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EX-23.01 - EXHIBIT 23.01 - NuStar Energy L.P.ns2015ex2301.htm
EX-31.02 - EXHIBIT 31.02 - NuStar Energy L.P.ns2015ex3102.htm
EX-99.03 - EXHIBIT 99.03 - NuStar Energy L.P.ns2015ex9903.htm
EX-99.01 - EXHIBIT 99.01 - NuStar Energy L.P.ns2015ex9901.htm
EX-10.26 - EXHIBIT 10.26 - NuStar Energy L.P.ns2015ex1026.htm
EX-12.01 - EXHIBIT 12.01 - NuStar Energy L.P.ns2015ex1201.htm
EX-99.02 - EXHIBIT 99.02 - NuStar Energy L.P.ns2015ex9902.htm
EX-21.01 - EXHIBIT 21.01 - NuStar Energy L.P.ns2015ex2101.htm
EX-10.45 - EXHIBIT 10.45 - NuStar Energy L.P.ns2015ex1045.htm
EX-32.02 - EXHIBIT 32.02 - NuStar Energy L.P.ns2015ex3202.htm
EX-23.02 - EXHIBIT 23.02 - NuStar Energy L.P.ns2015ex2302.htm
EX-32.01 - EXHIBIT 32.01 - NuStar Energy L.P.ns2015ex3201.htm
EX-31.01 - EXHIBIT 31.01 - NuStar Energy L.P.ns2015ex3101.htm

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, 2015
OR
[    ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from                                          to                                         
Commission File Number 1-16417
NUSTAR ENERGY L.P.
(Exact name of registrant as specified in its charter)
Delaware
 
74-2956831
(State or other jurisdiction of
incorporation or organization)
 
(I.R.S. Employer
Identification No.)
 
 
 
19003 IH-10 West
 
78257
San Antonio, Texas
 
(Zip Code)
(Address of principal executive offices)
 
 
Registrant’s telephone number, including area code (210) 918-2000
Securities registered pursuant to Section 12(b) of the Act: Common units representing partnership interests listed on the New York Stock Exchange.
Securities registered pursuant to 12(g) of the Act: None.
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes [X] No [  ]
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.
Yes [  ] No [X]
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes [X] No [  ]
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes [X] No [ ]
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [ ]
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule12b-2 of the Exchange Act: 
Large accelerated filer
 
[X]
  
Accelerated filer [    ]
 
 
 
 
Non-accelerated filer
 
[    ]  (Do not check if a smaller reporting company)
  
Smaller reporting company
 
[    ]
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 $3,838 million based on the last sales price quoted as of June 30, 2015, the last business day of the registrant’s most recently completed second quarter.
The number of common units outstanding as of January 31, 2016 was 77,886,078.



NUSTAR ENERGY L.P.
FORM 10-K

TABLE OF CONTENTS
 
PART I
Items 1., 1A. & 2.
 
 
 
 
 
 
 
 
 
 
 
 
Item 1B.
 
 
 
Item 3.
 
 
 
Item 4.
 
PART II
Item 5.
 
 
 
Item 6.
 
 
 
Item 7.
 
 
 
Item 7A.
 
 
 
Item 8.
 
 
 
Item 9.
 
 
 
Item 9A.
 
 
 
Item 9B.
 
PART III
Item 10.
 
 
 
Item 11.
 
 
 
Item 12.
 
 
 
Item 13.
 
 
 
Item 14.
 
PART IV
Item 15.
 
 



2


PART I

Unless otherwise indicated, the terms “NuStar Energy L.P.,” “the Partnership,” “we,” “our” and “us” are used in this report to refer to NuStar Energy L.P., to one or more of our consolidated subsidiaries or to all of them taken as a whole. In this Form 10-K, we make certain forward-looking statements, including statements regarding our plans, strategies, objectives, expectations, intentions and resources. These forward-looking statements can generally be identified by the words “anticipates,” “believes,” “expects,” “plans,” “intends,” “estimates,” “forecasts,” “budgets,” “projects,” “will,” “could,” “should,” “may” and similar expressions. We do not undertake to update, revise or correct any of the forward-looking information. You are cautioned that such forward-looking statements should be read in conjunction with our disclosures beginning on page 34 of this report under the heading: “CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION.”

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

OVERVIEW
NuStar Energy L.P. (NuStar Energy), a Delaware limited partnership, was formed in 1999 and completed its initial public offering of common units on April 16, 2001. Our common units are traded on the New York Stock Exchange (NYSE) under the symbol “NS.” Our principal executive offices are located at 19003 IH-10 West, San Antonio, Texas 78257 and our telephone number is (210) 918-2000.
We are engaged in the transportation of petroleum products and anhydrous ammonia, the terminalling and storage of petroleum products and the marketing of petroleum products. The term “throughput” as used in this document generally refers to barrels of crude oil or refined product or tons of ammonia, as applicable, that pass through our pipelines, terminals or storage tanks.
We divide our operations into the following three reportable business segments: pipeline, storage and fuels marketing. As of December 31, 2015, our assets included:
5,500 miles of refined product pipelines with 21 associated terminals providing storage capacity of 5.0 million barrels and two tank farms providing storage capacity of 1.4 million barrels;
2,000 miles of anhydrous ammonia pipelines;
1,200 miles of crude oil pipelines, with 8 associated terminals, providing 4.0 million barrels of associated storage capacity; and
50 terminal and storage facilities providing 82.9 million barrels of storage capacity.
We conduct our operations through our wholly owned subsidiaries, primarily NuStar Logistics, L.P. (NuStar Logistics) and NuStar Pipeline Operating Partnership L.P. (NuPOP). Our revenues include:
tariffs for transporting crude oil, refined products and anhydrous ammonia through our pipelines;
fees for the use of our terminal and storage facilities and related ancillary services; and
sales of crude oil and refined petroleum products.
We strive to increase unitholder value by:
enhancing our existing assets through strategic internal growth projects that expand our business with current and new customers;
pursuing strategic expansion projects by constructing new assets;
improving our operations, including safety and environmental stewardship, cost control and asset reliability; and
identifying acquisition targets that meet our financial and strategic criteria.

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

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


3


RECENT DEVELOPMENTS

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

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 a summary of our organizational structure at December 31, 2015.

4


SEGMENTS
Detailed financial information about our segments is included in Note 25 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data.” The following map depicts our assets at December 31, 2015.
PIPELINE
Our pipeline operations consist of the transportation of refined petroleum products, crude oil and anhydrous ammonia. As of December 31, 2015, we owned and operated:
refined product pipelines with an aggregate length of 3,140 miles and crude oil pipelines with an aggregate length of 1,200 miles in Texas, Oklahoma, Kansas, Colorado and New Mexico (collectively, the Central West System);
a 1,920-mile refined product pipeline originating in southern Kansas and terminating at Jamestown, North Dakota, with a western extension to North Platte, Nebraska and an eastern extension into Iowa (the East Pipeline);
a 440-mile refined product pipeline originating at Tesoro Corporation’s (Tesoro) Mandan, North Dakota refinery and terminating in Minneapolis, Minnesota (the North Pipeline); and
a 2,000-mile anhydrous ammonia pipeline originating at the Louisiana delta area that travels north through the midwestern United States forking east and west to terminate in Nebraska and Indiana (the Ammonia Pipeline).
We charge tariffs on a per barrel basis for transporting refined products, crude oil and other feedstocks in our refined product and crude oil pipelines and on a per ton basis for transporting anhydrous ammonia in the Ammonia Pipeline.

5


The following table lists information about our pipeline assets as of December 31, 2015:
 
 
 
 
 
Throughput
 For the year ended December 31,
Region / Pipeline System
Length
 
Tank Capacity
 
2015
 
2014
 
(Miles)
 
(Barrels)
 
(Barrels/Day)
Central West System:
 
 
 
 
 
 
 
McKee System
2,276

 

 
172,590

 
164,589

Three Rivers System
373

 

 
74,361

 
78,177

Other
491

 

 
60,410

 
51,698

Central West Refined Products Pipelines
3,140

 

 
307,361

 
294,464

South Texas Crude System
319

 
2,157,000

 
179,734

 
155,439

Other
196

 

 
85,495

 
75,226

Eagle Ford System
515

 
2,157,000

 
265,229

 
230,665

McKee System
598

 
1,039,000

 
144,077

 
140,402

Ardmore System
87

 
824,000

 
62,326

 
66,690

Central West Crude Oil Pipelines
1,200

 
4,020,000

 
471,632

 
437,757

Total Central West System
4,340

 
4,020,000

 
778,993

 
732,221

 
 
 
 
 
 
 
 
Central East System:
 
 
 
 
 
 
 
East Pipeline
1,920

 
4,977,000

 
132,005

 
134,816

North Pipeline
440

 
1,437,000

 
46,951

 
45,641

Ammonia Pipeline
2,000

 

 
35,829

 
35,816

Total Central East System
4,360

 
6,414,000

 
214,785

 
216,273

 
 
 
 
 
 
 
 
Total
8,700

 
10,434,000

 
993,778

 
948,494

Description of Pipelines
Central West System. The Central West System covers a total of 4,340 miles. The Central West System pipelines support shale oil production and the refineries to which they are connected, including Valero Energy Corporation’s (Valero Energy) McKee, Three Rivers and Ardmore refineries. The refined product pipelines have an aggregate length of 3,140 miles (Central West Refined Products Pipelines) and transport gasoline, distillates (including diesel and jet fuel), natural gas liquids and other products produced at the refineries to which they are connected. The crude oil pipelines have an aggregate length of 1,200 miles (Central West Crude Oil Pipelines). Our crude oil pipelines transport crude oil and other feedstocks from various points to the refineries to which they are connected, and from the Eagle Ford Shale region to our North Beach marine terminal and refineries in Corpus Christi, Texas.
Central East System. The Central East System covers a total of 4,360 miles and consists of the East Pipeline, North Pipeline and Ammonia Pipeline.
The East Pipeline covers 1,920 miles and moves refined products and natural gas liquids north in pipelines ranging in diameter from 6 inches to 16 inches to NuStar Energy and third party terminals along the system and to receiving pipeline connections in Kansas. The East Pipeline system includes 17 terminals, discussed below, with storage capacity of approximately 3.6 million barrels and two tank farms with storage capacity of approximately 1.4 million barrels at McPherson and El Dorado, Kansas. Shippers on the East Pipeline obtain refined petroleum products from refineries in Kansas, Oklahoma and Texas.
The North Pipeline originates at Tesoro’s Mandan, North Dakota refinery and runs from west to east for approximately 440 miles to its termination in the Minneapolis, Minnesota area. The North Pipeline system includes 4 terminals, discussed below, with storage capacity of approximately 1.4 million barrels.
The East and North Pipelines include 21 truck-loading terminals through which refined petroleum products are delivered to storage tanks and then loaded into petroleum product transport trucks. Revenues earned at these terminals predominately relate to the volumes transported on the pipeline through fees included in the pipeline tariff. As a result, these terminals are included in this segment instead of the storage segment.

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The 2,000-mile Ammonia Pipeline originates in the Louisiana delta area, where it connects to three third-party marine terminals and three anhydrous ammonia plants on the Mississippi River. The line runs north through Louisiana and Arkansas into Missouri, where at Hermann, Missouri it splits and one branch goes east into Illinois and Indiana, while the other branch continues north into Iowa and then turns west into Nebraska. The Ammonia Pipeline is connected to multiple third-party-owned terminals, which include industrial facility delivery locations. Product is supplied to the pipeline from anhydrous ammonia plants in Louisiana and imported product delivered through the marine terminals. Anhydrous ammonia is primarily used as agricultural fertilizer. It is also used as a feedstock to produce other nitrogen derivative fertilizers and explosives.
Pipeline Operations
Revenues for the pipelines are based upon origin-to-destination throughput volumes traveling through our pipelines and their related tariff rates.
In general, shippers on our crude oil and refined product pipelines deliver petroleum products to our pipelines for transport to/from: (i) refineries that connect to our pipelines, (ii) third-party pipelines or terminals and (iii) NuStar Energy terminals for further delivery to marine vessels or pipelines. We charge our shippers tariff rates based on transportation from the origination point on the pipeline to the point of delivery.
Our pipelines are subject to federal regulation by one or more of the following governmental agencies: the Federal Energy Regulatory Commission (the FERC), the Surface Transportation Board (the STB), the Department of Transportation (DOT), the Environmental Protection Agency (EPA) and Homeland Security. Additionally, the operations and integrity of the pipelines are subject to the respective state jurisdictions.
The majority of our pipelines are common carrier. Common carrier activities are those for which transportation through our pipelines is available to any shipper of petroleum products who requests such services and satisfies the conditions and specifications for transportation. Published tariffs are (i) filed with the FERC for interstate petroleum product shipments, (ii) filed with the relevant state authority for intrastate petroleum product shipments and (iii) regulated by the STB for our Ammonia Pipeline.
We use a computerized Supervisory Control and Data Acquisition (SCADA) system to remotely operate pipelines. The SCADA system allows control center operators to control pumps and valves regulating and directing the transportation of petroleum products, while monitoring flow rates and pressures to assure system integrity and conform to pipeline schedules.
Demand for and Sources of Refined Products and Crude Oil
Throughputs on our Central West Refined Product Pipelines and the East and North Pipelines depend on the level of demand for refined products in the markets served by the pipelines and the ability and willingness of refiners and marketers having access to the pipelines to supply such demand by deliveries through the pipelines.
The majority of the refined products delivered through the Central West Refined Product Pipelines and the North Pipeline are gasoline and diesel fuel that originate at refineries connected to us. Demand for these products fluctuates as prices for these products fluctuate. Prices fluctuate for a variety of reasons including the overall balance in supply and demand, which is affected by general economic conditions, among other factors. Prices for gasoline and diesel fuel tend to increase in the warm weather months when people tend to drive automobiles more often and longer distances.
Much of the refined products and natural gas liquids delivered through the East Pipeline and a portion of volumes on the North Pipeline are ultimately used as fuel for railroads, ethanol denaturant or in agricultural operations, including fuel for farm equipment, irrigation systems, trucks used for transporting crops and crop-drying facilities. Demand for refined products for agricultural use, and the relative mix of products required, is affected by weather conditions in the markets served by the East and North Pipelines. The agricultural sector is also affected by government agricultural policies and crop prices. Although periods of drought suppress agricultural demand for some refined products, particularly those used for fueling farm equipment, the demand for fuel for irrigation systems often increases during such times. The mix of refined products delivered for agricultural use varies seasonally, with gasoline demand peaking in early summer, diesel fuel demand peaking in late summer and propane demand higher in the fall.
Our refined product pipelines are also dependent upon adequate levels of production of refined products by refineries connected to the pipelines, directly or through connecting pipelines. The refineries are, in turn, dependent upon adequate supplies of suitable grades of crude oil. Certain of our Central West Refined Products Pipelines are subject to long-term throughput agreements with Valero Energy. Valero Energy refineries connected directly to our pipelines obtain crude oil from a variety of foreign and domestic sources. If operations at one of these refineries were discontinued or significantly reduced, it could have a material adverse effect on our operations, although we would endeavor to minimize the impact by seeking alternative customers for those pipelines.

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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 adverse effect on our operations. The majority of the refined products transported through the East Pipeline are produced at three refineries located at McPherson and El Dorado, Kansas and Ponca City, Oklahoma, which are operated by CHS Inc., HollyFrontier Corporation (HollyFrontier) and Phillips 66, respectively. The East Pipeline also has access to Gulf Coast supplies of products through third party connecting pipelines that receive products originating on the Gulf Coast.
Other than the Valero Energy refineries described above and the Tesoro refinery, if operations at any one refinery were discontinued, we believe (assuming unchanged demand for refined products in markets served by the refined product pipelines) that the effects thereof would be short-term in nature and our business would not be materially adversely affected over the long-term because such discontinued production could be replaced by other refineries or other sources.
Our crude oil pipelines are dependent on our customers’ continued access to sufficient crude oil and sufficient demand for refined products for our customers to operate their refineries. The supply of crude oil production (domestic and foreign) could increase or decrease with the change in crude oil prices. Changes in crude oil prices could also affect the exploration and production of shale plays, which could impact crude oil pipelines serving those regions, such as our Eagle Ford System. However, many of our crude oil pipelines, including the McKee System, are the primary source of crude oil for our customers’ refineries. Therefore, these “demand-pull” pipelines are less affected by changes in crude oil prices.
Demand for and Sources of Anhydrous Ammonia
The Ammonia Pipeline is one of two major anhydrous ammonia pipelines in the United States and the only one capable of receiving foreign product directly into the system and transporting anhydrous ammonia into the nation’s corn belt.
Throughputs on our Ammonia Pipeline depend on overall nitrogen fertilizer use, the price of natural gas, which is the primary component of anhydrous ammonia, and the level of demand for direct application of anhydrous ammonia as a fertilizer for crop production (Direct Application). Demand for Direct Application is dependent on the weather, as Direct Application is not effective if the ground is too wet or too dry.
Corn producers have fertilizer alternatives to anhydrous ammonia, such as liquid or dry nitrogen fertilizers. Liquid and dry nitrogen fertilizers are both less sensitive to weather conditions during application but are generally more costly than anhydrous ammonia. In addition, anhydrous ammonia has the highest nitrogen content of any nitrogen-derivative fertilizer.
Customers
The largest customer of our pipeline segment was Valero Energy, which accounted for approximately 35% of the total segment revenues for the year ended December 31, 2015. In addition to Valero Energy, our customers include integrated oil companies, refining companies, farm cooperatives, railroads and others. No other customer accounted for a significant portion of the total revenues of the pipeline segment for the year ended December 31, 2015.
Competition and Business Considerations
Because pipelines are generally the lowest-cost method for intermediate and long-haul movement of crude oil and refined petroleum products, our more significant competitors are common carrier and proprietary pipelines owned and operated by major integrated and large independent oil companies and other companies in the areas where we deliver products. Competition between common carrier pipelines is based primarily on transportation charges, quality of customer service and proximity to end users. Trucks may competitively deliver products in some of the areas served by our pipelines; however, trucking costs render that mode of transportation uncompetitive for longer hauls or larger volumes.
Most of our refined product pipelines and certain of our crude oil pipelines within the Central West System are physically integrated with and principally serve refineries owned by Valero Energy. As a result, we do not believe that we will face significant competition for transportation services provided to the Valero Energy refineries we serve.
Certain of our crude oil pipelines serve areas or refineries impacted by domestic shale oil production in the Eagle Ford, Permian Basin and Granite Wash regions. Our pipelines also face competition from other crude oil pipelines and truck transportation in these regions. However, that exposure is mitigated through our long-term contracts and minimum volume commitments with credit-worthy customers.
The East and North Pipelines compete with an independent common carrier pipeline system owned by Magellan Midstream Partners, L.P. (Magellan) that operates approximately 100 miles east of and parallel to the East Pipeline and in close proximity to the North Pipeline. Certain of the East Pipeline’s and the North Pipeline’s delivery terminals are in direct competition with Magellan’s terminals. Competition with Magellan is based primarily on transportation charges, quality of customer service and proximity to end users.

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

STORAGE
Our storage segment includes terminal and storage facilities that provide storage, handling and other services for petroleum products, crude oil, specialty chemicals and other liquids. As of December 31, 2015, we owned and operated:
40 terminal and storage facilities in the United States and one terminal in Nuevo Laredo, Mexico, with total storage capacity of 51.2 million barrels;
A terminal on the island of St. Eustatius with tank capacity of 14.4 million barrels and a transshipment facility;
A terminal located in Point Tupper, Canada with tank capacity of 7.8 million barrels and a transshipment facility; and
Six terminals located in the United Kingdom and one terminal located in Amsterdam, the Netherlands, with total storage capacity of approximately 9.5 million barrels.
Description of Major Terminal Facilities
St. Eustatius. We own and operate a 14.4 million barrel petroleum storage and terminalling facility located on the island of St. Eustatius in the Caribbean, which is located at a point of minimal deviation from major shipping routes. This facility is capable of handling a wide range of petroleum products, including crude oil and refined products, and it can accommodate heavy-laden ultra large crude carriers, or ULCCs, for loading and discharging crude oil and other petroleum products. A two-berth jetty, a two-berth monopile with platform and buoy systems, a floating hose station and an offshore single point mooring buoy with loading and unloading capabilities serve the terminal’s customers’ vessels. The fuel oil and petroleum product facilities have in-tank and in-line blending capabilities, while the crude tanks have tank-to-tank blending capability and in-tank mixers. In addition to the storage and blending services at St. Eustatius, this facility has the flexibility to utilize certain storage capacity for both feedstock and refined products to support our atmospheric distillation unit, which is capable of handling up to 25,000 barrels per day of feedstock, ranging from condensates to heavy crude oil. We own and operate all of the berthing facilities at the St. Eustatius terminal. Separate fees apply for use of the berthing facilities, as well as associated services, including pilotage, tug assistance, line handling, launch service, emergency response services and other ship services.
St. James, Louisiana. Our St. James terminal, which is located on the Mississippi River near St. James, Louisiana, has a total storage capacity of 9.2 million barrels. The facility is located on almost 900 acres of land, some of which is undeveloped. The majority of the storage tanks and infrastructure are suited for light crude oil, with four tanks capable of fuel oil or heated crude oil storage. Additionally, the facility has one barge dock and two ship docks. Our St. James terminal can receive product from gathering pipelines in the Gulf of Mexico and deliver to connecting pipelines that supply refineries in the Gulf Coast and 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. In 2016, we expect to complete construction of two additional tanks with an aggregate storage capacity of 720,000 barrels.
Point Tupper. We own and operate a 7.8 million barrel terminalling and storage facility located at Point Tupper on the Strait of Canso, near Port Hawkesbury, Nova Scotia. This facility is the deepest independent, ice-free marine terminal on the North American Atlantic coast, with access to the East Coast, Canada and the Midwestern United States via the St. Lawrence Seaway and the Great Lakes system. With one of the premier jetty facilities in North America, the Point Tupper facility can accommodate heavy-laden ULCCs for loading and discharging crude oil, petroleum products and petrochemicals. Crude oil and petroleum product movements at the terminal are fully automated. Separate fees apply for 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.
Linden, New Jersey. Our Linden terminal facility has two terminals that provide deep-water terminalling capabilities in the New York Harbor and primarily stores petroleum products, including gasoline, jet fuel and fuel oils. The two terminals have a total storage capacity of 4.6 million barrels and can receive and deliver products via ship, barge and pipeline. The terminal facility includes two docks. On January 2, 2015, we acquired full ownership of one of the terminals located at the Linden facility that we previously owned 50% through a joint venture.

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.

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Corpus Christi North Beach. We own and operate a 2.1 million barrel crude oil storage and terminalling facility located at the Port of Corpus Christi in Texas. The facility supports our South Texas Crude System and provides our customers with the flexibility to segregate and deliver crude oil and processed condensate. In addition, this facility has three docks, including one private dock, and can load crude oil onto ships simultaneously on all three docks at a maximum rate of 65,000 barrels per hour. The Corpus Christi North Beach terminal has the capacity to move on average between 350,000 and 400,000 barrels per day and can accommodate Panamax-class vessels (which carry between 350,000 and 500,000 barrels).
Terminal and Storage Facilities
The following table sets forth information about our terminal and storage facilities as of December 31, 2015:
Facility
Tank Capacity
 
(Barrels)
Colorado Springs, CO
328,000

Denver, CO
110,000

Albuquerque, NM
251,000

Abernathy, TX
160,000

Amarillo, TX
269,000

Corpus Christi, TX
329,000

Corpus Christi, TX (North Beach)
2,136,000

Edinburg, TX
340,000

El Paso, TX (b)
419,000

Harlingen, TX
286,000

Laredo, TX
215,000

San Antonio, TX (c)
375,000

Southlake, TX
569,000

Nuevo Laredo, Mexico
35,000

Central West Terminals
5,822,000

 
 
Pittsburg, CA
398,000

Rosario, NM
166,000

Catoosa, OK
358,000

Houston, TX
86,000

Asphalt Terminals
1,008,000

 
 
Jacksonville, FL
2,593,000

St. James, LA
9,190,000

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

Gulf Coast Terminals
14,747,000

 
 
Blue Island, IL
690,000

Andrews AFB, MD (a)
75,000

Baltimore, MD
818,000

Piney Point, MD
5,402,000

Linden, NJ (c)
4,649,000

Paulsboro, NJ
74,000

Virginia Beach, VA (a)
41,000

North East Terminals
11,749,000

 
 
 
 

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Facility
Tank Capacity
 
(Barrels)
Los Angeles, CA
608,000

Selby, CA
3,060,000

Stockton, CA
816,000

Portland, OR
1,365,000

Tacoma, WA
391,000

Vancouver, WA (c)
774,000

West Coast Terminals
7,014,000

 
 
Corpus Christi, TX
4,030,000

Texas City, TX
3,141,000

Benicia, CA
3,683,000

Refinery Storage Tanks
10,854,000

 
 
Grays, England
1,958,000

Eastham, England
2,096,000

Runcorn, England
149,000

Grangemouth, Scotland
719,000

Glasgow, Scotland
353,000

Belfast, Northern Ireland
408,000

United Kingdom Terminals
5,683,000

 
 
St. Eustatius, the Netherlands
14,411,000

Amsterdam, the Netherlands
3,834,000

Point Tupper, Canada
7,778,000

 
 
Total Terminals and Storage Facilities
82,900,000

 
(a)
Terminal facility also includes pipelines to U.S. government military base locations.
(b)
We own a 67% undivided interest in the El Paso refined product terminal. The tank capacity represents the proportionate share of capacity attributable to our ownership interest.
(c)
Location includes two terminal facilities.

During 2015, we divested our refined product terminals with an aggregate storage capacity of 0.7 million barrels and located in Indianapolis, Indiana; Alamogordo, New Mexico and Placedo, Texas.
Storage Operations
Revenues for the storage segment include fees for tank storage agreements, where a customer agrees to pay for a certain amount of storage in a tank over a period of time (storage lease revenues), and throughput agreements, where a customer pays a fee per barrel for volumes moving through our terminals (throughput revenues). Our terminals also provide blending, additive injections, handling and filtering services for which we charge additional fees. We charge a fee for each barrel of crude oil and certain other feedstocks that we deliver to Valero Energy’s Benicia, Corpus Christi West and Texas City refineries from our crude oil refinery storage tanks. Certain of our facilities charge fees to provide marine services such as pilotage, tug assistance, line handling, launch service, emergency response services and other ship services.
Demand for Refined Petroleum Products and Crude Oil
The operations of our refined product terminals depend in large part on the level of demand for products stored in our terminals in the markets served by those assets. The majority of products stored in our terminals are refined petroleum products. Demand for our terminalling services will generally increase or decrease with demand for refined petroleum products, and demand for refined petroleum products tends to increase or decrease with the relative strength of the economy. In addition, the forward pricing curve can impact demand. For example, in a contango market (when the price for future storage is expected to exceed

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current prices), demand for storage services will generally increase. As of December 31, 2015, almost all of our tank storage capacity is under contract.
Crude oil delivered to our St. James terminal through our unit train facilities, and crude oil delivered to our Corpus Christi North Beach terminal will generally increase or decrease with crude oil production rates in the Bakken and Eagle Ford shale plays, respectively. In addition, the market price relationship between various grades of crude oil impacts the demand for our unit train facilities at our St. James terminal, which can affect our profit sharing and volumes.
Customers
We provide storage and terminalling services for crude oil and refined petroleum products to many of the world’s largest producers of crude oil, integrated oil companies, chemical companies, oil traders and refiners. In addition, our blending capabilities in our storage assets have attracted customers who have leased capacity primarily for blending purposes. The largest customer of our storage segment is Valero Energy, which accounted for approximately 19% of the total revenues of the segment for the year ended December 31, 2015. No other customer accounted for a significant portion of the total revenues of the storage segment for the year ended December 31, 2015.
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.
Terminal versatility is a function of the operator’s ability to offer complex handling requirements for diverse products. The services typically provided by the terminal include, among other things, the safe storage of the product at specified temperature, moisture and other conditions, as well as receipt at and delivery from the terminal, all of which must comply with applicable environmental regulations. A terminal operator’s ability to obtain attractive pricing is often dependent on the quality, versatility and reputation of the facilities owned by the operator. Although many products require modest terminal modification, operators with versatile storage capabilities typically require less modification prior to usage, ultimately making the storage cost to the customer more attractive.
Our St. Eustatius and Point Tupper terminals have historically functioned as “break bulk” facilities, which handled imports of light crude from foreign sources into the U.S. to satisfy U.S. East Coast and Gulf Coast refinery demand for light crude.  Light crude suppliers brought the crude from the Middle East and other foreign regions on very large ships,which are efficient for long routes.  These large ships, due to draft constraints, are unable to navigate far enough inland to deliver directly to U.S. shores, which necessitates unloading these ships to storage and subsequent loading onto smaller ships that can bring the crude to the refiners, a process referred to as “break bulk.”  Both terminals are well-located to provide this service.
As the supply of light crude from various U.S. shale formations has increased, U.S. demand for foreign light crude oil has dropped substantially.  This reduced demand for imported light crude has, in turn, dramatically changed oil trade flow patterns around the world, thereby depressing the demand for break bulk services.  At the same time, South American and Canadian production of heavy crude has ramped up significantly.  As demand for export of heavy crude and natural gas liquids (NGL) out of South America, as well as from Canada, has risen, so has the demand for “build bulk” services. In order to reduce costs and increase efficiencies for long routes to customers abroad, exporting producers need to consolidate their heavy oil cargos from the small ships used to move the heavy crude off shore to a large vessel that is more efficient for long routes, a process referred to as “build bulk.” Our St. Eustatius terminal’s location is well-suited to build bulk for South American producers headed to customers overseas, primarily in Asia.  Our Point Tupper facility’s location is similarly well-positioned, in this case to build bulk for heavy Canadian crude oil and NGL production.  
We may face increased competition from new and/or expanding terminals near our locations, if those facilities offer either break bulk or build bulk services, as demanded by the applicable oil trade flows, now and in the future.

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

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

Within our fuels marketing operations, we purchase crude oil and refined petroleum products for resale. The results of operations for the fuels marketing segment depend largely on the margin between our cost and the sales prices of the products we market. Therefore, the results of operations for this segment are more sensitive to changes in commodity prices compared to the operations of the pipeline and storage segments.

Since our fuels marketing operations expose us to commodity price risk, we enter into derivative instruments to mitigate the effect of commodity price fluctuations on our operations. The derivative instruments we use consist primarily of commodity futures and swap contracts.
Customers
Fuels marketing customers include major integrated refiners and trading companies. Customers for our bunker fuel sales are mainly ship owners, including cruise line companies. No customer accounted for a significant portion of the total revenues of the fuels marketing segment for the year ended December 31, 2015.
Competition and Business Considerations
Our fuels marketing operations have numerous competitors, including large integrated refiners, marketing affiliates of other partnerships in our industry, as well as various international and domestic trading companies. In the sale of bunker fuel, we compete with ports offering bunker fuels that are along the route of travel of the vessel.

EMPLOYEES

Our operations are managed by NuStar GP, LLC. As of December 31, 2015, NuStar GP, LLC had 1,251 domestic employees and certain of our wholly owned subsidiaries had 393 employees performing services for our international operations. We believe that NuStar GP, LLC and our subsidiaries each have satisfactory relationships with their employees. Please refer to Note 28 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for a discussion of the employee transfer from NuStar GP, LLC.

RATE REGULATION

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

The Ammonia Pipeline is subject to regulation by the STB pursuant to the Interstate Commerce Act applicable to such pipelines (which differs from the ICA applicable to interstate liquids pipelines). Under that regulation, the Ammonia Pipeline’s rates, classifications, rules and practices related to the interstate transportation of anhydrous ammonia must be reasonable and, in

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providing interstate transportation, the Ammonia Pipeline may not subject a person, place, port or type of traffic to unreasonable discrimination.

Additionally, the rates and practices for our intrastate common carrier pipelines are subject to regulation by state commissions, including in Colorado, Kansas, Louisiana, North Dakota and Texas. Although the applicable state statutes and regulations vary, they generally require that intrastate pipelines publish tariffs setting forth all rates, rules and regulations applying to intrastate service, and generally require that pipeline rates and practices be just, reasonable and nondiscriminatory.

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

ENVIRONMENTAL AND SAFETY REGULATION

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

We have adopted policies, practices and procedures including in the areas of pollution control, pipeline integrity, operator qualifications, public relations and education, process safety management, risk management planning, hazard communication, emergency response planning, community right-to-know, occupational health and the handling, storage, use and disposal of hazardous materials, that are designed to comply with applicable federal, state and local regulations and to prevent material environmental or other damage, to ensure the safety of our pipelines, our employees, the public and the environment and to limit the financial liability that could result from such events. Future governmental action and regulatory initiatives could 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. While we believe that we are in substantial compliance with the health, safety and environmental regulations applicable to us, 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 Statutes and Regulations. It is possible that these statutes and the related regulations may be revised to be more restrictive in the future, necessitating additional capital expense to ensure our operations are in compliance. We are unable to estimate the effect on our financial condition or results of operations or the amount and timing of such required expenditures. In 2015, our capital expenditures attributable to compliance with environmental regulations were $11.4 million, and are currently estimated to be approximately $18.0 million for 2016.

RENEWABLE ENERGY AND ALTERNATIVE FUEL MANDATES

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

WATER

The federal Water Pollution Control Act, as amended, also known as the Clean Water Act, and analogous or more stringent state and local statutes and regulations impose restrictions and strict controls regarding the discharge of pollutants into state waters or waters of the United States. The discharge of pollutants into state waters or waters of the United States is generally prohibited, except in accordance with the terms of a permit issued by applicable federal or state authorities. The Oil Pollution Act, enacted in 1990, amends provisions of the Clean Water Act as they pertain to prevention, response to and liability for oil spills. Spill prevention control and countermeasure requirements of the Clean Water Act and some state laws require response

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plans and the use of dikes and similar structures to help prevent contamination of state waters or waters of the United States in the event of an unauthorized discharge. Violations of any of these statutes and the related regulations could result in significant costs and liabilities. It is possible that these statutes and the related regulations may be revised to be more restrictive in the future, necessitating additional capital expense to ensure our operations are in compliance. We are unable to estimate the effect on our financial condition or results of operations or the amount and timing of such required expenditures.

AIR

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

SOLID WASTE

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

HAZARDOUS SUBSTANCES

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

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

While remediation of subsurface contamination is in process at several of our facilities, based on current available information, we believe that the cost of these activities will not materially affect our financial condition or results of operations. Such costs, however, are often unpredictable and, therefore, there can be no assurances that the future costs will not become material.

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Further, it is possible that these statutes and the related regulations may be revised to be more restrictive in the future, necessitating additional capital expense to ensure compliance. We are unable to estimate the effect on our financial condition or results of operations or the amount and timing of such required expenditures.

INTEGRITY AND SAFETY

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


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RISK FACTORS
RISKS RELATED TO OUR BUSINESS

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

In addition, the amount of cash that we will have available for distribution will depend on other factors, including:
our debt service requirements and restrictions on distributions contained in our current or future debt agreements;
the sources of cash used to fund our acquisitions;
our capital expenditures;
fluctuations in our working capital needs;
issuances of debt and equity securities; and
adjustments in cash reserves made by our general partner, in its discretion.

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

Our inability to develop and execute growth projects and acquire new assets could limit our ability to maintain and grow quarterly distributions to our unitholders.
Our ability to maintain and grow our distributions to unitholders depends on the growth of our existing businesses and strategic acquisitions.  If we are unable to implement business development opportunities and finance such activities on economically acceptable terms, our future growth will be limited, which could adversely impact our results of operations and cash flows and, accordingly, result in reduced distributions over time.

Failure to complete capital projects as planned could adversely affect our financial condition, results of operations and cash flows.
Delays or cost increases related to capital spending programs involving construction of new facilities (or improvements and repairs to our existing facilities) could adversely affect our ability to achieve forecasted operating results. Although we evaluate and monitor each capital spending project and try to anticipate difficulties that may arise, such delays or cost increases may arise as a result of factors that are beyond our control, including:
denial or delay in issuing requisite regulatory approvals and/or permits;
unplanned increases in the cost of construction materials or labor;
disruptions in transportation of modular components and/or construction materials;
severe adverse weather conditions, natural disasters or other events (such as equipment malfunctions, explosions, fires or spills) affecting our facilities, or those of vendors and suppliers;
shortages of sufficiently skilled labor, or labor disagreements resulting in unplanned work stoppages;
market-related increases in a project’s debt or equity financing costs; or
non-performance by, or disputes with, vendors, suppliers, contractors or sub-contractors involved with a project.

Our forecasted operating results are also based upon our projections of future market fundamentals that are not within our control, including changes in general economic conditions, the supply and demand of crude oil and refined products,

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availability to our customers of attractively priced alternative solutions for storage, transportation or supplies of crude oil and refined products and overall customer demand.

If we are unable to retain current, and obtain new, customers through renewing or establishing leases and throughput agreements at current or better rates or the utilization of our leased assets suffers a material decrease, our revenue and cash flows could be reduced to levels that could adversely affect our ability to make quarterly distributions to our unitholders.
Our revenue and cash flows are generated primarily from our customers’ payments of fees under throughput contracts and lease agreements. Failure to renew or enter into new contracts or our leasing customers’ material reduction of their utilization under our existing leases could result from many factors, including:
a material decrease in the supply or price of crude oil;
a material decrease in demand for refined products in the markets served by our pipelines and terminals;
scheduled turnarounds or unscheduled maintenance at refineries we serve;
operational problems or catastrophic events at a refinery we serve or our assets;
environmental proceedings or other litigation that compel the cessation of all or a portion of the operations at a refinery we serve or our assets;
a decision by our current customers to redirect refined products transported in our pipelines to markets not served by our pipelines or to transport crude oil or refined products by means other than our pipelines;
increasingly stringent environmental regulations; or
a decision by our current customers to sell one or more of the refineries we serve to a purchaser that elects not to use our pipelines and terminals.

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

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 conditions in the financial markets.
As of December 31, 2015, our consolidated debt was $3.2 billion. We also may be required to post cash collateral under certain of our hedging arrangements, which we expect to fund with borrowings under our revolving credit agreement. In addition to any potential direct financial impact of our debt, it is possible that any material increase to our debt or other negative financial factors may be viewed negatively by credit rating agencies, which could result in ratings downgrades and increased costs for us to access the capital markets. Any downgrades in our credit ratings in the future could result in increases to the interest rates on borrowings under our credit facilities and the 7.65% senior notes due 2018, significantly increase our capital costs, reduce our liquidity and adversely affect our ability to raise capital in the future.

Our revolving credit agreement contains restrictive covenants, such as limitations on indebtedness, liens, mergers, asset transfers and certain investing activities. In addition, the revolving credit agreement requires us to maintain, as of the end of each rolling period, which consists of any period of four consecutive fiscal quarters, a consolidated debt coverage ratio (consolidated debt to consolidated EBITDA, each as defined in the revolving credit agreement) not to exceed 5.00-to-1.00. Failure to comply with any of the revolving credit agreement restrictive covenants or this coverage ratio will result in a default and could result in acceleration of this agreement and possibly other indebtedness.

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

Our debt service obligations, restrictive covenants and maturities resulting from our leverage may adversely affect our ability to finance future operations, pursue acquisitions, fund our capital needs and pay cash distributions to our unitholders at current levels. In addition, this leverage may make our results of operations more susceptible to adverse economic or operating

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conditions. For example, during an event of default under certain of our debt agreements, we would be prohibited from making cash distributions to our unitholders. If our lenders file for bankruptcy or experience severe financial hardship, they may not honor their pro rata share of our borrowing requests under the revolving credit agreement, which may significantly reduce our available borrowing capacity and, as a result, materially adversely affect our financial condition and ability to pay distributions to our unitholders at current levels. Additionally, we may not be able to access the capital markets in the future at economically attractive terms, which may adversely affect our future financial and operating flexibility and our ability to pay cash distributions at current levels.

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, 2015, we had approximately $3.2 billion of consolidated debt, of which $1.8 billion was at fixed interest rates and $1.4 billion was at variable interest rates. In addition, prior ratings downgrades on our existing indebtedness caused interest rates under our revolving credit agreement and our senior notes due 2018 to increase effective January 2013, and future downgrades may cause interest rates on our variable interest rate debt to increase further. Additionally, at December 31, 2015, we had $600.0 million aggregate notional amount of interest rate swap arrangements, which increase our exposure to variable interest rates. As a result, our results of operations, cash flows and financial position could be materially adversely affected by significant increases in interest rates above current levels. In addition, we historically have funded our strategic capital expenditures and acquisitions from external sources, primarily borrowings under our revolving credit agreement or funds raised through debt or equity offerings. An increase in interest rates may negatively impact our ability to access the capital markets at economically attractive rates. Further, the trading price of our units is sensitive to changes in interest rates and any rise in interest rates could adversely impact the trading price of our units, which would effectively increase our cost of raising funds through equity offerings.

Low crude oil prices could have an adverse impact on our results of operations, cash flows and ability to make distributions to our unitholders, as well as our ability to access the capital markets at economically attractive rates.
During 2015 and early 2016, the price of crude oil has continued to decline, reaching lows not seen in 13 years. The sustained period of low prices has forced most crude oil producers to reduce their capital spending and drilling activity and narrow their focus to assets in the most cost-advantaged regions. On the other hand, refiners generally have benefitted from lower crude prices, particularly to the extent that lower feedstock price has been coupled with higher demand for certain refined products in some regional markets. However, a protracted period of depressed crude oil prices and overall economic downturn could have a negative impact on our results of operations.

In addition, regardless of insulation from or lack of exposure to commodity prices, continued low crude oil prices seem to be having a direct, negative impact on the unit price of many master limited partnerships, including our own, and unfavorable market conditions have increased the cost of financing capital spending through the public debt and equity markets.

Reduced demand for or supply of crude oil and refined products could affect our results of operations and ability to make distributions at current levels to our unitholders.
Our business is dependent upon the demand for and supply of the crude oil and refined products transported by our pipelines and stored in our terminals. Any sustained decrease in demand for refined products in the markets served by our pipelines and terminals could result in a significant reduction in throughputs in our pipelines and storage in our terminals, which would reduce our cash flows and our ability to make distributions at current levels to our unitholders. Factors that could lead to a decrease in market demand include:
a recession or other adverse economic condition that results in lower spending by consumers on gasoline, diesel and travel;
higher fuel taxes or other governmental or regulatory actions that increase, directly or indirectly, the cost of gasoline;
an increase in automotive engine fuel economy, whether as a result of a shift by consumers to more fuel-efficient vehicles or technological advances by manufacturers;
an increase in the market price of crude oil that leads to higher refined product prices, which may reduce demand for refined products and drive demand for alternative products. Market prices for crude oil and refined products, including fuel oil, are subject to wide fluctuation in response to changes in global and regional supply that are beyond our control, and increases in the price of crude oil may result in a lower demand for refined products that we transport, store and market, including fuel oil;
a decrease in corn acres planted, which may reduce demand for anhydrous ammonia; and
the increased use of alternative fuel sources, such as battery-powered engines.


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Similarly, any sustained decrease in the supply of crude oil and refined products could result in a significant reduction in throughputs in our pipelines and storage in our terminals, which would reduce our cash flows and our ability to make distributions at current levels to our unitholders. Factors that could lead to a decrease in supply to our pipelines and terminals include:
prolonged periods of low prices for crude oil and refined products, which could lead to a decrease in exploration and development activity and reduced production in markets served by our pipelines and storage terminals;
changes in the regulatory environment, governmental policies or taxation that directly or indirectly delay production or increase the cost of production of refined products; and
actions taken by foreign oil and gas producing nations that impact prices for crude oil and refined products.

Our 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.

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 or other claims related to the operation of our assets and the services we provide to our customers.
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. We also could face other claims by our customers if our assets do not operate as expected by our customers or our services otherwise do not meet our customers’ expectations. A successful claim or series of claims against us could result in unforeseen expenditures and a loss of one or more customers.

We are exposed to counterparty credit risk. Nonpayment and nonperformance by our customers, vendors or derivative counterparties could reduce our revenues, increase our expenses and otherwise have a negative impact on our ability to conduct our business, our operating results, cash flows and ability to make distributions to our unitholders.
We are subject to risks of loss resulting from nonpayment or nonperformance by our customers to whom we extend credit. In addition, nonperformance by vendors who have committed to provide us with critical products or services could raise our costs or interfere with our ability to successfully conduct our business. Furthermore, nonpayment by the counterparties to any of our outstanding derivatives could expose us to additional interest rate or commodity price risk. Weak economic conditions and widespread financial stress could reduce the liquidity of our customers, vendors or counterparties, making it more difficult for them to meet their obligations to us. Any substantial increase in the nonpayment and nonperformance by our customers, vendors or counterparties could have a material adverse effect on our results of operations, cash flows and ability to make distributions to unitholders.

Axeon’s failure to repay the Axeon Term Loan and any liability we incur as a result of the financing arrangements and guarantees of Axeon required by that loan could have a material and adverse impact on our financial condition, results of operations and cash flows and could adversely affect our ability to make quarterly distributions to our unitholders.
In connection with our sale of NuStar Asphalt LLC (now known as Axeon), our operating subsidiary, NuStar Logistics, agreed to convert the revolving credit facility with Axeon into a $190 million term loan (the Axeon Term Loan). We also agreed to continue to provide credit support to Axeon in the form of guarantees, letters of credit and cash collateral of up to $150 million (the Credit Support) until February 26, 2016, at which point the amount of Credit Support will begin to decline until the obligation is terminated no later than September 28, 2019.

Axeon was scheduled to repay principal amounts under the Axeon Term Loan to reduce the principal amount outstanding to $175 million by December 31, 2014 and to $150 million by September 30, 2015, with repayment in full no later than September 28, 2019 and earlier repayment possible, depending on the amount of excess cash flows (if any) generated by

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Axeon. Any repayments of the Axeon Term Loan are subject to Axeon meeting certain restrictive requirements contained in its third-party asset-based revolving credit facility (ABL Facility). Axeon failed to make the scheduled principal payments by December 31, 2014 and September 30, 2015, respectively, increasing the interest rate payable by Axeon until Axeon makes the payments.

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

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

Potential future acquisitions and expansions, if any, may increase substantially the level of our indebtedness and contingent liabilities or otherwise change our capital structure, and we may be unable to integrate acquisitions and expansions effectively into our existing operations.
From time to time, we evaluate and acquire assets and businesses that we believe complement or diversify our existing assets and businesses. Acquisitions may require us to raise a substantial amount of equity or incur a substantial amount of indebtedness. If we consummate any future material acquisitions, our capitalization and results of operations may change significantly, and 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 do not own all of the land on which our pipelines and facilities have been constructed, and we are therefore subject to the possibility of increased costs or the inability to retain necessary land use.
We obtain the rights to construct and operate our pipelines, storage terminals and other facilities on land owned by third parties and governmental agencies. Many of these rights-of-way or other property rights are perpetual in duration while others are for a specific period of time. In addition, some of our facilities are located on leased premises. Our loss of these rights, through our inability to renew right-of-way contracts or leases or otherwise, could adversely affect our operations and cash flows available for distribution to unitholders.


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

We may have liabilities from our assets that pre-exist our acquisition of those assets, but that may not be covered by indemnification rights we may have against the sellers of the assets.
In some cases, we have indemnified the previous owners and operators of acquired assets. Some of our assets have been used for many years to transport and store crude oil and refined products. Releases may have occurred in the past that could require costly future remediation. If a significant release or event occurred in the past, the liability for which was not retained by the seller, or for which indemnification by the seller is not available, it could adversely affect our financial position and results of operations.

Climate change legislation and other regulatory initiatives may decrease demand for the products we store, transport and sell and increase our operating costs.
Scientific studies have suggested that emissions of certain gases, commonly referred to as “greenhouse gases” and including carbon dioxide and methane, may be contributing to warming of the Earth’s atmosphere. In response to such studies, the U.S. Congress, European Union and other political bodies have considered legislation or regulation to reduce emissions of greenhouse gases. In December 2015, representatives from 195 countries, including the United States, met at the 2015 United Nations Climate Change Conference and adopted an accord wherein each country committed to take certain steps to reduce global carbon emissions. While adherence to the accord is voluntary and not currently binding on the United States, if the U.S. Congress adopts legislation implementing its provisions, this could have an adverse effect on demand for our products and increase our operating costs. In addition, several states and local governmental bodies, either individually or through multi-member initiatives, have already taken legal measures to reduce emissions of greenhouse gases, including through the development of greenhouse gas emission inventories and/or greenhouse gas cap and trade programs. As an alternative to reducing emission of greenhouse gases under cap and trade programs, governmental bodies may consider the implementation of a program to tax the emission of carbon dioxide and other greenhouse gases. Passage of climate change legislation or other regulatory initiatives in areas in which we conduct business, could result in changes to the demand for the products we store, transport and sell, and could increase the costs of our operations, including costs to operate and maintain our facilities, install new emission controls on our facilities, acquire allowances to authorize our greenhouse gas emissions, pay any taxes related to our greenhouse gas emissions or administer and manage a greenhouse gas emissions program. Even though we attempt to mitigate such lost revenues or increased costs through the contracts we sign with our customers, we may be unable to recover those revenues or mitigate the increased costs, and any such recovery may depend on events beyond our control, including the outcome of future rate proceedings before the FERC, the STB or other regulators and the provisions of any final legislation or regulations. Reductions in our revenues or increases in our expenses as a result of climate control or other initiatives could have adverse effects on our business, financial position, results of operations and prospects.

We operate a global business that exposes us to additional risk.
We operate a global business and a significant portion of our revenues come from our business outside of the United States. Our operations outside the United States may be affected by changes in trade protection laws, policies and measures, and other regulatory requirements affecting trade and investment, including the Foreign Corrupt Practices Act, the United Kingdom Bribery Act and other foreign laws prohibiting corrupt payments, as well as import and export regulations. We have assets in certain emerging markets, and the developing nature of these markets presents a number of risks. Deterioration of social, political, labor or economic conditions, including the increasing threat of drug cartels, in a specific country or region and difficulties in staffing and managing foreign operations may also adversely affect our operations or financial results.

Our operations are subject to federal, state and local laws and regulations, in the U.S. and in the foreign countries in which we operate, relating to environmental protection and operational safety that could require us to make substantial expenditures.
Our operations are subject to increasingly stringent environmental, health and safety laws and regulations. Transporting, storing and distributing products, including petroleum products, produces a risk that these products may be released into the environment, potentially causing substantial expenditures for a response action, significant government penalties, liability to government agencies for damages to natural resources, personal injury or property damages to private parties and significant business interruption. We own or lease a number of properties that have been used to transport, store or distribute products for many years. Many of these properties were operated by third parties whose handling, disposal or release of products and wastes was not under our control.


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If we were to incur a significant liability pursuant to environmental, health or safety laws or regulations, such a liability could have a material adverse effect on our financial position, our ability to make distributions to our unitholders at current levels and our ability to meet our debt service requirements. Please read Item 3. “Legal Proceedings” and Note 15 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data.”

Our interstate common carrier pipelines are subject to regulation by the FERC.
The FERC regulates the tariff rates and terms and conditions of service for interstate oil movements on our common carrier pipelines. FERC regulations require that these rates must be just and reasonable and that the pipeline not engage in undue discrimination or undue preference with respect to any shipper. Under the ICA, FERC or shippers may challenge our pipeline tariff filings, including rates and terms and conditions of service. Further, other than for rates set under market-based rate authority, if a new rate is challenged by protest and investigated by the FERC, the FERC may suspend collection of such new rate for up to seven months. If such new rate is found to be unjust and unreasonable, the FERC may order refunds of amounts collected in excess of amounts generated by the just and reasonable rate determined by FERC. A successful rate challenge could result in a common carrier paying refunds together with interest for the period that the rate was in effect. In addition, shippers may challenge by complaint tariff rates and terms and conditions of service even after the rates and terms and conditions of service are in effect. If the FERC, in response to such a complaint or on its own initiative, initiates an investigation of rates that are already in effect, the FERC may order a carrier to change its rates prospectively. If existing rates are challenged and are determined by the FERC to be in excess of a just and reasonable level, a shipper may obtain reparations for damages sustained during the two years prior to the date the shipper filed a complaint.

We use various FERC-authorized rate change methodologies for our interstate pipelines, including indexing, cost-of-service rates, market-based rates and settlement rates. Typically, we adjust our rates annually in accordance with FERC indexing methodology, which currently allows a pipeline to change their rates within prescribed ceiling levels that are tied to an inflation index. For the five-year period beginning July 1, 2011, the index is measured by the year-over-year change in the Bureau of Labor’s producer price index for finished goods, plus 2.65%. For the five-year period beginning July 1, 2016, the index is measured by the year-over-year change in the Bureau of Labor’s producer price index for finished goods, plus 1.23%. We anticipate that the oil pipeline index for the five-year period beginning July 1, 2016 may be subject to further review by FERC. Some of our newer projects that involved an open season include negotiated indexation rate caps. These methodologies could result in changes in our revenue that do not fully reflect changes in costs we incur to operate and maintain our pipelines. For example, our costs could increase more quickly or by a greater amount than the negotiated indexation rate cap. Shippers may protest rate increases made within the ceiling levels, but such protests must show that the portion of the rate increase resulting from application of the index is substantially in excess of the pipeline’s change in costs from the previous year. However, if the index results in a negative adjustment, we are required to reduce any rates that exceed the new maximum allowable rate. In addition, changes in the index might not be large enough to fully reflect actual increases in our costs. If the FERC’s rate-making methodologies change, any such change or new methodologies could result in rates that generate lower revenues and cash flow and could adversely affect our ability to make distributions at current levels to our unitholders and to meet our debt service requirements. Additionally, competition constrains our rates in various markets. As a result, we may from time to time be forced to reduce some of our rates to remain competitive.

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. Circuit), and on May 29, 2007, the D.C. Circuit issued an opinion upholding the FERC’s tax allowance policy.

In two proceedings involving SFPP, L.P., a refined products pipeline system, shippers again challenged the FERC’s income tax allowance policy, alleging that it is unlawful for a pipeline organized as a tax-pass-through entity to be afforded an income tax allowance and that the income tax allowance is unnecessary because an allowance for income taxes for such pipelines is recovered indirectly through the rate of return on equity. The FERC rejected these shipper arguments in multiple orders. Petitions for review of FERC’s rulings on the income tax allowance have been filed with the D.C. Circuit. Because the extent to which an interstate oil pipeline is entitled to an income tax allowance is subject to a case-by-case review at the FERC and is a matter under litigation, the level of income tax allowance to which we would ultimately be entitled in a cost-of-service rate review is not certain. Although the FERC’s current income tax allowance policy is generally favorable for pipelines that are organized as pass-through entities, it still entails rate risks due to the case-by-case review requirement and the above-noted

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pending litigation. How the FERC’s income tax allowance policy is applied in practice to pipelines owned by publicly traded partnerships could impose limits on our ability to include a full income tax allowance in cost of service.

The rates that we may charge on our interstate ammonia pipeline are subject to regulation by the STB.
The Ammonia Pipeline is subject to regulation under the ICA by the STB. Under that regulation the Ammonia Pipeline’s rates, classifications, rules and practices related to the interstate transportation of anhydrous ammonia must be reasonable and, in providing interstate transportation, our ammonia pipeline may not subject a person, place, port or type of traffic to unreasonable discrimination.

Increases in natural gas and power prices could adversely affect our operating expenses and our ability to make distributions at current levels to our unitholders.
Power costs constitute a significant portion of our operating expenses. For the year ended December 31, 2015, our power costs equaled approximately $44.9 million, or 9.5% of our operating expenses for the year. We use mainly electric power at our pipeline pump stations and terminals, and such electric power is furnished by various utility companies that primarily use natural gas to generate electricity. Accordingly, our power costs typically fluctuate with natural gas prices. Increases in natural gas prices may cause our power costs to increase further. If natural gas prices increase, our cash flows may be adversely affected, which could adversely affect our ability to make distributions at current levels to our unitholders.

Terrorist attacks and the threat of terrorist attacks have resulted in increased costs to our business. Continued hostilities in the Middle East or other sustained military campaigns may adversely impact our results of operations.
Increased security measures we have taken as a precaution against possible terrorist attacks have resulted in increased costs to our business. Uncertainty surrounding continued hostilities in the Middle East or other sustained military campaigns may affect our operations in unpredictable ways, including disruptions of crude oil supplies and markets for refined products, and the possibility that infrastructure facilities could be direct targets of, or indirect casualties of, an act of terror or 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 historically have relied upon external financing sources, including commercial borrowings and other debt and equity issuances, to fund our acquisition capital expenditures. Accordingly, to the extent we do not have sufficient cash reserves or are unable to finance growth externally, our cash distribution policy will significantly impair our ability to grow. In addition, to the extent we issue additional units in connection with any acquisitions or growth capital expenditures, the payment of distributions on those additional units may increase the risk that we will be unable to maintain or increase our current per unit distribution level.

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

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

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


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

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

If we fail to maintain an effective system of internal controls, we may not be able to report our financial results accurately or prevent fraud, which could have a material and adverse impact on our financial condition, results of operations, and cash flows and our ability to make distributions to our unitholders.
We are required to disclose material changes made in our internal controls over financial reporting on a quarterly basis and we are required to assess the effectiveness of our controls annually. Effective internal controls are necessary for us to provide reliable and timely financial reports, to prevent fraud, and to operate successfully as a publicly traded limited partnership. We may be unable to maintain effective controls over our financial processes and reporting in the future or to comply with our obligations under Section 404 of the Sarbanes-Oxley Act of 2002. For example, Section 404 requires us, among other things, annually to review and report on the effectiveness of our internal control over financial reporting. Any failure to maintain effective internal controls or to improve our internal controls could harm our operating results or cause us to fail to meet our reporting obligations.

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

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, 2015, an aggregate 12.9% limited partner interest in us out of the total possible ownership. 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

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

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

The general partner interest, the control of our general partner and the incentive distribution rights of our general partner may be transferred to a third party without unitholder consent.
Our general partner may transfer its general partner interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of our unitholders. Furthermore, the general partner may transfer its general partnership interest to a third party without the consent of our unitholders. Any new owner of our general partner would be in a position to replace the officers of the general partner with its own choices and to control the decisions made by such officers.

Additionally, our general partner may transfer its incentive distribution rights to a third party at any time without the consent of our unitholders. If our general partner transfers its incentive distribution rights to a third party but retains its general partner interest, our general partner may not have the same incentive to grow our partnership and increase quarterly distributions to unitholders over time as it would if it had retained ownership of its incentive distribution rights.

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

Unitholders may not have limited liability if a court finds that unitholder action constitutes control of our business or that we have not complied with applicable statutes, which may have an impact on the cash we have available to make distributions.
Under Delaware law, unitholders could be held liable for our obligations to the same extent as a general partner if a court determined that actions of a unitholder constituted participation in the “control” of our business.

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

Unitholders may have liability to repay distributions.
Under certain circumstances, our unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 17-607 of the Delaware Act, we may not make a distribution to our unitholders if the distribution would cause our liabilities to exceed the fair value of our assets. Liabilities to partners on account of their partnership interests and liabilities that are nonrecourse to the partnership are not counted for purposes of determining whether a distribution is permitted.

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

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


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

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

If we were treated as a corporation for federal or state income tax purposes or we were otherwise subject to a material amount of entity-level taxation, then our cash available for distribution to unitholders would be substantially reduced.
The anticipated after-tax benefit of an investment in our units depends largely on our being treated as a partnership for federal income tax purposes. We have not requested, and do not plan to request, a ruling from the Internal Revenue Service (the IRS) on this matter.

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

If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate, which is currently a maximum of 35%, and would likely pay state and local income tax at varying rates. Distributions to unitholders would generally be taxed again as corporate dividends (to the extent of our current and accumulated earnings and profits), and no income, gains, losses, deductions or credits would flow through to unitholders. Because a tax would be imposed upon us as a corporation, our distributable cash flow would be substantially reduced.

In addition, recently enacted legislation applicable to partnership tax years beginning after 2017 changes the audit procedures for large partnerships and, in certain circumstances, would permit the IRS to assess and collect taxes (including any applicable penalties and interest) resulting from partnership-level federal income tax audits directly from us in the year in which the audit is completed. If we are required to make payments of taxes, penalties and interest resulting from audit adjustments, our cash available for distribution to our unitholders might be substantially reduced.

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


27


The tax treatment of publicly traded partnerships or an investment in our units could be subject to potential legislative, judicial or administrative changes or differing interpretations, possibly applied on a retroactive basis.
The present U.S. federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative, legislative or judicial changes or differing interpretations at any time. From time to time, members of Congress propose and consider such substantive changes to the existing federal income tax laws that affect publicly traded partnerships. Further, the U.S. Treasury Department and the IRS issued proposed regulations regarding qualifying income within the meaning of Section 7704 of the Code (the “Proposed Regulations”). We believe the income that we treat as qualifying income satisfies the requirements for qualifying income under the Proposed Regulations. However, the Proposed Regulations could be changed before they are finalized and could take a position that is contrary to our interpretation of Section 7704 of the Code.

Any modification to the federal income tax laws may be applied retroactively and could make it more difficult or impossible for us to meet the exception for certain publicly traded partnerships to be treated as partnerships for federal income tax purposes. We are unable to predict whether any of these changes or other proposals will ultimately be enacted. Any such changes could negatively impact the value of an investment in our common units.

A successful IRS contest of the federal income tax positions we take may adversely impact the market for our units, and the costs of any contest will reduce cash available for distribution to our unitholders.
The IRS may adopt positions that differ from the positions we take, even positions taken with the advice of counsel. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take. A court may not agree with all of the positions we take. Any contest with the IRS may materially and adversely impact the market for our units and the prices at which they trade. Moreover, recently enacted legislation applicable to partnership tax years beginning after 2017 changes the audit procedures for large partnerships and, in certain circumstances, would permit the IRS to assess and collect taxes (including any applicable penalties and interest) resulting from partnership-level federal income tax audits directly from us in the year in which the audit is completed. If we are required to make payments of taxes, penalties and interest resulting from audit adjustments, our cash available for distribution to our unitholders might be substantially reduced. 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 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 their respective share of our taxable income, whether or not the unitholders receive cash distributions from us. Unitholders may not receive cash distributions from us equal to their respective share of our taxable income or even equal to the actual tax liability that results from their respective share of our taxable income.

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.
We will be considered to have terminated for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. For purposes of determining whether the 50% threshold has been met, multiple sales of the same interest will be counted only once.

Our termination for federal income tax purposes would, among other things, result in the closing of our taxable year for all unitholders, which would result in us filing two tax returns for one calendar year and could result in a significant deferral of depreciation deductions allowable in computing our taxable income. In the case of a unitholder reporting on a taxable year other than a calendar year, the closing of our taxable year may also result in more than twelve months of our taxable income or loss being includable in taxable income for the unitholder’s taxable year that includes our termination. Our termination would not affect our classification as a partnership for federal income tax purposes, but it would result in our being treated as a new partnership for U.S. federal income tax purposes following the termination. If we were treated as a new partnership, we would be required to make new tax elections and could be subject to penalties if we were unable to determine that a termination occurred. The IRS has announced a relief procedure whereby if a publicly traded partnership that has technically terminated requests, and the IRS grants, special relief, among other things, the partnership may be permitted to provide only a single Schedule K-1 to unitholders for the two short tax periods included in the year in which the termination occurs.

Tax gain or loss on the disposition of our units could be different than expected.
If a unitholder sells units, the selling unitholder will recognize a gain or loss equal to the difference between the amount realized and the unitholder’s tax basis in those units. Prior distributions to the selling unitholder in excess of the total net taxable income the unitholder was allocated for a unit, which decreased the unitholder’s tax basis in that unit, will, in effect, become taxable income to the selling unitholder if the unit is sold at a price greater than the unitholder’s tax basis in that unit,

28


even if the price the unitholder receives is less than the unit’s original cost. A substantial portion of the amount realized, whether or not representing gain, may be ordinary income to the selling unitholder.

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 with all aspects of existing Treasury regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to unitholders. It also could affect the timing of these tax benefits or the amount of gain from a unitholder’s sale of units and could have a negative impact on the value of our units or result in audit adjustments to the unitholder’s tax returns.

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

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

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.


29


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

PROPERTIES

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

ITEM 1B. UNRESOLVED STAFF COMMENTS
None.

ITEM 3. LEGAL PROCEEDINGS

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

We are insured against various business risks to the extent we believe is prudent; however, we cannot assure you that the nature and amount of such insurance will be adequate, in every case, to protect us against liabilities arising from future legal proceedings as a result of our ordinary business activity.
 
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 SEC regulations, including those which require us to disclose proceedings arising under federal, state or local provisions regulating the discharge of materials into the environment or primarily for the purpose of protecting the environment if a governmental authority is a party to the proceeding and 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, dioxin/furans and other pollutants. Shore and more than 90 other parties have received a

30


“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 clean-up. 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 if and to what extent natural resource damage claims or third party contribution or damage claims will be asserted against Shore.

ITEM 4. MINE SAFETY DISCLOSURES
Not applicable.

31


PART II

ITEM 5.
MARKET FOR REGISTRANT’S COMMON UNITS, RELATED UNITHOLDER MATTERS AND ISSUER PURCHASES OF COMMON UNITS
Our common units are listed and traded on the New York Stock Exchange under the symbol “NS.” At the close of business on February 8, 2016, we had 535 holders of record of our common units. The high and low sales prices (composite transactions) by quarter for the years ended December 31, 2015 and 2014 were as follows:
 
Price Range of Common Unit
 
High
 
Low
Year 2015
 
 
 
4th Quarter
$
52.24

 
$
31.20

3rd Quarter
$
60.48

 
$
42.00

2nd Quarter
$
68.10

 
$
58.81

1st Quarter
$
63.78

 
$
54.58

Year 2014
 
 
 
4th Quarter
$
66.94

 
$
50.91

3rd Quarter
$
68.33

 
$
61.02

2nd Quarter
$
62.88

 
$
53.76

1st Quarter
$
55.15

 
$
47.51

Our partnership agreement requires that we distribute all “Available Cash” to our partners each quarter, and this term is defined in the partnership agreement as cash on hand at the end of the quarter, plus certain permitted borrowings made subsequent to the end of the quarter, less cash reserves determined by our board of directors. See Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” for further information regarding our sources of cash to fund distributions. The cash distributions applicable to each of the quarters in the years ended December 31, 2015 and 2014 were as follows:
 
Record Date
 
Payment Date
 
Amount
Per Unit
Year 2015
 
 
 
 
 
4th Quarter
February 8, 2016
 
February 12, 2016
 
$
1.095

3rd Quarter
November 9, 2015
 
November 13, 2015
 
$
1.095

2nd Quarter
August 7, 2015
 
August 13, 2015
 
$
1.095

1st Quarter
May 8, 2015
 
May 14, 2015
 
$
1.095

Year 2014
 
 
 
 
 
4th Quarter
February 9, 2015
 
February 13, 2015
 
$
1.095

3rd Quarter
November 10, 2014
 
November 14, 2014
 
$
1.095

2nd Quarter
August 6, 2014
 
August 11, 2014
 
$
1.095

1st Quarter
May 7, 2014
 
May 12, 2014
 
$
1.095

Our general partner is entitled to incentive distributions if the amount that we distribute with respect to any quarter exceeds specified target levels shown below:
 
 
Percentage of Distribution
Quarterly Distribution Amount per Unit
 
Unitholders
 
General Partner
Up to $0.60
 
98%
 
2%
Above $0.60 up to $0.66
 
90%
 
10%
Above $0.66
 
75%
 
25%

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Our general partner’s incentive distributions totaled $43.2 million for each of the years ended December 31, 2015 and 2014. The general partner’s share of our distributions for the years ended December 31, 2015 and 2014 was 13.0% in each year due to the impact of the incentive distributions.

The following table sets forth the purchases of our common units made during the quarter ended December 31, 2015 by or on behalf of us or an affiliated purchaser:
Period
 
Total Number of Units Purchased(1)
 
Average Price Paid per Unit(1)
 
Total Number of Units Purchased as Part of Publicly Announced Plans or Programs
 
Maximum Number (or Approximate Dollar Value) of Units that May Yet Be Purchased Under the Plans or Programs
October 1 through October 31
 

 
$

 

 
$

November 1 through November 30
 

 

 

 

December 1 through December 31
 
30,000

 
34.20

 

 

Total
 
30,000

 
$
34.20

 

 
$

 
(1)   
During the quarter ended December 31, 2015, NuStar GP, LLC, the general partner of our general partner, purchased 30,000 of our common units in the open market to satisfy NuStar GP, LLC’s obligations under its long-term incentive plans.

ITEM 6. SELECTED FINANCIAL DATA
The following table contains selected financial data derived from our audited financial statements.
 
Year Ended December 31,
 
2015
 
2014
 
2013 (a)
 
2012 (a)
 
2011
 
(Thousands of Dollars, Except Per Unit Data)
Statement of Income Data:
 
 
 
 
 
 
 
 
 
Revenues (b)
$
2,084,040

 
$
3,075,118

 
$
3,463,732

 
$
5,945,736

 
$
6,257,629

Operating income (loss)
390,704

 
346,901

 
(19,121
)
 
(18,168
)
 
310,883

Income (loss) from continuing operations
305,946

 
214,169

 
(185,509
)
 
(166,001
)
 
218,674

Income (loss) from continuing operations per
unit applicable to limited partners
3.29

 
2.14

 
(2.89
)
 
(2.79
)
 
2.74

Cash distributions per unit applicable to
limited partners
4.380

 
4.380

 
4.380

 
4.380

 
4.360

 
 
 
 
 
 
 
 
 
 
 
December 31,
 
2015
 
2014
 
2013
 
2012
 
2011
 
(Thousands of Dollars)
Balance Sheet Data:
 
 
 
 
 
 
 
 
 
Property, plant and equipment, net
$
3,683,571

 
$
3,460,732

 
$
3,310,653

 
$
3,238,460

 
$
3,430,468

Total assets
5,149,262

 
4,918,796

 
5,032,186

 
5,613,089

 
5,881,190

Long-term debt, less current portion
3,079,349

 
2,749,452

 
2,655,553

 
2,124,582

 
1,928,071

Total partners’ equity
1,609,844

 
1,716,210

 
1,903,794

 
2,584,995

 
2,864,335


(a)
The losses for the years ended December 31, 2013 and 2012 are mainly due to goodwill impairment and other asset impairment charges.
(b)
The decline in revenues is due to reductions in our fuels marketing segment mainly resulting from disposals and lower commodity prices.

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ITEM 7.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following review of our results of operations and financial condition should be read in conjunction with Items 1., 1A. and 2. “Business, Risk Factors and Properties” and Item 8. “Financial Statements and Supplementary Data” included in this report.
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION
This Form 10-K contains certain estimates, predictions, projections, assumptions and other forward-looking statements that involve various risks and uncertainties. While these forward-looking statements, and any assumptions upon which they are based, are made in good faith and reflect our current judgment regarding the direction of our business, actual results will almost always vary, sometimes materially, from any estimates, predictions, projections, assumptions or other future performance suggested in this report. These forward-looking statements can generally be identified by the words “anticipates,” “believes,” “expects,” “plans,” “intends,” “estimates,” “forecasts,” “budgets,” “projects,” “will,” “could,” “should,” “may” and similar expressions. These statements reflect our current views with regard to future events and are subject to various risks, uncertainties and assumptions. Please read Item 1A. “Risk Factors” for a discussion of certain of those risks, uncertainties and assumptions.

If one or more of these risks or uncertainties materialize, or if the underlying assumptions prove incorrect, our actual results may vary materially from those described in any forward-looking statement. Other unknown or unpredictable factors could also have material adverse effects on our future results. Readers are cautioned not to place undue reliance on this forward-looking information, which is as of the date of this Form 10-K. We do not intend to update these statements unless we are required by the securities laws to do so, and we undertake no obligation to publicly release the result of any revisions to any such forward-looking statements that may be made to reflect events or circumstances after the date of this report or to reflect the occurrence of unanticipated events.
OVERVIEW
NuStar Energy L.P. (NuStar Energy) (NYSE: NS) is engaged in the transportation of petroleum products and anhydrous ammonia, the terminalling and storage of petroleum products and the marketing of petroleum products. Unless otherwise indicated, the terms “NuStar Energy,” “the Partnership,” “we,” “our” and “us” are used in this report to refer to NuStar Energy, to one or more of our consolidated subsidiaries or to all of them taken as a whole. NuStar GP Holdings, LLC (NuStar GP Holdings) (NYSE: NSH) owns our general partner, Riverwalk Logistics, L.P., and owns a 14.9% total interest in us as of December 31, 2015. Our Management’s Discussion and Analysis of Financial Condition and Results of Operations is presented in seven sections:
Overview
Results of Operations
Trends and Outlook
Liquidity and Capital Resources
Related Party Transactions
Critical Accounting Policies
New Accounting Pronouncements
Acquisitions and Dispositions
Linden Acquisition. On January 2, 2015, we acquired full ownership of ST Linden Terminal, LLC (Linden), which owns a refined products terminal in Linden, NJ with 4.3 million barrels of storage capacity (the Linden Acquisition). Linden is located on a 44-acre facility that provides deep-water terminalling capabilities in the New York Harbor and primarily stores petroleum products, including gasoline, jet fuel and fuel oils. Prior to the Linden Acquisition, Linden operated as a joint venture between us and Linden Holding Corp., with each party owning 50%.

In connection with the Linden Acquisition, we ceased applying the equity method of accounting and consolidated Linden, which is included in our storage segment. The consolidated statements of income include the results of operations for Linden commencing on January 2, 2015. On the acquisition date, we remeasured our existing 50% equity investment in Linden to its fair value of $128.0 million and we recognized a gain of $56.3 million in “Other income, net” in the consolidated statements of income for the year ended December 31, 2015. Please refer to Note 4 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for a discussion of the Linden Acquisition.

Discontinued Operations. In 2014, we divested our terminals in Mobile, AL, Wilmington, NC and Dumfries, VA and our 75% interest in our facility in Mersin, Turkey. We presented the results of operations for those facilities as discontinued operations,

34


including an impairment loss of $102.5 million for the year ended December 31, 2013. On January 1, 2013, we sold our fuels refinery in San Antonio, Texas and related assets for approximately $117.0 million (the San Antonio Refinery Sale) and recognized a gain of $9.3 million.

2014 Asphalt Sale. On February 26, 2014, we sold our remaining 50% ownership interest in NuStar Asphalt LLC to Lindsay Goldberg LLC, a private investment firm (the 2014 Asphalt Sale). Effective February 27, 2014, NuStar Asphalt LLC changed its name to Axeon Specialty Products LLC (Axeon). As a result of the 2014 Asphalt Sale, we ceased applying the equity method of accounting, and we ceased reporting transactions between us and Axeon as related party transactions in our consolidated financial statements. Upon completion of the 2014 Asphalt Sale, the parties agreed to: (i) convert the $250.0 million unsecured revolving credit facility provided by us to Axeon (the NuStar JV Facility) from a revolving credit agreement into a $190.0 million term loan (the Axeon Term Loan); (ii) terminate the terminal services agreements with respect to our terminals in Rosario, NM, Catoosa, OK and Houston, TX; (iii) amend the terminal services agreements for our terminals in Baltimore, MD and Jacksonville, FL; and (iv) transfer ownership of both the Wilmington, NC and Dumfries, VA terminals to Axeon. Please refer to Note 10 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for additional information on the Axeon Term Loan.
2013 Goodwill Impairment
In the fourth quarter of 2013, we recognized a $304.5 million goodwill impairment loss in the storage segment, which represents the write-down of the carrying value of goodwill associated with our St. Eustatius and Point Tupper terminal operations. Please refer to Note 11 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for a discussion of the goodwill impairment loss.
Operations
We conduct our operations through our subsidiaries, primarily NuStar Logistics, L.P. (NuStar Logistics) and NuStar Pipeline Operating Partnership L.P. (NuPOP). Our operations are divided into three reportable business segments: pipeline, storage and fuels marketing. For a more detailed description of our segments, please refer to “Segments” under Item 1. “Business.”

Pipeline. We own 3,140 miles of refined product pipelines pipelines and 1,200 miles of crude oil pipelines, as well as approximately 4.0 million barrels of storage capacity, which comprise our Central West System. In addition, we own 2,360 miles of refined product pipelines, consisting of the East and North Pipelines, and a 2,000 mile ammonia pipeline, which comprise our Central East System. The East and North Pipelines have storage capacity of approximately 6.4 million barrels.

Storage. We own terminals and storage facilities in the United States, Canada, Mexico, the Netherlands, including St. Eustatius in the Caribbean, and the United Kingdom (UK), with approximately 82.9 million barrels of storage capacity.

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

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

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RESULTS OF OPERATIONS
Year Ended December 31, 2015 Compared to Year Ended December 31, 2014
Financial Highlights
(Thousands of Dollars, Except Unit and Per Unit Data)
 
Year Ended December 31,
 
 
 
2015
 
2014
 
Change
Statement of Income Data:
 
 
 
Revenues:
 
 
 
 
 
Service revenues
$
1,114,153

 
$
1,026,446

 
$
87,707

Product sales
969,887

 
2,048,672

 
(1,078,785
)
Total revenues
2,084,040

 
3,075,118

 
(991,078
)
 
 
 
 
 
 
Costs and expenses:
 
 
 
 
 
Cost of product sales
907,574

 
1,967,528

 
(1,059,954
)
Operating expenses
473,031

 
472,925

 
106

General and administrative expenses
102,521

 
96,056

 
6,465

Depreciation and amortization expense
210,210

 
191,708

 
18,502

Total costs and expenses
1,693,336

 
2,728,217

 
(1,034,881
)
 
 
 
 
 
 
Operating income
390,704

 
346,901

 
43,803

Equity in earnings of joint ventures

 
4,796

 
(4,796
)
Interest expense, net
(131,868
)
 
(132,281
)
 
413

Interest income from related party

 
1,055

 
(1,055
)
Other income, net
61,822

 
4,499

 
57,323

Income from continuing operations before income tax expense
320,658

 
224,970

 
95,688

Income tax expense
14,712

 
10,801

 
3,911

Income from continuing operations
305,946

 
214,169

 
91,777

Income (loss) from discontinued operations, net of tax
774

 
(3,791
)
 
4,565

Net income
$
306,720

 
$
210,378

 
$
96,342

Net income (loss) per unit applicable to limited partners:
 
 
 
 


Continuing operations
$
3.29

 
$
2.14

 
$
1.15

Discontinued operations
0.01

 
(0.04
)
 
0.05

Total
$
3.30

 
$
2.10

 
$
1.20

Weighted-average limited partner units outstanding
77,886,078

 
77,886,078

 



36


Segment Operating Highlights
(Thousands of Dollars, Except Barrel/Day Information)
 
 
Year Ended December 31,
 
 
 
2015
 
2014
 
Change
Pipeline:
 
 
 
 
 
Refined products pipelines throughput (barrels/day)
522,146

 
510,737

 
11,409

Crude oil pipelines throughput (barrels/day)
471,632

 
437,757

 
33,875

Total throughput (barrels/day)
993,778

 
948,494

 
45,284

Throughput revenues
$
508,522

 
$
477,030

 
$
31,492

Operating expenses
153,222

 
154,106

 
(884
)
Depreciation and amortization expense
84,951

 
77,691

 
7,260

Segment operating income
$
270,349

 
$
245,233

 
$
25,116

 
 
 
 
 
 
Storage:
 
 
 
 
 
Throughput (barrels/day)
899,606

 
887,607

 
11,999

Throughput revenues
$
130,127

 
$
123,051

 
$
7,076

Storage lease revenues
494,781

 
441,455

 
53,326

Total revenues
624,908

 
564,506

 
60,402

Operating expenses
290,322

 
277,554

 
12,768

Depreciation and amortization expense
116,768

 
103,848

 
12,920

Segment operating income
$
217,818

 
$
183,104

 
$
34,714

 
 
 
 
 
 
Fuels Marketing:
 
 
 
 
 
Product sales and other revenue
$
976,216

 
$
2,060,017

 
$
(1,083,801
)
Cost of product sales
922,906

 
1,983,339

 
(1,060,433
)
Gross margin
53,310

 
76,678

 
(23,368
)
Operating expenses
39,803

 
51,857

 
(12,054
)
Depreciation and amortization expense

 
16

 
(16
)
Segment operating income
$
13,507

 
$
24,805

 
$
(11,298
)
 
 
 
 
 
 
Consolidation and Intersegment Eliminations:
 
 
 
 
 
Revenues
$
(25,606
)
 
$
(26,435
)
 
$
829

Cost of product sales
(15,332
)
 
(15,811
)
 
479

Operating expenses
(10,316
)
 
(10,592
)
 
276

Total
$
42

 
$
(32
)
 
$
74

 
 
 
 
 
 
Consolidated Information:
 
 
 
 
 
Revenues
$
2,084,040

 
$
3,075,118

 
$
(991,078
)
Cost of product sales
907,574

 
1,967,528

 
(1,059,954
)
Operating expenses
473,031

 
472,925

 
106

Depreciation and amortization expense
201,719

 
181,555

 
20,164

Segment operating income
501,716

 
453,110

 
48,606

General and administrative expenses
102,521

 
96,056

 
6,465

Other depreciation and amortization expense
8,491

 
10,153

 
(1,662
)
Consolidated operating income
$
390,704

 
$
346,901

 
$
43,803


37


Annual Highlights
Net income increased $96.3 million for the year ended December 31, 2015, compared to the year ended December 31, 2014, primarily due to an increase of $48.6 million in segment operating income, resulting mainly from improvements in the pipeline and storage segments, and a $56.3 million gain associated with the Linden Acquisition.
Pipeline
Revenues increased $31.5 million and throughputs increased 45,284 barrels per day for the year ended December 31, 2015, compared to the year ended December 31, 2014, primarily due to:
an increase in revenues of $17.0 million and an increase in throughputs of 34,564 barrels per day on our Eagle Ford System, primarily resulting from completion of expansion projects that increased our overall capacity;
an increase in revenues of $11.9 million and an increase in throughputs of 11,676 barrels per day as a result of increased production in 2015 and a turnaround during the first quarter of 2014 at the refinery served by our McKee systems; and
an increase in revenues of $3.6 million, despite throughputs that remained flat, on our Ammonia Pipeline as a result of increased long-haul deliveries and the annual index adjustment in July 2015.
The increases in pipeline revenues and throughputs were partially offset by a decrease in revenues of $4.4 million and a decrease in throughputs of 2,811 barrels per day due to turnarounds at refineries served by the East Pipeline and unfavorable pricing differentials in markets served by the East Pipeline.
Operating expenses decreased $0.9 million, despite an increase in throughputs, for the year ended December 31, 2015, compared to the year ended December 31, 2014, primarily due to the completion of a capital project to install permanent power along our South Texas Crude System reducing power and rental costs.
Depreciation and amortization expense increased $7.3 million for the year ended December 31, 2015, compared to the year ended December 31, 2014, mainly due to the completion of expansion projects.

Storage
Throughput revenues increased $7.1 million and throughputs increased 11,999 barrels per day for the year ended December 31, 2015, compared to the year ended December 31, 2014, primarily due to:
an increase in revenues of $2.5 million and an increase in throughputs of 19,853 barrels per day at our Corpus Christi North Beach terminal due to an increase in Eagle Ford Shale crude oil being shipped to Corpus Christi and the completion of related expansion projects;
an increase in revenues of $2.3 million and an increase in throughputs of 6,263 barrels per day at our terminals in Edinburg, Harlingen and Paulsboro, mainly due to increased demand; and
an increase in revenues of $2.0 million and an increase in throughputs of 12,558 barrels per day as a result of a turnaround during the first quarter of 2014 at the refinery served by our Benicia crude oil refinery tanks.
The increases in storage throughput revenues and throughputs were partially offset by a decrease in revenues of $0.9 million and a decrease in throughputs of 21,107 barrels per day as a result of a turnaround during the first quarter of 2015 at the refinery served by our Texas City crude oil refinery tanks.
Storage lease revenues increased $53.3 million for the year ended December 31, 2015, compared to the year ended December 31, 2014, primarily due to:
an increase of $41.5 million as a result of the Linden Acquisition;
an increase of $11.8 million at our domestic terminal facilities, mainly due to storage rate escalations and new customers at our Texas City, West Coast and Asphalt Terminals;
an increase of $9.9 million at our St. Eustatius terminal facility, mainly due to higher demand for storage and increased throughput and related handling fees; and
an increase of $5.0 million at our Point Tupper terminal facility, due to new customers and rate escalations, as well as increased throughput and related handling fees.

The increases in storage lease revenues were partially offset by:
a decrease of $8.4 million at our Amsterdam terminal facility, primarily due to the effect of foreign exchange rates; and
a decrease of $3.5 million at our St. James terminal facility, mainly due to reduced volumes delivered to one of our unit train offloading facilities, partially offset by increased revenues from storage rate escalations.

38


Operating expenses increased $12.8 million for the year ended December 31, 2015, compared to the year ended December 31, 2014, primarily due to:
an increase of $12.6 million as a result of the Linden Acquisition; and
an increase of $4.6 million in regulatory and maintenance expenses, mainly at our St. James and St. Eustatius terminal facilities.

The increases in storage operating expenses were partially offset by a decrease of $3.4 million in contract services, mainly at our St. James terminal facility due to a reduction in dock and rail labor costs.
Depreciation and amortization expense increased $12.9 million for the year ended December 31, 2015, compared to the year ended December 31, 2014, mainly due to the assets associated with the Linden Acquisition.
Fuels Marketing
Segment operating income decreased $11.3 million for the year ended December 31, 2015, compared to the year ended December 31, 2014, primarily due to lower product margins from our bunker fuel operations and refined product sales. The lower product margins were partially offset by a reduction in operating expenses due to decreased marine vessel costs and lower bad debt expense in 2015.
Consolidation and Intersegment Eliminations
Revenue and operating expense eliminations primarily relate to storage fees charged to the fuels marketing segment by the storage segment. Cost of product sales eliminations represent expenses charged to the fuels marketing segment for costs associated with inventory that are expensed once the inventory is sold.
General
General and administrative expenses increased $6.5 million for the year ended December 31, 2015, compared to the year ended December 31, 2014, primarily due to:
a $3.6 million increase in outside legal and other professional fees;
a $3.5 million increase in salaries and wages mainly due to increased headcount and higher employee benefit costs; and
a $3.1 million increase as a result of the termination of a services agreement between Axeon and NuStar GP, LLC in June 2014, under which Axeon reimbursed us for certain corporate support services.
The increases in general and administrative expenses were partially offset by a decrease of $4.5 million in compensation expense associated with our long-term incentive plans, which fluctuates with our unit price.
Equity in earnings of joint ventures for the year ended December 31, 2014 primarily relates to our equity investment in Linden prior to the Linden Acquisition.
Interest expense, net decreased $0.4 million for the year ended December 31, 2015, compared to the year ended December 31, 2014, mainly due to increased interest income from the Axeon Term Loan. The decrease in interest expense, net was partially offset by increased interest costs associated with higher borrowings under our revolving credit agreement.
Other income, net increased by $57.3 million for the year ended December 31, 2015, compared to the year ended December 31, 2014, mainly due to the $56.3 million gain associated with the Linden Acquisition.
Income tax expense increased $3.9 million for the year ended December 31, 2015, compared to the year ended December 31, 2014, mainly due to estimated withholding taxes on our planned repatriation of cash held by foreign subsidiaries in 2016. Please refer to Note 24 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for a discussion on income taxes.
For the year ended December 31, 2015, we recorded income from discontinued operations of $0.8 million, compared to a loss from discontinued operations of $3.8 million for the year ended December 31, 2014. Discontinued operations include the results of operations of certain storage assets that were divested in 2014 and the first quarter of 2015.

39


Year Ended December 31, 2014 Compared to Year Ended December 31, 2013
Financial Highlights
(Thousands of Dollars, Except Unit and Per Unit Data)
 
Year Ended December 31,
 
 
 
2014
 
2013
 
Change
Statement of Income Data:
 
Revenues:
 
 
 
 
 
Service revenues
$
1,026,446

 
$
938,138

 
$
88,308

Product sales
2,048,672

 
2,525,594

 
(476,922
)
Total revenues
3,075,118

 
3,463,732

 
(388,614
)
 
 
 
 
 
 
Costs and expenses:
 
 
 
 
 
Cost of product sales
1,967,528

 
2,453,997

 
(486,469
)
Operating expenses
472,925

 
454,396

 
18,529

General and administrative expenses
96,056

 
91,086

 
4,970

Depreciation and amortization expense
191,708

 
178,921

 
12,787

Goodwill impairment loss

 
304,453

 
(304,453
)
Total costs and expenses
2,728,217

 
3,482,853

 
(754,636
)
 
 
 
 
 
 
Operating income (loss)
346,901

 
(19,121
)
 
366,022

Equity in earnings (loss) of joint ventures
4,796

 
(39,970
)
 
44,766

Interest expense, net
(132,281
)
 
(127,119
)
 
(5,162
)
Interest income from related party
1,055

 
6,113

 
(5,058
)
Other income, net
4,499

 
7,341

 
(2,842
)
Income (loss) from continuing operations before income tax expense
224,970

 
(172,756
)
 
397,726

Income tax expense
10,801

 
12,753

 
(1,952
)
Income (loss) from continuing operations
214,169

 
(185,509
)
 
399,678

Loss from discontinued operations, net of tax
(3,791
)
 
(99,162
)
 
95,371

Net income (loss)
$
210,378

 
$
(284,671
)
 
$
495,049

Net income (loss) per unit applicable to limited partners:
 
 
 
 


Continuing operations
$
2.14

 
$
(2.89
)
 
$
5.03

Discontinued operations
(0.04
)
 
(1.11
)
 
1.07

Total
$
2.10

 
$
(4.00
)
 
$
6.10

Weighted-average limited partner units outstanding
77,886,078

 
77,886,078

 




40


Segment Operating Highlights
(Thousands of Dollars, Except Barrel/Day Information)
 
Year Ended December 31,
 
 
 
2014
 
2013
 
Change
Pipeline:
 
 
 
 
 
Refined products pipelines throughput (barrels/day)
510,737

 
487,021

 
23,716

Crude oil pipelines throughput (barrels/day)
437,757

 
365,749

 
72,008

Total throughput (barrels/day)
948,494

 
852,770

 
95,724

Throughput revenues
$
477,030

 
$
411,529

 
$
65,501

Operating expenses
154,106

 
134,365

 
19,741

Depreciation and amortization expense
77,691

 
68,871

 
8,820

Segment operating income
$
245,233

 
$
208,293

 
$
36,940

 
 
 
 
 
 
Storage:
 
 
 
 
 
Throughput (barrels/day)
887,607

 
781,213

 
106,394

Throughput revenues
$
123,051

 
$
104,553

 
$
18,498

Storage lease revenues
441,455

 
451,996

 
(10,541
)
Total revenues
564,506

 
556,549

 
7,957

Operating expenses
277,554

 
279,712

 
(2,158
)
Depreciation and amortization expense
103,848

 
99,868

 
3,980

Goodwill impairment loss

 
304,453

 
(304,453
)
Segment operating income (loss)
$
183,104

 
$
(127,484
)
 
$
310,588

 
 
 
 
 
 
Fuels Marketing:
 
 
 
 
 
Product sales and other revenue
$
2,060,017

 
$
2,527,698

 
$
(467,681
)
Cost of product sales
1,983,339

 
2,474,612

 
(491,273
)
Gross margin
76,678

 
53,086

 
23,592

Operating expenses
51,857

 
53,185

 
(1,328
)
Depreciation and amortization expense
16

 
27

 
(11
)
Segment operating income (loss)
$
24,805

 
$
(126
)
 
$
24,931

 
 
 
 
 
 
Consolidation and Intersegment Eliminations:
 
 
 
 
 
Revenues
$
(26,435
)
 
$
(32,044
)
 
$
5,609

Cost of product sales
(15,811
)
 
(20,615
)
 
4,804

Operating expenses
(10,592
)
 
(12,866
)
 
2,274

Total
$
(32
)
 
$
1,437

 
$
(1,469
)
 
 
 
 
 
 
Consolidated Information:
 
 
 
 
 
Revenues
$
3,075,118

 
$
3,463,732

 
$
(388,614
)
Cost of product sales
1,967,528

 
2,453,997

 
(486,469
)
Operating expenses
472,925

 
454,396

 
18,529

Depreciation and amortization expense
181,555

 
168,766

 
12,789

Goodwill impairment loss

 
304,453

 
(304,453
)
Segment operating income
453,110

 
82,120

 
370,990

General and administrative expenses
96,056

 
91,086

 
4,970

Other depreciation and amortization expense
10,153

 
10,155

 
(2
)
Consolidated operating income (loss)
$
346,901

 
$
(19,121
)
 
$
366,022


41


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

Loss from discontinued operations decreased $95.4 million for the year ended December 31, 2014, compared to the prior year, mainly due to an asset impairment charge of $102.5 million in 2013 associated with certain storage assets. Therefore, we reported net income of $210.4 million for the year ended December 31, 2014, compared to a loss of $284.7 million for the year ended December 31, 2013.
Pipeline
Revenues increased $65.5 million and throughputs increased 95,724 barrels per day for the year ended December 31, 2014, compared to the year ended December 31, 2013, primarily due to:
an increase in revenues of $39.3 million and an increase in throughputs of 61,947 barrels per day on our Eagle Ford System, primarily resulting from continued growth in the region and the completion of expansion projects in 2014 and the third quarter of 2013 that increased our overall capacity;
an increase in revenues of $9.1 million and an increase in throughputs of 26,369 barrels per day on our McKee systems mainly due to increased production by the McKee refinery in 2014;
an increase in revenues of $7.1 million and an increase in throughputs of 2,341 barrels per day on the East Pipeline due to higher average tariffs resulting from the annual index adjustments and increased long-haul deliveries, as well as higher demand due to favorable weather conditions during 2014 compared to last year; and
an increase in revenues of $4.9 million and an increase in throughputs of 3,140 barrels per day on the Ammonia Pipeline mainly due to favorable weather conditions during 2014 compared to last year.
Operating expenses increased $19.7 million for the year ended December 31, 2014, compared to the year ended December 31, 2013, primarily due to:
an $8.0 million gain in 2013 for the reduction of the contingent consideration liability recorded in association with our acquisition of certain assets from TexStar Midstream Services, LP;
an increase of $6.3 million in maintenance and regulatory expenses, mainly associated with our East Pipeline and Ammonia Pipeline; and
an increase of $5.0 million in power costs, mainly due to the increase in throughputs on our Eagle Ford System and the East Pipeline.
Depreciation and amortization expense increased $8.8 million for the year ended December 31, 2014, compared to the year ended December 31, 2013, mainly due to the completion of various projects that serve Eagle Ford Shale production.

Storage
Throughput revenues increased $18.5 million and throughputs increased 106,394 barrels per day for the year ended December 31, 2014, compared to the year ended December 31, 2013, primarily due to:
an increase in revenues of $12.5 million and an increase in throughputs of 56,908 barrels per day at our Corpus Christi North Beach terminal due to an increase in Eagle Ford Shale crude oil being shipped to Corpus Christi and the completion of a new dock in the first quarter of 2014;
an increase in revenues of $3.0 million and an increase in throughputs of 37,822 barrels per day as a result of turnarounds and operational issues during the first quarter of 2013 at the refineries served by our Corpus Christi and Texas City crude oil refinery storage tanks; and
an increase in revenues of $1.7 million and an increase in throughputs of 7,727 barrels per day at our McKee system terminals due to higher demand in those markets.
Storage lease revenues decreased $10.5 million for the year ended December 31, 2014, compared to the year ended December 31, 2013, primarily due to:
a decrease of $15.8 million at various domestic terminals, mainly as a result of reduced demand in several markets, resulting in lower throughputs and storage fees;
a decrease of $1.6 million at our Point Tupper, Canada terminal facility, mainly due to lower throughput and related handling fees; and

42


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

The declines in storage lease revenues were partially offset by an increase of $5.5 million at our UK terminal facilities, mainly due to the effect of foreign exchange rates and increased throughput and related handling fees. In addition, our asphalt terminals increased $3.6 million due to renegotiating the storage contracts.
Operating expenses decreased $2.2 million for the year ended December 31, 2014, compared to the year ended December 31, 2013, primarily due to reduced maintenance and regulatory expenses of $2.8 million, mainly at our West Coast and Gulf Coast terminals.
Depreciation and amortization expense increased $4.0 million for the year ended December 31, 2014, compared to the year ended December 31, 2013, primarily due to the completion of a unit train offloading facility in the fourth quarter of 2013 at our St. James terminal.
Fuels Marketing
Segment operating income increased $24.9 million for the year ended December 31, 2014, compared to the year ended December 31, 2013, primarily due to higher earnings of $36.2 million from our bunker fuel operations, which benefitted from improved product margins and decreased vessel lease and fuel costs. The increase in segment operating income from our bunker fuel operations was partially offset by lower earnings of $7.6 million in fuel oil trading, mainly resulting from lower product margins due to a lack of supply for blend components. In addition, operating expense in our bunker fuel and fuel oil trading operations increased by $7.5 million related to an allowance for doubtful accounts recorded in the fourth quarter of 2014. For the year ended December 31, 2014, we recognized a $3.8 million lower of cost or market adjustment, mainly impacting fuel oil trading operations.
Consolidation and Intersegment Eliminations
Revenue and operating expense eliminations primarily relate to storage fees charged to the fuels marketing segment by the storage segment. Cost of product sales eliminations represent expenses charged to the fuels marketing segment for costs associated with inventory that are expensed once the inventory is sold.
General
General and administrative expenses increased $5.0 million for the year ended December 31, 2014, compared to the year ended December 31, 2013, primarily as a result of higher compensation expense associated with satisfying obligations under our long-term incentive plans, which fluctuates with our unit price, and the termination of a services agreement between Axeon and NuStar GP, LLC in June 2014, under which Axeon reimbursed us for certain corporate support services. These increases were partially offset by reduced employee benefit costs.
We recorded equity in earnings of joint ventures of $4.8 million for the year ended December 31, 2014, compared to a loss in equity of joint ventures of $40.0 million for the year ended December 31, 2013, primarily due to losses from our investment in Axeon for the year ended December 31, 2013.
Interest expense, net increased $5.2 million for the year ended December 31, 2014, compared to the year ended December 31, 2013, mainly due to the issuance of the $300.0 million of 6.75% senior notes in August 2013. Interest income from related party represents the interest earned on the NuStar JV Facility prior to the 2014 Asphalt Sale. Interest income from the Axeon Term Loan after the 2014 Asphalt Sale is not a related party transaction and, therefore, is reported in “Interest expense, net” on the consolidated statements of income.
Other income, net decreased by $2.8 million for the year ended December 31, 2014, compared to the year ended December 31, 2013, mainly due to changes in foreign exchange rates related to our foreign subsidiaries.
Income tax expense decreased $2.0 million for the year ended December 31, 2014, compared to the year ended December 31, 2013, mainly due to a decrease in the margin tax in Texas.
The loss from discontinued operations decreased $95.4 million for the year ended December 31, 2014, compared to the year ended December 31, 2013, mainly due to the asset impairment charges of $102.5 million associated with certain storage terminals, partially offset by a gain of $9.3 million related to the San Antonio Refinery Sale.


43


TRENDS AND OUTLOOK
Current Market Conditions
During 2015 and early 2016, the price of crude oil has continued to decline, reaching lows not seen in 13 years. The sustained period of low prices has forced most crude oil producers to reduce their capital spending and drilling activity and narrow their focus to assets in the most cost-advantaged regions. On the other hand, refiners generally have benefitted from lower crude prices, particularly to the extent the lower feedstock price has been coupled with higher demand for certain refined products in some regional markets.

We believe a number of factors serve to minimize our direct exposure to the risks associated with fluctuating commodity prices. We own assets and offer services in regional markets across the United States and around the world, and we are not dependent on the regions or markets that have been hardest hit by depressed crude oil prices, the domestic shale play regions: in 2015, revenue from our Eagle Ford pipeline and storage assets constituted less than 16% of our total pipeline and storage segment revenue. In our view, the fact that our pipeline segment and our storage segment are approximately equal serves to balance the impact of market fluctuations. High crude prices have tended to correlate with high pipeline demand, while low prices have tended to correlate with high storage demand. In addition, many of our commercial contracts are long-term, take-or-pay arrangements for committed storage or throughput capacity, which mitigates the short-term impact of low crude oil prices on our results of operations. However, a protracted period of depressed crude oil prices and overall economic downturn could have a negative impact on our results of operations.

Regardless of insulation from or the lack of exposure to commodity prices, continued low crude oil prices seem to be having a direct, negative impact on the unit price of many master limited partnerships, including our own. Unfavorable market conditions have increased the cost of financing capital spending through the public debt and equity markets, and, as a result, we have reduced our overall capital spending budget for 2016 and have prioritized our capital projects to minimize the need to access the public capital markets.

Pipeline Segment
We expect our pipeline segment to benefit from higher forecasted volumes on our refined product pipelines. However, we expect these increases to be more than offset by reduced throughput volumes on our Eagle Ford crude pipelines due to lower domestic shale production, resulting in lower earnings in the first quarter and full-year 2016 as compared to the comparable periods of 2015.

Storage Segment
We expect storage segment earnings for the first quarter 2016 to be slightly higher than the first quarter 2015 mainly due to favorable storage contract renewals at several of our terminal facilities. However, we expect that the reduced throughput on our Eagle Ford crude pipelines, as referred to and with regard to our Pipeline Segment, will also result in lower throughputs in the first quarter at our Corpus Christi North Beach terminal.

We expect the full-year earnings for 2016 to benefit from favorable storage contract renewals and higher forecasted throughput volumes at several of our terminal facilities. However, we expect these increases to be more than offset by lower throughputs at our Corpus Christi North Beach terminal and overall lower revenue from some of our foreign terminal facilities, resulting in lower earnings in the full-year 2016 as compared to 2015.

Fuels Marketing Segment
We expect first quarter 2016 results for our fuels marketing segment to be lower than the first quarter 2015 and full-year 2016 results in this segment to be comparable or higher than 2015. However, earnings in this segment, as in any margin-based business, are subject to many factors that can increase or reduce margins, which may cause the segment’s actual results to vary significantly from our forecast.

Our outlook for the partnership, both overall and for any of our segments, may change, as we base our expectations on our continuing evaluation of a number of factors, many of which are outside our control, including the price of crude oil, the state of the economy and the capital markets, changes to refinery maintenance schedules and unplanned refinery downtime, supply of and demand for crude oil, refined products and anhydrous ammonia, demand for our transportation and storage services and changes in laws or regulations affecting our assets.



44


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

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

For the years ended December 31, 2015, 2014 and 2013, our cash flow from operations exceeded our distributions to our partners and our reliability capital expenditures. For 2016, we currently expect to continue to produce cash from operations in excess of our distribution and reliability capital expenditures.

As described above, we and many other master limited partnerships have experienced significant declines in our unit prices, and current market conditions have increased the cost of financing capital spending through public debt and equity offerings. As a result, we have prioritized our capital budget for 2016 to minimize our need to access the public debt and equity markets in 2016, and we intend to first utilize other sources of funding, including cash on hand and borrowings under our revolver, for our strategic capital spending, before availing ourselves of cost-prohibitive public debt or equity financing. Our current 2016 strategic capital program includes projects that we can reduce in scope or forego entirely, depending on our evaluation of changing market conditions and our analysis of each project’s relative expected returns, strategic importance and overall capital requirements.

Cash Flows for the Years Ended December 31, 2015, 2014 and 2013
The following table summarizes our cash flows from operating, investing and financing activities:
 
Year Ended December 31,
 
2015
 
2014
 
2013
 
(Thousands of Dollars)
Net cash provided by (used in):
 
 
 
 
 
Operating activities
$
524,937

 
$
518,523

 
$
485,219

Investing activities
(452,029
)
 
(340,231
)
 
(310,961
)
Financing activities
(29,229
)
 
(188,185
)
 
(149,350
)
Effect of foreign exchange rate changes on cash
(12,729
)
 
(2,938
)
 
(7,767
)
Net increase (decrease) in cash and cash equivalents
$
30,950

 
$
(12,831
)
 
$
17,141

Net cash provided by operating activities remained relatively flat for the year ended December 31, 2015 compared to the year ended December 31, 2014, despite higher net income in 2015. Net income for the year ended December 31, 2015 includes the $56.3 million non-cash gain associated with the Linden Acquisition. In addition, changes in working capital provided cash flow of $50.6 million for the year ended December 31, 2015 compared to $82.4 million for the year ended December 31, 2014. Please refer to the Working Capital Requirements section below for a discussion of the changes in working capital.
For the year ended December 31, 2015, the majority of net cash provided by operating activities was used to fund our distributions to unitholders and our general partner in the aggregate amount of $392.2 million and to fund $40.0 million of

45


reliability capital expenditures. The proceeds from debt borrowings, net of repayments, combined a portion of net cash provided by operating activities, were used to fund our strategic capital expenditures, including the Linden Acquisition.
For the year ended December 31, 2014, the majority of net cash provided by operating activities was used to fund our distributions to unitholders and our general partner in the aggregate amount of $392.2 million and to fund $28.6 million of reliability capital expenditures. The proceeds from debt borrowings, net of repayments, combined with net cash provided by operating activities and proceeds from the sales of assets, were used to fund our strategic capital expenditures primarily related to our pipeline and storage segments and advances to Axeon under the NuStar JV Facility.
For the year ended December 31, 2013, net cash provided by operating activities exceeded our distribution requirements and reliability capital expenditures. Proceeds from the San Antonio Refinery Sale and proceeds from long-term debt borrowings, net of repayments, combined with net cash provided by operating activities, were used to fund our strategic capital expenditures and advances to Axeon under the NuStar JV Facility.
Revolving Credit Agreement
NuStar Logistics is a party to a $1.5 billion five-year revolving credit agreement (Revolving Credit Agreement), which matures on October 29, 2019. The Revolving Credit Agreement includes an option allowing NuStar Logistics to request an aggregate increase in the commitments from the lenders of up to $250.0 million (after which increase the aggregate commitment from all lenders shall not exceed $1.75 billion). The Revolving Credit Agreement also includes the ability to borrow up to the equivalent of $250.0 million in Euros and up to the equivalent of $250.0 million in British Pounds Sterling. Obligations under the Revolving Credit Agreement are guaranteed by NuStar Energy and NuPOP.
The Revolving Credit Agreement contains customary restrictive covenants, such as limitations on indebtedness, liens, mergers, asset transfers and certain investing activities. In addition, the Revolving Credit Agreement requires us to maintain, as of the end of each rolling period of four consecutive fiscal quarters, a consolidated debt coverage ratio (consolidated debt to consolidated EBITDA, each as defined in the Revolving Credit Agreement) not to exceed 5.00-to-1.00. If we consummate an acquisition for an aggregate net consideration of at least $50.0 million, the maximum consolidated debt coverage ratio will increase to 5.50-to-1.00 for two rolling periods. The requirement not to exceed a maximum consolidated debt coverage ratio may limit the amount we can borrow under the Revolving Credit Agreement to an amount less than the total amount available for borrowing. As of December 31, 2015, our consolidated debt coverage ratio was 4.5x, and we had $587.3 million available for borrowing.
Letters of credit issued under our Revolving Credit Agreement totaled $30.1 million as of December 31, 2015. Letters of credit are limited to $750.0 million (including up to the equivalent of $25.0 million in Euros and up to the equivalent of $25.0 million in British Pounds Sterling) and also restrict the amount we can borrow under the Revolving Credit Agreement.
Please refer to Note 13 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for a discussion of our debt agreements.

Other Sources of Liquidity
Other sources of liquidity consist of the following:
$365.4 million in revenue bonds pursuant to the Gulf Opportunity Zone Act of 2005 (the Gulf Opportunity Zone Revenue Bonds), with $54.8 million remaining in trust as of December 31, 2015, supported by $370.2 million letters of credit issued by individual banks that do no restrict the amount we can borrow under our Revolving Credit Agreement;
a $125.0 million receivables financing agreement between NuStar Energy, NuStar Finance LLC and third-party lenders (the Receivables Financing Agreement), with the amount available for borrowing based on the availability of eligible receivables and other customary factors and conditions; and
two short-term line of credit agreements with an aggregate uncommitted borrowing capacity of up to $105.0 million with $84.0 million outstanding as of December 31, 2015.

Please refer to Note 13 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for a more detailed discussion of these debt agreements.

LOC Agreement
NuStar Logistics is a party to a $100.0 million uncommitted letter of credit agreement, which provides for standby letters of credit or guarantees with a term of up to one year (LOC Agreement). Any letters of credit issued under the LOC Agreement do not reduce availability under our Revolving Credit Agreement. As of December 31, 2015, letters of credit issued under the LOC Agreement totaled $14.7 million. The interest rate and maturity vary and are determined at the time of borrowing.

46


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

On January 22, 2013, NuStar Logistics issued $402.5 million of 7.625% fixed-to-floating rate subordinated notes due January 15, 2043 (the Subordinated Notes), including the underwriters’ option to purchase up to an additional $52.5 million principal amount of the notes, which was exercised in full. We received net proceeds of approximately $390.9 million, which we used for general partnership purposes, including repayment of outstanding borrowings under our Revolving Credit Agreement. The Subordinated Notes bear interest at a fixed annual rate of 7.625%, payable quarterly in arrears beginning on April 15, 2013 and ending on January 15, 2018. Thereafter, the Subordinated Notes will bear interest at an annual rate equal to the sum of the three-month LIBOR rate for the related quarterly interest period, plus 6.734% payable quarterly, commencing April 15, 2018, unless payment is deferred in accordance with the terms of the notes.
Shelf Registration Statement
On June 2, 2015, the Securities and Exchange Commission declared our shelf registration statement on Form S-3 effective, which permits us to offer and sell NuStar Energy common units having an aggregate purchase price of up to $500.0 million (the Shelf Registration Statement).

On September 30, 2015, in connection with the Shelf Registration Statement, we entered into an Equity Distribution Agreement (the Equity Distribution Agreement) with various banks (each a Manager, and collectively, the Managers). Under the Equity Distribution Agreement, we may from time to time sell NuStar Energy common units representing limited partner interests having an aggregate offering price of up to $500.0 million, using the Managers as our sales agents. 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 the Managers. Under the terms of the Equity Distribution Agreement, we may also sell common units to any Manager as principal for its own account at a price to be agreed upon at the time of sale. As of December 31, 2015, we have not sold any NuStar Energy common units under the Equity Distribution Agreement.
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 the existing operating capacity of existing assets or extend their useful lives, as well as those required to maintain equipment reliability and safety; and
strategic capital expenditures, such as those to expand or upgrade the operating capacity, increase efficiency or increase the earnings potential of existing assets, whether through construction or acquisition, as well as certain capital expenditures related to support functions.
The following table summarizes our capital expenditures, and the amount we expect to spend for 2016:
 
 
Reliability Capital Expenditures (a)
 
Strategic Capital Expenditures (b)
 
Total
 
 
(Thousands of Dollars)
For the year ended December 31:
 
 
 
 
 
 
2013
 
$
41,319

 
$
302,001

 
$
343,320

2014
 
$
28,635

 
$
328,330

 
$
356,965

2015 (c)
 
$
40,002

 
$
430,870

 
$
470,872

Expected for the year ended December 31, 2016
 
$ 35,000 - 45,000

 
 $ 360,000 - 380,000

 
$ 395,000 - 425,000

(a)
Reliability capital primarily relates to maintenance upgrade projects at our terminals.
(b)
For each of 2013, 2014 and 2015, strategic capital expenditures primarily related to projects associated with the Eagle Ford Shale region in South Texas. In 2015, strategic capital also included $142.5 million for the Linden Acquisition. In 2014 and 2015, strategic capital also included the reactivation and conversion of our 200-mile pipeline between Mont Belvieu and Corpus Christi, Texas. In 2013, strategic capital also included projects at our St. James, Louisiana terminal.
(c)
In 2015, our completed Eagle Ford Shale region capital projects included the expansion of our South Texas Crude System, which increased throughput capacity of the system, construction of additional storage at our Corpus Christi North Beach and Oakville terminals and projects that connected our South Texas Crude System to two major refineries in the Corpus Christi area.

For 2016, we continue to evaluate our capital budget and make changes as economic conditions warrant, and our actual capital expenditures for 2016 may increase or decrease from the budgeted amounts. We believe cash on hand, combined with other

47


sources of liquidity previously described, will be sufficient to fund our capital expenditures in 2016, and our internal growth projects can be accelerated or scaled back depending on the condition of the capital markets.
Working Capital Requirements
Working capital requirements, particularly in our fuels marketing segment, may vary with the seasonality of demand and the volatility of commodity prices for the products we market. This seasonality in demand and the volatility of commodity prices affect our accounts receivable and accounts payable balances, which vary depending on timing of payments.

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

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

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

Axeon Term Loan and Credit Support
The Axeon Term Loan includes scheduled repayments to reduce the outstanding amount from $190.0 million to $175.0 million as of December 31, 2014 and then to $150.0 million on September 30, 2015. Any repayments of the Axeon Term Loan, including those that were scheduled in 2014 and 2015, are subject to Axeon meeting certain restrictive requirements contained in its third-party asset-based revolving credit facility. Axeon failed to make the two scheduled principal payments, increasing the interest rate payable by Axeon until Axeon makes the payments. While the Axeon Term Loan does not provide for any other scheduled payments, Axeon is required to use all of its excess cash, as defined in the Axeon Term Loan, to repay the Axeon Term Loan, which must be repaid in full no later than September 28, 2019. The Axeon Term Loan bears interest based on either an alternative base rate or a LIBOR-based rate. We recognize interest income over the term of the loan in “Interest expense, net” on the consolidated statements of income. During the year ended December 31, 2015, the weighted average interest rate was 5.2%.

We also are obligated to provide credit support, such as guarantees, letters of credit and cash collateral, as applicable, of up to $150.0 million to Axeon, until February 26, 2016, at which point the amount of credit support will decrease by $25.0 million. Our obligation will continue to decrease until the obligation is terminated no later than September 28, 2019. As of December 31, 2015, we provided guarantees for Axeon with an aggregate maximum potential exposure of $71.9 million, plus two guarantees to suppliers that do not specify a maximum amount, but for which we believe any amounts due would be minimal. As of December 31, 2015, we have also provided $36.2 million in letters of credit on behalf of Axeon. In the event that we are obligated to perform under any of these guarantees or letters of credit, the amount paid by us will be treated as additional borrowings under the Axeon Term Loan.
Distributions
NuStar Energy’s partnership agreement, as amended, determines the amount and priority of cash distributions that our common unitholders and general partner may receive. The general partner receives a 2% distribution with respect to its general partner interest. The general partner is also entitled to incentive distributions if the amount we distribute with respect to any quarter exceeds $0.60 per unit. For a detailed discussion of the incentive distribution targets, please read Item 5. “Market for Registrant’s Common Units, Related Unitholder Matters and Issuer Purchases of Common Units.”


48


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,
 
2015
 
2014
 
2013
 
(Thousands of Dollars, Except Per Unit Data)
General partner interest
$
7,844

 
$
7,844

 
$
7,844

General partner incentive distribution
43,220

 
43,220

 
43,220

Total general partner distribution
51,064

 
51,064

 
51,064

Limited partners’ distribution
341,140

 
341,140

 
341,140

Total cash distributions
$
392,204

 
$
392,204

 
$
392,204

 
 
 
 
 
 
Cash distributions per unit applicable to limited partners
$
4.380

 
$
4.380

 
$
4.380

Actual distribution payments are made within 45 days after the end of each quarter as of a record date that is set after the end of each quarter. The following table summarizes information related to our quarterly cash distributions:
Quarter Ended
 
Cash Distributions Per Unit
 
Total Cash Distributions
 
Record Date
 
Payment Date
 
 
 
 
(Thousands of Dollars)
 
 
 
 
December 31, 2015 (a)
 
$
1.095

 
$
98,051

 
February 8, 2016
 
February 12, 2016
September 30, 2015
 
$
1.095

 
$
98,051

 
November 9, 2015
 
November 13, 2015
June 30, 2015
 
$
1.095

 
$
98,051

 
August 7, 2015
 
August 13, 2015
March 31, 2015
 
$
1.095

 
$
98,051

 
May 8, 2015
 
May 14, 2015
(a)
The distribution was announced on January 29, 2016.
Debt Obligations
As of December 31, 2015, we were a party to the following debt agreements:
the Revolving Credit Agreement due October 29, 2019, with a balance of $882.7 million as of December 31, 2015;
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;
$365.4 million Gulf Opportunity Zone Revenue Bonds due from 2038 to 2041;
$105.0 million line of credit agreements with $84.0 million outstanding as of December 31, 2015; and
Receivables Financing Agreement due June 15, 2018, with $53.5 million of borrowings outstanding as of December 31, 2015.
Management believes that we are in compliance with the ratios and covenants contained under our debt instruments. A default under certain of our debt agreements would be considered an event of default under other of our debt instruments. Please refer to Note 13 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for a more detailed discussion of our debt agreements.
Credit Ratings
The following table reflects the current outlook and ratings that have been assigned to our debt:
 
Standard & Poor’s
 Ratings Services
 
Moody’s Investor 
Service Inc.
 
Fitch, Inc.
 
 
 
 
 
 
Ratings
BB+
 
Ba1
 
BB
Outlook
Stable
 
Stable
 
Stable