NS 2014 10-K
Table of Contents

UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2014
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 $4,194 million based on the last sales price quoted as of June 30, 2014, the last business day of the registrant’s most recently completed second quarter.
The number of common units outstanding as of January 31, 2015 was 77,886,078.


Table of Contents

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

Table of Contents

PART I

Unless otherwise indicated, the terms “NuStar Energy L.P.,” “the Partnership,” “we,” “our” and “us” are used in this report to refer to NuStar Energy L.P., to one or more of our consolidated subsidiaries or to all of them taken as a whole. In this Form 10-K, we make certain forward-looking statements, including statements regarding our plans, strategies, objectives, expectations, intentions and resources. These forward-looking statements can generally be identified by the words “anticipates,” “believes,” “expects,” “plans,” “intends,” “estimates,” “forecasts,” “budgets,” “projects,” “will,” “could,” “should,” “may” and similar expressions. We do not undertake to update, revise or correct any of the forward-looking information. You are cautioned that such forward-looking statements should be read in conjunction with our disclosures beginning on page 31 of this report under the heading: “CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION.”

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

OVERVIEW
NuStar Energy L.P. (NuStar Energy), a Delaware limited partnership, was formed in 1999 and completed its initial public offering of common units on April 16, 2001. Our common units are traded on the New York Stock Exchange (NYSE) under the symbol “NS.” Our principal executive offices are located at 19003 IH-10 West, San Antonio, Texas 78257 and our telephone number is (210) 918-2000.
We are engaged in the transportation of petroleum products and anhydrous ammonia, the terminalling and storage of petroleum products and the marketing of petroleum products. The term “throughput” as used in this document generally refers to barrels of crude oil or refined product or tons of ammonia, as applicable, that pass through our pipelines, terminals or storage tanks.
We divide our operations into the following three reportable business segments: pipeline, storage and fuels marketing. As of December 31, 2014, our assets included:
5,463 miles of refined product pipelines with 21 associated terminals providing storage capacity of 4.9 million barrels and two tank farms providing storage capacity of 1.4 million barrels;
2,000 miles of anhydrous ammonia pipelines;
1,180 miles of crude oil pipelines providing 3.5 million barrels of associated storage capacity; and
53 terminal and storage facilities providing 80.9 million barrels of storage capacity.
We conduct our operations through our wholly owned subsidiaries, primarily NuStar Logistics, L.P. (NuStar Logistics) and NuStar Pipeline Operating Partnership L.P. (NuPOP). Our revenues include:
tariffs for transporting crude oil, refined products and anhydrous ammonia through our pipelines;
fees for the use of our terminal and storage facilities and related ancillary services; and
sales of crude oil and refined petroleum products.
Our goal is to increase per unit quarterly distributions to our partners. We strive to achieve this goal by:
enhancing our existing assets through strategic internal growth projects that expand our business with current and new customers;
pursuing strategic expansion projects by constructing new assets;
improving our operations, including safety and environmental stewardship, cost control and asset reliability; and
identifying acquisition targets that meet our financial and strategic criteria.

Our internet website address is http://www.nustarenergy.com. Information contained on our website is not part of this report. Our annual reports on Form 10-K, quarterly reports on Form 10-Q and current reports on Form 8-K filed with (or furnished to) the Securities and Exchange Commission (SEC) are available on our internet website, free of charge, as soon as reasonably practicable after we file or furnish such material (select the “Investors” link, then the “SEC Filings” link). We also post our corporate governance guidelines, code of business conduct and ethics, code of ethics for senior financial officers and the charters of our board’s committees on our internet website free of charge (select the “Investors” link, then the “Corporate Governance” link). Our governance documents are available in print to any unitholder that makes a written request to Corporate Secretary, NuStar Energy L.P., 19003 IH-10 West, San Antonio, Texas 78257 or corporatesecretary@nustarenergy.com.


3

Table of Contents

RECENT DEVELOPMENTS

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

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

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

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

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

4

Table of Contents

SEGMENTS
Our three reportable business segments are pipeline, storage and fuels marketing. Detailed financial information about our segments is included in Note 26 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data.”
The following map depicts our operations at December 31, 2014.


5

Table of Contents

PIPELINE
Our pipeline operations consist of the transportation of refined petroleum products, crude oil and anhydrous ammonia. As of December 31, 2014, we owned and operated:
refined product pipelines with an aggregate length of 3,113 miles and crude oil pipelines with an aggregate length of 1,180 miles in Texas, Oklahoma, Kansas, Colorado and New Mexico (collectively, the Central West System);
a 1,910-mile refined product pipeline originating in southern Kansas and terminating at Jamestown, North Dakota, with a western extension to North Platte, Nebraska and an eastern extension into Iowa (the East Pipeline);
a 440-mile refined product pipeline originating at Tesoro Corporation’s (Tesoro) Mandan, North Dakota refinery and terminating in Minneapolis, Minnesota (the North Pipeline); and
a 2,000-mile anhydrous ammonia pipeline originating at the Louisiana delta area that travels north through the midwestern United States forking east and west to terminate in Nebraska and Indiana (the Ammonia Pipeline).
We charge tariffs on a per barrel basis for transporting refined products, crude oil and other feedstocks in our refined product and crude oil pipelines and on a per ton basis for transporting anhydrous ammonia in the Ammonia Pipeline. The following table lists information about our pipeline assets as of December 31, 2014:
 
 
 
 
 
Throughput
 For the year ended December 31,
Region / Pipeline System
Length
 
Tank Capacity
 
2014
 
2013
 
(Miles)
 
(Barrels)
 
(Barrels/Day)
Central West System:
 
 
 
 
 
 
 
McKee System
2,276

 

 
164,589

 
148,541

Three Rivers System
377

 

 
78,177

 
76,512

Other
460

 

 
51,698

 
50,826

Central West Refined Products Pipelines
3,113

 

 
294,464

 
275,879

Eagle Ford System
438

 
1,600,000

 
230,665

 
168,718

McKee System
598

 
1,050,000

 
140,402

 
130,081

Ardmore System
87

 
824,000

 
66,690

 
66,950

Other
57

 

 

 

Central West Crude Oil Pipelines
1,180

 
3,474,000

 
437,757

 
365,749

Total Central West System
4,293

 
3,474,000

 
732,221

 
641,628

 
 
 
 
 
 
 
 
East Pipeline
1,910

 
4,916,000

 
134,816

 
132,475

North Pipeline
440

 
1,437,000

 
45,641

 
45,991

Ammonia Pipeline
2,000

 

 
35,816

 
32,676

Total
8,643

 
9,827,000

 
948,494

 
852,770

Description of Pipelines
Central West System. The Central West System covers a total of 4,293 miles. The Central West System pipelines support shale oil production and the refineries to which they are connected, including Valero Energy Corporation’s (Valero Energy) McKee, Three Rivers and Ardmore refineries. The refined product pipelines have an aggregate length of 3,113 miles (Central West Refined Products Pipelines), including 289 miles of temporarily idled 6-inch Amarillo, Texas to Albuquerque, New Mexico refined product pipeline. The refined products transported in these pipelines include gasoline, distillates (including diesel and jet fuel), natural gas liquids and other products produced at the refineries to which they are connected. The crude oil pipelines have an aggregate length of 1,180 miles (Central West Crude Oil Pipelines), including 214 miles of temporarily idled Cheyenne Wells, Colorado to McKee and Healdton to Ringling, Oklahoma crude oil pipelines. Our crude oil pipelines transport crude oil and other feedstocks from various points to the refineries to which they are connected, and from the Eagle Ford Shale region to our North Beach marine terminal in Corpus Christi, Texas.
East Pipeline. The East Pipeline covers 1,910 miles, including 111 miles that are temporarily idled, and moves refined products and natural gas liquids north in pipelines ranging in diameter from 6 inches to 16 inches to NuStar Energy and third party terminals along the system and to receiving pipeline connections in Kansas. The East Pipeline system includes 17 terminals, discussed below, with storage capacity of approximately 3.5 million barrels and two tank farms with storage capacity of

6

Table of Contents

approximately 1.4 million barrels at McPherson and El Dorado, Kansas. Shippers on the East Pipeline obtain refined petroleum products from refineries in Kansas, Oklahoma and Texas.
North Pipeline. The North Pipeline originates at Tesoro’s Mandan, North Dakota refinery and runs from west to east for approximately 440 miles to its termination in the Minneapolis, Minnesota area. The North Pipeline system includes 4 terminals, discussed below, with storage capacity of approximately 1.4 million barrels.
Pipeline-Related Terminals. The East and North Pipelines include 21 truck-loading terminals through which refined petroleum products are delivered to storage tanks and then loaded into petroleum product transport trucks. Revenues earned at these terminals relate solely to the volumes transported on the pipeline. Separate fees are not charged for the use of these terminals. Instead, the terminalling fees are a portion of the transportation rate included in the pipeline tariff. As a result, these terminals are included in this segment instead of the storage segment.
Ammonia Pipeline. The 2,000-mile pipeline, including 57 miles that are temporarily idled, originates in the Louisiana delta area, where it has access to three third-party marine terminals and three anhydrous ammonia plants on the Mississippi River. The line runs north through Louisiana and Arkansas into Missouri, where at Hermann, Missouri it splits and one branch goes east into Illinois and Indiana, while the other branch continues north into Iowa and then turns west into Nebraska. The Ammonia Pipeline is connected to multiple third-party-owned terminals, which include industrial facility delivery locations. Product is supplied to the pipeline from anhydrous ammonia plants in Louisiana and imported product delivered through the marine terminals. Anhydrous ammonia is primarily used as agricultural fertilizer. It is also used as a feedstock to produce other nitrogen derivative fertilizers and explosives.
Pipeline Operations
Revenues for the pipelines are based upon origin-to-destination throughput volumes traveling through our pipelines and their related tariff rates.
In general, a shipper on our refined petroleum product pipelines delivers products to the pipeline from refineries or third-party pipelines. We charge our shippers tariff rates based on transportation from the origination point on the pipeline to the point of delivery. We invoice our refined product shippers upon delivery for our Central West System and our North and Ammonia Pipelines, and we invoice our shippers on our East Pipeline when their product enters the line.

Shippers on our crude oil pipelines deliver crude oil to our pipelines for transport to: (i) refineries that connect to our pipelines, (ii) third-party pipelines and (iii) NuStar terminals for further delivery to marine vessels or third-party pipelines.
Our pipelines are subject to federal regulation by one or more of the following governmental agencies or laws: the Federal Energy Regulatory Commission (the FERC), the Surface Transportation Board (the STB), the Department of Transportation (DOT), the Environmental Protection Agency (EPA) and the Homeland Security Act. Additionally, the operations and integrity of the pipelines are subject to the respective state jurisdictions.
The majority of our pipelines are common carrier and adopt market-based rates. Common carrier activities are those for which transportation through our pipelines is available, at published tariffs filed, in the case of interstate petroleum product shipments, with the FERC and the STB or, in the case of intrastate petroleum product shipments, with the relevant state authority, to any shipper of petroleum products who requests such services and satisfies the conditions and specifications for transportation.
We use Supervisory Control and Data Acquisition remote supervisory control software programs to continuously monitor and control our pipelines. The system monitors quantities of products injected in and delivered through the pipelines and automatically signals the appropriate personnel upon deviations from normal operations that require attention.
Demand for and Sources of Refined Products and Crude Oil
Throughputs on our Central West Refined Product Pipelines and the East and North Pipelines depend on the level of demand for refined products in the markets served by the pipelines and the ability and willingness of refiners and marketers having access to the pipelines to supply such demand by deliveries through the pipelines.
The majority of the refined products delivered through the Central West Refined Product Pipelines and the North Pipeline are gasoline and diesel fuel that originate at refineries connected to us. Demand for these products fluctuates as prices for these products fluctuate. Prices fluctuate for a variety of reasons including the overall balance in supply and demand, which is affected by general economic conditions, among other factors. Prices for gasoline and diesel fuel tend to increase in the warm weather months when people tend to drive automobiles more often and further distances.


7

Table of Contents

Much of the refined products and natural gas liquids delivered through the East Pipeline and a portion of volumes on the North Pipeline are ultimately used as fuel for railroads, ethanol denaturant or in agricultural operations, including fuel for farm equipment, irrigation systems, trucks used for transporting crops and crop-drying facilities. Demand for refined products for agricultural use, and the relative mix of products required, is affected by weather conditions in the markets served by the East and North Pipelines. The agricultural sector is also affected by government agricultural policies and crop prices. Although periods of drought suppress agricultural demand for some refined products, particularly those used for fueling farm equipment, the demand for fuel for irrigation systems often increases during such times. The mix of refined products delivered for agricultural use varies seasonally, with gasoline demand peaking in early summer, diesel fuel demand peaking in late summer and propane demand higher in the fall.
Our refined product pipelines are also dependent upon adequate levels of production of refined products by refineries connected to the pipelines, directly or through connecting pipelines. The refineries are, in turn, dependent upon adequate supplies of suitable grades of crude oil. Certain of our Central West Refined Products Pipelines are subject to long-term throughput agreements with Valero Energy. Valero Energy refineries connected directly to our pipelines obtain crude oil from a variety of foreign and domestic sources. If operations at one of these refineries were discontinued or significantly reduced, it could have a material adverse effect on our operations, although we would endeavor to minimize the impact by seeking alternative customers for those pipelines.
The North Pipeline is heavily dependent on Tesoro’s Mandan, North Dakota refinery, which primarily runs North Dakota crude oil (although it has the ability to process other crude oils). If operations at the Tesoro refinery were interrupted, it could have a material effect on our operations. The majority of the refined products transported through the East Pipeline are produced at three refineries located at McPherson and El Dorado, Kansas and Ponca City, Oklahoma, which are operated by the National Cooperative Refining Association (NCRA), HollyFrontier Corporation (HollyFrontier) and Phillips 66, respectively. The NCRA and HollyFrontier refineries are connected directly to the East Pipeline. The East Pipeline also has access to Gulf Coast supplies of products through third party connecting pipelines that receive products originating on the Gulf Coast.
Other than the Valero Energy refineries described above and the Tesoro refinery, if operations at any one refinery were discontinued, we believe (assuming unchanged demand for refined products in markets served by the refined product pipelines) that the effects thereof would be short-term in nature and our business would not be materially adversely affected over the long-term because such discontinued production could be replaced by other refineries or other sources.
Our crude oil pipelines depend upon the continued production of domestic crude oil in regions served by our crude oil pipelines or connecting carriers. Our crude oil pipelines are also dependent on our customers’ continued access to sufficient foreign crude oil and sufficient demand for refined products for our customers to operate their refineries. The supply of crude oil production (domestic and foreign) could increase or decrease with the change in crude oil prices.
Demand for and Sources of Anhydrous Ammonia
The Ammonia Pipeline is one of two major anhydrous ammonia pipelines in the United States and the only one capable of receiving foreign product directly into the system and transporting anhydrous ammonia into the nation’s corn belt.
Throughputs on our Ammonia Pipeline depend on overall nitrogen fertilizer use, management practices, the price of natural gas, which is the primary component of anhydrous ammonia, and the level of demand for direct application of anhydrous ammonia as a fertilizer for crop production (Direct Application). Demand for Direct Application is dependent on the weather, as Direct Application is not effective if the ground is too wet or too dry.
Corn producers have fertilizer alternatives to anhydrous ammonia, such as liquid or dry nitrogen fertilizers. Liquid and dry nitrogen fertilizers are both less sensitive to weather conditions during application but are generally more costly than anhydrous ammonia. In addition, anhydrous ammonia has the highest nitrogen content of any nitrogen-derivative fertilizer.
Customers
The largest customer of our pipeline segment was Valero Energy, which accounted for approximately 35% of the total segment revenues for the year ended December 31, 2014. In addition to Valero Energy, our customers include integrated oil companies, refining companies, farm cooperatives, railroads and others. No other customer accounted for a significant portion of the total revenues of the pipeline segment for the year ended December 31, 2014.

8

Table of Contents

Competition and Business Considerations
Because pipelines are generally the lowest-cost method for intermediate and long-haul movement of crude oil and refined petroleum products, our more significant competitors are common carrier and proprietary pipelines owned and operated by major integrated and large independent oil companies and other companies in the areas where we deliver products. Competition between common carrier pipelines is based primarily on transportation charges, quality of customer service and proximity to end users. Trucks may competitively deliver products in some of the areas served by our pipelines. However, trucking costs render that mode of transportation uncompetitive for longer hauls or larger volumes.
Most of our refined product pipelines and certain of our crude oil pipelines within the Central West System are physically integrated with and principally serve refineries owned by Valero Energy. As a result, we do not believe that we will face significant competition for transportation services provided to the Valero Energy refineries we serve.
Our crude oil pipelines serve areas or refineries impacted by growing domestic shale oil production in the Eagle Ford, Permian Basin and Granite Wash regions. This growing domestic production has reduced demand for imported crude oil and shifted supply sources for refineries and markets served by our pipelines. Our pipelines also face competition from other crude oil pipelines and truck transportation in these regions.
The East and North Pipelines compete with an independent common carrier pipeline system owned by Magellan Midstream Partners, L.P. (Magellan) that operates approximately 100 miles east of and parallel to the East Pipeline and in close proximity to the North Pipeline. Certain of the East Pipeline’s and the North Pipeline’s delivery terminals are in direct competition with Magellan’s terminals. Competition with Magellan is based primarily on transportation charges, quality of customer service and proximity to end users.
Competitors of the Ammonia Pipeline include the other major anhydrous ammonia pipeline, which originates in Oklahoma and Texas and terminates in Minnesota. The competing pipeline has the same Direct Application demand and weather issues as the Ammonia Pipeline but is restricted to domestically produced anhydrous ammonia. Midwest production facilities, nitrogen fertilizer substitutes and barge and railroad transportation represent other forms of direct competition to the pipeline under certain market conditions.

STORAGE
Our storage segment includes terminal and storage facilities that provide storage, handling and other services for petroleum products, crude oil, specialty chemicals and other liquids. As of December 31, 2014, we owned and operated:
43 terminal and storage facilities in the United States, with total storage capacity of 49.2 million barrels;
A terminal on the island of St. Eustatius with tank capacity of 14.4 million barrels and a transshipment facility;
A terminal located in Point Tupper with tank capacity of 7.7 million barrels and a transshipment facility;
Six terminals located in the United Kingdom and one terminal located in Amsterdam, the Netherlands, with total storage capacity of approximately 9.5 million barrels;
A terminal located in Nuevo Laredo, Mexico.
Description of Major Terminal Facilities
St. Eustatius. We own and operate a 14.4 million barrel petroleum storage and terminalling facility located on the island of St. Eustatius in the Caribbean, which is located at a point of minimal deviation from major shipping routes. This facility is capable of handling a wide range of petroleum products, including crude oil and refined products, and it can accommodate heavy-laden ultra large crude carriers, or ULCCs, for loading and discharging crude oil and other petroleum products. A two-berth jetty, a two-berth monopile with platform and buoy systems, a floating hose station and an offshore single point mooring buoy with loading and unloading capabilities serve the terminal’s customers’ vessels. The fuel oil and petroleum product facilities have in-tank and in-line blending capabilities, while the crude tanks have tank-to-tank blending capability and in-tank mixers. In addition to the storage and blending services at St. Eustatius, this facility has the flexibility to utilize certain storage capacity for both feedstock and refined products to support our atmospheric distillation unit. This unit is capable of handling up to 25,000 barrels per day of feedstock, ranging from condensates to heavy crude oil. We own and operate all of the berthing facilities at the St. Eustatius terminal. Separate fees apply for the use of the berthing facilities, as well as associated services, including pilotage, tug assistance, line handling, launch service, emergency response services and other ship services.
St. James, Louisiana. Our St. James terminal, which is located on the Mississippi River near St. James, Louisiana, has a total storage capacity of 9.2 million barrels. The facility is located on almost 900 acres of land, some of which is undeveloped. The majority of the storage tanks and infrastructure are suited for light crude oil, with four tanks capable of fuel oil or heated crude oil storage. Additionally, the facility has one barge dock and two ship docks. Our St. James terminal can receive product from gathering pipelines in the Gulf of Mexico and deliver to connecting pipelines that supply refineries in the Gulf Coast and

9

Table of Contents

Midwest. The St. James terminal also has two unit train rail facilities and a manifest rail facility, which are served by the Union Pacific Railroad and have a combined capacity of approximately 200,000 barrels per day.
Point Tupper. We own and operate a 7.7 million barrel terminalling and storage facility located at Point Tupper on the Strait of Canso, near Port Hawkesbury, Nova Scotia. This facility is the deepest independent, ice-free marine terminal on the North American Atlantic coast, with access to the East Coast, Canada and the Midwestern United States via the St. Lawrence Seaway and the Great Lakes system. With one of the premier jetty facilities in North America, the Point Tupper facility can accommodate heavy-laden ULCCs, for loading and discharging crude oil, petroleum products and petrochemicals. Crude oil and petroleum product movements at the terminal are fully automated. Separate fees apply for the use of the jetty facility, as well as associated services, including pilotage, tug assistance, line handling, launch service, emergency response services and other ship services.

Amsterdam. Our Amsterdam terminal has a total storage capacity of 3.8 million barrels. This facility is located at the Port of Amsterdam and primarily stores petroleum products including gasoline, diesel and fuel oil. This facility has two docks for vessels and five docks for inland barges.
Linden, New Jersey. In 2014, we owned 50% of ST Linden Terminal LLC (Linden), which owns a terminal and storage facility in Linden, New Jersey. On January 2, 2015, we acquired full ownership of Linden by purchasing the remaining ownership interest from Linden Holding Corp for $142.5 million. The terminal is located on a 44-acre facility that provides it with deep-water terminalling capabilities in the New York Harbor. This terminal primarily stores petroleum products, including gasoline, jet fuel and fuel oils. The facility has a total storage capacity of 4.3 million barrels and can receive and deliver products via ship, barge and pipeline. The terminal includes two dock facilities.
Terminal and Storage Facilities
The following table sets forth information about our terminal and storage facilities as of December 31, 2014:
Facility
Tank Capacity
 
Primary Products Handled
 
(Barrels)
 
 
Colorado Springs, CO
328,000

 
Petroleum products, ethanol
Denver, CO
110,000

 
Petroleum products, ethanol
Alamogordo, NM (a) (e)
124,000

 
Petroleum products
Albuquerque, NM
251,000

 
Petroleum products, ethanol
Abernathy, TX
160,000

 
Petroleum products
Amarillo, TX
269,000

 
Petroleum products
Corpus Christi, TX
329,000

 
Petroleum products
Corpus Christi, TX (North Beach)
1,721,000

 
Crude oil and feedstocks
Edinburg, TX
288,000

 
Petroleum products
El Paso, TX (b)
428,000

 
Petroleum products, ethanol
Harlingen, TX
286,000

 
Petroleum products
Laredo, TX
215,000

 
Petroleum products
Placedo, TX (c)
100,000

 
Petroleum products
San Antonio (East), TX
150,000

 
Petroleum products
San Antonio (South), TX
225,000

 
Petroleum products
Southlake, TX
569,000

 
Petroleum products, ethanol
Nuevo Laredo, Mexico
50,000

 
Petroleum products
Central West Terminals
5,603,000

 
 
 
 
 
 
Pittsburg, CA
398,000

 
Asphalt
Rosario, NM
166,000

 
Asphalt
Catoosa, OK
358,000

 
Asphalt
Houston, TX
86,000

 
Asphalt
Asphalt Terminals
1,008,000

 
 
 
 
 
 

10

Table of Contents

Facility
Tank Capacity
 
Primary Products Handled
 
(Barrels)
 
 
Blue Island, IL
690,000

 
Petroleum products, ethanol
Indianapolis, IN
428,000

 
Petroleum products
Central East Terminals
1,118,000

 
 
 
 
 
 
Jacksonville, FL
2,593,000

 
Petroleum products, asphalt
St. James, LA
9,190,000

 
Crude oil and feedstocks
Texas City, TX
128,000

 
Petroleum products
Texas City, TX
2,836,000

 
Chemicals, petroleum products
Gulf Coast Terminals
14,747,000

 
 
 
 
 
 
Andrews AFB, MD (a)
75,000

 
Petroleum products
Baltimore, MD
818,000

 
Chemicals, asphalt, petroleum products
Piney Point, MD
5,402,000

 
Petroleum products
Linden, NJ
389,000

 
Petroleum products
Linden, NJ (d)
2,130,000

 
Petroleum products
Paulsboro, NJ
74,000

 
Petroleum products
Virginia Beach, VA (a)
41,000

 
Petroleum products
North East Terminals
8,929,000

 
 
 
 
 
 
Los Angeles, CA
608,000

 
Petroleum products
Selby, CA
3,060,000

 
Petroleum products, ethanol
Stockton, CA
816,000

 
Petroleum products, ethanol, fertilizer
Portland, OR
1,365,000

 
Petroleum products, ethanol
Tacoma, WA
391,000

 
Petroleum products, ethanol
Vancouver, WA
341,000

 
Chemicals
Vancouver, WA
433,000

 
Petroleum products
West Coast Terminals
7,014,000

 
 
 
 
 
 
Corpus Christi, TX
4,030,000

 
Crude oil and feedstocks
Texas City, TX
3,141,000

 
Crude oil and feedstocks
Benicia, CA
3,683,000

 
Crude oil and feedstocks
Refinery Storage Tanks
10,854,000

 
 
 
 
 
 
Grays, England
1,958,000

 
Petroleum products
Eastham, England
2,096,000

 
Chemicals, petroleum products
Runcorn, England
149,000

 
Molten sulfur
Grangemouth, Scotland
719,000

 
Petroleum products, chemicals
Glasgow, Scotland
353,000

 
Petroleum products
Belfast, Northern Ireland
408,000

 
Petroleum products
United Kingdom Terminals
5,683,000

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 

11

Table of Contents

Facility
Tank Capacity
 
Primary Products Handled
 
(Barrels)
 
 
St. Eustatius, the Netherlands
14,396,000

 
Petroleum products, crude oil and feedstocks
Amsterdam, the Netherlands
3,834,000

 
Petroleum products
Point Tupper, Canada
7,725,000

 
Petroleum products, crude oil and feedstocks
 
 
 
 
Total Terminals and Storage Facilities
80,911,000

 
 
 
(a)
Terminal facility also includes pipelines to U.S. government military base locations.
(b)
We own a 67% undivided interest in the El Paso refined product terminal. The tank capacity represents the proportionate share of capacity attributable to our ownership interest.
(c)
The Placedo, TX terminal is temporarily idled.
(d)
As of December 31, 2014, we owned 50% of this terminal through a joint venture. The tank capacity represents the proportionate share of capacity attributable to our ownership interest. On January 2, 2015, we purchased the other 50% ownership interest.
(e)
On January 7, 2015, we sold the Alamogordo, NM terminal and the related pipeline.
Storage Operations
Revenues for the storage segment include fees for tank storage agreements, where a customer agrees to pay for a certain amount of storage in a tank over a period of time (storage lease revenues), and throughput agreements, where a customer pays a fee per barrel for volumes moving through our terminals (throughput revenues). Our terminals also provide blending, additive injections, handling and filtering services for which we charge additional fees. We charge a fee for each barrel of crude oil and certain other feedstocks that we deliver to Valero Energy’s Benicia, Corpus Christi West and Texas City refineries from our crude oil storage tanks. Certain of our facilities charge fees to provide marine services such as pilotage, tug assistance, line handling, launch service, emergency response services and other ship services.
Demand for Refined Petroleum Products and Crude Oil
The operations of our refined product terminals depend in large part on the level of demand for products stored in our terminals in the markets served by those assets. The majority of products stored in our terminals are refined petroleum products. Demand for our terminalling services will generally increase or decrease with demand for refined petroleum products, and demand for refined petroleum products tends to increase or decrease with the relative strength of the economy. In addition, the forward pricing curve can impact demand. For example, in a contango market (when the price for future storage is expected to exceed current prices), demand for storage services will generally increase.
Crude oil delivered to our St. James terminal through our unit train facilities, and crude oil delivered to our Corpus Christi North Beach terminal will generally increase or decrease with crude oil production rates in the Bakken and Eagle Ford shale plays, respectively. In addition, the market price relationship between various grades of crude oil impacts the demand for our unit train facilities at our St. James terminal, which can affect our profit sharing and volumes.
Customers
We provide storage and terminalling services for crude oil and refined petroleum products to many of the world’s largest producers of crude oil, integrated oil companies, chemical companies, oil traders and refiners. In addition, our blending capabilities in our storage assets have attracted customers who have leased capacity primarily for blending purposes. The largest customer of our storage segment is Valero Energy, which accounted for approximately 19% of the total revenues of the segment for the year ended December 31, 2014. No other customer accounted for a significant portion of the total revenues of the storage segment for the year ended December 31, 2014.
Competition and Business Considerations
Many major energy and chemical companies own extensive terminal storage facilities. Although such terminals often have the same capabilities as terminals owned by independent operators, they generally do not provide terminalling services to third parties. In many instances, major energy and chemical companies that own storage and terminalling facilities are also significant customers of independent terminal operators. Such companies typically have strong demand for terminals owned by independent operators when independent terminals have more cost-effective locations near key transportation links, such as deep-water ports. Major energy and chemical companies also need independent terminal storage when their owned storage facilities are inadequate, either because of size constraints, the nature of the stored material or specialized handling requirements.

12

Table of Contents

Independent terminal owners generally compete on the basis of the location and versatility of terminals, service and price. A favorably located terminal will have access to various cost-effective transportation modes both to and from the terminal. Transportation modes typically include waterways, railroads, roadways and pipelines.
Terminal versatility is a function of the operator’s ability to offer complex handling requirements for diverse products. The services typically provided by the terminal include, among other things, the safe storage of the product at specified temperature, moisture and other conditions, as well as receipt at and delivery from the terminal, all of which must be in compliance with applicable environmental regulations. A terminal operator’s ability to obtain attractive pricing is often dependent on the quality, versatility and reputation of the facilities owned by the operator. Although many products require modest terminal modification, operators with versatile storage capabilities typically require less modification prior to usage, ultimately making the storage cost to the customer more attractive.
Our St. Eustatius and Pt. Tupper terminals have historically functioned as “break bulk” facilities, which handled imports of light crude from foreign sources into the U.S. to satisfy U.S. East Coast and Gulf Coast refinery demand for light crude.  Light crude suppliers brought the crude from the Middle East and other foreign regions on very large ships that are efficient for long routes.  These large ships, due to draft constraints, are unable to navigate far enough inland to deliver directly to U.S. shores, which necessitate unloading these ships to storage and subsequent loading on the smaller ships that can bring the crude to the refiners, a process referred to as “break bulk.”  Both terminals are well located to provide this service.
As the supply of light crude from various U.S. shale formations has increased, U.S. demand for foreign light crude oil has dropped substantially.  This reduced demand for imported light crude has, in turn, dramatically changed oil trade flow patterns around the world, thereby depressing the demand for break bulk services.  At the same time, South American and Canadian production of heavy crude has ramped up significantly.  As demand for export of heavy crude and natural gas liquids (NGL) out of South America, as well as from Canada, has risen, so has the demand for “build bulk” services.  In order to reduce costs and increase efficiencies for long routes to customers abroad, exporting producers need to consolidate their heavy oil cargos from the small ships used to move the heavy crude off shore to a large vessel that is more efficient for long routes, a process referred to as “build bulk.”    Our St. Eustatius terminal’s location is well suited to build bulk for South American producers headed to customers overseas, primarily in Asia.  Our Point Tupper facility’s location is similarly well-positioned, in this case to build bulk for heavy Canadian crude oil and NGL production.  
We may face increased competition from new and/or expanding terminals near our locations, if those facilities offer either break bulk or build bulk services, as demanded by the applicable oil trade flows, now and in the future.
Our crude oil refinery storage tanks are physically integrated with and serve refineries owned by Valero Energy. Additionally, we have entered into various agreements with Valero Energy governing the usage of these tanks. As a result, we believe that we will not face significant competition for our services provided to those refineries.

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

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

Since our fuels marketing operations expose us to commodity price risk, we enter into derivative instruments to mitigate the effect of commodity price fluctuations on our operations. The derivative instruments we use consist primarily of commodity futures and swap contracts.
Customers
Fuels marketing customers include major integrated refiners and trading companies. Customers for our bunker fuel sales are mainly ship owners, including cruise line companies. No customer accounted for a significant portion of the total revenues of the fuels marketing segment for the year ended December 31, 2014.

13

Table of Contents

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

EMPLOYEES

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

RATE REGULATION

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

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

Additionally, the rates and practices for our intrastate common carrier pipelines are subject to regulation by state commissions in Colorado, Kansas, Louisiana, North Dakota and Texas. Although the applicable state statutes and regulations vary, they generally require that intrastate pipelines publish tariffs setting forth all rates, rules and regulations applying to intrastate service, and generally require that pipeline rates and practices be just, reasonable and nondiscriminatory.
Shippers may challenge tariff rates rules and regulations on our pipelines. In most instances, state commissions have not initiated investigations of the rates or practices of pipelines in the absence of shipper complaints. There are no pending challenges or complaints regarding our tariffs.

ENVIRONMENTAL AND SAFETY REGULATION

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

We have adopted policies, practices and procedures including in the areas of pollution control, pipeline integrity, operator qualifications, public relations and education, process safety management, occupational health and the handling, storage, use and disposal of hazardous materials, that are designed to prevent material environmental or other damage, to ensure the safety of our pipelines, our employees, the public and the environment and to limit the financial liability that could result from such events. Future governmental action and regulatory initiatives could result in changes to expected operating permits and procedures, additional remedial actions or increased capital expenditures and operating costs that cannot be assessed with certainty at this time. In addition, contamination resulting from spills of petroleum and other products occurs within the industry. Risks of additional costs and liabilities are inherent within the industry, and there can be no assurances that significant costs and liabilities will not be incurred in the future.

14

Table of Contents


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

RENEWABLE ENERGY AND ALTERNATIVE FUEL MANDATES

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

WATER

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

AIR

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

SOLID WASTE

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


15

Table of Contents

HAZARDOUS SUBSTANCES

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

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

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

PIPELINE INTEGRITY AND SAFETY

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


16

Table of Contents

RISK FACTORS
RISKS RELATED TO OUR BUSINESS

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

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

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

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

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

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

17

Table of Contents


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

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

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

Similarly, any sustained decrease in the supply of crude oil and refined products could result in a significant reduction in throughputs in our pipelines and storage in our terminals, which would reduce our cash flows and our ability to make distributions at current levels to our unitholders. Factors that could lead to a decrease in supply to our pipelines and terminals include:
prolonged periods of low prices for crude oil and refined products, which could lead to a decrease in exploration and development activity and reduced production in markets served by our pipelines and storage terminals;

18

Table of Contents

changes in the regulatory environment, governmental policies or taxation that directly or indirectly delay production or increase the cost of production of refined products; and
actions taken by foreign oil and gas producing nations that impact prices for crude oil and refined products.

Our future financial and operating flexibility may be adversely affected by our significant leverage, downgrades of our credit ratings, restrictions in our debt agreements or disruptions in the financial markets.
As of December 31, 2014, our consolidated debt was $2.8 billion. In addition to any potential direct financial impact of debt, it is possible that any material increase to our debt or other negative financial factors may be viewed negatively by credit rating agencies, which could result in ratings downgrades and increased costs for us to access the capital markets. The ratings of NuStar Logistics’ were downgraded to Ba1 by Moody’s Investor Service Inc. (Moody’s) in January 2013, BB+ by Standard & Poor’s Ratings Services (S&P) in July 2012 and BB by Fitch, Inc. in November 2012. As a result of the S&P and Moody’s downgrades, interest rates on borrowings under our five-year revolving credit agreement and our 7.65% senior notes due 2018 increased. Also, we may be required to post cash collateral under certain of our hedging arrangements, which we expect to fund with borrowings under our revolving credit agreement. Any further downgrades in the future could result in additional increases to the interest rates on borrowings under our credit facilities and the 7.65% senior notes due 2018, significantly increase our capital costs and adversely affect our ability to raise capital in the future.

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

Debt service obligations, restrictive covenants in our credit facilities and the indentures governing our outstanding senior and subordinated notes and maturities resulting from our leverage may adversely affect our ability to finance future operations, pursue acquisitions, fund our capital needs and pay cash distributions to our unitholders at current levels. In addition, this leverage may make our results of operations more susceptible to adverse economic or operating conditions. For example, during an event of default under certain of our debt agreements, we would be prohibited from making cash distributions to our unitholders. If our lenders file for bankruptcy or experience severe financial hardship, they may not honor their pro rata share of our borrowing requests under the revolving credit agreement, which may significantly reduce our available borrowing capacity and, as a result, materially adversely affect our financial condition and ability to pay distributions to our unitholders at current levels. Additionally, we may not be able to access the capital markets in the future at economically attractive terms, which may adversely affect our future financial and operating flexibility and our ability to pay cash distributions at current levels.

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

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

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

19

Table of Contents

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

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

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

Our operations are subject to operational hazards and unforeseen interruptions, and we do not insure against all potential losses. Therefore, we could be seriously harmed by unexpected liabilities.
Our operations are subject to operational hazards and unforeseen interruptions such as natural disasters, adverse weather, accidents, fires, explosions, hazardous materials releases, mechanical failures and other events beyond our control. These events might result in a loss of equipment or life, injury or extensive property damage, as well as an interruption in our operations. In the event any of our facilities are forced to shut down for a significant period of time, it may have a material adverse effect on our earnings, our other results of operations and our financial condition as a whole.

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

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

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


20

Table of Contents

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

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

We do not own all of the land on which our pipelines and facilities have been constructed, and we are therefore subject to the possibility of increased costs or the inability to retain necessary land use.
We obtain the rights to construct and operate our pipelines, storage terminals and other facilities on land owned by third parties and governmental agencies. Many of these rights-of-way or other property rights are perpetual in duration while others are for a specific period of time. In addition, some of our facilities are located on leased premises. Our loss of these rights, through our inability to renew right-of-way contracts or leases or otherwise, could adversely affect our operations and cash flows available for distribution to unitholders.

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

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

Climate change legislation and other regulatory initiatives may decrease demand for the products we store, transport and sell and increase our operating costs.
Scientific studies have suggested that emissions of certain gases, commonly referred to as “greenhouse gases” and including carbon dioxide and methane, may be contributing to warming of the Earth’s atmosphere. In response to such studies, the U.S. Congress, European Union and other political bodies have considered legislation or regulation to reduce emissions of greenhouse gases. In addition, several states and local governmental bodies, either individually or through multi-member initiatives, have already taken legal measures to reduce emissions of greenhouse gases, including through the development of greenhouse gas emission inventories and/or greenhouse gas cap and trade programs. As an alternative to reducing emission of greenhouse gases under cap and trade programs, governmental bodies may consider the implementation of a program to tax the emission of carbon dioxide and other greenhouse gases. Passage of climate change legislation or other regulatory initiatives in areas in which we conduct business, could result in changes to the demand for the products we store, transport and sell, and could increase the costs of our operations, including costs to operate and maintain our facilities, install new emission controls on our facilities, acquire allowances to authorize our greenhouse gas emissions, pay any taxes related to our greenhouse gas emissions or administer and manage a greenhouse gas emissions program. Even though we attempt to mitigate such lost revenues or increased costs through the contracts we sign with our customers, we may be unable to recover those revenues or mitigate the increased costs, and any such recovery may depend on events beyond our control, including the outcome of future rate proceedings before the FERC, the STB or other regulators and the provisions of any final legislation or regulations. Reductions in our revenues or increases in our expenses as a result of climate control or other initiatives could have adverse effects on our business, financial position, results of operations and prospects.


21

Table of Contents

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

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

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

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

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


22

Table of Contents

Changes to FERC rate-making principles could have an adverse impact on our ability to recover the full cost of operating our pipeline facilities and our ability to make distributions at current levels to our unitholders.
In May 2005, the FERC issued a statement of general policy stating it will permit pipelines to include in cost of service a tax allowance to reflect actual or potential tax liability on their public utility income attributable to all partnership or limited liability company interests, if the ultimate owner of the interest has an actual or potential income tax liability on such income. Whether a pipeline’s owners have such actual or potential income tax liability will be reviewed by the FERC on a case-by-case basis. Although this policy is generally favorable for pipelines that are organized as pass-through entities, it still entails rate risk due to the case-by-case review requirement. This tax allowance policy and the FERC’s application of that policy were appealed to the United States Court of Appeals for the District of Columbia Circuit (D.C. Court), and on May 29, 2007, the D.C. Court issued an opinion upholding the FERC’s tax allowance policy.

In two proceedings involving SFPP, L.P., a refined products pipeline system, shippers again challenged the FERC’s income tax allowance policy, alleging that it is unlawful for a pipeline organized as a tax-pass-through entity to be afforded an income tax allowance and that the income tax allowance is unnecessary because an allowance for income taxes for such pipelines is recovered indirectly through the rate of return on equity. The FERC rejected these shipper arguments in multiple orders. Nonetheless, these issues are currently pending before the FERC on rehearing and, absent settlement, will likely be reviewed by the D.C. Court. Because the extent to which an interstate oil pipeline is entitled to an income tax allowance is subject to a case-by-case review at the FERC and is a matter under litigation, the level of income tax allowance to which we will ultimately be entitled is not certain. Although the FERC’s current income tax allowance policy is generally favorable for pipelines that are organized as pass-through entities, it still entails rate risks due to the case-by-case review requirement and the above-noted pending litigation. How the FERC’s income tax allowance policy is applied in practice to pipelines owned by publicly traded partnerships could impose limits on our ability to include a full income tax allowance in cost of service.

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

Increases in natural gas and power prices could adversely affect our operating expenses and our ability to make distributions at current levels to our unitholders.
Power costs constitute a significant portion of our operating expenses. For the year ended December 31, 2014, our power costs equaled approximately $44.1 million, or 9.3% of our operating expenses for the year. We use mainly electric power at our pipeline pump stations and terminals, and such electric power is furnished by various utility companies that use primarily natural gas to generate electricity. Accordingly, our power costs typically fluctuate with natural gas prices. Increases in natural gas prices may cause our power costs to increase further. If natural gas prices increase, our cash flows may be adversely affected, which could adversely affect our ability to make distributions at current levels to our unitholders.

Terrorist attacks and the threat of terrorist attacks have resulted in increased costs to our business. Continued hostilities in the Middle East or other sustained military campaigns may adversely impact our results of operations.
Increased security measures we have taken as a precaution against possible terrorist attacks have resulted in increased costs to our business. Uncertainty surrounding continued hostilities in the Middle East or other sustained military campaigns may affect our operations in unpredictable ways, including disruptions of crude oil supplies and markets for refined products, the possibility that infrastructure facilities could be direct targets of, or indirect casualties of, an act of terror and instability in the financial markets that could restrict our ability to raise capital.

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

23

Table of Contents


We could be subject to damages based on claims brought against us by our customers or lose customers as a result of the failure of our products to meet certain quality specifications.
Certain of our products are produced to precise customer specifications. If a product fails to perform in a manner consistent with the detailed quality specifications required by the customer, the customer could seek replacement of the product or damages for costs incurred as a result of the product failing to perform as guaranteed. A successful claim or series of claims against us could result in a loss of one or more customers.

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

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

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

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

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

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

NuStar GP Holdings may have conflicts of interest and limited fiduciary responsibilities, which may permit it to favor its own interests to the detriment of our unitholders.
NuStar GP Holdings currently indirectly owns our general partner and as of December 31, 2014, an aggregate 12.9% limited partner interest in us. Conflicts of interest may arise between NuStar GP Holdings and its affiliates, including our general partner, on the one hand, and us and our limited partners, on the other hand. As a result of these conflicts, the general partner

24

Table of Contents

may favor its own interests and the interests of its affiliates over the interests of our unitholders. These conflicts include, among others, the following situations:
Our general partner is allowed to take into account the interests of parties other than us, such as NuStar GP Holdings, in resolving conflicts of interest, which has the effect of limiting its fiduciary duty to the unitholders;
Our general partner may limit its liability and reduce its fiduciary duties, while also restricting the remedies available to unitholders. As a result of purchasing our common units, unitholders have consented to some actions and conflicts of interest that might otherwise constitute a breach of fiduciary or other duties under applicable state law;
Our general partner determines the amount and timing of asset purchases and sales, capital expenditures, borrowings, issuance of additional limited partner interests and reserves, each of which can affect the amount of cash that is paid to our unitholders;
Our general partner determines in its sole discretion which costs incurred by NuStar GP Holdings and its affiliates are reimbursable by us;
Our general partner may cause us to pay the general partner or its affiliates for any services rendered on terms that are fair and reasonable to us or enter into additional contractual arrangements with any of these entities on our behalf;
Our general partner decides whether to retain separate counsel, accountants or others to perform services for us; and
In some instances, our general partner may cause us to borrow funds in order to permit the payment of distributions.

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

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

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

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

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

A successful IRS contest of the federal income tax positions we take may adversely impact the market for our units, and the costs of any contest will reduce cash available for distribution to our unitholders.
The IRS may adopt positions that differ from the positions we take, even positions taken with the advice of counsel. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take. A court may not agree

25

Table of Contents

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

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

The sale or exchange of 50% or more of our capital and profits interests, within a twelve-month period, will result in the termination of our partnership for federal income tax purposes.
A termination would, among other things, result in the closing of our taxable year for all unitholders and would result in a deferral of depreciation and cost recovery deductions allowable in computing our taxable income. If our partnership were terminated for federal income tax purposes, a NuStar Energy unitholder would be allocated an increased amount of federal taxable income for the year in which the partnership is considered terminated and the subsequent years as a percentage of the cash distributed to the unitholder with respect to that period.

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

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

We will treat each purchaser of our units as having the same tax benefits without regard to the units purchased. The IRS may challenge this treatment, which could adversely affect the value of our units.
Because we cannot match transferors and transferees of units, we will adopt depreciation and amortization positions that may not conform to all aspects of existing Treasury regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to unitholders. It also could affect the timing of these tax benefits or the amount of gain from any sale of units and could have a negative impact on the value of our units or result in audit adjustments to a unitholder’s tax returns.

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

We have adopted certain valuation methodologies that may result in a shift of income, gain, loss and deduction between the general partner and the unitholders. The IRS may challenge this treatment, which could adversely affect the value of our common units.
When we issue additional units or engage in certain other transactions, we determine the fair market value of our assets and allocate any unrealized gain or loss attributable to our assets to the capital accounts of our unitholders and our general partner. Our methodology may be viewed as understating the value of our assets. In that case, there may be a shift of income, gain, loss and deduction between certain unitholders and the general partner, which may be unfavorable to such unitholders. Moreover,

26

Table of Contents

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

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

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

PROPERTIES

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

ITEM 1B. UNRESOLVED STAFF COMMENTS
None.

ITEM 3. LEGAL PROCEEDINGS

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

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

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

27

Table of Contents

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

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

ITEM 4. MINE SAFETY DISCLOSURES
Not applicable.

28

Table of Contents

PART II

ITEM 5.
MARKET FOR REGISTRANT’S COMMON UNITS, RELATED UNITHOLDER MATTERS AND ISSUER PURCHASES OF COMMON UNITS
Market Information, Holders and Distributions
Our common units are listed and traded on the New York Stock Exchange under the symbol “NS.” At the close of business on February 9, 2015, we had 576 holders of record of our common units. The high and low sales prices (composite transactions) by quarter for the years ended December 31, 2014 and 2013 were as follows:
 
Price Range of Common Unit
 
High
 
Low
Year 2014
 
 
 
4th Quarter
$
66.94

 
$
50.91

3rd Quarter
68.33

 
61.02

2nd Quarter
62.88

 
53.76

1st Quarter
55.15

 
47.51

Year 2013
 
 
 
4th Quarter
$
53.69

 
$
39.52

3rd Quarter
46.52

 
36.15

2nd Quarter
54.95

 
42.31

1st Quarter
53.45

 
43.40

Our partnership agreement requires that we distribute all “Available Cash” to our partners each quarter, and this term is defined in the partnership agreement as cash on hand at the end of the quarter, plus certain permitted borrowings made subsequent to the end of the quarter, less cash reserves determined by our board of directors. See Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” for further information regarding our sources of cash to fund distributions. The cash distributions applicable to each of the quarters in the years ended December 31, 2014 and 2013 were as follows:
 
Record Date
 
Payment Date
 
Amount
Per Unit
Year 2014
 
 
 
 
 
4th Quarter
February 9, 2015
 
February 13, 2015
 
$
1.095

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

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

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

Year 2013
 
 
 
 
 
4th Quarter
February 10, 2014
 
February 14, 2014
 
$
1.095

3rd Quarter
November 11, 2013
 
November 14, 2013
 
1.095

2nd Quarter
August 5, 2013
 
August 9, 2013
 
1.095

1st Quarter
May 6, 2013
 
May 10, 2013
 
1.095

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

29

Table of Contents

Our general partner’s incentive distributions totaled $43.2 million for each of the years ended December 31, 2014 and 2013. The general partner’s share of our distributions for the years ended December 31, 2014 and 2013 was 13.0% in each year due to the impact of the incentive distributions.

The following table sets forth the purchases of our common units made during the quarter ended December 31, 2014 by or on behalf of us or an affiliated purchaser:
Period
 
Total Number of Units Purchased(1)
 
Average Price Paid per Unit(1)
 
Total Number of Units Purchased as Part of Publicly Announced Plans or Programs
 
Maximum Number (or Approximate Dollar Value) of Units that May Yet Be Purchased Under the Plans or Programs
October 1 through October 31
 

 
$

 

 
$

November 1 through November 30
 

 

 

 

December 1 through December 31
 
25,000

 
52.80

 

 

Total
 
25,000

 
$
52.80

 

 
$

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

ITEM 6. SELECTED FINANCIAL DATA
The following table contains selected financial data derived from our audited financial statements. On January 1, 2013, we sold the San Antonio Refinery. As a result, we have presented the results of operations for the San Antonio Refinery and related assets as discontinued operations for all periods presented. As of December 31, 2013, we reclassified certain storage assets as “Assets held for sale” on the consolidated balance sheet. As a result, we have presented the results of operations for those assets as discontinued operations for all periods presented.
 
Year Ended December 31,
 
2014
 
2013 (a)
 
2012 (a)
 
2011
 
2010
 
(Thousands of Dollars, Except Per Unit Data)
Statement of Income Data:
 
 
 
 
 
 
 
 
 
Revenues
$
3,075,118

 
$
3,463,732

 
$
5,945,736

 
$
6,257,629

 
$
4,395,083

Operating income (loss)
346,901

 
(19,121
)
 
(18,168
)
 
310,883

 
306,747

Income (loss) from continuing operations
214,169

 
(185,509
)
 
(166,001
)
 
218,674

 
243,931

Income (loss) from continuing operations per
unit applicable to limited partners
2.14

 
(2.89
)
 
(2.79
)
 
2.74

 
3.27

Cash distributions per unit applicable to
limited partners
4.380

 
4.380

 
4.380

 
4.360

 
4.280

 
 
 
 
 
 
 
 
 
 
 
December 31,
 
2014
 
2013
 
2012
 
2011
 
2010
 
(Thousands of Dollars)
Balance Sheet Data:
 
 
 
 
 
 
 
 
 
Property, plant and equipment, net
$
3,460,732

 
$
3,310,653

 
$
3,238,460

 
$
3,430,468

 
$
3,187,457

Total assets
4,918,796

 
5,032,186

 
5,613,089

 
5,881,190

 
5,386,393

Long-term debt, less current portion
2,749,452

 
2,655,553

 
2,124,582

 
1,928,071

 
2,136,248

Total partners’ equity
1,716,210

 
1,903,794

 
2,584,995

 
2,864,335

 
2,702,700


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

30

Table of Contents

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

If one or more of these risks or uncertainties materialize, or if the underlying assumptions prove incorrect, our actual results may vary materially from those described in any forward-looking statement. Other unknown or unpredictable factors could also have material adverse effects on our future results. Readers are cautioned not to place undue reliance on this forward-looking information, which is as of the date of the Form 10-K. We do not intend to update these statements unless we are required by the securities laws to do so, and we undertake no obligation to publicly release the result of any revisions to any such forward-looking statements that may be made to reflect events or circumstances after the date of this report or to reflect the occurrence of unanticipated events.
OVERVIEW
NuStar Energy L.P. (NuStar Energy) (NYSE: NS) is engaged in the transportation of petroleum products and anhydrous ammonia, the terminalling and storage of petroleum products and the marketing of petroleum products. Unless otherwise indicated, the terms “NuStar Energy,” “the Partnership,” “we,” “our” and “us” are used in this report to refer to NuStar Energy, to one or more of our consolidated subsidiaries or to all of them taken as a whole. NuStar GP Holdings, LLC (NuStar GP Holdings) (NYSE: NSH) owns our general partner, Riverwalk Logistics, L.P., and owns a 14.9% total interest in us as of December 31, 2014. Our Management’s Discussion and Analysis of Financial Condition and Results of Operations is presented in seven sections:
Overview
Results of Operations
Trends and Outlook
Liquidity and Capital Resources
Related Party Transactions
Critical Accounting Policies
New Accounting Pronouncements
Dispositions and Acquisitions
Asphalt Dispositions. On September 28, 2012, we sold a 50% ownership interest (the 2012 Asphalt Sale) in NuStar Asphalt LLC, previously a wholly owned subsidiary, to an affiliate of Lindsay Goldberg LLC (Lindsay Goldberg), a private investment firm. NuStar Asphalt LLC owns and operates the asphalt refining assets that were previously wholly owned by NuStar Energy, including an asphalt refinery located in Paulsboro, New Jersey and a terminal in Savannah, Georgia (collectively, the Asphalt Operations). Lindsay Goldberg paid $175.0 million for the Class A equity interests (Class A Interests) of NuStar Asphalt LLC, while we retained the Class B equity interests with a fair value of $52.0 million (Class B Interests). We also received $263.8 million from NuStar Asphalt LLC for inventory related to the Asphalt Operations. At closing, the fair value of the consideration we received was less than the carrying amount of the assets of the Asphalt Operations, and we recognized a loss of $23.8 million in “Other income (expense), net” in the consolidated statements of income for the year ended December 31, 2012. Upon closing, we deconsolidated NuStar Asphalt LLC and started reporting our remaining investment in NuStar Asphalt LLC using the equity method of accounting.

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

31

Table of Contents

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

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

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

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

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

TexStar Asset Acquisition. On December 13, 2012, we acquired the TexStar Crude Oil Assets (as defined below) from TexStar Midstream Services, LP and certain of its affiliates (collectively, TexStar) for $325.4 million (the TexStar Asset Acquisition), pursuant to an asset purchase agreement. The TexStar Crude Oil Assets consist of approximately 140 miles of crude oil pipelines and gathering lines, as well as five terminals and storage facilities providing 0.6 million barrels of storage capacity. The consolidated statements of income include the results of operations for the TexStar Asset Acquisition in the pipeline segment commencing on December 13, 2012.
2013 Goodwill Impairment
In the fourth quarter of 2013, we recognized a $304.5 million goodwill impairment loss in the storage segment, which represents the write-down of the carrying value of goodwill associated with our St. Eustatius and Point Tupper terminal operations. Please refer to Note 11 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for a discussion of the goodwill impairment loss.
Operations
We conduct our operations through our subsidiaries, primarily NuStar Logistics, L.P. (NuStar Logistics) and NuStar Pipeline Operating Partnership L.P. (NuPOP). Our operations are divided into three reportable business segments: pipeline, storage and fuels marketing. For a more detailed description of our segments, please refer to Segments under Item 1. “Business.”

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

32

Table of Contents

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

Storage. We own terminals and storage facilities in the United States, Canada, Mexico, the Netherlands, including St. Eustatius in the Caribbean, and the United Kingdom (UK) providing approximately 80.9 million barrels of storage capacity.

Fuels Marketing. Within our fuels marketing operations, we purchase crude oil and refined petroleum products for resale. Our fuels marketing segment includes our fuels marketing operations and, prior to the 2012 Asphalt Sale, the Asphalt Operations. The results of operations for the fuels marketing segment depend largely on the margin between our cost and the sales prices of the products we market. Therefore, the results of operations for this segment are more sensitive to changes in commodity prices compared to the operations of the pipeline and storage segments.

We enter into derivative contracts to attempt to mitigate the effects of commodity price fluctuations. The derivative instruments we use consist primarily of commodity futures and swap contracts. Not all of our derivative instruments qualify for hedge accounting treatment under U.S. generally accepted accounting principles. In such cases, we record the changes in the fair values of these derivative instruments in cost of product sales. The changes in the fair values of these derivative instruments generally are offset, at least partially, by changes in the values of the hedged physical inventory. However, we do not recognize those changes in the value of the hedged inventory until the physical sale of such inventory takes place. Therefore, our earnings for a period may include the gain or loss related to derivative instruments without including the offsetting effect of the hedged item, which could result in greater earnings volatility. In addition, we value our inventory at the lower of cost or market. If changes in commodity markets cause market prices to fall below the cost of our inventory, we may be required to reduce the value of our inventory to market.
Factors That Affect Results of Operations
The following factors affect the results of our operations:
company-specific factors, such as facility integrity issues and maintenance requirements that impact the throughput rates of our assets;
seasonal factors that affect the demand for products transported by and/or stored in our assets and the demand for products we sell;
industry factors, such as changes in the prices of petroleum products that affect demand and operations of our competitors;
factors such as commodity price volatility that impact our fuels marketing segment; and
other factors, such as refinery utilization rates and maintenance turnaround schedules, that impact the operations of refineries served by our pipeline and storage assets.


33

Table of Contents

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

 
$
938,138

 
$
88,308

Product sales
2,048,672

 
2,525,594

 
(476,922
)
Total revenues
3,075,118

 
3,463,732

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

 
2,453,997

 
(486,469
)
Operating expenses
472,925

 
454,396

 
18,529

General and administrative expenses
96,056

 
91,086

 
4,970

Depreciation and amortization expense
191,708

 
178,921

 
12,787

Goodwill impairment loss

 
304,453

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

 
3,482,853

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

 
(19,121
)
 
366,022

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

 
(39,970
)
 
44,766

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

 
6,113

 
(5,058
)
Other income, net
4,499

 
7,341

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

 
(172,756
)
 
397,726

Income tax expense
10,801

 
12,753

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

 
(185,509
)
 
399,678

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

Net income (loss)
$
210,378

 
$
(284,671
)
 
$
495,049

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


Continuing operations
$
2.14

 
$
(2.89
)
 
$
5.03

Discontinued operations
(0.04
)
 
(1.11
)
 
1.07

Total
$
2.10

 
$
(4.00
)
 
$
6.10

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

 
77,886,078

 



34

Table of Contents

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


35

Table of Contents

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

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

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

36

Table of Contents

a decrease of $1.6 million at our Point Tupper, Canada terminal facility, mainly due to lower throughput and related handling fees; and
a decrease of $0.9 million at our St. James terminal, mainly due to the narrowing price differential on two traded crude oil grades (WTI and LLS) that reduced our profit sharing and volumes delivered to one of our unit train offloading facilities. This decrease was partially offset by increased revenues resulting from the completion of another unit train offloading facility in the fourth quarter of 2013, new contracts and rate increases.

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

37

Table of Contents

Year Ended December 31, 2013 Compared to Year Ended December 31, 2012
Financial Highlights
(Thousands of Dollars, Except Unit and Per Unit Data)
 
Year Ended December 31,
 
 
 
2013
 
2012
 
Change
Statement of Income Data:
 
Revenues:
 
 
 
 
 
Service revenues
$
938,138

 
$
870,157

 
$
67,981

Product sales
2,525,594

 
5,075,579

 
(2,549,985
)
Total revenues
3,463,732

 
5,945,736

 
(2,482,004
)
 
 
 
 
 
 
Costs and expenses:
 
 
 
 
 
Cost of product sales
2,453,997

 
4,930,174

 
(2,476,177
)
Operating expenses
454,396

 
526,145

 
(71,749
)
General and administrative expenses
91,086

 
104,756

 
(13,670
)
Depreciation and amortization expense
178,921

 
159,789

 
19,132

Goodwill impairment loss
304,453

 
22,132

 
282,321

Asset impairment loss

 
249,646

 
(249,646
)
Gain on legal settlement

 
(28,738
)
 
28,738

Total costs and expenses
3,482,853

 
5,963,904

 
(2,481,051
)
 
 
 
 
 
 
Operating loss
(19,121
)
 
(18,168
)
 
(953
)
Equity in loss of joint ventures
(39,970
)
 
(9,378
)
 
(30,592
)
Interest expense, net
(127,119
)
 
(90,535
)
 
(36,584
)
Interest income from related party
6,113

 
1,219

 
4,894

Other income (expense), net
7,341

 
(24,689
)
 
32,030

Loss from continuing operations before income tax expense
(172,756
)
 
(141,551
)
 
(31,205
)
Income tax expense
12,753

 
24,450

 
(11,697
)
Loss from continuing operations
(185,509
)
 
(166,001
)
 
(19,508
)
Loss from discontinued operations, net of tax
(99,162
)
 
(61,236
)
 
(37,926
)
Net loss
$
(284,671
)
 
$
(227,237
)
 
$
(57,434
)
Net loss per unit applicable to limited partners:
 
 
 
 


Continuing operations
$
(2.89
)
 
$
(2.79
)
 
$
(0.10
)
Discontinued operations
(1.11
)
 
(0.82
)
 
(0.29
)
Total
$
(4.00
)
 
$
(3.61
)
 
$
(0.39
)
Weighted-average limited partner units outstanding
77,886,078

 
72,957,417

 
4,928,661




38

Table of Contents

Segment Operating Highlights
(Thousands of Dollars, Except Barrel/Day Information)
 
Year Ended December 31,
 
 
 
2013
 
2012
 
Change
Pipeline:
 
 
 
 
 
Refined products pipelines throughput (barrels/day)
487,021

 
498,321

 
(11,300
)
Crude oil pipelines throughput (barrels/day)
365,749

 
345,648

 
20,101

Total throughput (barrels/day)
852,770

 
843,969

 
8,801

Throughput revenues
$
411,529

 
$
340,455

 
$
71,074

Operating expenses
134,365

 
128,987

 
5,378

Depreciation and amortization expense
68,871

 
52,878

 
15,993

Segment operating income
$
208,293

 
$
158,590

 
$
49,703

 
 
 
 
 
 
Storage:
 
 
 
 
 
Throughput (barrels/day)
781,213

 
765,556

 
15,657

Throughput revenues
$
104,553

 
$
95,612

 
$
8,941

Storage lease revenues
451,996

 
482,454

 
(30,458
)
Total revenues
556,549

 
578,066

 
(21,517
)
Operating expenses
279,712

 
288,881

 
(9,169
)
Depreciation and amortization expense
99,868

 
88,217

 
11,651

Goodwill and asset impairment loss
304,453

 
2,126

 
302,327

Segment operating (loss) income
$
(127,484
)
 
$
198,842

 
$
(326,326
)
 
 
 
 
 
 
Fuels Marketing:
 
 
 
 
 
Product sales and other revenue
$
2,527,698

 
$
5,086,383

 
$
(2,558,685
)
Cost of product sales
2,474,612

 
4,957,100

 
(2,482,488
)
Gross margin
53,086

 
129,283

 
(76,197
)
Operating expenses
53,185

 
148,458

 
(95,273
)
Depreciation and amortization expense
27

 
11,253

 
(11,226
)
Goodwill and asset impairment loss

 
266,357

 
(266,357
)
Segment operating loss
$
(126
)
 
$
(296,785
)
 
$
296,659

 
 
 
 
 
 
Consolidation and Intersegment Eliminations:
 
 
 
 
 
Revenues
$
(32,044
)
 
$
(59,168
)
 
$
27,124

Cost of product sales
(20,615
)
 
(26,926
)
 
6,311

Operating expenses
(12,866
)
 
(40,181
)
 
27,315

Total
$
1,437

 
$
7,939

 
$
(6,502
)
 
 
 
 
 
 
Consolidated Information:
 
 
 
 
 
Revenues
$
3,463,732

 
$
5,945,736

 
$
(2,482,004
)
Cost of product sales
2,453,997

 
4,930,174

 
(2,476,177
)
Operating expenses
454,396

 
526,145

 
(71,749
)
Depreciation and amortization expense
168,766

 
152,348

 
16,418

Goodwill and asset impairment loss
304,453

 
268,483

 
35,970

Segment operating income
82,120

 
68,586

 
13,534

General and administrative expenses
91,086

 
104,756

 
(13,670
)
Other depreciation and amortization expense
10,155

 
7,441

 
2,714

Other asset impairment loss

 
3,295

 
(3,295
)
Gain on legal settlement

 
(28,738
)
 
28,738

Consolidated operating loss
$
(19,121
)
 
$
(18,168
)
 
$
(953
)

39

Table of Contents

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

Loss from continuing operations increased $19.5 million for the year ended December 31, 2013, compared to the year ended December 31, 2012, primarily due to an increase of $36.6 million in interest expense, net and an increase of $30.6 million in the equity in loss of joint ventures. Loss from discontinued operations, net of tax, increased $37.9 million for the year ended December 31, 2013, compared to the year ended December 31, 2012, mainly due to asset impairment charges of $102.5 million in 2013 associated with certain storage assets that were classified as “Assets held for sale” on the consolidated balance sheet as of December 31, 2013. Discontinued operations also include the results of operations for the San Antonio Refinery and related assets. As a result, we reported a net loss of $284.7 million for the year ended December 31, 2013, compared to a net loss of $227.2 million for the year ended December 31, 2012.
Pipeline
Revenues increased $71.1 million and throughputs increased 8,801 barrels per day for the year ended December 31, 2013, compared to the year ended December 31, 2012, primarily due to:
an increase in revenues of $57.4 million and an increase in throughputs of 49,855 barrels per day on crude oil pipelines that serve Eagle Ford Shale production in South Texas, primarily resulting from the TexStar Asset Acquisition and crude oil pipelines that were placed in service in the fourth quarter of 2012 and third quarter of 2013;
an increase in revenues of $6.3 million on the East Pipeline, despite lower throughputs of 2,997 barrels per day, due to higher average tariffs resulting from the annual index adjustment in July 2013 and increased long-haul deliveries;
an increase in revenues of $5.6 million and an increase in throughputs of 2,067 barrels per day on the North Pipeline, mainly due to the completion of an expansion project at the Mandan refinery in June 2012; and
an increase in revenues of $5.2 million and an increase in throughputs of 4,210 barrels per day on refined product and crude oil pipelines serving the McKee refinery resulting from increased volumes on pipelines with higher tariffs.

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

Revenues decreased $3.9 million and throughputs decreased 5,613 barrels per day on the Ammonia Pipeline due to unseasonably cold and wet weather in the second and fourth quarters of 2013. Also, revenues decreased $1.6 million and throughputs decreased 6,731 barrels per day on the Houston pipeline as it is being converted to new service.
Operating expenses increased $5.4 million for the year ended December 31, 2013, compared to the year ended December 31, 2012, primarily due to an increase of $18.6 million on crude oil pipelines that serve Eagle Ford Shale production in South Texas, mainly resulting from the TexStar Asset Acquisition and crude oil pipelines that were placed in service in the fourth quarter of 2012.
This increase was partially offset by:
a decrease of $8.0 million resulting from the reduction of the contingent consideration liability recorded in association with the TexStar Asset Acquisition; and
a decrease of $3.5 million due to temporary barge rental costs in 2012 needed to transport a customer’s product in conjunction with an Eagle Ford Shale project.
Depreciation and amortization expense increased $16.0 million for the year ended December 31, 2013, compared to the year ended December 31, 2012, mainly due to the TexStar Asset Acquisition in December 2012 and the completion of various projects that serve Eagle Ford Shale production.

40

Table of Contents

Storage
Throughput revenues increased $8.9 million and throughputs increased 15,657 barrels per day for the year ended December 31, 2013, compared to the year ended December 31, 2012. Revenues increased $14.3 million and throughputs increased 73,741 barrels per day at our Corpus Christi crude storage tank facility due to increased volumes of Eagle Ford Shale crude oil being shipped to Corpus Christi on our pipelines in South Texas. The TexStar Asset Acquisition in December 2012, the completion of several pipeline capital projects in 2012 and 2013 and changing our Corpus Christi crude storage tank facility from a lease-based to a throughput-based facility in the third quarter of 2012 were among the drivers for the increased volumes. These increases were partially offset by decreased throughputs of 53,768 barrels per day and decreased revenues of $5.2 million resulting from turnarounds, maintenance and operational issues in 2013 at the refineries served by our Corpus Christi, Texas City and Benicia crude oil storage tanks and our Three Rivers refined products terminals.
Storage lease revenues decreased $30.5 million for the year ended December 31, 2013, compared to the year ended December 31, 2012, primarily due to:
a decrease of $26.6 million at various domestic terminals, mainly as a result of reduced demand in several markets, resulting in lower throughputs, storage fees and reimbursable revenues;
a decrease of $7.7 million at our UK and Amsterdam terminals, mainly due to reduced demand for storage and the effect of foreign exchange rates;
a decrease of $7.6 million at our St. Eustatius terminal facility, mainly due to reduced demand for storage and decreased reimbursable revenue;
a decrease of $6.2 million at our Corpus Christi crude storage tank facility due to the change to throughput-based fees in July 2012;
a decrease of $3.8 million at asphalt terminals under storage agreements with Axeon, which we entered into simultaneously with the 2012 Asphalt Sale; and
a decrease of $2.9 million due to the sale of five refined product terminals in April 2012.

Those declines in storage lease revenues were partially offset by an increase in storage lease revenues of $19.2 million resulting from a completed unit train offloading facility at our St. James terminal and completed tank expansion projects at our St. James and St. Eustatius terminals. In addition, revenues increased $5.2 million as a result of our acquisition of a lease at the Red Fish Bay terminal in conjunction with the TexStar Asset Acquisition.
Operating expenses decreased $9.2 million for the year ended December 31, 2013, compared to the year ended December 31, 2012, primarily due to:
a decrease of $9.0 million associated with cancelled capital projects, mainly at our St. James and St. Eustatius terminals in 2012; and
a decrease of $6.3 million in reimbursable expenses, mainly for tank cleanings at our Piney Point terminal and maintenance expenses at our St. Eustatius terminal. Reimbursable expenses are charged back to our customers and are offset by reimbursable revenues.

These decreases were partially offset by an increase of $3.9 million in salaries and wages due to a collective labor agreement that became effective in mid-2012 associated with our St. Eustatius terminal, our acquisition of a lease at the Redfish Bay terminal in conjunction with the TexStar Asset Acquisition, and higher employee benefit and temporary labor costs.
Depreciation and amortization expense increased $11.7 million for the year ended December 31, 2013, compared to the year ended December 31, 2012, primarily due to completion of a dock optimization project at our Corpus Christi crude storage tank facility, unit train and tank expansion projects at our St. James terminal and a tank expansion project at our St. Eustatius terminal.
The asset impairment loss of $304.5 million for the year ended December 31, 2013 represents the write-down of the carrying value of goodwill associated with our St. Eustatius and Point Tupper terminal operations. Please refer to Note 11 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for further discussion of this goodwill impairment.
Fuels Marketing
The consolidated statements of income (loss) include the results of operations for Axeon in “Equity in earnings (loss) of joint ventures” commencing on September 28, 2012. Previously, we reported the results of operations for our Asphalt Operations in the fuels marketing segment. For the year ended December 31, 2013, this segment mainly includes refined products marketing, crude oil trading, fuel oil trading and bunkering operations.

41

Table of Contents

The following table presents pro forma financial information that removes the historical financial information for our Asphalt Operations from the segment results for the year ended December 31, 2012 in order to provide a more meaningful comparison of the segment’s results.
 
 
 
Year Ended December 31, 2012
 
 
 
Year Ended
December 31, 2013
 
Actual
 
Asphalt Operations
 
Pro Forma
 
Change
 
(Thousands of Dollars)
Product sales
$
2,527,698

 
$
5,086,383

 
$
1,315,986

 
$
3,770,397

 
$
(1,242,699
)
Cost of product sales
2,474,612

 
4,957,100

 
1,258,308

 
3,698,792

 
(1,224,180
)
Gross margin
53,086

 
129,283

 
57,678

 
71,605

 
(18,519
)
Operating expenses
53,185

 
148,458

 
89,969

 
58,489

 
(5,304
)
Depreciation and amortization expense
27

 
11,253

 
11,138

 
115

 
(88
)
Asset and goodwill impairment loss

 
266,357

 
266,357

 

 

Segment operating (loss) income
$
(126
)
 
$
(296,785
)
 
$
(309,786
)
 
$
13,001

 
$
(13,127
)

Sales and cost of product sales decreased $1,242.7 million and $1,224.2 million, respectively, resulting in a decrease in total gross margin of $18.5 million for the year ended December 31, 2013, compared to the year ended December 31, 2012. The decrease in total gross margin was primarily due to a positive gross margin of $12.0 million from crude oil trading in 2012, as compared to a gross margin loss of $0.3 million in 2013. In 2012, higher volumes were traded in the first part of 2012 to benefit from the price differential on two traded crude oil grades (WTI and LLS). In addition, the gross margin from bunker fuel sales decreased $9.8 million for the year ended December 31, 2013, compared to the year ended December 31, 2012, mainly at our St. Eustatius and Texas City facilities. Reduced demand for bunker fuels and increased competition in the Caribbean and the U.S. Gulf Coast has negatively impacted our sales prices and resulted in lower gross margins as compared to the same period last year. These decreases were partially offset by an increase of $3.7 million in the gross margin from fuel oil trading attributable to lower costs that outweighed falling sales prices compared to the same period last year.
Operating expenses decreased $5.3 million for the year ended December 31, 2013, compared to the year ended December 31, 2012, mainly due to a decrease in operating expenses from our bunker fuel operations as we exited certain U.S. markets.
Consolidation and Intersegment Eliminations
Revenue and operating expense eliminations primarily relate to storage and transportation fees charged to the fuels marketing segment by the storage and pipeline segments. Revenue and operating expense eliminations changed by $27.1 million and $27.3 million, respectively, for the year ended December 31, 2013, compared to the year ended December 31, 2012, mainly due to the 2012 Asphalt Sale. Cost of product sales eliminations represent expenses charged to the fuels marketing segment for costs associated with inventory that are expensed once the inventory is sold.
General
General and administrative expenses decreased $13.7 million for the year ended December 31, 2013, compared to the year ended December 31, 2012, primarily due to the early termination of a lease for our previous corporate office and expenses that were reimbursed by Axeon for corporate support services under a services agreement between Axeon and NuStar GP, LLC. In addition, general and administrative expenses in the second quarter of 2012 included costs that resulted from a Canadian income tax audit.
Other depreciation and amortization expense increased $2.7 million for the year ended December 31, 2013, compared to the year ended December 31, 2012, mainly due to the completion of our corporate office in the fourth quarter of 2012.
The other asset impairment loss of $3.3 million for the year ended December 31, 2012 represents the write-down of the carrying value of certain corporate assets we sold in 2013.
The gain on legal settlement of $28.7 million for the year ended December 31, 2012 represents the settlement of a legal matter in the second quarter of 2012.
Equity in loss of joint ventures increased $30.6 million for the year ended December 31, 2013, compared to the year ended December 31, 2012, primarily due to a $49.6 million loss from our investment in Axeon in 2013, which continued to suffer from weak asphalt margins.

42

Table of Contents

Interest expense, net increased $36.6 million for the year ended December 31, 2013, compared to the year ended December 31, 2012, mainly due to the issuance of the $402.5 million of 7.625% fixed-to-floating rate subordinated notes in January 2013.
Interest income from related party increased $4.9 million for the year ended December 31, 2013, compared to the year ended December 31, 2012, as a result of a full year of borrowings by Axeon under the NuStar JV Facility that we entered into with Axeon in connection with the 2012 Asphalt Sale on September 28, 2012. Please refer to Note 19 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for additional information on our agreements with Axeon.
Other income (expense), net changed by $32.0 million for the year ended December 31, 2013, compared to the year ended December 31, 2012, mainly due to a loss of $23.8 million associated with the 2012 Asphalt Sale and changes in foreign exchange rates related to our foreign subsidiaries.
Income tax expense decreased $11.7 million for the year ended December 31, 2013, compared to the year ended December 31, 2012, mainly due to tax expense of $10.1 million related to the $28.7 million gain on legal settlement recognized in the second quarter of 2012.
For the year ended December 31, 2013, we recorded a loss from discontinued operations of $99.2 million, compared to a loss from discontinued operations of $61.2 million for the year ended December 31, 2012. For the year ended December 31, 2013, the loss from discontinued operations includes asset impairment charges of $102.5 million associated with certain storage terminals that were classified as “Assets held for sale” on the consolidated balance sheet as of December 31, 2013. Please refer to Note 5 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for further discussion of these asset impairment charges. This loss was partially offset by a gain of $9.3 million related to the San Antonio Refinery Sale.
For the year ended December 31, 2012, the loss from discontinued operations includes losses of $49.1 million from the San Antonio Refinery, mainly due to hedge losses and falling sales prices coupled with high weighted-average costs, which resulted in an overall negative gross margin.

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

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

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

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

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


43

Table of Contents

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

Our partnership agreement requires that we distribute all “Available Cash” to our partners each quarter, and this term is defined in the partnership agreement as cash on hand at the end of the quarter, plus certain permitted borrowings made subsequent to the end of the quarter, less cash reserves determined by our board of directors.

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

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

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

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

Cash Flows for the Years Ended December 31, 2014, 2013 and 2012
The following table summarizes our cash flows from operating, investing and financing activities:
 
Year Ended December 31,
 
2014
 
2013
 
2012
 
(Thousands of Dollars)
Net cash provided by (used in):
 
 
 
 
 
Operating activities
$
518,523

 
$
485,219

 
$
299,203

Investing activities
(340,231
)
 
(310,961
)
 
(345,800
)
Financing activities
(188,185
)
 
(149,350
)
 
110,669

Effect of foreign exchange rate changes on cash
(2,938
)
 
(7,767
)
 
2,033

Net (decrease) increase in cash and cash equivalents
$
(12,831
)
 
$
17,141

 
$
66,105

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

44

Table of Contents

December 31, 2013. Please refer to the Working Capital Requirements section below for a discussion of the changes in working capital.
For the year ended December 31, 2014, net cash provided by operating activities was used to fund our distributions to unitholders and our general partner in the aggregate amount of $392.2 million and to fund $28.6 million of reliability capital expenditures. The proceeds from debt borrowings, net of repayments, combined with net cash provided by operating activities and proceeds from the sales of assets, were used to fund strategic capital expenditures primarily related to our pipeline and storage segments and advances to Axeon under the NuStar JV Facility.

Net cash provided by operating activities for the year ended December 31, 2013 was $485.2 million, compared to $299.2 million for the year ended December 31, 2012, or an increase of $186.0 million. For the year ended December 31, 2013, we reported a net loss of $284.7 million, which included $407.0 million of non-cash goodwill and asset impairment charges, while the net loss for the year ended December 31, 2012 of $227.2 million included $271.8 million of non-cash asset impairment charges. Equity in loss of joint ventures increased to $40.0 million for the year ended December 31, 2013, compared to $9.4 million for the year ended December 31, 2012, mainly due to losses from our investment in Axeon. Changes in working capital provided cash flow of $112.8 million for the year ended December 31, 2013, compared to $90.2 million for the year ended December 31, 2012.
For the year ended December 31, 2013, net cash provided by operating activities exceeded our distribution requirements and reliability capital expenditures. Proceeds from the San Antonio Refinery Sale and proceeds from long-term debt borrowings, net of repayments, combined with net cash provided by operating activities, were used to fund our strategic capital expenditures and advances to Axeon under the NuStar JV Facility.
For the year ended December 31, 2012, net cash provided by operating activities, proceeds from long-term debt borrowings, net of repayments, proceeds from our issuance of common units and proceeds from the 2012 Asphalt Sale were used to fund our distributions to unitholders and our general partner, the TexStar Asset Acquisition and strategic and reliability capital expenditures.
Revolving Credit Agreement
On October 29, 2014, NuStar Logistics amended and restated its $1.5 billion five-year revolving credit agreement (Revolving Credit Agreement), which matures on October 29, 2019. The Revolving Credit Agreement includes an option allowing NuStar Logistics to request an aggregate increase in the commitments from the lenders of up to $250.0 million (after which increase the aggregate commitment from all lenders shall not exceed $1.75 billion). The Revolving Credit Agreement also includes the ability to borrow up to the equivalent of $250.0 million in Euros and up to the equivalent of $250.0 million in British Pounds Sterling. Obligations under the Revolving Credit Agreement are guaranteed by NuStar Energy and NuPOP. NuPOP will be released from its guarantee of the Revolving Credit Agreement when it no longer guarantees indebtedness of NuStar Energy or its subsidiaries in an aggregate principal amount exceeding $200.0 million.
The Revolving Credit Agreement contains customary restrictive covenants, such as limitations on indebtedness, liens, mergers, asset transfers and certain investing activities. In addition, the Revolving Credit Agreement requires us to maintain, as of the end of each rolling period of four consecutive fiscal quarters, a consolidated debt coverage ratio (consolidated debt to consolidated EBITDA, each as defined in the Revolving Credit Agreement) not to exceed 5.00-to-1.00. If we consummate an acquisition for an aggregate net consideration of at least $50.0 million, the maximum consolidated debt coverage ratio will increase to 5.50-to-1.00 for two rolling periods. The Revolving Credit Agreement permits unlimited investments in joint ventures and unconsolidated subsidiaries, provided that no default exists and we would be in compliance with the consolidated debt coverage ratio, but limits the amount of cash distributions for such joint ventures and unconsolidated subsidiaries included in the calculation of the consolidated debt coverage ratio to 20% of consolidated EBITDA. The requirement not to exceed a maximum consolidated debt coverage ratio may limit the amount we can borrow under the Revolving Credit Agreement to an amount less than the total amount available for borrowing. As of December 31, 2014, our consolidated debt coverage ratio was 4.0x, and we had $842.3 million available for borrowing.
Letters of credit issued under our Revolving Credit Agreement totaled $56.2 million as of December 31, 2014. Letters of credit are limited to $750.0 million (including up to the equivalent of $25.0 million in Euros and up to the equivalent of $25.0 million in British Pounds Sterling) and also restrict the amount we can borrow under the Revolving Credit Agreement.
Please refer to Note 14 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for a more detailed discussion of our long-term debt agreements.

45

Table of Contents

Short-term Lines of Credit
In 2014, we entered into two short-term line of credit agreements with an aggregate uncommitted borrowing capacity of up to $80.0 million. These agreements allow us to better manage the fluctuations in our daily cash requirements and minimize our excess cash balances. The interest rate and maturity vary and are determined at the time of the borrowing. We had $77.0 million outstanding under these short-term lines of credit as of December 31, 2014.
Gulf Opportunity Zone Revenue Bonds
In 2008, 2010 and 2011, the Parish of St. James, where our St. James, Louisiana, terminal is located, issued Revenue Bonds (NuStar Logistics, L.P. Project) Series 2008, Series 2010, Series 2010A, Series 2010B and Series 2011 associated with our St. James terminal expansion pursuant to the Gulf Opportunity Zone Act of 2005 (collectively, the Gulf Opportunity Zone Revenue Bonds). The interest rates on these bonds are based on a weekly tax-exempt bond market interest rate, and interest is paid monthly. Following the issuance, the proceeds were deposited with a trustee and are disbursed to us upon our request for reimbursement of expenditures related to our St. James terminal expansion. The amount remaining in trust is included in “Other long-term assets, net,” and the amount of bonds issued is included in “Long-term debt, less current portion” in our consolidated balance sheets.
NuStar Logistics is solely obligated to service the principal and interest payments associated with the Gulf Opportunity Zone Revenue Bonds. Letters of credit were issued on our behalf to guarantee the payment of interest and principal on the bonds. All letters of credit rank equally with existing senior unsecured indebtedness of NuStar Logistics. The letters of credit issued by individual banks do not restrict the amount we can borrow under the Revolving Credit Agreement.
The following table summarizes the Gulf Opportunity Zone Revenue Bonds outstanding as of December 31, 2014:
Date Issued
 
Maturity Date
 
Amount
Outstanding
 
Amount of
Letter of
Credit
 
Amount Received from
Trustee
 
Amount Remaining in
Trust
 
Average Annual
Interest Rate
 
 
 
 
(Thousands of Dollars)
 
 
June 26, 2008
 
June 1, 2038
 
$
55,440

 
$
56,169

 
$
55,440

 
$

 
0.1
%
July 15, 2010
 
July 1, 2040
 
100,000

 
101,315

 
100,000

 

 
0.1
%
October 7, 2010
 
October 1, 2040
 
50,000

 
50,658

 
35,760

 
14,240

 
0.1
%
December 29, 2010
 
December 1, 2040
 
85,000

 
86,118

 
27,689

 
57,311

 
0.1
%
August 29, 2011
 
August 1, 2041
 
75,000

 
75,986

 
75,000

 

 
0.1
%
 
 
Total
 
$
365,440

 
$
370,246

 
$
293,889

 
$
71,551

 
 
Issuance of Debt
On August 19, 2013, NuStar Logistics issued $300.0 million of 6.75% senior notes due February 1, 2021 (the 6.75% Senior Notes). We received net proceeds of approximately $296.0 million, which we used for general partnership purposes, including repayment of outstanding borrowings under our Revolving Credit Agreement.
On January 22, 2013, NuStar Logistics issued $402.5 million of 7.625% fixed-to-floating rate subordinated notes due January 15, 2043 (the Subordinated Notes), including the underwriters’ option to purchase up to an additional $52.5 million principal amount of the notes, which was exercised in full. We received net proceeds of approximately $390.9 million, which we used for general partnership purposes, including repayment of outstanding borrowings under our Revolving Credit Agreement. The Subordinated Notes bear interest at a fixed annual rate of 7.625%, payable quarterly in arrears beginning on April 15, 2013 and ending on January 15, 2018. Thereafter, the Subordinated Notes will bear interest at an annual rate equal to the sum of the three-month LIBOR rate for the related quarterly interest period, plus 6.734% payable quarterly, commencing April 15, 2018, unless payment is deferred in accordance with the terms of the notes.
On February 2, 2012, NuStar Logistics issued $250.0 million of 4.75% senior notes due February 1, 2022. The net proceeds of $247.4 million were used to repay the outstanding principal amount of NuPOP’s $250.0 million 7.75% senior notes due February 15, 2012.
Please refer to Note 14 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for a more detailed discussion of our debt agreements.
Issuance of Common Units
On September 10, 2012, we issued 7,130,000 common units representing limited partner interests at a price of $48.94 per unit. We used the net proceeds from this offering of $343.9 million, including a contribution of $7.1 million from our gen