NuStar Energy L.P. - Annual Report: 2014 (Form 10-K)

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Accelerated filer [ ]

Non-accelerated filer

[ ] (Do not check if a smaller reporting company)

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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, 2014

[ ] 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 partnership 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. [ ]

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 Rule12b-2 of the Exchange Act:

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

The aggregate market value of the common units held by non-affiliates was approximately $4,194 million based on the last sales price quoted as of June 30, 2014, the last business day of the registrant’s most recently completed second quarter.

The number of common units outstanding as of January 31, 2015 was 77,886,078.

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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	4
	Segments	5
	Employees	14
	Rate Regulation	14
	Environmental and Safety Regulation	14
	Risk Factors	17
	Properties	27

Item 1B.	Unresolved Staff Comments	27

Item 3.	Legal Proceedings	27

Item 4.	Mine Safety Disclosures	28

PART II
Item 5.	Market for Registrant’s Common Units, Related Unitholder Matters and Issuer Purchases of Common Units	29

Item 6.	Selected Financial Data	30

Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	31

Item 7A.	Quantitative and Qualitative Disclosures about Market Risk	53

Item 8.	Financial Statements and Supplementary Data	56

Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	110

Item 9A.	Controls and Procedures	110

Item 9B.	Other Information	110

PART III
Item 10.	Directors, Executive Officers and Corporate Governance	111

Item 11.	Executive Compensation	115

Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters	145

Item 13.	Certain Relationships and Related Transactions and Director Independence	148

Item 14.	Principal Accountant Fees and Services	151

PART IV
Item 15.	Exhibits and Financial Statement Schedules	152

Signatures		160

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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. In this Form 10-K, we make certain forward-looking statements, including statements regarding our plans, strategies, objectives, expectations, intentions and resources. 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. We do not undertake to update, revise or correct any of the forward-looking information. You are cautioned that such forward-looking statements should be read in conjunction with our disclosures beginning on page 31 of this report under the heading: “CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION.”

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 are traded on the New York Stock Exchange (NYSE) under the symbol “NS.” 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, the terminalling and storage of petroleum products and the 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, 2014, our assets included:


•	5,463 miles of refined product pipelines with 21 associated terminals providing storage capacity of 4.9 million barrels and two tank farms providing storage capacity of 1.4 million barrels;


•	2,000 miles of anhydrous ammonia pipelines;


•	1,180 miles of crude oil pipelines providing 3.5 million barrels of associated storage capacity; and


•	53 terminal and storage facilities providing 80.9 million barrels of storage capacity.

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 crude oil and refined petroleum products.

Our goal is to increase per unit quarterly distributions to our partners. We strive to achieve this goal 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 internet 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 internet website free of charge (select the “Investors” link, then the “Corporate Governance” link). Our governance documents are available in print to any unitholder that makes a written request to Corporate Secretary, NuStar Energy L.P., 19003 IH-10 West, San Antonio, Texas 78257 or corporatesecretary@nustarenergy.com.

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RECENT DEVELOPMENTS

On January 2, 2015, we acquired full ownership of a refined products terminal in Linden, NJ, for $142.5 million. Prior to the acquisition, the terminal operated as a joint venture between ourselves and Linden Holding Corp, with each party owning 50 percent.

On September 25, 2014, we sold our 75% interest in our facility in Mersin, Turkey for proceeds of $13.4 million.

On February 26, 2014, we sold our then-remaining 50% ownership interest in NuStar Asphalt LLC, which constituted all equity interests in that entity we retained after the first sale in 2012. Effective February 27, 2014, NuStar Asphalt LLC changed its name to Axeon Specialty Products LLC (Axeon). The purchaser, Lindsay Goldberg LLC (Lindsay Goldberg), a private investment firm, now owns 100% of Axeon, and we have completed our exit from the asphalt business. Please refer to Note 5 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for additional information regarding this sale.

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, LLC (NuStar GP Holdings) (NYSE: NSH).

The following chart depicts our organizational structure at December 31, 2014.

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SEGMENTS

Our three reportable business segments are pipeline, storage and fuels marketing. Detailed financial information about our segments is included in Note 26 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data.”

The following map depicts our operations at December 31, 2014.

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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, 2014, we owned and operated:


•	refined product pipelines with an aggregate length of 3,113 miles and crude oil pipelines with an aggregate length of 1,180 miles in Texas, Oklahoma, Kansas, Colorado and New Mexico (collectively, the Central West System);


•	a 1,910-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 440-mile refined product pipeline originating at Tesoro Corporation’s (Tesoro) Mandan, North Dakota refinery and terminating in Minneapolis, Minnesota (the North Pipeline); and


•	a 2,000-mile anhydrous ammonia pipeline originating at 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).

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. The following table lists information about our pipeline assets as of December 31, 2014:



			Throughput For the year ended December 31,
Region / Pipeline System	Length	Tank Capacity	2014	2013
	(Miles)	(Barrels)	(Barrels/Day)
Central West System:
McKee System	2,276	—	164,589	148,541
Three Rivers System	377	—	78,177	76,512
Other	460	—	51,698	50,826
Central West Refined Products Pipelines	3,113	—	294,464	275,879
Eagle Ford System	438	1,600,000	230,665	168,718
McKee System	598	1,050,000	140,402	130,081
Ardmore System	87	824,000	66,690	66,950
Other	57	—	—	—
Central West Crude Oil Pipelines	1,180	3,474,000	437,757	365,749
Total Central West System	4,293	3,474,000	732,221	641,628

East Pipeline	1,910	4,916,000	134,816	132,475
North Pipeline	440	1,437,000	45,641	45,991
Ammonia Pipeline	2,000	—	35,816	32,676
Total	8,643	9,827,000	948,494	852,770

Description of Pipelines

Central West System. The Central West System covers a total of 4,293 miles. The Central West System pipelines support shale oil production and the refineries to which they are connected, including Valero Energy Corporation’s (Valero Energy) McKee, Three Rivers and Ardmore refineries. The refined product pipelines have an aggregate length of 3,113 miles (Central West Refined Products Pipelines), including 289 miles of temporarily idled 6-inch Amarillo, Texas to Albuquerque, New Mexico refined product pipeline. The refined products transported in these pipelines include gasoline, distillates (including diesel and jet fuel), natural gas liquids and other products produced at the refineries to which they are connected. The crude oil pipelines have an aggregate length of 1,180 miles (Central West Crude Oil Pipelines), including 214 miles of temporarily idled Cheyenne Wells, Colorado to McKee and Healdton to Ringling, Oklahoma crude oil pipelines. Our crude oil pipelines transport crude oil and other feedstocks from various points to the refineries to which they are connected, and from the Eagle Ford Shale region to our North Beach marine terminal in Corpus Christi, Texas.

East Pipeline. The East Pipeline covers 1,910 miles, including 111 miles that are temporarily idled, and moves refined products and natural gas liquids north in pipelines ranging in diameter from 6 inches to 16 inches to NuStar Energy and third party terminals along the system and to receiving pipeline connections in Kansas. The East Pipeline system includes 17 terminals, discussed below, with storage capacity of approximately 3.5 million barrels and two tank farms with storage capacity of

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approximately 1.4 million barrels at McPherson and El Dorado, Kansas. Shippers on the East Pipeline obtain refined petroleum products from refineries in Kansas, Oklahoma and Texas.

North Pipeline. The North Pipeline originates at Tesoro’s Mandan, North Dakota refinery and runs from west to east for approximately 440 miles to its termination in the Minneapolis, Minnesota area. The North Pipeline system includes 4 terminals, discussed below, with storage capacity of approximately 1.4 million barrels.

Pipeline-Related Terminals. 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 relate solely to the volumes transported on the pipeline. Separate fees are not charged for the use of these terminals. Instead, the terminalling fees are a portion of the transportation rate included in the pipeline tariff. As a result, these terminals are included in this segment instead of the storage segment.

Ammonia Pipeline. The 2,000-mile pipeline, including 57 miles that are temporarily idled, originates in the Louisiana delta area, where it has access 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

Revenues for the pipelines are based upon origin-to-destination throughput volumes traveling through our pipelines and their related tariff rates.

In general, a shipper on our refined petroleum product pipelines delivers products to the pipeline from refineries or third-party pipelines. We charge our shippers tariff rates based on transportation from the origination point on the pipeline to the point of delivery. We invoice our refined product shippers upon delivery for our Central West System and our North and Ammonia Pipelines, and we invoice our shippers on our East Pipeline when their product enters the line.

Shippers on our crude oil pipelines deliver crude oil to our pipelines for transport to: (i) refineries that connect to our pipelines, (ii) third-party pipelines and (iii) NuStar terminals for further delivery to marine vessels or third-party pipelines.

Our pipelines are subject to federal regulation by one or more of the following governmental agencies or laws: 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 Homeland Security Act. Additionally, the operations and integrity of the pipelines are subject to the respective state jurisdictions.

The majority of our pipelines are common carrier and adopt market-based rates. Common carrier activities are those for which transportation through our pipelines is available, at published tariffs filed, in the case of interstate petroleum product shipments, with the FERC and the STB or, in the case of intrastate petroleum product shipments, with the relevant state authority, to any shipper of petroleum products who requests such services and satisfies the conditions and specifications for transportation.

We use Supervisory Control and Data Acquisition remote supervisory control software programs to continuously monitor and control our pipelines. The system monitors quantities of products injected in and delivered through the pipelines and automatically signals the appropriate personnel upon deviations from normal operations that require attention.

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 refiners and marketers having access to the pipelines to supply such demand by deliveries through the 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 us. 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 further 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 Tesoro’s Mandan, North Dakota refinery, which primarily runs North Dakota crude oil (although it has the ability to process other crude oils). If operations at the Tesoro refinery were interrupted, it could have a material 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 the National Cooperative Refining Association (NCRA), HollyFrontier Corporation (HollyFrontier) and Phillips 66, respectively. The NCRA and HollyFrontier refineries are connected directly to the East Pipeline. 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 described above and the Tesoro refinery, 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 depend upon the continued production of domestic crude oil in regions served by our crude oil pipelines or connecting carriers. Our crude oil pipelines are also dependent on our customers’ continued access to sufficient foreign 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.

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 foreign product 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, management practices, 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 35% of the total segment revenues for the year ended December 31, 2014. In addition to Valero Energy, our customers include integrated oil companies, refining companies, farm cooperatives, railroads and others. No other customer accounted for a significant portion of the total revenues of the pipeline segment for the year ended December 31, 2014.

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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.

Our crude oil pipelines serve areas or refineries impacted by growing domestic shale oil production in the Eagle Ford, Permian Basin and Granite Wash regions. This growing domestic production has reduced demand for imported crude oil and shifted supply sources for refineries and markets served by our pipelines. Our pipelines also face competition from other crude oil pipelines and truck transportation in these regions.

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, 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 pipeline under certain market conditions.

STORAGE

Our storage segment includes terminal and storage facilities that provide storage, handling and other services for petroleum products, crude oil, specialty chemicals and other liquids. As of December 31, 2014, we owned and operated:


•	43 terminal and storage facilities in the United States, with total storage capacity of 49.2 million barrels;


•	A terminal on the island of St. Eustatius with tank capacity of 14.4 million barrels and a transshipment facility;


•	A terminal located in Point Tupper with tank capacity of 7.7 million barrels and a transshipment facility;


•	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;


•	A terminal located in Nuevo Laredo, Mexico.

Description of Major Terminal Facilities

St. Eustatius. We own and operate a 14.4 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 heavy-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 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. This unit 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 the 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.

St. James, Louisiana. Our St. James terminal, which is located on the Mississippi River near St. James, Louisiana, has a total storage capacity of 9.2 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 four 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 can receive product from gathering pipelines in the Gulf of Mexico and deliver to connecting pipelines that supply refineries in the Gulf Coast and

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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 7.7 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 heavy-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 the use of the jetty facility, as well as associated services, including pilotage, tug assistance, line handling, launch service, emergency response services and other ship services.

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.

Linden, New Jersey. In 2014, we owned 50% of ST Linden Terminal LLC (Linden), which owns a terminal and storage facility in Linden, New Jersey. On January 2, 2015, we acquired full ownership of Linden by purchasing the remaining ownership interest from Linden Holding Corp for $142.5 million. The terminal is located on a 44-acre facility that provides it with deep-water terminalling capabilities in the New York Harbor. This terminal primarily stores petroleum products, including gasoline, jet fuel and fuel oils. The facility has a total storage capacity of 4.3 million barrels and can receive and deliver products via ship, barge and pipeline. The terminal includes two dock facilities.

Terminal and Storage Facilities

The following table sets forth information about our terminal and storage facilities as of December 31, 2014:



Facility	Tank Capacity	Primary Products Handled
	(Barrels)
Colorado Springs, CO	328,000	Petroleum products, ethanol
Denver, CO	110,000	Petroleum products, ethanol
Alamogordo, NM (a) (e)	124,000	Petroleum products
Albuquerque, NM	251,000	Petroleum products, ethanol
Abernathy, TX	160,000	Petroleum products
Amarillo, TX	269,000	Petroleum products
Corpus Christi, TX	329,000	Petroleum products
Corpus Christi, TX (North Beach)	1,721,000	Crude oil and feedstocks
Edinburg, TX	288,000	Petroleum products
El Paso, TX (b)	428,000	Petroleum products, ethanol
Harlingen, TX	286,000	Petroleum products
Laredo, TX	215,000	Petroleum products
Placedo, TX (c)	100,000	Petroleum products
San Antonio (East), TX	150,000	Petroleum products
San Antonio (South), TX	225,000	Petroleum products
Southlake, TX	569,000	Petroleum products, ethanol
Nuevo Laredo, Mexico	50,000	Petroleum products
Central West Terminals	5,603,000

Pittsburg, CA	398,000	Asphalt
Rosario, NM	166,000	Asphalt
Catoosa, OK	358,000	Asphalt
Houston, TX	86,000	Asphalt
Asphalt Terminals	1,008,000

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Facility	Tank Capacity	Primary Products Handled
	(Barrels)
Blue Island, IL	690,000	Petroleum products, ethanol
Indianapolis, IN	428,000	Petroleum products
Central East Terminals	1,118,000

Jacksonville, FL	2,593,000	Petroleum products, asphalt
St. James, LA	9,190,000	Crude oil and feedstocks
Texas City, TX	128,000	Petroleum products
Texas City, TX	2,836,000	Chemicals, petroleum products
Gulf Coast Terminals	14,747,000

Andrews AFB, MD (a)	75,000	Petroleum products
Baltimore, MD	818,000	Chemicals, asphalt, petroleum products
Piney Point, MD	5,402,000	Petroleum products
Linden, NJ	389,000	Petroleum products
Linden, NJ (d)	2,130,000	Petroleum products
Paulsboro, NJ	74,000	Petroleum products
Virginia Beach, VA (a)	41,000	Petroleum products
North East Terminals	8,929,000

Los Angeles, CA	608,000	Petroleum products
Selby, CA	3,060,000	Petroleum products, ethanol
Stockton, CA	816,000	Petroleum products, ethanol, fertilizer
Portland, OR	1,365,000	Petroleum products, ethanol
Tacoma, WA	391,000	Petroleum products, ethanol
Vancouver, WA	341,000	Chemicals
Vancouver, WA	433,000	Petroleum products
West Coast Terminals	7,014,000

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

Grays, England	1,958,000	Petroleum products
Eastham, England	2,096,000	Chemicals, petroleum products
Runcorn, England	149,000	Molten sulfur
Grangemouth, Scotland	719,000	Petroleum products, chemicals
Glasgow, Scotland	353,000	Petroleum products
Belfast, Northern Ireland	408,000	Petroleum products
United Kingdom Terminals	5,683,000

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Facility	Tank Capacity	Primary Products Handled
	(Barrels)
St. Eustatius, the Netherlands	14,396,000	Petroleum products, crude oil and feedstocks
Amsterdam, the Netherlands	3,834,000	Petroleum products
Point Tupper, Canada	7,725,000	Petroleum products, crude oil and feedstocks

Total Terminals and Storage Facilities	80,911,000


(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)	The Placedo, TX terminal is temporarily idled.


(d)	As of December 31, 2014, we owned 50% of this terminal through a joint venture. The tank capacity represents the proportionate share of capacity attributable to our ownership interest. On January 2, 2015, we purchased the other 50% ownership interest.


(e)	On January 7, 2015, we sold the Alamogordo, NM terminal and the related pipeline.

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 lease revenues), and throughput agreements, where a customer pays a fee per barrel for volumes moving through our terminals (throughput revenues). Our terminals also provide blending, additive injections, handling and filtering services for which we charge additional fees. We charge a fee for each barrel of crude oil and certain other feedstocks that we deliver to Valero Energy’s Benicia, Corpus Christi West and Texas City refineries from our crude oil storage tanks. 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 impact demand. For example, in a contango market (when the price for future storage 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, which can affect our profit sharing and volumes.

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 19% of the total revenues of the segment for the year ended December 31, 2014. No other customer accounted for a significant portion of the total revenues of the storage segment for the year ended December 31, 2014.

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 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.

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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 be in compliance 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 Pt. 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 that 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 necessitate unloading these ships to storage and subsequent loading on the 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 has dropped substantially. This reduced demand for imported light crude has, in turn, dramatically changed oil trade flow patterns around the world, thereby depressing the demand for break bulk services. At the same time, South American and Canadian production of heavy crude has ramped up significantly. As demand for export of heavy crude and natural gas liquids (NGL) out of South America, as well as from Canada, 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. Our Point Tupper facility’s location is similarly well-positioned, in this case to build bulk for heavy Canadian crude oil and NGL production.

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

Fuels Marketing Operations

Our fuels marketing operations involve the purchase of crude oil, fuel oil, bunker fuel, fuel oil blending components and other refined products for resale. These operations provide us the opportunity to generate additional gross margin while complementing the activities of our storage segment. We utilize storage assets, including our own terminals and rail unloading facilities, at our St. James, Texas City and St. Eustatius terminals. Rates charged by our storage segment to the fuels marketing segment are consistent with rates charged to third parties.

Within our fuels marketing operations, we purchase crude oil and refined petroleum products for resale. 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

Fuels marketing customers include major integrated refiners and trading companies. Customers for our bunker fuel sales are mainly ship owners, including cruise line companies. No customer accounted for a significant portion of the total revenues of the fuels marketing segment for the year ended December 31, 2014.

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Competition and Business Considerations

Our fuels marketing operations have numerous competitors, including large integrated refiners, marketing affiliates of other partnerships in our industry, as well as various international and domestic trading companies. In the sale of bunker fuel, we compete with ports offering bunker fuels that are along the route of travel of the vessel.

EMPLOYEES

Our operations are managed by NuStar GP, LLC. As of December 31, 2014, NuStar GP, LLC had 1,227 domestic employees and certain of our wholly owned subsidiaries had 397 employees performing services for our international operations. We believe that NuStar GP, LLC and our subsidiaries each have satisfactory relationships with their employees.

RATE REGULATION

Several of our petroleum 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 oil 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 oil pipelines to annually index their rates up to a prescribed ceiling level. In addition, the FERC retains cost-of-service ratemaking, market-based rates and settlement rates as alternatives to the indexing approach.

Our ammonia pipeline is subject to regulation by the Surface Transportation Board (STB) pursuant to the Interstate Commerce Act applicable to such pipelines (which differs from the ICA applicable to interstate liquids pipelines). Under that regulation, our ammonia pipeline’s rates, classifications, 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 person, place, port or type of traffic to unreasonable discrimination.

Additionally, the rates and practices for our intrastate common carrier pipelines are subject to regulation by state commissions in Colorado, Kansas, Louisiana, North Dakota and Texas. 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 AND SAFETY REGULATION

Our operations are subject to extensive federal, state and local environmental laws and regulations, including those relating to the discharge of materials into the environment, waste management, pollution prevention measures, pipeline integrity and operator qualifications, among others. Our operations are also subject to extensive federal and state health and safety laws and regulations, including those relating to worker and pipeline safety. The principal environmental and safety risks associated with our operations relate to unauthorized or unpermitted emissions into the air, unauthorized releases into soil, surface water or groundwater, and personal injury and property damage. Compliance with these environmental, health and safety laws, regulations and permits increases our capital expenditures and our overall cost of business, and violations of these laws, regulations or permits can result in significant civil and criminal liabilities, injunctions or other penalties.

We have adopted policies, practices and procedures including in the areas of pollution control, pipeline integrity, operator qualifications, public relations and education, process safety management, occupational health and the handling, storage, use and disposal of hazardous materials, that are designed 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 result in changes to expected operating permits and procedures, additional remedial actions or increased capital expenditures and operating costs that cannot be assessed with certainty at this time. In addition, contamination resulting from spills of petroleum and other products occurs within the industry. 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.

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Capital Expenditures Attributable to Compliance with Environmental Statutes and Regulations. It is possible that these statutes and the related regulations may be revised to be more restrictive in the future, necessitating additional capital expense to ensure our operations are in compliance. We are unable to estimate the effect on our financial condition or results of operations or the amount and timing of such required expenditures. In 2014, our capital expenditures attributable to compliance with environmental regulations were $9.7 million, and are currently estimated to be approximately $10.4 million for 2015.

RENEWABLE ENERGY AND ALTERNATIVE FUEL MANDATES

Several federal and state programs require, subsidize or encourage the purchase and use of renewable energy and alternative fuels, such as battery-powered engines, biodiesel, wind energy, and solar energy. These programs may over time offset projected increases or reduce the demand for refined petroleum products, particularly gasoline, in certain markets. The increased production and use of biofuels may also create opportunities for additional pipeline transportation and additional blending opportunities within the storage segment, although that potential cannot be quantified at present. Other legislative changes may similarly alter the expected demand and supply projections for refined petroleum products in ways that cannot be predicted.

WATER

The Federal Water Pollution Control Act of 1972, as amended, also known as the Clean Water Act, and analogous or more stringent state and local statutes 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 state waters or waters of the United States is generally prohibited, except in accordance with the terms of a permit issued by applicable federal or state authorities. The Oil Pollution Act, enacted in 1990, amends provisions of the Clean Water Act as they pertain to prevention, response to and liability for oil spills. Spill prevention control and countermeasure requirements of the Clean Water Act and some state laws require response plans and the use of dikes and similar structures to help prevent contamination of state waters or waters of the United States in the event of an unauthorized discharge. Violations of any of these statutes and the related regulations could result in significant costs and liabilities. It is possible that these statutes and the related regulations may be revised to be more restrictive in the future, necessitating additional capital expense to ensure our operations are in compliance. We are unable to estimate the effect on our financial condition or results of operations or the amount and timing of such required expenditures.

AIR

The Federal Clean Air Act, as amended, and analogous or more stringent state and local statutes and regulations impose restrictions and strict controls regarding the discharge of pollutants into the air. The discharge of pollutants into the air is generally prohibited, except in accordance with the terms of a permit issued by applicable federal or state authorities, and these laws and related regulations regulate emissions of air pollutants from various sources, including some of our operations, and also impose various monitoring and reporting requirements. Such laws and regulations may require a facility to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce air emissions or result in the increase of existing air emissions, and obtain and strictly comply with the provisions of any air permits. Violations of any of these statutes and the related regulations could result in significant costs and liabilities. It is possible that these statutes and the related regulations may be revised to be more restrictive in the future, necessitating additional capital expense to ensure our operations are in compliance. We are unable to estimate the effect on our financial condition or results of operations or the amount and timing of such required expenditures.

SOLID WASTE

The federal Resource Conservation and Recovery Act (RCRA) and analogous or more stringent state and local statutes and regulations impose restrictions and strict controls regarding solid wastes, including hazardous wastes. We currently are not required to comply with a substantial portion of RCRA requirements because we do not operate any waste treatment, storage or disposal facilities. However, it is possible that additional wastes, which could include wastes currently generated during operations, will also be designated as hazardous wastes. Hazardous wastes are subject to more rigorous and costly disposal requirements than are non-hazardous wastes. Violations of any of these statutes and the related regulations could result in significant costs and liabilities. It is possible that these statutes and the related regulations may be revised to be more restrictive in the future, necessitating additional capital expense to ensure our operations are in compliance. We are unable to estimate the effect on our financial condition or results of operations or the amount and timing of such required expenditures.

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HAZARDOUS SUBSTANCES

The federal Comprehensive Environmental Response, Compensation and Liability Act, referred to as CERCLA and also known as Superfund, and analogous or more stringent state and local statutes and regulations impose restrictions and liability, including joint and several liability, without regard to fault or the legality of the original act, on some classes of persons that contributed to the release or threatened release of a hazardous substance into the environment. These classes of persons can include the owner or operator of the facility and those that disposed or arranged for the disposal of the hazardous substances. CERCLA also authorizes the EPA and, in some instances, third parties to act in response to threats that endanger public health or the environment and to seek recovery from the responsible classes of persons for the costs that they incur. In the course of our ordinary operations, we may generate and arrange for the disposal of wastes that fall within CERCLA’s definition of a hazardous substance.

We currently own or lease, and have in the past owned or leased, properties where hazardous substances are being or have been handled. Although we believe that we have utilized operating and disposal practices that were standard in the industry at the time, substances may have been disposed of or released on or under the properties owned or leased by us or on or under other locations where these wastes have been taken for disposal. In addition, we acquired many of these properties from third parties, and we did not control those third parties’ treatment and disposal or release of hazardous substances. These properties and substances disposed thereon may be subject to CERCLA, RCRA and analogous state and local statutes and regulations. Under these laws, we could be required to remove or remediate previously disposed substances (including substances disposed of or released by prior owners or operators), to clean up contaminated property (including contaminated groundwater) or to perform remedial operations to prevent future contamination. In addition, we may be exposed to joint and several liability under CERCLA for all or part of the costs required to clean up sites at which hazardous substances may have been disposed of or released into the environment.

While remediation of subsurface contamination is in process at several of our facilities, based on current available information, we believe that the cost of these activities will not materially affect our financial condition or results of operations. Such costs, however, are often unpredictable and, therefore, there can be no assurances that the future costs will not become material. Further, it is possible that these statutes and the related regulations may be revised to be more restrictive in the future, necessitating additional capital expense to ensure compliance. We are unable to estimate the effect on our financial condition or results of operations or the amount and timing of such required expenditures.

PIPELINE INTEGRITY AND SAFETY

Our pipelines are subject to extensive federal, state and local statutes and regulations governing pipeline integrity and safety, including those in Title 49, Subchapter D of the Code of Federal Regulations. These statutes and regulations generally require safe operation, maintenance, testing and corrosion control of pipelines, and qualification programs for pipeline operating personnel. In addition, other requirements can include reviewing and updating existing pipeline safety public education programs, providing information for the National Pipeline Mapping System, maintaining spill response plans, conducting spill response training, implementing integrity management programs and managing pipeline control centers. Violations of any of these statutes and the related regulations could result in significant costs and liabilities. It is possible that these statutes and the related regulations may be revised to be more restrictive in the future, necessitating additional capital expense to ensure our operations are in compliance. However, while compliance may affect our capital expenditures and operating expenses, we believe that the cost of such compliance will not materially affect our competitive position or have a material effect on our financial condition or results of operations.

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RISK FACTORS

RISKS RELATED TO OUR BUSINESS

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

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 will fluctuate from quarter to quarter based on, among other things:


•	throughput volumes transported in our pipelines;


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


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


•	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;


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


•	the effect of worldwide energy conservation measures;


•	our operating costs;


•	weather conditions;


•	domestic and foreign governmental regulations and taxes; and


•	prevailing economic conditions.

In addition, the amount of cash that we will have available for distribution will depend 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


•	adjustments in cash reserves made by our general partner, in its discretion.

Because of these factors, we may not have sufficient available cash each quarter to continue paying distributions at their current level or at all. Furthermore, cash distributions to our unitholders depend primarily upon our cash flows, including cash flows from financial reserves and working capital borrowings, and not solely on profitability, which is affected by non-cash items. Therefore, we may make cash distributions during periods when we record net losses and may not make cash distributions during periods when we record net income.

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:


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


•	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 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;


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


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

Our forecasted operating results are also based upon our projections of future market fundamentals that are not within our control, including changes in general economic conditions, availability to our customers of attractively priced alternative solutions for storage, transportation or supplies of crude oil and refined products and overall customer demand.

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. If we are unable to implement business development opportunities and finance such activities on economically acceptable terms, our future growth will be limited, which could adversely impact our results of operations and cash flows and, accordingly, result in reduced distributions over time.

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If we are unable to retain current, and attain new, customers through renewing or establishing leases and throughput agreements at current or better rates or the utilization of our leased assets suffers a material decrease, 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 lease agreements. Failure to renew or enter into new contracts or our leasing customers’ material reduction of their utilization under our existing leases could result from many factors, including:


•	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;


•	scheduled refinery turnarounds or unscheduled refinery maintenance;


•	operational problems or catastrophic events at a refinery or our assets;


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


•	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;


•	increasingly stringent environmental regulations; or


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

Competing midstream service providers, including certain major energy and chemical companies, possess, or have greater financial resources to acquire, assets better suited to customer demand, which could undermine our ability to attain and retain customers or reduce utilization of our leased 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 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.

Reduced demand for or supply of crude oil and refined products could affect our results of operations and ability to make distributions at current levels to our unitholders.

Our business is dependent upon the demand for and supply of the crude oil and refined products transported by our pipelines and stored in our terminals. Any sustained decrease in demand for refined products in the markets served by our pipelines, terminals or fuels marketing operations could result in a significant reduction in throughputs in our pipelines, storage in our terminals or earnings in our fuels marketing operations, which would reduce our cash flows and our ability to make distributions at current levels to our unitholders. Factors that could lead to a decrease in 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;

•

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;


•	a decrease in corn acres planted, which may reduce demand for anhydrous ammonia; and


•	the increased use of alternative fuel sources, such as battery-powered engines.

Similarly, any sustained decrease in the supply of crude oil and refined products could result in a significant reduction in throughputs in our pipelines and storage in our terminals, which would reduce our cash flows and our ability to make distributions at current levels to our unitholders. Factors that could lead to a decrease in supply to 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;

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•	changes in the regulatory environment, governmental policies or taxation that directly or indirectly delay production or increase the cost of production of refined products; and


•	actions taken by foreign oil and gas producing nations that impact prices for crude oil and refined products.

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

As of December 31, 2014, our consolidated debt was $2.8 billion. In addition to any potential direct financial impact of 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. The ratings of NuStar Logistics’ were downgraded to Ba1 by Moody’s Investor Service Inc. (Moody’s) in January 2013, BB+ by Standard & Poor’s Ratings Services (S&P) in July 2012 and BB by Fitch, Inc. in November 2012. As a result of the S&P and Moody’s downgrades, interest rates on borrowings under our five-year revolving credit agreement and our 7.65% senior notes due 2018 increased. Also, we 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. Any further downgrades in the future could result in additional increases to the interest rates on borrowings under our credit facilities and the 7.65% senior notes due 2018, significantly increase our capital costs 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 requires us to maintain, as of the end of each rolling period, which consists 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. Failure to comply with any of the revolving credit agreement restrictive covenants or this coverage ratio will result in a default and could result in acceleration of this agreement and possibly other indebtedness.

Debt service obligations, restrictive covenants in our credit facilities and the indentures governing our outstanding senior and subordinated notes 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 at current levels. In addition, this leverage may make our results of operations more susceptible to adverse economic or operating conditions. For example, during an event of default under certain of our debt agreements, we would be prohibited from making cash distributions to our unitholders. If 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 at current levels. Additionally, we may not be able to access the capital markets in the future at economically attractive terms, which may adversely affect our future financial and operating flexibility and our ability to pay cash distributions at current levels.

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, our operating results, cash flows and ability to make distributions to our unitholders.

We are subject to risks of loss resulting from nonpayment or nonperformance by our customers to whom we extend credit. In addition, nonperformance by vendors who have committed to provide us with critical products or services could raise our costs or interfere with our ability to successfully conduct our business. Furthermore, nonpayment by the counterparties to any of our outstanding commodity derivatives could expose us to additional commodity price risk. 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. 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.

Axeon’s failure to repay the Axeon Term Loan and any liability we incur as a result of the financing arrangements and guarantees of Axeon required by that loan could have a material and adverse impact on our financial condition, results of operations and cash flows and could adversely affect our ability to make quarterly distributions to our unitholders.

In connection with our sale of NuStar Asphalt LLC (now known as Axeon), our operating subsidiary, NuStar Logistics, agreed to convert the revolving credit facility with Axeon into a $190 million term loan (the Axeon Term Loan). We also agreed to continue to provide credit support to Axeon in the form of guarantees, letters of credit and cash collateral of up to $150 million (the Credit Support) until February 2016, at which point the amount of Credit Support will begin to decline until the obligation is terminated no later than September 2019.

Axeon was scheduled to repay amounts under the Axeon Term Loan to reduce the amount outstanding to $175 million by December 31, 2014 and is scheduled to make further repayments to reduce the amount outstanding to $150 million by

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September 30, 2015, with repayment in full no later than September 2019 and earlier repayment possible, depending on the amount of excess cash flows (if any) generated by Axeon. Any repayments of the Axeon Term Loan are subject to Axeon meeting certain restrictive requirements contained in its third-party asset-based revolving credit facility (ABL Facility). Axeon failed to make the scheduled repayment by December 31, 2014.

In the event that Axeon defaults on any of its obligations under the Axeon Term Loan, we would have available only those measures available to an unsecured creditor with the rights and limitations provided in the Axeon Term Loan, and, to the extent provided in the agreements, the ABL Facility lenders would be senior to those rights. In the event of a default on any of the obligations underlying the Credit Support, we would be responsible for Axeon’s liabilities for the default and have only the rights of repayment associated with that instrument. The failure by Axeon to make scheduled repayments under the Axeon Term Loan or the default by Axeon of any of its obligations under the Axeon Term Loan or underlying the Credit Support may have an adverse impact on our financial condition, results of operations, cash flows and ability to pay distributions to our unitholders at current levels.

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. At December 31, 2014, we had approximately $2.8 billion of consolidated debt, of which $1.8 billion was at fixed interest rates and $1.0 billion was at variable interest rates. In addition, prior ratings downgrades on our existing indebtedness caused interest rates under our revolving credit agreement and our senior notes due 2018 to increase effective January 2013, and future downgrades may cause such interest rates to increase further. Our results of operations, cash flows and financial position could be materially adversely affected by significant increases in interest rates above current levels. Further, the trading price of our units is sensitive to changes in interest rates and any rise in interest rates could adversely impact such trading price.

Our operations are subject to operational hazards and unforeseen interruptions, and we do not insure against all potential losses. Therefore, we could be seriously harmed by unexpected liabilities.

Our operations are subject to operational hazards and unforeseen interruptions such as natural disasters, adverse weather, accidents, fires, explosions, hazardous materials releases, mechanical failures and other events beyond our control. These events might result in a loss of equipment or life, injury or extensive property damage, as well as an interruption in our operations. In the event any of our facilities 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.

We may not be able to maintain or obtain insurance of the type and amount we desire at reasonable rates. As a result of market conditions, premiums and deductibles for certain of our insurance policies have increased substantially and could escalate further. Certain insurance coverage could become unavailable or 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 and our ability to make distributions at current levels to our unitholders and to meet our debt service requirements.

A failure in our computer systems or a cyber-attack on us or third parties with whom we have a relationship may adversely affect our operations and reputation.

We rely on the use of technology to conduct our business. Our business is dependent upon our operational and financial computer systems to process the data necessary to conduct almost all aspects of our business, including operating our pipelines and storage facilities, recording and reporting commercial and financial transactions and receiving and making payments. Our systems and networks, as well as those of our customers, suppliers, vendors and counterparties, may become the target of cyber-attacks or information security breaches, which in turn could result in the unauthorized release and misuse of confidential and proprietary information as well as disrupt our operations, damage our facilities or those of third parties and harm our reputation. Any failure or disruption of our systems could have an adverse effect on our revenues and increase our operating and capital costs, which could reduce the amount of cash otherwise available for distributions. We also may be required to incur additional costs to modify or enhance our systems in order to try to prevent or remediate any such attacks.

Potential future acquisitions and expansions, if any, may increase substantially the level of our indebtedness and contingent liabilities, and we may be unable to integrate them 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 businesses. Acquisitions may require substantial capital or the incurrence of substantial indebtedness. If we consummate any future material acquisitions, our capitalization and results of operations may change significantly, and you will not have the opportunity to evaluate the economic, financial and other relevant information that we will consider in connection with any future acquisitions.

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Acquisitions and business expansions involve numerous risks, including difficulties in the assimilation of the assets and operations of the acquired businesses, inefficiencies and difficulties that arise because of unfamiliarity with new assets and the businesses associated with them and new geographic areas. Further, unexpected costs and challenges may arise whenever businesses with different operations or management are combined. Successful business combinations will require our management and other personnel to devote significant amounts of time to integrating the acquired businesses with our existing operations. These efforts may temporarily distract their attention from day-to-day business, the development or acquisition of new properties and other business opportunities. If we do not successfully integrate any past or future acquisitions, or if there is any significant delay in achieving such integration, our business and financial condition could be adversely affected.

Moreover, part of our 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.

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 these rights-of-way or other property rights are perpetual in duration while others are for a specific period of time. In addition, some of our facilities are located on leased premises. Our loss of these 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 have liabilities from our assets that pre-exist 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. Releases may have occurred in the past that could require costly future remediation. If a significant release or event occurred in the past, the liability for which was not retained by the seller, or for which indemnification by the seller is not available, it could adversely affect our financial position and results of operations.

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

Scientific studies have suggested that emissions of certain gases, commonly referred to as “greenhouse gases” and including carbon dioxide and methane, may be contributing to warming of the Earth’s atmosphere. In response to such studies, the U.S. Congress, European Union and other political bodies have considered legislation or regulation to reduce emissions of greenhouse gases. In addition, several states and local governmental bodies, either individually or through multi-member initiatives, have already taken legal measures to reduce emissions of greenhouse gases, including through the development of greenhouse gas emission inventories and/or greenhouse gas cap and trade programs. As an alternative to reducing emission of greenhouse gases under cap and trade programs, governmental bodies may consider the implementation of a program to tax the emission of carbon dioxide and other greenhouse gases. Passage of climate change legislation or other regulatory initiatives in 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 emissions, pay any taxes related to our greenhouse gas emissions or administer and manage a greenhouse gas emissions program. 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 control or other initiatives could have adverse effects on our business, financial position, results of operations and prospects.

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

We operate in six foreign countries and a significant portion of our revenues come from our business in these countries. Our operations outside the United States may 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. We have assets in certain emerging markets, and the developing nature of these markets presents a number of risks. Deterioration of social, political, labor or economic conditions, including the increasing threat of drug cartels, in a specific country or region and difficulties in staffing and managing foreign operations may also adversely affect our operations or financial results.

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

Our operations are subject to increasingly stringent environmental, health and safety laws and regulations. Transporting, storing and distributing products, including petroleum products, produces a 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 for damages to natural resources, personal injury or property damages to private parties and significant business interruption. We own or lease a number of properties that have been used to transport, store or distribute products for many years. Many of these properties were operated by third parties whose handling, disposal or release of products and wastes was not under our control.

If we were to incur a significant liability pursuant to environmental, health or safety laws or regulations, such a liability could have a material adverse effect on our financial position, our ability to make distributions to our unitholders at current levels and our ability to meet our debt service requirements. Please read Item 3. “Legal Proceedings” and Note 16 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data.”

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, 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 FERC. A successful rate challenge could result in a common carrier paying refunds together with interest for the period that the rate was in effect. In addition, shippers may challenge by complaint tariff rates and terms and conditions of service even after the rates and terms and conditions of service are in effect. If the FERC, in response to such a complaint or on its own initiative, initiates an investigation of rates that are already in effect, the FERC may order a carrier to change its rates prospectively. If existing rates are challenged and are determined by the FERC to be in excess of a just and reasonable level, a shipper may obtain reparations for damages sustained during the two years prior to the date the shipper filed a complaint.

We use various FERC-authorized rate change methodologies for our interstate pipelines, including indexing, cost-of-service rates, market-based rates and settlement rates. Typically, we adjust our rates annually in accordance with FERC indexing methodology, which currently allows a pipeline to change their rates within prescribed ceiling levels that are tied to an inflation index. For the five-year period beginning July 1, 2011, the current index is measured by the year-over-year change in the Bureau of Labor’s producer price index for finished goods, plus 2.65%. However, some of our newer projects that involved an open season include negotiated indexation rate caps. These methodologies 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 indexation rate cap. 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 at current levels to our unitholders and to meet our debt service requirements. Additionally, competition constrains our rates in various markets. As a result, we may from time to time be forced to reduce some of our rates to remain competitive.

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

In May 2005, the FERC issued a statement of general policy stating it will permit pipelines to include in cost 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 United States Court of Appeals for the District of Columbia Circuit (D.C. Court), and on May 29, 2007, the D.C. Court 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. Nonetheless, these issues are currently pending before the FERC on rehearing and, absent settlement, will likely be reviewed by the D.C. Court. Because the extent to which an interstate oil pipeline is entitled to an income tax allowance is subject to a case-by-case review at the FERC and is a matter under litigation, the level of income tax allowance to which we will ultimately be entitled is not certain. Although the FERC’s current income tax allowance policy is generally favorable for pipelines that are organized as pass-through entities, it still entails rate risks due to the case-by-case review requirement and the above-noted pending litigation. How the FERC’s income tax allowance policy is applied in practice to pipelines owned by publicly traded partnerships could impose limits on our ability to include a full income tax allowance in cost of service.

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

Our ammonia pipeline is subject to regulation under the ICA by the STB. Under that regulation our ammonia pipeline’s rates, classifications, 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 person, place, port or type of traffic to unreasonable discrimination.

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

Power costs constitute a significant portion of our operating expenses. For the year ended December 31, 2014, our power costs equaled approximately $44.1 million, or 9.3% 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 use primarily natural gas to generate electricity. Accordingly, our power costs typically fluctuate with natural gas prices. 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 at current levels to our unitholders.

Terrorist attacks and the threat of terrorist attacks have resulted in increased costs to our business. Continued hostilities in the Middle East or other sustained military campaigns may adversely impact our results of operations.

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, the possibility that infrastructure facilities could be direct targets of, or indirect casualties of, an act of terror and instability in the financial markets that could restrict our ability to raise capital.

Our cash distribution policy may limit our growth.

Consistent with the terms of our partnership agreement, we distribute our available cash to our unitholders 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 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.

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We could be subject to damages based on claims brought against us by our customers or lose customers as a result of the failure of our products to meet certain quality specifications.

Certain of our products are produced to precise customer specifications. If a product fails to perform in a manner consistent with the detailed 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. A successful claim or series of claims against us could result in a loss of one or more customers.

The price volatility of crude oil and refined products can reduce our fuels marketing revenues and ability to make distributions to our unitholders.

Revenues associated with our fuels marketing operations result primarily from our crude blending and trading operations and fuel oil sales. We also maintain product inventory related to these activities. The price and market value of crude oil and refined products is volatile. Our revenues will be adversely affected by this volatility during periods of decreasing prices because of the reduction in the value and resale price of our inventory. Conversely, during periods of increasing petroleum product prices, our revenues may be adversely affected because of the increased costs associated with obtaining our inventory. Future price volatility could have an adverse impact on our results of operations, cash flows and ability to make distributions to our unitholders.

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.

In order to manage our exposure to commodity price fluctuations associated with our fuels marketing segment, we may engage in crude oil and petroleum product hedges. As a result, our marketing and trading of crude oil and petroleum products may expose us to 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. We may also 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. Further, 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.

As a result of the risks described above, the activities associated with our marketing and trading business may expose us to volatility in earnings and financial losses, which may adversely affect our financial condition and our ability to make our quarterly distributions to our unitholders.

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:


•	the counterparties to our futures contracts fail to perform under the contracts; or


•	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. In addition, it is not possible for us to engage in a hedging transaction that completely mitigates our exposure to commodity prices. 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.

NuStar GP Holdings may 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 and as of December 31, 2014, an aggregate 12.9% limited partner interest in us. 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

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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 the 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 common 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, issuance 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


•	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 will affect the amount of cash available for distribution.

We may issue an unlimited number of additional units, which will dilute existing interests of unitholders and may increase the risk that we will be unable to maintain or increase our per unit distribution level.

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 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 unit distribution level and may negatively affect the market price of the units.

TAX RISKS TO OUR UNITHOLDERS

If we were treated as a corporation for federal or state income tax purposes, 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.

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, which is currently a maximum of 35%. Distributions to unitholders would generally be taxed again as corporate distributions, and no income, gains, losses, deductions or credits would flow through to unitholders. Thus, treatment of us as a corporation would result in a material reduction in our anticipated cash flows and after-tax return to unitholders, likely causing a substantial reduction in the value of our units.

Current law may change, causing us to be treated as a corporation for federal income tax purposes or otherwise subjecting us to entity-level taxation. In addition, 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 or other forms of taxation. Partnerships and limited liability companies, unless specifically exempted, are also subject to a state-level tax imposed on revenues. Imposition of any entity-level tax on us by states in which we operate will reduce the cash available for distribution to our unitholders.

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

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with all of the positions we take. Any contest with the IRS may materially and adversely impact the market for our units and the prices at which they trade. Moreover, the costs of any contest between us and the IRS will result in a reduction in cash available for distribution to our unitholders and thus will be borne indirectly by our unitholders and our general partner.

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 the unitholder’s respective share of our taxable income, whether or not such unitholder receives cash distributions from us. Unitholders may not receive cash distributions from us equal to the unitholder’s respective share of our taxable income or even equal to the actual tax liability that results from the unitholder’s respective share of our taxable income.

The sale or exchange of 50% or more of our capital and profits interests, within a twelve-month period, will result in the termination of our partnership for federal income tax purposes.

A termination would, among other things, result in the closing of our taxable year for all unitholders and would result in a deferral of depreciation and cost recovery deductions allowable in computing our taxable income. If our partnership were terminated for federal income tax purposes, a NuStar Energy unitholder would be allocated an increased amount of federal taxable income for the year in which the partnership is considered terminated and the subsequent years as a percentage of the cash distributed to the unitholder with respect to that period.

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

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

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

Investment in units by tax-exempt entities, such as individual retirement accounts (known as IRAs) and non-United States persons raises issues unique to them. For example, virtually all of our income allocated to organizations exempt from federal income tax, including individual retirement accounts and other retirement plans, will be unrelated business taxable income and will be taxable to them. Distributions to non-United States persons will be reduced by withholding taxes at the highest applicable effective tax rate, and non-United States persons will be required to file United States federal income tax returns and pay tax on their share of our taxable income.

We will treat each purchaser of our 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 units.

Because we cannot match transferors and transferees of units, we will adopt depreciation and amortization positions that may not conform to 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 any sale of units and could have a negative impact on the value of our units or result in audit adjustments to a 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 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 or local tax returns.

We have adopted certain valuation methodologies that may result in a shift of income, gain, loss and deduction between the general partner and the unitholders. The IRS may challenge this treatment, which could adversely affect the value of our common units.

When we issue additional units or engage in certain other transactions, we determine the fair market value of our assets and allocate any unrealized gain or loss attributable to our assets to the capital accounts of our unitholders and our general partner. Our methodology may be viewed as understating the value of our assets. In that case, there may be a shift of income, gain, loss and deduction between certain unitholders and the general partner, which may be unfavorable to such unitholders. Moreover,

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under our current valuation methods, subsequent purchasers of common units may have a greater portion of their Internal Revenue Code Section 743(b) adjustment allocated to our tangible assets and a lesser portion allocated to our intangible assets. The IRS may challenge our valuation methods, our allocation of the Section 743(b) adjustment attributable to our tangible and intangible assets, and allocations of income, gain, loss and deduction between the general partner and certain of our unitholders.

A successful IRS challenge to these methods or allocations could adversely affect the amount of taxable income or loss being allocated to our 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 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.

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 assets. 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 related to environmental liabilities associated with historical operations, liens for current taxes and other burdens and easements, restrictions and other encumbrances 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.

ENVIRONMENTAL AND SAFETY COMPLIANCE MATTERS

With respect to the environmental proceeding listed below, if it was decided against us, we believe that it would not have a material effect on our consolidated financial position. However, it is not possible to predict the ultimate outcome of the

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proceeding or whether such ultimate outcome may have a material effect on our consolidated financial position. We are reporting this proceeding to comply with Securities and Exchange Commission regulations, which require us to disclose proceedings arising under federal, state or local provisions regulating the discharge of materials into the environment or protecting the environment if we reasonably believe that such proceedings will result in monetary sanctions of $100,000 or more.

In particular, our wholly owned subsidiary, Shore Terminals LLC (Shore), owns a refined product terminal in Portland, Oregon located adjacent to the Portland Harbor. The EPA has classified portions of the Portland Harbor, including the portion adjacent to our terminal, as a federal “Superfund” site due to sediment contamination (the Portland Harbor Site). Portland Harbor is contaminated with metals (such as mercury), pesticides, herbicides, polynuclear aromatic hydrocarbons, polychlorinated biphenyls, semi-volatile organics and dioxin/furans. Shore and more than 90 other parties have received a “General Notice” of potential liability from the EPA relating to the Portland Harbor Site. The letter advised Shore that it may be liable for the costs of investigation and remediation (which liability may be joint and several with other potentially responsible parties), as well as for natural resource damages resulting from releases of hazardous substances to the Portland Harbor Site. We have agreed to work with more than 90 other potentially responsible parties to attempt to negotiate an agreed method of allocating costs associated with the cleanup. The precise nature and extent of any clean-up of the Portland Harbor Site, the parties to be involved, the process to be followed for any clean-up and the allocation of any costs for the clean-up among responsible parties have not yet been determined. It is unclear to what extent, if any, we will be liable for environmental costs or damages associated with the Portland Harbor Site. It is also unclear to what extent natural resource damage claims or third party contribution or damage claims will be asserted against Shore.

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 COMMON UNITS

Market Information, Holders and 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 9, 2015, we had 576 holders of record of our common units. The high and low sales prices (composite transactions) by quarter for the years ended December 31, 2014 and 2013 were as follows:



	Price Range of Common Unit
	High		Low
Year 2014
4th Quarter	$	66.94	$	50.91
3rd Quarter	68.33		61.02
2nd Quarter	62.88		53.76
1st Quarter	55.15		47.51
Year 2013
4th Quarter	$	53.69	$	39.52
3rd Quarter	46.52		36.15
2nd Quarter	54.95		42.31
1st Quarter	53.45		43.40

Our partnership agreement requires that we distribute all “Available Cash” to our partners each quarter, and this term is defined in the partnership agreement as cash on hand at the end of the quarter, plus certain permitted borrowings made subsequent to the end of the quarter, less cash reserves determined by our board of directors. See Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” for further information regarding our sources of cash to fund distributions. The cash distributions applicable to each of the quarters in the years ended December 31, 2014 and 2013 were as follows:



	Record Date	Payment Date	Amount Per Unit
Year 2014
4th Quarter	February 9, 2015	February 13, 2015	$	1.095
3rd Quarter	November 10, 2014	November 14, 2014	1.095
2nd Quarter	August 6, 2014	August 11, 2014	1.095
1st Quarter	May 7, 2014	May 12, 2014	1.095
Year 2013
4th Quarter	February 10, 2014	February 14, 2014	$	1.095
3rd Quarter	November 11, 2013	November 14, 2013	1.095
2nd Quarter	August 5, 2013	August 9, 2013	1.095
1st Quarter	May 6, 2013	May 10, 2013	1.095

Our general partner is entitled to incentive distributions if the amount that we distribute with respect to any quarter exceeds specified target levels shown below:



	Percentage of Distribution
Quarterly Distribution Amount per Unit	Unitholders	General Partner
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 $43.2 million for each of the years ended December 31, 2014 and 2013. The general partner’s share of our distributions for the years ended December 31, 2014 and 2013 was 13.0% in each year due to the impact of the incentive distributions.

The following table sets forth the purchases of our common units made during the quarter ended December 31, 2014 by or on behalf of us or an affiliated purchaser:



Period	Total Number of Units Purchased⁽¹⁾	Average Price Paid per Unit⁽¹⁾		Total Number of Units Purchased as Part of Publicly Announced Plans or Programs	Maximum Number (or Approximate Dollar Value) of Units that May Yet Be Purchased Under the Plans or Programs
October 1 through October 31	—	$	—	—	$	—
November 1 through November 30	—	—		—	—
December 1 through December 31	25,000	52.80		—	—
Total	25,000	$	52.80	—	$	—


(1)	During the quarter ended December 31, 2014, NuStar GP, LLC, the general partner of our general partner, purchased 25,000 of our common units in the open market to satisfy NuStar GP, LLC’s obligations under its long-term incentive plans.

ITEM 6. SELECTED FINANCIAL DATA

The following table contains selected financial data derived from our audited financial statements. On January 1, 2013, we sold the San Antonio Refinery. As a result, we have presented the results of operations for the San Antonio Refinery and related assets as discontinued operations for all periods presented. As of December 31, 2013, we reclassified certain storage assets as “Assets held for sale” on the consolidated balance sheet. As a result, we have presented the results of operations for those assets as discontinued operations for all periods presented.



	Year Ended December 31,
	2014		2013 (a)			2012 (a)			2011		2010
	(Thousands of Dollars, Except Per Unit Data)
Statement of Income Data:
Revenues	$	3,075,118	$	3,463,732		$	5,945,736		$	6,257,629	$	4,395,083
Operating income (loss)	346,901		(19,121		)	(18,168		)	310,883		306,747
Income (loss) from continuing operations	214,169		(185,509		)	(166,001		)	218,674		243,931
Income (loss) from continuing operations per unit applicable to limited partners	2.14		(2.89		)	(2.79		)	2.74		3.27
Cash distributions per unit applicable to limited partners	4.380		4.380			4.380			4.360		4.280

	December 31,
	2014		2013			2012			2011		2010
	(Thousands of Dollars)
Balance Sheet Data:
Property, plant and equipment, net	$	3,460,732	$	3,310,653		$	3,238,460		$	3,430,468	$	3,187,457
Total assets	4,918,796		5,032,186			5,613,089			5,881,190		5,386,393
Long-term debt, less current portion	2,749,452		2,655,553			2,124,582			1,928,071		2,136,248
Total partners’ equity	1,716,210		1,903,794			2,584,995			2,864,335		2,702,700


(a)	The losses for the years ended December 31, 2013 and 2012 are mainly due to goodwill and other asset impairment charges. Please refer to Note 5 and Note 11 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for a discussion of goodwill and other asset impairments.

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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 Items 1., 1A. and 2. “Business, Risk Factors and Properties” and Item 8. “Financial Statements and Supplementary Data” included in this report.

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

This Form 10-K contains certain estimates, predictions, projections, assumptions and other forward-looking statements that involve various risks and uncertainties. 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. 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 the 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.

OVERVIEW

NuStar Energy L.P. (NuStar Energy) (NYSE: NS) is engaged in the transportation of petroleum products and anhydrous ammonia, the terminalling and storage of petroleum products and the marketing of petroleum products. Unless otherwise indicated, the terms “NuStar Energy,” “the Partnership,” “we,” “our” and “us” are used in this report to refer to NuStar Energy, to one or more of our consolidated subsidiaries or to all of them taken as a whole. NuStar GP Holdings, LLC (NuStar GP Holdings) (NYSE: NSH) owns our general partner, Riverwalk Logistics, L.P., and owns a 14.9% total interest in us as of December 31, 2014. 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

Dispositions and Acquisitions

Asphalt Dispositions. On September 28, 2012, we sold a 50% ownership interest (the 2012 Asphalt Sale) in NuStar Asphalt LLC, previously a wholly owned subsidiary, to an affiliate of Lindsay Goldberg LLC (Lindsay Goldberg), a private investment firm. NuStar Asphalt LLC owns and operates the asphalt refining assets that were previously wholly owned by NuStar Energy, including an asphalt refinery located in Paulsboro, New Jersey and a terminal in Savannah, Georgia (collectively, the Asphalt Operations). Lindsay Goldberg paid $175.0 million for the Class A equity interests (Class A Interests) of NuStar Asphalt LLC, while we retained the Class B equity interests with a fair value of $52.0 million (Class B Interests). We also received $263.8 million from NuStar Asphalt LLC for inventory related to the Asphalt Operations. At closing, the fair value of the consideration we received was less than the carrying amount of the assets of the Asphalt Operations, and we recognized a loss of $23.8 million in “Other income (expense), net” in the consolidated statements of income for the year ended December 31, 2012. Upon closing, we deconsolidated NuStar Asphalt LLC and started reporting our remaining investment in NuStar Asphalt LLC using the equity method of accounting.

On February 26, 2014, we sold our remaining 50% ownership interest in NuStar Asphalt LLC to Lindsay Goldberg (the 2014 Asphalt Sale). Effective February 27, 2014, NuStar Asphalt LLC changed its name to Axeon Specialty Products LLC (Axeon). Lindsay Goldberg now owns 100% of Axeon. As a result of the 2014 Asphalt Sale, we ceased applying the equity method of

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accounting. Upon completion of the 2014 Asphalt Sale, the parties agreed to: (i) convert the $250.0 million unsecured revolving credit facility provided by us to Axeon (the NuStar JV Facility) from a revolving credit agreement into a $190.0 million term loan (the Axeon Term Loan); (ii) terminate the terminal services agreements with respect to our terminals in Rosario, NM, Catoosa, OK and Houston, TX; (iii) amend the terminal services agreements for our terminals in Baltimore, MD and Jacksonville, FL; and (iv) transfer ownership of both the Wilmington, NC and Dumfries, VA terminals to Axeon, which were categorized as assets held for sale at December 31, 2013. Please refer to Note 19 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for a discussion of our agreements with Axeon.

As of December 31, 2013 and 2012, we presented our 50% ownership interest in Axeon as “Investment in joint ventures” on the consolidated balance sheet. The consolidated statements of income include the results of operations for Axeon in “Equity in earnings (loss) of joint ventures” from September 28, 2012 through February 25, 2014.

In anticipation of the 2012 Asphalt Sale, we evaluated the goodwill and other long-lived assets associated with the Asphalt Operations for potential impairment. We determined the fair value of the Asphalt Operations reporting unit was less than its carrying value, which resulted in the recognition of a goodwill impairment loss of $22.1 million in the second quarter of 2012. In addition, we recorded an impairment loss of $244.2 million in the second quarter of 2012 to write-down the carrying value of long-lived assets related to the Asphalt Operations, including fixed assets, intangible assets and other long-term assets, to their estimated fair value. The goodwill impairment loss and the asset impairment loss related to the Asphalt Operations are reported in the fuels marketing segment. Please refer to Note 5 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for a discussion of the 2012 Asphalt Sale, the related asset impairments and associated fair value measurements.

Terminal Dispositions. As of December 31, 2013, in addition to the terminals located in Wilmington, NC and Dumfries, VA that were transferred to Axeon as described above, we identified several non-strategic, underperforming terminal facilities and decided to divest those facilities. As a result, we classified the property, plant and equipment associated with these assets as “Assets held for sale” on the consolidated balance sheet. We presented the results of operations for those facilities as discontinued operations for all periods presented, including an impairment loss of $102.5 million for the year ended December 31, 2013. In September 2014, we sold our 75% interest in our facility in Mersin, Turkey for proceeds of $13.4 million (the Turkey Sale). We recognized a gain of $3.7 million, which is included in discontinued operations for the year ended December 31, 2014. In June 2014, we sold three terminals located in Mobile, AL with an aggregate storage capacity of 1.8 million barrels for proceeds of $13.7 million. In April 2012, we sold five terminals in Georgia and Alabama with an aggregate storage capacity of 1.8 million barrels for proceeds of $30.8 million.

San Antonio Refinery Disposition. On January 1, 2013, we sold our fuels refinery in San Antonio, Texas (the San Antonio Refinery) and related assets for approximately $117.0 million (the San Antonio Refinery Sale). We have presented the results of operations for the San Antonio Refinery and related assets as discontinued operations for all periods presented, including a gain of $9.3 million on the sale.

TexStar Asset Acquisition. On December 13, 2012, we acquired the TexStar Crude Oil Assets (as defined below) from TexStar Midstream Services, LP and certain of its affiliates (collectively, TexStar) for $325.4 million (the TexStar Asset Acquisition), pursuant to an asset purchase agreement. The TexStar Crude Oil Assets consist of approximately 140 miles of crude oil pipelines and gathering lines, as well as five terminals and storage facilities providing 0.6 million barrels of storage capacity. The consolidated statements of income include the results of operations for the TexStar Asset Acquisition in the pipeline segment commencing on December 13, 2012.

2013 Goodwill Impairment

In the fourth quarter of 2013, we recognized a $304.5 million goodwill impairment loss in the storage segment, which represents the write-down of the carrying value of goodwill associated with our St. Eustatius and Point Tupper terminal operations. Please refer to Note 11 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for a discussion of the goodwill impairment loss.

Operations

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

Pipeline. We own refined product pipelines covering approximately 5,463 miles of pipelines, which consist of Central West System refined product pipelines, the East Pipeline and the North Pipeline. The East and North Pipelines have storage capacity

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of approximately 6.3 million barrels. In addition, we own a 2,000 mile anhydrous ammonia pipeline and 1,180 miles of Central West System crude oil pipelines including approximately 3.5 million barrels of storage capacity.

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) providing approximately 80.9 million barrels of storage capacity.

Fuels Marketing. Within our fuels marketing operations, we purchase crude oil and refined petroleum products for resale. Our fuels marketing segment includes our fuels marketing operations and, prior to the 2012 Asphalt Sale, the Asphalt 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.

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, we record the changes in the fair values of these derivative instruments in cost of product sales. The changes in the fair values of these derivative instruments generally are offset, at least partially, by changes in the values of the hedged physical inventory. However, we do not recognize those changes in the value of the hedged inventory until the physical sale of such inventory takes place. Therefore, 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. In addition, we value our inventory at the lower of cost or market. If changes in commodity markets cause market prices to fall below the cost of our inventory, we may be required to reduce the value of our inventory to market.

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;


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


•	other factors, such as refinery utilization rates and maintenance turnaround schedules, that impact the operations of refineries served by our pipeline and storage assets.

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RESULTS OF OPERATIONS

Year Ended December 31, 2014 Compared to Year Ended December 31, 2013

Financial Highlights

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



	Year Ended December 31,
	2014			2013			Change
Statement of Income Data:
Revenues:
Service revenues	$	1,026,446		$	938,138		$	88,308
Product sales	2,048,672			2,525,594			(476,922		)
Total revenues	3,075,118			3,463,732			(388,614		)

Costs and expenses:
Cost of product sales	1,967,528			2,453,997			(486,469		)
Operating expenses	472,925			454,396			18,529
General and administrative expenses	96,056			91,086			4,970
Depreciation and amortization expense	191,708			178,921			12,787
Goodwill impairment loss	—			304,453			(304,453		)
Total costs and expenses	2,728,217			3,482,853			(754,636		)

Operating income (loss)	346,901			(19,121		)	366,022
Equity in earnings (loss) of joint ventures	4,796			(39,970		)	44,766
Interest expense, net	(132,281		)	(127,119		)	(5,162		)
Interest income from related party	1,055			6,113			(5,058		)
Other income, net	4,499			7,341			(2,842		)
Income (loss) from continuing operations before income tax expense	224,970			(172,756		)	397,726
Income tax expense	10,801			12,753			(1,952		)
Income (loss) from continuing operations	214,169			(185,509		)	399,678
Loss from discontinued operations, net of tax	(3,791		)	(99,162		)	95,371
Net income (loss)	$	210,378		$	(284,671	)	$	495,049
Net income (loss) per unit applicable to limited partners:
Continuing operations	$	2.14		$	(2.89	)	$	5.03
Discontinued operations	(0.04		)	(1.11		)	1.07
Total	$	2.10		$	(4.00	)	$	6.10
Weighted-average limited partner units outstanding	77,886,078			77,886,078			—

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Segment Operating Highlights

(Thousands of Dollars, Except Barrel/Day Information)



	Year Ended December 31,
	2014			2013			Change
Pipeline:
Refined products pipelines throughput (barrels/day)	510,737			487,021			23,716
Crude oil pipelines throughput (barrels/day)	437,757			365,749			72,008
Total throughput (barrels/day)	948,494			852,770			95,724
Throughput revenues	$	477,030		$	411,529		$	65,501
Operating expenses	154,106			134,365			19,741
Depreciation and amortization expense	77,691			68,871			8,820
Segment operating income	$	245,233		$	208,293		$	36,940

Storage:
Throughput (barrels/day)	887,607			781,213			106,394
Throughput revenues	$	123,051		$	104,553		$	18,498
Storage lease revenues	441,455			451,996			(10,541		)
Total revenues	564,506			556,549			7,957
Operating expenses	277,554			279,712			(2,158		)
Depreciation and amortization expense	103,848			99,868			3,980
Goodwill impairment loss	—			304,453			(304,453		)
Segment operating income (loss)	$	183,104		$	(127,484	)	$	310,588

Fuels Marketing:
Product sales and other revenue	$	2,060,017		$	2,527,698		$	(467,681	)
Cost of product sales	1,983,339			2,474,612			(491,273		)
Gross margin	76,678			53,086			23,592
Operating expenses	51,857			53,185			(1,328		)
Depreciation and amortization expense	16			27			(11		)
Segment operating income (loss)	$	24,805		$	(126	)	$	24,931

Consolidation and Intersegment Eliminations:
Revenues	$	(26,435	)	$	(32,044	)	$	5,609
Cost of product sales	(15,811		)	(20,615		)	4,804
Operating expenses	(10,592		)	(12,866		)	2,274
Total	$	(32	)	$	1,437		$	(1,469	)

Consolidated Information:
Revenues	$	3,075,118		$	3,463,732		$	(388,614	)
Cost of product sales	1,967,528			2,453,997			(486,469		)
Operating expenses	472,925			454,396			18,529
Depreciation and amortization expense	181,555			168,766			12,789
Goodwill impairment loss	—			304,453			(304,453		)
Segment operating income	453,110			82,120			370,990
General and administrative expenses	96,056			91,086			4,970
Other depreciation and amortization expense	10,153			10,155			(2		)
Consolidated operating income (loss)	$	346,901		$	(19,121	)	$	366,022

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Annual Highlights

Segment operating income increased $371.0 million for the year ended December 31, 2014, compared to the year ended December 31, 2013, mainly due to an operating loss of $127.5 million in the storage segment in 2013, which included a goodwill impairment charge of $304.5 million. Segment operating income in the pipeline segment increased $36.9 million for the year ended December 31, 2014 compared to the prior year, mainly due to increased throughputs on pipelines that serve Eagle Ford Shale production in South Texas. The fuels marketing segment operating income increased by $24.9 million for the year ended December 31, 2014, compared to the prior year, mainly due to improved product margins and lower operating expense in our bunker fuel operations. Additionally, we recorded equity in earnings of joint ventures of $4.8 million for the year ended December 31, 2014, compared to a loss in equity of joint ventures of $40.0 million for the year ended December 31, 2013, primarily due to losses from our investment in Axeon in 2013.

Loss from discontinued operations decreased $95.4 million for the year ended December 31, 2014, compared to the prior year, mainly due to an asset impairment charge of $102.5 million in 2013 associated with certain storage assets. Therefore we reported net income of $210.4 million for the year ended December 31, 2014, compared to a loss of $284.7 million for the year ended December 31, 2013.

Pipeline

Revenues increased $65.5 million and throughputs increased 95,724 barrels per day for the year ended December 31, 2014, compared to the year ended December 31, 2013, primarily due to:


•	an increase in revenues of $39.3 million and an increase in throughputs of 61,947 barrels per day on our South Texas crude oil pipelines that serve Eagle Ford Shale production, primarily resulting from continued growth in the region and the completion of expansion projects in 2014 and the third quarter of 2013 that increased our overall capacity;


•	an increase in revenues of $9.1 million and an increase in throughputs of 26,369 barrels per day on pipelines serving the McKee refinery mainly due to increased production by the McKee refinery in 2014;


•	an increase in revenues of $7.1 million and an increase in throughputs of 2,341 barrels per day on the East Pipeline due to higher average tariffs resulting from the annual index adjustments and increased long-haul deliveries, as well as higher demand due to favorable weather conditions during 2014 compared to last year; and


•	an increase in revenues of $4.9 million and an increase in throughputs of 3,140 barrels per day on the Ammonia Pipeline mainly due to favorable weather conditions during 2014 compared to last year.

Operating expenses increased $19.7 million for the year ended December 31, 2014, compared to the year ended December 31, 2013, primarily due to:


•	an $8.0 million gain in 2013 for the reduction of the contingent consideration liability recorded in association with the TexStar Asset Acquisition;


•	an increase of $6.3 million in maintenance and regulatory expenses, mainly associated with our East Pipeline and Ammonia Pipeline; and


•	an increase of $5.0 million in power costs, mainly due to the increase in throughputs on pipelines that serve Eagle Ford Shale production in South Texas and the East Pipeline.

Depreciation and amortization expense increased $8.8 million for the year ended December 31, 2014, compared to the year ended December 31, 2013, mainly due to the completion of various projects that serve Eagle Ford Shale production.

Storage

Throughput revenues increased $18.5 million and throughputs increased 106,394 barrels per day for the year ended December 31, 2014, compared to the year ended December 31, 2013, primarily due to:


•	an increase in revenues of $12.5 million and an increase in throughputs of 56,908 barrels per day at our Corpus Christi North Beach terminal due to an increase in Eagle Ford Shale crude oil being shipped to Corpus Christi and the completion of a new dock in the first quarter of 2014;


•	an increase in revenues of $3.0 million and an increase in throughputs of 37,822 barrels per day as a result of turnarounds and operational issues during the first quarter of 2013 at the refineries served by our Corpus Christi and Texas City crude oil storage tank facilities; and


•	an increase in revenues of $1.7 million and an increase in throughputs of 7,727 barrels per day at terminals serving the McKee refinery due to higher demand in those markets.

Storage lease revenues decreased $10.5 million for the year ended December 31, 2014, compared to the year ended December 31, 2013, primarily due to:


•	a decrease of $15.8 million at various domestic terminals, mainly as a result of reduced demand in several markets, resulting in lower throughputs and storage fees;

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•	a decrease of $1.6 million at our Point Tupper, Canada terminal facility, mainly due to lower throughput and related handling fees; and

•

a decrease of $0.9 million at our St. James terminal, mainly due to the narrowing price differential on two traded crude oil grades (WTI and LLS) that reduced our profit sharing and volumes delivered to one of our unit train offloading facilities. This decrease was partially offset by increased revenues resulting from the completion of another unit train offloading facility in the fourth quarter of 2013, new contracts and rate increases.

The declines in storage lease revenues were partially offset by an increase of $5.5 million at our UK terminal facilities, mainly due to the effect of foreign exchange rates and increased throughput and related handling fees. In addition, our asphalt terminals increased $3.6 million due to renegotiating the storage contracts.

Operating expenses decreased $2.2 million for the year ended December 31, 2014, compared to the year ended December 31, 2013, primarily due to reduced maintenance and regulatory expenses of $2.8 million, mainly at our West Coast and Gulf Coast terminals.

Depreciation and amortization expense increased $4.0 million for the year ended December 31, 2014, compared to the year ended December 31, 2013, primarily due to the completion of a unit train offloading facility in the fourth quarter of 2013 at our St. James terminal.

Fuels Marketing

Segment operating income increased $24.9 million for the year ended December 31, 2014, compared to the year ended December 31, 2013, primarily due to higher earnings of $36.2 million from our bunker fuel operations, which benefitted from improved product margins and decreased vessel lease and fuel costs. The increase in segment operating income from our bunker fuel operations was partially offset by lower earnings of $7.6 million in fuel oil trading, mainly resulting from lower product margins due to a lack of supply for blend components. In addition, operating expense in our bunker fuel and fuel oil trading operations increased by $7.5 million related to an allowance for doubtful accounts recorded in the fourth quarter of 2014. We also recognized a $3.8 million lower of cost or market adjustment, mainly impacting fuel oil trading operations.

Consolidation and Intersegment Eliminations

Revenue and operating expense eliminations 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 $5.0 million for the year ended December 31, 2014, compared to the year ended December 31, 2013, primarily as a result of higher compensation expense associated with satisfying obligations under our long-term incentive plans, which fluctuates with our unit price, and the termination of a services agreement between Axeon and NuStar GP, LLC in June 2014, under which Axeon reimbursed us for certain corporate support services. These increases were partially offset by reduced employee benefit costs.

We recorded equity in earnings of joint ventures of $4.8 million for the year ended December 31, 2014, compared to a loss in equity of joint ventures of $40.0 million for the year ended December 31, 2013, primarily due to losses from our investment in Axeon for the year ended December 31, 2013.

Interest expense, net increased $5.2 million for the year ended December 31, 2014, compared to the year ended December 31, 2013, mainly due to the issuance of the $300.0 million of 6.75% senior notes in August 2013. Interest income from related party represents the interest earned on the NuStar JV Facility prior to the 2014 Asphalt Sale. Interest income from the Axeon Term Loan after the 2014 Asphalt Sale is not a related party transaction and, therefore, is reported in “Interest expense, net” on the consolidated statements of income.

Other income, net decreased by $2.8 million for the year ended December 31, 2014, compared to the year ended December 31, 2013, mainly due to changes in foreign exchange rates related to our foreign subsidiaries.

Income tax expense decreased $2.0 million for the year ended December 31, 2014, compared to the year ended December 31, 2013, mainly due to a decrease in the margin tax in Texas.

The loss from discontinued operations decreased $95.4 million for the year ended December 31, 2014, compared to the year ended December 31, 2013, mainly due to the asset impairment charges of $102.5 million associated with certain storage terminals, partially offset by a gain of $9.3 million related to the San Antonio Refinery Sale.

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Year Ended December 31, 2013 Compared to Year Ended December 31, 2012

Financial Highlights

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



	Year Ended December 31,
	2013			2012			Change
Statement of Income Data:
Revenues:
Service revenues	$	938,138		$	870,157		$	67,981
Product sales	2,525,594			5,075,579			(2,549,985		)
Total revenues	3,463,732			5,945,736			(2,482,004		)

Costs and expenses:
Cost of product sales	2,453,997			4,930,174			(2,476,177		)
Operating expenses	454,396			526,145			(71,749		)
General and administrative expenses	91,086			104,756			(13,670		)
Depreciation and amortization expense	178,921			159,789			19,132
Goodwill impairment loss	304,453			22,132			282,321
Asset impairment loss	—			249,646			(249,646		)
Gain on legal settlement	—			(28,738		)	28,738
Total costs and expenses	3,482,853			5,963,904			(2,481,051		)

Operating loss	(19,121		)	(18,168		)	(953		)
Equity in loss of joint ventures	(39,970		)	(9,378		)	(30,592		)
Interest expense, net	(127,119		)	(90,535		)	(36,584		)
Interest income from related party	6,113			1,219			4,894
Other income (expense), net	7,341			(24,689		)	32,030
Loss from continuing operations before income tax expense	(172,756		)	(141,551		)	(31,205		)
Income tax expense	12,753			24,450			(11,697		)
Loss from continuing operations	(185,509		)	(166,001		)	(19,508		)
Loss from discontinued operations, net of tax	(99,162		)	(61,236		)	(37,926		)
Net loss	$	(284,671	)	$	(227,237	)	$	(57,434	)
Net loss per unit applicable to limited partners:
Continuing operations	$	(2.89	)	$	(2.79	)	$	(0.10	)
Discontinued operations	(1.11		)	(0.82		)	(0.29		)
Total	$	(4.00	)	$	(3.61	)	$	(0.39	)
Weighted-average limited partner units outstanding	77,886,078			72,957,417			4,928,661

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Segment Operating Highlights

(Thousands of Dollars, Except Barrel/Day Information)



	Year Ended December 31,
	2013			2012			Change
Pipeline:
Refined products pipelines throughput (barrels/day)	487,021			498,321			(11,300		)
Crude oil pipelines throughput (barrels/day)	365,749			345,648			20,101
Total throughput (barrels/day)	852,770			843,969			8,801
Throughput revenues	$	411,529		$	340,455		$	71,074
Operating expenses	134,365			128,987			5,378
Depreciation and amortization expense	68,871			52,878			15,993
Segment operating income	$	208,293		$	158,590		$	49,703

Storage:
Throughput (barrels/day)	781,213			765,556			15,657
Throughput revenues	$	104,553		$	95,612		$	8,941
Storage lease revenues	451,996			482,454			(30,458		)
Total revenues	556,549			578,066			(21,517		)
Operating expenses	279,712			288,881			(9,169		)
Depreciation and amortization expense	99,868			88,217			11,651
Goodwill and asset impairment loss	304,453			2,126			302,327
Segment operating (loss) income	$	(127,484	)	$	198,842		$	(326,326	)

Fuels Marketing:
Product sales and other revenue	$	2,527,698		$	5,086,383		$	(2,558,685	)
Cost of product sales	2,474,612			4,957,100			(2,482,488		)
Gross margin	53,086			129,283			(76,197		)
Operating expenses	53,185			148,458			(95,273		)
Depreciation and amortization expense	27			11,253			(11,226		)
Goodwill and asset impairment loss	—			266,357			(266,357		)
Segment operating loss	$	(126	)	$	(296,785	)	$	296,659

Consolidation and Intersegment Eliminations:
Revenues	$	(32,044	)	$	(59,168	)	$	27,124
Cost of product sales	(20,615		)	(26,926		)	6,311
Operating expenses	(12,866		)	(40,181		)	27,315
Total	$	1,437		$	7,939		$	(6,502	)

Consolidated Information:
Revenues	$	3,463,732		$	5,945,736		$	(2,482,004	)
Cost of product sales	2,453,997			4,930,174			(2,476,177		)
Operating expenses	454,396			526,145			(71,749		)
Depreciation and amortization expense	168,766			152,348			16,418
Goodwill and asset impairment loss	304,453			268,483			35,970
Segment operating income	82,120			68,586			13,534
General and administrative expenses	91,086			104,756			(13,670		)
Other depreciation and amortization expense	10,155			7,441			2,714
Other asset impairment loss	—			3,295			(3,295		)
Gain on legal settlement	—			(28,738		)	28,738
Consolidated operating loss	$	(19,121	)	$	(18,168	)	$	(953	)

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Annual Highlights

Operating loss for both years includes significant impairment charges. In 2013, we recognized a goodwill impairment charge of $304.5 million associated with our St. Eustatius and Point Tupper terminal operations, while 2012 included an impairment charge of $266.4 million related to the goodwill and long-lived assets of the Asphalt Operations. Segment operating income, which includes these impairment charges, increased $13.5 million for the year ended December 31, 2013, compared to the year ended December 31, 2012, primarily due to an increase of $49.7 million in the segment operating income of the pipeline segment. This increase was mainly due to increased throughputs on pipelines that serve Eagle Ford Shale production in South Texas and higher pipeline tariffs as a result of the annual index adjustment in July 2013.

Loss from continuing operations increased $19.5 million for the year ended December 31, 2013, compared to the year ended December 31, 2012, primarily due to an increase of $36.6 million in interest expense, net and an increase of $30.6 million in the equity in loss of joint ventures. Loss from discontinued operations, net of tax, increased $37.9 million for the year ended December 31, 2013, compared to the year ended December 31, 2012, mainly due to asset impairment charges of $102.5 million in 2013 associated with certain storage assets that were classified as “Assets held for sale” on the consolidated balance sheet as of December 31, 2013. Discontinued operations also include the results of operations for the San Antonio Refinery and related assets. As a result, we reported a net loss of $284.7 million for the year ended December 31, 2013, compared to a net loss of $227.2 million for the year ended December 31, 2012.

Pipeline

Revenues increased $71.1 million and throughputs increased 8,801 barrels per day for the year ended December 31, 2013, compared to the year ended December 31, 2012, primarily due to:


•	an increase in revenues of $57.4 million and an increase in throughputs of 49,855 barrels per day on crude oil pipelines that serve Eagle Ford Shale production in South Texas, primarily resulting from the TexStar Asset Acquisition and crude oil pipelines that were placed in service in the fourth quarter of 2012 and third quarter of 2013;


•	an increase in revenues of $6.3 million on the East Pipeline, despite lower throughputs of 2,997 barrels per day, due to higher average tariffs resulting from the annual index adjustment in July 2013 and increased long-haul deliveries;


•	an increase in revenues of $5.6 million and an increase in throughputs of 2,067 barrels per day on the North Pipeline, mainly due to the completion of an expansion project at the Mandan refinery in June 2012; and


•	an increase in revenues of $5.2 million and an increase in throughputs of 4,210 barrels per day on refined product and crude oil pipelines serving the McKee refinery resulting from increased volumes on pipelines with higher tariffs.

Those higher throughputs were partially offset by a decrease in throughputs of 28,438 barrels per day on crude oil pipelines serving the Ardmore refinery due to a new contract effective January 1, 2013 that combines two segments of a crude oil pipeline serving the Ardmore refinery for which throughputs were previously reported separately. That change in reporting throughputs did not adversely affect revenues, which increased by $0.4 million due to the new contract terms, despite a turnaround at the Ardmore refinery during the first quarter of 2013.

Revenues decreased $3.9 million and throughputs decreased 5,613 barrels per day on the Ammonia Pipeline due to unseasonably cold and wet weather in the second and fourth quarters of 2013. Also, revenues decreased $1.6 million and throughputs decreased 6,731 barrels per day on the Houston pipeline as it is being converted to new service.

Operating expenses increased $5.4 million for the year ended December 31, 2013, compared to the year ended December 31, 2012, primarily due to an increase of $18.6 million on crude oil pipelines that serve Eagle Ford Shale production in South Texas, mainly resulting from the TexStar Asset Acquisition and crude oil pipelines that were placed in service in the fourth quarter of 2012.

This increase was partially offset by:


•	a decrease of $8.0 million resulting from the reduction of the contingent consideration liability recorded in association with the TexStar Asset Acquisition; and


•	a decrease of $3.5 million due to temporary barge rental costs in 2012 needed to transport a customer’s product in conjunction with an Eagle Ford Shale project.

Depreciation and amortization expense increased $16.0 million for the year ended December 31, 2013, compared to the year ended December 31, 2012, mainly due to the TexStar Asset Acquisition in December 2012 and the completion of various projects that serve Eagle Ford Shale production.

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Storage

Throughput revenues increased $8.9 million and throughputs increased 15,657 barrels per day for the year ended December 31, 2013, compared to the year ended December 31, 2012. Revenues increased $14.3 million and throughputs increased 73,741 barrels per day at our Corpus Christi crude storage tank facility due to increased volumes of Eagle Ford Shale crude oil being shipped to Corpus Christi on our pipelines in South Texas. The TexStar Asset Acquisition in December 2012, the completion of several pipeline capital projects in 2012 and 2013 and changing our Corpus Christi crude storage tank facility from a lease-based to a throughput-based facility in the third quarter of 2012 were among the drivers for the increased volumes. These increases were partially offset by decreased throughputs of 53,768 barrels per day and decreased revenues of $5.2 million resulting from turnarounds, maintenance and operational issues in 2013 at the refineries served by our Corpus Christi, Texas City and Benicia crude oil storage tanks and our Three Rivers refined products terminals.

Storage lease revenues decreased $30.5 million for the year ended December 31, 2013, compared to the year ended December 31, 2012, primarily due to:


•	a decrease of $26.6 million at various domestic terminals, mainly as a result of reduced demand in several markets, resulting in lower throughputs, storage fees and reimbursable revenues;


•	a decrease of $7.7 million at our UK and Amsterdam terminals, mainly due to reduced demand for storage and the effect of foreign exchange rates;


•	a decrease of $7.6 million at our St. Eustatius terminal facility, mainly due to reduced demand for storage and decreased reimbursable revenue;


•	a decrease of $6.2 million at our Corpus Christi crude storage tank facility due to the change to throughput-based fees in July 2012;


•	a decrease of $3.8 million at asphalt terminals under storage agreements with Axeon, which we entered into simultaneously with the 2012 Asphalt Sale; and


•	a decrease of $2.9 million due to the sale of five refined product terminals in April 2012.

Those declines in storage lease revenues were partially offset by an increase in storage lease revenues of $19.2 million resulting from a completed unit train offloading facility at our St. James terminal and completed tank expansion projects at our St. James and St. Eustatius terminals. In addition, revenues increased $5.2 million as a result of our acquisition of a lease at the Red Fish Bay terminal in conjunction with the TexStar Asset Acquisition.

Operating expenses decreased $9.2 million for the year ended December 31, 2013, compared to the year ended December 31, 2012, primarily due to:


•	a decrease of $9.0 million associated with cancelled capital projects, mainly at our St. James and St. Eustatius terminals in 2012; and


•	a decrease of $6.3 million in reimbursable expenses, mainly for tank cleanings at our Piney Point terminal and maintenance expenses at our St. Eustatius terminal. Reimbursable expenses are charged back to our customers and are offset by reimbursable revenues.

These decreases were partially offset by an increase of $3.9 million in salaries and wages due to a collective labor agreement that became effective in mid-2012 associated with our St. Eustatius terminal, our acquisition of a lease at the Redfish Bay terminal in conjunction with the TexStar Asset Acquisition, and higher employee benefit and temporary labor costs.

Depreciation and amortization expense increased $11.7 million for the year ended December 31, 2013, compared to the year ended December 31, 2012, primarily due to completion of a dock optimization project at our Corpus Christi crude storage tank facility, unit train and tank expansion projects at our St. James terminal and a tank expansion project at our St. Eustatius terminal.

The asset impairment loss of $304.5 million for the year ended December 31, 2013 represents the write-down of the carrying value of goodwill associated with our St. Eustatius and Point Tupper terminal operations. Please refer to Note 11 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for further discussion of this goodwill impairment.

Fuels Marketing

The consolidated statements of income (loss) include the results of operations for Axeon in “Equity in earnings (loss) of joint ventures” commencing on September 28, 2012. Previously, we reported the results of operations for our Asphalt Operations in the fuels marketing segment. For the year ended December 31, 2013, this segment mainly includes refined products marketing, crude oil trading, fuel oil trading and bunkering operations.

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The following table presents pro forma financial information that removes the historical financial information for our Asphalt Operations from the segment results for the year ended December 31, 2012 in order to provide a more meaningful comparison of the segment’s results.



				Year Ended December 31, 2012
	Year Ended December 31, 2013			Actual			Asphalt Operations			Pro Forma		Change
	(Thousands of Dollars)
Product sales	$	2,527,698		$	5,086,383		$	1,315,986		$	3,770,397	$	(1,242,699	)
Cost of product sales	2,474,612			4,957,100			1,258,308			3,698,792		(1,224,180		)
Gross margin	53,086			129,283			57,678			71,605		(18,519		)
Operating expenses	53,185			148,458			89,969			58,489		(5,304		)
Depreciation and amortization expense	27			11,253			11,138			115		(88		)
Asset and goodwill impairment loss	—			266,357			266,357			—		—
Segment operating (loss) income	$	(126	)	$	(296,785	)	$	(309,786	)	$	13,001	$	(13,127	)

Sales and cost of product sales decreased $1,242.7 million and $1,224.2 million, respectively, resulting in a decrease in total gross margin of $18.5 million for the year ended December 31, 2013, compared to the year ended December 31, 2012. The decrease in total gross margin was primarily due to a positive gross margin of $12.0 million from crude oil trading in 2012, as compared to a gross margin loss of $0.3 million in 2013. In 2012, higher volumes were traded in the first part of 2012 to benefit from the price differential on two traded crude oil grades (WTI and LLS). In addition, the gross margin from bunker fuel sales decreased $9.8 million for the year ended December 31, 2013, compared to the year ended December 31, 2012, mainly at our St. Eustatius and Texas City facilities. Reduced demand for bunker fuels and increased competition in the Caribbean and the U.S. Gulf Coast has negatively impacted our sales prices and resulted in lower gross margins as compared to the same period last year. These decreases were partially offset by an increase of $3.7 million in the gross margin from fuel oil trading attributable to lower costs that outweighed falling sales prices compared to the same period last year.

Operating expenses decreased $5.3 million for the year ended December 31, 2013, compared to the year ended December 31, 2012, mainly due to a decrease in operating expenses from our bunker fuel operations as we exited certain U.S. markets.

Consolidation and Intersegment Eliminations

Revenue and operating expense eliminations primarily relate to storage and transportation fees charged to the fuels marketing segment by the storage and pipeline segments. Revenue and operating expense eliminations changed by $27.1 million and $27.3 million, respectively, for the year ended December 31, 2013, compared to the year ended December 31, 2012, mainly due to the 2012 Asphalt Sale. Cost of product sales eliminations represent expenses charged to the fuels marketing segment for costs associated with inventory that are expensed once the inventory is sold.

General

General and administrative expenses decreased $13.7 million for the year ended December 31, 2013, compared to the year ended December 31, 2012, primarily due to the early termination of a lease for our previous corporate office and expenses that were reimbursed by Axeon for corporate support services under a services agreement between Axeon and NuStar GP, LLC. In addition, general and administrative expenses in the second quarter of 2012 included costs that resulted from a Canadian income tax audit.

Other depreciation and amortization expense increased $2.7 million for the year ended December 31, 2013, compared to the year ended December 31, 2012, mainly due to the completion of our corporate office in the fourth quarter of 2012.

The other asset impairment loss of $3.3 million for the year ended December 31, 2012 represents the write-down of the carrying value of certain corporate assets we sold in 2013.

The gain on legal settlement of $28.7 million for the year ended December 31, 2012 represents the settlement of a legal matter in the second quarter of 2012.

Equity in loss of joint ventures increased $30.6 million for the year ended December 31, 2013, compared to the year ended December 31, 2012, primarily due to a $49.6 million loss from our investment in Axeon in 2013, which continued to suffer from weak asphalt margins.

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Interest expense, net increased $36.6 million for the year ended December 31, 2013, compared to the year ended December 31, 2012, mainly due to the issuance of the $402.5 million of 7.625% fixed-to-floating rate subordinated notes in January 2013.

Interest income from related party increased $4.9 million for the year ended December 31, 2013, compared to the year ended December 31, 2012, as a result of a full year of borrowings by Axeon under the NuStar JV Facility that we entered into with Axeon in connection with the 2012 Asphalt Sale on September 28, 2012. Please refer to Note 19 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for additional information on our agreements with Axeon.

Other income (expense), net changed by $32.0 million for the year ended December 31, 2013, compared to the year ended December 31, 2012, mainly due to a loss of $23.8 million associated with the 2012 Asphalt Sale and changes in foreign exchange rates related to our foreign subsidiaries.

Income tax expense decreased $11.7 million for the year ended December 31, 2013, compared to the year ended December 31, 2012, mainly due to tax expense of $10.1 million related to the $28.7 million gain on legal settlement recognized in the second quarter of 2012.

For the year ended December 31, 2013, we recorded a loss from discontinued operations of $99.2 million, compared to a loss from discontinued operations of $61.2 million for the year ended December 31, 2012. For the year ended December 31, 2013, the loss from discontinued operations includes asset impairment charges of $102.5 million associated with certain storage terminals that were classified as “Assets held for sale” on the consolidated balance sheet as of December 31, 2013. Please refer to Note 5 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for further discussion of these asset impairment charges. This loss was partially offset by a gain of $9.3 million related to the San Antonio Refinery Sale.

For the year ended December 31, 2012, the loss from discontinued operations includes losses of $49.1 million from the San Antonio Refinery, mainly due to hedge losses and falling sales prices coupled with high weighted-average costs, which resulted in an overall negative gross margin.

TRENDS AND OUTLOOK

Pipeline Segment

We expect the first quarter of 2015 to continue to benefit from expansion projects we completed in the first half of 2014, which increased our system’s overall capacity. We expect earnings for the pipeline segment to be higher than the first quarter of 2014 and comparable to the fourth quarter of 2014.

We expect our full-year earnings for 2015 to exceed 2014 mainly due to the planned completion in the first half of 2015 of pipeline expansion projects, as well as reduced turnaround activity at our customers’ refineries and the July 1, 2015 tariff increase on our pipelines subject to regulation by the Federal Energy Regulatory Commission. Although the drop in crude prices in late 2014 and early 2015 has not reduced the demand for our transportation services so far, continued weak crude oil prices could have a negative impact on demand in the future, which could cause our earnings to decline.

Storage Segment

We expect storage segment earnings for the first quarter of 2015 and the full-year of 2015 to exceed the comparable periods in 2014 mainly due to our January 2015 purchase of the remaining 50% interest in the former joint venture terminal in Linden, New Jersey and higher throughputs at our North Beach terminal as a result of the increase in Eagle Ford Shale crude oil being shipped to Corpus Christi.

Fuels Marketing Segment

We expect first quarter of 2015 results for our fuels marketing segment to be comparable to the first quarter of 2014, although higher than the fourth quarter of 2014. We expect the full-year 2015 results in this segment to be comparable to 2014 results. However, earnings in this segment, as in any margin-based business, are subject to many factors that can increase or reduce margins, which may cause the segment’s actual results to vary significantly from our forecast.

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, including the price of crude oil, the state of the economy, changes to refinery maintenance schedules, demand for crude oil, refined products and 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

Primary Cash Requirements. Our primary cash requirements are for distributions to our partners, working capital (including inventory purchases), debt service, capital expenditures, including reliability capital, a financing agreement with Axeon, acquisitions and operating expenses.

Sources of Funds. Each year, we work to fund our annual total operating expenses, interest expense, 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 those requirements, we utilize other sources of cash flow, which in the past have 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. Additionally, we typically fund 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 that our cash flow from operations is less than our distribution and reliability capital requirements, we may maintain our distribution level because we can utilize other sources of Available Cash, as provided in our partnership agreement, including borrowing under our revolving credit agreement and the 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 the distribution.

Cash Requirements and Sources. For the year ended December 31, 2012, we did not generate sufficient cash from operations to exceed our distribution and reliability capital requirements. The shortfall in cash from operations resulted primarily from our fuels marketing segment. Poor margins in the segment drove our earnings down sharply, thus reducing our net cash provided by operating activities below our distribution and reliability capital requirements. In 2012, we embarked on a strategic redirection (i) to focus on our core, fee-based segments, pipeline and storage and (ii) to reduce earnings volatility and working capital requirements stemming from the fuels marketing segment.

For the years ended December 31, 2014 and 2013, our cash flow from operations exceeded our distributions to our partners and our reliability capital expenditures, mainly due to our strategic redirection discussed above. For 2015, we currently expect to continue to produce cash from operations in excess of our distribution and reliability capital expenditures.

Cash Flows for the Years Ended December 31, 2014, 2013 and 2012

The following table summarizes our cash flows from operating, investing and financing activities:



	Year Ended December 31,
	2014			2013			2012
	(Thousands of Dollars)
Net cash provided by (used in):
Operating activities	$	518,523		$	485,219		$	299,203
Investing activities	(340,231		)	(310,961		)	(345,800		)
Financing activities	(188,185		)	(149,350		)	110,669
Effect of foreign exchange rate changes on cash	(2,938		)	(7,767		)	2,033
Net (decrease) increase in cash and cash equivalents	$	(12,831	)	$	17,141		$	66,105

Net cash provided by operating activities for the year ended December 31, 2014 was $518.5 million, compared to $485.2 million for the year ended December 31, 2013, or an increase of $33.3 million. For the year ended December 31, 2014, we reported net income of $210.4 million, compared to a net loss of $284.7 million for the year ended December 31, 2013, which included $407.0 million of non-cash goodwill and asset impairment charges. We recorded equity in earnings of joint ventures of $4.8 million for the year ended December 31, 2014, compared to a loss in equity of joint ventures of $40.0 million for the year ended December 31, 2013, primarily due to losses from our investment in Axeon in 2013. Changes in working capital provided cash flow of $82.4 million for the year ended December 31, 2014, compared to $112.8 million for the year ended

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December 31, 2013. Please refer to the Working Capital Requirements section below for a discussion of the changes in working capital.

For the year ended December 31, 2014, 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 $28.6 million of reliability capital expenditures. The proceeds from debt borrowings, net of repayments, combined with net cash provided by operating activities and proceeds from the sales of assets, were used to fund strategic capital expenditures primarily related to our pipeline and storage segments and advances to Axeon under the NuStar JV Facility.

Net cash provided by operating activities for the year ended December 31, 2013 was $485.2 million, compared to $299.2 million for the year ended December 31, 2012, or an increase of $186.0 million. For the year ended December 31, 2013, we reported a net loss of $284.7 million, which included $407.0 million of non-cash goodwill and asset impairment charges, while the net loss for the year ended December 31, 2012 of $227.2 million included $271.8 million of non-cash asset impairment charges. Equity in loss of joint ventures increased to $40.0 million for the year ended December 31, 2013, compared to $9.4 million for the year ended December 31, 2012, mainly due to losses from our investment in Axeon. Changes in working capital provided cash flow of $112.8 million for the year ended December 31, 2013, compared to $90.2 million for the year ended December 31, 2012.

For the year ended December 31, 2013, net cash provided by operating activities exceeded our distribution requirements and reliability capital expenditures. Proceeds from the San Antonio Refinery Sale and proceeds from long-term debt borrowings, net of repayments, combined with net cash provided by operating activities, were used to fund our strategic capital expenditures and advances to Axeon under the NuStar JV Facility.

For the year ended December 31, 2012, net cash provided by operating activities, proceeds from long-term debt borrowings, net of repayments, proceeds from our issuance of common units and proceeds from the 2012 Asphalt Sale were used to fund our distributions to unitholders and our general partner, the TexStar Asset Acquisition and strategic and reliability capital expenditures.

Revolving Credit Agreement

On October 29, 2014, NuStar Logistics amended and restated its $1.5 billion five-year revolving credit agreement (Revolving Credit Agreement), which matures on October 29, 2019. The Revolving Credit Agreement includes an option allowing NuStar Logistics to request an aggregate increase in the commitments from the lenders of up to $250.0 million (after which increase the aggregate commitment from all lenders shall not exceed $1.75 billion). The Revolving Credit Agreement also 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. NuPOP will be released from its guarantee of the Revolving Credit Agreement when it no longer guarantees indebtedness of NuStar Energy or its subsidiaries in an aggregate principal amount exceeding $200.0 million.

The Revolving Credit Agreement contains customary restrictive covenants, such as limitations on indebtedness, liens, mergers, asset transfers and certain investing activities. In addition, the Revolving Credit Agreement requires us to maintain, as of the end of each rolling 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. If we consummate an acquisition for an aggregate net consideration of at least $50.0 million, the maximum consolidated debt coverage ratio will increase to 5.50-to-1.00 for two rolling periods. The Revolving Credit Agreement permits unlimited investments in joint ventures and unconsolidated subsidiaries, provided that no default exists and we would be in compliance with the consolidated debt coverage ratio, but limits the amount of cash distributions for such joint ventures and unconsolidated subsidiaries included in the calculation of the consolidated debt coverage ratio to 20% of consolidated EBITDA. 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, 2014, our consolidated debt coverage ratio was 4.0x, and we had $842.3 million available for borrowing.

Letters of credit issued under our Revolving Credit Agreement totaled $56.2 million as of December 31, 2014. Letters of credit are limited to $750.0 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 restrict the amount we can borrow under the Revolving Credit Agreement.

Please refer to Note 14 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for a more detailed discussion of our long-term debt agreements.

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Short-term Lines of Credit

In 2014, we entered into two short-term line of credit agreements with an aggregate uncommitted borrowing capacity of up to $80.0 million. These agreements allow us to better manage the 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 the borrowing. We had $77.0 million outstanding under these short-term lines of credit as of December 31, 2014.

Gulf Opportunity Zone Revenue Bonds

In 2008, 2010 and 2011, the Parish of St. James, where our St. James, Louisiana, terminal is located, issued Revenue Bonds (NuStar Logistics, L.P. Project) Series 2008, Series 2010, Series 2010A, Series 2010B and Series 2011 associated with our St. James terminal expansion pursuant to the Gulf Opportunity Zone Act of 2005 (collectively, the Gulf Opportunity Zone Revenue 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 issuance, 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 expansion. The amount remaining in trust is included in “Other long-term assets, net,” and the amount of bonds issued is included in “Long-term debt, less current portion” in our consolidated balance sheets.

NuStar Logistics is solely obligated to service the principal and interest payments associated with the Gulf Opportunity Zone Revenue Bonds. Letters of credit were issued 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. 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 Gulf Opportunity Zone Revenue Bonds outstanding as of December 31, 2014:



Date Issued	Maturity Date	Amount Outstanding		Amount of Letter of Credit		Amount Received from Trustee		Amount Remaining in Trust		Average Annual Interest Rate
		(Thousands of Dollars)
June 26, 2008	June 1, 2038	$	55,440	$	56,169	$	55,440	$	—	0.1	%
July 15, 2010	July 1, 2040	100,000		101,315		100,000		—		0.1	%
October 7, 2010	October 1, 2040	50,000		50,658		35,760		14,240		0.1	%
December 29, 2010	December 1, 2040	85,000		86,118		27,689		57,311		0.1	%
August 29, 2011	August 1, 2041	75,000		75,986		75,000		—		0.1	%
	Total	$	365,440	$	370,246	$	293,889	$	71,551

Issuance of Debt

On August 19, 2013, NuStar Logistics issued $300.0 million of 6.75% senior notes due February 1, 2021 (the 6.75% Senior Notes). We received net proceeds of approximately $296.0 million, which we used for general partnership purposes, including repayment of outstanding borrowings under our Revolving Credit Agreement.

On January 22, 2013, NuStar Logistics issued $402.5 million of 7.625% fixed-to-floating rate subordinated notes due January 15, 2043 (the Subordinated Notes), including the underwriters’ option to purchase up to an additional $52.5 million principal amount of the notes, which was exercised in full. We received net proceeds of approximately $390.9 million, which we used for general partnership purposes, including repayment of outstanding borrowings under our Revolving Credit Agreement. The Subordinated Notes bear 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 will 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.

On February 2, 2012, NuStar Logistics issued $250.0 million of 4.75% senior notes due February 1, 2022. The net proceeds of $247.4 million were used to repay the outstanding principal amount of NuPOP’s $250.0 million 7.75% senior notes due February 15, 2012.

Please refer to Note 14 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for a more detailed discussion of our debt agreements.

Issuance of Common Units

On September 10, 2012, we issued 7,130,000 common units representing limited partner interests at a price of $48.94 per unit. We used the net proceeds from this offering of $343.9 million, including a contribution of $7.1 million from our general partner

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to maintain its 2% general partner interest, for general partnership purposes, including repayments of outstanding borrowings under our Revolving Credit Agreement and working capital purposes.

If the capital markets become more volatile, our access to the capital markets may be limited, or we could face increased costs. In addition, it is possible that our ability to access the capital markets may be limited at a time when we would like or need access, which could have an impact on our ability to refinance maturing debt and/or react to changing economic and business conditions.

Capital Requirements

Our operations require significant investments to maintain, upgrade or enhance the operating capacity of our existing assets. Our capital expenditures consist of:


•	reliability capital expenditures, such as those required to maintain equipment reliability and safety; and


•	strategic capital expenditures, such as those to expand and upgrade pipeline capacity or terminal facilities and to construct new pipelines, terminals and storage tanks. In addition, strategic capital expenditures may include acquisitions of pipelines, terminals or storage tank assets, as well as certain capital expenditures related to support functions.

During the year ended December 31, 2014, our reliability capital expenditures totaled $28.6 million, primarily related to maintenance upgrade projects at our terminals. Strategic capital expenditures for the year ended December 31, 2014 totaled $328.3 million and were primarily related to projects associated with Eagle Ford Shale production in South Texas and the reactivation and conversion of our 200-mile pipeline between Mont Belvieu and Corpus Christi, Texas.

During the year ended December 31, 2013, our reliability capital expenditures totaled $41.3 million, primarily related to maintenance upgrade projects at our terminals. Strategic capital expenditures for the year ended December 31, 2013 totaled $302.0 million and were primarily related to projects in the Eagle Ford Shale region in South Texas and projects at our St. James, Louisiana terminal.

For 2015, we expect to incur approximately $440.0 million to $470.0 million of capital expenditures, including approximately $40.0 million to $50.0 million for reliability capital expenditures and $400.0 million to $420.0 million for strategic capital expenditures, including acquisitions. We continue to evaluate our capital budget and make changes as economic conditions warrant, and our actual capital expenditures for 2015 may increase or decrease from the budgeted amounts. We believe cash generated from operations, combined with other sources of liquidity previously described, will be sufficient to fund our capital expenditures in 2015, and our internal growth projects can be accelerated or scaled back depending on the condition of the capital markets.

Working Capital Requirements

Our fuels marketing operations require us to make investments in working capital. Those working capital requirements may vary with fluctuations in the commodity prices and with the seasonality of demand for the products we market. This seasonality in demand affects our accounts receivable and accounts payable balances, which vary depending on timing of payments.

Inventories decreased $82.1 million during the year ended December 31, 2014, primarily due to a steep decline in crude oil market price during the fourth quarter of 2014. We also continued a bunker fuel supply strategy that further reduced the inventory carried in our bunker fuel operations and we reduced inventories associated with our heavy fuel oil trading operations. During the year ended December 31, 2014, accounts receivable decreased $72.3 million and accounts payable decreased $153.7 million mainly due to the bunker fuel supply strategy and less crude oil trading activity. In addition, the termination of the crude oil supply agreement with Axeon on January 1, 2014 caused a decrease in both accounts payable and the receivable from related parties.

Within working capital, inventories decreased $32.0 million during the year ended December 31, 2013, primarily as a result of a new bunker fuel supply agreement that reduced the inventory carried in our St. Eustatius bunker fuel operations. In addition, accounts receivable decreased $107.2 million and accounts payable decreased $96.3 million during the year ended December 31, 2013, primarily due to less crude oil trading and bunker fuel operations activity in 2013 and the San Antonio Refinery Sale. Accounts payable also decreased due to timing of payments for crude oil purchases related to Axeon, which corresponds with the decrease in the receivable from related parties of $58.7 million during the year ended December 31, 2013.

Axeon Term Loan and Credit Support

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third-party asset-based revolving credit facility. Axeon failed to make a scheduled repayment by December 31, 2014, which will increase the interest rate until Axeon makes the repayment. While the Axeon Term Loan does not provide for any other scheduled payments, Axeon is required to use all of its excess cash, as defined in the Axeon Term Loan, to repay the Axeon Term Loan. The Axeon Term Loan must be repaid in full on September 28, 2019. The Axeon Term Loan bears interest based on either an alternative base rate or a LIBOR-based rate. We recognize interest income over the term of the loan in “Interest expense, net” on the consolidated statements of income. As of December 31, 2014, the interest rate was 3.1%.

We will continue to provide credit support, such as guarantees, letters of credit and cash collateral, as applicable, of up to $150.0 million. Our obligation to provide credit support will be reduced by a minimum of $25.0 million beginning February 2016 and will terminate in full no later than September 28, 2019. As of December 31, 2014, we provided guarantees for Axeon with an aggregate maximum potential exposure of $25.3 million, plus two guarantees to suppliers that do not specify a maximum amount, but for which we believe any amounts due would be minimal. As of December 31, 2014, we have also provided $50.1 million in letters of credit on behalf of Axeon. In the event we are obligated to perform under any of these guarantees or letters of credit, the amount paid by us will be treated as additional borrowings under the Axeon Term Loan.

Distributions

NuStar Energy’s partnership agreement, as amended, determines the amount and priority of cash distributions that our common 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 Common Units.”

The following table reflects the allocation of total cash distributions to the general and limited partners applicable to the period in which the distributions were earned:



	Year Ended December 31,
	2014		2013		2012
	(Thousands of Dollars, Except Per Unit Data)
General partner interest	$	7,844	$	7,844	$	7,486
General partner incentive distribution	43,220		43,220		41,242
Total general partner distribution	51,064		51,064		48,728
Limited partners’ distribution	341,140		341,140		325,526
Total cash distributions	$	392,204	$	392,204	$	374,254

Cash distributions per unit applicable to limited partners	$	4.380	$	4.380	$	4.380

Actual distribution payments 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:



Quarter Ended	Cash Distributions Per Unit		Total Cash Distributions (Thousands of Dollars)		Record Date	Payment Date
December 31, 2014 (a)	$	1.095	$	98,051	February 9, 2015	February 13, 2015
September 30, 2014	$	1.095	$	98,051	November 10, 2014	November 14, 2014
June 30, 2014	$	1.095	$	98,051	August 6, 2014	August 11, 2014
March 31, 2014	$	1.095	$	98,051	May 7, 2014	May 12, 2014


(a)	The distribution was announced on January 30, 2015.

Debt Obligations

As of December 31, 2014, we were a party to the following debt agreements:


•	the Revolving Credit Agreement due October 29, 2019, with a balance of $601.5 million as of December 31, 2014;


•	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

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million; 4.75% senior notes due February 1, 2022 with a face value of $250.0 million; and 7.625% subordinated notes due January 15, 2043 with a face value of $402.5 million;


•	$365.4 million Gulf Opportunity Zone Revenue Bonds due from 2038 to 2041; and


•	$80.0 million line of credit agreements with $77.0 million outstanding as of December 31, 2014.

In 2013, we repaid NuStar Logistics’ $229.9 million of 6.05% senior notes due March 15, 2013, NuPOP’s $250.0 million of 5.875% senior notes due June 1, 2013, and NuStar Terminals Limited’s £21 million amended and restated term loan, which matured on December 10, 2013, with borrowings under the Revolving Credit Agreement.

Management believes that, as of December 31, 2014, we are in compliance with all ratios and covenants of the Revolving Credit Agreement. Our other debt obligations do not contain any financial covenants that differ from those contained in the Revolving Credit Agreement. However, a default under any of our debt instruments would be considered an event of default under all of our debt instruments. Please refer to Note 14 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for a more detailed discussion of our debt agreements.

Credit Ratings

The following table reflects the current outlook and ratings that have been assigned to our debt:



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

Ratings	BB+	Ba1	BB
Outlook	Stable	Stable	Stable

The interest rate payable on the senior notes and the Revolving Credit Agreement is subject to adjustment if our debt rating is downgraded (or upgraded) by certain credit rating agencies. We may also be required to provide additional credit support for certain contracts, although as of December 31, 2014, we have not been required to provide any additional credit support.

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, 2014:



	Payments Due by Period
	2015		2016		2017		2018		2019		Thereafter		Total
	(Thousands of Dollars)
Long-term debt maturities	$	—	$	—	$	—	$	350,000	$	601,496	$	1,767,940	$	2,719,436
Interest payments	129,861		129,861		129,861		121,794		106,213		1,092,595		1,710,185
Operating leases	30,179		26,135		21,885		19,536		13,297		66,635		177,667
Purchase obligations	6,294		3,880		694		216		—		—		11,084

The interest payments calculated for our variable-rate debt are based on the outstanding borrowings and the interest rate as of December 31, 2014. The interest payments on our fixed-rate debt are based on the stated interest rates, the outstanding balances as of December 31, 2014 and interest payment dates.

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

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.

In November 2013, we came to a mutual agreement with PDVSA-Petróleo S.A. (PDVSA) to terminate that certain Crude

Oil Sales Agreement dated effective as of March 1, 2008. The termination was effective January 1, 2014, and in connection therewith, we also terminated our crude oil supply agreement with Axeon effective January 1, 2014.

Environmental, Health and Safety

We are subject to extensive federal, state and local environmental and safety laws and regulations, including those relating to the discharge of materials into the environment, waste management, pollution prevention measures, pipeline integrity and

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operator qualifications, among others. Because more stringent environmental and safety laws and regulations are continuously being enacted or proposed, the level of future expenditures required for environmental, health and safety matters is expected to increase.

The balance of and changes in our accruals for environmental matters as of and for the years ended December 31, 2014 and 2013 are included in Note 15 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplemental 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 16 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplemental Data.”

RELATED PARTY TRANSACTIONS

The following table summarizes information pertaining to related party transactions:



	Year Ended December 31,
	2014		2013		2012
	(Thousands of Dollars)
Revenues	$	929	$	14,897	$	1,990
Operating expenses	$	125,736	$	122,677	$	133,654
General and administrative expenses	$	66,910	$	58,602	$	62,490
Interest income	$	1,055	$	6,113	$	1,219
Revenues included in discontinued operations, net of tax	$	528	$	3,720	$	3,390
Expenses included in discontinued operations, net of tax	$	1,680	$	6,051	$	14,328

NuStar GP, LLC

Our operations are managed by NuStar GP, LLC, the general partner of our general partner. Under the services agreement described below, employees of NuStar GP, LLC provide services to both NuStar Energy and NuStar GP Holdings; therefore, we reimburse NuStar GP, LLC for all costs related to its employees, other than costs associated with NuStar GP Holdings.

NuStar Energy and NuStar GP, LLC entered into a services agreement effective January 1, 2008 (the GP Services Agreement). On July 19, 2006, we entered into a non-compete agreement with NuStar GP Holdings, Riverwalk Logistics, L.P., and NuStar GP, LLC effective on December 22, 2006 (the Non-Compete Agreement). Please refer to Note 19 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for a more detailed discussion of agreements with NuStar GP Holdings.

We had a payable to NuStar GP, LLC of $15.1 million and $8.3 million as of December 31, 2014 and 2013, respectively, with both amounts representing payroll, employee benefit plan expenses and unit-based compensation. We also had a long-term payable to NuStar GP, LLC as of December 31, 2014 and 2013 of $33.5 million and $41.1 million, respectively, for amounts payable for retiree medical benefits and other post-employment benefits.

Axeon

As a result of the 2014 Asphalt Sale, we ceased reporting transactions between us and Axeon as related party transactions in

our consolidated financial statements on February 26, 2014.

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 Supplemental 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

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equipment over periods ranging from 10 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. Our qualitative annual 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 perform an impairment test for that reporting unit.

We assess goodwill, and, if necessary, measure impairment for each reporting unit to which goodwill has been allocated, consisting of the following:


•	crude oil pipelines;


•	refined product pipelines;


•	refined product terminals, excluding our St. Eustatius and Point Tupper facilities; and


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

We recognize an impairment of goodwill if the estimated fair value of goodwill exceeds its carrying value. In order to estimate the fair value of goodwill, management must make certain estimates and assumptions that affect the total fair value of the reporting unit including, among other things, an assessment of market conditions, projected cash flows, discount rates and growth rates. Management’s estimates of projected cash flows related to the reporting unit include, but are not limited to, future earnings of the reporting unit, assumptions about the use or disposition of the asset, estimated remaining life of the asset, and future expenditures necessary to maintain the asset’s existing service potential.

We calculate the estimated fair value of each of our reporting units using a weighted-average of values calculated using an income approach and a market approach. The income approach involves estimating the fair value of each reporting unit by discounting its estimated future cash flows using a discount rate, consistent with a market participant’s assumption. The market 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, 2014 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 commodity price risk and interest rate 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.

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 over a 20-year time period using currently available technology and applying current regulations, as well as our own internal environmental policies. The

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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, including tax contingencies, 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. From time to time, we have also utilized forward-starting interest rate swap agreements to lock in the rate on the interest payments related to forecasted debt issuances and fixed-to-floating interest rate swap agreements to manage a portion of the exposure to changing interest rates by converting certain fixed-rate debt to variable-rate debt. Borrowings under the Revolving Credit Agreement, the Gulf Opportunity Zone Revenue Bonds and the short-term lines of credit expose us to increases in applicable interest rates.

We had no forward-starting or fixed-to-floating interest rate swap agreements outstanding as of December 31, 2014 and 2013. Please refer to Note 2 and Note 18 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplemental 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, 2014
	Expected Maturity Dates
	2015		2016		2017		2018			2019			There- after			Total			Fair Value
	(Thousands of Dollars, Except Interest Rates)
Long-term Debt:
Fixed rate	$	—	$	—	$	—	$	350,000		$	—		$	1,402,500		$	1,752,500		$	1,796,536
Weighted-average interest rate	—		—		—		8.2		%	—			6.0		%	6.4		%
Variable rate	$	—	$	—	$	—	$	—		$	601,496		$	365,440		$	966,936		$	967,706
Weighted-average interest rate	—		—		—		—			2.0		%	0.1		%	1.2		%



	December 31, 2013
	Expected Maturity Dates
	2014		2015		2016		2017			2018			There- after			Total			Fair Value
	(Thousands of Dollars, Except Interest Rates)
Long-term Debt:
Fixed rate	$	—	$	—	$	—	$	—		$	350,000		$	1,402,500		$	1,752,500		$	1,767,759
Weighted-average interest rate	—		—		—		—			8.2		%	6.0		%	6.4		%
Variable rate	$	—	$	—	$	—	$	503,036		$	—		$	365,440		$	868,476		$	868,975
Weighted-average interest rate	—		—		—		2.2		%	—			0.1		%	1.3		%

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 Supplemental Data” for further information.

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, which was 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 18 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplemental Data” for the volume and related fair value of all commodity contracts.



	December 31, 2014
	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)	162	$	59.82	N/A		$	(1,060	)
Futures – short:
(crude oil)	169	N/A		$	59.56	$	1,064
Swaps – long:
(crude oil and refined products)	251	$	48.86	N/A		$	(1,341	)
Swaps – short:
(crude oil and refined products)	1,005	N/A		$	55.66	$	11,861

Economic Hedges and Other Derivatives:
Futures – long:
(refined products)	24	$	75.91	N/A		$	26
Swaps – long:
(refined products)	106	$	44.97	N/A		$	(120	)
Swaps – short:
(crude oil and refined products)	50	N/A		$	54.98	$	553
Forward purchase contracts:
(crude oil)	812	$	65.81	N/A		$	(11,624	)
Forward sales contracts:
(crude oil)	812	N/A		$	65.95	$	12,109

Total fair value of open positions exposed to commodity price risk						$	11,468

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	December 31, 2013
	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)	7	$	128.38	N/A		$	3
Futures – short:
(refined products)	40	N/A		$	124.50	$	(170	)

Economic Hedges and Other Derivatives:
Futures – long:
(crude oil and refined products)	245	$	95.67	N/A		$	682
Futures – short:
(crude oil and refined products)	179	N/A		$	115.09	$	(200	)
Swaps – long:
(refined products)	95	$	92.39	N/A		$	(76	)
Swaps – short:
(refined products)	1,377	N/A		$	91.18	$	(522	)
Forward purchase contracts:
(crude oil)	1,015	$	97.79	N/A		$	3,171
Forward sales contracts:
(crude oil)	1,015	N/A		$	98.39	$	(2,561	)

Total fair value of open positions exposed to commodity price risk						$	327

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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, 2014. In its evaluation, management used the criteria set forth by the Committee of Sponsoring Organization of the Treadway Commission (COSO) in Internal Control-Integrated Framework (2013). Based on this assessment, management believes that, as of December 31, 2014, our internal control over financial reporting was effective based on those criteria.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.

The effectiveness of internal control over financial reporting as of December 31, 2014 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 58.

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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.:

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, 2014 and 2013, and the related consolidated statements of income (loss), comprehensive income (loss), partners’ equity, and cash flows for each of the years in the three-year period ended December 31, 2014. 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 conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of NuStar Energy L.P. and subsidiaries as of December 31, 2014 and 2013, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2014, 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), NuStar Energy L.P. and subsidiaries’ internal control over financial reporting as of December 31, 2014, based on criteria established in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated February 26, 2015 expressed an unqualified opinion on the effectiveness of the Partnership’s internal control over financial reporting.

/s/ KPMG LLP

San Antonio, Texas

February 26, 2015

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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.:

We have audited NuStar Energy L.P. (a Delaware limited partnership) and subsidiaries’ (the Partnership’s) internal control over financial reporting as of December 31, 2014, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). 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 conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). 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 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.

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.

In our opinion, NuStar Energy L.P. and subsidiaries maintained, in all material respects, effective internal control over financial reporting as of December 31, 2014, based on criteria established in Internal Control – Integrated Framework (2013) issued by COSO.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of NuStar Energy L.P. and subsidiaries as of December 31, 2014 and 2013, and the related consolidated statements of income (loss), comprehensive income (loss), partners’ equity, and cash flows for each of the years in the three-year period ended December 31, 2014, and our report dated February 26, 2015 expressed an unqualified opinion on those consolidated financial statements.

/s/ KPMG LLP

San Antonio, Texas

February 26, 2015

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NUSTAR ENERGY L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Thousands of Dollars, Except Unit Data)



	December 31,
	2014			2013
Assets
Current assets:
Cash and cash equivalents	$	87,912		$	100,743
Accounts receivable, net of allowance for doubtful accounts of $7,808 and $1,224 as of December 31, 2014 and 2013, respectively	208,314			281,310
Receivable from related parties	164			51,084
Inventories	55,713			138,147
Other current assets	35,944			40,278
Assets held for sale	1,100			21,987
Total current assets	389,147			633,549
Property, plant and equipment, at cost	4,815,396			4,500,837
Accumulated depreciation and amortization	(1,354,664		)	(1,190,184		)
Property, plant and equipment, net	3,460,732			3,310,653
Intangible assets, net	58,670			71,249
Goodwill	617,429			617,429
Investment in joint ventures	74,223			68,735
Deferred income tax asset	4,429			5,769
Note receivable from related party, net	—			165,440
Other long-term assets, net	314,166			159,362
Total assets	$	4,918,796		$	5,032,186
Liabilities and Partners’ Equity
Current liabilities:
Accounts payable	$	162,056		$	298,751
Payable to related party	15,128			8,325
Short-term debt	77,000			—
Accrued interest payable	33,345			33,113
Accrued liabilities	61,025			38,632
Taxes other than income tax	14,121			9,745
Income tax payable	2,517			4,006
Total current liabilities	365,192			392,572
Long-term debt	2,749,452			2,655,553
Long-term payable to related party	33,537			41,139
Deferred income tax liability	27,308			27,350
Other long-term liabilities	27,097			11,778
Commitments and contingencies (Note 16)
Partners’ equity:
Limited partners (77,886,078 common units outstanding as of December 31, 2014 and 2013)	1,744,810			1,921,726
General partner	39,312			43,804
Accumulated other comprehensive loss	(67,912		)	(63,394		)
Total NuStar Energy L.P. partners’ equity	1,716,210			1,902,136
Noncontrolling interest	—			1,658
Total partners’ equity	1,716,210			1,903,794
Total liabilities and partners’ equity	$	4,918,796		$	5,032,186

See Notes to Consolidated Financial Statements.

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NUSTAR ENERGY L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME (LOSS)

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



	Year Ended December 31,
	2014			2013			2012
Revenues:
Service revenues	$	1,026,446		$	938,138		$	870,157
Product sales	2,048,672			2,525,594			5,075,579
Total revenues	3,075,118			3,463,732			5,945,736
Costs and expenses:
Cost of product sales	1,967,528			2,453,997			4,930,174
Operating expenses:
Third parties	347,189			331,719			392,491
Related party	125,736			122,677			133,654
Total operating expenses	472,925			454,396			526,145
General and administrative expenses:
Third parties	29,146			32,484			42,266
Related party	66,910			58,602			62,490
Total general and administrative expenses	96,056			91,086			104,756
Depreciation and amortization expense	191,708			178,921			159,789
Goodwill impairment loss	—			304,453			22,132
Asset impairment loss	—			—			249,646
Gain on legal settlement	—			—			(28,738		)
Total costs and expenses	2,728,217			3,482,853			5,963,904
Operating income (loss)	346,901			(19,121		)	(18,168		)
Equity in earnings (loss) of joint ventures	4,796			(39,970		)	(9,378		)
Interest expense, net	(132,281		)	(127,119		)	(90,535		)
Interest income from related party	1,055			6,113			1,219
Other income (expense), net	4,499			7,341			(24,689		)
Income (loss) from continuing operations before income tax expense	224,970			(172,756		)	(141,551		)
Income tax expense	10,801			12,753			24,450
Income (loss) from continuing operations	214,169			(185,509		)	(166,001		)
Loss from discontinued operations, net of tax	(3,791		)	(99,162		)	(61,236		)
Net income (loss)	210,378			(284,671		)	(227,237		)
Less loss attributable to noncontrolling interest	(395		)	(10,901		)	(621		)
Net income (loss) attributable to NuStar Energy L.P.	$	210,773		$	(273,770	)	$	(226,616	)
Net income (loss) per unit applicable to limited partners:
Continuing operations	$	2.14		$	(2.89	)	$	(2.79	)
Discontinued operations	(0.04		)	(1.11		)	(0.82		)
Total (Note 23)	$	2.10		$	(4.00	)	$	(3.61	)
Weighted-average limited partner units outstanding	77,886,078			77,886,078			72,957,417

See Notes to Consolidated Financial Statements.

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NUSTAR ENERGY L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(Thousands of Dollars)



	Year Ended December 31,
	2014			2013			2012
Net income (loss)	$	210,378		$	(284,671	)	$	(227,237	)

Other comprehensive loss:
Foreign currency translation adjustment, net of income tax expense of $0, $0 and $414	(15,614		)	(19,364		)	10,677
Net unrealized gain (loss) on cash flow hedges	—			7,213			(94,269		)
Net loss reclassified into income on cash flow hedges	10,663			7,570			53,232
Total other comprehensive loss	(4,951		)	(4,581		)	(30,360		)

Comprehensive income (loss)	205,427			(289,252		)	(257,597		)
Less comprehensive (loss) income attributable to noncontrolling interest	(828		)	(10,953		)	477
Comprehensive income (loss) attributable to NuStar Energy L.P.	$	206,255		$	(278,299	)	$	(258,074	)

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,
	2014			2013			2012
Cash Flows from Operating Activities:
Net income (loss)	$	210,378		$	(284,671	)	$	(227,237	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization expense	191,708			184,363			170,651
Amortization of debt related items	8,969			4,329			(7,016		)
(Gain) loss on sale or disposition of assets	(3,853		)	(7,829		)	26,902
Asset and goodwill impairment loss	4,201			406,982			271,778
Gain on legal settlement	—			—			(28,738		)
Deferred income tax expense (benefit)	3,467			(6,739		)	1,542
Equity in (earnings) loss of joint ventures	(4,796		)	39,970			9,378
Distributions of equity in earnings of joint ventures	7,587			7,956			6,364
Changes in current assets and current liabilities (Note 24)	82,418			112,776			90,247
Other, net	18,444			28,082			(14,668		)
Net cash provided by operating activities	518,523			485,219			299,203
Cash Flows from Investing Activities:
Capital expenditures	(356,965		)	(343,320		)	(410,595		)
Change in accounts payable related to capital expenditures	4,903			(5,384		)	—
Acquisitions	—			—			(315,810		)
Investment in other long-term assets	—			—			(2,610		)
Proceeds from sale or disposition of assets	26,012			119,006			478,926
Increase in note receivable from related party	(13,328		)	(80,961		)	(95,711		)
Other, net	(853		)	(302		)	—
Net cash used in investing activities	(340,231		)	(310,961		)	(345,800		)
Cash Flows from Financing Activities:
Proceeds from long-term debt borrowings	743,719			1,738,451			2,549,145
Proceeds from short-term debt borrowings	574,900			—			71,880
Proceeds from note offering, net of issuance costs	—			686,863			247,398
Long-term debt repayments	(623,770		)	(2,150,743		)	(2,648,475		)
Short-term debt repayments	(497,900		)	—			(71,880		)
Proceeds from issuance of common units, net of issuance costs	—			—			336,415
Contributions from general partner	—			—			7,121
Distributions to unitholders and general partner	(392,204		)	(392,204		)	(365,279		)
Payments for termination of interest rate swaps	—			(33,697		)	(5,678		)
Other, net	7,070			1,980			(9,978		)
Net cash (used in) provided by financing activities	(188,185		)	(149,350		)	110,669
Effect of foreign exchange rate changes on cash	(2,938		)	(7,767		)	2,033
Net (decrease) increase in cash and cash equivalents	(12,831		)	17,141			66,105
Cash and cash equivalents as of the beginning of the period	100,743			83,602			17,497
Cash and cash equivalents as of the end of the period	$	87,912		$	100,743		$	83,602

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, 2014, 2013 and 2012

(Thousands of Dollars, Except Unit Data)



	Limited Partners				General Partner			Accumulated Other Comprehensive Loss			Total NuStar Energy L.P. Partners’ Equity			Noncontrolling Interest			Total Partners’ Equity
	Units	Amount			General Partner			Accumulated Other Comprehensive Loss			Total NuStar Energy L.P. Partners’ Equity			Noncontrolling Interest			Total Partners’ Equity
Balance as of January 1, 2012	70,756,078	$	2,817,069		$	62,539		$	(27,407	)	$	2,852,201		$	12,134		$	2,864,335
Net (loss) income	—	(262,502		)	35,886			—			(226,616		)	(621		)	(227,237		)
Other comprehensive (loss) income	—	—			—			(31,458		)	(31,458		)	1,098			(30,360		)
Cash distributions to partners	—	(317,719		)	(47,560		)	—			(365,279		)	—			(365,279		)
Issuance of common units, including contribution from general partner	7,130,000	336,739			7,121			—			343,860			—			343,860
Other	—	(324		)	—			—			(324		)	—			(324		)
Balance as of December 31, 2012	77,886,078	2,573,263			57,986			(58,865		)	2,572,384			12,611			2,584,995
Net (loss) income	—	(310,652		)	36,882			—			(273,770		)	(10,901		)	(284,671		)
Other comprehensive loss	—	—			—			(4,529		)	(4,529		)	(52		)	(4,581		)
Cash distributions to partners	—	(341,140		)	(51,064		)	—			(392,204		)	—			(392,204		)
Other	—	255			—			—			255			—			255
Balance as of December 31, 2013	77,886,078	1,921,726			43,804			(63,394		)	1,902,136			1,658			1,903,794
Net income (loss)	—	164,201			46,572			—			210,773			(395		)	210,378
Other comprehensive loss	—	—			—			(4,518		)	(4,518		)	(433		)	(4,951		)
Cash distributions to partners	—	(341,140		)	(51,064		)	—			(392,204		)	—			(392,204		)
Other	—	23			—			—			23			(830		)	(807		)
Balance as of December 31, 2014	77,886,078	$	1,744,810		$	39,312		$	(67,912	)	$	1,716,210		$	—		$	1,716,210

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, 2014, 2013 and 2012

1. ORGANIZATION AND OPERATIONS

Organization

NuStar Energy L.P. (NuStar Energy) (NYSE: NS) is engaged in the transportation of petroleum products and anhydrous ammonia, the terminalling and storage of petroleum products and the marketing of petroleum products. 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. NuStar GP Holdings, LLC (NuStar GP Holdings) (NYSE: NSH) owns our general partner, Riverwalk Logistics, L.P., and owns a 14.9% total interest in us as of December 31, 2014.

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 refined product pipelines covering approximately 5,463 miles, which consist of Central West System refined product pipelines, the East Pipeline and the North Pipeline. The East and North Pipelines have storage capacity of approximately 6.3 million barrels. In addition, we own a 2,000 mile anhydrous ammonia pipeline (the Ammonia Pipeline) and 1,180 miles of Central West System crude oil pipelines including approximately 3.5 million barrels of storage capacity. 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 providing approximately 80.9 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 crude oil and refined petroleum products for resale. Our fuels marketing segment included asphalt operations prior to the sale of a 50% ownership interest in NuStar Asphalt LLC on September 28, 2012. Please refer to Note 5 for a discussion of the asphalt sales. 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. Noncontrolling interests are separately disclosed on the financial statements. 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 their 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.

Restricted Cash

Restricted cash is cash held in escrow restricted to use under certain contractual obligations. Restricted cash is included in “Other current assets” in the consolidated balance sheets.

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NUSTAR ENERGY L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

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 their review.

Inventories

Inventories consist of crude oil, refined petroleum products, and materials and supplies. Inventories, except those associated with a qualifying fair value hedge, are valued at the lower of cost or market. 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 market adjustments on an aggregate basis. Inventories associated with qualifying fair value hedges are valued at current market prices. Materials and supplies are valued at the lower of average cost or market.

Property, Plant and Equipment

We record additions to property, plant and equipment, including reliability and strategic capital expenditures, at cost.

Reliability capital expenditures are capital expenditures to replace partially or fully depreciated assets to maintain the existing operating capacity of existing assets and extend their useful lives. Strategic capital expenditures are capital expenditures to expand or upgrade the operating capacity, increase efficiency or increase the earnings potential of existing assets, whether through construction or acquisition, along with certain capital expenditures related to support functions. 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. Gains or losses on sales or other dispositions of property are recorded in income and are reported in “Other income (expense), net” in the consolidated statements of income. When property or equipment is retired or otherwise disposed of, the difference between the carrying value and the net proceeds is recognized in the year retired.

Goodwill and Intangible Assets

Goodwill acquired in a business combination is not amortized. Instead, 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, 2014 and 2013, and we determined that no impairment charges resulted from our October 1, 2014 impairment assessment. See Note 11 for a discussion of the goodwill impairment recognized in 2013. As of October 1, 2012, based on our review of the qualitative factors present, we determined that a quantitative goodwill impairment test was not necessary, and no goodwill impairment had 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 involved 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.

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


•	crude oil pipelines;


•	refined product pipelines;


•	refined product terminals, excluding our St. Eustatius and Point Tupper facilities; 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.

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Intangible assets are recorded at cost and are assets that lack physical substance (excluding financial assets). Our intangible assets are amortized on a straight-line basis over 10 to 47 years.

Investment in Joint Ventures

We account for our investment in the joint ventures using the equity method of accounting. We report our ownership interest in our equity method investments within “Investment in joint ventures” on the consolidated balance sheet and our portion of the results of operations for our equity method investments in “Equity in earnings (loss) of joint ventures” in the consolidated statements of income (loss). See Note 12 for a discussion of our investments in ST Linden Terminal, LLC and NuStar Asphalt LLC (now known as Axeon Specialty Products LLC, or Axeon).

Note Receivable from Related Party

The note receivable from related party consisted of the amounts due to us from Axeon under a $250.0 million unsecured revolving credit facility. We recognized interest income ratably over the term of the facility in “Interest income from related party” on the consolidated statements of income. Effective upon the sale of our remaining 50% ownership interest in Axeon, this revolving credit facility was converted into a term loan, and its carrying value is now included in “Other long-term assets” on the consolidated balance sheet. The revolving credit facility and term loan are both recorded at the outstanding principal amount, adjusted for equity losses from our investment in Axeon that exceeded the carrying value of our investment in Axeon, and for the fair value of guarantees issued on behalf of Axeon. We recognize interest income for the term loan ratably over the term of the loan in “Interest expense, net” on the consolidated statements of income (loss). See Note 5 and Note 19 for additional information on our agreements with Axeon.

Other Long-Term Assets

“Other long-term assets, net” primarily include the following:


•	the term loan to Axeon (see Note 17 for additional information);


•	funds deposited with a trustee related to revenue bonds issued by the Parish of St. James associated with our St. James terminal expansion (see Note 14 for additional information on the Gulf Opportunity Zone Revenue Bonds);


•	ammonia pipeline linefill and tank heel inventory;


•	deferred financing costs amortized over the life of the related debt obligation using the effective interest method; and


•	long-term derivative assets.

Impairment of Long-Lived Assets

We review long-lived assets, including property, plant and equipment and investment in joint ventures, 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, 2014 are recoverable. See Note 5 for a discussion of impairments of long-lived assets.

Taxes Other than Income Taxes

Taxes other than income taxes include liabilities for ad valorem taxes, franchise taxes, sales and use taxes, excise fees and taxes and value added taxes.

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, 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.

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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, 2014 and 2013.

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 2010 through 2013, 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 approximately $0.8 million and $0.6 million as of December 31, 2014 and 2013, 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 over a 20-year time period 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.

Product Imbalances

We incur product imbalances as a result of variances in pipeline meter readings and volume fluctuations within the East Pipeline system 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 product, 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.

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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 lease revenues), and throughput agreements, whereby a customer pays a fee per barrel for volumes moving through our terminals for which we charge additional fees (throughput 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 lease 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 and as crude oil and certain other refinery feedstocks are received by the related refinery. 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 net income for each quarterly reporting period is first allocated 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 among the limited and general partners in accordance with their respective 98% and 2% interests.

Net Income per Unit Applicable to Limited Partners

We have identified the general partner interest and incentive distribution rights as participating securities and use the two-class method when calculating the net income per unit applicable to limited partners, which is based on the weighted-average number of common units outstanding during the period. Basic and diluted net income per unit applicable to limited partners are the same as we have no potentially dilutive securities outstanding.

Comprehensive Income

Comprehensive income consists of net income and other gains and losses affecting partners’ equity that are excluded from net income, such as foreign currency translation adjustments and mark-to-market adjustments on derivative instruments designated and qualifying as cash flow hedges.

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.

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” (AOCI) until the underlying hedged forecasted transactions occur and are recognized in income. 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.”

We terminated all forward-starting interest rate swaps during the years ended December 31, 2013 and 2012. Prior to December 31, 2013, we were a party to forward-starting interest rate swap agreements for the purpose of hedging the interest rate risk associated with forecasted interest payments of probable debt issuances. Under the terms of these swap agreements, we paid a fixed rate and received a variable rate. We entered into the swaps in order to hedge the risk of changes in the interest

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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 accounted for the forward-starting interest rate swaps as Cash Flow Hedges, and we recognized the fair value of each interest rate swap in the consolidated balance sheets. We recorded the effective portion of mark-to-market adjustments as a component of AOCI, and any hedge ineffectiveness was 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.

We terminated all fixed-to-floating interest rate swaps during the year ended December 31, 2012. Prior to December 31, 2012, we entered into fixed-to-floating interest rate swap agreements associated with a portion of our fixed-rate senior notes. Under the terms of these swap agreements, we received a fixed rate and paid a variable rate that varied with each agreement. We accounted for the fixed-to-floating interest rate swaps as Fair Value Hedges and recognized the fair value of each interest rate swap in the consolidated balance sheets. The interest rate swap agreements qualified for the shortcut method of accounting. As a result, changes in the fair value of the swaps completely offset the changes in the fair value of the underlying hedged debt.

Although we no longer enter into commodity derivatives without underlying physical inventory, in 2012 we entered into derivative commodity instruments based on our analysis of market conditions in order to attempt to profit from market fluctuations. These derivative instruments were financial positions entered into without underlying physical inventory and are not considered hedges. We recorded these derivatives in the consolidated balance sheets as assets or liabilities at fair value with mark-to-market adjustments recorded in “Product sales.”

See Note 18 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

NuStar GP, LLC, a wholly owned subsidiary of NuStar GP Holdings, has adopted various long-term incentive plans that provide the Compensation Committee of the Board of Directors of NuStar GP, LLC with the right to grant employees and directors of NuStar GP, LLC providing services to NuStar Energy the right to receive NS common units. NuStar GP, LLC accounts for awards of NS common unit options, restricted units and performance awards at fair value as a derivative, whereby a liability for the award is recorded at inception. Subsequent changes in the fair value of the award are included in the determination of net income. NuStar GP, LLC determines the fair value of NS unit options using the Black-Scholes model at each reporting date. NuStar GP, LLC determines the fair value of NS restricted units and performance awards using the market price of NS common units at each reporting date. However, performance awards are earned only upon NuStar Energy’s achievement of an objective performance measure. NuStar GP, LLC records compensation expense each reporting period such that the cumulative compensation expense recognized equals the current fair value of the percentage of the award that has vested. NuStar GP, LLC records compensation expense related to NS unit options until such options are exercised, and compensation expense related to NS restricted units until the date of vesting.

NuStar GP Holdings has adopted a long-term incentive plan that provides the Compensation Committee of the Board of Directors of NuStar GP Holdings with the right to grant employees, consultants and directors of NuStar GP Holdings and its affiliates, including NuStar GP, LLC, rights to receive NSH common units. NuStar GP Holdings accounts for awards of NSH restricted units and unit options granted to its directors or employees of NuStar GP, LLC at fair value. The fair value of NSH unit options is determined using the Black-Scholes model at the grant date, and the fair value of the NSH restricted unit equals the market price of NSH common units at the grant date. NuStar GP Holdings recognizes compensation expense for NSH restricted units and unit options ratably over the vesting period based on the fair value of the units at the grant date.

Under these long-term incentive plans, certain awards provide that the grantee’s award vests immediately upon retirement. Compensation expense is recognized immediately if these awards are granted to retirement-eligible employees, as defined in each award. In addition, if, during a vesting period of a grant, the grantee will become retirement-eligible, then compensation expense associated with the grant is recognized from the grant date through the grantee’s retirement eligibility date.

We reimburse NuStar GP, LLC for the expenses resulting from grants of NS and NSH awards under our long-term incentive plans to employees and directors of NuStar GP, LLC. We include such compensation expense in “General and administrative

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expenses” on the consolidated statements of income. We do not reimburse NuStar GP, LLC for the expense resulting from NSH awards to non-employee directors of NuStar GP Holdings.

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 currency of the country in which the subsidiary is 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 income (expense), net” in the consolidated statements of income.

3. NEW ACCOUNTING PRONOUNCEMENTS

Consolidation

In February 2015, the Financial Accounting Standards Board (FASB) issued new consolidation guidance that modifies the criterion involved in a reporting organization’s evaluation of whether certain legal entities are subject to consolidation under the standard. The standard is effective for public companies for annual and interim reporting periods beginning after December 15, 2015, with early adoption permitted. We are currently assessing the impact of this new guidance on our financial statements and disclosures.

Revenue Recognition

In May 2014, the FASB and the International Accounting Standards Board jointly issued a comprehensive new revenue recognition standard. The standard is effective for public entities for annual and interim periods beginning after December 15, 2016, using one of two retrospective transition methods. Early adoption is not permitted for public entities. We are currently assessing the impact of this new guidance on our financial statements and disclosures, and we have not yet selected a transition method.

Discontinued Operations

In April 2014, the FASB amended the disclosure requirements for discontinued operations. Under the amended guidance, a discontinued operation is defined as the disposal of a component that represents a strategic shift that has (or will have) a major effect on an entity's operations and financial results. The amended guidance also requires expanded disclosures about discontinued operations and disposals of a significant part of an entity that do not qualify as discontinued operations. The amended guidance is effective prospectively to new disposals and new classifications of assets held for sale in annual periods beginning after December 15, 2014, and interim periods within those annual periods. Accordingly, we adopted the amended guidance on January 1, 2015.

4. ACQUISITIONS

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We accounted for the TexStar Asset Acquisition using the acquisition method. The fair value of the consideration transferred was allocated based on the estimated fair values of the individual assets acquired and liabilities assumed at the date of acquisition. The purchase price and purchase price allocation was as follows (in thousands of dollars):



Cash paid for the TexStar Asset Acquisition	$	315,810
Fair value of liabilities assumed	9,600
Purchase price	$	325,410

Accounts receivable	$	537
Property, plant and equipment	125,614
Goodwill	131,359
Intangible assets	67,900
Purchase price allocation	$	325,410

5. DISPOSITIONS AND DISCONTINUED OPERATIONS

Dispositions

2012 Asphalt Sale. On September 28, 2012, we sold a 50% ownership interest (the 2012 Asphalt Sale) in NuStar Asphalt LLC, previously a wholly owned subsidiary, to an affiliate of Lindsay Goldberg LLC (Lindsay Goldberg), a private investment firm. NuStar Asphalt LLC owns and operates the asphalt refining assets that were previously wholly owned by NuStar Energy, including an asphalt refinery located in Paulsboro, New Jersey and a terminal in Savannah, Georgia (collectively, the Asphalt Operations). Lindsay Goldberg paid $175.0 million for the Class A equity interests (Class A Interests) of NuStar Asphalt LLC, while we retained the Class B equity interests with a fair value of $52.0 million (Class B Interests). We also received $263.8 million from NuStar Asphalt LLC for inventory related to the Asphalt Operations. At closing, the fair value of the consideration we received was less than the carrying amount of the net assets of the Asphalt Operations and we recognized a loss of $23.8 million in “Other income (expense), net” in the consolidated statements of income for the year ended December 31, 2012. Upon closing, we deconsolidated NuStar Asphalt LLC and started reporting our remaining investment in NuStar Asphalt LLC using the equity method of accounting.

2014 Asphalt Sale. On February 26, 2014, we sold our remaining 50% ownership interest in NuStar Asphalt LLC to Lindsay Goldberg (the 2014 Asphalt Sale). Effective February 27, 2014, NuStar Asphalt LLC changed its name to Axeon Specialty Products LLC (Axeon). Lindsay Goldberg now owns 100% of Axeon. As a result of the 2014 Asphalt Sale, we ceased applying the equity method of accounting. Therefore, the results of our investment in Axeon were reported in “Equity in earnings (loss) of joint ventures” in the consolidated statements of income from September 28, 2012 through February 26, 2014. Upon completion of the 2014 Asphalt Sale, the parties agreed to: (i) convert the $250.0 million unsecured revolving credit facility provided by us to Axeon (the NuStar JV Facility) from a revolving credit agreement into a $190.0 million term loan (the Axeon Term Loan); (ii) terminate the terminal services agreements with respect to our terminals in Rosario, NM, Catoosa, OK and Houston, TX; (iii) amend the terminal services agreements for our terminals in Baltimore, MD and Jacksonville, FL; and (iv) transfer ownership of both the Wilmington, NC and Dumfries, VA terminals to Axeon, which were categorized as assets held for sale at December 31, 2013. We have presented transactions between us and Axeon as related party transactions in the consolidated financial statements from September 28, 2012 through February 25, 2014.

The Axeon Term Loan includes scheduled repayments to reduce the outstanding amount from $190.0 million to $175.0 million as of December 31, 2014 and then to $150.0 million on September 30, 2015. Any repayments of the Axeon Term Loan, including those scheduled in 2014 and 2015, are subject to Axeon meeting certain restrictive requirements contained in its third-party asset-based revolving credit facility. Axeon failed to make a scheduled repayment by December 31, 2014, which will increase the interest rate until Axeon makes the repayment. While the Axeon Term Loan does not provide for any other scheduled payments, Axeon is required to use all of its excess cash, as defined in the Axeon Term Loan, to repay the Axeon Term Loan. The Axeon Term Loan must be repaid in full on September 28, 2019. The carrying value of the Axeon Term Loan is included in “Other long-term assets, net” on the consolidated balance sheet as of December 31, 2014.

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million, plus two guarantees to suppliers that do not specify a maximum amount. A majority of these guarantees have no expiration date. As of December 31, 2014, we have also provided $50.1 million in letters of credit on behalf of Axeon. In the event we are obligated to perform under any of these guarantees or letters of credit, the amount paid by us will be treated as additional borrowings under the Axeon Term Loan. See Note 17 for a discussion on the fair value of these guarantees.

Asphalt Operations Impairments. In anticipation of the 2012 Asphalt Sale, we evaluated the goodwill and other long-lived assets associated with the Asphalt Operations for potential impairment. The estimated fair value of the Asphalt Operations reporting unit was less than its carrying value, which resulted in the recognition of a goodwill impairment loss of $22.1 million in the second quarter of 2012. In addition, in the second quarter of 2012, we recorded an asset impairment loss of $244.2 million in order to write-down the carrying value of long-lived assets related to the Asphalt Operations, including fixed assets, intangible assets and other long-term assets, to their estimated fair value. The goodwill impairment loss and the asset impairment loss related to the Asphalt Operations were reported in the fuels marketing segment.

The Asphalt Operations asset impairment loss consisted of the following:



	Year Ended December 31, 2012
	(Thousands of Dollars)
Property, plant and equipment, net	$	232,759
Intangible assets, net	6,564
Other long-term assets, net	4,902
Asset impairment loss	$	244,225

Discontinued Operations

Terminals Dispositions. As of December 31, 2013, in addition to the terminals located in Wilmington, NC and Dumfries, VA that were transferred to Axeon as described above, we identified several non-strategic, underperforming terminal facilities and decided to divest those facilities. As a result, we classified the associated assets as “Assets held for sale” on the consolidated balance sheet. As of December 31, 2014 and 2013, assets held for sale consisted of property, plant and equipment of $1.1 million and $22.0 million, respectively. We presented the results of operations for those facilities, which were previously reported in the storage segment, as discontinued operations for all periods presented. We allocated interest expense of $0.8 million, $1.4 million and $0.8 million for the years ended December 31, 2014, 2013 and 2012, respectively, to discontinued operations based on the ratio of net assets discontinued to consolidated net assets.

In connection with the plan for disposal, we determined that the estimated fair value, less cost to sell, was less than the carrying amount of each disposal group, resulting in an impairment loss of $102.5 million. Since these terminal facilities met the required criteria to be classified as assets held for sale on the consolidated balance sheet, we recorded the impairment loss in “Loss from discontinued operations, net of tax” on the consolidated statement of income for the year ended December 31, 2013.

The impairment loss consisted of the following:



	Year Ended December 31, 2013
	(Thousands of Dollars)
Property, plant and equipment, net	$	68,213
Intangible assets, net (customer relationships)	6,856
Goodwill	27,460
Asset impairment loss	$	102,529

In September 2014, we sold our 75% interest in our facility in Mersin, Turkey for proceeds of $13.4 million. We recognized a gain of $3.7 million, which is included in discontinued operations for the year ended December 31, 2014. In June 2014, we sold three terminals located in Mobile, AL with an aggregate storage capacity of 1.8 million barrels for proceeds of $13.7 million. In April 2012, we sold five terminals in Georgia and Alabama with an aggregate storage capacity of 1.8 million barrels for proceeds of $30.8 million.

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operations for the San Antonio Refinery and related assets as discontinued operations for all periods presented. We allocated interest expense of $3.9 million for the year ended December 31, 2012 to discontinued operations based on the ratio of net assets discontinued to consolidated net assets. We recognized a gain of $9.3 million on the sale, which is included in discontinued operations for the year ended December 31, 2013.

The following table summarizes the results from discontinued operations for the terminal dispositions and the San Antonio Refinery:



	Year Ended December 31,
	2014			2013			2012
	(Thousands of Dollars)
Revenues	$	4,265		$	7,758		$	571,071

Loss before income tax expense	$	(3,791	)	$	(106,033	)	$	(63,165	)

6. ALLOWANCE FOR DOUBTFUL ACCOUNTS

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



	Year Ended December 31,
	2014			2013			2012
	(Thousands of Dollars)
Balance as of beginning of year	$	1,224		$	808		$	2,147
Increase in allowance	7,649			1,039			27
Accounts charged against the allowance, net of recoveries	(1,065		)	(625		)	(1,367		)
Foreign currency translation	—			2			1
Balance as of end of year	$	7,808		$	1,224		$	808

7. INVENTORIES

Inventories consisted of the following:



	December 31,
	2014		2013
	(Thousands of Dollars)
Crude oil	$	3,527	$	6,485
Finished products	43,206		123,656
Materials and supplies	8,980		8,006
Total	$	55,713	$	138,147

Our finished 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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8. OTHER CURRENT ASSETS

Other current assets consisted of the following:



	December 31,
	2014		2013
	(Thousands of Dollars)
Prepaid expenses	$	16,140	$	16,487
Restricted cash	—		9,316
Derivative assets	16,362		4,948
Margin deposits	—		3,285
Product advances	2,392		3,076
Other	1,050		3,166
Other current assets	$	35,944	$	40,278

9. PROPERTY, PLANT AND EQUIPMENT

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



	Estimated Useful Lives			December 31,
	Estimated Useful Lives			2014			2013
	(Years)			(Thousands of Dollars)
Land		—		$	120,351		$	129,731
Land and leasehold improvements	5	-	40	160,283			142,122
Buildings	15	-	40	134,857			133,531
Pipelines, storage and terminals	20	-	40	3,963,134			3,787,499
Rights-of-way	20	-	40	160,008			155,833
Construction in progress		—		276,763			152,121
Total				4,815,396			4,500,837
Less accumulated depreciation and amortization				(1,354,664		)	(1,190,184		)
Property, plant and equipment, net				$	3,460,732		$	3,310,653

Capitalized interest costs added to property, plant and equipment totaled $5.7 million, $4.5 million and $7.7 million for the years ended December 31, 2014, 2013 and 2012, respectively. Depreciation and amortization expense for property, plant and equipment totaled $177.3 million, $168.8 million and $157.8 million for the years ended December 31, 2014, 2013 and 2012, respectively, which includes depreciation expense included in “Loss from discontinued operations, net of tax” on the consolidated statements of income (loss).

10. INTANGIBLE ASSETS

Intangible assets consisted of the following:



	December 31, 2014					December 31, 2013
	Cost		Accumulated Amortization			Cost		Accumulated Amortization
	(Thousands of Dollars)
Customer relationships	$	126,566	$	(69,711	)	$	127,614	$	(58,230	)
Other	2,359		(544		)	2,359		(494		)
Total	$	128,925	$	(70,255	)	$	129,973	$	(58,724	)

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NUSTAR ENERGY L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

All of our intangible assets are subject to amortization. Amortization expense for intangible assets was $12.6 million, $13.8 million and $7.8 million for the years ended December 31, 2014, 2013 and 2012, respectively. The estimated aggregate amortization expense for the next five years is as follows:



	Amortization Expense
	(Thousands of Dollars)
2015	$	9,709
2016	$	6,840
2017	$	6,840
2018	$	6,840
2019	$	6,840

11. 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, 2013:
Goodwill	$	302,744	$	617,157		$	53,255		$	973,156
Accumulated impairment losses	—		—			(22,132		)	(22,132		)
Net goodwill	302,744		617,157			31,123			951,024

Activity for the year ended December 31, 2013:
TexStar Asset Acquisition final purchase price allocation	3,463		—			—			3,463
Other (a)	—		(5,145		)	—			(5,145		)
Impairment losses	—		(331,913		)	—			(331,913		)

Balances as of December 31, 2013 and 2014:
Goodwill	306,207		612,012			53,255			971,474
Accumulated impairment losses	—		(331,913		)	(22,132		)	(354,045		)
Net goodwill	$	306,207	$	280,099		$	31,123		$	617,429


(a)	Includes foreign currency translation adjustments.

2013 Goodwill Impairment

The estimated fair value of the Statia Terminals reporting unit was less than its carrying value. To determine the amount of goodwill impairment loss, we first considered whether any other assets assigned to the Statia Terminals reporting unit were impaired. The only significant assets of this reporting unit, other than goodwill, consist of property, plant and equipment, which we determined were fully recoverable. The hypothetical fair value allocation for the Statia Terminals reporting unit indicated the estimated fair value of goodwill was $0. As a result, we recognized a $304.5 million goodwill impairment charge in the fourth quarter of 2013, which represented all of the goodwill allocated to the Statia Terminals reporting unit.

The goodwill impairment charge resulted from changes in demand for storage at our St. Eustatius and Point Tupper terminal locations. Increased supply from various shale formations within the U.S. has reduced the need for storage at these locations, which historically functioned as break bulk facilities for light crude moving from foreign sources into the U.S. These changes in crude flow patterns, as well as the backwardation of the forward pricing curve, reduced demand at these terminals. Primarily resulting from those factors, a customer at our St. Eustatius terminal vacated a significant portion of its storage in the fourth quarter of 2013.

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NUSTAR ENERGY L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

12. INVESTMENT IN JOINT VENTURES

ST Linden Terminal, LLC. The 44-acre facility provides deep-water terminalling capabilities in the New York Harbor and primarily stores petroleum products, including gasoline, jet fuel and fuel oils. As part of our acquisition of Kaneb Pipeline Partners, L.P. and Kaneb Services LLC in July 2005 (the Kaneb Acquisition), we acquired a 50% ownership interest in ST Linden Terminal, LLC (Linden), with the remaining 50% owned by Linden Holding Corp. In connection with the Kaneb Acquisition, we recorded our investment in Linden at fair value, which exceeded our 50% share of its members’ equity. This excess totaled $42.3 million and $42.6 million as of December 31, 2014 and 2013, respectively, a portion of which is being amortized into expense over the average life of the assets held by Linden, or 25 years. The remaining balance not amortized represents goodwill of Linden. On January 2, 2015, we acquired full ownership of Linden by purchasing the remaining ownership interest from Linden Holding Corp for $142.5 million.

Axeon. Axeon was owned 50% by the Partnership and 50% by Lindsay Goldberg. On February 26, 2014, we sold our remaining 50% ownership interest in Axeon. See Note 5 for additional discussion.

13. ACCRUED LIABILITIES

Accrued liabilities consisted of the following:



	December 31,
	2014		2013
	(Thousands of Dollars)
Derivative liabilities	$	4,623	$	2,233
Employee wages and benefit costs	32,349		16,698
Unearned income	10,884		8,225
TexStar Asset Acquisition contingent consideration	—		1,318
Other	13,169		10,158
Accrued liabilities	$	61,025	$	38,632

14. DEBT

Long-term debt consisted of the following:



				December 31,
	Maturity			2014		2013
				(Thousands of Dollars)
$1.5 billion revolving credit agreement		2019		$	601,496	$	503,036
4.75% senior notes		2022		250,000		250,000
6.75% senior notes		2021		300,000		300,000
4.80% senior notes		2020		450,000		450,000
7.65% senior notes		2018		350,000		350,000
7.625% subordinated notes		2043		402,500		402,500
Gulf Opportunity Zone revenue bonds	2038	thru	2041	365,440		365,440
Net fair value adjustments and unamortized discounts		N/A		30,016		34,577
Total long-term debt				$	2,749,452	$	2,655,553

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NUSTAR ENERGY L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

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



2015 - 2017	$	—
2018	350,000
2019	601,496
Thereafter	1,767,940
Total repayments	2,719,436
Net fair value adjustments and unamortized discounts	30,016
Total long-term debt	$	2,749,452

Interest payments totaled $135.0 million, $118.3 million and $118.4 million for the years ended December 31, 2014, 2013 and 2012, respectively.

Revolving Credit Agreement

On October 29, 2014, NuStar Logistics amended and restated its $1.5 billion five-year revolving credit agreement (the Revolving Credit Agreement), which matures on October 29, 2019. The Revolving Credit Agreement includes an option allowing NuStar Logistics to request an aggregate increase in the commitments from the lenders of up to $250.0 million (after which increase the aggregate commitment from all lenders shall not exceed $1.75 billion). The Revolving Credit Agreement also 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. NuPOP will be released from its guarantee of the Revolving Credit Agreement when it no longer guarantees indebtedness of NuStar Energy or its subsidiaries in an aggregate principal amount exceeding $200.0 million. For the year ended December 31, 2014, we recorded deferred issuance costs of $4.8 million associated with the Revolving Credit Agreement to “Other long-term assets, net” on the consolidated balance sheet.

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, 2014, our weighted-average interest rate was 2.0%. During the year ended December 31, 2014, the weighted-average interest rate related to borrowings under the Revolving Credit Agreement was 2.2%.

Letters of credit issued under our Revolving Credit Agreement totaled $56.2 million as of December 31, 2014. Letters of credit are limited to $750.0 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.

Notes

NuStar Logistics’ Senior Notes. On August 19, 2013, NuStar Logistics issued $300.0 million of 6.75% senior notes due February 1, 2021. We received net proceeds of approximately $296.0 million, which we used for general partnership purposes, including repayment of outstanding borrowings under our Revolving Credit Agreement. Interest is payable semi-annually in arrears for the $250.0 million of 4.75% senior notes, $300.0 million of 6.75% senior notes, $450.0 million of 4.80% senior notes and $350.0 million of 7.65% 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 is at 8.2% as of December 31, 2014. The NuStar Logistics Senior Notes do not have sinking fund requirements. These notes rank equally with existing senior unsecured indebtedness of NuStar Logistics and contain restrictions on NuStar

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NUSTAR ENERGY L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Logistics’ ability to incur 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.

The NuStar Logistics Senior Notes are fully and unconditionally guaranteed by NuStar Energy and NuPOP. NuPOP will be released from its guarantee of senior notes issued by NuStar Logistics when it no longer guarantees any obligations of NuStar Energy, or any of its subsidiaries, including NuStar Logistics, under any bank facility or public debt instrument.

In 2013, we repaid Nustar Logistics’ $229.9 million of 6.05% senior notes due March 15, 2013 and NuPOP’s $250.0 million of 5.875% senior notes due June 1, 2013, both with borrowings under the Revolving Credit Agreement.

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 bear 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 will 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 interest is deferred.

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. At the option of NuStar Logistics, the Subordinated Notes may be redeemed in whole or in part at any time at a redemption price, which may include a make-whole premium, plus accrued and unpaid interest to the redemption date.

Gulf Opportunity Zone Revenue Bonds

In 2008, 2010 and 2011, the Parish of St. James, where our St. James, Louisiana, terminal is located, issued Revenue Bonds (NuStar Logistics, L.P. Project) Series 2008, Series 2010, Series 2010A, Series 2010B and Series 2011 associated with our St. James terminal expansion pursuant to the Gulf Opportunity Zone Act of 2005 (collectively, the Gulf Opportunity Zone Revenue 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 issuance, 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 expansion. We include the amount remaining in trust in “Other long-term assets, net,” and we include the amount of bonds issued in “Long-term debt” in our consolidated balance sheets. For the years ended December 31, 2014 and 2013, the amount received from the trustee totaled $11.9 million and $43.1 million, respectively.

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NUSTAR ENERGY L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

The following table summarizes the Gulf Opportunity Zone Revenue Bonds outstanding as of December 31, 2014:



Date Issued	Maturity Date	Amount Outstanding		Amount of Letter of Credit		Amount Received from Trustee		Amount Remaining in Trust		Average Annual Interest Rate
		(Thousands of Dollars)
June 26, 2008	June 1, 2038	$	55,440	$	56,169	$	55,440	$	—	0.1	%
July 15, 2010	July 1, 2040	100,000		101,315		100,000		—		0.1	%
October 7, 2010	October 1, 2040	50,000		50,658		35,760		14,240		0.1	%
December 29, 2010	December 1, 2040	85,000		86,118		27,689		57,311		0.1	%
August 29, 2011	August 1, 2041	75,000		75,986		75,000		—		0.1	%
	Total	$	365,440	$	370,246	$	293,889	$	71,551

UK Term Loan

In 2013, we repaid our UK subsidiary, NuStar Terminals Limited’s, £21 million amended and restated term loan, which matured on December 10, 2013, with borrowings under the Revolving Credit Agreement.

Short-term Lines of Credit

In 2014, we entered into two short-term line of credit agreements with an aggregate uncommitted borrowing capacity of up to $80.0 million. The agreements 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 the borrowing. We had $77.0 million outstanding under these lines of credit as of December 31, 2014. The weighted-average interest rate related to outstanding borrowings under these short-term lines of credit during the year ended December 31, 2014 was 1.8%.

15. HEALTH, SAFETY AND ENVIRONMENTAL MATTERS

Most of our pipelines are subject to federal regulation by one or more of the following governmental agencies or laws: 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 Homeland Security Act. Additionally, the operations and integrity of the pipelines are subject to the respective state jurisdictions along the route of the systems.

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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NUSTAR ENERGY L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

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



	Year Ended December 31,
	2014			2013
	(Thousands of Dollars)
Balance as of the beginning of year	$	6,233		$	13,451
Additions to accrual	3,292			3,623
Payments	(2,878		)	(2,940		)
San Antonio Refinery Sale	—			(7,910		)
Foreign currency translation	(49		)	9
Balance as of the end of year	$	6,598		$	6,233

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



	December 31,
	2014		2013
	(Thousands of Dollars)
Accrued liabilities	$	3,518	$	3,299
Other long-term liabilities	3,080		2,934
Accruals for environmental matters	$	6,598	$	6,233

16. 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. As of December 31, 2014, we have accrued $2.1 million for contingent losses. The amount that will ultimately be paid related to these 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

Future minimum rental payments applicable to all noncancellable operating leases and purchase obligations as of December 31, 2014 are as follows:



	Payments Due by Period
	2015		2016		2017		2018		2019		There- after		Total
	(Thousands of Dollars)
Operating leases	$	30,179	$	26,135	$	21,885	$	19,536	$	13,297	$	66,635	$	177,667
Purchase obligations	6,294		3,880		694		216		—		—		11,084

Rental expense for all operating leases totaled $46.1 million, $52.9 million and $73.9 million for the years ended December 31, 2014, 2013 and 2012, respectively, including rental expense included in “Loss from discontinued operations, net of tax” on the consolidated statements of income. 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.

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NUSTAR ENERGY L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

17. 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 in 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, 2014
	Level 1			Level 2			Level 3			Total
	(Thousands of Dollars)
Assets:
Other current assets:
Product imbalances	$	117		$	—		$	—		$	117
Commodity derivatives	11,009			5,353			—			16,362
Total	$	11,126		$	5,353		$	—		$	16,479
Liabilities:
Accrued liabilities:
Product imbalances	$	(1,388	)	$	—		$	—		$	(1,388	)
Commodity derivatives	—			(4,623		)	—			(4,623		)
Other long-term liabilities:
Guarantee liability	—			—			(580		)	(580		)
Total	$	(1,388	)	$	(4,623	)	$	(580	)	$	(6,591	)



	December 31, 2013
	Level 1			Level 2			Level 3			Total
	(Thousands of Dollars)
Assets:
Other current assets:
Product imbalances	$	1,980		$	—		$	—		$	1,980
Commodity derivatives	—			4,948			—			4,948
Other long-term assets, net:
Commodity derivatives	—			6,977			—			6,977
Total	$	1,980		$	11,925		$	—		$	13,905
Liabilities:
Accrued liabilities:
Product imbalances	$	(2,190	)	$	—		$	—		$	(2,190	)
Commodity derivatives	(1,433		)	(800		)	—			(2,233		)
Contingent consideration	—			—			(1,318		)	(1,318		)
Other long-term liabilities:
Commodity derivatives	—			(1,575		)	—			(1,575		)
Guarantee liability	—			—			(1,880		)	(1,880		)
Total	$	(3,623	)	$	(2,375	)	$	(3,198	)	$	(9,196	)

Product Imbalances. We value our assets and liabilities related to product imbalances using quoted market prices in active markets as of the reporting date.

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NUSTAR ENERGY L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Commodity Derivatives. We base the fair value of certain of our commodity derivative instruments on quoted prices on an exchange; accordingly, we include these in Level 1 of the fair value hierarchy. We also have derivative instruments for which we determine fair value using industry pricing services and other observable inputs, such as quoted prices on an exchange for similar derivative instruments. Therefore, we include these derivative instruments in Level 2 of the fair value hierarchy. See Note 18 for a discussion of our derivative instruments.

Contingent Consideration. In connection with the TexStar Asset Acquisition, we could have been obligated to pay additional consideration to TexStar, depending upon the cost of work required to complete certain assets and obtain outstanding real estate rights (collectively, the Contingent Consideration). In August 2014, we settled with TexStar and reduced the associated liability to $0.

Guarantees. As of December 31, 2014 and 2013, we recorded a liability of $0.6 million and $1.9 million, respectively, representing the fair value of guarantees we have issued on behalf of Axeon. We estimated the fair value considering the probability of default by Axeon and an estimate of the amount we would be obligated to pay under the guarantees at the time of default. We calculated the fair value based on the guarantees outstanding as of December 31, 2014 and 2013, totaling $25.3 million and $79.7 million, respectively, plus two guarantees that do not specify a maximum amount. Our estimate of the fair value is based on significant inputs not observable in the market and thus falls within Level 3 of the fair value hierarchy. See Note 5 for a discussion of our financing agreements with Axeon.

In the event we are obligated to perform under these guarantees, that amount paid by us will be treated as additional borrowings under the Axeon Term Loan. As a result, we increased the carrying value of the note receivable from Axeon by the same amount as the increase to the liability for the fair value of the guarantees outstanding as of December 31, 2014.

The following table summarizes the activity in our Level 3 liabilities:



	Year Ended December 31, 2014
	(Thousands of Dollars)
Beginning balance	$	3,198
Amounts settled	(870		)
Adjustment to guarantee liability	(1,300		)
Changes in fair value recorded in earnings:
Operating expenses	(448		)
Ending balance	$	580

Non-recurring Fair Value Measurements

We classified the property, plant and equipment associated with certain terminals as “Assets held for sale” on the consolidated balance sheet and recorded those assets at fair value, less costs to sell. As of December 31, 2014, the fair value totaled $1.1 million, based on the sales price of the terminal. We estimated the fair value of $22.0 million as of December 31, 2013, using a weighted-average of values calculated using an income approach and a market approach. The income approach calculates fair value by discounting the estimated net cash flows generated by the related terminal. The market approach involves estimating the fair value measurement on an earnings multiple based on public company transaction data. Our estimate of the fair value is based on significant inputs not observable in the market and thus falls within Level 3 of the fair value hierarchy.

Fair Value of Financial Instruments

We recognize cash equivalents, receivables, note receivables, payables and debt in our consolidated balance sheets at their carrying amounts. The fair values of these financial instruments, except for a note receivable from Axeon and long-term debt, approximate their carrying amounts. The estimated fair values and carrying amounts of the debt and note receivable were as follows:



	December 31, 2014				December 31, 2013
	Fair Value		Carrying Amount		Fair Value		Carrying Amount
	(Thousands of Dollars)
Long-term debt	$	2,764,242	$	2,749,452	$	2,636,734	$	2,655,553
Note receivable from Axeon	$	164,386	$	169,235	$	133,416	$	165,440

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NUSTAR ENERGY L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

We estimated the fair value of our publicly-traded senior notes based upon quoted prices in active markets; therefore, we determined 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 the fair value falls in Level 2 of the fair value hierarchy.

We estimated the fair value of the note receivable using discounted cash flows, which use observable inputs such as time to maturity and market interest rates, and determined the fair value falls in Level 2 of the fair value hierarchy. See Note 5 for additional information on the note receivable from Axeon.

As of December 31, 2014, the carrying amount of the note receivable from Axeon is $169.2 million, consisting of the following: (i) the outstanding principal amount from the Axeon Term Loan of $190.0 million; (ii) plus the fair value of guarantees of $0.6 million; and (iii) less equity losses from our investment in Axeon of $21.3 million incurred prior to the 2014 Asphalt Sale and after the carrying value of our equity investment in Axeon was reduced to zero.

18. DERIVATIVES AND RISK MANAGEMENT ACTIVITIES

We utilize various derivative instruments to manage our exposure to commodity price risk and interest rate 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. 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.

Interest Rate Risk

We were a party to certain interest rate swap agreements to manage our exposure to changes in interest rates. We entered into fixed-to-floating interest rate swap agreements associated with a portion of our fixed-rate senior notes. We accounted for our fixed-to-floating interest rate swaps as fair value hedges. In 2012, we entered into and terminated fixed-to-floating interest rate swap agreements with an aggregate notional amount of $200.0 million related to our 4.75% senior notes issued on February 2, 2012. We also terminated fixed-to-floating interest rate swap agreements with an aggregate notional amount of $270.0 million associated with 4.80% senior notes. Under the terms of these interest rate swap agreements, we received a fixed rate of 4.75% and 4.80% and paid a variable rate based on one month USD LIBOR, plus a percentage that varies with each agreement. We received $19.7 million in connection with the terminations, which are amortizing into “Interest expense, net” over the remaining lives of the 4.75% and 4.80% senior notes. The termination payments are included in cash flows from financing activities on the consolidated statements of cash flows. We had no fixed-to-floating interest rate swaps as of December 31, 2014 and 2013.

We were also a party to forward-starting interest rate swap agreements related to the interest payments associated with forecasted probable debt issuances in 2013. Under the terms of the swaps, we paid a fixed rate and received a rate based on three month USD LIBOR. We entered into these 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. These swaps qualified, and we designated them, as cash flow hedges of future interest payments associated with forecasted debt issuances. In connection with the issuance of the 4.75% senior notes on February 2, 2012, we terminated forward-starting interest rate swap agreements with an aggregate notional amount of $225.0 million. We paid $25.4 million in connection with the terminations, which is being reclassified out of “Accumulated other comprehensive Loss” and into “Interest expense, net” as the interest payments occur over the life of the 4.75% senior notes.

In 2013, in connection with the maturity of the 6.05% senior notes due March 15, 2013 and 5.875% senior notes due June 1, 2013, we terminated forward-starting interest rate swap agreements with an aggregate notional amount of $275.0 million. We paid $33.7 million in connection with the terminations, which we reclassify from “Accumulated other comprehensive loss” into “Interest expense, net” as the interest payments occur or if the interest payments are probable not to occur. During the second quarter of 2013, we determined that one forecasted interest payment was probable not to occur, and we reclassified $2.0 million from “Accumulated other comprehensive loss” to “Interest expense, net.” The termination payments are included in cash flows from financing activities on the consolidated statements of cash flows. We had no forward-starting interest rate swaps as of December 31, 2014 and 2013.

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Commodity Price Risk

We are exposed to market risks related to the volatility of crude oil and refined product prices. In order to reduce the risk of commodity price fluctuations with respect to our crude oil and finished 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.

We entered into commodity swap contracts to hedge the price risk associated with the San Antonio Refinery. These contracts fixed the purchase price of crude oil and sale prices of refined products for a portion of the expected production of the San Antonio Refinery, thereby attempting to mitigate the risk of volatility of future cash flows associated with hedged volumes. These contracts qualified, and we designated them, as cash flow hedges. In anticipation of the San Antonio Refinery Sale, we concluded that all of the remaining forecasted sales were probable not to occur. Therefore, we discontinued cash flow hedging treatment for the related commodity contracts in December 2012 and incurred a loss of $21.7 million, which we reclassified from accumulated other comprehensive loss to “Loss from discontinued operations, net of tax.”

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 4.7 million barrels and 15.2 million barrels as of December 31, 2014 and 2013, respectively.

As of December 31, 2013, we had $3.3 million of margin deposits related to our derivative instruments and none as of December 31, 2014.

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	2014		2013		2014			2013
		(Thousands of Dollars)
Derivatives Designated as Hedging Instruments:
Commodity contracts	Other current assets	$	5,609	$	—	$	—		$	—
Commodity contracts	Accrued liabilities	—		—		—			(130		)
Total		5,609		—		—			(130		)

Derivatives Not Designated as Hedging Instruments:
Commodity contracts	Other current assets	38,704		16,168		(27,951		)	(11,220		)
Commodity contracts	Other long-term assets, net	—		15,883		—			(8,906		)
Commodity contracts	Accrued liabilities	13,081		4,523		(17,704		)	(6,626		)
Commodity contracts	Other long-term liabilities	—		5,448		—			(7,023		)
Total		51,785		42,022		(45,655		)	(33,775		)

Total Derivatives		$	57,394	$	42,022	$	(45,655	)	$	(33,905	)

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	2014			2013
	(Thousands of Dollars)
Net amounts of assets presented in the consolidated balance sheets	$	16,362		$	11,925
Net amounts of liabilities presented in the consolidated balance sheets	$	(4,623	)	$	(3,808	)

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The earnings impact of our derivative activity was as follows:



Derivatives Designated as Fair Value Hedging Instruments	Income Statement Location	Amount of Gain (Loss) Recognized in Income on Derivative (Effective Portion)			Amount of Gain (Loss) Recognized in Income on Hedged Item			Amount of Gain (Loss) Recognized in Income on Derivative (Ineffective Portion)
		(Thousands of Dollars)
Year ended December 31, 2014:
Commodity contracts	Cost of product sales	$	21,951		$	(21,587	)	$	364

Year ended December 31, 2013:
Commodity contracts	Cost of product sales	$	3,964		$	(6,327	)	$	(2,363	)

Year ended December 31, 2012:
Interest rate swaps	Interest expense, net	$	17,345		$	(17,345	)	$	—
Commodity contracts	Cost of product sales	(10,505		)	12,139			1,634
Total		$	6,840		$	(5,206	)	$	1,634



Derivatives Designated as Cash Flow Hedging Instruments	Amount of Gain (Loss) Recognized in OCI on Derivative (Effective Portion)			Income Statement Location (a)	Amount of Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)			Amount of Gain (Loss) Recognized in Income on Derivative (Ineffective Portion)
	(Thousands of Dollars)				(Thousands of Dollars)
Year ended December 31, 2014:
Interest rate swaps	$	—		Interest expense, net	$	(10,663	)	$	—

Year ended December 31, 2013:
Interest rate swaps	$	7,213		Interest expense, net	$	(7,570	)	$	—

Year ended December 31, 2012:
Interest rate swaps	$	(17,069	)	Interest expense, net	$	(1,749	)	$	—
Commodity contracts	(77,200		)	Loss from discontinued operations	(51,483		)	4,010
Total	$	(94,269	)		$	(53,232	)	$	4,010


(a)	Amounts are included in specified location for both the gain (loss) reclassified from accumulated OCI into income (effective portion) and the gain (loss) recognized in income on derivative (ineffective portion).

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)



Derivatives Not Designated as Hedging Instruments	Income Statement Location	Amount of Gain (Loss) Recognized in Income
		(Thousands of Dollars)
Year ended December 31, 2014:
Commodity contracts	Cost of product sales	$	18,407

Year ended December 31, 2013:
Commodity contracts	Cost of product sales	$	(5,323	)
Commodity contracts	Loss from discontinued operations	(218		)
Total		$	(5,541	)

Year ended December 31, 2012:
Commodity contracts	Revenues	$	(7,654	)
Commodity contracts	Cost of product sales	20,138
Commodity contracts	Loss from discontinued operations	6,176
Total		$	18,660

For derivatives designated as cash flow hedging instruments, once a hedged transaction occurs, we reclassify the effective portion from AOCI to “Interest expense, net” for our forward-starting interest rate swaps or to “Loss from discontinued operations, net of tax” for our commodity contracts associated with the San Antonio Refinery. As of December 31, 2014, we expect to reclassify a loss of $9.8 million to “Interest expense, net” within the next twelve months.

19. RELATED PARTY TRANSACTIONS

The following table summarizes information pertaining to related party transactions:



	Year Ended December 31,
	2014		2013		2012
	(Thousands of Dollars)
Revenues	$	929	$	14,897	$	1,990
Operating expenses	$	125,736	$	122,677	$	133,654
General and administrative expenses	$	66,910	$	58,602	$	62,490
Interest income	$	1,055	$	6,113	$	1,219
Revenues included in discontinued operations, net of tax	$	528	$	3,720	$	3,390
Expenses included in discontinued operations, net of tax	$	1,680	$	6,051	$	14,328

NuStar GP, LLC

Our operations are managed by NuStar GP, LLC, the general partner of our general partner. Under a services agreement between NuStar Energy and NuStar GP, LLC, employees of NuStar GP, LLC perform services for our U.S. operations. Certain of our wholly owned subsidiaries employ persons who perform services for our international operations.

GP Services Agreement. NuStar Energy and NuStar GP, LLC entered into a services agreement effective January 1, 2008 (the GP Services Agreement). The GP Services Agreement provides that NuStar GP, LLC will furnish administrative and certain operating services necessary to conduct the business of NuStar Energy. All employees providing services to both NuStar GP Holdings and NuStar Energy are employed by NuStar GP, LLC; therefore, NuStar Energy reimburses NuStar GP, LLC for all employee costs, other than the expenses allocated to NuStar GP Holdings (the Holdco Administrative Services Expense). The GP Services Agreement had an original termination date of December 31, 2014, which was subsequently renewed automatically and will continue to renew automatically every two years unless terminated by either party upon six months’ prior written notice.

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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.

Axeon

As a result of the 2014 Asphalt Sale, we ceased reporting transactions between us and Axeon as related party transactions in our consolidated financial statements on February 26, 2014.

Terminal Service Agreements. Simultaneously with the 2012 Asphalt Sale, we entered into four terminal service agreements with Axeon for our terminals in Wilmington, NC, Rosario, NM, Catoosa, OK and Houston, TX. Pursuant to the terms of the agreements, we provided aggregate storage capacity of 0.8 million barrels and blending services to Axeon for a service charge of $1.5 million per year. In addition, we had terminal service agreements with Axeon for our terminals in Jacksonville, FL, Dumfries, VA, and Baltimore, MD. Pursuant to the terms of the agreements, we provided aggregate storage capacity of approximately 0.6 million barrels to Axeon for a storage charge of approximately $6.3 million per year, plus applicable throughput and handling fees. As a result of the 2014 Asphalt Sale, these terminal service agreements were either amended or terminated. See Note 5 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for additional discussion.

Crude Oil Supply Agreement. We were a party to a crude oil supply agreement with Axeon (the Axeon Crude Oil Supply Agreement) that committed Axeon to purchase from us a minimum number of barrels of crude oil in a given year. The Axeon Crude Oil Supply Agreement terminated effective January 1, 2014. As of December 31, 2013, we had a receivable from Axeon of $50.7 million, mainly associated with crude oil sales under the Axeon Crude Oil Supply Agreement.

Services Agreements. NuStar GP, LLC and Axeon were a party to a services agreement, which provided that NuStar GP, LLC would furnish certain administrative and other operating services necessary to conduct the business of Axeon for an annual fee totaling $10.0 million, subject to adjustment (the Axeon Services Agreement). The Axeon Services Agreement terminated on June 30, 2014. In addition, NuStar GP, LLC and Axeon were a party to an employee services agreement, which provided that certain of NuStar GP, LLC employees provide employee-services to Axeon (the Axeon Employee Services Agreement). In exchange, Axeon reimbursed NuStar GP, LLC for the compensation expense of those employees. The Axeon Employee Services Agreement terminated on December 31, 2012, and effective January 1, 2013, those employees became employees of Axeon.

20. EMPLOYEE BENEFIT PLANS AND LONG-TERM INCENTIVE PLANS

Employee Benefit Plans

We rely on employees of NuStar GP, LLC to provide the necessary services to conduct our U.S. operations. NuStar GP, LLC sponsors various employee benefit plans.

The NuStar Pension Plan (the Pension Plan) is a qualified non-contributory defined benefit pension plan that provides eligible employees with retirement income as calculated under a cash balance formula. Under the cash balance formula, benefits are 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.

NuStar GP, LLC also maintains 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 of NuStar GP, LLC. The supplemental executive retirement plan terminated in 2014.

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 is open to substantially all NuStar GP, LLC employees upon their date 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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

pre-tax and/or after tax employee contributions. NuStar GP, LLC makes 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.

NuStar GP, LLC also maintains an excess thrift plan (the Excess Thrift Plan) that became effective July 1, 2006. The Excess Thrift Plan is a nonqualified deferred compensation plan that provides benefits to those employees of NuStar GP, LLC whose compensation and/or annual contributions under the Thrift Plan are subject to the limitations applicable to qualified retirement plans under the Code.

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.

NuStar GP, LLC also sponsors a contributory medical benefits plan for employees that retired prior to April 1, 2014. For employees that retire on or after April 1, 2014, NuStar GP, LLC provides partial reimbursement for eligible third-party health care premiums.

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, 2014, 2013 and 2012, our costs for these plans totaled $2.7 million, $2.5 million and $2.6 million, respectively.

Long-Term Incentive Plans

NuStar GP, LLC sponsors the following:

•

The Fourth Amended and Restated 2000 Long-Term Incentive Plan (the 2000 LTIP), under which NuStar GP, LLC may award up to 3,250,000 NS common units. Awards under the 2000 LTIP can include NS unit options, restricted units, performance awards, distribution equivalent rights (DER) and contractual rights to receive common units. As of December 31, 2014, NS common units that remained available to be awarded totaled 1,441,988 under the 2000 LTIP.

•

The 2006 Long-Term Incentive Plan (the 2006 LTIP) under which NuStar GP Holdings may award up to 2,000,000 NSH units to employees, consultants and directors of NuStar GP Holdings and its affiliates, including us. Awards under the 2006 LTIP can include NSH unit options, performance awards, DER, restricted units, phantom units, unit grants and unit appreciation rights. As of December 31, 2014, a total of 1,527,164 NSH units remained available to be awarded under the 2006 LTIP.

The 2003 Employee Unit Incentive Plan (the UIP), under which NuStar GP, LLC awarded NS common units to employees of NuStar GP, LLC or its affiliates, terminated on June 16, 2013. The 2002 Unit Option Plan (the UOP), under which NuStar GP, LLC awarded NS unit options to officers and directors of NuStar GP, LLC or its affiliates, terminated on March 22, 2012.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

The number of awards granted under the above-described plans were as follows:



	Year Ended December 31,
	2014		2013		2012
	Granted	Vesting	Granted	Vesting	Granted	Vesting
2000 LTIP:
Performance awards	28,841	(a)	38,786	(a)	33,445	(a)
Restricted units (b)	208,714	1/5 per year	269,182	1/5 per year	231,855	1/5 per year
Restricted units (grants to non-employee directors of NuStar GP, LLC)	7,009	1/3 per year	8,904	1/3 per year	8,170	1/3 per year
UIP:
Restricted units (c)	—	—	—	—	15,382	1/5 per year
2006 LTIP:
Restricted units	16,895	1/5 per year	18,620	1/5 per year	25,640	1/5 per year
Restricted units (grants to non-employee directors of NuStar GP Holdings) (d)	8,911	1/3 per year	13,183	1/3 per year	10,601	1/3 per year


(a)	Performance awards vest 1/3 per year if certain performance measures are met, as defined in the award agreements.


(b)	The 2000 LTIP restricted unit grants include 2,844 and 3,882 restricted unit awards granted to certain international employees for the years ended December 31, 2014 and 2013, respectively, that vest 1/3 per year, as defined in the award agreements.


(c)	The UIP restricted unit grants include 3,392 restricted unit awards granted to certain international employees for the year ended December 31, 2012, that vest 1/3 per year, as defined in the award agreements.


(d)	We do not reimburse NuStar GP, LLC for compensation expense relating to these awards.

Our share of compensation expense related to the benefit plans and long-term incentive plans sponsored by NuStar GP, LLC described above is as follows:



	Year Ended December 31,
	2014		2013		2012
	(Thousands of Dollars)
Benefit plans	$	11,385	$	27,741	$	32,003
Long-term incentive plans	$	10,934	$	7,369	$	5,831

21. OTHER INCOME (EXPENSE)

Other income (expense) consisted of the following:



	Year Ended December 31,
	2014		2013			2012
	(Thousands of Dollars)
Foreign exchange gains (losses)	$	2,057	$	7,707		$	(1,429	)
Gain (loss) from sale or disposition of assets	642		(524		)	(1,522		)
Loss on deconsolidation of Axeon	—		—			(23,800		)
Other, net	1,800		158			2,062
Other income (expense), net	$	4,499	$	7,341		$	(24,689	)

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

22. PARTNERS’ EQUITY

Issuance of Common Units

In September 2012, we issued 7,130,000 common units representing limited partner interests at a price of $48.94 per unit. We used the net proceeds from this offering of $343.9 million, including a contribution of $7.1 million from our general partner to maintain its 2% general partner interest, for general partnership purposes, including repayments of outstanding borrowings under our Revolving Credit Agreement and working capital purposes.

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			Total
	(Thousands of Dollars)
Balance as of January 1, 2012	$	(3,925	)	$	(23,482	)	$	(27,407	)
Other comprehensive income (loss) before reclassifications	9,579			(94,269		)	(84,690		)
Net loss reclassified into interest expense, net	—			1,749			1,749
Net loss reclassified into loss from discontinued operations	—			51,483			51,483
Other comprehensive income (loss)	9,579			(41,037		)	(31,458		)
Balance as of December 31, 2012	5,654			(64,519		)	(58,865		)
Other comprehensive (loss) income before reclassifications	(19,312		)	7,213			(12,099		)
Net loss reclassified into interest expense, net	—			7,570			7,570
Other comprehensive (loss) income	(19,312		)	14,783			(4,529		)
Balance as of December 31, 2013	(13,658		)	(49,736		)	(63,394		)
Other comprehensive loss before reclassifications	(15,181		)	—			(15,181		)
Net loss reclassified into interest expense, net	—			10,663			10,663
Other comprehensive (loss) income	(15,181		)	10,663			(4,518		)
Balance as of December 31, 2014	$	(28,839	)	$	(39,073	)	$	(67,912	)

Other comprehensive loss attributable to the noncontrolling interest consisted of foreign currency translation adjustment losses of $0.4 million, $0.1 million and gains of $1.1 million, for the years ended December 31, 2014, 2013 and 2012, respectively.

Allocations of Net Income

General Partner. Our partnership agreement, as amended, sets forth the calculation to be used to determine the amount and priority of cash distributions that the common unitholders and general partner will receive. The partnership agreement also contains provisions for the allocation of net income and loss to the unitholders and the general partner. For purposes of maintaining partner capital accounts, the partnership agreement specifies that items of income and loss shall be allocated among the partners in accordance with their respective percentage interests. Normal allocations according to percentage interests are made after giving effect to priority income allocations, if any, in an amount equal to incentive cash distributions allocated 100% to the general partner.

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NUSTAR ENERGY L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

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



	Year Ended December 31,
	2014			2013			2012
	(Thousands of Dollars)
Net income (loss) attributable to NuStar Energy L.P.	$	210,773		$	(273,770	)	$	(226,616	)
Less general partner incentive distribution	43,220			43,220			41,242
Net income (loss) after general partner incentive distribution	167,553			(316,990		)	(267,858		)
General partner interest	2		%	2		%	2		%
General partner allocation of net income (loss) after general partner incentive distribution	3,352			(6,338		)	(5,356		)
General partner incentive distribution	43,220			43,220			41,242
Net income applicable to general partner	$	46,572		$	36,882		$	35,886

Cash Distributions

We make quarterly distributions of 100% of our available cash, generally defined as cash receipts less cash disbursements 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 limited partner unitholders are entitled to receive a minimum quarterly distribution of $0.60 per unit each quarter ($2.40 annualized). Our cash is first distributed 98% to the limited partners and 2% to the general partner until the amount distributed to our unitholders is equal to the minimum quarterly distribution and arrearages in the payment of the minimum quarterly distribution for any prior quarter. Cash in excess of the minimum quarterly distributions is distributed to our unitholders and our general partner based on the percentages shown below.

Our general partner is entitled to incentive distributions if the amount we distribute with respect to any quarter exceeds specified target levels shown below:



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

The following table reflects the allocation of total cash distributions to our general and limited partners applicable to the period in which the distributions were earned:



	Year Ended December 31,
	2014		2013		2012
	(Thousands of Dollars, Except Per Unit Data)
General partner interest	$	7,844	$	7,844	$	7,486
General partner incentive distribution	43,220		43,220		41,242
Total general partner distribution	51,064		51,064		48,728
Limited partners’ distribution	341,140		341,140		325,526
Total cash distributions	$	392,204	$	392,204	$	374,254

Cash distributions per unit applicable to limited partners	$	4.380	$	4.380	$	4.380

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NUSTAR ENERGY L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

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



Quarter Ended	Cash Distributions Per Unit		Total Cash Distributions (Thousands of Dollars)		Record Date	Payment Date
December 31, 2014 (a)	$	1.095	$	98,051	February 9, 2015	February 13, 2015
September 30, 2014	$	1.095	$	98,051	November 10, 2014	November 14, 2014
June 30, 2014	$	1.095	$	98,051	August 6, 2014	August 11, 2014
March 31, 2014	$	1.095	$	98,051	May 7, 2014	May 12, 2014


(a)	The distribution was announced on January 30, 2015.

23. NET INCOME (LOSS) PER UNIT

The following table details the calculation of earnings per unit:



	Year Ended December 31,
	2014			2013			2012
	(Thousands of Dollars, Except Per Unit Data)
Net income (loss) attributable to NuStar Energy L.P.	$	210,773		$	(273,770	)	$	(226,616	)
Less general partner distribution (including incentive distribution rights)	51,064			51,064			48,728
Less limited partner distribution	341,140			341,140			325,526
Distributions greater than earnings	$	(181,431	)	$	(665,974	)	$	(600,870	)

General partner earnings:
Distributions	$	51,064		$	51,064		$	48,728
Allocation of distributions greater than earnings (2%)	(3,630		)	(13,318		)	(12,019		)
Total	$	47,434		$	37,746		$	36,709

Limited partner earnings:
Distributions	$	341,140		$	341,140		$	325,526
Allocation of distributions greater than earnings (98%)	(177,801		)	(652,656		)	(588,851		)
Total	$	163,339		$	(311,516	)	$	(263,325	)

Weighted-average limited partner units outstanding	77,886,078			77,886,078			72,957,417

Net income (loss) per unit applicable to limited partners	$	2.10		$	(4.00	)	$	(3.61	)

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

24. STATEMENTS OF CASH FLOWS

Changes in current assets and current liabilities were as follows:



	Year Ended December 31,
	2014			2013			2012
	(Thousands of Dollars)
Decrease (increase) in current assets:
Accounts receivable	$	72,298		$	107,209		$	160,435
Receivable from related parties	50,918			58,692			(113,018		)
Inventories	82,075			31,975			112,589
Income tax receivable	(24		)	414			2,921
Other current assets	3,809			25,725			(26,050		)
Increase (decrease) in current liabilities:
Accounts payable	(153,671		)	(96,330		)	(43,451		)
Payable to related party	837			6,922			(5,339		)
Accrued interest payable	303			9,370			(6,092		)
Accrued liabilities	22,980			(32,452		)	11,259
Taxes other than income tax	4,341			(87		)	(2,444		)
Income tax payable	(1,448		)	1,338			(563		)
Changes in current assets and current liabilities	$	82,418		$	112,776		$	90,247

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


•	the changes in assets held for sale being reflected in the line items to which the changes relate in the table above;


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


•	the change in the amount accrued for capital expenditures; and


•	the effect of foreign currency translation.

Non-cash investing and financing activities for the years ended December 31, 2013 and 2012 mainly consist of changes in the fair values of our fixed-to-floating and forward-starting interest rate swaps.

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



	Year Ended December 31,
	2014		2013		2012
	(Thousands of Dollars)
Cash paid for interest, net of amount capitalized	$	129,377	$	113,805	$	110,679
Cash paid for income taxes, net of tax refunds received	$	6,699	$	11,386	$	21,032

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

25. INCOME TAXES

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,
	2014			2013			2012
	(Thousands of Dollars)
Current:
U.S.	$	(182	)	$	3,098		$	4,416
Foreign	7,516			9,273			16,480
Total current	7,334			12,371			20,896

Deferred:
U.S.	1,889			1,687			7,494
Foreign	1,578			(1,305		)	(3,940		)
Total deferred	3,467			382			3,554

Total income tax expense	$	10,801		$	12,753		$	24,450

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.

The tax effects of significant temporary differences representing deferred income tax assets and liabilities were as follows:



	December 31,
	2014			2013
	(Thousands of Dollars)
Deferred income tax assets:
Net operating losses	$	35,698		$	28,945
Environmental and legal reserves	664			433
Allowance for bad debt	1,261			—
Other	1,827			1,772
Total deferred income tax assets	39,450			31,150
Less: Valuation allowance	(14,532		)	(12,237		)
Net deferred income tax assets	24,918			18,913

Deferred income tax liabilities:
Property, plant and equipment	(47,797		)	(40,494		)

Net deferred income tax liability	$	(22,879	)	$	(21,581	)

Reported on the consolidated balance sheets as:
Deferred income tax asset	$	4,429		$	5,769
Deferred income tax liability	(27,308		)	(27,350		)
Net deferred income tax liability	$	(22,879	)	$	(21,581	)

As of December 31, 2014, our U.S. and foreign corporate operations have net operating loss carryforwards for tax purposes totaling approximately $90.0 million and $14.0 million, respectively, which are subject to various limitations on use and expire in years 2019 through 2024 for U.S. losses and in years 2018 and 2019 for foreign losses.

As of December 31, 2014 and 2013, we recorded a valuation allowance of $14.5 million and $12.2 million, respectively, related to our deferred tax assets. We estimate the amount of valuation allowance based upon our expectations of taxable income in the

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

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 2014, the valuation allowance for the U.S. net operating loss remained the same and we increased the foreign net operating loss by $2.3 million, 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, 2014 is dependent upon our ability to generate future taxable income in the United States. We believe it is more likely than not that the deferred income tax assets as of December 31, 2014 will be realized, based on expected future taxable income.

Grace Energy Corporation Matter

In connection with the settlement of a legal matter, we recognized a pre-tax gain of $28.7 million in 2012 within one of our taxable subsidiaries. As a result, we recorded related income tax expense of $10.1 million, resulting from the reduction of the related deferred income tax asset.

Canadian Income Tax Audit

During the second quarter of 2012, we recorded $1.0 million of additional income tax liability and $2.2 million of interest and penalties associated with an ongoing Canadian income tax audit for the years 2006 through 2011. We also recorded $1.3 million of Canadian withholding tax and $0.7 million of interest and penalties associated with the withholding tax liability related to interest payments made from our Canadian subsidiaries to a United States entity from 2003 to 2009. We believe that adequate provisions for uncertainties related to the Canadian audits have been reflected in the financial statements.

We settled Canadian income tax audits for the years 2006 through 2009.

St. Eustatius Tax Agreement

On February 22, 2006, we entered into a Tax and Maritime Agreement with the governments of St. Eustatius and the Netherlands Antilles (the 2005 Tax Agreement). The 2005 Tax Agreement was effective beginning January 1, 2005 and expired on December 31, 2014. Under the terms of the 2005 Tax Agreement, we agreed to make a one-time payment of 5.0 million Netherlands Antilles guilders (approximately $2.8 million) in full and final settlement of all of our liabilities, taxes, fees, levies, charges, or otherwise (including settlement of audits) due or potentially due to St. Eustatius. The 2005 Tax Agreement provides for annual minimum profit tax of 1.0 million Netherlands Antilles guilders (approximately $0.6 million), beginning as of January 1, 2005. To the extent the minimum annual profit tax exceeds 2% of taxable profit (as defined in the 2005 Tax Agreement), we can carry forward that excess to offset future tax liabilities. If the minimum annual profit tax is less than 2% of taxable profit, we agreed to pay that difference.

Effective January 1, 2011, the Netherlands Antilles ceased to exist, and St. Eustatius became part of the Netherlands. The Netherlands Tax Ministry (the Ministry) contends that as of January 2011, we are subject to real estate tax rather than profit tax as expressed in our 2005 Tax Agreement. In 2013, the Ministry issued a property tax assessment for years 2011 through 2012. We objected to and appealed the assessment. The Ministry later issued property tax assessments for the years 2013 and 2014, to which we have or will file similar objections. In 2013, we filed a lawsuit in the Netherlands civil court seeking to enforce the terms of our existing 2005 Tax Agreement. In 2014, the Netherlands civil court determined that it did not have jurisdiction and deferred to the jurisdiction of the tax court. We have appealed this decision. In the tax court proceeding, a hearing was held in late 2014, and we expect a ruling in 2015. We believe it is likely that we will prevail.

26. 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 lease rates consistent with rates charged to third parties for storage. Related party revenues mainly result from storage agreements with our joint ventures.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Results of operations for the reportable segments were as follows:



	Year Ended December 31,
	2014			2013			2012
	(Thousands of Dollars)
Revenues:
Pipeline:
Third parties	$	477,030		$	411,529		$	340,455
Storage:
Third parties	537,142			518,253			517,699
Intersegment	26,435			32,044			59,168
Related party	929			6,252			1,199
Total storage	564,506			556,549			578,066
Fuels marketing:
Third parties	2,060,017			2,519,053			5,085,592
Related party	—			8,645			791
Total fuels marketing	2,060,017			2,527,698			5,086,383
Consolidation and intersegment eliminations	(26,435		)	(32,044		)	(59,168		)
Total revenues	$	3,075,118		$	3,463,732		$	5,945,736

Depreciation and amortization expense:
Pipeline	$	77,691		$	68,871		$	52,878
Storage	103,848			99,868			88,217
Fuels marketing	16			27			11,253
Total segment depreciation and amortization expense	181,555			168,766			152,348
Other depreciation and amortization expense	10,153			10,155			7,441
Total depreciation and amortization expense	$	191,708		$	178,921		$	159,789

Operating income (loss):
Pipeline	$	245,233		$	208,293		$	158,590
Storage	183,104			(127,484		)	198,842
Fuels marketing	24,805			(126		)	(296,785		)
Consolidation and intersegment eliminations	(32		)	1,437			7,939
Total segment operating income	453,110			82,120			68,586
Less general and administrative expenses	96,056			91,086			104,756
Less other depreciation and amortization expense	10,153			10,155			7,441
Other asset impairment loss	—			—			3,295
Gain on legal settlement	—			—			(28,738		)
Total operating income (loss)	$	346,901		$	(19,121	)	$	(18,168	)

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Revenues by geographic area are shown in the table below.



	Year Ended December 31,
	2014		2013		2012
	(Thousands of Dollars)
United States	$	2,276,609	$	2,340,694	$	4,230,607
Netherlands	705,207		1,027,260		1,438,297
Other	93,302		95,778		276,832
Consolidated revenues	$	3,075,118	$	3,463,732	$	5,945,736

For the years ended December 31, 2014, 2013 and 2012, Valero Energy Corporation accounted for approximately 9%, or $282.9 million, 15%, or $534.2 million, and 11%, or $668.1 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,
	2014		2013
	(Thousands of Dollars)
United States	$	2,809,462	$	2,635,792
Netherlands	451,564		467,660
Other	199,706		207,201
Consolidated long-lived assets	$	3,460,732	$	3,310,653

Total assets by reportable segment were as follows:



	December 31,
	2014		2013
	(Thousands of Dollars)
Pipeline	$	1,962,821	$	1,797,698
Storage	2,241,573		2,275,183
Fuels marketing	227,642		445,882
Total segment assets	4,432,036		4,518,763
Other partnership assets	486,760		513,423
Total consolidated assets	$	4,918,796	$	5,032,186

Capital expenditures, including acquisitions and investments in other noncurrent assets, by reportable segment were as follows:



	Year Ended December 31,
	2014		2013		2012
	(Thousands of Dollars)
Pipeline	$	244,713	$	165,096	$	493,028
Storage	108,457		170,637		161,672
Fuels marketing	—		69		20,333
Other partnership assets	3,795		7,518		53,982
Total capital expenditures	$	356,965	$	343,320	$	729,015

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

27. CONDENSED CONSOLIDATING FINANCIAL STATEMENTS

NuStar Energy has no operations, and its assets consist mainly of its investments in NuStar Logistics and NuPOP, both wholly owned subsidiaries. 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, 2014

(Thousands of Dollars)



	NuStar Energy		NuStar Logistics		NuPOP		Non-Guarantor Subsidiaries		Eliminations			Consolidated
Assets
Cash and cash equivalents	$	923	$	6	$	—	$	86,983	$	—		$	87,912
Receivables, net	—		47,038		18,347		143,093		—			208,478
Inventories	—		1,998		3,768		49,989		(42		)	55,713
Other current assets	—		10,403		418		25,239		(116		)	35,944
Assets held for sale	—		—		—		1,100		—			1,100
Intercompany receivable	—		1,438,675		—		—		(1,438,675		)	—
Total current assets	923		1,498,120		22,533		306,404		(1,438,833		)	389,147
Property, plant and equipment, net	—		1,820,126		559,808		1,080,798		—			3,460,732
Intangible assets, net	—		55,801		—		2,869		—			58,670
Goodwill	—		149,453		170,652		297,324		—			617,429
Investment in wholly owned subsidiaries	2,289,673		37,179		910,394		913,343		(4,150,589		)	—
Investment in joint venture	—		—		—		74,223		—			74,223
Deferred income tax asset	—		—		—		4,429		—			4,429
Other long-term assets, net	673		279,058		26,329		8,106		—			314,166
Total assets	$	2,291,269	$	3,839,737	$	1,689,716	$	2,687,496	$	(5,589,422	)	$	4,918,796
Liabilities and Partners’ Equity
Payables	$	—	$	60,687	$	8,211	$	108,286	$	—		$	177,184
Short-term debt	—		77,000		—		—		—			77,000
Accrued interest payable	—		33,340		—		5		—			33,345
Accrued liabilities	862		32,178		6,965		21,020		—			61,025
Taxes other than income tax	125		7,896		3,099		3,001		—			14,121
Income tax payable	—		—		4		2,629		(116		)	2,517
Intercompany payable	506,160		—		751,023		181,492		(1,438,675		)	—
Total current liabilities	507,147		211,101		769,302		316,433		(1,438,791		)	365,192
Long-term debt	—		2,749,452		—		—		—			2,749,452
Long-term payable to related party	—		28,094		—		5,443		—			33,537
Deferred income tax liability	—		528		22		26,758		—			27,308
Other long-term liabilities	—		13,681		6,963		6,453		—			27,097
Total partners’ equity	1,784,122		836,881		913,429		2,332,409		(4,150,631		)	1,716,210
Total liabilities and partners’ equity	$	2,291,269	$	3,839,737	$	1,689,716	$	2,687,496	$	(5,589,422	)	$	4,918,796

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Condensed Consolidating Balance Sheets

December 31, 2013

(Thousands of Dollars)



	NuStar Energy		NuStar Logistics		NuPOP		Non-Guarantor Subsidiaries		Eliminations			Consolidated
Assets
Cash and cash equivalents	$	904	$	22,307	$	—	$	77,532	$	—		$	100,743
Receivables, net	—		87,899		13,281		231,220		(6		)	332,394
Inventories	—		2,083		2,879		133,195		(10		)	138,147
Other current assets	—		18,109		2,334		19,835		—			40,278
Assets held for sale	—		—		—		21,987		—			21,987
Intercompany receivable	—		1,521,552		—		—		(1,521,552		)	—
Total current assets	904		1,651,950		18,494		483,769		(1,521,568		)	633,549
Property, plant and equipment, net	—		1,556,893		573,694		1,180,066		—			3,310,653
Intangible assets, net	—		16,993		—		54,256		—			71,249
Goodwill	—		149,453		170,652		297,324		—			617,429
Investment in wholly owned subsidiaries	2,469,331		177,961		860,787		918,339		(4,426,418		)	—
Investment in joint ventures	—		—		—		68,735		—			68,735
Deferred income tax asset	—		—		—		5,769		—			5,769
Note receivable from related party, net	—		165,440		—		—		—			165,440
Other long-term assets, net	611		118,254		26,331		14,166		—			159,362
Total assets	$	2,470,846	$	3,836,944	$	1,649,958	$	3,022,424	$	(5,947,986	)	$	5,032,186
Liabilities and Partners’ Equity
Payables	$	123	$	84,533	$	7,517	$	214,909	$	(6	)	$	307,076
Accrued interest payable	—		33,066		—		47		—			33,113
Accrued liabilities	585		18,850		6,133		13,064		—			38,632
Taxes other than income tax	125		6,272		2,873		475		—			9,745
Income tax payable	—		618		6		3,382		—			4,006
Intercompany payable	504,483		—		714,847		302,222		(1,521,552		)	—
Total current liabilities	505,316		143,339		731,376		534,099		(1,521,558		)	392,572
Long-term debt	—		2,655,553		—		—		—			2,655,553
Long-term payable to related party	—		35,696		—		5,443		—			41,139
Deferred income tax liability	—		—		—		27,350		—			27,350
Other long-term liabilities	—		4,961		306		6,511		—			11,778
Total partners’ equity	1,965,530		997,395		918,276		2,449,021		(4,426,428		)	1,903,794
Total liabilities and partners’ equity	$	2,470,846	$	3,836,944	$	1,649,958	$	3,022,424	$	(5,947,986	)	$	5,032,186

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Condensed Consolidating Statements of Income

For the Year Ended December 31, 2014

(Thousands of Dollars)



	NuStar Energy			NuStar Logistics			NuPOP			Non-Guarantor Subsidiaries			Eliminations			Consolidated
Revenues	$	—		$	510,833		$	229,211		$	2,344,750		$	(9,676	)	$	3,075,118
Costs and expenses	1,753			287,614			149,955			2,298,540			(9,645		)	2,728,217
Operating (loss) income	(1,753		)	223,219			79,256			46,210			(31		)	346,901
Equity in earnings (loss) of subsidiaries	212,527			(12,798		)	62,946			142,238			(404,913		)	—
Equity in (loss) earnings of joint ventures	—			(8,278		)	—			13,074			—			4,796
Interest (expense) income, net	—			(132,274		)	89			959			—			(131,226		)
Other income (expense), net	—			511			(37		)	4,025			—			4,499
Income from continuing operations before income tax expense	210,774			70,380			142,254			206,506			(404,944		)	224,970
Income tax expense	1			5			23			10,772			—			10,801
Income from continuing operations	210,773			70,375			142,231			195,734			(404,944		)	214,169
Loss from discontinued operations, net of tax	—			(169		)	—			(3,622		)	—			(3,791		)
Net income	210,773			70,206			142,231			192,112			(404,944		)	210,378
Less net loss attributable to noncontrolling interest	—			—			—			(395		)	—			(395		)
Net income attributable to NuStar Energy L.P.	$	210,773		$	70,206		$	142,231		$	192,507		$	(404,944	)	$	210,773

100

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Condensed Consolidating Statements of Income (Loss)

For the Year Ended December 31, 2013

(Thousands of Dollars)



	NuStar Energy			NuStar Logistics			NuPOP			Non-Guarantor Subsidiaries			Eliminations			Consolidated
Revenues	$	—		$	415,128		$	218,591		$	2,864,160		$	(34,147	)	$	3,463,732
Costs and expenses	1,908			242,743			147,117			3,125,253			(34,168		)	3,482,853
Operating (loss) income	(1,908		)	172,385			71,474			(261,093		)	21			(19,121		)
Equity in (loss) earnings of subsidiaries	(271,862		)	16,531			(347,808		)	(281,327		)	884,466			—
Equity in (loss) earnings of joint ventures	—			(49,599		)	—			9,629			—			(39,970		)
Interest (expense) income, net	—			(116,624		)	(4,851		)	469			—			(121,006		)
Other (expense) income, net	—			(115		)	(127		)	7,583			—			7,341
(Loss) income from continuing operations before income tax expense	(273,770		)	22,578			(281,312		)	(524,739		)	884,487			(172,756		)
Income tax expense	—			579			8			12,166			—			12,753
(Loss) income from continuing operations	(273,770		)	21,999			(281,320		)	(536,905		)	884,487			(185,509		)
Loss from discontinued operations, net of tax	—			(12,317		)	—			(86,845		)	—			(99,162		)
Net (loss) income	(273,770		)	9,682			(281,320		)	(623,750		)	884,487			(284,671		)
Less net loss attributable to noncontrolling interest	—			—			—			(10,901		)	—			(10,901		)
Net (loss) income attributable to NuStar Energy L.P.	$	(273,770	)	$	9,682		$	(281,320	)	$	(612,849	)	$	884,487		$	(273,770	)

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Condensed Consolidating Statements of Income (Loss)

For the Year Ended December 31, 2012

(Thousands of Dollars)



	NuStar Energy			NuStar Logistics			NuPOP			Non-Guarantor Subsidiaries			Eliminations			Consolidated
Revenues	$	—		$	362,451		$	210,712		$	5,397,626		$	(25,053	)	$	5,945,736
Costs and expenses	1,699			216,159			151,185			5,620,326			(25,465		)	5,963,904
Operating (loss) income	(1,699		)	146,292			59,527			(222,700		)	412			(18,168		)
Equity in (loss) earnings of subsidiaries	(224,917		)	(361,830		)	65,505			112,818			408,424			—
Equity in (loss) earnings of joint ventures	—			(16,117		)	—			6,739			—			(9,378		)
Interest expense, net	—			(76,311		)	(12,546		)	(459		)	—			(89,316		)
Other (expense) income, net	—			(26,596		)	1,679			228			—			(24,689		)
(Loss) income from continuing operations before income tax expense	(226,616		)	(334,562		)	114,165			(103,374		)	408,836			(141,551		)
Income tax expense	—			255			1,329			22,866			—			24,450
(Loss) income from continuing operations	(226,616		)	(334,817		)	112,836			(126,240		)	408,836			(166,001		)
Loss from discontinued operations, net of tax	—			(2,085		)	—			(58,765		)	(386		)	(61,236		)
Net (loss) income	(226,616		)	(336,902		)	112,836			(185,005		)	408,450			(227,237		)
Less net loss attributable to noncontrolling interest	—			—			—			(621		)	—			(621		)
Net (loss) income attributable to NuStar Energy L.P.	$	(226,616	)	$	(336,902	)	$	112,836		$	(184,384	)	$	408,450		$	(226,616	)

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Condensed Consolidating Statements of Comprehensive Income

For the Year Ended December 31, 2014

(Thousands of Dollars)



	NuStar Energy		NuStar Logistics		NuPOP		Non-Guarantor Subsidiaries			Eliminations			Consolidated
Net income	$	210,773	$	70,206	$	142,231	$	192,112		$	(404,944	)	$	210,378

Other comprehensive income (loss):
Foreign currency translation adjustment	—		3,723		—		(19,337		)	—			(15,614		)
Net loss reclassified into income on cash flow hedges	—		10,663		—		—			—			10,663
Total other comprehensive income (loss)	—		14,386		—		(19,337		)	—			(4,951		)

Comprehensive income	210,773		84,592		142,231		172,775			(404,944		)	205,427
Less comprehensive loss attributable to noncontrolling interest	—		—		—		(828		)	—			(828		)
Comprehensive income attributable to NuStar Energy L.P.	$	210,773	$	84,592	$	142,231	$	173,603		$	(404,944	)	$	206,255

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Condensed Consolidating Statements of Comprehensive Income (Loss)

For the Year Ended December 31, 2013

(Thousands of Dollars)



	NuStar Energy			NuStar Logistics			NuPOP			Non-Guarantor Subsidiaries			Eliminations		Consolidated
Net (loss) income	$	(273,770	)	$	9,682		$	(281,320	)	$	(623,750	)	$	884,487	$	(284,671	)

Other comprehensive income (loss):
Foreign currency translation adjustment	—			(3,090		)	—			(16,274		)	—		(19,364		)
Net unrealized gain on cash flow hedges	—			7,213			—			—			—		7,213
Net loss reclassified into income on cash flow hedges	—			7,570			—			—			—		7,570
Total other comprehensive income (loss)	—			11,693			—			(16,274		)	—		(4,581		)

Comprehensive (loss) income	(273,770		)	21,375			(281,320		)	(640,024		)	884,487		(289,252		)
Less comprehensive loss attributable to noncontrolling interest	—			—			—			(10,953		)	—		(10,953		)
Comprehensive (loss) income attributable to NuStar Energy L.P.	$	(273,770	)	$	21,375		$	(281,320	)	$	(629,071	)	$	884,487	$	(278,299	)

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NUSTAR ENERGY L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Condensed Consolidating Statements of Comprehensive Income (Loss)

For the Year Ended December 31, 2012

(Thousands of Dollars)



	NuStar Energy			NuStar Logistics			NuPOP		Non-Guarantor Subsidiaries			Eliminations		Consolidated
Net (loss) income	$	(226,616	)	$	(336,902	)	$	112,836	$	(185,005	)	$	408,450	$	(227,237	)

Other comprehensive loss:
Foreign currency translation adjustment	—			—			—		10,677			—		10,677
Net unrealized loss on cash flow hedges	—			(17,069		)	—		(77,200		)	—		(94,269		)
Net loss reclassified into income on cash flow hedges	—			1,749			—		51,483			—		53,232
Total other comprehensive loss	—			(15,320		)	—		(15,040		)	—		(30,360		)

Comprehensive (loss) income	(226,616		)	(352,222		)	112,836		(200,045		)	408,450		(257,597		)
Less comprehensive income attributable to noncontrolling interest	—			—			—		477			—		477
Comprehensive (loss) income attributable to NuStar Energy L.P.	$	(226,616	)	$	(352,222	)	$	112,836	$	(200,522	)	$	408,450	$	(258,074	)

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NUSTAR ENERGY L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Condensed Consolidating Statements of Cash Flows

For the Year Ended December 31, 2014

(Thousands of Dollars)



	NuStar Energy			NuStar Logistics			NuPOP			Non-Guarantor Subsidiaries			Eliminations			Consolidated
Net cash provided by operating activities	$	390,543		$	221,422		$	111,931		$	333,936		$	(539,309	)	$	518,523
Cash flows from investing activities:
Capital expenditures	—			(273,785		)	(14,625		)	(68,555		)	—			(356,965		)
Change in accounts payable related to capital expenditures	—			8,741			789			(4,627		)	—			4,903
Proceeds from sale or disposition of assets	—			651			22			25,339			—			26,012
Increase in note receivable from related party	—			(13,328		)	—			—			—			(13,328		)
Investment in subsidiaries	(23		)	—			13,340			—			(13,317		)	—
Other, net	23			(45		)	—			(831		)	—			(853		)
Net cash used in investing activities	—			(277,766		)	(474		)	(48,674		)	(13,317		)	(340,231		)
Cash flows from financing activities:
Debt borrowings	—			1,318,619			—			—			—			1,318,619
Debt repayments	—			(1,121,670		)	—			—			—			(1,121,670		)
Distributions to unitholders and general partner	(392,204		)	(245,127		)	(147,077		)	(147,105		)	539,309			(392,204		)
Contributions from (distributions to) affiliates	—			—			—			(13,340		)	13,340			—
Net intercompany borrowings (repayments)	1,680			83,387			35,620			(120,687		)	—			—
Other, net	—			(1,166		)	—			8,259			(23		)	7,070
Net cash (used in) provided by financing activities	(390,524		)	34,043			(111,457		)	(272,873		)	552,626			(188,185		)
Effect of foreign exchange rate changes on cash	—			—			—			(2,938		)	—			(2,938		)
Net increase (decrease) in cash and cash equivalents	19			(22,301		)	—			9,451			—			(12,831		)
Cash and cash equivalents as of the beginning of the period	904			22,307			—			77,532			—			100,743
Cash and cash equivalents as of the end of the period	$	923		$	6		$	—		$	86,983		$	—		$	87,912

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NUSTAR ENERGY L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Condensed Consolidating Statements of Cash Flows

For the Year Ended December 31, 2013

(Thousands of Dollars)



	NuStar Energy			NuStar Logistics			NuPOP			Non-Guarantor Subsidiaries			Eliminations			Consolidated
Net cash provided by operating activities	$	390,002		$	210,742		$	84,490		$	192,228		$	(392,243	)	$	485,219
Cash flows from investing activities:
Capital expenditures	—			(224,798		)	(19,049		)	(99,473		)	—			(343,320		)
Change in accounts payable related to capital expenditures	—			(9,700		)	824			3,492			—			(5,384		)
Proceeds from sale or disposition of assets	—			118,806			35			165			—			119,006
Increase in note receivable from related party	—			(80,961		)	—			—			—			(80,961		)
Investment in subsidiaries	(302		)	527			—			3			(228		)	—
Other, net	302			(604		)	—			—			—			(302		)
Net cash used in investing activities	—			(196,730		)	(18,190		)	(95,813		)	(228		)	(310,961		)
Cash flows from financing activities:
Debt borrowings	—			1,738,451			—			—			—			1,738,451
Debt repayments	—			(1,866,282		)	(250,000		)	(34,461		)	—			(2,150,743		)
Proceeds from note offerings, net of issuance costs	—			686,863			—			—			—			686,863
Distributions to unitholders and general partner	(392,204		)	(392,204		)	—			(39		)	392,243			(392,204		)
Payments for termination of interest rate swaps	—			(33,697		)	—			—			—			(33,697		)
Contributions from (distributions to) affiliates	—			302			—			(530		)	228			—
Net intercompany (repayments) borrowings	(3,880		)	(128,277		)	183,700			(51,543		)	—			—
Other, net	(47		)	2,027			—			—			—			1,980
Net cash (used in) provided by financing activities	(396,131		)	7,183			(66,300		)	(86,573		)	392,471			(149,350		)
Effect of foreign exchange rate changes on cash	—			—			—			(7,767		)	—			(7,767		)
Net (decrease) increase in cash and cash equivalents	(6,129		)	21,195			—			2,075			—			17,141
Cash and cash equivalents as of the beginning of the period	7,033			1,112			—			75,457			—			83,602
Cash and cash equivalents as of the end of the period	$	904		$	22,307		$	—		$	77,532		$	—		$	100,743

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NUSTAR ENERGY L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Condensed Consolidating Statements of Cash Flows

For the Year Ended December 31, 2012

(Thousands of Dollars)



	NuStar Energy			NuStar Logistics			NuPOP			Non-Guarantor Subsidiaries			Eliminations			Consolidated
Net cash provided by operating activities	$	363,639		$	86,333		$	81,700		$	149,369		$	(381,838	)	$	299,203
Cash flows from investing activities:
Capital expenditures	—			(292,873		)	(16,114		)	(101,608		)	—			(410,595		)
Acquisitions	—			(201,610		)	—			(114,200		)	—			(315,810		)
Investment in other long-term assets	—			—			—			(2,610		)	—			(2,610		)
Proceeds from sale or disposition of assets	—			441,442			4,537			32,947			—			478,926
Increase in note receivable from related party	—			(95,711		)	—			—			—			(95,711		)
Investment in subsidiaries	(337,123		)	(114,200		)	—			(34		)	451,357			—
Net cash used in investing activities	(337,123		)	(262,952		)	(11,577		)	(185,505		)	451,357			(345,800		)
Cash flows from financing activities:
Debt borrowings	—			2,621,025			—			—			—			2,621,025
Debt repayments	—			(2,470,355		)	(250,000		)	—			—			(2,720,355		)
Proceeds from note offering, net of issuance costs	—			247,398			—			—			—			247,398
Proceeds from issuance of common units, net of issuance costs	336,415			—			—			—			—			336,415
Contributions from general partner	7,121			—			—			—			—			7,121
Distributions to unitholders and general partner	(365,279		)	(365,279		)	—			(16,567		)	381,846			(365,279		)
Payments for termination of interest rate swaps	—			(5,678		)	—			—			—			(5,678		)
Contributions from (distributions to) affiliates	—			337,123			—			114,234			(451,357		)	—
Net intercompany borrowings (repayments)	2,254			(177,851		)	179,877			(4,272		)	(8		)	—
Other, net	(133		)	(9,845		)	—			—			—			(9,978		)
Net cash (used in) provided by financing activities	(19,622		)	176,538			(70,123		)	93,395			(69,519		)	110,669
Effect of foreign exchange rate changes on cash	—			1,179			—			854			—			2,033
Net increase in cash and cash equivalents	6,894			1,098			—			58,113			—			66,105
Cash and cash equivalents as of the beginning of the period	139			14			—			17,344			—			17,497
Cash and cash equivalents as of the end of the period	$	7,033		$	1,112		$	—		$	75,457		$	—		$	83,602

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NUSTAR ENERGY L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

28. QUARTERLY FINANCIAL DATA (UNAUDITED)

The following table summarizes quarterly financial data for the years ended December 31, 2014 and 2013:



	First Quarter			Second Quarter			Third Quarter			Fourth Quarter			Total
	(Thousands of Dollars, Except Per Unit Data)
2014:
Revenues	$	849,213		$	749,745		$	794,422		$	681,738		$	3,075,118
Operating income	$	81,103		$	89,354		$	95,098		$	81,346		$	346,901
Income from continuing operations	$	42,996		$	57,187		$	59,117		$	54,869		$	214,169
(Loss) income from discontinued operations, net of tax	(3,359		)	(1,788		)	2,831			(1,475		)	(3,791		)
Net income	$	39,637		$	55,399		$	61,948		$	53,394		$	210,378
Net income (loss) per unit applicable to limited partners:
Continuing operations	$	0.40		$	0.58		$	0.61		$	0.55		$	2.14
Discontinued operations	(0.04		)	(0.02		)	0.03			(0.01		)	(0.04		)
Total	$	0.36		$	0.56		$	0.64		$	0.54		$	2.10
Cash distributions per unit applicable to limited partners	$	1.095		$	1.095		$	1.095		$	1.095		$	4.380

2013:
Revenues	$	998,186		$	902,014		$	778,145		$	785,387		$	3,463,732
Operating income (loss)	$	63,358		$	76,972		$	68,751		$	(228,202	)	$	(19,121	)
Income (loss) from continuing operations	$	19,599		$	34,712		$	35,682		$	(275,502	)	$	(185,509	)
Income (loss) from discontinued operations, net of tax	4,805			(1,743		)	(2,446		)	(99,778		)	(99,162		)
Net income (loss)	$	24,404		$	32,969		$	33,236		$	(375,280	)	$	(284,671	)
Net income (loss) per unit applicable to limited partners:
Continuing operations	$	0.10		$	0.30		$	0.31		$	(3.60	)	$	(2.89	)
Discontinued operations	0.07			(0.02		)	(0.03		)	(1.13		)	(1.11		)
Total	$	0.17		$	0.28		$	0.28		$	(4.73	)	$	(4.00	)
Cash distributions per unit applicable to limited partners	$	1.095		$	1.095		$	1.095		$	1.095		$	4.380

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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, 2014.

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 report, 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 Controls 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, LLC (NuStar GP Holdings), the sole member of NuStar GP, LLC, selects the directors of NuStar GP, LLC (the Board). Officers of NuStar GP, LLC are appointed by its directors.

Set forth below is certain information concerning the directors and executive officers of NuStar GP, LLC, effective as of February 25, 2015.



Name	Age	Position Held with NuStar GP, LLC
William E. Greehey	78	Chairman of the Board
Bradley C. Barron	49	President, Chief Executive Officer and Director
J. Dan Bates	70	Director
Dan J. Hill	74	Director
Rodman D. Patton	71	Director
W. Grady Rosier	66	Director
Mary Rose Brown	58	Executive Vice President and Chief Administrative Officer
Thomas R. Shoaf	56	Executive Vice President and Chief Financial Officer
Jorge A. del Alamo	45	Senior Vice President and Controller
Amy L. Perry	46	Senior Vice President, General Counsel-Corporate & Commercial Law and Corporate Secretary
Karen M. Thompson	47	Senior Vice President and General Counsel-Litigation, Regulatory & Environmental

As a limited partnership, we are not required by the NYSE rules to have a nominating committee, and the Board has historically performed the functions served by 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. Patton. 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. In addition, we ask that our directors commit to working hard for our company. The Nominating/Governance & Conflicts Committee strives to find the best possible candidates to represent the interests of NuStar Energy L.P. and its unitholders. As part of its annual self-assessment process, the Board and each of its committees evaluates the mix of independent and non-independent directors, as well as the performance of the directors and the committees, and the Board annually elects a presiding director.

The Board is led by its Chairman, Mr. Greehey. The Board has determined that separating the roles of Chairman and CEO is in the best interest of unitholders at this time. In addition, the Board 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 CEO of Valero Energy from 1979 through December 2005, and President of Valero Energy from 1998 until January 2003.

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Mr. Barron became Chief Executive Officer, President 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 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. Patton became a director of NuStar GP, LLC in June 2001. He retired from Merrill Lynch & Co. in 1999 where he had served as Managing Director in the Energy Group since 1993. Prior to that, he served in investment banking and corporate finance positions with Credit Suisse First Boston (1981 - 1993) and Blyth Eastman Paine Webber (1971 - 1981). He also has served as a director of Apache Corporation since 1999 and is a member of its audit committee.

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 $44 billion 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 his appointment with NuStar GP, LLC.

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 to Valero Energy.

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.

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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 Counsel to Valero Energy.

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 within two business days. We believe that our executive officers, directors and greater than 10% unitholders timely filed all Section 16(a) reports during or with respect to the year ended December 31, 2014, except for one late Form 4 with respect to one transaction for Ms. Thompson, which was untimely due to an administrative oversight by NuStar Energy L.P.

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. 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 NuStar GP, LLC files with the SEC, compliance with applicable laws, rules and regulations, adherence to the code and reporting of violations of the code.

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. Patton and Mr. Rosier. The Board has determined that Mr. Bates and Mr. Patton are “audit committee financial experts” (as defined by the SEC), and that each of the members 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 2014. 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, 2014, 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 Statement on Auditing Standards No. 61, as amended (AICPA Professional Standards, Vol. 1 AU Section 380) as adopted by the PCAOB in Rule 3200T. 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.

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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, 2014.

Members of the Audit Committee:

J. Dan Bates (Chairman)

Dan J. Hill

Rodman D. Patton

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 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 approves and administers NuStar Energy’s equity compensation plans and incentive bonus plan. The Board has adopted a written charter for the Compensation Committee. The members of the Compensation Committee are Mr. Hill (Chairman), Mr. Bates, Mr. Patton 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 in 2014.

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

Rodman D. Patton

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 NuStar Energy’s and the executive’s 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, superior growth for our unitholders.

Compensation for our NEOs primarily consists of base salary, an annual incentive bonus and long-term, equity-based incentives. Our executives participate in the same group benefit programs available to our salaried employees in the United States. In addition, see “Post-Employment Benefits” below in this Compensation Discussion and Analysis. Our executives do not have employment or severance agreements, other than the change of control severance agreements described below 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 median practices of our peer companies and information from survey sources. 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 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.

Our NEOs for the year ended December 31, 2014 were: Bradley C. Barron, Thomas R. Shoaf, Mary Rose Brown, Amy L. Perry and Karen M. Thompson. On January 1, 2014, Mr. Barron, formerly Executive Vice President (EVP) & General Counsel (GC), was named President & Chief Executive Officer (CEO) and Thomas R. Shoaf, formerly Senior Vice President (SVP) & Controller, was named EVP & Chief Financial Officer (CFO). Also on January 1, 2014, Amy L. Perry, formerly Vice President

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(VP), Assistant GC-Corporate and Commercial Law & Corporate Secretary, was named SVP, GC-Corporate and Commercial Law & Corporate Secretary and Karen M. Thompson, formerly VP & Assistant GC-Litigation, was named SVP & GC-Litigation, Regulatory and Environmental.

Administration of Executive Compensation Programs

Our executive compensation programs are administered by our Board’s Compensation Committee. The Compensation Committee is composed of four independent directors who are not participants in our executive compensation programs. Policies adopted by the Compensation Committee are implemented by our compensation and benefits staff.

Annually, the Compensation Committee reviews market trends in compensation, including the practices of identified competitors, and the alignment of the compensation program with NuStar Energy’s strategy. Specifically, for executive officers, the Compensation Committee:


•	establishes and approves target compensation levels for each executive officer;


•	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 executives.

In making determinations about total compensation for executives, 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 executive’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 executive relative to the executive’s 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.

The Compensation Committee has retained BDO USA, LLP (BDO) as its independent compensation consultant for BDO’s expertise and guidance with respect to executive compensation matters. In its role as advisor to the Compensation Committee, BDO 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 Committee and BDO because BDO provides no other services to NuStar Energy; fees paid to BDO represent less than a fraction of 1% of BDO’s worldwide revenues; BDO has policies in place to prevent a conflict of interest, including a policy that no employee of BDO may own NuStar Energy units; and there is no business or personal relationship between BDO’s consultant and any of NuStar Energy’s officers or directors.

Selection of Compensation Comparative Data

The Compensation Committee has relied upon two primary sources of data in developing competitive market reference points for base salaries and annual cash incentive and long-term incentive targets: a group of master limited partnerships and other companies in our industry and broader survey data on comparably sized entities.

To establish compensation for the NEOs, including the CEO, the Compensation Committee, in consultation with management and BDO, identified a specific peer group to evaluate competitive levels of compensation. Historically, our peer group was composed of master limited partnerships and independent, regional refining companies against which we felt that we competed for executive talent at the time (the Historical Compensation Comparative Group). During 2013, we sold our refining assets and, during 2014, we sold our remaining 50% interest in the asphalt business. Accordingly, during 2014, the Compensation Committee, in consultation with management and BDO, reevaluated our peer group. Beginning in July 2014, our peer group (the Current Compensation Comparative Group) is composed entirely of master limited partnerships against which we believe we compete for executive talent. The competitive data for the companies in the Historical Compensation Comparative Group and the Current Compensation Comparative Group is derived from their respective publicly filed annual proxy statements or Annual Reports on Form 10-K.

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The companies included in the Historical Compensation Comparative Group are listed below:



Company	Ticker
1. Boardwalk Pipeline Partners, LP	BWP
2. Buckeye Partners L.P.	BPL
3. EnLink Midstream Partners, LP (formerly Crosstex Energy L.P.)	ENLK (formerly XTEX)
4. Enbridge Energy Partners, L.P.	EEP
5. Energy Transfer Partners, L.P.	ETP
6. Enterprise Product Partners L.P.	EPD
7. Kinder Morgan Energy Partners, L.P.	KMP
8. Magellan Midstream Partners, L.P.	MMP
9. MarkWest Energy Partners, L.P.	MWE
10. ONEOK Partners, L.P.	OKS
11. Plains All American Pipeline, L.P.	PAA
12. Regency Energy Partners LP	RGP
13. Sunoco Logistics Partners L.P.	SXL
14. HollyFrontier Corporation	HFC
15. Western Refining, Inc.	WNR

The companies included in the Current Compensation Comparative Group are listed below:



Company	Ticker
1. Access Midstream Partners LP	ACMP
2. Arc Logistics Partners LP	ARCX
3. Atlas Pipeline Partners, L.P.	APL
4. Boardwalk Pipeline Partners, LP	BWP
5. Buckeye Partners, L.P.	BPL
6. Enable Midstream Partners LP	ENBL
7. Enbridge Energy Partners, L.P.	EEP
8. Energy Transfer Partners L.P.	ETP
9. EnLink Midstream Partners, LP	ENLK
10. Enterprise Product Partners L.P.	EPD
11. Genesis Energy, L.P.	GEL
12. Holly Energy Partners, L.P.	HEP
13. Kinder Morgan Energy Partners LP	KMP
14. Magellan Midstream Partners, L.P.	MMP
15. MarkWest Energy Partners LP	MWE
16. MPLX LP	MPLX
17. Phillips 66 Partners LP	PSXP
18. Plains All American Pipeline, L.P.	PAA
19. Regency Energy Partners LP	RGP
20. Sunoco Logistics Partners L.P.	SXL
21. Targa Resources Partners LP	NGLS
22. Tesoro Logistics LP	TLLP
23. Valero Energy Partners LP	VLP
24. Western Refining Logistics LP	WNRL

Periodically, at the Compensation Committee’s request, BDO 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 executive positions reported in the Towers Watson General Industry Executive Compensation database, a proprietary

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compensation database of more than 400 U.S. industrial companies that is updated each year. We refer to the competitive survey data, together with the Historical 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 for the NEOs. Recommendations regarding compensation for NEOs other than the CEO are developed by the CEO in consultation with our Human Resources department and with BDO. In making these recommendations, the CEO considers the Compensation Comparative Data and evaluates the individual performance of each NEO and their respective contributions to the Company. The recommendations are then reviewed by the Compensation Committee, which may accept the recommendations or may make adjustments to the recommended compensation based on their own assessment of the individual’s performance and contributions to NuStar Energy.

As required by the Compensation Committee’s charter, the compensation of the CEO is reviewed and approved by the Compensation Committee based on the Compensation Comparative Data and other factors. Discretionary adjustments may be made based upon their independent evaluation of the CEO’s performance and contributions.

Each July, the Compensation Committee reviews the NEOs’ total 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 BDO, an evaluation of the total compensation of the executive officer group from an internal equity perspective and reviews of reports on the compensation history of each executive. Based on these reviews and evaluations, the Compensation Committee establishes annual salary rates for executive officer positions 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.

The following table summarizes the typical timing of some of our significant compensation events:



Event	Timing
Establish financial performance objectives for current year’s annual incentive bonus; evaluate achievement of bonus metrics in prior year	First quarter
Review and certify financial performance for performance units granted in prior years; grant performance units	First quarter
Review base salaries for executive officers for the current year and targets for annual incentive bonus and long-term incentive grants	Third quarter
Consider grants of restricted units to employees and officers and grant restricted units to directors	Fourth quarter
Set meeting dates for action by the Compensation Committee for the upcoming year	Fourth quarter

Additional information regarding the timing of 2014 long-term incentive grants is discussed below under “Performance Units” and “Restricted Units.”

Elements of Executive Compensation

Our executive compensation programs currently consist of the following material elements:


•	base salaries;


•	annual incentive bonuses;


•	long-term equity-based incentives, including:


•	performance units; and


•	restricted units; and


•	medical and other insurance benefits, retirement benefits and other perquisites.

We use base salary as the foundation for our executive compensation program. We believe that base salary should provide a fixed level of competitive pay that reflects the executive officer’s primary duties and responsibilities, as well as a foundation for incentive opportunities and benefit levels. Our annual incentive bonuses are designed to focus our executives on improving NuStar Energy’s distributable cash flow (DCF), a non-GAAP measure of financial performance, which is widely regarded among the master limited partnership (MLP) investment community as a significant determinant of an MLP’s unit price. Our long-term equity incentive awards are designed to directly tie an executive’s financial reward opportunities with the rewards to unitholders

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on both an absolute and relative basis, as measured by long-term unit price performance and payment of distributions. Throughout this Item 11, we use the term “Total Direct Compensation” to refer to the sum of an executive officer’s base salary, annual incentive bonus and long-term incentive awards for a particular fiscal year. We also offer group medical benefits to provide our employees (including 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 executive compensation, the Compensation Committee considers the aggregate amount of compensation payable to an executive officer 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 executive officers with those of our unitholders. The size of each element is based on competitive market practices, as well as company and individual performance.

The level of incentive compensation typically increases in relation to an executive officer’s responsibilities, with the level of incentive compensation for more senior executive officers being a greater percentage of total compensation than for less senior executives. The Compensation Committee believes that tying a significant portion of an executive officer’s incentive compensation to NuStar Energy’s performance more closely aligns the executive officer’s interests with those of our unitholders.

Because we place such a large proportion of our total executive 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.

The following table summarizes the relative size of base salary and incentive compensation targets for 2014 for each of our NEOs:



Name	Target Percentage of Total Direct Compensation
Name	Base Salary (%)	Annual Incentive Bonus (%)	Long-Term Incentives (%)	TOTAL (%) ⁽¹⁾
Barron	26	23	51	100
Shoaf	32	19	48	100
Brown	32	19	48	100
Perry	39	22	39	100
Thompson	39	22	39	100

(1) The sum of the Base Salary, Annual Incentive Bonus and Long-Term Incentive percentages may vary slightly from 100% due to rounding.

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 executive officer’s ability to lead, ability to communicate and successful adherence to NuStar’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.

We use our evaluation of individual performance to supplement our objective compensation criteria and adjust an executive officer’s recommended compensation. For example, although an individual officer’s indicated bonus may be calculated to be $100,000 based on NuStar Energy’s performance, an individual performance evaluation might result in a reduction or increase in that amount.

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Base Salaries

The base salaries for our executive officers are reviewed annually by the Compensation Committee based on recommendations of our CEO, with input from BDO and our compensation and benefits staff. Our CEO’s base salary is reviewed and approved by the Compensation Committee based on its review of recommendations by BDO, our Chairman and our compensation and benefits staff.

The competitiveness of base salaries for each executive position is determined by an evaluation of the compensation 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. Salaries are also periodically adjusted to remain competitive with the Compensation Comparative Data.

Based on recommendations from BDO, the Chairman (in the case of the CEO’s base salary) and the CEO (in the case of the base salaries for Mr. Shoaf, Ms. Perry and Ms. Thompson), the Compensation Committee raised the base salaries of each of Mr. Barron, Mr. Shoaf, Ms. Perry and Ms. Thompson effective January 1, 2014 to reflect their respective promotions and increased responsibilities, as provided in the table below.



Name	Annualized Base Salary at January 1, 2014 ($)	January 1, 2014 Increase to Prior Annualized Salary ($)
Barron	430,000	85,430
Shoaf	320,000	57,660
Perry	240,000	21,755
Thompson	240,000	22,068

In July 2014, BDO performed a comprehensive review of our NEOs’ Total Direct Compensation. After consultation with BDO, 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, 2014 to remain competitive with the Compensation Comparative Data, as provided in the table below.



Name	Annualized Base Salary at December 31, 2014 ($)	July 1, 2014 Increase to Prior Annualized Salary ($)
Barron	490,000	60,000
Shoaf	329,600	9,600
Brown	355,000	10,430
Perry	260,000	20,000
Thompson	260,000	20,000

Annual Incentive Bonus

Our NEOs participate in the annual incentive plan in which all domestic company employees participate. Under the 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 executive’s performance.

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The Compensation Committee raised the annual incentive bonus target of each of Mr. Barron, Mr. Shoaf, Ms. Perry and Ms. Thompson effective January 1, 2014 to reflect their respective promotions and increased responsibilities, as provided in the table below.



Name	Annual Incentive Bonus Target (% of Eligible Earnings) Effective January 1, 2014	Prior Annual Incentive Bonus Target (% of Eligible Earnings)
Barron	90	60
Shoaf	60	55
Perry	50	35
Thompson	50	35

In July 2014, BDO performed a comprehensive review of our NEOs’ Total Direct Compensation. After consultation with BDO and the CEO, the Compensation Committee raised the annual incentive bonus targets for Ms. Perry and Ms. Thompson from 50% to 55%. The following table shows each NEO’s annual bonus target for the fiscal year ended December 31, 2014.



Name	Annual Incentive Bonus Target (% of Eligible Earnings)
Barron	90
Shoaf	60
Brown	60
Perry	55
Thompson	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 bonus plan. For example, in a year with a 100% score, an executive paid $200,000 and a target annual incentive opportunity equal to 60% of his Eligible Earnings would receive a bonus of $120,000.

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, and other considerations. This discretionary judgment may result in an increase or decrease in the aggregate earned award for all employees based upon the attainment of the financial goals noted above.

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 executive bonus on a case-by-case basis, considering such factors as teamwork, leadership, individual accomplishments and initiative, and may adjust the bonus awarded 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 based upon its independent evaluation of the CEO’s performance and contributions.

Company Performance Objectives

In 2014, as in prior years, the Compensation Committee approved a DCF-based metric for NuStar Energy’s bonus metric, based on management’s recommendations and input from BDO. In the MLP investment community, DCF is widely regarded as a significant determinant of unit price. As such, the Compensation Committee believes the measure appropriately aligns our management’s interest with our unitholders’ interest in continuously increasing distributions in a prudent manner.

We derive DCF from our financial statements by adjusting our net income for depreciation and amortization expense, equity earnings from joint ventures and unrealized gains and losses arising from certain derivative contracts. Additionally, we subtract our aggregate annual reliability capital expenditures and add the aggregate annual amount of cash distributions received from equity investments in joint ventures.

Each year, the Compensation Committee establishes a target DCF for NuStar Energy to achieve for the year and establishes corresponding levels of performance for which the incentive opportunity would be paid. The Compensation Committee has

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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. For 2014, the Compensation Committee determined that a bonus pool for all employees would be established with DCF in excess of the amount needed to attain a distribution coverage ratio of 1.0 times. After achieving a 100% bonus, incremental DCF earned would be divided between the bonus pool and NuStar Energy until employees achieve a 200% bonus.

Determination of Awards

For the 2014 annual incentive bonus determination, the Compensation Committee reviewed NuStar Energy’s DCF against the established target of attaining a coverage ratio of 1.0 times and considered the performance of each officer to determine the amount of incentive award earned. Based on this review, the Compensation Committee set the bonus award for our NEOs at 165%. Actual bonuses awarded are shown in the following table:



Name	Bonuses Paid For 2014 ($)
Barron	683,100
Shoaf	321,552
Brown	346,287
Perry	226,875
Thompson	226,875

Long-Term Incentive Awards

We provide unit-based, long-term incentive compensation for employees, including executives, and directors through our Fourth Amended and Restated 2000 Long-Term Incentive Plan (the 2000 LTIP), effective as of January 1, 2014. The 2000 LTIP provides for a variety of unit and unit-based awards, including unit options, restricted units and performance units. Performance units vest (become nonforfeitable) upon the achievement of an objective performance goal. Long-term incentive awards vest over a period determined by the Compensation Committee.

Under the design of our long-term incentive awards, each plan participant, including each NEO, is designated a target long-term incentive award expressed as a percentage of base salary. This percentage reflects the fair value of the awards to be granted.

The Compensation Committee raised the long-term incentive targets for 2014 (expressed as a percent of base salary) for each of Mr. Barron, Mr. Shoaf, Ms. Perry and Ms. Thompson effective January 1, 2014 to reflect their respective promotions and increased responsibilities, as provided in the table below.



Name	Long-Term Incentive Target (% of Base Salary) Effective January 1, 2014	Prior Long-Term Incentive Target (% of Base Salary)
Barron	175	125
Shoaf	125	110
Perry	60	39
Thompson	60	39

In July 2014, BDO performed a comprehensive review of our NEOs’ Total Direct Compensation. After consultation with BDO, the Chairman (in the case of the CEO’s long-term incentive target) and the CEO (in the case of the long-term incentive targets for each other NEO), the Compensation Committee raised the long-term incentive target for each of our NEOs. The following table shows each NEO’s long-term incentive target for 2014 (expressed as a percent of base salary).



Name	Long-Term Incentive Target (% of base salary)
Barron	200
Shoaf	150
Brown	150
Perry	100
Thompson	100

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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. Beginning with the long-term incentive award in the fourth quarter of 2011, the target levels were allocated in the following manner for each individual:


•	35% of the targeted long-term incentive dollar value is awarded to the executive in a grant of performance units. The number of performance units granted is based upon the expected fair value of a single performance unit at the time of grant; and


•	65% of the targeted long-term incentive dollar value is awarded to the executive in the form of restricted units. The number of restricted units granted is based upon the expected fair value of a single restricted unit at the time of grant.

The Compensation Committee reviews and approves grants for the NEOs. The CEO develops individual grant recommendations 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 based upon its independent evaluation of the CEO’s performance and contributions.

Restricted Units

Restricted units comprise approximately 65% of each executive’s total NuStar Energy long-term incentive target. The Compensation Committee presently expects to grant restricted units annually. The executives’ long-term incentive targets include approximately 70% NuStar Energy restricted units and 30% NuStar GP Holdings restricted units (in both cases, calculated from an assumed unit value based on the average closing price for the first 10 business days of the month prior to the Compensation 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. 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. The annual grants of NuStar GP Holdings restricted units, as well as the annual grants of the 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.

In 2014, the Compensation Committee and management made a determination that the grants for employees, including management, and non-employee directors 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 2014 annual grants were not effective until December 19, 2014.



Name	Restricted Units Granted in 2014
Name	NuStar Energy	NuStar GP Holdings
Barron	7,155	4,805
Shoaf	3,610	2,425
Brown	3,885	2,610
Perry ⁽¹⁾	2,000	1,275
Thompson ⁽¹⁾	2,150	1,275


(1)	The grants of NuStar Energy restricted units in 2014 include 100 units and 250 units granted to Ms. Perry and Ms. Thompson, respectively, on January 1, 2014 as special recognition for their 2013 performance prior to their promotions.

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Performance Units

Performance units comprise approximately 35% of each of our NEOs’ total NuStar Energy long-term incentive targets and typically have been granted in January of each year. 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.

For performance unit awards granted prior to 2014, the objective performance measure is tied to NuStar Energy’s total unitholder return (TUR), as compared with the Historical Compensation Comparative Group. NuStar Energy’s TUR is the total return to unitholders, based upon the growth in the unit price, as well as cash distributions to unitholders, during the year. Each award is subject to vesting in three annual increments, based upon our TUR during rolling three-year periods that end on December 31 of each year following the date of grant. At the end of each performance period, our TUR is compared to the Historical Compensation Comparative Group and ranked by quartile. Executives then earn 0%, 50%, 100% or 150% of that portion of the initial grant amount that is eligible for vesting, depending upon whether our TUR is in the last, 3rd, 2nd or 1st quartile, respectively, and they earn 200% if we rank highest in the group. Amounts not earned in a given performance period can be carried forward for one additional performance period and up to 100% of the carried amount can still be earned, depending upon the quartile achieved for that subsequent period.

For 2014, the Compensation Committee delayed consideration of the annual performance unit awards until completion of BDO’s comprehensive review of our NEOs’ Total Direct Compensation. After consultation with BDO and management regarding the appropriate performance metric to use for the performance unit awards, the Compensation Committee adopted a different performance metric for the 2014 performance unit awards. As described above, in the MLP investment community, distribution coverage is widely regarded as a significant determinant of unit price. BDO’s review reflected the fact that cash flow metrics are the most common measures that MLPs use to determine the vesting of performance unit awards. The Compensation Committee believes that distribution coverage appropriately aligns our management’s interest with our unitholders’ interest in increasing distributions in a prudent manner over time.

In July, the Compensation Committee determined that the target performance measure for the 2014 performance unit awards is NuStar Energy achieving a distribution coverage ratio, after taking into account the aggregate expense of the performance units (DCR), of 1:1 for 2014. The target metric for performance unit vesting with respect to 2015 and each year thereafter will be the DCR determined by the Compensation Committee in the first quarter of the year, based on the approved budget for that year. The Compensation Committee also may designate one or more DCRs that are above the targeted DCR as goals that will be used to determine vesting greater than 100% (up to 200%) of an officer’s performance units available for vesting in that year. Each award is subject to vesting in three annual increments, based upon our DCR during the one-year periods that end on December 31 of each year following the date of grant. Notwithstanding anything above, the Committee has full discretion to increase the vesting determination for any officer (up to the 200% cap).

The number of performance units granted in July 2014 was determined by multiplying annual base salary rate by the long-term incentive target percentage, and then multiplying that product by 35%. That product is then divided by the assumed value of an individual unit, which is the product of (x) the average unit price for the period of December 15 through December 31 (using the daily closing prices) and (y) a factor that reflects the present value of the award and a risk that the award might be forfeited.



Name	Performance Unit Grants in 2014
Barron	8,000
Shoaf	4,284
Brown	4,614
Perry	2,142
Thompson	2,142

On January 29, 2015, the Compensation Committee met and discussed NuStar Energy’s performance for the performance period ended December 31, 2014, and determined that NuStar Energy’s TUR was in the third quartile of its peer group for that three-year performance period. As a result, the performance units granted in 2011, 2012 and 2013 that were available to vest for the performance period ending on December 31, 2014 vested at 50%, in accordance with the award terms. On January 29, 2015, the Compensation Committee also determined that NuStar Energy achieved a DCR of 1:1 for 2014 and, in accordance with the award terms, the performance units available to vest for the 2014 awards vested at 100%.

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Perquisites and Other Benefits

Perquisites

We provide only minimal perquisites to our executive officers. Mr. Barron, Mr. Shoaf and Ms. Brown received federal income tax preparation services in 2014. Executives also are eligible to receive personal liability insurance. 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 conditions. 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. Executive officers 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 plans, as well as the Excess Pension Plan, please see the narrative description accompanying the Pension Benefits table below in this Item 11.

Nonqualified Deferred Compensation Plan (Excess Thrift Plan)

The Excess Thrift Plan provides unfunded benefits to those employees of NuStar GP, LLC whose annual additions under the Thrift Plan are subject to the limitations on such annual additions as provided 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 which 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 ($260,000 for 2014), 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 reduced pursuant to §401; and


•	The actual company matching contributions credited to such participant’s account.

Mr. Barron, Mr. Shoaf and Ms. Brown participated in the Excess Thrift Plan in 2014.

Change of Control Severance Arrangements

We entered into change of control severance agreements with each of the NEOs in, or prior to, 2007. These agreements are intended to assure 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, which terms are automatically extended for one year upon each anniversary unless a notice not to extend is given by us. 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 executive’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 of us.

Particular payments under the agreements are triggered commensurate with the occurrence of any of the following: (1) termination of employment by the company other than for “cause” (as defined in the agreements) or disability; (2) termination by the executive for “good reason” (as defined in the agreements); (3) termination by the executive other than for “good reason;” and (4) termination of employment because of death or disability. These triggers were designed to ensure the continued availability of the executives following a change of control, and to compensate the executives at appropriate levels if their employment is unfairly or prematurely terminated during the applicable term following a change of control. For more information regarding payments that may be made under our change of control severance arrangements, see our disclosures below under the caption “Potential Payments upon Termination or Change of Control.”

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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 does not follow 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, as applicable, the defined contribution, defined benefit, medical or long-term incentive plans.

Impact of Accounting and Tax Treatments

Accounting Treatment

NuStar Energy’s financial statements include the expense for awards of NuStar Energy unit options, restricted units and performance units to NuStar GP, LLC employees and directors and the expense for awards of NuStar GP Holdings unit options and restricted units to NuStar GP, LLC employees, as we are obligated to pay for all costs of NuStar GP, LLC’s employees working on our behalf in accordance with the Services Agreement described below in Item 13. Under the Services Agreement, 1% of NuStar GP, LLC’s domestic unit compensation expense is charged back to NuStar GP Holdings.

NuStar GP, LLC accounts for awards of NuStar Energy common unit options, restricted units and performance units to NuStar GP, LLC’s employees and directors at fair value as a derivative, whereby a liability for the award is recorded at inception. Subsequent changes in the fair value of the award are included in the determination of net income. NuStar GP, LLC determines the fair value of unit options using the Black-Scholes model at each reporting date. The fair value of restricted units and performance units equals the market price of NuStar Energy common units at each reporting date. However, performance units are earned only upon NuStar Energy’s achievement of an objective performance measure. NuStar GP, LLC records compensation expense each reporting period such that the cumulative compensation expense recorded equals the current fair value of the percentage of the award that has vested. NuStar GP, LLC records compensation expense related to unit options until such options are exercised, and records compensation expense for restricted units until the date of vesting.

NuStar GP Holdings accounts for awards of NuStar GP Holdings restricted units and unit options awarded to its directors, as well as the employees and directors of NuStar GP, LLC, at fair value. NuStar GP Holdings uses the market price at the grant date as the fair value of restricted units. NuStar GP Holdings estimates the fair value of unit options at the grant date using the Black-Scholes model. For both restricted units and unit options, NuStar GP Holdings recognizes the resulting compensation expense ratably over the vesting period.

Tax Treatment

Under Section 162(m) of the Code, publicly held corporations may not take a tax deduction for compensation in excess of $1 million paid to the CEO or the other four most highly compensated executive officers unless that compensation meets the Code’s definition of “performance-based” compensation. Section 162(m) allows a deduction for compensation to a specified executive that exceeds $1 million only if it is paid (1) solely upon attainment of one or more performance goals, (2) pursuant to a qualifying performance-based compensation plan adopted by the Compensation Committee and (3) the material terms, including the performance goals, of such plan are approved by the unitholders before payment of the compensation. The Compensation Committee considers deductibility under Section 162(m) with respect to compensation arrangements for executive officers.

Although Section 162(m) does not now apply to master limited partnerships, if a similar limitation were to be applied to NuStar Energy, the Compensation Committee believes that it would be in the company’s best interest for the Compensation Committee to retain its flexibility and discretion to make compensation awards to foster achievement of performance goals established by the Compensation Committee (which may include performance goals defined in the Code) and other corporate goals the Compensation Committee deems important to NuStar Energy’s success, such as encouraging employee retention, rewarding achievement of non-quantifiable goals and achieving progress with specific projects. The Compensation Committee believes that unit options and performance unit grants qualify as performance-based compensation and, therefore, would not be subject to any deductibility limitations under an applicable section similar to Section 162(m). Grants of restricted units and other equity-based awards that are not subject to specific quantitative performance measures will likely not qualify as “performance-based” compensation and, in such event, would be subject to such deduction restrictions.

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Compensation-Related Policies

Unit Ownership Guidelines

Our Board, the Compensation Committee and management recognize that ownership of NuStar Energy units is an effective means by which to align the interests of NuStar GP, LLC 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 NuStar GP, LLC directors and officers to ensure continuation of our successful track record in aligning the interests of NuStar GP, LLC directors and officers with those of NuStar Energy’s unitholders through ownership of NuStar Energy units. The guidelines were approved by the Compensation Committee in January 2006. In view of the public offerings of units of NuStar GP Holdings in 2006, the guidelines were amended to include ownership of either NuStar GP Holdings units or NuStar Energy units.

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 $50,000. 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.

Officer Unit Ownership Guidelines

Unit ownership guidelines for officers of NuStar GP, LLC are as follows:



Officer	Value of NuStar Energy Units and/or NuStar GP Holdings Units Owned
Chief Executive Officer, President or any Executive Vice Presidents	3.0x Base Salary
Senior Vice Presidents	2.0x Base Salary
Vice Presidents	1.0x Base Salary

Our officers are expected to meet the applicable guideline within five years of their initial appointment and continuously own sufficient units to meet the guideline, once attained.

Prohibition on Insider Trading and Speculation on 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, which includes 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 are also required to receive 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.

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,” NuStar Energy’s compensation programs are structured so that a considerable amount of our management’s compensation is tied to NuStar Energy’s long-term fiscal health. The only short-term incentive available to NuStar Energy employees and executives is the all-employee performance bonus. All bonuses, including executive bonuses, are determined with reference to well-defined performance metrics selected by the Compensation Committee and applicable to all employees. Historically, our long-term incentives have taken the form of performance units, restricted units and unit options that typically vest over three- and five-year periods, which we believe serves to align our employees’ interests with

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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 metric selected by the Compensation Committee. As such, we believe that our compensation policies encourage employees to operate our business in a fundamentally sound manner and do not create incentives to take risks that are reasonably likely to have a material adverse effect on NuStar Energy.

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, 2014, December 31, 2013 and December 31, 2012 to NuStar GP, LLC’s CEO, CFO and to its three other most highly compensated executive officers serving during 2014. Mr. Shoaf, Ms. Perry and Ms. Thompson were not executive officers prior to 2014 and, accordingly, their compensation is reported only with respect to 2014. For each NEO, the table shows amounts earned for services rendered to NuStar GP, LLC in all capacities in which the NEO served during the periods presented for that NEO.



Name and Principal Position	Year	Salary ($)	Bonus ($)⁽¹⁾	Unit Awards ($)⁽²⁾	Option Awards ($)	Non-Equity Incentive Plan Compensation ($)	Change in Pension Value and Nonqualified Deferred Compensation Earnings ($)⁽³⁾	All Other Compensation ($)⁽⁴⁾	Total ($)
Bradley C. Barron President and CEO	2014	460,000	683,100	1,086,708	—	—	147,448	29,815	2,407,071
	2013	327,160	125,000	530,915	—	—	2,328	21,818	1,007,221
	2012	304,875	—	503,574	—	—	134,758	19,483	962,690
Thomas R. Shoaf Executive Vice President and CFO	2014	324,800	321,552	564,231	—	—	142,990	21,703	1,375,276
Mary Rose Brown Executive Vice President and Chief Administrative Officer	2014	349,785	346,287	607,456	—	—	136,213	23,202	1,462,943
	2013	345,983	110,000	546,876	—	—	48,510	24,302	1,075,671
	2012	329,265	—	547,821	—	—	127,380	22,400	1,026,866
Amy L. Perry Senior Vice President, General Counsel-Corporate and Commercial Law & Corporate Secretary	2014	250,000	226,875	294,772	—	—	51,525	8,865	832,037
Karen M. Thompson Senior Vice President and General Counsel-Litigation, Regulatory & Environmental	2014	250,000	226,875	302,421	—	—	68,726	16,466	864,488

(1)

Bonus amounts for 2014 were paid in February 2015 with respect to 2014 performance. Bonus amounts for 2013 were paid in February 2014 with respect to 2013 performance. The NEOs were not awarded bonuses for 2012. Bonuses were determined taking into consideration NuStar Energy’s performance in the applicable year, the individual executive’s targets and the executive’s performance, as described above under “Compensation Discussion and Analysis-Annual Incentive Bonus.” For an explanation of the amount of salary and bonus in proportion to total compensation, see “Compensation Discussion and Analysis-Relative Size of Primary Elements of Compensation.”

(2)

The amounts reported represent the grant date fair value of grants of NuStar Energy restricted units, NuStar Energy performance units and NuStar GP Holdings restricted units. Please see “Compensation Discussion and Analysis-Impact of Accounting and Tax Treatments-Accounting Treatment” above in this Item 11 and the footnotes to the Grants of Plan-Based Awards During the Year Ended December 31, 2014 table below in this Item 11 for information regarding the assumptions made in the valuation.

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(3)

The following table identifies the separate amounts attributable to (A) the aggregate change in the actuarial present value of the NEOs’ accumulated benefit under NuStar GP, LLC’s defined benefit and actuarial pension plans, including supplemental plans (but excluding tax-qualified defined contribution plans and nonqualified defined contribution plans), and (B) above-market or preferential earnings on compensation that is deferred on a basis that is not tax-qualified.



Name	Year	(A) ($)		(B) ($)	TOTAL ($)
Barron	2014		147,448	—		147,448
	2013	2,328		—	2,328
	2012	134,758		—	134,758
Shoaf	2014	142,990		—	142,990
Brown	2014	136,213		—	136,213
	2013	48,510		—	48,510
	2012	127,380		—	127,380
Perry	2014	51,525		—	51,525
Thompson	2014	68,726		—	68,726

(4) The amounts reported in this column for 2014 consist of the following for each officer:



Name	Company Contribution to Thrift Plan ($)	Company Contribution to Excess Thrift Plan ($)	Tax Preparation ($)	Personal Liability Insurance ($)	Executive Health Exams ($)^(a)	TOTAL ($)
Barron	15,600	12,000	850	1,365	—	29,815
Shoaf	15,600	3,888	850	1,365	—	21,703
Brown	13,887	7,100	850	1,365	—	23,202
Perry	7,500	—	—	1,365	—	8,865
Thompson	14,433	—	—	—	2,033	16,466


(a)	The amount reported is the difference between the value of executive health exams made available to NuStar Energy officers and the value of NuStar Energy’s all-employee wellness assessments.

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GRANTS OF PLAN-BASED AWARDS

DURING THE YEAR ENDED DECEMBER 31, 2014

The following table provides information regarding the grants of plan-based awards to the NEOs during 2014.



Name	Grant Date		Date of Approval of Compensation Committee	Estimated Future Payouts Under Equity Incentive Plan Awards			All Other Unit Awards: Number of Units (#)	All Other Option Awards: Number of Securities Underlying Options (#)	Exercise or Base Price of Option Awards ($/Unit)	Grant Date Fair Value of Unit and Unit Option Awards ($)
Name	Grant Date		Date of Approval of Compensation Committee	Threshold (#)	Target (#)	Maximum (#)	All Other Unit Awards: Number of Units (#)		Exercise or Base Price of Option Awards ($/Unit)	Grant Date Fair Value of Unit and Unit Option Awards ($)
Barron	7/23/2014	⁽¹⁾	7/23/2014	—	8,000	16,000	—	—	—		514,160	⁽⁵⁾
	12/19/2014	⁽²⁾	10/29/2014	—	—	—	7,155	—	—		408,121	⁽⁶⁾
	12/19/2014	⁽³⁾	10/29/2014	—	—	—	4,805	—	—		164,427	⁽⁷⁾
Shoaf	7/23/2014	⁽¹⁾	7/23/2014	—	4,284	8,568	—	—	—	275,333		⁽⁵⁾
	12/19/2014	⁽²⁾	10/29/2014	—	—	—	3,610	—	—	205,914		⁽⁶⁾
	12/19/2014	⁽³⁾	10/29/2014	—	—	—	2,425	—	—	82,984		⁽⁷⁾
Brown	7/23/2014	⁽¹⁾	7/23/2014	—	4,614	9,228	—	—	—	296,542		⁽⁵⁾
	12/19/2014	⁽²⁾	10/29/2014	—	—	—	3,885	—	—	221,600		⁽⁶⁾
	12/19/2014	⁽³⁾	10/29/2014	—	—	—	2,610	—	—	89,314		⁽⁷⁾
Perry	1/1/2014	⁽⁴⁾	⁽⁴⁾	—	—	—	100	—	—	5,099		⁽⁸⁾
	7/23/2014	⁽¹⁾	7/23/2014	—	2,142	4,284	—	—	—	137,666		⁽⁵⁾
	12/19/2014	⁽²⁾	10/29/2014	—	—	—	1,900	—	—	108,376		⁽⁶⁾
	12/19/2014	⁽³⁾	10/29/2014	—	—	—	1,275	—	—	43,631		⁽⁷⁾
Thompson	1/1/2014	⁽⁴⁾	⁽⁴⁾	—	—	—	250	—	—	12,748		⁽⁸⁾
	7/23/2014	⁽¹⁾	7/23/2014	—	2,142	4,284	—	—	—	137,666		⁽⁵⁾
	12/19/2014	⁽²⁾	10/29/2014	—	—	—	1,900	—	—	108,376		⁽⁶⁾
	12/19/2014	⁽³⁾	10/29/2014	—	—	—	1,275	—	—	43,631		⁽⁷⁾

(1)

Performance units were awarded by the Compensation Committee on July 23, 2014 pursuant to the 2000 LTIP. Each award is subject to vesting in three annual increments, based upon our DCR during the one-year performance periods that end on December 31 of each year following the date of grant. For the 2014 performance unit awards, the target performance measure is NuStar Energy achieving a DCR of 1:1 for 2014. The target metric for performance unit vesting with respect to 2015 and each year thereafter will be the DCR determined by the Compensation Committee in the first quarter of the year, based on the approved budget for that year. The Compensation Committee also may designate one or more DCRs that are above the targeted DCR as goals that will be used to determine vesting greater than 100% (up to 200%) of an officer’s performance units available for vesting in that year. Notwithstanding anything above, the Compensation Committee has full discretion to increase the vesting determination for any officer (up to the 200% cap). For the performance period ended December 31, 2014, we achieved a DCR of 1:1 and the performance units available to vest for the 2014 awards vested at 100%.

(2)

Restricted units of NuStar Energy were approved by the Compensation Committee at a joint meeting with the Compensation Committee of NuStar GP Holdings on October 29, 2014, 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 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, provided that such amounts are subject to the same restrictions as the restricted units.


(3)	Restricted units of NuStar GP Holdings were approved by the Compensation Committee of NuStar GP Holdings at a joint meeting with the Compensation Committee of NuStar GP, LLC on October 29, 2014, 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

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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 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, provided that such amounts are subject to the same restrictions as the restricted units.

(4)

On January 1, 2014, Ms. Perry and Ms. Thompson received grants of NuStar Energy units pursuant to the 2000 LTIP as special recognition for their 2013 performance prior to their promotions. Due to the nature of the special awards, the units were 100% vested on the date of grant. The CEO awarded each grant prior to Ms. Perry and Ms. Thompson becoming executive officers, pursuant to delegated authority to him by the Compensation Committee, and the grants were not separately approved by the Compensation Committee.


(5)	The grant date fair value for performance units was determined by multiplying the number of performance units that were granted by the NYSE closing unit price of our units on the date of grant, $64.27. See “Compensation Discussion and Analysis-Impact of Accounting and Tax Treatments-Accounting Treatment” above in this Item 11 for information regarding the assumptions made in valuation.


(6)	The grant date fair value for restricted units was determined by multiplying the number of restricted units that were granted by the NYSE closing unit price of our units on the date of grant, $57.04. See “Compensation Discussion and Analysis-Impact of Accounting and Tax Treatments-Accounting Treatment” above in this Item 11 for information regarding the assumptions made in valuation.

(7)

The grant date fair value for restricted units was determined by multiplying the number of NuStar GP Holdings restricted units that were granted by the NYSE closing unit price of NuStar GP Holdings units on the date of grant, $34.22. See “Compensation Discussion and Analysis-Impact of Accounting and Tax Treatments-Accounting Treatment” above in this Item 11 for information regarding the assumptions made in valuation.

(8)

The grant date for these restricted units was not a trading day on the NYSE. Accordingly, the grant date fair value was determined by multiplying the number of restricted units that were granted by the NYSE closing unit price of our units on the last business day before the date of grant, $50.99. See “Compensation Discussion and Analysis-Impact of Accounting and Tax Treatments-Accounting Treatment” above in this Item 11 for information regarding the assumptions made in valuation.

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OUTSTANDING EQUITY AWARDS

AT DECEMBER 31, 2014

The following table provides information regarding our NEOs’ unexercised unit options, unvested restricted units and unvested performance units as of December 31, 2014. The value of NuStar Energy restricted units and performance units reported below is equal to the number of restricted units or performance units, as applicable, multiplied by $57.75, the NuStar Energy closing price on the NYSE on December 31, 2014. The value of the NuStar GP Holdings restricted units reported below is equal to the number of restricted units multiplied by $34.42, the NuStar GP Holdings closing price on the NYSE on December 31, 2014.



	Option Awards					Unit Awards
Name	Number of Securities Underlying Unexercised Options (#) Exercisable	Number of Securities Underlying Unexercised Options (#) Unexercisable	Equity Incentive Plan Awards: Number of Securities Underlying Unexercised Unearned Options (#)	Option Exercise Price ($)	Option Expiration Date	Number of Units That Have Not Vested (#)	Market Value of Units That Have Not Vested ($)	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	—	—	—	—	—	—	—	14,428⁽¹²⁾	833,217
	—	—	—	—	—	15,378⁽²⁾	888,080	—	—
	—	—	—	—	—	10,357⁽³⁾	356,488	—	—
Shoaf	2,825⁽¹⁾	—	—	57.51	10/27/2015	—	—	—	—
	—	—	—	—	—	—	—	8,505⁽¹³⁾	491,164
	—	—	—	—	—	8,711⁽⁴⁾	503,060	—	—
	—	—	—	—	—	5,913⁽⁵⁾	203,525	—	—
Brown	—	—	—	—	—	—	—	11,581⁽¹⁴⁾	668,803
	—	—	—	—	—	12,504⁽⁶⁾	722,106	—	—
	—	—	—	—	—	8,400⁽⁷⁾	289,128	—	—
Perry	—	—	—	—	—	—	—	2,142⁽¹⁵⁾	123,701
	—	—	—	—	—	5,576⁽⁸⁾	322,014	—	—
	—	—	—	—	—	1,275⁽⁹⁾	43,886	—	—
Thompson	—	—	—	—	—	—	—	2,142⁽¹⁶⁾	123,701
	—	—	—	—	—	5,456⁽¹⁰⁾	315,084	—	—
	—	—	—	—	—	1,275⁽¹¹⁾	43,886	—	—


(1)	Mr. Shoaf’s options granted on October 27, 2005 vested in 1/5 increments over five years, beginning on the first anniversary of the date of grant. In 2012, the Compensation Committee extended the expiration date for these options from 2012 to 2015.

(2)

Mr. Barron’s restricted NuStar Energy units consist of: 491 restricted units granted December 30, 2010; 1,256 restricted units granted December 16, 2011; 606 restricted units granted January 26, 2012; 2,070 restricted units granted December 19, 2012; 3,800 restricted units granted December 16, 2013; and 7,155 restricted units granted December 19, 2014. The restricted units granted January 26, 2012 vest in 1/3 increments over three years, beginning on the first anniversary of the date of grant. All of Mr. Barron’s other 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: 410 restricted units granted December 30, 2010; 956 restricted units granted December 16, 2011; 1,434 restricted units granted December 19, 2012; 2,752 restricted units

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granted December 16, 2013; and 4,805 restricted units granted December 19, 2014. 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 restricted NuStar Energy units consist of: 235 restricted units granted December 30, 2010; 618 restricted units granted December 16, 2011; 296 restricted units granted January 26, 2012; 1,404 restricted units granted December 19, 2012; 2,548 restricted units granted December 16, 2013; and 3,610 restricted units granted December 19, 2014. The restricted units granted January 26, 2012 vest in 1/3 increments over three years, beginning on the first anniversary of the date of grant. All of Mr. Shoaf’s other restricted units vest in 1/5 increments over five years, beginning on the first anniversary of the date of grant.

(5)

Mr. Shoaf’s restricted NuStar GP Holdings units consist of: 200 restricted units granted December 30, 2010; 472 restricted units granted December 16, 2011; 972 restricted units granted December 19, 2012; 1,844 restricted units granted December 16, 2013; and 2,425 restricted units granted December 19, 2014. 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.

(6)

Ms. Brown’s restricted NuStar Energy units consist of: 550 restricted units granted December 30, 2010; 1,356 restricted units granted December 16, 2011; 675 restricted units granted January 26, 2012; 2,238 restricted units granted December 19, 2012; 3,800 restricted units granted December 16, 2013; and 3,885 restricted units granted December 19, 2014. The restricted units granted January 26, 2012 vest in 1/3 increments over three years, beginning on the first anniversary of the date of grant. All of Ms. Brown’s other restricted units vest in 1/5 increments over five years, beginning on the first anniversary of the date of grant.

(7)

Ms. Brown’s restricted NuStar GP Holdings units consist of: 458 restricted units granted December 30, 2010; 1,032 restricted units granted December 16, 2011; 1,548 restricted units granted December 19, 2012; 2,752 restricted units granted December 16, 2013; and 2,610 restricted units granted December 19, 2014. 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.

(8)

Ms. Perry’s restricted NuStar Energy units consist of: 270 restricted units granted December 30, 2010; 570 restricted units granted December 16, 2011; 1,116 restricted units granted December 19, 2012; 1,720 restricted units granted December 16, 2013; and 1,900 restricted units granted December 19, 2014. All of Ms. Perry’s restricted units vest in 1/5 increments over five years, beginning on the first anniversary of the date of grant.


(9)	Ms. Perry’s restricted NuStar GP Holdings units consist of 1,275 restricted units granted December 19, 2014. Ms. Perry’s NuStar GP Holdings restricted units vest in 1/5 increments over five years, beginning on the first anniversary of the date of grant.

(10)

Ms. Thompson’s restricted NuStar Energy units consist of: 270 restricted units granted December 30, 2010; 570 restricted units granted December 16, 2011; 996 restricted units granted December 19, 2012; 1,720 restricted units granted December 16, 2013; and 1,900 restricted units granted December 19, 2014. All of Ms. Thompson’s restricted units vest in 1/5 increments over five years, beginning on the first anniversary of the date of grant.


(11)	Ms. Thompson’s restricted NuStar GP Holdings units consist of 1,275 restricted units granted December 19, 2014. Ms. Thompson’s NuStar GP Holdings restricted units vest in 1/5 increments over five years, beginning on the first anniversary of the date of grant.


(12)	Mr. Barron’s unvested NuStar Energy performance units consist of: 525 units granted January 28, 2011; 1,970 units granted April 24, 2012; 3,933 units granted January 30, 2013; and 8,000 units granted July 23, 2014.

The performance units awarded in 2011, 2012 and 2013 are eligible to vest in three annual increments and are payable in NuStar Energy’s units. Upon vesting, the performance units are converted into a number of NuStar Energy units based on NuStar Energy’s TUR during rolling three-year periods that end of December 31 of each year following the date of grant. At the end of each performance period, NuStar Energy’s TUR is compared to the peer group and ranked by quartile. Holders of the performance units then earn 0%, 50%, 100% or 150% of that portion of the initial grant that is eligible for vesting, depending upon whether NuStar Energy’s TUR is in the last, third, second or first quartile, respectively. Holders earn 200% if NuStar Energy is the highest ranking entity in the peer group. For the periods ended December 31, 2011, December 31, 2012 and December 31, 2013, NuStar’s TUR was in the last quartile of its peer group, which resulted in no vesting for participants. For the performance period ended December 31, 2014, NuStar’s TUR was in the third quartile of its peer group, which resulted in 50% vesting of the units eligible to vest under the 2011, 2012 and 2013 performance unit awards.

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The performance units awarded in 2014 are eligible to vest in three annual increments and are payable in NuStar Energy’s units. Upon vesting, the performance units are converted into a number of NuStar Energy units based upon NuStar Energy’s DCR during the one-year performance periods that end on December 31 of each year following the date of grant. For the 2014 performance unit awards, the target performance measure is NuStar Energy achieving a DCR of 1:1 for 2014. The target metric for performance unit vesting with respect to 2015 and each year thereafter will be the DCR determined by the Compensation Committee in the first quarter of the year, based on the approved budget for that year. The Compensation Committee also may designate one or more DCRs that are above the targeted DCR as goals that will be used to determine vesting greater than 100% (up to 200%) of an officer’s performance units available for vesting in that year. Notwithstanding anything above, the Compensation Committee has full discretion to increase the vesting determination for any officer (up to the 200% cap). For the performance period ended December 31, 2014, NuStar Energy achieved a DCR of 1:1 and the performance units available to vest under the 2014 awards vested at 100%.


(13)	Mr. Shoaf’s unvested NuStar Energy performance units consist of: 251 units granted January 28, 2011; 970 units granted April 24, 2012; 3,000 units granted January 30, 2013; and 4,284 units granted July 23, 2014. The performance units vest in accordance with the description in Footnote (12) above.


(14)	Ms. Brown’s unvested NuStar Energy performance units consist of: 589 units granted January 28, 2011; 2,130 units granted April 24, 2012; 4,248 units granted January 30, 2013; and 4,614 units granted July 23, 2014. The performance units vest in accordance with the description in Footnote (12) above.


(15)	Ms. Perry’s unvested NuStar Energy performance units consist of 2,142 units granted July 23, 2014. The performance units vest in accordance with the description in Footnote (12) above.


(16)	Ms. Thompson’s unvested NuStar Energy performance units consist of 2,142 units granted July 23, 2014. The performance units vest in accordance with the description in Footnote (12) above.

OPTION EXERCISES AND UNITS VESTED

DURING THE YEAR ENDED DECEMBER 31, 2014

The following table provides information regarding option exercises by our NEOs, and the vesting of restricted units and performance units held by our NEOs, during 2014.



	Option Awards		Unit Awards
Name	Number of Units Acquired on Exercise (#)	Value Realized on Exercise ($)⁽⁴⁾	Number of Units Acquired on Vesting (#)	Value Realized on Vesting ($)⁽¹⁰⁾
Barron	36,975⁽¹⁾	485,889	6,241⁽⁵⁾	286,938
Shoaf	25,700⁽²⁾	122,846	3,576⁽⁶⁾	164,490
Brown	35,000⁽³⁾	470,750	6,698⁽⁷⁾	308,071
Perry	—	—	1,749⁽⁸⁾	96,101
Thompson	—	—	1,859⁽⁹⁾	103,097


(1)	Mr. Barron exercised 1,975 NuStar Energy unit options and 35,000 NuStar GP Holdings unit options on July 28, 2014.


(2)	Mr. Shoaf exercised 25,700 NuStar GP Holdings unit options on November 14, 2014.


(3)	Ms. Brown exercised 35,000 NuStar GP Holdings unit options on July 28, 2014.

(4)

For exercises of NuStar Energy unit options, the value realized on exercise was calculated by multiplying the number of NuStar Energy units to which the option exercise related by the difference between the price of NuStar Energy units on the NYSE at the time of exercise and the option exercise price. For exercises of NuStar GP Holdings unit options, the value realized on exercise was calculated by multiplying the number of NuStar GP Holdings units to which the option exercise related by the difference between the price of NuStar GP Holdings units on the NYSE at the time of exercise and the option exercise price.


(5)	Mr. Barron's NuStar Energy units vested in 2014 as follows: 606 units on January 26, 2014; 423 units on December 14, 2014; 1,578 units on December 16, 2014; 690 units on December 19, 2014; and 491 units on December 30, 2014. Mr.

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Barron's NuStar GP Holdings units vested in 2014 as follows: 399 units on December 14, 2014; 1,166 units on December 16, 2014; 478 units on December 19, 2014; and 410 units on December 30, 2014.

(6)

Mr. Shoaf’s NuStar Energy units vested in 2014 as follows: 295 on January 26, 2014; 211 units on December 14, 2014; 946 units on December 16, 2014; 468 units on December 19, 2014; and 235 units on December 30, 2014. Mr. Shoaf’s NuStar GP Holdings units vested in 2014 as follows: 200 units on December 14, 2014; 697 units on December 16, 2014; 324 units on December 19, 2014; and 200 units on December 30, 2014.

(7)

Ms. Brown’s NuStar Energy units vested in 2014 as follows: 675 on January 26, 2014; 474 units on December 14, 2014; 1,628 units on December 16, 2014; 746 units on December 19, 2014; and 550 units on December 30, 2014. Ms. Brown’s NuStar GP Holdings units vested in 2014 as follows: 447 units on December 14, 2014; 1,204 units on December 16, 2014; 516 units on December 19, 2014; and 458 units on December 30, 2014.


(8)	Ms. Perry’s NuStar Energy units vested in 2014 as follows: 100 on January 1, 2014; 292 units on December 14, 2014; 715 units on December 16, 2014; 372 units on December 19, 2014; and 270 units on December 30, 2014.


(9)	Ms. Thompson’s NuStar Energy units vested in 2014 as follows: 250 on January 1, 2014; 292 units on November 6, 2014; 715 units on December 16, 2014; 332 units on December 19, 2014; and 270 units on December 30, 2014.

(10)

The value realized on vesting of NuStar Energy restricted units was calculated by multiplying the closing price of NuStar Energy 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 units on the NYSE on the date of vesting by the number of NuStar GP Holdings units vested. The closing prices on the applicable dates are as follows:



2014 Restricted Unit Vesting
Date	NuStar Energy Closing Price ($)
December 31 , 2013 (for January 1, 2014 vesting)	50.99
January 26, 2014	48.23
November 6, 2014	60.10
December 14, 2014	54.52
December 16, 2014	53.82
December 19, 2014	57.04
December 30, 2014	56.97
Date	NuStar GP Holdings Closing Price ($)
December 14, 2014	32.45
December 16, 2014	33.45
December 19, 2014	34.22
December 30, 2014	34.35

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POST-EMPLOYMENT COMPENSATION

PENSION BENEFITS

FOR THE YEAR ENDED DECEMBER 31, 2014

The following table provides information regarding the accumulated benefits of our NEOs under NuStar GP, LLC’s pension plans during the year ended December 31, 2014.



Name	Plan Name	Number of Years Credited Service	Present Value of Accumulated Benefit ($)⁽¹⁾	Payments During Last Fiscal Year ($)
Barron	NuStar GP, LLC Pension Plan	⁽²⁾	244,268	—
Barron	NuStar GP, LLC Excess Pension Plan	⁽²⁾	281,669	—
Shoaf	NuStar GP, LLC Pension Plan	⁽²⁾	332,824	—
Shoaf	NuStar GP, LLC Excess Pension Plan	⁽²⁾	289,425	—
Brown	NuStar GP, LLC Pension Plan	⁽²⁾	324,725	—
Brown	NuStar GP, LLC Excess Pension Plan	⁽²⁾	266,334	—
Perry	NuStar GP, LLC Pension Plan	⁽²⁾	132,853	—
Perry	NuStar GP, LLC Excess Pension Plan	⁽²⁾	21,825	—
Thompson	NuStar GP, LLC Pension Plan	⁽²⁾	206,059	—
Thompson	NuStar GP, LLC Excess Pension Plan	⁽²⁾	24,511	—

(1)

The present values stated in the table above were calculated using the same interest rate and mortality table we use for our financial reporting. The present values as of December 31, 2014 were determined using a 4.22% discount rate and the plans’ earliest unreduced retirement age (i.e., age 62). The present values reflect post-retirement mortality rates based on the RP2014 generational mortality table projected using scale MP2014. No decrements were included for pre-retirement termination, mortality or disability. Where applicable, lump sums were determined based on a 3.72% 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 2009-2015.

(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.



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	NuStar GP, LLC Pension Plan	7.5	14.0
Barron	NuStar GP, LLC Excess Pension Plan	13.0	14.0
Shoaf	NuStar GP, LLC Pension Plan	7.5	29.5
Shoaf	NuStar GP, LLC Excess Pension Plan	28.5	29.5
Brown	NuStar GP, LLC Pension Plan	6.7	17.3
Brown	NuStar GP, LLC Excess Pension Plan	6.7	17.3
Perry	NuStar GP, LLC Pension Plan	7.5	12.0
Perry	NuStar GP, LLC Excess Pension Plan	7.5	12.0
Thompson	NuStar GP, LLC Pension Plan	6.7	12.7
Thompson	NuStar GP, LLC Excess Pension Plan	11.7	12.7

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We maintain a noncontributory defined benefit 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, 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.

NuStar GP, LLC 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 NuStar GP, LLC’s employees and generally provides retirement income calculated under a cash balance formula (CBF), which is based on age, years of service and interest credits. Employees become fully vested in their CBF benefits upon attaining three years of 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. 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.

NuStar GP, LLC Excess Pension Plan

The Excess Pension Plan, which became effective July 1, 2006, provides benefits to eligible employees of NuStar GP, LLC 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 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 employees of NuStar GP, LLC 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 this Excess Pension Plan.

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 service for service through December 31, 2013 plus the employee’s CBF benefits for service after December 31, 2013, less


•	the employee’s Pension Plan benefit.

All of our NEOs participated in the Excess Pension Plan during 2014.

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NONQUALIFIED DEFERRED COMPENSATION

FOR THE YEAR ENDED DECEMBER 31, 2014

The following table provides information regarding contributions by NuStar GP, LLC and each of our NEOs under our non-qualified defined contribution plan during the year ended December 31, 2014. The table also presents each NEOs withdrawals, earnings and year-end balances in such plan. Please see the description of our Excess Thrift Plan above in “Compensation Discussion and Analysis-Post-Employment Benefits.”



Name	Executive Contributions in 2014 ($)⁽¹⁾	Registrant Contributions in 2014 ($)⁽²⁾	Aggregate Earnings in 2014 ($)⁽³⁾	Aggregate Withdrawals/ Distributions ($)	Aggregate Balance at December 31, 2014 ($)⁽⁴⁾
Barron	—	12,000	5,977	—	46,415
Shoaf	—	3,888	30	—	1,823
Brown	—	7,100	8,293	—	52,190
Perry	—	—	—	—	—
Thompson	—	—	—	—	—


(1)	The NEOs made no contributions during 2014.


(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 2014 in the Summary Compensation Table.


(3)	Amounts include the earnings (excluding dividends, if any), if any, of the NEO’s respective account in our Excess Thrift Plan.


(4)	Amounts include the aggregate balance at year end, if any, of the NEO’s respective account in our Excess Thrift Plan.

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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, 2014” and “Nonqualified Deferred Compensation For The Year Ended December 31, 2014” 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 follow 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 NuStar GP, LLC. These agreements seek to assure the continued availability of these executives in the event of a “change of control” (described below) of NuStar Energy. 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.

When a change of control occurs, the agreement becomes operative for a fixed three-year period. The agreements provide generally that the executive’s terms of employment will not be adversely changed during the three-year period after a change of control. In addition, outstanding unit options held by the executive will automatically vest, restrictions applicable to outstanding restricted units held by the executive will lapse and all unvested performance units held by the executive will fully vest and become payable at 200% of target. Certain of the executives also are entitled to receive a payment in an amount sufficient to make the executive 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 executive to obligations of confidentiality, both during the term and after termination, for secret and confidential information relating to NuStar Energy, NuStar GP, LLC and their affiliates (as defined in the agreement) that the executive acquired during his or her employment.

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 affiliates;


•	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;


•	sale of all or substantially all of the assets of NuStar GP Holdings to anyone other than its affiliates;


•	sale of all or substantially all of the assets of NuStar Energy to anyone other than its affiliates; or


•	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 agreement.

In the agreements, “cause” is defined to mean, generally, the willful and continued failure of the executive to perform substantially the executive’s duties, or the willful engaging by the executive in illegal or gross misconduct that is materially and demonstrably injurious to NuStar Energy, NuStar GP, LLC or an affiliate. “Good reason” is defined to mean, generally:


•	a diminution in the executive’s position, authority, duties and responsibilities;


•	failure of the successor of NuStar Energy to assume and perform under the agreement; and


•	relocation of the executive or increased travel requirements.

Except as otherwise noted, the values in the table below assume that a change of control occurred on December 31, 2014 and that the NEO’s employment terminated on that date.

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Under the change of control severance agreements, if an executive officer’s employment is terminated for “cause” following a change of control, the officer 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, if any. Therefore, there is no presentation of termination for “cause” in the table below.



Executive Benefits and Payments	Termination of Employment by the Company 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		980,000		—		—		—
Shoaf	659,200		—		—		—
Brown	710,000		—		—		—
Perry	390,000		—		—		—
Thompson	390,000		—		—		—
Bonus ⁽¹⁾
Barron		1,366,200		683,100		683,100		—
Shoaf	643,104		321,552		321,552		—
Brown	692,574		346,287		346,287		—
Perry	340,313		226,875		226,875		—
Thompson	340,313		226,875		226,875		—
Pension and Excess Pension Benefits
Barron		131,682		—		—		—
Shoaf	129,392		—		—		—
Brown	151,434		—		—		—
Perry	38,103		—		—		—
Thompson	43,006		—		—		—
Contributions under Defined Contribution Plans
Barron		55,200		—		—		—
Shoaf	38,976		—		—		—
Brown	41,974		—		—		—
Perry	11,250		—		—		—
Thompson	21,650		—		—		—
Health and Welfare Plan Benefits ⁽⁶⁾
Barron		27,479		—		—		—
Shoaf	37,510		—		—		—
Brown	23,564		—		—		—
Perry	18,040		—		—		—
Thompson	28,132		—		—		—

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Executive Benefits and Payments	Termination of Employment by the Company 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	—		—		—		—
Perry	—		—		—		—
Thompson	—		—		—		—
Accelerated Vesting of Restricted Units ⁽⁷⁾
Barron		1,244,567		1,244,567		1,244,567		1,244,567
Shoaf	706,586		706,586		706,586		706,586
Brown	1,011,234		1,011,234		1,011,234		1,011,234
Perry	365,900		365,900		365,900		365,900
Thompson	358,970		358,970		358,970		358,970
Accelerated Vesting of Performance Units ⁽⁸⁾
Barron		1,666,434		1,666,434		1,666,434		1,666,434
Shoaf	982,328		982,328		982,328		982,328
Brown	1,337,606		1,337,606		1,337,606		1,337,606
Perry	247,401		247,401		247,401		247,401
Thompson	247,401		247,401		247,401		247,401
280G Tax Gross-Up ⁽⁹⁾
Barron		2,146,296		—		—		—
Shoaf	1,235,956		—		—		—
Brown	1,369,537		—		—		—
Perry	—		—		—		—
Thompson	—		—		—		—
Totals
Barron		7,617,858		3,594,101		3,594,101		2,911,001
Shoaf	4,433,052		2,010,466		2,010,466		1,688,914
Brown	5,337,923		2,695,127		2,695,127		2,348,840
Perry	1,411,007		840,176		840,176		613,301
Thompson	1,429,472		833,246		833,246		606,371

(1)

Per SEC regulations, for purposes of this analysis we assumed each executive’s compensation at the time of each triggering event to be as stated below. The listed salary is the executive’s actual annualized rate of pay as of December 31, 2014. The listed bonus amount represents the highest bonus earned by the executive in any of the fiscal years 2012, 2013 and 2014 (the three years prior to the assumed change of control):



Name	Annual Salary ($)	Bonus ($)
Barron	490,000	683,100
Shoaf	329,600	321,552
Brown	355,000	346,287
Perry	260,000	226,875
Thompson	260,000	226,875

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(2)	The change of control severance agreements provide that if the company terminates the executive officer’s employment (other than for “cause,” death or “disability,” as defined in the agreement) or if the executive officer terminates his or her employment for “good reason,” as defined in the agreement, the executive is generally entitled to receive the following:

(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 (for this table, we assumed that the executive officers’ bonuses for the year of termination were paid at year end);


(ii)	two times the sum of the executive officer’s (1.5 times for Ms. Perry and Ms. Thompson) annual base salary plus the executive officer’s highest annual bonus from the past three years;


(iii)	the amount of the excess of the actuarial present value of the pension benefits (qualified and nonqualified) the executive would have received for an additional two years (1.5 years for Ms. Perry and Ms. Thompson) of service over the actuarial present value of the executive officer’s actual pension benefits; and


(iv)	the equivalent of two years (1.5 years for Ms. Perry and Ms. Thompson) of employer contributions under NuStar GP, LLC’s tax-qualified and supplemental defined contribution plans;

(B) continued welfare benefits for two years (1.5 years for Ms. Perry and Ms. Thompson); and

(3)

If the executive’s employment is terminated by reason of his 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 bonus earned by the executive in the prior three years (prorated to the date of termination). In this example, the termination of employment was deemed to occur on the last day of the year. Therefore, a full year’s bonus is shown in the table. In addition, in the case of disability, the executive would be entitled to any disability and related benefits at least as favorable as those provided by NuStar GP, LLC under its plans and programs during the 120-days prior to the executive’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 executive voluntarily terminates his 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 bonus earned by the executive in the prior three years (prorated to the date of termination). In this example, the termination of employment was deemed to occur on the last day of the year. Therefore, a full year’s bonus is shown in the table. 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 agreements provide for a three-year term of employment following a change of control. The agreements generally provide that the executive will continue to enjoy compensation and benefits on terms at least as favorable as in effect prior to the change of control. In addition, all outstanding equity incentive awards will automatically vest on the date of the change of control, as described above.


(6)	The executive is entitled to coverage under the welfare benefit plans (e.g., health, dental, etc.) for two years (1.5 years for Ms. Perry and Ms. Thompson) following the date of termination.

(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) $57.75 (the closing price of NuStar Energy’s units on the NYSE on December 31, 2014) or $34.42 (the closing price of NuStar GP Holdings’ units on the NYSE on December 31, 2014).


(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) $57.75 (the closing price of NuStar Energy’s units on the NYSE on December 31, 2014).

(9)

If any payment or benefit to Mr. Barron, Mr. Shoaf or Ms. Brown is determined to be subject to an excise tax under Section 4999 of the Code, the impacted executive 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 executive is entitled to receive an additional payment to adjust for the incremental tax cost but the value of all payments to the executive does not exceed 100% of 2.99 times the executive’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 executive 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, 2014

The following table provides a summary of compensation paid for the year ended December 31, 2014 to the Board. The table shows amounts earned by such persons for services rendered to NuStar GP, LLC in all capacities in which they served.



Name	Fees Earned or Paid in Cash ($)⁽¹⁾	Unit Awards ($)⁽³⁾	Option Awards ($)⁽³⁾	Non-Equity Incentive Plan Compensation ($)	Change in Pension Value and Nonqualified Deferred Compensation Earnings ($)	All Other Compensation ($)	TOTAL ($)
William E. Greehey	118,083	99,991	—	—	n/a	—	218,074
Bradley C. Barron	⁽²⁾	⁽²⁾	⁽²⁾	⁽²⁾	⁽²⁾	⁽²⁾	⁽²⁾
J. Dan Bates	84,583	74,951	—	—	n/a	—	159,534
Dan J. Hill	91,333	74,951	—	—	n/a	—	166,284
Rodman D. Patton	106,333	74,951	—	—	n/a	—	181,284
W. Grady Rosier	76,333	74,951	—	—	n/a	—	151,284


(1)	The amounts disclosed in this column exclude reimbursement for expenses for commercial transportation to and from Board meetings and lodging while attending meetings.


(2)	Mr. Barron was not compensated for his service as a director of NuStar GP, LLC. His compensation for his services as President and CEO are included above in the Summary Compensation Table.

(3)

The amounts reported represent the grant date fair value for the December 19, 2014 grant of restricted NuStar Energy units to our non-employee directors for the fiscal year ended December 31, 2014 (1,753 restricted units for Mr. Greehey, as Chairman, and 1,314 restricted units for each of the other non-employee directors) based on the closing price of NuStar Energy’s units on the NYSE on December 19, 2014 ($57.04). Please see “Compensation Discussion and Analysis-Impact of Accounting and Tax Treatments-Accounting Treatment” above in this Item 11 for information regarding the assumptions made in the valuation.

As of December 31, 2014, each director holds the following aggregate number of NuStar Energy restricted unit and option awards:



Name	Aggregate # of Restricted Units	Aggregate # of Unit Options
Greehey	3,711	—
Barron	*	*
Bates	2,757	—
Hill	2,757	—
Patton	2,757	—
Rosier	3,180	—

* Mr. Barron’s aggregate holdings are disclosed above in the Outstanding Equity Awards at December 31, 2014 table in this Item 11.

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. Directors who are employees of NuStar GP, LLC receive no compensation (other than reimbursement of expenses) for serving as directors.

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During 2014, BDO conducted a comprehensive review of the compensation for our non-employee directors. Based on that review, in July 2014, the Compensation Committee recommended and the Board approved revisions to the compensation for our non-employee directors beginning in August 2014, as described below.



Non-Employee Director Compensation Component	Prior to August 2014		Beginning in August 2014
Annual Cash Retainer ($)		55,000	60,000
Annual Restricted Unit Grant ($ value of restricted units)	70,000		75,000
Per Meeting Fees (in-person attendance) ($)		1,250	1,500
Per Meeting Fees (telephonic attendance) ($)		500	500
Annual Audit and Compensation Committee Chair Retainers ($)		10,000	15,000
Annual Nominating, Governance and Conflicts Committee Chair Retainer ($)		10,000	10,000
Annual Chairman of the Board Retainer ($25,000 of value in restricted units/$50,000 cash)		75,000	75,000
Annual Lead Director Retainer ($)		n/a	15,000

As described above, NuStar GP, LLC supplements 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 units. Upon a non-employee director’s initial election to the Board, the director will receive a grant of restricted units equal to the pro-rated amount of the annual grant of restricted units from the time of his or her election through the next annual grant of restricted units.

In the event of a “change of control” as defined in the 2000 LTIP, all unvested restricted units and unit options previously granted immediately become vested or exercisable. Each plan also contains anti-dilution provisions providing for an adjustment in the number of restricted units or unit options, respectively, that have been granted to prevent dilution of benefits in the event any change in the capital structure of NuStar Energy affects the NuStar Energy units.

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. Patton and Mr. Rosier. None of the members of our Compensation Committee have served as an officer or employee of NuStar GP, LLC. Furthermore, except for compensation arrangements disclosed in this Annual Report on Form 10-K, NuStar Energy has not participated in any contracts, loans, fees, awards or 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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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 ownership of NuStar Energy L.P. units and NuStar GP Holdings, LLC units on December 31, 2014 by the directors and executive officers of NuStar GP, LLC as of February 25, 2015. 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.



Name of Beneficial Owner ⁽¹⁾	NuStar Energy Units Beneficially Owned ⁽²⁾	NuStar Energy Units under Exercisable Options ⁽³⁾	Percentage of Outstanding NuStar Energy Units ⁽⁴⁾	NuStar GP Holdings Units Beneficially Owned ⁽⁵⁾	Percentage of Outstanding NuStar GP Holdings Units⁽⁶⁾
William E. Greehey	2,671,366	—	3.43%	8,213,774	19.14%
Bradley C. Barron	28,977	—	*	29,299	*
J. Dan Bates	22,400	—	*	2,000	*
Dan J. Hill	19,992	—	*	11,000	*
Rodman D. Patton	27,447	—	*	15,000	*
W. Grady Rosier	18,113	—	*	—	*
Mary Rose Brown	44,603	—	*	49,233	*
Thomas R. Shoaf	17,228	2,825	*	13,773	*
Jorge A. del Alamo	10,750	—	*	1,225	*
Amy L. Perry ⁽⁷⁾	6,327	—	*	1,275	*
Karen M. Thompson	11,322	—	*	1,275	*
All directors and executive officers as a group (11 people)	2,878,525	2,825	3.70%	8,337,854	19.43%

* 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)

This column includes restricted units issued under the long-term incentive plans of NuStar GP, LLC. Restricted units granted under NuStar GP, LLC’s long-term incentive plans are rights to receive NuStar Energy units upon vest and, as such, may not be disposed of or voted until vested. The column does not include units that could be acquired under options, which information is set forth in the next column.


(3)	This column discloses units that may be acquired within 60 days of December 31, 2014 through the exercise of unit options.


(4)	As of December 31, 2014, 77,886,078 NuStar Energy units were issued and outstanding. There are no classes of equity securities of NuStar Energy outstanding other than the units. The calculation for “Percentage of Outstanding NuStar Energy Units” includes units listed under the captions “NuStar Energy Units Beneficially Owned” and “NuStar Energy Units under Exercisable Options.”


(5)	This column includes restricted units issued under the long-term incentive plan of NuStar GP Holdings. Restricted units granted under NuStar GP Holdings’ long-term incentive plan are rights to receive NuStar GP Holdings units upon vest and, as such, may not be disposed of or voted until vested.


(6)	As of December 31, 2014, 42,913,277 NuStar GP Holdings units were issued and outstanding. There are no classes of equity securities of NuStar GP Holdings outstanding other than the units.


(7)	Ms. Perry was divorced in September 2012 and, as a part of the settlement, Ms. Perry agreed to give her ex-spouse a portion of any NuStar Energy units she would receive in the future upon vesting of restricted units that were granted to her prior to September 2012 (in 2007 through 2011) and remained outstanding at the time of the divorce.

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SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS

Except as otherwise indicated, the following table sets forth certain information as of December 31, 2014 with respect to each entity known to us to be the beneficial owner of more than 5% of NuStar Energy’s outstanding units.



Name and Address of Beneficial Owner	Units	Percentage of Units ⁽⁴⁾
NuStar GP Holdings ⁽¹⁾	10,248,179	13.2%
Oppenheimer Funds, Inc. ⁽²⁾	7,771,109	10.0%
ALPS Advisors, Inc. ⁽³⁾	4,155,451	5.3%


(1)	NuStar GP Holdings owns the units through its wholly owned subsidiaries, NuStar GP, LLC and Riverwalk Holdings, LLC. NuStar GP Holdings controls voting and investment power of the units through these wholly owned subsidiaries. NuStar GP Holdings’ business address is 19003 IH-10 West, San Antonio, Texas 78257.

(2)

As reported on a Schedule 13G filed on January 30, 2015, Oppenheimer Funds, Inc. (OFI) is an investment adviser that may be deemed to beneficially own, and has shared voting and dispositive power with respect to, 7,771,109 units. The 7,771,109 units that OFI may be deemed to beneficially own include 6,208,932 units that Oppenheimer SteelPath MLP Income Fund (OSP), an investment company, may be deemed to beneficially own. OSP has shared voting and dispositive power with respect to the 6,208,932 units. OFI disclaims beneficial ownership of the units pursuant to Rule 13d-4 of the Securities Exchange Act of 1934. OPI’s business address is Two World Financial Center, 225 Liberty Street, New York, New York 10281. OSP’s business address is 6803 S. Tucson Way, Centennial, Colorado 80112.

(3)

As reported on a Schedule 13G filed on February 17, 2015, 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, 4,155,451 units. The 4,155,451 units that AAI may be deemed to beneficially own include 4,143,307 units that Alerian MLP ETF (Alerian) may be deemed to beneficially own. Alerian has shared voting and dispositive power with respect to the 4,143,307 units. AAI disclaims beneficial ownership of the 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.


(4)	Assumes 77,886,078 units outstanding.

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EQUITY COMPENSATION PLAN INFORMATION

The following table sets forth information about NuStar GP, LLC’s equity compensation plans as of December 31, 2014, which are described in further detail in Note 20 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 ⁽³⁾	Weighted-average exercise price of outstanding unit options, warrants and rights ($) ⁽⁴⁾	Number of securities remaining for future issuance under equity compensation plans
Equity Compensation Plans approved by security holders ⁽¹⁾	669,906	57.44	1,441,988
Equity Compensation Plans not approved by security holders ⁽²⁾	63,584	57.51	—


(1)	The information in this row relates to NuStar GP, LLC’s Fourth Amended and Restated 2000 Long-Term Incentive Plan.


(2)	The information in this row relates to NuStar GP, LLC’s 2003 Employee Unit Incentive Plan, which terminated on June 16, 2013, and NuStar GP, LLC’s 2002 Unit Option Plan, which terminated on March 22, 2012.

(3)

Grants under NuStar GP, LLC’s long-term incentive plans do not dilute the interests of NuStar Energy unitholders. Upon the vesting of a restricted unit or performance unit or the exercise of a unit option granted under NuStar GP, LLC’s plan, NuStar GP, LLC purchases NuStar Energy units on the open market to satisfy that vesting or exercise. No new NuStar Energy units are issued to satisfy the vesting of restricted units or performance units or the exercises of unit options.


(4)	The information in this column includes only the exercise price for unit options. No value is included in this column for restricted units or performance units because they do not have an exercise price.

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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 or director; (2) any 5% or greater unitholder of NuStar Energy, its controlled affiliates or NuStar GP Holdings; (3) any immediate family member of any officer or director; or (4) any entity controlled by any of (1), (2) or (3) (or in which any of (1), (2) or (3) owns more than 5%) 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 our Corporate Secretary of his or her immediate family members, as well as any entities in which he or she controls or owns more than 5%.

Please see “Potential Payments upon Termination or Change of Control” in Item 11 for a discussion of NuStar Energy’s 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 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.

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). The Services Agreement provides that NuStar GP, LLC will furnish all services necessary for the conduct of the business of NuStar Energy, and NuStar Energy will reimburse 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 Holdco Services Expense). The Holdco Services Expense is equal 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. For fiscal year 2014, the Holdco Services Expense was equal to $1.7 million. The Holdco Services Expense is subject to adjustment (a) by an annual amount equal to NuStar GP, LLC’s annual merit increase percentage for the most recently completed contract year and (b) 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 December 31, 2014, the Services Agreement automatically renewed for a two-year term and will continue to renew automatically for two-year terms unless terminated by either party on six months’ written notice.

John D. Greehey, a NuStar 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 a subsidiary of NuStar Energy L.P. In 2014, Mr. J. Greehey did not attend any Board or Committee meetings. The aggregate value of compensation paid by NuStar to Mr. J. Greehey in 2014 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.

Garrett Brown, a NuStar employee, is the son of Mary Rose Brown, Executive Vice President and Chief Administrative Officer. As such, he is deemed to be a “related person” under Item 404(a) of the SEC’s Regulation S-K. Mr. Brown works in the Corporate Communications department at NuStar, as a Government Relations Coordinator. In 2014, Mr. Brown did not attend any Board or Committee meetings. The aggregate value of compensation paid by NuStar to Mr. Brown in 2014 was less than $500,000. There were no material differences between the compensation paid to Mr. Brown and the compensation paid to any other employees who hold analogous positions.

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RIGHTS OF NUSTAR GP HOLDINGS

Due to its ownership of NuStar GP, LLC and Riverwalk Holdings, LLC, as of December 31, 2014, NuStar GP Holdings indirectly owned:


•	the 2% 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, currently at the maximum percentage of 23%; and


•	10,248,179 NuStar Energy L.P. units representing 13.2% of the issued and outstanding 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, 2014, owned 19.1% 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 have reasonably 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 one hand, and NuStar Energy, on the other hand.

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 2014, the Board held six 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 of which he was a member.

Independent Directors

The Board has one member of management, Mr. Barron, President and CEO, 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 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. Patton 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, 2014, owned 19.1% of NuStar GP Holdings. Mr. Greehey is not an independent director under the NYSE’s listing standards.

Mr. Barron has been President and CEO of NuStar GP, LLC since January 2014. Mr. Barron also serves as President and CEO 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 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.

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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.

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, 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 internet website at www.nustarenergy.com (in the “Investor Relations” 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 of Senior Financial Officers and the Charters of the Audit Committee, Compensation Committee and Nominating/Governance & Conflicts Committee on NuStar Energy’s internet website at www.nustarenergy.com (in the “Investor Relations” 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, 2014 and 2013 were:



Category of Service	2014		2013
Audit fees ⁽¹⁾	$	2,433,000	$2,433,000
Audit-related fees ⁽²⁾	—		186,000
Tax fees ⁽³⁾	8,000		22,612
All other fees	—		—
Total	$	2,441,000	$	2,641,612

(1)

Audit fees for 2014 and 2013 were for professional services rendered by KPMG in connection with the audits of our annual financial statements for the years ended December 31, 2014 and 2013, 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, 2014 and 2013, respectively, and related services that 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 2013 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.”


(3)	Tax fees for 2014 and 2013 were for professional services rendered by KPMG for tax compliance, tax advice and tax planning.

AUDIT COMMITTEE PRE-APPROVAL POLICY

The Audit Committee has adopted a pre-approval policy to address the approval of services rendered to us by our independent auditors, which is filed herewith as Exhibit 99.01.

None of the services (described above) for 2014 or 2013 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, 2014 and 2013 Consolidated Statements of Income for the Years Ended December 31, 2014, 2013 and 2012 Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2014, 2013 and 2012 Consolidated Statements of Cash Flows for the Years Ended December 31, 2014, 2013 and 2012 Consolidated Statements of Partners’ Equity for the Years Ended December 31, 2014, 2013 and 2012 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
			Filed as part of this Form 10-K are the following:



Exhibit Number	Description	Incorporated by Reference to the Following Document

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	Third Amended and Restated Agreement of Limited Partnership of Valero L.P., dated as of March 18, 2003	NuStar Energy L.P.’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2003 (File No. 001-16417), Exhibit 3.1

3.04	Amendment No. 1 to Third Amended and Restated Agreement of Limited Partnership of Valero L.P., dated as of March 11, 2004	NuStar Energy L.P.’s Annual Report on Form 10-K for year ended December 31, 2003 (File No. 001-16417), Exhibit 4.3

3.05	Amendment No. 2 to Third Amended and Restated Agreement of Limited Partnership of Valero L.P., dated as of July 1, 2005	NuStar Energy L.P.’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2005 (File No. 001-16417), Exhibit 4.01

3.06	Amendment No. 3 to Third Amended and Restated Agreement of Limited Partnership of NuStar Energy L.P., dated as of April 10, 2008	NuStar Energy L.P.’s Current Report on Form 8-K filed April 15, 2008 (File No. 001-16417), Exhibit 3.1

3.07	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

3.08	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 the quarter ended March 31, 2007 (File No. 001-16417), Exhibit 3.03

3.09	Certificate of Amendment to Certificate of Limited Partnership of NuStar Logistics, L.P., dated and effective as of March 18, 2014	*

3.10	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

3.11	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 the quarter ended June 30, 2001 (File No. 001-16417), Exhibit 4.1

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3.12	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

3.13	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

3.14	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

3.15	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

3.16	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

3.17	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 the quarter ended March 31, 2007 (File No. 001-16417), Exhibit 3.02

3.18	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

3.19	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

3.20	Second Amendment to First Amended and Restated Limited Liability Company Agreement of Valero GP, LLC, effective as of June 1, 2006	*

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	First Supplemental Indenture, dated as of July 15, 2002, to Indenture dated as of July 15, 2002, in each case among Valero Logistics Operations, L.P., as Issuer, Valero L.P., as Guarantor, and The Bank of New York, as Trustee, relating to 6 7/8% Senior Notes due 2012	NuStar Energy L.P.’s Current Report on Form 8-K filed July 15, 2002 (File No. 001-16417), Exhibit 4.2

4.03	Second Supplemental Indenture, dated as of March 18, 2003, to Indenture dated as of July 15, 2002, as amended and supplemented by a First Supplemental Indenture thereto dated as of July 15, 2002, in each case among Valero Logistics Operations, L.P., as Issuer, Valero L.P., as Guarantor, and The Bank of New York, as Trustee (including, form of global note representing $250,000,000 6.05% Senior Notes due 2013)	NuStar Energy L.P.’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2003 (File No. 001-16417), Exhibit 4.1

4.04	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 the quarter ended June 30, 2005 (File No. 001-16417), Exhibit 4.02

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4.05	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

4.06	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

4.07	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

4.08	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

4.09	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

4.10	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

4.11	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	5-Year Revolving Credit Agreement, dated as of May 2, 2012, among NuStar Logistics, L.P., NuStar Energy L.P., the Lenders party thereto and JPMorgan Chase Bank, N.A., as Administrative Agent, Suntrust Bank, Mizuho Corporate Bank, Ltd., as Co-Syndication Agents, and Wells Fargo Bank, National Association, Barclays Bank PLC, as Co-Documentation Agents, and J.P. Morgan Securities Inc., Suntrust Robinson Humphrey, Inc., Mizuho Corporate Bank, Ltd., Wells Fargo Securities, LLC and Barclays Bank PLC as Joint Bookrunners and Joint Lead Arrangers	NuStar Energy L.P.’s Current Report on Form 8-K filed May 8, 2012 (File No. 001-16417), Exhibit 10.01

10.02	First Amendment to 5-Year Revolving Credit Agreement, dated as of June 29, 2012, 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 July 6, 2012 (File No. 001-16417), Exhibit 10.01

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10.03	Second Amendment to 5-Year Revolving Credit Agreement, dated as of November 30, 2012, 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 Annual Report on Form 10-K for year ended December 31, 2012 (File No. 001-16417), Exhibit 10.03

10.04	Third Amendment to 5-Year Revolving Credit Agreement, dated as of January 11, 2013, 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 Annual Report on Form 10-K for year ended December 31, 2012 (File No. 001-16417), Exhibit 10.04

10.05	Fourth Amendment to 5-Year Revolving Credit Agreement, dated as of December 4, 2013, 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 Annual Report on Form 10-K for year ended December 31, 2013 (File No. 001-16417), Exhibit 10.05

10.06	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

10.07	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

10.08	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

10.09	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 10.02

10.10	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	*

10.11	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	*

10.12	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	*

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10.13	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	*

10.14	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

10.15	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

10.16	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 10.01

10.17	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

10.18	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

10.19	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

10.20	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

+10.21	NuStar GP, LLC Amended and Restated 2003 Employee Unit Incentive Plan, amended and restated as of April 1, 2007	NuStar Energy L.P.’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2007 (File No. 001-16417), Exhibit 10.03

+10.22	Form of Unit Option Agreement under the NuStar GP, LLC Amended and Restated 2003 Employee Unit Incentive Plan, as amended	NuStar Energy L.P.’s Annual Report on Form 10-K for year ended December 31, 2006 (File No. 001-16417), Exhibit 10.11

+10.23	NuStar GP, LLC Amended and Restated 2002 Unit Option Plan, amended and restated as of April 1, 2007	NuStar Energy L.P.’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2007 (File No. 001-16417), Exhibit 10.02

+10.24	NuStar GP, LLC Third Amended and Restated 2000 Long-Term Incentive Plan, amended and restated as of May 1, 2011	NuStar Energy L.P.’s Current Report on Form 8-K filed May 10, 2011 (File No. 001-16417), Exhibit 10.01

+10.25	NuStar GP, LLC Fourth Amended and Restated 2000 Long-Term Incentive Plan, amended and restated as of January 1, 2014	NuStar Energy L.P.’s Annual Report on Form 10-K for year ended December 31, 2013 (File No. 001-16417), Exhibit 10.10

+10.26	Form of Restricted Unit Award Agreement under the NuStar GP, LLC Second Amended and Restated 2000 Long-Term Incentive Plan (substantially the same for 2008 and 2009 awards)	NuStar Energy L.P.’s Current Report on Form 8-K filed November 10, 2008 (File No. 001-16417), Exhibit 10.03

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+10.27	Form of Unit Option Award Agreement under the NuStar GP, LLC Second Amended and Restated 2000 Long-Term Incentive Plan	NuStar Energy L.P.’s Current Report on Form 8-K filed November 3, 2006 (File No. 001-16417), Exhibit 10.02

+10.28	Form of 2010 Restricted Unit Award Agreement under the NuStar GP, LLC Second Amended and Restated 2000 Long-Term Incentive Plan	NuStar Energy L.P.’s Current Report on Form 8-K filed January 5, 2011(File No. 001-16417), Exhibit 10.03

+10.29	Form of 2011 and 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

+10.30	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

+10.31	Form of Amended and Restated Performance Unit Agreement under the NuStar GP, LLC Second Amended and Restated 2000 Long-Term Incentive Plan (for 2006, 2007, 2008 and 2009 awards)	NuStar Energy L.P.’s Current Report on Form 8-K filed December 8, 2009 (File No. 001-16417), Exhibit 10.02

+10.32	Omnibus Amendment to Form of Amended and Restated Performance Unit Agreements under the NuStar GP, LLC Second Amended and Restated 2000 Long-Term Incentive Plan (for 2006, 2007, 2008 and 2009 awards)	NuStar Energy L.P.’s Current Report on Form 8-K filed February 2, 2010 (File No. 001-16417), Exhibit 10.03

+10.33	Form of Performance Unit Agreement under the NuStar GP, LLC Second Amended and Restated 2000 Long-Term Incentive Plan (substantially the same for 2010, 2011, 2012 and 2013 awards with appropriate adjustments based on award dates)	NuStar Energy L.P.’s Annual Report on Form 10-K for year ended December 31, 2009 (File No. 001-16417), Exhibit 10.11

+10.34	Form of Waiver Related to Certain Performance Units (for 2009, 2010 and 2011 awards)	NuStar Energy L.P.’s Current Report on Form 8-K filed January 31, 2012 (File No. 001-16417), Exhibit 10.3

+10.35	Form of Non-employee Director Restricted Unit Agreement under the NuStar GP, LLC Second Amended and Restated 2000 Long-Term Incentive Plan (substantially the same for 2010, 2011 and 2012 awards)	NuStar Energy L.P.’s Current Report on Form 8-K filed January 5, 2011(File No. 001-16417), Exhibit 10.02

+10.36	Form of 2013 Non-employee Director Restricted Unit 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 10.21

+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 Change of Control Severance Agreement with executive officers of NuStar GP, LLC (substantially the same for all executive officers, except for payment multiple)	NuStar Energy L.P.’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2006 (File No. 001-16417), Exhibit 10.06

+10.39	NuStar Excess Pension 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 10.29

+10.40	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

10.41	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

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10.42	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

10.43	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

10.44	Crude Oil Sales Agreement between NuStar Marketing LLC and PDVSA-Petróleo S.A., an affiliate of Petróleos de Venezuela S.A., the national oil company of the Bolivarian Republic of Venezuela, dated effective as of March 1, 2008	NuStar Energy L.P.’s Current Report on Form 8-K filed March 25, 2008 (File No. 001-16417), Exhibit 10.1

10.45	Amendment to Crude Oil Sales Agreement between PDVSA-Petróleo S.A., NuStar Logistics, L.P. and NuStar Marketing LLC, effective as of October 1, 2012	NuStar Energy L.P.’s Quarterly Report on Form 10-Q for quarter ended June 30, 2013 (File No. 001-16417), Exhibit 10.01

10.46	Purchase and Sale Agreement by and among NuStar Energy L.P., NuStar Logistics, L.P., NuStar Asphalt Refining, LLC, NuStar Marketing LLC, NuStar GP, LLC, NuStar Asphalt LLC and Asphalt Acquisition LLC dated as of July 3, 2012	NuStar Energy L.P.’s Current Report on Form 8-K filed July 6, 2012 (File No. 001-16417), Exhibit 10.01

10.47	Letter Agreement by and among Asphalt Acquisition LLC, NuStar Energy L.P., NuStar Logistics, L.P., NuStar Asphalt Refining, LLC, NuStar Marketing LLC, NuStar GP, LLC and NuStar Asphalt LLC dated August 2, 2012	NuStar Energy L.P.’s Quarterly Report on Form 10-Q for quarter ended September 30, 2012 (File No. 001-16417), Exhibit 10.02

10.48	Amendment No. 1 to Purchase and Sale Agreement dated as of September 28, 2012 by and among NuStar Energy L.P., NuStar Logistics, L.P., NuStar Asphalt Refining, LLC, NuStar Marketing LLC, NuStar GP, LLC, NuStar Asphalt LLC and Asphalt Acquisition LLC	NuStar Energy L.P.’s Quarterly Report on Form 10-Q for quarter ended September 30, 2012 (File No. 001-16417), Exhibit 10.03

10.49	Amended and Restated Transaction Agreement by and between LG Asphalt L.P. and NuStar Logistics, L.P. dated as of December 20, 2013	NuStar Energy L.P.’s Annual Report on Form 10-K for year ended December 31, 2013 (File No. 001-16417), Exhibit 10.47

10.50	Amendment No. 1 to Amended and Restated Transaction Agreement dated as of January 29, 2014	NuStar Energy L.P.’s Annual Report on Form 10-K for year ended December 31, 2013 (File No. 001-16417), Exhibit 10.48

10.51	Amendment No. 2 to Amended and Restated Transaction Agreement dated as of February 26, 2014	NuStar Energy L.P.’s Annual Report on Form 10-K for year ended December 31, 2013 (File No. 001-16417), Exhibit 10.49

12.01	Statement of Computation of Ratio of Earnings to Fixed Charges	*

14.01	Code of Ethics for Senior Financial Officers	NuStar Energy L.P.’s Annual Report on Form 10-K for year ended December 31, 2003 (File No. 001-16417), Exhibit 14.1

21.01	List of subsidiaries of NuStar Energy L.P.	*

23.01	Consent of KPMG LLP dated February 26, 2015 (NuStar Energy L.P.)	*

23.02	Consent of KPMG LLP dated February 26, 2015 (NuStar Asphalt LLC)	*

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	*

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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	**

99.01	Audit Committee Pre-Approval Policy	*

99.02	Consolidated Financial Statements of NuStar Asphalt LLC for December 31, 2013 and 2012	*

99.03	Unaudited Consolidated Financial Statements of NuStar Asphalt LLC as of February 25, 2014 and for the period from January 1, 2014 to February 25, 2014	*

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.

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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 26, 2015

By:	/s/ Thomas R. Shoaf
	Thomas R. Shoaf
	Executive Vice President and Chief Financial Officer
	February 26, 2015

By:	/s/ Jorge A. del Alamo
	Jorge A. del Alamo
	Senior Vice President and Controller
	February 26, 2015

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Table of Contents

POWER OF ATTORNEY

KNOW ALL MEN BY THESE PRESENTS, that each person whose signature appears below hereby constitutes and appoints Bradley C. Barron, Thomas R. Shoaf and Amy L. Perry, or any of them, each with power to act without the other, his 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 26, 2015
William E. Greehey

/s/ Bradley C. Barron	President, Chief Executive	February 26, 2015
Bradley C. Barron	Officer and Director (Principal Executive Officer)

/s/ Thomas R. Shoaf	Executive Vice President	February 26, 2015
Thomas R. Shoaf	and Chief Financial Officer (Principal Financial Officer)

/s/ Jorge A. del Alamo	Senior Vice President and Controller	February 26, 2015
Jorge A. del Alamo	(Principal Accounting Officer)

/s/ J. Dan Bates	Director	February 26, 2015
J. Dan Bates

/s/ Dan J. Hill	Director	February 26, 2015
Dan J. Hill

/s/ Rodman D. Patton	Director	February 26, 2015
Rodman D. Patton

/s/ W. Grady Rosier	Director	February 26, 2015
W. Grady Rosier

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