NS 2013 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, 2013
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. [X]
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule12b-2 of the Exchange Act: 
Large accelerated filer
 
[X]
  
Accelerated filer [    ]
 
 
 
 
Non-accelerated filer
 
[    ]  (Do not check if a smaller reporting company)
  
Smaller reporting company
 
[    ]
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes [    ] No [X]
The aggregate market value of the common units held by non-affiliates was approximately $3,086 million based on the last sales price quoted as of June 28, 2013, the last business day of the registrant’s most recently completed second quarter.
The number of common units outstanding as of January 31, 2014 was 77,886,078.


Table of Contents

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.
 
 



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PART I
Unless otherwise indicated, the terms “NuStar Energy L.P.,” “the Partnership,” “we,” “our” and “us” are used in this report to refer to NuStar Energy L.P., to one or more of our consolidated subsidiaries or to all of them taken as a whole. In the following Items 1., 1A. and 2., “Business, Risk Factors and Properties,” we make certain forward-looking statements, including statements regarding our plans, strategies, objectives, expectations, intentions and resources. The words “forecasts,” “intends,” “believes,” “expects,” “plans,” “scheduled,” “goal,” “may,” “anticipates,” “estimates” and similar expressions identify forward-looking statements. We do not undertake to update, revise or correct any of the forward-looking information. You are cautioned that such forward-looking statements should be read in conjunction with our disclosures beginning on page 32 of this report under the heading: “CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION.”

ITEM 1. BUSINESS, RISK FACTORS AND PROPERTIES

OVERVIEW
NuStar Energy L.P. (NuStar Energy), a Delaware limited partnership, completed its initial public offering of common units on April 16, 2001. Our common units are traded on the New York Stock Exchange (NYSE) under the symbol “NS.” Our principal executive offices are located at 19003 IH-10 West, San Antonio, Texas 78257 and our telephone number is (210) 918-2000.
We are engaged in the terminalling and storage of petroleum products, the transportation of petroleum products and anhydrous ammonia, and the marketing of petroleum products. We divide our operations into the following three reportable business segments: storage, pipeline, and fuels marketing. As of December 31, 2013, our assets included:
60 terminal and storage facilities providing 84.8 million barrels of storage capacity;
5,463 miles of refined product pipelines with 21 associated terminals providing storage capacity of 4.9 million barrels and two tank farms providing storage capacity of 1.4 million barrels;
2,000 miles of anhydrous ammonia pipelines; and
1,180 miles of crude oil pipelines providing 3.4 million barrels of associated storage capacity.
We conduct our operations through our wholly owned subsidiaries, primarily NuStar Logistics, L.P. (NuStar Logistics) and NuStar Pipeline Operating Partnership L.P. (NuPOP). Our revenues include:
tariffs for transporting crude oil, refined products and anhydrous ammonia through our pipelines;
fees for the use of our terminal and storage facilities and related ancillary services; and
sales of crude oil and refined petroleum products.
Our business strategy is to increase per unit cash distributions to our partners through:
continuous improvement of our operations by improving safety and environmental stewardship, cost controls and asset reliability and integrity;
internal growth through enhancing the utilization of our existing assets by expanding our business with current and new customers, as well as investments in strategic expansion projects;
external growth from acquisitions that meet our financial and strategic criteria;
identification of non-core assets that do not meet our financial and strategic criteria and evaluation of potential dispositions; and
complementary operations such as our fuels marketing operations, which provide us the opportunity to optimize the use and profitability of our assets.
The term “throughput” as used in this document generally refers to the crude oil or refined product barrels or tons of ammonia, as applicable, that pass through our pipelines, terminals, storage tanks or refineries.

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


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RECENT DEVELOPMENTS

Divestment of ownership interest in Asphalt JV
On February 26, 2014, we sold our then-remaining 50% ownership interest in NuStar Asphalt LLC (Asphalt JV), which constitutes all equity interest in that entity we retained after the first sale in 2012.   The purchaser, Lindsay Goldberg LLC (Lindsay Goldberg), a private investment firm, now owns 100% of Asphalt JV, and we have completed our exit from the asphalt business. Please refer to Note 29 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for additional information regarding this sale.

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

The following chart depicts our organizational structure at December 31, 2013.


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SEGMENTS
Our three reportable business segments are storage, pipeline, and fuels marketing. Detailed financial information about our segments is included in Note 26 in the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data.”
The following map depicts our operations at December 31, 2013.

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STORAGE
Our storage segment includes terminal and storage facilities that provide storage, handling and other services for petroleum products, specialty chemicals, crude oil and other liquids. As of December 31, 2013, we owned and operated:
48 terminal and storage facilities in the United States, with total storage capacity of 51.7 million barrels;
A terminal on the island of St. Eustatius with tank capacity of 14.4 million barrels and a transshipment facility;
A terminal located in Point Tupper with tank capacity of 7.7 million barrels and a transshipment facility;
Six terminals located in the United Kingdom and one terminal located in Amsterdam, the Netherlands, with total storage capacity of approximately 9.5 million barrels;
Two terminals in Mersin, Turkey with total storage capacity of 1.4 million barrels; and
A terminal located in Nuevo Laredo, Mexico.
Description of Largest Terminal Facilities
St. Eustatius. We own and operate a 14.4 million barrel petroleum storage and terminalling facility located on the island of St. Eustatius in the Caribbean, which is located at a point of minimal deviation from major shipping routes. This facility is capable of handling a wide range of petroleum products, including crude oil and refined products, and it can accommodate the world’s largest tankers for loading and discharging crude oil and other petroleum products. A two-berth jetty, a two-berth monopile with platform and buoy systems, a floating hose station and an offshore single point mooring buoy with loading and unloading capabilities serve the terminal’s customers’ vessels. The fuel oil and petroleum product facilities have in-tank and in-line blending capabilities, while the crude tanks have tank-to-tank blending capability and in-tank mixers. In addition to the storage and blending services at St. Eustatius, this facility has the flexibility to utilize certain storage capacity for both feedstock and refined products to support our atmospheric distillation unit. This unit is capable of processing up to 25,000 barrels per day of feedstock, ranging from condensates to heavy crude oil. We own and operate all of the berthing facilities at the St. Eustatius terminal. Separate fees apply for the use of the berthing facilities, as well as associated services, including pilotage, tug assistance, line handling, launch service, emergency response services and other ship services.
St. James, Louisiana. Our St. James terminal, which is located on the Mississippi River near St. James, Louisiana, has a total storage capacity of 8.9 million barrels. The facility is located on almost 900 acres of land, some of which is undeveloped. The majority of the storage tanks and infrastructure are suited for light crude oil, with four tanks capable of fuel oil or heated crude oil storage. Additionally, the facility has one barge dock and two ship docks. Our St. James terminal can receive product from gathering pipelines in the Gulf of Mexico and deliver to connecting pipelines that supply refineries in the Gulf Coast and Midwest. The St. James terminal also has two unit train rail facilities and a manifest rail facility, which are served by the Union Pacific Railroad and have a combined capacity of approximately 200,000 barrels per day.
Point Tupper. We own and operate a 7.7 million barrel terminalling and storage facility located at Point Tupper on the Strait of Canso, near Port Hawkesbury, Nova Scotia. This facility is the deepest independent, ice-free marine terminal on the North American Atlantic coast, with access to the East Coast, Canada and the Midwestern United States via the St. Lawrence Seaway and the Great Lakes system. With one of the premier jetty facilities in North America, the Point Tupper facility can accommodate substantially all of the world’s largest, fully laden very large crude carriers and ultra large crude carriers for loading and discharging crude oil, petroleum products and petrochemicals. Crude oil and petroleum product movements at the terminal are fully automated. Separate fees apply for the use of the jetty facility, as well as associated services, including pilotage, tug assistance, line handling, launch service, emergency response services and other ship services.
Piney Point, Maryland. Our terminal and storage facility in Piney Point is located on approximately 400 acres on the Potomac River. The Piney Point terminal has 5.4 million barrels of storage capacity and is the closest deep-water facility to Washington, D.C. This terminal competes with other large petroleum terminals in the East Coast water-borne market extending from New York Harbor to Norfolk, Virginia. The terminal has a dock with a 36-foot draft for tankers and four berths for barges. It also has truck-loading facilities and product-blending capabilities.

Amsterdam. Our Amsterdam terminal has a total storage capacity of 3.8 million barrels. This facility is located at the Port of Amsterdam and primarily stores petroleum products including gasoline, diesel and fuel oil. This facility has two docks for vessels and five docks for inland barges.
Linden, New Jersey. We own 50% of ST Linden Terminal LLC, which owns a terminal and storage facility in Linden, New Jersey. The terminal is located on a 44-acre facility that provides it with deep-water terminalling capabilities at New York Harbor. This terminal primarily stores petroleum products, including gasoline, jet fuel and fuel oils. The facility has a total storage capacity of 4.3 million barrels and can receive and deliver products via ship, barge and pipeline. The terminal includes two docks with draft limits of 36 and 26 feet, respectively.

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Terminal and Storage Facilities
The following table sets forth information about our terminal and storage facilities as of December 31, 2013:
 
Facility
Tank
Capacity
 
Primary Products Handled
 
(Barrels)
 
 
U.S. Terminals and Storage Facilities:
 
 
 
Mobile, AL (Blakely Island)
1,185,000

 
Petroleum products, crude oil and feedstocks
Mobile, AL (Chickasaw North)
333,000

 
Crude oil and feedstocks
Mobile, AL (Chickasaw South)
327,000

 
Petroleum products, crude oil and feedstocks
Los Angeles, CA
608,000

 
Petroleum products
Benicia, CA (Refinery Tankage)
3,655,000

 
Crude oil and feedstocks
Pittsburg, CA
398,000

 
Asphalt
Selby, CA
3,060,000

 
Petroleum products, ethanol
Stockton, CA
810,000

 
Petroleum products, ethanol, fertilizer
Colorado Springs, CO
328,000

 
Petroleum products, ethanol
Denver, CO
110,000

 
Petroleum products, ethanol
Jacksonville, FL
2,593,000

 
Petroleum products, asphalt
Blue Island, IL
732,000

 
Petroleum products, ethanol
Indianapolis, IN
428,000

 
Petroleum products
St. James, LA
8,943,000

 
Crude oil and feedstocks
Andrews AFB, MD (a)
75,000

 
Petroleum products
Baltimore, MD
827,000

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

 
Petroleum products
Wilmington, NC (f)
331,000

 
Asphalt
Linden, NJ
389,000

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

 
Petroleum products
Paulsboro, NJ
74,000

 
Petroleum products
Alamogordo, NM (a)
124,000

 
Petroleum products
Albuquerque, NM
251,000

 
Petroleum products, ethanol
Rosario, NM
166,000

 
Asphalt
Catoosa, OK
358,000

 
Asphalt
Portland, OR
1,359,000

 
Petroleum products, ethanol
Abernathy, TX
160,000

 
Petroleum products
Amarillo, TX
273,000

 
Petroleum products
Corpus Christi, TX
329,000

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

 
Crude oil and feedstocks
Corpus Christi, TX (Refinery Tankage)
4,030,000

 
Crude oil and feedstocks
Edinburg, TX
276,000

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

 
Petroleum products, ethanol
Harlingen, TX
286,000

 
Petroleum products
Houston, TX
91,000

 
Asphalt
Laredo, TX
219,000

 
Petroleum products
Placedo, TX (d)
100,000

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

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

 
Petroleum products
Southlake, TX
453,000

 
Petroleum products, ethanol
Texas City, TX
128,000

 
Petroleum products

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Facility
Tank
Capacity
 
Primary Products Handled
 
(Barrels)
 
 
Texas City, TX
2,878,000

 
Chemicals, petroleum products
Texas City, TX (Refinery Tankage)
3,141,000

 
Crude oil and feedstocks
Dumfries, VA (f)
556,000

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

 
Petroleum products
Tacoma, WA
413,000

 
Petroleum products, ethanol
Vancouver, WA
345,000

 
Chemicals
Vancouver, WA
433,000

 
Petroleum products
Total U.S.
51,672,000

 
 
 
 
 
 
Foreign Terminals and Storage Facilities:
 
 
 
St. Eustatius, the Netherlands
14,385,000

 
Petroleum products, crude oil and feedstocks
Amsterdam, the Netherlands
3,845,000

 
Petroleum products
Point Tupper, Canada
7,725,000

 
Petroleum products, crude oil and feedstocks
Grays, England
1,958,000

 
Petroleum products
Eastham, England
2,064,000

 
Chemicals, petroleum products
Runcorn, England
149,000

 
Molten sulfur
Grangemouth, Scotland
579,000

 
Petroleum products, chemicals
Glasgow, Scotland
401,000

 
Petroleum products
Belfast, Northern Ireland
480,000

 
Petroleum products
Mersin, Turkey (e)
790,000

 
Petroleum products
Mersin, Turkey (e)
656,000

 
Petroleum products
Nuevo Laredo, Mexico
50,000

 
Petroleum products
Total Foreign
33,082,000

 
 
 
 
 
 
Total Terminals and Storage Facilities
84,754,000

 
 
 
(a)
Terminal facility also includes pipelines to U.S. government military base locations.
(b)
We own 50% of this terminal through a joint venture. The tank capacity represents the proportionate share of capacity attributable to our ownership interest.
(c)
We own a 66.67% undivided interest in the El Paso refined product terminal. The tank capacity represents the proportionate share of capacity attributable to our ownership interest.
(d)
The Placedo, TX terminal is temporarily idled.
(e)
We own 75% of the outstanding capital of a Turkish company, which owns two terminals in Mersin, Turkey.
(f)
In February 2014, we divested these terminals in connection with the divestiture of our remaining 50% ownership interest in Asphalt JV. See Note 29 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for additional discussion.
Storage Operations
Revenues for the storage segment include fees for tank storage agreements, where a customer agrees to pay for a certain amount of storage in a tank over a period of time (storage lease revenues), and throughput agreements, where a customer pays a fee per barrel for volumes moving through our terminals (throughput revenues). Our terminals also provide blending, additive injections, handling and filtering services. We charge a fee for each barrel of crude oil and certain other feedstocks that we deliver to Valero Energy Corporation’s (Valero Energy) Benicia, Corpus Christi West and Texas City refineries from our crude oil storage tanks. Our facilities at Point Tupper and St. Eustatius charge fees to provide services such as pilotage, tug assistance, line handling, launch service, emergency response services and other ship services.

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Demand for Refined Petroleum Products and Crude Oil
The operations of our refined product terminals depend in large part on the level of demand for products stored in our terminals in the markets served by those assets. The majority of products stored in our terminals are refined petroleum products. Demand for our terminalling services will generally increase or decrease with demand for refined petroleum products, and demand for refined petroleum products tends to increase or decrease with the relative strength of the economy.
Crude oil throughputs coming to our St. James terminal through our unit train facilities, and crude oil throughputs at our Corpus Christi North Beach terminal will generally increase or decrease with crude oil production rates in the Bakken and Eagle Ford shale plays, respectively.
Customers
We provide storage and terminalling services for crude oil and refined petroleum products to many of the world’s largest producers of crude oil, integrated oil companies, chemical companies, oil traders and refiners. In addition, our blending capabilities in our storage assets have attracted customers who have leased capacity primarily for blending purposes. The largest customer of our storage segment is Valero Energy, which accounted for approximately 18% of the total revenues of the segment for the year ended December 31, 2013. No other customer accounted for more than 10% of the revenues of the segment for this period.
Competition and Business Considerations
Many major energy and chemical companies own extensive terminal storage facilities. Although such terminals often have the same capabilities as terminals owned by independent operators, they generally do not provide terminalling services to third parties. In many instances, major energy and chemical companies that own storage and terminalling facilities are also significant customers of independent terminal operators. Such companies typically have strong demand for terminals owned by independent operators when independent terminals have more cost-effective locations near key transportation links, such as deep-water ports. Major energy and chemical companies also need independent terminal storage when their owned storage facilities are inadequate, either because of size constraints, the nature of the stored material or specialized handling requirements.
Independent terminal owners generally compete on the basis of the location and versatility of terminals, service and price. A favorably located terminal will have access to various cost-effective transportation modes both to and from the terminal. Transportation modes typically include waterways, railroads, roadways and pipelines. Terminals located near deep-water port facilities are referred to as “deep-water terminals,” and terminals without such facilities are referred to as “inland terminals,” although some inland facilities located on or near navigable rivers are served by barges.
Terminal versatility is a function of the operator’s ability to offer complex handling requirements for diverse products. The services typically provided by the terminal include, among other things, the safe storage of the product at specified temperature, moisture and other conditions, as well as receipt at and delivery from the terminal, all of which must be in compliance with applicable environmental regulations. A terminal operator’s ability to obtain attractive pricing is often dependent on the quality, versatility and reputation of the facilities owned by the operator. Although many products require modest terminal modification, operators with versatile storage capabilities typically require less modification prior to usage, ultimately making the storage cost to the customer more attractive.
Our St. Eustatius and Pt. Tupper terminals have historically functioned as “break bulk” facilities and have handled primarily imports of light crude from foreign sources into the U.S.  These non-domestic crude producers supplied the light crude demanded by U.S. East Coast and Gulf Coast refineries.  Light crude suppliers brought the crude from the Middle East and other regions of the world on very large ships that are efficient for long routes.  These large ships, due to draft constraints, are unable to navigate far enough inland to deliver, which necessitate unloading these ships to storage and subsequent loading on the smaller ships that can bring the crude to the refiners, a process referred to as “break bulk.”  Both facilities are well-located to provide this service.
As supply of light crude from various U.S. shale formations has increased, U.S. demand for foreign light crude oil has dropped substantially.  This reduced demand for imported light crude has, in turn, dramatically changed oil trade flow patterns around the world, as well as depressed the demand for break bulk services.  At the same time, South American and Canadian  production of heavy crude has ramped up significantly.  As demand for export of heavy crude and natural gas liquids (NGL) out of South America, as well as from Canada, has risen, so has the demand for “build bulk” services.  In order to reduce costs and increase efficiencies for long routes to customers abroad, exporting producers need to consolidate their heavy oil cargos from the small ships used to move the heavy crude off shore to a large vessel that is more efficient for long routes, referred to as “build bulk.”    Our St. Eustatius terminal’s location is well suited to build bulk for South American producers headed to customers overseas, primarily in Asia.  Our Point Tupper facility’s location is similarly well-positioned, in this case to build bulk for heavy Canadian crude oil and NGL production.  

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We may face increased competition from new and/or expanding terminals near our locations, if those facilities offer either break bulk or build bulk services, as demanded by the applicable oil trade flows, now and in the future.
Our crude oil storage tanks are physically integrated with and serve refineries owned by Valero Energy. Additionally, we have entered into various agreements with Valero Energy governing the usage of these tanks. As a result, we believe that we will not face significant competition for our services provided to those refineries.

PIPELINE
Our pipeline operations consist of the transportation of refined petroleum products, crude oil and anhydrous ammonia. Refined product pipelines in Texas, Oklahoma, Colorado, New Mexico, Kansas, Nebraska, Iowa, South Dakota, North Dakota and Minnesota cover approximately 5,463 miles. Our crude oil pipelines in Texas, Oklahoma, Kansas, Colorado and Illinois cover 1,180 miles. Our anhydrous ammonia pipeline in Louisiana, Arkansas, Missouri, Illinois, Indiana, Iowa and Nebraska covers 2,000 miles.
As of December 31, 2013, we owned and operated:
refined product pipelines in Texas, Oklahoma, Colorado and New Mexico with an aggregate length of 3,113 miles originating at Valero Energy’s McKee, Three Rivers and Corpus Christi refineries and terminating at certain of NuStar Energy’s terminals, or connecting to third-party pipelines or terminals for further distribution, including a 25-mile hydrogen pipeline (collectively, the Central West System);
a 1,910-mile refined product pipeline originating in southern Kansas and terminating at Jamestown, North Dakota, with a western extension to North Platte, Nebraska and an eastern extension into Iowa (the East Pipeline);
a 440-mile refined product pipeline originating at Tesoro Corporation’s Mandan, North Dakota refinery and terminating in Minneapolis, Minnesota (the North Pipeline);
crude oil pipelines in Texas, Oklahoma, Kansas, Colorado and Illinois with an aggregate length of 1,180 miles and crude oil storage facilities providing 3.4 million barrels of storage capacity in Texas, Oklahoma and Colorado that are located along the crude oil pipelines; and
a 2,000-mile anhydrous ammonia pipeline originating at the Louisiana delta area that travels north through the midwestern United States forking east and west to terminate in Nebraska and Indiana (the Ammonia Pipeline).
We charge tariffs on a per barrel basis for transporting refined products, crude oil and other feedstocks in our refined product and crude oil pipelines and on a per ton basis for transporting anhydrous ammonia in the Ammonia Pipeline.
Description of Pipelines
Central West System. The Central West System pipelines were constructed to support the refineries to which they are connected. These pipelines are physically integrated with and principally serve refineries owned by Valero Energy. The refined products transported in these pipelines include gasoline, distillates (including diesel and jet fuel), natural gas liquids and other products produced primarily by Valero Energy’s McKee, Three Rivers and Corpus Christi refineries in Texas. These pipelines deliver refined products to key markets in Texas, New Mexico and Colorado. The Central West System transported approximately 100.7 million barrels for the year ended December 31, 2013.


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The following table lists information about each of our refined product pipelines included in the Central West System:
 
Origin and Destination
 
Refinery
 
Length
 
Ownership
 
Capacity
 
 
 
 
(Miles)
 
 
 
(Barrels/Day)
McKee to El Paso, TX
 
McKee
 
408

 
67
%
 
42,000

McKee to Colorado Springs, CO
 
McKee
 
256

 
100
%
 
32,500

Colorado Springs, CO to Airport
 
McKee
 
2

 
100
%
 
12,000

Colorado Springs to Denver, CO
 
McKee
 
101

 
100
%
 
32,000

McKee to Denver, CO
 
McKee
 
321

 
30
%
 
11,000

McKee to Amarillo, TX (6”) (a)
 
McKee
 
49

 
100
%
 
51,000

McKee to Amarillo, TX (8”) (a)
 
McKee
 
49

 
100
%
 
 
Amarillo to Abernathy, TX
 
McKee
 
102

 
67
%
 
16,800

Amarillo, TX to Albuquerque, NM
 
McKee
 
293

 
50
%
 
17,000

Abernathy to Lubbock, TX
 
McKee
 
19

 
46
%
 
8,000

McKee to Southlake, TX
 
McKee
 
375

 
100
%
 
26,000

Three Rivers to San Antonio, TX
 
Three Rivers
 
85

 
100
%
 
33,500

Three Rivers to US/Mexico International Border
near Laredo, TX
 
Three Rivers
 
108

 
100
%
 
32,000

Three Rivers to Corpus Christi, TX
 
Three Rivers
 
72

 
100
%
 
15,000

Three Rivers to Pettus to San Antonio, TX
 
Three Rivers
 
112

 
100
%
 
27,500

El Paso, TX to Kinder Morgan
 
McKee
 
12

 
67
%
 
65,500

Mont Belview to Corpus Christi, TX
 
N/A
 
208

 
100
%
 
105,000

Corpus Christi to Brownsville, TX
 
Corpus Christi
 
194

 
100
%
 
45,000

US/Mexico International Border
near Penitas, TX to Edinburg, TX
 
N/A
 
33

 
100
%
 
24,000

Clear Lake, TX to Texas City, TX
 
N/A
 
25

 
100
%
 
N/A

Other refined product pipeline (b)
 
N/A
 
289

 
50
%
 
N/A

Total
 
 
 
3,113

 
 
 
595,800

(a)
The capacity information disclosed above for the McKee to Amarillo, Texas 6-inch pipeline reflects both McKee to Amarillo, Texas pipelines on a combined basis.
(b)
This category consists of the temporarily idled 6-inch Amarillo, Texas to Albuquerque, New Mexico refined product pipeline.
East Pipeline. The East Pipeline covers 1,910 miles, including 242 miles that are temporarily idled, and moves refined products and natural gas liquids north in pipelines ranging in diameter from 6 inches to 16 inches. The East Pipeline system also includes storage capacity of approximately 1.4 million barrels at our two tanks farms at McPherson and El Dorado, Kansas. The East Pipeline transports refined petroleum products and natural gas liquids to NuStar Energy and third party terminals along the system and to receiving pipeline connections in Kansas. Shippers on the East Pipeline obtain refined petroleum products from refineries in Kansas, Oklahoma and Texas. The East Pipeline transported approximately 48.4 million barrels for the year ended December 31, 2013.
North Pipeline. The North Pipeline originates at Tesoro’s Mandan, North Dakota refinery and runs from west to east for approximately 440 miles from its origin to the Minneapolis, Minnesota area. For the year ended December 31, 2013, the North Pipeline transported approximately 16.8 million barrels.
Pipeline-Related Terminals. The East and North Pipelines also include 21 truck-loading terminals through which refined petroleum products are delivered to storage tanks and then loaded into petroleum product transport trucks. Revenues earned at these terminals relate solely to the volumes transported on the pipeline. Separate fees are not charged for the use of these terminals. Instead, the terminalling fees are a portion of the transportation rate included in the pipeline tariff. As a result, these terminals are included in this segment instead of the storage segment.

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The following table lists information about each terminal integrated into our East and North Pipelines as of December 31, 2013:
 
Location of Terminals
Tank Capacity
 
Related Pipeline
System
 
(Barrels)
 
 
Iowa:
 
 
 
LeMars
111,000

 
East
Milford
180,000

 
East
Rock Rapids
230,000

 
East
Kansas:
 
 
 
Concordia
83,000

 
East
Hutchinson
116,000

 
East
Salina
85,000

 
East
Minnesota:
 
 
 
Moorhead
497,000

 
North
Sauk Centre
148,000

 
North
Roseville
625,000

 
North
Nebraska:
 
 
 
Columbus
178,000

 
East
Geneva
677,000

 
East
Norfolk
178,000

 
East
North Platte
256,000

 
East
Osceola
83,000

 
East
North Dakota:
 
 
 
Jamestown (North)
173,000

 
North
Jamestown (East)
181,000

 
East
South Dakota:
 
 
 
Aberdeen
186,000

 
East
Mitchell
74,000

 
East
Sioux Falls
417,000

 
East
Wolsey
144,000

 
East
Yankton
259,000

 
East
Total
4,881,000

 
 
Ammonia Pipeline. The 2,000-mile pipeline, including 59 miles that are temporarily idled, originates in the Louisiana delta area, where it has access to three third-party marine terminals and three anhydrous ammonia plants on the Mississippi River. The line runs north through Louisiana and Arkansas into Missouri, where at Hermann, Missouri, one branch splits and goes east into Illinois and Indiana, while the other branch continues north into Iowa and then turns west into Nebraska. The Ammonia Pipeline is connected to multiple third-party-owned terminals, which include industrial facility delivery locations. Product is supplied to the pipeline from anhydrous ammonia plants in Louisiana and imported product delivered through the marine terminals. Anhydrous ammonia is primarily used as agricultural fertilizer. It is also used as a feedstock to produce other nitrogen derivative fertilizers and explosives. In 2013, the Ammonia Pipeline transported an aggregate of approximately 1.3 million tons (or approximately 11.9 million barrels) of anhydrous ammonia.
Crude Oil Pipelines. Shippers on our crude oil pipelines deliver crude oil to our pipelines for transport to: (i) refineries that connect to our pipelines, (ii) third-party pipelines and (iii) NuStar terminals for further delivery to marine vessels or third-party pipelines. Our crude oil pipelines transport crude oil and other feedstocks from various points in Texas, notably the South Texas Eagle Ford Shale region, Oklahoma, Kansas and Colorado to Valero Energy’s McKee, Three Rivers and Ardmore, Oklahoma refineries and to other U.S. refinery centers via our North Beach marine terminal in Corpus Christi, Texas. We transported an aggregate of approximately 133.5 million barrels on our crude oil pipelines for the year ended December 31, 2013.

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The following table sets forth information about each of our crude oil pipelines as of December 31, 2013:
 
Origin and Destination
Refinery
Length
 
Ownership
 
Capacity
 
 
(Miles)
 
 
 
(Barrels/Day)
Dixon, TX to McKee
McKee
44

 
100
%
 
63,500

Hooker, OK to Clawson, TX (a)
McKee
41

 
50
%
 
22,000

Clawson, TX to McKee
McKee
31

 
100
%
 
36,000

Wichita Falls, TX to McKee
McKee
272

 
100
%
 
110,000

Ringgold, TX to Ardmore
Ardmore
83

 
100
%
 
90,000

Patoka, IL to Wood River
Three Rivers
57

 
24
%
 
60,500

Corpus Christi, TX to Three Rivers, TX (Odem)
Corpus Christi
68

 
100
%
 
38,000

Pettus, TX to Corpus Christi, TX
(b)
60

 
100
%
 
30,000

Three Rivers, TX to Corpus Christi, TX (12”)
(b)
66

 
100
%
 
55,000

Gardendale, TX to Oakville, TX
(b)
140

 
100
%
 
100,000

Pawnee, TX to Oakville, TX
(b)
43

 
100
%
 
110,000

Oakville, TX to Corpus Christi, TX (16”)
(b)
61

 
100
%
 
200,000

Other (c)
N/A
214

 
100
%
 
N/A

Total
 
1,180

 
 
 
915,000

(a)
We receive 50% of the tariff with respect to 100% of the barrels transported in the Hooker, Oklahoma to Clawson, Texas pipeline. Accordingly, the capacity is given with respect to 100% of the pipeline.
(b)
These pipelines serve production from the South Texas Eagle Ford Shale.
(c)
This category consists of the temporarily idled Cheyenne Wells, CO to McKee and Healdton to Ringling, Oklahoma crude oil pipelines.
The following table sets forth information about the crude oil storage facilities located along our crude oil pipelines as of December 31, 2013:
 
Location
Refinery
Capacity
 
 
(Barrels)
Dixon, TX
McKee
244,000

Ringgold, TX
Ardmore
598,000

Wichita Falls, TX
McKee
661,000

Wasson, OK
Ardmore
226,000

Clawson, TX
McKee
77,000

South Texas (a)
N/A
701,000

Oakville, TX
N/A
718,000

Pawnee, TX
N/A
112,000

Other (b)
McKee
68,000

Total
 
3,405,000

(a)
This category includes crude oil tanks at various locations along the Gardendale, Texas to Oakville, Texas pipeline.
(b)
This category includes crude oil tanks along the Cheyenne Wells, Colorado to McKee crude oil pipelines located at Carlton, Colorado, Sturgis, Oklahoma, and Stratford, Texas.
Pipeline Operations
Revenues for the pipelines are based upon origin-to-destination throughput volumes traveling through our pipelines and their related tariff rates.
In general, a shipper on our refined petroleum product pipelines delivers products to the pipeline from refineries or third-party pipelines. Shippers are required to supply us with a notice of shipment indicating sources of products and destinations. Shipments are tested or receive certifications to ensure compliance with our product specifications. We charge our shippers tariff rates based on transportation from the origination point on the pipeline to the point of delivery. We invoice our refined

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product shippers upon delivery for our Central West System and our North and Ammonia Pipelines, and we invoice our shippers on our East Pipeline when their product enters the line.

Shippers on our crude oil pipelines deliver crude oil to our pipelines for transport to: (i) refineries that connect to our pipelines, (ii) third-party pipelines and (iii) NuStar terminals for further delivery to marine vessels or third-party pipelines.
The pipelines in the Central West System, the East Pipeline, the North Pipeline and the Ammonia Pipeline and the crude oil pipelines are subject to federal regulation by one or more of the following governmental agencies or laws: the Federal Energy Regulatory Commission (the FERC), the Surface Transportation Board (the STB), the Department of Transportation (DOT), the Environmental Protection Agency (EPA) and the Homeland Security Act. Additionally, the operations and integrity of the pipelines are subject to the respective state jurisdictions.
The majority of our pipelines are common carrier and are subject to federal and state tariff regulation. In general, we are authorized by the FERC to adopt market-based rates. Common carrier activities are those for which transportation through our pipelines is available, at published tariffs filed, in the case of interstate petroleum product shipments, with the FERC or, in the case of intrastate petroleum product shipments, with the relevant state authority, to any shipper of petroleum products who requests such services and satisfies the conditions and specifications for transportation. The Ammonia Pipeline is subject to federal regulation by the STB and state regulation by Louisiana.
We use Supervisory Control and Data Acquisition remote supervisory control software programs to continuously monitor and control our pipelines. The system monitors quantities of products injected in and delivered through the pipelines and automatically signals the appropriate personnel upon deviations from normal operations that require attention.
Demand for and Sources of Refined Products and Crude Oil
The operations of our Central West System and the East and North Pipelines depend on the level of demand for refined products in the markets served by the pipelines and the ability and willingness of refiners and marketers having access to the pipelines to supply such demand by deliveries through the pipelines.
The majority of the refined products delivered through the pipelines in the Central West System are gasoline and diesel fuel that originate at refineries owned by Valero Energy. Demand for these products fluctuates as prices for these products fluctuate. Prices fluctuate for a variety of reasons including the overall balance in supply and demand, which is affected by general economic conditions and affects refinery utilization rates, among other factors. Prices for gasoline and diesel fuel tend to increase in the warm weather months when people tend to drive automobiles more often and further distances.
The majority of the refined products delivered through the North Pipeline are delivered to the Minneapolis, Minnesota metropolitan area and consist of gasoline and diesel fuel. Demand for those products fluctuates based on general economic conditions and with changes in the weather as more people drive during the warmer months.
Much of the refined products and natural gas liquids delivered through the East Pipeline and volumes on the North Pipeline that are not delivered to Minneapolis are ultimately used as fuel for railroads, ethanol denaturant or in agricultural operations, including fuel for farm equipment, irrigation systems, trucks used for transporting crops and crop-drying facilities. Demand for refined products for agricultural use, and the relative mix of products required, is affected by weather conditions in the markets served by the East and North Pipelines. The agricultural sector is also affected by government agricultural policies and crop prices. Although periods of drought suppress agricultural demand for some refined products, particularly those used for fueling farm equipment, the demand for fuel for irrigation systems often increases during such times. The mix of refined products delivered for agricultural use varies seasonally, with gasoline demand peaking in early summer, diesel fuel demand peaking in late summer and propane demand higher in the fall. In addition, weather conditions in the areas served by the East Pipeline affect the mix of the refined products delivered through the East Pipeline, although historically any overall impact on the total volumes shipped has not been significant.
Our refined product pipelines are also dependent upon adequate levels of production of refined products by refineries connected to the pipelines, directly or through connecting pipelines. The refineries are, in turn, dependent upon adequate supplies of suitable grades of crude oil. Certain of the pipelines in the Central West System and certain of our crude oil pipelines are subject to long-term throughput agreements with Valero Energy. Valero Energy refineries connected directly to our pipelines obtain crude oil from a variety of foreign and domestic sources. If operations at one of these refineries were discontinued or significantly reduced, it could have a material adverse effect on our operations, although we would endeavor to minimize the impact by seeking alternative customers for those pipelines.

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Our crude oil pipelines are dependent on the continued production of adequate supply of domestic crude oil in regions served by our crude oil pipelines or connecting carriers. Our crude oil pipelines are also dependent on our customers’ continued access to sufficient foreign crude oil and sufficient demand for refined products for our customers to operate their refineries.
The North Pipeline is heavily dependent on Tesoro’s Mandan, North Dakota refinery, which primarily runs North Dakota crude oil (although it has the ability to process other crude oils). If operations at the Tesoro refinery were interrupted, it could have a material effect on our operations. Other than the Valero Energy refineries described above and the Tesoro refinery, if operations at any one refinery were discontinued, we believe (assuming unchanged demand for refined products in markets served by the refined product pipelines) that the effects thereof would be short-term in nature and our business would not be materially adversely affected over the long term because such discontinued production could be replaced by other refineries or other sources.
The refineries connected directly to the East Pipeline obtain crude oil from producing fields located primarily in Kansas, Oklahoma and Texas, and, to a much lesser extent, from other domestic or foreign sources. In addition, refineries in Kansas, Oklahoma and Texas are also connected to the East Pipeline by third party pipelines. These refineries obtain their supplies of crude oil from a variety of sources. The majority of the refined products transported through the East Pipeline are produced at three refineries located at McPherson and El Dorado, Kansas and Ponca City, Oklahoma, which are operated by the National Cooperative Refining Association (NCRA), HollyFrontier Corporation (HollyFrontier) and Phillips 66, respectively. The NCRA and HollyFrontier refineries are connected directly to the East Pipeline. The East Pipeline also has access to Gulf Coast supplies of products through third party connecting pipelines that receive products originating on the Gulf Coast.
Demand for and Sources of Anhydrous Ammonia
The Ammonia Pipeline is one of two major anhydrous ammonia pipelines in the United States and the only one capable of receiving foreign product directly into the system and transporting anhydrous ammonia into the nation’s corn belt.
Our Ammonia Pipeline operations depend on overall nitrogen fertilizer use, management practices, the price of natural gas, which is the primary component of anhydrous ammonia, and the level of demand for direct application of anhydrous ammonia as a fertilizer for crop production (Direct Application). Demand for Direct Application is dependent on the weather, as Direct Application is not effective if the ground is too wet or too dry.
Corn producers have fertilizer alternatives to anhydrous ammonia, such as liquid or dry nitrogen fertilizers. Liquid and dry nitrogen fertilizers are both less sensitive to weather conditions during application but are generally more costly than anhydrous ammonia. In addition, anhydrous ammonia has the highest nitrogen content of any nitrogen-derivative fertilizer.
Customers
The largest customer of our pipeline segment was Valero Energy, which accounted for approximately 37% of the total segment revenues for the year ended December 31, 2013. In addition to Valero Energy, our customers include integrated oil companies, refining companies, farm cooperatives, railroads and others. No other customer accounted for greater than 10% of the total revenues of the pipeline segment for the year ended December 31, 2013.
Competition and Business Considerations
Because pipelines are generally the lowest-cost method for intermediate and long-haul movement of crude oil and refined petroleum products, our more significant competitors are common carrier and proprietary pipelines owned and operated by major integrated and large independent oil companies and other companies in the areas where we deliver products. Competition between common carrier pipelines is based primarily on transportation charges, quality of customer service and proximity to end users.
The costs associated with transporting products from a loading terminal to end users limit the geographic size of the market that can be served economically by any terminal. Transportation to end users from our loading terminals is conducted primarily by trucking operations of unrelated third parties. Trucks may competitively deliver products in some of the areas served by our pipelines. However, trucking costs render that mode of transportation uncompetitive for longer hauls or larger volumes. We do not believe that trucks are, or will be, effective competition to our long-haul volumes over the long term.
Most of our refined product pipelines within the Central West System and certain of our crude oil pipelines are physically integrated with and principally serve refineries owned by Valero Energy. As a result, we do not believe that we will face significant competition for transportation services provided to the Valero Energy refineries we serve.
Our crude oil pipelines serve areas or refineries impacted by growing domestic shale oil production in the Eagle Ford, Permian Basin and Granite Wash regions. This growing domestic production has reduced demand for imported crude oil and shifted

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supply sources for refineries and markets served by our pipelines. Our pipelines also face competition from other crude oil pipelines and truck transportation in these regions.
The East and North Pipelines compete with an independent common carrier pipeline system owned by Magellan Midstream Partners, L.P. (Magellan) that operates approximately 100 miles east of and parallel to the East Pipeline and in close proximity to the North Pipeline. The Magellan system is a more extensive system than the East and North Pipelines. Competition with Magellan is based primarily on transportation charges, quality of customer service and proximity to end users. In addition, refined product pricing at either the origin or terminal point on a pipeline may outweigh transportation costs. Certain of the East Pipeline’s and the North Pipeline’s delivery terminals are in direct competition with Magellan’s terminals.
Competitors of the Ammonia Pipeline include the other major anhydrous ammonia pipeline that originates in Oklahoma and Texas and terminates in Minnesota. The competing pipeline has the same Direct Application demand and weather issues as the Ammonia Pipeline but is restricted to domestically produced anhydrous ammonia. Midwest production facilities, nitrogen fertilizer substitutes and barge and railroad transportation represent other forms of direct competition to the pipeline under certain market conditions.
FUELS MARKETING
In 2013, we changed the name of the “Asphalt and Fuels Marketing” segment to the “Fuels Marketing” segment. This name more accurately reflects the operations that remain after we sold a 50% ownership interest in NuStar Asphalt LLC (Asphalt JV) in 2012 and the San Antonio Refinery Sale as discussed below.
Fuels Marketing Operations
Within our fuels marketing operations, we purchase crude oil and refined petroleum products for resale. The results of operations for the fuels marketing segment depend largely on the margin between our cost and the sales prices of the products we market. Therefore, the results of operations for this segment are more sensitive to changes in commodity prices compared to the operations of the storage and pipeline segments.

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

Since our fuels marketing operations expose us to commodity price risk, we sometimes enter into derivative instruments to mitigate the effect of commodity price fluctuations on our operations. The derivative instruments we use consist primarily of commodity futures and swap contracts.
Customers
Fuels marketing customers include major integrated refiners and trading companies. Customers for our bunker fuel sales are mainly ship owners, including cruise line companies. No customer accounted for greater than 11% of the total segment revenues of the fuels marketing segment for the year ended December 31, 2013.
Competition and Business Considerations
Our fuels marketing operations have numerous competitors, including large integrated refiners, marketing affiliates of other partnerships in our industry, as well as various international and domestic trading companies. In the sale of bunker fuel, we compete with ports offering bunker fuels that are along the route of travel of the vessel.
Dispositions
San Antonio Refinery Sale. On January 1, 2013, we sold the San Antonio Refinery and related assets, which included inventory, a terminal in Elmendorf, Texas and a pipeline connecting the terminal and refinery. We have presented the results of operations for the San Antonio Refinery and related assets, previously reported in the fuels marketing and pipeline segments, as discontinued operations for the years ended December 31, 2013, 2012 and 2011.
Asphalt Operations. On September 28, 2012, we sold a 50% ownership interest (the Asphalt Sale) in NuStar Asphalt LLC (Asphalt JV), previously a wholly-owned subsidiary, to an affiliate of Lindsay Goldberg LLC, a private investment firm. Asphalt JV owns and operates the asphalt refining assets that were previously wholly owned by NuStar Energy, including an asphalt refinery located in Paulsboro, New Jersey and a terminal in Savannah, Georgia. Upon closing, we deconsolidated Asphalt JV and started reporting our remaining investment in Asphalt JV using the equity method of accounting.

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

EMPLOYEES
Our operations are managed by NuStar GP, LLC. As of December 31, 2013, NuStar GP, LLC had 1,221 domestic employees. Certain of our wholly owned subsidiaries had 433 employees performing services for our international operations. We believe that NuStar GP, LLC and our subsidiaries each have satisfactory relationships with their employees.

RATE REGULATION
Several of our petroleum pipelines are interstate common carrier pipelines, which are subject to regulation by the FERC under the Interstate Commerce Act (ICA) and the Energy Policy Act of 1992 (the EP Act). The ICA and its implementing regulations give the FERC authority to regulate the rates charged for service on interstate common carrier pipelines and generally require the rates and practices of interstate oil pipelines to be just, reasonable and nondiscriminatory. The ICA also requires tariffs that set forth the rates a common carrier pipeline charges for providing transportation services on its interstate common carrier liquids pipelines, as well as the rules and regulations governing these services, to be maintained on file with the FERC. The EP Act deemed certain rates in effect prior to its passage to be just and reasonable and limited the circumstances under which a complaint can be made against such “grandfathered” rates. The EP Act and its implementing regulations also allow interstate common carrier oil pipelines to annually index their rates up to a prescribed ceiling level. In addition, the FERC retains cost-of-service ratemaking, market-based rates and settlement rates as alternatives to the indexing approach.
The Ammonia Pipeline is subject to regulation by the STB under the current version of the ICA. The ICA and its implementing regulations give the STB authority to regulate the rates we charge for service on the Ammonia Pipeline and generally require that our rates and practices be reasonable and nondiscriminatory.
Additionally, the rates and practices for our intrastate common carrier pipelines are subject to regulation by state commissions in Colorado, Kansas, Louisiana, North Dakota and Texas. Although the applicable state statutes and regulations vary, they generally require that intrastate pipelines publish tariffs setting forth all rates, rules and regulations applying to intrastate service, and generally require that pipeline rates and practices be just, reasonable and nondiscriminatory.
Shippers may challenge tariff rates rules and regulations on our pipelines. There are no pending challenges or complaints regarding our tariffs.

ENVIRONMENTAL AND SAFETY REGULATION
Our operations are subject to extensive federal, state and local environmental laws and regulations, including those relating to the discharge of materials into the environment, waste management, pollution prevention measures, pipeline integrity and operator qualifications, among others. Our operations are also subject to extensive federal and state health and safety laws and regulations, including those relating to pipeline safety. The principal environmental and safety risks associated with our operations relate to unauthorized emissions into the air, unauthorized releases into soil, surface water or groundwater and personal injury and property damage. Compliance with these environmental and safety laws, regulations and permits increases our capital expenditures and our overall cost of business, and violations of these laws, regulations and/or permits can result in significant civil and criminal liabilities, injunctions or other penalties.
We have adopted policies, practices and procedures in the areas of pollution control, pipeline integrity, operator qualifications, public relations and education, product safety, process safety management, occupational health and the handling, storage, use and disposal of hazardous materials that are designed to prevent material environmental or other damage, to ensure the safety of our pipelines, our employees, the public and the environment and to limit the financial liability that could result from such events. Future governmental action and regulatory initiatives could result in changes to expected operating permits and procedures, additional remedial actions or increased capital expenditures and operating costs that cannot be assessed with certainty at this time. In addition, contamination resulting from spills of petroleum and other products occurs within the industry. Risks of additional costs and liabilities are inherent within the industry, and there can be no assurances that significant costs and liabilities will not be incurred in the future.

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

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RENEWABLE ENERGY AND ALTERNATIVE FUEL MANDATES
Several federal and state programs require the purchase and use of renewable energy and alternative fuels, such as battery-powered engines, biodiesel, wind energy, and solar energy. These statutory mandates and programs may over time offset projected increases or reduce the demand for refined petroleum products, particularly gasoline, in certain markets. The increased production and use of biofuels may also create opportunities for additional pipeline transportation and additional blending opportunities within the terminals division, although that potential cannot be quantified at present. Other legislative changes may similarly alter the expected demand and supply projections for refined petroleum products in ways that cannot be predicted.
WATER
The Federal Water Pollution Control Act of 1972, as amended, also known as the Clean Water Act, and analogous or more stringent state statutes impose restrictions and strict controls regarding the discharge of pollutants into state waters or waters of the United States. The discharge of pollutants into state waters or waters of the United States is prohibited, except in accordance with the terms of a permit issued by applicable federal or state authorities. The Oil Pollution Act, enacted in 1990, amends provisions of the Clean Water Act as they pertain to prevention, response to and liability for oil spills. Spill prevention control and countermeasure requirements of the Clean Water Act and some state laws require response plans and the use of dikes and similar structures to help prevent contamination of state waters or waters of the United States in the event of an unauthorized discharge. Violations of any of these statutes and the related regulations could result in significant costs and liabilities.
AIR EMISSIONS
Our operations are subject to the Federal Clean Air Act, as amended, and analogous or more stringent state and local statutes. These laws and related regulations regulate emissions of air pollutants from various sources, including some of our operations, and also impose various monitoring and reporting requirements. Such laws and regulations may require a facility to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce air emissions or result in the increase of existing air emissions, and obtain and strictly comply with the provisions of any air permits. It is possible that these statutes and the related regulations may be revised to be more restrictive in the future, necessitating additional capital expense to ensure our operations are in compliance. We are unable to estimate the effect on our financial condition or results of operations or the amount and timing of such required expenditures.
SOLID WASTE
We generate non-hazardous and hazardous solid wastes that are subject to the requirements of the federal Resource Conservation and Recovery Act (RCRA) and analogous or more stringent state statutes. We are not currently required to comply with a substantial portion of RCRA requirements because we do not operate any waste treatment, storage or disposal facilities. However, it is possible that additional wastes, which could include wastes currently generated during operations, will also be designated as “hazardous wastes.” Hazardous wastes are subject to more rigorous and costly disposal requirements than are non-hazardous wastes.

HAZARDOUS SUBSTANCES
The Comprehensive Environmental Response, Compensation and Liability Act, referred to as CERCLA and also known as Superfund, and analogous or more stringent state laws, impose joint and several liability, without regard to fault or the legality of the original act, on some classes of persons that contributed to the release of a “hazardous substance” into the environment. These persons include the owner or operator of the site and entities that disposed or arranged for the disposal of the hazardous substances found at the site. CERCLA also authorizes the EPA and, in some instances, third parties to act in response to threats to the public health or the environment and to seek recovery from the responsible classes of persons for the costs that they incur. In the course of our ordinary operations, we may generate waste that falls within CERCLA’s definition of a “hazardous substance.”
We currently own or lease, and have in the past owned or leased, properties where hydrocarbons are being or have been handled. Although we believe that we have utilized operating and disposal practices that were standard in the industry at the time, hydrocarbons or other wastes may have been disposed of or released on or under the properties owned or leased by us or on or under other locations where these wastes have been taken for disposal. In addition, we acquired many of these properties from third parties, and we did not control those third parties’ treatment and disposal or release of hydrocarbons or other wastes. These properties and wastes disposed thereon may be subject to CERCLA, RCRA and analogous state laws. Under these laws, we could be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators), to clean up contaminated property (including contaminated groundwater) or to perform remedial

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operations to prevent future contamination. In addition, we may be exposed to joint and several liability under CERCLA for all or part of the costs required to clean up sites at which hazardous substances may have been disposed of or released into the environment.
While remediation of subsurface contamination is in process at several of our facilities, based on current available information, we believe that the cost of these activities will not materially affect our financial condition or results of operations. Such costs, however, are often unpredictable and, therefore, there can be no assurances that the future costs will not become material.
PIPELINE INTEGRITY AND SAFETY
Our pipelines are subject to extensive federal and state laws and regulations governing pipeline integrity and safety. These statutes and their respective implementing regulations generally require pipeline operators to maintain qualification programs for key pipeline operating personnel, to review and update their existing pipeline safety public education programs, to provide information for the National Pipeline Mapping System, to maintain spill response plans, to conduct spill response training, to implement integrity management programs for pipelines that could affect high consequence areas (i.e., areas with concentrated populations, navigable waterways and other unusually sensitive areas), maintain detailed operating and maintenance procedures and to manage human factors in pipeline control centers, including controller fatigue. While compliance with the statutes and analogous or more stringent state laws may affect our capital expenditures and operating expenses, we believe that the cost of such compliance will not materially affect our competitive position or have a material effect on our financial condition or results of operations.

RISK FACTORS
RISKS RELATED TO OUR BUSINESS
We may not be able to generate sufficient cash from operations to enable us to pay distributions at current levels to our unitholders every quarter.
The amount of cash that we can distribute to our unitholders each quarter principally depends upon the amount of cash we generate from our operations, which will fluctuate from quarter to quarter based on, among other things:
throughput volumes transported in our pipelines;
lease renewals or throughput volumes in our terminals and storage facilities;
tariff rates and fees we charge and the returns we realize for our services;
the results of our marketing, trading and hedging activities, which fluctuate depending upon the relationship between refined product prices and prices of crude oil and other feedstocks;
demand for and supply of crude oil, refined products and anhydrous ammonia;
the effect of worldwide energy conservation measures;
our operating costs;
weather conditions;
domestic and foreign governmental regulations and taxes; and
prevailing economic conditions.
In addition, the amount of cash that we will have available for distribution will depend on other factors, including:
our debt service requirements and restrictions on distributions contained in our current or future debt agreements;
the sources of cash used to fund our acquisitions;
our capital expenditures;
fluctuations in our working capital needs;
issuances of debt and equity securities; and
adjustments in cash reserves made by our general partner, in its discretion.
Because of these factors, we may not have sufficient available cash each quarter to continue paying distributions at their current level or at all. Furthermore, cash distributions to our unitholders depend primarily upon cash flow, including cash flow from financial reserves and working capital borrowings, and not solely on profitability, which is affected by non-cash items. Therefore, we may make cash distributions during periods when we record net losses and may not make cash distributions during periods when we record net income.

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

A decrease in lease renewals or throughputs in our assets would cause our revenues to decline and could adversely affect our ability to make cash distributions to our unitholders.
A decrease in lease renewals or throughputs in our assets would cause our revenues to decline and could adversely affect our ability to make cash distributions at current levels to our unitholders. Such a decrease could result from a customer’s failure to renew a lease, a temporary or permanent decline in the amount of crude oil or refined products stored at and transported from the refineries we serve or construction by our competitors of new transportation or storage assets in the markets we serve. Factors that could result in such a decline include:
a material decrease in the supply of crude oil;
a material decrease in demand for refined products in the markets served by our pipelines, terminals and refineries;
scheduled refinery turnarounds or unscheduled refinery maintenance;
operational problems or catastrophic events at a refinery;
environmental proceedings or other litigation that compel the cessation of all or a portion of the operations at a refinery;
a decision by our current customers to redirect refined products transported in our pipelines to markets not served by our pipelines or to transport crude oil or refined products by means other than our pipelines;
increasingly stringent environmental regulations; or
a decision by our current customers to sell one or more of the refineries we serve to a purchaser that elects not to use our pipelines and terminals.
If we are unable to complete capital projects at their expected costs and/or in a timely manner, or if the market conditions assumed in our project economics deteriorate, our financial condition, results of operations, or cash flows could be affected materially and adversely.
Delays or cost increases related to capital spending programs involving construction of new facilities (or improvements and repairs to our existing facilities) could adversely affect our ability to achieve forecasted operating results. Although we evaluate and monitor each capital spending project and try to anticipate difficulties that may arise, such delays or cost increases may arise as a result of factors that are beyond our control, including:
denial or delay in issuing requisite regulatory approvals and/or permits;
unplanned increases in the cost of construction materials or labor;
disruptions in transportation of modular components and/or construction materials;
severe adverse weather conditions, natural disasters or other events (such as equipment malfunctions, explosions, fires or spills) affecting our facilities, or those of vendors and suppliers;
shortages of sufficiently skilled labor, or labor disagreements resulting in unplanned work stoppages;
market-related increases in a project’s debt or equity financing costs; or

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non-performance by, or disputes with, vendors, suppliers, contractors or sub-contractors involved with a project.
Our forecasted operating results are also based upon our projections of future market fundamentals that are not within our control, including changes in general economic conditions, availability to our customers of attractively priced alternative solutions for storage, transportation or supplies of crude oil and refined products and overall customer demand.
Our operations are subject to operational hazards and unforeseen interruptions, and we do not insure against all potential losses. Therefore, we could be seriously harmed by unexpected liabilities.
Our operations are subject to operational hazards and unforeseen interruptions such as natural disasters, adverse weather, accidents, fires, explosions, hazardous materials releases, mechanical failures and other events beyond our control. These events might result in a loss of equipment or life, injury or extensive property damage, as well as an interruption in our operations. In the event any of our facilities are forced to shut down for a significant period of time, it may have a material adverse effect on our earnings, our other results of operations and our financial condition as a whole.
We may not be able to maintain or obtain insurance of the type and amount we desire at reasonable rates. As a result of market conditions, premiums and deductibles for certain of our insurance policies have increased substantially and could escalate further. Certain insurance coverage could become unavailable or available only for reduced amounts of coverage and at higher rates. For example, our insurance carriers require broad exclusions for losses due to terrorist acts. If we were to incur a significant liability for which we are not fully insured, such a liability could have a material adverse effect on our financial position and our ability to make distributions at current levels to our unitholders and to meet our debt service requirements.
The price volatility of crude oil and refined products can reduce our revenues and ability to make distributions to our unitholders.
Revenues associated with our fuels marketing operations result primarily from our crude blending and trading operations and fuel oil sales. We also maintain product inventory related to these activities. The price and market value of crude oil and refined products is volatile. Our revenues will be adversely affected by this volatility during periods of decreasing prices because of the reduction in the value and resale price of our inventory. Conversely, during periods of increasing petroleum product prices, our revenues may be adversely affected because of the increased costs associated with obtaining our inventory. Future price volatility could have an adverse impact on our results of operations, cash flow and ability to make distributions to our unitholders.
Our purchase and sale of crude oil and refined products may expose us to trading losses and hedging losses, and non-compliance with our risk management policies could result in significant financial losses.
In order to manage our exposure to commodity price fluctuations associated with our fuels marketing segment, we may engage in crude oil and refined product hedges. As a result, our marketing and trading of crude oil and refined products may expose us to price volatility risk for the purchase and sale of crude oil and petroleum products, including distillates and fuel oil. We attempt to mitigate this volatility risk through hedging, but we are still exposed to basis risk. We may also be exposed to inventory and financial liquidity risk due to the inability to trade certain products or rising costs of carrying some inventories. Further, our marketing and trading activities, including any hedging activities, may cause volatility in our earnings. In addition, we will be exposed to credit risk in the event of non-performance by counterparties.
Our risk management policies may not eliminate all price risk since open trading positions will expose us to price volatility. Further, there is a risk that our risk management policies will not be complied with. Although we have designed procedures to anticipate and detect non-compliance, we cannot assure you that these steps will detect and prevent all violations of our trading policies and procedures, particularly if deception and other intentional misconduct are involved.
As a result of the risks described above, the activities associated with our marketing and trading business may expose us to volatility in earnings and financial losses, which may adversely affect our financial condition and our ability to distribute cash to our unitholders.
Hedging transactions may limit our potential gains or result in significant financial losses.
While intended to reduce the effects of volatile crude oil and refined product prices, hedging transactions, depending on the hedging instrument used, may limit our potential gains if crude oil and refined product prices were to rise substantially over the price established by the hedge. In addition, such transactions may expose us to the risk of financial loss in certain circumstances, including instances in which:
the counterparties to our futures contracts fail to perform under the contracts; or
there is a change in the expected differential between the underlying price in the hedging agreement and the actual prices received.

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The accounting standards regarding hedge accounting are complex, and even when we engage in hedging transactions that are effective economically, these transactions may not be considered effective for accounting purposes. Accordingly, our financial statements will reflect increased volatility due to these hedges, even when there is no underlying economic impact at that point. In addition, it is not possible for us to engage in a hedging transaction that completely mitigates our exposure to commodity prices. Our financial statements may reflect a gain or loss arising from an exposure to commodity prices for which we are unable to enter into an effective hedge.
We are exposed to counterparty credit risk. Nonpayment and nonperformance by our customers, vendors or derivative counterparties could reduce our revenues, increase our expenses or otherwise have a negative impact on our operating results, cash flows and ability to make distributions to our unitholders.
We are subject to risks of loss resulting from nonpayment or nonperformance by our customers to whom we extend credit. In addition, nonperformance by vendors who have committed to provide us with products or services could result in higher costs or interfere with our ability to successfully conduct our business. Furthermore, nonpayment by the counterparties to any of our outstanding commodity derivatives could expose us to additional commodity price risk. Weak economic conditions and widespread financial stress could reduce the liquidity of our customers, vendors or counterparties, making it more difficult for them to meet their obligations to us. Any substantial increase in the nonpayment and nonperformance by our customers, vendors or counterparties could have a material adverse effect on our results of operations, cash flows and ability to make distributions to unitholders.
Our future financial and operating flexibility may be adversely affected by our significant leverage, downgrades of our credit ratings, restrictions in our debt agreements or disruptions in the financial markets.
As of December 31, 2013, our consolidated debt was $2.7 billion. Among other things, our significant leverage may be viewed negatively by credit rating agencies, which could result in increased costs for us to access the capital markets. The ratings of NuStar Logistics’ were downgraded to Ba1 (negative outlook) by Moody’s Investor Service Inc. (Moody’s) in January 2013, BB+ (stable outlook) by Standard & Poor’s Ratings Services (S&P) in July 2012 and BB (stable outlook) by Fitch, Inc. in November 2012. As a result of the S&P and Moody’s downgrades, interest rates on borrowings under our five-year revolving credit agreement (the 2012 Revolving Credit Agreement) and our 7.65% senior notes due 2018 increased. We may also be required to post cash collateral under certain of our hedging arrangements, which we expect to fund with borrowings under our 2012 Revolving Credit Agreement. Any future downgrades could result in additional increases to the interest rates on borrowings under our credit facilities and the 7.65% senior notes due 2018, significantly increasing our capital costs and adversely affecting our ability to raise capital in the future.
Our 2012 Revolving Credit Agreement contains restrictive covenants, including a requirement that, as of the end of each rolling period, which consists of any period of four consecutive fiscal quarters, we maintain a consolidated debt coverage ratio (consolidated indebtedness to consolidated EBITDA, as defined in the 2012 Revolving Credit Agreement) not to exceed 5.00-to-1.00. Failure to comply with any of the restrictive covenants in the 2012 Revolving Credit Agreement will result in a default under the terms of our credit agreement and could result in acceleration of this and possibly other indebtedness.
Debt service obligations, restrictive covenants in our credit facilities and the indentures governing our outstanding senior and subordinated notes and maturities resulting from this leverage may adversely affect our ability to finance future operations, pursue acquisitions and fund other capital needs and our ability to pay cash distributions to our unitholders at current levels. In addition, this leverage may make our results of operations more susceptible to adverse economic or operating conditions. For example, during an event of default under any of our debt agreements, we would be prohibited from making cash distributions to our unitholders. If our lenders file for bankruptcy or experience severe financial hardship, they may not honor their pro rata share of our borrowing requests under the 2012 Revolving Credit Agreement, which may significantly reduce our available borrowing capacity and, as a result, materially adversely affect our financial condition and ability to pay distributions to our unitholders at current levels. Additionally, we may not be able to access the capital markets in the future at economically attractive terms, which may adversely affect our future financial and operating flexibility and our ability to pay cash distributions at current levels.

We may become liable as a result of our financing arrangements and guarantees of Asphalt JV.
In connection with the sale of our 50% ownership interest in Asphalt JV, NuStar Logistics agreed to convert the existing revolving credit facility with Asphalt JV into a $190 million term loan (the NuStar Facility), which such amount will be reduced to $175 million by December 31, 2014 and then $150 million by September 30, 2015. The NuStar Facility must be repaid in full no later than September 2019; earlier repayment is possible, depending on the amount of excess cash flows (if any) generated by Asphalt JV over the next several years. We also agreed to continue to provide credit support to Asphalt JV in the form of guarantees or letters of credit of up to $150 million (the Credit Support) until February 2016, at which point the amount of Credit Support will begin to decline until the obligation is terminated no later than September 2019.


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In addition to the NuStar Facility (which includes the Credit Support), Asphalt JV also entered into a third-party asset-based revolving credit facility (ABL Facility). In the event that Asphalt JV defaults on any of its obligations under the NuStar Facility, we would have available only those measures available to an unsecured creditor with the rights and limitations provided in the NuStar Facility, and, to the extent provided in the agreements, the ABL Facility lenders would be senior to those rights. In the event of a default on any of the obligations underlying the Credit Support, we would be responsible for Asphalt JV’s liabilities for the default and have only the rights of repayment associated with that instrument. In either scenario, the liability imposed on us may have an adverse impact on our financial condition, results of operations and ability to pay distributions to our unitholders at current levels.
Increases in interest rates could adversely affect our business and the trading price of our units.
We have significant exposure to increases in interest rates. At December 31, 2013, we had approximately $2.7 billion of consolidated debt, of which $1.8 billion was at fixed interest rates and $0.9 billion was at variable interest rates. In addition, prior ratings downgrades on our existing indebtedness caused interest rates under our 2012 Revolving Credit Agreement and our senior notes due 2018 to increase effective January 2013, and future downgrades may cause such interest rates to increase further. Our results of operations, cash flows and financial position could be materially adversely affected by significant increases in interest rates above current levels. Further, the trading price of our units is sensitive to changes in interest rates and any rise in interest rates could adversely impact such trading price.
We could be subject to damages based on claims brought against us by our customers or lose customers as a result of the failure of our products to meet certain quality specifications.
Certain of our products are produced to precise customer specifications. If a product fails to perform in a manner consistent with the detailed quality specifications required by the customer, the customer could seek replacement of the product or damages for costs incurred as a result of the product failing to perform as guaranteed. A successful claim or series of claims against us could result in a loss of one or more customers.
Potential future acquisitions and expansions, if any, may increase substantially the level of our indebtedness and contingent liabilities, and we may be unable to integrate them effectively into our existing operations.
From time to time, we evaluate and acquire assets and businesses that we believe complement or diversify our existing assets and businesses. Acquisitions may require substantial capital or the incurrence of substantial indebtedness. If we consummate any future material acquisitions, our capitalization and results of operations may change significantly, and you will not have the opportunity to evaluate the economic, financial and other relevant information that we will consider in connection with any future acquisitions.
Acquisitions and business expansions involve numerous risks, including difficulties in the assimilation of the assets and operations of the acquired businesses, inefficiencies and difficulties that arise because of unfamiliarity with new assets and the businesses associated with them and new geographic areas. Further, unexpected costs and challenges may arise whenever businesses with different operations or management are combined. Successful business combinations will require our management and other personnel to devote significant amounts of time to integrating the acquired businesses with our existing operations. These efforts may temporarily distract their attention from day-to-day business, the development or acquisition of new properties and other business opportunities. If we do not successfully integrate any past or future acquisitions, or if there is any significant delay in achieving such integration, our business and financial condition could be adversely affected.

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

We may have liabilities from our assets that pre-exist our acquisition of those assets, but that may not be covered by indemnification rights we may have against the sellers of the assets.
In some cases, we have indemnified the previous owners and operators of acquired assets. Some of our assets have been used for many years to transport and store crude oil and refined products. Releases may have occurred in the past that could require costly future remediation. If a significant release or event occurred in the past, the liability for which was not retained by the seller, or for which indemnification by the seller is not available, it could adversely affect our financial position and results of operations.
Climate change legislation and regulatory initiatives may decrease demand for the products we store, transport and sell and increase our operating costs.
Scientific studies have suggested that emissions of certain gases, commonly referred to as “greenhouse gases” and including carbon dioxide and methane, may be contributing to warming of the Earth’s atmosphere. In response to such studies, the U.S.

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Congress has considered legislation to reduce emissions of greenhouse gases. In addition, at least one-third of the states, either individually or through multi-state regional initiatives, have already taken legal measures to reduce emissions of greenhouse gases, primarily through the planned development of greenhouse gas emission inventories and/or greenhouse gas cap and trade programs. As an alternative to reducing emission of greenhouse gases under cap and trade programs, Congress may consider the implementation of a program to tax the emission of carbon dioxide and other greenhouse gases. In December 2009, the EPA issued an endangerment finding that greenhouse gases may reasonably be anticipated to endanger public health and welfare and are a pollutant to be regulated under the Clean Air Act. Passage of climate change legislation or other regulatory initiatives by Congress or various states of the United States or the adoption of regulations by the EPA or analogous state agencies that regulate or restrict emissions of greenhouse gases in areas in which we conduct business, could result in changes to the demand for the products we store, transport and sell, and could increase the costs of our operations, including costs to operate and maintain our facilities, install new emission controls on our facilities, acquire allowances to authorize our greenhouse gas emissions, pay any taxes related to our greenhouse gas emissions and administer and manage a greenhouse gas emissions program. We may be unable to recover any such lost revenues or increased costs in the rates we charge our customers, and any such recovery may depend on events beyond our control, including the outcome of future rate proceedings before the FERC and the provisions of any final legislation or regulations. Reductions in our revenues or increases in our expenses as a result of climate control initiatives could have adverse effects on our business, financial position, results of operations and prospects.
We operate a global business that exposes us to additional risk.
We operate in seven foreign countries and a significant portion of our revenues come from our business in these countries. Our operations outside the United States may be affected by changes in trade protection laws, policies and measures, and other regulatory requirements affecting trade and investment, including the Foreign Corrupt Practices Act, the United Kingdom Bribery Act and other foreign laws prohibiting corrupt payments. We have assets in certain emerging markets, and the developing nature of these markets presents a number of risks. Deterioration of social, political, labor or economic conditions in a specific country or region and difficulties in staffing and managing foreign operations may also adversely affect our operations or financial results.

Our operations are subject to federal, state and local laws and regulations, in the U.S. and in the foreign countries in which we operate, relating to environmental protection and operational safety that could require us to make substantial expenditures.
Our operations are subject to increasingly stringent environmental and safety laws and regulations. Transporting and storing petroleum products produces a risk that these products may be released into the environment, potentially causing substantial expenditures for a response action, significant government penalties, liability to government agencies for damages to natural resources, personal injury or property damages to private parties and significant business interruption. We own or lease a number of properties that have been used to store or distribute refined products for many years. Many of these properties were operated by third parties whose handling, disposal or release of hydrocarbons and other wastes was not under our control.
If we were to incur a significant liability pursuant to environmental or safety laws or regulations, such a liability could have a material adverse effect on our financial position, our ability to make distributions to our unitholders at current levels and our ability to meet our debt service requirements. Please read Item 3. “Legal Proceedings” and Note 16 of Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data.”
Our interstate common carrier pipelines are subject to regulation by the FERC.
The FERC regulates the tariff rates for interstate oil movements on our common carrier pipelines. Shippers may protest our pipeline tariff filings, and the FERC may investigate new or changed tariff rates. Further, other than for rates set under market-based rate authority, the FERC may order refunds of amounts collected under newly filed rates that are determined by the FERC to exceed what the FERC determines to be a just and reasonable level. In addition, shippers may challenge tariff rates even after the rates have been deemed final and effective. The FERC may also investigate such rates absent shipper complaint. If existing rates are challenged and are determined by the FERC to be in excess of a just and reasonable level, a shipper may obtain reparations for damages sustained during the two years prior to the date the shipper filed a complaint.

We use various FERC-authorized rate change methodologies for our interstate pipelines, including indexing, cost-of-service rates, market-based rates and settlement rates. Typically, we adjust our rates annually in accordance with FERC indexing methodology, which currently allows a pipeline to change their rates within prescribed ceiling levels that are tied to an inflation index. The current index (which runs through June 30, 2014) is measured by the year-over-year change in the Bureau of Labor’s producer price index for finished goods, plus 2.65%. Shippers may protest rate increases made within the ceiling levels, but such protests must show that the portion of the rate increase resulting from application of the index is substantially in excess of the pipeline’s increase in costs from the previous year. However, if the index results in a negative adjustment, we are required to reduce any rates that exceed the new maximum allowable rate. In addition, changes in the index might not be large enough to fully reflect actual increases in our costs. If the FERC’s rate-making methodologies change, any such change or

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new methodologies could result in rates that generate lower revenues and cash flow and could adversely affect our ability to make distributions at current levels to our unitholders and to meet our debt service requirements. Additionally, competition constrains our rates in various markets. As a result, we may from time to time be forced to reduce some of our rates to remain competitive.
Changes to FERC rate-making principles could have an adverse impact on our ability to recover the full cost of operating our pipeline facilities and our ability to make distributions at current levels to our unitholders.
In May 2005, the FERC issued a statement of general policy stating it will permit pipelines to include in cost of service a tax allowance to reflect actual or potential tax liability on their public utility income attributable to all partnership or limited liability company interests, if the ultimate owner of the interest has an actual or potential income tax liability on such income. Whether a pipeline’s owners have such actual or potential income tax liability will be reviewed by the FERC on a case-by-case basis. Although this policy is generally favorable for pipelines that are organized as pass-through entities, it still entails rate risk due to the case-by-case review requirement. This tax allowance policy and the FERC’s application of that policy were appealed to the United States Court of Appeals for the District of Columbia Circuit (D.C. Court), and on May 29, 2007, the D.C. Court issued an opinion upholding the FERC’s tax allowance policy.
In December 2006, the FERC issued an order addressing income tax allowance in rates, in which it reaffirmed prior statements regarding its income tax allowance policy, but raised a new issue regarding the implications of the FERC’s policy statement for publicly traded partnerships. The FERC noted that the tax deferral features of a publicly traded partnership may cause some investors to receive, for some indeterminate duration, cash distributions in excess of their taxable income, creating an opportunity for those investors to earn additional return, funded by ratepayers. Responding to this concern, the FERC adjusted the equity rate of return of the pipeline at issue downward based on the percentage by which the publicly traded partnership’s cash flow exceeded taxable income. Requests for rehearing of the order are currently pending before the FERC.
Because the extent to which an interstate oil pipeline is entitled to an income tax allowance is subject to a case-by-case review at the FERC, the level of income tax allowance to which we will ultimately be entitled is not certain. Although the FERC’s current income tax allowance policy is generally favorable for pipelines that are organized as pass-through entities, it still entails rate risks due to the case-by-case review requirement. How the FERC’s policy statement is applied in practice to pipelines owned by publicly traded partnerships could impose limits on our ability to include a full income tax allowance in cost of service.
The FERC instituted a rulemaking proceeding in July 2007 to determine whether any changes should be made to the FERC’s methodology for determining pipeline equity returns to be included in cost-of-service based rates. The FERC determined that it would retain its current methodology for determining return on equity but that, when stock prices and cash distributions of tax pass-through entities are used in the return on equity calculations, the growth forecasts for those entities should be reduced by 50%. Despite the FERC’s determination, some complainants in rate proceedings have advocated that the FERC disallow the full use of cash distributions in the return on equity calculation. If the FERC were to disallow the use of full cash distributions in the return on equity calculation, such a result might adversely affect our ability to achieve a reasonable return.
The rates that we may charge on our interstate ammonia pipeline are subject to regulation by the STB.
The STB, a part of the DOT, has jurisdiction over interstate pipeline transportation and rate regulations of anhydrous ammonia. Transportation rates must be reasonable, and a pipeline carrier may not unreasonably discriminate among its shippers. If the STB finds that a carrier’s rates violate these statutory commands, it may prescribe a reasonable rate. In determining a reasonable rate, the STB will consider, among other factors, the effect of the rate on the volumes transported by that carrier, the carrier’s revenue needs and the availability of other economic transportation alternatives. The STB does not provide rate relief unless shippers lack effective competitive alternatives. If the STB determines that effective competitive alternatives are not available and we hold market power, then we may be required to show that our rates are reasonable.
Increases in natural gas and power prices could adversely affect our operating expenses and our ability to make distributions at current levels to our unitholders.
Power costs constitute a significant portion of our operating expenses. For the year ended December 31, 2013, our power costs equaled approximately $40.1 million, or 8.8% of our operating expenses for the year. We use mainly electric power at our pipeline pump stations and terminals, and such electric power is furnished by various utility companies that use primarily natural gas to generate electricity. Accordingly, our power costs typically fluctuate with natural gas prices. Increases in natural gas prices may cause our power costs to increase further. If natural gas prices increase, our cash flows may be adversely affected, which could adversely affect our ability to make distributions at current levels to our unitholders.

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

NuStar GP Holdings may have conflicts of interest and limited fiduciary responsibilities, which may permit it to favor its own interests to the detriment of our unitholders.
NuStar GP Holdings currently indirectly owns our general partner and as of December 31, 2013, an aggregate 12.9% limited partner interest in us. Conflicts of interest may arise between NuStar GP Holdings and its affiliates, including our general partner, on the one hand, and us and our limited partners, on the other hand. As a result of these conflicts, the general partner may favor its own interests and the interests of its affiliates over the interests of our unitholders. These conflicts include, among others, the following situations:
Our general partner is allowed to take into account the interests of parties other than us, such as NuStar GP Holdings, in resolving conflicts of interest, which has the effect of limiting its fiduciary duty to the unitholders;
Our general partner may limit its liability and reduce its fiduciary duties, while also restricting the remedies available to unitholders. As a result of purchasing our common units, unitholders have consented to some actions and conflicts of interest that might otherwise constitute a breach of fiduciary or other duties under applicable state law;
Our general partner determines the amount and timing of asset purchases and sales, capital expenditures, borrowings, issuance of additional limited partner interests and reserves, each of which can affect the amount of cash that is paid to our unitholders;
Our general partner determines in its sole discretion which costs incurred by NuStar GP Holdings and its affiliates are reimbursable by us;
Our general partner may cause us to pay the general partner or its affiliates for any services rendered on terms that are fair and reasonable to us or enter into additional contractual arrangements with any of these entities on our behalf;
Our general partner decides whether to retain separate counsel, accountants or others to perform services for us; and
In some instances, our general partner may cause us to borrow funds in order to permit the payment of distributions.
Our partnership agreement gives the general partner broad discretion in establishing financial reserves for the proper conduct of our business, including interest payments. These reserves also will affect the amount of cash available for distribution.
TAX RISKS TO OUR UNITHOLDERS
If we were treated as a corporation for federal or state income tax purposes, then our cash available for distribution to unitholders would be substantially reduced.
The anticipated after-tax benefit of an investment in our units depends largely on our being treated as a partnership for federal income tax purposes. We have not requested, and do not plan to request, a ruling from the Internal Revenue Service (the IRS) on this matter.
If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate, which is currently a maximum of 35%. Distributions to unitholders would generally be taxed again as corporate distributions, and no income, gains, losses, deductions or credits would flow through to unitholders. Thus, treatment

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of us as a corporation would result in a material reduction in our anticipated cash flow and after-tax return to unitholders, likely causing a substantial reduction in the value of our units.
Current law may change, causing us to be treated as a corporation for federal income tax purposes or otherwise subjecting us to entity-level taxation. In addition, because of widespread state budget deficits, several states are evaluating ways to subject partnerships to entity level taxation through the imposition of state income, franchise or other forms of taxation. Partnerships and limited liability companies, unless specifically exempted, are also subject to a state-level tax imposed on revenues. Imposition of any entity-level tax on us by states in which we operate will reduce the cash available for distribution to our unitholders.
A successful IRS contest of the federal income tax positions we take may adversely impact the market for our units, and the costs of any contest will reduce cash available for distribution to our unitholders.
The IRS may adopt positions that differ from the positions we take, even positions taken with the advice of counsel. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take. A court may not agree with all of the positions we take. Any contest with the IRS may materially and adversely impact the market for our units and the prices at which they trade. In addition, the costs of any contest between us and the IRS will result in a reduction in cash available for distribution to our unitholders. Moreover, the costs of any contest between us and the IRS will result in a reduction in cash available for distribution to our unitholders and thus will be borne indirectly by our unitholders and our general partner.
Even if unitholders do not receive any cash distributions from us, they will be required to pay taxes on their respective share of our taxable income.
Unitholders will be required to pay federal income taxes and, in some cases, state and local income taxes on the unitholder’s respective share of our taxable income, whether or not such unitholder receives cash distributions from us. Unitholders may not receive cash distributions from us equal to the unitholder’s respective share of our taxable income or even equal to the actual tax liability that results from the unitholder’s respective share of our taxable income.
The sale or exchange of 50% or more of our capital and profits interests, within a twelve-month period, will result in the termination of our partnership for federal income tax purposes.
A termination would, among other things, result in the closing of our taxable year for all unitholders and would result in a deferral of depreciation and cost recovery deductions allowable in computing our taxable income. If our partnership were terminated for federal income tax purposes, a NuStar Energy unitholder would be allocated an increased amount of federal taxable income for the year in which the partnership is considered terminated and the subsequent years as a percentage of the cash distributed to the unitholder with respect to that period.
Tax gain or loss on the disposition of our units could be different than expected.
If a unitholder sells units, the unitholder will recognize a gain or loss equal to the difference between the amount realized and that unitholder’s tax basis in those units. Prior distributions to the unitholder in excess of the total net taxable income the unitholder was allocated for a unit, which decreased the tax basis in that unit, will, in effect, become taxable income to the unitholder if the unit is sold at a price greater than the tax basis in that unit, even if the price the unitholder receives is less than the original cost. A substantial portion of the amount realized, whether or not representing gain, may be ordinary income to the selling unitholder.
Tax-exempt entities and foreign persons face unique tax issues from owning units that may result in adverse tax consequences to them.
Investment in units by tax-exempt entities, such as individual retirement accounts (known as IRAs) and non-United States persons raises issues unique to them. For example, virtually all of our income allocated to organizations exempt from federal income tax, including individual retirement accounts and other retirement plans, will be unrelated business taxable income and will be taxable to them. Distributions to non-United States persons will be reduced by withholding taxes at the highest applicable effective tax rate, and non-United States persons will be required to file United States federal income tax returns and pay tax on their share of our taxable income.
We will treat each purchaser of our units as having the same tax benefits without regard to the units purchased. The IRS may challenge this treatment, which could adversely affect the value of our units.
Because we cannot match transferors and transferees of units, we will adopt depreciation and amortization positions that may not conform to all aspects of existing Treasury regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to unitholders. It also could affect the timing of these tax benefits or the amount of gain from any sale of units and could have a negative impact on the value of our units or result in audit adjustments to a unitholder’s tax returns.

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

We have adopted certain valuation methodologies that may result in a shift of income, gain, loss and deduction between the general partner and the unitholders. The IRS may challenge this treatment, which could adversely affect the value of our common units.
When we issue additional units or engage in certain other transactions, we determine the fair market value of our assets and allocate any unrealized gain or loss attributable to our assets to the capital accounts of our unitholders and our general partner. Our methodology may be viewed as understating the value of our assets. In that case, there may be a shift of income, gain, loss and deduction between certain unitholders and the general partner, which may be unfavorable to such unitholders. Moreover, under our current valuation methods, subsequent purchasers of common units may have a greater portion of their Internal Revenue Code Section 743(b) adjustment allocated to our tangible assets and a lesser portion allocated to our intangible assets. The IRS may challenge our valuation methods, our allocation of the Section 743(b) adjustment attributable to our tangible and intangible assets, and allocations of income, gain, loss and deduction between the general partner and certain of our unitholders.
A successful IRS challenge to these methods or allocations could adversely affect the amount of taxable income or loss being allocated to our unitholders. It also could affect the amount of gain from our unitholders’ sale of common units and could have a negative impact on the value of the common units or result in audit adjustments to our unitholders’ tax returns without the benefit of additional deductions.

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

ITEM 1B. UNRESOLVED STAFF COMMENTS
None.

ITEM 3. LEGAL PROCEEDINGS
We are named as a defendant in litigation relating to our normal business operations, including regulatory and environmental matters. Due to the inherent uncertainty of litigation, there can be no assurance that the resolution of any particular claim or proceeding would not have a material adverse effect on our results of operations, financial position or liquidity.
We are insured against various business risks to the extent we believe is prudent; however, we cannot assure you that the nature and amount of such insurance will be adequate, in every case, to protect us against liabilities arising from future legal proceedings as a result of our ordinary business activity.
 
ENVIRONMENTAL AND SAFETY COMPLIANCE MATTERS
With respect to the environmental proceeding listed below, if it was decided against us, we believe that it would not have a material effect on our consolidated financial position. However, it is not possible to predict the ultimate outcome of the proceeding or whether such ultimate outcome may have a material effect on our consolidated financial position. We are reporting this proceeding to comply with Securities and Exchange Commission regulations, which require us to disclose

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proceedings arising under federal, state or local provisions regulating the discharge of materials into the environment or protecting the environment if we reasonably believe that such proceedings will result in monetary sanctions of $100,000 or more.
In particular, our wholly owned subsidiary, Shore Terminals LLC (Shore) owns a refined product terminal in Portland, Oregon located adjacent to the Portland Harbor. The EPA has classified portions of the Portland Harbor, including the portion adjacent to our terminal, as a federal “Superfund” site due to sediment contamination (the Portland Harbor Site). Portland Harbor is contaminated with metals (such as mercury), pesticides, herbicides, polynuclear aromatic hydrocarbons, polychlorinated biphenyls, semi-volatile organics and dioxin/furans. Shore and more than 90 other parties have received a “General Notice” of potential liability from the EPA relating to the Portland Harbor Site. The letter advised Shore that it may be liable for the costs of investigation and remediation (which liability may be joint and several with other potentially responsible parties), as well as for natural resource damages resulting from releases of hazardous substances to the Portland Harbor Site. We have agreed to work with more than 90 other potentially responsible parties to attempt to negotiate an agreed method of allocating costs associated with the cleanup. The precise nature and extent of any clean-up of the Portland Harbor Site, the parties to be involved, the process to be followed for any clean-up and the allocation of any costs for the clean-up among responsible parties have not yet been determined. It is unclear to what extent, if any, we will be liable for environmental costs or damages associated with the Portland Harbor Site. It is also unclear to what extent natural resource damage claims or third party contribution or damage claims will be asserted against Shore.
We are also a party to additional claims and legal proceedings arising in the ordinary course of business. Due to the inherent uncertainty of litigation, there can be no assurance that the resolution of any particular claim or proceeding would not have a material adverse effect on our results of operations, financial position or liquidity.

ITEM 4. MINE SAFETY DISCLOSURES
Not applicable.

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PART II

ITEM 5.
MARKET FOR REGISTRANT’S COMMON UNITS, RELATED UNITHOLDER MATTERS AND ISSUER PURCHASES OF COMMON UNITS
Market Information, Holders and Distributions
Our common units are listed and traded on the New York Stock Exchange under the symbol “NS.” At the close of business on February 10, 2014, we had 627 holders of record of our common units. The high and low sales prices (composite transactions) by quarter for the years ended December 31, 2013 and 2012 were as follows:
 
Price Range of Common Unit
 
High
 
Low
Year 2013
 
 
 
4th Quarter
$
53.69

 
$
39.52

3rd Quarter
46.52

 
36.15

2nd Quarter
54.95

 
42.31

1st Quarter
53.45

 
43.40

Year 2012
 
 
 
4th Quarter
$
51.97

 
$
39.07

3rd Quarter
54.88

 
48.44

2nd Quarter
59.51

 
49.38

1st Quarter
62.64

 
55.12

The cash distributions applicable to each of the quarters in the years ended December 31, 2013 and 2012 were as follows:
 
 
 
 
 
 
 
Record Date
 
Payment Date
 
Amount
Per Unit
Year 2013
 
 
 
 
 
4th Quarter
February 10, 2014
 
February 14, 2014
 
$
1.095

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

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

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

Year 2012
 
 
 
 
 
4th Quarter
February 11, 2013
 
February 14, 2013
 
$
1.095

3rd Quarter
November 9, 2012
 
November 14, 2012
 
1.095

2nd Quarter
August 7, 2012
 
August 10, 2012
 
1.095

1st Quarter
May 8, 2012
 
May 11, 2012
 
1.095

Our general partner is entitled to incentive distributions if the amount that we distribute with respect to any quarter exceeds specified target levels shown below:
 
 
Percentage of Distribution
Quarterly Distribution Amount per Unit
 
Unitholders
 
General Partner
Up to $0.60
 
98%
 
2%
Above $0.60 up to $0.66
 
90%
 
10%
Above $0.66
 
75%
 
25%
Our general partner’s incentive distributions for the years ended December 31, 2013 and 2012 totaled $43.2 million and $41.2 million, respectively. The general partner’s share of our distributions for the years ended December 31, 2013 and 2012 was 13.0% in each year due to the impact of the incentive distributions.


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ITEM 6. SELECTED FINANCIAL DATA
The following table contains selected financial data derived from our audited financial statements. On January 1, 2013, we sold the San Antonio Refinery. As a result, we have presented the results of operations for the San Antonio Refinery and related assets as discontinued operations for all periods presented. As of December 31, 2013, we reclassified certain storage assets as “Assets held for sale” on the consolidated balance sheet. As a result, we have presented the results of operations for those assets as discontinued operations for all periods presented.
 
Year Ended December 31,
 
2013 (a)
 
2012 (a)
 
2011
 
2010
 
2009
 
(Thousands of Dollars, Except Per Unit Data)
Statement of Income Data:
 
 
 
 
 
 
 
 
 
Revenues
$
3,463,732

 
$
5,945,736

 
$
6,257,629

 
$
4,395,083

 
$
3,854,895

Operating (loss) income
(19,121
)
 
(18,168
)
 
310,883

 
306,747

 
277,729

(Loss) income from continuing operations
(185,509
)
 
(166,001
)
 
218,674

 
243,931

 
229,360

(Loss) income from continuing operations per
unit applicable to limited partners
(2.89
)
 
(2.79
)
 
2.74

 
3.27

 
3.55

Cash distributions per unit applicable to
limited partners
4.380

 
4.380

 
4.360

 
4.280

 
4.245

 
 
 
 
 
 
 
 
 
 
 
December 31,
 
2013
 
2012
 
2011
 
2010
 
2009
 
(Thousands of Dollars)
Balance Sheet Data:
 
 
 
 
 
 
 
 
 
Property, plant and equipment, net
$
3,310,653

 
$
3,238,460

 
$
3,430,468

 
$
3,187,457

 
$
3,028,196

Total assets
5,032,186

 
5,613,089

 
5,881,190

 
5,386,393

 
4,774,673

Long-term debt, less current portion
2,655,553

 
2,124,582

 
1,928,071

 
2,136,248

 
1,828,993

Total partners’ equity
1,903,794

 
2,584,995

 
2,864,335

 
2,702,700

 
2,484,968


(a)
The losses for the years ended December 31, 2013 and 2012 are mainly due to goodwill and other asset impairment charges. Please refer to Note 5 and Note 6 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for a discussion of goodwill and other asset impairments.

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ITEM 7.MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
The following review of our results of operations and financial condition should be read in conjunction with Items 1., 1A. and 2. “Business, Risk Factors and Properties” and Item 8. “Financial Statements and Supplementary Data” included in this report.
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION
This Form 10-K contains certain estimates, predictions, projections, assumptions and other forward-looking statements that involve various risks and uncertainties. While these forward-looking statements, and any assumptions upon which they are based, are made in good faith and reflect our current judgment regarding the direction of our business, actual results will almost always vary, sometimes materially, from any estimates, predictions, projections, assumptions or other future performance suggested in this report. These forward-looking statements can generally be identified by the words “anticipates,” “believes,” “expects,” “plans,” “intends,” “estimates,” “forecasts,” “budgets,” “projects,” “will,” “could,” “should,” “may” and similar expressions. These statements reflect our current views with regard to future events and are subject to various risks, uncertainties and assumptions. Please read Item 1A. “Risk Factors” for a discussion of certain of those risks.
If one or more of these risks or uncertainties materialize, or if the underlying assumptions prove incorrect, our actual results may vary materially from those described in any forward-looking statement. Other unknown or unpredictable factors could also have material adverse effects on our future results. Readers are cautioned not to place undue reliance on this forward-looking information, which is as of the date of the Form 10-K. We do not intend to update these statements unless it is required by the securities laws to do so, and we undertake no obligation to publicly release the result of any revisions to any such forward-looking statements that may be made to reflect events or circumstances after the date of this report or to reflect the occurrence of unanticipated events.
OVERVIEW
NuStar Energy L.P. (NuStar Energy) (NYSE: NS) is engaged in the terminalling and storage of petroleum products, the transportation of petroleum products and anhydrous ammonia, and the marketing of petroleum products. Unless otherwise indicated, the terms “NuStar Energy,” “the Partnership,” “we,” “our” and “us” are used in this report to refer to NuStar Energy, to one or more of our consolidated subsidiaries or to all of them taken as a whole. NuStar GP Holdings, LLC (NuStar GP Holdings) (NYSE: NSH) owns our general partner, Riverwalk Logistics, L.P., and owns a 14.9% total interest in us as of December 31, 2013. Our Management’s Discussion and Analysis of Financial Condition and Results of Operations is presented in six sections:
Overview
Results of Operations
Trends and Outlook
Liquidity and Capital Resources
Related Party Transactions
Critical Accounting Policies
2013 Goodwill Impairment
In the fourth quarter of 2013, we recognized a $304.5 million goodwill impairment loss in the storage segment, which represents the write-down of the carrying value of goodwill associated with our St. Eustatius and Point Tupper terminal operations. Please refer to Note 6 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for a discussion of the goodwill impairment loss.
Acquisitions and Dispositions
Terminal Facilities Held for Sale. We identified several non-strategic, underperforming terminal facilities, and as of December 31, 2013, we reclassified the property, plant and equipment associated with these assets as “Assets held for sale” on the consolidated balance sheet. We presented the results of operations for these assets, previously in the storage segment, as discontinued operations for all periods presented, including an impairment loss of $102.5 million for the year ended December 31, 2013. Please refer to Note 5 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for a discussion of these assets held for sale.

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

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terminal and refinery for approximately $117.0 million (the San Antonio Refinery Sale). As of December 31, 2012, we reclassified the assets related to the sale of the San Antonio Refinery as “Assets held for sale” on the consolidated balance sheet. We have presented the results of operations for the San Antonio Refinery and related assets, previously reported in the fuels marketing and pipeline segments, as discontinued operations for all periods presented. Please refer to Note 5 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for a discussion of the San Antonio Refinery Sale.

TexStar Asset Acquisition. On December 13, 2012, NuStar Logistics completed its acquisition of the TexStar Crude Oil Assets (as defined below), including 100% of the partnership interest in TexStar Crude Oil Pipeline, LP, from TexStar Midstream Services, LP and certain of its affiliates (collectively, TexStar) for $325.4 million (the TexStar Asset Acquisition). The TexStar Crude Oil Assets consist of approximately 140 miles of crude oil pipelines and gathering lines, as well as five terminals and storage facilities providing 0.6 million barrels of storage capacity. The consolidated statements of income include the results of operations for the TexStar Asset Acquisition in the pipeline segment commencing on December 13, 2012.

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

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

In anticipation of the Asphalt Sale, we evaluated the goodwill and other long-lived assets associated with the Asphalt Operations for potential impairment. We determined the fair value of the Asphalt Operations reporting unit was less than its carrying value, which resulted in the recognition of a goodwill impairment loss of $22.1 million in the second quarter of 2012. In addition, we recorded an impairment loss of $244.3 million in the second quarter of 2012 to write-down the carrying value of long-lived assets related to the Asphalt Operations, including fixed assets, intangible assets and other long-term assets, to their estimated fair value. The goodwill impairment loss and the asset impairment loss related to the Asphalt Operations are reported in the asphalt and fuels marketing segment. Please refer to Note 5 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for a discussion of the Asphalt Sale, the related asset impairments and associated fair value measurements.

In February 2014, we divested of our remaining 50% ownership interest in Asphalt JV. See Note 29 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data”for additional discussion.
Operations
We conduct our operations through our subsidiaries, primarily NuStar Logistics, L.P. (NuStar Logistics) and NuStar Pipeline Operating Partnership L.P. (NuPOP). Our operations are divided into three reportable business segments: storage, pipeline, and fuels marketing. For a more detailed description of our segments, please refer to Segments under Item 1. “Business.”

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

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


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Fuels Marketing. In 2013, we changed the name of the “Asphalt and Fuels Marketing” segment to the “Fuels Marketing” segment. This name more accurately reflects the operations that remain after the Asphalt Sale and the San Antonio Refinery Sale. Our fuels marketing segment includes our fuels marketing operations and, prior to the Asphalt Sale, the Asphalt Operations. Within our fuels marketing operations, we purchase crude oil and refined petroleum products for resale. The results of operations for the fuels marketing segment depend largely on the margin between our cost and the sales prices of the products we market. Therefore, the results of operations for this segment are more sensitive to changes in commodity prices compared to the operations of the storage and pipeline segments.

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


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

 
$
870,157

 
$
67,981

Product sales
2,525,594

 
5,075,579

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

 
5,945,736

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

 
4,930,174

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

 
526,145

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

 
104,756

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

 
159,789

 
19,132

Goodwill impairment loss
304,453

 
22,132

 
282,321

Asset impairment loss

 
249,646

 
(249,646
)
Gain on legal settlement

 
(28,738
)
 
28,738

Total costs and expenses
3,482,853

 
5,963,904

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

 
1,219

 
4,894

Other income (expense), net
7,341

 
(24,689
)
 
32,030

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

 
24,450

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


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

 
72,957,417

 
4,928,661


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

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

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Segment Operating Highlights
(Thousands of Dollars, Except Barrel/Day Information)
 
 
Year Ended December 31,
 
 
 
2013
 
2012
 
Change
Storage:
 
 
 
 
 
Throughput (barrels/day)
781,213

 
765,556

 
15,657

Throughput revenues
$
104,553

 
$
95,612

 
$
8,941

Storage lease revenues
451,996

 
482,454

 
(30,458
)
Total revenues
556,549

 
578,066

 
(21,517
)
Operating expenses
279,712

 
288,881

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

 
88,217

 
11,651

Goodwill and asset impairment loss
304,453

 
2,126

 
302,327

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

 
$
(326,326
)
 
 
 
 
 
 
Pipeline:
 
 
 
 
 
Refined products pipelines throughput (barrels/day)
487,021

 
498,321

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

 
345,648

 
20,101

Total throughput (barrels/day)
852,770

 
843,969

 
8,801

Throughput revenues
$
411,529

 
$
340,455

 
$
71,074

Operating expenses
134,365

 
128,987

 
5,378

Depreciation and amortization expense
68,871

 
52,878

 
15,993

Segment operating income
$
208,293

 
$
158,590

 
$
49,703

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

 
$
5,086,383

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

 
4,957,100

 
(2,482,488
)
Gross margin
53,086

 
129,283

 
(76,197
)
Operating expenses
53,185

 
148,458

 
(95,273
)
Depreciation and amortization expense
27

 
11,253

 
(11,226
)
Goodwill and asset impairment loss

 
266,357

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

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

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

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

Total
$
1,437

 
$
7,939

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

 
$
5,945,736

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

 
4,930,174

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

 
526,145

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

 
152,348

 
16,418

Asset and goodwill impairment loss
304,453

 
268,483

 
35,970

Segment operating income
82,120

 
68,586

 
13,534

General and administrative expenses
91,086

 
104,756

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

 
7,441

 
2,714

Other asset impairment loss

 
3,295

 
(3,295
)
Gain on legal settlement

 
(28,738
)
 
28,738

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

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

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

These decreases were partially offset by an increase of $3.9 million in salaries and wages due to a collective labor agreement that became effective in mid-2012 associated with our St. Eustatius terminal, our acquisition of a lease at the Redfish Bay terminal in conjunction with the TexStar Asset Acquisition, and higher employee benefit and temporary labor costs.
Depreciation and amortization expense increased $11.7 million for the year ended December 31, 2013, compared to the year ended December 31, 2012, primarily due to completion of a dock optimization project at our Corpus Christi crude storage tank facility, unit train and tank expansion projects at our St. James terminal and a tank expansion project at our St. Eustatius terminal.
The asset impairment loss of $304.5 million for the year ended December 31, 2013 represents the write-down of the carrying value of goodwill associated with our St. Eustatius and Point Tupper terminal operations. Please refer to Note 6 of the Condensed Notes to Consolidated Financial Statements in Item 1. “Financial Statements” for further discussion of this goodwill impairment.
Pipeline
Revenues increased $71.1 million and throughputs increased 8,801 barrels per day for the year ended December 31, 2013, compared to the year ended December 31, 2012, primarily due to:
an increase in revenues of $57.4 million and an increase in throughputs of 49,855 barrels per day on crude oil pipelines that serve Eagle Ford Shale production in South Texas, primarily resulting from the TexStar Asset Acquisition and crude oil pipelines that were placed in service in the fourth quarter of 2012 and third quarter of 2013;

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an increase in revenues of $6.3 million on the East Pipeline, despite lower throughputs of 2,997 barrels per day, due to higher average tariffs resulting from the annual index adjustment in July 2013 and increased long-haul deliveries;
an increase in revenues of $5.6 million and an increase in throughputs of 2,067 barrels per day on the North Pipeline, mainly due to the completion of an expansion project at the Mandan refinery in June 2012; and
an increase in revenues of $5.2 million and an increase in throughputs of 4,210 barrels per day on refined product and crude oil pipelines serving the McKee refinery resulting from increased volumes on pipelines with higher tariffs.

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

Revenues decreased $3.9 million and throughputs decreased 5,613 barrels per day on the Ammonia Pipeline due to unseasonably cold and wet weather in the second and fourth quarters of 2013. Also, revenues decreased $1.6 million and throughputs decreased 6,731 barrels per day on the Houston pipeline as it is being converted to new service.
Operating expenses increased $5.4 million for the year ended December 31, 2013, compared to the year ended December 31, 2012, primarily due to an increase of $18.6 million on crude oil pipelines that serve Eagle Ford Shale production in South Texas, mainly resulting from the TexStar Asset Acquisition and crude oil pipelines that were placed in service in the fourth quarter of 2012.
This increase was partially offset by:
a decrease of $8.0 million resulting from the reduction of the contingent consideration liability recorded in association with the TexStar Asset Acquisition. Please refer to Note 17 of the Condensed Notes to Consolidated Financial Statements in Item 1. “Financial Statements” for further discussion; and
a decrease of $3.5 million due to temporary barge rental costs in 2012 needed to transport a customer’s product in conjunction with an Eagle Ford Shale project.
Depreciation and amortization expense increased $16.0 million for the year ended December 31, 2013, compared to the year ended December 31, 2012, mainly due to the TexStar Asset Acquisition in December 2012 and the completion of various projects that serve Eagle Ford Shale production.
Fuels Marketing
The consolidated statements of income (loss) include the results of operations for Asphalt JV in “Equity in (loss) earnings of joint ventures” commencing on September 28, 2012. Previously, we reported the results of operations for our Asphalt Operations in the fuels marketing segment. For the year ended December 31, 2013, this segment mainly includes refined products marketing, crude oil trading, fuel oil trading and bunkering operations. The table below presents pro forma financial information that removes the historical financial information for our Asphalt Operations from the segment results for the year ended December 31, 2012 in order to provide a more meaningful comparison of the segment’s results.
 
 
 
Year Ended December 31, 2012
 
 
 
Year Ended
December 31, 2013
 
Actual
 
Asphalt Operations
 
Pro Forma
 
Change
 
(Thousands of Dollars)
Product sales
$
2,527,698

 
$
5,086,383

 
$
1,315,986

 
$
3,770,397

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

 
4,957,100

 
1,258,308

 
3,698,792

 
(1,224,180
)
Gross margin
53,086

 
129,283

 
57,678

 
71,605

 
(18,519
)
Operating expenses
53,185

 
148,458

 
89,969

 
58,489

 
(5,304
)
Depreciation and amortization expense
27

 
11,253

 
11,138

 
115

 
(88
)
Asset and goodwill impairment loss

 
266,357

 
266,357

 

 

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

 
$
(13,127
)

Sales and cost of product sales decreased $1,242.7 million and $1,224.2 million, respectively, resulting in a decrease in total gross margin of $18.5 million for the year ended December 31, 2013, compared to the year ended December 31, 2012. The decrease in total gross margin was primarily due to a positive gross margin of $12.0 million from crude oil trading in 2012, as

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compared to a gross margin loss of $0.3 million in 2013. In 2012, higher volumes were traded in the first part of 2012 to benefit from the price differential on two traded crude oil grades (WTI and LLS). In addition, the gross margin from bunker fuel sales decreased $9.8 million for the year ended December 31, 2013, compared to the year ended December 31, 2012, mainly at our St. Eustatius and Texas City facilities. Reduced demand for bunker fuels and increased competition in the Caribbean and the U.S. Gulf Coast has negatively impacted our sales prices and resulted in lower gross margins as compared to the same period last year. These decreases were partially offset by an increase of $3.7 million in the gross margin from fuel oil trading attributable to lower costs that outweighed falling sales prices compared to the same period last year.
Operating expenses decreased $5.3 million for the year ended December 31, 2013, compared to the year ended December 31, 2012, mainly due to a decrease in operating expenses from our bunker fuel operations as we exited certain U.S. markets.
Consolidation and Intersegment Eliminations
Revenue and operating expense eliminations primarily relate to storage and transportation fees charged to the fuels marketing segment by the storage and pipeline segments. Revenue and operating expense eliminations changed by $27.1 million and $27.3 million, respectively, for the year ended December 31, 2013, compared to the year ended December 31, 2012, mainly due to the Asphalt Sale in September 2012. Cost of product sales eliminations represent expenses charged to the fuels marketing segment for costs associated with inventory that are expensed once the inventory is sold.
General
General and administrative expenses decreased $13.7 million for the year ended December 31, 2013, compared to the year ended December 31, 2012, primarily due to the early termination of a lease for our previous corporate office and expenses that are now reimbursed by Asphalt JV for corporate support services under a services agreement between Asphalt JV and NuStar GP, LLC. In addition, general and administrative expenses in the second quarter of 2012 included costs that resulted from a Canadian income tax audit.
Other depreciation and amortization expense increased $2.7 million for the year ended December 31, 2013, compared to the year ended December 31, 2012, mainly due to the completion of our corporate office in the fourth quarter of 2012.
The other asset impairment loss of $3.3 million for the year ended December 31, 2012 represents the write-down of the carrying value of certain corporate assets we sold in 2013.
The gain on legal settlement of $28.7 million for the year ended December 31, 2012 represents the settlement of a legal matter in the second quarter of 2012.
Equity in loss of joint ventures increased $30.6 million for the year ended December 31, 2013, compared to the year ended December 31, 2012, primarily due to a $49.6 million loss from our investment in Asphalt JV in 2013, which continued to suffer from weak asphalt margins.
Interest expense, net increased $36.6 million for the year ended December 31, 2013, compared to the year ended December 31, 2012, mainly due to the issuance of the $402.5 million of 7.625% fixed-to-floating rate subordinated notes in January 2013.
Interest income from related party increased $4.9 million for the year ended December 31, 2013, compared to the year ended December 31, 2012, as a result of a full year of borrowings by Asphalt JV under the $250.0 million seven-year unsecured revolving credit facility. We entered into this credit facility with Asphalt JV in connection with the Asphalt Sale on September 28, 2012. Please refer to Note 19 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for additional information on our agreements with Asphalt JV.
Other income (expense), net changed by $32.0 million for the year ended December 31, 2013, compared to the year ended December 31, 2012, mainly due to a loss of $23.8 million associated with the Asphalt Sale in 2012 and changes in foreign exchange rates related to our foreign subsidiaries.
Income tax expense decreased $11.7 million for the year ended December 31, 2013, compared to the year ended December 31, 2012, mainly due to tax expense of $10.1 million related to the $28.7 million gain on legal settlement recognized in the second quarter of 2012.
For the year ended December 31, 2013, we recorded a loss from discontinued operations of $99.2 million, compared to a loss from discontinued operations of $61.2 million for the year ended December 31, 2012. For the year ended December 31, 2013, the loss from discontinued operations includes asset impairment charges of $102.5 million associated with certain storage terminals that were classified as “Assets held for sale” on the consolidated balance sheet as of December 31, 2013. Please refer to Note 5 of the Condensed Notes to Consolidated Financial Statements in Item 1. “Financial Statements” for further discussion

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of these asset impairment charges. This loss was partially offset by a gain of $9.3 million related to the San Antonio Refinery Sale.
For the year ended December 31, 2012, the loss from discontinued operations includes losses of $49.1 million from the San Antonio Refinery, mainly due to hedge losses and falling sales prices coupled with high weighted-average costs, which resulted in an overall negative gross margin.

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Year Ended December 31, 2012 Compared to Year Ended December 31, 2011
Financial Highlights
(Thousands of Dollars, Except Unit and Per Unit Data)
 
Year Ended December 31,
 
 
 
2012
 
2011
 
Change
Statement of Income Data:
 
Revenues:
 
 
 
 
 
Service revenues
$
870,157

 
$
820,623

 
$
49,534

Product sales
5,075,579

 
5,437,006

 
(361,427
)
Total revenues
5,945,736

 
6,257,629

 
(311,893
)
 
 
 
 
 
 
Costs and expenses:
 
 
 
 
 
Cost of product sales
4,930,174

 
5,175,710

 
(245,536
)
Operating expenses
526,145

 
506,213

 
19,932

General and administrative expenses
104,756

 
103,050

 
1,706

Depreciation and amortization expense
159,789

 
161,773

 
(1,984
)
Asset impairment loss
249,646

 

 
249,646

Goodwill impairment loss
22,132

 

 
22,132

Gain on legal settlement
(28,738
)
 

 
(28,738
)
Total costs and expenses
5,963,904

 
5,946,746

 
17,158

 
 
 
 
 
 
Operating (loss) income
(18,168
)
 
310,883

 
(329,051
)
Equity in (loss) earnings of joint ventures
(9,378
)
 
11,458

 
(20,836
)
Interest expense, net
(90,535
)
 
(81,539
)
 
(8,996
)
Interest income from related party
1,219

 

 
1,219

Other expense, net
(24,689
)
 
(3,573
)
 
(21,116
)
(Loss) income from continuing operations before income tax expense
(141,551
)
 
237,229

 
(378,780
)
Income tax expense
24,450

 
18,555

 
5,895

(loss) income from continuing operations
(166,001
)
 
218,674

 
(384,675
)
(Loss) income from discontinued operations, net of tax
(61,236
)
 
2,927

 
(64,163
)
Net (loss) income
$
(227,237
)
 
$
221,601

 
$
(448,838
)
Net (loss) income per unit applicable to limited partners:
 
 
 
 


Continuing operations
$
(2.79
)
 
$
2.74

 
$
(5.53
)
Discontinued operations
(0.82
)
 
0.04

 
(0.86
)
Total
$
(3.61
)
 
$
2.78

 
$
(6.39
)
Weighted-average limited partner units outstanding
72,957,417

 
65,018,301

 
7,939,116

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

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Segment Operating Highlights
(Thousands of Dollars, Except Barrel/Day Information)
 
Year Ended December 31,
 
 
 
2012
 
2011
 
Change
Storage:
 
 
 
 
 
Throughput (barrels/day)
765,556

 
693,269

 
72,287

Throughput revenues
$
95,612

 
$
80,246

 
$
15,366

Storage lease revenues
482,454

 
466,381

 
16,073

Total revenues
578,066

 
546,627

 
31,439

Operating expenses
288,881

 
267,198

 
21,683

Depreciation and amortization expense
88,217

 
82,921

 
5,296

Asset impairment loss
2,126

 

 
2,126

Segment operating income
$
198,842

 
$
196,508

 
$
2,334

 
 
 
 
 
 
Pipeline:
 
 
 
 
 
Refined products pipelines throughput (barrels/day)
498,321

 
514,261

 
(15,940
)
Crude oil pipelines throughput (barrels/day)
345,648

 
317,427

 
28,221

Total throughput (barrels/day)
843,969

 
831,688

 
12,281

Throughput revenues
$
340,455

 
$
311,514

 
$
28,941

Operating expenses
128,987

 
113,946

 
15,041

Depreciation and amortization expense
52,878

 
51,165

 
1,713

Segment operating income
$
158,590

 
$
146,403

 
$
12,187

 
 
 
 
 
 
Fuels Marketing:
 
 
 
 
 
Product sales and other revenue
$
5,086,383

 
$
5,455,659

 
$
(369,276
)
Cost of product sales
4,957,100

 
5,205,574

 
(248,474
)
Gross margin
129,283

 
250,085

 
(120,802
)
Operating expenses
148,458

 
157,282

 
(8,824
)
Depreciation and amortization expense
11,253

 
20,949

 
(9,696
)
Asset and goodwill impairment loss
266,357

 

 
266,357

Segment operating (loss) income
$
(296,785
)
 
$
71,854

 
$
(368,639
)
 
 
 
 
 
 
Consolidation and Intersegment Eliminations:
 
 
 
 
 
Revenues
$
(59,168
)
 
$
(56,171
)
 
$
(2,997
)
Cost of product sales
(26,926
)
 
(29,864
)
 
2,938

Operating expenses
(40,181
)
 
(32,213
)
 
(7,968
)
Total
$
7,939

 
$
5,906

 
$
2,033

 
 
 
 
 
 
Consolidated Information:
 
 
 
 
 
Revenues
$
5,945,736

 
$
6,257,629

 
$
(311,893
)
Cost of product sales
4,930,174

 
5,175,710

 
(245,536
)
Operating expenses
526,145

 
506,213

 
19,932

Depreciation and amortization expense
152,348

 
155,035

 
(2,687
)
Asset and goodwill impairment loss
268,483

 

 
268,483

Segment operating income
68,586

 
420,671

 
(352,085
)
General and administrative expenses
104,756

 
103,050

 
1,706

Other depreciation and amortization expense
7,441

 
6,738

 
703

Other asset impairment loss
3,295

 

 
3,295

Gain on legal settlement
(28,738
)
 

 
(28,738
)
Consolidated operating (loss) income
$
(18,168
)
 
$
310,883

 
$
(329,051
)

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Storage
Throughput revenues increased $15.4 million and throughputs increased 72,287 barrels per day for the year ended December 31, 2012, compared to the year ended December 31, 2011, primarily due to:
an increase in revenues of $6.6 million and an increase in throughputs of 23,547 barrels per day at our Corpus Christi crude storage tank facility due to higher volumes from the Eagle Ford Shale region. In 2012, we changed this facility from a lease-based to a throughput-based facility in connection with the Eagle Ford Shale projects in our pipeline segment;
an increase in revenues of $3.2 million and an increase in throughputs of 23,711 barrels per day at our Benicia crude oil storage tanks due to a turnaround in the first quarter of 2011 at the refinery served by the crude oil storage tanks;
an increase in revenues of $2.7 million and an increase in throughputs of 11,566 barrels per day at our Paulsboro terminal and certain terminals serving the McKee refinery as customers shifted volumes to our terminals in 2012; and
an increase in revenues of $1.4 million and an increase in throughputs of 718 barrels per day at our Edinburg, Texas and Harlingen, Texas terminals due to a full year of ethanol blending services in 2012 that started in the third quarter of 2011.
Storage lease revenues increased $16.1 million for the year ended December 31, 2012, compared to the year ended December 31, 2011, primarily due to:
an increase of $36.7 million at our St. James terminal resulting from completed tank expansion projects and the unit train offloading facility project; and
an increase of $2.4 million at our St. Eustatius terminal facility, mainly due to rate escalations and increased reimbursable revenues.
These increases in revenues were partially offset by:
a decrease in revenues of $9.8 million at our Point Tupper terminal facility, mainly due to decreased dockage and throughputs, which were partially offset by rate escalations;
a decrease in revenues of $7.0 million due to the sale of five refined product terminals in April 2012;
a decrease in revenues of $6.6 million at our Corpus Christi crude storage tank facility due to the change to throughput-based fees in 2012; and
a decrease in revenues of $1.9 million at our UK and Amsterdam terminals, mainly due to the effect of foreign exchange rates and a decrease in customer product movements.
Operating expenses increased $21.7 million for the year ended December 31, 2012, compared to the year ended December 31, 2011, primarily due:
an increase of $6.6 million associated with cancelled capital projects, mainly at our St. James and St. Eustatius terminals;
an increase of $4.0 million in reimbursable expenses, mainly for tank cleanings at our Piney Point terminal and expenses associated with our atmospheric distillation unit at our St. Eustatius terminal. Reimbursable expenses are charged back to our customers and are offset by an increase in reimbursable revenues;
an increase of $3.5 million in other operating expenses mainly due to rectifying a contaminated tank at our St. Eustatius terminal; and
an increase of $1.9 million in internal overhead expense primarily as a result of fewer capital projects.
Depreciation and amortization expense increased $5.3 million for the year ended December 31, 2012, compared to the year ended December 31, 2011, primarily due to the completion of the St. James terminal unit train and tank expansion
projects.
The asset impairment loss of $2.1 million for the year ended December 31, 2012 represents the write-down of the carrying value of one of our terminals due to changing market conditions that reduced the estimated cash flows for that terminal.
Pipeline
Revenues increased $28.9 million and throughputs increased 12,281 barrels per day for the year ended December 31, 2012, compared to the year ended December 31, 2011, primarily due to:
an increase in revenues of $13.5 million and an increase in throughputs of 37,948 barrels per day on crude oil pipelines that serve Eagle Ford Shale production in South Texas, which consist of pipelines that were placed in service in the second and third quarters of 2011, as well as pipelines that were placed in service in the fourth quarter of 2012, including pipelines acquired from TexStar;
an increase in revenues of $7.2 million on the Ammonia Pipeline, while throughputs remained flat, due to increased long-haul deliveries resulting in a higher average tariff;

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an increase in revenues of $4.3 million and an increase in throughputs of 1,940 barrels per day on the North Pipeline, mainly due to an increase in the annual index adjustment and the completion of an expansion project at the Mandan refinery in June 2012;
an increase in revenues of $3.4 million and an increase in throughputs of 8,937 barrels per day on refined product pipelines serving the Three Rivers refinery, mainly due to a turnaround and operational issues in 2011 at the refinery and additional volumes delivered to a third-party terminal beginning in the third quarter of 2012;
an increase in revenues of $2.7 million on the East Pipeline, despite a decrease in throughputs of 6,586 barrels per day, due to higher average tariffs resulting from increased long-haul deliveries and an increase in the annual index adjustment. Fewer long-haul deliveries occurred in 2011 due to supply issues caused by flooding in the Midwest; and
an increase in revenues of $1.3 million and an increase in throughputs of 8,590 barrels per day on crude oil pipelines serving the Ardmore refinery due to a turnaround and operational issues in 2011.
These increases in revenues and throughputs were partially offset by:
a decrease in revenues of $2.8 million and a decease in throughputs of 8,684 barrels per day on the Houston pipeline as it was being converted to new service; and
a decrease in revenues of $1.1 million and a decrease in throughputs of 25,901 barrels per day on pipelines serving the McKee refinery, primarily due to a turnaround at the McKee refinery in April and May 2012. The decrease in revenues was partially offset by throughput deficiency payments received in 2012 related to one of the pipelines serving the McKee refinery.
Operating expenses increased $15.0 million for the year ended December 31, 2012, compared to the year ended December 31, 2011, mainly due to temporary barge rental costs to move a customer’s product associated with Eagle Ford Shale projects and losses on product imbalances on the East Pipeline.
Fuels Marketing
Sales and cost of product sales decreased $369.3 million and $248.5 million, respectively, resulting in a decrease in total gross margin of $120.8 million for the year ended December 31, 2012, compared to the year ended December 31, 2011. The gross margin from the Asphalt Operations decreased $86.1 million for the year ended December 31, 2012, compared to the year ended December 31, 2011, partly due to the deconsolidation of Asphalt JV on September 28, 2012. The gross margin decrease was also attributable to weak demand for asphalt, resulting in a decrease in volumes sold and a decrease in gross margin per barrel. The gross margin per barrel had decreased to $4.79 for the nine months ended September 30, 2012, compared to $7.49 for the twelve months ended December 31, 2011.
The gross margin from our fuels marketing operations decreased $34.7 million for the year ended December 31, 2012, compared to the year ended December 31, 2011, mainly due to rising costs, which outpaced rising sales prices, and hedge losses associated with fuel oil sales. In addition, the gross margin from bunker fuel sales decreased as a result of a decrease in the gross margin per barrel, despite an increase in volumes sold. We reduced the scope of our bunker fuel operations in 2012 by liquidating our inventory and exiting two markets where results had been weak, which contributed to the decrease in gross margin for bunker fuel sales. Furthermore, during the second quarter of 2012, crude oil prices fell sharply, causing a similar decline in prices for our fuel oil and bunker fuel. During this period of declining prices, we did not hedge our fuel oil and bunker fuel inventories, and the gross margin earned for sales of those products declined significantly.
Operating expenses decreased $8.8 million for the year ended December 31, 2012, compared to the year ended December 31, 2011, primarily due to the Asphalt Sale. Decreases in operating expenses for the Asphalt Operations were partially offset by increased fuel and vessel costs associated with bunker fuel sales and increased railcar costs associated with fuel oil sales. In addition, we incurred employee benefit costs in the fourth quarter of 2012 resulting from the Asphalt Sale.
Depreciation and amortization expense decreased $9.7 million for the year ended December 31, 2012, compared to the year ended December 31, 2011, as a result of reclassifying depreciable assets related to the Asphalt Operations to “Assets held for sale” on the consolidated balance sheet and discontinuing depreciation of these assets as of June 30, 2012.
The asset impairment loss of $266.4 million for year ended December 31, 2012 represents the write-down of the carrying value of our long-lived assets related to the Asphalt Operations, including fixed assets, goodwill, intangible assets and other long-term assets, in the second quarter of 2012.
Consolidation and Intersegment Eliminations
Revenue, cost of product sales and operating expense eliminations primarily relate to storage and transportation fees charged to the fuels marketing segment by the pipeline and storage segments.

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