Securities registered pursuant to Section 12(b) of the Act:Common units representing partnership interests listed on the New York Stock Exchange.

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.

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 (Check one):~~Act:

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes [ ] No [X]

The aggregate market value of the common units held by non-affiliates was approximately ~~$2,389~~$3,118 million based on the last sales price quoted as of June 30, ~~2009,~~2010, the last business day of the registrant’s most recently completed second quarter.

The number of common units outstanding as of February 1, ~~2010~~2011 was ~~60,210,549.~~64,610,549.

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 3938 of this report under the heading: “CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION.”

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 asphalt refining and fuels marketing. We divide our operations into the following three operating segments: storage, transportation, and asphalt and fuels marketing. As of December 31, 2010, our assets included:

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:

Our business strategy is to increase per unit cash distributions to our partners through:

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 ishttp://www.nustarenergy.com. Information contained on our website is not part of this report. Our annual reports on Form 10-K, quarterly reports on Form 10-Q and current reports on Form 8-K filed with (or furnished to) the Securities and Exchange Commission (SEC) are available on our internet website, free of charge, as soon as reasonably practicable after we file or furnish such material (select the “Investors” link, then the “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.

On May 21, 2010, we acquired the capital stock of Asphalt Holdings, Inc. for $53.3 million, including liabilities assumed. The acquisition included three storage terminals with 24 storage tanks and an aggregate capacity of approximately 1.8 million barrels located in Alabama along the Mobile River.

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).

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.”

Our storage segment includes terminal and storage facilities that provide storage and handling services on a fee basis for petroleum products, specialty chemicals, crude oil and other liquids and crude oil storage tanks used to store and deliver crude oil. In addition, our terminals located on the island of St. Eustatius in the Caribbean and Point Tupper, Nova Scotia provide services such as pilotage, tug assistance, line handling, launch service, emergency response services and other ship services. As of December 31, 2010, we owned and operated:

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 St. Eustatius facility has a total of 59 tanks. 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, spill response services and other ship services.

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. We also charter tugs, mooring launches and other vessels to assist with the movement of vessels through the Strait of Canso and the safe berthing of vessels at the terminal facility.

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 approximately 5.4 million barrels of storage capacity in 28 tanks 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.

St. James, Louisiana.Our St. James terminal has 26 crude oil storage tanks with a total capacity of approximately 5.0 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.

Amsterdam. Our Amsterdam terminal has 44 storage tanks with a total capacity of approximately 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 capacity of approximately 4.0 million barrels in 24 tanks 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.

The following table sets forth information about our terminal and storage facilities as of December 31, 2010:


Facility	Tank Capacity	Number of Tanks		Primary Products Handled
	(Barrels)

San Antonio (east), TX	148,000		5	Petroleum products
San Antonio (south), TX	215,000		5	Petroleum products
Southlake, TX	575,000		12	Petroleum products, ethanol
Texas City, TX	125,000		10	Petroleum products
Texas City, TX	2,775,000		67	Chemicals, petrochemicals, petroleum products
Texas City, TX	3,087,000		14	Crude oil and feedstocks
Dumfries, VA	548,000		14	Petroleum products, asphalt
Virginia Beach, VA (a)	41,000		2	Petroleum products
Tacoma, WA	359,000		14	Petroleum products, ethanol
Vancouver, WA	328,000		48	Chemicals
Vancouver, WA	408,000		7	Petroleum products

Total U.S.	50,593,000		798


Foreign Terminals and Storage Facilities:
St. Eustatius, Netherlands Antilles	12,986,000		59	Petroleum products, crude oil and feedstocks
Point Tupper, Canada	7,354,000		37	Petroleum products, crude oil and feedstocks
Grays, England	1,956,000		53	Petroleum products
Eastham, England	2,156,000		162	Chemicals, petroleum products
Runcorn, England	145,000		4	Molten sulfur
Grangemouth, Scotland	565,000		47	Petroleum products, chemicals
Glasgow, Scotland	360,000		16	Petroleum products
Belfast, Northern Ireland	440,000		41	Petroleum products
Amsterdam, the Netherlands	3,848,000		44	Petroleum products
Nuevo Laredo, Mexico	34,000		5	Petroleum products

Total Foreign	29,844,000		468

Total Terminals and Storage Facilities	80,437,000		1,266

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 (Valero Energy)’s 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.

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.

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, 2010. No other customer accounted for more than 10% of the revenues of the segment for this period.

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 is the process by which liquid cargo is transferred 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.

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 5,605 miles. Our crude oil pipelines in Texas, Oklahoma, Kansas, Colorado and Illinois cover 812 miles. Our anhydrous ammonia pipeline in Louisiana, Arkansas, Missouri, Illinois, Indiana, Iowa and Nebraska covers 2,000 miles. As of December 31, 2010, we owned and operated:

We charge tariffs on a throughput basis for transporting refined products, crude oil, feedstocks and anhydrous ammonia.

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 112.5 million barrels for the year ended December 31, 2010.

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

East Pipeline.The East Pipeline covers 1,910 miles 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 51.2 million barrels for the year ended December 31, 2010.

North Pipeline.The North Pipeline originates at Tesoro’s Mandan refinery and runs from west to east approximately 440 miles from its origin in Mandan, North Dakota to the Minneapolis, Minnesota area. For the year ended December 31, 2010, the North Pipeline transported approximately 13.7 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.

The following table lists information about each of our refined product terminals connected to the East or North Pipelines:

Ammonia Pipeline.The 2,000 mile pipeline 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 13.9 million barrels) for the year ended December 31, 2010.

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 pipelines transported approximately 135.7 million barrels for the year ended December 31, 2010.

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

The following table sets forth information about the crude oil storage facilities located along our crude oil pipelines:

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.

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.

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.

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 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), Frontier Oil 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.

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.

The largest customer of our transportation segment was Valero Energy, which accounted for approximately 47% of the total segment revenues for the year ended December 31, 2010. In addition to Valero Energy, we had a total of approximately 70 shippers for the year ended December 31, 2010, 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, 2010.

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.

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.

Our asphalt and fuels marketing segment includes our asphalt refining operations and our fuels marketing operations. We refine crude oil to produce asphalt and certain other refined products from our asphalt operations. Additionally, we purchase gasoline and other refined petroleum products for resale. The results of operations for the asphalt and fuels marketing segment depend largely on the margin between our cost and the sales price 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.

Our asphalt refining operations acquired on March 20, 2008 diversified our customer base, expanded our geographic presence and complemented our preexisting asphalt marketing and terminals business. The following table lists information about our asphalt refineries and related terminals as of December 31, 2010. The tank capacity includes storage for asphalt, crude oil and other feedstocks.

Paulsboro Refinery.The Paulsboro refinery is located in Paulsboro, New Jersey on the Delaware River. 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 provide us with an aggregate storage capacity of 4.0 million barrels that are either leased from third parties or owned by us. The Paulsboro refinery’s location on the Delaware River allows for direct access to receipts and shipments.

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. 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 provide us with an aggregate storage capacity of 1.9 million

barrels that are either leased from third parties or owned by us. The Savannah refinery’s location on the Savannah River allows for direct access to receipts and shipments.

We have access to an aggregate asphalt storage capacity of almost 8.0 million barrels, which includes the network of asphalt terminals associated with the Savannah and Paulsboro refineries combined with seven other asphalt terminals.

The following table lists the throughputs and percentages of yields for each refinery for the year ended December 31, 2010:

Customers.We produce several grades of asphalt products for various applications. The asphalt we produce is for hot mix paving, which is used in road construction, roofing shingles for housing, 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. Simultaneously with the acquisition of our asphalt operations, Petróleos de Venezuela S. A. (PDVSA), the national oil company of Venezuela, agreed to supply us with Boscan and Bachaquero BCF-13 crude oil as feedstocks for our refineries. Our cost of crude oil purchased under the supply agreement fluctuates based upon a market-based pricing formula using published market indices, subject to adjustment, based on the price of Mexican Maya crude. Our refineries are optimized to process Boscan and Bachaquero BCF-13 crude oil and doing so typically results in the best economic return. However, the refineries can also process alternative asphaltic crudes and other feedstocks.

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. The top asphalt producers in the U.S. are refiners that produce asphalt as a by-product.

Over the long term, we expect to benefit from higher asphalt margins because many U.S. refiners are planning new coker projects or coker expansions, which should reduce the overall supply of asphalt. Cokers break down the heaviest fractions of crude oil into lighter, higher value products and elemental carbon, or coke. As a result, asphalts and heavy fuel oils are reprocessed into transportation fuels like gasoline and diesel. As the supply of asphalt decreases, asphalt margins are expected to increase.

Our fuels marketing operations provide us the opportunity to generate additional gross margin while complementing the activities of our storage and transportation segments. Specifically, we purchase crude oil, gasoline, distillates and refinery feedstocks to take advantage of arbitrage opportunities and contango markets (when the price for future deliveries exceeds current prices). During a contango market, we can utilize storage at strategically located terminals, including our own terminals, to deliver products at favorable prices. Additionally, we may take advantage of geographic arbitrage opportunities by utilizing transportation and storage assets, including our own terminals and pipelines, to deliver products from one geographic region to another with more favorable pricing. We also purchase gasoline and distillates in spot markets from refiners and traders, which we then offer for sale to wholesale customers through terminals owned by us or third-parties. The gross margin we generate reflects the wholesale uplift above spot market prices, less terminalling and transportation fees.

As part of these operations, we may utilize storage space in certain of our refined products terminals and terminals operated by third parties. We may also obtain transportation services from our refined products pipelines and other third-party providers. Rates charged by our storage segment to the asphalt and fuels marketing segment are consistent with rates charged to third parties. Because the majority of our pipelines are common carrier pipelines, the tariffs charged to the asphalt and fuels marketing segment from the transportation segment are based upon the published tariff applicable to all shippers.

In addition, we sell bunker fuel from our terminal locations at St. Eustatius and Point Tupper where we also store bunker fuel for third parties. The strategic location of these two facilities and their storage capabilities provide us with a reliable supply of product and the ability to capture incremental sales margin. Also, the St. Eustatius terminal facility has six mooring locations that can supply bunkers to vessels up to 520,000 deadweight tons, and the Point Tupper facility has two mooring locations that can supply bunkers to vessels up to 400,000 deadweight tons. In 2009, we began limited bunkering operations at certain of our U.S. terminals, and in 2010, we increased our U.S. bunkering operations at our Texas City and Los Angeles terminals.

Since the operations of our asphalt and fuels marketing segment 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, as well as various wholesale suppliers, unbranded retailers and large high volume retailers. Customers for our bunker fuel sales are 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. We also compete with bunker fuel delivery locations around the world. In the Western Hemisphere, alternative bunker fuel locations include ports on the U.S. East Coast and Gulf Coast and in Panama, the Caribbean and Nova Scotia.

Our operations are managed by NuStar GP, LLC. As of December 31, 2010, NuStar GP, LLC had 1,413 employees performing services for our United States operations. Certain of our wholly owned subsidiaries had 389 employees performing services for our international operations. We believe that NuStar GP, LLC and our subsidiaries each have satisfactory relationships with their employees.

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.

Our operations are subject to extensive federal, state and local environmental laws and regulations, including those relating to the discharge of materials into the environment, waste management and pollution prevention measures. 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 crude oil and refined 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 2010, our capital expenditures attributable to compliance with environmental regulations were $16.7 million, and are currently estimated to be approximately $3.4 million for 2011. The estimate for 2011 does not include amounts related to capital investments at our facilities that management has deemed to be strategic investments rather than expenditures relating to environmental regulatory compliance.

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 products. In December 2007, Congress enacted the Energy Independence and Security Act of 2007, 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. These statutory mandates 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.

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 and response to oil spills. Spill prevention control and countermeasure requirements of the Clean Water Act and some state laws require 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 overflow or release. Violations of any of these statutes and the related regulations could result in significant costs and liabilities.

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.

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 our operations generate minimal quantities of hazardous wastes. 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.

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 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 was not under our control. 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 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.

Our pipelines are subject to extensive federal and state laws and regulations governing pipeline integrity and safety. The federal Pipeline Safety Improvement Act of 2002 and its implementing regulations (collectively, PSIA) 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 and 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). While compliance with PSIA 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.

The Pipeline Inspection, Protection, Enforcement, and Safety Act of 2006 (PIPES Act) became effective in December 2006. The PIPES Act included requirements to strengthen damage prevention measures designed to protect pipelines from excavation damage, eliminate an exemption from regulation for certain low-stress hazardous liquid pipelines, and require pipeline operators to manage human factors in pipeline control centers, including controller fatigue. While implementation of the PIPES Act is imposing additional operating requirements on pipeline operators, we do not believe that the costs of compliance with the PIPES Act will have a material effect on our financial condition or results of operations.

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:

In addition, the amount of cash that we will have available for distribution will depend on other factors, including:

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.

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 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:

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 asphalt 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 and intermediate product refining margins.

A large portion of our earnings from our asphalt operations are affected by the relationship, or margin, between asphalt and other intermediate 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 and other intermediate 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 and intermediate products produced by our asphalt 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 as the price of crude oil. Our increased exposure to unstable commodity prices will increase the volatility of our earnings.

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:

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 negatively impact 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.

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.

As of December 31, 2010, our consolidated debt was $2.1 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. Fitch, Moody’s and Standard & Poor’s have assigned NuStar Logistics and NuPOP a stable outlook. 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 asphalt 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.

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, 2010, we had approximately $2.1 billion of consolidated debt, of which $1.0 billion was at fixed interest rates and $1.1 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 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.

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:

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.

Potential future acquisitions and expansions, if any, may increase substantially the level of our indebtedness and contingent liabilities, and we may be unable to integrate them effectively into our existing operations.

From time to time, we evaluate and acquire assets and businesses that we believe complement or diversify our existing assets and businesses. Acquisitions may require substantial capital or the incurrence of substantial indebtedness. If we consummate any future material acquisitions, our capitalization and results of operations may change significantly.

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 and we may experience unanticipated delays in realizing the benefits of an acquisition. In some cases, we have indemnified the previous owners and operators of acquired assets.

Following an acquisition, we may discover previously unknown liabilities associated with the acquired business for which we have no recourse under applicable indemnification provisions. In addition, the terms of an acquisition may require us to assume certain prior known or unknown liabilities for which we may not be indemnified or have adequate insurance.

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 may not be able to integrate effectively and efficiently with future businesses or operations we may acquire. Any future acquisitions may substantially increase the levels of our indebtedness and contingent liabilities.

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. Our capitalization and results of operations may change significantly as a result of future acquisitions, 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. Unexpected costs or challenges may arise whenever businesses with different operations and management are combined. For example, the incurrence of substantial unforeseen environmental and other liabilities, including liabilities arising from the operation of an acquired business or asset prior to our acquisition for which we are not indemnified or for which indemnity is inadequate, may adversely affect our ability to realize the anticipated benefit from an acquisition. Inefficiencies and difficulties may arise because of unfamiliarity with new assets and new geographic areas of any acquired businesses. 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.

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.

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.

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, 2011) is measured by the year-over-year change in the Bureau of Labor’s producer price index for finished goods, plus 1.3%. 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 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, 2010, our power costs equaled approximately $52.1 million, or 11% of our operating expenses for the year. In addition, $17.6 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.

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, 2010, an aggregate 15.6% 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 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.

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 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.

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.

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.

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 are currently in settlement discussions with other potentially responsible parties and the DOJ, and a change in our estimate of this liability may occur in the near term. However, any settlement agreement that is reached must be approved by multiple parties and requires the approval of the bankruptcy court and the federal district court. We cannot currently estimate when or if a settlement will be finalized.

In August 2008, Eres N.V. (Eres) forwarded a demand for arbitration to CITGO Asphalt Refining Company (CARCO), CITGO Petroleum Corporation (CITGO), NuStar Asphalt Refining, LLC (NuStar Asphalt) and NuStar Marketing LLC (NuStar Marketing, and together with CARCO, CITGO and NuStar Asphalt, the Defendants) contending that the Defendants are in breach of a tanker voyage charter party agreement, dated November 2004, between Eres and CARCO (the Charter Agreement). The Charter Agreement provides for CARCO’s use of Eres’ vessels for the shipment of asphalt. Eres contends that NuStar Asphalt and/or NuStar Marketing (together, the NuStar Entities) assumed the Charter Agreement when NuStar Asphalt purchased the CARCO assets, and that the Defendants have failed to perform under the Charter Agreement since January 1, 2008. Eres has valued its damages for the alleged breach of contract claim at approximately $78.1 million. Pursuant to a May 2010 ruling by the United States District Court for the Southern District of Texas, the NuStar Entities were found to have assumed the Charter Agreement from CARCO and to be obligated to defend and indemnify CITGO and CARCO against Eres’ claims. The Defendants were ordered to proceed with arbitration. We intend to vigorously defend against Eres’ claims in arbitration.

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 any 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 80 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 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.

No matters were submitted to a vote of the unitholders, through solicitation of proxies or otherwise, during the fourth quarter of the year ended December 31, 2010.

Our common units are listed and traded on the New York Stock Exchange under the symbol “NS.” At the close of business on February 8, 2011, we had 737 holders of record of our common units. The high and low sales prices (composite transactions) by quarter for the years ended December 31, 2010 and 2009 were as follows:

The cash distributions applicable to each of the quarters in the years ended December 31, 2010 and 2009 were as follows:

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:

Our general partner’s incentive distributions for the years ended December 31, 2010 and 2009 totaled $33.3 million and $28.7 million, respectively. The general partner’s share of our distributions for the years ended December 31, 2010 and 2009 was 12.7% and 12.6%, respectively, due to the impact of the incentive distributions.

The following table contains selected financial data derived from our audited financial statements.

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.

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.

~~NuStar Energy L.P. (NuStar Energy), a Delaware limited partnership, completed its initial public offering~~The operations of ~~common units on April 16, 2001. Our common units are traded~~our refined product terminals depend in large part on the ~~New York Stock Exchange (NYSE)~~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.

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, 2010. No other customer accounted for more than 10% of the revenues of the segment for this period.

The main competition at our St. Eustatius and Point Tupper locations for crude oil handling and storage is from “lightering,” which is the process by which liquid cargo is transferred 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 ~~symbol “NS.”~~ 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 ~~principal executive offices~~crude oil storage tanks are ~~located at 2330 North Loop 1604 West, San Antonio, Texas 78248~~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 ~~telephone number is (210) 918-2000.~~services provided to those refineries.

Our pipeline operations consist of ~~petroleum products,~~ 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 5,605 miles. Our crude oil pipelines in Texas, Oklahoma, Kansas, Colorado and Illinois cover 812 miles. Our anhydrous ammonia pipeline in Louisiana, Arkansas, Missouri, Illinois, Indiana, Iowa and ~~asphalt and fuels marketing. We manage our operations through the following three operating segments: storage, transportation, and asphalt and fuels marketing.~~Nebraska covers 2,000 miles. As of December 31, ~~2009, our assets included:~~2010, we owned and operated:

We charge tariffs on a throughput basis for transporting refined products, crude oil, feedstocks and anhydrous ammonia.

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

The following table lists information about each of our refined product terminals connected to the East or North Pipelines:

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 ~~tanks providing~~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 pipelines transported approximately 135.7 million barrels for the year ended December 31, 2010.

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

The following table sets forth information about the crude oil storage facilities located along our crude oil pipelines:

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.

Revenues for the pipelines are based upon origin-to-destination throughput volumes traveling through our pipelines and their related tariff rates.

have a material adverse effect on our operations, although we would endeavor to minimize the impact by seeking alternative customers for those pipelines.

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.

~~We conduct our operations through our wholly owned subsidiaries, primarily NuStar Logistics, L.P. (NuStar Logistics)~~barrels, which includes the network of asphalt terminals associated with the Savannah and ~~NuStar Pipeline Operating Partnership L.P. (NuPOP). Our revenues include:~~Paulsboro refineries combined with seven other asphalt terminals.

The following table lists the throughputs and percentages of yields for each refinery for the year ended December 31, 2010:

~~Our business strategy is to increase per unit cash distributions to our partners through:~~

Our fuels marketing operations provide us the opportunity to generate additional gross margin while complementing the activities of our storage and transportation segments. Specifically, we purchase crude oil, gasoline, distillates and refinery feedstocks to take advantage of arbitrage opportunities and contango markets (when the price for future deliveries exceeds current prices). During a contango market, we can utilize storage at strategically located terminals, including our own terminals, to deliver products at favorable prices. Additionally, we may take advantage of geographic arbitrage opportunities by utilizing transportation and storage assets, including our own terminals and pipelines, to deliver products from one geographic region to another with more favorable pricing. We also purchase gasoline and distillates in spot markets from refiners and traders, which we then offer for sale to wholesale customers through terminals owned by us or third-parties. The ~~term “throughput” as used~~gross margin we generate reflects the wholesale uplift above spot market prices, less terminalling and transportation fees.

As part of these operations, we may utilize storage space in ~~this document generally refers~~certain of our refined products terminals and terminals operated by third parties. We may also obtain transportation services from our refined products pipelines and other third-party providers. Rates charged by our storage segment to the ~~crude oil or refined product barrels or tons~~asphalt and fuels marketing segment are consistent with rates charged to third parties. Because the majority of ~~ammonia, as applicable, that pass through~~ our pipelines are common carrier pipelines, the tariffs charged to the asphalt and fuels marketing segment from the transportation segment are based upon the published tariff applicable to all shippers.

In addition, we sell bunker fuel from our terminal locations at St. Eustatius and Point Tupper where we also store bunker fuel for third parties. The strategic location of these two facilities and their storage capabilities provide us with a reliable supply of product and the ability to capture incremental sales margin. Also, the St. Eustatius terminal facility has six mooring locations that can supply bunkers to vessels up to 520,000 deadweight tons, and the Point Tupper facility has two mooring locations that can supply bunkers to vessels up to 400,000 deadweight tons. In 2009, we began limited bunkering operations at certain of our U.S. terminals, ~~storage tanks or refineries.~~and in 2010, we increased our U.S. bunkering operations at our Texas City and Los Angeles terminals.

~~Our internet website address ishttp://www.nustarenergy.com. Information contained~~Since the operations of our asphalt and fuels marketing segment expose us to commodity price risk, we sometimes enter into derivative instruments to mitigate the effect of commodity price fluctuations on our ~~website is not part~~operations. The derivative instruments we use consist primarily of ~~this report.~~futures contracts and swaps traded on the NYMEX for the purposes of hedging the price risk of our physical inventory.

Competition and Business Considerations. Our ~~annual reports on Form 10-K, quarterly reports on Form 10-Q~~fuels marketing operations have numerous competitors, including large integrated refiners, marketing affiliates of other partnerships in our industry, as well as various international and ~~current reports on Form 8-K filed~~domestic trading companies. In the sale of bunker fuel, we compete with ~~(or furnished to)~~ports offering bunker fuels that are along the ~~Securities and Exchange Commission (SEC) are available on our internet website, free~~route of ~~charge, as soon as reasonably practicable after we file or furnish such material (select~~travel of the ~~“Investors” link, then the “Financial Reports SEC Filings” link).~~vessel. We also ~~post our corporate governance guidelines, code of business conduct~~compete with bunker fuel delivery locations around the world. In the Western Hemisphere, alternative bunker fuel locations include ports on the U.S. East Coast and ~~ethics, code of ethics for senior financial officers~~Gulf Coast and in Panama, 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.Caribbean and Nova Scotia.

In November 2009, we issued 5,750,000 common units representing limited partner interests at a price of $52.45 per unit. We received net proceeds of $288.8 million and a contribution of $6.2 million from our general partner to maintain its 2% general partner interest. The net proceeds were used mainly to reduce the outstanding principal balance under our revolving credit agreement.

Our operations are managed by NuStar GP, ~~LLC, the general partner~~LLC. As of ~~our general partner.~~December 31, 2010, NuStar GP, LLC ~~a Delaware limited liability company, is a consolidated subsidiary~~had 1,413 employees performing services for our United States operations. Certain of our wholly owned subsidiaries had 389 employees performing services for our international operations. We believe that NuStar GP, ~~Holdings,~~ LLC ~~(NuStar GP Holdings) (NYSE: NSH)~~and our subsidiaries each have satisfactory relationships with their employees.

Shippers may challenge tariff rates rules and regulations on our pipelines. There are no pending challenges or complaints regarding our tariffs.

Capital Expenditures Attributable to Compliance with Environmental Regulations. In 2010, our capital expenditures attributable to compliance with environmental regulations were $16.7 million, and are currently estimated to be approximately $3.4 million for 2011. The ~~following chart depicts~~estimate for 2011 does not include amounts related to capital investments at our ~~organizational structure~~facilities that management has deemed to be strategic investments rather than expenditures relating to environmental regulatory compliance.

The Pipeline Inspection, Protection, Enforcement, and Safety Act of 2006 (PIPES Act) became effective in December ~~31, 2009.~~

2006. The PIPES Act included requirements to strengthen damage prevention measures designed to protect pipelines from excavation damage, eliminate an exemption from regulation for certain low-stress hazardous liquid pipelines, and require pipeline operators to manage human factors in pipeline control centers, including controller fatigue. While implementation of the PIPES Act is imposing additional operating requirements on pipeline operators, we do not believe that the costs of compliance with the PIPES Act will have a material effect on our financial condition or results of operations.

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.

In addition, the amount of cash that we will have available for distribution will depend on other factors, including:

Reduced demand for refined products could affect our results of operations and ability to make 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.

Our ~~three reportable business segments~~operations are ~~storage, transportation,~~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.

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

Our financial results are affected by volatile asphalt and intermediate product refining margins.

Additionally, crude oil prices and prices for the asphalt and intermediate products produced by our asphalt 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. Detailed~~marketing segment will suffer if the market prices of asphalt and intermediate products do not increase as much as the price of crude oil. Our increased exposure to unstable commodity prices will increase the volatility of our earnings.

The operating results for our asphalt operations are seasonal and generally lower in the first and fourth quarters of the year.

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 ~~segments is included~~marketing and trading activities, including any hedging activities, may cause volatility in ~~Note 22~~our earnings. In addition, we will be exposed to credit risk in the event of non-performance by counterparties.

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

Increases in interest rates could adversely affect our business and the trading price of our units.

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.

Climate change legislation and regulatory initiatives may decrease demand for the products we store, transport and sell and increase our operating costs.

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.

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.

Some of our pipelines are interstate common carrier pipelines, subject to regulation by the FERC.

The ~~following map depicts~~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.

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

Increases in natural gas and power prices could adversely affect our ability to make distributions to our unitholders.

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 ~~at December 31, 2009.~~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.

~~STORAGE~~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.

~~Our storage segment includes terminal facilities that provide storage~~NuStar GP Holdings currently indirectly owns our general partner and handling services on a fee basis for petroleum products, specialty chemicals, crude oil and other liquids and crude oil storage tanks used to store and deliver crude oil. In addition, our terminals located on the island of St. Eustatius, the Netherlands Antilles and Point Tupper, Nova Scotia provide services such as ~~pilotage, tug assistance, line handling, launch service, emergency response services and other ship services. As~~ of December 31, ~~2009, we owned~~2010, an aggregate 15.6% limited partner interest in us. Conflicts of interest may arise between NuStar GP Holdings and ~~operated:~~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:

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.

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.

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.

Tax gain or loss on the disposition of our units could be different than expected.

Tax-exempt entities and foreign persons face unique tax issues from owning units that may result in adverse tax consequences to them.

Unitholders will likely be subject to state and local taxes and return filing requirements as a result of investing in our units.

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 ~~and intermediate feedstock storage~~ tanks and related ~~assets~~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.

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 ~~California~~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.

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 ~~aggregate storage capacity~~the Otis AFB pipeline. Relying on the final judgment of ~~approximately 12.5 million barrels.~~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 are currently in settlement discussions with other potentially responsible parties and the DOJ, and a change in our estimate of this liability may occur in the near term. However, any settlement agreement that is reached must be approved by multiple parties and requires the approval of the bankruptcy court and the federal district court. We cannot currently estimate when or if a settlement will be finalized.

~~St. Eustatius, Netherlands Antilles.~~In August 2008, Eres N.V. (Eres) forwarded a demand for arbitration to CITGO Asphalt Refining Company (CARCO), CITGO Petroleum Corporation (CITGO), NuStar Asphalt Refining, LLC (NuStar Asphalt) and NuStar Marketing LLC (NuStar Marketing, and together with CARCO, CITGO and NuStar Asphalt, the Defendants) contending that the Defendants are in breach of a tanker voyage charter party agreement, dated November 2004, between Eres and CARCO (the Charter Agreement). The Charter Agreement provides for CARCO’s use of Eres’ vessels for the shipment of asphalt. Eres contends that NuStar Asphalt and/or NuStar Marketing (together, the NuStar Entities) assumed the Charter Agreement when NuStar Asphalt purchased the CARCO assets, and that the Defendants have failed to perform under the Charter Agreement since January 1, 2008. Eres has valued its damages for the alleged breach of contract claim at approximately $78.1 million. Pursuant to a May 2010 ruling by the United States District Court for the Southern District of Texas, the NuStar Entities were found to have assumed the Charter Agreement from CARCO and to be obligated to defend and indemnify CITGO and CARCO against Eres’ claims. The Defendants were ordered to proceed with arbitration. We own and operate a 13.0 million barrel petroleum storage and terminalling facility located on the island of St. Eustatius, 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 St. Eustatius facility has a total of 58 tanks. 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 additionintend to vigorously defend against Eres’ claims in arbitration.

With respect to the ~~storage and blending services at St. Eustatius, this facility has~~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 ~~flexibility to utilize certain storage capacity for both feedstock and refined products to support our atmospheric distillation unit. This unit is capable~~ultimate outcome of ~~processing up to 25,000 barrels per day of feedstock, ranging from condensates to heavy crude oil. We own and operate all~~any of the ~~berthing facilities at~~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 ~~St. Eustatius terminal. Separate fees apply~~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 80 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 ~~use~~costs of ~~the berthing facilities,~~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 ~~services, including pilotage, tug assistance, line handling, launch service, spill response services~~with the cleanup. The precise nature and ~~other ship services.~~extent of any clean-up of the Portland Harbor Site, the parties to be involved, the process to be followed for any clean-up and the allocation of any costs for the clean-up among responsible parties have not yet been determined. It is unclear to what extent, if any, we will be liable for environmental costs or damages associated with the Portland Harbor Site. It is also unclear to what extent natural resource damage claims or third party contribution or damage claims will be asserted against Shore.

~~Point Tupper, Nova Scotia.~~~~We own and operate~~No matters were submitted to 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 onevote of the ~~premier jetty facilities in North America,~~unitholders, through solicitation of proxies or otherwise, during the ~~Point Tupper facility can accommodate substantially all~~fourth quarter 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. We also charter tugs, mooring launches and other vessels to assist with the movement of vessels through the Strait of Canso and the safe berthing of vessels at the terminal facility.

~~Piney Point, Maryland.~~Our terminal and storage facility in Piney Point, Maryland is located on approximately 400 acres on the Potomac River. The Piney Point terminal has approximately 5.4 million barrels of storage capacity in 28 tanks 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.year ended December 31, 2010.

~~St. James, Louisiana.~~Our St. James terminal has 29 crude oil storage tanks with a total capacity of approximately 4.9 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 land.PART II

~~Linden, New Jersey.~~~~We own 50% of ST Linden Terminal LLC, which owns a terminal~~Market Information, Holders and ~~storage facility in Linden, New Jersey. The terminal is located~~Distributions

Our common units are listed and traded on ~~a 44-acre facility that provides it with deep-water terminalling capabilities at~~the New York ~~Harbor. This terminal primarily stores petroleum products, including gasoline, jet fuel~~Stock Exchange under the symbol “NS.” At the close of business on February 8, 2011, we had 737 holders of record of our common units. The high and ~~fuel oils.~~ low sales prices (composite transactions) by quarter for the years ended December 31, 2010 and 2009 were as follows:

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. The largest customer of our storage segment is Valero Energy, which accounted for approximately 22% of the total revenues of the segment for the year ended December 31, 2009. No other customer accounted for more than 10% of the revenues of the segment for this period. Our customers include a major international oil company that leases and utilizes 4.1 million barrels of storage at Point Tupper under a long-term contract with us. During 2009, an oil producer leased and utilized 5.0 million barrels of storage at St. Eustatius. Beginning in 2010, we agreed to a long-term agreement to lease those 5.0 million barrels of storage to a national sponsored oil company, replacing the lease with the oil producer. 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, 2010. No other customer accounted for more than 10% of the revenues of the segment for this period.

Our pipeline operations consist ~~primarily~~ of the transportation of refined petroleum products, crude oil and ~~crude oil. Our common carrier, refined~~anhydrous ammonia. Refined product pipelines in Texas, Oklahoma, Colorado, New Mexico, Kansas, Nebraska, Iowa, South Dakota, North Dakota and Minnesota cover approximately 5,605 miles. ~~In addition, we own a 2,000 mile~~Our crude oil pipelines in Texas, Oklahoma, Kansas, Colorado and Illinois cover 812 miles. Our anhydrous ammonia

pipeline ~~located~~ in Louisiana, Arkansas, Missouri, Illinois, Indiana, Iowa and ~~Nebraska.~~Nebraska covers 2,000 miles. As of December 31, ~~2009,~~2010, we owned and operated:

~~As of December 31, 2009, we also had an ownership interest in eleven~~ crude oil pipelines in Texas, Oklahoma, Kansas, Colorado and Illinois with an aggregate length of 812 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.~~pipelines; and

We charge tariffs on a ~~per barrel~~throughput basis for transporting refined products, crude oil, feedstocks and ~~other feedstocks in our refined product and crude oil pipelines and on a per ton basis for transporting~~ anhydrous ~~ammonia in the Ammonia Pipeline.~~ammonia.

Central West System.The Central West System ~~was~~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 ~~crude oil, blendstocks~~ and other products produced primarily by Valero Energy’s McKee, Three Rivers and Corpus Christi ~~and Ardmore~~ refineries. These pipelines ~~connect the Valero Energy refineries~~deliver refined products to key markets in Texas, New Mexico and Colorado. The Central West System transported approximately ~~130.8~~112.5 million barrels for the year ended December 31, ~~2009.~~2010.

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		Refinery	Length		Ownership	Capacity
		(Miles)			(Barrels/Day)			(Miles)			(Barrels/Day)

McKee to El Paso, TX	McKee		408	67%		40,000	McKee		408	67%		40,000
McKee to Colorado Springs, CO	McKee		256	100%		38,000	McKee		256	100%		38,000
Colorado Springs, CO to Airport	McKee		2	100%		14,000	McKee		2	100%		14,000
Colorado Springs to Denver, CO	McKee		101	100%		32,000	McKee		101	100%		32,000
McKee to Denver, CO	McKee		321	30%		9,870	McKee		321	30%		9,870
McKee to Amarillo, TX (6”) (a)	McKee		49	100%		51,000	McKee		49	100%		51,000
McKee to Amarillo, TX (8”) (a)	McKee		49	100%			McKee		49	100%
Amarillo to Abernathy, TX	McKee		102	67%		11,733	McKee		102	67%		11,733
Amarillo, TX to Albuquerque, NM (b)	McKee		293	50%		17,150	McKee		293	50%		17,150
Abernathy to Lubbock, TX	McKee		19	46%		8,029	McKee		19	46%		8,029
McKee to Southlake, TX	McKee		375	100%		27,300	McKee		375	100%		27,300
Three Rivers to San Antonio, TX	Three Rivers		81	100%		33,600	Three Rivers		81	100%		33,600
Three Rivers to US/Mexico International Border near Laredo, TX	Three Rivers		108	100%		32,000	Three Rivers		108	100%		32,000
Corpus Christi to Three Rivers, TX	Corpus Christi		68	100%		32,000	Corpus Christi		68	100%		32,000
Three Rivers to Corpus Christi, TX	Three Rivers		72	100%		15,000	Three Rivers		72	100%		15,000
Three Rivers to Pettus to San Antonio, TX	Three Rivers		103	100%		30,000	Three Rivers		103	100%		30,000
Three Rivers to Pettus to Corpus Christi, TX (c)	Three Rivers		87	100%		N/A	Three Rivers		87	100%		N/A
El Paso, TX to Kinder Morgan	McKee		12	67%		65,600	McKee		12	67%		65,600
Corpus Christi to Pasadena, TX	Corpus Christi		208	100%		105,000	Corpus Christi		208	100%		105,000
Corpus Christi to Brownsville, TX	Corpus Christi		194	100%		45,000	Corpus Christi		194	100%		45,000
US/Mexico International Border near Penitas, TX to Edinburg, TX	N/A		33	100%		24,000	N/A		33	100%		24,000
Clear Lake, TX to Texas City, TX	N/A		25	100%		N/A	N/A		25	100%		N/A
Other refined product pipeline (d)	N/A		289	50%		N/A	N/A		289	50%		N/A

Total			3,255			631,282			3,255			631,282

~~On June 15, 2009, we sold the Ardmore-Wynnewood pipeline in Oklahoma and the Trans-Texas pipeline for proceeds of $29.0 million.~~

East Pipeline.The East Pipeline covers 1,910 miles 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 ~~21 product tanks with total~~ 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 ~~our~~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, ~~connected to the East Pipeline~~Oklahoma and ~~through other pipelines directly connected to the pipeline system.~~Texas. The East Pipeline transported approximately ~~49.8~~51.2 million barrels for the year ended December 31, ~~2009.~~2010.

North Pipeline.The North Pipeline ~~is currently supplied by the Tesoro~~originates at Tesoro’s Mandan refinery and runs from west to east approximately 440 miles from its origin in Mandan, North Dakota to the Minneapolis, Minnesota area. For the year ended December 31, ~~2009,~~2010, the North Pipeline transported approximately ~~15.3~~13.7 million barrels.

The following table lists information about each of our refined product terminals connected to the East or North Pipelines:

Ammonia Pipeline.The 2,000 mile pipeline 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 ~~1.2~~1.5 million tons (or approximately ~~11.0~~13.9 million barrels) for the year ended December 31, ~~2009.~~2010.

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. ~~Also, we~~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 pipelines transported approximately ~~128.4~~135.7 million barrels for the year ended December 31, ~~2009.~~2010.

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


Origin and Destination	Refinery	Length		Ownership	Capacity		Refinery	Length		Ownership		Capacity
		(Miles)			(Barrels/Day)			(Miles)				(Barrels/Day)

Cheyenne Wells, CO to McKee	McKee		210	100%		17,500	McKee		210		100%		17,500
Dixon, TX to McKee	McKee		44	100%		63,600	McKee		44		100%		63,600
Hooker, OK to Clawson, TX (a)	McKee		41	50%		22,000	McKee		41		50%		22,000
Clawson, TX to McKee	McKee		31	100%		36,000	McKee		31		100%		36,000
Wichita Falls, TX to McKee	McKee		272	100%		110,000	McKee		272		100%		110,000
Corpus Christi, TX to Three Rivers	Three Rivers		70	100%		120,000	Three Rivers		70		100%		120,000
Ringgold, TX to Wasson, OK	Ardmore		44	100%		90,000	Ardmore		44		100%		90,000
Healdton to Ringling, OK(b)	Ardmore		4	100%		52,000	Ardmore		4		100%		N/A
Wasson, OK to Ardmore (8”-10”) ~~(b)~~(c)	Ardmore		24	100%		90,000	Ardmore		24		100%		90,000
Wasson, OK to Ardmore (8”)	Ardmore		15	100%		40,000	Ardmore		15		100%		40,000
Patoka, IL to Wood River, IL	Wood River		57	24%		60,600
Patoka, IL to Wood River							Wood River		57		24%		60,600

Total			812			701,700			812				649,700

The following table sets forth information about the crude oil storage facilities located along our crude oil pipelines:

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.

Revenues for the pipelines are based upon origin-to-destination throughput volumes traveling through our pipelines and ~~the~~their related ~~tariffs.~~tariff rates.

In general, a shipper on ~~one of~~ our refined petroleum product pipelines delivers products to the pipeline from refineries or third-party ~~pipelines that connect to our~~ pipelines. ~~Each shipper transporting product on a pipeline is~~Shippers are required to supply us with a notice of shipment indicating sources of products and destinations. ~~All shipments~~Shipments are tested or receive ~~refinery~~ certifications to ensure compliance with our product specifications. We charge our shippers ~~tariffs~~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.

The ~~refined product~~ 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 along the route of the systems.~~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, ~~in Colorado, Kansas, North Dakota, Oklahoma and Texas,~~ with the relevant state authority, to any shipper of ~~refined~~ 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.

The operations of our Central West System and the East and North Pipelines depend ~~in large part~~ 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.

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 largest customer of our transportation segment was Valero Energy, which accounted for approximately ~~49%~~47% of the total segment revenues for the year ended December 31, ~~2009.~~2010. In addition to Valero Energy, we had a total of approximately 70 shippers for the year ended December 31, ~~2009,~~2010, 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, ~~2008.~~2010.

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.

Our asphalt refining operations acquired on March 20, 2008 diversified our customer base, expanded our geographic presence and complemented our preexisting asphalt marketing and terminals business. The following table lists information about our asphalt refineries and related terminals as of December 31, ~~2009.~~2010. The tank capacity includes storage for asphalt, crude oil and other feedstocks.


							Production				Number of
Facility	Production Capacity		Tank Capacity		Number of Tanks		Capacity		Tank Capacity		Tanks
	(Barrels Per Day)		(Barrels)				(Barrels Per Day)		(Barrels)

Paulsboro, NJ		74,000		3,640,000		24		74,000		3,640,000		24
Savannah, GA		30,000		1,359,000		25		30,000		1,359,000		25

Total		104,000		4,999,000		49		104,000		4,999,000		49

Paulsboro Refinery.The Paulsboro refinery is located in Paulsboro, New Jersey on the Delaware River. 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 11twelve asphalt terminals in the northeastern United States. These asphalt terminals provide us with an aggregate storage capacity of ~~3.8~~4.0 million barrels ~~and~~that are either leased from third parties or owned by us. The Paulsboro refinery’s location on the Delaware River allows for direct access ofto receipts and shipments.

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. 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 11nine asphalt terminals in the southeastern United States. These asphalt terminals provide us with an aggregate storage capacity of 1.9 million

barrels ~~and~~that are either leased from third parties or owned by us. The Savannah refinery’s location on the Savannah River allows for direct access ofto receipts and shipments.

The following table lists the throughputs and percentages of yields for each refinery for the year ended December 31, ~~2009:~~2010:


	Volumes	Percentage	Volumes		Percentage
	(barrels per day)		(barrels per day)

Paulsboro:
Crude oil throughput	45,025			40,782
Yields:
Asphalt	27,103	61%		26,839		66%
Naphtha	1,267	3%		1,165		3%
Marine diesel oil	6,786	15%		3,445		9%
Light marine gas oil				4,169		10%
Vacuum gas oil	3,651	8%		3,666		9%
HS fuel oil	5,982	13%		1,181		3%

Savannah:
Crude oil throughput	17,991			18,159
Yields:
Asphalt	13,362	75%		13,551		75%
Naphtha	591	3%		650		3%
Light marine gas oil	3,995	22%		3,945		22%

reprocessed into transportation fuels like gasoline and diesel. As the supply of asphalt decreases, asphalt margins are expected to increase.

Our operations are managed by NuStar GP, LLC. As of December 31, ~~2009,~~2010, NuStar GP, LLC had ~~1,379~~1,413 employees performing services for our ~~U.S.~~United States operations. Certain of our wholly owned subsidiaries had ~~374~~389 employees performing services for our international operations. We believe that NuStar GP, LLC and our subsidiaries each have satisfactory relationships with their employees.

Shippers may challenge tariff rates rules and regulations on our pipelines. There are no pending challenges or complaints regarding our tariffs. It is not likely that there will be a challenge to the tariffs on our ammonia, petroleum products or crude oil pipelines by a current shipper that would materially affect our revenues or cash flows. However, the FERC, the STB or a state regulatory commission could investigate our tariffs on their own motion or upon a complaint filed by a third party. Also, since our pipelines are common carrier pipelines, we may be required to accept new shippers who wish to transport in our pipelines and who could potentially decide to challenge our tariffs.

refined 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 ~~2009,~~2010, our capital expenditures attributable to compliance with environmental regulations were ~~$9.1~~$16.7 million, and are currently estimated to be approximately ~~$12.0~~$3.4 million for ~~2010.~~2011. The ~~estimates~~estimate for ~~2010~~2011 does not include amounts related to capital investments at our facilities that management has deemed to be strategic investments rather than expenditures relating to environmental regulatory compliance.

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 products. In December 2007, Congress enacted the Energy Independence and Security Act of 2007, 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, among other steps.~~vehicles. These statutory mandates 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.

The Comprehensive Environmental Response, Compensation and Liability Act, referred to as CERCLA and also known as Superfund, and analogous or more stringent state laws, ~~imposes~~impose 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 ~~have been operated by~~from third parties, ~~whose~~and we did not control those third parties’ treatment and disposal or release of hydrocarbons or other wastes was not under our control. 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 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.

~~Remediation~~While remediation of subsurface contamination is in process at ~~many~~several of our ~~facilities. Based~~facilities, based on current ~~investigative and remedial activities,~~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.

The Pipeline Inspection, Protection, Enforcement, and Safety Act of 2006 (PIPES Act) became effective in December 2006. The PIPES Act included requirements to strengthen damage prevention measures designed to protect pipelines from excavation damage, eliminate an exemption from regulation for certain low-stress hazardous liquid pipelines, and require pipeline operators to manage human factors in pipeline control centers, including controller fatigue. While implementation of the PIPES Act ~~imposed~~is imposing additional operating requirements on pipeline operators, we do not believe that the costs of compliance with the ~~Pipes~~PIPES Act will have a material effect on our financial condition or results of operations.

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.

In addition, the amount of cash that we will have available for distribution will depend on other factors, including:

Reduced demand for refined products could affect our results of operations and ability to make 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.

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 ~~either~~ a customer’s failure to renew a lease, or 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.~~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:

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. In December 2008, OPEC, which includes Venezuela, agreed to decrease production by 2.2 million barrels of crude oil per day and PDVSA reduced contractual deliveries by two 300,000 barrel Boscán cargoes in February 2009 and one in March 2009. These production decreases have not had a material impact on our financial results. Additional 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 ~~further~~ 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. ~~While we found satisfactory replacement crudes for the February and March 2009 cuts, it~~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.

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

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 and intermediate product refining margins.

A large portion of our earnings from our asphalt operations are affected by the relationship, or margin, between asphalt and other intermediate 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 and other intermediate 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, ~~U.S.~~the United States relationships with foreign governments, political affairs and the extent of governmental regulation.

The operating results for our asphalt operations are seasonal and generally lower in the first and fourth quarters of the year.

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 ~~on demand~~ 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.

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

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:

As of December 31, ~~2009,~~2010, our consolidated debt was ~~$1.8~~$2.1 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. Fitch, Moody’s and Standard & Poor’s have assigned NuStar Logistics and NuPOP a stable outlook. 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 ~~further~~ 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.

event of default under any of our debt agreements, we would be prohibited from making cash distributions to our unitholders.

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, ~~2009,~~2010, we had approximately ~~$1.8~~$2.1 billion of consolidated debt, of which $1.0 billion was at fixed interest rates and ~~$0.8~~$1.1 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.

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 ~~U.S.~~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 ~~U.S.~~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 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.

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 ~~from~~by the seller is not available, it could adversely affect our financial position and results of operations.

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.

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 1513 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.

system’s cost of service, a shipper may obtain reparations for damages sustained during the two years prior to the filing of a complaint.

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 ~~U.S.~~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.

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

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, ~~2009,~~2010, our power costs equaled approximately ~~$48.1~~$52.1 million, or ~~10%~~11% of our operating expenses for the year. In addition, ~~$17.7~~$17.6 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.

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, ~~2009,~~2010, an aggregate ~~16.7%~~15.6% 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 ~~the~~our unitholders. These conflicts include, among others, the following situations:

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.

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 in will reduce the cash available for distribution to our unitholders.

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.

The sale or exchange of 50% or more of our capital and profits interests, within a ~~12-month~~twelve-month period, will result in the termination of our partnership for federal income tax purposes.

Tax gain or loss on the disposition of our units could be different than expected.

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-U.S.~~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-U.S.~~non-United States persons will be reduced by withholding taxes at the highest applicable effective tax rate, and ~~non-U.S.~~non-United States persons will be required to file ~~U.S.~~United States federal income tax returns and pay tax on their share of our taxable income.

Unitholders will likely be subject to state and local taxes and return filing requirements as a result of investing in our 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 ~~methods,~~ 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.

In 1997, Grace Energy Corporation (Grace Energy) sued subsidiaries of Kaneb ~~Pipe Line~~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.

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 ~~U.S.~~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 are currently in settlement discussions with other potentially responsible parties and the DOJ, and a change in our estimate of this liability may occur in the near term. However, any settlement agreement that is reached must be approved by multiple parties and requires the approval of the bankruptcy court and the federal district court. We cannot currently estimate when or if a settlement will be finalized.

In August 2008, Eres N.V. (Eres) forwarded a demand for arbitration to CITGO Asphalt Refining Company (CARCO), CITGO Petroleum Corporation (CITGO), NuStar Asphalt Refining, LLC (NuStar Asphalt) and NuStar Marketing LLC (NuStar Marketing, and together with CARCO, CITGO and NuStar Asphalt, the Defendants) contending that the Defendants are in breach of a tanker voyage charter party agreement, dated November 2004, between Eres and CARCO (the Charter Agreement). The Charter Agreement provides for CARCO’s use of Eres’ vessels for the shipment of asphalt. Eres contends that NuStar Asphalt and/or NuStar Marketing (together, the NuStar Entities) assumed the Charter Agreement when NuStar Asphalt purchased the CARCO assets, and that the Defendants have failed to perform under the Charter Agreement since January 1, 2008. Eres ~~seeks to compel~~has valued its damages for the ~~Defendants to arbitrate a~~alleged breach of contract claim ~~in which Eres values its damages~~ at approximately $78.1 million. ~~CITGO/CARCO also contend that~~Pursuant to a May 2010 ruling by the NuStar Entities assumed the Eres contract and they have demanded that the NuStar Entities defend and indemnify them against Eres’ claims. Eres’ motion to compel arbitration and CITGO/CARCO’s indemnity claims are currently pending in the U.S.United States District Court for the Southern District of ~~Texas.~~Texas, the NuStar Entities were found to have assumed the Charter Agreement from CARCO and to be obligated to defend and indemnify CITGO and CARCO against Eres’ claims. The Defendants were ordered to proceed with arbitration. We intend to vigorously defend against ~~these claims.~~Eres’ claims in arbitration.

With respect to the environmental ~~proceedings~~proceeding listed below, if ~~any one or more of them were~~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 any of ~~these proceedings~~the proceeding or whether such ultimate outcome may have a material effect on our consolidated financial position. We ~~report these proceedings~~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, in September 2008, the Illinois State Attorney General’s Office proposed penalties totaling $240,000 related to a leak at a storage terminal in Chillicothe, Illinois that we previously owned through a joint venture with Center Oil Company until we sold our interest in October 2006. The leak was originally discovered and reported to the Illinois Emergency Management Agency (IEMA) in 2002. We are currently in settlement negotiations with IEMA to resolve this matter.

In February 2008, the DOJ advised us that the EPA has requested that the DOJ initiate a lawsuit against NuPOP for (a) failing to prepare adequate Facility Response Plans, as required by Section 311(j)(5) of the Clean Water Act, 33 U.S.C. §1321(j), for certain of our pipeline terminals located in Region VII, by August 30, 1994, and (b) maintaining Spill Prevention, Control and Countermeasure (SPCC) Plans at the terminal that deviate from the SPCC regulations, 40 C.F.R. §112.3. A Facility Response Plan is a plan for responding to a worst case discharge, and to a substantial threat of such a discharge, of oil or hazardous substances. The SPCC rule requires specific facilities to prepare, amend and implement plans to prevent, prepare and respond to oil discharges to navigable waters and adjoining shorelines. We are currently in settlement negotiations with the DOJ to resolve these matters.

~~In addition,~~ 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 80 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 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.

In September 2009, an administrative complaint was filed by the EPA in Region III against NuStar Terminals Operations Partnership, L.P. (NTOP) and NuStar Terminals Services, Inc. (NTS). The administrative complaint alleges the certain violations occurred at NTOP’s Baltimore, Maryland terminal facility. The alleged violations include failure to comply with certain discharge limitations and certain monitoring and reporting obligations, as required by Section 301 of the Clean Water Act, 33 U.S.C. § 1311. The administrative complaint further alleges that NTOP and NTS violated certain provisions of the Code of Maryland Regulations (COMAR), which the EPA is entitled to enforce on behalf of the State of Maryland pursuant to Section 3008(a) of the Resource Conservation and Recovery Act, 42 U.S.C. § 6928(a). The total civil penalty sought by the EPA is $199,400. We have agreed to mediate this dispute.

No matters were submitted to a vote of the unitholders, through solicitation of proxies or otherwise, during the fourth quarter of the year ended December 31, ~~2009~~2010.

Our common units are listed and traded on the New York Stock Exchange under the symbol “NS.” At the close of business on February ~~5, 2010,~~8, 2011, we had ~~792~~737 holders of record of our common units. The high and low sales prices (composite transactions) by quarter for the years ended December 31, ~~2009~~2010 and ~~2008~~2009 were as follows:


	Price Range of Common Unit				Price Range of Common Unit
	High		Low		High	Low
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
Year 2009
4th Quarter	$	57.34	$	50.54	$57.34	$50.54
3rd Quarter		57.20		50.51	57.20	50.51
2nd Quarter		57.68		45.51	57.68	45.51
1st Quarter		50.88		40.45	50.88	40.45
Year 2008
4th Quarter	$	46.89	$	27.00
3rd Quarter		50.45		40.00
2nd Quarter		54.90		47.00
1st Quarter		57.15		47.76

The cash distributions applicable to each of the quarters in the years ended December 31, ~~2009~~2010 and ~~2008~~2009 were as follows:

Record Date

Payment Date

Amount
Per Unit

Record Date

Payment Date

Amount
Per Unit

Year 2010

4th Quarter

February 8, 2011

February 14, 2011

1.0750

3rd Quarter

November 1, 2010

November 5, 2010

1.0750

2nd Quarter

August 6, 2010

August 13, 2010

1.0650

1st Quarter

May 7, 2010

May 14, 2010

1.0650

Year 2009

4th Quarter

February 5, 2010

February 12, 2010

1.0650

February 5, 2010

February 12, 2010

1.0650

3rd Quarter

November 5, 2009

November 12, 2009

1.0650

November 5, 2009

November 12, 2009

1.0650

2nd Quarter

August 6, 2009

August 13, 2009

1.0575

August 6, 2009

August 13, 2009

1.0575

1st Quarter

May 8, 2009

May 15, 2009

1.0575

May 8, 2009

May 15, 2009

1.0575

Year 2008

4th Quarter

February 5, 2009

February 12, 2009

1.0575

3rd Quarter

November 5, 2008

November 12, 2008

1.0575

2nd Quarter

August 6, 2008

August 13, 2008

0.9850

1st Quarter

May 7, 2008

May 14, 2008

0.9850

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:

Our general partner’s incentive distributions for the years ended December 31, 2010 and 2009 ~~and 2008~~ totaled ~~$28.7~~$33.3 million and ~~$25.3~~$28.7 million, respectively. The general partner’s share of our distributions for the years ended December 31, 2010 and 2009 was 12.7% and ~~2008 was~~ 12.6% ~~and 12.0%~~, respectively, due to the impact of the incentive distributions.

The following table contains selected financial data derived from our audited financial statements.


	Year Ended December 31,										Year Ended December 31,
	2009		2008 (a)		2007		2006		2005		2010		2009		2008 (a)		2007		2006
	(Thousands of Dollars, Except Per Unit Data)										(Thousands of Dollars, Except Per Unit Data)

Statement of Income Data:
Revenues	$	3,855,871	$	4,828,770	$	1,475,014	$	1,137,261	$	659,557	$	4,403,061	$	3,855,871	$	4,828,770	$	1,475,014	$	1,137,261
Operating income		273,316		310,073		192,599		212,899		152,952		302,557		273,316		310,073		192,599		212,899
Income from continuing operations		224,875		254,018		150,298		149,906		107,675		238,970		224,875		254,018		150,298		149,906
Income from continuing operations per unit applicable to limited partners (b)		3.47		4.22		2.73		2.82		2.76		3.19		3.47		4.22		2.73		2.82
Cash distributions per unit applicable to limited partners		4.245		4.085		3.835		3.600		3.365		4.280		4.245		4.085		3.835		3.600

	December 31,										December 31,
	2009		2008 (a)		2007		2006		2005		2010		2009		2008 (a)		2007		2006
	(Thousands of Dollars)										(Thousands of Dollars)

Balance Sheet Data:
Property, plant and equipment, net	$	3,028,196	$	2,941,824	$	2,492,086	$	2,345,135	$	2,160,213	$	3,187,457	$	3,028,196	$	2,941,824	$	2,492,086	$	2,345,135
Total assets		4,774,673		4,459,597		3,783,087		3,494,208		3,366,992		5,386,393		4,774,673		4,459,597		3,783,087		3,494,208
Long-term debt (less current portion)		1,828,993		1,872,015		1,445,626		1,353,720		1,169,659		2,136,248		1,828,993		1,872,015		1,445,626		1,353,720
Partners’ equity		2,484,968		2,206,997		1,994,832		1,875,681		1,900,779		2,702,700		2,484,968		2,206,997		1,994,832		1,875,681

ITEM 7.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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 asphalt refining and fuels marketing. 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, 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) ~~wholly~~ owns our general partner, Riverwalk Logistics, L.P., and owns ~~an 18.7%~~a 17.6% total interest in us as of December 31, ~~2009.~~2010. Our Management’s Discussion and Analysis of Financial Condition and Results of Operations is presented in ~~five~~six sections:

On May 21, 2010, we acquired the capital stock of Asphalt Holdings, Inc. for $53.3 million, including liabilities assumed (Asphalt Holdings Acquisition). The Asphalt Holdings Acquisition includes three storage terminals with 24 storage tanks and an aggregate 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 Asphalt Holdings, Inc. commencing on May 21, 2010.

On March 20, 2008, we acquired CITGO Asphalt Refining Company’s asphalt operations and assets (the East Coast Asphalt Operations), which included a 74,000 barrels per day asphalt refinery in Paulsboro, New Jersey, a 30,000 barrels per day asphalt refinery in Savannah, Georgia and three asphalt terminals in Paulsboro, New Jersey, Savannah, Georgia and Wilmington, North Carolina.

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 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 ~~terminals~~terminal and storage facilities in the United States, ~~the Netherland Antilles,~~ Canada, ~~Mexico,~~ the Netherlands, ~~and~~including St. Eustatius in the Caribbean, the United Kingdom and Mexico providing approximately ~~66.2~~80.4 million barrels of storage capacity. ~~We also own 60 crude oil and intermediate feedstock storage tanks and related assets that provide an aggregate 12.5 million barrels of storage capacity to refineries in California and Texas.~~

Asphalt and Fuels Marketing.Our asphalt and fuels marketing segment includes our asphalt refining operations and our fuels marketing operations. We refine crude oil to produce asphalt and certain other refined products from our asphalt operations. We own two asphalt refineries with a combined throughput capacity of 104,000 barrels per day and related terminal facilities providing storage capacity of 5.0 million barrels. Additionally, as part of our fuels marketing operations, we purchase gasoline and other refined petroleum products for resale. The results of operations for the asphalt and fuels marketing segment depend largely on the gross margin between our cost and the sales price 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 mitigate the effect of commodity price fluctuations. 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. 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.

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 of the products we market fluctuates seasonally. For example, demand for gasoline and asphalt is typically higher in the summer months than 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. In addition to purchasing inventory for immediate resale, we have and expect to continue to employ a strategy of purchasing inventory during times of lower demand and lower prices and storing that inventory until it can be sold at higher ~~prices. We expect that our overall level of~~prices, which can cause the working capital ~~will continue to increase to support the operations of the asphalt and fuels marketing segment. Additionally, the level of working capital employed by~~necessary for the asphalt and fuels marketing segment ~~will likely fluctuate seasonally.~~to fluctuate. The absolute increase 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.

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 last year.

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:

Operating expenses increased $18.4 million for the year ended December 31, 2010, compared to the year ended December 31, 2009, primarily due to:

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.

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:

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, 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.

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.

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 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.

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.

Net income decreased $29.1 million for the year ended December 31, 2009, compared to the year ended December 31, 2008, primarily due to an increase in general and administrative expenses and a decrease in segment operating income. This was partially offset by a decrease in interest expense.

Segment operating income decreased $17.1 million for the year ended December 31, 2009, compared to the year ended December 31, 2008, primarily due to a $51.9 million decrease in operating income for the asphalt and fuels marketing segment, which was mainly due to higher operating expenses associated with our asphalt operations. The decrease in operating income from our asphalt and fuels marketing segment was partially offset by increased operating income from our storage and transportation segments.

Throughputs decreased 75,430 barrels per day for the year ended December 31, 2009, compared to the year ended December 31, 2008, mainly due to the conversion of some throughput-based contracts to lease-based contracts in January 2009. Throughputs for these terminals are no longer reported, and revenues associated with these terminals are reported under storage lease revenues. In addition, throughputs decreased due to turnarounds in the first quarter of 2009 at a refinery served by our Texas City crude oil storage tanks and a turnaround at the McKee refinery in May 2009.

Total revenues increased by $33.5 million for the year ended December 31, 2009, compared to the year ended December 31, 2008, primarily due to higher storage revenues associated with:

These increases were partially offset by a decrease of $3.5 million due to the sales of our Westwego, Louisiana, Reno, Nevada and Milwaukee, Wisconsin terminals in December 2008.

Depreciation and amortization expense increased $4.2 million for the year ended December 31, 2009, compared to the year ended December 31, 2008, primarily due to the completion of various terminal expansion projects.

Throughputs decreased 140,131 barrels per day and revenues decreased $15.7 million for the year ended December 31, 2009, compared to the year ended December 31, 2008, primarily due to:

The tariff increase of 7.6% that became effective July 1, 2009 partially offset declines in revenues from the lower throughputs.

Operating expenses for this segment decreased $20.3 million for the year ended December 31, 2009, compared to the year ended December 31, 2008, primarily due to:

Sales and cost of product sales decreased $977.6 million and $981.3 million, respectively, resulting in an increase in total gross margin of $3.7 million for the year ended December 31, 2009, compared to the year ended December 31, 2008 due to the following:

Operating expenses increased by $50.8 million for the year ended December 31, 2009, compared to the year ended December 31, 2008, primarily due to:

Depreciation and amortization expense increased $4.7 million for the year ended December 31, 2009, compared to the year ended December 31, 2008, due to our acquisition of the East Coast Asphalt Operations in March 2008.

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 2009, the asphalt and fuels marketing segment utilized more terminal capacity from our storage segment, resulting in higher revenue and operating expense eliminations.

General and administrative expenses increased by $18.3 million for the year ended December 31, 2009, compared to the year ended December 31, 2008. This increase was primarily due to compensation expense associated with our long-term incentive plans resulting from an increase in our unit price during the year ended December 31, 2009 compared to a decrease in our unit price during the year ended December 31, 2008. In addition, general and administrative expenses increased due to higher external legal costs and other professional fees.

Interest expense, net decreased by $11.4 million for the year ended December 31, 2009, compared to the year ended December 31, 2008, primarily due to decreases in interest rates, including the variable interest rate paid on our interest rate swaps. These decreases in interest expense were partially offset by increased interest expense from the issuance of $350.0 million of 7.65% senior notes in April 2008 and lower capitalized interest.


	Year Ended December 31,					Year Ended December 31,
	2009			2008		2009			2008
	(Thousands of Dollars)					(Thousands of Dollars)

Gain from sale or disposition of assets	$	21,320		$	26,456	$	21,320		$	26,456
Gain from insurance proceeds		9,382			3,504
Gain from insurance recoveries							9,382			3,504
Foreign exchange (losses) gains		(5,118	)		5,888		(5,118	)		5,888
Other		6,275			1,891		6,275			1,891

Other income, net	$	31,859		$	37,739	$	31,859		$	37,739

See Note 18 of Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplemental Data” for further information regarding the other components of other income.

Net income increased $103.7 million for the year ended December 31, 2008, compared to the year ended December 31, 2007, primarily due to an increase in segment operating income, partially offset by increases in interest expense, net and general and administrative expenses. Segment operating income increased $127.9 million for the year ended December 31, 2008, compared to the year ended December 31, 2007, primarily due to a $91.4 million increase in operating income for the asphalt and fuels marketing segment, mainly resulting from robust sales volumes and strong gross margins from our East Coast Asphalt Operations during the third quarter. Operating income increased for our storage and transportation segments $26.4 million and $8.6 million, respectively, primarily due to increased throughputs and earnings in 2008 compared to 2007 due to a fire at the Valero Energy McKee refinery in February 2007, which shut down the refinery until mid-April 2007 and negatively impacted our transportation and storage segments during the year ended December 31, 2007. Operating income for the storage segment also improved due to the leasing of additional storage capacity to customers from completed tank expansion projects.

However, our earnings were negatively impacted by a hedging loss of approximately $61.0 million in the second quarter of 2008. Concurrent with the acquisition of the East Coast Asphalt Operations, we entered into certain derivative contracts intended to hedge our exposure to price fluctuations for approximately 30% of the inventory acquired. We entered into these contracts to protect the value of our acquired inventories in the case crude oil prices declined. However, the price of crude oil increased dramatically from the date we entered into the hedges until May 2008, at which time we terminated the contracts prior to their expiration. For the remainder of 2008, we did not have any derivative contracts related to inventories of the East Coast Asphalt Operations, and we managed our commodity risk by managing those physical inventory volumes. We monitor our exposure to commodity prices related to the inventories of our asphalt operations.

Throughputs decreased 57,733 barrels per day and throughput revenues decreased $5.5 million for the year ended December 31, 2008, compared to the year ended December 31, 2007, primarily due to a change in our Corpus Christi (North Beach) crude oil storage tank agreement from a throughput fee agreement to a storage lease agreement effective January 1, 2008. Partially offsetting these decreases were higher throughputs and revenues at terminals serving the McKee refinery mainly due to lower throughputs and revenues in 2007 resulting from the impact of the Valero Energy McKee refinery fire, which shut down the refinery until mid-April 2007.

~~Storage lease revenues increased by $48.9 million for the year ended December 31, 2008, compared to the year ended December 31, 2007, primarily due to:~~

~~Operating expenses increased $12.6 million for the year ended December 31, 2008, compared to the year ended December 31, 2007, primarily due to:~~

Depreciation and amortization expense increased $4.4 million for the year ended December 31, 2008, compared to the year ended December 31, 2007, primarily due to the completion of various terminal expansion projects.

Throughputs increased 9,584 barrels per day and revenues increased $21.0 million for the year ended December 31, 2008, compared to the year ended December 31, 2007, primarily due to increased throughputs and revenues of $21.5 million at pipelines serving the McKee refinery. 2007 revenues were adversely affected by the impact of the Valero Energy McKee refinery fire. 2008 revenues also increased due to higher tariffs on all of the refined product and crude oil pipelines as the annual index adjustment was effective July 1, 2008.

These increases were partially offset by decreased revenues and throughputs on our Houston pipeline in 2008 as one of our customers began to export more product rather than shipping inland through our pipeline. In addition, the Wynnewood pipeline experienced lower revenues due to decreased long-haul deliveries in 2008. Also, throughputs decreased mainly due to a turnaround, crude supply interruptions and other operational issues at a refinery served by the Wynnewood pipeline. Reduced demand in 2008 resulting from a prolonged winter and flooding in the Midwest and higher commodity prices, along with record throughputs in 2007, contributed to lower throughputs on our East Pipeline.

Operating expenses for this segment increased $11.6 million for the year ended December 31, 2008, compared to the year ended December 31, 2007, primarily due to increased power costs as a result of the increase in throughputs on pipelines serving the McKee refinery, higher natural gas prices and the impact of significantly lower product prices on product imbalances on the East Pipeline. Also, salaries and wages and internal overhead expense increased, both due primarily to increased headcount. These increases were partially offset by decreased maintenance and environmental expenses.

~~Sales and cost of product sales increased $3,309.8 million and $3,130.7 million, respectively, during the year ended December 31, 2008, compared to the year ended December 31, 2007, mainly due to:~~

~~Operating expenses increased by $73.4 million for the year ended December 31, 2008, compared to the year ended December 31, 2007, primarily due to:~~

Depreciation and amortization expense increased $14.3 million for the year ended December 31, 2008, compared to the year ended December 31, 2007, due to our acquisition of the East Coast Asphalt Operations in March 2008.

General and administrative expenses increased by $8.5 million for the year ended December 31, 2008, compared to the year ended December 31, 2007, primarily due to increased salary and wages resulting from higher headcount and additional costs required for the Partnership’s growth and separation from Valero Energy. In addition, compensation expense associated with unit options and restricted units increased as a result of the increase in the number of awards outstanding, partially offset by a decrease in our unit price.

Interest expense, net increased by $14.3 million for the year ended December 31, 2008, compared to the year ended December 31, 2007, primarily due to an increase in our outstanding debt balance resulting from our issuance of $350.0 million of 7.65% senior notes in April 2008 to finance the acquisition of the East Coast Asphalt Operations and increased borrowings under our revolving credit agreement to fund a portion of our capital expenditures and working capital requirements. This was partially offset by a decrease in interest rates, including a decrease in the variable interest rate paid on our interest rate swaps, which hedge a portion of our fixed-rate senior notes, and our revolving credit facility.

~~See Note 18 of Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplemental Data” for further information regarding the components of other income.~~

Overall, we expect our ~~results~~operating income for 2011 to be higher than 2010 due mainly to ~~improve compared to 2009. However, the~~increases in our storage segment. Our outlook ~~on our operations~~ could change depending on, among other things, the pace of the economic recovery, refinery maintenance schedules, and other ~~economic conditions.~~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.

For 2011, we expect our earnings for the storage segment to increase compared to 2010. We expect to benefit from a full year’s contribution of terminal expansion projects completed in 2010 and from new internal growth projects, a portion of which should be completed in 2011. In addition, we expect to benefit from our Turkey terminal acquisition, which closed in February of 2011.

We expect the transportation segment ~~results~~earnings for ~~2010~~2011 to be ~~comparable to slightly~~ lower than ~~2009.~~2010. Throughputs for ~~2010~~2011 are forecasted to ~~increase slightly~~decrease compared to ~~2009, barring any major unplanned~~2010 mainly due to planned turnaround activity ~~and excluding the impact from the sale of pipelines in 2009.~~at refineries served by our pipelines. However, ~~we expect~~ the tariffs on our pipelines regulated by the FERC, which adjust annually based upon changes in the producer price index, ~~to decline slightly in~~should increase effective July 1, 2011, when the adjustment takes effect. Even with the effect of the tariff rate decline, our overall tariff rate for 2010 should be slightly higher than 2009. If throughputs increase or if the cost of natural gas increases, we would expect our power expenses to increase in 2010 compared to 2009. The pace of the economic recovery, changes to refinery maintenance schedules, or other factors that impact overall demand for products we transport could affect our throughputs and revenues.

For 2010, we expect our earnings for the storage segment to increase compared to 2009. We expect to benefit from a full year’s contribution of terminal expansion projects completed in 2009 and from new internal growth projects, a portion of which should be completed in 2010. In addition, we expect to benefit in 2011 from ~~renewal rates~~the completion of a pipeline expansion project that ~~increased significantly in 2009.~~will serve Eagle Ford Shale production.

~~The earnings of~~We expect the asphalt and fuels marketing segment ~~largely depend upon~~results to increase for the ~~margin earned by~~full year 2011 compared to 2010. Our fuels marketing operations should benefit from a full year of heavy fuel and bunker fuel sales in new markets we entered into in 2010. Also, we expect the full year results from our asphalt ~~operations.~~operations to be slightly better than 2010 due to increases in both public and private demand driven by an improving economy. Our ~~margin results from~~outlook could change if the ~~difference between the sales prices of our products and the purchase prices of our raw materials, principally crude oil. The~~ prices of crude oil and the products produced by our asphalt operations fluctuate in response to ~~many~~ factors such as changes in supply, demand, seasonality, market uncertainties and other factors.

We expect our results for 2010 to improve compared to 2009. Specifically, we expect asphalt supply levels to remain below recent averages due to lower U.S. refinery utilization rates, resulting in lower refinery production, including asphalt, and the continued lack of asphalt imports. Assuming the spending associated with the American Recovery and Revitalization Act and other federal highway and public transportation programs increases in 2010 over 2009 levels, we would expect an increase in demand for asphalt. If supply levels remain lower than historical averages and demand increases, it should result in a higher margin per barrel and increased sales volumes in our asphalt operations.

Our primary cash requirements are for distributions to partners, working capital requirements, including inventory purchases, debt service, capital expenditures, acquisitions and normal operating expenses. On an annual basis, we attempt to fund our operating expenses, interest expense, reliability capital expenditures and distribution requirements with cash generated from our operations. If we do not generate sufficient cash from operations to meet those requirements, we utilize available borrowing capacity under our revolving credit ~~facility~~agreement and, to the extent necessary, funds raised through equity or debt offerings under our ~~$3.0 billion~~ shelf registration statement. Additionally, we typically fund our strategic capital expenditures from external sources, primarily borrowings under our revolving credit agreement or funds ~~available under our $3.0 billion shelf registration statement.~~raised through equity or debt offerings. However, our ability to raise funds by issuing debt or equity depends on many factors beyond our control. The volatility of the capital and credit markets could restrict our ability to issue debt or equity or may increase our cost of capital beyond rates acceptable to us.

Cash Flows for the Years Ended December 31, 2010, 2009 ~~2008~~ and ~~2007~~2008

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


	Year Ended December 31,									Year Ended December 31,
	2009			2008			2007			2010				2009			2008
	(Thousands of Dollars)										(Thousands of Dollars)
Net cash provided by (used in):
Operating activities	$	180,582		$	485,181		$	222,672		$		362,500		$	180,582		$	485,181
Investing activities		(167,705	)		(956,517	)		(238,396	)			(300,215	)		(167,705	)		(956,517	)
Financing activities		(2,672	)		440,063			37,060				56,266			(2,672	)		440,063
Effect of foreign exchange rate changes on cash		6,426			(13,190	)		(336	)			564			6,426			(13,190	)

Net increase (decrease) in cash and cash equivalents	$	16,631		$	(44,463	)	$	21,000		$		119,115		$	16,631		$	(44,463	)

Net cash provided by operating activities for the year ended December 31, 2010 was $362.5 million, compared to $180.6 million for the year ended December 31, 2009, primarily due to higher investments in working capital in 2009. Working capital increased by $6.9 million in 2010, compared to $142.9 million in 2009. Within working capital, our inventory

balances increased by $26.6 million in 2010 compared to an increase of $157.4 million in 2009. Net cash provided by operating activities also increased due to higher net income for the year ended December 31, 2010, compared to the year ended December 31, 2009. Net income for the year ended December 31, 2009 included the non-cash gain on the sale of the Ardmore-Wynnewood and Trans-Texas pipelines.

For the year ended December 31, 2010, net cash provided by operating activities was used to fund distributions to unitholders and the general partner in the aggregate amount of $305.2 million and reliability capital expenditures. The net proceeds of $245.2 million from our issuance of common units and the net proceeds of $445.4 million from the issuance of senior notes were used to reduce outstanding borrowings under our revolving credit agreement, fund the Asphalt Holdings Acquisition and fund our strategic capital expenditures. The capital expenditures were primarily related to projects at our St. Eustatius, St. James and Texas City terminals and our corporate office. Cash flows from investing activities also include insurance proceeds of $13.5 million related to damages caused by Hurricane Ike in the third quarter of 2008 primarily at our Texas City terminal.

For the year ended December 31, 2009, we generated cash from operations of $180.6 million compared to $485.2 million in the prior year. The decline resulted primarily from lower net income of $224.9 million in 2009 compared to $254.0 million in 2008 and higher investments in working capital in 2009 compared to 2008. In 2009, we increased our working capital by ~~$152.3~~$142.9 million compared to a decrease of $133.0 million in 2008. Within working capital, our inventory balances increased by ~~$156.2~~$157.4 million in 2009 compared to a decrease of ~~$194.0~~$192.2 million in 2008. Because of our significant investment in working capital and lower earnings in 2009, our cash generated from operations did not exceed our cash requirements for reliability capital expenditures and distributions. As a result, we utilized borrowings under our revolving credit agreement as well as the proceeds from our equity offering to fund that shortfall and our strategic capital expenditures. Additionally, we received $41.1 million from the sale of assets and insurance proceeds, which is included in cash flows from investing activities.

Net cash provided by operating activities for the year ended December 31, 2008 was $485.2 million compared to $222.7 million for the year ended December 31, 2007. The increase in cash generated from operating activities is primarily due to higher net income of $254.0 million for the year ended December 31, 2008 compared to net income of $150.3 million for the year ended December 31, 2007. Also, working capital decreased $133.0 million in 2008 providing an increase in cash, whereas working capital increased $21.3 million in 2007. Within working capital, inventory decreased $194.0 million for the year ended December 31, 2008, compared to an increase of $71.5 million in 2007. Cash flows from operations for the year ended December 31, 2008 also include proceeds from business interruption insurance of $3.5 million compared to $12.5 million for the year ended December 31, 2007.

~~Net cash provided by operating activities for the year ended December 31, 2008 was~~ used to fund distributions to unitholders and the general partner in the aggregate amount of $241.9 million. The proceeds from long-term and short-term debt borrowings, net of repayments, our issuance of common units and senior notes, combined with cash on hand, were used to fund the acquisition of the East Coast Asphalt Operations and our strategic capital expenditures primarily related to various terminal expansion projects.

Net cash provided by operating activities for the year ended December 31, 2007 was used to fund distributions to unitholders and the general partner in the aggregate amount of $197.3 million. The proceeds from long-term debt borrowings, net of repayments, were used to fund a portion of our capital expenditures, primarily related to various terminal expansion projects. Additionally, we issued 2,600,000 common units for proceeds of $146.1 million, including a contribution from our general partner, which were used to repay borrowing on our long-term debt.

~~The lenders under the~~NuStar Logistics is party to a $1.2 billion five-year revolving credit agreement (the 2007 Revolving Credit Agreement include Lehman Brothers Bank, FSB (LB Bank), a subsidiary of Lehman Brothers Holdings Inc. (Lehman), which filed for bankruptcy protection in October 2008. LB Bank’s participation in the 2007 Revolving Credit Agreement totaled $42.5 million, of which $5.0 million remained outstanding as of December 31, 2009. As a result of Lehman’s bankruptcy filing in October 2008, LB Bank has elected not to fund its pro rata share of any future borrowings we request, which reduced the total commitment under the 2007 Revolving Credit Agreement to approximately $1.2 billion. Excluding LB Bank’s participation, weAgreement). We had ~~$624.6~~$724.9 million available for borrowing under the 2007 Revolving Credit Agreement as of December 31, 2009. If other lenders under the 2007 Revolving Credit Agreement file for bankruptcy or experience severe financial hardship due to disruptions and steep declines in the global financial markets and tightening credit supply, they may not honor their pro rata share of our borrowing requests.

2010. The 2007 Revolving Credit Agreement requires that we maintain certain financial ratios and includes other restrictive covenants, including a prohibition on distributions if any defaults, as defined in the agreements, exist or would result from the distribution. The 2007 Revolving Credit Agreement requires us to maintain, as of the end of each four consecutive fiscal quarters, 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, which may restrict the amount we can borrow without exceeding the maximum allowed limit to an amount less than the total amount available for borrowing. As of December 31, ~~2009,~~2010, the consolidated debt coverage ratio was ~~4.1x.~~4.6x.

The 2007 Revolving Credit Agreement matures in December 2012, and we do not have any other significant debt maturing until ~~2012 and 2013, when four of our five senior notes become due.~~2012.

In 2008 and 2010, the Parish of St. James, where our St. James, Louisiana, terminal is located, issued Revenue Bonds (NuStar Logistics, L.P. Project) Series 2008, Series 2010, Series 2010A and Series 2010B associated with our St. James terminal expansion pursuant to the Gulf Opportunity Zone Act of 2005. The interest rate on these bonds is based on a weekly tax-exempt bond market interest rate, and interest is paid monthly. Following the issuance, the proceeds were deposited with a trustee and will be disbursed to us upon our request for reimbursement of expenditures related to our St. James terminal expansion. The amount remaining in trust is included in “Other long-term assets, net,” and the amount of bonds issued is included in “Long-term debt, less current portion” in our consolidated balance sheets.

interest and principal on the bonds. These letters of credit rank equally with existing senior unsecured indebtedness of NuStar Logistics.

The following table summarizes Gulf Opportunity Zone Revenue Bonds outstanding as of December 31, 2010:

~~Our~~On May 13, 2010, the Securities and Exchange Commission declared effective our shelf registration statement on Form S-3, which permits us to offer and sell various types of securities, including NuStar Energy ~~L.P.~~ common units and debt securities of NuStar Logistics and NuPOP ~~having an aggregate value of up to $3.0 billion~~ (the ~~2007~~2010 Shelf Registration Statement). We filed the ~~2007~~2010 Shelf Registration Statement to gain additional flexibility in accessing capital markets for, among other things, the repayment of outstanding indebtedness, working capital, capital expenditures and acquisitions. As of December 31, 2009, we have issued approximately $1.0 billion underreplace our ~~$3.0 billion~~three-year shelf registration ~~statement.~~statement, which was effective May 18, 2007.

If the capital markets become more volatile, ~~as was seen in recent years,~~ our access to the capital markets may be limited, or we could face increased ~~costs when accessing the capital markets.~~costs. In addition, it is possible that our ability to access the capital ~~and credit~~ markets may be limited by these or other factors at a time when we would like or need to do so, which could have an impact on our ability to refinance maturing debt and/or react to changing economic and business conditions.

~~Equity Offering.~~NuStar Logistics’ 4.80% Senior Notes~~In November 2009,~~

On August 12, 2010, NuStar Logistics issued $450.0 million of 4.80% senior notes under our 2010 Shelf Registration Statement for net proceeds of $445.4 million. The net proceeds were used to reduce outstanding borrowings under our 2007 Revolving Credit Agreement. The interest on the 4.80% senior notes is payable semi-annually in arrears on March 1 and September 1 of each year beginning on March 1, 2011. The notes will mature on September 1, 2020.

On May 19, 2010, we issued ~~5,750,000~~4,400,000 common units representing limited partner interests at a price of ~~$52.45~~$56.55 per unit. We ~~received~~used the net proceeds from this offering of ~~$288.8~~$245.2 million, ~~and~~including a contribution of ~~$6.2~~$5.1 million from our general partner to maintain its 2% general partner ~~interest. The net proceeds were used~~interest, mainly to reduce ~~the~~ outstanding ~~principal balance~~borrowings under our 2007 Revolving Credit ~~Agreement.~~Agreement and for the acquisition of Asphalt Holdings, Inc.

Our operations are capital intensive, requiring significant investments to maintain, upgrade or enhance existing operations and to comply with environmental and safety laws and regulations. Our capital expenditures consist of:

During the year ended December 31, ~~2009, we incurred~~2010, our reliability capital expenditures ~~of $45.0~~totaled $54.0 million, including $50.6 million primarily related to maintenance upgrade projects at our terminals and ~~pipelines.~~refineries. Strategic capital expenditures for the year ended December 31, ~~2009 of $163.6~~2010 totaled $219.3 million and were primarily related to ~~a pipeline expansion on the southern end of the East Pipeline and~~ projects at our St. Eustatius, St. James and Texas City ~~terminal.~~terminals and our corporate office.

For ~~2010,~~2011, we expect to incur approximately ~~$375.0~~$380.0 to ~~$400.0~~$405.0 million of capital expenditures, including approximately ~~$55.0~~$50.0 to ~~$60.0~~$55.0 million for reliability capital projects and ~~$320.0~~$330.0 to ~~$340.0~~$350.0 million for strategic capital expenditures. We

continue to evaluate our capital budget and make changes as economic conditions warrant. Depending upon current economic conditions, our actual capital expenditures for ~~2010~~2011 may exceed or be lower than the budgeted amounts. We believe cash generated from operations, combined with other sources of liquidity previously described, will be sufficient to fund our capital expenditures in ~~2010,~~2011, and our internal growth projects can be accelerated or scaled back depending on the capital markets.

The operations of the asphalt and fuels marketing segment require us to invest substantial amounts in working capital. ~~For example,~~Our inventory balances can vary significantly due to production levels, demand for our products and the cost of crude oil. Within our asphalt operations, we typically employ a winterfill strategy that involves manufacturing and purchasing inventory at times when demand and prices are seasonally lower, and storing that inventory until it can be sold at higher prices. Our refined product inventory volumes may also fluctuate as a result of our strategy to take advantage of contango markets, which occur when future prices for products exceed current prices. At times when the market is in contango, we purchase inventory at low prices and store it until we can sell it at higher prices, which may require that we store inventory over an extended period of time.

In 2010, the amount of inventory increased slightly. Increases in inventory resulted from the expansion of our bunkering operations, increases in the price of crude oil and the timing of crude oil shipments. We sold a substantial amount of inventory acquired in 2009 as part of a contango strategy, which partially offset those increases.

In 2009, our inventory balances increased by $156.2 million due to higher volumes and higher average prices. Crude oil volumes increased substantially at December 31, 2009 over December 31, 2008 due to lower production in 2009. Additionally, the average cost of our crude oil inventory was significantly higher at December 31, 2009 compared to December 31, 2008 due to the collapse in crude oil prices in the fourth quarter of 2008. Our refined product inventory volumes at December 31, 2009 also increased over the prior year as a result of our strategy to take advantage of contango markets, whereby we purchase inventory at seasonally low prices and store it until we can sell it at seasonally higher prices. To take advantage of contango markets, we may store inventory over an extended period of time, as occurred in 2009. Additionally, the average cost of our refined product inventories at December 31, 2009 increased compared to the prior year due to the significant decline in refined product prices in the fourth quarter of 2008 associated with the decline in crude oil prices.

Higher inventory balances would typically also result in higher ~~amount~~amounts of accounts payable, ~~which would reduce~~offsetting the impact to working capital. However, with respect to our contango and asphalt winterfill strategies, which often involve storing inventory for an extended period, we typically pay for the ~~associated accounts payable~~inventory prior to selling ~~the inventory.~~it. Due to the potential for this discrepancy in timing between paying ~~our invoice~~for and selling our inventory, increases in our accounts payable will not always offset increases in our inventory balances within our working capital. As a result, the volume of inventory we maintain and the average cost of those inventories associated with our contango and asphalt winterfill strategies can significantly affect our working capital balance.

In 2008, we acquired the East Coast Asphalt Operations, which included approximately $327.3 million allocated to inventories included in the purchase. The purchase of the inventories included with the East Coast Asphalt Operations was considered part of the acquisition price and recorded in the Statement of Cash Flows as an investing activity. Therefore, our cash flows from operations in 2008 reflect a reduction in inventories despite the fact that our inventory balance at December 31, 2008 increased compared to December 31, 2007.

NuStar Energy’s partnership agreement, as amended, determines the amount and priority of cash distributions that our common unitholders and general partner may receive. The general partner receives a 2% distribution with respect to its general partner interest. The general partner is also entitled to incentive distributions if the amount we distribute with respect to any quarter exceeds $0.60 per unit. For a detailed discussion of the incentive distribution targets, please read Item 5. “Market for Registrant’s Common Units, Related Unitholder Matters and Issuer Purchases of Common Units.”

The following table reflects the allocation of total cash distributions to the general and limited partners applicable to the period in which the distributions are earned:


	Year Ended December 31,
	2010		2009		2008
	(Thousands of Dollars, Except Per Unit Data)

General partner interest	$	6,227	$	5,430	$	5,058
General partner incentive distribution		33,304		28,712		25,294

Total general partner distribution		39,531		34,142		30,352
Limited partners’ distribution		271,847		237,308		222,470

Total cash distributions	$	311,378	$	271,450	$	252,822


Cash distributions per unit applicable to limited partners	$	4.280	$	4.245	$	4.085

Actual distribution payments are made within 45 days after the end of each quarter as of a record date that is set after the end of each quarter.

In January ~~2010,~~2011, we declared a quarterly cash distribution of ~~$1.065~~$1.075 that was paid on February ~~12, 2010~~14, 2011 to unitholders of record on February ~~5, 2010.~~8, 2011. This distribution related to the fourth quarter of ~~2009~~2010 and totaled ~~$73.4~~$79.6 million, of which ~~$9.3~~$10.2 million represented ~~the~~our general partner’s ~~share of such distribution. The general partner’s distribution included a $7.8 million~~interest and incentive distribution.

Management believes that, as of December 31, 2010, we are in compliance with all ratios and covenants of both the 2007 Revolving Credit Agreement and the UK Term Loan, ~~as of December 31, 2009,~~ which ~~are~~has substantially the same covenants as the 2007 Revolving Credit Agreement. Our other long-term debt obligations do not contain any financial ~~covenants.~~covenants that are different than those contained in the 2007 Revolving Credit Agreement. However, a default under any of our debt instruments would be considered an event of default under all of our debt instruments. Please refer to Note 11 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for a more detailed discussion of our long-term debt agreements.

The following table reflects the outlook and ratings that have been assigned to the debt of our wholly owned subsidiaries as of December 31, ~~2009:~~2010:

We are a party to interest rate swap agreements to manage our exposure to changes in interest rates. ~~The~~We have fixed-to-floating interest rate swap agreements that have an aggregate notional amount of $167.5 million, of which $60.0 million is tied to the maturity of the 6.875% senior notes and $107.5 million is tied to the maturity of the 6.05% senior notes. Under the terms of the interest rate swap agreements, we will receive a fixed rate (6.875% and 6.05% for the $60.0 million and $107.5 million of interest rate swap agreements, respectively) and will pay a variable rate based on six month USD LIBOR plus a percentage that varies with each agreement. ~~As of December 31, 2009~~In September and ~~2008, the aggregate fair value of our interest rate swaps included in “Other long-term assets, net” in our consolidated balance sheets was $8.6 million and $15.3 million, respectively.~~

~~The~~October 2010, we entered into fixed-to-floating interest rate swap ~~contracts qualify for~~agreements with an aggregate notional amount of $450.0 million related to the ~~shortcut method~~4.80% senior notes issued on August 12, 2010. Under the terms of ~~accounting. As~~these interest rate swap agreements, we will receive a ~~result,~~fixed 4.80% and will pay a variable rate based on six month USD LIBOR plus a percentage that varies with each agreement.

In August and September 2010, we also entered into forward-starting interest rate swap agreements with an aggregate notional amount of $500.0 million related to forecasted probable debt issuances in 2012 and 2013. Under the terms of the swaps, we will pay a fixed rate and receive a rate based on three month USD LIBOR. We entered into the swaps in order to hedge the risk of changes in the ~~fair value of the swaps will completely offset the~~interest payments attributable to changes in the ~~fair value~~benchmark interest rate during the period from the effective date of the ~~underlying hedged~~swap to the issuance of the forecasted debt. ~~As of December 31, 2009 and 2008, the weighted average effective interest rate for the interest rate swaps was 2.3% and 3.0%, respectively.~~

~~Line of Credit~~The following table summarizes information about our forward-starting swaps:

~~As of December 31, 2009, we had one short-term line of credit with an uncommitted borrowing capacity of up to $20.0 million.~~

Please refer to Note 112 and Note 15 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for a more detailed discussion on our ~~line of credit.~~interest rate swaps.

The following table presents our long-term contractual obligations and commitments and the related payments due, in total and by period, as of December 31, ~~2009:~~2010:


	Payments Due by Period														Payments Due by Period
	2010		2011		2012		2013		2014		There- after		Total		2011		2012		2013		2014		2015		There- after		Total
	(Thousands of Dollars)														(Thousands of Dollars)

Long-term debt maturities	$	770	$	832	$	909,942	$	480,902	$	67	$	406,200	$	1,798,713	$	832	$	571,969	$	479,986	$	-	$	-	$	1,090,440	$	2,143,227
Interest payments		89,804		89,742		79,501		41,597		27,220		100,150		428,014		109,478		98,353		63,798		49,246		49,246		196,157		566,278
Operating leases		51,734		60,808		44,415		41,453		37,760		187,638		423,808		78,023		61,812		56,313		48,225		46,437		148,053		438,863
Purchase obligations:
Crude oil		1,943,668		1,943,668		1,943,668		1,943,668		1,943,670		485,917		10,204,259		2,260,432		2,541,480		2,541,480		2,541,480		565,108		-		10,449,980
Other purchase obligations		23,561		18,329		2,197		1,036		744		-		45,867		19,446		3,341		1,950		743		-		-		25,480

Long-term debt maturities in the table represent our scheduled future maturities of long-term debt principal for the periods indicated. The interest payments calculated for our variable-rate debt are based on the outstanding borrowings as of December 31, ~~2009~~2010 and the weighted-average interest rate paid for the year ended December 31, ~~2009.~~2010. The interest payments on our fixed-rate debt are based on the stated interest rates, the outstanding balances as of December 31, ~~2009~~2010 and interest payment dates.

Our operating leases consist primarily of leases for tugs and barges utilized at our St. Eustatius and Point Tupper facilities, leases related to our asphalt and fuels marketing segment for tugs and barges and storage capacity at third-party terminals and land leases at various terminal facilities.

A purchase obligation is an enforceable and legally binding agreement to purchase goods or services that specifies significant terms, including (i) fixed or minimum quantities to be purchased, (ii) fixed, minimum or variable price provisions, and (iii) the approximate timing of the transaction.

Our crude oil purchase obligations result mainly from a crude supply agreement (CSA) we entered into simultaneously with the acquisition of the East Coast Asphalt Operations. Under the CSA, we committed to purchase an annual average of 75,000 barrels per day of crude oil over a minimum seven-year period from ~~PDVSA.~~an affiliate of Petróleos de Venezuela S. A. (PDVSA), the national oil company of Venezuela. Our crude oil purchase obligations also include a crude purchase/sale agreement with Statoil Brasil Oleo E Gas Limitada that we entered into on November 17, 2010. Under this agreement, we committed to purchase an average of 10,000 barrels per day of crude oil over a three-year period beginning when we are able to process the crude oil at our Paulsboro refinery. For purposes of the table above, we used January 1, 2012 as the start date for this agreement. The value of ~~this commitment~~these two crude oil purchase obligations fluctuates according to a market-based pricing formula using published market indices, subject to adjustment based on the price of Mexican Maya crude. We estimated the ~~annual payments due under~~value of the ~~CSA~~crude oil purchase obligations based on market prices as of December 31, ~~2009.~~2010.

We are subject to extensive federal, state and local environmental and safety laws and regulations, including those relating to the discharge of materials into the environment, waste management, pollution prevention measures, pipeline integrity and operator qualifications, among others. Because more stringent environmental and safety laws and regulations are continuously being enacted or proposed, the level of future expenditures required for environmental, health and safety matters is expected to increase.

The balance of and changes in our accruals for environmental matters as of and for the years ended December 31, ~~2009~~2010 and ~~2008~~2009 are included in Note 12 of Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplemental Data.” We believe that we have adequately accrued for our environmental exposures.

We are subject to certain loss contingencies, the outcomes of which could have an adverse effect on our cash flows and results of operations, as further disclosed in Note 13 of the Notes to Consolidated Financial Statements.

Our operations are managed by the general partner of our general partner, NuStar GP, LLC. The employees of NuStar GP, LLC perform services for our U.S. operations. We reimburse NuStar GP, LLC for all costs related to its employees, other than costs associated with NuStar GP Holdings under the services agreement described below and in Note 16 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data.” We had a payable of ~~$10.6~~$10.3 million and ~~$3.4~~$10.6 million, as of December 31, ~~2009~~2010 and ~~2008,~~2009, respectively, with both amounts representing payroll, ~~and~~employee benefit plan ~~costs, net of payments made by us.~~expenses and unit-based compensation. We also had a long-term payable as of December 31, 2010 and 2009 of $10.1 million and ~~2008 of~~ $7.7 million, ~~and $6.6 million,~~ respectively, to NuStar GP, LLC related to amounts payable for retiree medical benefits and other post-employment benefits.

The following table summarizes information pertaining to related party transactions with NuStar GP, LLC:


	Year Ended December 31,						Year Ended December 31,
	2009		2008		2007		2010		2009		2008
	(Thousands of Dollars)						(Thousands of Dollars)
Operating expenses	$	124,827	$	115,291	$	93,211	$	137,634	$	124,827	$	115,291
General and administrative expenses		58,878		44,988		37,702		71,554		58,878		44,988

On April 24, 2008, the boards of directors of NuStar GP, LLC and NuStar GP Holdings approved (i) the termination of the administration agreement, dated July 16, 2006, between NuStar GP Holdings and NuStar GP, LLC and (ii) the adoption of a services agreement between NuStar GP, LLC and NuStar Energy (the GP Services Agreement). On July 19, 2006, we entered into a non-compete agreement with NuStar GP Holdings, Riverwalk Logistics, L.P., and NuStar GP, LLC effective on December 22, 2006 (the Non-Compete Agreement). Please refer to Note 16 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for a more detailed discussion of agreements with NuStar GP Holdings.

The preparation of financial statements in accordance with United States generally accepted accounting principles requires management to select accounting policies and to make estimates and assumptions related thereto that affect the amounts reported in the consolidated financial statements and accompanying notes. Actual results could differ from those estimates. The accounting policies below are considered critical due to judgments made by management and the sensitivity of these estimates to deviations of actual results from management’s assumptions. The critical accounting policies should be read in conjunction with Note 2 of Notes to the Consolidated Financial Statements in Item 8. “Financial Statements and Supplemental Data,” which summarizes our significant accounting policies.

We calculate depreciation expense using the straight-line method over the estimated useful lives of our property, plant and equipment. Due to the expected long useful lives of our property, plant and equipment, we depreciate our property, plant and equipment over periods ranging from 10 years to 40 years. Changes in the estimated useful lives of our property, plant and equipment could have a material adverse effect on our results of operations.

We test long-lived assets for recoverability whenever events or changes in circumstances indicate that the carrying amount of the asset may not be recoverable. Goodwill must be tested for impairment annually or more frequently if events or changes in circumstances indicate that the related asset might be impaired. An impairment loss should be recognized only if the carrying amount of the asset/goodwill is not recoverable and exceeds its fair value. The goodwill impairment test is performed for each reporting unit to which goodwill has been allocated, consisting of the following:

In order to test for recoverability, management must make estimates of projected cash flows related to the asset which include, but are not limited to, assumptions about the use or disposition of the asset, estimated remaining life of the asset,

and future expenditures necessary to maintain the asset’s existing service potential. In order to determine fair value, management must make certain estimates and assumptions including, among other things, an assessment of market conditions, projected cash flows, investment rates, interest/equity rates and growth rates, that could significantly impact the fair value of the long-lived asset or goodwill. Due to the subjectivity of the assumptions used to test for recoverability and to determine fair value, significant impairment charges could result in the future, thus affecting our future reported net income.

We record a liability, which is referred to as an asset retirement obligation, at fair value for the estimated cost to retire a tangible long-lived asset at the time we incur that liability, which is generally when the asset is purchased, constructed or leased. We record a liability for asset retirement obligations when we have a legal obligation to incur costs to retire the asset and when a reasonable estimate of the fair value of the obligation can be made. If a reasonable estimate cannot be made at the time the liability is incurred, we record the liability when sufficient information is available to estimate the fair value.

We have asset retirement obligations with regard to certain of our assets that have various legal obligations to clean and/or dispose of those assets at the time they are retired. However, these assets can be used for extended and indeterminate periods of time as long as they are properly maintained and/or upgraded. It is our practice and current intent to maintain our assets and continue making improvements to those assets based on technological advances. As a result, we believe that our assets have indeterminate lives for purposes of estimating asset retirement obligations because dates or ranges of dates upon which we would retire these assets cannot reasonably be estimated at this time. When a date or range of dates can reasonably be estimated for the retirement of any asset, we estimate the cost of performing the retirement activities and record a liability for the fair value of that cost using established present value techniques.

We also have legal obligations in the form of leases and right-of-way agreements, which require us to remove certain of our assets upon termination of the agreement. However, these lease or right-of-way agreements generally contain automatic renewal provisions that extend our rights indefinitely or we have other legal means available to extend our rights. We have recorded a liability of approximately $0.6 million as of December 31, ~~2009~~2010 and ~~2008,~~2009, which is included in “Other long-term liabilities” in our consolidated balance sheets, for conditional asset retirement obligations related to the retirement of terminal assets with lease and right-of-way agreements.

Environmental remediation costs are expensed and an associated accrual established when site restoration and environmental remediation and cleanup obligations are either known or considered probable and can be reasonably estimated. Accrued liabilities are based on estimates of probable undiscounted future costs over a 20-year time period using currently available technology and applying current regulations, as well as our own internal environmental policies. The environmental liabilities have not been reduced by possible recoveries from third parties. Environmental costs include initial site surveys, costs for remediation and restoration and ongoing monitoring costs, as well as fines, damages and other costs, when estimable. Adjustments to initial estimates are recorded, from time to time, to reflect changing circumstances and estimates based upon additional information developed in subsequent periods. We believe that we have adequately accrued for our environmental exposures.

We accrue for costs relating to litigation, claims and other contingent matters, including tax contingencies, when such liabilities become probable and reasonably estimable. Such estimates may be based on advice from third parties or on management’s judgment, as appropriate. Due to the inherent uncertainty of litigation, actual amounts paid may differ from amounts estimated, and such differences will be charged to income in the period when final determination is made.

We ~~manage our debt by considering various financing alternatives available in the market and we~~ manage our exposure to changing interest rates principally through the use of a combination of fixed-rate debt and variable-rate debt. In addition, we utilize fixed-to-floating interest rate swap agreements to manage a portion of the exposure to changing interest rates by converting certain fixed-rate debt to variable-rate debt. We also enter into forward-starting interest rate swap agreements to lock in the rate on the interest payments related to forecasted debt issuances. Borrowings under the 2007 Revolving Credit Agreement and the Gulf Opportunity Zone Revenue Bonds expose us to increases in the ~~benchmark~~underlying interest ~~rate.~~rates.

The following ~~table provides~~tables provide information about our long-term debt and interest rate derivative instruments, all of which are sensitive to changes in interest rates. For long-term debt, principal cash flows and related weighted-average interest rates by expected maturity dates are presented. For our fixed-to-floating interest rate swaps, the table presents notional amounts and weighted-average interest rates by expected (contractual) maturity dates. Weighted-average variable rates are based on implied forward interest rates in the yield curve at the reporting date.

In August and September 2010, we entered into forward-starting interest rate swap agreements with an aggregate notional amount of $500.0 million. The following table presents information regarding our forward-starting interest rate swaps as of December 31, 2010:

Since the operations of our asphalt and fuels marketing segment expose us to commodity price risk, we enter into derivative instruments to mitigate the effect of commodity price fluctuations. The derivative instruments we use consist primarily of futures contracts and swaps traded on the NYMEX. Please refer to our derivative financial instruments accounting policy in Note 2 of Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplemental Data” for further information.

We have a risk management committee that oversees our trading controls and procedures and certain aspects of risk management. Our risk management committee also reviews all new risk management strategies in accordance with our risk management policy, which was approved by our board of directors.

The ~~following tables provide information about our derivative instruments,~~commodity contracts disclosed below represent only those contracts exposed to commodity price risk at the end of the period. Please refer to Note 15 of Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplemental Data” for the volume and related fair value of ~~which will fluctuate with changes in~~all commodity ~~prices:~~contracts.


	December 31, 2009								December 31, 2010
	Contract Volumes	Weighted Average				Fair Value of Current Asset (Liability)			Contract Volumes		Weighted Average				Fair Value of Current Asset (Liability)
	Contract Volumes	Pay Price		Receive Price		Fair Value of Current Asset (Liability)			Contract Volumes		Pay Price		Receive Price		Fair Value of Current Asset (Liability)
	(Thousands of Barrels)					(Thousands of Dollars)			(Thousands of Barrels)						(Thousands of Dollars)
Fair Value Hedges:
Futures – short:
(crude oil and refined products)										436		N/A	$	96.00	$	(1,015	)
Swaps – long:
(refined products)	1,184		N/A	$	79.89	$	(9,528	)		380	$	76.05		N/A	$	(557	)
Cash Flow Hedges:
Futures – short:
Swaps – short:
(refined products)	230		N/A	$	94.13		(240	)		823		N/A	$	74.53	$	(2,541	)
Economic Hedges:
Economic Hedges and Other Derivatives:
Futures – long:
(crude oil and refined products)	454	$	81.46		N/A		2,327			278	$	93.80		N/A	$	802
Futures – short:
(crude oil and refined products)	745		N/A	$	72.90		(10,692	)		936		N/A	$	100.74	$	(2,102	)
Swaps – long:
(crude oil and refined products)	200	$	70.34		N/A		398
(refined products)										385	$	76.27		N/A	$	1,684
Swaps – short:
(crude oil and refined products)	600		N/A	$	70.16		(1,316	)
(refined products)										157		N/A	$	73.22	$	(698	)
Forward purchase contracts:
(crude oil)										4,680	$	85.81		N/A	$	38,434
Forward sales contracts:
(crude oil)										4,680		N/A	$	86.48	$	(38,989	)

Total fair value of open positions exposed to commodity price risk						$	(19,051	)							$	(4,982	)


	December 31, 2008								December 31, 2009
	Contract Volumes	Weighted Average				Fair Value of Current Asset (Liability)			Contract Volumes		Weighted Average				Fair Value of Current Asset (Liability)
	Contract Volumes	Pay Price		Receive Price		Fair Value of Current Asset (Liability)			Contract Volumes		Pay Price		Receive Price		Fair Value of Current Asset (Liability)
	(Thousands of Barrels)					(Thousands of Dollars)			(Thousands of Barrels)						(Thousands of Dollars)
Fair Value Hedges:
Futures – short:
(refined products)	445		N/A	$	43.88	$	(2,370	)		1,184		N/A	$	79.89	$	(9,528	)

Cash Flow Hedges:
Futures – short:
(refined products)										230		N/A	$	94.13	$	(240	)

Economic Hedges:
Futures – long:
(crude oil and refined products)	119	$	39.92		N/A		654			454	$	81.46		N/A	$	2,327
Futures – short:
(crude oil and refined products)	754		N/A	$	48.95		(3,131	)		745		N/A	$	72.90	$	(10,692	)
Swaps – long:
(crude oil and refined products)										200	$	70.34		N/A	$	398
Swaps – short:
(crude oil and refined products)										600		N/A	$	70.16	$	(1,316	)


Total fair value of open positions exposed to commodity price risk						$	(4,847	)							$	(19,051	)

Our management is responsible for establishing and maintaining effective internal control over financial reporting as defined in Rule 13a-15(f) under the Securities Exchange Act of 1934. Our management assessed the effectiveness of NuStar Energy L.P’s internal control over financial reporting as of December 31, ~~2009.~~2010. In its evaluation, management used the criteria set forth by the Committee of Sponsoring Organization of the Treadway Commission (COSO) in Internal Control-Integrated Framework. Based on this assessment, management believes that, as of December 31, ~~2009,~~2010, our internal control over financial reporting was effective based on those criteria.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.

The effectiveness of internal control over financial reporting as of December 31, ~~2009~~2010 has been audited by KPMG LLP, the independent registered public accounting firm who audited our consolidated financial statements included in this Form 10-K. KPMG LLP’s attestation on the effectiveness of our internal control over financial reporting appears on page ~~62.~~63.

We have audited the accompanying consolidated balance sheets of NuStar Energy L.P. (a Delaware limited partnership) and subsidiaries (the Partnership) as of December 31, ~~2009~~2010 and ~~2008,~~2009, and the related consolidated statements of income, partners’ equity and cash flows for each of the years in the three-year period ended December 31, ~~2009.~~2010. These consolidated financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of NuStar Energy L.P. and subsidiaries as of December 31, ~~2009~~2010 and ~~2008,~~2009, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, ~~2009,~~2010, in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), NuStar Energy L.P. and subsidiaries’ internal control over financial reporting as of December 31, ~~2009,~~2010, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated February ~~26, 2010~~25, 2011 expressed an unqualified opinion on the effectiveness of the Partnership’s internal control over financial reporting.

We have audited NuStar Energy L.P. (a Delaware limited partnership) and subsidiaries’ (the Partnership’s) internal control over financial reporting as of December 31, ~~2009,~~2010, based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Partnership’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Partnership’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, NuStar Energy L.P. and subsidiaries maintained, in all material respects, effective internal control over financial reporting as of December 31, ~~2009,~~2010, based on criteria established in Internal Control – Integrated Framework issued by COSO.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of NuStar Energy L.P. and subsidiaries as of December 31, ~~2009~~2010 and ~~2008,~~2009, and the related consolidated statements of income, partners’ equity and cash flows for each of the years in the three-year period ended December 31, ~~2009,~~2010, and our report dated February ~~26, 2010~~25, 2011 expressed an unqualified opinion on those consolidated financial statements.


	December 31,						December 31,
	2009			2008			2010			2009
Assets
Current assets:
Cash and cash equivalents	$	62,006		$	45,375		$	181,121		$	62,006
Accounts receivable, net of allowance for doubtful accounts of $1,351 and $1,174 as of December 31, 2009 and 2008, respectively		211,797			178,216
Accounts receivable, net of allowance for doubtful accounts of $1,457 and $1,351 as of December 31, 2010 and 2009, respectively								302,053			211,797
Inventories		377,230			220,574			413,537			387,794
Other current assets		83,686			42,321			42,796			73,122

Total current assets		734,719			486,486			939,507			734,719


Property, plant and equipment, at cost		3,721,904			3,507,573			4,021,319			3,721,904
Accumulated depreciation and amortization		(693,708	)		(565,749	)		(833,862	)		(693,708	)

Property, plant and equipment, net		3,028,196			2,941,824			3,187,457			3,028,196
Intangible assets, net		44,127			51,704			43,033			44,127
Goodwill		807,742			806,330			813,270			807,742
Investment in joint ventures		68,728			68,813
Investment in joint venture								69,603			68,728
Deferred income tax asset		13,893			12,427			8,138			13,893
Other long-term assets, net		77,268			92,013			325,385			77,268

Total assets	$	4,774,673		$	4,459,597		$	5,386,393		$	4,774,673


Liabilities and Partners’ Equity
Current liabilities:
Current portion of long-term debt	$	770		$	713		$	832		$	770
Accounts payable		205,605			145,963			282,382			205,605
Payable to related party		10,639			3,441			10,345			10,639
Notes payable		20,000			22,120			0			20,000
Accrued interest payable		21,529			22,496			29,706			21,529
Accrued liabilities		64,651			37,454			57,953			64,651
Taxes other than income tax		15,534			15,333			10,718			15,534
Income tax payable		26			4,504			1,293			26

Total current liabilities		338,754			252,024			393,229			338,754


Long-term debt, less current portion		1,828,993			1,872,015			2,136,248			1,828,993
Long-term payable to related party		7,663			6,645			10,088			7,663
Deferred income tax liability		26,909			27,370			29,565			26,909
Other long-term liabilities		87,386			94,546			114,563			87,386
Commitments and contingencies (Note 13)

Partners’ equity:
Limited partners (60,210,549 and 54,460,549 common units outstanding as of December 31, 2009 and 2008, respectively)		2,423,689			2,173,462
Limited partners (64,610,549 and 60,210,549 common units outstanding as of December 31, 2010 and 2009, respectively)								2,598,873			2,423,689
General partner		53,469			47,801			57,327			53,469
Accumulated other comprehensive income (loss)		7,810			(14,266	)
Accumulated other comprehensive income								46,500			7,810

Total partners’ equity		2,484,968			2,206,997			2,702,700			2,484,968

Total liabilities and partners’ equity	$	4,774,673		$	4,459,597		$	5,386,393		$	4,774,673


		Year Ended December 31,
		2009			2008			2007				Year Ended December 31,
												2010				2009				2008
Revenues:
Services revenues	$	745,349		$	740,630		$	696,623		$			791,314		$		745,349		$		740,630
Product sales		3,110,522			4,088,140			778,391					3,611,747				3,110,522				4,088,140

Total revenues		3,855,871			4,828,770			1,475,014					4,403,061				3,855,871				4,828,770


Costs and expenses:
Cost of product sales		2,883,187			3,864,310			742,972					3,350,429				2,883,187				3,864,310
Operating expenses:
Third parties		334,065			326,957			264,024					348,398				334,065				326,957
Related party		124,827			115,291			93,211					137,634				124,827				115,291

Total operating expenses		458,892			442,248			357,235					486,032				458,892				442,248
General and administrative expenses:
Third parties		35,855			31,442			30,213					38,687				35,855				31,442
Related party		58,878			44,988			37,702					71,554				58,878				44,988

Total general and administrative expenses		94,733			76,430			67,915					110,241				94,733				76,430
Depreciation and amortization expense		145,743			135,709			114,293					153,802				145,743				135,709

Total costs and expenses		3,582,555			4,518,697			1,282,415					4,100,504				3,582,555				4,518,697


Operating income		273,316			310,073			192,599					302,557				273,316				310,073
Equity earnings from joint ventures		9,615			8,030			6,833
Equity in earnings of joint venture													10,500				9,615				8,030
Interest expense, net		(79,384	)		(90,818	)		(76,516	)				(78,280	)			(79,384	)			(90,818	)
Other income, net		31,859			37,739			38,830					15,934				31,859				37,739

Income before income tax expense		235,406			265,024			161,746					250,711				235,406				265,024
Income tax expense		10,531			11,006			11,448					11,741				10,531				11,006

Net income	$	224,875		$	254,018		$	150,298			$		238,970		$		224,875		$		254,018


Net income per unit applicable to limited partners (Note 19)	$	3.47		$	4.22		$	2.73
Net income per unit applicable to limited partners (Note 20)											$		3.19		$		3.47		$		4.22


Weighted average limited partner units outstanding		55,232,467			53,182,741			47,158,790					62,946,987				55,232,467				53,182,741


		Year Ended December 31,									Year Ended December 31,
		2009			2008			2007			2010				2009				2008
Cash Flows from Operating Activities:
Net income	$	224,875		$	254,018		$	150,298		$		238,970		$		224,875		$		254,018
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization expense		145,743			135,709			114,293				153,802				145,743				135,709
Amortization of debt related items		(7,122	)		(6,447	)		(5,516	)			(7,767	)			(7,122	)			(6,447	)
Gain on sale or disposition of assets		(21,322	)		(26,456	)		(8,356	)
(Benefit) provision for deferred income tax		(2,037	)		37			276
Equity earnings from joint ventures		(9,615	)		(8,030	)		(6,833	)
Distributions of equity earnings from joint ventures		9,700			2,835			544
Changes in current assets and current liabilities (Note 20)		(152,280	)		133,017			(21,326	)
Gain on sale or disposition of assets, including insurance recoveries												(12,990	)			(30,704	)			(26,456	)
Deferred income tax (benefit) expense												(1,733	)			(2,037	)			37
Equity in earnings of joint ventures												(10,500	)			(9,615	)			(8,030	)
Distributions of equity in earnings of joint ventures												9,625				9,700				2,835
Changes in current assets and current liabilities (Note 21)												(6,867	)			(142,898	)			133,017
Other, net		(7,360	)		498			(708	)			(40	)			(7,360	)			498

Net cash provided by operating activities		180,582			485,181			222,672				362,500				180,582				485,181


Cash Flows from Investing Activities:
Reliability capital expenditures		(44,951	)		(55,669	)		(40,333	)			(50,562	)			(44,951	)			(55,669	)
Strategic capital expenditures		(163,605	)		(146,474	)		(210,918	)			(219,268	)			(163,605	)			(146,474	)
East Coast Asphalt Operations acquisition		-			(803,184	)		-				0				0				(803,184	)
Other acquisitions		-			(7,027	)		-				(43,026	)			0				(7,027	)
Investment in other long-term assets		(211	)		-			(62	)			(3,469	)			(211	)			0
Proceeds from sale or disposition of assets		29,680			50,813			12,667				2,610				29,680				50,813
Proceeds from insurance settlement		11,382			5,000			250
Proceeds from insurance recoveries												13,500				11,382				5,000
Other, net		-			24			-				0				0				24

Net cash used in investing activities		(167,705	)		(956,517	)		(238,396	)			(300,215	)			(167,705	)			(956,517	)


Cash Flows from Financing Activities:
Proceeds from long-term debt borrowings		1,159,436			2,108,775			1,170,302				899,365				1,159,436				2,108,775
Proceeds from short-term debt borrowings		448,752			746,800			75,000				177,041				448,752				746,800
Proceeds from senior note offering, net of issuance costs		-			346,224			-				445,431				0				346,224
Long-term debt repayments		(1,190,247	)		(2,025,784	)		(1,077,975	)			(1,204,313	)			(1,190,247	)			(2,025,784	)
Short-term debt repayments		(450,872	)		(736,037	)		(82,353	)			(197,041	)			(450,872	)			(736,037	)
Proceeds from issuance of common units, net of issuance costs		288,761			236,215			143,083				240,148				288,761				236,215
Contributions from general partner		6,155			5,025			3,035				5,078				6,155				5,025
Distributions to unitholders and general partner		(263,896	)		(241,940	)		(197,333	)			(305,154	)			(263,896	)			(241,940	)
(Decrease) increase in cash book overdrafts		(761	)		945			3,676				(4,289	)			(761	)			945
Other, net		-			(160	)		(375	)			0				0				(160	)

Net cash (used in) provided by financing activities		(2,672	)		440,063			37,060
Net cash provided by (used in) financing activities												56,266				(2,672	)			440,063


Effect of foreign exchange rate changes on cash		6,426			(13,190	)		(336	)			564				6,426				(13,190	)

Net increase (decrease) in cash and cash equivalents		16,631			(44,463	)		21,000				119,115				16,631				(44,463	)
Cash and cash equivalents as of the beginning of year		45,375			89,838			68,838				62,006				45,375				89,838

Cash and cash equivalents as of the end of year	$	62,006		$	45,375		$	89,838		$		181,121		$		62,006		$		45,375


									Accumulated																Accumulated
									Other			Total													Other				Total
	Limited Partners					General			Comprehensive			Partners’		Limited Partners							General				Comprehensive				Partners’
	Units		Amount			Partner			Income (Loss)			Equity		Units			Amount				Partner				Income (Loss)				Equity

Balance as of January 1, 2007	46,809,749	$	1,830,047		$	38,815		$	6,819		$	1,875,681

Net income	-		129,235			21,063			-			150,298
Other comprehensive income:
Foreign currency translation	-		-			-			20,068			20,068

Total comprehensive income	-		129,235			21,063			20,068			170,366

Cash distributions to partners	-		(176,239	)		(21,094	)		-			(197,333	)
Issuance of common units in November 2007 and related contribution from general partner	2,600,000		143,083			3,035			-			146,118

Balance as of December 31, 2007	49,409,749		1,926,126			41,819			26,887			1,994,832

Balance as of January 1, 2008															49,409,749	$		1,926,126		$		41,819		$		26,887		$		1,994,832

Net income	-		224,668			29,350			-			254,018			0			224,668				29,350				0				254,018
Other comprehensive loss:
Foreign currency translation	-		-			-			(41,153	)		(41,153	)		0			0				0				(41,153	)			(41,153	)

Total comprehensive loss	-		224,668			29,350			(41,153	)		212,865
Total comprehensive income (loss)															0			224,668				29,350				(41,153	)			212,865

Cash distributions to partners	-		(213,547	)		(28,393	)		-			(241,940	)		0			(213,547	)			(28,393	)			0				(241,940	)
Issuance of common units in April 2008 and related contribution from general partner	5,050,800		236,215			5,025			-			241,240			5,050,800			236,215				5,025				0				241,240

Balance as of December 31, 2008	54,460,549		2,173,462			47,801			(14,266	)		2,206,997			54,460,549			2,173,462				47,801				(14,266	)			2,206,997


Net income	-		192,239			32,636			-			224,875			0			192,239				32,636				0				224,875
Other comprehensive income (loss):
Foreign currency translation	-		-			-			22,316			22,316			0			0				0				22,316				22,316
Unrealized loss on cash flow hedges	-		-			-			(240	)		(240	)		0			0				0				(240	)			(240	)

Total comprehensive income	-		192,239			32,636			22,076			246,951			0			192,239				32,636				22,076				246,951

Cash distributions to partners	-		(230,773	)		(33,123	)		-			(263,896	)		0			(230,773	)			(33,123	)			0				(263,896	)
Issuance of common units in November 2009 and related contribution from general partner	5,750,000		288,761			6,155			-			294,916			5,750,000			288,761				6,155				0				294,916

Balance as of December 31, 2009	60,210,549	$	2,423,689		$	53,469		$	7,810		$	2,484,968			60,210,549			2,423,689				53,469				7,810				2,484,968


Net income															0			201,553				37,417				0				238,970
Other comprehensive income (loss):
Foreign currency translation															0			0				0				3,450				3,450
Net unrealized gain on cash flow hedges															0			0				0				33,560				33,560
Net loss reclassified into income on cash flow hedges															0			0				0				1,680				1,680

Total comprehensive income															0			201,553				37,417				38,690				277,660

Cash distributions to partners															0			(266,517	)			(38,637	)			0				(305,154	)
Issuance of common units in May 2010 and related contribution from general partner															4,400,000			240,148				5,078				0				245,226

Balance as of December 31, 2010															64,610,549	$		2,598,873		$		57,327		$		46,500		$		2,702,700

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 asphalt and fuels marketing. Unless otherwise indicated, the terms “NuStar Energy L.P.,” “the Partnership,” “we,” “our” and “us” are used in this report to refer to NuStar Energy L.P., to one or more of our consolidated subsidiaries or to all of them taken as a whole. NuStar GP Holdings, LLC (NuStar GP Holdings) (NYSE: NSH) owns ~~an 18.7%~~our general partner, Riverwalk Logistics, L.P., and owns a 17.6% total interest in us as of December 31, ~~2009.~~2010.

We conduct our operations through our subsidiaries, primarily NuStar Logistics, L.P. (NuStar Logistics) and NuStar Pipeline Operating Partnership L.P. (NuPOP). We have three business segments: storage, transportation, and asphalt and fuels marketing.

Storage.We own ~~terminals~~terminal and storage facilities in the United States, the Netherlands, ~~Antilles,~~including St. Eustatius in the Caribbean, Canada, ~~Mexico, the Netherlands and~~ the United Kingdom and Mexico providing approximately ~~66.2~~80.4 million barrels of storage capacity. Our terminals provide storage and handling services on a fee basis for petroleum products, specialty chemicals and other liquids, including crude oil and other feedstocks. ~~We also own 60 crude oil and intermediate feedstock storage tanks and related assets that provide an aggregate 12.5 million barrels of storage capacity to refineries in California and Texas.~~

Transportation.We own common carrier refined product pipelines in Texas, Oklahoma, Colorado, New Mexico, Kansas, Nebraska, Iowa, South Dakota, North Dakota and Minnesota covering approximately 5,605 miles, consisting of the Central West System, the East Pipeline and the North Pipeline. The East and North Pipelines also include 21 terminals providing storage capacity of 4.6 million barrels, and the East Pipeline includes two tank farms providing storage capacity of 1.2 million barrels. In addition, we own a 2,000 mile anhydrous ammonia pipeline located in Louisiana, Arkansas, Missouri, Illinois, Indiana, Iowa and Nebraska. We also own 812 miles of crude oil pipelines in Texas, Oklahoma, Kansas, Colorado and Illinois, as well as associated crude oil storage facilities providing storage capacity of 1.9 million barrels in Texas and Oklahoma that are located along the crude oil pipelines. We charge tariffs on a per barrel basis for transporting refined products, crude oil and other feedstocks in our refined product and crude oil pipelines and on a per ton basis for transporting anhydrous ammonia in our ammonia pipeline.

Asphalt and Fuels Marketing.Our asphalt and fuels marketing segment includes our asphalt refining operations and our fuels marketing operations. We refine crude oil to produce asphalt and certain other refined products from our asphalt operations. Our asphalt operations include two asphalt refineries with a combined throughput capacity of 104,000 barrels per day and related terminal facilities providing storage capacity of 5.0 million barrels. Additionally, as part of our fuels marketing operations, we purchase crude oil, gasoline and other refined petroleum products for resale. The activities of the asphalt and fuels marketing segment expose us to the risk of fluctuations in commodity prices, which has a direct impact on the results of operations for the asphalt and fuels marketing segment. We enter into derivative contracts to mitigate the effect of commodity price fluctuations.

The accompanying consolidated financial statements represent the consolidated operations of the Partnership and our subsidiaries. Inter-partnership balances and transactions have been eliminated in consolidation. The operations of certain pipelines and terminals in which we own an undivided interest are proportionately consolidated in the accompanying consolidated financial statements.

The preparation of consolidated financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and accompanying notes. Actual results could differ from those estimates. On an

ongoing basis, management reviews their estimates based on currently available information. Management may revise estimates due to changes in facts and circumstances.

Cash equivalents are all highly liquid investments with an original maturity of three months or less when acquired.

Accounts receivable represent valid claims against non-affiliated customers for products sold or services rendered. We extend credit terms to certain customers after review of various credit indicators, including the customer’s credit rating. Outstanding customer receivable balances are regularly reviewed for possible non-payment indicators and allowances for doubtful accounts are recorded based upon management’s estimate of collectability at the time of their review.

Inventories consist of crude oil, ~~and~~ refined petroleum ~~products. All inventories~~products, and material and supplies. Inventories, except those associated with a qualifying fair value hedge, are valued at the lower of cost or ~~market and cost~~market. Cost is determined using the weighted-average cost method. Our inventory, other than materials and supplies, consists ~~entirely~~ of one end-product category, petroleum products, which we include in the asphalt and fuels marketing segment. Accordingly, we determine lower of cost or market adjustments on an aggregate basis. Inventories associated with qualifying fair value hedges are valued at current market prices. Materials and supplies are valued at the lower of average cost or market.

We record additions to property, plant and equipment, including reliability and strategic capital expenditures, at cost.

Reliability capital expenditures are capital expenditures to replace partially or fully depreciated assets to maintain the existing operating capacity of existing assets and extend their useful lives. Strategic capital expenditures are capital expenditures to expand or upgrade the operating capacity, increase efficiency or increase the earnings potential of existing assets, whether through construction or acquisition, along with certain capital expenditures related to support functions. Repair and maintenance costs associated with existing assets that are minor in nature and do not extend the useful life of existing assets are charged to operating expenses as incurred.

Depreciation of property, plant and equipment is recorded on a straight-line basis over the estimated useful lives of the related assets. Gains or losses on sales or other dispositions of property are recorded in income and are reported in “Other income, net” in the consolidated statements of income. When property or equipment is retired or otherwise disposed of, the difference between the carrying value and the net proceeds is recognized in the year retired.

Goodwill ~~is the excess of cost of an acquired entity over the fair value of assets acquired less liabilities assumed. Goodwill~~ acquired in a business combination is not amortized and is tested for impairment annually or more frequently if events or changes in circumstances indicate the asset might be impaired. We use October 1 ~~of each year is~~as our annual valuation date for the impairment test. Based on the results of the impairment tests performed as of October 1, 2010, 2009 ~~2008~~ and ~~2007,~~2008, no impairment had occurred.

Intangible assets are recorded at cost and are assets that lack physical substance (excluding financial assets). Intangible assets with finite useful lives are amortized on a straight-line basis over ~~three~~five to 47 years.

We account for our ~~investments~~investment in the joint ~~ventures~~venture using the equity method of accounting.

ST Linden Terminals, LLC.The 44-acre facility provides deep-water terminalling capabilities at New York Harbor and primarily stores petroleum products, including gasoline, jet fuel and fuel oils. As part of our acquisition of Kaneb Services LLC (KSL) and Kaneb Pipe Line Partners, L.P. (KPP, and, together with KSL, Kaneb) on July 1, 2005 (the Kaneb Acquisition), we acquired an investment in ST Linden Terminals, LLC (Linden). Linden is owned 50% by the Partnership and 50% by NIC Holding Corp. In connection with the Kaneb Acquisition, we recorded our investment in

Linden at fair value, which exceeded our 50% share of its members’ equity. This excess totaled ~~$43.9~~$43.6 million and ~~$44.2~~$43.9 million as of December 31, ~~2009~~2010 and ~~2008,~~2009, respectively, of which $8.0 million is being amortized into expense over the average life of the assets held by Linden, or 25 years. The remaining balance not amortized represents goodwill of Linden.

Skelly-Belvieu Pipeline Company.The Skelly-Belvieu Pipeline Company (Skelly-Belvieu) owns a liquefied petroleum gas pipeline that begins in Skellytown, Texas and extends to Mont Belvieu, Texas near Houston. On December 1, 2008, we agreed to dispose of our interest in Skelly-Belvieu. See Note 4. Acquisitions and Dispositions below for further discussion on Skelly-Belvieu.

We review long-lived assets, including property, plant and equipment and investment in joint ~~ventures,~~venture, for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. We perform the evaluation of recoverability using undiscounted estimated net cash flows generated by the related asset. If we deem an asset to be impaired, we determine the amount of impairment as the amount by which the net carrying value exceeds its fair value. We believe that the carrying amounts of our long-lived assets as of December 31, ~~2009~~2010 are recoverable.

Taxes other than income taxes include liabilities for ad valorem taxes, franchise taxes, sales and use taxes, excise fees and taxes and value added taxes.

We are a limited partnership and generally are not subject to federal or state income taxes. Accordingly, our taxable income or loss, which may vary substantially from income or loss reported for financial reporting purposes, is generally included in the federal and state income tax returns of our partners. For transfers of publicly held units subsequent to our initial public offering, we have made an election permitted by Section 754 of the Internal Revenue Code to adjust the common unit purchaser’s tax basis in our underlying assets to reflect the purchase price of the units. This results in an allocation of taxable income and expenses to the purchaser of the common units, including depreciation deductions and gains and losses on sales of assets, based upon the new unitholder’s purchase price for the common units.

We conduct certain of our operations through taxable wholly owned corporate subsidiaries. We account for income taxes related to our taxable subsidiaries using the asset and liability method. Under this method, we recognize deferred tax assets and liabilities for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. We measure deferred taxes using enacted tax rates expected to apply to taxable income in the year those temporary differences are expected to be recovered or settled.

We recognize a tax position if it is more-likely-than-not that the tax position will be sustained, based on the technical merits of the position, upon examination. We record uncertain tax positions in the financial statements at the largest amount of benefit that is more-likely-than-not to be realized. We had no unrecognized tax benefits as of December 31, ~~2009~~2010 and ~~2008.~~2009.

NuStar Energy or certain of its subsidiaries file income tax returns in the U.S. federal jurisdiction and various state and foreign jurisdictions. For U.S. federal and state purposes, tax years subject to examination are ~~2005~~2006 through ~~2009~~2010 and for our major non-U.S. jurisdictions, tax years subject to examination are ~~2003~~2004 through ~~2009,~~2010, both according to standard statute of limitations.

We record a liability for asset retirement obligations, at the fair value of the estimated costs to retire a tangible long-lived asset at the time we incur that liability, which is generally when the asset is purchased, constructed or leased, when we have a legal obligation to incur costs to retire the asset and when a reasonable estimate of the fair value of the obligation can be made. If a reasonable estimate cannot be made at the time the liability is incurred, we record the liability when sufficient information is available to estimate the fair value.

We have asset retirement obligations with respect to certain of our assets due to various legal obligations to clean and/or dispose of those assets at the time they are retired. However, these assets can be used for an extended and indeterminate period of time as long as they are properly maintained and/or upgraded. It is our practice and current intent to maintain our assets and continue making improvements to those assets based on technological advances. As a result, we believe that our assets have indeterminate lives for purposes of estimating asset retirement obligations because dates or ranges of dates upon which we would retire these assets cannot reasonably be estimated at this time. When a date or range of dates can reasonably be estimated for the retirement of any asset, we estimate the costs of performing the retirement activities and record a liability for the fair value of these costs.

We also have legal obligations in the form of leases and right-of-way agreements, which require us to remove certain of our assets upon termination of the agreement. However, these lease or right-of-way agreements generally contain automatic renewal provisions that extend our rights indefinitely or we have other legal means available to extend our rights. We have recorded a liability of approximately $0.6 million as of December 31, ~~2009~~2010 and ~~2008,~~2009, which is included in “Other long-term liabilities” in the consolidated balance sheets, for conditional asset retirement obligations related to the retirement of terminal assets with lease and right-of-way agreements.

Environmental remediation costs are expensed and an associated accrual established when site restoration and environmental remediation and cleanup obligations are either known or considered probable and can be reasonably estimated. These environmental obligations are based on estimates of probable undiscounted future costs over a 20-year time period using currently available technology and applying current regulations, as well as our own internal environmental policies. The environmental liabilities have not been reduced by possible recoveries from third parties. Environmental costs include initial site surveys, costs for remediation and restoration and ongoing monitoring costs, as well as fines, damages and other costs, when estimable. Adjustments to initial estimates are recorded, from time to time, to reflect changing circumstances and estimates based upon additional information developed in subsequent periods.

We incur product imbalances as a result of variances in pipeline meter readings and volume fluctuations within the East Pipeline system due to pressure and temperature changes. We use quoted market prices as of the reporting date to value our assets and liabilities related to product imbalances. Product imbalance liabilities are included in “Accrued liabilities” and product imbalance assets are included in “Other current assets” in the consolidated balance sheets.

Revenues for the storage segment include fees for tank storage agreements, whereby a customer agrees to pay for a certain amount of storage in a tank over a period of time (storage lease revenues), and throughput agreements, whereby a customer pays a fee per barrel for volumes moving through our terminals and tanks (throughput revenues). Our terminals also provide blending, handling and filtering services. Our facilities at Point Tupper and St. Eustatius also charge fees to provide ancillary services such as pilotage, tug assistance, line handling, launch service, emergency response services and other ship services. Storage lease revenues are recognized when services are provided to the customer. Throughput revenues are recognized as refined products are received in or delivered out of our terminal and as crude oil and certain other refinery feedstocks are received by the related refinery. Revenues for ancillary services are recognized as those services are provided.

Revenues for the transportation segment are derived from interstate and intrastate pipeline transportation of refined product, crude oil and anhydrous ammonia. Transportation revenues (based on pipeline tariffs) are recognized as the refined product, crude oil or anhydrous ammonia is delivered out of the pipelines.

Revenues from the sale of asphalt and other petroleum products, which are included in our asphalt and fuels marketing segment, are recognized when product is delivered to the customer and title and risk pass to the customer. Additionally,

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

We collect taxes on certain revenue transactions to be remitted to governmental authorities, which may include sales, use, value added and some excise taxes. These taxes are not included in revenue.

Our net income for each quarterly reporting period is first allocated to the general partner in an amount equal to the general partner’s incentive distribution calculated based upon the declared distribution for the respective reporting period. We allocate the remaining net income among the limited and general partners in accordance with their respective 98% and 2% interests.

We have identified the general partner interest and incentive distribution rights (IDR) as participating securities and use the two-class method when calculating the net income per unit applicable to limited partners, which is based on the weighted-average number of common units outstanding during the period.

In 2008, the Financial Accounting Standards Board (FASB) provided additional guidance clarifying the application of the two-class method to calculate earnings per unit for master limited partnerships with IDR that are accounted for as equity interests. Under the new guidance, effective January 1, 2009, a master limited partnership must allocate earnings to its IDR in the calculation of earnings per unit. The terms of our partnership agreement limit distributions to the IDR holders to the amount of available cash calculated for the period. As a result, IDR are not allocated undistributed earnings or distributions in excess of earnings, thus the effect of adopting the additional guidance was not significant to our calculation of earnings per unit. Previous periods have been restated to conform to this presentation.Basic and diluted net income per unit applicable to limited partners are the same as we have no potentially dilutive securities outstanding.

Comprehensive income consists of net income and other gains and losses affecting partners’ equity that are excluded from net income, such as foreign currency translation adjustments and mark-to-market adjustments on derivative instruments designated and qualifying as cash flow hedges.

We are a party to certain interest rate swap agreements for the purpose of hedging the interest rate risk associated with a portion of our fixed-rate senior notes. We account for the interest rate swaps as fair value hedges and recognize the fair value of each interest rate swap in the consolidated balance sheet as either an asset or liability. The interest rate swap agreements qualify for the shortcut method of accounting. As a result, changes in the fair value of the swaps completely offset the changes in the fair value of the underlying hedged debt.

We record commodity derivative instruments in the consolidated balance sheets ~~as assets or liabilities~~ at fair value based on quoted market prices. We recognize mark-to-market adjustments for derivative instruments designated and qualifying as fair value hedges (Fair Value Hedges) and the related change in the fair value of the associated hedged physical inventory or firm commitment within “Cost of product sales.” For derivative instruments designated and qualifying as cash flow hedges (Cash Flow Hedges), we record the effective portion of mark-to-market adjustments as a component of “Accumulated other comprehensive income” (AOCI) until the underlying hedged forecasted transactions occur and are recognized in income. Any hedge ineffectiveness is recognized immediately in “Cost of product sales.” Once a hedged transaction occurs, we reclassify the effective portion from ~~“Accumulated other comprehensive income”~~AOCI to “Cost of product sales.” For derivative instruments that do not qualify for hedge accounting (Economic ~~Hedges)~~Hedges and Other Derivatives), we record the mark-to-market adjustments in “Cost of product ~~sales.~~sales” or “Operating expenses.”

We are a party to certain interest rate swap agreements for the purpose of hedging the interest rate risk associated with a portion of our fixed-rate senior notes. Under the terms of our fixed-to-floating interest rate swap agreements, we will receive a fixed rate and will pay a variable rate that varies with each agreement. We account for the fixed-to-floating interest rate swaps as fair value hedges and recognize the fair value of each interest rate swap in the consolidated balance sheets. The interest rate swap agreements qualify for the shortcut method of accounting. As a result, changes in the fair value of the swaps completely offset the changes in the fair value of the underlying hedged debt.

We are also a party to forward-starting interest rate swap agreements related to forecasted probable debt issuances. Under the terms of these swaps, we will pay a fixed rate and receive a rate based on three month USD LIBOR. We entered into the swaps in order to hedge the risk of changes in the interest payments attributable to changes in the benchmark interest rate during the period from the effective date of the swap to the issuance of the forecasted debt. We account for the forward-starting interest rate swaps as cash flow hedges, and we recognize the fair value of each interest rate swap in the consolidated balance sheets. We record the effective portion of mark-to-market adjustments as a component of AOCI, and any hedge ineffectiveness is recognized immediately in “Interest expense, net.” The amount in AOCI will be amortized into “Interest expense, net” over the term of the forecasted debt.

From time to time, we also enter into derivative commodity instruments based on our analysis of market conditions in order to attempt to profit from market fluctuations. These derivative instruments are financial positions entered into without underlying physical inventory and are not considered hedges. We record these derivatives in the consolidated balance sheets as assets or liabilities at fair value with mark-to-market adjustments recorded in “Product sales.”

We formally document all relationships between hedging instruments and hedged items. This process includes identification of the hedging instrument and the hedged transaction, the nature of the risk being hedged and how the hedging instrument’s effectiveness will be assessed. To qualify for hedge accounting, at inception of the hedge we assess whether the derivative instruments that are used in our hedging transactions are expected to be highly effective in offsetting changes in cash flows or the fair value of the hedged items. Throughout the designated hedge period and at least quarterly, we assess whether the derivative instruments are highly effective and continue to qualify for hedge accounting. To assess the effectiveness of the hedging relationship both prospectively and retrospectively, we use regression analysis to calculate the correlation of the changes in the fair values of the derivative instrument and related hedged item.

All cash flows associated with our commodity derivative instruments are classified as operating cash flows in the Consolidated Statements of Cash Flows.

See Note 15. Derivatives and Risk Management Activities for additional information regarding our derivative financial instruments.

We recognize rent expense on a straight-line basis over the lease term, including the impact of both scheduled rent increases and free or reduced rents (commonly referred to as “rent holidays”).

NuStar GP, LLC, a wholly owned subsidiary of NuStar GP Holdings, has adopted various long-term incentive plans, which provide the Compensation Committee of the Board of Directors of NuStar GP, LLC with the right to grant employees and directors of NuStar GP, LLC providing services to NuStar Energy the right to receive NS common units. NuStar GP, LLC accounts for awards of NS common unit options, ~~and~~ restricted units and performance awards at fair value as a derivative, whereby a liability for the award is recorded at inception. Subsequent changes in the fair value of the award are included in the determination of net income. NuStar GP, LLC determines the fair value of NS unit options using the Black-Scholes model at each reporting date. NuStar GP, LLC determines the fair value of NS restricted units and performance awards using the market price of NS common units at each reporting date. However, performance awards are earned only upon NuStar Energy’s achievement of an objective performance measure. NuStar GP, LLC records compensation expense each reporting period such that the cumulative compensation expense recognized equals the current fair value of the percentage of the award that has vested. NuStar GP, LLC records compensation expense related to NS unit options until such options are exercised, and compensation expense related to NS restricted units until the date of vesting.

NuStar GP Holdings has adopted a long-term incentive plan that provides the Compensation Committee of the Board of Directors of NuStar GP Holdings with the right to grant employees, consultants and directors of NuStar GP Holdings and its affiliates, including NuStar GP, LLC, rights to receive NuStar GP Holdings common units. NuStar GP Holdings accounts for awards of NSH restricted units and unit options granted to its directors or employees of NuStar GP, LLC at fair value. The fair value of NSH unit options is determined using the Black-Scholes model at the grant date, and the fair value of the NSH restricted unit equals the market price of NSH common units at the grant date. NuStar GP Holdings recognizes compensation expense for NSH restricted units and unit options ratably over the vesting period based on the fair value of the units at the grant date.

We reimburse NuStar GP, LLC for the expenses resulting from NS and NSH awards to employees and directors of NuStar GP, LLC. We include such compensation expense in “General and administrative expenses” on the consolidated statements of income. We do not reimburse ~~our general partner~~NuStar GP, LLC for the expense resulting from NSH awards to non-employee directors of NuStar GP Holdings.

Under these long-term incentive plans, certain awards provide that employees vest in the award when they retire or will continue to vest in the award after retirement over the nominal vesting period established in the award. We accounted for awards granted through 2005 by recognizing compensation expense over the nominal vesting period. We changed our method of recognizing compensation expense to the non-substantive vesting period approach for any awards granted after January 1, 2006. Under the non-substantive vesting period approach, compensation expense is recognized immediately for awards granted to retirement-eligible employees or over the period from the grant date to the date retirement eligibility is achieved if that date is expected to occur during the nominal vesting period.

Margin deposits relate to our exchange-traded derivative contracts and generally vary based on changes in the value of the contracts. Margin deposits are included in “Other current assets” in the consolidated balance sheets.

The functional currencies of our foreign subsidiaries are the local currency of the country in which the subsidiary is located, except for our subsidiaries located in St. Eustatius in the Caribbean (formerly the Netherlands Antilles), whose functional currency is the U.S. dollar. The assets and liabilities of our foreign subsidiaries with local functional currencies are translated to U.S. dollars at period-end exchange rates, and income and expense items are translated to U.S. dollars at weighted-average exchange rates in effect during the period. These translation adjustments are included in “Accumulated other comprehensive income” in the equity section of the consolidated balance sheets. Gains and losses on foreign currency transactions are included in “Other income, net” in the consolidated statements of income.

Certain previously reported amounts in the ~~2008~~2009 and ~~2007~~2008 consolidated financial statements have been reclassified to conform to the ~~2009~~2010 presentation.

In December 2010, the FASB amended the goodwill impairment guidance for entities that have recognized goodwill and have reporting units that have a zero or negative carrying amount for purposes of performing step 1 of the goodwill impairment test. Goodwill is tested for impairment at the reporting unit level using a two step process. Step 1 compares the fair value of the reporting unit to the carrying amount of the reporting unit. If the carrying amount exceeds fair value, Step 2 is completed to measure the amount of impairment, if any. If the fair value exceeds the carrying amount, then no further steps are necessary and no impairment is recorded. For reporting units that have a zero or negative carrying amount, the amended guidance requires that step 2 be performed if qualitative factors indicate that it is more likely than not that goodwill impairment exists. The amended guidance is effective for interim and annual periods beginning after December 15, 2010. Accordingly, we will be required to comply with the amended guidance on January 1, 2011 and do not expect it to materially affect our financial position or results of operations.

In December 2010, the FASB revised the guidance for pro forma disclosure requirements for business combinations. The accounting guidance for business combinations requires public entities to disclose certain pro forma financial information for material business combinations that occur during the period. Previously, public entities were required to disclose pro forma information as if the business combination had occurred as of the beginning of the year and had occurred as of the beginning of the comparable prior year. The revised guidance would require pro forma disclosures be presented as if the business combination occurred at the beginning of the prior annual period. The revised disclosure provisions are effective for business combinations with acquisition dates occurring in fiscal years beginning after December 15, 2010. We adopted these provisions on January 1, 2011.

In January 2010, the FASB issued additional guidance that requires new disclosures regarding significant transfers in and out of Level 1 and Level 2 fair value measurements and additional information on the roll forward of Level 3 fair value measurements. This guidance also clarified the existing provisions on determining the appropriate classes of assets and liabilities to be reported and disclosures about the valuation techniques and inputs used to measure fair value for both recurring and nonrecurring fair value measurements. This additional guidance is effective for interim and annual periods beginning after December 15, 2009, with the exception of the new requirements in the Level 3 roll forward, which will be effective for fiscal years beginning after December 15, 2010. We adopted these provisions effective January 1, 2010,

except the requirements related to the Level 3 roll forward, which we adopted January 1, 2011, and dothey did not ~~expect them to~~ have a material impact on our disclosures.

In August 2009, the FASB clarified the guidance on the fair value measurement of liabilities for circumstances in which a quoted price in an active market for an identical liability is not available. This guidance is effective the first reporting period after issuance. Accordingly, we adopted these provisions effective October 1, 2009, and they did not materially affect our financial position or results of operations.

In June 2009, the FASB amended certain requirements related to variable interest entities (VIEs), including the requirements for determining whether an entity is a VIE or the primary beneficiary of a VIE. In addition, the amended requirements include additional disclosures about an entity’s involvement with a VIE. These amended requirements become effective as of the beginning of a company’s first annual reporting period that begins after November 15, 2009 and for interim periods within that first annual reporting period. Accordingly, we will be required to comply with the amended requirements on January 1, 2010 and do not expect them to materially affect our financial position or results of operations.

On May 21, 2010, we acquired the capital stock of Asphalt Holdings, Inc. for $53.3 million, including liabilities assumed (Asphalt Holdings Acquisition). The acquisition includes three storage terminals with 24 storage tanks and an aggregate 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. Since the effect of the Asphalt Holdings Acquisition was not significant, we have not presented pro forma financial information for the years ended December 31, 2010, 2009 and 2008 that give effect to the Asphalt Holdings Acquisition as of January 1, 2008. The Asphalt Holdings Acquisition was accounted for using the acquisition method. The purchase price has been preliminarily allocated based on the estimated fair values of the individual assets acquired and liabilities assumed at the date of acquisition pending completion of an independent appraisal and other evaluations.

On March 20, 2008, we acquired CITGO Asphalt Refining Company’s asphalt operations and assets (the East Coast Asphalt Operations) for approximately $840.4 million. The East Coast Asphalt Operations include a 74,000 barrels-per-day (BPD) asphalt refinery in Paulsboro, New Jersey, a 30,000 BPD asphalt refinery in Savannah, Georgia and three asphalt terminals in Paulsboro, New Jersey, Savannah, Georgia and Wilmington, North Carolina.

We funded the acquisition with proceeds from our common unit offerings in November 2007 and April 2008, related contributions from our general partner to maintain its 2% interest, proceeds from our issuance of $350.0 million of senior notes and borrowings under our revolving credit agreement. The results of operations for the refineries, including the two related terminals in Paulsboro and Savannah, as well as the associated marketing activities, are included in the asphalt and fuels marketing segment. The results of operations for the Wilmington terminal are included in the storage segment.

The acquisition of the East Coast Asphalt Operations complemented our existing asphalt marketing operations by giving us exposure to the largest asphalt market in the United States, diversifying our customer base and expanding our geographic presence.

The acquisition of the East Coast Asphalt Operations was accounted for using the purchase method. The purchase price was allocated based on the estimated fair values of the individual assets acquired and liabilities assumed at the date of acquisition. The purchase price and final purchase price allocation were as follows (in thousands):

The consolidated statements of income include the results of operations for the East Coast Asphalt Operations commencing on March 20, 2008. The unaudited pro forma financial information presented below combines the historical financial information for the East Coast Asphalt Operations and the Partnership for ~~those periods.~~the year ended December 31, 2008. This information assumes that we:

The following unaudited pro forma information is not necessarily indicative of the results of future operations:

On June 15, 2009, we sold the Ardmore-Wynnewood pipeline in Oklahoma and the Trans-Texas pipeline. We received proceeds of $29.0 million and recognized a gain of $21.4 million in “Other income, net” in the consolidated statements of income in 2009.

On December 1, 2008, we agreed to dispose of our interest in ~~Skelly-Belvieu.~~the Skelly-Belvieu Pipeline Company, which owns a liquefied petroleum gas pipeline in Texas. We received proceeds of $36.0 million and recognized a gain of $18.9 million in “Other income, net” in the consolidated statements of ~~income.~~


	Year Ended December 31,						Year Ended December 31,
	2009			2008				2010				2009				2008
	(Thousands of Dollars)						(Thousands of Dollars)

Balance as of beginning of year	$	1,174		$	365		$		1,351		$		1,174		$		365
Increase in allowance		613			973				506				613				973
Accounts charged against the allowance, net of recoveries		(453	)		(119	)			(396	)			(453	)			(119	)
Foreign currency translation		17			(45	)			(4	)			17				(45	)

Balance as of end of year	$	1,351		$	1,174		$		1,457		$		1,351		$		1,174


	December 31,					December 31,
	2009		2008			2010			2009
	(Thousands of Dollars)				(Thousands of Dollars)

Crude oil	$	74,250	$	14,912	$		122,945	$		74,250
Finished products		302,980		205,662			281,197			302,980
Materials and supplies							9,395			10,564

Total	$	377,230	$	220,574	$		413,537	$		387,794

We purchase crude oil for the production of asphalt and other refined ~~products.~~products, as well as for resale. Our ~~“Finished products”~~finished products consist of asphalt, intermediates, gasoline, distillates and other petroleum products. We purchase gasoline, distillates and other petroleum products for resale. Materials and supplies mainly consist of blending and additive chemicals and maintenance materials used in our transportation and storage segments.


								Estimated
	Estimated Useful Lives	December 31,						Useful			December 31,
	Estimated Useful Lives	2009			2008			Lives			2010				2009
	(Years)	(Thousands of Dollars)						(Years)			(Thousands of Dollars)

Land	-	$	118,040		$	114,323			-	$		123,805		$		118,040
Land and leasehold improvements	10 - 35		98,272			91,843			10 - 35			105,055				98,272
Buildings	15 - 40		56,992			46,663			15 - 40			64,528				56,992
Pipelines, storage and terminals	20 - 35		2,843,163			2,688,198			20 - 35			3,044,538				2,843,163
Refining equipment	20 - 35		424,220			412,549			20 - 35			447,848				424,220
Rights-of-way	20 - 40		101,587			102,336			20 - 40			101,538				101,587
Construction in progress	-		79,630			51,661			-			134,007				79,630

Total			3,721,904			3,507,573						4,021,319				3,721,904
Less accumulated depreciation and amortization			(693,708	)		(565,749	)					(833,862	)			(693,708	)

Property, plant and equipment, net		$	3,028,196		$	2,941,824				$		3,187,457		$		3,028,196

Capitalized interest costs ~~included in~~added to property, plant and equipment totaled $3.7 million, $1.7 million ~~$5.1 million~~ and ~~$6.0~~$5.1 million for the years ended December 31, 2010, 2009 ~~2008~~ and ~~2007,~~2008, respectively. Depreciation and amortization expense for property,

plant and equipment totaled $144.2 million, $136.1 million ~~$125.3 million~~ and ~~$102.8~~$125.3 million for the years ended December 31, 2010, 2009 ~~2008~~ and ~~2007,~~2008, respectively.


	December 31, 2009					December 31, 2008					December 31, 2010								December 31, 2009
	Cost		Accumulated Amortization			Cost		Accumulated Amortization				Cost			Accumulated Amortization				Cost			Accumulated Amortization
	(Thousands of Dollars)											(Thousands of Dollars)
Intangible assets subject to amortization:
Customer relationships	$	70,410	$	(28,529	)	$	70,410	$	(21,476	)	$		76,910	$		(35,983	)	$		70,410	$		(28,529	)
Non-compete agreements		1,515		(1,515	)		1,515		(1,464	)			-			-				1,515			(1,515	)
Terminalling agreement		1,000		(1,000	)		1,000		(667	)			-			-				1,000			(1,000	)
Other		2,809		(563	)		2,809		(423	)			2,809			(703	)			2,809			(563	)

Total	$	75,734	$	(31,607	)	$	75,734	$	(24,030	)	$		79,719	$		(36,686	)	$		75,734	$		(31,607	)

All of our intangible assets are subject to amortization. Amortization expense for intangible assets was $7.6 million for each of the years ended December 31, 2010, 2009 and ~~2008 and $7.2 million for the year ended December 31, 2007.~~2008. The estimated aggregate amortization expense for the next five years is as follows:


	Amortization Expense	Amortization Expense
	(Thousands of Dollars)	(Thousands of Dollars)
2010	$ 7,193
2011	7,193	$ 7,843
2012	7,103	7,753
2013	7,103	7,753
2014	7,103	7,753
2015		7,753


	December 31,							December 31,
	2009			2008				2010				2009
		(Thousands of Dollars)						(Thousands of Dollars)

$1.2 billion revolving credit agreement	$	525,126		$	555,294		$		188,282		$		525,126
7.65% senior notes due 2018, net of unamortized discount of ($610) in 2009 and ($661) in 2008		349,390			349,339
6.05% senior notes due 2013, net of unamortized discount of ($209) in 2009 and ($273) in 2008 and a fair value adjustment of $5,885 in 2009 and $10,433 in 2008		235,608			240,092
6.875% senior notes due 2012, net of unamortized discount of ($80) in 2009 and ($111) in 2008 and a fair value adjustment of $2,738 in 2009 and $4,851 in 2008		102,658			104,740
7.75% senior notes due 2012, including a fair value adjustment of $16,148 in 2009 and $22,522 in 2008		266,148			272,522
5.875% senior notes due 2013, including a fair value adjustment of $7,178 in 2009 and $8,982 in 2008		257,178			258,982
4.80% senior notes due 2020, net of unamortized discount of ($848) and a fair value adjustment of ($29,483)									419,669				-
7.65% senior notes due 2018, net of unamortized discount of ($556) in 2010 and ($610) in 2009									349,444				349,390
6.05% senior notes due 2013, net of unamortized discount of ($145) in 2010 and ($209) in 2009 and a fair value adjustment of $7,580 in 2010 and $5,885 in 2009									237,367				235,608
6.875% senior notes due 2012, net of unamortized discount of ($48) in 2010 and ($80) in 2009 and a fair value adjustment of $3,083 in 2010 and $2,738 in 2009									103,035				102,658
7.75% senior notes due 2012, including a fair value adjustment of $9,023 in 2010 and $16,148 in 2009									259,023				266,148
5.875% senior notes due 2013, including a fair value adjustment of $5,247 in 2010 and $7,178 in 2009									255,247				257,178
Gulf Opportunity Zone revenue bonds									290,440				56,200
UK term loan		33,917			30,748				32,789				33,917
Gulf Opportunity Zone revenue bonds		56,200			56,200
Port Authority of Corpus Christi note payable		3,538			4,811				1,784				3,538

Total debt		1,829,763			1,872,728				2,137,080				1,829,763
Less current portion		(770	)		(713	)			(832	)			(770	)

Long-term debt, less current portion	$	1,828,993		$	1,872,015		$		2,136,248		$		1,828,993

Interest payments totaled $91.4 million, $95.3 million ~~$103.9 million~~ and ~~$89.5~~$103.9 million for the years ended December 31, 2010, 2009 ~~2008~~ and ~~2007,~~2008, respectively.

On August 12, 2010, NuStar Logistics issued $450.0 million of 4.80% senior notes under our shelf registration statement for net proceeds of $445.4 million. The net proceeds were used to reduce outstanding borrowings under our 2007 Revolving Credit Agreement. The interest on the 4.80% senior notes is payable semi-annually in arrears on March 1 and September 1 of each year beginning on March 1, 2011. The notes will mature on September 1, 2020.

The $350.0 million of 7.65% senior notes mature in 2018, with interest payable semi-annually in arrears on April 15 and October 15 of each year. The interest rate payable on the notes is subject to adjustment if our debt rating is downgraded (or subsequently upgraded) by certain credit rating agencies.

The $229.9 million of 6.05% senior notes mature in 2013, with interest payable semi-annually in arrears on March 15 and September 15 of each year.

The $100.0 million of 6.875% senior notes mature in 2012, with interest payable semi-annually in arrears on January 15 and July 15 of each year.

The 4.80%, 7.65%, 6.05% and the 6.875% senior notes do not have sinking fund requirements. These notes rank equally with existing senior unsecured indebtedness of NuStar Logistics and contain restrictions on NuStar Logistics’ ability to incur secured indebtedness unless the same security is also provided for the benefit of holders of the senior notes. In addition, the senior notes limit NuStar Logistics’ ability to incur indebtedness secured by certain liens and to engage in certain sale-leaseback transactions.

At the option of NuStar Logistics, the 4.80%, 7.65%, 6.05% and ~~the~~ 6.875% senior notes may be redeemed in whole or in part at any time at a redemption price, which includes a make-whole premium, plus accrued and unpaid interest to the redemption date. ~~Those~~The 6.05% and the 6.875% senior notes also include a change-in-control provision, which requires that (1) an investment-grade entity own, directly or indirectly, 51% of our general partner interests; and (2) we (or an investment-grade entity) own, directly or indirectly, all of the general partner and limited partner interests in NuStar Logistics.

As a result of the Kaneb Acquisition, we assumed the outstanding senior notes issued by NuPOP, having an aggregate face value of $500.0 million, and an aggregate fair value of $555.0 million. We use the effective interest method to amortize the difference between the fair value and the face value of the senior notes as a reduction of interest expense over the remaining lives of the senior notes.

The senior notes were issued in two series, the first of which bears interest at 7.75% annually (due semi-annually on February 15 and August 15) and matures February 15, 2012. The second series bears interest at 5.875% annually (due on June 1 and December 1) and matures June 1, 2013.

The 7.75% and 5.875% senior notes do not contain sinking fund requirements. These notes contain restrictions on our ability to incur indebtedness secured by liens, to engage in certain sale-leaseback transactions, to engage in certain transactions with affiliates, as defined, and to utilize proceeds from the disposition of certain assets. At the option of NuPOP, the 7.75% and 5.875% senior notes may be redeemed in whole or in part at any time at a redemption price, which includes a make-whole premium, plus accrued and unpaid interest to the redemption date.

The senior notes issued by NuStar Logistics are fully and unconditionally guaranteed by NuStar Energy. In connection with the Kaneb Acquisition, NuStar Energy fully and unconditionally guaranteed the outstanding senior notes issued by NuPOP. Additionally, effective July 1, 2005, both NuStar Logistics and NuPOP fully and unconditionally guaranteed the outstanding senior notes of the other. NuPOP will be released from its guarantee of senior notes issued by NuStar Logistics when it no longer guarantees any obligations of NuStar Energy, or any of its subsidiaries, including NuStar Logistics, under any bank facility or public debt instrument.

NuStar Logistics is party to a $1.2 billion five-year revolving credit agreement (the 2007 Revolving Credit Agreement), which includes the ability to borrow up to the equivalent of ~~$250~~$250.0 million in Euros. The 2007 Revolving Credit Agreement matures on December 10, 2012. Obligations under the 2007 Revolving Credit Agreement are guaranteed by NuStar Energy and NuPOP. NuPOP will be released from its guarantee of the 2007 Revolving Credit Agreement when it no longer guarantees NuStar Logistics’ public debt instruments.

The 2007 Revolving Credit Agreement bears interest, at our option, based on either an alternative base rate or a LIBOR based rate, which was 1.0% as of December 31, ~~2009.~~2010. The weighted-average interest rate related to borrowings under the 2007 Revolving Credit Agreement during the year ended December 31, ~~2009~~2010 was ~~1.0%~~0.9%.

The lenders under the 2007 Revolving Credit Agreement include Lehman Brothers Bank, FSB (LB Bank), a subsidiary of Lehman Brothers Holdings Inc. (Lehman), which filed for bankruptcy protection in October 2008. LB Bank’s participation in the 2007 Revolving Credit Agreement totaled $42.5 million, of which $5.0 million remained outstanding as of December 31, 2009. As a result of Lehman’s bankruptcy filing in October 2008, LB Bank has elected not to fund its pro rata share of any future borrowings we request, which reduced the total commitment under the 2007 Revolving Credit Agreement to approximately $1.2 billion. Excluding LB Bank’s participation, we We had ~~$624.6~~$724.9 million available for borrowing under the 2007 Revolving Credit Agreement as of December 31, 2009. If other lenders under the 2007 Revolving Credit Agreement file for bankruptcy or experience severe financial hardship due to disruptions and steep declines in the global financial markets and tightening credit supply, they may not honor their pro rata share of our borrowing requests.2010.

The 2007 Revolving Credit Agreement includes restrictive covenants, including a prohibition on distributions if any defaults, as defined in the agreements, exist or would result from the distribution. The 2007 Revolving Credit Agreement also requires us to maintain, as of the end of each rolling period, consisting of any period of four consecutive fiscal quarters, 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; provided, that if at any time NuStar Energy or any of its restricted subsidiaries consummates an acquisition for an aggregate net consideration of at least ~~$100~~$100.0 million, then for two rolling periods, the last day of which immediately follows the day on which such acquisition is consummated, the maximum consolidated debt coverage ratio will increase to 5.50-to-1.00. This consolidated debt coverage ratio may restrict the amount we can borrow without exceeding the maximum allowed limit to an amount less than the total amount available for borrowing. As of December 31, ~~2009,~~2010, the consolidated debt coverage ratio was ~~4.1x.~~4.6x.

Letters of credit issued under our 2007 Revolving Credit Agreement totaled $298.8 million as of December 31, 2010. Letters of credit are limited to $500.0 million and also may restrict the amount we can borrow under the 2007 Revolving Credit Agreement.

NuStar Logistics is solely obligated to service the principal and interest payments associated with the bonds. Certain lenders under our 2007 Revolving Credit Agreement issued letters of credit on our behalf to guarantee the payment of interest and principal on the bonds. These letters of credit rank equally with existing senior unsecured indebtedness of NuStar Logistics.

The following table summarizes Gulf Opportunity Zone Revenue Bonds outstanding as of December 31, 2010:

NuPOP’s UK subsidiary, NuStar Terminals Limited, is the party to the £21 million amended and restated term loan agreement (the UK Term Loan), which bears interest at 6.65% annually and matures on December 11, 2012. Management believes that we are in compliance with all ratios and covenants of the UK Term Loan as of December 31, ~~2009,~~2010, which are substantially the same as the 2007 Revolving Credit Agreement.

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

On June 26, 2008, the Parish of St. James, where our St. James, Louisiana, terminal is located, issued $56.2 million of Revenue Bonds (NuStar Logistics, L.P. Project) Series 2008 associated with our St. James terminal expansion. The bonds mature on June 1, 2038. The interest rate is based on a weekly tax-exempt bond market interest rate and is paid monthly. The average interest rate was 0.5% for the year ended December 31, 2009. Following the issuance, the proceeds were deposited with a trustee and will be disbursed to us upon our request for reimbursement of expenditures related to our St. James terminal expansion. As of December 31, 2009, we have received $55.5 million from the trustee, of which $3.2 million was received during the year ended December 31, 2009. As of December 31, 2009, the remaining $0.7 milion in trust are included in “Other long-term assets, net,” and the $56.2 million obligation is included in “Long-term debt, less current portion” in our consolidated balance sheets.

NuStar Logistics is solely obligated to service the principal and interest payments associated with the bonds. One of the lenders under our 2007 Revolving Credit Agreement issued a letter of credit in the amount of $56.9 million on our behalf, to guarantee the payment of interest and principal on the bonds. This letter of credit ranks equally with existing senior unsecured indebtedness of NuStar Logistics and was issued under our 2007 Revolving Credit Agreement.

The proceeds from the original $12.0 million note payable due to the Port of Corpus Christi Authority of Nueces County, Texas (Port Authority of Corpus Christi) were used for the construction of a crude oil storage facility in Corpus Christi, Texas. The note payable is due in annual installments of $1.2 million through December 31, 2015 and is collateralized by the crude oil storage facility. Interest on the unpaid principal balance accrues at a rate of 8.0% per annum. The land on

which the crude oil storage facility was constructed is leased from the Port Authority of Corpus Christi. The wharfage and dockage fees paid to the Port Authority of Corpus Christi in connection with the use of the crude oil storage facility

have exceeded certain limits per the terms of the note, which have accelerated the repayment of the unpaid principal balance.

As of December 31, ~~2009,~~2010, we had one short-term line of credit with an uncommitted borrowing capacity of up to $20.0 million. The interest rate and maturity vary and are determined at the time of the borrowing. The interest rate fluctuates with the Federal Funds rate.

We borrowed $177.0 million and repaid ~~$448.8~~$197.0 million during the year ended December 31, ~~2009~~2010 under this line of credit based on liquidity needs. ~~Outstanding~~We had no outstanding borrowings on this line of credit ~~totaled~~as of December 31, 2010, and we had $20.0 million outstanding as of December 31, 2009 at an interest rate of 2.4%. The weighted-average interest rate related to outstanding borrowings under this short-term line of credit during the year ended December 31, ~~2009~~2010 was ~~2.4%~~2.5%.

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.

The pipelines in the Central West System, the East Pipeline, the North Pipeline and the Ammonia Pipeline are subject to federal regulation by one or more of the following governmental agencies or laws: the Federal Energy Regulatory Commission (the FERC), the Surface Transportation Board (the STB), the Department of Transportation (DOT), the Environmental Protection Agency (EPA) and the Homeland Security Act. Additionally, the operations and integrity of the pipelines are subject to the respective state jurisdictions along the route of the systems.

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

Environmental and safety exposures and liabilities are difficult to assess and estimate due to unknown factors such as the timing and extent of remediation, the determination of our liability in proportion to other parties, improvements in cleanup technologies and the extent to which environmental and safety laws and regulations may change in the future. Although environmental and safety costs may have a significant impact on the results of operations for any single period, we believe that such costs will not have a material adverse effect on our financial position.

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


	Year Ended December 31,							Year Ended December 31,
	2009			2008				2010			2009
	(Thousands of Dollars)							(Thousands of Dollars)

Balance as of beginning of year	$	10,270		$	11,124		$		9,384		$	10,270
Additions to accrual		2,248			4,393				2,431			2,248
Payments		(3,241	)		(4,877	)			(3,210	)		(3,241	)
Foreign currency translation		107			(370	)			(36	)		107

Balance as of end of year	$	9,384		$	10,270		$		8,569		$	9,384

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


	December 31,					December 31,
	2009		2008			2010			2009
	(Thousands of Dollars)					(Thousands of Dollars)

Accrued liabilities	$	2,798	$	3,994	$		2,659	$		2,798
Other long-term liabilities		6,586		6,276			5,910			6,586

Accruals for environmental matters	$	9,384	$	10,270	$		8,569	$		9,384

We have contingent liabilities resulting from various litigation, claims and commitments, the most significant of which are discussed below. We record accruals for loss contingencies when losses are considered probable and can be reasonably estimated. Legal fees associated with defending the Partnership in legal matters are expensed as incurred. As of December 31, ~~2009,~~2010, we have accrued ~~$0.5 million related to settled matters and $74.4~~$73.3 million for contingent losses. The amount that will ultimately be paid related to these matters may differ from the recorded accruals, and the timing of such payments is uncertain.

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.

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 are currently in settlement discussions with other potentially responsible parties and the DOJ, and a change in our estimate of this liability may occur in the near term. However, any settlement agreement that is reached must be approved by multiple parties and requires the approval of the bankruptcy court and the federal district court. We cannot currently estimate when or if a settlement will be finalized.

Eres Matter. In August 2008, Eres N.V. (Eres) forwarded a demand for arbitration to CITGO Asphalt Refining Company (CARCO), CITGO Petroleum Corporation (CITGO), NuStar Asphalt Refining, LLC (NuStar Asphalt) and NuStar Marketing LLC (NuStar Marketing, and together with CARCO, CITGO and NuStar Asphalt, the Defendants) contending that the Defendants are in breach of a tanker voyage charter party agreement, dated November 2004, between Eres and CARCO (the Charter Agreement). The Charter Agreement provides for CARCO’s use of Eres’ vessels for the shipment of asphalt. Eres contends that NuStar Asphalt and/or NuStar Marketing (together, the NuStar Entities) assumed the Charter

Agreement when NuStar Asphalt purchased the CARCO assets, and that the Defendants have failed to perform under the Charter Agreement since January 1, 2008. Eres ~~seeks to compel~~has valued its damages for the ~~Defendants to arbitrate a~~alleged breach of contract claim ~~in which Eres values its damages~~ at approximately $78.1 million. ~~CITGO/CARCO also contend that~~Pursuant to a May 2010 ruling by the NuStar Entities assumed the Eres contract and they have demanded that the NuStar Entities defend and indemnify them against Eres’ claims. Eres’ motion to compel arbitration and CITGO/CARCO’s indemnity claims are currently pending in the U.S.United States District Court for the Southern District of ~~Texas.~~Texas, the NuStar Entities were found to have assumed the Charter Agreement from CARCO and to be obligated to defend and indemnify CITGO and CARCO against Eres’ claims. The Defendants were ordered to proceed with arbitration. We intend to vigorously defend against ~~these claims.~~

~~Department of Justice Matter.~~ In February 2008, the DOJ advised us that the EPA has requested that the DOJ initiate a lawsuit against NuPOP for (a) failing to prepare adequate Facility Response Plans, as required by Section 311(j)(5) of the Clean Water Act, 33 U.S.C. §1321(j), for certain of our pipeline terminals locatedEres’ claims in Region VII, by August 30, 1994, and (b) maintaining Spill Prevention, Control and Countermeasure Plans (SPCC) Plans at the terminal that deviate from the SPCC regulations, 40 C.F.R. §112.3. A Facility Response Plan is a plan for responding to a worst case discharge, and to a substantial threat of such a discharge, of oil or hazardous substances. The SPCC rule requires specific facilities to prepare, amend and implement plans to prevent, prepare and respond to oil discharges to navigable waters and adjoining shorelines. We are currently in settlement negotiations with the DOJ to resolve these matters.arbitration.

Other. 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 above 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.

Future minimum rental payments applicable to all noncancellable operating leases and purchase obligations as of December 31, ~~2009~~2010 are as follows:

Rental expense for all operating leases totaled $63.7 million, $64.8 million ~~$45.2 million~~ and ~~$21.0~~$45.2 million for the years ended December 31, 2010, 2009 ~~2008~~ and ~~2007,~~2008, respectively. Our operating leases consist primarily of the following:

Our crude oil purchase obligations result mainly from a crude supply agreement (CSA) we entered into simultaneously with the acquisition of the East Coast Asphalt Operations. Under the CSA, we committed to purchase an annual average of 75,000 barrels per day of crude oil over a minimum seven-year period from an affiliate of Petróleos de Venezuela S. A. (PDVSA), the national oil company of Venezuela. Our crude oil purchase obligations also include a crude purchase/sale agreement with Statoil Brasil Oleo E Gas Limitada that we entered into on November 17, 2010. Under this agreement, we committed to purchase an average of 10,000 barrels per day of crude oil over a three-year period beginning when we are able to process the crude oil at our Paulsboro refinery. For purposes of the table above, we used January 1, 2012 as the start date for this agreement. The value of ~~this commitment~~these two crude oil purchase obligations fluctuates according to a market-based pricing formula using published market indices, subject to adjustment based on the price of Mexican Maya crude. We estimated the value of the crude oil purchase ~~obligation~~obligations based on market prices as of December 31, ~~2009.~~2010.

We segregate the inputs used in measuring fair value into three levels: Level 1, defined as observable inputs such as quoted prices in active markets; Level 2, defined as inputs other than quoted prices in active markets that are either directly or indirectly observable; and Level 3, defined as unobservable inputs in which little or no market data exists.

We have applied fair value recognition and disclosure provisions for financial assets and liabilities and for nonfinancial assets and liabilities that are re-measured at least annually as of January 1, 2008. As permitted, we applied the provisions for nonfinancial assets and liabilities that are not recognized or disclosed at fair value on a recurring basis as of January 1, 2009, which did not affect our financial position or results of operations.


	December 31, 2010
	Level 1			Level 2			Level 3		Total
	(Thousands of Dollars)

Other current assets:
Product imbalances	$	991		$	-		$	-	$	991
Other long-term assets, net:
Interest rate swaps		-			45,663			-		45,663
Accrued liabilities:
Product imbalances		(988	)		-			-		(988	)
Commodity derivatives		(14,741	)		-			-		(14,741	)
Other long-term liabilities:
Interest rate swaps		-			(29,483	)		-		(29,483	)

Total	$	(14,738	)	$	16,180		$	-	$	1,442


	December 31, 2009
	Level 1			Level 2			Level 3		Total
	(Thousands of Dollars)

Other current assets:
Product imbalances	$	2,096		$	-		$	-	$	2,096
Other long-term assets, net:
Interest rate swaps		-			8,623			-		8,623
Accrued liabilities:
Derivatives		(30,788	)		-			-		(30,788	)
Product imbalances		(676	)		-			-		(676	)

Total	$	(29,368	)	$	8,623		$	-	$	(20,745	)

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

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

Our commodity derivative instruments consist of futures contracts and swaps traded on the NYMEX, and the fair values of these contracts are based on their quoted prices. We have consistently applied these valuation techniques in all periods presented. See Note 15. Derivatives and Risk Management Activities for a discussion of our derivative instruments.

~~We estimate the fair value of the interest rate swaps using discounted cash flows, which uses observable inputs such as time to maturity and market interest rates.~~

As of December 31, 2008, we valued assets and liabilities related to product imbalances by petroleum product at adjusted market prices. Effective January 1, 2009, we began using quoted market prices as of the reporting date to value our assets and liabilities related to product imbalances.

In April 2009, the FASB revised its existing disclosure requirements for the fair value of financial instruments to include the disclosure of the fair value of all financial instruments, whether or not recognized at fair value in the balance sheet, along with the related carrying value and methods and significant assumptions used to estimate the fair value.

We do not record our outstanding debt at fair value in our consolidated balance sheet. The estimated fair value and carrying amount of our ~~fixed-rate~~ debt was as follows:


	December 31,				December 31,
	2009		2008		2010		2009
	(Thousands of Dollars)				(Thousands of Dollars)

Fair value	$	1,306,301	$	1,157,470	$	2,249,190	$	1,877,373
Carrying amount	$	1,248,437	$	1,261,234	$	2,137,080	$	1,849,763

~~As of December 31, 2009, the fair value and carrying value of our variable rate debt was $551.1 million and $601.3 million, respectively.~~ We estimated the fair values of our debt using a discounted cash flow analysis using current incremental borrowing rates for similar types of borrowing arrangements.

We utilize various derivative instruments to: (i) manage our exposure to commodity price risk, (ii) engage in a trading program and (iii) manage our exposure to interest rate risk. Our risk management policies and procedures are designed to monitor interest rates, NYMEX and over-the-counter positions, as well as physical volumes, grades, locations and delivery schedules to help ensure that our hedging activities address our market risks. We have a risk management committee that oversees our trading controls and procedures and certain aspects of commodity and trading risk management. Our risk management committee also reviews all new commodity and trading risk management strategies in accordance with our risk management policy, as approved by our board of directors.

In March 2008, the FASB amended and expanded the existing disclosure requirements for derivative instruments to require enhanced disclosures on how and why an entity uses derivative instruments, how derivative instruments and related hedged items are accounted for and their impact on an entity’s financial performance, financial position and cash flows. We adopted these disclosure requirements as of January 1, 2009.

agreement. In September and October 2010, we entered into fixed-to-floating interest rate swap agreements with an aggregate notional amount of $450.0 million related to the 4.80% senior notes issued on August 12, 2010. Under the terms of these interest rate swap agreements, we will receive a fixed 4.80% and will pay a variable rate based on six month USD LIBOR plus a percentage that varies with each agreement. As of December 31, ~~2009~~2010 and ~~2008,~~2009, the weighted-average interest ~~rates~~rate that we paid under our fixed-to-floating interest rate swaps ~~were~~was 2.4% and 2.3% ~~and 3.0%~~, respectively.

In August and September 2010, we also entered into seven forward-starting interest rate swap agreements with an aggregate notional amount of $500.0 million related to forecasted probable debt issuances in 2012 and 2013. Under the terms of the swaps, we will pay a fixed rate and receive a rate based on three month USD LIBOR. We entered into the swaps in order to hedge the risk of changes in the interest payments attributable to changes in the benchmark interest rate during the period from the effective date of the swap to the issuance of the forecasted debt. The following table summarizes information about our forward-starting swaps:

We are exposed to commodity price risk with respect to our product inventories and related firm commitments to purchase and/or sell such inventories. We utilize futures contracts and swaps traded on the NYMEX to manage our exposure to changes in commodity prices, with the objective of stabilizing cash flows. We also enter into forward contracts in order to attempt to profit from market fluctuations.

~~The following table presents the volume of our fair value and cash flow derivative positions.~~ The volume of commodity contracts is based on open derivative positions and represents the combined volume of our long and short positions on an absolute ~~basis.~~basis, which totaled 12.8 million barrels and 11.8 million barrels as of December 31, 2010 and 2009, respectively.

As of December 31, 2010 and 2009, we had $17.8 million and $38.7 million, respectively, of margin deposits related to our derivative instruments.

The fair values of our derivative instruments included in our consolidated balance sheets were as follows:

No component of the associated derivative instruments’ gains or losses was excluded from our assessment of hedge ineffectiveness. The earnings impact of our derivative activity was as ~~follows for the year ended December 31, 2009:~~follows:


Derivatives Designated as Fair Value Hedging Instruments	Income Statement Location	Amount of Gain (Loss) Recognized in Income on Derivative (Effective Portion)			Amount of Gain (Loss) Recognized in Income on Hedged Item		Amount of Gain (Loss) Recognized in Income on Derivative (Ineffective Portion)			Income Statement Location	Amount of Gain (Loss) Recognized in Income on Derivative (Effective Portion)				Amount of Gain (Loss) Recognized in Income on Hedged Item		Amount of Gain (Loss) Recognized in Income on Derivative (Ineffective Portion)
			(Thousands of Dollars)									(Thousands of Dollars)

Year ended December 31, 2010:									Year ended December 31, 2010:
Interest rate swaps	Interest expense, net	$	(6,661	)	$	6,661	$	-		Interest expense, net	$		(27,443	)	$	27,443	$	-
Commodity contracts	Cost of product sales		(22,939	)		35,512		12,573		Cost of product sales			(3,221	)		13,946		10,725

Total		$	(29,600	)	$	42,173	$	12,573			$		(30,664	)	$	41,389	$	10,725


Year ended December 31, 2009:									Year ended December 31, 2009:
Interest rate swaps										Interest expense, net	$		(6,661	)	$	6,661	$	-
Commodity contracts										Cost of product sales			(22,939	)		35,512		12,573

Total											$		(29,600	)	$	42,173	$	12,573

For derivatives designated as cash flow hedging instruments, once a hedged transaction occurs, we reclassify the effective portion from AOCI to “Cost of product sales” or “Interest expense, net.” As of December 31, 2010, we had $35.0 million in AOCI related to our forward-starting swaps, none of which we expect to reclassify to “Interest expense” within the next twelve months as these swaps relate to debt we expect to issue in 2012 and 2013. As such, the maximum length of time over which we are hedging our exposure to the variability in future cash flows is two to three years for our forward-starting swaps.

We are exposed to credit risk on our hedging instruments in the event of nonperformance by counterparties. However, because our hedging activities are transacted only with highly rated institutions, we do not anticipate nonperformance by any of these counterparties.

Our operations are managed by NuStar GP, LLC, the general partner of our general ~~partner, NuStar GP, LLC. The employees~~partner. Employees of NuStar GP, LLC perform services for our U.S. operations. Certain of our wholly owned subsidiaries employ persons who perform services for our international operations. WeEmployees of NuStar GP, LLC provide services to both NuStar Energy and NuStar GP Holdings; therefore, we reimburse NuStar GP, LLC for all costs related to its employees, other than costs associated with NuStar GP Holdings under the services agreement described below. We had a payable of ~~$10.6~~$10.3 million and ~~$3.4~~$10.6 million as of December 31, ~~2009~~2010 and ~~2008,~~2009, respectively, with both amounts representing payroll,

~~employee-related~~ employee benefit plan expenses and unit-based compensation. We also had a long-term payable as of December 31, 2010 and 2009 ~~and 2008~~ of ~~$7.7~~$10.1 million and ~~$6.6~~$7.7 million, respectively, to NuStar GP, LLC related to amounts payable for retiree medical benefits and other post-employment benefits.

The following table summarizes information pertaining to related party transactions with NuStar GP, LLC:


	Year Ended December 31,			Year Ended December 31,
	2009	2008	2007	2010		2009		2008
	(Thousands of Dollars)			(Thousands of Dollars)

Operating expenses	$ 124,827	$ 115,291	$ 93,211	$	137,634	$	124,827	$	115,291
General and administrative expenses	58,878	44,988	37,702		71,554		58,878		44,988

GP Services Agreement. On April 24, 2008, the boards of directors of NuStar GP, LLC and NuStar GP Holdings approved (i) the termination of the administration agreement, dated July 16, 2006, between NuStar GP Holdings and NuStar GP, LLC (the Administration Agreement) and (ii) the adoption of a services agreement between NuStar GP, LLC and NuStar Energy (the GP Services Agreement). All employees providing services to both NuStar GP Holdings and NuStar Energy are employed by NuStar GP, LLC.

Under the Administration Agreement, NuStar GP Holdings paid annual charges of $500,000, subject to certain adjustments, to NuStar GP, LLC in return for NuStar GP, LLC’s provision of all executive management, accounting, legal, cash management, corporate finance and other administrative services to NuStar GP Holdings. NuStar GP Holdings also reimbursed NuStar GP, LLC for all direct public company costs and any other direct costs, such as outside legal and accounting fees, that NuStar GP, LLC incurred while providing services to NuStar GP Holdings.

Effective as of January 1, 2008, NuStar Energy and NuStar GP, LLC entered into the GP Services Agreement. The GP Services Agreement provides that NuStar GP, LLC will furnish administrative and certain operating services necessary to conduct the business of NuStar Energy. All employees providing services to both NuStar GP Holdings and NuStar Energy are employed by NuStar GP, LLC; therefore, NuStar Energy reimburses NuStar GP, LLC for all employee costs, other than the expenses allocated to NuStar GP Holdings (the Holdco Administrative Services Expense).

For the 2009 fiscal year and each fiscal year thereafter, the Holdco Administrative Services Expense totals $1.1 million (as adjusted), plus 1.0% of NuStar GP, LLC’s domestic bonus and unit compensation expense, subject to certain other adjustments. For 2008, the Holdco Administrative Services Expense totaled $0.8 million, plus 1.0% of NuStar GP, LLC’s domestic bonus and unit compensation expense. The GP Services Agreement will terminate on December 31, 2012, with automatic two-year renewals unless terminated by either party upon six months’ prior written notice. The aggregate amounts allocated to NuStar GP Holdings related to the Administration Agreement and the GP Services Agreement were $1.5 million, $1.4 million ~~$0.9 million~~ and ~~$0.5~~$0.9 million for the years ended December 31, 2010, 2009 ~~2008~~ and ~~2007,~~2008, respectively.

Non-Compete Agreement. On July 19, 2006, we entered into a non-compete agreement with NuStar GP Holdings, Riverwalk Logistics, L.P. and NuStar GP, LLC (the Non-Compete Agreement). The Non-Compete Agreement became effective on December 22, 2006 when NuStar GP Holdings ceased to be subject to the Amended and Restated Omnibus Agreement, dated March 31, 2006. Under the Non-Compete Agreement, we will have a right of first refusal with respect to the potential acquisition of assets that relate to the transportation, storage or terminalling of crude oil, feedstocks or refined petroleum products (including petrochemicals) in the United States and internationally. NuStar GP Holdings will have a right of first refusal with respect to the potential acquisition of general partner and other equity interests in publicly traded partnerships under common ownership with the general partner interest. With respect to any other business opportunities, neither the Partnership nor NuStar GP Holdings are prohibited from engaging in any business, even if the Partnership and NuStar GP Holdings would have a conflict of interest with respect to such other business opportunity.

We rely on employees of NuStar GP, LLC to provide the necessary services to conduct our U.S. operations. NuStar GP, LLC sponsors various employee benefit plans.

The NuStar Pension Plan (the Pension Plan) is a qualified non-contributory defined benefit pension plan that became effective July 1, 2006. The Pension Plan covers substantially all of NuStar GP, LLC’s employees and generally provides eligible employees with retirement income calculated under a defined benefit formula based on years of service and compensation during their period of service. Employees become fully vested in their Pension Plan benefits upon attaining five years of vesting service.

NuStar GP, LLC also maintains an excess pension plan (the Excess Pension Plan) and a supplemental executive retirement plan (the SERP). The Excess Pension Plan and the SERP are nonqualified deferred compensation plans that provide benefits to a select group of management or other highly compensated employees of NuStar GP, LLC. Benefits under the Excess Pension Plan and the SERP are generally payable in a single lump sum payment upon the employee’s separation from service.

The NuStar Thrift Plan (the Thrift Plan) is a qualified employee profit-sharing plan that became effective June 26, 2006. Participation in the Thrift Plan is voluntary and is open to substantially all NuStar GP, LLC employees upon their date of hire, except for part-time employees (as defined in the Thrift Plan), who become eligible upon completing one year of service (as defined in the Thrift Plan). Thrift Plan participants can contribute from 1% up to 30% of their total annual compensation to the Thrift Plan in the form of pre-tax and/or after tax employee contributions. NuStar GP, LLC makes matching contributions in an amount equal to 100% of each participant’s employee contributions up to a maximum of 6% of the participant’s total annual compensation.

NuStar GP, LLC also maintains an excess thrift plan (the Excess Thrift Plan) that became effective July 1, 2006. The Excess Thrift Plan is a nonqualified deferred compensation plan that provides benefits to those employees of NuStar GP, LLC whose compensation and/or annual contributions under the Thrift Plan are subject to the limitations applicable to qualified retirement plans under the Internal Revenue Code of 1986, as amended. Benefits under the Excess Thrift Plan are generally payable in a single lump sum payment upon the employee’s separation from service.

NuStar GP, LLC also provides a post-retirement medical benefits plan for retired employees, referred to as other post-retirement benefits.

None of the Excess Thrift Plan, the Excess Pension Plan or the SERP is intended to constitute either a qualified plan under the provisions of Section 401 of the Internal Revenue Code or a funded plan subject to ~~ERISA.~~the Employee Retirement Income Security Act.

We also maintain several other defined contribution plans for certain international employees located in Canada, the Netherlands and the United Kingdom. Our contributions to these plans for the years ended December 31, 2010, 2009 and 2008 totaled $2.5 million, $2.2 million and $1.5 million, respectively.


	Year Ended December 31,						Year Ended December 31,
	2009		2008		2007		2010				2009				2008
	Granted	Vesting	Granted	Vesting	Granted	Vesting	Granted		Vesting		Granted		Vesting		Granted		Vesting
2000 LTIP:
Performance awards	23,233	(a)	14,470	(a)	10,840	(a)		21,380		(a)		23,233		(a)		14,470		(a)
Unit options	-	-	10,670	1/5 per year	204,675	1/5 per year		-		-		-		-		2,600		1/5 per year
Restricted units	194,973	1/5 per year	236,868	1/5 per year	117,575	1/5 per year		191,430		1/5 per year		194,973		1/5 per year		236,868		1/5 per year
Restricted units (grants to non-employee directors of NuStar GP, LLC)	5,076	1/3 per year	5,625	1/3 per year	3,510	1/3 per year		3,938		1/3 per year		5,076		1/3 per year		5,625		1/3 per year
UIP:
Unit options	-	-	795	1/5 per year	-	-		-		-		-		-		795		1/5 per year
Restricted units	10,692	1/5 per year	16,321	1/5 per year	12,730	1/5 per year
Restricted units (b)								11,520		1/5 per year		10,692		1/5 per year		16,321		1/5 per year
2006 LTIP:
Restricted units	24,290	1/5 per year	30,300	1/5 per year	-	-		21,935		1/5 per year		24,290		1/5 per year		30,300		1/5 per year
Unit options	-	-	-	-	324,100	(c)
Restricted units (grants to non-employee directors of NuStar GP Holdings) (b)	8,627	1/3 per year	10,308	1/3 per year	5,489	1/3 per year
Restricted units (grants to non-employee directors of NuStar GP Holdings) (c)								6,156		1/3 per year		8,627		1/3 per year		10,308		1/3 per year

Our share of compensation expense related to the various long-term incentive plans and benefit plans described above is as follows:


	Year Ended December 31,						Year Ended December 31,
	2009		2008		2007		2010		2009		2008
	(Thousands of Dollars)						(Thousands of Dollars)

Long-term incentive plans	$	15,060	$	5,254	$	3,833	$	20,349	$	15,060	$	5,254
Benefit plans		9,359		8,196		8,704		13,129		9,359		8,196

The gain from insurance recoveries in both 2010 and 2009 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, 2008, the gain from insurance recoveries related to business interruption insurance proceeds associated with lost earnings in

2007 at our pipelines and terminals that serve Valero Energy’s McKee refinery, which experienced a fire in February 2007.

For the year ended December 31, 2009, the gain from sale or ~~disposal~~disposition of ~~fixed~~ assets includes 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. For the year ended December 31, 2008, the gain from sale or ~~disposal~~disposition of ~~fixed~~ assets includes a gain of $18.9 million related to the sale of interest in Skelly-Belvieu.

For the year ended December 31, 2009, the gain from insurance proceeds results from insurance claims related to damage caused by Hurricane Ike primarily at our Texas City terminal in the third quarter of 2008. For the years ended December 31, 2008 and 2007, the gain from insurance proceeds relates to business interruption insurance proceeds associated with lost earnings in 2007 at our pipelines and terminals that serve Valero Energy’s McKee refinery, which experienced a fire in February 2007.

Valero Energy provided certain services to us under the terms of a services agreement dated December 22, 2006 (the 2007 Services Agreement). On April 16, 2007, Valero Energy exercised its option to terminate the 2007 Services Agreement. In accordance with the terms of the 2007 Services Agreement, Valero Energy paid us a termination fee of $13.0 million at that time.

On May 19, 2010, we issued 4,400,000 common units representing limited partner interests at a price of $56.55 per unit. We used the net proceeds from this offering of $245.2 million, including a contribution of $5.1 million from our general partner to maintain its 2% general partner interest, mainly to reduce outstanding borrowings under our 2007 Revolving Credit Agreement and for the acquisition of Asphalt Holdings, Inc.

In November 2009, we issued 5,750,000 common units representing limited partner interests at a price of $52.45 per unit. We ~~received~~used the net proceeds from this offering of ~~$288.8~~$294.9 million, ~~and~~including a contribution of $6.2 million from our general partner to maintain its 2% general partner ~~interest. The net proceeds were used~~interest, mainly to reduce the outstanding principal balance under our 2007 Revolving Credit Agreement.

In April 2008, we issued 5,050,800 common units representing limited partner interests at a price of $48.75 per unit. We ~~received~~used the net proceeds from this offering of ~~$236.2~~$241.2 million, ~~and~~including a contribution of $5.0 million from our general partner to maintain its 2% general partner ~~interest. The proceeds were used~~interest, to repay the $124.0 million balance under a term loan agreement and a portion of the outstanding principal balance under our 2007 Revolving Credit Agreement.

In November 2007, we issued 2,600,000 common units representing limited partner interests at a price of $57.20 per unit. We received net proceeds of $143.1 million and a contribution of $3.0 million from our general partner to maintain its 2% general partner interest. The proceeds were used to repay a portion of the outstanding principal balance under our revolving credit agreement.

~~Changes~~The balance of and changes in the ~~amounts~~components included in “Accumulated other comprehensive income (loss)” were as follows:


	Foreign Currency Translation			Cash Flow Hedges			Accumulated Other Comprehensive Income (Loss)			Foreign Currency Translation			Commodity Contracts			Forward- Starting Interest Rate Swaps		Accumulated Other Comprehensive Income (Loss)

Balance as of January 1, 2008	$	26,887		$	-		$	26,887		$	26,887		$	-		$	-	$	26,887
Foreign currency translation		(41,153	)		-			(41,153	)		(41,153	)		-			-		(41,153	)

Balance as of December 31, 2008	$	(14,266	)	$	-		$	(14,266	)		(14,266	)		-			-		(14,266	)

Foreign currency translation		22,316			-			22,316			22,316			-			-		22,316
Unrealized loss on cash flow hedges		-			(240	)		(240	)
Net unrealized loss on cash flow hedges											-			(240	)		-		(240	)

Balance as of December 31, 2009	$	8,050		$	(240	)	$	7,810			8,050			(240	)		-		7,810

Foreign currency translation											3,450			-			-		3,450
Net unrealized (loss) gain on cash flow hedges											-			(1,440	)		35,000		33,560
Net loss reclassified into income on cash flow hedges											-			1,680			-		1,680

Balance as of December 31, 2010										$	11,500		$	-		$	35,000	$	46,500

There was no tax effect from foreign currency translation or the ~~unrealized loss~~gain (loss) on ~~certain derivative instruments~~cash flow hedges as these transactions related to non-taxable entities.

Our partnership agreement, as amended, sets forth the calculation to be used to determine the amount and priority of cash distributions that our unitholders and general partner will receive. The partnership agreement also contains provisions for the allocation of net income and loss to our unitholders and the general partner. For purposes of maintaining partner

capital accounts, the partnership agreement specifies that items of income and loss shall be allocated among the partners

in accordance with their respective percentage interests. Normal allocations according to percentage interests are ~~done~~made after giving effect, if any, to priority income allocations in an amount equal to incentive cash distributions allocated 100% to the general partner.

The following table details the calculation of net income applicable to the general partner:


		Year Ended December 31,						Year Ended December 31,
	2009		2008		2007		2010			2009		2008
		(Thousands of Dollars)						(Thousands of Dollars)

Net income applicable to general partner and limited partners’ interest	$	224,875	$	254,018	$	150,298	$		238,970	$	224,875	$	254,018
Less general partner incentive distribution (a)		28,712		24,764		18,426			33,304		28,712		24,764

Net income after general partner incentive distribution		196,163		229,254		131,872			205,666		196,163		229,254
General partner interest		2%		2%		2%			2%		2%		2%

General partner allocation of net income after general partner incentive distribution		3,924		4,586		2,637			4,113		3,924		4,586
General partner incentive distribution		28,712		24,764		18,426			33,304		28,712		24,764

Net income applicable to general partner	$	32,636	$	29,350	$	21,063	$		37,417	$	32,636	$	29,350

In 2008, the FASB 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. The following table details the calculation of earnings per unit:

We make quarterly distributions of 100% of our available cash, generally defined as cash receipts less cash disbursements and cash reserves established by the general partner, in its sole discretion. These quarterly distributions are declared and paid within 45 days subsequent to each quarter-end. The limited partner unitholders are entitled to receive a minimum quarterly distribution of $0.60 per unit each quarter ($2.40 annualized). Our cash is first distributed 98% to the limited partners and 2% to the general partner until the amount distributed to our unitholders is equal to the minimum quarterly distribution and arrearages in the payment of the minimum quarterly distribution for any prior quarter. Cash in excess of the minimum quarterly distributions is distributed to our unitholders and our general partner based on the percentages shown below.

Our general partner is entitled to incentive distributions if the amount we distribute with respect to any quarter exceeds specified target levels shown below:

The following table reflects the allocation of total cash distributions to our general and limited partners applicable to the period in which the distributions are earned:


	Year Ended December 31,						Year Ended December 31,
		2009		2008		2007		2010			2009			2008
		(Thousands of Dollars, Except Per Unit Data)					(Thousands of Dollars, Except Per Unit Data)

General partner interest	$	5,430	$	5,058	$	4,092	$		6,227	$		5,430	$		5,058
General partner incentive distribution		28,712		25,294		18,426			33,304			28,712			25,294

Total general partner distribution		34,142		30,352		22,518			39,531			34,142			30,352
Limited partners’ distribution		237,308		222,470		182,076			271,847			237,308			222,470

Total cash distributions	$	271,450	$	252,822	$	204,594	$		311,378	$		271,450	$		252,822


Cash distributions per unit applicable to limited partners	$	4.245	$	4.085	$	3.835	$		4.280	$		4.245	$		4.085

In January ~~2010,~~2011, we declared a quarterly cash distribution of ~~$1.065~~$1.075 that was paid on February ~~12, 2010~~14, 2011 to unitholders of record on February ~~5, 2010.~~8, 2011. This distribution related to the fourth quarter of ~~2009~~2010 and totaled ~~$73.4~~$79.6 million, of which ~~$9.3~~$10.2 million represented our general partner’s ~~share of such distribution. Our general partner’s distribution included a $7.8 million~~interest and incentive distribution.


		Year Ended December 31,									Year Ended December 31,
		2009			2008			2007			2010				2009				2008
		(Thousands of Dollars)									(Thousands of Dollars)
Decrease (increase) in current assets:
Accounts receivable	$	(31,505	)	$	(52,372	)	$	(22,079	)	$		(90,369	)	$		(31,505	)	$		(52,372	)
Receivable from related party		-			786			(786	)			-				-				786
Inventories		(156,234	)		193,992			(71,457	)			(26,595	)			(157,439	)			192,236
Other current assets		(39,400	)		6,920			(8,603	)			31,373				(38,195	)			8,676
Increase (decrease) in current liabilities:
Payable to related party		7,051			3,760			(2,315	)			(218	)			7,051				3,760
Accounts payable		59,284			(16,419	)		72,918				80,980				59,284				(16,419	)
Accrued interest payable		(969	)		4,781			182				8,179				(969	)			4,781
Accrued liabilities		17,492			(13,237	)		9,546				(6,488	)			26,874				(13,237	)
Taxes other than income tax		209			4,730			2				(4,793	)			209				4,730
Income tax payable		(8,208	)		76			1,266				1,064				(8,208	)			76

Changes in current assets and current liabilities	$	(152,280	)	$	133,017		$	(21,326	)	$		(6,867	)	$		(142,898	)	$		133,017

The above changes in current assets and current liabilities differ from changes between amounts reflected in the applicable consolidated balance sheets ~~for the following reasons:~~

Non-cash investing and financing activities for the years ended December 31, 2010, 2009 and 2008 mainly consist of changes in the fair values of our fixed-to-floating and forward-starting interest rate swaps and the effect of foreign currency translation.

~~Non-cash financing activities for the year ended December 31, 2009 included a decrease in the fair value of our interest rate swaps.~~

~~Non-cash investing and financing activities for the year ended December 31, 2008 included:~~

~~Non-cash investing and financing activities for the year ended December 31, 2007 included:~~

Components of income tax expense related to certain of our operations conducted through separate taxable wholly owned corporate subsidiaries were as follows:


	Year Ended December 31,									Year Ended December 31,
	2009			2008			2007			2010				2009			2008
		(Thousands of Dollars)									(Thousands of Dollars)
Current:
U.S.	$	2,424		$	1,059		$	2,373		$		2,010		$	2,424		$	1,059
Foreign		10,144			9,910			8,799				11,464			10,144			9,910

Total current		12,568			10,969			11,172				13,474			12,568			10,969


Deferred:
U.S.		(1,466	)		(1,280	)		827				(3,786	)		(1,466	)		(1,280	)
Foreign		(571	)		1,317			(551	)			2,053			(571	)		1,317

Total deferred		(2,037	)		37			276				(1,733	)		(2,037	)		37


Total income tax expense	$	10,531		$	11,006		$	11,448		$		11,741		$	10,531		$	11,006

The difference between income tax expense recorded in our consolidated statements of income and income taxes computed by applying the statutory federal income tax rate (35% for all years presented) to income before income tax expense is due to the fact that the majority of our income is not subject to federal income tax due to our status as a limited partnership.

The tax effects of significant temporary differences representing deferred income tax assets and liabilities were as follows:


	December 31,							December 31,
		2009			2008			2010				2009
		(Thousands of Dollars)						(Thousands of Dollars)

U.S.:
Net operating losses	$	20,788		$	23,283		$		16,531		$		20,788
Environmental and legal reserves		14,234			14,252				14,774				14,234
Other		1,525			902				392				1,525
Valuation allowance		(9,457	)		(13,366	)			-				(9,457	)

Deferred tax assets – U. S.		27,090			25,071				31,697				27,090


Property, plant and equipment		(13,197	)		(12,644	)			(23,559	)			(13,197	)


Net deferred income tax asset – U.S.	$	13,893		$	12,427		$		8,138		$		13,893


Foreign:
Net operating losses	$	3,253		$	-		$		3,156		$		3,253
Other		687			1,022				732				687
Capital loss		2,166			1,569				1,264				2,166
Valuation allowance		-			(1,312	)			(1,129	)			-

Deferred tax assets – foreign		6,106			1,279				4,023				6,106


Property, plant and equipment		(33,015	)		(28,649	)			(33,588	)			(33,015	)


Net deferred income tax liability – foreign	$	(26,909	)	$	(27,370	)
Net deferred income tax liability – foreign.							$		(29,565	)	$		(26,909	)

As of December 31, 2010, our U.S. corporate operations have net operating loss carryforwards for tax purposes totaling approximately ~~$59.4~~$47.2 million, which are subject to various limitations on use and expire in years ~~2010~~2011 through 2029.

As of December 31, 2009, ~~and 2008,~~ we recorded a valuation allowance to reduce our net U.S. deferred income tax asset to an amount that is more-likely-than-not to be realized. We estimate the amount of valuation allowance based upon our expectations of taxable income in the various jurisdictions in which we operate and the period over which we can utilize those future deductions. The valuation allowance reflects uncertainties related to our ability to utilize certain federal net operating loss carryforwards before they expire. ~~In 2009,~~During the year ended December 31, 2010, we received $13.5 million of proceeds resulting from insurance claims related to damage caused by Hurricane Ike primarily at our Texas City, Texas terminal in the third quarter of 2008, resulting in tax expense of approximately $4.7 million. Additionally, our corporate subsidiary that received the insurance proceeds was part of the federal consolidated group that acquired Asphalt Holdings, Inc, a corporation subject to income tax. The acquisition of Asphalt Holdings, Inc. included approximately $9.5 million of deferred tax liabilities related to temporary differences primarily related to property, plant and equipment. The receipt of the insurance proceeds and the acquisition of Asphalt Holdings, Inc. caused us to reevaluate the valuation allowance recorded related to certain net operating loss carryforwards previously expected to expire unused. We concluded that the income generated from the insurance proceeds, the deferred tax liability associated with Asphalt Holdings, Inc. and other tax planning strategies increased the likelihood of utilizing the net operating loss carryforwards, and we reduced the valuation allowance ~~for both the U.S. net operating loss and the foreign capital loss assets~~ by ~~$5.2~~$8.6 million ~~due to changes~~ in ~~our estimates of the amount of those loss carryforwards that will be realized, based upon future taxable income and potential tax planning strategies.~~2010.

The realization of net deferred income tax assets recorded as of December 31, ~~2009~~2010 is dependent upon our ability to generate future taxable income in the United States. We believe it is more-likely-than not that the deferred income tax assets ~~net of the valuation allowance,~~ as of December 31, ~~2009~~2010 will be realized, based on expected future taxable income and potential tax planning strategies.

During the year ended December 31, 2010, we recorded a valuation allowance of $1.1 million to reduce our foreign deferred tax assets. The valuation reflects uncertainties related to our ability to utilize certain net operating losses before they expire.

On June 1, 1989, the governments of the Netherlands Antilles and St. Eustatius approved a Free Zone and Profit Tax Agreement retroactive to January 1, 1989, which expired on December 31, 2000. This agreement required a subsidiary of Kaneb, which we acquired on July 1, 2005, to pay the greater of 2% of taxable income, as defined therein, or 500,000 Netherlands Antilles guilders (approximately $0.3 million) per year. The agreement further provided that any amounts paid in order to meet the minimum annual payment were available to offset future tax liabilities under the agreement to the extent that the minimum annual payment is greater than 2% of taxable income.

On February 22, 2006, we entered into a revised agreement (the 2005 Tax and Maritime Agreement) with the governments of St. Eustatius and the Netherlands Antilles. The 2005 Tax and Maritime Agreement is effective beginning January 1, 2005 and expires on December 31, 2014. Under the terms of the 2005 Tax and Maritime Agreement, we

agreed to make a one-time payment of 5.0 million Netherlands Antilles guilders (approximately $2.8 million) in full and final settlement of all of our liabilities, taxes, fees, levies, charges, or otherwise (including settlement of audits) due or potentially due to St. Eustatius. We further agreed to pay an annual minimum profit tax to St. Eustatius of 1.0 million Netherlands Antilles guilders (approximately $0.6 million), beginning as of January 1, 2005. We agreed to pay the minimum annual profit tax in twelve equal monthly installments. To the extent the minimum annual profit tax exceeds 2% of taxable profit (as defined in the 2005 Tax and Maritime Agreement), we can carry forward that excess to offset future tax liabilities. If the minimum annual profit tax is less than 2% of taxable profit, we agreed to pay that difference.

Effective January 1, 2011, the Netherlands Antilles was dissolved, and St. Eustatius became part of the Netherlands. We are uncertain of the impact, if any, to our overall tax liability in St. Eustatius.

Our reportable business segments consist of storage, transportation, and asphalt and fuels marketing. Our segments represent strategic business units that offer different services. We evaluate the performance of each segment based on its respective operating income, before general and administrative expenses and certain non-segmental depreciation and amortization expense. General and administrative expenses are not allocated to the operating segments since those expenses relate primarily to the overall management at the entity level. Our principal operations include terminalling and storage of petroleum products, the transportation of petroleum products and anhydrous ammonia, and asphalt and fuels marketing. Intersegment revenues result from storage and throughput agreements with related parties at lease rates ~~consistent with rates charged to third parties for storage and at pipeline tariffs based upon the published tariff applicable to all shippers.~~

consistent with rates charged to third parties for storage and at pipeline tariff rates based upon the published tariff applicable to all shippers.

For the years ended December 31, 2010, 2009 and 2008, no single customer accounted for more than 10% of our consolidated revenues. For the year ended December 31, 2007, revenues from Valero Energy accounted for 18% of our consolidated revenues, respectively, and no other single customer accounted for more than 10% of our consolidated revenue. Revenues from Valero Energy by operating segment were as follows:

Long-lived assets include property, plant and equipment, intangible assets subject to amortization and certain long-lived assets included in “Other long-term assets, net” in the consolidated balance sheets. Total amounts of long-lived assets by ~~country~~geographic area were as follows:


	December 31,				December 31,
	2009		2008		2010			2009
		(Thousands of Dollars)				(Thousands of Dollars)

United States	$	2,667,559	$	2,630,940	$		3,010,753	$	2,667,559
Netherlands Antilles		252,030		253,355
St. Eustatius (a)							312,640		252,030
Netherlands		126,545		121,977			117,929		126,545
Canada		93,801		80,956			98,607		93,801
United Kingdom		83,144		70,335			84,556		83,144
Mexico		9,133		9,218			9,131		9,133

Consolidated long-lived assets	$	3,232,212	$	3,166,781	$		3,633,616	$	3,232,212

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

NuStar Energy has no operations and its assets consist mainly of its investments in NuStar Logistics and NuPOP, both wholly owned subsidiaries. The senior notes issued by NuStar Logistics and NuPOP are fully and unconditionally guaranteed by NuStar Energy, and both NuStar Logistics and NuPOP fully and unconditionally guarantee the outstanding senior notes of the other. As a result, the following condensed consolidating financial statements are being presented as an alternative to providing separate financial statements for NuStar Logistics and NuPOP.


														NuStar Energy		NuStar Logistics		NuPOP		Non-Guarantor Subsidiaries (a)		Eliminations			Consolidated
	NuStar Energy		NuStar Logistics		NuPOP		Non-Guarantor Subsidiaries (a)		Eliminations			Consolidated
Assets
Cash and cash equivalents	$	53	$	2	$	656	$	44,664	$	-		$	45,375	$	53	$	107,655	$	-	$	73,413	$	-		$	181,121
Receivables, net		8		33,620		8,421		143,141		(6,974	)		178,216		-		27,708		10,648		266,885		(3,188	)		302,053
Inventories		-		-		347		220,937		(710	)		220,574		-		1,776		6,712		405,521		(472	)		413,537
Other current assets		9		9,472		13,673		19,167		-			42,321		-		10,116		1,202		31,478		-			42,796
Intercompany receivable		-		337,685		666,052		-		(1,003,737	)		-		-		786,658		729,365		-		(1,516,023	)		-

Current assets		70		380,779		689,149		427,909		(1,011,421	)		486,486		53		933,913		747,927		777,297		(1,519,683	)		939,507

Property, plant and equipment, net		-		954,487		629,091		1,358,246		-			2,941,824		-		1,006,479		614,762		1,566,216		-			3,187,457
Intangible assets, net		-		2,771		-		48,933		-			51,704		-		2,106		-		40,927		-			43,033
Goodwill		-		18,613		170,652		617,065		-			806,330		-		18,094		170,652		624,524		-			813,270
Investment in wholly owned subsidiaries		2,341,184		82,435		806,706		1,679,065		(4,909,390	)		-		3,167,764		159,813		994,249		2,112,355		(6,434,181	)		-
Investments in joint ventures		-		-		-		68,813		-			68,813
Investment in joint venture															-		-		-		69,603		-			69,603
Deferred income tax asset		-		-		-		12,427		-			12,427		-		-		-		8,138		-			8,138
Other long-term assets, net		56		34,557		26,517		30,883		-			92,013		-		267,532		26,329		31,524		-			325,385

Total assets	$	2,341,310	$	1,473,642	$	2,322,115	$	4,243,341	$	(5,920,811	)	$	4,459,597	$	3,167,817	$	2,387,937	$	2,553,919	$	5,230,584	$	(7,953,864	)	$	5,386,393


Liabilities and Partners’ Equity
Current portion of long-term debt	$	-	$	713	$	-	$	-	$	-		$	713	$	-	$	832	$	-	$	-	$	-		$	832
Payables		-		23,900		10,171		122,307		(6,974	)		149,404		-		28,705		9,559		257,651		(3,188	)		292,727
Notes payable		-		22,120		-		-		-			22,120
Accrued interest payable		-		13,830		8,490		176		-			22,496		-		21,180		8,490		36		-			29,706
Accrued liabilities		1,032		14,998		5,076		16,365		(17	)		37,454		680		18,154		3,973		35,146		-			57,953
Taxes other than income tax		125		3,866		2,687		8,655		-			15,333		125		4,273		2,587		3,733		-			10,718
Income tax payable		-		976		-		3,528		-			4,504		-		1,140		-		153		-			1,293
Intercompany payable		118,890		-		-		884,847		(1,003,737	)		-		510,812		-		-		1,005,211		(1,516,023	)		-

Current liabilities		120,047		80,403		26,424		1,035,878		(1,010,728	)		252,024		511,617		74,284		24,609		1,301,930		(1,519,211	)		393,229

Long-term debt, less current portion		-		1,309,763		531,504		30,748		-			1,872,015		-		1,589,189		514,270		32,789		-			2,136,248
Long-term payable to related party		-		-		-		6,645		-			6,645		-		3,571		-		6,517		-			10,088
Deferred income tax liability		-		-		-		27,370		-			27,370		-		-		-		29,565		-			29,565
Other long-term liabilities		-		4,992		965		88,589		-			94,546		-		33,458		228		80,877		-			114,563
Total partners’ equity		2,221,263		78,484		1,763,222		3,054,111		(4,910,083	)		2,206,997		2,656,200		687,435		2,014,812		3,778,906		(6,434,653	)		2,702,700

Total liabilities and partners’ equity	$	2,341,310	$	1,473,642	$	2,322,115	$	4,243,341	$	(5,920,811	)	$	4,459,597	$	3,167,817	$	2,387,937	$	2,553,919	$	5,230,584	$	(7,953,864	)	$	5,386,393


	NuStar Energy			NuStar Logistics			NuPOP			Non-Guarantor Subsidiaries (a)			Eliminations			Consolidated			NuStar Energy			NuStar Logistics			NuPOP			Non-Guarantor Subsidiaries (a)			Eliminations			Consolidated
Revenues	$	-		$	297,929		$	153,268		$	3,441,422		$	(36,748	)	$	3,855,871		$	-		$	297,929		$	153,268		$	3,441,422		$	(36,748	)	$	3,855,871
Costs and expenses		2,006			184,330			112,161			3,319,305			(35,247	)		3,582,555			2,006			184,330			112,161			3,319,305			(35,247	)		3,582,555

Operating income		(2,006	)		113,599			41,107			122,117			(1,501	)		273,316			(2,006	)		113,599			41,107			122,117			(1,501	)		273,316

Equity earnings in subsidiaries		226,881			35,864			91,716			155,481			(509,942	)		-
Equity earnings from joint ventures		-			-			-			9,615			-			9,615
Equity in earnings of subsidiaries																				226,881			35,864			91,716			155,481			(509,942	)		-
Equity in earnings of joint venture																				-			-			-			9,615			-			9,615
Interest expense, net		-			(51,715	)		(24,168	)		(3,501	)		-			(79,384	)		-			(51,715	)		(24,168	)		(3,501	)		-			(79,384	)
Other (expense) income, net		-			23,078			(957	)		9,738			-			31,859
Other income (expense) net																				-			23,078			(957	)		9,738			-			31,859

Income before income tax expense		224,875			120,826			107,698			293,450			(511,443	)		235,406			224,875			120,826			107,698			293,450			(511,443	)		235,406
Income tax expense		-			1,332			-			9,199			-			10,531			-			1,332			-			9,199			-			10,531

Net income	$	224,875		$	119,494		$	107,698		$	284,251		$	(511,443	)	$	224,875		$	224,875		$	119,494		$	107,698		$	284,251		$	(511,443	)	$	224,875


	NuStar Energy			NuStar Logistics			NuPOP			Non-Guarantor Subsidiaries (a)			Eliminations			Consolidated			NuStar Energy			NuStar Logistics			NuPOP			Non-Guarantor Subsidiaries (a)			Eliminations			Consolidated
Revenues	$	-		$	298,003		$	157,067		$	4,386,481		$	(12,781	)	$	4,828,770		$	-		$	298,003		$	157,067		$	4,386,481		$	(12,781	)	$	4,828,770
Costs and expenses		1,628			181,216			116,057			4,231,959			(12,163	)		4,518,697			1,628			181,216			116,057			4,231,959			(12,163	)		4,518,697

Operating income		(1,628	)		116,787			41,010			154,522			(618	)		310,073			(1,628	)		116,787			41,010			154,522			(618	)		310,073

Equity earnings in subsidiaries		255,725			80,760			76,044			133,243			(545,772	)		-
Equity earnings from joint ventures		-			609			-			7,421			-			8,030
Equity in earnings of subsidiaries																				255,725			80,760			76,044			133,243			(545,772	)		-
Equity in earnings of joint ventures																				-			609			-			7,421			-			8,030
Interest expense, net		-			(61,792	)		(24,704	)		(4,322	)		-			(90,818	)		-			(61,792	)		(24,704	)		(4,322	)		-			(90,818	)
Other (expense) income, net		(79	)		28,668			(453	)		9,603			-			37,739			(79	)		28,668			(453	)		9,603			-			37,739

Income before income tax expense		254,018			165,032			91,897			300,467			(546,390	)		265,024			254,018			165,032			91,897			300,467			(546,390	)		265,024
Income tax expense		-			752			-			10,254			-			11,006			-			752			-			10,254			-			11,006

Net income	$	254,018		$	164,280		$	91,897		$	290,213		$	(546,390	)	$	254,018		$	254,018		$	164,280		$	91,897		$	290,213		$	(546,390	)	$	254,018


		NuStar Energy			NuStar Logistics			NuPOP			Non- Guarantor Subsidiaries (a)			Elim- inations			Consolidated			NuStar Energy				NuStar Logistics				NuPOP				Non- Guarantor Subsidiaries (a)				Elim- inations				Consolidated
Net cash provided by (used in) operating activities	$	263,017		$	103,753		$	70,433		$	32,302		$	(288,923	)	$	180,582		$		263,017		$		103,753		$		70,433		$		32,302		$		(288,923	)	$		180,582


Cash flows from investing activities:
Capital expenditures		-			(49,800	)		(23,734	)		(135,022	)		-			(208,556	)			-				(49,800	)			(23,734	)			(135,022	)			-				(208,556	)
Investment in other long-term assets																					-				-				-				(211	)			-				(211	)
Proceeds from sale or disposition of assets																					-				29,215				108				357				-				29,680
Proceeds from insurance recoveries																					-				-				-				11,382				-				11,382
Investment in subsidiaries		(295,178	)		-			-			(30	)		295,208			-				(295,178	)			-				-				(30	)			295,208				-
Proceeds from sale or disposition of assets		-			29,215			108			357			-			29,680
Proceeds from insurance settlement		-			-			-			11,382			-			11,382
Investment in other noncurrent assets		-			-			-			(211	)		-			(211	)

Net cash used in investing activities		(295,178	)		(20,585	)		(23,626	)		(123,524	)		295,208			(167,705	)			(295,178	)			(20,585	)			(23,626	)			(123,524	)			295,208				(167,705	)


Cash flows from financing activities:
Debt borrowings		-			1,608,188			-			-			-			1,608,188				-				1,608,188				-				-				-				1,608,188
Debt repayments		-			(1,641,119	)		-			-			-			(1,641,119	)			-				(1,641,119	)			-				-				-				(1,641,119	)
Issuance of common units, net of issuance costs		288,761			-			-			-			-			288,761				288,761				-				-				-				-				288,761
General partner contribution		6,155			-			-			-			-			6,155				6,155				-				-				-				-				6,155
Partners’ contributions		-			295,178			-			30			(295,208	)		-				-				295,178				-				30				(295,208	)			-
Distributions to unitholders and general partner		(263,896	)		(263,896	)		-			(25,027	)		288,923			(263,896	)			(263,896	)			(263,896	)			-				(25,027	)			288,923				(263,896	)
Net intercompany (repayments) borrowings		1,141			(80,506	)		(47,483	)		126,848			-			-
Net intercompany borrowings (repayments)																					1,141				(80,506	)			(47,483	)			126,848				-				-
Other, net		-			(1,982	)		20			1,201			-			(761	)			-				(1,982	)			20				1,201				-				(761	)

Net cash (used in) provided by financing activities		32,161			(84,137	)		(47,463	)		103,052			(6,285	)		(2,672	)
Net cash provided by (used in) financing activities																					32,161				(84,137	)			(47,463	)			103,052				(6,285	)			(2,672	)


Effect of foreign exchange rate changes on cash		-			2,569			-			3,857			-			6,426				-				2,569				-				3,857				-				6,426

Net increase (decrease) in cash and cash equivalents		-			1,600			(656	)		15,687			-			16,631				-				1,600				(656	)			15,687				-				16,631
Cash and cash equivalents as of the beginning of year		53			2			656			44,664			-			45,375				53				2				656				44,664				-				45,375

Cash and cash equivalents as of the end of year	$	53		$	1,602		$	-		$	60,351		$	-		$	62,006		$		53		$		1,602		$		-		$		60,351		$		-		$		62,006


		NuStar Energy			NuStar Logistics			NuPOP			Non- Guarantor Subsidiaries (a)			Elim- inations			Consolidated			NuStar Energy				NuStar Logistics				NuPOP				Non-Guarantor Subsidiaries (a)				Elim- inations				Consolidated
Net cash provided by (used in) operating activities	$	239,707		$	111,078		$	34,487		$	341,873		$	(241,964	)	$	485,181		$		239,707		$		111,078		$		34,487		$		341,873		$		(241,964	)	$		485,181


Cash flows from investing activities:
Capital expenditures		-			(51,575	)		(14,009	)		(136,559	)		-			(202,143	)			-				(51,575	)			(14,009	)			(136,559	)			-				(202,143	)
Acquisition of East Coast Asphalt Operations		-			-			-			(803,184	)		-			(803,184	)			-				-				-				(803,184	)			-				(803,184	)
Other acquisitions		-			(7,027	)		-			-			-			(7,027	)			-				(7,027	)			-				-				-				(7,027	)
Proceeds from sale or disposition of assets		-			40,396			1			10,416			-			50,813				-				40,396				1				10,416				-				50,813
Proceeds from insurance settlement		-			-			-			5,000			-			5,000
Proceeds from insurance recoveries																					-				-				-				5,000				-				5,000
Other, net		-			-			-			24			-			24				-				-				-				24				-				24

Net cash used in investing activities		-			(18,206	)		(14,008	)		(924,303	)		-			(956,517	)			-				(18,206	)			(14,008	)			(924,303	)			-				(956,517	)


Cash flows from financing activities:
Debt borrowings		-			2,855,575			-			-			-			2,855,575				-				2,855,575				-				-				-				2,855,575
Debt repayments		-			(2,761,821	)		-			-			-			(2,761,821	)			-				(2,761,821	)			-				-				-				(2,761,821	)
Senior note offering, net		-			346,224			-			-			-			346,224				-				346,224				-				-				-				346,224
Issuance of common units, net of issuance costs		236,215			-			-			-			-			236,215				236,215				-				-				-				-				236,215
General partner contribution		5,025			-			-			-			-			5,025				5,025				-				-				-				-				5,025
Distributions to unitholders and general partner		(241,940	)		(241,940	)		-			(24	)		241,964			(241,940	)			(241,940	)			(241,940	)			-				(24	)			241,964				(241,940	)
Net intercompany (repayments) borrowings		(238,961	)		(298,292	)		(19,945	)		557,198			-			-				(238,961	)			(298,292	)			(19,945	)			557,198				-				-
Other, net		-			440			-			345			-			785				-				440				-				345				-				785

Net cash (used in) provided by financing activities		(239,661	)		(99,814	)		(19,945	)		557,519			241,964			440,063				(239,661	)			(99,814	)			(19,945	)			557,519				241,964				440,063


Effect of foreign exchange rate changes on cash		-			(5,340	)		-			(7,850	)		-			(13,190	)			-				(5,340	)			-				(7,850	)			-				(13,190	)

Net increase (decrease) in cash and cash equivalents		46			(12,282	)		534			(32,761	)		-			(44,463	)			46				(12,282	)			534				(32,761	)			-				(44,463	)
Cash and cash equivalents as of the beginning of year		7			12,284			122			77,425			-			89,838				7				12,284				122				77,425				-				89,838

Cash and cash equivalents as of the end of year	$	53		$	2		$	656		$	44,664		$	-		$	45,375		$		53		$		2		$		656		$		44,664		$		-		$		45,375


	First Quarter			Second Quarter		Third Quarter	Fourth Quarter			Total	First Quarter			Second Quarter			Third Quarter		Fourth Quarter			Total
											(Thousands of Dollars, Except Per Unit Data)
2010:
Revenues											$	945,529	$		1,124,941	$		1,138,379	$	1,194,212	$		4,403,061
Operating income												39,773			102,030			90,290		70,464			302,557
Net income												19,703			99,422			68,310		51,535			238,970
Net income per unit applicable to limited partners												0.19			1.43			0.90		0.65			3.19
Cash distributions per unit applicable to limited partners												1.0650			1.0650			1.0750		1.0750			4.280
	(Thousands of Dollars, Except Per Unit Data)
2009:
Revenues	$	634,004	$	987,842	$	1,251,247	$	982,778	$	3,855,871	$	634,004	$		987,842	$		1,251,247	$	982,778	$		3,855,871
Operating income		55,434		84,076		87,190		46,616		273,316		55,434			84,076			87,190		46,616			273,316
Net income		39,355		83,735		64,440		37,345		224,875		39,355			83,735			64,440		37,345			224,875
Net income per unit applicable to limited partners		0.58		1.38		1.03		0.50		3.47		0.58			1.38			1.03		0.50			3.47
Cash distributions per unit applicable to limited partners		1.0575		1.0575		1.0650		1.0650		4.245		1.0575			1.0575			1.0650		1.0650			4.245

2008:
Revenues	$	592,774	$	1,377,580	$	1,825,226	$	1,033,190	$	4,828,770
Operating income		65,186		40,362		175,478		29,047		310,073
Net income		55,869		14,090		151,277		32,782		254,018
Net income per unit applicable to limited partners (a)		1.01		0.15		2.60		0.46		4.22
Cash distributions per unit applicable to limited partners		0.985		0.985		1.0575		1.0575		4.085

On February 9, 2011, we acquired 75 percent of a company for approximately $54.0 million, excluding working capital of $2.4 million. The acquired company owns two terminals located in Mersin, Turkey with an aggregate 44 storage tanks and 1.3 million barrels of storage capacity. Both terminals are connected via pipelines to an offshore platform located approximately three miles off the Mediterranean Sea coast.

ITEM 9.

CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

Our management has evaluated, with the participation of the principal executive officer and principal financial officer of NuStar GP, LLC, the effectiveness of our disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934 (the Exchange Act)) as of the end of the period covered by this report, and has concluded that our disclosure controls and procedures were operating effectively as of December 31, ~~2009.~~2010.

Management’s report on NuStar Energy L.P.’s internal control over financial reporting required by Item 9A. appears in Item 8. of this report, and is incorporated herein by reference.

The report of KPMG LLP on NuStar Energy L.P.’s internal control over financial reporting appears in Item 8. of this Form 10-K, and is incorporated herein by reference.

There has been no change in our internal control over financial reporting that occurred during our last fiscal quarter that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

We do not have directors or officers. The directors and officers of NuStar GP, LLC, the general partner of our general partner, Riverwalk Logistics, L.P., perform all of our management functions. NuStar GP Holdings, LLC (NuStar GP Holdings), the sole member of NuStar GP, LLC, selects the directors of NuStar GP, LLC (the Board). Officers of NuStar GP, LLC are appointed by its directors.

Set forth below is certain information concerning the directors and executive officers of NuStar GP, LLC:

As a limited partnership, we are not required by the NYSE rules to have a nominating committee, and the Board has historically performed the functions served by a nominating committee. In accordance with our Corporate Governance Guidelines, individuals are considered for membership on the Board based on their character, judgment, integrity, diversity, age, skills (including financial literacy), independence and experience in the context of the overall needs of the Board. Our directors are also selected based on their knowledge about our industry and their respective experience leading or advising large companies. We require that our directors have the ability to work collegially, exercise good judgment and think critically. In addition, we ask that our directors commit to working hard for our company. The Board strives to find the best possible candidates to represent the interests of NuStar Energy L.P. and its unitholders. As part of its annual self-assessment process, the Board ~~annually~~ evaluates the mix of independent and non-independent directors, ~~the selection~~ and ~~functions of the presiding director and whether~~ the Board ~~has the appropriate range of talents, expertise and backgrounds.~~annually elects a presiding director.

The Board is led by its Chairman, Mr. Greehey. The Board has determined that separating the roles of Chairman and CEO is in the best interest of unitholders at this time. In addition, the Board has appointed Mr. Patton as its presiding director to serve as a point of contact for unitholders wishing to communicate with the Board and to lead executive sessions of the non-management directors.

Mr. Greehey became Chairman ~~of the board of directors~~ of the Board in January 2002. He has also been the Chairman of the board of directors of NuStar GP Holdings since March 2006. Mr. Greehey served as Chairman of the board of directors of Valero Energy Corporation (Valero Energy) from 1979 through January 2007. Mr. Greehey was CEO of Valero Energy from 1979 through December 2005, and President of Valero Energy from 1998 until January 2003.

Mr. Anastasiobecame the President and a director of NuStar GP, LLC in December 1999. He also became its CEO in June 2000. Mr. Anastasio has also served as President and Chief Executive Officer of NuStar GP Holdings since March 2006, and he has been a director of NuStar GP Holdings since January 2007.

Mr. Bates became a director of NuStar GP, LLC in April 2006. He has been President and CEO of the Southwest Research Institute since 1997. Mr. Bates also serves as Chairman of the board of Signature Science L.L.C. and Vice Chairman of Southwest Automotive Research Center. He served as Vice Chairman of the board of directors of the Federal Reserve Bank of Dallas’ San Antonio Branch from January 2005 through December 2009.

Mr. Hill became a director of NuStar GP, LLC in July 2004. From February 2001 through May 2004, he served as a consultant to El Paso Corporation. Prior to that, he served as President and CEO of Coastal Refining and Marketing Company. In 1978, Mr. Hill was named as Senior Vice President of The Coastal Corporation and President of Coastal States Crude Gathering. In 1971, he began managing Coastal’s NGL business. Previously, Mr. Hill worked for Amoco and Mobil.

Mr. McLelland became a director of NuStar GP, LLC in October 2005. He has also served as a director of NuStar GP Holdings since July 2006. Mr. McLelland has served as a director of two privately held companies, Patton Surgical Corp. and the general partner of Yorktown Technologies, LP, since November 2003 and June 2004, respectively. Mr. McLelland was U.S. Ambassador to Jamaica from January 1997 until March 2001. Prior to being named U.S. Ambassador to Jamaica, Mr. McLelland was a senior executive with Valero Energy. He joined Valero Energy in 1981 as Senior Vice President and General Counsel, and he served as Executive Vice President and General Counsel from 1990 until 1997.

Mr. Patton became a director of NuStar GP, LLC in June 2001. He retired from Merrill Lynch & Co. in 1999 where he had served as Managing Director in the Energy Group since 1993. Prior to that, he served in investment banking and corporate finance positions with Credit Suisse First Boston (1981-1993) and Blyth Eastman Paine Webber (1971-1981). He has also served as a director of Apache Corporation since 1999 and is a member of its audit committee.

Mr. Barron became Senior Vice President and General Counsel of NuStar GP, LLC and NuStar GP Holdings in April 2007. He also served as Secretary of NuStar GP, LLC and NuStar GP Holdings from April 2007 to February 2009. He served as Vice President, General Counsel and Secretary of NuStar GP, LLC from January 2006 until his promotion in April 2007. Mr. Barron also served as Vice President, General Counsel and Secretary of NuStar GP Holdings from March 2006 until his promotion in April 2007. Mr. Barron served as Managing Counsel and Corporate Secretary of NuStar GP, LLC from July 2003 until January 2006. From January 2001 until July 2003, he served as Counsel, and then Senior Counsel, to Valero Energy.

Mr. Blank became Senior Vice President and CFO of NuStar GP, LLC in January 2002, and he became NuStar GP, LLC’s Treasurer as well in July 2005. He has also served as Senior Vice President, CFO and Treasurer of NuStar GP Holdings since March 2006. From December 1999 until January 2002, he was Chief Accounting and Financial Officer and a director of NuStar GP, LLC. He served as Vice President and Treasurer of Ultramar Diamond Shamrock Corporation from December 1996 until January 2002.

Mr. Bluntzerbecame Senior Vice President-Operations of NuStar GP, LLC in October 2005. He served as Vice President-Operations of NuStar GP, LLC from February 2004 until October 2005. He served as Vice President-Terminal Operations of NuStar GP, LLC from May 2003 to February 2004. He served as Special Projects Director of NuStar GP, LLC from January 2002 to May 2003 and as Vice President of Midstream Operations of Valero Energy from June 2001 to January 2002. He served as Refinery Logistics & Supply Chain Director of Valero Energy from July 2000 to June 2001.

Mr. Brattlof became Senior Vice President-Trading and Supply of NuStar GP, LLC in April 2007. Previously, Mr. Brattlof served in various positions, including Vice President-Trading, for Valero Energy from May 1997 through April 2007.

Ms. Brown became Senior Vice President-Administration of NuStar GP, LLC in April 2008. She served as Senior Vice President-Corporate Communications from April 2007 through April 2008. Prior to her service to NuStar GP, LLC, Ms. Brown served as Senior Vice President-Corporate Communications for Valero Energy from September 1997 to April 2007.

Mr. Oliver became Senior Vice President-Marketing and Business Development of NuStar GP, LLC in April 2010. He served as Vice President-Marketing and Business Development in October ~~2008.~~2008 through April 2010. Prior to that, Mr. Oliver served as Vice President for NuStar Marketing LLC. Previously, Mr. Oliver served as Vice President-Product Supply & Distribution for Valero Energy from May 1997 to July 2007.

Mr. Shoaf became Vice President and Controller of NuStar GP, LLC in July 2005. He has also served as Vice President and Controller of NuStar GP Holdings since March 2006. Mr. Shoaf served as Vice President-Structured Finance for Valero Corporate Services Company, a subsidiary of Valero Energy, from 2001 until his appointment with NuStar GP, LLC.

Section 16(a) of the Exchange Act requires directors, executive officers and persons who beneficially own more than 10% of NuStar Energy L.P.’s equity securities to file certain reports with the Securities and Exchange Commission (SEC) concerning their beneficial ownership of NuStar Energy’s equity securities within two business days. We believe that during the year ended December 31, ~~2009~~2010 all Section 16(a) reports applicable to our executive officers, directors and greater than 10% stockholders were timely filed, with the exception of: (i) seven filings, each made one day late, to report trades of ~~an inadvertent omission~~units made on December 14, 2010 for taxes in connection with the vesting of ~~907~~restricted units ~~from the Form 3 for~~for: Mr. Barron, Mr. Blank, Mr. Bluntzer, Mr. Brattlof, ~~(which was subsequently corrected~~Ms. Brown, Mr. Oliver and Mr. Shoaf; and (ii) as reported on Form 5 filed on February ~~10, 2010) and the filing~~14, 2011, four purchases of units by Ms. Brown’s son and Mr. Oliver’s Forms 3 one day late. In addition, Mr. Bluntzer filed a Form 5 on February 24, 2010 to report the acquisition of an aggregate 40 common units that were purchased pursuant to a dividend reinvestment program administered by his securities broker.daughter during 2010.

NuStar GP, LLC has adopted a Code of Ethics for Senior Financial Officers that applies to NuStar GP, LLC’s principal executive officer, principal financial officer and controller. This code charges the senior financial officers with responsibilities regarding honest and ethical conduct, the preparation and quality of the disclosures in documents and reports NuStar GP, LLC files with the SEC and compliance with applicable laws, rules and regulations.

The Audit Committee reviews and reports to the Board on various auditing and accounting matters, including the quality, objectivity and performance of NuStar Energy’s internal and external accountants and auditors, the adequacy of its financial controls and the reliability of financial information reported to the public. The Audit Committee also monitors NuStar Energy’s compliance with environmental laws and regulations. The Board has adopted a written charter for the Audit Committee. The members of the Audit Committee during ~~2009~~2010 were Rodman D. Patton (Chairman), J. Dan Bates and Dan J. Hill. The Audit Committee met eight times in ~~2009.~~2010. For further information, see the“Report of the Audit Committee” below.

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

Management of NuStar GP, LLC is responsible for NuStar Energy’s internal controls and the financial reporting process. KPMG LLP (KPMG), NuStar Energy’s independent registered public accounting firm for the year ended December 31, ~~2009,~~2010, is responsible for performing an independent audit of NuStar Energy’s consolidated financial statements in accordance with the standards of the Public Company Accounting Oversight Board (PCAOB) and generally accepted auditing standards, and an audit of NuStar Energy’s internal control over financial reporting in accordance with the standards of the PCAOB, and issuing a report thereon. The Audit Committee monitors and oversees these processes and approves the selection and appointment of NuStar Energy’s independent registered public accounting firm and recommends the ratification of such selection and appointment to the Board.

The Audit Committee has reviewed and discussed NuStar Energy’s audited consolidated financial statements with management and KPMG. The Audit Committee has discussed with KPMG the matters required to be discussed by Statement on Auditing Standards No. 114 ~~as adopted~~ by the PCAOB. The Audit Committee

has received written disclosures and the letter from KPMG required by applicable requirements of the Audit Committee concerning independence and has discussed with KPMG that firm’s independence.

Based on the foregoing review and discussions and such other matters the Audit Committee deemed relevant and appropriate, the Audit Committee recommended to the Board that the audited consolidated financial statements of NuStar Energy be included in NuStar Energy’s Annual Report on Form 10-K for the year ended December 31, ~~2009.~~2010.

While it is the job of management to assess and manage our risk, the Board of Directors and its Audit Committee (each where applicable) discuss the guidelines and policies that govern the process by which risk assessment and management is undertaken and evaluate reports from various functions with the management team on risk assessment and management. The Board interfaces regularly with management and receives periodic reports that include updates on operational, financial, legal and risk management matters. The Audit Committee assists the Board in oversight of the integrity of NuStar Energy’s financial statements and NuStar Energy’s compliance with legal and regulatory requirements, including those related to the health, safety and environmental performance of our company. The Audit Committee also reviews and assesses the performance of NuStar Energy’s internal audit function and its independent auditors. The Board receives regular reports from the Audit Committee. We do not believe that the Board’s role in risk oversight has an effect on the Board’s leadership structure.

Evaluation of Compensation ~~Risk.~~Risk. The Compensation Committee has focused on aligning our compensation policies with the long-term interests of NuStar Energy and avoiding short-term rewards for management decisions that could pose long-term risks to NuStar Energy. NuStar Energy’s compensation programs are structured so that a considerable amount of our management’s compensation is tied to NuStar Energy’s long-term fiscal health. The only short-term incentive available to NuStar Energy employees and executives is the all-employee performance bonus. All bonuses, including executive bonuses, are determined with reference to performance metrics selected by the Compensation Committee and applicable to all employees. Historically, our long-term incentives have taken the form of performance units, restricted units and unit options that typically vest over three- and five-year periods, thereby aligning our employees’ interests with the long-term goals of NuStar Energy. No business group or unit is compensated differently than any other, regardless of profitability. As such, we believe that our compensation policies encourage employees to operate our business in a fundamentally sound manner and do not create incentives to take risks that are reasonably likely to have a material adverse effect on NuStar Energy.

The Compensation Committee has reviewed and discussed the Compensation Discussion and Analysis with management. Based on ~~the foregoing~~its review and discussion and such other matters the Compensation Committee deemed relevant and appropriate, the Compensation Committee recommended to the Board that the Compensation Discussion and Analysis be included in this annual report.

Our philosophy for compensating our named executive officers ~~(NEO)~~(NEOs) is based on the belief that a significant portion of executive compensation should be incentive-based and determined by both NuStar Energy’s and the executive’s performance objectives. Our executive compensation programs are designed to accomplish the following long-term objectives:

Compensation for our ~~named executive officers~~NEOs primarily consists of base salary, an annual incentive bonus and long-term, equity-based incentives. Our executives participate in the same group benefit programs available to our salaried employees in the United States. In addition, see “Post-Employment Benefits” below in this Item 11. Our executives do not have employment or severance agreements, other than the change-of-control agreements described below in “Potential Payments Upon Termination or Change of Control.” The Compensation Committee targets base salary for our ~~named executive officers,~~NEOs, as well as annual incentive bonus and long-term incentive awards (expressed, in each case, as a percentage of base salary), at or near the median of our peer group and after reviewing survey data for a group of 825 industrial companies. In each case, an executive’s salary and incentive opportunities are determined by the unique responsibilities of his or her position and by each executive’s experience and performance, with the market information in mind.

~~Throughout this Item 11,~~Our NEOs for the ~~individuals serving as our principal executive officer and our principal financial officer during the last completed fiscal~~ year ~~(Curtis~~ended December 31, 2010 were: Curtis V. Anastasio, ~~and~~ Steven A. Blank, ~~respectively) and our three other most highly compensated executive officers who were serving as executive officers at the end of the last completed fiscal year (James~~James R. Bluntzer, Paul W. Brattlof and Mary Rose ~~Brown) are referred to collectively as the “named executive officers” or NEOs.~~Brown.

Our executive compensation programs are administered by our Board’s Compensation Committee. The Compensation Committee is composed of three independent directors who are not participants in our executive compensation programs. Policies adopted by the Compensation Committee are implemented by our compensation and benefits staff.

Annually, the Compensation Committee reviews market trends in compensation, including the practices of identified competitors, and the alignment of the compensation program with NuStar Energy’s strategy. Specifically, for executive officers, the Compensation Committee:

In making determinations about total compensation for executives, the Compensation Committee takes into account a number of factors, including: the competitive market for talent; compensation paid at peer companies; NuStar Energy’s performance; the particular executive’s role, responsibilities, experience and performance; and retention. The Compensation Committee also considers other equitable factors such as the role, contribution and performance of an individual executive relative to the executive’s peers at the company. The Compensation Committee does not assign specific weight to these factors, but rather makes a subjective judgment taking all of these factors into account.

The Compensation Committee has retained BDO Seidman, LLP (BDO) as its independent compensation consultant with respect to executive compensation matters. In its role as advisor to the Compensation Committee, BDO was retained directly by the Compensation Committee, which has the authority to select, retain and/or terminate its relationship with a consulting firm.

~~In 2009, the~~The Compensation Committee ~~relied~~relies upon two primary sources of competitive compensation data in assessing base salary rates, annual incentive compensation and long-term incentive compensation: a group of master limited partnerships and other companies in our industry and broader survey data on comparably sized entities.

To establish compensation for the ~~named executive officers,~~NEOs, including the CEO, the Committee, in consultation with management and BDO, identified a specific group of 15 master limited partnerships and three independent, regional refining companies to evaluate competitive rates of compensation (the Compensation Comparative Group). The three refining companies, Frontier Oil Corporation, Holly Corporation and Western Refining Inc., were added to our prior peer list ~~last year~~in 2008 to account for our acquisition of asphalt refining and marketing assets from CITGO Asphalt Refining Company in March 2008. Each of these organizations is in our industry, and, in our opinion, competes with us for executive talent. The competitive data for these companies is derived from their respective publicly filed annual proxy statements or annual reports on Form 10-K. ~~The 2009 data was compiled and analyzed by BDO.~~

The Compensation Committee also ~~reviewed~~periodically reviews survey data reported on a position-by-position basis to ascertain additional information regarding compensation of comparable positions. The survey data consists of general industry data for executive positions reported in the Towers Perrin Executive Compensation General Industry database, a proprietary compensation database of an approximate 825 U.S. industrial companies that is updated each year. ~~At our request,~~In 2009, BDO reviewed and interpreted the tabular data from the Towers Perrin survey for companies in a range of reported revenues comparable to NuStar Energy’s. We refer to the competitive survey data, together with the Compensation Comparative Group data, as the Compensation Comparative Data.

The Compensation Committee reviews and approves all compensation for the ~~named executive officers.~~NEOs. Recommendations regarding compensation for ~~named executive officers~~NEOs other than the CEO are developed by the CEO in consultation with BDO. In making these recommendations, the CEO ~~takes into consideration~~considers the Compensation Comparative Data and evaluates the individual performance of each named executive officer and their respective contributions to the Company. The recommendations are then reviewed by the Compensation Committee, which may accept the recommendations or may make adjustments to the recommended compensation based on their own assessment of the individual’s performance and contributions to NuStar Energy.

As required by the Compensation Committee’s charter, the compensation of the CEO is reviewed and approved by the Compensation Committee based on the Compensation Comparative Data; discretionary adjustments may be made based upon their independent evaluation of the CEO’s performance and contributions.

Each July, the Compensation Committee reviews the ~~named executive officers’~~NEOs’ total compensation, including base salary and the target levels of annual incentive and long-term incentive compensation. ~~Its~~Prior to 2010, the review ~~includes~~has included a comparison with competitive market data provided by BDO, an evaluation of the total compensation of the executive officer group from an internal equity perspective and reviews of reports on the compensation history of each executive. Based on these reviews and evaluations, the Compensation Committee ~~establishes~~established annual salary rates for executive officer positions for the upcoming 12-month period and sets target levels of annual incentive and long-term incentive compensation. Although the target levels are established in July, the long-term incentives are reviewed again at the time of grant, typically in the fourth quarter for unit options and restricted units and in the first quarter for performance units. The Compensation Committee may also review salaries or grant long-term incentive awards at other times during the year because of new appointments, promotions or other extraordinary circumstances.

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

Setting meeting dates for action by the Compensation Committee for the upcoming year

Fourth quarter

Additional information regarding the timing of ~~2009~~2010 long-term incentive grants is discussed below under “Performance Units” and “Restricted Units.”

Our executive compensation programs currently consist of the following material elements:

We use base salary as the foundation for our executive compensation program. We believe that base salary should provide a fixed level of competitive pay that reflects the executive officer’s primary duties and responsibilities, as well as a foundation for incentive opportunities and benefit levels. Our annual incentive bonuses are designed to focus our executives on NuStar Energy’s attainment of our distributable cash flow (DCF), which is widely regarded among the master limited partnership (MLP) investment community as a significant determinant of an MLP’s unit price. Our long-term equity incentive awards are designed to directly tie an executive’s financial reward opportunities with the rewards to unitholders, as measured by long-term unit price performance and payment of distributions. Throughout this Item 11, we use the term “Total Direct Compensation” to refer to the sum of an executive officer’s base salary, annual incentive bonus and long-term incentive awards for a particular fiscal year. We also offer group medical benefits that allow employees (including NEOs) affordable coverage at group rates, as well as pension benefits that reward continued service and a thrift plan that provides a tax-advantaged savings opportunity.

In setting executive compensation, the Compensation Committee considers the aggregate amount of compensation payable to an executive officer and the form of the compensation. The Compensation Committee seeks to achieve the appropriate balance between salary, cash rewards earned for the achievement of company and personal objectives and long-term incentives that align the interests of our executive officers with those of our unitholders. The size of each element is based on competitive market practices, as well as company and individual performance.

The level of incentive compensation typically increases in relation to an executive officer’s responsibilities, with the level of incentive compensation for more senior executive officers being a greater percentage of total compensation than for less senior executives. The Compensation Committee believes that making a significant portion of an executive officer’s incentive compensation contingent on long-term unit price performance more closely aligns the executive officer’s interests with those of our unitholders.

Because we place such a large proportion of our total executive compensation at risk in the form of variable pay ~~(i.e.~~(i.e. annual and long-term incentives), the Compensation Committee does not adjust current compensation based upon realized gains or losses from prior incentive awards. For example, we will not reduce the size of a target long-term incentive grant in a particular year solely because NuStar Energy’s unit price performed well during the immediately preceding years. We believe that adopting a policy of making such adjustments would penalize management’s current compensation for NuStar Energy’s prior success.

The following table summarizes the relative size of base salary and incentive compensation targets for ~~2009~~2010 for each of our ~~named executive officers:~~


	Target Percentage of Total Direct Compensation
Name					Target Percentage of Total Direct Compensation
Name	Base Salary	Annual Incentive Bonus	Long-Term Incentives	TOTAL	Base Salary (%)	Annual Incentive Bonus	Long-Term Incentives	TOTAL
Anastasio	30	24	46	100	29	24	47	100
Blank	43	22	35	100	40	20	40	100
Bluntzer	43	22	35	100	40	20	40	100
Brattlof	43	22	35	100	42	20	38	100
Brown	43	22	35	100	40	20	40	100

The Compensation Committee evaluates our ~~named executive officers’~~NEOs’ individual performance and personal objectives with input from our CEO. Our CEO’s performance is evaluated by the Compensation Committee in consultation with other members of the Board.

Assessment of individual performance may include objective criteria, but is a largely subjective process. The criteria used to measure an individual’s performance may include use of quantitative criteria (e.g., execution of projects within budget, improving an operating unit’s profitability, or timely completion of an acquisition or divestiture), as well as more qualitative factors, such as the executive officer’s ability to lead, ability to communicate and successful adherence to NuStar’s core values (i.e., environmental and workplace safety, integrity, work commitment, effective communication and teamwork). There are no specific weights given to any of these various elements of individual performance.

We use our evaluation of individual performance to supplement our objective compensation criteria and adjust an executive officer’s recommended compensation. For example, although an individual officer’s indicated bonus may be calculated to be $100,000, an individual performance evaluation might result in a reduction ~~to $90,000~~ or increase ~~to $120,000~~ of that indicated bonus.

The base salaries for our executive officers are reviewed annually by the Compensation Committee based on recommendations of our CEO, with input from BDO and our compensation and benefits staff. Our CEO’s base salary is reviewed and approved by the Compensation Committee based on its review of recommendations by BDO and our compensation and benefits staff.

The competitiveness of base salaries for each executive position is determined by an evaluation of the compensation data described above. Base salaries may be adjusted to achieve what is determined to be a reasonably competitive level or to reflect promotions, the assignment of additional responsibilities, individual performance or the performance of NuStar Energy. Salaries are also periodically adjusted to remain competitive with the Compensation Comparative Data.

In July ~~2009,~~2010, our ~~named executive officers~~NEOs received the same 3% adjustment to annualized base salaries that was approved for all eligible employees.


Name	Annualized Base Salary	July 2009 Increase to Prior Annualized Base Salary	Annualized Base Salary at December 31, 2010	July 2010 Increase to Prior Annualized Base Salary
Anastasio	$473,800	$13,800	$488,000	$14,200
Blank	340,900	9,900	351,130	10,230
Bluntzer	305,500	8,900	314,670	9,170
Brattlof	289,600	8,400	298,290	8,690
Brown	305,500	8,900	314,670	9,170

Our ~~named executive officers~~NEOs participate in ~~a formal~~the annual incentive plan in which all domestic company employees participate. Under the plan, ~~the named executive officers~~participants can earn annual incentive bonuses based on the following three factors:

The following table shows the percentage of each ~~named executive officer’s annual base~~NEO’s salary paid in 2010 that represents his or her annual bonus target for the fiscal year ended December 31, ~~2009,~~2010, before discretionary adjustments, as discussed below:

As stated above, each named executive officer has an annual incentive opportunity generally based on a stated percentage of his or her base salary. This target proportion is the annual incentive award for achieving a 100% score on our stated financial goal under the bonus plan. For example, Mr. Anastasio has a target annual incentive opportunity equal to 80% of his base annual salary. Mr. ~~Anastasio’s annual~~Anastasio was paid $480,900 in salary ~~rate beginning July 2009 was $473,800,~~for 2010, and therefore, his target annual incentive opportunity for a 100% score was ~~$379,040.~~$384,700. In addition, the plan allows for the upward or downward adjustment of awards, based upon attainment of the financial goal, equal to a range of 0% to 200% of the target award. If we failed to reach at least the threshold level of performance for our financial goal, the participant would have earned an incentive award of $0. Likewise, if we had achieved the maximum level of performance for the financial goal, the participant could earn up to 200% of his target award.

Once the financial goals have been reviewed and measured, the Compensation Committee has the authority to exercise its discretion in evaluating NuStar Energy’s performance. In exercising this discretionary judgment, the Compensation Committee considers such relevant performance factors as growth, attainment of strategic objectives, acquisitions and divestitures, safety and environmental compliance, and other considerations. This discretionary judgment may result in an increase or decrease of as much as 25% of the aggregate earned award for all employees based upon the attainment of the financial goals noted above.

The CEO develops individual incentive bonus recommendations based upon the methodology described above. In addition, both the CEO and the Compensation Committee may make adjustments to the recommended incentive bonus amounts based upon an assessment of an individual’s performance and contributions to NuStar Energy. The CEO and the Compensation Committee also review and discuss each executive bonus on a case-by-case basis, considering such factors as teamwork, leadership, individual accomplishments and initiative, and may adjust the bonus awarded to reflect these factors.

The bonus target for the CEO is decided solely by the Compensation Committee, and the Compensation Committee may make discretionary adjustments to the calculated level of bonus based upon its independent evaluation of the CEO’s performance and contributions.

In ~~2007,~~2010, as in prior years, the Compensation Committee ~~adopted~~approved a DCF ~~per unit (DCF Per Unit) as the~~metric for NuStar Energy’s bonus metric, ~~in acknowledgement that, in~~based on management’s recommendations and input from BDO. In the ~~master limited partnership~~MLP investment community, DCF is widely regarded as a significant determinant of unit price, and, as such, the Compensation Committee believes the measure appropriately focuses employees on improving DCF. ~~In 2008, the Compensation Committee approved a change to a simple DCF metric, based on~~

management’s recommendations and input from BDO. Management’s recommendation to move to a simple DCF target rather than DCF Per Unit was based on the fact that an increase to the distribution serves to reduce DCF Per Unit (but not DCF) through the operation of the incentive distribution rights held by our general partner, NuStar GP Holdings. We believe that basing bonus on DCF ~~more properly~~ aligns our management’s interest with our unitholders’ interest in continuously increasing distributions in a prudent manner.

We derive DCF from our financial statements by adjusting our net income for depreciation and amortization expense, equity earnings from joint ventures and unrealized gains and losses arising from certain derivative contracts. Additionally, we subtract our aggregate annual reliability capital expenditures and add the aggregate annual amount of cash distributions received from equity method investees.

Each year, the Compensation Committee establishes NuStar Energy’s budgeted DCF for the year as a target and establishes corresponding levels of performance for which the incentive opportunity would be paid, such that if less than 90% of the target was attained, no bonus would be paid; if 90% of the target was attained, 50% of the incentive opportunity could be paid; if the target was achieved, 100% of the incentive opportunity could be paid; if 110% of the target was attained, 150% of the incentive opportunity could be paid; and if 120% or more of the target was attained, 200% of the incentive opportunity could be paid. The budgeted DCF may be adjusted during the year to account for acquisitions or other significant changes not anticipated at the time the target was determined. In ~~2009,~~2010, NuStar’s budgeted DCF was ~~$355,000,000.~~$335,400,000.

For the ~~2009~~2010 annual incentive bonus determination, the Compensation Committee measured NuStar Energy’s DCF against the established target to determine the amount of incentive award earned. NuStar Energy’s DCF for ~~2009~~2010 would have resulted in payment of ~~65%~~101% of the incentive opportunity.

Upon reviewing the ~~65%~~101% performance score and upon management’s recommendation, the Compensation Committee exercised its discretionary judgment regarding the plan and ~~further~~ adjusted the performance score ~~upward~~ to ~~75%~~100%. This resulted in each employee, including the ~~named executive officers,~~NEOs, having a potential annual incentive award equal to ~~75%~~100% of his or her target award. In making the adjustment, the Compensation Committee took into consideration ~~the 42% increase in unit price and 48% total unitholder return for 2009, the successful completion of the integration of our asphalt operations,~~ NuStar Energy’s ~~exceptional health and safety record, and our~~management’s continuing emphasis on cost-control, balanced by a desire to appropriately recognize and reward our employees’ significant ~~accomplishments.~~accomplishments in 2010.

We provide unit-based, long-term compensation for employees, including executives and directors, through our Second Amended and Restated 2000 Long-Term Incentive Plan (the 2000 LTIP), which was approved by our unitholders on September 18, 2006. ~~In previous years, we have provided such compensation under the NuStar GP, LLC Amended and Restated 2002 Unit Option Plan and the NuStar GP, LLC Amended and Restated 2003 Employee Unit Incentive Plan.~~ The 2000 LTIP provides for a variety of unit and unit-based awards, including unit options, restricted units and performance units. Performance units vest (become nonforfeitable) upon the achievement of an objective performance goal. ~~Grants of restricted unit and unit options each~~Long-term incentive awards vest over a period determined by the Compensation Committee.

Under the design of the long-term incentive award plan, each plan participant, including the ~~named executive officers,~~NEOs, are designated a target long-term incentive award expressed as a percentage of base salary. This percentage reflects the expected fair value of the awards to be granted in aggregate each year. In determining the expected fair value, BDO employed a projected value model to determine the value of long-term incentive grants, which requires first calculating

an award by projecting the growth in the fair market value of a unit and then calculating the present value of the expected gain at the end of five years.

For the ~~named executive officers,~~NEOs, the ~~2009~~2010 long-term incentive target percentages (expressed as a percent of base salary) were established as shown in the table below.

These targets, as well as the allocation between time- and performance-based grants described below, reflect the Compensation Committee’s 2009 review of the Compensation Comparative Data and discussion of the appropriate balance to best retain executives, align management with unitholder concerns and reward management for increases in unitholder value. The committee reviews these targets, as well as allocation between types of grants on at least an annual basis. At its meeting on February 26, 2010, after a discussion of the current Compensation Comparative Data and the factors described above, the Compensation Committee determined it to be appropriate to raise the long-term incentive targets as follows: Mr. Anastasio 160%, Mr. Blank, Mr. Bluntzer and Ms. Brown, 100% and Mr. Brattlof, 90%.

The Compensation Committee allocates a percentage of long-term award value to performance-based awards and a percentage to awards that focus on retention and increasing ownership levels of executive officers. In ~~2009,~~2010, the target levels were allocated in the following manner for each individual:

The Compensation Committee reviews and approves all grants for the ~~named executive officers, as well as all other participants in the program.~~NEOs. The CEO develops individual grant recommendations based upon the methodology described above, but both the CEO and the Compensation Committee may make adjustments to the recommended grants based upon an assessment of an individual’s performance and contributions to NuStar Energy. The ~~grant for~~grants to the CEO is decided solely by the Compensation Committee following the methodology described above, and the Compensation Committee may make discretionary adjustments to the calculated ~~number~~level of long-term incentives to grant based upon its independent evaluation of the CEO’s performance and contributions.


Name	Restricted Units Granted in 2009		Restricted Units Granted in 2010
Name	NS	NSH	NS	NSH
Anastasio	6,900	6,500	6,900	6,500
Blank	2,645	2,495	3,065	2,560
Bluntzer	2,370	2,235	2,750	2,290
Brattlof	2,245	2,120	2,345	1,955
Brown	2,370	2,235	2,750	2,290

The restricted units comprise approximately 70% of each executive’s total NuStar Energy long-term incentive target. The Compensation Committee presently expects to grant restricted units annually. The executives’ long-term incentive targets include approximately 70% NuStar Energy restricted units and 30% NuStar GP Holdings restricted units (in both cases, calculated from an assumed unit value based on the average closing price for the business days in the last two weeks of August ~~2009,~~2010, and adjusted for the risk of forfeiture). The restricted units all vest in equal increments on the anniversary of the grant date over five years. Restricted units of NuStar GP Holdings were introduced into the compensation program in 2008 to reflect the fact that the performance of NuStar GP Holdings is directly tied to the performance of NuStar Energy, ~~due to the fact that~~since NuStar GP Holdings’ sole asset is its interest in NuStar Energy. The ~~grant of the~~ NuStar GP Holdings restricted units grants, as well as the ~~grant~~grants of the NuStar Energy restricted units, were approved in a joint meeting of the Compensation Committee and the compensation committee of NuStar GP Holdings’ Board of ~~Directors~~Directors.

In ~~2009,~~2010, the Compensation Committee and management made a determination that the grants for employees, ~~excluding~~including management and non-employee directors, would be made as soon as administratively practicable after the third business day following our third quarter earnings release, which was ~~November 6, 2009. At~~October 25, 2010. Due to an across-company evaluation by management designed to standardize long-term incentive grant targets across titles and departments, along with management’s introduction of improvements to the ~~time the Compensation Committee approved~~software tool used to execute the grants, ~~of restricted units, NuStar Energy’s Board had approved an equity offering of NuStar Energy units. Given~~ the ~~impending offering, the Committee determined that the grants to executive management, certain other employees and the non-employee directors would be delayed~~grant date was not administratively practicable until December ~~14, 2009, which was thirty (30) calendar days after the closing date of the equity offering.~~30, 2010.

Performance units comprise approximately 30% of each of our ~~named executive officers’~~NEOs’ total NuStar Energy long-term incentive targets. The Compensation Committee expects to award performance units annually. Performance units are earned only upon NuStar Energy’s achievement of an objective performance measure, total unitholder return (TUR), as compared with ~~a subset of~~ the Compensation Comparative ~~Group consisting of the first nine entities listed in the peer group table above.~~Group. NuStar Energy’s TUR is the total return to unitholders, based upon the growth in the unit price, as well as cash distributions to unitholders, during the year. The entities selected most closely track with our size and business, making their TUR performance most comparable with ours (the Peer Group). Further, while the Compensation Comparative Group represents the market in which we compete for executive talent, the smaller group selected for purposes of measuring relative TUR is representative of the market in which we compete for capital. The Compensation Committee believes this type of incentive award strengthens the tie between the named executive’s pay and our financial performance.

The number of performance units granted is determined by multiplying annual base salary rate by the Long-Term Incentive Target Percentage, and then multiplying that product by 30%. That product is then divided by the assumed

value of an individual unit, which is the product of (x) the average unit price for the period of December 15 through December 31 (using the daily high and low prices) and (y) a factor that reflects the present value of the award and a risk that the award might be forfeited.

Each award is subject to vesting in three annual increments, based upon our TUR during rolling three-year periods that end on December 31 of each year following the date of grant. At the end of each performance period, our TUR is compared to the ~~Peer~~Compensation Comparative Group and ranked by quartile. Executives then earn 0%, 50%, 100% or 150% of that portion of the initial grant amount that is vesting, depending upon whether our TUR is in the last, 3rd, 2nd or 1st quartile, respectively, and they earn 200% if we rank highest in the group. Amounts not earned in a given performance period can be carried forward for one additional performance period and up to 100% of the carried amount can still be earned, depending upon the quartile achieved for that subsequent period. For the performance period ended December 31, ~~2009,~~2010, our performance ranked in the ~~fourth~~first quartile of the group for the rolling three-year period, which ~~results~~resulted in no vesting of 150% the ~~2009~~2010 performance units available to vest in ~~2010. Due to the fact~~2011. Units that ~~NuStar Energy generated a 48% total unitholder return for 2009 alone, the Committee decided to carry forward the performance units that would~~did not vest in prior years and have been ~~forfeited for that period for one additional year.~~carried over vested at 100%.

We provide only minimal perquisites to our executive officers. Mr. Anastasio and Ms. Brown ~~receive~~received reimbursement for club membership dues. Mr. Anastasio, Mr. Blank, Mr. Brattlof and Ms. Brown received federal income tax preparation services in ~~2009.~~2010. Executives are also eligible to receive liability insurance. For more information on perquisites, see the Summary Compensation Table and its footnotes.

We provide other benefits, including medical, life, dental and disability insurance in line with competitive market conditions. Our ~~named executive officers~~NEOs are eligible for the same benefit plans provided to our other employees, including our pension plan, 401(K) thrift plan (the Thrift Plan) and insurance and supplemental plans chosen and paid for by employees who desire additional coverage. Executive officers and other employees whose compensation exceeds certain limits are eligible to participate in non-qualified excess benefit programs whereby those individuals can choose to make larger contributions than allowed under the qualified plan rules and receive correspondingly higher benefits. These plans are described below under “Post-Employment Benefits.”

For a discussion of our pension plans, including the Excess Pension Plan and the Supplemental Executive Retirement Plan, please see the narrative description accompanying the Pension Benefits table below this item.

The Excess Thrift Plan provides unfunded benefits to those employees of NuStar GP, LLC whose annual additions under the Thrift Plan are subject to the limitations on such annual additions as provided under §415 of the Internal Revenue Code of 1986, as amended (the Code), and/or who are constrained from making maximum contributions under the Thrift Plan by §401(a)(17) of the Code, which limits the amount of an employee’s annual compensation which may be taken into account under that plan. The Excess Thrift Plan is comprised of two separate components, consisting of (1) an “excess benefit plan” as defined under §3(36) of The Employee Retirement Income Security Act of 1974, as amended (ERISA) and (2) a plan that is maintained primarily for the purpose of providing deferred compensation for a select group of management or highly compensated employees. Each component of the Excess Thrift Plan consists of a separate plan for purposes of Title I of ERISA. To the extent a participant’s annual total compensation exceeds the compensation limits for the calendar year under §401(a)(17) of the Code ($245,000 for ~~2009)~~2010), the participant’s excess thrift plan account is credited with that number of hypothetical NuStar Energy units that could have been purchased with the difference between:

Mr. Anastasio, Mr. Blank, Mr. Bluntzer, Mr. Brattlof and Ms. Brown participated in the Excess Thrift Plan in ~~2009.~~2010.

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

We entered into change of control agreements with each of the ~~named executive officers~~NEOs in, or prior to, 2007. These agreements are intended to assure the continued availability of these executives in the event of certain transactions culminating in a “change of control” as defined in the agreements. The change of control employment agreements have three-year terms, which terms are automatically extended for one year upon each anniversary unless a notice not to extend is given by us. If a “change of control” (as defined in the agreements) occurs during the term of an agreement, then the

agreement becomes operative for a fixed three-year period. The agreements provide generally that the executive’s terms and conditions of employment (including position, location, compensation and benefits) will not be adversely changed during the three-year period after a change of control of us.

Particular payments under the agreements are triggered commensurate with the occurrence of any of the following: (i) termination of employment by the company other than for “cause” (as defined in the agreements) or disability, (ii) termination by the executive for “good reason” (as defined in the agreements), (iii) termination by the executive other than for “good reason,” and (iv) termination of employment because of death or disability. These triggers were designed to ensure the continued availability of the executives following a change of control, and to compensate the executives at appropriate levels if their employment is unfairly or prematurely terminated during the applicable term following a change of control. For more information regarding payment that may be made under our severance arrangements, see our disclosures below under the caption “Potential Payments upon Termination or Change-in-Control Payments.”

None of the named executive officers have employment agreements other than the change-of-control agreements described above. As a result, in the event of a termination, retirement, death or disability, an officer will only receive compensation or benefits to which he or she would be entitled under the terms of, as applicable, the defined contribution, defined benefit, medical or long-term incentive plans.

NuStar Energy’s financial statements include the expense for awards of NuStar Energy unit options and restricted units to NuStar GP, LLC employees and directors and the expense for awards of NuStar GP Holdings unit options and restricted units to NuStar GP, LLC employees, as we are obligated to pay for all costs of NuStar GP, LLC’s employees working on our behalf in accordance with the Services Agreement described below in Item 13. Certain Relationships and Related Transactions and Director Independence. Under the Services Agreement, 1% of NuStar GP, LLC’s domestic unit compensation expense is charged back to NuStar GP Holdings.

NuStar GP, LLC accounts for awards of NuStar Energy L.P. common units to NuStar GP, LLC’s employees and directors as a derivative, whereby a liability for the award is recorded at inception. Subsequent changes in the fair value of the award are included in the determination of net income.

Each month, NuStar GP, LLC determines the fair value of its liability for awards of NuStar Energy unit options and restricted units. The fair value of unit options is determined using the Black-Scholes model at each reporting date. The fair value of restricted units equals the market price of NuStar Energy common units at each reporting date. NuStar GP, LLC records compensation expense each reporting period such that the cumulative compensation expense recorded equals the current fair value, considering the percentage of the award that has vested to date. NuStar GP, LLC records compensation expense related to unit options until such options are exercised, and records compensation expense for restricted units until the date of vesting.

NuStar GP Holdings accounts for awards of restricted units and unit options awarded to its directors, oras well as the employees and directors of NuStar GP, LLC, at fair value. NuStar GP Holdings uses the market price at the grant date as the fair value of restricted units. NuStar GP Holdings estimates the fair value of unit options at the grant date using the Black-Scholes ~~model~~model. For both restricted units and unit options, NuStar GP Holdings recognizes the resulting compensation expense ~~is recognized over the vesting period. NuStar GP Holdings estimates the fair value of restricted units equal to the market price at the grant date. The resulting compensation expense is recognized~~ over the vesting period.

For certain awards, the terms of the compensation plans provide that employees vest in the award when they retire or will continue to vest in the award after retirement over the nominal vesting period established in the award. For any awards subsequent to January 1, 2006, we recognize compensation expense immediately for awards granted to retirement-eligible employees or over the period from the grant date to the date retirement eligibility is achieved if that date is expected to occur during the nominal vesting period. Employees are typically retirement eligible at age 55.

Under Section 162(m) of the Code, publicly held corporations may not take a tax deduction for compensation in excess of $1 million paid to the CEO or the other four most highly compensated executive officers unless that compensation meets the Code’s definition of “performance-based” compensation. Section 162(m) allows a deduction for compensation to a specified executive that exceeds $1 million only if it is paid (i) solely upon attainment of one or more performance goals, (ii) pursuant to a qualifying performance-based compensation plan adopted by the Compensation Committee, and (iii) the material terms, including the performance goals, of such plan are approved by the unitholders before payment of the compensation. The Compensation Committee considers deductibility under Section 162(m) with respect to compensation arrangements for executive officers. The Compensation Committee believes that it is in the best interest of NuStar Energy for the Compensation Committee to retain its flexibility and discretion to make compensation awards to foster achievement of performance goals established by the Compensation Committee (which may include performance goals defined in the Code) and other corporate goals the Compensation Committee deems important to NuStar Energy’s success, such as encouraging employee retention, rewarding achievement of nonquantifiable goals and achieving progress with specific projects. NuStar Energy believes that unit options and performance unit grants qualify as performance-based compensation and are not subject to any deductibility limitations under Section 162(m). Grants of restricted units and other equity-based awards that are not subject to specific quantitative performance measures will likely not qualify as “performance-based” compensation and, in such event, would be subject to 162(m) deduction restrictions.

Our Board, the Compensation Committee and our executives recognize that ownership of NuStar Energy L.P. units is an effective means by which to align the interests of NuStar GP, LLC directors and executives with those of NuStar Energy’s unitholders. We have long emphasized and reinforced the importance of unit ownership among our executives and directors.

During 2006, the Compensation Committee worked with its independent compensation consultant to formalize unit ownership and retention guidelines for directors and NuStar GP, LLC officers to ensure continuation of our successful track record in aligning the interests of NuStar GP, LLC directors and officers with those of NuStar Energy’s unitholders through ownership of NuStar Energy units. The guidelines were approved by the Compensation Committee and the Board in March 2006. In February 2007, in view of the public offerings of NuStar GP Holdings in 2006, the Compensation Committee amended the guidelines to include ownership of either NuStar GP Holdings units or NuStar Energy units. An officer or a director’s ownership also includes units subject to vesting.

Non-employee directors are expected to acquire and hold during their service as a Board member NuStar Energy units and/or NuStar GP Holdings units with an aggregate value of at least $50,000. Directors have five years from their initial election to the Board to meet the target unit ownership guidelines, and they are expected to continuously own sufficient units to meet the guidelines, once attained.

Our officers are expected to meet the applicable guideline within five years and continuously own sufficient units to meet the guideline, once attained.

Prohibition on Insider Trading and Speculation on NuStar Energy L.P. or NuStar GP Holdings, LLC Units

We have established policies prohibiting our officers, directors and employees from purchasing or selling either NuStar Energy L.P. or NuStar GP Holdings, LLC securities while in possession of material, nonpublic information or otherwise using such information for their personal benefit or in any manner that would violate applicable laws and regulations. Our outside directors, officers and certain other employees are prohibited from trading in either NuStar Energy L.P. or NuStar GP Holdings, LLC securities for the period beginning on the last business day of each calendar quarter through the second business day following our disclosure of our quarterly or annual financial results. In addition, our policies prohibit our officers, directors and employees from speculating in the either NuStar Energy L.P. or NuStar GP Holdings, LLC units, which includes short selling (profiting if the market price of our units decreases), buying or selling publicly traded options (including writing covered calls), hedging or any other type of derivative arrangement that has a similar economic effect. Our directors, officers and certain other employees are also required to receive management consent before they enter into margin loans or other financing arrangements that may lead to the ownership or other rights to their NuStar Energy L.P. or NuStar GP Holdings, LLC securities being transferred to a third party.

The tables that appear in the following ~~sections~~pages of this ~~proxy statement~~section provide information required by the SEC regarding compensation paid to or earned by our ~~named executive officers~~NEOs for the year ended December 31, ~~2009.~~2010. We have used captions and headings in these tables in accordance with the SEC regulations requiring these disclosures. The footnotes to these tables provide important information to explain the values presented in the tables, and are an important part of our disclosures.

The following table provides a summary of compensation paid for the years ended December 31, ~~2009,~~2010, December 31, ~~2008~~2009 and December 31, ~~2007~~2008 to NuStar GP, LLC’s CEO, CFO and to its three other most highly compensated executive officers. The table shows amounts earned by such persons for services rendered to NuStar GP, LLC in all capacities in which they served.

Name and Principal
Position

Year

Salary ($)

Bonus ($)(1)

Unit Awards

($)(2)

Option

Awards ($)(3)

Non-Equity Incentive

Plan Compensation ($)

Change in Pension Value

and Nonqualified

Deferred Compensation

Earnings ($)(4)

All Other

Compensation

($)(5)

Total ($)

Year

Salary ($)

Bonus ($)(1)

Unit Awards
($)(2)

Option
Awards ($)(3)

Non-Equity Incentive

Plan Compensation ($)

Change in Pension Value
and Nonqualified
Deferred Compensation
Earnings ($)(4)

All Other
Compensation
($)(5)

Total ($)

Curtis V. Anastasio

President and

CEO

2009

466,900

284,300

832,123

195,281

37,632

1,816,236

2010

480,900

385,000

1,019,418

190,656

37,001

2,112,975

2008

448,400

368,000

739,738

172,039

41,159

1,769,336

2009

466,900

284,300

832,123

195,281

37,632

1,816,236

2007

428,400

393,120

620,167

413,667

46,806

39,568

1,941,728

2008

448,400

368,000

739,738

172,039

41,159

1,769,336

Steven A. Blank

Senior Vice President,

CFO and Treasurer

2009

335,950

127,800

316,949

124,551

24,266

929,516

2010

346,015

173,000

442,407

129,601

25,466

1,116,489

2008

324,516

165,500

301,406

137,330

73,227

1,001,979

2009

335,950

127,800

316,949

124,551

24,266

929,516

2007

311,916

238,524

288,565

301,250

36,731

24,150

1,201,136

2008

324,516

165,500

301,406

137,330

73,227

1,001,979

James R. Bluntzer

Senior Vice President -

Operations

2009

301,350

115,000

286,221

174,431

19,817

896,819

2008

273,840

148,000

260,195

150,751

21,172

853,958

2007

246,840

195,000

247,723

257,165

135,019

20,208

1,101,955

James R. Bluntzer

Senior Vice President-

Operations

2010

310,085

155,000

396,775

150,003

20,156

1,032,019

2009

301,350

115,000

286,221

174,431

19,817

896,819

2008

273,840

148,000

260,195

150,751

21,172

853,958

Paul W. Brattlof

Senior Vice President-

Supply and Trading

2010

293,945

147,000

338,466

47,013

22,342

848,856

2009

285,392

108,600

269,663

39,902

19,710

723,267

2009

285,392

108,600

269,663

39,902

19,710

723,267

Mary Rose Brown

Senior Vice President-

Administration

2009

301,350

115,000

286,221

54,276

25,737

782,584

2010

310,085

155,000

396,775

63,442

18,555

943,857

Mary Rose Brown

Senior Vice President-

Administration

2009

301,350

115,000

286,221

54,276

25,737

782,584

(1)

2010 bonus awards were paid in February 2011 with respect to 2010 performance. 2009 bonus amounts were paid in February 2010 with respect to 2009 performance. 2008 bonus amounts were paid in February 2009 with respect to 2008 ~~performance. 2007 bonus amounts were paid in January 2008 with respect to 2007~~ performance. Bonuses were determined taking into consideration the individual executive’s targets, the executive’s performance and NuStar Energy’s performance in the applicable year, as described above under “Compensation Disclosure & Analysis-Annual Incentive Bonus.”

(2)

The amounts reported represent the grant date fair value of grants of restricted NuStar Energy L.P. units, NuStar Energy L.P. performance units and ~~beginning in 2008,~~ restricted NuStar GP Holdings, LLC units. Please see “Compensation Discussion and Analysis-Impact of Accounting and Tax Treatment-Accounting Treatment” above in this item for more information.

(3)

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

(4)

For the applicable NEOs, the following table identifies the separate amounts attributable to (A) the aggregate change in the actuarial present value of the NEO’s accumulated benefit under NuStar GP, LLC’s defined benefit and actuarial pension plans, including supplemental plans (but excluding tax-qualified defined contribution plans and nonqualified defined contribution plans), and (B) above-market or preferential earnings on compensation that is deferred on a basis that is not tax-qualified.

(5)	The amounts reported in this column for ~~2009~~2010 consist of the following for each officer:


Name	Club Dues	Company Contribution to Thrift Plan	Company Contribution to Excess Thrift Plan	Tax Preparation	Personal Liability Insurance	Executive Health Exams (a)	TOTAL	Club Dues		Company Contribution to Thrift Plan		Company Contribution to Excess Thrift Plan		Tax Preparation		Personal Liability Insurance		Executive Health Exams (a)		TOTAL
Anastasio	$7,032	$12,650	$15,364	$850	$1,736	$0	$37,632		$7,032		$12,552		$14,154		$850		$2,413		$0		$37,001
Blank	0	14,700	5,457	850	1,736	1,523	24,266		0		14,700		6,061		850		2,413		1,442		25,466
Bluntzer	0	12,510	5,571	0	1,736	0	19,817		0		12,396		3,905		0		2,413		1,442		20,156
Brattlof	0	14,952	2,172	850	1,736	0	19,710		0		17,637		0		850		2,413		1,442		22,342
Brown	5,070	6,583	11,498	850	1,736	0	25,737		5,070		6,317		3,905		850		2,413		0		18,555

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


Name	Grant Date	Date of approval by Comp Committee		Estimated Future Payouts Under Equity Incentive Plan Awards						All Other Unit Awards: Number of Units (#)	All Other Option Awards: Number of Securities Underlying Options (#)	Exercise or Base Price of Option Awards ($/Un)	Grant Date Fair Value of Unit and Unit Option Awards ($)	Grant Date		Date of approval by Comp Committee		Estimated Future Payouts Under Equity Incentive Plan Awards							All Other Unit Awards: Number of Units (#)			All Other Option Awards: Number of Securities Underlying Options (#)		Exercise or Base Price of Option Awards ($/Unit)		Grant Date Fair Value of Unit and Unit Option Awards ($)
Name	Grant Date		Threshold (#)		Target (#)		Maximum (#)					Exercise or Base Price of Option Awards ($/Un)	Grant Date Fair Value of Unit and Unit Option Awards ($)	Grant Date	Threshold (#)				Target (#)		Maximum (#)				All Other Unit Awards: Number of Units (#)					Exercise or Base Price of Option Awards ($/Unit)		Grant Date Fair Value of Unit and Unit Option Awards ($)
	01/22/2009(1)	Date of approval by Comp Committee	01/22/2009		0		6,383		12,766	All Other Unit Awards: Number of Units (#)	-	-	-	288,895(4)
Anastasio	12/14/2009(2)	10/14/2009		-		-		-		6,900	-	-	373,773(5)	02/26/2010(1)		Date of approval by Comp Committee	02/26/2010			0		5,230		10,460			-		-		-			300,150	(4)
	12/14/2009(3)	10/14/2009		-		-		-		6,500	-	-	169,455(6)
	01/22/2009(1)	01/22/2009		0		2,400		4,800		-	-	-	108,624(4)
Anastasio														12/30/2010(2)		10/20/2010			-		-		-			6,900		-		-			481,758	(5)
														12/30/2010(3)		10/20/2010			-		-		-			6,500		-		-			237,510	(6)
	12/14/2009(2)	10/14/2009		-		-		-		2,645	-	-	143,280(5)	02/26/2010(1)		02/26/2010			0		2,350		4,700			-		-		-			134,867	(4)
	12/14/2009(3)	10/14/2009		-		-		-		2,495	-	-	65,045(6)
	01/22/2009(1)	01/22/2009		0		2,200		4,400		-	-	-	99,572(4)
Blank														12/30/2010(2)		10/20/2010			-		-		-			3,065		-		-			213,998	(5)
														12/30/2010(3)		10/20/2010			-		-		-			2,560		-		-			93,542	(6)
	12/14/2009(2)	10/14/2009		-		-		-		2,370	-	-	128,383(5)	02/26/2010(1)		02/26/2010			0		2,110		4,220			-		-		-			121,093	(4)
	12/14/2009(3)	10/14/2009		-		-		-		2,235	-	-	58,266(6)
	01/22/2009(1)	01/22/2009		0		2,050		4,100		-	-	-	92,783(4)
Bluntzer														12/30/2010(2)		10/20/2010			-		-		-			2,750		-		-			192,005	(5)
														12/30/2010(3)		10/20/2010			-		-		-			2,290		-		-			83,677	(6)
	12/14/2009(2)	10/14/2009		-		-		-		2,245	-	-	121,612(5)	02/26/2010(1)		02/26/2010			0		1,800		3,600			-		-		-			103,302	(4)
	12/14/2009(3)	10/14/2009		-		-		-		2,120	-	-	55,268(6)
Brattlof														12/30/2010(2)		10/20/2010			-		-		-			2,345		-		-			163,728	(5)
														12/30/2010(3)		10/20/2010			-		-		-			1,955		-		-			71,436	(6)
	01/22/2009(1)	01/22/2009		0		2,200		4,400		-	-	-	99,572(4)	02/26/2010(1)		02/26/2010			0		2,110		4,220			-		-		-			121,093	(4)
Brown	12/14/2009(2)	10/14/2009		-		-		-		2,370	-	-	128,383(5)	12/30/2010(2)		10/20/2010			-		-		-			2,750		-		-			192,005	(5)
	12/14/2009(3)	10/14/2009		-		-		-		2,235	-	-	58,266(6)	12/30/2010(3)		10/20/2010			-		-		-			2,290		-		-			83,677	(6)

(3)

Restricted units of NuStar GP Holdings, LLC were approved by the Compensation Committee of NuStar GP Holdings at a joint meeting with the Compensation Committee of NuStar GP, LLC on October ~~14, 2009,~~20, 2010, and the grant date for these restricted units was set at that time for the date ~~30 calendar days~~that was as soon as administratively practicable after the ~~close of NuStar Energy L.P.’s then-impending equity offering.~~third quarter earnings announcement. The restricted units vest 1/5 annually over five years beginning on the first anniversary of the grant date.

~~(3)~~

Restricted units of NuStar Energy were granted by the Compensation Committee at a joint meeting with the Compensation Committee of NuStar GP Holdings, LLC on October 14, 2009 and the grant date for these restricted units was set at that time for the date 30 calendar days after the close of

~~NuStar Energy L.P.’s then-impending equity offering. The restricted units vest 1/5 annually over five years beginning on the first anniversary of the grant date.~~

(4)

The grant date fair value for performance units was determined by multiplying the number of performance units that were granted by the NYSE closing unit price of our units on the date of grant, ~~$45.26.~~$57.39.

(5)

The grant date fair value for restricted units was determined by multiplying the number of restricted units that were granted by the NYSE closing unit price of our units on the date of grant, $69.82.

(6)

The grant date fair value for restricted units was determined by multiplying the number of NuStar GP Holdings, LLC restricted units that were granted by the NYSE closing unit price of NuStar GP Holdings, LLC units on the date of grant, ~~$26.07.~~

~~(6)~~

~~The grant date fair value for restricted units was determined by multiplying the number of restricted units that were granted by the NYSE closing unit price of our units on the date of grant, $54.17.~~$36.54.

The following table provides further information regarding our ~~named executive officers’~~NEOs’ unexercised unit options, unvested restricted units and unvested performance units as of December 31, ~~2009.~~2010. The value of NuStar Energy restricted units reported below is equal to ~~$56.09,~~$69.48, the NuStar Energy L.P. closing price on the NYSE on December 31, ~~2009.~~2010. The value of the NuStar GP Holdings, LLC restricted units reported below is equal to ~~$26.92,~~$36.33, the NuStar GP Holdings, LLC closing price on the NYSE on December 31, ~~2009.~~2010.


	Option Awards					Unit Awards				Option Awards							Unit Awards
Name	Number of Securities Underlying Unexercised Options (#) Exercisable	Number of Securities Underlying Unexercised Options (#) Unexercisable	Equity Incentive Plan Awards: Number of Securities Underlying Unexercised Unearned Options (#)	Option Exercise Price ($)	Option Expiration Date	Number of Units That Have Not Vested (#)	Market Value of Units That Have Not Vested ($)	Equity Incentive Plan Awards: Number of Unearned Units or Other Rights That Have Not Vested (#)	Equity Incentive Plan Awards: Market or Payout Value of Unearned Units or Other Rights That Have Not Vested ($)	Number of Securities Underlying Unexercised Options (#) Exercisable		Number of Securities Underlying Unexercised Options (#) Unexercisable		Equity Incentive Plan Awards: Number of Securities Underlying Unexercised Unearned Options (#)	Option Exercise Price ($)	Option Expiration Date	Number of Units That Have Not Vested (#)	Market Value of Units That Have Not Vested ($)		Equity Incentive Plan Awards: Number of Unearned Units or Other Rights That Have Not Vested (#)	Equity Incentive Plan Awards: Market or Payout Value of Unearned Units or Other Rights That Have Not Vested ($)
	14,000(1)	0	-	38.22	03/22/2012	-	-	-	-		14,000(1)		0	-	38.22	03/22/2012	-		-	-	-
	10,000(2)	0	-	36.30	09/23/2012	-	-	-	-		10,000(2)		0	-	36.30	09/23/2012	-		-	-	-
	11,800(3)	0	-	45.35	10/29/2013	-	-	-	-		11,800(3)		0	-	45.35	10/29/2013	-		-	-	-
Anastasio	9,625(4)	0	-	56.51	10/28/2014	-	-	-	-		9,625(4)		0	-	56.51	10/28/2014	-		-	-	-
	10,760(5)	2,690	-	57.51	10/27/2012	-	-	-	-		13,450(5)		0	-	57.51	10/27/2012	-		-	-	-
	6,600(6)	4,400	-	55.92	11/02/2013	-	-	-	-		8,800(6)		2,200	-	55.92	11/02/2013	-		-	-	-
	0(7)	56,300	-	31.55	11/16/2014	-	-	-	-		18,767(7)		37,533	-	31.55	11/16/2014	-		-	-	-
	-	-	-	-	-	20,602(9)	1,155,566	-	-		-		-	-	-	-	21,242(9)		1,475,894	-	-
	-	-	-	-	-	13,460(10)	362,343	-	-		-		-	-	-	-	16,920(10)		614,704	-	-
	-	-	-	-	-	11,739(11)	658,441	-	-		-		-	-	-	-	16,969(11)		1,179,006	-	-
	3,333(1)	0	-	38.22	03/22/2012	-	-	-	-		3,333(1)		0	-	38.22	03/22/2012	-		-	-	-
	3,333(2)	0	-	36.30	09/23/2012	-	-	-	-		3,333(2)		0	-	36.30	09/23/2012	-		-	-	-
	8,700(3)	0	-	45.35	10/29/2013	-	-	-	-		8,700(3)		0	-	45.35	10/29/2013	-		-	-	-
Blank	6,875(4)	0	-	56.51	10/28/2014	-	-	-	-		6,875(4)		0	-	56.51	10/28/2014	-		-	-	-
	5,780(5)	1,445	-	57.51	10/27/2012	-	-	-	-		7,225(5)		0	-	57.51	10/27/2012	-		-	-	-
	3,075(6)	2,050	-	55.92	11/02/2013	-	-	-	-		4,100(6)		1,025	-	55.92	11/02/2013	-		-	-	-
	0(7)	41,000	-	31.55	11/16/2014	-	-	-	-		13,667(7)		27,333	-	31.55	11/16/2014	-		-	-	-
	-	-	-	-	-	8,565(12)	480,411	-	-		-		-	-	-	-	8,895(12)		618,025	-	-
	-	-	-	-	-	5,215(13)	140,388	-	-		-		-	-	-	-	6,596(13)		239,633	-	-
	-	-	-	-	-	4,907(14)	275,234	-	-		-		-	-	-	-	7,257(14)		504,216
	4,500(1)	0	-	38.22	03/22/2012	-	-	-	-		4,500(1)		0	-	38.22	03/22/2012	-		-	-	-
	2,675(3)	0	-	45.35	10/29/2013	-	-	-	-		2,675(3)		0	-	45.35	10/29/2013	-		-	-	-
	2,475(4)	0	-	56.51	10/28/2014	-	-	-	-		2,475(4)		0	-	56.51	10/28/2014	-		-	-	-
Bluntzer	4,320(5)	1,080	-	57.51	10/27/2012	-	-	-	-		5,400(5)		0	-	57.51	10/27/2012	-		-	-	-
	2,430(6)	1,620	-	55.92	11/02/2013	-	-	-	-		3,240(6)		810	-	55.92	11/02/2013	-		-	-	-
	0(7)	35,000	-	31.55	11/16/2014	-	-	-	-		11,667(7)		23,333	-	31.55	11/16/2014	-		-	-	-
	-	-	-	-	-	7,472(15)	419,104	-	-		-		-	-	-	-	7,896(15)		548,614	-	-
	-	-	-	-	-	4,635(16)	124,774	-	-		-		-	-	-	-	5,878(16)		213,548	-	-
	-	-	-	-	-	4,216(17)	236,475	-	-		-		-	-	-	-	6,326(17)		439,530	-	-


										Option Awards							Unit Awards
Name										Number of Securities Underlying Unexercised Options (#) Exercisable		Number of Securities Underlying Unexercised Options (#) Unexercisable		Equity Incentive Plan Awards: Number of Securities Underlying Unexercised Unearned Options (#)	Option Exercise Price ($)	Option Expiration Date	Number of Units That Have Not Vested (#)	Market Value of Units That Have Not Vested ($)		Equity Incentive Plan Awards: Number of Unearned Units or Other Rights That Have Not Vested (#)	Equity Incentive Plan Awards: Market or Payout Value of Unearned Units or Other Rights That Have Not Vested ($)
	680(8)	1,020	-	69.15	04/30/2014	-	-	-	-		1,020(8)		680	-	69.15	04/30/2014	-		-	-	-
	0(7)	35,000	-	31.55	11/16/2014	-	-	-	-		11,667(7)		23,333	-	31.55	11/16/2014	-		-	-	-
Brattlof	-	-	-	-	-	6,885(18)	386,180	-	-		-		-	-	-	-	7,421(18)		515,611	-	-
	-	-	-	-	-	4,360(19)	117,371	-	-		-		-	-	-	-	5,331(19)		193,675	-	-
	-	-	-	-	-	3,578(20)	200,690	-	-		-		-	-	-	-	5,378(20)		373,663	-	-
	680(8)	1,020	-	69.15	04/30/2014	-	-	-	-		1,020(8)		680	-	69.15	04/30/2014	-		-	-	-
	0(7)	35,000	-	31.55	11/16/2014	-	-	-	-		11,667(7)		23,333	-	31.55	11/16/2014	-		-	-	-
Brown	-	-	-	-	-	7,090(21)	397,678	-	-		-		-	-	-	-	7,986(21)		554,867	-	-
	-	-	-	-	-	4,635(22)	124,774	-	-		-		-	-	-	-	5,878(22)		213,548	-	-
	-	-	-	-	-	3,728(23)	209,104	-	-		-		-	-	-	-	5,838(23)		405,624	-	-

(14)

Mr. Blank’s unvested NuStar Energy L.P. performance units were granted January 26, 2006, January 25, 2007, January 24, 2008, ~~and~~ January 22, 2009 and February 26, 2010 and vest in accordance with the description in Footnote (11) above.

~~For the 2007 period, Mr. Blank received no vested performance units.~~ For the 2008 period, Mr. Blank received a total of 1,350 units. For the 2009 period, Mr. Blank received no vested performance units.

For the 2010 period, Mr. Blank received a total of 5,965 units.

(15)

Mr. Bluntzer’s restricted NuStar Energy L.P. units consist of: ~~362 restricted units granted October 27, 2005; 620~~310 restricted units granted November 2, 2006; ~~1,800~~1,200 restricted units granted November 16, 2007; ~~2,320~~1,740 restricted units granted November 6, ~~2008 and 2,370~~2008; 1,896 restricted units granted December 14, ~~2009.~~2009; and 2,750 restricted units granted December 30, 2010. All of Mr. Bluntzer’s restricted units vest in 1/5 increments over five years, beginning on the first anniversary of the date of grant.

(16)

Mr. Bluntzer’s restricted NuStar GP Holdings, LLC units consist of: ~~2,400~~1,800 restricted units granted November 6, ~~2008 and 2,235~~2008; 1,788 restricted units granted December 14, ~~2009.~~2009; and 2,290 restricted units granted December 30, 2010. All of Mr. Bluntzer’s restricted units vest in 1/5 increments over five years, beginning on the first anniversary of the date of grant.

(17)

Mr. Bluntzer’s unvested NuStar Energy L.P. performance units were granted January 26, 2006, January 25, 2007, January 24, 2008, ~~and~~ January 22, 2009 and February 26, 2010 and vest in accordance with Footnote (11) above. ~~For the 2007 period, Mr. Bluntzer received no vested performance units.~~ For the 2008 period, Mr. Bluntzer received a total of 1,054 units. For the 2009 period, Mr. Bluntzer received no vested performance units. For the 2010 period, Mr. Bluntzer received a total of 5,136 units.

(18)

Mr. Brattlof’s restricted NuStar Energy L.P. units consist of: ~~600~~400 restricted units granted April 30, 2007; ~~1,800~~1,200 restricted units granted November 16, 2007; ~~2,240~~1,680 restricted units granted November 6, 2008; ~~and 2,245~~1,796 restricted units granted December 14, ~~2009.~~2009; and 2,345 restricted units granted December 30, 2010. All of Mr. Brattlof’s restricted units vest in 1/5 increments over five years, beginning on the first anniversary of the date of grant.

(19)

Mr. Brattlof’s restricted NuStar GP Holdings, LLC units consist of: ~~2,240~~1,680 restricted units granted November 6, ~~2008 and 2,120~~2008; 1,696 restricted units granted December 14, ~~2009.~~2009; and 1,955 restricted units granted December 30, 2010. All of Mr. Brattlof’s restricted units vest in 1/5 increments over five years, beginning on the first anniversary of the date of grant.

(20)

Mr. Brattlof’s unvested NuStar Energy L.P. performance units were granted April 30, 2007, January 24, 2008, ~~and~~ January 22, 2009 and February 26, 2010 and vest in accordance with Footnote (11) above. For the 2009 period, Mr. Brattlof received no vested performance units. For the 2010 period, Mr. Brattlof received a total of 4,369 units.

(21)

Ms. Brown’s restricted NuStar Energy L.P. units consist of: ~~600~~400 restricted units granted April 30, 2007; ~~1,800~~1,200 restricted units granted November 16, 2007; ~~2,320~~1,740 restricted units granted November 6, 2008; ~~and 2,370~~1,896 restricted units granted December 14, ~~2009.~~2009; and 2,750 restricted units granted December 30, 2010. All of Ms. Brown’s restricted units vest in 1/5 increments over five years, beginning on the first anniversary of the date of grant.

(22)

Ms. Brown’s restricted NuStar GP Holdings, LLC units consist of: ~~2,400~~1,800 restricted units granted November 6, ~~2008 and 2,235~~2008; 1,788 restricted units granted December 14, ~~2009.~~2009; and 2,290 restricted units granted December 30, 2010. All of Ms. Brown’s restricted units vest in 1/5 increments over five years, beginning on the first anniversary of the date of grant.

(23)

~~Mr.~~Ms. Brown’s unvested NuStar Energy L.P. performance units were granted April 30, 2007, January 24, 2008, ~~and~~ January 22, 2009 and February 26, 2010 and vest in accordance with Footnote (11) above. For the 2009 period, Ms. Brown received no vested performance units. For the 2010 period, Ms. Brown received a total of 4,648 units.

The following table provides further information regarding option exercises by our ~~named executive officers,~~NEOs, and the vesting of restricted units and performance units held by our ~~named executive officers,~~NEOs, during ~~2009.~~2010.


	Option Awards(1)		Unit Awards		Option Awards(1)		Unit Awards
Name	Number of Units Acquired on Exercise (#)	Value Realized on Exercise ($)	Number of Units Acquired on Vesting (#)	Value Realized on Vesting ($)(7)	Number of Units Acquired on Exercise (#)	Value Realized on Exercise ($)	Number of Units Acquired on Vesting (#)	Value Realized on Vesting ($)(7)
Anastasio	-	-	10,153(2)	469,220	-	-	9,300(2)	526,377
Blank	-	-	4,786(3)	224,864	-	-	3,914(3)	223,880
Bluntzer	-	-	3,704(4)	171,807	-	-	3,373(4)	192,297
Brattlof	-	-	2,396(5)	107,115	-	-	2,793(5)	156,344
Brown	-	-	2,456(6)	109,146	-	-	2,901(6)	161,715

The following table provides information regarding the accumulated benefits of our named executive officer under NuStar GP, LLC’s pension plans during the year ended December 31, ~~2009.~~2010.


Name	Plan Name	Number of Years Credited Service	Present Value of Accumulated Benefit($)(1)	Payments During Last Fiscal Year	Plan Name	Number of Years Credited Service	Present Value of Accumulated Benefit($)(1)	Payments During Last Fiscal Year
Anastasio	NuStar GP, LLC Pension Plan	3.5	80,323	0	NuStar GP, LLC Pension Plan	4.5	119,378	0
Anastasio	NuStar GP, LLC Excess Pension Plan	-	173,991	0	NuStar GP, LLC Excess Pension Plan	-	252,425	0
	NuStar GP, LLC Supplemental Executive Retirement Plan	8.0	419,371	0
Anastasio					NuStar GP, LLC Supplemental Executive Retirement Plan	9.0	492,537	0
	NuStar GP, LLC Pension Plan	3.5	87,858	0	NuStar GP, LLC Pension Plan	4.5	129,950	0
	NuStar GP, LLC Excess Pension Plan	-	98,318	0	NuStar GP, LLC Excess Pension Plan	-	139,029	0
	NuStar GP, LLC Supplemental Executive Retirement Plan	8.0	295,584	0
Blank					NuStar GP, LLC Supplemental Executive Retirement Plan	9.0	342,383	0
	NuStar GP, LLC Pension Plan	3.5	87,421	0	NuStar GP, LLC Pension Plan	4.5	129,339	0
	Excess Pension Plan	33.7	654,669	0	Excess Pension Plan	34.6	762,754	0
	Supplemental Executive Retirement Plan	-	-	0
Bluntzer					Supplemental Executive Retirement Plan	-	-	0
	NuStar GP, LLC Pension Plan	2.8	46,810	0	NuStar GP, LLC Pension Plan	3.8	74,741	0
	Excess Pension Plan	2.8	34,083	0	Excess Pension Plan	3.8	53,165	0
	Supplemental Executive Retirement Plan	-	-	0
Brattlof					Supplemental Executive Retirement Plan	-	-	0
	NuStar GP, LLC Pension Plan	2.7	61,538	0	NuStar GP, LLC Pension Plan	3.7	97,454	0
	Excess Pension Plan	2.7	54,526	0	Excess Pension Plan	3.7	82,053	0
	Supplemental Executive Retirement Plan	-	-	0
Brown					Supplemental Executive Retirement Plan	-	-	0

We maintain a noncontributory defined benefit pension plan in which most of our employees are eligible to participate and under which contributions by individual participants are neither required nor permitted. We also maintain a noncontributory, non-qualified excess pension plan and a non-qualified supplemental executive retirement plan, or SERP, which provide supplemental pension benefits to certain highly compensated employees. The excess pension plan and the SERP provide eligible employees with additional retirement savings opportunities that cannot be achieved with tax-qualified plans due to the Code’s limits on (1) annual compensation that can be taken into account under qualified plans or (2) annual benefits that can be provided under qualified plans. Employees who are eligible for the excess pension plans and the SERP may participate in one or the other, but not both plans.

The Pension Plan is a traditional defined benefit pension plan established as of July 1, 2006 and designed to provide retirement benefits to our eligible employees based upon a specific formula. The formula used to calculate a pension benefit under the plan takes into consideration final average salary and total years of credited service. Certain participants who were participants in the Valero Energy Pension Plan prior to becoming eligible for participation in the Pension Plan received credit for their service recognized under the Valero Energy Pension Plan for purposes of vesting and eligibility under this plan.

Under an agreement between the companies, Valero Energy will pay pension benefits to eligible NuStar GP, LLC employees for their years of service with Valero Energy under the Valero Energy pension plan, and the employee’s highest annual salary will be determined with regard to service with NuStar GP, LLC after July 1, 2006 until the individual commences a benefit under the Valero Energy pension plan or terminates employment with NuStar GP, LLC. For more information about the Valero Energy Pension Plan, please see Valero Energy’s annual report on Form 10-K for the year ended December 31, 2008 and its 2009 annual proxy statement. The Pension Plan is intended to be a qualified plan under, and subject to, relevant provisions of the Code and the Employee Retirement Income Security Act of 1974, as amended (ERISA).

The Pension Plan (supplemented, as necessary, by the excess pension plan or the SERP described below) provides a monthly pension at normal retirement equal to 1.6% of the eligible employee’s average monthly compensation (based upon the eligible employee’s earnings during the three consecutive calendar years during the last ten years of the eligible employee’s credited service, including service with our former parent, Valero Energy, affording the highest such average) times the eligible employee’s years of credited service. Pension benefits are not subject to any deduction for social security or other offset amounts.

Eligible employees are NuStar GP, LLC employees, except for those employees who are nonresident aliens, who are U.S. citizens but being paid by a foreign affiliated employer (as defined in the plan), who are covered by a collective bargaining agreement (unless it expressly provides for the benefits provided under the plan), or who are not yet participating.

The Excess Pension Plan was established effective as of July 1, 2006 for the purpose of providing benefits to eligible employees of NuStar GP, LLC whose pension benefits under the Pension Plan and the Valero Energy Pension Plan, where applicable, are subject to limitations under the Code. The Excess Pension Plan is an excess benefit plan as contemplated under ERISA for those benefits provided in excess of Section 415 of the Code. Benefits provided as a result of other statutory limitations are limited to a select group of management or highly compensated employees. The Excess Pension Plan is not intended to constitute either a qualified plan under the Code or a funded plan subject to ERISA. For employees of NuStar GP, LLC who were eligible to receive a benefit under the Valero Energy Excess Pension Plan (the Predecessor Excess Pension Plan) as of July 1, 2006, the Excess Pension Plan assumed the liabilities of the Predecessor Excess Pension Plan and will provide a single, nonqualified defined benefit to eligible employees for their pre-July 1, 2006 benefit accruals under the Predecessor Excess Pension Plan and their post-July 1, 2006 benefit accruals under this Excess Pension Plan.

An eligible employee’s monthly pension under the Excess Pension Plan will be equal to (i) 1.6% of the employee’s average monthly compensation multiplied by the employee’s years of serviceless (ii) the employee’s Pension Plan benefit. Mr. Bluntzer, Mr. Brattlof and Ms. Brown participate in the Excess Pension Plan.

The SERP was established effective as of July 1, 2006 for the purpose of providing certain highly compensated, management personnel of NuStar GP, LLC and its subsidiaries a supplement to the retirement benefit they may otherwise receive under the Pension Plan and the Valero Energy Pension Plan, where applicable. The SERP is not intended to constitute either a qualified plan under the Code or a funded plan subject to ERISA. For employees of NuStar GP, LLC who were eligible to receive a benefit under the Valero Energy Supplemental Executive Retirement Plan (the Prior SERP) as of July 1, 2006, the SERP assumed the liabilities of the Prior SERP and shall provide a single, nonqualified defined benefit to eligible employees for their pre-July 1, 2006 benefit accruals under the Prior SERP and their post-July 1, 2006 benefit accruals under this SERP.

The following table provides additional information regarding contributions by NuStar GP, LLC and each of our ~~named executive officers~~NEOs under our non-qualified defined contribution and other deferred compensation plans during the year ended December 31, ~~2009.~~2010. The table also presents each named executive officer’s withdrawals, earnings and year-end balances in such plans. Please see the descriptions of our Excess Thrift Plan and the Frozen Nonqualified 401(k) Plan above in “Compensation Discussion and Analysis- Post-Employment Benefits.”


Name	Executive Contributions in 2009 ($)(1)	Registrant Contributions in 2009 ($)(2)	Aggregate Earnings in 2009 ($)(3)	Aggregate Withdrawals/ Distributions ($)(4)	Aggregate Balance at December 31, 2009 ($)(5)	Executive Contributions in 2010 ($)(1)	Registrant Contributions in 2010 ($)(2)	Aggregate Earnings in 2010 ($)(3)	Aggregate Withdrawals/ Distributions ($)(4)	Aggregate Balance at December 31, 2010 ($)(5)
Anastasio	0	15,364	63,907	0	381,892	0	14,154	58,159	0	454,205
Blank	0	5,457	180,874	0	1,010,265	0	6,061	132,017	0	1,148,343
Bluntzer	0	5,571	2,847	0	15,211	0	3,905	4,859	0	23,975
Brattlof	0	2,172	1,165	0	6,527	0	0	1,945	0	8,472
Brown	0	11,498	686	0	12,258	0	3,905	4,104	0	20,267

Each of our ~~named executive officers~~NEOs has entered into a Change of Control Severance Agreement with NuStar Energy and NuStar GP, LLC. These agreements seek to assure the continued availability of these executives in the event of a “change of control” (described below) of NuStar. When determining the amounts and benefits payable under the agreements, the Compensation Committee sought to secure compensation that is competitive in our market in order to recruit and retain executive officer talent. Consideration was given to the principal economic terms found in written employment and change of control agreements of other publicly traded companies.

When a change of control occurs, the agreement becomes operative for a fixed three-year period. The agreements provide generally that the executive’s terms of employment will not be adversely changed during the three-year period after a change of control. In addition, outstanding unit options held by the executive will automatically vest, restrictions applicable to outstanding restricted units held by the executive will lapse, and all unvested performance units held by the executive will fully vest and become payable at 200% of target. The executives are also entitled to receive a payment in an amount sufficient to make the executive whole for any excise tax on excess parachute payments imposed under Section 4999 of the Code. Each agreement subjects the executive to obligations of confidentiality, both during the term and after termination, for secret and confidential information relating to NuStar Energy, NuStar GP, LLC and their affiliates (as defined in the agreement) that the executive acquired during his or her employment.

For purposes of these agreements, a “change of control” means any of the following (subject to additional particulars as stated in the agreements):

In the agreements, “cause” is defined to mean, generally, the willful and continued failure of the executive to perform substantially the executive’s duties, or the willful engaging by the executive in illegal or gross misconduct that is materially and demonstrably injurious to the company. “Good reason” is defined to mean, generally:

SEC regulations require us to disclose potential payments to an executive in connection with his or her termination or a change of control of NuStar. We have elected to use the following table to make the required disclosures. Except as noted, values assumes that a change of control occurred on December 31, ~~2009,~~2010, and that the executive’s employment was terminated on that date.

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


Executive Benefits and Payments	Termination of Employment by the Company Other Than for “Cause” or Disability, or by the Executive for “Good Reason” (2)	Termination of Employment because of Death or Disability (3)	Termination by the Executive Other Than for “Good Reason” (4)	Continued Employment Following Change of Control (5)	Termination of Employment by the Company Other Than for “Cause” or Disability, or by the Executive for “Good Reason” (2)	Termination of Employment because of Death or Disability (3)	Termination by the Executive Other Than for “Good Reason” (4)	Continued Employment Following Change of Control (5)
Salary (1)
Anastasio	$1,421,400	$0	$0	$0	$1,464,000	$0	$0	$0
Blank	681,800	0	0	0	702,260	0	0	0
Bluntzer	611,000	0	0	0	629,340	0	0	0
Brattlof	579,200	0	0	0	596,580	0	0	0
Brown	611,000	0	0	0	629,340	0	0	0


Bonus (1)
Anastasio	$1,179,360	$393,120	$393,120	$0	$1,155,000	$385,000	$385,000	$ 0
Blank	477,048	238,524	238,524	0	346,000	173,000	173,000	0
Bluntzer	390,000	195,000	195,000	0	310,000	155,000	155,000	0
Brattlof	390,000	195,000	195,000	0	294,000	147,000	147,000	0
Brown	390,000	195,000	195,000	0	310,000	155,000	155,000	0


Pension, Excess Pension, and SERP Benefits
Anastasio	$589,534	$0	$0	$0	$647,987	$ 0	$ 0	$ 0
Blank	225,641	0	0	0	216,395	0	0	0
Bluntzer	321,781	0	0	0	345,801	0	0	0
Brattlof	117,421	0	0	0	132,665	0	0	0
Brown	160,283	0	0	0	167,515	0	0	0


Contributions under Defined Contribution Plans
Anastasio	$156,046	$0	$0	$0	$157,086	$ 0	$ 0	$ 0
Blank	69,531	0	0	0	62,896	0	0	0
Bluntzer	60,060	0	0	0	56,360	0	0	0
Brattlof	58,152	0	0	0	53,435	0	0	0
Brown	60,060	0	0	0	56,360	0	0	0


Health and Welfare Plan Benefits (6)
Anastasio	$77,163	$0	$0	$0	$67,170	$ 0	$ 0	$ 0
Blank	47,702	0	0	0	49,460	0	0	0
Bluntzer	33,668	0	0	0	36,420	0	0	0
Brattlof	43,426	0	0	0	42,452	0	0	0
Brown	30,114	0	0	0	28,186	0	0	0


Accelerated Vesting of Unit Options (7)
Anastasio	$748	$748	$748	$748
Blank	349	349	349	349
Bluntzer	275	275	275	275
Brattlof	0	0	0	0
Brown	0	0	0	0

Accelerated Vesting of Restricted Units (8)
Anastasio	$1,517,909	$1,517,909	$1,517,909	$1,517,909
Blank	620,799	620,799	620,799	620,799
Bluntzer	543,878	543,878	543,878	543,878
Brattlof	503,551	503,551	503,551	503,551
Brown	522,452	522,452	522,452	522,452


Executive Benefits and Payments	Termination of Employment by the Company Other Than for “Cause” or Disability, or by the Executive for “Good Reason” (2)	Termination of Employment because of Death or Disability (3)	Termination by the Executive Other Than for “Good Reason” (4)	Continued Employment Following Change of Control (5)	Termination of Employment by the Company Other Than for “Cause” or Disability, or by the Executive for “Good Reason” (2)	Termination of Employment because of Death or Disability (3)	Termination by the Executive Other Than for “Good Reason” (4)	Continued Employment Following Change of Control (5)
Accelerated Vesting of Unit Options (7)
Anastasio					$209,240	$209,240	$209,240	$209,240
Blank					144,551	144,551	144,551	144,551
Bluntzer					122,516	122,516	122,516	122,516
Brattlof					111,756	111,756	111,756	111,756
Brown					111,756	111,756	111,756	111,756


Accelerated Vesting of Restricted
Units (8)
Anastasio					$2,090,598	$2,090,598	$2,090,598	$2,090,598
Blank					857,658	857,658	857,658	857,658
Bluntzer					762,162	762,162	762,162	762,162
Brattlof					709,286	709,286	709,286	709,286
Brown					768,415	768,415	768,415	768,415


Accelerated Vesting of Performance Units (9)
Anastasio	$966,319	$966,319	$966,319	$966,319	$1,923,762	$1,923,762	$1,923,762	$1,923,762
Blank	396,780	396,780	396,780	396,780	818,058	818,058	818,058	818,058
Bluntzer	344,899	344,899	344,899	344,899	720,438	720,438	720,438	720,438
Brattlof	303,505	303,505	303,505	303,505	658,531	658,531	658,531	658,531
Brown	317,526	317,526	317,526	317,526	686,532	686,532	686,532	686,532


280G Tax Gross-Up (10)
Anastasio	$0	$0	$0	$0	$0	$0	$0	$0
Blank	0	0	0	0	0	0	0	0
Bluntzer	1,159,396	0	0	0	0	0	0	0
Brattlof	0	0	0	0	0	0	0	0
Brown	0	0	0	0	0	0	0	0


Totals
*Anastasio*	$5,908,479	$2,878,096	$2,878,096	$2,878,096	$7,714,843	$4,608,600	$4,608,600	$4,223,600
*Blank*	2,519,650	1,176,944	1,176,944	1,176,944	3,197,278	1,993,267	1,993,267	1,820,267
*Bluntzer*	3,464,656	1,019,051	1,019,051	1,019,051	2,983,037	1,760,116	1,760,116	1,605,116
*Brattlof*	1,995,255	937,056	937,056	937,056	2,598,705	1,626,573	1,626,573	1,479,573
*Brown*	2,091,435	969,978	969,978	969,978	2,758,104	1,721,703	1,721,703	1,566,703


Name	Annual salary	Bonus	Annual Salary		Bonus
Anastasio	$473,800	$393,120		$488,000		$385,000
Blank	340,900	238,524		351,130		173,000
Bluntzer	305,500	195,000		314,670		155,000
Brattlof	289,600	195,000		298,290		147,000
Brown	305,500	195,000		314,670		155,000

terminates his or her employment for “good reason,” as defined in the agreement, the executive is generally entitled to receive the following:

(3)

If the executive’s employment is terminated by reason of his death or disability, then his or her estate or beneficiaries will be entitled to receive a lump sum cash payment equal to any accrued and unpaid salary and vacation pay plus a bonus equal to the highest bonus earned by the executive in the prior three years (prorated to the date of termination). In this example, the termination of employment was deemed to occur on the last day of the year; thus a full year’s bonus is shown in the table. In addition, in the case of disability, the executive would be entitled to any disability and related benefits at least as favorable as those provided by NuStar GP, LLC under its plans and programs during the 120-days prior to the executive’s termination of employment.

(4)

If the executive voluntarily terminates his employment other than for “good reason,” then he or she will be entitled to a lump sum cash payment equal to any accrued and unpaid salary and vacation pay plus a bonus equal to the highest bonus earned by the executive in the prior three years (prorated to the date of termination). In this example, the termination of employment was deemed to occur on the last day of the year; thus a full year’s bonus is shown in the table.

(5)

The change of control agreements provide for a three-year term of employment following a change of control. The agreements generally provide that the executive will continue to enjoy compensation and benefits on terms at least as favorable as in effect prior to the change of control. In addition, all outstanding equity incentive awards will automatically vest on the date of the change of control.

(6)

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

(7)

The amounts stated in the table ~~below~~ represent the gross value of previously unvested unit options derived by multiplying (x) the difference between (as applicable) ~~$56.09~~$69.48 (the closing price of NuStar Energy L.P.’s units on the NYSE on December 31, ~~2009)~~2010) or ~~$26.92~~$36.33 (the closing price of NuStar GP Holdings, LLC’s units on the NYSE on December 31, ~~2009)~~2010), and the options’ exercise prices, times (y) the number of unvested unit options.

The following table provides a summary of compensation paid for the year ended December 31, ~~2009,~~2010, to the Board. The table shows amounts earned by such persons for services rendered to NuStar GP, LLC in all capacities in which they served.


Name and Principal Position	Fees Earned or Paid in Cash ($)(1)	Unit Awards ($)(3)	Option Awards ($)(3)	Non-Equity Incentive Plan Compensation ($)	Change in Pension Value and Nonqualified Deferred Compensation Earnings ($)	All Other Compensation ($)	Total ($)	Fees Earned or Paid in Cash ($)(1)	Unit Awards ($)(3)	Option Awards ($)(3)	Non-Equity Incentive Plan Compensation ($)	Change in Pension Value and Nonqualified Deferred Compensation Earnings ($)	All Other Compensation ($)	Total ($)
William E. Greehey	98,000	74,971	0	0	n/a	0	172,971	102,500	74,987	0	0	n/a	0	177,487
Curtis V. Anastasio	(2)	(2)	(2)	(2)	(2)	(2)	(2)	(2)	(2)	(2)	(2)	(2)	(2)	(2)
J. Dan Bates	75,750	49,999	0	0	n/a	0	125,749	75,250	49,991	0	0	n/a	0	125,241
Dan J. Hill	75,750	49,999	0	0	n/a	0	125,749	77,551	49,991	0	0	n/a	0	127,542
Stan L. McLelland	51,750	49,999	0	0	n/a	0	101,749	52,649	49,991	0	0	n/a	0	102,640
Rodman D. Patton	75,000	49,999	0	0	n/a	0	124,999	75,250	49,991	0	0	n/a	0	125,241

As of December 31, ~~2009,~~2010, each director holds the following aggregate number of restricted unit and option awards:


Name	Aggregate # of Restricted Units	Aggregate # of Unit Options	Aggregate # of Restricted Units	Aggregate # of Unit Options
William E. Greehey	2,368	0	2,372	0
Curtis V. Anastasio	*	*	*	*
J. Dan Bates	1,907	0	1,707	0
Dan J. Hill	1,907	0	1,707	0
Stan L. McLelland	1,907	0	1,707	0
Rodman D. Patton	1,907	0	1,707	0

During ~~2009,~~2010, non-employee directors received a retainer fee of $45,000 per year, plus $1,250 for each Board and committee meeting attended in person and $500 for each Board and committee meeting attended telephonically. Directors who serve as chairperson of a committee receive an additional $10,000 annually. Each director is also reimbursed for expenses of meeting attendance. Directors who are employees of NuStar GP, LLC receive no compensation (other than reimbursement of expenses) for serving as directors. The Chairman of the Board receives an additional retainer fee of $50,000 per year. The Chairman of the Board receives no fees for attending committee meetings.

NuStar GP, LLC supplements the compensation paid to non-employee directors other than the Chairman of the Board with an annual grant of restricted NuStar Energy L.P. units valued at $50,000 that vests in equal annual installments over a three-year period. The Chairman of the Board receives an annual grant of restricted NuStar Energy L.P. units valued at $75,000 that vests in equal annual installments over a three-year period. We believe this annual grant of restricted units increases the non-employee directors’ identification with the interests of NuStar Energy L.P.’s unitholders through ownership of NuStar Energy L.P. units. Upon a non-employee director’s initial election to the Board, the director will receive a grant of restricted units equal to the pro-rated amount of the annual grant of restricted units from the time of his or her election through the next annual grant of restricted units.

In the event of a “Change of Control” as defined in the 2000 LTIP, all unvested restricted units and unit options previously granted immediately become vested or exercisable. Each plan also contains anti-dilution provisions providing for an adjustment in the number of restricted units or unit options, respectively, that have been granted to prevent dilution of benefits in the event any change in the capital structure of NuStar Energy affects the NuStar Energy L.P. units.

The Compensation Committee reviews and reports to the Board on matters related to compensation strategies, policies and programs, including certain personnel policies and policy controls, management development, management succession and benefit programs. The Compensation Committee also approves and administers NuStar Energy’s equity compensation plans and incentive bonus plan. The Board has adopted a written charter for the Compensation Committee. The members of the Compensation Committee are Dan J. Hill (Chairman), J. Dan Bates and Rodman D. Patton, none of whom is a current or former employee or officer of NuStar GP, LLC. The Compensation Committee met ~~five~~four times in ~~2009.~~2010.

There are no compensation committee interlocks. None of Mr. Hill, Mr. Bates or Mr. Patton has served as an officer or employee of NuStar GP, LLC. Furthermore, except for compensation arrangements disclosed in this annual report on Form 10-K, NuStar Energy has not participated in any contracts, loans, fees, awards or financial interests, direct or indirect, with any committee member, nor is NuStar Energy aware of any means, directly or indirectly, by which a committee member could receive a material benefit from NuStar Energy.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED UNITHOLDER MATTERS

The following table sets forth ownership of NuStar Energy L.P. units and NuStar GP Holdings, LLC units by directors and executive officers of NuStar GP, LLC as of December 31, ~~2009.~~2010. Unless otherwise indicated in the notes to the table, each of the named persons and members of the group has sole voting and investment power with respect to the units shown:


Name of Beneficial Owner(a)	Units Beneficially Owned (b)(c)	Units under Exercisable Options(d)	Percentage of Outstanding Units(c)	NuStar GP Holdings, LLC Units Beneficially Owned	NuStar GP Holdings, LLC Units under Exercisable Options	Percentage of Outstanding Units(e)	Units Beneficially Owned (b)		Units under Exercisable Options(c)		Percentage of Outstanding Units(d)		NuStar GP Holdings, LLC Units Beneficially Owned		NuStar GP Holdings, LLC Units under Exercisable Options		Percentage of Outstanding Units(e)
William E. Greehey	723,871	0	1.20%	6,945,276	0	16.32%		1,240,945		0		1.91%		7,183,803		0		16.84%

Curtis V. Anastasio	62,216	62,785	*	65,415	0	*		69,116		67,675		*		71,915		18,767		*

J. Dan Bates	4,682	0	*	2,000	0	*		5,898		0		*		2,000		0		*

Dan J. Hill	8,079	0	*	8,000	0	*		10,795		0		*		8,000		0		*

Stan McLelland	5,491	0	*	16,724	0	*		6,207		0		*		18,092		0		*

Rodman D. Patton	12,229	0	*	10,000	0	*		16,945		0		*		10,000		0		*

Bradley C. Barron	9,359	4,515	*	8,298	0	*		11,191		4,935		*		10,005		11,667		*

Steven A. Blank	28,584	31,096	*	42,647	0	*		30,650		33,566		*		44,777		13,667		*

James R. Bluntzer	12,903	16,400	*	30,235	0	*		14,804		18,290		*		31,924		11,667		*

Paul R. Brattlof	10,749	680	*	7,956	0	*		12,614		1,020		*		11,720		11,667		*

Mary Rose Brown	11,011	680	*	47,500	0	*		14,030		1,020		*		51,424		11,667		*

Daniel S. Oliver	5,528	400	*	1,710	0	*		7,205		600		*		3,279		0		*

Thomas R. Shoaf	5,222	3,460	*	4,205	0	*		6,110		4,425		*		5,083		8,567		*

All directors and officers as a group (13)	889,924	120,016	1.69%	7,189,966	0	16.90%		1,446,510		131,531		2.43%		7,452,022		87,669		17.67%

Except as otherwise indicated, the following table sets forth certain information as of December 31, ~~2009~~2010 with respect to each entity known to us to be the beneficial owner of more than 5% of our outstanding units.


Name and Address of Beneficial Owner	Units	Percentage of Units (b)	Units	Percentage of Units (2)

NuStar GP Holdings(a) 2330 North Loop 1604 West San Antonio, Texas 78248	10,257,207	17.0%
NuStar GP Holdings(1) 2330 North Loop 1604 West San Antonio, Texas 78248			10,283,359	15.9%

Tortoise Capital Advisors, L.L.C.			3,420,520	5.3%

The following table sets forth information about NuStar GP, LLC’s equity compensation plans, which are described in further detail in Note 17 of Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data:”


Plan categories	Number of Securities to be issued upon exercise of outstanding unit options, warrants and rights(1)	Weighted-Average exercise price of outstanding unit options, warrants and rights	Number of securities remaining for future issuance under equity compensation plans	Number of Securities to be issued upon exercise of outstanding unit options, warrants and rights(1)		Weighted-Average exercise price of outstanding unit options, warrants and rights		Number of securities remaining for future issuance under equity compensation plans

Equity Compensation Plans approved by security holders	1,205,606	50.91	294,394		1,377,158		$54.40		122,842

Equity Compensation Plans not approved by security holders	444,423	47.91	255,577(2)		451,709		50.34		248,291	(2)

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE

In January 2007, our Board adopted a written related person transaction policy that codifies our prior practice. For purposes of the policy, a related person transaction is one that is not available to all employees generally or involves less than $10,000 when aggregated with similar transactions. The policy requires that any related person transaction between NuStar Energy or NuStar GP, LLC and: (i) any vice president, Section 16 officer or director, (ii) any 5% or greater unitholder of NuStar Energy, its controlled affiliates or NuStar GP Holdings, (iii) any immediate family member of any officer or director, or (iv) any entity controlled by any of (i), (ii) or (iii) (or in which any of (i), (ii) or (iii) owns more than 5%) must be approved by the disinterested members of the Board. In addition, the policy requires that the officers and directors have an affirmative obligation to inform our Corporate Secretary of his or her immediate family members, as well as any entities in which he or she controls or owns more than 5%.

Please see “Executive Compensation, Potential Payments upon Termination or Change in Control” for a discussion of NuStar Energy’s Change of Control Agreements with the ~~named executive officers.~~NEOs.

On December 10, 2007, NuStar Logistics, L.P., our wholly owned subsidiary, entered into a non-exclusive Aircraft Time Sharing Agreement (the Time Share Agreement) with William E. Greehey, Chairman of our Board. The Time Share Agreement provides that NuStar Logistics, L.P. will sublease the aircraft to Mr. Greehey on an “as needed and as available” basis, and will provide a fully qualified flight crew for all Mr. Greehey’s flights. Mr. Greehey will pay NuStar Logistics an amount equal to the maximum amount of expense reimbursement permitted in accordance with Section 91.501(d) of the Aeronautics Regulations of the Federal Aviation Administration and the Department of Transportation, which expenses include and are limited to: fuel oil, lubricants, and other additives; travel expenses of the crew, including food, lodging and ground transportation; hangar and tie down costs away from the aircraft’s base of operation; insurance obtained for the specific flight; landing fees, airport taxes and similar assessments; customs, foreign permit, and similar fees directly related to the flight; in-flight food and beverages; passenger ground transportation; flight planning and weather contract services; and an additional charge equal to 100% of the costs of the fuel oil, lubricants, and other additives. The Time Share Agreement has an initial term of two years, after which the Time Share Agreement will automatically renew for one-year terms until terminated by either party. The Time Share Agreement was approved by the disinterested members of the Board on December 5, 2007. The Time Share Agreement was amended, as of September 4, 2009, to reflect the addition of another aircraft.

Effective on September 16, 2007, NuStar Logistics entered into an assignment and assumption agreement (the Assignment) with Valero Energy, pursuant to which NuStar Logistics, L.P. assumed certain of Valero Energy’s obligations under a letter agreement between Valero Energy and Mr. Greehey regarding his resignation from employment with Valero Energy (the Letter Agreement). Under the Letter Agreement, Valero Energy agreed to provide Mr. Greehey with “off-site office facilities and secretarial and other office services reasonably commensurate with Mr. Greehey’s position as retired CEO of Valero Energy (the Office Services). Since we moved our headquarters out of Valero Energy’s corporate headquarters in April 2007, we have provided office space for Mr. Greehey, the cost of which we billed to Valero Energy. In order to further simplify the relationship between us and Valero Energy, we assumed responsibility for the Office Services, for which Valero Energy paid us $1.2 million, the operating expense associated with providing Office Services to Mr. Greehey. The Conflicts Committee, consisting of the disinterested members of the Board, approved the Assignment on August 24, 2007.

On April 24, 2008, the independent directors of NuStar GP, LLC approved the adoption of a Services Agreement, effective January 1, 2008, between NuStar GP, LLC and NuStar Energy (the Services Agreement). The Services Agreement provides that NuStar GP, LLC will furnish all services necessary for the conduct of the business of NuStar Energy, and NuStar Energy will reimburse NuStar GP, LLC for all payroll and related benefit costs, including pension and unit-based compensation costs, other than the expenses allocated to NuStar Holdings (the Holdco Administrative Services Expense). ~~For fiscal year 2009, the Holdco Administrative Services Expense was equal to $1.35 million. For the 2010 fiscal year and each fiscal year thereafter, the~~The Holdco Administrative Services Expense is equal to $1.1 million (as adjusted), plus 1.0% of NuStar GP, LLC’s domestic

employee bonus and unit compensation expense for the applicable fiscal year. For fiscal year 2010, the Holdco Administrative Services Expense was

equal to $1.47 million. The Holdco Administrative Services expense is subject to adjustment (a) by an annual amount equal to NuStar GP, LLC’s annual merit increase percentage for the most recently completed contract year and (b) for changed levels of services due to expansion of operations through, among other things, expansion of operations, acquisitions or the construction of new businesses or assets. The Services Agreement will terminate December 31, 2012, with automatic two-year renewals unless terminated by either party on six months’ written notice.

Shay Bluntzer, a NuStar employee, is the son of James R. Bluntzer, one of our NEOs. As such, he is deemed to be a “related person” under Item 404(a) of the SEC’s Regulation S-K. Mr. S. Bluntzer is NuStar’s Director of Government Relations. In 2010, Mr. S. Bluntzer did not attend any Board or Committee meetings. The aggregate value of compensation paid by NuStar to Mr. S. Bluntzer in 2010 was less than $500,000. There were no material differences between the compensation paid to Mr. S. Bluntzer and the compensation paid to any other employees who hold analogous positions.

Chester Bullard, a NuStar employee, is the son-in-law of James R. Bluntzer, one of our NEOs. As such, he is deemed to be a “related person” under Item 404(a) of the SEC’s Regulation S-K. Mr. Bullard is a Senior Manager-Pipelines and Terminals for NuStar’s Central West operations. In 2010, Mr. Bullard did not attend any Board or Committee meetings. The aggregate value of compensation paid by NuStar to Mr. Bullard in 2010 was less than $500,000. There were no material differences between the compensation paid to Mr. Bullard and the compensation paid to any other employees who hold analogous positions.

John D. Greehey, a NuStar employee, is the son of William E. Greehey, the Chairman of our Board. As such, he is deemed to be a “related person” under Item 404(a) of the SEC’s Regulation S-K. Mr. J. Greehey is a Vice President of a subsidiary of NuStar Energy L.P., NuStar Marketing LLC. In 2010, Mr. J. Greehey did not attend any Board or Committee meetings. The aggregate value of compensation paid by NuStar to Mr. J. Greehey in 2010 was less than $500,000. There were no material differences between the compensation paid to Mr. J. Greehey and the compensation paid to any other employees who hold analogous positions.

Michael T. Stone, a NuStar employee, is the brother-in-law of Mary Rose Brown, one of our NEOs. As such, he is deemed to a “related person” under Item 404(a) of the SEC’s Regulation S-K. Mr. Stone is a Vice President of a subsidiary of NuStar Energy L.P., NuStar Marketing LLC. In 2010, Mr. Stone attended one Board meeting and no Committee meetings. The aggregate value of compensation paid by NuStar to Mr. Stone in 2010 was less than $500,000. There were no material differences between the compensation paid to Mr. Stone and the compensation paid to any other employees who hold analogous positions.

Due to its ownership of NuStar GP, LLC and Riverwalk Holdings, LLC, as of December 31, ~~2009,~~2010, NuStar GP Holdings indirectly ~~owns:~~owned:

Certain of our officers are also officers of NuStar GP Holdings. Our Chairman, William E. Greehey, is also the Chairman of NuStar GP Holdings. NuStar GP Holdings appoints NuStar GP, LLC’s directors. NuStar GP, LLC’s board is responsible for overseeing NuStar GP, LLC’s role as the owner of the general partner of NuStar Energy. NuStar GP Holdings must also approve matters that have or would have reasonably expected to have a material effect on NuStar GP Holdings’ interests as one of our major unitholders.

NuStar Energy’s partnership agreement requires that NuStar GP, LLC maintain a Conflicts Committee, composed entirely of independent directors, to review and resolve certain potential conflicts of interest between Riverwalk Logistics, L.P. and its affiliates, on one hand, and NuStar Energy, on the other hand.

Our business is managed under the direction of the Board of NuStar GP, LLC, the general partner of Riverwalk Logistics, L.P., the general partner of NuStar Energy. The Board conducts its business through meetings of the Board and its committees. During ~~2009,~~2010, the Board held six meetings. No member of the Board attended less than 75% of the meetings of the Board and committees of which he was a member.

The Board has standing Audit and Compensation Committees. Each committee has a written charter. The committees of the Board and the number of meetings held by the committees in ~~2009~~2010 are described below.

The Board has one member of management, Curtis V. Anastasio, President and CEO, and five non-management directors. The Board has determined that three of five of its non-management directors meet the independence requirements of the NYSE listing standards as set forth in the NYSE Listed Company Manual. As a limited partnership, NuStar Energy is not required to have a majority of independent directors. The independent directors are: J. Dan Bates, Dan J. Hill and Rodman D. Patton.

William E. Greehey, Chairman of the Board, retired as CEO of Valero Energy at the end of 2005. He remained Chairman of Valero Energy’s board of directors until January 2007. Mr. Greehey also serves as the Chairman of the NuStar GP Holdings board of directors and owns ~~16.32%~~16.87% of NuStar GP Holdings.

Curtis V. Anastasio has been President of NuStar GP, LLC since December 1999 and CEO since June 2000. As a member of management, Mr. Anastasio is not an independent director under the NYSE’s listing standards. Mr. Anastasio also serves as President and CEO of NuStar GP Holdings.

Stan L. McLelland has been a member of the Board since October 2005. In July 2006, Mr. McLelland also became a member of the board of directors of NuStar GP Holdings. Mr. McLelland stepped down from the

Audit and Compensation Committees of NuStar GP, LLC when he joined the NuStar GP Holdings board of directors.

The Audit and Compensation committees of the Board are each composed entirely of directors who meet the independence requirements of the NYSE listing standards. Each member of the Audit Committee also meets the additional independence standards for Audit Committee members set forth in the regulations of the SEC. For further information about the committees, see also Item 10 and Item 11 above.

Under the NYSE’s listing standards, no director qualifies as independent unless the Board affirmatively determines that the director has no material relationship with NuStar Energy. Based upon information requested from and provided by each director concerning their background, employment and affiliations, including commercial, industrial, banking, consulting, legal, accounting, charitable and familial relationships, the Board has determined that, other than being a director of NuStar GP, LLC and/or unitholder of NuStar Energy, each of the independent directors named above has either no relationship with NuStar Energy, either directly or as a partner, unitholder or officer of an organization that has a relationship with NuStar Energy, or has only immaterial relationships with NuStar Energy, and is therefore independent under the NYSE’s listing standards.

As provided for under the NYSE listing standards, the Board has adopted categorical standards or guidelines to assist the Board in making its independence determinations with respect to each director. Under the NYSE listing standards, immaterial relationships that fall within the guidelines are not required to be disclosed in this ~~proxy statement.~~annual report on Form 10-K.

NuStar GP, LLC’s Corporate Governance Guidelines contain the director qualification standards, including the guidelines listed above, and are available on NuStar Energy’s internet website athttp://www.nustarenergy.com (in the “Investor Relations” section) or are available in print upon request to NuStar GP, LLC’s Corporate Secretary at the address indicated on the cover page of this annual report on Form 10-K.

The Board has designated Mr. Patton to serve as the Presiding Director for meetings of the non-management Board members outside the presence of management.

Unitholders and other interested parties may communicate with the Board, the non-management directors or the Presiding Director by sending a written communication in an envelope addressed to “Board of Directors,” “Non-Management Directors,” or “Presiding Director” in care of NuStar GP, LLC’s Corporate Secretary at the address indicated on the cover page of this annual report on Form 10-K.

NuStar Energy has posted its Corporate Governance Guidelines, Code of Business Conduct and Ethics, Code of Ethics of Senior Financial Officers, the Audit Committee Charter and other governance documents on NuStar Energy’s internet website athttp://www.nustarenergy.com (in the “Investor Relations” section). NuStar

Energy’s governance documents are available in print to any unitholder of record who makes a written request to NuStar Energy. Requests must be directed to NuStar GP, LLC’s Corporate Secretary at the address indicated on the cover page of this annual report on Form 10-K.

The aggregate fees for fiscal year 2010 for professional services rendered by KPMG for the audit of the annual financial statements for the year ended December 31, 2010 included in this Form 10-K, review of NuStar Energy’s interim financial statements included in NuStar Energy’s 2010 Forms 10-Q, the audit of the effectiveness of NuStar Energy’s internal control over financial reporting as of December 31, 2010 and related services that are normally provided by the principal auditor (e.g., comfort letters and assistance with review of documents filed with the SEC) were $2,218,660.

The aggregate fees for the fiscal year 2010 for assurance and related services rendered by KPMG that are reasonably related to the performance of the audit or review of NuStar Energy’s financial statements and not reported in the preceding caption were $60,930.

The aggregate fees for the fiscal year 2010 for professional services rendered by KPMG for tax compliance, tax advice and tax planning were $0.

The aggregate fees for the fiscal year 2010 for services rendered by KPMG, other than the services reported under the preceding captions, were $0.

The aggregate fees for fiscal year 2009 for professional services rendered by KPMG for the audit of the annual financial statements for the year ended December 31, 2009 included in this Form 10-K, review of NuStar Energy’s interim financial statements included in NuStar Energy’s 2009 Forms 10-Q, the audit of the effectiveness of NuStar Energy’s internal control over financial reporting as of December 31, 2009 and related services that are normally provided by the principal auditor (e.g., comfort letters and assistance with review of documents filed with the SEC) were $1,994,200.

The aggregate fees for the fiscal year 2009 for assurance and related services rendered by KPMG that are reasonably related to the performance of the audit or review of NuStar Energy’s financial statements and not reported in the preceding caption were $0.

The aggregate fees for the fiscal year 2009 for professional services rendered by KPMG for tax compliance, tax advice and tax planning were $0.

The aggregate fees for the fiscal year 2009 for services rendered by KPMG, other than the services reported under the preceding captions, were $0.

The aggregate fees for fiscal year 2008 for professional services rendered by KPMG for the audit of the annual financial statements for the year ended December 31, 2008 included in this Form 10-K, review of NuStar Energy’s interim financial statements included in NuStar Energy’s 2008 Forms 10-Q, the audit of the effectiveness of NuStar Energy’s internal control over financial reporting as of December 31, 2008 and related services that are normally provided by the principal auditor (~~e.g.~~~~, comfort letters and assistance with review of documents filed with the SEC) were $2,097,546.~~

The aggregate fees for the fiscal year 2008 for assurance and related services rendered by KPMG that are reasonably related to the performance of the audit or review of NuStar Energy’s financial statements and not reported in the preceding caption were $245,000. The fees related primarily to audit fees incurred for Kaneb benefit plans and the audit of assets and operations acquired from CITGO Asphalt Refining Company on March 20, 2008.

~~The aggregate fees for the fiscal year 2008 for professional services rendered by KPMG for tax compliance, tax advice and tax planning were $23,895.~~

~~The aggregate fees for the fiscal year 2008 for services rendered by KPMG, other than the services reported under the preceding captions, were $0.~~

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

None of the services (described above) for ~~2008~~2009 or ~~2009~~2010 provided by KPMG were approved by the audit committee pursuant to paragraph (c)(7)(i)(C) of Rule 2-01 of Regulation S-X.


Exhibit Number ~~Number~~				Description		Incorporated by Reference to the Following Document

	3.05		~~Third Amended and Restated Agreement of Limited Partnership of Valero L.P.~~		~~NuStar Energy L.P.’s Quarterly Report on Form 10-Q for quarter ended March 31, 2003 (File No. 001-16417), Exhibit 3.1~~

~~3.06~~		~~First Amendment to Third Amended and Restated Agreement of Limited Partnership of Valero L.P.~~		~~NuStar Energy L.P.’s Annual Report on Form 10-K for year ended December 31, 2003 (File No. 001-16417), Exhibit 4.3~~

~~3.07~~		Amendment No. 2 to Third Amended and Restated Agreement of Limited Partnership of Valero L.P., dated as of July 1, 2005		NuStar Energy L.P.’s Quarterly Report on Form 10-Q for quarter ended June 30, 2005 (File No. 001-16417), Exhibit 4.01

~~3.08~~	3.06		~~Certificate~~	Amendment No. 3 to Third Amended and Restated Agreement of Limited Partnership of ~~Valero Logistics Operations,~~NuStar Energy L.P., dated as of April 10, 2008		NuStar Energy L.P.’s ~~Registration Statement~~Current Report on Form ~~S-1~~8-K filed April 15, 2008 (File No. ~~333-43668)~~001-16417), Exhibit ~~3.4~~3.1

~~3.09~~	3.07		~~Certificate of Amendment to~~	Amended and Restated Certificate of Limited Partnership of ~~Valero~~Shamrock Logistics Operations, L.P., dated as of January 7, 2002		NuStar Energy L.P.’s ~~Registration Statement~~Annual Report on Form ~~S-1~~10-K for year ended December 31, 2001 (File No. ~~333-43668)~~001-16417), Exhibit ~~3.5~~3.8

~~3.10~~	3.08			Certificate of Amendment to Certificate of Limited Partnership of Valero Logistics Operations, L.P., dated March 21, 2007 and effective April 1, 2007		NuStar Energy L.P.’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2007 ~~File~~(File No. ~~001-16417,~~001-16417), Exhibit 3.03

~~3.11~~	3.09			Second Amended and Restated Agreement of Limited Partnership of ~~Valero~~Shamrock Logistics Operations, L.P., dated as of April 16, 2001		NuStar Energy L.P.’s Annual Report on Form 10-K for year ended December 31, 2001 (File No. 001-16417), Exhibit 3.9

~~3.12~~	3.10			First Amendment to Second Amended and Restated Agreement of Limited Partnership of Shamrock Logistics Operations, L.P., effective as of April 16, 2001		NuStar Energy L.P.’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2001 (File No. 001-16417), Exhibit 4.1

	3.11			Second Amendment to Second Amended and Restated Agreement of Limited Partnership of ~~Valero~~Shamrock Logistics Operations, L.P., dated as of January 7, 2002		NuStar Energy L.P.’s Annual Report on Form 10-K for year ended December 31, 2001 (File No. 001-16417), Exhibit 3.10

~~3.13~~	3.12			Certificate of Limited Partnership of Riverwalk Logistics, L.P., dated June 5, 2000		NuStar Energy L.P.’s Registration Statement on Form S-1 filed August 14, 2000 (File No. 333-43668), Exhibit 3.7

~~3.14~~	3.13			First Amended and Restated Limited Partnership Agreement of Riverwalk Logistics, L.P., dated as of April 16, 2001		NuStar Energy L.P.’s Annual Report on Form 10-K for the year ended December 31, 2001 (File No. 001-16417), Exhibit 3.16

~~3.15~~	3.14			Certificate of Formation of ~~Valero~~Shamrock Logistics GP, LLC, dated December 7, 1999		NuStar Energy L.P.’s Registration Statement on Form S-1 filed August 14, 2000 (File No. 333-43668), Exhibit 3.9

~~3.16~~		~~Amendment to Certificate of Formation of Valero GP, LLC, dated March 21, 2007 and effective April 1, 2007~~		~~NuStar Energy L.P.’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2007, File No.001-16417, Exhibit 3.02~~


Exhibit Number ~~Number~~				Description		Incorporated by Reference to the Following Document

~~3.17~~	3.15			Certificate of Amendment to Certificate of Formation of ~~Valero~~Shamrock Logistics GP, LLC, dated December 31, 2001		NuStar Energy L.P.’s Annual Report on Form 10-K for year ended December 31, 2001 (File No. 001-16417), Exhibit 3.14

~~3.18~~	3.16			Certificate of Amendment to Certificate of Formation of Valero GP, LLC, dated March 21, 2007 and effective April 1, 2007		NuStar Energy L.P.’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2007 (File No. 001-16417), Exhibit 3.02

	3.17			First Amended and Restated ~~LLC~~Limited Liability Company Agreement of Shamrock Logistics GP, LLC, dated as of June 5, 2000		NuStar Energy L.P.’s Amendment No. 5 to Registration Statement on Form S-1 filed March 29, 2001 (File No. 333-43668), Exhibit 3.10

~~3.19~~	3.18			First Amendment to First Amended and Restated Limited Liability Company Agreement of ~~Valero~~Shamrock Logistics GP, LLC, effective as of December 31, 2001		NuStar Energy L.P.’s Annual Report on Form 10-K for year ended December 31, 2001 (File No. 001-16417), Exhibit 3.15

~~3.20~~	4.01		~~First Amended and Restated Limited Partnership Agreement of Riverwalk Logistics, L.P.~~		~~NuStar Energy L.P.’s Annual Report on Form 10-K for year ended December 31, 2001 (File No. 001-16417), Exhibit 3.16~~

~~4.01~~		Indenture, dated as of July 15, 2002, among Valero Logistics Operations, L.P., as Issuer, Valero L.P., as Guarantor, and The Bank of New York, as Trustee, relating to Senior Debt Securities		NuStar Energy L.P.’s Current Report on Form 8-K filed July 15, 2002 (File No. 001-16417), Exhibit 4.1

	4.02			First Supplemental Indenture, dated as of July 15, 2002, to Indenture dated as of July 15, 2002, in each case among Valero Logistics Operations, L.P., as Issuer, Valero L.P., as Guarantor, and The Bank of New York, as Trustee, relating to 6 7/8% Senior Notes ~~Due~~due 2012		NuStar Energy L.P.’s Current Report on Form 8-K filed July 15, 2002 (File No. 001-16417), Exhibit 4.2

	4.03			Second Supplemental Indenture, dated as of March 18, 2003, to Indenture dated as of July 15, 2002, as amended and supplemented by a First Supplemental Indenture thereto dated as of July 15, 2002, in each case among Valero Logistics Operations, L.P., as Issuer, Valero L.P., as Guarantor, and The Bank of New York, as Trustee (including, form of global note representing $250,000,000 6.05% Senior Notes due 2013)		NuStar Energy L.P.’s ~~Current~~Quarterly Report on Form ~~8-K filed May 9,~~10-Q for the quarter ended March 31, 2003 (File No. 001-16417), Exhibit 4.1

	4.04			Third Supplemental Indenture, dated as of July 1, 2005, to Indenture dated as of July 15, 2002, as amended and supplemented, among Valero Logistics Operations, L.P.;, Valero L.P.;, Kaneb Pipe Line Operating Partnership, L.P.;, and The Bank of New York Trust Company, N.A.		NuStar Energy L.P.’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2005 (File No. 001-16417), Exhibit 4.02


Exhibit Number ~~Number~~		Description	Incorporated by Reference to the Following Document

	4.05	Instrument of Resignation, Appointment and Acceptance, dated March 31, 2008, among NuStar Logistics, L.P., NuStar Energy L.P., Kaneb Pipeline Operating Partnership, L.P., The Bank of New York Trust Company N.A., and Wells Fargo Bank, National Association	NuStar Energy L.P.’s Annual Report on Form 10-K for year ended December 31, 2008 (File No. 001-16417), Exhibit 4.05

	4.06	Fourth Supplemental Indenture, dated as of April 4, 2008, to Indenture dated as of July 15, 2002, among NuStar Logistics L.P., as issuer, NuStar Energy L.P., as guarantor, NuStar Pipeline Operating Partnership L.P., as affiliate guarantor, and Wells Fargo Bank, National Association, as Successor Trustee	NuStar Energy L.P.’s Current Report on Form 8-K filed April 4, 2008 (File No. 001-16417), Exhibit 4.2

	4.07	Fifth Supplemental Indenture, dated as of August 12, 2010, to Indenture dated as of July 15, 2002, among NuStar Logistics, L.P., as Issuer, NuStar Energy L.P., as Guarantor, NuStar Pipeline Operating Partnership L.P., as Affiliate Guarantor and Wells Fargo Bank, National Association, as Successor Trustee	NuStar Energy L.P.’s Current Report on Form 8-K filed August 16, 2010 (File No. 001-16417), Exhibit 4.3

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

~~4.07~~	4.09	First Supplemental Indenture, dated as of February 21, 2002, to Indenture dated as of February 21, 2002, between Kaneb Pipe Line Operating Partnership, L.P. and JPMorgan Chase Bank (including form of 7.750% Senior Unsecured Notes due 2012)	NuStar Energy L.P.’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2005 (File No. 001-16417), Exhibit 4.04

~~4.08~~	4.10	Second Supplemental Indenture, dated as of August 9, 2002 and effective as of April 4, 2002, to Indenture dated as of February 21, 2002, as amended and supplemented, between Kaneb Pipe Line Operating Partnership, L.P.;, Statia Terminals Canada ~~Partnership;~~Partnership, and JPMorgan Chase Bank	NuStar Energy L.P.’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2005 (File No. 001-16417), Exhibit 4.05

~~4.09~~	4.11	Third Supplemental Indenture, dated and effective as of May 16, 2003, to Indenture dated as of February 21, 2002, as amended and supplemented, between Kaneb Pipe Line Operating Partnership, L.P.;, Statia Terminals Canada ~~Partnership;~~Partnership, and JPMorgan Chase Bank	NuStar Energy L.P.’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2005 (File No. 001-16417), Exhibit 4.06


~~Exhibit~~ ~~Number~~		~~Description~~	~~Incorporated by Reference~~ ~~to the Following Document~~

~~4.12~~	4.14		Instrument of Resignation, Appointment and Acceptance, dated June 30, 2008, among NuStar Pipeline Operating Partnership L.P., NuStar Energy L.P., NuStar Logistics, L.P., The Bank of New York Trust Company N.A., and Wells Fargo Bank, National Association	NuStar Energy L.P.’s Annual Report on Form 10-K for year ended December 31, 2008 (File No. 001-16417), Exhibit 4.12

~~4.13~~		Registration Rights Agreement, dated March 18, 2003, among Valero Logistics Operations, L.P., as Issuer, Valero L.P., as Guarantor, and the initial purchasers of Valero Logistics Operations, L.P. 6.05% Senior Notes due 201310.01	~~NuStar Energy L.P.’s Quarterly Report on Form 10-Q for quarter ended March 31, 2003 (File No. 001-16417), Exhibit 10.10~~

~~10.01~~		5-Year Revolving Credit Agreement, dated as of December 10, 2007, among NuStar Logistics, L.P., NuStar Energy L.P., the Lenders party thereto and JPMorgan Chase Bank, N.A., as Administrative Agent, Suntrust Bank, as Syndication Agent, and Barclays Bank PLC and Mizuho Corporate Bank Ltd., as Co-Documentation Agents, J.P. Morgan Securities Inc., as Sole Bookrunner and J.P. Morgan Securities Inc. and Suntrust Robinson Humphrey, as Co-lead Arrangers	NuStar Energy L.P.’s Annual Report on Form 10-K for the year ended December 31, 2007 (File No. 001-16417), Exhibit 10.01

	10.02		First Amendment to 5-Year Revolving Credit Agreement, dated as of August 18, 2010, among NuStar Logistics, L.P., as Borrower, NuStar Energy L.P., JPMorgan Chase Bank, N.A., as Administrative Agent, and the Lenders Party thereto	NuStar Energy L.P.’s Current Report on Form 8-K filed August 20, 2010 (File No. 001-16417), Exhibit 10.01

	+~~10.02~~10.03		NuStar GP, LLC Amended and Restated 2003 Employee Unit Incentive Plan, amended and restated as of April 1, 2007	NuStar Energy L.P.’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2007 (File No. 001-16417), Exhibit 10.03

	+~~10.03~~10.04		Form of Unit Option Agreement under the Valero GP, LLC Amended and Restated 2003 Employee Unit Incentive ~~Plan~~Plan. as amended	NuStar Energy L.P.’s Annual Report on Form 10-K for year ended December 31, 2006 (File No. 001-16417), Exhibit 10.11


Exhibit Number		Description	Incorporated by Reference to the Following Document

	+~~10.04~~10.05	NuStar GP, LLC Amended and Restated 2002 Unit Option Plan, amended and restated as of April 1, 2007	NuStar Energy L.P.’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2007 (File No. 001-16417), Exhibit 10.02

	+~~10.05~~10.06	NuStar GP, LLC Second Amended and Restated 2000 Long-Term Incentive Plan, amended and restated as of April 1, 2007	NuStar Energy L.P.’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2007 (File No. 001-16417), Exhibit 10.01

	+~~10.06~~10.07	Form of Restricted Unit Award Agreement under the NuStar GP, LLC Second Amended and Restated 2000 Long-Term Incentive Plan	NuStar Energy L.P.’s Current Report on Form 8-K filed November 10, 2008 (File No. 001-16417), Exhibit 10.03

	+~~10.07~~10.08	Form of Unit Option Award Agreement under the ~~NuStar~~Valero GP, LLC Second Amended and Restated 2000 Long-Term Incentive Plan	NuStar Energy L.P.’s Current Report on Form 8-K filed November 3, 2006 (File No. 001-16417), Exhibit 10.02

	+~~10.08~~10.09	Form of ~~Performance~~Restricted Unit Award Agreement under the Valero GP, LLC Second Amended and Restated 2000 Long-Term Incentive Plan	NuStar Energy L.P.’s Current Report on Form 8-K filed November 3, 2006 (File No. 001-16417), Exhibit 10.03

	+10.10	Form of Restricted Unit Award Agreement under the NuStar GP, LLC Second Amended and Restated 2000 Long-Term Incentive Plan	NuStar Energy L.P.’s Current Report on Form 8-K filed October 29, 2007 (File No. 001-16417), Exhibit 10.03

	+10.11	Form of 2010 Restricted Unit Award Agreement under the NuStar GP, LLC Second Amended and Restated 2000 Long-Term Incentive Plan	NuStar Energy L.P.’s Current Report on Form 8-K filed January ~~26,~~5, 2011(File No. 001-16417), Exhibit 10.03

	+10.12	Form of Performance Unit Agreement under the Valero GP, LLC 2000 Amended and Restated Long-Term Incentive Plan	NuStar Energy L.P.’s Current Report on Form 8-K filed January 27, 2006 (File No. 001-16417), Exhibit 10.02

	+~~10.09~~10.13	Form of Amended and Restated Performance Unit Agreement under the NuStar GP, LLC Second Amended and Restated 2000 Long-Term Incentive Plan	NuStar Energy L.P.’s Current Report on Form 8-K filed December 8, 2009 (File No. 001-16417), Exhibit 10.02

	+~~10.10~~10.14	Omnibus Amendment to Form of Amended and Restated Performance Unit Agreements under the NuStar GP LLC Second Amended and Restated 2000 Long-Term Incentive Plan	NuStar Energy L.P.’s Current Report on Form 8-K filed February 2, 2010 (File No. 001-16417), Exhibit 10.03


~~Exhibit~~ ~~Number~~		~~Description~~	~~Incorporated by Reference~~ ~~to the Following Document~~

	+~~10.11~~10.15		Form of Performance Unit Agreement under the Second Amended and Restated 2000 Long-Term Incentive Plan	*NuStar Energy L.P.’s Annual Report on Form 10-K for year ended December 31, 2009 (File No. 001-16417), Exhibit 10.11

	+~~10.12~~10.16		Form of Non-employee Director Restricted Unit Agreement under the NuStar GP, LLC Second Amended and Restated 2000 Long-Term Incentive Plan	NuStar Energy L.P.’s Current Report on Form 8-K filed October 29, 2007 (File No. 001-16417), Exhibit 10.02

	+10.17		Form of Non-employee Director Restricted Unit Agreement under the NuStar GP, LLC Second Amended and Restated 2000 Long-Term Incentive Plan	NuStar Energy L.P.’s Current Report on Form 8-K filed November 10, 2008 (File No. 001-16417), Exhibit 10.02

	+~~10.13~~10.18		Form of 2010 Non-employee Director Restricted Unit Agreement under the NuStar GP, LLC Second Amended and Restated 2000 Long-Term Incentive Plan	NuStar Energy L.P.’s Current Report on Form 8-K filed January 5, 2011(File No. 001-16417), Exhibit 10.02


Exhibit Number				Description	Incorporated by Reference to the Following Document

	+10.19			Valero L.P. Annual Bonus Plan	NuStar Energy L.P.’s Annual Report on Form 10-K for year ended December 31, 2006 (File No. 001-16417), Exhibit 10.18

	+~~10.14~~10.20			Change of Control Severance Agreement by and among Valero GP, LLC, Valero L.P. and Curtis V. Anastasio, dated November 6, 2006.	NuStar Energy L.P.’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2006 (File No. 001-16417), Exhibit 10.05

	+~~10.15~~10.21			Form of Change of Control Severance Agreement by and among Valero LP, Valero GP, LLC ~~Valero L.P.~~ and each of the other executive officers of Valero GP, LLC, dated as of November 6, 2006	NuStar Energy L.P.’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2006 (File No. 001-16417), Exhibit 10.06

~~10.16~~	10.22			Non-Compete Agreement between Valero GP Holdings, LLC, Valero L.P., Riverwalk Logistics, L.P. and Valero GP, LLC, effective as of July 19, 2006	NuStar Energy L.P.’s Quarterly Report on Form 10-Q for quarter ended September 30, 2006 (File No. 001-16417), Exhibit 10.03

~~10.17~~	10.23			Services Agreement, effective January 1, 2008, between NuStar GP, LLC and NuStar Energy L.P.	NuStar Energy L.P.’s Quarterly Report on Form 10-Q for quarter ended March 31, 2008 (File No. 001-16417), Exhibit 10.01

~~10.18~~	+10.24			NuStar ~~GP, LLC~~ Excess Pension Plan, amended and restated effective as of January 1, 2008	NuStar Energy L.P.’s Annual Report on Form 10-K for year ended December 31, 2008 (File No. 001-16417), Exhibit 10.29

~~10.19~~	+10.25			NuStar ~~GP, LLC~~ Excess Thrift Plan, amended and restated effective as of January 1, 2008	NuStar Energy L.P.’s Annual Report on Form 10-K for year ended December 31, 2008 (File No. 001-16417), Exhibit 10.30

~~10.20~~	+10.26			NuStar ~~GP, LLC~~ Supplemental Executive Retirement Plan, amended and restated effective as of January 1, 2008	NuStar Energy L.P.’s Annual Report on Form 10-K for year ended December 31, 2008 (File No. 001-16417), Exhibit 10.31

~~10.21~~	+10.27		~~NuStar~~	Shamrock Logistics GP, LLC ~~Short-Term~~Year 2001 Annual Incentive Plan	NuStar Energy L.P.’s Amendment No. 5 to Registration Statement on Form S-1 filed March 29, 2001 (File No. 333-43668), Exhibit 10.4

~~10.22~~		~~NuStar GP, LLC Intermediate-Term Incentive Plan~~		~~NuStar Energy L.P.’s Registration Statement on Form S-1 filed March 29, 2001 (File No. 333-43668), Exhibit 10.9~~


Exhibit Number ~~Number~~		Description	Incorporated by Reference to the Following Document

~~10.23~~	+10.28	Shamrock Logistics GP, LLC Intermediate Incentive Compensation Plan	NuStar Energy L.P.’s Amendment No. 5 to Registration Statement on Form S-1 filed March 29, 2001 (File No. 333-43668), Exhibit 10.9

	10.29	Sale and Purchase Agreement, dated as of November 5, 2007, by and between CITGO Asphalt Refining Company and NuStar Asphalt Refining, LLC	NuStar Energy L.P.’s Annual Report on Form 10-K for year ended December 31, ~~2008~~2007 (File No. 001-16417), Exhibit 10.37

~~10.24~~	10.30	Amendment to Sale and Purchase Agreement dated January 10, 2008, by and between CITGO Asphalt Refining Company and NuStar Asphalt Refining, LLC	NuStar Energy L.P.’s Current Report on Form 8-K filed March 25, 2008 (File No. 001-16417), Exhibit 10.4

	10.31	Second Amendment to Sale and Purchase Agreement dated March 20, 2008, by and between CITGO Asphalt Refining Company and NuStar Asphalt Refining, LLC	NuStar Energy L.P.’s Current Report on Form 8-K filed March 25, 2008 (File No. 001-16417), Exhibit 10.5

	10.32	Amended and Restated Aircraft Time Sharing Agreement, dated as of September 4, 2009, between NuStar Logistics, L.P. and William E. Greehey	*NuStar Energy L.P.’s Annual Report on Form 10-K for year ended December 31, 2009 (File No. 001-16417), Exhibit 10.24

	10.33	Crude Oil Sales Agreement between NuStar Marketing LLC and PDVSA-Petróleo S.A., an affiliate of Petróleos de Venezuela S.A., the national oil company of the Bolivarian Republic of Venezuela, dated effective as of March 1, 2008	NuStar Energy L.P.’s Current Report on Form 8-K filed March 25, 2008 (File No. 001-16417), Exhibit 10.1

	10.34	Peregrino Crude Oil Purchase/Sale Agreement between Statoil Brasil Óleo E Gas Limitada and NuStar Marketing LLC dated as of November 17, 2010	*#


Exhibit Number		Description	Incorporated by Reference to the Following Document

	10.35	Lease Agreement Between Parish of St. James, State of Louisiana and NuStar Logistics, L.P. dated as of July 1, 2010	NuStar Energy L.P.’s Current Report on Form 8-K filed July 21, 2010 (File No. 001-16417), Exhibit 10.01

	10.36	Application for Letter of Credit and Reimbursement Agreement Between JPMorgan Chase Bank, N.A. and NuStar Logistics, L.P. dated as of July 15, 2010	NuStar Energy L.P.’s Current Report on Form 8-K filed July 21, 2010 (File No. 001-16417), Exhibit 10.02

	10.37	Lease Agreement between Parish of St. James, State of Louisiana and NuStar Logistics, L.P. dated as of December 1, 2010	NuStar Energy L.P.’s Current Report on Form 8-K filed December 30, 2010 (File No. 001-16417), Exhibit 10.01

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

	12.01	Statement of Computation of Ratio of Earnings to Fixed Charges	*

	14.01	Code of Ethics for Senior Financial Officers	NuStar Energy L.P.’s Annual Report on Form 10-K for year ended December 31, 2003 (File No. 001-16417), Exhibit 14.1

	21.01	List of subsidiaries of NuStar Energy L.P.	*

	23.01	Consent of KPMG LLP, dated February ~~26, 2010~~25, 2011	*

	24.01	Powers of Attorney (included in signature page of this Form 10-K)	*

	31.01	Rule 13a-14(a) ~~Certifications~~Certification (under Section 302 of the Sarbanes-Oxley Act of 2002) of principal executive officer	*

	31.02	Rule 13a-14(a) Certification (under Section 302 of the Sarbanes-Oxley Act of 2002) of principal financial officer	*

	32.01	Section 1350 ~~Certifications~~Certification (under Section 906 of the Sarbanes-Oxley Act of 2002) of principal executive officer	*

	32.02	Section 1350 Certification (under Section 906 of the Sarbanes-Oxley Act of 2002) of principal financial officer	*

	99.01	Audit Committee Pre-Approval Policy	*

In accordance with Rule 406T of regulation S-T, the XBRL information in Exhibit 101 to this annual report on Form 10-K shall not be deemed to be “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended (Exchange Act), or otherwise subject to the liability of that section, and shall not be incorporated by reference into any registration statement or other document filed under the Securities Act of 1933, as amended, or the Exchange Act. The financial information contained in the XBRL-related documents is “unaudited” or “unreviewed.”

Copies of exhibits filed as a part of this Form 10-K may be obtained by unitholders of record at a charge of $0.15 per page, minimum $5.00 each request. Direct inquiries to Corporate Secretary, NuStar Energy L.P., 2330 North Loop 1604 West, San Antonio, Texas 78248.

Pursuant to the requirements of Section 13 or 15(d) of the Exchange Act, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

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

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


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)


PART I
Items 1., 1A. & 2.	Business, Risk Factors and Properties		3
	Overview		3
	Recent Developments		4
	Organizational Structure		4
	Segments		6
	Employees		20
	Rate Regulation		20
	Environmental and Safety ~~Regulations~~Regulation		20
	Risk Factors		23
	Properties		33

Items 1B.	Unresolved Staff Comments		34

Item 3.	Legal Proceedings		34

Item 4.	Submission of Matters to a Vote of Security Holders		3635

PART II
Item 5.	Market for Registrant’s Common Units, Related Unitholder Matters and Issuer Purchases of Common Units		3736

Item 6.	Selected Financial Data		3837

Item 7.	~~Management’s~~Management's Discussion and Analysis of Financial Condition and Results of Operations	39

~~Item 7A.~~	~~Quantitative and Qualitative Disclosure About Market Risk~~38	57

Item 8.	Financial Statements and Supplementary Data		6061

Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		~~109~~111

Item 9A.	Controls and Procedures		~~109~~111

Item 9B.	Other Information		~~109~~111

PART III
Item 10.	Directors, Executive Officers and Corporate Governance		~~110~~112

Item 11.	Executive Compensation		~~114~~116

Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters		~~148~~150

Item 13.	Certain Relationships and Related Transactions and Director Independence		~~150~~152

Item 14.	Principal Accountant Fees and Services		~~153~~155

PART IV
Item 15.	Exhibits and Financial Statement Schedules		~~155~~157

Signatures			~~162~~167


Location of Terminals	Tank Capacity		Number of Tanks		Related Pipeline System
	(Barrels)

Iowa:
LeMars		103,000		8		East
Milford		172,000		11		East
Rock Rapids		223,000		5		East

Kansas:
Concordia		79,000		6		East
Hutchinson		114,000		5		East
Salina		86,000		8		East

Minnesota:
Moorhead		518,000		10		North
Sauk Centre		116,000		7		North
Roseville		479,000		10		North

Nebraska:
Columbus		171,000		8		East
Geneva		674,000		37		East
Norfolk		182,000		15		East
North Platte		247,000		23		East
Osceola		79,000		7		East

North Dakota:
Jamestown (North)		139,000		6		North
Jamestown (East)		176,000		11		East

South Dakota:
Aberdeen		181,000		12		East
Mitchell		63,000		6		East
Sioux Falls		381,000		12		East
Wolsey		148,000		20		East
Yankton		245,000		25		East

Total		4,576,000		252


Location of Terminals	Tank Capacity		Number of Tanks		Related Pipeline System
	(Barrels)

Iowa:
LeMars		103,000		8		East
Milford		172,000		11		East
Rock Rapids		223,000		5		East

Kansas:
Concordia		79,000		6		East
Hutchinson		114,000		5		East
Salina		86,000		8		East

Minnesota:
Moorhead		518,000		10		North
Sauk Centre		116,000		7		North
Roseville		479,000		10		North

Nebraska:
Columbus		171,000		8		East
Geneva		674,000		37		East
Norfolk		182,000		15		East
North Platte		247,000		23		East
Osceola		79,000		7		East

North Dakota:
Jamestown (North)		139,000		6		North
Jamestown (East)		176,000		11		East

South Dakota:
Aberdeen		181,000		12		East
Mitchell		63,000		6		East
Sioux Falls		381,000		12		East
Wolsey		148,000		20		East
Yankton		245,000		25		East

Total		4,576,000		252


	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%


		Year Ended December 31,						Change
		2008			2007			Change
Statement of Income Data:
Revenues:
Service revenue	$	740,630		$	696,623		$	44,007
Product sales		4,088,140			778,391			3,309,749

Total revenues		4,828,770			1,475,014			3,353,756

Costs and expenses:
Cost of product sales		3,864,310			742,972			3,121,338
Operating expenses		442,248			357,235			85,013
General and administrative expenses		76,430			67,915			8,515
Depreciation and amortization expense		135,709			114,293			21,416

Total costs and expenses		4,518,697			1,282,415			3,236,282


Operating income		310,073			192,599			117,474
Equity earnings from joint ventures		8,030			6,833			1,197
Interest expense, net		(90,818	)		(76,516	)		(14,302	)
Other income , net		37,739			38,830			(1,091	)

Income before income tax expense		265,024			161,746			103,278
Income tax expense		11,006			11,448			(442	)

Net income	$	254,018		$	150,298		$	103,720


Net income per unit applicable to limited partners	$	4.22		$	2.73		$	1.49


Weighted average limited partner units outstanding		53,182,741			47,158,790			6,023,951


Date Issued	Maturity Date	Amount Outstanding		Amount of Letter of Credit		Amount Received from Trustee		Amount Remaining in Trust		Average Annual Interest Rate
		(Thousands of Dollars)

June 26, 2008	June 1, 2038	$	55,440	$	56,169	$	55,440	$	-		0.3	%
July 15, 2010	July 1, 2040		100,000		101,315		28,218		71,782		0.3	%
October 7, 2010	October 1, 2040		50,000		50,658		581		49,419		0.3	%
December 29, 2010	December 1, 2040		85,000		86,118		835		84,165		0.4	%


	Total	$	290,440	$	294,260	$	85,074	$	205,366


	Standard & Poor’s	Moody’s ~~Moody’s~~Investor Service	Fitch

Outlook	Stable	Stable	Stable
Ratings	BBB-	Baa3	BBB-


Notional Amount	Period of Hedge	Weighted- Average Fixed Rate			Fair Value
(Thousands of Dollars)					(Thousands of Dollars)

$ 125,000	03/13 – 03/23		3.5	%	$	8,717
150,000	06/13 – 06/23		3.5	%		11,243
225,000	02/12 – 02/22		3.1	%		15,040
$ 500,000			3.3	%	$	35,000


		December 31, 2009
		Expected Maturity Dates																		Total			Fair Value
		2010			2011			2012			2013			2014			There- after			Total			Fair Value
		(Thousands of Dollars, Except Interest Rates)
Long-term Debt:
Fixed rate	$	770		$	832		$	384,816		$	480,902		$	67		$	350,000		$	1,217,387		$	1,306,301
Average interest rate		8.0	%		8.0	%		7.4	%		6.0	%		8.0	%		7.7	%		6.9	%
Variable rate	$	-		$	-		$	525,126		$	-		$	-		$	56,200		$	581,326		$	551,072
Average interest rate		-			-			1.0	%		-			-			0.2	%		0.9	%

Interest Rate Swaps Fixed to Variable:
Notional amount	$	-		$	-		$	60,000		$	107,500		$	-		$	-		$	167,500		$	8,623
Average pay rate		3.4	%		4.8	%		5.8	%		5.6	%		-			-			4.3	%
Average receive rate		6.3	%		6.3	%		6.3	%		6.1	%		-			-			6.3	%

		December 31, 2008
		Expected Maturity Dates																		Total			Fair Value
		2009			2010			2011			2012			2013			There- after			Total			Fair Value
		(Thousands of Dollars, Except Interest Rates)
Long-term Debt:
Fixed rate	$	713		$	770		$	832		$	381,647		$	480,902		$	350,627		$	1,215,491		$	1,157,470
Average interest rate		8.0	%		8.0	%		8.0	%		7.4	%		6.0	%		7.7	%		6.9	%
Variable rate	$	-		$	-		$	-		$	555,294		$	-		$	56,200		$	611,494		$	611,494
Average interest rate		-			-			-			1.9	%		-			0.9	%		1.8	%

Interest Rate Swaps Fixed to Variable:
Notional amount	$	-		$	-		$	-		$	60,000		$	107,500		$	-		$	167,500		$	15,284
Average pay rate		3.2	%		3.9	%		4.3	%		4.5	%		4.3	%		-			4.0	%
Average receive rate		6.3	%		6.3	%		6.3	%		6.3	%		6.1	%		-			6.3	%


Cash paid for the East Coast Asphalt Operations	$	801,686
Transaction costs		1,498

Total cash paid		803,184
Fair value of liabilities assumed		37,238

Purchase price	$	840,422


Inventories	$	327,312
Other current assets		1,439
Property, plant and equipment		450,310
Goodwill		22,132
Intangible assets		11,510
Other long-term assets		27,719

Purchase price allocation	$	840,422


	Year Ended December 31, 2008
	(Thousands of Dollars, Except Per Unit Data)

Revenues		$5,008,623
Operating income		318,626
Net income		254,539

Net income per unit applicable to limited partners		$ 4.13


Date Issued	Maturity Date		Amount Outstanding		Amount of Letter of Credit		Amount Received from Trustee		Amount Remaining in Trust	Average Annual Interest Rate
				(Thousands of Dollars)

June 26, 2008	June 1, 2038	$	55,440	$	56,169	$	55,440	$	-	0.3%
July 15, 2010	July 1, 2040		100,000		101,315		28,218		71,782	0.3%
October 7, 2010	October 1, 2040		50,000		50,658		581		49,419	0.3%
December 29, 2010	December 1, 2040		85,000		86,118		835		84,165	0.4%

	Total	$	290,440	$	294,260	$	85,074	$	205,366


Notional Amount			Period of Hedge		Weighted-Average Fixed Rate
(Thousands of Dollars)

	$	125,000		03/13 – 03/23		3.5	%
		150,000		06/13 – 06/23		3.5	%
		225,000		02/12 – 02/22		3.1	%

	$	500,000				3.3	%


		~~December 31, 2009~~
		~~(Thousands of barrels)~~

~~Commodity contracts – Fair Value Hedges~~		~~11,619~~
~~Commodity contracts – Cash Flow Hedges~~		~~230~~


	Balance Sheet Location	Asset Derivatives				Liability Derivatives
		December 31,				December 31,
		2009		2008		2009			2008
			(Thousands of Dollars)
Derivatives Designated as Hedging Instruments:
Interest rate swaps	Other long-term assets, net	$	8,623	$	15,284	$	-		$	-
Commodity contracts	Other current assets		-		7,005		-			(6,911	)
Commodity contracts	Accrued liabilities		3,797		-		(14,279	)		-

Total			12,420		22,289		(14,279	)		(6,911	)


Derivatives Not Designated as Hedging Instruments:
Commodity contracts	Other current assets		-		8,408		-			-
Commodity contracts	Accrued liabilities		9,766		-		(30,072	)		-

Total			9,766		8,408		(30,072	)		-


Total Derivatives		$	22,186	$	30,697	$	(44,351	)	$	(6,911	)


~~Derivatives~~ ~~Designated as Cash~~ ~~Flow Hedging~~ ~~Instruments~~	~~Amount of Gain~~ ~~(Loss) Recognized~~ ~~in OCI on~~ ~~Derivative~~ ~~(Effective Portion)~~	~~Income Statement~~ ~~Location (a)~~	~~Amount of Gain~~ ~~(Loss) Reclassified~~ ~~from~~ ~~Accumulated OCI~~ ~~into Income~~ ~~(Effective Portion)~~	~~Amount of Gain~~ ~~(Loss) Recognized~~ ~~in Income on~~ ~~Derivative~~ ~~(Ineffective~~ ~~Portion)~~
	~~(Thousands of Dollars)~~		~~(Thousands of Dollars)~~

~~Commodity contracts~~	~~$ (240)~~	~~Cost of product sales~~	~~$ -~~	~~$ -~~


Derivatives Not Designated as Hedging Instruments	Income Statement Location	Amount of Gain (Loss) Recognized in Income
		(Thousands of Dollars)

Year ended December 31, 2010:
Commodity contracts	Cost of product sales		$	(3,050	)
Commodity contracts	Operating expenses			(52	)

Total			$	(3,102	)


Year ended December 31, 2009:
Commodity contracts	Cost of product sales		$	(13,594	)
Commodity contracts	Operating expenses			(3,589	)

Total			$	(17,183	)


	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%


	~~Year Ended~~ ~~December 31, 2007~~
	~~(Thousands of Dollars)~~

~~Revenues:~~
~~Storage~~		$	~~115,417~~
~~Transportation~~			~~147,597~~
~~Asphalt and fuels marketing~~			~~7,426~~

~~Total revenues~~		$	~~270,440~~


	Storage		Transportation			Asphalt and Fuels Marketing		Total
	(Thousands of Dollars)

Balance as of January 1, 2008	$	578,529	$	175,367		$	31,123	$	785,019
East Coast Asphalt Operations acquisition preliminary purchase price allocation		-		-			20,201		20,201
Other		1,110		-			-		1,110

Balance as of December 31, 2008	$	579,639	$	175,367		$	51,324	$	806,330

East Coast Asphalt Operations acquisition final purchase price allocation		-		-			1,931		1,931
Sale of assets		-		(519	)		-		(519	)

Balance as of December 31, 2009	$	579,639	$	174,848		$	53,255	$	807,742


	Storage		Transportation			Asphalt and Fuels Marketing		Total
	(Thousands of Dollars)

Balance as of January 1, 2009	$	579,639	$	175,367		$	51,324	$	806,330
East Coast Asphalt Operations acquisition final purchase price allocation		-		-			1,931		1,931
Sale of assets		-		(519	)		-		(519	)

Balance as of December 31, 2009		579,639		174,848			53,255		807,742

Asphalt Holdings, Inc. acquisition preliminary purchase price allocation		5,528		-			-		5,528

Balance as of December 31, 2010	$	585,167	$	174,848		$	53,255	$	813,270


	NuStar Energy		NuStar Logistics		NuPOP		Non-Guarantor Subsidiaries (a)			Eliminations			Consolidated

Assets
Cash and cash equivalents	$	53	$	1,602	$	-	$	60,351		$	-		$	62,006
Receivables, net		-		38,973		6,771		176,778			(10,725	)		211,797
Inventories		-		-		-		379,472			(2,242	)		377,230
Other current assets		-		10,746		3,820		69,120			-			83,686
Intercompany receivable		-		806,005		713,451		-			(1,519,456	)		-

Current assets		53		857,326		724,042		685,721			(1,532,423	)		734,719

Property, plant and equipment, net		-		947,895		626,698		1,453,603			-			3,028,196
Intangible assets, net		-		2,247		-		41,880			-			44,127
Goodwill		-		18,094		170,652		618,996			-			807,742
Investment in wholly owned subsidiaries		2,986,970		118,299		873,422		1,907,118			(5,885,809	)		-
Investments in joint ventures		-		-		-		68,728			-			68,728
Deferred income tax asset		-		-		-		13,893			-			13,893
Other long-term assets, net		49		21,942		26,392		28,885			-			77,268

Total assets	$	2,987,072	$	1,965,803	$	2,421,206	$	4,818,824		$	(7,418,232	)	$	4,774,673


Liabilities and Partners’ Equity
Current portion of long-term debt	$	-	$	770	$	-	$	-		$	-		$	770
Payables		944		18,566		10,654		196,805			(10,725	)		216,244
Notes payable		-		20,000		-		-			-			20,000
Accrued interest payable		-		12,996		8,490		43			-			21,529
Accrued liabilities		1,191		14,380		4,652		44,472			(44	)		64,651
Taxes other than income tax		125		4,183		2,280		8,946			-			15,534
Income tax payable		-		1,271		-		(1,245	)		-			26
Intercompany payable		507,654		-		-		1,011,806			(1,519,460	)		-

Current liabilities		509,914		72,166		26,076		1,260,827			(1,530,229	)		338,754

Long-term debt, less current portion		-		1,271,750		523,326		33,917			-			1,828,993
Long-term payable to related party		-		1,082		-		6,581			-			7,663
Deferred tax liability		-		-		-		26,909			-			26,909
Other long-term liabilities		-		3,923		883		82,580			-			87,386
Total partners’ equity		2,477,158		616,882		1,870,921		3,408,010			(5,888,003	)		2,484,968

Total liabilities and partners’ equity	$	2,987,072	$	1,965,803	$	2,421,206	$	4,818,824		$	(7,418,232	)	$	4,774,673


Name	Age	Position Held with NuStar GP, LLC
William E. Greehey	7374	Chairman of the Board
Curtis V. Anastasio	5354	President, Chief Executive Officer (CEO) and Director
J. Dan Bates	66	Director
Dan J. Hill	70	Director
Stan McLelland	65	Director
~~Dan J. Hill~~ Rodman D. Patton	6967	Director
~~Stan McLelland~~ Bradley C. Barron	64	~~Director~~
~~Rodman D. Patton~~	66	~~Director~~
~~Bradley C. Barron~~	4445	Senior Vice President and General Counsel
Steven A. Blank	5556	Senior Vice President, Chief Financial Officer (CFO) and Treasurer
James R. Bluntzer	5556	Senior Vice President-Operations
Paul W. Brattlof	4849	Senior Vice President-Trading and Supply
Mary Rose Brown	5354	Senior Vice President-Administration
Daniel S. Oliver	4344	Senior Vice ~~President-Marketing~~President- Marketing and Business Development
Thomas R. Shoaf	5152	Vice President and Controller



Company	Ticker
1.	Boardwalk Pipeline Partners	BWP
2.	Buckeye Partners LP	BPL
3.	Copano Energy LLC	CPNO
4.	Crosstex Energy LP	XTEX
5.	Enbridge Energy Partners LP	EEP
6.	Energy Transfer Partners	ETP
7.	Enterprise Product Partners LP	EPD
8.	Kinder Morgan Energy LP	KMP
9.	Magellan Midstream Partners LP	MMP
10.	Mark West Energy Partners	MWE
11.	ONEOK Partners, L.P.	OKS
12.	Plains All American Pipeline LP	PAA
13.	Regency Energy Partners	RGNC
14.	Sunoco Logistics Partners LP	SXL
15.	~~Teppco Partners LP~~	~~TPP~~
~~16.~~	Frontier Oil Corporation*	FTO


~~17.~~	16. Holly Corporation*	HOC
~~18.~~	17. Western Refining Inc.*	WNR


Event		Timing
Establishing financial performance objectives for current year’s annual incentive bonus; evaluating achievement of bonus metrics in prior year		First quarter
Review and certify financial performance for performance units granted in prior years; grant performance units		First quarter
Review base salaries for executive officers for the current year and targets for annual incentive bonus and long-term incentive grants		Third quarter
Consider grant of restricted unit and unit options to employees and officers and grant restricted units to directors		Fourth ~~quarter; three business days after third~~ quarter ~~earnings releases (or as soon as practicable thereafter)~~


Name		Annual Incentive Bonus Target as a Percentage of Base Salary
Anastasio		80
Blank		50
Bluntzer		50
Brattlof		50
Brown		50


Name		Bonuses Paid For ~~2009~~2010
Anastasio		$~~284,300~~385,000
Blank		~~127,800~~173,000
Bluntzer		~~115,000~~155,000
Brattlof		~~108,600~~147,000
Brown		~~115,000~~155,000


Name		Long-Term Incentive Target (% of base salary)
Anastasio		~~150~~160
Blank		80100
Bluntzer		80100
Brattlof		8090
Brown		80100


Name		Performance Unit Grants in ~~2009~~2010
Anastasio		~~6,383~~5,230
Blank		~~2,400~~2,350
Bluntzer		~~2,200~~2,110
Brattlof		~~2,050~~1,800
Brown		~~2,200~~2,110


Vesting Date		NS Closing Price ($)
~~January 22, 2009~~April 30, 2010		~~45.26~~
~~April 30, 2009~~		~~50.39~~61.56
October 27, ~~2009~~2010		~~53.59~~
~~October 28, 2009~~		~~53.35~~63.13
November 2, ~~2009~~2010		~~53.60~~64.65
November 6, ~~2009~~2010		~~54.11~~66.39
November 16, ~~2009~~2010		~~53.20~~65.77
December 14, 2010		70.66
		NSH Closing Price ($)
November 6, ~~2009~~2010		~~23.70~~35.50
December 14, 2010		37.23


~~Name~~		~~Gross Value of Previously~~ ~~Unvested Options~~

~~Anastasio~~		~~-263,741~~

~~Blank~~		~~-191,533~~

~~Bluntzer~~		~~-163,308~~

~~Brattlof~~		~~-175,371~~

~~Brown~~		~~-179,371~~


(a)	(1)	Financial Statements. The following consolidated financial statements of NuStar Energy L.P. and its subsidiaries are included in Part II, Item 8 of this Form 10-K:

		Management’s Report on Internal Control over Financial Reporting Reports of independent registered public accounting firm (KPMG LLP) Consolidated Balance Sheets as of December 31, ~~2009~~2010 and ~~2008~~2009 Consolidated Statements of Income for the Years Ended December 31, 2010, 2009 ~~2008~~ and ~~2007~~2008 Consolidated Statements of Cash Flows for the Years Ended December 31, 2010, 2009 ~~2008~~ and ~~2007~~2009 Consolidated Statements of Partners’ Equity for the Years Ended December 31, 2010, 2009 ~~2008~~ and ~~2007~~2008 Notes to Consolidated Financial Statements

	(2)	Financial Statement Schedules and Other Financial Information. No financial statement schedules are submitted because either they are inapplicable or because the required information is included in the consolidated financial statements or notes thereto.

	(3)	Exhibits

Exhibit
Number

Description

Incorporated by Reference
to the Following Document

Fourth Supplemental Indenture, dated and effective as of May 27, 2003, to Indenture dated as of February 21, 2002, as amended and supplemented, between Kaneb Pipe Line Operating Partnership, L.P. and JPMorgan Chase Bank (including form of 5.875% Senior Unsecured Notes due 2013)

NuStar Energy L.P.’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2005 (File No. 001-16417), Exhibit 4.07

Fifth Supplemental Indenture, dated and effective as of July 1, 2005, to Indenture dated as of February 21, 2002, as amended and supplemented, among Kaneb Pipe Line Operating Partnership, L.P.;, Valero L.P.;, Valero Logistics Operations, L.P.;, and JPMorgan Chase Bank

NuStar Energy L.P.’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2005 (File No. 001-16417), Exhibit 4.08