NYSE on the date of vesting by the number of NuStar GP Holdings units vested. In the case of the December 16, 2017 vesting date, which was not a trading day, the value realized was calculated using the NuStar Energy or NuStar GP Holdings closing price, as applicable, on the preceding trading day. The closing prices on the applicable dates are as follows:

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Closing Prices for 2017 Vestings
Date	NuStar Energy Closing Price ($)
January 26, 2017	55.31
November 16, 2017	29.22
December 15, 2017	30.54
December 19, 2017	30.18
Date	NuStar GP Holdings Closing Price ($)
November 16, 2017	15.65
December 15, 2017	15.05
December 19, 2017	14.50

(2)

Mr. Barron's restricted NuStar Energy units vested in 2017 as follows: 4,200 units on November 16, 2017; 950 units on December 16, 2017; and 2,121 units on December 19, 2017. Mr. Barron's restricted NuStar GP Holdings units vested in 2017 as follows: 3,260 units on November 16, 2017; 688 units on December 16, 2017; and 1,439 units on December 19, 2017. On January 26, 2017, 14,611 of Mr. Barron’s NuStar Energy performance units vested.

(3)

Mr. Shoaf’s restricted NuStar Energy units vested in 2017 as follows: 1,914 units on November 16, 2017; 637 units on December 16, 2017; and 1,190 units on December 19, 2017. Mr. Shoaf’s restricted NuStar GP Holdings units vested in 2017 as follows: 1,494 units on November 16, 2017; 461 units on December 16, 2017; and 809 units on December 19, 2017. On January 26, 2017, 7,229 of Mr. Shoaf’s NuStar Energy performance units vested.

(4)

Ms. Brown’s restricted NuStar Energy units vested in 2017 as follows: 2,061 units on November 16, 2017; 950 units on December 16, 2017; and 1,523 units on December 19, 2017. Ms. Brown’s restricted NuStar GP Holdings units vested in 2017 as follows: 1,609 units on November 16, 2017; 688 units on December 16, 2017; and 1,038 units on December 19, 2017. On January 26, 2017, 7,785 of Ms. Brown’s NuStar Energy performance units vested.

(5)

Mr. Oliver’s restricted NuStar Energy units vested in 2017 as follows: 1,451 units on November 16, 2017; 671 units on December 16, 2017; and 1,114 units on December 19, 2017. Mr. Oliver’s restricted NuStar GP Holdings units vested in 2017 as follows: 1,133 units on November 16, 2017; 486 units on December 16, 2017; and 733 units on December 19, 2017. On January 26, 2017, 5,400 of Mr. Oliver’s NuStar Energy performance units vested.


(6)	Mr. Truby’s restricted NuStar Energy units vested in 2017 as follows: 1,023 units on November 16, 2017; 747 units on December 16, 2017; and 841 units on December 19, 2017. On November 16, 2017, 799 of Mr. Truby’s restricted NuStar GP Holdings units vested. On January 26, 2017, 2,664 of Mr. Truby’s NuStar Energy performance units vested.

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POST-EMPLOYMENT COMPENSATION

PENSION BENEFITS

FOR THE YEAR ENDED DECEMBER 31, 2017

We maintain a noncontributory defined benefit pension plan (the Pension Plan) in which most of our employees are eligible to participate and under which contributions by individual participants are neither required nor permitted. We also maintain a noncontributory, non-qualified excess pension plan (the Excess Pension Plan), which provides supplemental pension benefits to certain highly compensated employees. The Excess Pension Plan provides eligible employees with additional retirement savings opportunities that cannot be achieved with tax-qualified plans due to the Code’s limits on (1) annual compensation that can be taken into account under qualified plans or (2) annual benefits that can be provided under qualified plans.

The following table provides information regarding the accumulated benefits of our NEOs under our pension plans during the year ended December 31, 2017.



Name	Plan Name	Number of Years Credited Service	Present Value of Accumulated Benefit ($)⁽¹⁾	Payments During Last Fiscal Year ($)
Barron	Pension Plan	⁽²⁾	366,056	—
Barron	Excess Pension Plan	⁽²⁾	610,215	—
Shoaf	Pension Plan	⁽²⁾	483,611	—
Shoaf	Excess Pension Plan	⁽²⁾	482,321	—
Brown	Pension Plan	⁽²⁾	484,661	—
Brown	Excess Pension Plan	⁽²⁾	611,118	—
Oliver	Pension Plan	⁽²⁾	336,416	—
Oliver	Excess Pension Plan	⁽²⁾	376,814	—
Truby	Pension Plan	⁽²⁾	465,657	—
Truby	Excess Pension Plan	⁽²⁾	132,458	—

(1)

The present values stated in the table above were calculated using the same interest rates and mortality tables we use for our financial reporting. The present values as of December 31, 2017 were determined using plan-specific discount rates (3.73% for the Pension Plan and 3.42% for the Excess Pension Plan) and the plans’ earliest unreduced retirement age (age 62). The present values reflect post-retirement mortality rates based on the RP2006 generational mortality table projected using scale MP2016. No decrements were included for pre-retirement termination, mortality or disability. Where applicable, lump sums were determined based on a 3.23% interest rate and the mortality table prescribed by the IRS in Rev. Ruling 2007-67 and updated by IRS Notices 2008-85 and 2013-49 for distributions in the years 2009-2017.

(2)

As of December 31, 2013, the final average pay formula used in the Pension Plan and the Excess Pension Plan, which was based on years of service and compensation during service, was frozen. Benefits for service after December 31, 2013 accrue under a cash balance formula described below. The number of years of credited service under the final average pay formula and the cash balance formula for each of our NEOs under the Pension Plan and the Excess Pension Plan are set forth below.

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Name	Plan Name	Number of Years Credited Service - Final Average Pay Formula (Frozen as of December 31, 2013)	Number of Years Credited Service - Cash Balance Formula
Barron	Pension Plan	7.5	17.0
Barron	Excess Pension Plan	13.0	17.0
Shoaf	Pension Plan	7.5	32.5
Shoaf	Excess Pension Plan	28.5	32.5
Brown	Pension Plan	6.7	20.3
Brown	Excess Pension Plan	6.7	20.3
Oliver	Pension Plan	6.8	20.7
Oliver	Excess Pension Plan	6.8	20.7
Truby	Pension Plan	7.5	25.0
Truby	Excess Pension Plan	7.5	25.0

Pension Plan

The Pension Plan is a qualified, non-contributory defined benefit pension plan that became effective as of July 1, 2006. The Pension Plan covers substantially all of our employees and generally provides retirement income calculated under a cash balance formula (CBF), which is comprised of contribution credits based on age and years of vesting service and interest credits. Employees become fully vested in their CBF benefits upon attaining three years of vesting service. Prior to January 1, 2014, eligible employees were covered under either the CBF or a defined benefit final average pay formula (FAP) based on years of service and compensation during their period of service, and employees became fully vested in their benefits upon attaining five years of service under the FAP and upon attaining three years of service under the CBF. The Pension Plan was amended to freeze the FAP benefit at December 31, 2013 and, on or after January 1, 2014, all employees are covered under the CBF.

An eligible employee’s benefits under the Pension Plan will be equal to:


•	1.6% of the employee’s average monthly compensation multiplied by the employee’s years of credited service for service through December 31, 2013 for the FAP benefit plus


•	the employee’s CBF account balance.

An employee may start receiving his or her benefits under the Pension Plan at any time following his or her separation of service, but must begin receiving benefits by April 1 of the year after the employee attains age 70½. Mr. Shoaf, Ms. Brown and Mr. Truby have attained the Early Retirement Age, which is defined in the Pension Plan as age 55. If an employee with a FAP benefit begins receiving benefits after the Early Retirement Age and before age 62, the FAP benefit amount will be reduced by 4% for each full year between the benefit start date and age 62. If an employee with a FAP benefit begins receiving benefits before the Early Retirement Age, the amount of the FAP benefit will be the actuarial equivalent of the lump sum that otherwise would have been payable on the date the employee starts benefits. The CBF benefit amount under the Pension Plan is based on the CBF account balance and, therefore, is not reduced based on the age at which the employee begins receiving benefits.

Excess Pension Plan

The Excess Pension Plan, which became effective July 1, 2006, provides benefits to our eligible employees whose pension benefits under the Pension Plan and the Valero Energy Pension Plan, where applicable, are subject to limitations under the Code. The Excess Pension Plan is an excess benefit plan as contemplated under ERISA for those benefits provided in excess of the maximum amount allowable under Section 415 of the Code. Benefits provided as a result of other statutory limitations are limited to a select group of management or highly compensated employees. The Excess Pension Plan is not intended to constitute either a qualified plan under the Code or a funded plan subject to ERISA. For our employees who were eligible to receive a benefit under the Valero Energy Excess Pension Plan (the Predecessor Excess Pension Plan) as of July 1, 2006, the Excess Pension Plan assumed the liabilities of the Predecessor Excess Pension Plan and will provide a single, nonqualified defined benefit to eligible employees for their pre-July 1, 2006 benefit accruals under the Predecessor Excess Pension Plan and their post-July 1, 2006 benefit accruals under the Excess Pension Plan.

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An eligible employee’s monthly pension under the Excess Pension Plan will be equal to:


•	1.6% of the employee’s average monthly compensation multiplied by the employee’s years of credited service for service through December 31, 2013, plus


•	the employee’s CBF benefits, in each case without regard to the limitations imposed by the Code, less


•	the employee’s Pension Plan benefit.

All of our NEOs participated in the Excess Pension Plan during 2017.

NONQUALIFIED DEFERRED COMPENSATION

FOR THE YEAR ENDED DECEMBER 31, 2017

The following table provides information regarding our contributions and the contributions by each of our NEOs under our non-qualified defined contribution plan, the Excess Thrift Plan, during the year ended December 31, 2017. The table also presents each NEO’s withdrawals, earnings and year-end balances in such plan. Please see the description of our Excess Thrift Plan above in “Compensation Discussion and Analysis-Elements of Executive Compensation-Post-Employment Benefits.”



Name	Executive Contributions in 2017 ($)⁽¹⁾	Registrant Contributions in 2017 ($)⁽²⁾	Aggregate Earnings/(Losses) in 2017 ($)⁽³⁾		Aggregate Withdrawals/ Distributions ($)	Aggregate Balance at December 31, 2017 ($)⁽⁴⁾
Barron	—	36,316	(37,400	)	—	83,402
Shoaf	—	7,226	(5,798	)	—	15,482
Brown	—	42,543	(36,590	)	—	75,737
Oliver	—	11,392	(6,711	)	—	15,728
Truby	—	4,678	(1,349	)	—	3,637


(1)	The NEOs made no contributions during 2017.


(2)	Amounts reported represent our contributions to our Excess Thrift Plan. All of the amounts included in this column are included within the amounts reported as “All Other Compensation” for 2017 in the Summary Compensation Table.


(3)	Amounts reported reflect the losses for each NEO’s respective account in our Excess Thrift Plan.


(4)	Amounts include the aggregate balance at year end, if any, of each NEO’s respective account in our Excess Thrift Plan and include registrant contributions that were previously reported as compensation to each of the NEOs in the “All Other Compensation” column in the Summary Compensation Table for 2017 and previous years, as applicable.

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POTENTIAL PAYMENTS UPON TERMINATION OR CHANGE OF CONTROL

SEC regulations require us to disclose potential payments to an NEO in connection with his or her termination or a change of control of NuStar Energy, other than those amounts disclosed under the headings “Pension Benefits For The Year Ended December 31, 2017” and “Nonqualified Deferred Compensation For The Year Ended December 31, 2017” above in this Item 11 or amounts pursuant to arrangements that do not discriminate in favor of executive officers and are generally available to salaried employees. The following narrative and table provide the required disclosures.

None of our NEOs have employment agreements, other than the change of control severance agreements described below. As a result, in the event of a termination, retirement, death or disability that does not occur in connection with a change of control, an NEO will only receive the compensation or benefits to which he or she would already be entitled under the terms of, as applicable, the defined contribution, defined benefit, medical or long-term incentive plans. Therefore, these scenarios are not presented in the table below.

Each of our NEOs has entered into a change of control severance agreement with NuStar Energy and our wholly owned subsidiary, NuStar Services Co. These agreements seek to ensure the continued availability of these executives in the event of a “change of control” (described below). The agreements contain tiers of compensation and benefits based on each NEO’s position. Each tier corresponds to a certain “severance multiple” used to calculate cash severance and other benefits to be provided under the agreements. The following table sets forth the severance multiple applicable to each NEO, based on his or her current officer position.



Name	Applicable Officer Position	Severance Multiple
Barron	Chief Executive Officer	3
Shoaf	Executive Vice President	2.5
Brown	Executive Vice President	2.5
Oliver	Senior Vice President	2
Truby	Senior Vice President	2

If a change of control occurs, the agreements become operative for a fixed three-year period. The agreements provide generally that the NEO’s terms of employment will not be adversely changed during the three-year period after a change of control. In addition, any outstanding unit options held by the NEO will automatically vest, restrictions applicable to any outstanding restricted units held by the NEO will lapse and any unvested performance units held by the NEO will fully vest and become payable at 200% of target. The NEOs also are entitled to receive a payment in an amount sufficient to make the NEO whole for any excise tax on excess parachute payments imposed under Section 4999 of the Code, as set forth in the table below. Each agreement subjects the NEO to obligations of confidentiality, both during the term and after termination, for secret and confidential information that the NEO acquired during his or her employment relating to NuStar Energy, NuStar Services Co and affiliated companies.

For purposes of these agreements, a “change of control” means any of the following (subject to additional particulars as stated in the agreements):


•	the acquisition by an individual, entity or group of beneficial ownership of 40% of NuStar GP Holdings’ voting interests;


•	the failure of NuStar GP Holdings to control NuStar GP, LLC, NuStar Energy’s general partner, Riverwalk Logistics, L.P., or all of the general partner interests of NuStar Energy;


•	Riverwalk Logistics, L.P. ceases to be NuStar Energy’s general partner or Riverwalk Logistics, L.P. is no longer controlled by either NuStar GP, LLC or one of its affiliated companies;


•	the acquisition of more than 50% of all voting interests of NuStar Energy then outstanding;


•	certain consolidations or mergers of NuStar GP Holdings;


•	certain consolidations or mergers of NuStar Energy;


•	the sale of all or substantially all of the assets of NuStar GP Holdings to anyone other than its affiliated companies;


•	the sale of all or substantially all of the assets of NuStar Energy to anyone other than its affiliated companies; or


•	a change in the composition of the NuStar GP Holdings board of directors so that fewer than a majority of those directors are “incumbent directors” as defined in the agreements.

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In the agreements, “cause” is defined to mean, generally, the willful and continued failure of the NEO to perform substantially his or her duties, or the willful engaging by the NEO in illegal or gross misconduct that is materially and demonstrably injurious to NuStar Energy, NuStar Services Co or any affiliated company.

“Good reason” is defined to mean, generally:


•	a diminution in the NEO’s position, authority, duties or responsibilities;


•	failure of the successor of NuStar Energy or NuStar Services Co to assume and perform under the agreement; and


•	relocation of the NEO or increased travel requirements.

Except as otherwise noted, the values in the table below assume that a change of control occurred on December 31, 2017 and that the NEO’s employment terminated on that date.

Under the change of control severance agreements, if an NEO’s employment is terminated for “cause” following a change of control, the NEO will not receive any additional benefits or compensation as a result of the termination and will only receive accrued salary or vacation pay that remained unpaid through the date of termination and any other benefits that the NEO would already be entitled to receive, if any. Therefore, there is no presentation of termination for “cause” in the table below.

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Executive Benefits and Payments⁽¹⁾	Termination of Employment by the Employer Other Than for “Cause,” Death or Disability, or by the Executive for “Good Reason” ($)⁽²⁾		Termination of Employment because of Death or Disability ($)⁽³⁾		Termination by the Executive Other Than for “Good Reason” ($)⁽⁴⁾		Continued Employment Following Change of Control ($)⁽⁵⁾
Salary ⁽¹⁾
Barron		1,776,750		—		—		—
Shoaf	900,500		—		—		—
Brown	970,000		—		—		—
Oliver	656,000		—		—		—
Truby	610,000		—		—		—
Bonus ⁽¹⁾
Barron		3,200,000		800,000		800,000		800,000
Shoaf	1,125,432		321,552		321,552		321,552
Brown	1,212,005		346,287		346,287		346,287
Oliver	784,761		261,587		261,587		261,587
Truby	630,000		210,000		210,000		210,000
Pension and Excess Pension Benefits
Barron		424,576		—		—		—
Shoaf	247,975		—		—		—
Brown	348,378		—		—		—
Oliver	142,462		—		—		—
Truby	137,743		—		—		—
Contributions under Defined Contribution Plans
Barron		157,547		—		—		—
Shoaf	58,564		—		—		—
Brown	139,321		—		—		—
Oliver	55,184		—		—		—
Truby	41,755		—		—		—
Health and Welfare Plan Benefits ⁽⁶⁾
Barron		43,932		—		—		—
Shoaf	53,709		—		—		—
Brown	28,662		—		—		—
Oliver	42,209		—		—		—
Truby	27,566		—		—		—

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Executive Benefits and Payments⁽¹⁾	Termination of Employment by the Employer Other Than for “Cause,” Death or Disability, or by the Executive for “Good Reason” ($)⁽²⁾		Termination of Employment because of Death or Disability ($)⁽³⁾		Termination by the Executive Other Than for “Good Reason” ($)⁽⁴⁾		Continued Employment Following Change of Control ($)⁽⁵⁾
Accelerated Vesting of Unit Options
Barron		—		—		—		—
Shoaf		—		—		—		—
Brown		—		—		—		—
Oliver		—		—		—		—
Truby		—		—		—		—
Accelerated Vesting of Restricted Units ⁽⁷⁾
Barron		1,488,225		1,488,225		1,488,225		1,488,225
Shoaf	679,306		679,306		679,306		679,306
Brown	742,561		742,561		742,561		742,561
Oliver	483,903		483,903		483,903		483,903
Truby	387,284		387,284		387,284		387,284
Accelerated Vesting of Performance Units ⁽⁸⁾
Barron		1,346,552		1,346,552		1,346,552		1,346,552
Shoaf	613,676		613,676		613,676		613,676
Brown	660,996		660,996		660,996		660,996
Oliver	465,542		465,542		465,542		465,542
Truby	326,096		326,096		326,096		326,096
280G Tax Gross-Up ⁽⁹⁾
Barron		3,312,255		—		—		—
Shoaf	1,350,583		—		—		—
Brown	1,388,646		—		—		—
Oliver	—		—		—		—
Truby	777,507		—		—		—
Totals
Barron		11,749,837		3,634,777		3,634,777		3,634,777
Shoaf	5,029,745		1,614,534		1,614,534		1,614,534
Brown	5,490,569		1,749,844		1,749,844		1,749,844
Oliver	2,630,061		1,211,032		1,211,032		1,211,032
Truby	2,937,951		923,380		923,380		923,380

(1)

Per SEC regulations, for purposes of this analysis we assumed each NEO’s compensation at the time of each triggering event to be as stated below. The listed salary is the NEO’s actual annualized rate of pay as of December 31, 2017. The listed bonus amount (referred to in these footnotes as the Highest Annual Bonus) represents the highest bonus earned by the executive with respect to any of the fiscal years 2014, 2015 and 2016 (the three full fiscal years prior to the date of the assumed change of control) or the most recent fiscal year (2017):



Name	Annual Salary ($)	Highest Annual Bonus ($)
Barron	592,250	800,000
Shoaf	360,200	321,552
Brown	388,000	346,287
Oliver	328,000	261,587
Truby	305,000	210,000


(2)	The change of control severance agreements provide that if the employer terminates the NEO’s employment (other than for “cause,” death or “disability,” as defined in the agreements) or if the NEO terminates his or her employment for “good reason,” as defined in the agreements, the NEO is generally entitled to receive the following:

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(A) a lump sum cash payment equal to the sum of:


(i)	accrued and unpaid compensation through the date of termination, including a pro-rata annual bonus based on the Highest Annual Bonus;


(ii)	the NEO’s severance multiple multiplied by the sum of the NEO’s annual base salary plus the NEO’s Highest Annual Bonus;


(iii)	the amount of the excess of the actuarial present value of the pension benefits (qualified and nonqualified) the NEO would have received for an additional number of years of service equal to the NEO’s severance multiple over the actuarial present value of the NEO’s actual pension benefits; and


(iv)	the equivalent of employer contributions under the tax-qualified and supplemental defined contribution plans for the number of years equal to the NEO’s severance multiple;

(B) continued welfare benefits for a number of years equal to the NEO’s severance multiple; and

(3)

If the NEO’s employment is terminated by reason of his or her death or disability, then his or her estate or beneficiaries will be entitled to receive a lump sum cash payment equal to any accrued and unpaid salary and vacation pay plus a bonus equal to the Highest Annual Bonus earned by the NEO (prorated to the date of termination). In addition, in the case of disability, the NEO would be entitled to any disability and related benefits at least as favorable as those provided by us under our plans and programs during the 120-days prior to the NEO’s termination of employment. In addition, all outstanding equity incentive awards will automatically vest on the date of the change of control, as described above.

(4)

If the NEO voluntarily terminates his or her employment other than for “good reason,” then he or she will be entitled to a lump sum cash payment equal to any accrued and unpaid salary and vacation pay plus a bonus equal to the Highest Annual Bonus earned by the NEO (prorated to the date of termination). In addition, all outstanding equity incentive awards will automatically vest on the date of the change of control, as described above.

(5)

The change of control severance agreements provide for a three-year term of employment following a change of control. The agreements generally provide that the NEO will continue to receive a salary and bonus at least as favorable as the highest salary received during the past 12 months and the highest bonus received during the past three years and will continue to receive benefits on terms at least as favorable as in effect prior to the change of control. Accordingly, no additional amounts are shown for salary, pension and excess pension benefits, contributions under defined contribution plans and health and welfare plan benefits because those amounts would remain as in effect at the time of a change of control. The amount shown as bonus reflects each NEO’s Highest Annual Bonus. In addition, all outstanding equity incentive awards will automatically vest on the date of the change of control, as described above.


(6)	The NEO is entitled to coverage under the welfare benefit plans (e.g., health, dental, etc.) for a number of years following the date of termination equal to the NEO’s severance multiple.

(7)

The amounts stated in the table represent the gross value of previously unvested restricted units, derived by multiplying (x) the number of units whose restrictions lapsed because of the change of control, times (y) (as applicable) $29.95 (the closing price of NuStar Energy’s common units on the NYSE on December 29, 2017, the last trading day of 2017) or $15.70 (the closing price of NuStar GP Holdings’ common units on the NYSE on December 29, 2017, the last trading day of 2017).


(8)	The amounts stated in the table represent the product of (x) the number of performance units whose vesting was accelerated because of the change of control, times (y) 200%, times (z) $29.95 (the closing price of NuStar Energy’s common units on the NYSE on December 29, 2017, the last trading day of 2017).

(9)

If any payment or benefit is determined to be subject to an excise tax under Section 4999 of the Code, the impacted NEO is entitled to receive an additional payment to adjust for the incremental tax cost of the payment or benefit. However, if it is determined that the NEO is entitled to receive an additional payment to adjust for the incremental tax cost but the value of all payments to the NEO does not exceed 110% of 2.99 times the NEO’s “base amount” (as defined by Section 280G(b)(3) of the Code) (the Safe Harbor Amount), the additional payment will not be made and the amount payable to the NEO will be reduced so that the aggregate value of all payments equals the Safe Harbor Amount.

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DIRECTOR COMPENSATION

FOR THE YEAR ENDED DECEMBER 31, 2017

The following table provides a summary of compensation paid for the year ended December 31, 2017 to the directors who served on the Board during 2017. The table shows amounts earned by such persons for services rendered to NuStar GP, LLC in all capacities in which they served during 2017.

Name

Fees Earned or Paid in Cash

($)⁽¹⁾

Unit Awards

($)⁽²⁾

Non-Equity

Incentive Plan

Compensation

($)⁽³⁾

Change in Pension

Value and

Nonqualified

Deferred

Compensation

Earnings

($)⁽³⁾

All Other

Compensation

($)

TOTAL

($)

William E. Greehey

141,167

119,977

N/A

—

261,144

Bradley C. Barron

⁽⁴⁾

⁽⁴

⁾

⁽⁴

⁾

⁽⁴⁾

⁽⁴

⁾

⁽⁴

⁾

J. Dan Bates

106,667

94,994

N/A

—

201,661

Dan J. Hill

121,667

94,994

N/A

—

216,661

Robert J. Munch

90,667

94,994

N/A

—

185,661

W. Grady Rosier

97,167

94,994

N/A

—

192,161


(1)	The amounts disclosed in this column exclude reimbursement for expenses for transportation to and from Board meetings and lodging while attending meetings.

(2)

The amounts reported for Messrs. Greehey, Bates, Hill and Rosier represent the grant date fair value for the November 16, 2017 grant of restricted NuStar Energy units to them as non-employee directors for the fiscal year ended December 31, 2017 (4,106 restricted units for Mr. Greehey, as Chairman, and 3,251 restricted units for each of Messrs. Bates, Hill, Munch and Rosier) based on the closing price of NuStar Energy’s common units on the NYSE on November 16, 2017 ($29.22). Please see “Compensation Discussion and Analysis-Impact of Accounting and Tax Treatments-Accounting Treatment” above in this Item 11 and Note 23 of the Notes to Consolidated Financial Statements in Item 8 for information regarding the assumptions made in the valuation.

As of December 31, 2017, each director listed in the table above held the following aggregate number of NuStar Energy restricted units. None of the directors had outstanding unit options as of December 31, 2017.



Name	Aggregate # of Restricted Units
Greehey	6,336
Barron	*
Bates	4,924
Hill	4,924
Munch	5,989
Rosier	4,924

* Mr. Barron’s aggregate holdings are disclosed above in the Outstanding Equity Awards at December 31, 2017 table in this Item 11.


(3)	Non-employee directors do not participate in these plans.


(4)	Mr. Barron was not compensated for his service as a director of NuStar GP, LLC. His compensation for his services as President and Chief Executive Officer is included above in the Summary Compensation Table.

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Directors who are our employees receive no compensation (other than reimbursement of expenses) for serving as directors. The compensation structure for our non-employee directors consists of the following components: (1) an annual cash retainer; (2) an annual restricted unit grant; (3) an additional cash payment for each meeting attended in-person and telephonically; (4) an additional annual cash retainer for each committee chair; (5) an additional annual retainer for the Chairman of the Board, which includes both cash and restricted units; and (6) an additional annual cash retainer for the lead director.

During 2017, the Compensation Committee engaged EPPA to review our non-employee directors’ compensation. Based on its review, EPPA recommended, and our Board and Compensation Committee approved effective July 27, 2017, increasing the annual cash retainer from $60,000 to $70,000 and increasing the value of the annual equity award from $75,000 to $95,000, resulting in the compensation structure for our non-employee directors set forth in the table below.



Non-Employee Director Compensation Component	Amount
Annual Cash Retainer ($)	70,000
Annual Restricted Unit Grant ($ value of restricted units)	95,000
Per Meeting Fees (in-person attendance) ($)	1,500
Per Meeting Fees (telephonic attendance) ($)	500
Annual Audit and Compensation Committee Chair Additional Retainers ($)	15,000
Annual Nominating, Governance and Conflicts Committee Chair Additional Retainer ($)	10,000
Annual Chairman of the Board Retainer ($25,000 value in restricted units/$50,000 cash)	75,000
Annual Lead Director Additional Retainer ($)	15,000

As described above, we supplement the cash compensation paid to non-employee directors with an annual grant of restricted NuStar Energy units that vests in equal annual installments over a three-year period. We believe this annual grant of restricted units increases the non-employee directors’ identification with the interests of NuStar Energy’s unitholders through ownership of NuStar Energy common units. Upon a non-employee director’s initial election to the Board, the director will receive a grant of restricted units.

In the event of a “change of control” as defined in the 2000 LTIP, all unvested restricted units previously granted immediately become vested. The 2000 LTIP also contains anti-dilution provisions providing for an adjustment in the number of restricted units that have been granted to prevent dilution of benefits in the event there is a change in the capital structure of NuStar Energy that affects the NuStar Energy units. Each of our directors has agreed and acknowledged that the Merger will not be deemed to trigger a “change of control” as defined under any NuStar Energy or NuStar GP Holdings plan or award, and has waived any rights to vesting, payment or other benefit thereunder that would arise upon a “change of control,” to which he might otherwise have been entitled.

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ITEM 12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED UNITHOLDER MATTERS

SECURITY OWNERSHIP OF MANAGEMENT AND DIRECTORS

The following table sets forth information as of February 20, 2018 regarding: (1) NuStar Energy common units, 8.50% Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units (Series A Preferred Units) and 7.625% Series B Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units (Series B Preferred Units); and (2) NuStar GP Holdings common units, in each case beneficially owned (or deemed beneficially owned) by each director, each named executive officer and all of our directors and executive officers as a group. Unless otherwise indicated in the notes to the table, each of the named persons and members of the group has sole voting and investment power with respect to the units shown and none of the units shown are pledged as security. None of the named persons or members of the group beneficially owns (or is deemed to beneficially own) any NuStar Energy 9.00% Series C Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units.



	NuStar Energy L.P.							NuStar GP Holdings, LLC
	Common Units			Series A Preferred Units		Series B Preferred Units		Common Units
Name of Beneficial Owner ⁽¹⁾	Number of Units Beneficially Owned ⁽²⁾	Percentage of Units Beneficially Owned ⁽²⁾		Number of Units Beneficially Owned ⁽²⁾	Percentage of Units Beneficially Owned ⁽²⁾	Number of Units Beneficially Owned ⁽²⁾	Percentage of Units Beneficially Owned ⁽²⁾	Number of Units Beneficially Owned ⁽²⁾	Percentage of Units Beneficially Owned ⁽²⁾
William E. Greehey ⁽³⁾	3,480,533	3.7	%	—	*	—	*	9,178,320	21.4	%
Bradley C. Barron	53,640	*		—	*	—	*	31,540	*
J. Dan Bates ⁽⁴⁾	33,107	*		—	*	—	*	—	*
Dan J. Hill ⁽⁵⁾	28,149	*		—	*	8,000	*	—	*
Robert J. Munch	2,406	*		1,000	*	—	*	—	*
W. Grady Rosier ⁽⁶⁾	35,035	*		—	*	12,000	*	—	*
Mary Rose Brown	59,125	*		—	*	—	*	46,977	*
Thomas R. Shoaf	25,137	*		—	*	—	*	12,022	*
Daniel S. Oliver	30,628	*		—	*	—	*	12,920	*
Michael Truby	16,633	*		—	*	—	*	1,028	*

All directors and executive officers as a group (13 people) ⁽⁷⁾	3,797,807	4.1	%	1,000	*	20,000	*	9,286,349	21.6	%

* Indicates that the percentage of beneficial ownership does not exceed 1% of the class.


(1)	The business address for all beneficial owners listed above is 19003 IH-10 West, San Antonio, Texas 78257.

(2)

As of February 20, 2018, 93,182,030 NuStar Energy common units, 9,060,000 NuStar Energy Series A Preferred Units, 15,400,000 NuStar Energy Series B Preferred Units, 6,900,000 NuStar Energy Series C Preferred Units and 42,953,132 NuStar GP Holdings common units were outstanding. Beneficial ownership is calculated in accordance with Rule 13d-3 of the Exchange Act. Restricted units awarded under NuStar GP, LLC’s long-term incentive plan and phantom units (which we refer to as “restricted units” for purposes of Part III of this Annual Report on Form 10-K) awarded under NuStar GP Holdings’ long-term incentive plan are rights to receive NuStar Energy common units or NuStar GP Holdings common units, respectively, upon vesting and, as such, may not be disposed of or voted until vested. The restricted units do not vest within 60 days after February 20, 2018. Accordingly, the restricted units set forth in the table below are not included in the calculation of beneficial ownership pursuant to Rule 13d-3 and are not reflected in the table above. As described below in Item 13, on February 7, 2018, we, Riverwalk Logistics, L.P., NuStar GP, LLC, Merger Sub, Riverwalk Holdings, LLC and NuStar GP Holdings entered into the Merger Agreement pursuant to which Merger Sub will merge with and into NuStar GP Holdings with NuStar GP Holdings being the surviving entity, such that we will be the sole member of NuStar GP Holdings following the Merger. At the effective time of the Merger, each NuStar GP Holdings common unit outstanding will be converted into the right to receive 0.55 of a NuStar Energy common unit and each award of NuStar GP Holdings restricted units will be converted into an award of NuStar Energy restricted units, in each case as provided in the Merger Agreement.

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	Restricted Units Not Reflected in Table Above
Name	NuStar Energy L.P.	NuStar GP Holdings, LLC
William E. Greehey	6,336	10,558
Bradley C. Barron	35,272	27,505
J. Dan Bates	4,924	—
Dan J. Hill	4,924	—
Robert J. Munch	5,166	—
W. Grady Rosier	4,924	—
Mary Rose Brown	17,607	13,709
Thomas R. Shoaf	16,102	12,551
Daniel S. Oliver	11,479	8,924
Michael Truby	9,650	6,259
All directors and executive officers as a group (13 people)	140,897	97,670


(3)	The number of NuStar GP Holdings common units shown as beneficially owned by Mr. Greehey includes 385,889 common units owned indirectly by Mr. Greehey through a limited liability company.


(4)	The number of NuStar Energy common units shown as beneficially owned by Mr. Bates includes 28,526 common units owned indirectly by Mr. Bates through a trust.


(5)	The number of NuStar Energy common units shown as beneficially owned by Mr. Hill includes 600 common units owned indirectly by Mr. Hill through his spouse.


(6)	The number of NuStar Energy common units shown as beneficially owned by Mr. Rosier includes an aggregate of 29,215 common units owned indirectly by Mr. Rosier through two trusts.

(7)

The number of NuStar Energy common units shown as beneficially owned by all directors and executive officers as a group includes 28,526 common units owned indirectly by Mr. Bates, 600 common units owned indirectly by Mr. Hill and 29,215 common units owned indirectly by Mr. Rosier, as described above. The number of NuStar GP Holdings common units shown as beneficially owned by all directors and executive officers as a group includes 385,889 common units owned indirectly by Mr. Greehey.

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS

The following table sets forth information as of December 31, 2017 regarding each entity known to us to be the beneficial owner of more than 5% of NuStar Energy’s outstanding common units, and is based solely upon reports filed by such entities with the SEC.



Name and Address of Beneficial Owner	Number of Common Units Beneficially Owned	Percentage of Common Units Beneficially Owned⁽¹⁾
NuStar GP Holdings ⁽²⁾	10,214,626	11.0	%
OppenheimerFunds, Inc. ⁽³⁾	6,732,640	7.2	%
ALPS Advisors, Inc. ⁽⁴⁾	6,571,734	7.1	%


(1)	As of December 31, 2017, there were 93,176,683 NuStar Energy common units issued and outstanding.


(2)	As of December 31, 2017, NuStar GP Holdings owns these NuStar Energy common units through its wholly owned subsidiaries, NuStar GP, LLC and Riverwalk Holdings, LLC. NuStar GP Holdings controls voting and investment power over the common units through these wholly owned subsidiaries. NuStar GP Holdings’ business address is 19003 IH-10 West, San Antonio, Texas 78257.

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(3)	As reported on a Schedule 13G/A filed on February 6, 2018, OppenheimerFunds, Inc. (OFI) is an investment adviser that may be deemed to beneficially own, and has shared voting and dispositive power with respect to, 6,732,640 common units. OFI’s business address is 225 Liberty Street, New York, New York 10281.

(4)

As reported on a Schedule 13G/A filed on February 6, 2018, ALPS Advisors, Inc. (AAI) is an investment adviser that may be deemed to beneficially own, and has shared voting and dispositive power with respect to, 6,571,734 common units. The 6,571,734 common units that AAI may be deemed to beneficially own include 6,549,442 common units that Alerian MLP ETF (Alerian), an investment company, may be deemed to beneficially own. Alerian has shared voting and dispositive power with respect to the 6,549,442 common units. AAI disclaims beneficial ownership of the common units pursuant to Rule 13d-4 of the Securities Exchange Act of 1934. The business address of AAI and Alerian is 1290 Broadway, Suite 1100, Denver, Colorado 80203.

EQUITY COMPENSATION PLAN INFORMATION

The following table sets forth information as of December 31, 2017 about the equity compensation plan under which securities of NuStar Energy are issuable, which is described in further detail in Note 23 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data.”



Plan categories	Number of securities to be issued upon exercise of outstanding unit options, warrants and rights (#)	Weighted-average exercise price of outstanding unit options, warrants and rights ($) ⁽¹⁾	Number of securities remaining for future issuance under equity compensation plans (#)
Equity Compensation Plans approved by security holders ⁽²⁾	902,911	—	679,045
Equity Compensation Plans not approved by security holders	—	—	—


(1)	No value is included in this column because there were no unit options outstanding as of December 31, 2017 and because restricted units and performance units do not have an exercise price.


(2)	The information in this row relates to the 2000 LTIP. See the “Compensation Discussion and Analysis” section of Item 11 above for further details regarding the 2000 LTIP.

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ITEM 13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE

TRANSACTIONS WITH MANAGEMENT AND OTHERS

In January 2007, our Board adopted a written related person transaction policy that codifies our prior practice. For purposes of the policy, a related person transaction is one that is not available to all employees generally or involves $10,000 or more when aggregated with similar transactions. The policy requires that any related person transaction between NuStar Energy or NuStar GP, LLC and: (1) any vice president, Section 16 officer, director or any other person designated for these purposes as an officer by the Board; (2) any unitholder owning greater than 5% of NuStar Energy, its controlled affiliates or NuStar GP Holdings; (3) any immediate family member of any officer or director; or (4) any entity owned or controlled by any of (1), (2) or (3) (or in which any of (1), (2) or (3) owns a 5% or greater ownership interest or controls such entity) must be approved by the disinterested members of the Board. In addition, the policy requires that the officers and directors have an affirmative obligation to inform and provide updates to our Corporate Secretary regarding his or her immediate family members, as well as any entities in which he or she controls or owns 5% or more.

Please see “Potential Payments upon Termination or Change of Control” in Item 11 for a discussion of our change of control severance agreements with the NEOs.

On December 10, 2007, NuStar Logistics, L.P., our wholly owned subsidiary, entered into a non-exclusive Aircraft Time Sharing Agreement (the Time Share Agreement) with William E. Greehey, Chairman of our Board. The Time Share Agreement provides that NuStar Logistics, L.P. will sublease the aircraft to Mr. Greehey on an “as needed and as available” basis, and will provide a fully qualified flight crew for all of Mr. Greehey’s flights. Mr. Greehey will pay NuStar Logistics, L.P. an amount equal to the maximum amount of expense reimbursement permitted in accordance with Section 91.501(d) of the Aeronautics Regulations of the Federal Aviation Administration and the Department of Transportation, which expenses include and are limited to: fuel oil, lubricants and other additives; travel expenses of the crew, including food, lodging and ground transportation; hangar and tie down costs away from the aircraft’s base of operation; insurance obtained for the specific flight; landing fees, airport taxes and similar assessments; customs, foreign permit and similar fees directly related to the flight; in-flight food and beverages; passenger ground transportation; flight planning and weather contract services; and an additional charge equal to 100% of the costs of the fuel oil, lubricants and other additives. The Time Share Agreement had an initial term of two years, and automatically renews for one-year terms until terminated by either party. The Time Share Agreement was approved by the disinterested members of the Board on December 5, 2007. The Time Share Agreement was amended as of September 4, 2009 to reflect the addition of another aircraft and as of August 18, 2017 to reflect a change in the aircraft owner trustee.

On April 24, 2008, the independent directors of NuStar GP, LLC approved the adoption of a Services Agreement, effective January 1, 2008, between NuStar GP, LLC and NuStar Energy (the Services Agreement). Pursuant to the Services Agreement, NuStar GP, LLC historically furnished all services necessary for the conduct of the business of NuStar Energy, and NuStar Energy reimbursed NuStar GP, LLC for all payroll and related benefit costs, including pension and unit-based compensation costs, other than the expenses allocated to NuStar GP Holdings. The expenses allocated to NuStar GP Holdings under the Services Agreement equaled to $1.1 million (as adjusted), plus 1.0% of NuStar GP, LLC’s domestic employee bonus and unit compensation expense for the applicable fiscal year, subject to adjustment (1) by an annual amount equal to NuStar GP, LLC’s annual merit increase percentage for the most recently completed contract year and (2) for changed levels of services due to expansion of operations through, among other things, expansion of operations, acquisitions or the construction of new businesses or assets. On March 1, 2016, NuStar GP, LLC transferred and assigned to NuStar Services Co, a wholly owned subsidiary of NuStar Energy, employment of all of NuStar GP, LLC’s employees. Our executive officers continue to serve as officers of NuStar GP Holdings and NuStar GP, LLC, and also serve as officers of NuStar Services Co and other NuStar Energy subsidiaries. In connection with the transfer and assignment, we amended and restated the Services Agreement (the Amended and Restated Services Agreement) such that, beginning March 1, 2016, NuStar GP Holdings and NuStar Energy receive all management and administrative services from NuStar Services Co. NuStar Energy reimburses NuStar Services Co for all services provided to NuStar Energy, including payroll and benefit costs, as well as NuStar Energy unit-based compensation costs. NuStar GP Holdings pays NuStar Services Co an administrative services fee of $1.0 million per year, subject to adjustment (1) by an annual amount equal to NuStar Services Co’s annual merit increase percentage for the most recently completed fiscal year and (2) for changed levels of services due to expansion of operations through acquisitions, construction of new businesses or assets or otherwise. For 2017 the administrative services fee was approximately $900,000. Beginning March 1, 2016, NuStar GP Holdings no longer pays 1.0% of our domestic bonus and unit compensation expenses. Instead, NuStar GP Holdings retains the expense associated with any NuStar GP Holdings common unit awards or other compensation that it provides to its officers.

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John D. Greehey, an employee, is the son of Mr. Greehey. As such, he is deemed to be a “related person” under Item 404(a) of the SEC’s Regulation S-K. Mr. J. Greehey is a Vice President of certain subsidiaries of NuStar Energy. In 2017, Mr. J. Greehey did not attend any Board or Committee meetings. The aggregate value of compensation paid to Mr. J. Greehey in 2017 was less than $500,000. There were no material differences between the compensation paid to Mr. J. Greehey and the compensation paid to any other employees who hold analogous positions.

RIGHTS OF NUSTAR GP HOLDINGS

Due to its ownership of NuStar GP, LLC and Riverwalk Holdings, LLC, as of December 31, 2017, NuStar GP Holdings indirectly owned:


•	the general partner interest in NuStar Energy, through its indirect 100% ownership interest in Riverwalk Logistics, L.P.;


•	100% of the incentive distribution rights issued by us, which entitle NuStar GP Holdings to receive increasing percentages of the cash we distribute; and


•	10,214,626 NuStar Energy common units.

Certain of our officers also are officers of NuStar GP Holdings. Our Chairman, Mr. Greehey, also is the Chairman of Board and, as of December 31, 2017, beneficially owned approximately 21% of the common units of NuStar GP Holdings. NuStar GP Holdings appoints NuStar GP, LLC’s directors. NuStar GP, LLC’s board is responsible for overseeing NuStar GP, LLC’s role as the owner of the general partner of NuStar Energy. NuStar GP Holdings must also approve matters that have or would reasonably be expected to have a material effect on NuStar GP Holdings’ interests as one of our major unitholders.

NuStar Energy’s partnership agreement requires that NuStar GP, LLC maintain a Conflicts Committee, composed entirely of independent directors, to review and resolve certain potential conflicts of interest between Riverwalk Logistics, L.P. and its affiliates, on the one hand, and NuStar Energy, on the other.

MERGER AGREEMENT

On February 7, 2018, NuStar Energy, Riverwalk Logistics, L.P., NuStar GP, LLC, Merger Sub, Riverwalk Holdings, LLC and NuStar GP Holdings entered into the Merger Agreement pursuant to which Merger Sub will merge with and into NuStar GP Holdings with NuStar GP Holdings being the surviving entity, such that NuStar Energy will be the sole member of NuStar GP Holdings following the Merger. Pursuant to the Merger Agreement and at the effective time of the Merger, NuStar Energy’s partnership agreement will be amended and restated to, among other things, (1) cancel the incentive distribution rights held by the general partner, (2) convert the 2% general partner interest in NuStar Energy held by the general partner into a non-economic management interest and (3) provide the holders of NuStar Energy common units with voting rights in the election of the members of the Board of NuStar GP, LLC at an annual meeting, beginning in 2019.

The Merger Agreement contains customary representations and warranties and covenants by each of the parties. Completion of the Merger is conditioned upon, among other things: (1) approval of the Merger Agreement by the affirmative vote of holders of a Unit Majority, as defined in the Second Amended and Restated Limited Liability Company Agreement of NuStar GP Holdings, as amended; (2) the effectiveness of a registration statement on Form S-4 with respect to the issuance by NuStar Energy of its common units in connection with the Merger; (3) the absence of certain legal injunctions or impediments prohibiting the transactions; (4) the receipt of certain tax opinions from a nationally recognized tax counsel; and (5) the approval for the listing on the New York Stock Exchange of NuStar Energy’s common units to be issued in the Merger.

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NuStar Energy entered into a Support Agreement, dated as of February 7, 2018 (the Support Agreement), with Merger Sub, WLG Holdings, LLC, a Texas limited liability company controlled by Mr. Greehey (WLG Holdings), Mr. Greehey (together, WLG Holdings and Mr. Greehey are referred to as the Greehey Unitholders), and, for limited purposes, NuStar GP Holdings, pursuant to which the Greehey Unitholders have agreed to vote in favor of the approval and adoption of the Merger Agreement, the approval of the Merger and any other action required in furtherance thereof submitted for the vote or written consent of NuStar GP Holdings unitholders. The Support Agreement will terminate (1) at the effective time of the Merger, (2) upon the termination of the Merger Agreement as provided therein, or (3) at such time as NuStar Energy and the Greehey Unitholders agree in writing to terminate the Support Agreement.

After the Merger, the NuStar GP, LLC Board is expected to consist of nine members, initially composed of the six members of the NuStar GP, LLC Board and the three independent directors of the board of directors of NuStar GP Holdings, LLC.

DIRECTOR INDEPENDENCE

Our business is managed under the direction of the Board of NuStar GP, LLC, the general partner of Riverwalk Logistics, L.P., the general partner of NuStar Energy. The Board conducts its business through meetings of the Board and its committees. The Board has standing Audit, Compensation and Nominating/Governance & Conflicts Committees. Each committee has a written charter. During 2017, the Board held ten meetings, the Audit Committee held eight meetings, the Compensation Committee held four meetings and the Nominating/Governance & Conflicts Committee held one meeting. No member of the Board attended less than 75% of the meetings of the Board and committees during the period in which he was a member during 2017.

INDEPENDENT DIRECTORS

The Board has one member of management, Mr. Barron, President and Chief Executive Officer, and five non-management directors. As a limited partnership, NuStar Energy is not required to have a majority of independent directors. However, the Board has determined that four of five of its current non-management directors meet the independence requirements of the NYSE listing standards as set forth in the NYSE Listed Company Manual. The independent directors are: Mr. Bates, Mr. Hill, Mr. Munch and Mr. Rosier.

Mr. Greehey, Chairman of the Board, also serves as the Chairman of the NuStar GP Holdings board of directors and, as of December 31, 2017, beneficially owned approximately 21% of the common units of NuStar GP Holdings. Mr. Greehey is not an independent director under the NYSE’s listing standards.

Mr. Barron has been President and Chief Executive Officer of NuStar GP, LLC since January 2014. Mr. Barron also serves as President and Chief Executive Officer of NuStar GP Holdings. As a member of management, Mr. Barron is not an independent director under the NYSE’s listing standards.

The Audit, Compensation and Nominating/Governance & Conflicts Committees of the Board are each composed entirely of directors who meet the independence requirements of the NYSE listing standards. Each member of the Audit Committee also meets the additional independence standards for Audit Committee members set forth in the regulations of the SEC. For further information about the committees, see also Item 10 and Item 11 above.

INDEPENDENCE DETERMINATIONS

Under the NYSE’s listing standards, no director qualifies as independent unless the Board affirmatively determines that the director has no material relationship with NuStar Energy. Based upon information requested annually from and provided by each director concerning their background, employment and affiliations, including commercial, industrial, banking, consulting, legal, accounting, charitable and familial relationships, the Board has determined that, other than being a director of NuStar GP, LLC, a unitholder of NuStar Energy and/or a unitholder of NuStar GP Holdings, each of the independent directors named above has either no relationship with NuStar Energy, either directly or as a partner, equityholder or officer of an organization that has a relationship with NuStar Energy, or has only immaterial relationships with NuStar Energy, and is therefore independent under the NYSE’s listing standards.

As provided for under the NYSE listing standards, the Board has adopted categorical standards or guidelines to assist the Board in making its independence determinations with respect to each director. Under the NYSE listing standards, immaterial relationships that fall within the guidelines are not required to be disclosed in this Annual Report on Form 10-K.

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A relationship falls within the guidelines adopted by the Board if it:


•	is not a relationship that would preclude a determination of independence under Section 303A.02(b) of the NYSE Listed Company Manual;


•	consists of charitable contributions by NuStar Energy to an organization where a director is an executive officer and does not exceed the greater of $1 million or 2% of the organization’s gross revenue in any of the last three years;


•	consists of charitable contributions by NuStar Energy to any organization with which a director, or any member of a director’s immediate family, is affiliated as an officer, director or trustee pursuant to a matching gift program of NuStar Energy and made on terms applicable to employees and directors generally, or is in amounts that do not exceed $250,000 per year; and


•	is not required to be disclosed in this Annual Report on Form 10-K.

Our Corporate Governance Guidelines contain the director qualification standards, including the guidelines listed above, and are available on NuStar Energy’s website at www.nustarenergy.com (in the “Investors” section) or are available in print upon request to NuStar GP, LLC’s Corporate Secretary at the address indicated on the cover page of this Annual Report on Form 10-K or corporatesecretary@nustarenergy.com.

PRESIDING DIRECTOR/MEETINGS OF NON-MANAGEMENT DIRECTORS

The Board has designated Mr. Hill to serve as the Presiding Director for meetings of the non-management Board members outside the presence of management.

COMMUNICATIONS WITH THE BOARD, NON-MANAGEMENT DIRECTORS OR PRESIDING DIRECTOR

Unitholders and other interested parties may communicate with the Board, the non-management directors or the Presiding Director by sending a written communication in an envelope addressed to “Board of Directors,” “Non-Management Directors,” or “Presiding Director” in care of NuStar GP, LLC’s Corporate Secretary at the address indicated on the cover page of this Annual Report on Form 10-K or corporatesecretary@nustarenergy.com.

AVAILABILITY OF GOVERNANCE DOCUMENTS

NuStar Energy has posted its Corporate Governance Guidelines, Code of Business Conduct and Ethics, Code of Ethics for Senior Financial Officers and the Charters of the Audit Committee, Compensation Committee and Nominating/Governance & Conflicts Committee on NuStar Energy’s website at www.nustarenergy.com (in the “Investors” section). NuStar Energy’s governance documents are available in print to any unitholder of record who makes a written request to NuStar Energy. Requests must be directed to NuStar GP, LLC’s Corporate Secretary at the address indicated on the cover page of this Annual Report on Form 10-K or corporatesecretary@nustarenergy.com.

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ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

KPMG FEES

The aggregate fees for professional services rendered to us by KPMG for the years ended December 31, 2017 and 2016 were:



Category of Service	2017		2016
Audit fees ⁽¹⁾	$	3,227,500	$	2,633,321
Audit-related fees ⁽²⁾	3,000		—
Tax fees	—		—
All other fees	—		—
Total	$	3,230,500	$	2,633,321

(1)

Audit fees for 2017 and 2016 were for professional services rendered by KPMG in connection with the audits of our annual financial statements for the years ended December 31, 2017 and 2016, respectively, included in our Annual Reports on Form 10-K, reviews of our interim financial statements included in our Quarterly Reports on Form 10-Q, the audit of the effectiveness of our internal control over financial reporting as of December 31, 2017 and 2016, respectively, and related services that are normally provided by the principal auditor (e.g., comfort letters and assistance with review of documents filed with the SEC).


(2)	Audit-related fees for 2017 were for assurance and related services rendered by KPMG that are reasonably related to the performance of the audit or review of our financial statements and are not reported under “Audit fees.”

AUDIT COMMITTEE PRE-APPROVAL POLICY

The Audit Committee has adopted a pre-approval policy to address the pre-approval of all services to be rendered to us by our independent auditor and ensure that the provision of any non-audit services does not impair the auditor’s independence. None of the services (described above) for 2017 or 2016 provided by KPMG were approved by the Audit Committee pursuant to the pre-approval waiver contained in paragraph (c)(7)(i)(C) of Rule 2-01 of Regulation S-X.

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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, 2017 and 2016 Consolidated Statements of Income for the Years Ended December 31, 2017, 2016 and 2015 Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2017, 2016 and 2015 Consolidated Statements of Cash Flows for the Years Ended December 31, 2017, 2016 and 2015 Consolidated Statements of Partners’ Equity for the Years Ended December 31, 2017, 2016 and 2015 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

2.01	Membership Interest Purchase and Sale Agreement, dated April 11, 2017, by and between NuStar Logistics, L.P., NuStar Energy L.P. and FR Navigator Holdings LLC	NuStar Energy L.P.’s Current Report on Form 8-K filed April 11, 2017 (File No. 001-16417), Exhibit 2.1

2.02	Agreement and Plan of Merger, dated as of February 7, 2018, by and among NuStar Energy L.P., Riverwalk Logistics, L.P., NuStar GP, LLC, Marshall Merger Sub LLC, Riverwalk Holdings, LLC and NuStar GP Holdings, LLC	NuStar Energy L.P.’s Current Report on Form 8-K filed February 8, 2018 (File No. 001-16417), Exhibit 2.1

3.01	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

3.02	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

3.03	Sixth Amended and Restated Agreement of Limited Partnership of NuStar Energy L.P., dated as of November 30, 2017	NuStar Energy L.P.’s Current Report on Form 8-K filed November 30, 2017 (File No. 001-16417), Exhibit 3.1

3.04	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

3.05	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

3.06	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

3.07	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

3.08	First Amendment to Second Amended and Restated Agreement of Limited Partnership of Shamrock Logistics Operations, L.P., effective as of April 16, 2001	NuStar Energy L.P.’s Quarterly Report on Form 10-Q for quarter ended June 30, 2001 (File No. 001-16417), Exhibit 4.1

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Exhibit Number	Description	Incorporated by Reference to the Following Document

3.09	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 Annual Report on Form 10-K for year ended December 31, 2001 (File No. 001-16417), Exhibit 3.10

3.10	Certificate of Limited Partnership of Riverwalk Logistics, L.P., dated as of June 5, 2000	NuStar Energy L.P.’s Registration Statement on Form S-1 filed August 14, 2000 (File No. 333-43668), Exhibit 3.7

3.11	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

3.12	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

3.13	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

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

3.15	First Amended and Restated Limited Liability Company Agreement of Shamrock Logistics GP, LLC, dated as of June 5, 2000	NuStar Energy L.P.’s Amendment No. 5 to Registration Statement on Form S-1 filed March 29, 2001 (File No. 333-43668), Exhibit 3.10

3.16	First Amendment to First Amended and Restated Limited Liability Company Agreement of Shamrock Logistics GP, LLC, effective 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 3.15

3.17	Second Amendment to First Amended and Restated Limited Liability Company Agreement of Valero GP, LLC, effective as of June 1, 2006	NuStar Energy L.P.’s Annual Report on Form 10-K for year ended December 31, 2014 (File No. 001-16417), Exhibit 3.20

3.18	Third Amendment to First Amended and Restated Limited Liability Company Agreement of NuStar GP, LLC, dated as of July 29, 2016 and effective as of March 21, 2007	NuStar Energy L.P.’s Quarterly Report on Form 10-Q for quarter ended June 30, 2016 (File No. 001-16417), Exhibit 3.01

4.01	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	NuStar Energy L.P.’s Current Report on Form 8-K filed July 15, 2002 (File No. 001-16417), Exhibit 4.1

4.02	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.	NuStar Energy L.P.’s Quarterly Report on Form 10-Q for quarter ended June 30, 2005 (File No. 001-16417), Exhibit 4.02

4.03	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	NuStar Energy L.P.’s Annual Report on Form 10-K for year ended December 31, 2008 (File No. 001-16417), Exhibit 4.05

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Exhibit Number	Description	Incorporated by Reference to the Following Document

4.04	Fourth Supplemental Indenture, dated as of April 4, 2008, 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 April 4, 2008 (File No. 001-16417), Exhibit 4.2

4.05	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	NuStar Energy L.P.’s Current Report on Form 8-K filed August 16, 2010 (File No. 001-16417), Exhibit 4.3

4.06	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 February 7, 2012 (File No. 001-16417), Exhibit 4.3

4.07	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	NuStar Energy L.P.’s Current Report on Form 8-K filed August 23, 2013 (File No. 001-16417), Exhibit 4.3

4.08	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	NuStar Energy L.P.’s Current Report on Form 8-K filed April 28, 2017 (File No. 001-16417), Exhibit 4.4

4.09	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	NuStar Energy L.P.’s Current Report on Form 8-K filed January 22, 2013 (File No. 001-16417), Exhibit 4.1

4.10	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	NuStar Energy L.P.’s Current Report on Form 8-K filed January 22, 2013 (File No. 001-16417), Exhibit 4.2

10.01	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	NuStar Energy L.P.’s Current Report on Form 8-K filed October 31, 2014 (File No. 001-16417), Exhibit 10.1

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Exhibit Number	Description	Incorporated by Reference to the Following Document

10.02	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 Quarterly Report on Form 10-Q for quarter ended June 30, 2015 (File No. 001-16417), Exhibit 10.01

10.03	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	NuStar Energy L.P.’s Current Report on Form 8-K filed August 22, 2017 (File No. 001-16417), Exhibit 10.01

10.04	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	NuStar Energy L.P.’s Current Report on Form 8-K filed November 22, 2017 (File No. 001-16417), Exhibit 10.01

10.05	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

10.06	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	NuStar Energy L.P.’s Current Report on Form 8-K filed June 12, 2012 (File No. 001-16417), Exhibit 10.01

10.07	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	NuStar Energy L.P.’s Current Report on Form 8-K filed July 6, 2012 (File No. 001-16417), Exhibit 10.2

10.08	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	NuStar Energy L.P.’s Annual Report on Form 10-K for year ended December 31, 2014 (File No. 001-16417), Exhibit 10.10

10.09	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	NuStar Energy L.P.’s Annual Report on Form 10-K for year ended December 31, 2014 (File No. 001-16417), Exhibit 10.11

10.10	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	NuStar Energy L.P.’s Annual Report on Form 10-K for year ended December 31, 2014 (File No. 001-16417), Exhibit 10.12

10.11	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	NuStar Energy L.P.’s Annual Report on Form 10-K for year ended December 31, 2014 (File No. 001-16417), Exhibit 10.13

10.12	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	NuStar Energy L.P.’s Current Report on Form 8-K filed November 6, 2014 (File No. 001-16417), Exhibit 10.1

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Exhibit Number	Description	Incorporated by Reference to the Following Document

10.13	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	NuStar Energy L.P.’s Quarterly Report on Form 10-Q for quarter ended June 30, 2015 (File No. 001-16417), Exhibit 10.02

10.14	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	NuStar Energy L.P.’s Quarterly Report on Form 10-Q for quarter ended June 30, 2016 (File No. 001-16417), Exhibit 10.01

10.15	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	NuStar Energy L.P.’s Quarterly Report on Form 10-Q for quarter ended March 31, 2017 (File No. 001-16417), Exhibit 10.03

10.16	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

10.17	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	NuStar Energy L.P.’s Current Report on Form 8-K filed September 9, 2014 (File No. 001-16417), Exhibit 10.1

10.18	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 November 6, 2014 (File No. 001-16417), Exhibit 10.3

10.19	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	NuStar Energy L.P.’s Quarterly Report on Form 10-Q for quarter ended September 30, 2015 (File No. 001-16417), Exhibit 10.01

10.20	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	NuStar Energy L.P.’s Quarterly Report on Form 10-Q for quarter ended June 30, 2016 (File No. 001-16417), Exhibit 10.02

10.21	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	NuStar Energy L.P.’s Quarterly Report on Form 10-Q for quarter ended June 30, 2017 (File No. 001-16417), Exhibit 10.02

10.22	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

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Exhibit Number	Description	Incorporated by Reference to the Following Document

10.23	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	NuStar Energy L.P.’s Current Report on Form 8-K filed June 11, 2013 (File No. 001-16417), Exhibit 10.01

10.24	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	NuStar Energy L.P.’s Current Report on Form 8-K filed November 6, 2014 (File No. 001-16417), Exhibit 10.2

10.25	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 19, 2015 (File No. 001-16417), Exhibit 10.1

10.26	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	NuStar Energy L.P.'s Current Report on Form 8-K filed June 19, 2015 (File No. 001-16417), Exhibit 10.2

10.27	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	NuStar Energy L.P.’s Annual Report on Form 10-K for year ended December 31, 2015 (File No. 001-16417), Exhibit 10.26

10.28	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	NuStar Energy L.P.’s Current Report on Form 8-K filed September 20, 2017 (File No. 001-16417), Exhibit 10.01

10.29	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	NuStar Energy L.P.’s Current Report on Form 8-K filed September 20, 2017 (File No. 001-16417), Exhibit 10.02

+10.30	NuStar GP, LLC Fifth Amended and Restated 2000 Long-Term Incentive Plan, amended and restated as of January 28, 2016	* Originally filed as Appendix A to NuStar Energy L.P.’s Proxy Statement on Schedule 14A filed December 17, 2015 (File No. 001-16417) and refiled herewith

+10.31	First Amendment to the NuStar GP, LLC Fifth Amended and Restated 2000 Long-Term Incentive Plan, dated as of February 7, 2018	*

+10.32	Form of 2012 Restricted Unit Award Agreement under the NuStar GP, LLC Third Amended and Restated 2000 Long-Term Incentive Plan	NuStar Energy L.P.’s Current Report on Form 8-K filed January 31, 2012 (File No. 001-16417), Exhibit 10.2

+10.33	Form of 2013 Restricted Unit Award Agreement under the NuStar GP, LLC Third Amended and Restated 2000 Long-Term Incentive Plan	NuStar Energy L.P.’s Annual Report on Form 10-K for year ended December 31, 2013 (File No. 001-16417), Exhibit 10.15

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Exhibit Number	Description	Incorporated by Reference to the Following Document

+10.34	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

+10.35	Form of 2017 Performance Unit 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

+10.36	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

+10.37	NuStar Energy L.P. Annual Bonus Plan	NuStar Energy L.P.’s Annual Report on Form 10-K for year ended December 31, 2006 (File No. 001-16417), Exhibit 10.18

+10.38	Form of NuStar Energy L.P. Amended and Restated Change of Control Severance Agreement	NuStar Energy L.P.’s Current Report on Form 8-K filed August 4, 2016 (File No. 001-16417), Exhibit 10.1

+10.39	Form of Executive Change of Control Waiver Agreement dated effective as of February 7, 2018	*

+10.40	Form of Non-employee Director Change of Control Waiver Agreement dated effective as of February 7, 2018	*

+10.41	NuStar Excess Pension Plan, amended and restated effective as of January 1, 2014	NuStar Energy L.P.’s Annual Report on Form 10-K for year ended December 31, 2015 (File No. 001-16417), Exhibit 10.45

+10.42	NuStar Excess Thrift Plan, amended and restated effective as of January 1, 2008	NuStar Energy L.P.’s Annual Report on Form 10-K for year ended December 31, 2008 (File No. 001-16417), Exhibit 10.30

+10.43	Amendment to NuStar Excess Thrift Plan, effective as of January 1, 2017	NuStar Energy L.P.’s Quarterly Report on Form 10-Q for quarter ended March 31, 2017 (File No. 001-16417), Exhibit 10.02

10.44	Non-Compete Agreement, dated July 19, 2006, between Valero GP Holdings, LLC, Valero L.P., Riverwalk Logistics, L.P. and Valero GP, LLC	NuStar Energy L.P.’s Quarterly Report on Form 10-Q for quarter ended September 30, 2006 (File No. 001-16417), Exhibit 10.03

10.45	Services Agreement, effective as of January 1, 2008, between NuStar GP, LLC and NuStar Energy L.P.	NuStar Energy L.P.’s Quarterly Report on Form 10-Q for quarter ended March 31, 2008 (File No. 001-16417), Exhibit 10.01

10.46	Amended and Restated Services Agreement dated March 1, 2016 between NuStar Energy L.P., NuStar GP Holdings, LLC, 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 10.2

10.47	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

10.48	Amended and Restated Aircraft Time Sharing Agreement, dated as of September 4, 2009, between NuStar Logistics, L.P. and William E. Greehey	NuStar Energy L.P.’s Annual Report on Form 10-K for year ended December 31, 2009 (File No. 001-16417), Exhibit 10.24

10.49	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	NuStar Energy L.P.’s Quarterly Report on Form 10-Q for quarter ended September 30, 2017 (File No. 001-16417), Exhibit 10.02

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Exhibit Number	Description	Incorporated by Reference to the Following Document

10.50	Support Agreement, dated as of February 7, 2018, by and among NuStar Energy L.P., Riverwalk Logistics, L.P., NuStar GP, LLC, Marshall Merger Sub LLC, Riverwalk Holdings, LLC and NuStar GP Holdings, LLC	NuStar Energy L.P.’s Current Report on Form 8-K filed February 8, 2018 (File No. 001-16417), Exhibit 10.1

12.01	Statement of Computation of Ratio of Earnings to Fixed Charges	*

21.01	List of subsidiaries of NuStar Energy L.P.	*

23.01	Consent of KPMG LLP dated February 28, 2018 (NuStar Energy L.P.)	*

24.01	Powers of Attorney (included in signature page of this Form 10-K)	*

31.01	Rule 13a-14(a) Certification (under Section 302 of the Sarbanes-Oxley Act of 2002) of principal executive officer	*

31.02	Rule 13a-14(a) Certification (under Section 302 of the Sarbanes-Oxley Act of 2002) of principal financial officer	*

32.01	Section 1350 Certification (under Section 906 of the Sarbanes-Oxley Act of 2002) of principal executive officer	**

32.02	Section 1350 Certification (under Section 906 of the Sarbanes-Oxley Act of 2002) of principal financial officer	**

101.INS	XBRL Instance Document	*

101.SCH	XBRL Taxonomy Extension Schema Document	*

101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document	*

101.DEF	XBRL Taxonomy Extension Definition Linkbase Document	*

101.LAB	XBRL Taxonomy Extension Label Linkbase Document	*

101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document	*



*	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.

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.

ITEM 16. FORM 10-K SUMMARY

Not applicable.

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SIGNATURES

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.




NUSTAR ENERGY L.P.
(Registrant)

By:	Riverwalk Logistics, L.P., its general partner
	By: NuStar GP, LLC, its general partner

By:	/s/ Bradley C. Barron
	Bradley C. Barron
	President and Chief Executive Officer
	February 28, 2018

By:	/s/ Thomas R. Shoaf
	Thomas R. Shoaf
	Executive Vice President and Chief Financial Officer
	February 28, 2018

By:	/s/ Jorge A. del Alamo
	Jorge A. del Alamo
	Senior Vice President and Controller
	February 28, 2018

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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 true and lawful attorney-in-fact and agent, with full power of substitution and resubstitution, for him and in his 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 might or could do in person, hereby qualifying and confirming all that said attorney-in-fact and agent or his 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	Chairman of the Board	February 28, 2018
William E. Greehey

/s/ Bradley C. Barron	President, Chief Executive	February 28, 2018
Bradley C. Barron	Officer and Director (Principal Executive Officer)

/s/ Thomas R. Shoaf	Executive Vice President	February 28, 2018
Thomas R. Shoaf	and Chief Financial Officer (Principal Financial Officer)

/s/ Jorge A. del Alamo	Senior Vice President and Controller	February 28, 2018
Jorge A. del Alamo	(Principal Accounting Officer)

/s/ J. Dan Bates	Director	February 28, 2018
J. Dan Bates

/s/ Dan J. Hill	Director	February 28, 2018
Dan J. Hill

/s/ Robert J. Munch	Director	February 28, 2018
Robert J. Munch

/s/ W. Grady Rosier	Director	February 28, 2018
W. Grady Rosier

185