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NS-2011.12.31-10K
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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
[ X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2011
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.)
 
 
 
2330 North Loop 1604 West
 
78248
San Antonio, Texas
 
(Zip Code)
(Address of principal executive offices)
 
 
Registrant’s telephone number, including area code (210) 918-2000
Securities registered pursuant to Section 12(b) of the Act: Common units representing partnership interests listed on the New York Stock Exchange.
Securities registered pursuant to 12(g) of the Act: None.
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes [X] No [    ]
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.
Yes [    ] No [X]
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes [X] No [    ]
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes [X] No [ ]
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [ ]
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule12b-2 of the Exchange Act: 
Large accelerated filer
 
[X]
  
Accelerated filer [    ]
 
 
 
 
Non-accelerated filer
 
[    ]  (Do not check if a smaller reporting company)
  
Smaller reporting company
 
[    ]
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes [    ] No [X]
The aggregate market value of the common units held by non-affiliates was approximately $3,517 million based on the last sales price quoted as of June 30, 2011, the last business day of the registrant’s most recently completed second quarter.
The number of common units outstanding as of January 31, 2012 was 70,756,078.


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 37 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 2330 North Loop 1604 West, San Antonio, Texas 78248 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 petroleum refining and marketing. We divide our operations into the following three reportable business segments: storage, transportation, and asphalt and fuels marketing. As of December 31, 2011, our assets included:
66 terminal and storage facilities providing 84.6 million barrels of storage capacity;
5,480 miles of refined product pipelines with 21 associated terminals providing storage capacity of 4.5 million barrels and two tank farms providing storage capacity of 1.2 million barrels;
2,000 miles of anhydrous ammonia pipelines;
940 miles of crude oil pipelines with 1.9 million barrels of associated storage capacity;
two asphalt refineries with a combined throughput capacity of 104,000 barrels per day and two associated terminal facilities with a combined storage capacity of 5.0 million barrels; and
a fuels refinery with a throughput capacity of 14,500 barrels per day and 0.4 million barrels of aggregate 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 asphalt and other 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;
complementary operations such as our fuels marketing operations, which provide us the opportunity to optimize the use and profitability of our assets; and
growth and improvement of our asphalt operations to benefit from anticipated decreases in overall asphalt supply and higher asphalt margins.
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)

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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 “Financial Reports 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., 2330 North Loop 1604 West, San Antonio, Texas 78248.

RECENT DEVELOPMENTS

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

On April 19, 2011, we purchased certain refining and storage assets, inventory and other working capital items from AGE Refining, Inc. for $62.0 million, including the assumption of certain environmental liabilities. The assets consist of a 14,500 barrel per day refinery in San Antonio, Texas and 0.4 million barrels of aggregate storage capacity.

On February 9, 2011, we acquired 75% of the outstanding capital of a Turkish company, which owns two terminals in Mersin,
Turkey, with an aggregate 1.3 million barrels of storage capacity, for approximately $57.0 million. Both terminals are connected via pipelines to an offshore platform located approximately three miles off the Mediterranean Sea coast.

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).


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The following chart depicts our organizational structure at December 31, 2011.



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SEGMENTS
Our three reportable business segments are storage, transportation, and asphalt and fuels marketing. Detailed financial information about our segments is included in Note 23 in the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data.”
The following map depicts our operations at December 31, 2011.


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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 and storage tanks used to store and deliver crude oil. As of December 31, 2011, we owned and operated:
54 terminal and storage facilities in the United States, with total storage capacity of 53.4 million barrels;
A terminal on the island of St. Eustatius with tank capacity of 13.0 million barrels and a transshipment facility;
A terminal located in Point Tupper with tank capacity of 7.4 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 5.6 million barrels;
Two terminals in Mersin, Turkey with total storage capacity of 1.3 million barrels; and
A terminal located in Nuevo Laredo, Mexico.
Description of Largest Terminal Facilities
St. Eustatius. We own and operate a 13.0 million barrel petroleum storage and terminalling facility located on the island of St. Eustatius in the Caribbean (formerly the Netherlands Antilles), 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 has a total storage capacity of 8.2 million barrels. Additionally, the facility has a rail-loading facility and three docks with barge and ship access. The facility is located on almost 900 acres of land, some of which is undeveloped.
Point Tupper. We own and operate a 7.4 million barrel terminalling and storage facility located at Point Tupper on the Strait of Canso, near Port Hawkesbury, Nova Scotia, which is located approximately 700 miles from New York City and 850 miles from Philadelphia. 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, spill 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 currently stores petroleum products consisting primarily of fuel oils and asphalt. The terminal has a dock with a 36-foot draft for tankers and four berths for barges. It also has truck-loading facilities, product-blending capabilities and is connected to a pipeline that supplies residual fuel oil to two power generating stations.

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 4.0 million barrels and can receive and deliver products via ship, barge and pipeline. The terminal includes two docks and leases a third with draft limits of 36, 26 and 20 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, 2011:
 
Facility
Tank
Capacity
 
Primary Products Handled
 
(Barrels)
 
 
U.S. Terminals and Storage Facilities:
 
 
 
Mobile, AL (Blakely Island)
1,100,000

 
Crude oil and feedstocks
Mobile, AL (Chickasaw North)
294,000

 
Crude oil and feedstocks
Mobile, AL (Chickasaw South)
286,000

 
Crude oil and feedstocks
Montgomery, AL
162,000

 
Petroleum products
Moundville, AL
310,000

 
Petroleum products
Los Angeles, CA
606,000

 
Petroleum products
Benicia, CA (refinery tankage)
3,815,000

 
Crude oil and feedstocks
Pittsburg, CA
361,000

 
Asphalt
Selby, CA
2,829,000

 
Petroleum products, ethanol
Stockton, CA
676,000

 
Petroleum products, ethanol, fertilizer
Colorado Springs, CO
320,000

 
Petroleum products, ethanol
Denver, CO
100,000

 
Petroleum products, ethanol
Jacksonville, FL
2,505,000

 
Petroleum products, asphalt
Bremen, GA
178,000

 
Petroleum products
Macon, GA (a)
307,000

 
Petroleum products
Savannah, GA
857,000

 
Petroleum products, chemicals
Blue Island, IL
719,000

 
Petroleum products, ethanol
Indianapolis, IN
366,000

 
Petroleum products
St. James, LA
8,196,000

 
Crude oil and feedstocks
Andrews AFB, MD (a)
72,000

 
Petroleum products
Baltimore, MD
809,000

 
Chemicals, asphalt, petroleum products
Piney Point, MD
5,404,000

 
Petroleum products, asphalt
Wilmington, NC
304,000

 
Asphalt
Linden, NJ
353,000

 
Petroleum products
Linden, NJ (b)
3,957,000

 
Petroleum products
Paulsboro, NJ
69,000

 
Petroleum products
Alamogordo, NM (a)
120,000

 
Petroleum products
Albuquerque, NM
245,000

 
Petroleum products, ethanol
Rosario, NM
160,000

 
Asphalt
Catoosa, OK
340,000

 
Asphalt
Portland, OR
1,203,000

 
Petroleum products, ethanol
Abernathy, TX
155,000

 
Petroleum products
Amarillo, TX
260,000

 
Petroleum products
Corpus Christi, TX
327,000

 
Petroleum products
Corpus Christi, TX (North Beach)
1,600,000

 
Crude oil and feedstocks
Corpus Christi, TX (refinery tankage)
4,023,000

 
Crude oil and feedstocks
Edinburg, TX
267,000

 
Petroleum products
El Paso, TX (c)
343,000

 
Petroleum products, ethanol
Harlingen, TX
281,000

 
Petroleum products
Houston, TX (Hobby Airport)
106,000

 
Petroleum products
Houston, TX
90,000

 
Asphalt

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Facility
Tank
Capacity
 
Primary Products Handled
 
(Barrels)
 
 
Laredo, TX
215,000

 
Petroleum products
Placedo, TX
97,000

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

 
Petroleum products
San Antonio (south), TX
215,000

 
Petroleum products
Southlake, TX
575,000

 
Petroleum products, ethanol
Texas City, TX
125,000

 
Petroleum products
Texas City, TX
2,775,000

 
Chemicals, petroleum products
Texas City, TX (refinery tankage)
3,087,000

 
Crude oil and feedstocks
Dumfries, VA
544,000

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

 
Petroleum products
Tacoma, WA
359,000

 
Petroleum products, ethanol
Vancouver, WA
328,000

 
Chemicals
Vancouver, WA
408,000

 
Petroleum products
Total U.S.
53,394,000

 
 
 
 
 
 
Foreign Terminals and Storage Facilities:
 
 
 
St. Eustatius, the Netherlands
12,986,000

 
Petroleum products, crude oil and feedstocks
Amsterdam, the Netherlands
3,848,000

 
Petroleum products
Point Tupper, Canada
7,354,000

 
Petroleum products, crude oil and feedstocks
Grays, England
1,956,000

 
Petroleum products
Eastham, England
2,156,000

 
Chemicals, petroleum products
Runcorn, England
145,000

 
Molten sulfur
Grangemouth, Scotland
555,000

 
Petroleum products, chemicals
Glasgow, Scotland
360,000

 
Petroleum products
Belfast, Northern Ireland
440,000

 
Petroleum products
Mersin, Turkey (d)
740,000

 
Petroleum products
Mersin, Turkey (d)
606,000

 
Petroleum products
Nuevo Laredo, Mexico
34,000

 
Petroleum products
Total Foreign
31,180,000

 
 
 
 
 
 
Total Terminals and Storage Facilities
84,574,000

 
 
 
(a)
Terminal facility also includes pipelines to U.S. government military base locations.
(b)
We own 50% of this terminal through a joint venture.
(c)
We own a 66.67% undivided interest in the El Paso refined product terminal. The tankage capacity and number of tanks represent the proportionate share of capacity attributable to our ownership interest.
(d)
We own 75% of the outstanding capital of a Turkish company, which owns two terminals in Mersin, Turkey.
Storage Operations
Revenues for the storage segment include fees for tank storage agreements, in which 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, in which 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, spill response services and other ship services.

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Demand for Refined Petroleum Products
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.
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 20% of the total revenues of the segment for the year ended December 31, 2011. 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.
The main competition at our St. Eustatius and Point Tupper locations for crude oil handling and storage is from “lightering,” which involves transferring liquid cargo from larger vessels to smaller vessels, usually while at sea. The price differential between lightering and terminalling is primarily driven by the charter rates for vessels of various sizes. Lightering generally takes significantly longer than discharging at a terminal. Depending on charter rates, the longer charter period associated with lightering is generally offset by various costs associated with terminalling, including storage costs, dock charges and spill response fees. However, terminalling is generally safer and reduces the risk of environmental damage associated with lightering, provides more flexibility in the scheduling of deliveries and allows our customers to deliver their products to multiple locations. Lightering in U.S. territorial waters creates a risk of liability for owners and shippers of oil under the U.S. Oil Pollution Act of 1990 and other state and federal legislation. In Canada, similar liability exists under the Canadian Shipping Act. Terminalling also provides customers with the ability to access value-added terminal services.
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.


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TRANSPORTATION
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 5,480 miles. Our crude oil pipelines in Texas, Oklahoma, Kansas, Colorado and Illinois cover 940 miles. Our anhydrous ammonia pipeline in Louisiana, Arkansas, Missouri, Illinois, Indiana, Iowa and Nebraska covers 2,000 miles. As of December 31, 2011, we owned and operated:
refined product pipelines with an aggregate length of 3,130 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 940 miles and crude oil storage facilities providing 1.9 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 throughput basis for transporting refined products, crude oil, feedstocks and anhydrous ammonia.
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. These pipelines deliver refined products to key markets in Texas, New Mexico and Colorado. The Central West System transported approximately 104.8 million barrels for the year ended December 31, 2011.


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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
%
 
12,000

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
%
 
19,000

Three Rivers to San Antonio, TX
 
Three Rivers
 
81

 
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
 
103

 
100
%
 
27,500

Three Rivers to Pettus, TX (b)
 
Three Rivers
 
30

 
100
%
 
N/A

El Paso, TX to Kinder Morgan
 
McKee
 
12

 
67
%
 
65,500

Corpus Christi to Pasadena, TX
 
Corpus Christi
 
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 (c)
 
N/A
 
289

 
50
%
 
N/A

Total
 
 
 
3,130

 
 
 
584,000

 
(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)
The refined product pipeline from Three Rivers to Pettus, Texas is temporarily idled. The Pettus to Corpus Christi, Texas segment of this refined product pipeline was reactivated as a crude oil pipeline in the second quarter of 2011.
(c)
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 1.2 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 51.9 million barrels for the year ended December 31, 2011.
North Pipeline. The North Pipeline originates at Tesoro’s Mandan, North Dakota refinery and runs from west to east approximately 440 miles from its origin to the Minneapolis, Minnesota area. For the year ended December 31, 2011, the North Pipeline transported approximately 15.3 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 of our refined product terminals connected to the East or North Pipelines:
 
Location of Terminals
Tank Capacity
 
Related Pipeline
System
 
(Barrels)
 
 
Iowa:
 
 
 
LeMars
103,000

 
East
Milford
172,000

 
East
Rock Rapids
223,000

 
East
Kansas:
 
 
 
Concordia
79,000

 
East
Hutchinson
114,000

 
East
Salina
90,000

 
East
Minnesota:
 
 
 
Moorhead
451,000

 
North
Sauk Centre
116,000

 
North
Roseville
479,000

 
North
Nebraska:
 
 
 
Columbus
171,000

 
East
Geneva
674,000

 
East
Norfolk
182,000

 
East
North Platte
247,000

 
East
Osceola
79,000

 
East
North Dakota:
 
 
 
Jamestown (North)
139,000

 
North
Jamestown (East)
176,000

 
East
South Dakota:
 
 
 
Aberdeen
181,000

 
East
Mitchell
63,000

 
East
Sioux Falls
381,000

 
East
Wolsey
148,000

 
East
Yankton
245,000

 
East
Total
4,513,000

 
 
Ammonia Pipeline. The 2,000 mile pipeline, including 57 miles that are temporarily idled, originates in the Louisiana delta area, where it has access to three marine terminals and three anhydrous ammonia plants on the Mississippi River. It 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. The Ammonia Pipeline transported approximately 1.5 million tons (or approximately 13.8 million barrels) for the year ended December 31, 2011.
Crude Oil Pipelines. Our crude oil pipelines primarily transport crude oil and other feedstocks from various points in Texas, Oklahoma, Kansas and Colorado to Valero Energy’s McKee, Three Rivers and Ardmore refineries. We can use our crude oil storage facilities in Texas, Oklahoma and Colorado, located along the crude oil pipelines, to store and batch crude oil prior to shipment in the crude oil pipelines. Our crude oil pipelines also transport crude oil and other feedstocks to the ConocoPhillips Wood River refinery in Illinois. The crude oil pipelines transported approximately 111.6 million barrels for the year ended December 31, 2011.

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The following table sets forth information about each of our crude oil pipelines:
 
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

Corpus Christi, TX to Three Rivers
Three Rivers
70

 
100
%
 
120,000

Ringgold, TX to Wasson, OK
Ardmore
44

 
100
%
 
90,000

Wasson, OK to Ardmore (8”-10”) (b)
Ardmore
24

 
100
%
 
90,000

Wasson, OK to Ardmore (8”)
Ardmore
15

 
100
%
 
40,000

Patoka, IL to Wood River
Wood River
57

 
24
%
 
60,500

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

 
100
%
 
38,000

Pettus to Corpus Christi, TX
N/A
60

 
100
%
 
30,000

Other (c)
N/A
214

 
 
 
N/A

Total
 
940

 
 
 
700,000


(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)
The Wasson, Oklahoma to Ardmore (8”- 10”) pipelines referred to above originate at Wasson as two pipelines but merge into one pipeline prior to reaching Ardmore.
(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:
 
Location
Refinery
Capacity
 
 
(Barrels)
Dixon, TX
McKee
240,000

Ringgold, TX
Ardmore
600,000

Wichita Falls, TX
McKee
660,000

Wasson, OK
Ardmore
225,000

Clawson, TX
McKee
65,000

Other (a)
McKee
67,000

Total
 
1,857,000


(a)
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.
Other Pipelines. We also own three single-use pipelines, located near Umatilla, Oregon, Rawlins, Wyoming and Pasco, Washington, each of which supplies diesel fuel to a railroad fueling facility.
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 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.


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Shippers on our crude oil pipelines deliver crude oil to the pipelines for transport to refineries that connect to the pipelines. The costs associated with the crude oil storage facilities located along the crude oil pipelines are considered in establishing the tariffs charged for transporting crude oil from the crude oil storage facilities to the refineries.
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
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. The pipelines in the Central West System and our crude oil pipelines are connected to refineries owned by Valero Energy, and certain pipelines are subject to long-term throughput agreements with Valero Energy. Valero Energy refineries connected directly to our pipelines obtain crude oil from a variety of foreign and domestic sources. If operations at one of these refineries were discontinued or significantly reduced, it could have a material adverse effect on our operations, although we would endeavor to minimize the impact by seeking alternative customers for those pipelines.
The North Pipeline is heavily dependent on Tesoro’s Mandan, North Dakota refinery, which primarily runs North Dakota crude oil (although it has the ability to process other crude oils). If operations at the Tesoro refinery were interrupted, it could have a material effect on our operations. 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

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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 and ConocoPhillips Company, respectively. The NCRA and Frontier Oil Corporation 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 production 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 transportation segment was Valero Energy, which accounted for approximately 45% of the total segment revenues for the year ended December 31, 2011. In addition to Valero Energy, we had a total of approximately 65 shippers for the year ended December 31, 2011, including integrated oil companies, refining companies, farm cooperatives, railroads and others. No other customer accounted for greater than 10% of the total revenues of transportation segment for the year ended December 31, 2011.
Competition and Business Considerations
Because pipelines are generally the lowest-cost method for intermediate and long-haul movement of 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. We believe high capital costs, tariff regulation, environmental considerations and problems in acquiring rights-of-way make it unlikely that other competing pipeline systems comparable in size and scope to our pipelines will be built in the near future, as long as our pipelines have available capacity to satisfy demand and our tariffs remain at economically reasonable levels.
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 our crude oil pipelines are physically integrated with and principally serve refineries owned by Valero Energy. As the pipelines are physically integrated with Valero Energy’s refineries, we believe that we will not face significant competition for transportation services provided to the Valero Energy refineries we serve.
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.

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Competitors of the Ammonia Pipeline include another 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.
ASPHALT AND FUELS MARKETING
Our asphalt and fuels marketing segment includes our asphalt operations, our fuels marketing operations and our San Antonio refinery. Our asphalt operations include two asphalt refineries at which we refine crude oil to produce asphalt and certain other refined products. Within our fuels marketing operations, we purchase crude oil and refined petroleum products for resale. Additionally, this segment includes a fuels refinery in San Antonio, Texas, at which we refine crude oil to produce various refined petroleum products. The results of operations for the asphalt and 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 transportation segments.
Asphalt Operations
The following table lists information about our asphalt refineries and related terminals as of December 31, 2011. The tank capacity includes storage for asphalt, crude oil and other feedstocks.
 
Facility
Production
Capacity
 
Tank Capacity
 
(Barrels Per Day)
 
(Barrels)
Paulsboro, NJ
74,000

 
3,643,000

Savannah, GA
30,000

 
1,369,000

Total
104,000

 
5,012,000

Paulsboro Refinery. The Paulsboro refinery is located in Paulsboro, New Jersey on the Delaware River. Its location on the Delaware River allows for direct access to receipts and shipments. The refinery consists of two petroleum refining units, a liquid storage terminal for petroleum and chemical products, three marine docks, a polymer-modified asphalt production facility and a testing laboratory. The Paulsboro refinery supplies various asphalt grades and intermediate products by ship, barge, railcar and tanker trucks to a network of twelve asphalt terminals in the northeastern United States. These asphalt terminals, combined with asphalt storage at the refinery, provide us with an aggregate storage capacity of 4.0 million barrels that we own or lease from third parties.
Savannah Refinery. The Savannah refinery is located in Savannah, Georgia adjacent to the Savannah River and is the only asphalt producer on the United States southeastern seaboard. Its location on the Savannah River allows for direct access to receipts and shipments. The refinery includes two atmospheric towers, a tank farm, a marine dock, a polymer modified asphalt production facility, a testing laboratory and processing areas. The Savannah refinery supplies various asphalt grades by truck, rail and marine vessel to a network of nine asphalt terminals in the southeastern United States. These asphalt terminals, combined with asphalt storage at the refinery, provide us with an aggregate storage capacity of 1.9 million barrels that we own or lease from third parties.

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The following table lists the throughputs and yields for each refinery for the year ended December 31, 2011:
 
 
Volumes
Percentage
 
(barrels per day)
 
Paulsboro:
 
 
Crude oil throughput
35,844
 
Yields:
 
 
Asphalt
24,474
69%
Naphtha
915
2%
Marine diesel oil
5,982
17%
Light marine gas oil
200
1%
Vacuum gas oil
4,000
11%
Savannah:
 
 
Crude oil throughput
10,439
 
Yields:
 
 
Asphalt
7,779
75%
Naphtha
366
4%
Light marine gas oil
2,225
21%
Customers. We produce several grades of asphalt products for various applications. Those applications include hot mix paving, which is used in road construction, roofing shingles for housing construction, asphalt emulsions and asphalt cutbacks used for street maintenance, as well as polymer-modified asphalt, which is a premium asphalt cement used for roads with heavy traffic in harsh weather conditions. The majority of our asphalt customers are road and bridge construction companies who operate asphalt hot mix plants that combine rock aggregate with asphalt to make road pavements. Our customers serve the private commercial sector by building residential roads, parking lots, asphalt paths and courts as well as the public sector by building highways and transportation infrastructure for the various state Departments of Transportation.
Crude Supply. We obtain the majority of the crude oil processed in our asphalt refineries from Petróleos de Venezuela S. A. (PDVSA), the national oil company of Venezuela, under a long-term supply agreement. In 2011, we began purchasing crude oil from Statoil Brasil Oleo E Gas Limitada (Statoil) under a three-year agreement. Our cost of crude oil purchased under the supply agreements fluctuates based upon a market-based pricing formula using published market indices, subject to adjustments per the agreements. The refineries can process alternative asphaltic crudes and other feedstocks and we are currently working to diversify our crude supply options.
Competition and Business Considerations. The asphalt industry is highly fragmented and regional in nature. Our competitors range in size from major oil companies and independent refiners to small family-owned businesses. It is considered a niche business with few integrated, asphalt-focused refiners that have production, logistics and wholesale and marketing capabilities.

Fuels Marketing Operations
Our fuels marketing operations provide us the opportunity to generate additional gross margin while complementing the activities of our storage and transportation segments. These operations involve the purchase of crude oil, fuel oil, bunker fuel and other refined products for resale. We utilize transportation and storage assets, including our own terminals and pipelines. Rates charged by our storage segment and tariffs charged by our transportation segment to the asphalt and 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 futures contracts and swaps traded on the NYMEX for the purposes of hedging the price risk of our physical inventory.
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.
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.

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San Antonio Refinery
On April 19, 2011, we purchased a fuels refinery with a throughput capacity of 14,500 barrels per day located in San Antonio, Texas (the San Antonio Refinery) and 0.4 million barrels of aggregate storage capacity. The refinery includes a 14,500 barrel per day crude unit, a naphtha hydrotreater unit, a diesel hydrotreater unit and a reformate splitter unit. In addition, the refinery has a seven-bay truck loading rack and approximately 0.2 million barrels of storage capacity at the refinery, as well as 0.2 million barrels of crude oil storage capacity in Elmendorf, Texas. We mainly produce jet fuels, ultra-low sulfer diesel (ULSD), reformates, naphtha and vacuum gas oil.

The operations of San Antonio Refinery expose us to commodity price risk. In an attempt to mitigate the impact of commodity price fluctuations, we entered into over-the-counter swaps. Those swaps fix the purchase price of a portion of the crude oil supply and the sales price of a portion of certain products produced by the refinery.

The following table lists the throughputs and yields for the San Antonio Refinery for the year ended December 31, 2011:
 
Volumes
Percentage
 
(barrels per day)
 
 
 
 
Crude oil throughput
10,857
 
Yields:
 
 
Jet fuels
1,332
13%
ULSD
2,864
27%
Reformates
2,001
19%
Naphtha
1,361
13%
Vacuum gas oil
1,961
19%
Other
950
9%
Customers. The San Antonio refinery customers include major integrated refiners, trading companies and chemical companies. The majority of our sales occur at our truck rack at current market prices. We sell a portion of our jet fuel to the federal government under a supply agreement, with the balance sold to commercial and private jet operators.
Crude Oil Supply. We purchase various grades of crude oil from local suppliers operating in South Texas. Local production, including the developing Eagle Ford shale, provides us a reliable source of crude oil. We purchase crude oil from our suppliers under short-term and spot agreements, generally at current market prices. This local supply of crude oil enables us to take advantage of lower transportation costs.

Competition and Business Considerations. Although we are the only refinery in the San Antonio area, our competitors include large integrated oil companies and independent refiners, that have product terminals located in close proximity to our refinery.

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EMPLOYEES
Our operations are managed by NuStar GP, LLC. As of December 31, 2011, NuStar GP, LLC had 1,508 employees performing services for our United States operations. Certain of our wholly owned subsidiaries had 436 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 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 2011, our capital expenditures attributable to compliance with environmental regulations were $6.0 million, and are currently estimated to be approximately $17.7 million for 2012.
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 mandates could impact the demand for refined petroleum

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products. For example, Congress enacted the Energy Independence and Security Act of 2007 and the American Recovery and Reinvestment Act of 2009, which, among things, mandated annually increasing levels for the use of renewable fuels such as ethanol, commencing in 2008 and escalating for 15 years, as well as increasing energy efficiency goals, including higher fuel economy standards for motor vehicles, subsidized loans for renewable energy projects, and provided funding for energy efficiency and renewable energy programs. 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 regulations regulate emissions of air pollutants from various industrial 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 minimal quantities of 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. For example, the federal Pipeline Safety Act of 1968, the Pipeline Safety Improvement Act of 2002, the Pipeline Inspection, Protection, Enforcement, and Safety Act of 2006 and the Pipeline Safety, Regulatory Certainty and Job Creation Act of 2011 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 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 to our unitholders.
Any sustained decrease in demand for refined products in the markets served by our pipelines, terminals or refineries could result in a significant reduction in throughputs in our pipelines, storage in our terminals or sales of asphalt and other refined products, which would reduce our cash flow and our ability to make distributions 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;
a decrease in spending on construction projects, including road paving and maintenance;
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, including asphalt prices, which may reduce demand for refined products and drive demand for alternative products. Market prices for crude oil and refined products, including asphalt, 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, including asphalt;
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 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 and own 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;

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market-related increases in a project’s debt or equity financing costs; and/or
nonperformance by, or disputes with, vendors, suppliers, contractors or sub-contractors involved with a project.
Our forecasted operating results also are 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 supplies of crude oil and refined products and overall customer demand.
Our asphalt refineries are dependent upon a steady supply of crude oil from PDVSA, the national oil company of Venezuela, and decisions of the Organization of Petroleum Exporting Countries (OPEC) to decrease production of crude oil, as well as the Venezuelan economic and political environment, may disrupt our supply of crude oil.
We have an agreement with PDVSA, pursuant to which PDVSA agrees to sell and we agree to purchase an annual average of 75,000 barrels per day of crude oil. OPEC cuts, coupled with Venezuela’s recent political, economic and social turmoil could have a severe impact on PDVSA’s production or delivery of crude oil. In the event PDVSA reduces its production or delivery of Boscán or Bachaquero BCF-13, the crude oil for which our refineries are currently optimized, we will be forced to replace all or a portion of the crude oil we would normally have purchased under our PDVSA crude oil supply contract with purchases of crude oil on the spot market, potentially at a price less favorable than we would have obtained under the PDVSA crude oil supply contract. It is possible that processing a more significant proportion of alternate crudes could result in reduced refinery run rates, significantly reduced production and additional capital expenditures, which could be material. Accordingly, any major disruption of our supply of crude oil from Venezuela could result in substantially lower revenues and additional volatility in our earnings and cash flow.
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 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 refining operations result from the refining of crude oil into asphalt and other products and the sale of those products. 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. Future price volatility could have an adverse impact on our results of operations, cash flow and ability to make distributions to our unitholders.

Our financial results are affected by volatile asphalt, intermediate and refined product refining margins.
A large portion of our earnings from our refining operations are affected by the relationship, or margin, between asphalt, other intermediate and refined product prices and the prices for crude oil and other feedstocks. Our cost to acquire feedstocks and the price at which we can ultimately sell asphalt, other intermediate and refined products depend upon several factors beyond our control, including regional and global supply of and demand for crude oil, asphalt and other feedstocks and intermediate and refined products. These in turn depend on, among other things, the availability and quantity of imports, the production levels of domestic and foreign suppliers, levels of intermediate and refined product inventories, the United States relationships with foreign governments, political affairs and the extent of governmental regulation.
Additionally, crude oil prices and prices for the asphalt, intermediate and refined products produced by our refining operations may not fluctuate consistently. Typically, increases in the prices of asphalt and intermediate products lag behind increases in the price of crude oil. Furthermore, much of the asphalt produced by our asphalt operations is marketed to satisfy governmental contracts. The governmental agencies with which we or our customers contract may have budgetary or other constraints that limit their ability to absorb increases to asphalt prices. Our results of operations in our asphalt and fuels marketing segment will suffer if the market prices of asphalt and intermediate products do not increase as much, or as quickly, as the price of crude oil. Our increased exposure to unstable commodity prices will increase the volatility of our earnings.

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The operating results for our asphalt operations are seasonal and generally lower in the first and fourth quarters of the year.
The selling prices of asphalt products we produce are seasonal. Asphalt demand is generally lower in the first and fourth quarters of the year as compared to the second and third quarters, due to the seasonality of road construction. In addition, our natural gas costs can be higher during the winter months. Our operating results for the first and fourth calendar quarters will likely be lower than those for the second and third calendar quarters of each year as a result of this seasonality.
Competition in the asphalt industry is intense, and such competition in the markets in which we sell our asphalt products could adversely affect our earnings and ability to make distributions to our unitholders.
Our asphalt operations compete with other refiners and with regional and national asphalt marketing companies. Many of these competitors are larger, more diverse companies with greater resources, providing them advantages in obtaining crude oil and other blendstocks and in competing through bidding process for asphalt supply contracts.
Our marketing and trading 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.
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 gasoline, distillates, fuel oil and asphalt. 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.
In order to manage our exposure to commodity price fluctuations associated with our asphalt and fuels marketing segment, we may engage in crude oil and refined product hedges. While intended to reduce the effects of volatile crude oil and refined product prices, such 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:
production is substantially less than expected;
the counterparties to our futures contracts fail to perform under the contracts; or
there is a change in the expected differential between the underlying price in the hedging agreement and the actual prices received.
The accounting standards regarding hedge accounting are complex, and even when we engage in hedging transactions that are effective economically, these transactions may not be considered effective for accounting purposes. Accordingly, our financial statements will reflect increased volatility due to these hedges, even when there is no underlying economic impact at that point. In addition, it is not possible for us to engage in a hedging transaction that completely mitigates our exposure to commodity prices. Our financial statements may reflect a gain or loss arising from an exposure to commodity prices for which we are unable to enter into an effective hedge.
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 our interest rate and commodity derivatives could expose us to additional interest rate or commodity price risk. Weak economic conditions and widespread financial stress could reduce the liquidity of our customers, vendors or counterparties, making it more difficult for them to meet their obligations to us. Any substantial increase in the nonpayment and nonperformance by our customers, vendors or counterparties could have a material adverse effect on our results of operations, cash flows and ability to make distributions to unitholders.

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Our future financial and operating flexibility may be adversely affected by our significant leverage, our significant working capital needs, restrictions in our debt agreements and disruptions in the financial markets; 2007 Revolving Credit Agreement matures in December 2012.
As of December 31, 2011, our consolidated debt was $2.3 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. NuStar Logistics and NuPOP have senior unsecured ratings of Baa3 with Moody’s Investor Service and BBB minus with Standard & Poor’s and Fitch. Moody’s and Standard & Poor’s have assigned NuStar Logistics and NuPOP a stable outlook, while Fitch assigned a negative outlook in August 2011 due to its analysis of our leverage. Any future downgrade of the debt issued by these wholly owned subsidiaries could significantly increase our capital costs and adversely affect our ability to raise capital in the future. Additionally, any ratings downgrade on the debt issued by NuStar Logistics could result in an adjustment to the interest rates on the bonds issued by NuStar Logistics in April 2008, which would significantly increase our capital costs and adversely affect our ability to raise capital in the future.
We require significant amounts of working capital to make purchases of crude oil and maintain necessary seasonal inventories to support our refining operations. We believe that our current sources of capital are adequate to meet our working capital needs. However, if our working capital needs increase more than anticipated, we may be forced to seek additional sources of capital, which may not be available or available on commercially reasonable terms.
Our five-year revolving credit agreement (the 2007 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 2007 Revolving Credit Agreement) not to exceed 5.00-to-1.00. Failure to comply with any of the restrictive covenants in the 2007 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 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. 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 2007 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.
The 2007 Revolving Credit Agreement matures in December 2012. It is possible that our lenders may not agree to renew the 2007 Revolving Credit Agreement or may only agree to renew it at substantially less favorable terms. If the 2007 Revolving Credit Agreement is renewed on substantially less favorable terms, or if it is not renewed and we must enter into alternative financing arrangements, various limitations in these financing agreements may significantly affect our ability to conduct business as we have in the past.
Additionally, we may not be able to access the capital markets in the future at economically attractive terms, which may adversely affect our future financial and operating flexibility and our ability to pay cash distributions at current levels.
Increases in interest rates could adversely affect our business and the trading price of our units.
We have significant exposure to increases in interest rates. At December 31, 2011, we had approximately $2.3 billion of consolidated debt, of which $1.4 billion was at fixed interest rates and $0.9 billion was at variable interest rates after giving effect to interest rate swap agreements. 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.
Our specialty asphalt products and certain refined 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

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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 will 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 refine, 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.
Recent 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 United States Congress is actively considering 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, and other foreign laws prohibiting corrupt payments. Emerging markets are a significant focus of our international growth strategy. 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 an managing foreign operations may also adversely affect our operations or financial results. Although we hedge a portion of our international currency exposure, significant fluctuations in exchange rates between the U.S. dollar and foreign currencies may adversely affect our net revenues.


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Our operations are subject to federal, state and local laws and regulations 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. Refining, transporting and storing petroleum and other products, such as specialty liquids, 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 and our ability to meet our debt service requirements. Please read Item 3. “Legal Proceedings” and Note 13 of Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data.”
Some of our pipelines are interstate common carrier pipelines, 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 be in excess of a just and reasonable level when taking into consideration our pipeline system’s cost of service. In addition, shippers may challenge by complaint the lawfulness of tariff rates that have become final and effective. The FERC may also investigate such rates absent shipper complaint. If existing rates challenged by complaint are determined by the FERC to be in excess of a just and reasonable level when taking into consideration our pipeline system’s cost of service, a shipper may obtain reparations for damages sustained during the two years prior to the filing of 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 annually adjust our rates 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, 2012) 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 new methodologies could result in rates that generate lower revenues and cash flow and could adversely affect our ability to make distributions 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 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, 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

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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 ability to make distributions to our unitholders.
Power costs constitute a significant portion of our operating expenses. For the year ended December 31, 2011, our power costs equaled approximately $59.2 million, or 11% of our operating expenses for the year. In addition, $12.8 million of power costs were capitalized into inventory related to our asphalt refineries, which will be expensed into cost of product sales as the inventory is sold. We use mainly electric power at our pipeline pump stations, terminals and refineries, 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 to our unitholders.
Terrorist attacks and the threat of terrorist attacks have resulted in increased costs to our business. Continued hostilities in the Middle East or other sustained military campaigns may adversely impact our results of operations.
Increased security measures we have taken as a precaution against possible terrorist attacks have resulted in increased costs to our business. Uncertainty surrounding continued hostilities in the Middle East or other sustained military campaigns may affect our operations in unpredictable ways, including disruptions of crude oil supplies and markets for refined products, the possibility that infrastructure facilities could be direct targets of, or indirect casualties of, an act of terror and instability in the financial markets that could restrict our ability to raise capital.
Our cash distribution policy may limit our growth.
Consistent with the terms of our partnership agreement, we distribute our available cash to our unitholders each quarter. In determining the amount of cash available for distribution, our management sets aside cash reserves, which we use to fund our growth capital expenditures. Additionally, we have relied upon external financing sources, including commercial borrowings and other debt and equity issuances, to fund our acquisition capital expenditures. Accordingly, to the extent we do not have sufficient cash reserves or are unable to finance growth externally, our cash distribution policy will significantly impair our ability to grow. In addition, to the extent we issue additional units in connection with any acquisitions or growth capital expenditures, the payment of distributions on those additional units may increase the risk that we will be unable to maintain or increase our current per unit distribution level.

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, 2011, an aggregate 14.3% 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

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

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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 gain or loss equal to the difference between the amount realized and that unitholder’s tax basis in those units. Prior distributions to the unitholder in excess of the total net taxable income the unitholder was allocated for a unit, which decreased the tax basis in that unit, will, in effect, become taxable income to the unitholder if the unit is sold at a price greater than the tax basis in that unit, even if the price the unitholder receives is less than the original cost. A substantial portion of the amount realized, whether or not representing gain, may be ordinary income to the selling unitholder.
Tax-exempt entities and foreign persons face unique tax issues from owning units that may result in adverse tax consequences to them.
Investment in units by tax-exempt entities, such as individual retirement accounts (known as IRAs) and non-United States persons raises issues unique to them. For example, virtually all of our income allocated to organizations exempt from federal income tax, including individual retirement accounts and other retirement plans, will be unrelated business taxable income and will be taxable to them. Distributions to non-United States persons will be reduced by withholding taxes at the highest applicable effective tax rate, and non-United States persons will be required to file United States federal income tax returns and pay tax on their share of our taxable income.
We will treat each purchaser of our units as having the same tax benefits without regard to the units purchased. The IRS may challenge this treatment, which could adversely affect the value of our units.
Because we cannot match transferors and transferees of units, we will adopt depreciation and amortization positions that may not conform to all aspects of existing Treasury regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to unitholders. It also could affect the timing of these tax benefits or the amount of gain from any sale of units and could have a negative impact on the value of our units or result in audit adjustments to a unitholder’s tax returns.
Unitholders will likely be subject to state and local taxes and return filing requirements as a result of investing in our units.
In addition to federal income taxes, unitholders will likely be subject to other taxes, such as state and local income taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by various jurisdictions in which we do business or own property. Unitholders will likely be required to file state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions. Further, unitholders may be subject to penalties for failure to comply with those requirements. We may own property or conduct business in other states or foreign countries in the future. It is each unitholder’s responsibility to file all federal, state or local tax returns.

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


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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.


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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. 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.
GRACE ENERGY CORPORATION MATTER
In 1997, Grace Energy Corporation (Grace Energy) sued subsidiaries of Kaneb Pipeline Partners, L.P. (KPP) and Kaneb Services LLC (KSL and collectively with KPP and their respective subsidiaries, Kaneb) in Texas state court. We acquired Kaneb on July 1, 2005. The complaint sought recovery of the cost of remediation of fuel leaks in the 1970s from a pipeline that had once connected a former Grace Energy terminal with Otis Air Force Base in Massachusetts (Otis AFB). Grace Energy alleges the Otis AFB pipeline and related environmental liabilities had been transferred in 1978 to an entity that was part of Kaneb’s acquisition of Support Terminal Services, Inc. and its subsidiaries from Grace Energy in 1993. Kaneb contends that it did not acquire the Otis AFB pipeline and never assumed any responsibility for any associated environmental damage.
In 2000, the court entered final judgment that: (i) Grace Energy could not recover its own remediation costs of $3.5 million, (ii) Kaneb owned the Otis AFB pipeline and its related environmental liabilities and (iii) Grace Energy was awarded $1.8 million in attorney costs. Both Kaneb and Grace Energy appealed the final judgment of the trial court to the Texas Court of Appeals in Dallas. In 2001, Grace Energy filed a petition in bankruptcy, which created an automatic stay of actions against Grace Energy. In September 2008, Grace Energy filed its Joint Plan of Reorganization and Disclosure Statement.
The Otis AFB is a part of a Superfund Site pursuant to the Comprehensive Environmental Response Compensation and Liability Act (CERCLA). The site contains a number of groundwater contamination plumes, two of which are allegedly associated with the Otis AFB pipeline. Relying on the final judgment of the Texas state court assigning ownership of the Otis AFB pipeline to Kaneb, the United States Department of Justice (the DOJ) advised Kaneb in 2001 that it intends to seek reimbursement from Kaneb for the remediation costs associated with the two plumes. In November 2008, the DOJ forwarded information to us indicating that the past and estimated future remediation expenses associated with one plume are $71.9 million. The DOJ has indicated that they will not seek recovery of remediation costs for the second plume. The DOJ has not filed a lawsuit against us related to this matter, and we have not made any payments toward costs incurred by the DOJ. We have reached an agreement to settle the claims of the United States government with respect to the Otis AFB pipeline and to resolve the underlying dispute between Kaneb and Grace. Pursuant to the settlement, NuStar agreed to pay $11.7 million plus interest to the United States. Although the settlement requires approval of the United States Bankruptcy Court for the District of Delaware, as well as the United States District Court for the District of Massachusetts, we remain hopeful that the necessary approvals will be obtained and that the settlement will be finalized in the near term.
 
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 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 byphenyls, 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 65 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

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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. It is possible that if one or more of the matters described in Item 3. were decided against us, the effects could be material to our results of operations in the period in which we would be required to record or adjust the related liability and could also be material to our cash flows in the periods we would be required to pay such liability.

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 7, 2012, we had 702 holders of record of our common units. The high and low sales prices (composite transactions) by quarter for the years ended December 31, 2011 and 2010 were as follows:
 
Price Range of Common Unit
 
High
 
Low
Year 2011
 
 
 
4th Quarter
$
58.96

 
$
49.02

3rd Quarter
66.39

 
51.34

2nd Quarter
68.80

 
59.47

1st Quarter
70.87

 
64.26

Year 2010
 
 
 
4th Quarter
$
71.69

 
$
61.76

3rd Quarter
61.92

 
55.51

2nd Quarter
64.50

 
51.80

1st Quarter
60.79

 
51.49

The cash distributions applicable to each of the quarters in the years ended December 31, 2011 and 2010 were as follows:
 
 
 
 
 
 
 
Record Date
 
Payment Date
 
Amount
Per Unit
Year 2011
 
 
 
 
 
4th Quarter
February 7, 2012
 
February 10, 2012
 
$
1.095

3rd Quarter
November 8, 2011
 
November 14, 2011
 
1.095

2nd Quarter
August 9, 2011
 
August 12, 2011
 
1.095

1st Quarter
May 9, 2011
 
May 13, 2011
 
1.075

Year 2010
 
 
 
 
 
4th Quarter
February 8, 2011
 
February 14, 2011
 
$
1.075

3rd Quarter
November 1, 2010
 
November 5, 2010
 
1.075

2nd Quarter
August 6, 2010
 
August 13, 2010
 
1.065

1st Quarter
May 7, 2010
 
May 14, 2010
 
1.065

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, 2011 and 2010 totaled $36.3 million and $33.3 million, respectively. The general partner’s share of our distributions for the years ended December 31, 2011 and 2010 was 13.0% and 12.7%, respectively, 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.
 
Year Ended December 31,
 
2011
 
2010
 
2009
 
2008 (a)
 
2007
 
(Thousands of Dollars, Except Per Unit Data)
Statement of Income Data:
 
 
 
 
 
 
 
 
 
Revenues
$
6,575,255

 
$
4,403,061

 
$
3,855,871

 
$
4,828,770

 
$
1,475,014

Operating income
313,994

 
302,557

 
273,316

 
310,073

 
192,599

Income from continuing operations
221,601

 
238,970

 
224,875

 
254,018

 
150,298

Income from continuing operations per unit
applicable to limited partners (b)
2.78

 
3.19

 
3.47

 
4.22

 
2.73

Cash distributions per unit applicable to
limited partners
4.360

 
4.280

 
4.245

 
4.085

 
3.835

 
 
 
 
 
 
 
 
 
 
 
December 31,
 
2011
 
2010
 
2009
 
2008 (a)
 
2007
 
(Thousands of Dollars)
Balance Sheet Data:
 
 
 
 
 
 
 
 
 
Property, plant and equipment, net
$
3,430,468

 
$
3,187,457

 
$
3,028,196

 
$
2,941,824

 
$
2,492,086

Total assets
5,881,190

 
5,386,393

 
4,774,673

 
4,459,597

 
3,783,087

Long-term debt (less current portion)
1,928,071

 
2,136,248

 
1,828,993

 
1,872,015

 
1,445,626

Total partners’ equity
2,864,335

 
2,702,700

 
2,484,968

 
2,206,997

 
1,994,832


(a)
The significant increase in revenues, operating income, income from continuing operations and balance sheet data are primarily due to the acquisition of our asphalt operations in March 2008.
(b)
In 2008, the Financial Accounting Standards Board provided additional guidance regarding the application of the two-class method to calculate earnings per unit for master limited partnerships, which was effective January 1, 2009. As a result, income from continuing operations per unit applicable to limited partners for the year ended December 31, 2007 changed from $2.74 previously reported.


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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 petroleum refining and marketing. 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 16.3% total interest in us as of December 31, 2011. 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
Acquisitions
On April 19, 2011, we purchased certain refining and storage assets, inventory and other working capital items from AGE
Refining, Inc. for $62.0 million, including the assumption of certain environmental liabilities. The assets consist of a 14,500
barrel per day refinery in San Antonio, Texas and 0.4 million barrels of aggregate storage capacity (the San Antonio Refinery Acquisition). The consolidated statements of income include the results of operations for the San Antonio Refinery Acquisition commencing on April 19, 2011 in the asphalt and fuels marketing segment.

On February 9, 2011, we acquired 75% of the outstanding capital of a Turkish company, which owns two terminals in Mersin, Turkey, with an aggregate 1.3 million barrels of storage capacity, for approximately $57.0 million (the Turkey Acquisition). Both terminals are connected via pipelines to an offshore platform located in the Mediterranean Sea approximately three miles off the coast. The consolidated statements of income include the results of operations for the Turkey Acquisition commencing on February 9, 2011 in the storage segment.

On May 21, 2010, we acquired the capital stock of Asphalt Holdings, Inc. for $53.3 million, including liabilities assumed (the Asphalt Holdings Acquisition). The Asphalt Holdings Acquisition includes three storage terminals with an aggregate storage capacity of approximately 1.8 million barrels located in Alabama along the Mobile River. The consolidated statements of income include the results of operations for the Asphalt Holdings Acquisition commencing on May 21, 2010 in the storage segment.

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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, transportation, and asphalt 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 and Turkey providing approximately 84.6 million barrels of storage capacity.
Transportation. We own common carrier refined product pipelines covering approximately 5,480 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 940 miles of crude oil pipelines.
Asphalt and Fuels Marketing. Our asphalt and fuels marketing segment includes our asphalt operations, our fuels marketing operations and our San Antonio refinery. Our asphalt operations include two asphalt refineries with a combined throughput capacity of 104,000 barrels per day at which we refine crude oil to produce asphalt and certain other refined products. Within our fuels marketing operations, we purchase crude oil and refined petroleum products for resale. Additionally, this segment includes a fuels refinery in San Antonio, Texas, with a throughput capacity of 14,500 barrels per day at which we refine crude oil to produce various refined petroleum products. The results of operations for the asphalt and 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 transportation 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 United States 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.
During the second quarter of 2011, we entered into commodity swap contracts associated with the San Antonio Refinery. These contracts fix the purchase price of crude oil and sales prices of refined products for a portion of the expected production of the San Antonio Refinery, thereby attempting to mitigate the volatility of future cash flows associated with hedged volumes. These contracts qualified, and we designated them, as cash flow hedges.
In addition, we value our inventory at the lower of cost or market. If changes in commodity prices result in market prices below the cost of our inventory, we may be required to reduce the value of our inventory to market.
Demand for certain products that we market fluctuates seasonally. For example, demand for gasoline and asphalt typically increases in the summer months compared to the winter months, whereas demand for heating oil is higher in the winter months than the summer months. Prices for these commodities generally are highest during those times of higher demand. We also purchase inventory at lower prices with the intention of storing that inventory until it can be sold at higher prices, which causes the working capital necessary for the asphalt and fuels marketing segment to fluctuate. Increases in the level of working capital, as well as the seasonal fluctuations, may require us to borrow additional amounts or utilize other sources of liquidity.

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, particularly asphalt;
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 asphalt and fuels marketing segment; and
other factors, such as refinery utilization rates and maintenance turnaround schedules, that impact our refineries as well as the operations of refineries served by our storage and transportation assets.


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RESULTS OF OPERATIONS
Year Ended December 31, 2011 Compared to Year Ended December 31, 2010
Financial Highlights
(Thousands of Dollars, Except Unit and Per Unit Data)
 
 
Year Ended December 31,
 
 
 
2011
 
2010
 
Change
Statement of Income Data:
 
 
 
Revenues:
 
 
 
 
 
Service revenues
$
825,938

 
$
791,314

 
$
34,624

Product sales
5,749,317

 
3,611,747

 
2,137,570

Total revenues
6,575,255

 
4,403,061

 
2,172,194

 
 
 
 
 
 
Costs and expenses:
 
 
 
 
 
Cost of product sales
5,460,520

 
3,350,429

 
2,110,091

Operating expenses
529,002

 
486,032

 
42,970

General and administrative expenses
103,453

 
110,241

 
(6,788
)
Depreciation and amortization expense
168,286

 
153,802

 
14,484

Total costs and expenses
6,261,261

 
4,100,504

 
2,160,757

 
 
 
 
 
 
Operating income
313,994

 
302,557

 
11,437

Equity in earnings of joint venture
11,458

 
10,500

 
958

Interest expense, net
(83,681
)
 
(78,280
)
 
(5,401
)
Other (expense) income, net
(3,291
)
 
15,934

 
(19,225
)
Income before income tax expense
238,480

 
250,711

 
(12,231
)
Income tax expense
16,879

 
11,741

 
5,138

Net income
$
221,601

 
$
238,970

 
$
(17,369
)
Net income per unit applicable to limited partners
$
2.78

 
$
3.19

 
$
(0.41
)
Weighted-average limited partner units outstanding
65,018,301

 
62,946,987

 
2,071,314

Annual Highlights
Segment operating income increased $5.5 million for the year ended December 31, 2011, compared to the year ended December 31, 2010, due to increased operating income from the storage segment, partially offset by decreased operating income from the transportation and asphalt and fuels marketing segments. Consolidated operating income benefited from the increased segment operating income and lower general and administrative expenses. However, net income decreased $17.4 million for the year ended December 31, 2011, compared to the year ended December 31, 2010, primarily due to a decrease in other income.

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Segment Operating Highlights
(Thousands of Dollars, Except Barrel/Day Information)
 
 
Year Ended December 31,
 
 
 
2011
 
2010
 
Change
Storage:
 
 
 
 
 
Throughput (barrels/day)
693,269

 
669,435

 
23,834

Throughput revenues
$
80,246

 
$
75,605

 
$
4,641

Storage lease revenues
486,525

 
444,233

 
42,292

Total revenues
566,771

 
519,838

 
46,933

Operating expenses
285,639

 
263,820

 
21,819

Depreciation and amortization expense
87,737

 
77,071

 
10,666

Segment operating income
$
193,395

 
$
178,947

 
$
14,448

 
 
 
 
 
 
Transportation:
 
 
 
 
 
Refined products pipelines throughput (barrels/day)
514,261

 
529,946

 
(15,685
)
Crude oil pipelines throughput (barrels/day)
305,890

 
371,726

 
(65,836
)
Total throughput (barrels/day)
820,151

 
901,672

 
(81,521
)
Throughput revenues
$
311,514

 
$
316,072

 
$
(4,558
)
Operating expenses
114,726

 
116,884

 
(2,158
)
Depreciation and amortization expense
51,175

 
50,617

 
558

Segment operating income
$
145,613

 
$
148,571

 
$
(2,958
)
 
 
 
 
 
 
Asphalt and Fuels Marketing:
 
 
 
 
 
Product sales
$
5,759,099

 
$
3,615,890

 
$
2,143,209

Cost of product sales
5,490,384

 
3,371,854

 
2,118,530

Gross margin
268,715

 
244,036

 
24,679

Operating expenses
160,850

 
132,918

 
27,932

Depreciation and amortization expense
22,636

 
20,257

 
2,379

Segment operating income
$
85,229

 
$
90,861

 
$
(5,632
)
 
 
 
 
 
 
Consolidation and Intersegment Eliminations:
 
 
 
 
 
Revenues
$
(62,129
)
 
$
(48,739
)
 
$
(13,390
)
Cost of product sales
(29,864
)
 
(21,425
)
 
(8,439
)
Operating expenses
(32,213
)
 
(27,590
)
 
(4,623
)
Total
$
(52
)
 
$
276

 
$
(328
)
 
 
 
 
 
 
Consolidated Information:
 
 
 
 
 
Revenues
$
6,575,255

 
$
4,403,061

 
$
2,172,194

Cost of product sales
5,460,520

 
3,350,429

 
2,110,091

Operating expenses
529,002

 
486,032

 
42,970

Depreciation and amortization expense
161,548

 
147,945

 
13,603

Segment operating income
424,185

 
418,655

 
5,530

General and administrative expenses
103,453

 
110,241

 
(6,788
)
Other depreciation and amortization expense
6,738

 
5,857

 
881

Consolidated operating income
$
313,994

 
$
302,557

 
$
11,437



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Table of Contents

Storage
Storage revenues increased $46.9 million for the year ended December 31, 2011, compared to the year ended December 31, 2010, primarily due to:
an increase of $18.8 million from completed tank expansion projects at our St. Eustatius and St. James terminals;
an increase of $8.7 million at our St. Eustatius facility mainly due to increased throughput and related handling fees, as well as new customer contracts, rate escalations and increased reimbursable revenues;
an increase of $7.0 million across various domestic terminals due to rate escalations, new customer contracts, and increased reimbursable revenues;
an increase of $6.4 million related to the Turkey Acquisition and the Asphalt Holdings Acquisition; and
an increase of $5.1 million at our UK and Amsterdam terminals, primarily due to the effect of foreign exchange rates and new customer contracts.
Operating expenses increased $21.8 million for the year ended December 31, 2011, compared to the year ended December 31, 2010, primarily due to increased expenses at our St. Eustatius and UK terminals resulting from the increased activity discussed above, cancelled capital projects, the Turkey Acquisition and the Asphalt Holdings Acquisition.
Depreciation and amortization expense increased $10.7 million for the year ended December 31, 2011, compared to the year ended December 31, 2010, primarily due to the completion of various terminal upgrade and expansion projects, the Turkey Acquisition and the Asphalt Holdings Acquisition.
Transportation
Revenues decreased $4.6 million and throughputs decreased 81,521 barrels per day for the year ended December 31, 2011, compared to the year ended December 31, 2010, primarily due to:
a decrease in revenues of $8.5 million and a decrease in throughputs of 32,395 barrels per day on our crude oil and refined product pipelines serving the Three Rivers refinery mainly due to a turnaround in 2011 and the customer receiving crude oil from alternate sources, thus reducing the volume transported on our crude oil pipeline;
a decrease in revenues of $6.2 million and a decrease of 48,564 barrels per day on our pipelines serving the Ardmore refinery, mainly due to a turnaround in March and April 2011, followed by operational issues and a shift in supply volumes; and
a decrease in revenues of $5.3 million and a decrease in throughputs of 18,453 barrels per day on the Houston pipeline mainly due to market conditions that favored exporting instead of shipping on our pipeline.
These decreases in revenues were partially offset by:
an increase in revenues of $7.0 million and an increase in throughputs of 14,891 barrels per day on pipelines serving the McKee refinery mainly due to increased crude run rates in 2011 resulting from more favorable economic conditions compared to 2010, as well as operational issues and turnaround activity at the refinery in 2010;
an increase in revenues of $4.6 million and an increase in throughputs of 8,123 barrels per day on two reactivated pipelines in South Texas due to increased activity in the Eagle Ford shale formation area; and
an increase in revenues of $4.5 million and an increase in throughputs of 4,349 barrels per day on the North Pipeline mainly due to turnaround activity during the second quarter of 2010 at the refinery served by the pipeline.
Asphalt and Fuels Marketing
Sales and cost of product sales increased $2,143.2 million and $2,118.5 million, respectively, resulting in an increase in total gross margin of $24.7 million for the year ended December 31, 2011, compared to the year ended December 31, 2010. The increase in total gross margin was primarily due to an increase of $35.0 million in the gross margin from our fuels marketing operations resulting from increased volumes and higher sales prices in 2011 for our crude trading, fuel oil trading and bunker fuel sales.

The San Antonio refinery contributed $18.6 million to the increase in gross margin, which included $16.4 million in hedge gains. During the fourth quarter of 2011, we decided to adjust the refinery's operations, which caused a shift in the future production yields of the San Antonio refinery. This change caused certain forecasted sales of gasoline products to be replaced with distillate sales; therefore, we concluded these forecasted gasoline sales were probable not to occur, and we discontinued cash flow hedging treatment for the related commodity contracts. We recorded gains of $16.4 million related to these contracts for the year ended December 31, 2011.

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These increases in gross margin were partially offset by a decrease of $28.9 million in the gross margin from our asphalt operations, mainly due to a decrease in sales volumes, as well as a lower gross margin per barrel. Volumes decreased in 2011 due to weak demand for asphalt in our market. Midwest refiners, which currently have access to lower cost crude oil, sold lower-priced asphalt in our market, which contributed to the decrease in volumes and gross margin per barrel. The gross margin per barrel for our asphalt operations decreased to $7.49 for the year ended December 31, 2011, compared to $7.73 for the year ended December 31, 2010.
Operating expenses increased $27.9 million for the year ended December 31, 2011, compared to the year ended December 31, 2010, primarily due to higher idle capacity costs at our asphalt refineries, increased rental expenses resulting mainly from additional tank rentals and the San Antonio Refinery Acquisition.
Depreciation and amortization expense increased $2.4 million for the year ended December 31, 2011, compared to the year ended December 31, 2010, primarily due the San Antonio Refinery Acquisition and amortization of deferred costs related to completed turnarounds at our asphalt refineries.
Consolidation and Intersegment Eliminations
Revenue, cost of product sales and operating expense eliminations primarily relate to storage and transportation fees charged to the asphalt and fuels marketing segment by the transportation and storage segments. The increases in consolidation and intersegment eliminations for the year ended December 31, 2011, compared to the year ended December 31, 2010, were mainly due to higher additional tank rentals by the asphalt and fuels marketing segment from the storage segment.
General
General and administrative expenses decreased $6.8 million for the year ended December 31, 2011, compared to the year ended December 31, 2010, primarily due to lower compensation expense associated with our long-term incentive plans, which fluctuates with our unit price.
Interest expense, net increased $5.4 million for the year ended December 31, 2011, compared to the year ended December 31, 2010, mainly due to the issuance of $450.0 million of 4.80% senior notes in August 2010, partially offset by a lower weighted-average pay rate on our fixed-to-floating interest rate swaps.
Other (expense) income, net consisted of the following:
 
Year Ended December 31,
 
2011
 
2010
 
(Thousands of Dollars)
Storage agreement early termination costs
$
(5,000
)
 
$

Contingent loss adjustment
(3,250
)
 

Gain from insurance recoveries

 
13,500

Gain (loss) from sale or disposition of assets
262

 
(510
)
Foreign exchange gains (losses)
2,078

 
(1,507
)
Other, net
2,619

 
4,451

Other (expense) income, net
$
(3,291
)
 
$
15,934


For the year ended December 31, 2011, “Other (expense) income, net” included $5.0 million in costs associated with the early termination of a third-party storage agreement at our Paulsboro, New Jersey asphalt refinery and a contingent loss adjustment of $3.3 million related to the Eres matter discussed in Note 13. Commitments and Contingencies in Item 8. “Financial Statements and Supplemental Data.” The gain from insurance recoveries for the year ended December 31, 2010 resulted from insurance claims related to damage primarily at our Texas City, Texas terminal caused by Hurricane Ike in 2008.
Income tax expense increased $5.1 million for the year ended December 31, 2011, compared to the year ended December 31, 2010, mainly due to the reversal of a deferred tax asset valuation allowance in 2010. The receipt of $13.5 million in insurance proceeds in 2010 related to Hurricane Ike and the Asphalt Holdings Acquisition caused us to reevaluate the recorded valuation allowance related to certain net operating loss carryforwards previously expected to expire unused. In addition, income tax expense in 2011 increased as a result of higher taxable income subject to the Texas Margins Tax.

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Table of Contents

Year Ended December 31, 2010 Compared to Year Ended December 31, 2009
Financial Highlights
(Thousands of Dollars, Except Unit and Per Unit Data)
 
 
Year Ended December 31,
 
 
 
2010
 
2009
 
Change
Statement of Income Data:
 
Revenues:
 
 
 
 
 
Service revenues
$
791,314

 
$
745,349

 
$
45,965

Product sales
3,611,747

 
3,110,522

 
501,225

Total revenues
4,403,061

 
3,855,871

 
547,190

 
 
 
 
 
 
Costs and expenses:
 
 
 
 
 
Cost of product sales
3,350,429

 
2,883,187

 
467,242

Operating expenses
486,032

 
458,892

 
27,140

General and administrative expenses
110,241

 
94,733

 
15,508

Depreciation and amortization expense
153,802

 
145,743

 
8,059

Total costs and expenses
4,100,504

 
3,582,555

 
517,949

 
 
 
 
 
 
Operating income
302,557

 
273,316

 
29,241

Equity in earnings of joint venture
10,500

 
9,615

 
885

Interest expense, net
(78,280
)
 
(79,384
)
 
1,104

Other income, net
15,934

 
31,859

 
(15,925
)
Income before income tax expense
250,711

 
235,406

 
15,305

Income tax expense
11,741

 
10,531

 
1,210

Net income
$
238,970

 
$
224,875

 
$
14,095

Net income per unit applicable to limited partners
$
3.19

 
$
3.47

 
$
(0.28
)
Weighted-average limited partner units outstanding
62,946,987

 
55,232,467

 
7,714,520

Annual Highlights
Net income increased $14.1 million for the year ended December 31, 2010, compared to the year ended December 31, 2009, primarily due to increased segment operating income, which was partially offset by an increase in general and administrative expenses and a decrease in other income.
Segment operating income increased $45.7 million for the year ended December 31, 2010, compared to the year ended December 31, 2009, mainly due to increased operating income from our asphalt and fuels marketing segment. Operating income in our transportation and storage segments also increased compared to 2009.




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Table of Contents

Segment Operating Highlights
(Thousands of Dollars, Except Barrel/Day Information)
 
 
Year Ended December 31,
 
 
 
2010
 
2009
 
Change
Storage:
 
 
 
 
 
Throughput (barrels/day)
669,435

 
667,169

 
2,266

Throughput revenues
$
75,605

 
$
78,353

 
$
(2,748
)
Storage lease revenues
444,233

 
409,219

 
35,014

Total revenues
519,838

 
487,572

 
32,266

Operating expenses
263,820

 
245,439

 
18,381

Depreciation and amortization expense
77,071

 
70,888

 
6,183

Segment operating income
$
178,947

 
$
171,245

 
$
7,702

 
 
 
 
 
 
Transportation:
 
 
 
 
 
Refined products pipelines throughput (barrels/day)
529,946

 
573,778

 
(43,832
)
Crude oil pipelines throughput (barrels/day)
371,726

 
351,888

 
19,838

Total throughput (barrels/day)
901,672

 
925,666

 
(23,994
)
Throughput revenues
$
316,072

 
$
302,070

 
$
14,002

Operating expenses
116,884

 
111,673

 
5,211

Depreciation and amortization expense
50,617

 
50,528

 
89

Segment operating income
$
148,571

 
$
139,869

 
$
8,702

 
 
 
 
 
 
Asphalt and Fuels Marketing:
 
 
 
 
 
Product sales
$
3,615,890

 
$
3,110,522

 
$
505,368

Cost of product sales
3,371,854

 
2,899,457

 
472,397

Gross margin
244,036

 
211,065

 
32,971

Operating expenses
132,918

 
130,973

 
1,945

Depreciation and amortization expense
20,257

 
19,463

 
794

Segment operating income
$
90,861

 
$
60,629

 
$
30,232

 
 
 
 
 
 
Consolidation and Intersegment Eliminations:
 
 
 
 
 
Revenues
$
(48,739
)
 
$
(44,293
)
 
$
(4,446
)
Cost of product sales
(21,425
)
 
(16,270
)
 
(5,155
)
Operating expenses
(27,590
)
 
(29,193
)
 
1,603

Total
$
276

 
$
1,170

 
$
(894
)
 
 
 
 
 
 
Consolidated Information:
 
 
 
 
 
Revenues
$
4,403,061

 
$
3,855,871

 
$
547,190

Cost of product sales
3,350,429

 
2,883,187

 
467,242

Operating expenses
486,032

 
458,892

 
27,140

Depreciation and amortization expense
147,945

 
140,879

 
7,066

Segment operating income
418,655

 
372,913

 
45,742

General and administrative expenses
110,241

 
94,733

 
15,508

Other depreciation and amortization expense
5,857

 
4,864

 
993

Consolidated operating income
$
302,557

 
$
273,316

 
$
29,241



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Table of Contents

Storage
Although throughputs increased 2,266 barrels per day, throughput revenues decreased $2.7 million for the year ended December 31, 2010, compared to the year ended December 31, 2009. Throughputs increased 11,114 barrels per day resulting in a net increase of only $0.3 million in revenues at our crude oil storage tank facilities, as these facilities have lower throughput fees per barrel. In addition, throughputs increased 7,958 barrels per day and revenues increased $1.7 million at our Amarillo and Albuquerque terminals. Throughputs at other terminals serving the McKee refinery decreased 13,888 barrels per day resulting in lower revenues of $4.1 million due to a shipper diverting throughput from our terminals.
Storage lease revenues increased $35.0 million for the year ended December 31, 2010, compared to the year ended December 31, 2009, primarily due to:
an increase of $18.8 million mainly at our Gulf Coast and West Coast terminals primarily due to rate escalations and new customer contracts, as well as higher throughput and related handling fees;
an increase of $7.1 million related to the Asphalt Holdings Acquisition in May 2010;
an increase of $5.2 million at our international terminals mainly due to rate escalations, new customer contracts and higher throughput and related handling fees; and
an increase of $3.9 million due to completed tank expansion projects at our Amsterdam, St. Eustatius and Texas City terminals.
Operating expenses increased $18.4 million for the year ended December 31, 2010, compared to the year ended December 31, 2009, primarily due to:
an increase of $10.9 million mainly related to higher salary and wage expenses resulting from increased headcount and increases in other employee benefit expenses;
an increase of $5.0 million related to the Asphalt Holdings Acquisition in May 2010;
an increase of $2.3 million in reimbursable expenses, primarily due to increases in tank cleaning, wharfage costs and other various projects. Reimbursable expenses are charged back to our customers and are offset by an increase in reimbursable revenues; and
an increase of $2.1 million related to higher environmental costs.
These increases were partially offset by a decrease of $2.5 million in maintenance expenses for the year ended December 31, 2010, compared to the year ended December 31, 2009, mainly due to tank cleanings and repairs in 2009.
Depreciation and amortization expense increased $6.2 million for the year ended December 31, 2010, compared to the year ended December 31, 2009, primarily due to the completion of various terminal upgrade and expansion projects and the Asphalt Holdings Acquisition.
Transportation
Although revenues increased, throughputs decreased for the year ended December 31, 2010, compared to the year ended December 31, 2009, on pipelines with lower tariffs, including pipelines sold in 2009.
Revenues increased $14.0 million for the year ended December 31, 2010, compared to the year ended December 31, 2009, primarily due to:
an increase in throughputs of 7,936 barrels per day and an increase in revenues of $10.1 million on the Ammonia Pipeline due to more favorable weather conditions compared to the prior year;
an increase in throughputs of 3,979 barrels per day and an increase in revenues of $9.1 million on the East Pipeline, mainly due to increased long-haul deliveries resulting in a higher average tariff and higher throughputs resulting from more favorable economic conditions compared to 2009;
an increase in throughputs of 14,230 barrels per day and an increase in revenues of $2.4 million on our pipelines that serve a refinery in South Texas due to the completion of a turnaround in 2009, in addition to increased crude run rates resulting from more favorable economic conditions compared to 2009; and
an increase of 13,687 barrels per day and an increase of $2.2 million on our pipelines serving the Ardmore refinery, which experienced operational issues in the second quarter of 2009 and was shut down in the third quarter of 2009 following a lightning strike.
Despite the increase in revenues, throughputs decreased 23,994 barrels per day for the year ended December 31, 2010, compared to the year ended December 31, 2009. This decrease in throughputs was mainly due to a decrease in throughputs of 31,421 barrels per day and a decrease in revenues of $6.9 million on the Houston pipeline mainly due to market conditions that favored exporting instead of shipping on our pipeline and a refinery project by one of our customers that limited the volumes shipped. In addition,

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Table of Contents

we sold the Ardmore-Wynnewood and Trans-Texas pipelines in 2009, which resulted in decreased throughputs of 28,737 barrels per day and decreased revenues of $3.0 million in 2010, as these pipelines had lower throughput fees per barrel compared to other pipelines.
Operating expenses for this segment increased $5.2 million for the year ended December 31, 2010, compared to the year ended December 31, 2009, primarily due to lower gains in 2010 on product imbalances on the East Pipeline resulting mainly from an increase in prices.

Asphalt and Fuels Marketing
Sales and cost of product sales increased $505.4 million and $472.4 million, respectively, resulting in an increase in total gross margin of $33.0 million for the year ended December 31, 2010, compared to the year ended December 31, 2009. The increase in total gross margin was primarily due to an increase of $17.2 million in the gross margin of our asphalt operations resulting primarily from a higher gross margin per barrel, partially offset by a decrease in sales volumes. For the year ended December 31, 2010, gross margin per barrel for our asphalt operations increased to $7.73 from $6.37 for the year ended December 31, 2009. In addition, the gross margin of our fuels marketing operations increased $15.8 million for the year ended December 31, 2010, compared to the year ended December 31, 2009. Improved gross margins from our bunker fuel sales resulting from higher gross margin per barrel and increased sales volumes at our domestic bunkering locations contributed to the improved gross margin of our fuels marketing operations. The gross margin of our fuels marketing operations also benefitted from increased volumes in certain of our fuel oil markets in 2010.
Operating expenses increased $1.9 million for the year ended December 31, 2010, compared to the year ended December 31, 2009, primarily due to new storage and power costs at asphalt terminals leased by our asphalt operations for the full year of 2010 that we leased for only a portion of 2009.
Consolidation and Intersegment Eliminations
Revenue, cost of product sales and operating expense eliminations primarily relate to storage and transportation fees charged to the asphalt and fuels marketing segment by the transportation and storage segments. In 2010, the asphalt and fuels marketing segment utilized more terminal capacity from our storage segment than in 2009, resulting in higher eliminations for revenue and cost of product sales.
General
General and administrative expenses increased $15.5 million for the year ended December 31, 2010, compared to the year ended December 31, 2009. This increase was primarily due to salary and wage expenses resulting from increased headcount and increases in other employee benefit expenses, as well as higher compensation expense associated with our long-term incentive plans.
Other income, net consisted of the following:
 
Year Ended December 31,
 
2010
 
2009
 
(Thousands of Dollars)
Gain from insurance recoveries
$
13,500

 
$
9,382

(Loss) gain from sale or disposition of assets
(510
)
 
21,320

Foreign exchange losses
(1,507
)
 
(5,118
)
Other
4,451

 
6,275

Other income, net
$
15,934

 
$
31,859

For the year ended December 31, 2010 and 2009, the gain from insurance recoveries resulted from insurance claims related to damage in the third quarter of 2008 primarily at our Texas City, Texas terminal caused by Hurricane Ike. For the year ended December 31, 2009, the gain from the sale or disposition of assets included a gain of $21.4 million related to the June 15, 2009 sale of the Ardmore-Wynnewood pipeline in Oklahoma and the Trans-Texas pipeline.
Income tax expense increased $1.2 million for the year ended December 31, 2010, compared to the year ended December 31, 2009, primarily due to increased expense resulting from higher taxable income, partially offset by the reversal of a deferred tax asset valuation allowance. The receipt of $13.5 million in insurance proceeds related to Hurricane Ike and the Asphalt Holdings Acquisition caused us to reevaluate the recorded valuation allowance related to certain net operating loss carryforwards previously expected to expire unused.


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Table of Contents

TRENDS AND OUTLOOK
We expect our operating income for 2012 to be higher than 2011 mainly due to increases in the earnings from all three of our reportable segments.

Storage Segment
We continue to pursue growth in this segment through expansion and optimization of our existing assets. We expect our 2012 results to benefit from internal growth projects that we completed in 2011, including our 3.2 million barrel storage tank expansion project at our St. James, Louisiana terminal facility completed during the third quarter of 2011. In addition, our 2012 results should benefit from new internal growth projects at our St. James, Louisiana, Texas City, Texas, and St. Eustatius terminal facilities, a portion of which should be completed in 2012. As a result, we expect our earnings in 2012 for the storage segment to exceed 2011.

Transportation Segment
We expect throughputs for 2012 to be higher than 2011 mainly as a result of the pipeline expansion projects completed in 2011 that serve Eagle Ford shale production. The tariffs on our pipelines regulated by the Federal Energy Regulatory Commission, which adjust annually on July 1st based upon changes in the producer price index, are expected to increase effective July 1, 2012. We are continuing our strategy for growth in this segment into 2012 through construction of new assets and optimization of existing assets. We expect to benefit in 2012 from the tariff increase, the completion of expansion projects during 2012, and a full year's contribution of the pipeline expansion projects completed in 2011. Therefore, we expect the transportation segment earnings for 2012 to be higher than 2011.

Asphalt and Fuels Marketing Segment
In 2012, we plan on making further investments to improve the results of our asphalt and fuels marketing segment. In an attempt to improve margins from our asphalt operations, we are taking steps to diversify our crude supply and upgrade our product slate. Weak demand for asphalt that we experienced in our markets in 2011 could continue into 2012. We currently expect the results in 2012 for the asphalt and fuels marketing segment to improve compared to 2011.
 
Our outlook for the company overall could change depending on, among other things, the prices of crude oil, the state of the economy, changes to refinery maintenance schedules and other factors that affect overall demand for the products we store, transport and sell, as well as changes in commodity prices for the products we market.



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