NuStar Energy L.P. - Annual Report: 2013 (Form 10-K)

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Non-accelerated filer

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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, 2013

[ ] 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. [X]

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in 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 $3,086 million based on the last sales price quoted as of June 28, 2013, the last business day of the registrant’s most recently completed second quarter.

The number of common units outstanding as of January 31, 2014 was 77,886,078.

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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	17
	Rate Regulation	17
	Environmental and Safety Regulation	17
	Risk Factors	19
	Properties	28

Item 1B.	Unresolved Staff Comments	28

Item 3.	Legal Proceedings	28

Item 4.	Mine Safety Disclosures	29

PART II
Item 5.	Market for Registrant’s Common Units, Related Unitholder Matters and Issuer Purchases of Common Units	30

Item 6.	Selected Financial Data	31

Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	32

Item 7A.	Quantitative and Qualitative Disclosures about Market Risk	57

Item 8.	Financial Statements and Supplementary Data	60

Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	119

Item 9A.	Controls and Procedures	119

Item 9B.	Other Information	119

PART III
Item 10.	Directors, Executive Officers and Corporate Governance	120

Item 11.	Executive Compensation	125

Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters	153

Item 13.	Certain Relationships and Related Transactions and Director Independence	156

Item 14.	Principal Accountant Fees and Services	159

PART IV
Item 15.	Exhibits and Financial Statement Schedules	160

Signatures		169

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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 the following Items 1., 1A. and 2., “Business, Risk Factors and Properties,” we make certain forward-looking statements, including statements regarding our plans, strategies, objectives, expectations, intentions and resources. The words “forecasts,” “intends,” “believes,” “expects,” “plans,” “scheduled,” “goal,” “may,” “anticipates,” “estimates” and similar expressions identify forward-looking statements. 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 32 of this report under the heading: “CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION.”

ITEM 1. BUSINESS, RISK FACTORS AND PROPERTIES

OVERVIEW

NuStar Energy L.P. (NuStar Energy), a Delaware limited partnership, 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 terminalling and storage of petroleum products, the transportation of petroleum products and anhydrous ammonia, and the marketing of petroleum products. We divide our operations into the following three reportable business segments: storage, pipeline, and fuels marketing. As of December 31, 2013, our assets included:


•	60 terminal and storage facilities providing 84.8 million barrels of storage capacity;


•	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; and


•	1,180 miles of crude oil pipelines providing 3.4 million barrels of associated 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 business strategy is to increase per unit cash distributions to our partners through:


•	continuous improvement of our operations by improving safety and environmental stewardship, cost controls and asset reliability and integrity;


•	internal growth through enhancing the utilization of our existing assets by expanding our business with current and new customers, as well as investments in strategic expansion projects;


•	external growth from acquisitions that meet our financial and strategic criteria;


•	identification of non-core assets that do not meet our financial and strategic criteria and evaluation of potential dispositions; and


•	complementary operations such as our fuels marketing operations, which provide us the opportunity to optimize the use and profitability of our assets.

The term “throughput” as used in this document generally refers to the crude oil or refined product barrels or tons of ammonia, as applicable, that pass through our pipelines, terminals, storage tanks or refineries.

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.

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RECENT DEVELOPMENTS

Divestment of ownership interest in Asphalt JV

On February 26, 2014, we sold our then-remaining 50% ownership interest in NuStar Asphalt LLC (Asphalt JV), which constitutes all equity interest in that entity we retained after the first sale in 2012. The purchaser, Lindsay Goldberg LLC (Lindsay Goldberg), a private investment firm, now owns 100% of Asphalt JV, and we have completed our exit from the asphalt business. Please refer to Note 29 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, 2013.

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SEGMENTS

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

The following map depicts our operations at December 31, 2013.

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STORAGE

Our storage segment includes terminal and storage facilities that provide storage, handling and other services for petroleum products, specialty chemicals, crude oil and other liquids. As of December 31, 2013, we owned and operated:


•	48 terminal and storage facilities in the United States, with total storage capacity of 51.7 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;


•	Two terminals in Mersin, Turkey with total storage capacity of 1.4 million barrels; and


•	A terminal located in Nuevo Laredo, Mexico.

Description of Largest 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 the world’s largest tankers 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 processing 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 8.9 million barrels. The facility is located on almost 900 acres of land, some of which is undeveloped. The majority of the storage tanks and infrastructure are suited for light crude oil, with 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 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 substantially all of the world’s largest, fully laden very large crude carriers and ultra large crude carriers 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.

Piney Point, Maryland. Our terminal and storage facility in Piney Point is located on approximately 400 acres on the Potomac River. The Piney Point terminal has 5.4 million barrels of storage capacity and is the closest deep-water facility to Washington, D.C. This terminal competes with other large petroleum terminals in the East Coast water-borne market extending from New York Harbor to Norfolk, Virginia. The terminal has a dock with a 36-foot draft for tankers and four berths for barges. It also has truck-loading facilities and product-blending capabilities.

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. We own 50% of ST Linden Terminal LLC, which owns a terminal and storage facility in Linden, New Jersey. The terminal is located on a 44-acre facility that provides it with deep-water terminalling capabilities at 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 docks with draft limits of 36 and 26 feet, respectively.

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Terminal and Storage Facilities

The following table sets forth information about our terminal and storage facilities as of December 31, 2013:



Facility	Tank Capacity	Primary Products Handled
	(Barrels)
U.S. Terminals and Storage Facilities:
Mobile, AL (Blakely Island)	1,185,000	Petroleum products, crude oil and feedstocks
Mobile, AL (Chickasaw North)	333,000	Crude oil and feedstocks
Mobile, AL (Chickasaw South)	327,000	Petroleum products, crude oil and feedstocks
Los Angeles, CA	608,000	Petroleum products
Benicia, CA (Refinery Tankage)	3,655,000	Crude oil and feedstocks
Pittsburg, CA	398,000	Asphalt
Selby, CA	3,060,000	Petroleum products, ethanol
Stockton, CA	810,000	Petroleum products, ethanol, fertilizer
Colorado Springs, CO	328,000	Petroleum products, ethanol
Denver, CO	110,000	Petroleum products, ethanol
Jacksonville, FL	2,593,000	Petroleum products, asphalt
Blue Island, IL	732,000	Petroleum products, ethanol
Indianapolis, IN	428,000	Petroleum products
St. James, LA	8,943,000	Crude oil and feedstocks
Andrews AFB, MD (a)	75,000	Petroleum products
Baltimore, MD	827,000	Chemicals, asphalt, petroleum products
Piney Point, MD	5,402,000	Petroleum products
Wilmington, NC (f)	331,000	Asphalt
Linden, NJ	389,000	Petroleum products
Linden, NJ (b)	2,130,000	Petroleum products
Paulsboro, NJ	74,000	Petroleum products
Alamogordo, NM (a)	124,000	Petroleum products
Albuquerque, NM	251,000	Petroleum products, ethanol
Rosario, NM	166,000	Asphalt
Catoosa, OK	358,000	Asphalt
Portland, OR	1,359,000	Petroleum products, ethanol
Abernathy, TX	160,000	Petroleum products
Amarillo, TX	273,000	Petroleum products
Corpus Christi, TX	329,000	Petroleum products
Corpus Christi, TX (North Beach)	1,721,000	Crude oil and feedstocks
Corpus Christi, TX (Refinery Tankage)	4,030,000	Crude oil and feedstocks
Edinburg, TX	276,000	Petroleum products
El Paso, TX (c)	428,000	Petroleum products, ethanol
Harlingen, TX	286,000	Petroleum products
Houston, TX	91,000	Asphalt
Laredo, TX	219,000	Petroleum products
Placedo, TX (d)	100,000	Petroleum products
San Antonio (East), TX	150,000	Petroleum products
San Antonio (South), TX	225,000	Petroleum products
Southlake, TX	453,000	Petroleum products, ethanol
Texas City, TX	128,000	Petroleum products

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Facility	Tank Capacity	Primary Products Handled
	(Barrels)
Texas City, TX	2,878,000	Chemicals, petroleum products
Texas City, TX (Refinery Tankage)	3,141,000	Crude oil and feedstocks
Dumfries, VA (f)	556,000	Petroleum products, asphalt
Virginia Beach, VA (a)	41,000	Petroleum products
Tacoma, WA	413,000	Petroleum products, ethanol
Vancouver, WA	345,000	Chemicals
Vancouver, WA	433,000	Petroleum products
Total U.S.	51,672,000

Foreign Terminals and Storage Facilities:
St. Eustatius, the Netherlands	14,385,000	Petroleum products, crude oil and feedstocks
Amsterdam, the Netherlands	3,845,000	Petroleum products
Point Tupper, Canada	7,725,000	Petroleum products, crude oil and feedstocks
Grays, England	1,958,000	Petroleum products
Eastham, England	2,064,000	Chemicals, petroleum products
Runcorn, England	149,000	Molten sulfur
Grangemouth, Scotland	579,000	Petroleum products, chemicals
Glasgow, Scotland	401,000	Petroleum products
Belfast, Northern Ireland	480,000	Petroleum products
Mersin, Turkey (e)	790,000	Petroleum products
Mersin, Turkey (e)	656,000	Petroleum products
Nuevo Laredo, Mexico	50,000	Petroleum products
Total Foreign	33,082,000

Total Terminals and Storage Facilities	84,754,000


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


(b)	We own 50% of this terminal through a joint venture. The tank capacity represents the proportionate share of capacity attributable to our ownership interest.


(c)	We own a 66.67% undivided interest in the El Paso refined product terminal. The tank capacity represents the proportionate share of capacity attributable to our ownership interest.


(d)	The Placedo, TX terminal is temporarily idled.


(e)	We own 75% of the outstanding capital of a Turkish company, which owns two terminals in Mersin, Turkey.


(f)	In February 2014, we divested these terminals in connection with the divestiture of our remaining 50% ownership interest in Asphalt JV. See Note 29 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for additional discussion.

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. We charge a fee for each barrel of crude oil and certain other feedstocks that we deliver to Valero Energy Corporation’s (Valero Energy) Benicia, Corpus Christi West and Texas City refineries from our crude oil storage tanks. Our facilities at Point Tupper and St. Eustatius charge fees to provide services such as pilotage, tug assistance, line handling, launch service, emergency response services and other ship services.

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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.

Crude oil throughputs coming to our St. James terminal through our unit train facilities, and crude oil throughputs at 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.

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 18% of the total revenues of the segment for the year ended December 31, 2013. No other customer accounted for more than 10% of the revenues of the segment for this period.

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.

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. Terminals located near deep-water port facilities are referred to as “deep-water terminals,” and terminals without such facilities are referred to as “inland terminals,” although some inland facilities located on or near navigable rivers are served by barges.

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 and have handled primarily imports of light crude from foreign sources into the U.S. These non-domestic crude producers supplied the light crude demanded by U.S. East Coast and Gulf Coast refineries. Light crude suppliers brought the crude from the Middle East and other regions of the world 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, 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 facilities are well-located to provide this service.

As 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, as well as depressed 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, 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.

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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 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.

PIPELINE

Our pipeline operations consist of the transportation of refined petroleum products, crude oil and anhydrous ammonia. Refined product pipelines in Texas, Oklahoma, Colorado, New Mexico, Kansas, Nebraska, Iowa, South Dakota, North Dakota and Minnesota cover approximately 5,463 miles. Our crude oil pipelines in Texas, Oklahoma, Kansas, Colorado and Illinois cover 1,180 miles. Our anhydrous ammonia pipeline in Louisiana, Arkansas, Missouri, Illinois, Indiana, Iowa and Nebraska covers 2,000 miles.

As of December 31, 2013, we owned and operated:

•

refined product pipelines in Texas, Oklahoma, Colorado and New Mexico with an aggregate length of 3,113 miles originating at Valero Energy’s McKee, Three Rivers and Corpus Christi refineries and terminating at certain of NuStar Energy’s terminals, or connecting to third-party pipelines or terminals for further distribution, including a 25-mile hydrogen pipeline (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 Mandan, North Dakota refinery and terminating in Minneapolis, Minnesota (the North Pipeline);


•	crude oil pipelines in Texas, Oklahoma, Kansas, Colorado and Illinois with an aggregate length of 1,180 miles and crude oil storage facilities providing 3.4 million barrels of storage capacity in Texas, Oklahoma and Colorado that are located along the crude oil pipelines; 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.

Description of Pipelines

Central West System. The Central West System pipelines were constructed to support the refineries to which they are connected. These pipelines are physically integrated with and principally serve refineries owned by Valero Energy. The refined products transported in these pipelines include gasoline, distillates (including diesel and jet fuel), natural gas liquids and other products produced primarily by Valero Energy’s McKee, Three Rivers and Corpus Christi refineries in Texas. These pipelines deliver refined products to key markets in Texas, New Mexico and Colorado. The Central West System transported approximately 100.7 million barrels for the year ended December 31, 2013.

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The following table lists information about each of our refined product pipelines included in the Central West System:



Origin and Destination	Refinery	Length	Ownership		Capacity
		(Miles)			(Barrels/Day)
McKee to El Paso, TX	McKee	408	67	%	42,000
McKee to Colorado Springs, CO	McKee	256	100	%	32,500
Colorado Springs, CO to Airport	McKee	2	100	%	12,000
Colorado Springs to Denver, CO	McKee	101	100	%	32,000
McKee to Denver, CO	McKee	321	30	%	11,000
McKee to Amarillo, TX (6”) (a)	McKee	49	100	%	51,000
McKee to Amarillo, TX (8”) (a)	McKee	49	100	%
Amarillo to Abernathy, TX	McKee	102	67	%	16,800
Amarillo, TX to Albuquerque, NM	McKee	293	50	%	17,000
Abernathy to Lubbock, TX	McKee	19	46	%	8,000
McKee to Southlake, TX	McKee	375	100	%	26,000
Three Rivers to San Antonio, TX	Three Rivers	85	100	%	33,500
Three Rivers to US/Mexico International Border near Laredo, TX	Three Rivers	108	100	%	32,000
Three Rivers to Corpus Christi, TX	Three Rivers	72	100	%	15,000
Three Rivers to Pettus to San Antonio, TX	Three Rivers	112	100	%	27,500
El Paso, TX to Kinder Morgan	McKee	12	67	%	65,500
Mont Belview to Corpus Christi, TX	N/A	208	100	%	105,000
Corpus Christi to Brownsville, TX	Corpus Christi	194	100	%	45,000
US/Mexico International Border near Penitas, TX to Edinburg, TX	N/A	33	100	%	24,000
Clear Lake, TX to Texas City, TX	N/A	25	100	%	N/A
Other refined product pipeline (b)	N/A	289	50	%	N/A
Total		3,113			595,800


(a)	The capacity information disclosed above for the McKee to Amarillo, Texas 6-inch pipeline reflects both McKee to Amarillo, Texas pipelines on a combined basis.


(b)	This category consists of the temporarily idled 6-inch Amarillo, Texas to Albuquerque, New Mexico refined product pipeline.

East Pipeline. The East Pipeline covers 1,910 miles, including 242 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. The East Pipeline system also includes storage capacity of approximately 1.4 million barrels at our two tanks farms at McPherson and El Dorado, Kansas. The East Pipeline transports refined petroleum products and natural gas liquids to NuStar Energy and third party terminals along the system and to receiving pipeline connections in Kansas. Shippers on the East Pipeline obtain refined petroleum products from refineries in Kansas, Oklahoma and Texas. The East Pipeline transported approximately 48.4 million barrels for the year ended December 31, 2013.

North Pipeline. The North Pipeline originates at Tesoro’s Mandan, North Dakota refinery and runs from west to east for approximately 440 miles from its origin to the Minneapolis, Minnesota area. For the year ended December 31, 2013, the North Pipeline transported approximately 16.8 million barrels.

Pipeline-Related Terminals. The East and North Pipelines also 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.

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The following table lists information about each terminal integrated into our East and North Pipelines as of December 31, 2013:



Location of Terminals	Tank Capacity	Related Pipeline System
	(Barrels)
Iowa:
LeMars	111,000	East
Milford	180,000	East
Rock Rapids	230,000	East
Kansas:
Concordia	83,000	East
Hutchinson	116,000	East
Salina	85,000	East
Minnesota:
Moorhead	497,000	North
Sauk Centre	148,000	North
Roseville	625,000	North
Nebraska:
Columbus	178,000	East
Geneva	677,000	East
Norfolk	178,000	East
North Platte	256,000	East
Osceola	83,000	East
North Dakota:
Jamestown (North)	173,000	North
Jamestown (East)	181,000	East
South Dakota:
Aberdeen	186,000	East
Mitchell	74,000	East
Sioux Falls	417,000	East
Wolsey	144,000	East
Yankton	259,000	East
Total	4,881,000

Ammonia Pipeline. The 2,000-mile pipeline, including 59 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, one branch splits and 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. In 2013, the Ammonia Pipeline transported an aggregate of approximately 1.3 million tons (or approximately 11.9 million barrels) of anhydrous ammonia.

Crude Oil Pipelines. 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 crude oil pipelines transport crude oil and other feedstocks from various points in Texas, notably the South Texas Eagle Ford Shale region, Oklahoma, Kansas and Colorado to Valero Energy’s McKee, Three Rivers and Ardmore, Oklahoma refineries and to other U.S. refinery centers via our North Beach marine terminal in Corpus Christi, Texas. We transported an aggregate of approximately 133.5 million barrels on our crude oil pipelines for the year ended December 31, 2013.

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The following table sets forth information about each of our crude oil pipelines as of December 31, 2013:



Origin and Destination	Refinery	Length	Ownership		Capacity
		(Miles)			(Barrels/Day)
Dixon, TX to McKee	McKee	44	100	%	63,500
Hooker, OK to Clawson, TX (a)	McKee	41	50	%	22,000
Clawson, TX to McKee	McKee	31	100	%	36,000
Wichita Falls, TX to McKee	McKee	272	100	%	110,000
Ringgold, TX to Ardmore	Ardmore	83	100	%	90,000
Patoka, IL to Wood River	Three Rivers	57	24	%	60,500
Corpus Christi, TX to Three Rivers, TX (Odem)	Corpus Christi	68	100	%	38,000
Pettus, TX to Corpus Christi, TX	(b)	60	100	%	30,000
Three Rivers, TX to Corpus Christi, TX (12”)	(b)	66	100	%	55,000
Gardendale, TX to Oakville, TX	(b)	140	100	%	100,000
Pawnee, TX to Oakville, TX	(b)	43	100	%	110,000
Oakville, TX to Corpus Christi, TX (16”)	(b)	61	100	%	200,000
Other (c)	N/A	214	100	%	N/A
Total		1,180			915,000


(a)	We receive 50% of the tariff with respect to 100% of the barrels transported in the Hooker, Oklahoma to Clawson, Texas pipeline. Accordingly, the capacity is given with respect to 100% of the pipeline.


(b)	These pipelines serve production from the South Texas Eagle Ford Shale.


(c)	This category consists of the temporarily idled Cheyenne Wells, CO to McKee and Healdton to Ringling, Oklahoma crude oil pipelines.

The following table sets forth information about the crude oil storage facilities located along our crude oil pipelines as of December 31, 2013:



Location	Refinery	Capacity
		(Barrels)
Dixon, TX	McKee	244,000
Ringgold, TX	Ardmore	598,000
Wichita Falls, TX	McKee	661,000
Wasson, OK	Ardmore	226,000
Clawson, TX	McKee	77,000
South Texas (a)	N/A	701,000
Oakville, TX	N/A	718,000
Pawnee, TX	N/A	112,000
Other (b)	McKee	68,000
Total		3,405,000


(a)	This category includes crude oil tanks at various locations along the Gardendale, Texas to Oakville, Texas pipeline.


(b)	This category includes crude oil tanks along the Cheyenne Wells, Colorado to McKee crude oil pipelines located at Carlton, Colorado, Sturgis, Oklahoma, and Stratford, Texas.

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. Shippers are required to supply us with a notice of shipment indicating sources of products and destinations. Shipments are tested or receive certifications to ensure compliance with our product specifications. 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

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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.

The pipelines in the Central West System, the East Pipeline, the North Pipeline and the Ammonia Pipeline and the crude oil 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 are subject to federal and state tariff regulation. In general, we are authorized by the FERC to 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 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. The Ammonia Pipeline is subject to federal regulation by the STB and state regulation by Louisiana.

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

The operations of our Central West System 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 pipelines in the Central West System are gasoline and diesel fuel that originate at refineries owned by Valero Energy. 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 and affects refinery utilization rates, 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.

The majority of the refined products delivered through the North Pipeline are delivered to the Minneapolis, Minnesota metropolitan area and consist of gasoline and diesel fuel. Demand for those products fluctuates based on general economic conditions and with changes in the weather as more people drive during the warmer months.

Much of the refined products and natural gas liquids delivered through the East Pipeline and volumes on the North Pipeline that are not delivered to Minneapolis 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. In addition, weather conditions in the areas served by the East Pipeline affect the mix of the refined products delivered through the East Pipeline, although historically any overall impact on the total volumes shipped has not been significant.

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 the pipelines in the Central West System and certain of our crude oil 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.

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Our crude oil pipelines are dependent on the continued production of adequate supply 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 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. 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.

The refineries connected directly to the East Pipeline obtain crude oil from producing fields located primarily in Kansas, Oklahoma and Texas, and, to a much lesser extent, from other domestic or foreign sources. In addition, refineries in Kansas, Oklahoma and Texas are also connected to the East Pipeline by third party pipelines. These refineries obtain their supplies of crude oil from a variety of sources. 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.

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.

Our Ammonia Pipeline operations 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 37% of the total segment revenues for the year ended December 31, 2013. In addition to Valero Energy, our customers include integrated oil companies, refining companies, farm cooperatives, railroads and others. No other customer accounted for greater than 10% of the total revenues of the pipeline segment for the year ended December 31, 2013.

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.

The costs associated with transporting products from a loading terminal to end users limit the geographic size of the market that can be served economically by any terminal. Transportation to end users from our loading terminals is conducted primarily by trucking operations of unrelated third parties. 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. We do not believe that trucks are, or will be, effective competition to our long-haul volumes over the long term.

Most of our refined product pipelines within the Central West System and certain of our crude oil pipelines 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

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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. The Magellan system is a more extensive system than the East and North Pipelines. Competition with Magellan is based primarily on transportation charges, quality of customer service and proximity to end users. In addition, refined product pricing at either the origin or terminal point on a pipeline may outweigh transportation costs. Certain of the East Pipeline’s and the North Pipeline’s delivery terminals are in direct competition with Magellan’s terminals.

Competitors of the Ammonia Pipeline include the other major anhydrous ammonia pipeline that 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.

FUELS MARKETING

In 2013, we changed the name of the “Asphalt and Fuels Marketing” segment to the “Fuels Marketing” segment. This name more accurately reflects the operations that remain after we sold a 50% ownership interest in NuStar Asphalt LLC (Asphalt JV) in 2012 and the San Antonio Refinery Sale as discussed below.

Fuels Marketing Operations

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 storage and pipeline segments.

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

Since our fuels marketing operations expose us to commodity price risk, we sometimes 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 greater than 11% of the total segment revenues of the fuels marketing segment for the year ended December 31, 2013.

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.

Dispositions

San Antonio Refinery Sale. On January 1, 2013, we sold the San Antonio Refinery and related assets, which included inventory, a terminal in Elmendorf, Texas and a pipeline connecting the terminal and refinery. We have presented the results of operations for the San Antonio Refinery and related assets, previously reported in the fuels marketing and pipeline segments, as discontinued operations for the years ended December 31, 2013, 2012 and 2011.

Asphalt Operations. On September 28, 2012, we sold a 50% ownership interest (the Asphalt Sale) in NuStar Asphalt LLC (Asphalt JV), previously a wholly-owned subsidiary, to an affiliate of Lindsay Goldberg LLC, a private investment firm. Asphalt JV 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. Upon closing, we deconsolidated Asphalt JV and started reporting our remaining investment in Asphalt JV using the equity method of accounting.

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In February 2014, we divested our remaining 50% ownership interest in Asphalt JV. See Note 29 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data”for additional discussion.

EMPLOYEES

Our operations are managed by NuStar GP, LLC. As of December 31, 2013, NuStar GP, LLC had 1,221 domestic employees. Certain of our wholly owned subsidiaries had 433 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 and nondiscriminatory. 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. 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.

The Ammonia Pipeline is subject to regulation by the STB under the current version of the ICA. The ICA and its implementing regulations give the STB authority to regulate the rates we charge for service on the Ammonia Pipeline and generally require that our rates and practices be reasonable and nondiscriminatory.

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. 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 pipeline safety. The principal environmental and safety risks associated with our operations relate to unauthorized emissions into the air, unauthorized releases into soil, surface water or groundwater and personal injury and property damage. Compliance with these environmental and safety laws, regulations and permits increases our capital expenditures and our overall cost of business, and violations of these laws, regulations and/or permits can result in significant civil and criminal liabilities, injunctions or other penalties.

We have adopted policies, practices and procedures in the areas of pollution control, pipeline integrity, operator qualifications, public relations and education, product safety, 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.

Capital Expenditures Attributable to Compliance with Environmental Regulations. In 2013, our capital expenditures attributable to compliance with environmental regulations were $6.6 million, and are currently estimated to be approximately $9.1 million for 2014.

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RENEWABLE ENERGY AND ALTERNATIVE FUEL MANDATES

Several federal and state programs require the purchase and use of renewable energy and alternative fuels, such as battery-powered engines, biodiesel, wind energy, and solar energy. These statutory mandates and 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 terminals division, 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 statutes 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 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.

AIR EMISSIONS

Our operations are subject to the Federal Clean Air Act, as amended, and analogous or more stringent state and local statutes. 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. 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

We generate non-hazardous and hazardous solid wastes that are subject to the requirements of the federal Resource Conservation and Recovery Act (RCRA) and analogous or more stringent state statutes. We are not currently 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.

HAZARDOUS SUBSTANCES

The Comprehensive Environmental Response, Compensation and Liability Act, referred to as CERCLA and also known as Superfund, and analogous or more stringent state laws, impose 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 of a “hazardous substance” into the environment. These persons include the owner or operator of the site and entities that disposed or arranged for the disposal of the hazardous substances found at the site. CERCLA also authorizes the EPA and, in some instances, third parties to act in response to threats to the 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 waste that falls within CERCLA’s definition of a “hazardous substance.”

We currently own or lease, and have in the past owned or leased, properties where hydrocarbons 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, hydrocarbons or other wastes 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 hydrocarbons or other wastes. These properties and wastes disposed thereon may be subject to CERCLA, RCRA and analogous state laws. Under these laws, we could be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators), to clean up contaminated property (including contaminated groundwater) or to perform remedial

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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.

PIPELINE INTEGRITY AND SAFETY

Our pipelines are subject to extensive federal and state laws and regulations governing pipeline integrity and safety. These statutes and their respective implementing regulations generally require pipeline operators to maintain qualification programs for key pipeline operating personnel, to review and update their existing pipeline safety public education programs, to provide information for the National Pipeline Mapping System, to maintain spill response plans, to conduct spill response training, to implement integrity management programs for pipelines that could affect high consequence areas (i.e., areas with concentrated populations, navigable waterways and other unusually sensitive areas), maintain detailed operating and maintenance procedures and to manage human factors in pipeline control centers, including controller fatigue. While compliance with the statutes and analogous or more stringent state laws 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.

RISK FACTORS

RISKS RELATED TO OUR BUSINESS

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

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 cash flow, including cash flow 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.

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

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 flow 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 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.

A decrease in lease renewals or throughputs in our assets would cause our revenues to decline and could adversely affect our ability to make cash distributions to our unitholders.

A decrease in lease renewals or throughputs in our assets would cause our revenues to decline and could adversely affect our ability to make cash distributions at current levels to our unitholders. Such a decrease could result from a customer’s failure to renew a lease, a temporary or permanent decline in the amount of crude oil or refined products stored at and transported from the refineries we serve or construction by our competitors of new transportation or storage assets in the markets we serve. Factors that could result in such a decline include:


•	a material decrease in the supply of crude oil;


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


•	scheduled refinery turnarounds or unscheduled refinery maintenance;


•	operational problems or catastrophic events at a refinery;


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


•	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.

If we are unable to complete capital projects at their expected costs and/or in a timely manner, or if the market conditions assumed in our project economics deteriorate, our financial condition, results of operations, or cash flows could be affected materially and adversely.

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

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•	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 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.

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

Our purchase and sale of crude oil and refined 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 refined product hedges. As a result, our marketing and trading of crude oil and refined 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 distribute cash to our unitholders.

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

While intended to reduce the effects of volatile crude oil and refined product prices, hedging transactions, depending on the hedging instrument used, may limit our potential gains if crude oil and refined 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.

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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.

We are exposed to counterparty credit risk. Nonpayment and nonperformance by our customers, vendors or derivative counterparties could reduce our revenues, increase our expenses or otherwise have a negative impact on 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 products or services could result in higher 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.

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, 2013, our consolidated debt was $2.7 billion. Among other things, our significant leverage may be viewed negatively by credit rating agencies, which could result in increased costs for us to access the capital markets. The ratings of NuStar Logistics’ were downgraded to Ba1 (negative outlook) by Moody’s Investor Service Inc. (Moody’s) in January 2013, BB+ (stable outlook) by Standard & Poor’s Ratings Services (S&P) in July 2012 and BB (stable outlook) 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 (the 2012 Revolving Credit Agreement) and our 7.65% senior notes due 2018 increased. We may also be required to post cash collateral under certain of our hedging arrangements, which we expect to fund with borrowings under our 2012 Revolving Credit Agreement. Any future downgrades could result in additional increases to the interest rates on borrowings under our credit facilities and the 7.65% senior notes due 2018, significantly increasing our capital costs and adversely affecting our ability to raise capital in the future.

Our 2012 Revolving Credit Agreement contains restrictive covenants, including a requirement that, as of the end of each rolling period, which consists of any period of four consecutive fiscal quarters, we maintain a consolidated debt coverage ratio (consolidated indebtedness to consolidated EBITDA, as defined in the 2012 Revolving Credit Agreement) not to exceed 5.00-to-1.00. Failure to comply with any of the restrictive covenants in the 2012 Revolving Credit Agreement will result in a default under the terms of our credit agreement and could result in acceleration of this 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 this leverage may adversely affect our ability to finance future operations, pursue acquisitions and fund other capital needs and our ability to 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 any 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 2012 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 may become liable as a result of our financing arrangements and guarantees of Asphalt JV.

In connection with the sale of our 50% ownership interest in Asphalt JV, NuStar Logistics agreed to convert the existing revolving credit facility with Asphalt JV into a $190 million term loan (the NuStar Facility), which such amount will be reduced to $175 million by December 31, 2014 and then $150 million by September 30, 2015. The NuStar Facility must be repaid in full no later than September 2019; earlier repayment is possible, depending on the amount of excess cash flows (if any) generated by Asphalt JV over the next several years. We also agreed to continue to provide credit support to Asphalt JV in the form of guarantees or letters of credit 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.

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In addition to the NuStar Facility (which includes the Credit Support), Asphalt JV also entered into a third-party asset-based revolving credit facility (ABL Facility). In the event that Asphalt JV defaults on any of its obligations under the NuStar Facility, we would have available only those measures available to an unsecured creditor with the rights and limitations provided in the NuStar Facility, 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 Asphalt JV’s liabilities for the default and have only the rights of repayment associated with that instrument. In either scenario, the liability imposed on us may have an adverse impact on our financial condition, results of operations 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, 2013, we had approximately $2.7 billion of consolidated debt, of which $1.8 billion was at fixed interest rates and $0.9 billion was at variable interest rates. In addition, prior ratings downgrades on our existing indebtedness caused interest rates under our 2012 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.

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.

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.

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 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 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.

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Congress has considered legislation to reduce emissions of greenhouse gases. In addition, at least one-third of the states, either individually or through multi-state regional initiatives, have already taken legal measures to reduce emissions of greenhouse gases, primarily through the planned 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, Congress may consider the implementation of a program to tax the emission of carbon dioxide and other greenhouse gases. In December 2009, the EPA issued an endangerment finding that greenhouse gases may reasonably be anticipated to endanger public health and welfare and are a pollutant to be regulated under the Clean Air Act. Passage of climate change legislation or other regulatory initiatives by Congress or various states of the United States or the adoption of regulations by the EPA or analogous state agencies that regulate or restrict emissions of greenhouse gases 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 and administer and manage a greenhouse gas emissions program. We may be unable to recover any such lost revenues or increased costs in the rates we charge our customers, and any such recovery may depend on events beyond our control, including the outcome of future rate proceedings before the FERC and the provisions of any final legislation or regulations. Reductions in our revenues or increases in our expenses as a result of climate control initiatives could have adverse effects on our business, financial position, results of operations and prospects.

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

We operate in seven 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. 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 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 and safety laws and regulations. Transporting and storing 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 store or distribute refined products for many years. Many of these properties were operated by third parties whose handling, disposal or release of hydrocarbons and other wastes was not under our control.

If we were to incur a significant liability pursuant to environmental 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 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 for interstate oil movements on our common carrier pipelines. Shippers may protest our pipeline tariff filings, and the FERC may investigate new or changed tariff rates. Further, other than for rates set under market-based rate authority, the FERC may order refunds of amounts collected under newly filed rates that are determined by the FERC to exceed what the FERC determines to be a just and reasonable level. In addition, shippers may challenge tariff rates even after the rates have been deemed final and effective. The FERC may also investigate such rates absent shipper complaint. 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. The current index (which runs through June 30, 2014) is measured by the year-over-year change in the Bureau of Labor’s producer price index for finished goods, plus 2.65%. 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 increase 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

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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.

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 December 2006, the FERC issued an order addressing income tax allowance in rates, in which it reaffirmed prior statements regarding its income tax allowance policy, but raised a new issue regarding the implications of the FERC’s policy statement for publicly traded partnerships. The FERC noted that the tax deferral features of a publicly traded partnership may cause some investors to receive, for some indeterminate duration, cash distributions in excess of their taxable income, creating an opportunity for those investors to earn additional return, funded by ratepayers. Responding to this concern, the FERC adjusted the equity rate of return of the pipeline at issue downward based on the percentage by which the publicly traded partnership’s cash flow exceeded taxable income. Requests for rehearing of the order are currently pending before the FERC.

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, 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. How the FERC’s policy statement 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 FERC instituted a rulemaking proceeding in July 2007 to determine whether any changes should be made to the FERC’s methodology for determining pipeline equity returns to be included in cost-of-service based rates. The FERC determined that it would retain its current methodology for determining return on equity but that, when stock prices and cash distributions of tax pass-through entities are used in the return on equity calculations, the growth forecasts for those entities should be reduced by 50%. Despite the FERC’s determination, some complainants in rate proceedings have advocated that the FERC disallow the full use of cash distributions in the return on equity calculation. If the FERC were to disallow the use of full cash distributions in the return on equity calculation, such a result might adversely affect our ability to achieve a reasonable return.

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

The STB, a part of the DOT, has jurisdiction over interstate pipeline transportation and rate regulations of anhydrous ammonia. Transportation rates must be reasonable, and a pipeline carrier may not unreasonably discriminate among its shippers. If the STB finds that a carrier’s rates violate these statutory commands, it may prescribe a reasonable rate. In determining a reasonable rate, the STB will consider, among other factors, the effect of the rate on the volumes transported by that carrier, the carrier’s revenue needs and the availability of other economic transportation alternatives. The STB does not provide rate relief unless shippers lack effective competitive alternatives. If the STB determines that effective competitive alternatives are not available and we hold market power, then we may be required to show that our rates are reasonable.

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, 2013, our power costs equaled approximately $40.1 million, or 8.8% 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.

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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.

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, 2013, 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 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.

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

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of us as a corporation would result in a material reduction in our anticipated cash flow 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, 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 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. In addition, the costs of any contest between us and the IRS will result in a reduction in cash available for distribution to our unitholders. 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.

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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, 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.

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 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 refineries, pipelines, terminals, crude oil tanks and related equipment and make repairs and replacements when necessary or appropriate. We believe that our refineries, 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 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 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

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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.

We are also a party to additional claims and legal proceedings arising in the ordinary course of business. 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.

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 10, 2014, we had 627 holders of record of our common units. The high and low sales prices (composite transactions) by quarter for the years ended December 31, 2013 and 2012 were as follows:



	Price Range of Common Unit
	High		Low
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
Year 2012
4th Quarter	$	51.97	$	39.07
3rd Quarter	54.88		48.44
2nd Quarter	59.51		49.38
1st Quarter	62.64		55.12

The cash distributions applicable to each of the quarters in the years ended December 31, 2013 and 2012 were as follows:




	Record Date	Payment Date	Amount Per Unit
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
Year 2012
4th Quarter	February 11, 2013	February 14, 2013	$	1.095
3rd Quarter	November 9, 2012	November 14, 2012	1.095
2nd Quarter	August 7, 2012	August 10, 2012	1.095
1st Quarter	May 8, 2012	May 11, 2012	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%

Our general partner’s incentive distributions for the years ended December 31, 2013 and 2012 totaled $43.2 million and $41.2 million, respectively. The general partner’s share of our distributions for the years ended December 31, 2013 and 2012 was 13.0% in each year due to the impact of the incentive distributions.

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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,
	2013 (a)			2012 (a)			2011		2010		2009
	(Thousands of Dollars, Except Per Unit Data)
Statement of Income Data:
Revenues	$	3,463,732		$	5,945,736		$	6,257,629	$	4,395,083	$	3,854,895
Operating (loss) income	(19,121		)	(18,168		)	310,883		306,747		277,729
(Loss) income from continuing operations	(185,509		)	(166,001		)	218,674		243,931		229,360
(Loss) income from continuing operations per unit applicable to limited partners	(2.89		)	(2.79		)	2.74		3.27		3.55
Cash distributions per unit applicable to limited partners	4.380			4.380			4.360		4.280		4.245

	December 31,
	2013			2012			2011		2010		2009
	(Thousands of Dollars)
Balance Sheet Data:
Property, plant and equipment, net	$	3,310,653		$	3,238,460		$	3,430,468	$	3,187,457	$	3,028,196
Total assets	5,032,186			5,613,089			5,881,190		5,386,393		4,774,673
Long-term debt, less current portion	2,655,553			2,124,582			1,928,071		2,136,248		1,828,993
Total partners’ equity	1,903,794			2,584,995			2,864,335		2,702,700		2,484,968


(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 6 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.

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 it is 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 terminalling and storage of petroleum products, the transportation of petroleum products and anhydrous ammonia, 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, 2013. Our Management’s Discussion and Analysis of Financial Condition and Results of Operations is presented in six sections:


•	Overview


•	Results of Operations


•	Trends and Outlook


•	Liquidity and Capital Resources


•	Related Party Transactions


•	Critical Accounting Policies

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 6 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for a discussion of the goodwill impairment loss.

Acquisitions and Dispositions

Terminal Facilities Held for Sale. We identified several non-strategic, underperforming terminal facilities, and as of December 31, 2013, we reclassified 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 these assets, previously in the storage segment, as discontinued operations for all periods presented, including an impairment loss of $102.5 million for the year ended December 31, 2013. Please refer to Note 5 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for a discussion of these assets held for sale.

San Antonio Refinery Acquisition and Disposition. On April 19, 2011, we purchased certain refining and storage assets, inventory and other working capital items from AGE Refining, Inc. The assets consisted of a fuels refinery in San Antonio, Texas (the San Antonio Refinery) and 0.4 million barrels of aggregate storage capacity. On January 1, 2013, we sold the San Antonio Refinery and related assets, which included inventory, a terminal in Elmendorf, Texas and a pipeline connecting the

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terminal and refinery for approximately $117.0 million (the San Antonio Refinery Sale). As of December 31, 2012, we reclassified the assets related to the sale of the San Antonio Refinery as “Assets held for sale” on the consolidated balance sheet. We have presented the results of operations for the San Antonio Refinery and related assets, previously reported in the fuels marketing and pipeline segments, as discontinued operations for all periods presented. 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 San Antonio Refinery Sale.

TexStar Asset Acquisition. On December 13, 2012, NuStar Logistics completed its acquisition of the TexStar Crude Oil Assets (as defined below), including 100% of the partnership interest in TexStar Crude Oil Pipeline, LP, from TexStar Midstream Services, LP and certain of its affiliates (collectively, TexStar) for $325.4 million (the TexStar Asset Acquisition). 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.

Asphalt Sale. On September 28, 2012, we sold a 50% ownership interest (the Asphalt Sale) in NuStar Asphalt LLC (Asphalt JV), previously a wholly owned subsidiary, to an affiliate of Lindsay Goldberg LLC (Lindsay Goldberg), a private investment firm. Asphalt JV 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 Asphalt JV, while we retained the Class B equity interests with a fair value of $52.0 million (Class B Interests). The Class A Interests have a distribution preference over the Class B Interests, as well as a liquidation preference. We also received $263.8 million from Asphalt JV 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 (expense) income, net” in the consolidated statements of income for the year ended December 31, 2012.

Upon closing, we deconsolidated Asphalt JV and started reporting our remaining investment in Asphalt JV using the equity method of accounting. Therefore, as of December 31, 2013 and 2012, we have presented our 50% ownership interest in Asphalt JV as “Investment in joint ventures” on the consolidated balance sheet. The consolidated statements of income include the results of operations for Asphalt JV in “Equity in (loss) earnings of joint ventures” commencing on September 28, 2012. Because of our continued involvement with Asphalt JV, we have not presented the results of operations for the Asphalt Operations prior to closing as discontinued operations.

In anticipation of the 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 $244.3 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 asphalt and 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 Asphalt Sale, the related asset impairments and associated fair value measurements.

In February 2014, we divested of our remaining 50% ownership interest in Asphalt JV. See Note 29 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data”for additional discussion.

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: storage, pipeline, and fuels marketing. For a more detailed description of our segments, please refer to Segments under Item 1. “Business.”

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

Pipeline. We own common carrier refined product pipelines covering approximately 5,463 miles, consisting of the Central West System, the East Pipeline and the North Pipeline. In addition, we own a 2,000 mile anhydrous ammonia pipeline and 1,180 miles of crude oil pipelines.

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Fuels Marketing. In 2013, we changed the name of the “Asphalt and Fuels Marketing” segment to the “Fuels Marketing” segment. This name more accurately reflects the operations that remain after the Asphalt Sale and the San Antonio Refinery Sale. Our fuels marketing segment includes our fuels marketing operations and, prior to the Asphalt Sale, the Asphalt Operations. 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 storage and pipeline 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 storage and pipeline assets.

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RESULTS OF OPERATIONS

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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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.

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Segment Operating Highlights

(Thousands of Dollars, Except Barrel/Day Information)



	Year Ended December 31,
	2013			2012			Change
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	)

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

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
Asset and goodwill 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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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 Asphalt JV, which we entered into simultaneously with the 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 6 of the Condensed Notes to Consolidated Financial Statements in Item 1. “Financial Statements” for further discussion of this goodwill impairment.

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;

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•	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. Please refer to Note 17 of the Condensed Notes to Consolidated Financial Statements in Item 1. “Financial Statements” for further discussion; 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.

Fuels Marketing

The consolidated statements of income (loss) include the results of operations for Asphalt JV in “Equity in (loss) earnings 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. The table below 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

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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 Asphalt Sale in September 2012. 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 are now reimbursed by Asphalt JV for corporate support services under a services agreement between Asphalt JV 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 Asphalt JV in 2013, which continued to suffer from weak asphalt margins.

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 Asphalt JV under the $250.0 million seven-year unsecured revolving credit facility. We entered into this credit facility with Asphalt JV in connection with the 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 Asphalt JV.

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 Asphalt Sale in 2012 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 Condensed Notes to Consolidated Financial Statements in Item 1. “Financial Statements” for further discussion

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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.

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Year Ended December 31, 2012 Compared to Year Ended December 31, 2011

Financial Highlights

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



	Year Ended December 31,
	2012			2011			Change
Statement of Income Data:
Revenues:
Service revenues	$	870,157		$	820,623		$	49,534
Product sales	5,075,579			5,437,006			(361,427		)
Total revenues	5,945,736			6,257,629			(311,893		)

Costs and expenses:
Cost of product sales	4,930,174			5,175,710			(245,536		)
Operating expenses	526,145			506,213			19,932
General and administrative expenses	104,756			103,050			1,706
Depreciation and amortization expense	159,789			161,773			(1,984		)
Asset impairment loss	249,646			—			249,646
Goodwill impairment loss	22,132			—			22,132
Gain on legal settlement	(28,738		)	—			(28,738		)
Total costs and expenses	5,963,904			5,946,746			17,158

Operating (loss) income	(18,168		)	310,883			(329,051		)
Equity in (loss) earnings of joint ventures	(9,378		)	11,458			(20,836		)
Interest expense, net	(90,535		)	(81,539		)	(8,996		)
Interest income from related party	1,219			—			1,219
Other expense, net	(24,689		)	(3,573		)	(21,116		)
(Loss) income from continuing operations before income tax expense	(141,551		)	237,229			(378,780		)
Income tax expense	24,450			18,555			5,895
(loss) income from continuing operations	(166,001		)	218,674			(384,675		)
(Loss) income from discontinued operations, net of tax	(61,236		)	2,927			(64,163		)
Net (loss) income	$	(227,237	)	$	221,601		$	(448,838	)
Net (loss) income per unit applicable to limited partners:
Continuing operations	$	(2.79	)	$	2.74		$	(5.53	)
Discontinued operations	(0.82		)	0.04			(0.86		)
Total	$	(3.61	)	$	2.78		$	(6.39	)
Weighted-average limited partner units outstanding	72,957,417			65,018,301			7,939,116

Annual Highlights

For the year ended December 31, 2012, we reported a net loss of $227.2 million, compared to net income of $221.6 million for the year ended December 31, 2011, primarily due to an operating loss of $296.8 million in the fuels marketing segment. The operating loss of the fuels marketing segment mainly resulted from an asset impairment charge of $266.4 million in the second quarter of 2012 related to the goodwill and long-lived assets of the Asphalt Operations. In addition, the equity in loss of joint ventures of $9.4 million and other expense of $24.7 million for the year ended December 31, 2012 were primarily related to Asphalt JV and associated loss upon deconsolidation. The loss from discontinued operations of $61.2 million also contributed to the decrease in net income, which was mainly attributable to the San Antonio Refinery. Discontinued operations also include the results of operations for certain storage assets that were classified as “Assets held for sale” on the consolidated balance sheet as of December 31, 2013.

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Segment Operating Highlights

(Thousands of Dollars, Except Barrel/Day Information)



	Year Ended December 31,
	2012			2011			Change
Storage:
Throughput (barrels/day)	765,556			693,269			72,287
Throughput revenues	$	95,612		$	80,246		$	15,366
Storage lease revenues	482,454			466,381			16,073
Total revenues	578,066			546,627			31,439
Operating expenses	288,881			267,198			21,683
Depreciation and amortization expense	88,217			82,921			5,296
Asset impairment loss	2,126			—			2,126
Segment operating income	$	198,842		$	196,508		$	2,334

Pipeline:
Refined products pipelines throughput (barrels/day)	498,321			514,261			(15,940		)
Crude oil pipelines throughput (barrels/day)	345,648			317,427			28,221
Total throughput (barrels/day)	843,969			831,688			12,281
Throughput revenues	$	340,455		$	311,514		$	28,941
Operating expenses	128,987			113,946			15,041
Depreciation and amortization expense	52,878			51,165			1,713
Segment operating income	$	158,590		$	146,403		$	12,187

Fuels Marketing:
Product sales and other revenue	$	5,086,383		$	5,455,659		$	(369,276	)
Cost of product sales	4,957,100			5,205,574			(248,474		)
Gross margin	129,283			250,085			(120,802		)
Operating expenses	148,458			157,282			(8,824		)
Depreciation and amortization expense	11,253			20,949			(9,696		)
Asset and goodwill impairment loss	266,357			—			266,357
Segment operating (loss) income	$	(296,785	)	$	71,854		$	(368,639	)

Consolidation and Intersegment Eliminations:
Revenues	$	(59,168	)	$	(56,171	)	$	(2,997	)
Cost of product sales	(26,926		)	(29,864		)	2,938
Operating expenses	(40,181		)	(32,213		)	(7,968		)
Total	$	7,939		$	5,906		$	2,033

Consolidated Information:
Revenues	$	5,945,736		$	6,257,629		$	(311,893	)
Cost of product sales	4,930,174			5,175,710			(245,536		)
Operating expenses	526,145			506,213			19,932
Depreciation and amortization expense	152,348			155,035			(2,687		)
Asset and goodwill impairment loss	268,483			—			268,483
Segment operating income	68,586			420,671			(352,085		)
General and administrative expenses	104,756			103,050			1,706
Other depreciation and amortization expense	7,441			6,738			703
Other asset impairment loss	3,295			—			3,295
Gain on legal settlement	(28,738		)	—			(28,738		)
Consolidated operating (loss) income	$	(18,168	)	$	310,883		$	(329,051	)

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Storage

Throughput revenues increased $15.4 million and throughputs increased 72,287 barrels per day for the year ended December 31, 2012, compared to the year ended December 31, 2011, primarily due to:


•	an increase in revenues of $6.6 million and an increase in throughputs of 23,547 barrels per day at our Corpus Christi crude storage tank facility due to higher volumes from the Eagle Ford Shale region. In 2012, we changed this facility from a lease-based to a throughput-based facility in connection with the Eagle Ford Shale projects in our pipeline segment;


•	an increase in revenues of $3.2 million and an increase in throughputs of 23,711 barrels per day at our Benicia crude oil storage tanks due to a turnaround in the first quarter of 2011 at the refinery served by the crude oil storage tanks;


•	an increase in revenues of $2.7 million and an increase in throughputs of 11,566 barrels per day at our Paulsboro terminal and certain terminals serving the McKee refinery as customers shifted volumes to our terminals in 2012; and


•	an increase in revenues of $1.4 million and an increase in throughputs of 718 barrels per day at our Edinburg, Texas and Harlingen, Texas terminals due to a full year of ethanol blending services in 2012 that started in the third quarter of 2011.

Storage lease revenues increased $16.1 million for the year ended December 31, 2012, compared to the year ended December 31, 2011, primarily due to:


•	an increase of $36.7 million at our St. James terminal resulting from completed tank expansion projects and the unit train offloading facility project; and


•	an increase of $2.4 million at our St. Eustatius terminal facility, mainly due to rate escalations and increased reimbursable revenues.

These increases in revenues were partially offset by:


•	a decrease in revenues of $9.8 million at our Point Tupper terminal facility, mainly due to decreased dockage and throughputs, which were partially offset by rate escalations;


•	a decrease in revenues of $7.0 million due to the sale of five refined product terminals in April 2012;


•	a decrease in revenues of $6.6 million at our Corpus Christi crude storage tank facility due to the change to throughput-based fees in 2012; and


•	a decrease in revenues of $1.9 million at our UK and Amsterdam terminals, mainly due to the effect of foreign exchange rates and a decrease in customer product movements.

Operating expenses increased $21.7 million for the year ended December 31, 2012, compared to the year ended December 31, 2011, primarily due:


•	an increase of $6.6 million associated with cancelled capital projects, mainly at our St. James and St. Eustatius terminals;


•	an increase of $4.0 million in reimbursable expenses, mainly for tank cleanings at our Piney Point terminal and expenses associated with our atmospheric distillation unit at our St. Eustatius terminal. Reimbursable expenses are charged back to our customers and are offset by an increase in reimbursable revenues;


•	an increase of $3.5 million in other operating expenses mainly due to rectifying a contaminated tank at our St. Eustatius terminal; and


•	an increase of $1.9 million in internal overhead expense primarily as a result of fewer capital projects.

Depreciation and amortization expense increased $5.3 million for the year ended December 31, 2012, compared to the year ended December 31, 2011, primarily due to the completion of the St. James terminal unit train and tank expansion

projects.

The asset impairment loss of $2.1 million for the year ended December 31, 2012 represents the write-down of the carrying value of one of our terminals due to changing market conditions that reduced the estimated cash flows for that terminal.

Pipeline

Revenues increased $28.9 million and throughputs increased 12,281 barrels per day for the year ended December 31, 2012, compared to the year ended December 31, 2011, primarily due to:


•	an increase in revenues of $13.5 million and an increase in throughputs of 37,948 barrels per day on crude oil pipelines that serve Eagle Ford Shale production in South Texas, which consist of pipelines that were placed in service in the second and third quarters of 2011, as well as pipelines that were placed in service in the fourth quarter of 2012, including pipelines acquired from TexStar;


•	an increase in revenues of $7.2 million on the Ammonia Pipeline, while throughputs remained flat, due to increased long-haul deliveries resulting in a higher average tariff;

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•	an increase in revenues of $4.3 million and an increase in throughputs of 1,940 barrels per day on the North Pipeline, mainly due to an increase in the annual index adjustment and the completion of an expansion project at the Mandan refinery in June 2012;


•	an increase in revenues of $3.4 million and an increase in throughputs of 8,937 barrels per day on refined product pipelines serving the Three Rivers refinery, mainly due to a turnaround and operational issues in 2011 at the refinery and additional volumes delivered to a third-party terminal beginning in the third quarter of 2012;


•	an increase in revenues of $2.7 million on the East Pipeline, despite a decrease in throughputs of 6,586 barrels per day, due to higher average tariffs resulting from increased long-haul deliveries and an increase in the annual index adjustment. Fewer long-haul deliveries occurred in 2011 due to supply issues caused by flooding in the Midwest; and


•	an increase in revenues of $1.3 million and an increase in throughputs of 8,590 barrels per day on crude oil pipelines serving the Ardmore refinery due to a turnaround and operational issues in 2011.

These increases in revenues and throughputs were partially offset by:


•	a decrease in revenues of $2.8 million and a decease in throughputs of 8,684 barrels per day on the Houston pipeline as it was being converted to new service; and


•	a decrease in revenues of $1.1 million and a decrease in throughputs of 25,901 barrels per day on pipelines serving the McKee refinery, primarily due to a turnaround at the McKee refinery in April and May 2012. The decrease in revenues was partially offset by throughput deficiency payments received in 2012 related to one of the pipelines serving the McKee refinery.

Operating expenses increased $15.0 million for the year ended December 31, 2012, compared to the year ended December 31, 2011, mainly due to temporary barge rental costs to move a customer’s product associated with Eagle Ford Shale projects and losses on product imbalances on the East Pipeline.

Fuels Marketing

Sales and cost of product sales decreased $369.3 million and $248.5 million, respectively, resulting in a decrease in total gross margin of $120.8 million for the year ended December 31, 2012, compared to the year ended December 31, 2011. The gross margin from the Asphalt Operations decreased $86.1 million for the year ended December 31, 2012, compared to the year ended December 31, 2011, partly due to the deconsolidation of Asphalt JV on September 28, 2012. The gross margin decrease was also attributable to weak demand for asphalt, resulting in a decrease in volumes sold and a decrease in gross margin per barrel. The gross margin per barrel had decreased to $4.79 for the nine months ended September 30, 2012, compared to $7.49 for the twelve months ended December 31, 2011.

The gross margin from our fuels marketing operations decreased $34.7 million for the year ended December 31, 2012, compared to the year ended December 31, 2011, mainly due to rising costs, which outpaced rising sales prices, and hedge losses associated with fuel oil sales. In addition, the gross margin from bunker fuel sales decreased as a result of a decrease in the gross margin per barrel, despite an increase in volumes sold. We reduced the scope of our bunker fuel operations in 2012 by liquidating our inventory and exiting two markets where results had been weak, which contributed to the decrease in gross margin for bunker fuel sales. Furthermore, during the second quarter of 2012, crude oil prices fell sharply, causing a similar decline in prices for our fuel oil and bunker fuel. During this period of declining prices, we did not hedge our fuel oil and bunker fuel inventories, and the gross margin earned for sales of those products declined significantly.

Operating expenses decreased $8.8 million for the year ended December 31, 2012, compared to the year ended December 31, 2011, primarily due to the Asphalt Sale. Decreases in operating expenses for the Asphalt Operations were partially offset by increased fuel and vessel costs associated with bunker fuel sales and increased railcar costs associated with fuel oil sales. In addition, we incurred employee benefit costs in the fourth quarter of 2012 resulting from the Asphalt Sale.

Depreciation and amortization expense decreased $9.7 million for the year ended December 31, 2012, compared to the year ended December 31, 2011, as a result of reclassifying depreciable assets related to the Asphalt Operations to “Assets held for sale” on the consolidated balance sheet and discontinuing depreciation of these assets as of June 30, 2012.

The asset impairment loss of $266.4 million for year ended December 31, 2012 represents the write-down of the carrying value of our long-lived assets related to the Asphalt Operations, including fixed assets, goodwill, intangible assets and other long-term assets, in the second quarter of 2012.

Consolidation and Intersegment Eliminations

Revenue, cost of product sales and operating expense eliminations primarily relate to storage and transportation fees charged to the fuels marketing segment by the pipeline and storage segments.

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General

The other asset impairment loss of $3.3 million for the year ended December 31, 2012 represented 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.

For the year ended December 31, 2012, we recorded equity in loss of joint ventures of $9.4 million, compared to equity in earnings of joint ventures of $11.5 million for the year ended December 31, 2011, primarily due to a $16.1 million loss resulting from our investment in Asphalt JV for the year ended December 31, 2012.

Interest expense, net increased $9.0 million for the year ended December 31, 2012, compared to the year ended December 31, 2011. We had reduced benefits from interest rate swaps for the year ended December 31, 2012, compared to the year ended December 31, 2011, as we had fewer fixed-to-floating interest rate swaps in 2012 compared to 2011, and in February 2012, we began recognizing the interest expense related to terminated forward-starting interest rate swap agreements. In addition, we incurred higher interest rates and letter of credit fees on the new $1.5 billion five-year revolving credit agreement (the 2012 Revolving Credit Agreement).

Interest income from related party of $1.2 million for the year ended December 31, 2012 represents the interest earned on a $250.0 million seven-year unsecured revolving credit facility with Asphalt JV. Please refer to Note 18. Related Party Transactions of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for additional information on our agreements with Asphalt JV.

Other expense, net increased $21.1 million for the year ended December 31, 2012, compared to the year ended December 31, 2011, mainly due to a $23.8 million loss associated with the deconsolidation of Asphalt JV in September 2012. For the year ended December 31, 2011, other expense, net included $5.0 million in costs associated with the early termination of a third-party storage agreement at the Paulsboro, New Jersey asphalt refinery and a contingent loss adjustment of $3.3 million related to a legal settlement.

Income tax expense increased $5.9 million for the year ended December 31, 2012, compared to the year ended December 31, 2011, 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, which was partially offset by lower taxable income.

For the year ended December 31, 2012, we recorded a loss from discontinued operations of $61.2 million, compared to income from discontinued operations of $2.9 million for the year ended December 31, 2011, which is mainly attributable to the San Antonio Refinery. The gross margin from the San Antonio Refinery decreased $58.8 million for the year ended December 31, 2012, compared to the year ended December 31, 2011, mainly due to hedge losses and falling sales prices coupled with higher weighted-average costs, which resulted in an overall negative gross margin.

We entered into commodity swap contracts associated with the San Antonio Refinery to fix the purchase price of crude oil and sales prices of refined products for a portion of the expected production of the San Antonio Refinery, thereby attempting to mitigate the 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 these 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. During the fourth quarter of 2011, we decided to adjust the refinery’s operations, which caused a shift in the future production yields of the San Antonio Refinery. This change caused certain forecasted sales of gasoline products to be replaced with distillate sales; therefore, we concluded these forecasted gasoline sales were probable not to occur, and we discontinued cash flow hedging treatment for the related commodity contracts. We recorded gains of $16.4 million related to these contracts for the year ended December 31, 2011, including $15.1 million which we reclassified from accumulated other comprehensive loss.

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TRENDS AND OUTLOOK

Strategic Redirection and Its Impact

In 2012, we embarked on a strategic redirection. The first goal of the strategic redirection was to focus on our core, fee-based businesses, storage and pipelines. The second goal was to reduce earnings volatility and working capital requirements stemming from the fuels marketing segment. Since then, we have made significant progress on our first goal through the development of a number of internal growth projects, as well as the TexStar Asset Acquisition in December 2012. We have achieved our second goal by selling a 50% ownership interest in our asphalt business in September 2012, which allowed us to deconsolidate the results of our remaining interest in those operations, selling the San Antonio Refinery in January 2013 and divesting of our remaining 50% ownership interest in Asphalt JV in February 2014.

These changes have moved us in the right direction, and, in 2014, we are working to execute and build on our strategy, through focusing on our in-progress and planned pipeline and storage capital projects and also identifying additional opportunities for internal growth or synergistic acquisitions.

Storage Segment

We expect our storage segment to benefit from the completion of a second rail-car offloading facility at our St. James, Louisiana terminal in the fourth quarter of 2013 and from additional storage throughputs associated with the completion of Eagle Ford Shale projects.

However, continued backwardation of the forward pricing curve has resulted in reduced demand for storage at certain of our terminal locations. The reduced demand is putting downward pressure on storage rates in certain markets as some of our storage contracts come up for renewal, thus negatively affecting our earnings. In addition, we expect the segment to be impacted by lower profit sharing on our unit train at our St. James, Louisiana terminal resulting from the narrowing of the LLS to WTI spread. Although we expect earnings for the first quarter of 2014 to be lower than the same period of 2013, the full-year earnings for 2014 are expected to be comparable to 2013, excluding the non-cash charges in 2013.

Pipeline Segment

We expect that our pipeline segment earnings for the first quarter and full year of 2014 will exceed comparable periods in 2013, mainly due to higher throughputs resulting from our Eagle Ford Shale project completed in August 2013. Recently, we expanded our private dock at our Corpus Christi crude storage tank facility, and the increased efficiency and capacity at that dock will, in turn, expand the system’s capability to ship additional barrels into Corpus Christi.

For the remainder of the year, we also expect to benefit from a pipeline expansion project that should be completed in the second quarter of 2014, as well as the July 1, 2013 tariff increase on pipelines regulated by the Federal Energy Regulatory Commission.

Fuels Marketing Segment

We expect that first quarter 2014 results for our remaining fuels marketing business will improve over the same period in 2013, primarily due to higher projected earnings from our bunker fuel operations. Last year, during the third quarter, we entered into a new bunker fuel supply agreement, which reduced our working capital requirements and allowed us to reduce operating costs. We expect to continue to reduce both working capital and costs for this segment during first quarter of 2014. Overall, we expect the full year 2014 results in this segment to exceed 2013 results. However, earnings in this segment, as in any margin-based business, are subject to many factors that can raise or lower margins, which may cause the segment’s actual results to vary significantly from our forecast. For the full year 2014, we expect our fuels marketing segment to constitute approximately 5% of total segment operating income.

Our outlook for the partnership may change as it is based on our continuing evaluation of a number of factors, including factors outside our control, such as the price of crude oil, the state of the economy and changes to refinery maintenance schedules, that affect demand for crude oil, refined products and ammonia, as well as demand for our storage and transportation services. Please see Item 1A. “Risk Factors” for further description of important risks affecting our operations.

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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 Asphalt JV, acquisitions and operating expenses.

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.

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 the 2012 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 from external sources, primarily borrowings under the 2012 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 the 2012 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 in 2012 and 2011. For the years ended December 31, 2012 and 2011, we did not generate sufficient cash from operations to exceed our distribution and reliability capital requirements. Those shortfalls in cash from operations in 2012 and 2011 resulted primarily from our fuels marketing segment. Our 2011 acquisition of the San Antonio refinery, along with expansion in other aspects of the segment, significantly increased our working capital requirements, which in turn reduced our net cash provided by operating activities during that fiscal year. In 2012, poor margins in the segment drove our earnings down sharply and again reduced our net cash provided by operating activities below our distribution and reliability capital requirements.

Cash Requirements and Sources in 2014 and 2013. For the year ended December 31, 2013, our cash flow from operations was sufficient to cover our distributions to our partners and our reliability capital expenditures, mainly due to our strategic redirection discussed previously in the Trends and Outlook section. For 2014, we currently expect to produce cash from operations in excess of our distribution. We also expect to fund our reliability capital expenditures with cash from operations as well as from other sources of liquidity as described below.

Cash Flows for the Years Ended December 31, 2013, 2012 and 2011

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



	Year Ended December 31,
	2013			2012			2011
	(Thousands of Dollars)
Net cash provided by (used in):
Operating activities	$	485,219		$	299,203		$	94,468
Investing activities	(310,961		)	(345,800		)	(443,254		)
Financing activities	(149,350		)	110,669			186,721
Effect of foreign exchange rate changes on cash	(7,767		)	2,033			(1,559		)
Net increase (decrease) in cash and cash equivalents	$	17,141		$	66,105		$	(163,624	)

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

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million for the year ended December 31, 2012, mainly due to losses from our investment in Asphalt JV. 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. Please refer to the Working Capital Requirements section below for a discussion of the changes in working capital.

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 Asphalt JV under the NuStar JV Facility.

In connection with the Asphalt Sale, we agreed to provide Asphalt JV with an unsecured revolving credit facility in an aggregate principal amount not to exceed $250.0 million for a term of seven years (the NuStar JV Facility), and to provide credit support, such as guarantees, letters of credit and cash collateral, as applicable, of up to $150.0 million. The NuStar JV Facility is used to fund working capital and general corporate needs of Asphalt JV. During the year ended December 31, 2013, we advanced $81.0 million, net of repayments, to Asphalt JV under the NuStar JV Facility.

Net cash provided by operating activities for the year ended December 31, 2012 was $299.2 million, compared to $94.5 million for the year ended December 31, 2011. For the year ended December 31, 2012, we reported a net loss of $227.2 million, compared to net income of $221.6 million for the year ended December 31, 2011. The net loss for the year ended December 31, 2012 included $271.8 million of non-cash asset impairment charges. In addition, working capital decreased by $90.2 million for the year ended December 31, 2012, compared to an increase of $265.5 million for the year ended December 31, 2011. Please refer to the Working Capital Requirements section below for a discussion of the changes in working capital. Cash flows from operating activities for the year ended December 31, 2012 also include an adjustment to net loss for a pre-tax, non-cash gain on a legal settlement of $28.7 million.

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 Asphalt Sale were used to fund our distributions to unitholders and our general partner, the TexStar Asset Acquisition and strategic and reliability capital expenditures.

Our significant investment in working capital in 2011 caused our cash generated from operations to fall short of our cash requirements for reliability capital expenditures and distributions. As a result, we utilized borrowings under our revolving credit agreement and Gulf Opportunity Zone revenue bonds, combined with cash on hand, to fund that shortfall, our strategic capital expenditures and acquisitions. We used the net proceeds of $324.0 million from our issuance of common units, including the general partner contribution to maintain its 2% general partner interest, to reduce outstanding borrowings under our 2007 revolving credit agreement.

Revolving Credit Agreement

NuStar Logistics is a party to the 2012 Revolving Credit Agreement, which includes the ability to borrow up to the equivalent of $250.0 million in Euros. On December 4, 2013, we amended the 2012 Revolving Credit Agreement to add the ability to borrow up to the equivalent of $250.0 million in British Pounds Sterling. The 2012 Revolving Credit Agreement matures on May 2, 2017. Obligations under the 2012 Revolving Credit Agreement are guaranteed by NuStar Energy and NuPOP. NuPOP will be released from its guarantee of the 2012 Revolving Credit Agreement when it no longer guarantees NuStar Logistics’ public debt instruments.

The 2012 Revolving Credit Agreement contains customary restrictive covenants, including requiring 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 indebtedness to consolidated EBITDA, as defined in the 2012 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 2012 Revolving Credit Agreement permits unlimited investments in joint ventures and unconsolidated subsidiaries, provided that no default exists, 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 2012 Revolving Credit Agreement to an amount less than the total amount available for borrowing. As of December 31, 2013, our consolidated debt coverage ratio was 4.4x, and we had $829.3 million available for borrowing.

Letters of credit issued under our 2012 Revolving Credit Agreement totaled $167.6 million as of December 31, 2013. Letters of credit are limited to $750.0 million and also may restrict the amount we can borrow under the 2012 Revolving Credit Agreement.

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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.

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 2012 Revolving Credit Agreement.

The following table summarizes the Gulf Opportunity Zone Revenue Bonds outstanding as of December 31, 2013:



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	$	—	0.10	%
July 15, 2010	July 1, 2040	100,000		101,315			100,000		—		0.10	%
October 7, 2010	October 1, 2040	50,000		50,658		(a)	24,580		25,420		0.11	%
December 29, 2010	December 1, 2040	85,000		86,118		(a)	26,924		58,076		0.11	%
August 29, 2011	August 1, 2041	75,000		75,986			75,000		—		0.10	%
	Total	$	365,440	$	370,246		$	281,944	$	83,496


(a)	Letters of credit issued under the 2012 Revolving Credit Agreement.

Shelf Registration Statements

On June 18, 2013, the Securities and Exchange Commission declared effective our shelf registration statement on Form S-3, which permits us to offer and sell various types of securities, including NuStar Energy common units and debt securities of NuStar Logistics and NuPOP.

We also have a shelf registration statement that became effective on April 29, 2011 that permits us to sell various types of securities, including NuStar Energy common units and debt securities of NuStar Logistics and NuPOP, having an aggregate value of up to $200.0 million.

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 proceeds of approximately $296.0 million, net of the underwriters’ discount and deferred issuance costs of $4.0 million, which we used for general partnership purposes, including repayment of outstanding borrowings under our 2012 Revolving Credit Agreement. The interest on the 6.75% Senior Notes is payable semi-annually in arrears on February 1 and August 1 of each year beginning on February 1, 2014.

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 proceeds of approximately $390.9 million, net of $11.6 million of deferred issuance costs, which we used for general partnership purposes, including repayment of outstanding borrowings under our 2012 Revolving Credit Agreement. The Subordinated Notes bear interest at a fixed annual rate of 7.625%, payable quarterly in arrears on January 15, April 15, July 15 and October 15 of each year 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 on January 15, April 15, July 15 and October 15 of each year, commencing April 15, 2018, unless payment is deferred in accordance with the terms of the notes.

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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. The interest on the 4.75% senior notes is payable semi-annually in arrears on February 1 and August 1 of each year beginning on August 1, 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 to maintain its 2% general partner interest, for general partnership purposes, including repayments of outstanding borrowings under our 2012 Revolving Credit Agreement and working capital purposes.

On December 9, 2011, we issued 6,037,500 common units representing limited partner interests at a price of $53.45 per unit. We used the net proceeds from this offering of $318.0 million, including a contribution of $6.6 million from our general partner to maintain its 2% general partner interest, mainly to reduce outstanding borrowings under our 2007 revolving credit agreement.

On May 23, 2011, we entered into an Equity Distribution Agreement (the Equity Distribution Agreement) with Citigroup Global Markets Inc. (Citigroup). Under the Equity Distribution Agreement, we may from time to time sell an aggregate of up to $200.0 million NuStar Energy common units representing limited partner interests, using Citigroup as our sales agent. Sales of common units will be made by means of ordinary brokers’ transactions on the New York Stock Exchange at market prices, in block transactions or as otherwise agreed by us and Citigroup. Under the terms of the Equity Distribution Agreement, we may also sell common units to Citigroup as principal for its own account at a price to be agreed upon at the time of sale. In September and October 2011, we sold 108,029 NuStar Energy common units under the Equity Distribution Agreement for net proceeds of $6.0 million, including a contribution of $0.1 million from our general partner to maintain its 2% general partner interest.

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, 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 2014, we expect to incur approximately $405.0 million to $435.0 million of capital expenditures, including approximately $35.0 million to $45.0 million for reliability capital expenditures and $370.0 million to $390.0 million for strategic capital expenditures, not including acquisitions. We continue to evaluate our capital budget and make changes as economic conditions warrant, and our actual capital expenditures for 2014 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 2014, 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 of inventory and with the seasonality of demand for the products we market.

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This seasonality in demand affects our accounts receivable and accounts payable balances, which vary depending on timing of payments. As a result of the Asphalt Sale and the San Antonio Refinery Sale, our working capital requirements have been significantly reduced.

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 Asphalt JV, which corresponds with the decrease in the receivable from related parties of $58.7 million during the year ended December 31, 2013. The Asphalt JV Crude Oil Supply Agreement terminated effective January 1, 2014. Please refer to Note 19 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplemental Data” for a detailed discussion of our other related party transactions with Asphalt JV.

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,
	2013		2012		2011
	(Thousands of Dollars, Except Per Unit Data)
General partner interest	$	7,844	$	7,486	$	6,630
General partner incentive distribution	43,220		41,242		36,326
Total general partner distribution	51,064		48,728		42,956
Limited partners’ distribution	341,140		325,526		288,550
Total cash distributions	$	392,204	$	374,254	$	331,506

Cash distributions per unit applicable to limited partners	$	4.380	$	4.380	$	4.360

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, 2013 (a)	$	1.095	$	98,051	February 10, 2014	February 14, 2014
September 30, 2013	$	1.095	$	98,051	November 11, 2013	November 14, 2013
June 30, 2013	$	1.095	$	98,051	August 5, 2013	August 9, 2013
March 31, 2013	$	1.095	$	98,051	May 6, 2013	May 10, 2013


(a)	The distribution was announced on January 30, 2014.

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Debt Obligations

As of December 31, 2013, we were a party to the following debt agreements:


•	the 2012 Revolving Credit Agreement due May 2, 2017, with a balance of $503.0 million as of December 31, 2013;

•

NuStar Logistics’: 7.65% senior notes due April 15, 2018 with a face value of $350.0 million; 4.80% senior notes due September 1, 2020 with a face value of $450.0 million; 6.75% senior notes due February 1, 2021 with a face value of $300.0 million; 4.75% senior notes due February 1, 2022 with a face value of $250.0 million; and 7.625% subordinated notes due January 15, 2043 with a face value of $402.5 million; and


•	NuStar Logistics’ $365.4 million Gulf Opportunity Zone Revenue Bonds due from 2038 to 2041.

In February 2013, we repaid the remaining principal balance of $0.6 million on our $12.0 million note payable due to the Port of Corpus Christi Authority of Nueces County, Texas. We also 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 our 2012 Revolving Credit Agreement.

Management believes that, as of December 31, 2013, we are in compliance with all ratios and covenants of the 2012 Revolving Credit Agreement. Our other long-term debt obligations do not contain any financial covenants that differ from those contained in the 2012 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 the debt of our wholly owned subsidiaries:



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

Ratings	BB+	Ba1	BB
Outlook	Stable	Negative	Stable

In January 2013, Moody’s Investor Service Inc. lowered our credit rating to Ba1 from Baa3. This downgrade caused the interest rates on the 2012 Revolving Credit Agreement and NuStar Logistics’ $350.0 million of 7.65% senior notes due 2018 to increase by 0.375% and 0.25%, respectively, effective January 2013. We may also be required to provide additional credit support for certain contracts, although as of December 31, 2013, we have not been required to provide any additional credit support.

Interest Rate Swaps

As of December 31, 2012, we were a party to forward-starting swap agreements for the purpose of hedging interest rate risk. 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 and paid $33.7 million in connection with the terminations. We had no interest rate swaps as of December 31, 2013. Please refer to Note 2 and Note 18 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for a more detailed discussion on our interest rate swaps.

Long-Term Contractual Obligations

The following table presents our long-term contractual obligations and commitments and the related payments due, in total and by period, as of December 31, 2013:



	Payments Due by Period
	2014		2015		2016		2017		2018		Thereafter		Total
	(Thousands of Dollars)
Long-term debt maturities	$	—	$	—	$	—	$	503,036	$	350,000	$	1,767,940	$	2,620,976
Interest payments	130,307		130,307		130,307		123,414		116,103		1,374,244		2,004,682
Operating leases	30,300		24,886		21,274		18,954		16,980		80,090		192,484
Purchase obligations	8,571		5,108		3,841		694		216		—		18,430

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The interest payments calculated for our variable-rate debt are based on the outstanding borrowings and the interest rate as of December 31, 2013. The interest payments on our fixed-rate debt are based on the stated interest rates, the outstanding balances as of December 31, 2013 and interest payment dates.

Our operating leases consist primarily of leases for tugs and barges utilized at our St. Eustatius and Point Tupper facilities 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.

On November 6, 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 CSA). The termination was effective January 1, 2014, and in connection therewith, we also terminated our crude oil supply agreement with Asphalt JV effective January 1, 2014. See Note 19 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for a discussion of our crude oil supply agreement with Asphalt JV.

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 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, 2013 and 2012 are included in Note 15 of 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,
	2013		2012		2011
	(Thousands of Dollars)
Revenues	$	14,897	$	1,990	$	—
Operating expenses	$	122,677	$	133,654	$	138,324
General and administrative expenses	$	58,602	$	62,490	$	66,220
Interest income	$	6,113	$	1,219	$	—
Revenues included in discontinued operations, net of tax	$	3,720	$	3,390	$	1,039
Expenses included in discontinued operations, net of tax	$	6,051	$	14,328	$	12,238

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.

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payable to NuStar GP, LLC as of December 31, 2013 and 2012 of $41.1 million and $18.1 million, respectively, for amounts payable for retiree medical benefits and other post-employment benefits.

Asphalt JV

In connection with the Asphalt Sale, we provided an unsecured revolving credit facility that will be available to fund working capital needs and for general purposes of Asphalt JV in an aggregate principal amount not to exceed $250.0 million for a term of seven years. The NuStar JV Facility matures on September 28, 2019 and bears interest based on either an alternative base rate or a LIBOR-based rate. We recognize interest income over the term of the facility in “Interest income from related party” on the consolidated statements of income. As of December 31, 2013, the interest rate was 3.2%. On December 31, 2013, the face value of our note receivable from Asphalt JV totaled $176.7 million.

In addition, during the term of the NuStar JV Facility, we will provide credit support, such as guarantees, letters of credit and cash collateral, as applicable, of up to $150.0 million. As of December 31, 2013, we provided guarantees for commodity purchases, lease obligations and certain utilities for Asphalt JV with a maximum potential exposure of $79.7 million, plus two guarantees to suppliers that do not specify a maximum amount, but for which we believe any amounts due would be minimal. A majority of the guarantees were in existence prior to the Asphalt Sale and have no expiration date. In the event we are obligated to perform under these guarantees, that amount paid by us will be added to borrowings under the NuStar JV Facility, but it will not reduce the availability under the NuStar Facility.

Also, as of December 31, 2013, we had a receivable from Asphalt JV of $50.7 million mainly associated with crude oil sales under our crude oil supply agreement with Asphalt JV. Please refer to Note 19 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplemental Data” for a detailed discussion of our other related party transactions with Asphalt JV.

CRITICAL ACCOUNTING POLICIES

The preparation of financial statements in accordance with United States 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 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 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.

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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;


•	St. Eustatius and Point Tupper terminal operations; 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.

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 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.

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ITEM 7A.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Interest Rate Risk

We manage our exposure to changing interest rates principally through the use of a combination of fixed-rate debt and variable-rate debt. In addition, we have utilized forward-starting interest rate swap agreements to lock in the rate on the interest payments related to forecasted debt issuances. We have also entered into 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 2012 Revolving Credit Agreement and the Gulf Opportunity Zone Revenue Bonds expose us to increases in applicable interest rates.

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. As a result, we

had no forward-starting interest rate swaps outstanding as of December 31, 2013. During 2012, we terminated all of our outstanding fixed-to-floating interest rate swap agreements, which had an aggregate notional amount of $470.0 million. We had no fixed-to-floating interest rate swaps as of December 31, 2013 and 2012. Please refer to Note 2 of 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, 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		%



	December 31, 2012
	Expected Maturity Dates
	2013			2014		2015		2016		2017			There- after			Total			Fair Value
	(Thousands of Dollars, Except Interest Rates)
Long-term Debt:
Fixed rate	$	514,651		$	—	$	—	$	—	$	—		$	1,050,000		$	1,564,651		$	1,601,985
Weighted-average interest rate	5.7		%	—		—		—		—			5.8		%	5.8		%
Variable rate	$	—		$	—	$	—	$	—	$	440,330		$	365,440		$	805,770		$	775,135
Weighted-average interest rate	—			—		—		—		1.9		%	0.1		%	1.1		%

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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 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.

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 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, 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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	December 31, 2012
	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)	10	$	127.47	N/A		$	(1	)
Futures – short:
(refined products)	55	N/A		$	127.99	$	36
Swaps – long:
(refined products)	11	$	97.76	N/A		$	2
Swaps – short:
(refined products)	36	N/A		$	96.58	$	(51	)

Economic Hedges and Other Derivatives:
Futures – long:
(crude oil and refined products)	88	$	97.60	N/A		$	202
Futures – short:
(crude oil and refined products)	94	N/A		$	100.13	$	(142	)
Swaps – long:
(crude oil and refined products)	5,196	$	93.75	N/A		$	(2,329	)
Swaps – short:
(crude oil and refined products)	6,952	N/A		$	94.43	$	(2,033	)
Forward purchase contracts:
(crude oil)	2,998	$	100.03	N/A		$	12,574
Forward sales contracts:
(crude oil)	2,998	N/A		$	99.68	$	(9,365	)

Total fair value of open positions exposed to commodity price risk						$	(1,107	)

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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, 2013. 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 (1992). Based on this assessment, management believes that, as of December 31, 2013, 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, 2013 has been audited by KPMG LLP, the independent registered public accounting firm who audited our consolidated financial statements included in this Form 10-K. KPMG LLP’s attestation on the effectiveness of our internal control over financial reporting appears on page 62.

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Report of Independent Registered Public Accounting Firm

The Board of Directors of NuStar GP, LLC

and Unitholders of NuStar Energy L.P.:

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, 2013 and 2012, 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, 2013. 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, 2013 and 2012, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2013, 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, 2013, based on criteria established in Internal Control—Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated March 3, 2014 expressed an unqualified opinion on the effectiveness of the Partnership’s internal control over financial reporting.

/s/ KPMG LLP

San Antonio, Texas

March 3, 2014

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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, 2013, based on criteria established in Internal Control – Integrated Framework (1992) 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, 2013, based on criteria established in Internal Control – Integrated Framework (1992) 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, 2013 and 2012, 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, 2013, and our report dated March 3, 2014 expressed an unqualified opinion on those consolidated financial statements.

/s/ KPMG LLP

San Antonio, Texas

March 3, 2014

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NUSTAR ENERGY L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Thousands of Dollars, Except Unit Data)



	December 31,
	2013			2012
Assets
Current assets:
Cash and cash equivalents	$	100,743		$	83,602
Accounts receivable, net of allowance for doubtful accounts of $1,224 and $808 as of December 31, 2013 and 2012, respectively	281,310			387,943
Receivable from related parties	51,084			109,833
Inventories	138,147			173,228
Income tax receivable	826			1,265
Other current assets	39,452			65,238
Assets held for sale	21,987			118,334
Total current assets	633,549			939,443
Property, plant and equipment, at cost	4,500,837			4,287,859
Accumulated depreciation and amortization	(1,190,184		)	(1,049,399		)
Property, plant and equipment, net	3,310,653			3,238,460
Intangible assets, net	71,249			92,435
Goodwill	617,429			951,024
Investment in joint ventures	68,735			102,945
Deferred income tax asset	5,769			3,108
Note receivable from related party, net	165,440			95,711
Other long-term assets, net	159,362			189,963
Total assets	$	5,032,186		$	5,613,089
Liabilities and Partners’ Equity
Current liabilities:
Current portion of long-term debt	$	—		$	286,422
Accounts payable	298,751			397,633
Payable to related party	8,325			1,408
Accrued interest payable	33,113			23,741
Accrued liabilities	38,632			124,203
Taxes other than income tax	9,745			9,893
Income tax payable	4,006			2,671
Total current liabilities	392,572			845,971
Long-term debt, less current portion	2,655,553			2,124,582
Long-term payable to related party	41,139			18,071
Deferred income tax liability	27,350			32,114
Other long-term liabilities	11,778			7,356
Commitments and contingencies (Note 16)
Partners’ equity:
Limited partners (77,886,078 common units outstanding as of December 31, 2013 and 2012)	1,921,726			2,573,263
General partner	43,804			57,986
Accumulated other comprehensive loss	(63,394		)	(58,865		)
Total NuStar Energy L.P. partners’ equity	1,902,136			2,572,384
Noncontrolling interest	1,658			12,611
Total partners’ equity	1,903,794			2,584,995
Total liabilities and partners’ equity	$	5,032,186		$	5,613,089

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,
	2013			2012			2011
Revenues:
Service revenues	$	938,138		$	870,157		$	820,623
Product sales	2,525,594			5,075,579			5,437,006
Total revenues	3,463,732			5,945,736			6,257,629
Costs and expenses:
Cost of product sales	2,453,997			4,930,174			5,175,710
Operating expenses:
Third parties	331,719			392,491			367,889
Related party	122,677			133,654			138,324
Total operating expenses	454,396			526,145			506,213
General and administrative expenses:
Third parties	32,484			42,266			36,830
Related party	58,602			62,490			66,220
Total general and administrative expenses	91,086			104,756			103,050
Depreciation and amortization expense	178,921			159,789			161,773
Goodwill impairment loss	304,453			22,132			—
Asset impairment loss	—			249,646			—
Gain on legal settlement	—			(28,738		)	—
Total costs and expenses	3,482,853			5,963,904			5,946,746
Operating (loss) income	(19,121		)	(18,168		)	310,883
Equity in (loss) earnings of joint ventures	(39,970		)	(9,378		)	11,458
Interest expense, net	(127,119		)	(90,535		)	(81,539		)
Interest income from related party	6,113			1,219			—
Other income (expense), net	7,341			(24,689		)	(3,573		)
(Loss) income from continuing operations before income tax expense	(172,756		)	(141,551		)	237,229
Income tax expense	12,753			24,450			18,555
(Loss) income from continuing operations	(185,509		)	(166,001		)	218,674
(Loss) income from discontinued operations, net of tax	(99,162		)	(61,236		)	2,927
Net (loss) income	(284,671		)	(227,237		)	221,601
Less (loss) income attributable to noncontrolling interest	(10,901		)	(621		)	140
Net (loss) income attributable to NuStar Energy L.P.	$	(273,770	)	$	(226,616	)	$	221,461
Net (loss) income per unit applicable to limited partners:
Continuing operations	$	(2.89	)	$	(2.79	)	$	2.74
Discontinued operations	(1.11		)	(0.82		)	$	0.04
Total (Note 23)	$	(4.00	)	$	(3.61	)	$	2.78
Weighted-average limited partner units outstanding	77,886,078			72,957,417			65,018,301

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,
	2013			2012			2011
Net (loss) income	$	(284,671	)	$	(227,237	)	$	221,601

Other comprehensive (loss) income:
Foreign currency translation adjustment, net of income tax expense of $0, $414 and $458	(19,364		)	10,677			(18,431		)
Net unrealized gain (loss) on cash flow hedges	7,213			(94,269		)	(53,452		)
Net loss (gain) reclassified into income on cash flow hedges	7,570			53,232			(5,030		)
Total other comprehensive loss	(4,581		)	(30,360		)	(76,913		)

Comprehensive (loss) income	(289,252		)	(257,597		)	144,688
Less comprehensive (loss) income attributable to noncontrolling interest	(10,953		)	477			(2,866		)
Comprehensive (loss) income attributable to NuStar Energy L.P.	$	(278,299	)	$	(258,074	)	$	147,554

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,
	2013			2012			2011
Cash Flows from Operating Activities:
Net (loss) income	$	(284,671	)	$	(227,237	)	$	221,601
Adjustments to reconcile net (loss) income to net cash provided by operating activities:
Depreciation and amortization expense	184,363			170,651			168,286
Amortization of debt related items	4,329			(7,016		)	(12,392		)
Loss (gain) on sale or disposition of assets	(7,829		)	26,902			(262		)
Asset and goodwill impairment loss	406,982			271,778			—
Gain on legal settlement	—			(28,738		)	—
Deferred income tax (benefit) expense	(6,739		)	1,542			4,351
Equity in loss (earnings) of joint ventures	39,970			9,378			(11,458		)
Distributions of equity in earnings of joint ventures	7,956			6,364			14,374
Changes in current assets and current liabilities (Note 24)	112,776			90,247			(265,453		)
Other, net	28,082			(14,668		)	(24,579		)
Net cash provided by operating activities	485,219			299,203			94,468
Cash Flows from Investing Activities:
Capital expenditures	(343,320		)	(410,595		)	(335,660		)
Change in accounts payable related to capital expenditures	(5,384		)	—			—
Acquisitions	—			(315,810		)	(100,690		)
Investment in other long-term assets	—			(2,610		)	(8,990		)
Proceeds from sale or disposition of assets	119,006			478,926			2,086
Increase in note receivable from related party	(80,961		)	(95,711		)	—
Other, net	(302		)	—			—
Net cash used in investing activities	(310,961		)	(345,800		)	(443,254		)
Cash Flows from Financing Activities:
Proceeds from long-term debt borrowings	1,738,451			2,549,145			915,749
Proceeds from short-term debt borrowings	—			71,880			33,800
Proceeds from note offering, net of issuance costs	686,863			247,398			—
Long-term debt repayments	(2,150,743		)	(2,648,475		)	(768,150		)
Short-term debt repayments	—			(71,880		)	(33,800		)
Proceeds from issuance of common units, net of issuance costs	—			336,415			317,285
Contributions from general partner	—			7,121			6,708
Distributions to unitholders and general partner	(392,204		)	(365,279		)	(322,046		)
(Payments for) proceeds from termination of interest rate swaps	(33,697		)	(5,678		)	33,433
Other, net	1,980			(9,978		)	3,742
Net cash (used in) provided by financing activities	(149,350		)	110,669			186,721
Effect of foreign exchange rate changes on cash	(7,767		)	2,033			(1,559		)
Net increase (decrease) in cash and cash equivalents	17,141			66,105			(163,624		)
Cash and cash equivalents as of the beginning of the period	83,602			17,497			181,121
Cash and cash equivalents as of the end of the period	$	100,743		$	83,602		$	17,497

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, 2013, 2012 and 2011

(Thousands of Dollars, Except Unit Data)



	Limited Partners				General Partner			Accumulated Other Comprehensive Income (Loss)			Total NuStar Energy L.P. Partners’ Equity			Noncontrolling Interest			Total Partners’ Equity
	Units	Amount			General Partner			Accumulated Other Comprehensive Income (Loss)			Total NuStar Energy L.P. Partners’ Equity			Noncontrolling Interest			Total Partners’ Equity
Balance as of January 1, 2011	64,610,549	$	2,598,873		$	57,327		$	46,500		$	2,702,700		$	—		$	2,702,700
Acquisition	—	—			—			—			—			15,000			15,000
Net income	—	181,439			40,022			—			221,461			140			221,601
Other comprehensive loss	—	—			—			(73,907		)	(73,907		)	(3,006		)	(76,913		)
Cash distributions to partners	—	(280,528		)	(41,518		)	—			(322,046		)	—			(322,046		)
Issuance of common units, including contribution from general partner	6,145,529	317,285			6,708			—			323,993			—			323,993
Balance as of December 31, 2011	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

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, 2013, 2012 and 2011

1. ORGANIZATION AND OPERATIONS

Organization

NuStar Energy L.P. (NuStar Energy) (NYSE: NS) is engaged in the terminalling and storage of petroleum products, the transportation of petroleum products and anhydrous ammonia, 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, 2013.

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: storage, pipeline and fuels marketing.

Storage. We own terminal and storage facilities in the United States, Canada, Mexico, the Netherlands, including St. Eustatius in the Caribbean, the United Kingdom and Turkey providing approximately 84.8 million barrels of storage capacity. Our terminals and storage facilities provide storage and handling services on a fee basis for petroleum products, specialty chemicals and other liquids, including crude oil and other feedstocks.

Pipeline. We own common carrier refined product pipelines in Texas, Oklahoma, Colorado, New Mexico, Kansas, Nebraska, Iowa, South Dakota, North Dakota and Minnesota covering approximately 5,463 miles, consisting of the Central West System, the East Pipeline and the North Pipeline. The East and North Pipelines also include 21 terminals providing storage capacity of 4.9 million barrels, and the East Pipeline includes two tank farms providing storage capacity of 1.4 million barrels. In addition, we own a 2,000 mile anhydrous ammonia pipeline located in Louisiana, Arkansas, Missouri, Illinois, Indiana, Iowa and Nebraska. We also own 1,180 miles of crude oil pipelines in Texas, Oklahoma, Kansas, Colorado and Illinois, as well as associated crude oil terminal and storage facilities providing storage capacity of 3.4 million barrels in Texas and Oklahoma that are located along the crude oil pipelines. 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 our ammonia pipeline.

Fuels Marketing. In 2013, we changed the name of the “Asphalt and Fuels Marketing” segment to the “Fuels Marketing” segment since this name more accurately reflects the operations that remain after our deconsolidation of NuStar Asphalt LLC in 2012 and the sale of our fuels refinery in San Antonio, Texas (the San Antonio Refinery) on January 1, 2013. 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, through September 28, 2012, our asphalt operations. On September 28, 2012, we sold a 50% ownership interest in NuStar Asphalt LLC, previously a wholly owned subsidiary, and started reporting our remaining investment using the equity method of accounting. Therefore, the results of our asphalt operations are reported in “Equity in (loss) earnings of joint ventures” in the consolidated statements of income beginning on September 28, 2012. In addition, we have presented the results of operations for the San Antonio Refinery and related assets, previously reported in the fuels marketing and pipeline segments, as discontinued operations for all periods presented. See Note 5 for additional discussion.

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.

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NUSTAR ENERGY L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

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.

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 first assess qualitative factors to determine whether it is necessary to perform a quantitative goodwill impairment test. As of October 1, 2012 and 2011, 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 performed a quantitative goodwill impairment test as of October 1, 2013.

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.

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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;


•	St. Eustatius and Point Tupper terminal operations (Statia Terminals); 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 current and long term 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. See Note 6 for a discussion of the goodwill impairment recognized in 2013.

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 (loss) earnings of joint ventures” in the statements of income (loss). See Note 12 for a discussion of our investments in NuStar Asphalt LLC and St Linden Terminals, LLC.

Note Receivable from Related Party

The note receivable from related party consists of the amounts due to us from Asphalt JV under a $250.0 million unsecured revolving credit facility. The note receivable is recorded at the outstanding principal amount, adjusted for equity losses from our investment in Asphalt JV that exceeded the carrying value of our investment in Asphalt JV, and for the fair value of guarantees issued under the NuStar JV Facility. We recognize interest income ratably over the term of the facility in “Interest income from related party” on the consolidated statements of income. See Note 19 for additional information on our agreements with Asphalt JV.

Other Long-Term Assets

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


•	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, 2013 are recoverable. See Note 5 for a discussion of impairments of long-lived assets.

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NUSTAR ENERGY L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

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.

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, 2013 and 2012.

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, tax years subject to examination are 2009 through 2013 and for our major non-U.S. jurisdictions, tax years subject to examination are 2009 through 2013, both according to standard statute of limitations. NuStar has waived the statute of limitations for limited items for the tax years 2006 and 2007 as a result of an income tax audit in Canada that is currently being appealed in the Tax Court of Canada.

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 $0.6 million as of December 31, 2013 and 2012, 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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

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 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 and tanks (throughput revenues). Our terminals also provide blending, handling and filtering services. Our facilities at Point Tupper and St. Eustatius charge fees to provide ancillary 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 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 ancillary services are recognized as those services are provided.

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.

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. Additionally, the revenues of our fuels marketing segment include the mark-to-market impact of certain derivative instruments that are part of our limited trading program.

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 (IDR) 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.

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NUSTAR ENERGY L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

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” or “Operating expenses.”

We were a party to forward-starting interest rate swap agreements for the purpose of hedging the interest rate risk associated with forecasted probable debt issuances. Under the terms of these swap agreements, we paid a fixed rate and received a rate based on three month USD LIBOR. We entered into the swaps in order to hedge the risk of changes in the interest payments attributable to changes in the benchmark interest rate during the period from the effective date of the swap to the issuance of the forecasted debt. We 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” over the term of the forecasted debt as the interest payments occur or if the interest payments are probable not to occur. We terminated all remaining forward-starting interest rate swaps during the year ended December 31, 2013.

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.

In addition, 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. Except for one interest rate swap agreement we entered into and terminated in 2011, 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. We terminated all remaining fixed-to-floating interest rate swaps during the year ended December 31, 2012.

From time to time, we also 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.” We no longer enter into commodity derivatives without underlying physical inventory.

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

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 or that the grantee’s award will continue to vest on schedule after retirement. Compensation expense is recognized immediately if these awards are granted to retirement-eligible employees. 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. Currently, employees are typically retirement eligible at age 55.

We reimburse NuStar GP, LLC for the expenses resulting from NS and NSH awards to employees and directors of NuStar GP, LLC. We include such compensation expense in “General and administrative 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.

Reclassifications

Certain previously reported amounts in the 2012 and 2011 consolidated financial statements and notes have been reclassified to conform to the 2013 presentation. As further discussed in Note 5, we reclassified certain storage assets as “Assets held for sale” on the consolidated balance sheet as of December 31, 2013. As a result, we have presented the results of operations for these assets, previously reported in the storage segment, as discontinued operations for all periods presented.

3. NEW ACCOUNTING PRONOUNCEMENTS

Balance Sheet Offsetting

In December 2011, the Financial Accounting Standards Board (FASB) amended the disclosure requirements with respect to offsetting assets and liabilities. The amended guidance requires new disclosures to enable users of financial statements to reconcile differences in the offsetting requirements under U.S. GAAP and International Financial Reporting Standards. The new disclosure requirements mandate that entities disclose both gross and net information about instruments and transactions eligible for offset in the balance sheet as well as instruments and transactions subject to an agreement similar to a master netting arrangement. In January 2013, the FASB further amended and clarified the scope of balance sheet offsetting disclosure requirements. The amended guidance limits the scope of the new balance sheet offsetting disclosures to derivatives, repurchase agreements, and securities lending transactions to the extent that they are offset in the financial statements or subject to an enforceable master netting arrangement or similar agreement. The disclosures are required irrespective of whether the transactions are offset in the consolidated balance sheets. The amended guidance is effective for annual and interim reporting periods beginning on or after January 1, 2013, and retrospective application is required. Accordingly, we adopted the amended guidance January 1, 2013, and it did not have a material impact on our disclosures.

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Other Comprehensive Income

In February 2013, the FASB further amended the disclosure requirements for the presentation of comprehensive income.

The amended guidance requires that entities present either in a single note or parenthetically on the face of the financial statements, the effect of significant amounts reclassified from each component of accumulated other comprehensive income and the income statement line items affected by the reclassification. The amended guidance is effective prospectively for annual and interim reporting periods beginning after December 15, 2012. Accordingly, we adopted the amended guidance January 1, 2013, and it did not have a material impact on our disclosures.

4. ACQUISITIONS

Completed During 2012

TexStar Asset Acquisition. On December 13, 2012, NuStar Logistics acquired the TexStar Crude Oil Assets (as defined below), including 100% of the partnership interest in TexStar Crude Oil Pipeline, LP, 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 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.

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

Completed During 2011

San Antonio Refinery. On April 19, 2011, we purchased certain refining and storage assets, inventory and other working capital items from AGE Refining, Inc. for $62.0 million, including the assumption of certain environmental liabilities. The assets consisted of a 14,500 barrel per day refinery in San Antonio, Texas and 0.4 million barrels of aggregate storage capacity (the San Antonio Refinery Acquisition). The final purchase price was allocated based on the estimated fair values of the individual assets acquired and liabilities assumed at the date of acquisition. On January 1, 2013, we sold the refinery and related assets; see Note 5 for additional discussion of the sale.

Turkey Acquisition. On February 9, 2011, we acquired 75% of the outstanding capital of a Turkish company, which owns two terminals in Mersin, Turkey, with an aggregate 1.4 million barrels of storage capacity, for approximately $57.0 million (the Turkey Acquisition). Both terminals are connected via pipelines to an offshore platform located approximately three miles off the Mediterranean Sea coast. The Turkey Acquisition was accounted for using the acquisition method. The purchase price was allocated based on the estimated fair values of the individual assets acquired, liabilities assumed and noncontrolling interest at the date of acquisition.

5. DISPOSITIONS AND ASSETS HELD FOR SALE

Terminals Held for Sale

As of December 31, 2013, we identified several non-strategic, underperforming terminal facilities and decided to divest those facilities. As a result, we reclassified the associated assets as “Assets held for sale” on the consolidated balance sheet. 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 $1.4 million, $0.8 million and $0.6 million for the years ended December 31, 2013, 2012 and 2011, respectively, to discontinued operations based on the ratio of net assets discontinued to consolidated net assets.

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NUSTAR ENERGY L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

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) income 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

San Antonio Refinery Sale

On January 1, 2013, we sold the San Antonio Refinery and related assets, which included inventory, a terminal in Elmendorf, Texas and a pipeline connecting the terminal and refinery for approximately $117.0 million (the San Antonio Refinery Sale). As of December 31, 2012, we reclassified the assets related to the San Antonio Refinery as “Assets held for sale” on the consolidated balance sheet. The liabilities held for sale related to the San Antonio Refinery are included within “Accrued liabilities” on the consolidated balance sheet. We have presented the results of operations for the San Antonio Refinery and related assets, previously reported in the fuels marketing and pipeline segments, as discontinued operations for all periods presented. We allocated interest expense of $3.9 million and $2.0 million for the years ended December 31, 2012 and 2011, respectively, 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 facilities held for sale and the San Antonio Refinery:



	Year Ended December 31,
	2013			2012			2011
	(Thousands of Dollars)
Revenues	$	7,758		$	571,071		$	317,626

Income (loss) before income tax expense	$	(106,033	)	$	(63,165	)	$	1,251

The total assets and liabilities held for sale consisted of the following:



	December 31,
	2013		2012
	(Thousands of Dollars)
Inventories	$	—	$	15,939
Property, plant and equipment, net	21,987		96,745
Other long-term assets, net	—		5,650
Assets held for sale	$	21,987	$	118,334

Accrued liabilities (environmental reserve)	$	—	$	289
Other long-term liabilities (environmental reserve)	—		7,621
Liabilities held for sale	$	—	$	7,910

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NUSTAR ENERGY L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Asphalt Sale

On September 28, 2012, we sold a 50% ownership interest (the Asphalt Sale) in NuStar Asphalt LLC (Asphalt JV), previously a wholly owned subsidiary, to an affiliate of Lindsay Goldberg LLC (Lindsay Goldberg), a private investment firm. Asphalt JV 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 Asphalt JV, while we retained the Class B equity interests with a fair value of $52.0 million (Class B Interests). The Class A Interests have a distribution preference over the Class B Interests, as well as a liquidation preference. We also received $263.8 million from Asphalt JV for inventory related to the Asphalt Operations.

Deconsolidation. We determined the equity of Asphalt JV is not sufficient to finance its activities without additional subordinated support, including support provided by us as described in Note 19. Therefore, we determined Asphalt JV is a variable interest entity (VIE). An entity is required to consolidate a VIE if the entity is considered the primary beneficiary of the VIE. We analyzed our relationship with Asphalt JV, including our representation on the board of managers, our equity interests and our rights under the various agreements with Asphalt JV and determined that we do not have the power to direct the activities most significant to the economic performance of Asphalt JV. As a result, we are not the primary beneficiary of Asphalt JV. Upon closing, we deconsolidated Asphalt JV and started reporting our remaining investment in Asphalt JV using the equity method of accounting. At closing, the fair value of the consideration we received was less than the carrying amount of the net assets of the Asphalt Operations upon deconsolidation, 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. Because of our continued involvement with Asphalt JV, we have not presented the results of operations for the Asphalt Operations prior to closing as discontinued operations. Beginning on September 28, 2012, we have presented transactions between us and Asphalt JV as related party transactions in the consolidated financial statements.

Impairments. In anticipation of the Asphalt Sale, we evaluated the goodwill and other long-lived assets associated with the Asphalt Operations for potential impairment. As of June 30, 2012, we estimated the fair value of the Asphalt Operations reporting unit as the sum of (i) the purchase price to be paid by Lindsay Goldberg for the Class A Interests of Asphalt JV, (ii) the fair value of the Class B Interests of Asphalt JV that we would retain and (iii) the fair value of the working capital, primarily inventory. We determined the fair value of the Class B Interests using a combination of estimated discounted future cash flows and a pricing model. The fair value of the working capital was based on estimated current market prices. 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 $244.3 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

In February 2014, we divested of our remaining 50% ownership interest in Asphalt JV. See Note 29 for additional discussion.

Terminal Sales

On April 16, 2012, we sold five terminals in Georgia and Alabama with an aggregate storage capacity of 1.8 million barrels for total proceeds of $30.8 million.

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NUSTAR ENERGY L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

6. GOODWILL

2013 Goodwill Impairment

The estimated fair value was less than the carrying value of the Statia Terminals reporting unit. 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 represents 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.

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



	Storage			Pipeline		Fuels Marketing			Total
	(Thousands of Dollars)
Balances as of January 1, 2012
Goodwill	$	618,614		$	174,848	$	53,255		$	846,717
Accumulated impairment losses	—			—		—			—
Net goodwill	618,614			174,848		53,255			846,717
TexStar Asset Acquisition preliminary purchase price allocation	—			127,896		—			127,896
Asphalt Operations impairment	—			—		(22,132		)	(22,132		)
Terminal sales (a)	(3,764		)	—		—			(3,764		)
Other (b)	2,307			—		—			2,307
Balances as of December 31, 2012
Goodwill	617,157			302,744		53,255			973,156
Accumulated impairment losses	—			—		(22,132		)	(22,132		)
Net goodwill	617,157			302,744		31,123			951,024
TexStar Asset Acquisition final purchase price allocation	—			3,463		—			3,463
Impairments	(331,913		)	—		—			(331,913		)
Other (b)	(5,145		)	—		—			(5,145		)
Balances as of December 31, 2013
Goodwill	612,012			306,207		53,255			971,474
Accumulated impairment losses	(331,913		)	—		(22,132		)	(354,045		)
Net goodwill	$	280,099		$	306,207	$	31,123		$	617,429


(a)	Goodwill associated with five terminals in Georgia and Alabama sold on April 16, 2012.


(b)	Includes purchase price adjustments related to acquisitions still subject to the measurement period that ends at the earlier of 12 months from the acquisition date or when information becomes available. Also includes foreign currency translation adjustments.

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NUSTAR ENERGY L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

7. ALLOWANCE FOR DOUBTFUL ACCOUNTS

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



	Year Ended December 31,
	2013			2012			2011
	(Thousands of Dollars)
Balance as of beginning of year	$	808		$	2,147		$	1,457
Increase in allowance	1,039			27			934
Accounts charged against the allowance, net of recoveries	(625		)	(1,367		)	(243		)
Foreign currency translation	2			1			(1		)
Balance as of end of year	$	1,224		$	808		$	2,147

8. INVENTORIES

Inventories consisted of the following:



	December 31,
	2013		2012
	(Thousands of Dollars)
Crude oil	$	6,485	$	447
Finished products	123,656		164,894
Materials and supplies	8,006		7,887
Total	$	138,147	$	173,228

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.

9. OTHER CURRENT ASSETS

Other current assets consisted of the following:



	December 31,
	2013		2012
	(Thousands of Dollars)
Prepaid expenses	$	16,487	$	18,008
Restricted cash	9,316		15,227
Derivative assets	4,948		9,358
Margin deposits	3,285		6,192
Product advances	3,076		14,764
Product imbalances	1,980		1,232
Other	360		457
Other current assets	$	39,452	$	65,238

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NUSTAR ENERGY L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

10. PROPERTY, PLANT AND EQUIPMENT

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



	Estimated Useful Lives			December 31,
	Estimated Useful Lives			2013			2012
	(Years)			(Thousands of Dollars)
Land		—		$	129,731		$	133,341
Land and leasehold improvements	10	-	35	142,122			110,575
Buildings	15	-	40	133,531			120,499
Pipelines, storage and terminals	20	-	35	3,787,499			3,531,925
Rights-of-way	20	-	40	155,833			148,021
Construction in progress		—		152,121			243,498
Total				4,500,837			4,287,859
Less accumulated depreciation and amortization				(1,190,184		)	(1,049,399		)
Property, plant and equipment, net				$	3,310,653		$	3,238,460

Capitalized interest costs added to property, plant and equipment totaled $4.5 million, $7.7 million and $5.4 million for the years ended December 31, 2013, 2012 and 2011, respectively. Depreciation and amortization expense for property, plant and equipment totaled $168.8 million, $157.8 million and $157.2 million for the years ended December 31, 2013, 2012 and 2011, respectively, including depreciation expense included in “(Loss) income from discontinued operations, net of tax” on the consolidated statements of income.

11. INTANGIBLE ASSETS

Intangible assets consisted of the following:



	December 31, 2013					December 31, 2012
	Cost		Accumulated Amortization			Cost		Accumulated Amortization
	(Thousands of Dollars)
Customer relationships	$	127,614	$	(58,230	)	$	137,470	$	(46,951	)
Other	2,359		(494		)	2,359		(443		)
Total	$	129,973	$	(58,724	)	$	139,829	$	(47,394	)

All of our intangible assets are subject to amortization. Amortization expense for intangible assets was $13.8 million, $7.8 million and $8.3 million for the years ended December 31, 2013, 2012 and 2011, respectively. The estimated aggregate amortization expense for the next five years is as follows:



	Amortization Expense
	(Thousands of Dollars)
2014	$	12,579
2015	$	9,709
2016	$	6,840
2017	$	6,840
2018	$	6,840

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NUSTAR ENERGY L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

12. INVESTMENT IN JOINT VENTURES

Summary Financial Information

Condensed combined financial information related to our joint ventures is presented below:



	December 31,
	2013		2012
	(Thousands of Dollars)
Balance Sheet Information:
Current assets	$	263,683	$	375,686
Long-term assets	300,484		289,584
Total assets	$	564,167	$	665,270
Current liabilities	$	118,720	$	185,525
Long-term liabilities	273,220		231,559
Total liabilities	391,940		417,084
Total equity	172,227		248,186
Total liabilities and equity	$	564,167	$	665,270



	Year Ended December 31,
	2013			2012			2011
	(Thousands of Dollars)
Statement of (Loss) Income Information:
Revenues	$	1,623,155		$	458,816		$	36,419
Operating (loss) income	$	(45,373	)	$	(4,801	)	$	23,062
Net (loss) income	$	(59,963	)	$	(12,418	)	$	23,066

NuStar Asphalt LLC. Asphalt JV is owned 50% by the Partnership and 50% by Lindsay Goldberg. Asphalt JV 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.

During the year ended December 31, 2013, our equity in loss of joint ventures included a $49.6 million loss from our investment in Asphalt JV, which exceeded our investment in Asphalt JV. From the point our investment in Asphalt JV reached $0, we recorded additional losses of $13.1 million, as a reduction of the carrying value of the note receivable from Asphalt JV. See Note 19 for a discussion of our agreements with Asphalt JV. In February 2014, we divested of our remaining 50% ownership interest in Asphalt JV. See Note 29 for additional discussion.

ST Linden Terminals, LLC. The 44-acre facility provides deep-water terminalling capabilities at 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 an investment in ST Linden Terminals, LLC (Linden). Linden is owned 50% by the Partnership and 50% by NIC 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 $42.6 million and $43.0 million as of December 31, 2013 and 2012, 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.

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NUSTAR ENERGY L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

13. ACCRUED LIABILITIES

Accrued liabilities consisted of the following:



	December 31,
	2013		2012
	(Thousands of Dollars)
Derivative liabilities	$	2,233	$	60,121
Employee wages and benefit costs	16,698		15,381
Unearned income	8,225		10,476
TexStar Asset Acquisition contingent consideration	1,318		9,600
Liabilities held for sale	—		7,910
Other	10,158		20,715
Accrued liabilities	$	38,632	$	124,203

14. DEBT

Long-term debt consisted of the following:



				December 31,
	Maturity			2013		2012
				(Thousands of Dollars)
$1.5 billion revolving credit agreement		2017		$	503,036	$	440,330
4.75% senior notes		2022		250,000		250,000
6.75% senior notes		2021		300,000		—
4.80% senior notes		2020		450,000		450,000
7.65% senior notes		2018		350,000		350,000
6.05% senior notes		2013		—		229,932
5.875% senior notes		2013		—		250,000
7.625% subordinated notes		2043		402,500		—
Gulf Opportunity Zone revenue bonds	2038	thru	2041	365,440		365,440
UK term loan		2013		—		34,142
Port Authority of Corpus Christi note payable		2015		—		577
Net fair value adjustments and unamortized discounts		N/A		34,577		40,583
Total debt				2,655,553		2,411,004
Less current portion				—		286,422
Long-term debt, less current portion				$	2,655,553	$	2,124,582

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



2014	$	—
2015	—
2016	—
2017	503,036
2018	350,000
Thereafter	1,767,940
Total repayments	2,620,976
Net fair value adjustments and unamortized discounts	34,577
Total debt	$	2,655,553

Interest payments totaled $118.3 million, $118.4 million and $115.1 million for the years ended December 31, 2013, 2012 and 2011, respectively.

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NUSTAR ENERGY L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Revolving Credit Agreements

NuStar Logistics is a party to a $1.5 billion five-year revolving credit agreement, as amended (the 2012 Revolving Credit Agreement), which includes the ability to borrow up to the equivalent of $250.0 million in Euros. On December 4, 2013, we amended the 2012 Revolving Credit Agreement to add the ability to borrow up to the equivalent of $250.0 million in British Pounds Sterling. The 2012 Revolving Credit Agreement matures on May 2, 2017. Obligations under the 2012 Revolving Credit Agreement are guaranteed by NuStar Energy and NuPOP. NuPOP will be released from its guarantee of the 2012 Revolving Credit Agreement when it no longer guarantees NuStar Logistics public debt instruments.

The 2012 Revolving Credit Agreement bears interest, at our option, based on either an alternative base rate or a LIBOR-based rate. The interest rate on the 2012 Revolving Credit Agreement is subject to adjustment if our debt rating is downgraded (or subsequently upgraded) by certain credit rating agencies. In July 2012, Standard & Poor’s Ratings Services (S&P) lowered our credit rating to BB+ from BBB-, and in January 2013, Moody’s Investor Service Inc. (Moody’s) lowered our credit rating to Ba1 from Baa3. The interest rates applicable to the 2012 Revolving Credit Agreement do not adjust unless both S&P and Moody’s change their ratings; therefore, the interest rate on the 2012 Revolving Credit Agreement increased by 0.375% effective January 2013. As of December 31, 2013, our weighted-average interest rate was 2.2%. During the year ended December 31, 2013, the weighted-average interest rate related to borrowings under the 2012 Revolving Credit Agreement was 2.2%.

Notes

NuStar Logistics’ Senior Notes. 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 proceeds of approximately $296.0 million, net of the underwriters’ discount and deferred issuance costs of $4.0 million, which we used for general partnership purposes, including repayment of outstanding borrowings under our 2012 Revolving Credit Agreement. The interest on the 6.75% Senior Notes is payable semi-annually in arrears on February 1 and August 1 of each year beginning on February 1, 2014.

In March 2013, we repaid NuStar Logistics’ $229.9 million of 6.05% senior notes due March 15, 2013 with borrowings under our 2012 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 subsequently upgraded) by certain credit rating agencies. The interest rate on NuStar Logistics’ $350.0 million of 7.65% senior notes increased by another 0.25% in January 2013 as a result of the Moody’s downgrade. 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 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.

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NUSTAR ENERGY L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

NuStar Logistics’ 7.625% Fixed-to-Floating Rate Subordinated Notes. 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 proceeds of approximately $390.9 million, net of $11.6 million of deferred issuance costs, which we used for general partnership purposes, including repayment of outstanding borrowings under our 2012 Revolving Credit Agreement. 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 on January 15, April 15, July 15 and October 15 of each year 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 on January 15, April 15, July 15 and October 15 of each year, 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 certain 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.

NuPOP’s Senior Notes. As a result of the Kaneb Acquisition, we assumed the outstanding senior notes issued by NuPOP, having an aggregate face value of $500.0 million, and an aggregate fair value of $555.0 million at the acquisition date (the NuPOP Senior Notes). We used the effective interest method to amortize the difference between the fair value and the face value of the senior notes as a reduction of interest expense over the lives of the senior notes. The senior notes were issued in two series, the first of which bore interest at 7.75% annually and matured in 2012, and the second series which bore interest 5.875% annually and matured in 2013. We repaid NuPOP’s $250.0 million of 5.875% senior notes due June 1, 2013 with borrowings under our 2012 Revolving Credit Agreement.

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, less current portion” in our consolidated balance sheets. For the year ended December 31, 2013, we received $43.1 million from the trustee.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

The following table summarizes the Gulf Opportunity Zone Revenue Bonds outstanding as of December 31, 2013:



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	$	—	0.10	%
July 15, 2010	July 1, 2040	100,000		101,315			100,000		—		0.10	%
October 7, 2010	October 1, 2040	50,000		50,658		(a)	24,580		25,420		0.11	%
December 29, 2010	December 1, 2040	85,000		86,118		(a)	26,924		58,076		0.11	%
August 29, 2011	August 1, 2041	75,000		75,986			75,000		—		0.10	%
	Total	$	365,440	$	370,246		$	281,944	$	83,496


(a)	Letters of credit issued under the 2012 Revolving Credit Agreement.

UK Term Loan

In December 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 our 2012 Revolving Credit Agreement.

Our other long-term debt obligations do not contain any financial covenants. However, a default under any of our debt instruments would be considered an event of default under all of our debt instruments.

Port Authority of Corpus Christi Note Payable

The proceeds from the original $12.0 million note payable due to the Port of Corpus Christi Authority of Nueces County, Texas (Port Authority of Corpus Christi) were used for the construction of a crude oil storage facility in Corpus Christi, Texas. The note payable was due in annual installments of $1.2 million through December 31, 2015 and was collateralized by the crude oil storage facility. The wharfage and dockage fees paid to the Port Authority of Corpus Christi in connection with the use of the crude oil storage facility exceeded certain limits per the terms of the note, which have accelerated the repayment of the unpaid principal balance. On February 6, 2013, we repaid the remaining principle balance of $0.6 million.

15. HEALTH, SAFETY AND ENVIRONMENTAL MATTERS

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 pipeline safety. The principal environmental and safety risks associated with our operations relate to unauthorized emissions into the air, unauthorized releases into soil, surface water or groundwater, and personal injury and property damage. Compliance with these environmental and safety laws, regulations and permits increases our capital expenditures and our overall cost of business, and violations of these laws, regulations and/or permits can result in significant civil and criminal liabilities, injunctions or other penalties.

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.

We have adopted policies, practices and procedures in the areas of pollution control, pipeline integrity, operator qualifications, public relations and education, product safety, 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 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.

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

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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.

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



	Year Ended December 31,
	2013			2012
	(Thousands of Dollars)
Balance as of the beginning of year	$	13,451		$	23,113
Additions to accrual	3,623			4,766
San Antonio Refinery Acquisition purchase price adjustment	—			(5,957		)
Payments	(2,940		)	(5,242		)
San Antonio Refinery Sale	(7,910		)	—
Asphalt Sale	—			(3,300		)
Foreign currency translation	9			71
Balance as of the end of year	$	6,233		$	13,451

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



	December 31,
	2013		2012
	(Thousands of Dollars)

Accrued liabilities	$	3,299	$	10,627
Other long-term liabilities	2,934		2,824
Accruals for environmental matters	$	6,233	$	13,451

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, 2013, we have accrued $0.7 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, 2013 are as follows:



	Payments Due by Period
	2014		2015		2016		2017		2018		There- after		Total
	(Thousands of Dollars)
Operating leases	$	30,300	$	24,886	$	21,274	$	18,954	$	16,980	$	80,090	$	192,484
Purchase obligations:	8,571		5,108		3,841		694		216		—		18,430

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Rental expense for all operating leases totaled $52.9 million, $73.9 million and $70.0 million for the years ended December 31, 2013, 2012 and 2011, respectively, including rental expense included in “(Loss) income 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;


•	leases for tugs and barges utilized at our Point Tupper facility for bunker fuel sales, with lease terms ranging from five to ten years; and


•	land leases at various terminal facilities.

On November 6, 2013, we came to a mutual agreement with PDVSA-Petróleo S.A. (PDVSA) effective January 1, 2014 to terminate that certain Crude Oil Sales Agreement dated effective as of March 1, 2008 (the CSA). We previously amended the CSA on July 5, 2013 to reduce the crude oil purchase obligations from 75,000 barrels per day to 30,000 barrels per day, which remained in effect through the end of 2013. Effective January 1, 2014, our crude oil supply agreement with Asphalt JV will also terminate. See Note 19 for a discussion of our crude oil supply agreement with Asphalt JV.

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, 2013
	Level 1			Level 2			Level 3			Total
	(Thousands of Dollars)
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
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	$	(1,643	)	$	9,550		$	(3,198	)	$	4,709

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	December 31, 2012
	Level 1			Level 2			Level 3			Total
	(Thousands of Dollars)
Other current assets:
Product imbalances	$	1,232		$	—		$	—		$	1,232
Commodity derivatives	1,001			8,357			—			9,358
Other long-term assets, net:
Commodity derivatives	—			9,206			—			9,206
Accrued liabilities:
Product imbalances	(1,686		)	—			—			(1,686		)
Commodity derivatives	—			(19,210		)	—			(19,210		)
Interest rate swaps	—			(40,911		)	—			(40,911		)
Contingent consideration	—			—			(9,600		)	(9,600		)
Total	$	547		$	(42,558	)	$	(9,600	)	$	(51,611	)

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

Interest Rate Swaps. We estimate the fair value of both our fixed-to-floating and forward-starting interest rate swaps using discounted cash flows, which use observable inputs such as time to maturity and market interest rates.

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 be obligated to pay additional consideration to TexStar. Such obligations are dependent upon the cost of work required to complete certain assets and obtain outstanding real estate rights (collectively, the Contingent Consideration). We estimated the fair value of the Contingent Consideration using a probability-weighted discounted cash flow model, which reflects possible outcomes and our estimates of the probabilities of those outcomes. 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. The probability-weighted cash flows were discounted using a discount rate of 11%.

Based on our assessment of the costs necessary to complete the assets in accordance with our agreement with TexStar, and considering the probability of possible outcomes, we determined that it is unlikely we would be obligated to pay a portion of the Contingent Consideration. The undiscounted amount of potential future payments that we could be required to make under the applicable agreements is between $0 and $1.3 million.

Guarantees. As of December 31, 2013, we recorded a liability of $1.9 million representing the fair value of guarantees we have issued on behalf of Asphalt JV. We estimated the fair value considering the probability of default by Asphalt JV 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, 2013, totaling $79.7 million, 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 19 for a discussion of our agreements with Asphalt JV.

In the event we are obligated to perform under these guarantees, that amount paid by us will be added to borrowings under the NuStar JV Facility. As a result, we increased the carrying value of the note receivable from Asphalt JV by the same amount as the liability for the fair value of the guarantees outstanding as of December 31, 2013.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

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



	Year Ended December 31, 2013
	(Thousands of Dollars)
Beginning balance	$	9,600
Amounts settled	(1,114		)
Adjustment to guarantee liability	1,880
Changes in fair value recorded in earnings:
Operating expenses	(8,000		)
Interest expense, net	832
Ending balance	$	3,198

Non-recurring Fair Value Measurements

As of December 31, 2013, we reclassified 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. We estimated the fair value of $22.0 million 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, the note receivable from Asphalt JV, payables and debt in our consolidated balance sheets at their carrying amount. The fair values of these financial instruments, except for the note receivable from related party and debt, approximate their carrying amounts.

The estimated fair values and carrying amounts of our debt and note receivable from Asphalt JV were as follows:



	December 31,
	2013		2012
	(Thousands of Dollars)
Debt:
Fair value	$	2,636,734	$	2,377,120
Carrying amount	$	2,655,553	$	2,411,004

Note Receivable from Related Party:
Fair value	$	133,416	$	91,705
Carrying amount	$	165,440	$	95,711

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.

The note receivable related to the NuStar JV Facility is recorded at the outstanding principal amount, adjusted for equity losses from our investment in Asphalt JV after the carrying value of our investment in Asphalt JV was reduced to zero and for the fair value of guarantees issued under the NuStar JV Facility. 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.

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18. DERIVATIVES AND RISK MANAGEMENT ACTIVITIES

We utilize various derivative instruments to manage our exposure to commodity price risk and manage our exposure to 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 policies 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 NuStar Logistics’ 4.75% senior notes issued on February 2, 2012. Under the terms of these interest rate swap agreements, we received a fixed rate of 4.75% and paid a variable rate based on one month USD LIBOR plus a percentage that varied with each agreement. We also terminated fixed-to-floating interest rate swap agreements with an aggregate notional amount of $270.0 million associated with NuStar Logistics’ 4.80% senior notes. Under the terms of these interest rate swap agreements, we received a fixed rate of 4.8% 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 we are amortizing into “Interest expense, net” over the remaining lives of the 4.80% and 4.75% 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, 2013 and 2012.

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 out of “Accumulated other comprehensive loss” and 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 out of “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, 2013, and the total aggregate notional amount of the forward-starting interest rate swaps was $275.0 million as of December 31, 2012.

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 sales 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. During the fourth quarter of 2011, we decided to adjust the refinery’s operations, which caused a shift in the future production yields of the San Antonio Refinery. This change caused certain forecasted sales of gasoline products to be replaced with distillate sales; therefore, we concluded that these forecasted gasoline sales were probable not to occur, and we discontinued cash flow hedging treatment for the related commodity contracts. We recorded gains of $16.4 million related to these contracts for the year ended December 31, 2011,

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including $15.1 million which we reclassified from accumulated other comprehensive loss. In anticipation of the San Antonio Refinery Sale, we concluded that all of the 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) income 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 positions on an absolute basis, which totaled 15.2 million barrels and 22.7 million barrels as of December 31, 2013 and 2012, respectively.

As of December 31, 2013 and 2012, we had $3.3 million and $6.2 million, respectively, of margin deposits related to our derivative instruments.

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	2013		2012		2013			2012
		(Thousands of Dollars)
Derivatives Designated as Hedging Instruments:
Commodity contracts	Other current assets	$	—	$	1,471	$	—		$	(811	)
Commodity contracts	Accrued liabilities	—		—		(130		)	—
Interest rate swaps	Accrued liabilities	—		—		—			(40,911		)
Total		—		1,471		(130		)	(41,722		)

Derivatives Not Designated as Hedging Instruments:
Commodity contracts	Other current assets	16,168		22,269		(11,220		)	(13,571		)
Commodity contracts	Other long-term assets, net	15,883		39,322		(8,906		)	(30,116		)
Commodity contracts	Accrued liabilities	4,523		17,406		(6,626		)	(36,616		)
Commodity contracts	Other long-term liabilities	5,448		—		(7,023		)	—
Total		42,022		78,997		(33,775		)	(80,303		)

Total Derivatives		$	42,022	$	80,468	$	(33,905	)	$	(122,025	)

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	2013			2012
	(Thousands of Dollars)
Net amounts of assets presented in the consolidated balance sheets	$	11,925		$	18,564
Net amounts of liabilities presented in the consolidated balance sheets	$	(3,808	)	$	(19,210	)

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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, 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

Year ended December 31, 2011:
Interest rate swaps	Interest expense, net	$	(55,183	)	$	54,588		$	(595	)
Commodity contracts	Cost of product sales	(10,228		)	9,004			(1,224		)
Total		$	(65,411	)	$	63,592		$	(1,819	)



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) (b)			Amount of Gain (Loss) Recognized in Income on Derivative (Ineffective Portion)
	(Thousands of Dollars)				(Thousands of Dollars)
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) income from discontinued operations	(51,483		)	4,010
Total	$	(94,269	)		$	(53,232	)	$	4,010

Year ended December 31, 2011:
Interest rate swaps	$	(84,199	)	Interest expense, net	$	—		$	—
Commodity contracts	30,747			(Loss) income from discontinued operations	5,030			(4,010		)
Total	$	(53,452	)		$	5,030		$	(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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Derivatives Not Designated as Hedging Instruments	Income Statement Location	Amount of Gain (Loss) Recognized in Income
		(Thousands of Dollars)
Year ended December 31, 2013:
Commodity contracts	Cost of product sales	$	(5,323	)
Commodity contracts	(Loss) income 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) income from discontinued operations	6,176
Total		$	18,660

Year ended December 31, 2011:
Commodity contracts	Revenues	$	235
Commodity contracts	Cost of product sales	(11,661		)
Commodity contracts	Operating expenses	46
Commodity contracts	(Loss) income from discontinued operations	7,207
Total		$	(4,173	)

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 “Income (loss) from discontinued operations, net of tax” for our commodity contracts associated with the San Antonio Refinery. As of December 31, 2013, we expect to reclassify a loss of $10.7 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,
	2013		2012		2011
	(Thousands of Dollars)
Revenues	$	14,897	$	1,990	$	—
Operating expenses	$	122,677	$	133,654	$	138,324
General and administrative expenses	$	58,602	$	62,490	$	66,220
Interest income	$	6,113	$	1,219	$	—
Revenues included in discontinued operations, net of tax	$	3,720	$	3,390	$	1,039
Expenses included in discontinued operations, net of tax	$	6,051	$	14,328	$	12,238

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 has an original termination date of December 31, 2012, but will automatically renew every two-year unless terminated by either party upon six months’ prior written notice.

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We had a payable to NuStar GP, LLC of $8.3 million and $1.4 million as of December 31, 2013 and 2012, 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, 2013 and 2012 of $41.1 million and $18.1 million, respectively, for amounts payable for retiree medical benefits and other post-employment benefits.

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.

Asphalt JV

Financing Agreements and Credit Support. The NuStar JV Facility is an unsecured revolving credit facility provided by NuStar Energy that will be available to fund working capital needs and for general purposes of Asphalt JV in an aggregate principal amount not to exceed $250.0 million for a term of seven years. The NuStar JV Facility matures on September 28, 2019 and bears interest based on either an alternative base rate or a LIBOR-based rate. As of December 31, 2013, the interest rate was 3.2%. In the event NuStar Energy no longer owns an equity interest in Asphalt JV, the interest rate increases and the availability under the NuStar JV Facility is reduced to a maximum of $167.0 million after two years and $83.0 million after three years. As of December 31, 2013, the face amount of our note receivable from Asphalt JV totaled $176.7 million.

In addition, during the term of the NuStar JV Facility, we will provide credit support, such as guarantees, letters of credit and cash collateral, as applicable, of up to $150.0 million. As of December 31, 2013, we provided guarantees for commodity purchases, lease obligations and certain utilities for Asphalt JV with a maximum potential exposure of $79.7 million, plus two guarantees to suppliers that do not specify a maximum amount. A majority of the guarantees were in existence prior to the Asphalt Sale and have no expiration date. As of December 31, 2013, NuStar Energy has also provided $9.7 million in letters of credit on behalf of Asphalt JV. In the event we are obligated to perform under these guarantees, that amount paid by us will be added to borrowings under the NuStar JV Facility, but it will not reduce the availability under the NuStar Facility.

Variable Interest Entity. We determined the equity of Asphalt JV is not sufficient to finance its activities without additional subordinated support, including support provided by us as described above. Therefore, we determined the Asphalt JV is a VIE. As of December 31, 2013, our maximum exposure to loss as a result of our involvement with Asphalt JV is approximately $450.7 million, which consists of the following (in thousands of dollars):



	Maximum Exposure to Loss		Carrying Value
			asset/(liability)
Receivable from Asphalt JV	$	50,717	$	50,717
Note receivable under the NuStar JV Facility	250,000		165,440
Credit support, including guarantees	150,000		(1,880		)
Total	$	450,717	$	214,277

Terminal Service Agreements. Simultaneously with the Asphalt Sale, we entered into four terminal service agreements with Asphalt JV for our terminals in Wilmington, NC, Rosario, NM, Catoosa, OK and Houston, TX. Pursuant to the terms of the agreements, we provide aggregate storage capacity of 0.8 million barrels and blending services to Asphalt JV for a service charge of $1.5 million per year. The storage charge will be adjusted annually based on the percentage increase in the consumer price index. The terminal service agreements each have a term of ten years, with Asphalt JV’s option to extend for an additional five years. Asphalt JV also has the option to terminate any terminal service agreement with 90 days written notice. If any of the terminal service agreements are extended, the storage charge will be based on the then-current fair market storage rates for comparable storage services charged by us to third parties.

In addition, we have terminal service agreements with Asphalt JV for our terminals in Jacksonville, FL, Dumfries, VA, and Baltimore, MD. These terminal service agreements have lease terms ranging from one to five years, with annual renewal

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options. Asphalt JV has the option to terminate any of these agreements at the end of a lease term with 90 days written notice. Pursuant to the terms of the agreements, we provide aggregate storage capacity of approximately 0.6 million barrels to Asphalt JV for a storage charge of approximately $6.3 million per year, plus applicable throughput and handling fees.

Crude Oil Supply Agreement. We entered into a crude oil supply agreement with Asphalt JV (the Asphalt JV Crude Oil Supply Agreement) that commits Asphalt JV to purchase from us in a given year the lesser of (i) the number of barrels of crude oil required to be purchased by us from PDVSA under the CSA for such year or (ii) 35,000 barrels per day of crude oil multiplied by the number of days in such year. As a result of the termination of the CSA, the Asphalt JV Crude Oil Supply Agreement will also terminate effective January 1, 2014. See Note 16 for additional discussion of the CSA. As of December 31, 2013 and December 31, 2012, we had a receivable from Asphalt JV of $50.7 million and $109.4 million, respectively, mainly associated with crude oil sales under the Asphalt JV Crude Oil Supply Agreement.

Services Agreements Between Asphalt JV and NuStar GP,LLC. In conjunction with the Asphalt Sale, NuStar GP, LLC entered into a services agreement with Asphalt JV, effective September 28, 2012 (the Asphalt JV Services Agreement). The Asphalt JV Services Agreement provides that NuStar GP, LLC furnish certain administrative and other operating services necessary to conduct the business of Asphalt JV. Asphalt JV compensates NuStar GP, LLC for these services through an annual fee totaling $10.0 million, subject to adjustment based on the annual merit increase percentage applicable to NuStar GP, LLC employees for the most recently completed contract year. The Asphalt JV Services Agreement will terminate on December 31, 2017 and will automatically renew for successive two-year terms. Asphalt JV may terminate the Asphalt JV Services Agreement at any time, with 180 days prior written notice or reduce the level of service with 45 days prior written notice. During the year ended December 31, 2013, Asphalt JV provided written notice to reduce the level of services that NuStar GP, LLC provides to Asphalt JV to 63% of the original service level.

In addition, NuStar GP, LLC entered into an employee services agreement with Asphalt JV, effective September 28, 2012 (the Asphalt JV Employee Services Agreement). The Asphalt JV Employee Services Agreement provided that certain of NuStar GP, LLC employees would provide employee-services to Asphalt JV. In exchange, Asphalt JV would reimburse NuStar GP, LLC for the compensation expense of those employees at the same rates that were in effect at the effective date of the Asphalt JV Employee Services Agreement, including an annual bonus amount that does not exceed NuStar GP, LLC’s target bonus plan. The employees covered under the Asphalt JV Employee Services Agreement were not entitled to any new unit-based compensation grants from NuStar GP, LLC, and Asphalt JV was not responsible for unit-based compensation costs prior to the effective date. The Asphalt JV Employee Services Agreement terminated on December 31, 2012, and effective January 1, 2013, those employees became employees of Asphalt JV.

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 became effective July 1, 2006. The Pension Plan covers substantially all of NuStar GP, LLC’s employees and generally provides eligible employees with retirement income calculated under a final average pay formula (FAP) or a cash balance formula. Employees hired before January 1, 2011 are covered under FAP, which is based on years of service and compensation during their period of service, and employees become fully vested in their benefits upon attaining five years of vesting service. Employees hired on January 1, 2011 or after are covered under the cash balance formula, which is based on age and service and interest credits, and employees become fully vested in their benefits upon attaining three years of vesting service. Effective January 1, 2014, the Pension Plan was amended to freeze the FAP benefit as of December 31, 2013 and all employees will be covered under the cash balance formula.

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 (the SERP) has no participants, and it will terminate in 2014 upon a final payment to the former participants.

The NuStar Thrift Plan (the Thrift Plan) is a qualified employee profit-sharing 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, except for part-time employees (as defined in the Thrift Plan), who become eligible upon completing one year of service (as

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defined in the Thrift Plan). Thrift Plan participants can contribute from 1% up to 30% of their total annual compensation to the Thrift Plan in the form of pre-tax and/or after tax employee contributions. 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. Benefits under the Excess Thrift Plan are generally payable in a single lump sum payment upon the employee’s separation from service.

None of the Excess Thrift Plan, the Excess Pension Plan or the SERP 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 provides a medical benefits plan for retired employees. In 2013, the plan was amended for employees that retire on or after April 1, 2014 to provide a defined subsidy 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, 2013, 2012 and 2011, our costs for these plans totaled $2.5 million, $2.6 million and $2.6 million, respectively.

Long-Term Incentive Plans

NuStar GP, LLC sponsors the following:

•

The Third 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, 2013, a total of 1,517,027 NS common units remained available to be awarded 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, 2013, a total of 1,494,177 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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The number of awards granted under the above-described plans were as follows:



	Year Ended December 31,
	2013		2012		2011
	Granted	Vesting	Granted	Vesting	Granted	Vesting
2000 LTIP:
Performance awards	38,786	(a)	33,445	(a)	27,111	(a)
Restricted units (b)	269,182	1/5 per year	231,855	1/5 per year	208,195	1/5 per year
Restricted units (grants to non-employee directors of NuStar GP, LLC)	8,904	1/3 per year	8,170	1/3 per year	6,760	1/3 per year
UIP:
Restricted units (c)	—	—	15,382	1/5 per year	14,005	1/5 per year
2006 LTIP:
Restricted units	18,620	1/5 per year	25,640	1/5 per year	24,970	1/5 per year
Restricted units (grants to non-employee directors of NuStar GP Holdings) (d)	13,183	1/3 per year	10,601	1/3 per year	9,987	1/3 per year


(a)	Performance awards vest 1/3 per year if certain performance measures are met.


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


(c)	The UIP restricted unit grants include 3,392 and 2,880 restricted unit awards granted to certain international employees for the years ended December 31, 2012 and 2011, respectively, 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 various long-term incentive plans and benefit plans described above is as follows:



	Year Ended December 31,
	2013		2012		2011
	(Thousands of Dollars)
Long-term incentive plans	$	9,818	$	7,745	$	8,521
Benefit plans	$	18,204	$	23,602	$	13,684

21. OTHER INCOME (EXPENSE)

Other income (expense) consisted of the following:



	Year Ended December 31,
	2013			2012			2011
	(Thousands of Dollars)
Foreign exchange gains (losses)	$	7,707		$	(1,429	)	$	1,902
(Loss) gain from sale or disposition of assets	(524		)	(1,522		)	155
Loss on deconsolidation of Asphalt JV	—			(23,800		)	—
Storage agreement early termination costs	—			—			(5,000		)
Contingent loss adjustment	—			—			(3,250		)
Other, net	158			2,062			2,620
Other income (expense), net	$	7,341		$	(24,689	)	$	(3,573	)

For the year ended December 31, 2011, “Other income (expense), net” included $5.0 million in costs associated with the early termination of a third-party storage agreement at the Paulsboro, New Jersey asphalt refinery and a contingent loss adjustment of $3.3 million related to a legal settlement.

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22. PARTNERS’ EQUITY

Issuance of Common Units

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, 2011	$	11,500		$	35,000		$	46,500
Other comprehensive loss before reclassifications	(15,425		)	(53,452		)	(68,877		)
Net loss reclassified into (loss) income from discontinued operations	—			(5,030		)	$	(5,030	)
Other comprehensive loss	(15,425		)	(58,482		)	(73,907		)
Balance as of December 31, 2011	(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) income 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 income (loss) attributable to the noncontrolling interest consisted of foreign currency translation adjustment losses of $0.1 million, gains of $1.1 million and losses of $3.0 million, for the years ended December 31, 2013, 2012 and 2011, 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

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allocated 100% to the general partner. The following table details the calculation of net income applicable to the general partner:



	Year Ended December 31,
	2013			2012			2011
	(Thousands of Dollars)
Net income (loss) attributable to NuStar Energy L.P.	$	(273,770	)	$	(226,616	)	$	221,461
Less general partner incentive distribution (a)	43,220			41,242			36,319
Net income (loss) after general partner incentive distribution	(316,990		)	(267,858		)	185,142
General partner interest	2		%	2		%	2		%
General partner allocation of net income (loss) after general partner incentive distribution	(6,338		)	(5,356		)	3,703
General partner incentive distribution	43,220			41,242			36,319
Net income applicable to general partner	$	36,882		$	35,886		$	40,022


(a)	The net income allocation to the general partner’s incentive distribution is less than the actual distribution made with respect to 2011, which is shown in the distribution table below, due to the issuance of common units after the end of the third quarter but before the record date.

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,
	2013		2012		2011
	(Thousands of Dollars, Except Per Unit Data)
General partner interest	$	7,844	$	7,486	$	6,630
General partner incentive distribution	43,220		41,242		36,326
Total general partner distribution	51,064		48,728		42,956
Limited partners’ distribution	341,140		325,526		288,550
Total cash distributions	$	392,204	$	374,254	$	331,506

Cash distributions per unit applicable to limited partners	$	4.380	$	4.380	$	4.360

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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, 2013 (a)	$	1.095	$	98,051	February 10, 2014	February 14, 2014
September 30, 2013	$	1.095	$	98,051	November 11, 2013	November 14, 2013
June 30, 2013	$	1.095	$	98,051	August 5, 2013	August 9, 2013
March 31, 2013	$	1.095	$	98,051	May 6, 2013	May 10, 2013


(a)	The distribution was announced on January 30, 2014.

23. NET (LOSS) INCOME PER UNIT

The following table details the calculation of earnings per unit:



	Year Ended December 31,
	2013			2012			2011
	(Thousands of Dollars, Except Per Unit Data)
Net (loss) income attributable to NuStar Energy L.P.	$	(273,770	)	$	(226,616	)	$	221,461
Less general partner distribution (including IDR)	51,064			48,728			42,948
Less limited partner distribution	341,140			325,526			288,497
Distributions greater than earnings	$	(665,974	)	$	(600,870	)	$	(109,984	)

General partner earnings:
Distributions	$	51,064		$	48,728		$	42,948
Allocation of distributions greater than earnings (2%)	(13,318		)	(12,019		)	(2,201		)
Total	$	37,746		$	36,709		$	40,747

Limited partner earnings:
Distributions	$	341,140		$	325,526		$	288,497
Allocation of distributions greater than earnings (98%)	(652,656		)	(588,851		)	(107,783		)
Total	$	(311,516	)	$	(263,325	)	$	180,714

Weighted-average limited partner units outstanding	77,886,078			72,957,417			65,018,301

Net (loss) income per unit applicable to limited partners	$	(4.00	)	$	(3.61	)	$	2.78

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24. STATEMENTS OF CASH FLOWS

Changes in current assets and current liabilities were as follows:



	Year Ended December 31,
	2013			2012			2011
	(Thousands of Dollars)
Decrease (increase) in current assets:
Accounts receivable	$	107,209		$	160,435		$	(230,980	)
Receivable from related parties	58,692			(113,018		)	—
Inventories	31,975			112,589			(160,139		)
Income tax receivable	414			2,921			(4,265		)
Other current assets	25,725			(26,050		)	(1,825		)
Increase (decrease) in current liabilities:
Accounts payable	(96,330		)	(43,451		)	140,898
Payable to related party	6,922			(5,339		)	(3,603		)
Accrued interest payable	9,370			(6,092		)	126
Accrued liabilities	(32,452		)	11,259			(10,087		)
Taxes other than income tax	(87		)	(2,444		)	2,574
Income tax payable	1,338			(563		)	1,848
Changes in current assets and current liabilities	$	112,776		$	90,247		$	(265,453	)

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, 2012 and 2011 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,
	2013		2012		2011
	(Thousands of Dollars)
Cash paid for interest, net of amount capitalized	$	113,805	$	110,679	$	109,027
Cash paid for income taxes, net of tax refunds received	$	11,386	$	21,032	$	14,920

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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,
	2013			2012			2011
	(Thousands of Dollars)
Current:
U.S.	$	3,098		$	4,416		$	3,769
Foreign	9,273			16,480			8,596
Total current	12,371			20,896			12,365

Deferred:
U.S.	1,687			7,494			2,962
Foreign	(1,305		)	(3,940		)	3,228
Total deferred	382			3,554			6,190

Total income tax expense	$	12,753		$	24,450		$	18,555

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,
	2013			2012
	(Thousands of Dollars)
Deferred income tax assets:
Net operating losses	$	28,945		$	25,567
Environmental and legal reserves	433			291
Valuation allowance	(12,237		)	(78		)
Other	1,772			—
Total deferred income tax assets	18,913			25,780

Deferred income tax liabilities:
Property, plant and equipment	(40,494		)	(54,155		)
Other	—			(631		)
Total deferred income tax liabilities	(40,494		)	(54,786		)

Net deferred income tax liability	$	(21,581	)	$	(29,006	)

Reported on the consolidated balance sheets as:
Deferred income tax asset	$	5,769		$	3,108
Deferred income tax liability	(27,350		)	(32,114		)
Net deferred income tax liability	$	(21,581	)	$	(29,006	)

As of December 31, 2013, our U.S. and foreign corporate operations have net operating loss carryforwards for tax purposes totaling approximately $80.0 million and $4.7 million, respectively, which are subject to various limitations on use and expire in years 2021 through 2033 for U.S. losses and in years 2017 and 2018 for foreign losses.

As of December 31, 2013 and 2012, we recorded a valuation allowance of $12.2 million and $0.1 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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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 2013, we increased the valuation allowance for the U.S. and foreign net operating loss by $10.3 million and $1.8 million, respectively, 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, 2013 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, 2013 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.

St. Eustatius Tax Agreement

On June 1, 1989, the governments of the Netherlands Antilles and St. Eustatius approved a Free Zone and Profit Tax Agreement retroactive to January 1, 1989, which expired on December 31, 2000. This agreement required a subsidiary of Kaneb, which we acquired on July 1, 2005, to pay the greater of 2% of taxable income, as defined therein, or 500,000 Netherlands Antilles guilders (approximately $0.3 million) per year. The agreement further provided that any amounts paid in order to meet the minimum annual payment were available to offset future tax liabilities under the agreement to the extent that the minimum annual payment is greater than 2% of taxable income. On February 22, 2006, we entered into a revised agreement (the 2005 Tax and Maritime Agreement) with the governments of St. Eustatius and the Netherlands Antilles. The 2005 Tax and Maritime Agreement was effective beginning January 1, 2005 and expires on December 31, 2014. Under the terms of the 2005 Tax and Maritime 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. We further agreed to pay an annual minimum profit tax to St. Eustatius of 1.0 million Netherlands Antilles guilders (approximately $0.6 million), beginning as of January 1, 2005. We agreed to pay the minimum annual profit tax in twelve equal monthly installments. To the extent the minimum annual profit tax exceeds 2% of taxable profit (as defined in the 2005 Tax and Maritime 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 contends that as of January 2011, we are subject to real estate tax rather than profit tax as expressed in our tax agreement. In 2013, the Ministry issued a property tax assessment for years 2011 through 2012. We objected to and appealed the assessment. In 2013, we filed a lawsuit in the Netherlands civil court seeking to enforce the terms of our existing St. Eustatius tax agreement. We believe it is likely that we will prevail in the lawsuit.

26. SEGMENT INFORMATION

Our reportable business segments consist of storage, pipeline (formerly known as the transportation segment), and fuels marketing. In 2013, we changed the name of the “Asphalt and Fuels Marketing” segment to the “Fuels Marketing” segment since this name more accurately reflects the operations that remain after the Asphalt Sale and the San Antonio Refinery Sale.

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 terminalling and storage of petroleum products, the transportation of petroleum products and anhydrous ammonia, and fuels marketing. Intersegment revenues result from storage and throughput agreements with wholly owned subsidiaries of NuStar Energy at lease rates consistent with rates charged to third parties for storage and at pipeline tariff rates based upon the applicable

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published tariff. Related party revenues mainly result from storage agreements with our joint ventures and the noncontrolling shareholder of our Turkey subsidiary.

Results of operations for the reportable segments were as follows:



	Year Ended December 31,
	2013			2012			2011
	(Thousands of Dollars)
Revenues:
Storage:
Third parties	$	518,253		$	517,699		$	500,303
Intersegment	32,044			59,168			46,324
Related party	6,252			1,199			—
Total storage	556,549			578,066			546,627
Pipeline:
Third parties	411,529			340,455			311,449
Intersegment	—			—			65
Total pipeline	411,529			340,455			311,514
Fuels marketing:
Third parties	2,519,053			5,085,592			5,445,877
Intersegment	—			—			9,782
Related party	8,645			791			—
Total fuels marketing	2,527,698			5,086,383			5,455,659
Consolidation and intersegment eliminations	(32,044		)	(59,168		)	(56,171		)
Total revenues	$	3,463,732		$	5,945,736		$	6,257,629

Depreciation and amortization expense:
Storage	$	99,868		$	88,217		$	82,921
Pipeline	68,871			52,878			51,165
Fuels marketing	27			11,253			20,949
Total segment depreciation and amortization expense	168,766			152,348			155,035
Other depreciation and amortization expense	10,155			7,441			6,738
Total depreciation and amortization expense	$	178,921		$	159,789		$	161,773

Operating (loss) income:
Storage	$	(127,484	)	$	198,842		$	196,508
Pipeline	208,293			158,590			146,403
Fuels marketing	(126		)	(296,785		)	71,854
Consolidation and intersegment eliminations	1,437			7,939			5,906
Total segment operating income	82,120			68,586			420,671
Less general and administrative expenses	91,086			104,756			103,050
Less other depreciation and amortization expense	10,155			7,441			6,738
Other asset impairment loss	—			3,295			—
Gain on legal settlement	—			(28,738		)	—
Total operating (loss) income	$	(19,121	)	$	(18,168	)	$	310,883

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Revenues by geographic area are shown in the table below.



	Year Ended December 31,
	2013		2012		2011
	(Thousands of Dollars)
United States	$	2,340,694	$	4,230,607	$	4,521,553
Netherlands	1,027,260		1,438,297		1,564,062
Other	95,778		276,832		172,014
Consolidated revenues	$	3,463,732	$	5,945,736	$	6,257,629

For the years ended December 31, 2013, 2012 and 2011, Valero Energy Corporation accounted for approximately 15%, or $534.2 million, 11%, or $668.1 million, and 11%, or $684.1 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,
	2013		2012
	(Thousands of Dollars)
United States	$	2,635,792	$	2,560,608
Netherlands	467,660		454,560
Other	207,201		223,292
Consolidated long-lived assets	$	3,310,653	$	3,238,460

Total assets by reportable segment were as follows:



	December 31,
	2013		2012
	(Thousands of Dollars)
Storage	$	2,275,183	$	2,627,946
Pipeline	1,797,698		1,720,711
Fuels marketing	445,882		885,661
Total segment assets	4,518,763		5,234,318
Other partnership assets	513,423		378,771
Total consolidated assets	$	5,032,186	$	5,613,089

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



	Year Ended December 31,
	2013		2012		2011
	(Thousands of Dollars)
Storage	$	170,637	$	161,672	$	263,918
Pipeline	165,096		493,028		45,170
Fuels marketing	69		20,333		90,683
Other partnership assets	7,518		53,982		45,569
Total capital expenditures	$	343,320	$	729,015	$	445,340

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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, 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
Income tax receivable	—		—		—		826		—			826
Other current assets	—		18,109		2,334		19,009		—			39,452
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, less current portion	—		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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Condensed Consolidating Balance Sheets

December 31, 2012

(Thousands of Dollars)



	NuStar Energy		NuStar Logistics		NuPOP		Non-Guarantor Subsidiaries		Eliminations			Consolidated
Assets
Cash and cash equivalents	$	7,033	$	1,112	$	—	$	75,457	$	—		$	83,602
Receivables, net	—		157,452		10,561		340,144		(10,381		)	497,776
Inventories	—		2,320		5,590		165,349		(31		)	173,228
Income tax receivable	—		—		—		1,265		—			1,265
Other current assets	—		26,353		1,468		37,417		—			65,238
Assets held for sale	—		35,337		—		82,997		—			118,334
Intercompany receivable	—		353,384		599,599		—		(952,983		)	—
Total current assets	7,033		575,958		617,218		702,629		(963,395		)	939,443
Property, plant and equipment, net	—		1,423,991		582,299		1,232,170		—			3,238,460
Intangible assets, net	—		18,733		—		73,702		—			92,435
Goodwill	—		145,990		170,652		634,382		—			951,024
Investment in wholly owned subsidiaries	3,133,097		161,957		1,208,595		2,329,595		(6,833,244		)	—
Investment in joint ventures	—		35,883		—		67,062		—			102,945
Deferred income tax asset	—		—		—		3,108		—			3,108
Note receivable from related party, net	—		95,711		—		—		—			95,711
Other long-term assets, net	490		148,384		26,330		14,759		—			189,963
Total assets	$	3,140,620	$	2,606,607	$	2,605,094	$	5,057,407	$	(7,796,639	)	$	5,613,089
Liabilities and Partners’ Equity
Current portion of long-term debt	$	—	$	1,313	$	250,967	$	34,142	$	—		$	286,422
Payables	15		122,706		12,657		274,044		(10,381		)	399,041
Accrued interest payable	—		22,512		1,224		5		—			23,741
Accrued liabilities	862		76,322		7,542		39,477		—			124,203
Taxes other than income tax	129		5,671		2,830		1,263		—			9,893
Income tax payable	—		247		—		2,424		—			2,671
Intercompany payable	508,365		—		—		444,618		(952,983		)	—
Total current liabilities	509,371		228,771		275,220		795,973		(963,364		)	845,971
Long-term debt, less current portion	—		2,124,582		—		—		—			2,124,582
Long-term payable to related party	—		12,629		—		5,442		—			18,071
Deferred income tax liability	—		—		—		32,114		—			32,114
Other long-term liabilities	—		2,701		279		4,376		—			7,356
Total partners’ equity	2,631,249		237,924		2,329,595		4,219,502		(6,833,275		)	2,584,995
Total liabilities and partners’ equity	$	3,140,620	$	2,606,607	$	2,605,094	$	5,057,407	$	(7,796,639	)	$	5,613,089

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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 (a)			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		)
Income (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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Condensed Consolidating Statements of Income (Loss)

For the Year Ended December 31, 2011

(Thousands of Dollars)



	NuStar Energy			NuStar Logistics			NuPOP			Non-Guarantor Subsidiaries			Eliminations			Consolidated
Revenues	$	—		$	296,142		$	199,569		$	5,794,433		$	(32,515	)	$	6,257,629
Costs and expenses	1,663			174,360			142,077			5,661,577			(32,931		)	5,946,746
Operating (loss) income	(1,663		)	121,782			57,492			132,856			416			310,883
Equity in earnings of subsidiaries	223,125			12,883			108,644			145,218			(489,870		)	—
Equity in earnings of joint venture	—			—			—			11,458			—			11,458
Interest expense, net	—			(56,389		)	(22,840		)	(2,310		)	—			(81,539		)
Other income (expense), net	—			1,309			1,936			(6,818		)	—			(3,573		)
Income from continuing operations before income tax expense	221,462			79,585			145,232			280,404			(489,454		)	237,229
Income tax expense (benefit)	1			(575		)	13			19,116			—			18,555
Income from continuing operations	221,461			80,160			145,219			261,288			(489,454		)	218,674
(Loss) income from discontinued operations, net of tax	—			(2,334		)	—			5,261			—			2,927
Net income	221,461			77,826			145,219			266,549			(489,454		)	221,601
Less net income attributable to noncontrolling interest	—			—			—			140			—			140
Net income attributable to NuStar Energy L.P.	$	221,461		$	77,826		$	145,219		$	266,409		$	(489,454	)	$	221,461

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

Comprehensive (loss) income	(273,770		)	21,375			(281,320		)	(640,024		)	884,487		(289,252		)
Less comprehensive gain 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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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Condensed Consolidating Statements of Comprehensive Income

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) income:
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 gain 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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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Condensed Consolidating Statements of Comprehensive Income

For the Year Ended December 31, 2011

(Thousands of Dollars)



	NuStar Energy		NuStar Logistics			NuPOP		Non-Guarantor Subsidiaries			Eliminations			Consolidated
Net income	$	221,461	$	77,826		$	145,219	$	266,549		$	(489,454	)	$	221,601

Other comprehensive (loss) income:
Foreign currency translation adjustment	—		—			—		(18,431		)	—			(18,431		)
Net unrealized (loss) gain on cash flow hedges	—		(84,199		)	—		30,747			—			(53,452		)
Net gain reclassified into income on cash flow hedges	—		—			—		(5,030		)	—			(5,030		)
Total other comprehensive (loss) income	—		(84,199		)	—		7,286			—			(76,913		)

Comprehensive income (loss)	221,461		(6,373		)	145,219		273,835			(489,454		)	144,688
Less comprehensive loss attributable to noncontrolling interest	—		—			—		(2,866		)	—			(2,866		)
Comprehensive income (loss) attributable to NuStar Energy L.P.	$	221,461	$	(6,373	)	$	145,219	$	276,701		$	(489,454	)	$	147,554

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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	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 offering, 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 borrowings (repayments)	(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 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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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 senior note offering, net of issuance costs	—			247,398			—			—			—			247,398
Issuance of common units, net of issuance costs	336,415			—			—			—			—			336,415
General partner contribution	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 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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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Condensed Consolidating Statements of Cash Flows

For the Year Ended December 31, 2011

(Thousands of Dollars)



	NuStar Energy			NuStar Logistics			NuPOP			Non-Guarantor Subsidiaries			Eliminations			Consolidated
Net cash provided by (used in) operating activities	$	377,469		$	121,416		$	59,109		$	(84,135	)	$	(379,391	)	$	94,468
Cash flows from investing activities:
Capital expenditures	—			(197,845		)	(8,093		)	(129,722		)	—			(335,660		)
Acquisitions	—			(47,817		)	—			(52,873		)	—			(100,690		)
Investment in other long-term assets	—			—			—			(8,990		)	—			(8,990		)
Proceeds from sale or disposition of assets	—			63			86			1,937			—			2,086
Investment in subsidiaries	(374,628		)	—			(56,727		)	(56,759		)	488,114			—
Net cash used in investing activities	(374,628		)	(245,599		)	(64,734		)	(246,407		)	488,114			(443,254		)
Cash flows from financing activities:
Debt borrowings	—			949,549			—			—			—			949,549
Debt repayments	—			(801,950		)	—			—			—			(801,950		)
Issuance of common units, net of issuance costs	317,285			—			—			—			—			317,285
General partner contribution	6,708			—			—			—			—			6,708
Distributions to unitholders and general partner	(322,046		)	(322,046		)	—			(32		)	322,078			(322,046		)
Proceeds from termination of interest rate swaps	—			33,433			—			—			—			33,433
Contributions from (distributions to) affiliates	—			260,028			56,727			114,053			(430,808		)	—
Net intercompany borrowings (repayments)	(4,702		)	(105,944		)	(51,102		)	161,741			7			—
Other, net	—			4,705			—			(963		)	—			3,742
Net cash (used in) provided by financing activities	(2,755		)	17,775			5,625			274,799			(108,723		)	186,721
Effect of foreign exchange rate changes on cash	—			(1,233		)	—			(326		)	—			(1,559		)
Net increase (decrease) in cash and cash equivalents	86			(107,641		)	—			(56,069		)	—			(163,624		)
Cash and cash equivalents as of the beginning of the period	53			107,655			—			73,413			—			181,121
Cash and cash equivalents as of the end of the period	$	139		$	14		$	—		$	17,344		$	—		$	17,497

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NUSTAR ENERGY L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

28. QUARTERLY FINANCIAL DATA (UNAUDITED)

As further discussed in Note 5, we reclassified certain storage assets as “Assets held for sale” on the consolidated balance sheet as of December 31, 2013. We presented the results of operations for those facilities as discontinued operations for all periods presented. As a result, the amounts shown below differ from those previously reported in our quarterly reports on Form 10-Q and in our annual report for the year ended December 31, 2012.



	First Quarter			Second Quarter			Third Quarter			Fourth Quarter			Total
	(Thousands of Dollars, Except Per Unit Data)
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

2012:
Revenues	$	1,606,449		$	1,764,667		$	1,591,730		$	982,890		$	5,945,736
Operating income (loss)	$	60,882		$	(201,925	)	$	62,750		$	60,125		$	(18,168	)
Income (loss) from continuing operations	$	39,978		$	(241,871	)	$	17,000		$	18,892		$	(166,001	)
Loss from discontinued operations, net of tax	(13,724		)	(4,939		)	(12,658		)	(29,915		)	(61,236		)
Net income (loss)	$	26,254		$	(246,810	)	$	4,342		$	(11,023	)	$	(227,237	)
Net income (loss) per unit applicable to limited partners:
Continuing operations	$	0.41		$	(3.48	)	$	0.08		$	0.10		$	(2.79	)
Discontinued operations	(0.18		)	(0.08		)	(0.17		)	(0.37		)	(0.82		)
Total	$	0.23		$	(3.56	)	$	(0.09	)	$	(0.27	)	$	(3.61	)
Cash distributions per unit applicable to limited partners	$	1.095		$	1.095		$	1.095		$	1.095		$	4.380

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NUSTAR ENERGY L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

29. SUBSEQUENT EVENTS

On February 26, 2014, we sold our remaining 50% ownership interest in Asphalt JV to Lindsay Goldberg, and Lindsay Goldberg now owns 100% of Asphalt JV. Since we no longer own any part of Asphalt JV, we ceased applying the equity method of accounting. Upon the sale, the NuStar JV Facility was converted from a revolving credit agreement into a term loan (the Term Loan) with a reduced principal, and the Term Loan will continue to step down from $190.0 million over time: first, to $175.0 million on December 31, 2014 and then to $150.0 million on September 30, 2015. While the Term Loan does not provide for any scheduled amortization payments, Asphalt JV is required to use all of its excess cash, as defined in the agreement, to repay the Term Loan. Like the NuStar JV Facility, the Term Loan must be repaid in full on September 28, 2019. NuStar Logistics’ obligation to provide credit support will be reduced in two years. This entire support obligation will terminate no later than September 28, 2019. Also at the time of the sale, the parties agreed to: terminate the service agreements for our terminals in Rosario, NM, Catoosa, OK and Houston, TX, amend the terminal services agreements for the Baltimore, MD and Jacksonville, FL terminals, and transfer the title to both the Wilmington, NC and Dumfries, VA terminals to Asphalt JV.

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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 operating effectively as of December 31, 2013.

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 January 1, 2014.



Name	Age	Position Held with NuStar GP, LLC
William E. Greehey	77	Chairman of the Board
Bradley C. Barron	48	President, Chief Executive Officer (CEO) and Director
J. Dan Bates	69	Director
Dan J. Hill	73	Director
Rodman D. Patton	70	Director
W. Grady Rosier	65	Director
Mary Rose Brown	57	Executive Vice President and Chief Administrative Officer
Douglas W. Comeau	57	Executive Vice President
Thomas R. Shoaf	55	Executive Vice President and Chief Financial Officer (CFO)
Amy L. Perry	45	Senior Vice President, General Counsel-Corporate & Commercial Law and Corporate Secretary
Karen M. Thompson	46	Senior Vice President and General Counsel-Litigation, Regulatory & Environmental
Jorge A. del Alamo	44	Vice President and Controller

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. 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. Patton 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 has also 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.

Mr. Barron became CEO, 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

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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 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 has been President and CEO of the Southwest Research Institute since 1997. Mr. Bates also serves as Chairman of the board of Signature Science L.L.C., Vice Chairman of Southwest Automotive Research Center and as a director of both 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 has also 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 CEO 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 has also 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. Comeau became Executive Vice President of NuStar GP, LLC and NuStar GP Holdings in September 2012. He served as Senior Vice President-Corporate Development and Strategic Planning of NuStar GP, LLC from March 2012 until his promotion in September 2012. Prior to his service to NuStar GP, LLC, Mr. Comeau served as Vice President and General Manager of the Benicia Refinery for Valero Energy from August 2003 to March 2012. He served as Vice President-Strategic Capital Review for Valero Energy from January 2001 to August 2003.

Mr. Shoaf became Executive Vice President and CFO 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.

Ms. Perry became Senior Vice President, General Counsel-Corporate & Commercial Law and Corporate Secretary of NuStar GP, LLC and NuStar GP Holdings in January 2014. She served as Vice President, Assistant General Counsel and Corporate Secretary of NuStar GP, LLC and as Corporate Secretary of NuStar GP Holdings from February 2010 until her promotion in January 2014. From June 2005 to February 2010 she served as Assistant General Counsel and Assistant Secretary of NuStar GP, LLC and from March 2006 to February 2010, Assistant Secretary of NuStar GP Holdings. Prior to her service at NuStar GP, LLC, Ms. Perry served as Counsel to Valero Energy.

Ms. Thompson became Senior Vice President, General Counsel-Litigation, Regulatory & Environmental of NuStar GP, LLC and NuStar GP Holdings in January 2014. She served as Vice President, Assistant General Counsel and Assistant Secretary of NuStar GP, LLC from February 2010 until her promotion in January 2014. From May 2007 to February 2010 she served as Assistant General Counsel and Assistant Secretary of NuStar GP, LLC. Prior to her service at NuStar GP, LLC, Ms. Thompson served as Senior Counsel to Valero Energy.

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Mr. del Alamo became Vice President and Controller of NuStar GP, LLC and NuStar GP Holdings in 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 February 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.

COMPLIANCE WITH SECTION 16(a) OF THE EXCHANGE ACT

Section 16(a) of the Exchange Act requires directors, executive officers and persons who beneficially own more than 10% of NuStar Energy L.P.’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 during the year ended December 31, 2013 all Section 16(a) reports applicable to our executive officers, directors and greater than 10% stockholders were timely filed.

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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 and compliance with applicable laws, rules and regulations.

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 during 2013 were Mr. Patton (Chairman), Mr. Bates, Mr. Hill and Mr. Rosier. The Audit Committee met seven times in 2013. For further information, see the “Report of the Audit Committee” below.

The Board has determined that Mr. Patton is an “audit committee financial expert” (as defined by the SEC), and that he is “independent” as that term is used in the NYSE Listing Standards.

REPORT OF THE AUDIT COMMITTEE FOR FISCAL YEAR 2013

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, 2013, 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.

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, 2013.

Members of the Audit Committee:

Rodman D. Patton (Chairman)

J. Dan Bates

Dan J. Hill

W. Grady Rosier

RISK OVERSIGHT

While 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.

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Evaluation of Compensation Risk. The Compensation Committee has focused on aligning our compensation policies with the long-term interests of NuStar Energy and avoiding short-term rewards for management decisions that could pose long-term risks to NuStar Energy. 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 the long-term goals of NuStar Energy. No business group or unit is compensated differently than any other, regardless of profitability. There is also a maximum number of performance units that may be earned, based on the performance of NuStar Energy relative to certain peer companies. 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.

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ITEM 11. EXECUTIVE COMPENSATION

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.

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 Item 11. Our executives do not have employment or severance agreements, other than the change-of-control agreements described below in “Potential Payments Upon Termination or Change of Control.” The Compensation Committee targets base salary for our NEOs, as well as annual incentive bonus and long-term incentive awards (expressed, in each case, as a percentage of base salary), at or near the median of our peer group and after reviewing survey data for a group of 849 industrial companies. 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, 2013 were: Curtis V. Anastasio, Bradley C. Barron, Steven A. Blank, Mary Rose Brown and Douglas W. Comeau. Mr. Anastasio and Mr. Blank each retired effective December 31, 2013. 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, Jorge A. del Alamo, formerly Vice President (VP) & Assistant Controller, was named VP & Controller; Amy L. Perry, formerly VP, Assistant GC-Corporate/Commercial & Corporate Secretary, was named SVP, GC-Corporate/Commercial & Corporate Secretary; and Karen M. Thompson, formerly VP & Assistant GC-Litigation, was named SVP & GC-Litigation.

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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 relies upon two primary sources of competitive compensation data in assessing base salary rates, annual incentive compensation and long-term incentive compensation: 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 Committee, in consultation with management and BDO, identified a specific peer group (listed below), composed primarily of master limited partnerships but also including independent, regional refining companies, to evaluate competitive rates of compensation (the Compensation Comparative Group). Each of these organizations, in our opinion, competes with us for executive talent. We intend to reevaluate this group in 2014, particularly with respect to the refining companies, in view of the fact we no longer directly own any refining assets, due to our third quarter 2012 sale of 50% of the Asphalt Business, our first quarter 2013 sale of the San Antonio refinery and our 2014 sale of our remaining 50% interest in the Asphalt Business. The competitive data for these companies is derived from their respective publicly filed annual proxy statements or annual reports on Form 10-K.

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Company	Ticker
1. Boardwalk Pipeline Partners, LP	BWP
2. Buckeye Partners L.P.	BPL
3. Crosstex Energy L.P.	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 Compensation Committee also periodically 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 compensation database of approximately 849 U.S. industrial companies that is updated each year. Periodically, at the Committee’s request, BDO reviews and interprets tabular data from the Towers Watson survey for companies in a range of reported revenues comparable to NuStar Energy’s. We refer to the competitive survey data, together with the Compensation Comparative Group data, 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 unit options and restricted units and in the first quarter for performance units. The Compensation Committee may also review salaries or grant long-term incentive awards at other times during the year because of new appointments, promotions or other extraordinary circumstances.

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



Event	Timing
Establish financial performance objectives for current year’s annual incentive bonus; evaluating 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 grant of restricted unit and unit options 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 2013 long-term incentive grants is discussed below under “Performance Units” and “Restricted Units.”

Elements of Executive Compensation

General

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 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 making a significant portion of an executive officer’s incentive compensation contingent on long-term unit price 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

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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 2013 for each of our NEOs:



Name	Target Percentage of Total Direct Compensation
Name	Base Salary (%)	Annual Incentive Bonus (%)	Long-Term Incentives (%)	TOTAL
Anastasio	26	23	51	100
Barron	35	21	44	100
Blank	35	21	44	100
Brown	35	21	44	100
Comeau	31	23	46	100

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.

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.

In July 2011, BDO performed a comprehensive review of our NEO’s Total Direct Compensation. In July 2012 and 2013, management reviewed several sets of survey data, including a Aon Hewitt study, a Mercer study and The World At Work, and they also considered anecdotal information about compensation by local companies. In 2013, management recommended that each NuStar employee throughout the company, including the NEOs, be eligible to receive a merit-based pay raise in the range of 0% to 3% of his or her actual salary paid during the prior 12-month period (Eligible Salary). Each NEO, other than Mr. Barron, received a raise in their base salary in the amount of 3% of their Eligible Salary, as provided in the table below. The Compensation Committee awarded Mr. Barron an 8.24% raise in order to address internal pay disparities.

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Name	Annualized Base Salary at December 31, 2013		July 2013 Increase to Prior Annualized Salary
Anastasio		$553,000		$16,100
Barron	344,570		34,820
Blank	384,610		11,200
Brown	344,570		10,040
Comeau	395,920		10,920

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 and a determination of 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.

The following table shows each NEO’s annual bonus target for the fiscal year ended December 31, 2013, before discretionary adjustments:



Name	Annual Incentive Bonus Target (% of Eligible Earnings)
Anastasio	90
Barron	60
Blank	60
Brown	60
Comeau	75

Determination of Annual Incentive Target Opportunities

As illustrated by the example 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. In addition, the plan allows for the upward or downward adjustment of awards, based upon attainment of the financial goal, equal to a range of 0% to 200% of the target award. If we failed to reach at least the threshold level of performance for our financial goal, the participant would have earned an incentive award of $0. Likewise, if we had achieved the maximum level of performance for the financial goal, the participant could earn up to 200% of his target award.

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 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.

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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 2013, as in prior years, the Compensation Committee approved a DCF 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 NuStar Energy’s budgeted DCF for the year as a target and establishes corresponding levels of performance for which the incentive opportunity would be paid, such that if less than 90% of the target was attained, no bonus would be paid; if 90% of the target was attained, 50% of the incentive opportunity could be paid; if the target was achieved, 100% of the incentive opportunity could be paid; if 110% of the target was attained, 150% of the incentive opportunity could be paid; and if 120% or more of the target was attained, 200% of the incentive opportunity could be paid. The Compensation Committee has discretion to raise or lower the incentive opportunity resulting from this calculation by 25%. In addition, the budgeted DCF may be adjusted during the year in order to account for acquisitions or other significant changes not anticipated at the time the target was determined. In 2013, NuStar’s budgeted DCF was $338,190,000.

Determination of Awards

For the 2013 annual incentive bonus determination, the Compensation Committee compared NuStar Energy’s DCF with the established target to determine the amount of incentive award earned. NuStar Energy’s DCF for 2013 was below 100%, but above 90% of the target. The Compensation Committee set the potential bonus target award at 50%. Actual bonuses awarded are shown in the following table:



Name	Bonuses Paid For 2013 ($)
Anastasio	200,000
Barron	125,000
Blank	100,000
Brown	110,000
Comeau	100,000

Long-term Incentive Awards

We provide unit-based, long-term compensation for employees, including executives and directors, through our Fourth Amended and Restated 2000 Long-Term Incentive Plan (the 2000 LTIP), effective as of May 1, 2011. 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 the long-term incentive award plan, each plan participant, including the NEOs, are 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.

Based on BDO’s periodic review and analysis, the Compensation Committee has designated each NEO’s long-term incentive targets (expressed as a percent of base salary) as shown in the table below.

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Name	Long-Term Incentive Target (% of base salary)
Anastasio	200
Barron	125
Blank	125
Brown	125
Comeau	150

The Compensation Committee allocates a percentage of long-term 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 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 all 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



Name	Restricted Units Granted in 2013
Name	NS	NSH
Anastasio (1)	—	—
Barron	4,750	3,440
Blank (1)	—	—
Brown	4,750	3,440
Comeau	6,550	4,745

(1) Mr. Anastasio and Mr. Blank retired, effective December 31, 2013, and, in accordance with the terms of the 2013 restricted unit grant agreements, their respective 2013 grants were forfeited as of the date of retirement.

The 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 10 business days approximately one month prior to the Compensation Committee meeting at which the awards are to be approved). The restricted units all vest in equal increments on the anniversary of the grant date over five years. 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 NuStar GP Holdings restricted units grants, as well as the 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 2013, 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 grant was not made until December 16, 2013.

Performance Units

In January 2013, performance units comprised approximately 35% of each of our NEOs’ total NuStar Energy long-term incentive targets. Performance units are earned only upon NuStar Energy’s achievement of an objective performance measure,

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total unitholder return (TUR), as compared with the 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. The Compensation Committee believes this type of incentive award strengthens the tie between the named executive’s pay and our financial performance.

The number of performance units granted in 2013 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 2013
Anastasio	11,000
Barron	3,933
Blank	4,740
Brown	4,248
Comeau	5,865

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 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 vested, 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.

On January 30, 2014, the Compensation Committee met and discussed NuStar Energy’s performance for the performance period ended December 31, 2013, and determined that our performance ranked in the fourth quartile of our peer group for that three-year period. This performance determination resulted in the NEOs receiving none of the 2013 performance units available to vest in January 2014.

Perquisites and Other Benefits

Perquisites

We provide only minimal perquisites to our executive officers. Mr. Anastasio, Mr. Barron, Mr. Blank, Ms. Brown and Mr. Comeau received federal income tax preparation services in 2013. Executives are also 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.”

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Post-Employment Benefits

Pension Plans

For a discussion of our pension plans, as well as the Excess Pension Plan and the Supplemental Executive Retirement Plan (which has no participants and is scheduled to terminate during 2014), please see the narrative description accompanying the Pension Benefits table below this item.

Nonqualified Deferred Compensation Plans

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 ($255,000 for 2013), 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. Anastasio, Mr. Barron and Ms. Brown participated in the Excess Thrift Plan in 2013.

Frozen Nonqualified 401(k) Plan

Effective July 1, 2006, we established the NuStar GP, LLC Frozen Nonqualified 401(k) Plan for Former Employees of Ultramar Diamond Shamrock Corporation (the Frozen Plan). The Frozen Plan assumes and continues the frozen Ultramar Diamond Shamrock Corporation Nonqualified 401(k) Plan (the UDS Plan) with respect to the current NuStar GP, LLC employees who had accrued benefits under the UDS Plan. No additional benefits accrue under the Frozen Plan, and we make no contributions to the Frozen Plan. Mr. Anastasio and Mr. Blank, who both retired in 213, are the only participants in the Frozen Plan accounts.

Change-of-Control Severance Arrangements

We entered into change of control 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 employment 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: (i) termination of employment by the company other than for “cause” (as defined in the agreements) or disability, (ii) termination by the executive for “good reason” (as defined in the agreements), (iii) termination by the executive other than for “good reason,” and (iv) 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 severance arrangements, see our disclosures below under the caption “Potential Payments upon Termination or Change-in-Control Payments.”

Employment Agreements

None of the NEOs have employment agreements, other than the change-of-control agreements described above. As a result, in the event of a termination, retirement, death or disability, an officer will only receive 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.

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Impact of Accounting and Tax Treatments

Accounting Treatment

NuStar Energy’s financial statements include the expense for awards of NuStar Energy unit options and restricted 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. Certain Relationships and Related Transactions and Director Independence. 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 L.P. common 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.

Each month, NuStar GP, LLC determines the fair value of its liability for awards of NuStar Energy unit options and restricted units. The fair value of unit options is determined 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. 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, considering the percentage of the award that has vested to date. 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 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 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 (i) solely upon attainment of one or more performance goals, (ii) pursuant to a qualifying performance-based compensation plan adopted by the Compensation Committee, and (iii) 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 committee believes that unit options and performance unit grants qualify as performance-based compensation and would therefore 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 L.P. 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 directors and NuStar GP, LLC 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 and the Board in March 2006. In February 2007, in view of the public offerings of NuStar GP Holdings in 2006, the Compensation Committee amended the guidelines to include ownership of either NuStar GP Holdings units or NuStar Energy units. An officer or a director’s ownership also includes units subject to vesting.

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
President	3.0x Base Salary
Senior Vice Presidents and above	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 L.P. or NuStar GP Holdings, LLC Units

We have established policies prohibiting our officers, directors and employees from purchasing or selling either NuStar Energy L.P. or NuStar GP Holdings, LLC 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 outside directors, officers and certain other employees are prohibited from trading in either NuStar Energy L.P. or NuStar GP Holdings, LLC securities for the period beginning on the last business day of each calendar quarter through the second 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 the either NuStar Energy L.P. or NuStar GP Holdings, LLC 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 management consent before they enter into margin loans or other financing arrangements that may lead to the ownership or other rights to their NuStar Energy L.P. or NuStar GP Holdings, LLC securities being transferred to a third party.

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EXECUTIVE COMPENSATION

The tables that appear in the following pages of this section provide information required by the SEC regarding compensation paid to or earned by our NEOs for the year ended December 31, 2013. We have used captions and headings in these tables 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

FOR FISCAL YEAR ENDED DECEMBER 31, 2013

The following table provides a summary of compensation paid for the years ended December 31, 2013, December 31, 2012 and December 31, 2011 to NuStar GP, LLC’s CEO, CFO and to its three other most highly compensated executive officers. The table shows amounts earned by such persons for services rendered to NuStar GP, LLC in all capacities in which they served.



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 ($)(4)	Total ($)
Curtis V. Anastasio Retired President and CEO	2013	513,755	200,000	557,370	—	—	(9,124	)	3,428,647	4,690,648
	2012	528,450	—	1,414,505	—	—	194,066		34,940	2,171,961
	2011	504,000	453,600	988,617	—	—	241,385		38,628	2,381,917
Bradley C. Barron Former Executive Vice President and General Counsel (Current President and CEO)	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
	2011	290,570	174,300	355,723	—	—	79,153		15,937	915,683
Steven A. Blank Retired Executive Vice President, CFO and Treasurer	2013	358,793	100,000	240,176	—	—	1,662		1,678,678	2,379,309
	2012	367,535	—	610,065	—	—	145,953		24,113	1,147,666
	2011	356,395	213,800	433,693	—	—	303,970		26,289	1,253,774
Mary Rose Brown Executive Vice President- Administration	2013	345,983	110,000	546,876	—	—	8,444		24,302	1,035,605
	2012	329,265	—	547,821	—	—	127,380		22,400	1,026,866
	2011	319,335	191,600	388,490	—	—	99,450		14,826	1,013,701
Douglas W. Comeau Executive Vice President	2013	390,460	100,000	754,520	—	—	20,601		25,615	1,291,196
Douglas W. Comeau Executive Vice President	2012	251,820	—	821,121	—	—	—		11,594	1,084,535

Footnotes:

(1)

2013 bonus amounts were paid in February 2014 with respect to 2013 performance. The NEOs were not awarded a bonus for 2012. 2011 bonus awards were paid in February 2012 with respect to 2011 performance. 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 Disclosure & Analysis-Annual Incentive Bonus.”


(2)	The amounts reported represent the grant date fair value of grants of restricted NuStar Energy L.P. units, NuStar Energy L.P. performance units and restricted NuStar GP Holdings, LLC units. Please see “Compensation Discussion and Analysis-Impact of Accounting and Tax Treatment-Accounting Treatment” above in this item for more information.


(3)	For the applicable NEOs, the following table identifies the separate amounts attributable to (A) the aggregate change in the actuarial present value of the NEO’s 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

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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
Anastasio	2013	$	(9,124	)	—	$	(9,124	)
	2012	194,066			—	194,066
	2011	241,385			—	241,385
Barron	2013	2,328			—	2,328
	2012	134,758			—	134,758
	2011	79,153			—	79,153
Blank	2013	1,662			—	1,662
	2012	145,953			—	145,953
	2011	303,970			—	303,970
Brown	2013	8,444			—	8,444
	2012	127,380			—	127,380
	2011	99,450			—	99,450
Comeau	2013	20,601			—	20,601
Comeau	2012	—			—	—

(4) The amounts reported in this column for 2013 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)	Retirement-related Payments (b)		TOTAL
Anastasio	$	22,092	$	7,840	$	850	$	1,226	—	$	3,396,634	$	3,428,642
Barron	18,853		777		850		1,338		—	—		21,818
Blank	20,967		—		850		1,226		1,741	1,653,894		1,678,678
Brown	14,343		6,030		850		1,338		1,741	—		24,302
Comeau	23,427		n/a		850		1,338		—	—		25,615


(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.


(b)	Retirement-related payments with respect to Mr. Anastasio’s and Mr. Blank’s respective retirements in 2013 were composed of the following:



Name	Retirement Pay		Excess Thrift Plan Benefit Payment		SERP Benefit Payment		TOTAL
Anastasio	$	1,445,560	$	521,668	$	1,429,406	$	3,396,634
Blank	648,144		286,931		718,818		1,653,893

The “Retirement Pay” column is composed of salary and vacation for an agreed period and an actuarially calculated amount for “bridging” the retiree for purposes of the Pension Plan. The Pension Plan, the Excess Thrift Plan and the SERP are described on page 15, 25 and 26, respectively.

At the time of their retirement, in accordance with the terms of the applicable long-term incentive plan and grant agreement, each of Mr. Anastasio and Mr. Blank were fully vested in their then-outstanding NuStar Energy and NuStar GP Holdings Restricted Units, other than those granted in 2013. We have not included these amounts in the total Retirement-related Payments sum, due to the fact that the value of these units has been reported in full in the Summary Compensation table in prior years, as the Restricted Units were granted. Would we to use the market price as of December 31, 2013 at the closing (NS-$50.99; NSH- $28.09), rather than the price at of the units at the time granted, as previously reported each year, Mr. Anastasio’s value realized would be $1,894,388 and Mr. Blank’s value realized would be $652,838.

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GRANTS OF PLAN-BASED AWARDS

FOR FISCAL YEAR ENDED DECEMBER 31, 2013

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



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 ($/Unit)	Grant Date Fair Value of Unit and Unit Option Awards ($)
Anastasio	1/30/2013	(1)	1/30/2013	—	11,000	22,000	—	—	—	$	557,370	(4)
Barron	1/30/2013	(1)	1/30/2013	—	3,933	7,866	—	—	—	199,285		(4)
	12/16/2013	(2)	11/7/2013	—	—	—	4,750	—	—	237,168		(5)
	12/16/2013	(3)	11/7/2013	—	—	—	3,440	—	—	94,462		(6)
Blank	1/30/2013	(1)	1/30/2013	—	4,740	9,480	—	—	—	240,176		(4)
Brown	1/30/2013	(1)	1/30/2013	—	4,248	8,496	—	—	—	215,246		(4)
	12/16/2013	(2)	11/7/2013	—	—	—	4,750	—	—	237,168		(5)
	12/16/2013	(3)	11/7/2013	—	—	—	3,440	—	—	94,462		(6)
Comeau	1/30/2013	(1)	1/30/2013	—	5,865	11,730	—	—	—	297,180		(4)
	12/16/2013	(2)	11/7/2013	—	—	—	6,550	—	—	327,042		(5)
	12/16/2013	(3)	11/7/2013	—	—	—	4,745	—	—	130,298		(6)

Footnotes:

(1)

Performance units were awarded by the Board, upon recommendation of the Compensation Committee, on January 30, 2013. 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 Peer Group and ranked by quartile. Executives then earn 0%, 50%, 100% or 150% of that portion of the initial grant amount that is 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. For the performance period ended December 31, 2013, our performance ranked in the fourth quartile of the group, and none of the eligible units were vested.

(2)

Restricted units of NuStar Energy were approved by the Compensation Committee at a joint meeting with the Compensation Committee of NuStar GP Holdings, LLC on November 7, 2013, and the grant date for these restricted units was set at that time for the date that was as soon as administratively practicable after the meeting. The restricted units vest 1/5 annually over five years beginning on the first anniversary of the grant date.

(3)

Restricted units of NuStar GP Holdings, LLC were approved by the Compensation Committee of NuStar GP Holdings at a joint meeting with the Compensation Committee of NuStar GP, LLC on November 7, 2013, and the grant date for these restricted units was set at that time for the date that was as soon as administratively practicable after the meeting. The restricted units vest 1/5 annually over five years beginning on the first anniversary of the grant date.


(4)	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, $50.67.


(5)	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, $49.93.


(6)	The grant date fair value for restricted units was determined by multiplying the number of NuStar GP Holdings, LLC restricted units that were granted by the NYSE closing unit price of NuStar GP Holdings, LLC units on the date of grant, $27.46.

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OUTSTANDING EQUITY AWARDS

AT DECEMBER 31, 2013

The following table provides further information regarding our NEOs’ unexercised unit options, unvested restricted units and unvested performance units as of December 31, 2013. The value of NuStar Energy restricted units reported below is equal to $50.99, the NuStar Energy L.P. closing price on the NYSE on December 31, 2013. The value of the NuStar GP Holdings, LLC restricted units reported below is equal to $28.09, the NuStar GP Holdings, LLC closing price on the NYSE on December 31, 2013.



	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 ($)
Anastasio	9,625(1)	—	—	56.51	10/28/2014	—	—		—	—
	13,450(2)	—	—	57.51	10/27/2015	—	—		—	—
	56,300(3)	—	—	31.55	11/16/2014	—	—		—	—
	—	—	—	—	—	13,810(5)	$	704,172	—	—
Barron	1,975(1)	—	—	56.51	10/28/2014	—	—		—	—
	35,000(3)	—	—	31.55	11/16/2014	—	—		—	—
	—	—	—	—	—	12,011(6)	612,441		—	—
	—	—	—	—	—	8,005(7)	224,860		—	—
	—	—	—	—	—	8,564(8)	436,678		—	—
Blank	6,875(1)	—	—	56.51	10/28/2014	—	—		—	—
	7,225(2)	—	—	57.51	10/27/2015	—	—		—	—
	41,000(3)	—	—	31.55	11/16/2014	—	—		—	—
	—	—	—	—	—	6,053(9)	308,642		—	—
	1,700(4)	—	—	69.15	4/30/2014	—	—		—	—
	35,000(3)	—	—	31.55	11/16/2014	—	—		—	—
Brown	—	—	—	—	—	12,692(10)	647,165		—	—
	—	—	—	—	—	8,415(11)	236,377		—	—
	—	—	—	—	—	9,324(12)	475,431		—	—
Comeau	—	—	—	—	—	15,470(13)	788,815		—	—
	—	—	—	—	—	7,597(14)	213,400		—	—
	—	—	—	—	—	8,425(15)	429,591		—	—

Footnotes:


(1)	Options granted on October 28, 2004, which vested in 1/5 increments over five years, beginning on the first anniversary of the date of grant.


(2)	Options granted on October 27, 2005, which 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.


(3)	Options of NuStar GP Holdings granted November 16, 2007, which vested in 1/3 increments over three years, beginning on the third anniversary of the date of grant.


(4)	Options granted April 30, 2007, which vested in 1/5 increments over five years, beginning on the first anniversary of the date of grant.


(5)	Mr. Anastasio’s unvested NuStar Energy L.P. performance units were granted February 26, 2010, January 28, 2011, April 24, 2012 and January 30, 2013 and vest annually in 1/3 increments over three years beginning on the first anniversary of their grant date. The performance units are payable in NuStar Energy L.P.’s units. Upon vesting, the performance units are

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converted into a number of NuStar Energy L.P. 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 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 period ended December 31, 2011, NuStar’s TUR was in the last quartile of its Peer Group, which resulted in no vesting for participants. For the period ended December 31, 2012, NuStar’s TUR was in the last quartile of its Peer Group, which resulted in no vesting for participants. For the period ended, December 13, 2013, NuStar’s TUR was in the last quartile of its Peer Group, which resulted in no vesting for participants.

(6)

Mr. Barron’s restricted NuStar Energy L.P. units consist of: 423 restricted units granted December 14, 2009; 982 restricted units granted December 30, 2010; 1,884 restricted units granted December 16, 2011; 1,212 restricted units granted January 26, 2012; 2,760 restricted units granted December 19, 2012; and 4,750 restricted units granted December 16, 2013. 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.

(7)

Mr. Barron’s restricted NuStar GP Holdings, LLC units consist of: 399 restricted units granted December 14, 2009; 820 restricted units granted December 30, 2010; 1,434 restricted units granted December 16, 2011; 1,912 restricted units granted December 19, 2012; and 3,440 restricted units granted December 16, 2013. All of Mr. Barron’s NuStar GP Holdings, LLC restricted units vest in 1/5 increments over five years, beginning on the first anniversary of the date of grant.


(8)	Mr. Barron’s unvested NuStar Energy L.P. performance units were granted and vest in accordance with the description in Footnote (5) above. No performance units vested in 2011, 2012 or 2013.


(9)	Mr. Blank’s unvested NuStar Energy L.P. performance units were granted and vest in accordance with the description in Footnote (5) above. No performance units vested for 2011, 2012 or 2013.

(10)

Ms. Brown’s restricted NuStar Energy L.P. units consist of: 474 restricted units granted December 14, 2009; 1,100 restricted units granted December 30, 2010; 2,034 restricted units granted December 16, 2011; 1,350 restricted units granted January 26, 2012; 2,894 restricted units granted December 19, 2012; and 4,750 restricted units granted December 16, 2013. 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.

(11)

Ms. Brown’s restricted NuStar GP Holdings, LLC units consist of: 447 restricted units granted December 14, 2009; 916 restricted units granted December 30, 2010; 1,548 restricted units granted December 16, 2011; 2,064 restricted units granted December 19, 2012; and 3,440 restricted units granted December 16, 2013. All of Ms. Brown’s NuStar GP Holdings, LLC restricted units vest in 1/5 increments over five years, beginning on the first anniversary of the date of grant.


(12)	Ms. Brown’s unvested NuStar Energy L.P. performance units were granted and vest in accordance with Footnote (5) above. No performance units vested for 2011, 2012 or 2013.


(13)	Mr. Comeau’s restricted NuStar Energy L.P. units consist of: 2,400 restricted units granted March 26, 2012; 2,400 restricted units granted October 23, 2012; 4,120 restricted units granted December 19, 2012; and 6,550 restricted units granted December 16, 2013. All of Mr. Comeau’s restricted units vest in 1/5 increments over five years, beginning on the first anniversary of the date of grant.


(14)	Mr. Comeau’s NuStar GP Holdings, LLC restricted units consist of: 2,852 restricted units granted December 19, 2012 and 4,745 restricted units granted December 16, 2013. All of Mr. Comeau’s NuStar GP Holdings, LLC restricted units vest in 1/5 increments over five years, beginning on the first anniversary of the date of grant.


(15)	Mr. Comeau’s unvested NuStar Energy L.P. performance units were granted April 24, 2012 and January 30, 2013 and vest in accordance with Footnote (5) above. No performance units vested for 2012 or 2013.

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OPTION EXERCISES AND UNITS VESTED

IN YEAR ENDED DECEMBER 31, 2013

The following table provides further information regarding option exercises by our NEOs, and the vesting of restricted units and performance units held by our NEOs, during 2013.



	Option Awards		Unit Awards
Name	Number of Units Acquired on Exercise (#)	Value Realized on Exercise ($)	Number of Units Acquired on Vesting (#)	Value Realized on Vesting ($)(6)
Anastasio	—	—	50,650(1)	2,063,755
Barron	—	—	5,663(2)	225,082
Blank	—	—	21,383(3)	880,987
Brown	—	—	6,240(4)	248,049
Comeau	—	—	2,943(5)	127,824

Footnotes:

(1)

Mr. Anastasio’s NuStar Energy L.P. units vested in 2013 as follows: 1,779 units vested on January 26, 2013, 1,700 units on November 6, 2013; and, in connection with his retirement, 26,997 units vested on December 13, 2013. Mr. Anastasio's NuStar GP Holdings, LLC units vested in 2013 as follows: 1,740 units on November 6, 2013; and , in connection with his retirement, 18,434 units vested on December 13, 2013.

(2)

Mr. Barron's NuStar Energy L.P. units vested in 2013 as follows: 606 units on January 26, 2013; 520 units on November 6, 2013; 423 units on December 14, 2013; 628 units on December 16, 2013; 690 units on December 19, 2013; and 491 units on December 30, 2013. Mr. Barron's NuStar GP Holdings, LLC units vested in 2013 as follows: 540 units on November 6, 2013; 399 units on December 14, 2013; 478 units on December 16, 2013; 478 units on December 19, 2013; and 410 units on December 30, 2013.

(3)

Mr. Blank’s NuStar Energy L.P. units vested in 2013 as follows: 746 units on January 26, 2013; 660 units on November 6, 2013; 529 units on December 14, 2013; 757 units on December 16, 2013; 832 units on December 19, 2013; and, in connection with his retirement, 9,461 units on December 30, 2013. Mr. Blank's NuStar GP Holdings, LLC units vested in 2013 as follows: 680 units on November 6, 2013; 499 units on December 14, 2013; 576 units on December 16, 2016; 576 units on December 19, 2013; and, in connection with his retirement, 6,067 units on December 30, 2013.

(4)

Ms. Brown’s units vested in 2013 as follows: 675 units on January 26, 2013; 580 units on November 6, 2013; 474 units on December 14, 2013; 678 units on December 16, 2013; 746 units on December 19, 2013; and 550 units on December 30, 2013. Ms. Brown's NuStar GP Holdings, LLC units vested in 2013 as follows: 600 units on November 6, 2013; 447 units on December 14, 2013; 516 units on December 16, 2013; 516 units on December 19, 2013; and 458 units on December 30, 2013.


(5)	Mr. Comeau’s units vested in 2013 as follows: 600 units on March 26, 2013; 600 units on October 23, 2013; and 1,030 units on December 19, 2013. Mr. Comeau's NuStar GP Holdings, LLC units vested in 2013 as follows: 713 units on December 19, 2013.

(6)

The value realized on vesting was calculated by multiplying the closing price of NuStar Energy L.P. units on the NYSE on the date of vesting by the number of NuStar Energy L.P. units vested or the closing price of NuStar GP Holdings, LLC units on the NYSE on the date of vesting by the number of NuStar GP Holdings, LLC units vested, as applicable. The closing prices of the applicable dates are as follows:

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2013 Vesting Date
NS Closing Price
January 26	$50.00
March 26	53.45
October 23	43.97
November 6	42.72
December 13	49.94
December 14	49.94
December 16	49.93
December 19	49.00
December 30	50.65
NSH Closing Price
November 6	$24.16
December 13	27.77
December 14	27.77
December 16	27.46
December 19	26.51
December 30	28.01

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POST-EMPLOYMENT COMPENSATION

PENSION BENEFITS

FOR YEAR ENDED DECEMBER 31, 2013

The following table provides information regarding the accumulated benefits of our named executive officer under NuStar GP, LLC’s pension plans during the year ended December 31, 2013.



Name	Plan Name	Number of Years Credited Service	Present Value of Accumulated Benefit($)(1)	Payments During Last Fiscal Year
Anastasio	NuStar GP, LLC Pension Plan	7.5	279,189	—
	NuStar GP, LLC Excess Pension Plan	—	—	—
	NuStar GP, LLC Supplemental Executive Retirement Plan	12.0	668,947	—
Barron	NuStar GP, LLC Pension Plan	7.5	175,060	—
	NuStar GP, LLC Excess Pension Plan	13.0	203,429	—
	NuStar GP, LLC Supplemental Executive Retirement Plan	—	—	—
Blank	NuStar GP, LLC Pension Plan	7.5	297,330	—
	NuStar GP, LLC Excess Pension Plan	—	—	—
	NuStar GP, LLC Supplemental Executive Retirement Plan	12.0	353,392	—
Brown	NuStar GP, LLC Pension Plan	6.7	247,772	—
	Excess Pension Plan	6.7	207,073	—
	Supplemental Executive Retirement Plan	—	—	—
Comeau	NuStar GP, LLC Pension Plan	—	284,480	—
	Excess Pension Plan	—	—	—
	Supplemental Executive Retirement Plan	—	—	—

Footnotes:

(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, 2013 were determined using a 5.04% discount rate and the plans’ earliest unreduced retirement age (i.e., age 62). The present values reflect post-retirement mortality rates based on the 2014 Static Mortality Table for Annuitants and Non-Annuitants per IR Reg. 1.430(h)(3)-1(e). No decrements were included for pre-retirement termination, mortality, or disability. Where applicable, lump sums were determined based on a 4.54% 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.

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 and a non-qualified supplemental executive retirement plan, or SERP, which provide supplemental pension benefits to certain highly compensated employees. The excess pension plan and the SERP provide 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. Employees who are eligible for the excess pension plans and the SERP may participate in one or the other, but not both 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 defined benefit final average pay formula (FAP) based on years of service and compensation during their period of service, and employees become fully vested in their benefits upon attaining five years of service. Employees hired on or after January 1, 2011 are covered 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. 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.

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NuStar GP, LLC Excess Pension Plan

The Excess Pension Plan, which became effective June 26, 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 (i) 1.6% of the employee’s average monthly compensation multiplied by the employee’s years of service less (ii) the employee’s Pension Plan benefit. Mr. Barron, Ms. Brown and Mr. Comeau participated in the Excess Pension Plan in 2013.

NuStar GP, LLC Supplemental Executive Retirement Plan

The SERP, which became effective July 1, 2006, was intended to provide certain highly compensated, management personnel with a supplement to their Pension Plan retirement benefit. The SERP, which was not either a qualified plan under the Code or a funded plan subject to ERISA. Mr. Anastasio and Mr. Blank were the only two employees who participated in the Valero Energy Supplemental Executive Retirement Plan (the Prior SERP) prior to our separation from Valero Energy, and as of July 1, 2006, the SERP assumed the liabilities of the Prior SERP to cover those individuals.

Under the SERP, the monthly pension is calculated as:


(i)	1.6% of the employee’s average monthly compensation multiplied by the employee’s years of service; plus


(ii)	0.35% of the product of the employee’s years of service and the amount that the employee’s average monthly compensation exceeds the lesser of:

a.1.25 multiplied by the employee’s monthly covered compensation and

b.the monthly FICA amount; minus


(iii)	the employee’s Pension Plan benefit.

With Mr. Anastasio’s and Mr. Blank’s respective retirement, both effective December 31, 2013, there are no more participants in the SERP. The SERP will terminate upon the final payment of benefits from the plan in May 2014.

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NONQUALIFIED DEFERRED COMPENSATION

FOR YEAR ENDED DECEMBER 31, 2013

The following table provides additional information regarding contributions by NuStar GP, LLC and each of our NEOs under our non-qualified defined contribution and other deferred compensation plans during the year ended December 31, 2013. The table also presents each named executive officer’s withdrawals, earnings and year-end balances in such plans. Please see the descriptions of our Excess Thrift Plan and the Frozen Nonqualified 401(k) Plan above in “Compensation Discussion and Analysis- Post-Employment Benefits.”



Name	Executive Contributions in 2013 ($)(1)	Registrant Contributions in 2013 ($)(2)	Aggregate Earnings in 2013 ($)(3)	Aggregate Withdrawals/ Distributions ($)(4)	Aggregate Balance at December 31, 2013 ($)(5)
Anastasio	—	7,840	137,369	—	661,644
Barron	—	777	7,146	—	27,336
Blank	—	—	265,178	—	1,495,131
Brown	—	6,330	14,399	—	38,598
Comeau	—	—	—	—	—

Footnotes:


(1)	The NEOs made no contributions to these plans in 2013.


(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 2013 in the Summary Compensation Table.


(3)	Amounts include the earnings (excluding dividends, if any), if any, of the executives’ respective account in (as applicable) our Excess Thrift Plan and our Frozen Nonqualified 401(k) Plan.


(4)	Mr. Anastatio and Mr. Blank each received a distribution in mid-January 2014 in connection with retirement in 2013, which were $521,668 and $286,931, respectively.


(5)	Amounts include the aggregate balance, at year end, if any, of the NEO’s respective account in (as applicable) our Excess Thrift Plan and our Frozen Nonqualified 401(k) Plan.

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POTENTIAL PAYMENTS UPON TERMINATION OR CHANGE OF CONTROL

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. 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. The executives are also 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. 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 the company. “Good reason” is defined to mean, generally:


•	a diminution in the executive’s position, authority, duties and responsibilities,


•	failure of the successor of NuStar to assume and perform under the agreement, and


•	relocation of the executive or increased travel requirements.

SEC regulations require us to disclose potential payments to an executive in connection with his or her termination or a change of control of NuStar. We have elected to use the following table to make the required disclosures. Except as noted, values assume that a change of control occurred on December 31, 2013, and that the executive’s employment was terminated on that date.

Under the change of control agreements, if an executive officer’s employment is terminated for “cause,” the officer will not receive any benefits or compensation other than any accrued salary or vacation pay that remained unpaid through the date of termination, and, therefore, there is no presentation of termination for “cause” below.

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PAYMENTS UNDER CHANGE OF CONTROL SEVERANCE AGREEMENTS



Executive Benefits and Payments	Termination of Employment by the Company Other Than for “Cause” 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)
Anastasio	$	1,659,000	$	—	$	—	$	—
Barron	689,140		—		—		—
Blank	769,220		—		—		—
Brown	689,140		—		—		—
Comeau	791,840		—		—		—
Bonus (1)
Anastasio	$	1,360,800	$	453,600	$	453,600	$	—
Barron	348,600		174,300		174,300		—
Blank	427,600		213,800		213,800		—
Brown	383,200		191,600		191,600		—
Comeau	200,000		200,000		200,000		—
Pension, Excess Pension, and SERP Benefits
Anastasio	$	1,429,406	$	—	$	—	$	—
Barron	105,151		—		—		—
Blank	718,818		—		—		—
Brown	148,277		—		—		—
Comeau	48,122		—		—		—
Contributions under Defined Contribution Plans
Anastasio	$	89,796	$	—	$	—	$	—
Barron	39,260		—		—		—
Blank	41,934		—		—		—
Brown	40,746		—		—		—
Comeau	46,854		—		—		—
Health and Welfare Plan Benefits	(6)
Anastasio	$	72,813	$	—	$	—	$	—
Barron	37,706		—		—		—
Blank	48,498		—		—		—
Brown	36,436		—		—		—
Comeau	26,084		—		—		—

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Executive Benefits and Payments	Termination of Employment by the Company Other Than for “Cause” 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 (7)
Anastasio	—		—		—		—
Barron	—		—		—		—
Blank	—		—		—		—
Brown	—		—		—		—
Comeau	—		—		—		—
Accelerated Vesting of Restricted
Units (8)
Anastasio	$	1,894,388	$	1,894,388	$	1,894,388	$	1,894,388
Barron	837,301		837,301		837,301		837,301
Blank	652,838		652,838		652,838		652,838
Brown	883,542		883,542		883,542		883,542
Comeau	1,002,215		1,002,215		1,002,215		1,002,215
Accelerated Vesting of Performance Units (9)
Anastasio	$	1,408,344	$	1,408,344	$	1,408,344	$	1,408,344
Barron	873,356		873,356		873,356		873,356
Blank	617,284		617,284		617,284		617,284
Brown	950,862		950,862		950,862		950,862
Comeau	858,982		858,982		858,982		858,982
280G Tax Gross-Up (10)
Anastasio	$	—	$	—	$	—	$	—
Barron	923,611		—		—		—
Blank	—		—		—		—
Brown	1,005,288		—		—		—
Comeau	1,054,041		—		—		—
Totals
Anastasio	$	7,918,447	$	3,756,332	$	3,756,332	$	3,302,732
Barron	3,782,802		1,884,957		1,884,957		1,710,657
Blank	3,253,792		1,483,922		1,483,922		1,270,122
Brown	4,117,935		2,026,004		2,026,004		1,834,404
Comeau	4,013,112		1,961,197		1,961,197		1,861,197

Footnotes:

(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, 2013. The listed bonus amount represents the highest bonus earned by the executive in any of the fiscal years 2011, 2012 and 2013 (the three years prior to the assumed change of control):



Name	Annual Salary		Bonus
Anastasio	$	553,000	$	453,600
Barron	344,570		174,300
Blank	384,610		213,800
Brown	344,570		191,600
Comeau	395,920		100,000


(2)	The change of control 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:

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(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 (three times for Mr. Anastasio) annual base salary plus the executive officer’s highest annual bonus from the past three years,


(iii)	the amount of the actuarial present value of the pension benefits (qualified and nonqualified) the executive would have received for an additional two years of service (three years for Mr. Anastasio), and (iv) the equivalent of two years (three years for Mr. Anastasio) of employer contributions under NuStar GP, LLC’s tax-qualified and supplemental defined contribution plans; and

(B) continued welfare benefits for two years (three years for Mr. Anastasio).

(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; thus 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.

(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; thus a full year’s bonus is shown in the table.


(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.


(6)	The executive is entitled to coverage under the welfare benefit plans (e.g., health, dental, etc.) for two years following the date of termination (three years for Mr. Anastasio).

(7)

The amounts stated in the table represent the gross value of previously unvested unit options derived by multiplying (x) the difference between (as applicable) $50.99 (the closing price of NuStar Energy L.P.’s units on the NYSE on December 31, 2013) or $28.09 (the closing price of NuStar GP Holdings, LLC’s units on the NYSE on December 31, 2013), and the options’ exercise prices, times (y) the number of unvested unit options.

(8)

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) $50.99 (the closing price of NuStar Energy L.P.’s units on the NYSE on December 31, 2013) or $28.09 (the closing price of NuStar GP Holdings, LLC’s units on the NYSE on December 31, 2013).


(9)	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 200%, times (y) $50.99 (the closing price of NuStar Energy L.P.’s units on the NYSE on December 31, 2013).


(10)	If any payment or benefit is determined to be subject to an excise tax under Section 4999 of the Code, the executive is entitled to receive an additional payment to adjust for the incremental tax cost of the payment or benefit.

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COMPENSATION OF DIRECTORS

DIRECTOR COMPENSATION (2013)

The following table provides a summary of compensation paid for the year ended December 31, 2013, 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 and Principal Position	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	111,750	94,967	—	—	n/a	—	206,717
Curtis V. Anastasio	(2)	(2)	(2)	(2)	(2)	(2)	(2)
J. Dan Bates	85,750	69,952	—	—	n/a	—	155,702
Dan J. Hill	87,250	69,952	—	—	n/a	—	157,202
Rodman D. Patton	85,750	69,952	—	—	n/a	—	155,702
W. Grady Rosier	58,435	139,908	—	—	n/a	—	198,343


(1)	In addition to the fees paid according to the non-employee director compensation described below, 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. Anastasio 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 grant of restricted NuStar Energy L.P. units for the fiscal year ended December 31, 2013. Please see “Compensation Discussion and Analysis- Impact of Accounting and Tax Treatment- Accounting Treatment” above in this item for more information.

As of December 31, 2013, each director holds the following aggregate number of restricted unit and option awards:



Name	Aggregate # of Restricted Units	Aggregate # of Unit Options
Greehey	3,853	—
Anastasio	*	*
Bates	2,839	—
Hill	2,839	—
Patton	2,839	—
Rosier	2,799	—

* Mr. Anastasio’s aggregate holdings are disclosed above in the Outstanding Equity Awards at December 31, 2013.

Non-employee directors receive a retainer fee of $55,000 per year, plus $1,250 for each Board and committee meeting attended in person and $500 for each Board and committee meeting attended telephonically. Directors who serve as chairperson of a committee receive an additional $10,000 annually. Each director is also reimbursed for expenses of meeting attendance. Directors who are employees of NuStar GP, LLC receive no compensation (other than reimbursement of expenses) for serving as directors. The Chairman of the Board receives an additional retainer fee of $50,000 per year. The Chairman of the Board receives no fees for attending committee meetings.

NuStar GP, LLC supplements the compensation paid to non-employee directors other than the Chairman of the Board with an annual grant of restricted NuStar Energy L.P. units valued at $70,000 that vests in equal annual installments over a three-year period. The Chairman of the Board receives an annual grant of restricted NuStar Energy L.P. units valued at $95,000 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 L.P.’s unitholders through ownership of NuStar Energy L.P. 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 L.P. units.

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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. Rosier and Mr. Patton, none of whom is a current or former employee or officer of NuStar GP, LLC and each of whom have been determined by the Board to be “independent,” as described below in Item 13. The Compensation Committee met five times in 2013.

Compensation Committee Interlocks and Insider Participation

There are no compensation committee interlocks. None of Mr. Hill, Mr. Bates, Mr. Rosier or Mr. Patton has 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 and no Board member is 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

DIRECTORS AND EXECUTIVE OFFICERS

The following table sets forth ownership of NuStar Energy L.P. units and NuStar GP Holdings, LLC units on December 31, 2013 by the directors and executive officers of NuStar GP, LLC as of January 1, 2014. 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)	Units Beneficially Owned (2)	Units under Exercisable Options (3)	Percentage of Outstanding Units (4)		NuStar GP Holdings, LLC Units Beneficially Owned	NuStar GP Holdings, LLC Units under Exercisable Options	Percentage of Outstanding Units (5)
William E. Greehey	2,329,579	—	2.99	%	8,068,198	—	18.90	%
Bradley C. Barron	22,690	1,975	*		17,604	35,000	*
J. Dan Bates	21,086	—	*		2,000	—	*
Dan J. Hill	18,678	—	*		10,000	—	*
Rodman D. Patton	26,133	—	*		15,000	—	*
W. Grady Rosier	16,799	—	*		—	—	*
Mary Rose Brown	43,367	1,700	*		64,350	35,000	*
Douglas W. Comeau	19,927	—	*		9,283	—	*
Thomas R. Shoaf	14,226	2,825	*		—	25,700	*
Amy L. Perry (6)	5,434	—	*		—	—	*
Karen M. Thompson	9,725	1,000	*		—	—	*
Jorge A. del Alamo	9,127	—	*		10,954	—	*
All directors and officers as a group (12)	2,535,275	7,500	3.26	%	8,179,537	95,700	19.39	%

* 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 units issued under NuStar Energy’s long-term incentive plans. Restricted units granted under NuStar GP, LLC’s long-term incentive plans are rights to receive NuStar Energy L.P. 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, 2013 through the exercise of unit options.


(4)	As of December 31, 2013, 77,886,078 NuStar Energy L.P. 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 units includes units listed under the captions “Units Beneficially Owned” and “Units under Exercisable Options.”

(5)

As of December 31, 2013, 42,656,281 NuStar GP Holdings, LLC’s units were issued and outstanding. There are no classes of equity securities of NuStar GP Holdings, LLC outstanding other than the units. The calculation for Percentage of Outstanding Units includes units listed under the captions “NuStar GP Holdings, LLC Units Beneficially Owned” and “NuStar GP Holdings, LLC Units under Exercisable Options.”

(6)

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 the NuStar Energy L.P. units she would receive in the future upon vesting of her restricted units, which were granted to her prior to September 2012, in 2007 through 2011, and remained outstanding at the time of the divorce (as described in detail in the applicable document, the “Pre-decree Restricted Units”). The obligation will continue until the last of the Pre-decree Restricted Units, 1/5 of the 2011 grant, vests in 2016.

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Except as otherwise indicated, the following table sets forth certain information as of December 31, 2013 with respect to each entity known to us to be the beneficial owner of more than 5% of our outstanding units.



Name and Address of Beneficial Owner	Units	Percentage of Units (2)
NuStar GP Holdings (1) 19003 IH-10 West San Antonio, Texas 78257	10,228,945	13.1%


(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.


(2)	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, which are described in further detail in Note 20 of 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(1)	Weighted-average exercise price of outstanding unit options, warrants and rights		Number of securities remaining for future issuance under equity compensation plans
Equity Compensation Plans approved by security holders	1,659,302	$	53.05	1,517,027
Equity Compensation Plans not approved by security holders	363,393	48.17		—

(1)

Grants under NuStar GP, LLC’s long-term incentive plans do not dilute the interests of NuStar Energy L.P. unitholders. Upon the vest of a restricted unit or the exercise of a unit option granted under NuStar GP, LLC’s plan, NuStar GP, LLC purchases a NuStar Energy L.P. unit to satisfy that vest or exercise on the open market. No new NuStar Energy L.P. units are issued to satisfy vesting restricted units or exercises of unit options.

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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: (i) any vice president, Section 16 officer or director, (ii) any 5% or greater unitholder of NuStar Energy, its controlled affiliates or NuStar GP Holdings, (iii) any immediate family member of any officer or director, or (iv) any entity controlled by any of (i), (ii) or (iii) (or in which any of (i), (ii) or (iii) 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 “Executive Compensation, Potential Payments upon Termination or Change in Control” for a discussion of NuStar Energy’s Change of Control 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 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 has an initial term of two years, after which the Time Share Agreement will automatically renew 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 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 2013, the Holdco Services Expense was equal to $1.4 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 2013, Mr. J. Greehey did not attend any Board or Committee meetings. The aggregate value of compensation paid by NuStar to Mr. J. Greehey in 2013 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 Clerk. In 2013, Mr. Brown did not attend any Board or Committee meetings. The aggregate value of compensation paid by NuStar to Mr. Brown in 2013 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, 2013, 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


•	10,228,945 NuStar Energy L.P. units representing 13.1% of the issued and outstanding NuStar Energy common units.

Certain of our officers are also officers of NuStar GP Holdings. Our Chairman, Mr. Greehey, is also the Chairman of Board and owns 18.9% 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. During 2013, the Board held eight meetings. No member of the Board attended less than 75% of the meetings of the Board and committees of which he was a member.

In 2013, the Board had standing Audit, Compensation and Nominating/Governance & Conflicts Committees. Each committee has a written charter. The committees of the Board and the number of meetings held by the committees in 2013 are described below.

Independent Directors

The Board has one member of management, Mr. Barron, President and CEO, and five non-management directors. Mr. Anastasio, our former President and CEO, was a director until his retirement, effective December 31, 2013. 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. As a limited partnership, NuStar Energy is not required to have a majority of independent directors. 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 owns 18.9% 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 and Compensation 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 and/or unitholder of NuStar Energy, each of the independent directors named above has either no relationship with NuStar Energy, either directly or as a partner, unitholder 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 GP, LLC 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 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 GP, LLC 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, and it is not otherwise, disclosed in this annual report on Form 10-K.

NuStar GP, LLC’s Corporate Governance Guidelines contain the director qualification standards, including the guidelines listed above, and are available on NuStar Energy’s internet website at http://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.

Presiding Director/Meetings of Non-Management Directors

The Board has designated Mr. Patton 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.

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, the Audit Committee Charter and other governance documents on NuStar Energy’s internet website at http://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.

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ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

KPMG FEES FOR FISCAL YEAR 2013

Audit Fees

The aggregate fees for fiscal year 2013 for professional services rendered by KPMG for the audit of the annual financial statements for the year ended December 31, 2013 included in this Form 10-K, review of NuStar Energy’s interim financial statements included in NuStar Energy’s 2013 Forms 10-Q, the audit of the effectiveness of NuStar Energy’s internal control over financial reporting as of December 31, 2013 and related services that are normally provided by the principal auditor (e.g., comfort letters and assistance with review of documents filed with the SEC) were $2,433,000.

Audit-related Fees

The aggregate fees for the fiscal year 2013 for assurance and related services rendered by KPMG that are reasonably related to the performance of the audit or review of NuStar Energy’s financial statements and not reported in the preceding caption were $186,000.

Tax Fees

The aggregate fees for the fiscal year 2013 for professional services rendered by KPMG for tax compliance, tax advice and tax planning were $22,612.

All Other Fees

The aggregate fees for the fiscal year 2013 for services rendered by KPMG, other than the services reported under the preceding captions, were $0.

KPMG FEES FOR FISCAL YEAR 2012

Audit Fees

The aggregate fees for fiscal year 2012 for professional services rendered by KPMG for the audit of the annual financial statements for the year ended December 31, 2012 included in this Form 10-K, review of NuStar Energy’s interim financial statements included in NuStar Energy’s 2012 Forms 10-Q, the audit of the effectiveness of NuStar Energy’s internal control over financial reporting as of December 31, 2012 and related services that are normally provided by the principal auditor (e.g., comfort letters and assistance with review of documents filed with the SEC) were $2,509,000.

Audit-related Fees

The aggregate fees for the fiscal year 2012 for assurance and related services rendered by KPMG that are reasonably related to the performance of the audit or review of NuStar Energy’s financial statements and not reported in the preceding caption were $98,000.

Tax Fees

The aggregate fees for the fiscal year 2012 for professional services rendered by KPMG for tax compliance, tax advice and tax planning were $0.

All Other Fees

The aggregate fees for the fiscal year 2012 for services rendered by KPMG, other than the services reported under the preceding captions, were $0.

AUDIT COMMITTEE PRE-APPROVAL POLICY

The audit committee has adopted a pre-approval policy to address the approval of services rendered to NuStar Energy by its independent auditors, which is filed herewith as Exhibit 99.01.

None of the services (described above) for 2012 or 2013 provided by KPMG were approved by the audit committee pursuant to 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, 2013 and 2012 Consolidated Statements of Income for the Years Ended December 31, 2013, 2012 and 2011 Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2013, 2012 and 2011 Consolidated Statements of Cash Flows for the Years Ended December 31, 2013, 2012 and 2011 Consolidated Statements of Partners’ Equity for the Years Ended December 31, 2013, 2012 and 2011 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

2.01	Agreement and Plan of Merger, dated as of October 31, 2004, by and among Valero L.P., Riverwalk Logistics, L.P., Valero GP, LLC, VLI Sub A LLC and Kaneb Services LLC	NuStar Energy L.P.’s Current Report on Form 8-K filed November 4, 2004 (File No. 001-16417), Exhibit 99.1

2.02	Agreement and Plan of Merger, dated as of October 31, 2004, by and among Valero L.P., Riverwalk Logistics, L.P., Valero GP, LLC, VLI Sub B LLC and Kaneb Pipe Line Partners, L.P. and Kaneb Pipe Line Company LLC	NuStar Energy L.P.’s Current Report on Form 8-K filed November 4, 2004 (File No. 001-16417), Exhibit 99.2

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 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	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

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Exhibit Number	Description	Incorporated by Reference to the Following Document

3.09	Second Amended and Restated Agreement of Limited Partnership of Shamrock Logistics Operations, L.P., dated as of April 16, 2001	NuStar Energy L.P.’s Annual Report on Form 10-K for year ended December 31, 2001 (File No. 001-16417), Exhibit 3.9

3.10	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

3.11	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

3.12	Certificate of Limited Partnership of Riverwalk Logistics, L.P., dated 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

3.13	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 the year ended December 31, 2001 (File No. 001-16417), Exhibit 3.16

3.14	Certificate of Formation of Shamrock Logistics GP, LLC, dated 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

3.15	Certificate of Amendment to Certificate of Formation of Shamrock Logistics GP, LLC, dated 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

3.16	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

3.17	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

3.18	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

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

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Exhibit Number	Description	Incorporated by Reference to the Following Document

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

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 February 21, 2002, between Kaneb Pipe Line Operating Partnership, L.P. and JPMorgan Chase Bank (Senior Debt Securities)	NuStar Energy L.P.’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2005 (File No. 001-16417), Exhibit 4.03

4.11	First Supplemental Indenture, dated as of February 21, 2002, to Indenture dated as of February 21, 2002, between Kaneb Pipe Line Operating Partnership, L.P. and JPMorgan Chase Bank (including form of 7.750% Senior Unsecured Notes due 2012)	NuStar Energy L.P.’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2005 (File No. 001-16417), Exhibit 4.04

4.12	Second Supplemental Indenture, dated as of August 9, 2002 and effective as of April 4, 2002, to Indenture dated as of February 21, 2002, as amended and supplemented, between Kaneb Pipe Line Operating Partnership, L.P., Statia Terminals Canada Partnership, and JPMorgan Chase Bank	NuStar Energy L.P.’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2005 (File No. 001-16417), Exhibit 4.05

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Exhibit Number	Description	Incorporated by Reference to the Following Document

4.13	Third Supplemental Indenture, dated and effective as of May 16, 2003, to Indenture dated as of February 21, 2002, as amended and supplemented, between Kaneb Pipe Line Operating Partnership, L.P., Statia Terminals Canada Partnership, and JPMorgan Chase Bank	NuStar Energy L.P.’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2005 (File No. 001-16417), Exhibit 4.06

4.14	Fourth Supplemental Indenture, dated and effective as of May 27, 2003, to Indenture dated as of February 21, 2002, as amended and supplemented, between Kaneb Pipe Line Operating Partnership, L.P. and JPMorgan Chase Bank (including form of 5.875% Senior Unsecured Notes due 2013)	NuStar Energy L.P.’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2005 (File No. 001-16417), Exhibit 4.07

4.15	Fifth Supplemental Indenture, dated and effective as of July 1, 2005, to Indenture dated as of February 21, 2002, as amended and supplemented, among Kaneb Pipe Line Operating Partnership, L.P., Valero L.P., Valero Logistics Operations, L.P., and JPMorgan Chase Bank	NuStar Energy L.P.’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2005 (File No. 001-16417), Exhibit 4.08

4.16	Instrument of Resignation, Appointment and Acceptance, dated June 30, 2008, among NuStar Pipeline Operating Partnership L.P., NuStar Energy L.P., NuStar Logistics, 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 4.12

4.17	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

4.18	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

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

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Exhibit Number	Description	Incorporated by Reference to the Following Document

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 Hereto	*

+10.06	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

+10.07	Form of Unit Option Agreement under the Valero 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

+10.08	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

+10.09	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

+10.10	NuStar GP, LLC Fourth Amended and Restated 2000 Long-Term Incentive Plan, amended and restated as of January 1, 2014	*

+10.11	Form of 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 November 10, 2008 (File No. 001-16417), Exhibit 10.03

+10.12	Form of Unit Option Award Agreement under the Valero 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

+10.13	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

+10.14	Form of 2011 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

+10.15	Form of 2013 Restricted Unit Award Agreement under the NuStar GP, LLC Third Amended and Restated 2000 Long-Term Incentive Plan	*

+10.16	Form of Amended and Restated Performance Unit 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 December 8, 2009 (File No. 001-16417), Exhibit 10.02

+10.17	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	NuStar Energy L.P.’s Current Report on Form 8-K filed February 2, 2010 (File No. 001-16417), Exhibit 10.03

+10.18	Form of Performance Unit Agreement under the Second Amended and Restated 2000 Long-Term Incentive Plan	NuStar Energy L.P.’s Annual Report on Form 10-K for year ended December 31, 2009 (File No. 001-16417), Exhibit 10.11

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Exhibit Number	Description	Incorporated by Reference to the Following Document

+10.19	Form of Waiver Related to Certain Performance Units 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 10.3

+10.20	Form of Non-employee Director Restricted Unit 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 10.02

+10.21	Form of Non-employee Director Restricted Unit Agreement under the NuStar GP, LLC Third Amended and Restated 2000 Long-Term Incentive Plan	*

+10.22	Valero 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

+10.23	Change of Control Severance Agreement by and among Valero GP, LLC, Valero L.P. and Curtis V. Anastasio, dated November 6, 2006.	NuStar Energy L.P.’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2006 (File No. 001-16417), Exhibit 10.05

+10.24	Form of Change of Control Severance Agreement by and among Valero LP, Valero GP, LLC and each of the other executive officers of Valero GP, LLC, dated as of November 6, 2006	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

10.25	Non-Compete Agreement between Valero GP Holdings, LLC, Valero L.P., Riverwalk Logistics, L.P. and Valero GP, LLC, effective as of July 19, 2006	NuStar Energy L.P.’s Quarterly Report on Form 10-Q for quarter ended September 30, 2006 (File No. 001-16417), Exhibit 10.03

10.26	Services Agreement, effective 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

+10.27	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

+10.28	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

+10.29	NuStar Supplemental Executive Retirement 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 10.31

+10.30	Shamrock Logistics GP, LLC Year 2001 Annual Incentive Plan	NuStar Energy L.P.’s Amendment No. 5 to Registration Statement on Form S-1 filed March 29, 2001 (File No. 333-43668), Exhibit 10.4

+10.31	Shamrock Logistics GP, LLC Intermediate Incentive Compensation Plan	NuStar Energy L.P.’s Amendment No. 5 to Registration Statement on Form S-1 filed March 29, 2001 (File No. 333-43668), Exhibit 10.9

10.32	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

10.33	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

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Exhibit Number	Description	Incorporated by Reference to the Following Document

10.34	Amendment to Crude Oil Sales Agreement between PDVSA-Petróleo S.A., NuStar Logistics, L.P. and NuStar Marketing, 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

10.35	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

10.36	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

10.37	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

10.38	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

10.39	Application for Letter of Credit and Reimbursement Agreement between JPMorgan Chase Bank, N.A. and NuStar Logistics, L.P. dated as of December 29, 2010	NuStar Energy L.P.’s Current Report on Form 8-K filed December 30, 2010 (File No. 001-16417), Exhibit 10.02

10.40	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

10.41	Application for Letter of Credit and Reimbursement Agreement between JPMorgan Chase Bank, N.A. and NuStar Logistics, L.P. dated as of August 9, 2011	NuStar Energy L.P.’s Current Report on Form 8-K filed August 10, 2011 (File No. 001-16417), Exhibit 10.02

10.42	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

10.43	Equity Distribution Agreement, dated May 23, 2011 by and among NuStar Energy L.P., Riverwalk Logistics, L.P., NuStar GP, LLC, and Citigroup Global Markets Inc.	NuStar Energy L.P.’s Current Report on Form 8-K filed May 23, 2011 (File No. 001-16417), Exhibit 1.1

10.44	Purchase and Sale Agreement by and among NuStar Energy L.P., NuStar Logistics, L.P., NuStar Asphalt Refining, LLC, NuStar Marketing 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

10.45	Letter Agreement by and among Asphalt Acquisition LLC, NuStar Energy L.P., NuStar Logistics, L.P., NuStar Asphalt Refining, LLC, NuStar Marketing 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

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Exhibit Number	Description	Incorporated by Reference to the Following Document

10.46	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

10.47	Amended and Restated Transaction Agreement by and between LG Asphalt L.P. and NuStar Logistics, L.P. dated as of December 20, 2013	*

10.48	Amendment No. 1 to Amended and Restated Transaction Agreement dated as of January 29, 2014	*

10.49	Amendment No. 2 to Amended and Restated Transaction Agreement dated as of February 26, 2014	*

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 March 3, 2014 (NuStar Energy L.P.)	*

23.02	Consent of KPMG LLP dated February 28, 2014 (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	*

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	*

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	*

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Exhibit Number	Description	Incorporated by Reference to the Following Document

101.LAB	XBRL Taxonomy Extension Label Linkbase Document	*

101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document	*



*	Filed 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
	March 3, 2014

By:	/s/ Thomas R. Shoaf
	Thomas R. Shoaf
	Executive Vice President and Chief Financial Officer
	March 3, 2014

By:	/s/ Jorge A. del Alamo
	Jorge A. del Alamo
	Vice President and Controller
	March 3, 2014

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POWER OF ATTORNEY

KNOW ALL MEN BY THESE PRESENTS, that each person whose signature appears below hereby constitutes and appoints Bradley C. Barron, Thomas R. Shoaf and Amy L. Perry, or any of them, each with power to act without the other, his true and lawful attorney-in-fact and agent, with full power of substitution and resubstitution, for him and in his name, place and stead, in any and all capacities, to sign any or all subsequent amendments and supplements to this Annual Report on Form 10-K, and to file the same, or cause to be filed the same, with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission, granting unto each said attorney-in-fact and agent full power to do and perform each and every act and thing requisite and necessary to be done in and about the premises, as fully to all intents and purposes as he might or could do in person, hereby qualifying and confirming all that said attorney-in-fact and agent or his substitute or substitutes may lawfully do or cause to be done by virtue hereof.

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.



Signature	Title	Date

/s/ William E. Greehey	Chairman of the Board	March 3, 2014
William E. Greehey

/s/ Bradley C. Barron	President, Chief Executive	March 3, 2014
Bradley C. Barron	Officer and Director (Principal Executive Officer)

/s/ Thomas R. Shoaf	Executive Vice President	March 3, 2014
Thomas R. Shoaf	and Chief Financial Officer (Principal Financial Officer)

/s/ Jorge A. del Alamo	Vice President and Controller	March 3, 2014
Jorge A. del Alamo	(Principal Accounting Officer)

/s/ J. Dan Bates	Director	March 3, 2014
J. Dan Bates

/s/ Dan J. Hill	Director	March 3, 2014
Dan J. Hill

/s/ Rodman D. Patton	Director	March 3, 2014
Rodman D. Patton

/s/ W. Grady Rosier	Director	March 3, 2014
W. Grady Rosier

170