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  As Of               Filer                 Filing     As/For/On Docs:Pgs              Issuer               Agent

 2/29/08  NuStar Energy L/P                 10-K       12/31/07   11:450                                    RR Donnelley/FA

Document/Exhibit                   Description                      Pages   Size 

 1: 10-K        Annual Report                                       HTML  2,087K 
 2: EX-10.01    5-Year Revolving Credit Agreement                   HTML    411K 
 3: EX-10.37    Sale and Purchase Agreement                         HTML    319K 
 4: EX-10.38    Aircraft Time Sharing Agreement                     HTML     71K 
 5: EX-12.01    Statement of Computation of Ratio of Earnings to    HTML     31K 
                          Fixed Charges                                          
 6: EX-21.01    List of Subsidiaries of Nustar Energy L.P.          HTML     19K 
 7: EX-23.01    Consent of Kpmg Llp                                 HTML      6K 
 8: EX-31.01    Section 302 Certifications                          HTML     16K 
 9: EX-32.01    Section 906 Certifications                          HTML     10K 
10: EX-99.01    Audit Committee Pre-Approval Policy                 HTML     38K 
11: EX-99.02    Report of Independent Registered Public             HTML     41K 
                          Accountants                                            

Table of Contents

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

For the fiscal year ended December 31, 2007

OR

For the transition period from              to             

Commission File Number 1-16417

NUSTAR ENERGY L.P.

(Exact name of registrant as specified in its charter)

Registrant’s telephone number, including area code (210) 918-2000

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

Securities registered pursuant to 12(g) of the Act: None.

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.    Yes  x    No  ¨

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.    Yes  ¨    No  x

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  x    No  ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K 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):

Large accelerated filer  x    Accelerated filer  ¨    

Non-accelerated filer  ¨    (Do not check if a smaller reporting company)    Smaller reporting company  ¨

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

The aggregate market value of the common units held by non-affiliates was approximately $2,506 million based on the last sales price quoted as of June 29, 2007, the last business day of the registrant’s most recently completed second quarter.

The number of common units outstanding as of February 1, 2008 was 49,409,749.

Table of Contents

 TABLE OF CONTENTS

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 PART I

Unless otherwise indicated, the terms “NuStar Energy L.P.,” “the Partnership,” “we,” “our” and “us” are used in this report to refer to NuStar Energy L.P., to one or more of our consolidated subsidiaries or to all of them taken as a whole. In the following Items 1., 1A. and 2., “Business, Risk Factors and Properties,” we make certain forward-looking statements, including statements regarding our plans, strategies, objectives, expectations, intentions and resources. The words “forecasts,” “intends,” “believes,” “expects,” “plans,” “scheduled,” “goal,” “may,” “anticipates,” “estimates” and similar expressions identify forward-looking statements. We do not undertake to update, revise or correct any of the forward-looking information. You are cautioned that such forward-looking statements should be read in conjunction with our disclosures beginning on page 40 of this report under the heading: “CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION.”

OVERVIEW

NuStar Energy L.P., a Delaware limited partnership, completed its initial public offering of common units on April 16, 2001 (NuStar Energy). 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 crude oil and refined product transportation, terminalling and storage business in the United States, the Netherland Antilles, Canada, Mexico, the Netherlands and the United Kingdom. Also, we purchase certain petroleum products for resale to third parties.

During the fourth quarter of 2007, we revised the manner in which we internally evaluate our segment performance and made certain organizational changes. As a result, we changed the way we report our segmental results such that all product sales and related costs are included in the marketing segment. We now manage our operations through the following five operating segments: refined product terminals, refined product pipelines, crude oil pipelines, crude oil storage tanks and marketing. As of December 31, 2007, our assets included:

We conduct our operations through our wholly owned subsidiaries, primarily NuStar Logistics, L.P. (NuStar Logistics) and Kaneb Pipe Line Operating Partnership, L.P. (KPOP). Our revenues include:

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

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Our internet website address is http://www.nustarenergy.com. Information contained on our website is not part of this report on Form 10-K. 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 (in the “Investors” section), free of charge, as soon as reasonably practicable after we file or furnish such material. 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 in the same website location. 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.

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 each pipeline, terminal or storage tank.

 RECENT DEVELOPMENTS

On December 10, 2007, NuStar Logistics replaced the existing $600 million revolving credit agreement with a $1.25 billion five-year revolving credit agreement (the 2007 Revolving Credit Agreement). NuStar Logistics borrowed $528.4 million under the 2007 Revolving Credit Agreement to repay in full the balance on its $600 million revolving credit agreement and $525 million term loan agreement.

On November 19, 2007, we issued 2,600,000 common units representing limited partner interests at a price of $57.20 per unit. We received proceeds of $146.1 million, including a contribution of $3.0 million from our general partner to maintain its 2% general partner interest, net of issuance costs. The proceeds were used to repay a portion of the outstanding principal balance under our then active $600 million revolving credit agreement.

On November 6, 2007, we entered into a definitive agreement to acquire CITGO Asphalt Refining Company’s asphalt operations and assets (East Coast Asphalt Operations) for approximately $450.0 million, plus an inventory adjustment. 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 on the East Coast with a combined storage capacity of 4.8 million barrels.

 ACQUISITIONS AND DISPOSITIONS

On December 1, 2006, we acquired a crude oil storage and blending facility in St. James, Louisiana from Koch Supply and Trading, L.P. for approximately $141.7 million. The acquisition includes 17 crude oil tanks with a total capacity of approximately 3.4 million barrels. Additionally, the facility has three docks with barge and ship access. The facility is located on the west bank of the Mississippi River approximately 60 miles west of New Orleans. We funded the acquisition with borrowings under our revolving credit agreement.

On March 30, 2006, we sold our subsidiaries located in Australia and New Zealand to ANZ Terminals Pty. Ltd., for total proceeds of $70.1 million. This transaction included the sale of eight terminals with an aggregate storage capacity of 1.1 million barrels.

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On July 1, 2005, we completed our acquisition (the Kaneb Acquisition) of Kaneb Services LLC (KSL) and Kaneb Pipe Line Partners, L.P. (KPP, and, together with KSL, Kaneb). We acquired all of KSL’s outstanding equity securities for approximately $509 million in cash. Additionally, we issued approximately 23.8 million of our common units valued at approximately $1.45 billion in exchange for all of the outstanding common units of KPP.

 ORGANIZATIONAL STRUCTURE

Our operations are managed by NuStar GP, LLC, the general partner of Riverwalk Logistics, L.P., our general partner. NuStar GP, LLC is a wholly owned subsidiary of NuStar GP Holdings, LLC (NuStar GP Holdings) (NYSE: NSH). We use the term “general partner” in this report to refer to Riverwalk Logistics, L.P., NuStar GP, LLC, Riverwalk Holdings, LLC and/or NuStar GP Holdings.

In two separate public offerings in 2006, Valero Energy Corporation (Valero Energy) sold their ownership interest in NuStar GP Holdings. NuStar GP Holdings did not receive any proceeds from their public offering, and Valero Energy’s ownership interest in NuStar GP Holdings was reduced to zero.

On April 1, 2007, we changed our name to NuStar Energy L.P. (formerly Valero L.P.), and Valero GP Holdings, LLC changed its name to NuStar GP Holdings, LLC. Prior to April 1, 2007, our common units traded on the NYSE under the symbol “VLI” and the common units of NuStar GP Holdings traded under the symbol “VEH.”

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The following chart depicts our organizational structure at December 31, 2007.

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 SEGMENTS

During the fourth quarter of 2007, we revised the manner in which we internally evaluate our segment performance and made certain organizational changes. As a result, we changed the way we report our segmental results such that all product sales and related costs are included in the marketing segment. Previous periods have been restated to conform to this presentation.

Our five reportable business segments are refined product terminals, refined product pipelines, crude oil pipelines, crude oil storage tanks and marketing. Detailed financial information about our segments is included in Note 20 in the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data.”

The following map depicts our operations at December 31, 2007.

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REFINED PRODUCT TERMINALS

Our terminal facilities provide storage and handling services on a fee basis for petroleum products, specialty chemicals, crude oil and other liquids. In addition, our terminals located on the island of St. Eustatius, Netherlands Antilles and in 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, 2007, we owned and operated:

Our five largest terminal facilities are located on the island of St. Eustatius, Netherlands Antilles; in Point Tupper, Nova Scotia; in Piney Point, Maryland; in Linden, New Jersey (50% owned joint venture); and in St. James, Louisiana.

Description of Largest Terminal Facilities

St. Eustatius, Netherlands Antilles. We own and operate a 13.0 million barrel petroleum storage and terminalling facility located on the Netherlands Antilles island of St. Eustatius, 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 as well as 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, Nova Scotia. 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 and Canada as well as 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, 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.

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

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York Harbor. This terminal primarily stores petroleum products, including gasoline, jet fuel and fuel oils. The facility has a total capacity of approximately 4.1 million barrels in 24 tanks, can receive products via ship, barge and pipeline and delivers product by ship, barge, pipeline and truck. The terminal includes two docks and leases a third with draft limits of 36, 26 and 20 feet, respectively.

St. James, Louisiana. Our terminal has 17 crude oil storage tanks with a total capacity of approximately 3.4 million barrels. Additionally, the facility has a rail-loading facility and three docks with barge and ship access. The facility is located on approximately 220 acres of land on the west bank of the Mississippi River approximately 60 miles west of New Orleans and has an additional 675 acres of undeveloped land.

In 2007, we began construction of four crude oil storage tanks with capacity of approximately 1.5 million barrels at our St. James facility, with estimated completion in the fourth quarter of 2008.

In addition, we are constructing 18 tanks with storage capacity of approximately 2.7 million barrels at our Amsterdam terminal with estimated completion in phases throughout 2008.

The following table outlines our terminal locations, tank capacity in barrels, number of tanks and primary products handled:

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In 2007, we sold three refined product terminals with approximately 700,000 barrels of storage capacity for total proceeds of approximately $3.6 million.

Terminal Operations

Revenues for the refined product terminals 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 (throughput revenues). Our terminals also provide blending, additive injections, handling and filtering services. Our facilities at Point Tupper and St. Eustatius charge fees to provide services such as pilotage, tug assistance, line handling, launch service, emergency response services and other ship services.

Demand for Refined Petroleum Products

The operations of our refined product terminals depend in large part on the level of demand for products stored in our terminals in the markets served by those assets. The majority of products stored in our terminals are refined petroleum products. Demand for our terminalling services will generally increase or decrease with demand for refined petroleum products, and demand for refined petroleum products tends to increase or decrease with the relative strength of the economy.

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Customers

We provide 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 refined product terminals segment is Valero Energy, which accounted for $70.2 million, or 19.2% of the total revenues of the segment, for the year ended December 31, 2007. No other customer accounted for more than 10% of the revenues of the segment for this period. Our crude oil transshipment customers include an oil producer that leases and utilizes 5.0 million barrels of storage at St. Eustatius and a major international oil company which leases and utilizes 3.6 million barrels of storage at Point Tupper, both of which have long-term contracts with us. In addition, two different international oil companies each lease and utilize more than 1.0 million barrels of clean products storage at St. Eustatius and Point Tupper. Also in Canada, a consortium consisting of major oil companies sends natural gas liquids via pipeline to certain processing facilities on land leased from us. After processing, certain products are stored at the Point Tupper facility under a long-term contract. In addition, our blending capabilities have attracted customers who have leased capacity primarily for blending purposes.

Competition and Business Considerations

Many major energy and chemical companies own extensive terminal storage facilities. Although such terminals often have the same capabilities as terminals owned by independent operators, they generally do not provide terminalling services to third parties. In many instances, major energy and chemical companies that own storage and terminalling facilities are also significant customers of independent terminal operators. Such companies typically have strong demand for terminals owned by independent operators when independent terminals have more cost-effective locations near key transportation links, such as deep-water ports. Major energy and chemical companies also need independent terminal storage when their owned storage facilities are inadequate, either because of size constraints, the nature of the stored material or specialized handling requirements.

Independent terminal owners generally compete on the basis of the location and versatility of terminals, service and price. A favorably located terminal will have access to various cost-effective transportation modes both to and from the terminal. Transportation modes typically include waterways, railroads, roadways and pipelines. Terminals located near deep-water port facilities are referred to as “deep-water terminals,” and terminals without such facilities are referred to as “inland terminals,” although some inland facilities located on or near navigable rivers are served by barges.

Terminal versatility is a function of the operator’s ability to offer complex handling requirements for diverse products. The services typically provided by the terminal include, among other things, the safe storage of the product at specified temperature, moisture and other conditions, as well as receipt at and delivery from the terminal, all of which must be in compliance with applicable environmental regulations. A terminal operator’s ability to obtain attractive pricing is often dependent on the quality, versatility and reputation of the facilities owned by the operator. Although many products require modest terminal modification, operators with versatile storage capabilities typically require less modification prior to usage, ultimately making the storage cost to the customer more attractive.

The main competition at our St. Eustatius and Point Tupper locations for crude oil handling and storage is from “lightering,” which is the process by which liquid cargo is transferred 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.

REFINED PRODUCT PIPELINES

Our refined product pipelines operations consist primarily of the transportation of refined petroleum products as a common carrier in Texas, Oklahoma, Colorado, New Mexico, Kansas, Nebraska, Iowa, South Dakota, North Dakota and Minnesota and cover approximately 6,251 miles. In addition, we own a 2,000 mile anhydrous ammonia pipeline located in Louisiana, Arkansas, Missouri, Illinois, Indiana, Iowa and Nebraska. As of December 31, 2007, we owned and operated:

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We charge tariffs on a per barrel basis for transporting refined products in our refined product pipelines and on a per ton basis for transporting anhydrous ammonia in our ammonia pipeline.

Description of Pipelines

Central West System. The pipelines included in the Central West System 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. We have entered into various agreements with Valero Energy governing the usage of these pipelines. Please read the disclosure contained in Note 14 of Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for additional information.

The refined products transported in these pipelines include gasoline, distillates (including diesel and jet fuel), natural gas liquids (such as propane and butane), blendstocks and other products produced primarily by Valero Energy’s refineries. These pipelines connect certain of Valero Energy’s refineries to key markets in Texas, New Mexico and Colorado.

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

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East Pipeline. The East Pipeline covers 1,900 miles and moves refined products north in pipelines ranging in size from 6 inches to 16 inches. The East Pipeline system also includes 22 product tanks with total storage capacity of approximately 1.2 million barrels at our two tank farms at McPherson and El Dorado, Kansas. The East Pipeline transports refined petroleum products to our terminals along the system and to receiving pipeline connections in Kansas. Shippers on the East Pipeline obtain refined petroleum products from refineries in southeast Kansas connected to the East Pipeline or through other pipelines directly connected to the pipeline system. The East Pipeline transported approximately 56.5 million barrels for the year ended December 31, 2007.

North Pipeline. The North Pipeline runs from west to east approximately 440 miles from its origin at the Tesoro Mandan refinery to the Minneapolis, Minnesota area. The North Pipeline crosses our East Pipeline near Jamestown, North Dakota where the two pipelines are connected. While the North Pipeline is currently supplied primarily by the Tesoro Mandan refinery, it is capable of delivering or receiving products to or from the East Pipeline. The North Pipeline transported approximately 16.8 million barrels for the year ended December 31, 2007.

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 transport trucks. Revenues earned at these terminals relate solely to the volumes transported on the pipeline. In the case of the North 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. In the case of the East Pipeline, separate fees are charged for the use of the terminals, even though such fees are separately stated within the filed pipeline tariff. As a result, these terminals are included in this segment instead of the refined product terminals segment.

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The following table shows the number of tanks we own as of December 31, 2007 at each of the 21 refined petroleum product terminals connected to the East or North Pipelines, the storage capacity in barrels and the pipeline to which each such terminal was connected:

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 13.8 million barrels (converted from tons) for the year ended December 31, 2007.

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

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Pipeline Operations

Revenues for the Central West System are based upon throughput volumes traveling through our system and the related tariffs. Revenues for the East Pipeline, North Pipeline and Ammonia Pipeline are based upon volumes and the distance the product is shipped and the related tariffs.

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 the pipelines. Each shipper transporting product on a pipeline is required to supply us with a notice of shipment indicating sources of products and destinations. All shipments are tested or receive refinery certifications to ensure compliance with our specifications. Refined product shippers are generally invoiced by us upon delivery for the Central West, North and Ammonia pipelines and upon the product entering our East pipeline. Tariffs for transportation are charged to shippers based upon transportation from the origination point on the pipeline to the point of delivery.

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.

The majority of our pipelines are common carrier and are subject to federal 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.

We use Supervisory Control and Data Acquisition remote supervisory control software programs to continuously monitor and control the pipelines. The system monitors quantities of products injected in and delivered through the pipelines and automatically signals the appropriate personnel upon deviations from normal operations that require attention.

Demand for and Sources of Refined Products

The operations of our Central West, 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.

Virtually all 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 refinery utilization rates, among other factors. Prices for gasoline and diesel fuel tend to increase in the warm weather months as more people drive automobiles.

The majority of the refined products delivered through the North Pipeline are delivered to the Minneapolis, Minnesota metropolitan area and consist primarily 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 delivered through the East Pipeline and volumes on the North Pipeline that are not delivered to Minneapolis are ultimately used as fuel for railroads 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.

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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 are connected to refineries owned by Valero Energy and generally are subject to long-term throughput agreements with Valero Energy. Valero Energy’s refineries connected directly to our pipelines obtain crude oil from a variety of foreign and domestic 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 through other pipelines. These refineries obtain their supplies of crude oil from a variety of sources. The pipelines in our Central West System are dependent upon the refineries owned by Valero Energy to which they connect. If operations at one of these refineries were discontinued or 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 the Tesoro Mandan refinery, which primarily runs North Dakota crude oil (although it has the ability to run other crude oils). If operations at the Tesoro Mandan refinery were interrupted, it could have a material effect on our operations. Other than the Valero Energy refineries described above and the Tesoro Mandan 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.

Virtually all of the refined products transported through the pipelines in the Central West System are produced by refineries owned by Valero Energy. 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 Refining refineries are connected directly to the East Pipeline. The East Pipeline also has direct access by third party pipelines to four other refineries in Kansas, Oklahoma and Texas and to Gulf Coast supplies of products through connecting pipelines that receive products from pipelines originating on the Gulf Coast.

Demand for and Sources of Anhydrous Ammonia

The Ammonia Pipeline is one of two major anhydrous ammonia pipelines in the United States and the only one capable of receiving foreign production directly into the system and transporting anhydrous ammonia into the nation’s corn belt.

Our Ammonia Pipeline operations depend on overall nitrogen fertilizer use, management practice, the level of demand for direct application of anhydrous ammonia as a fertilizer for crop production (Direct Application), the weather, as Direct Application is not effective if the ground is too wet or too dry, and the price of natural gas, the primary component of anhydrous ammonia.

Corn producers have fertilizer alternatives such as liquid or dry nitrogen fertilizers. Liquid and dry nitrogen fertilizers are both upgrades of anhydrous ammonia and therefore are generally more costly but are less sensitive to weather conditions during application. However, anhydrous ammonia has the highest nitrogen content of any nitrogen derivative fertilizer.

Customers

The largest customer of our refined product pipeline segment was Valero Energy, which accounted for $96.7 million, or 39.8% of the total segment revenues, for the year ended December 31, 2007. In addition to Valero Energy, we had a total of approximately 54 shippers for the year ended December 31, 2007, including integrated oil companies, refining companies, farm cooperatives and a railroad. No other customer accounted for greater than 15% of the total revenues of the refined product pipeline segment for the year ended December 31, 2007.

Competition and Business Considerations

Because pipelines are generally the lowest cost method for intermediate and long-haul movement of refined petroleum products, our more significant competitors are common carrier and proprietary pipelines owned and operated by major integrated and large independent oil companies and other companies in the areas where we deliver products. Competition between common carrier pipelines is based primarily on transportation charges, quality of customer service and proximity

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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.

The pipelines within the Central West System are physically integrated with and principally serve refineries owned by Valero Energy. Additionally, we have entered into various agreements with Valero Energy governing the usage of these pipelines. As a result, we believe that we will not face significant competition for transportation services provided to the Valero Energy refineries we serve. Please read the disclosure contained in Note 14 of Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for additional information on our agreements with Valero Energy.

The East and North Pipelines compete with an independent, regulated common carrier pipeline system owned by Magellan Midstream Partners, L.P. (Magellan), formerly the Williams Companies, Inc., 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 substantially 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 Iowa. 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 barges, nitrogen fertilizer substitutes and railroads represent other forms of direct competition to the pipeline under certain market conditions.

CRUDE OIL PIPELINES

Our crude oil pipeline operations consist primarily of the transportation of crude oil and other feedstocks, such as gas oil, from various points in Texas, Oklahoma, Kansas and Colorado to Valero Energy’s McKee, Three Rivers and Ardmore refineries. Also included in this segment are our four crude oil storage facilities in Texas and Oklahoma that are located along the crude oil pipelines and in which crude oil may be stored and batched prior to shipment in the crude oil pipelines. With the exception of the crude oil storage tanks at Corpus Christi discussed below in “Crude Oil Storage Tanks,” we do not generate any separate revenue from these four crude oil storage facilities. The costs associated with the crude oil storage facilities are considered in establishing the tariffs charged for transporting crude oil from the crude oil storage facilities to the refineries.

As of December 31, 2007, we had an ownership interest in eleven crude oil pipelines with an aggregate length of 812 miles. We charge tariffs on a per barrel basis for transporting crude oil and other feedstocks in our crude oil pipelines.

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

The following table sets forth information about our crude oil storage facilities associated with the crude oil pipeline segment:

Principal Customers

The primary customer of our crude oil pipeline segment is Valero Energy, which accounted for $50.6 million, or 95.6% of the total revenues of the segment, for the year ended December 31, 2007.

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Competition and Business Considerations

Our crude oil pipelines are physically integrated with and principally serve refineries owned by Valero Energy. Additionally, we have entered into various agreements with Valero Energy governing the usage of these pipelines. As a result, we believe that we will not face significant competition for transportation services provided to those refineries owned by Valero Energy. Please read the disclosure contained in Note 14 of Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for additional information.

CRUDE OIL STORAGE TANKS

Our crude oil storage tanks operations consist primarily of storing and delivering crude oil to Valero Energy’s refineries in Benicia, Corpus Christi and Texas City.

At December 31, 2007, we owned 60 crude oil and intermediate feedstock storage tanks and related assets with aggregate storage capacity of approximately 12.5 million barrels. The land underlying these tanks is subject to long-term operating leases. We charge a fee for each barrel of crude oil and certain other feedstocks that we deliver to Valero Energy’s Benicia, Corpus Christi West and Texas City refineries.

The following table sets forth information about our crude oil storage tanks:

Principal Customers

For the year ended December 31, 2007, Valero Energy accounted for 100% of the crude oil storage tanks segment revenues.

Competition and Business Considerations

Our crude oil storage tanks are physically integrated with and principally 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 owned by Valero Energy. Please read the disclosure contained in Note 14 of Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for additional information.

MARKETING

Our marketing segment operations consist primarily of purchasing petroleum products for resale to third parties. As part of its operations, our marketing segment may utilize storage space in certain of our refined products terminals and terminals operated by third parties. The marketing segment may also obtain transportation services from our refined products pipelines segment and other third party providers. Generally, the storage and throughput rates charged by our refined products terminals segment to the marketing segment are consistent with rates charged to third parties. Because our refined products pipelines are common carrier pipelines, the tariffs charged to the marketing segment from the refined products pipeline segment are based upon the published tariff applicable to all shippers.

We primarily market the following products:

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The operations of the marketing segment are meant to provide us the opportunity to generate additional margin while complementing the activities of our refined products terminals and refined product pipelines segments. Specifically, sales of bunker fuel occur 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. Additionally, we purchase gasoline, distillates, refinery feedstocks and asphalt to take advantage of arbitrage opportunities. Such opportunities can arise during contango markets (when the price for future deliveries exceeds current prices) or from geographic differences. 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.

Since the operations of our marketing segment expose us to commodity price risk, we enter into derivative instruments to mitigate the effect of commodity price fluctuations. We record the fair value of our derivative instruments in our consolidated balance sheet, with the change in fair value recorded in earnings. The derivative instruments we use consist primarily of futures contracts and swaps traded on the NYMEX for the purposes of hedging the outright price risk of our physical inventory. However, not all of our derivative instruments qualify for hedge accounting treatment under United States generally accepted accounting principles. In such cases, changes in the fair values of the derivative instrument, which are included in cost of product sales, generally are offset, at least partially, by changes in the values of the hedged physical inventory. However, the market fluctuations in inventory are not recognized until the physical sale takes place, unless the market price of inventory falls below our cost. In such as circumstance, we reduce the value of our inventory to market immediately. Therefore, our results for a period may include the gain or loss related to the derivative instrument without including the offsetting effect of the hedged physical inventory, which could result in greater earnings volatility.

On a limited basis, we also enter into derivative commodity instruments based on our analysis of market conditions in order to profit from market fluctuations. These derivative instruments are financial positions entered into without underlying physical inventory and are not considered hedges. We record the mark-to-market adjustments resulting from these derivatives in revenues.

Competition and Business Considerations

In the sale of bunker fuel, we compete with ports offering bunker fuels to which, or from which, each vessel travels or 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, Puerto Rico, the Bahamas, Aruba, Curacao and Halifax, Nova Scotia.

 EMPLOYEES

Our operations are managed by the general partner of our general partner, NuStar GP, LLC. As of December 31, 2007, NuStar GP, LLC had 1,104 employees performing services for our U.S. operations. Certain of our wholly owned subsidiaries had 332 employees performing services for our international operations. We believe that NuStar GP, LLC and our subsidiaries each have satisfactory relationships with their employees.

 RATE REGULATION

Several of our petroleum pipelines are interstate common carrier pipelines, which are subject to regulation by the FERC under the 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 to be maintained on file with the FERC that set forth the rates it charges for providing transportation services on its interstate common carrier liquids pipelines as well as the rules and regulations governing these services. The EP Act deemed certain rates in effect prior to its passage to be just, 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.

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Our interstate anhydrous 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 our ammonia pipeline and generally require that our rates and practices be just, 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 also challenge our intrastate tariff rates and practices on our pipelines.

Neither the FERC nor the state commissions have investigated our rates or practices, and none of those rates are currently subject to challenge or complaint. We do not currently believe that it is likely that there will be a challenge to the tariffs on our petroleum products or crude oil pipelines by a current shipper that would materially affect our revenues or cash flows. In addition, Valero Energy is a significant shipper on many of our pipelines. Valero Energy has committed to refrain from challenging several of our petroleum products and crude oil tariffs until at least April 2008. Valero Energy has also agreed to be responsible for certain ICA liabilities with respect to activities or conduct occurring during periods prior to April 16, 2001. However, the FERC, the STB or a state regulatory commission could investigate our tariffs on their own motion or at the urging of 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.

 ENVIRONMENTAL AND SAFETY REGULATION

Our operations are subject to extensive federal, state and local environmental laws and regulations, including those relating to the discharge of materials into the environment, waste management and pollution prevention measures. 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, 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.

WATER

The Federal Water Pollution Control Act of 1972, as amended, also known as the Clean Water Act, and analogous or more stringent state statutes impose restrictions and strict controls regarding the discharge of pollutants into state waters or waters of the United States. The discharge of pollutants into state waters or waters of the United States is prohibited, except in accordance with the terms of a permit issued by applicable federal or state authorities. The Oil Pollution Act, enacted in 1990, amends provisions of the Clean Water Act as they pertain to prevention 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.

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AIR EMISSIONS

Our operations are subject to the Federal Clean Air Act, as amended, and analogous or more stringent state and local statutes. The Clean Air Act Amendments of 1990, along with more restrictive interpretations of the Clean Air Act, may result in the imposition over the next several years of certain pollution control requirements with respect to air emissions from the operations of our pipelines, storage tanks and terminals. The Environmental Protection Agency (EPA) has been developing, over a period of many years, regulations to implement these requirements, including the revisions to the fuel content requirement under Section 211 of the Clean Air Act tightening diesel fuel specifications and effectively eliminating the use of MTBE in gasoline. These revisions, as well as any new EPA regulations or requirements that may be imposed by state and local regulatory authorities, may require us or our customers to incur further capital expenditures over the next several years for air pollution control equipment in connection with maintaining or obtaining operating permits and approvals and addressing other air emission-related issues. Until such time as the new Clean Air Act requirements are completely implemented, we are unable to estimate the effect on our financial condition or results of operations or the amount and timing of such required expenditures. At this time, however, we do not believe that we will be materially affected by any such requirements.

The Kyoto Protocol to the United Nations Framework Convention on Climate Change became effective February 2005. Under the Protocol, participating nations are required to implement programs to reduce emissions of certain gases, generally referred to as greenhouse gases, which are suspected of contributing to global warming. The United States is not currently a participant in the Protocol. In November 2007, the Senate Subcommittee on Private Sector and Consumer Solutions to Global Warming and Wildlife Protection approved SB 2191, America’s Climate and Security Act of 2007, which would require companies to scale back certain emissions to 2005 levels by 2012 and to 1990 levels by 2020. SB 2191 is currently before the Senate Environment and Public Works Committee. The state of California adopted the California Global Warming Solutions Act of 2006, which requires a 25% reduction in greenhouse gas emissions by 2020. This legislation requires the California Air Resources Board to adopt regulations by 2012 that limit emissions until an overall reduction of 25% from all omission sources in California is achieved by 2020. Recently, the California Air Resources Board announced its intention to have a proposed draft of its 1990 baseline and mandatory reporting regulation by mid 2008 and commence mandatory reporting of Green House Gas emissions by mid-2009. The state of New Mexico and states that are a part of the Western Climate Initiative are proposing similar regulations. New Jersey, has adopted legislation addressing greenhouse gas emissions from various sources, primarily power plants. The oil and natural gas industry is a direct source of greenhouse gas emissions, namely carbon dioxide and methane, and future restrictions on such emissions could have an impact on our future operations. It is not possible, at this time to estimate accurately how regulations to be adopted by the California Air Resources Board in 2012 or that may be adopted by other states to address greenhouse gas emissions would affect our business.

SOLID WASTE

We generate non-hazardous and minimal quantities of hazardous solid wastes that are subject to the requirements of the federal Resource Conservation and Recovery Act (RCRA) and analogous or more stringent state statutes. We are not currently required to comply with a substantial portion of RCRA requirements because 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.

HAZARDOUS SUBSTANCES

The Comprehensive Environmental Response, Compensation and Liability Act, referred to as CERCLA and also known as Superfund, and analogous or more stringent state laws, imposes 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.”

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We currently own or lease, and have in the past owned or leased, properties where hydrocarbons are being or have been handled. Although 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, many of these properties have been operated by third parties whose 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 of subsurface contamination is in process at many of our pipeline and terminal sites. Based on current investigative and remedial activities, we believe that the cost of these activities will not materially affect our financial condition or results of operations. Such costs, however, are often unpredictable and, therefore, there can be no assurances that the future costs will not become material.

PIPELINE INTEGRITY AND SAFETY

Our pipelines are subject to extensive federal and state laws and regulations governing pipeline integrity and safety. 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 and will not have a material effect on our financial condition or results of operations.

 RISK FACTORS

RISKS RELATED TO OUR BUSINESS

We may not be able to generate sufficient cash from operations to enable us to pay distributions at current levels to our unitholders every quarter.

The amount of cash that we can distribute to our unitholders each quarter principally depends upon the amount of cash we generate from our operations, which will fluctuate from quarter to quarter based on, among other things:

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

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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 could result in a significant reduction in throughputs in our crude oil and refined product pipelines and therefore in our cash flow, reducing our ability to make distributions to our unitholders. Factors that could lead to a decrease in market demand include:

A decline in production at the Valero Energy refineries we serve or the Tesoro Mandan refinery could materially reduce the volume of crude oil and refined petroleum products we transport or store in our assets.

A decline in production at the Valero Energy refineries we serve, or at the Tesoro Mandan refinery, could materially reduce the volume of crude oil and refined petroleum products we transport on our pipelines that are connected to these refineries or the volumes we store in related terminals. As a result, our financial position and results of operations and our ability to make distributions to our partners could be adversely affected. The Valero Energy refineries served by our assets or the Tesoro Mandan refinery could partially or completely shut down their operations, temporarily or permanently, due to factors affecting their ability to produce refined petroleum products such as:

We depend on Valero Energy for a significant portion of our revenues and throughputs of crude oil and refined products. Any reduction in the crude oil and refined products that we transport or store for Valero Energy, as a result of scheduled or unscheduled refinery maintenance, upgrades or shutdowns or otherwise, could result in a decline in our revenues, earnings and cash available to pay distributions.

We continue to rely on Valero Energy for a significant portion of our revenues. For the year ended December 31, 2007, Valero Energy accounted for approximately 18% of our revenues. While some of our relationships with Valero Energy are subject to long-term contracts, we may be unable to negotiate extensions or replacements of these contracts on favorable terms, if at all. For example, the Pipelines and Terminals Usage Agreement with respect to the crude oil processed and the refined products produced at Valero Energy’s Ardmore, McKee and Three Rivers refineries will expire on April 16, 2008, and Valero Energy may elect not to renew such agreement or only agree to renew it at substantially less favorable terms.

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Additionally, if Valero Energy elects not to renew certain of these contracts, it will no longer be precluded from challenging our tariffs covered by these contracts. Should Valero Energy successfully challenge some or all of such tariffs, we may be required to reduce these tariffs, which could adversely affect our cash flow and therefore our ability to make distributions.

Because of the geographic location of certain of our pipelines, terminals and storage facilities, we depend largely upon Valero Energy to provide throughput for some of our assets. Any decrease in throughputs would cause our revenues to decline and adversely affect our ability to make cash distributions to our unitholders. A decrease in throughputs could result from a temporary or permanent decline in the amount of crude oil transported to and stored at or refined products stored at and transported from the refineries we serve. Factors that could result in such a decline include:

Unless we were able to find customers with comparable volumes, the loss of all or even a portion of the volumes of crude oil and refined petroleum products supplied by Valero Energy would have a material adverse effect on our business, results of operations and financial condition and our ability to make cash distributions.

Under the Pipelines and Terminals Usage Agreement, which expires April 2008, Valero Energy may use other transportation methods or providers for up to 25% of the crude oil processed and refined products produced at the Ardmore, McKee and Three Rivers refineries. Furthermore, Valero Energy is not required to use our pipelines if there is a change in market conditions that has a material adverse effect on Valero Energy for the transportation of crude oil and refined products, or in the markets for refined products served by these refineries. These factors could adversely affect our ability to make distributions to our unitholders.

The Pipelines and Terminals Usage Agreement expires on April 16, 2008, and Valero Energy may elect not to renew such agreement or only agree to renew it at substantially less favorable terms. If market conditions with respect to the transportation of crude oil or refined products or with respect to the end markets in which Valero Energy sells refined products change in a material manner such that Valero Energy would suffer a material adverse effect if it were to continue to use our pipelines and terminals at the required levels, Valero Energy’s obligation to us will be suspended during the period of the change in market conditions to the extent required to avoid the material adverse effect. Any suspension of Valero Energy’s obligation could adversely affect throughputs in our pipelines and terminals and therefore our ability to make distributions to our unitholders.

Our future financial and operating flexibility may be adversely affected by restrictions in our debt agreements and by our leverage.

As of December 31, 2007, our consolidated debt was approximately $1.4 billion. Among other things, this amount of debt may be viewed negatively by credit rating agencies, which could result in increased costs for us to access the capital markets. NuStar Logistics and KPOP have senior unsecured ratings of Baa3 with Moody’s Investor Service and BBB minus with Standard & Poors and Fitch, all with a negative outlook. The negative outlook was assigned by the credit rating agencies as a result of our announced acquisition of CITGO Asphalt Refining Company’s asphalt operations and assets (East Coast Asphalt Operations). Any future downgrade of the debt held by these wholly owned subsidiaries could significantly increase our capital costs or adversely affect our ability to raise capital in the future.

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 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.

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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, 2007, we had approximately $1.4 billion of consolidated debt, of which $0.7 billion was at fixed interest rates and $0.7 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 may not be able to integrate effectively and efficiently with any 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 cannot assure unitholders that we will 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 unitholders 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.

Our pending acquisition of the East Coast Asphalt Operations may not be successful and we may not realize the anticipated benefits from this acquisition.

We may be unable to consummate the acquisition of the East Coast Asphalt Operations. Customary conditions to closing may not be satisfied, or the parties may agree to terminate the agreement and, as a result, we may not be able to consummate the transaction without a material adjustment to its proposed terms or at all, which may have an adverse effect on the trading price of our units. Even if all conditions to the consummation of the acquisition are satisfied, our acquisition of the East Coast Asphalt Operations may pose risks to our business. In addition to the risks ordinarily associated with an acquisition, we will also be exposed to risks specific to the East Coast Asphalt Operations, such as:

Accordingly, we may not be able to realize strategic, operational and financial benefits as a result of the East Coast Asphalt Operations acquisition, which could adversely affect our operating and financial results.

In addition, we will face certain challenges as we work to integrate the asphalt operations into our business. In particular, the acquisition of the East Coast Asphalt Operations will, by adding two refineries, expand our operations and the types of businesses in which we engage, significantly expanding our geographic scope and increasing the number of our employees, thereby presenting us with significant challenges as we work to manage the increase in scale resulting from the acquisition. We must integrate a large number of systems, both operational and administrative, which we have not historically used in our operations. Delays in this process could have a material adverse effect on our revenues, expenses, operating results and financial condition. In addition, events outside of our control, including changes in state and federal regulation and laws as well as economic trends, also could adversely affect our ability to realize the anticipated benefits from the acquisition of the East Coast Asphalt Operations.

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Further, the asphalt operations may not perform in accordance with our expectations, we may lose customers or key employees, and our expectations with regards to integration and synergies may not be fully realized. Our failure to successfully integrate and operate the asphalt refineries, and to realize the anticipated benefits of the acquisition, could adversely affect our operating and financial results.

The East Coast Asphalt Operations are dependent upon a steady supply of crude oil from PDVSA, the national oil company of Venezuela, and the Venezuelan economic and political environment may disrupt our supply of Venezuelan crude oil.

The terms of the acquisition of the East Coast Asphalt Operations include commitments, over a minimum seven-year period, to purchase from PDVSA an annual average of 75,000 barrels per day of crude oil and provide us with a right of first offer to purchase up to 4,000,000 barrels of paving grade asphalt and 4,750,000 barrels of roofing flux asphalt each year for marketing and sale.

Venezuela has been experiencing political, economic and social turmoil, including labor strikes and demonstrations. Such instability could severely affect or halt PDVSA’s production or delivery of crude oil or asphalt. For example, in January 2008, Venezuela’s president ordered the halt of asphalt exports to the U.S. and threatened to nationalize companies that monopolize asphalt production in the country. Further, we may 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 on pricing and credit terms that are less favorable than we would have obtained under the PDVSA crude oil supply contract. The pricing terms of our crude oil supply contract with PDVSA will be designed to provide a measure of stability to our refining margins. If we are required to make purchases on the spot market instead of under our contract we will lose this protection. As a result, if we experience disruption to our purchases of crude oil under the PDVSA crude oil supply contract, we could experience additional volatility in our earnings and cash flow.

Additionally, the Paulsboro refinery and the Savannah refinery are optimized to process specific types of crude oil that are only produced in Venezuela. Processing alternate crudes would result in reduced refinery run rates, significantly reduced production, and additional capital expenditures, which could be material. Accordingly, any disruption of our supply of crude oil from Venezuela would result in substantially lower revenues and additional volatility in our earnings and cash flow.

A significant interruption or casualty loss at one of the refineries included in the East Coast Asphalt Operations could reduce our production, particularly if not fully covered by our insurance.

Upon closing the pending acquisition of the East Coast Asphalt Operations, our business will include owning and operating refineries. As a result, our operations could be subject to significant interruption if one of our refineries were to experience a major accident or fire, be damaged by severe weather or other natural disaster, or otherwise be forced to shut down. These hazards could result in substantial losses due to personal injury and/or loss of life, severe damage to and destruction of property and equipment and pollution or other environmental damage and may result in curtailment or suspension of our related operations. We also face risks of mechanical failure and equipment shutdowns. If any of these situations occur, undamaged refinery processing units may be dependent on or interact with damaged sections of our refineries and, accordingly, are also subject to being shut down. In the event any of our refining facilities are forced to shut down for a significant period of time, it would have a material adverse effect on our earnings, our other results of operations and our financial condition as a whole.

We carry property and casualty insurance policies which contain limits, terms, conditions, exclusions and deductibles that will impact the amount of any recovery from a loss. As a result of market conditions, premiums and deductibles for certain insurance policies could increase. In some instances, certain insurance could become unavailable or available only for reduced amounts of coverage. If we were to incur a significant liability for which we were not fully insured, it could diminish our ability to make distributions to unitholders.

The price volatility of hydrocarbon products and by-products can reduce our results of operations and ability to make distributions to our unitholders.

Expected revenues from the acquisition of the East Coast Asphalt Operations will be mostly generated by the refining of crude oil into asphalt products and other products and the marketing thereof. The price and market value of hydrocarbon

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products and by-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.

The operating results for the asphalt we will produce and sell, following the closing of the acquisition of the East Coast Asphalt Operations, will be seasonal and generally lower in the first and fourth quarters of the year.

The operating results and selling prices of asphalt products we will produce can be 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 may be lower than those for the second and third calendar quarters of each year as a result of this seasonality. As a result, our results and ability to make distributions to our unitholders may be adversely affected during periods with seasonally lower operating results.

Following our acquisition of the East Coast Asphalt Operations, 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.

The specialty asphalt products produced at the refineries of the East Coast Asphalt Operations provide precise performance attributes to our customers’ products. 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 and reduce our ability to make distributions to unitholders.

We may incur liabilities from the refining assets we acquire in the acquisition of the East Coast Asphalt Operations. These costs and liabilities may not be covered by indemnification rights we will have against the seller of the assets.

Some of the assets included in the East Coast Asphalt Operations have been used for many years to refine and store asphalt products. Releases may have occurred prior to our acquisition that require remediation. In addition, releases may have occurred in the past that have not yet been discovered, which 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 the seller is not available, it could adversely affect our financial position and results of operations.

The obligations of several of the East Coast Asphalt Operations’ key customers under their terminalling services agreements, as evidenced through “Key Customer” supply contracts, may be reduced or suspended in some circumstances, which would adversely affect our financial condition and results of operations.

The East Coast Asphalt Operations’ outstanding agreements with several of its significant customers provide that, if any of a number of events occur, which are referred to as events of force majeure, and the event renders performance impossible with respect to a facility, usually for a specified minimum period of days, the customer’s obligations would be temporarily suspended with respect to that facility. In that case, a significant customer’s minimum revenue commitment may be reduced or the contract may be subject to termination. As a result, our revenues and results of operations could be materially adversely affected.

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.

The East Coast 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 business may expose us to trading losses and hedging losses, and non-compliance with our risk management policies and could result in significant financial losses.

Our marketing and trading business for the purchase and sale of crude oil and petroleum products, including gasoline, distillates, fuel oil and asphalt may expose us to price volatility risk 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 our 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.

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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.

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 strict environmental and safety laws and regulations. The transportation and storage of petroleum and other products, such as specialty liquids, produces a risk that these products may be suddenly released into the environment, potentially causing substantial expenditures for a response action, significant government penalties, liability to government agencies for natural resources damages, 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 12 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 Federal Energy Regulatory Commission (FERC) under the Interstate Commerce Act (ICA).

Under the ICA, common carrier pipelines must maintain tariffs on file with the FERC. These tariffs include the rates we charge for providing transportation services on our common carrier pipelines as well as the rules and regulations governing these services. The ICA requires, among other things, that such rates on interstate common carrier pipelines be “just and reasonable” and nondiscriminatory. The ICA permits interested persons to challenge newly proposed or changed rates and authorizes the FERC to suspend the effectiveness of such rates for a period of up to seven months and to investigate such rates. If, upon completion of an investigation, the FERC finds that the new or changed rate is unlawful, it is authorized to require the carrier to refund the revenues in excess of the prior tariff collected during the pendency of the investigation. The FERC may also investigate, upon complaint or on its own motion, rates that are already in effect and may order a carrier to change its rates prospectively. Upon an appropriate showing, 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. In 2003, the FERC made a significant positive adjustment to the index that oil pipelines use to adjust their regulated tariffs for inflation. The former index used percent growth in the producer price index for finished goods, and then subtracted one percent. The index adjustment in 2003 eliminated the one percent reduction. Pursuant to a subsequent review of the index by the FERC in 2005, the index is now measured by the producer price index for finished goods plus 1.3%, and it will apply for five years, commencing July 1, 2006. 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. As a result of the 2003 index adjustment, we filed for indexed rate adjustments on a number of our pipelines and realized benefits from the new index. However, if the index results in a negative adjustment, we will typically be 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. The FERC’s authorized rate-making methodologies may also delay the use or implementation of rates that reflect increased 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.

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Our pipeline operations are subject to FERC rate-making principles that 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 the new 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. The new tax allowance policy and the FERC’s application of that policy were appealed to the U.S. 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. 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. If the FERC were to disallow a substantial portion of our income tax allowance, it is possible that the maximum rates that could be charged could decrease from current levels.

The rates that we may charge on our interstate pipelines are subject to regulation by the Surface Board of Transportation.

The Surface Transportation Board (STB), a part of the U.S. Department of Transportation, has jurisdiction over interstate pipeline transportation and rate regulations of 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 need to 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.

Some shipments on our pipeline system move within a single state and thus are considered to be intrastate commerce.

Shipments on our pipeline system are subject to regulation with respect to intrastate transportation by state regulatory authorities in the states of Colorado, Kansas, Louisiana, North Dakota and Texas.

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. Power costs represented approximately 10.9% of our operating expenses for the year ended December 31, 2007. We use mainly electric power at our pipeline pump stations and terminals and such electric power is furnished by various utility companies that use primarily natural gas to generate electricity. Accordingly, our power costs typically fluctuate with natural gas prices. Increases in natural gas prices may cause our power costs to increase further. If natural gas prices remain high or increase further, our cash flows may be adversely affected, which could adversely affect our ability to make distributions to our unitholders.

Our exposure to a diversified national and international geographic asset and product mix may have an adverse impact on our results of operations.

Our business is geographically diversified both in the United States and internationally, which exposes us to supply and demand risks in different markets. A significant overall decrease in supply or demand for refined petroleum products or anhydrous ammonia may have an adverse effect on our financial condition. Further, we have significant international terminalling operations, which expose us to risks particular to such operations. A significant decrease in supply or demand at our main international terminals in Point Tupper, Nova Scotia or St. Eustatius, Netherlands Antilles, as well as foreign currency risks and other risks associated with operations in foreign legal and political environments, could have an adverse impact on our financial results.

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Our pipeline integrity program may subject us to significant costs and liabilities.

As a result of pipeline integrity testing under the Pipeline Safety Improvement Act of 2002, we may incur significant and unanticipated operating and capital expenditures for repairs or upgrades deemed necessary to ensure the continued safe and reliable operation of our pipelines. Further, the Act or an increase in public expectations for pipeline safety may require additional reporting, the replacement of our pipeline segments, additional monitoring equipment and more frequent inspection or testing of our pipeline facilities. Any repair, remediation, preventative or mitigating actions may require significant capital and operating expenditures. Should we fail to comply with the U.S. Department of Transportation rules and related regulations and orders, we could be subject to penalties and fines, which could have a material adverse effect on our ability to make distributions to our unitholders.

Our operations are subject to operational hazards and unforeseen interruptions for which we may not be adequately insured.

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. We may not be able to maintain 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.

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.

The long-term impact of terrorist attacks, such as the attacks that occurred on September 11, 2001, and the threat of future terrorist attacks on the energy transportation industry in general, and on us in particular, is not known at this time. Increased security measures we have taken as a precaution against possible terrorist attacks have resulted in increased costs to our business. Uncertainty surrounding continued hostilities in the Middle East or other sustained military campaigns may affect our operations in unpredictable ways, including disruptions of crude oil supplies and markets for refined products, the possibility that infrastructure facilities could be direct targets of, or indirect casualties of, an act of terror and instability in the financial markets that could restrict our ability to raise capital.

Our cash distribution policy may limit our growth.

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

We may sell additional limited partnership units, diluting existing interests of our unitholders.

Our partnership agreement allows us to issue additional limited partnership units and certain other equity securities without unitholder approval. When we issue additional limited partnership units or other equity securities, the proportionate partnership interest of our existing unitholders will decrease. The issuance could negatively affect the amount of cash distributed to unitholders and the market price of the limited partnership units. Issuance of additional units will also diminish the relative voting strength of the previously outstanding units.

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 an aggregate 20.3% limited partner interest in us and owns NuStar Energy’s general partner. Conflicts of interest may arise between NuStar GP Holdings and its affiliates, including NuStar Energy’s general partner, on the one hand, and NuStar Energy and its limited partners, on the other hand. As a

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result of these conflicts, the general partner may favor its own interests and the interests of its affiliates over the interests of the 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.

TAX RISKS TO OUR UNITHOLDERS

If we were treated as a corporation for federal or state income tax purposes, then our cash available for distribution to unitholders would be substantially reduced.

The anticipated after-tax benefit of an investment in our units depends largely on our being treated as a partnership for federal income tax purposes. We have not requested, and do not plan to request, a ruling from the IRS on this matter.

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

Current law may change, causing us to be treated as a corporation for federal income tax purposes or otherwise subjecting us to entity-level taxation. In addition, because of widespread state budget deficits, several states are evaluating ways to subject partnerships to entity level taxation through the imposition of state income, franchise or other forms of taxation. For example, the State of New Jersey imposes a state level tax which we currently pay at the maximum amount of $250,000. Partnerships and limited liability companies, unless specifically exempted, are also subject to a state-level tax imposed on Texas source revenues. Specifically, the Texas margin tax is imposed at a maximum effective tax rate of 0.7% of our gross revenue or 1% of our gross margin that is apportioned to Texas. Imposition of any entity-level tax on us by Texas, or additional states, 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.

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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 12-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-U.S. 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. persons will be reduced by withholding taxes at the highest applicable effective tax rate, and non-U.S. persons will be required to file U.S. 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.

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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.

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

 PROPERTIES

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

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None.

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 indemnify us against liabilities arising from future legal proceedings as a result of our ordinary business activity. We believe that, should we be unable to successfully defend ourselves in any of these matters, the ultimate payment of any or all of the amounts reserved would not have a material adverse effect on our financial position or liquidity. However, if any actual losses exceed the amounts accrued, there could be a material adverse effect on our results of operations.

GRACE ENERGY CORPORATION MATTER

In 1997, Grace Energy Corporation (Grace Energy) sued subsidiaries of Kaneb in Texas state court. 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 (Otis AFB) in Massachusetts. 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 trial court’s final judgment 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. Once that stay is lifted, we intend to resume vigorous prosecution of the appeal.

The Otis AFB is a part of a Superfund Site pursuant to CERCLA. The site contains a number of groundwater contamination plumes, two of which are allegedly associated with the Otis AFB pipeline. Relying on the Texas state court’s final judgment assigning ownership of the Otis AFB pipeline to Kaneb, the U.S. Department of Justice advised Kaneb in 2001 that it intends to seek reimbursement from Kaneb for the remediation costs associated with the two spill areas. In 2002, the Department of Justice asserted that it had incurred over $49.0 million in costs and expected to incur additional costs of approximately $19.0 million for remediation of the two spill areas. The Department of Justice has not filed a lawsuit against us related to this matter and we have not made any payments toward costs incurred by the Department of Justice.

PORT OF VANCOUVER MATTER

We own a chemical and refined product terminal on property owned by the Port of Vancouver, and we lease the land under the terminal from the Port of Vancouver. Under an Agreed Order entered into with the Washington Department of Ecology when Kaneb purchased the terminal in 1998, Kaneb agreed to investigate and remediate groundwater contamination by the terminal’s previous owner and operator originating from the terminal. Investigation and remediation at the terminal are ongoing in compliance with the Agreed Order. In April 2006, the Washington Department of Ecology commented on our site investigation work plan and asserted that the groundwater contamination at the terminal was commingled with a groundwater contamination plume under other property owned by the Port of Vancouver. Since that time, we have negotiated with the Washington Department of Ecology, and on November 7, 2007, we entered into an Agreed Order that outlines a plan for site assessment, monitoring and interim action with regard to the plume for which Kaneb is responsible. The Agreed Order contains a diagram indicating that the plume for which Kaneb is responsible is separate from proximately located plumes. Based on the Agreed Order, and the fact that there is no currently pending claim asserting that Kaneb is responsible for the second plume, we believe at this time that this issue is resolved.

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ENVIRONMENTAL AND SAFETY COMPLIANCE MATTERS

With respect to the environmental proceedings listed below, if any one or more of them were 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 these proceedings or whether such ultimate outcome may have a material effect of our consolidated financial position. We report these proceedings 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, the Illinois State Attorney General’s Office has proposed penalties totaling $133,000 related to a pipeline leak at a storage terminal in Chillicothe, Illinois that we owned through a joint venture with Center Oil Company until we sold our interest in October 2006. The Pipeline and Hazardous Materials Safety Agency has proposed penalties totaling $255,000 based on alleged violations of various pipeline safety requirements in the McKee System. We are currently in settlement negotiations with these government agencies to resolve these matters.

On November 14, 2006, agents of the U.S. Environmental Protection Agency (the EPA) presented a search warrant issued by a U.S. District Court at one of our California terminals. Since then, the U.S. District Court has also served us with five subpoenas. The search warrant and subpoenas all seek information regarding allegations of potential illegal conduct by us, certain of our subsidiaries and/or our employees concerning compliance with certain environmental and safety laws and regulations. We are cooperating fully with the EPA in producing documents in response to the subpoenas. We have no information as to when the EPA will conclude their investigation, and we are also conducting an internal investigation of any possible noncompliance. At this time, the EPA has not suggested any fines or penalties. There can be no assurances that the conclusion of the EPA’s investigation will not result in a determination that we violated applicable laws. If we are found to have violated such laws, we could be subject to fines, civil penalties and criminal penalties. A final determination that we violated applicable laws could, among other things, result in our debarment from future federal government contracts. Because of the preliminary nature of the investigation, we are not able to estimate a loss or range of loss, if any. However, if any of the consequences described above ultimately occur, it is reasonably possible that the effects could be material to our results of operations in the period we would be required to record a liability, and could be material to our cash flows in the periods we would be required to pay such liability.

In a letter dated February 6, 2008, the Department of Justice (the DOJ) advised us that Region VII of the EPA has requested that the DOJ initiate a lawsuit against Kaneb Pipe Line Operating Partnership, L.P. (KPOP) for violations of the Clean Water Act. The notice alleges that KPOP violated the Clean Water Act by failing to prepare a Facility Response Plan, as required by Section 311(j)(5) of the Clean Water Act, 33 U.S.C. §1321(j), for certain of its pipeline terminals located in Region VII by August 30, 1994. 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 notice does not specify a penalty amount, but we reasonably believe that such proceeding may result in monetary sanctions of $100,000 or more.

We are also a party to additional claims and legal proceedings arising in the ordinary course of business. We believe the possibility is remote that the final outcome of any of the claims or proceedings to which we are a party would have a material adverse effect on our financial position, results of operations or liquidity; however, 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.

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, 2007.

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 PART II

Market Information, Holders and Distributions

Our common units are listed and traded on the New York Stock Exchange under the symbol “NS.” At the close of business on February 7, 2008, we had 896 holders of record of our common units. The high and low sales prices (composite transactions) by quarter for the years ended December 31, 2007 and 2006 were as follows:

The cash distributions applicable to each of the quarters in the years ended December 31, 2007 and 2006 were as follows:

Prior to May 8, 2006, we had 9,599,322 subordinated units outstanding, all of which were held by our general partner, for which there was no established public trading market. The issuance of subordinated units was exempt from registration with the SEC under Section 4(2) of the Securities Act of 1933. Effective April 1, 2006, we satisfied all the conditions included in our partnership agreement for the subordination period to end. Accordingly, all 9,599,322 subordinated units converted into common units on a one-for-one basis on May 8, 2006, the first business day after the record date for the distribution related to the first quarter earnings of 2006.

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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, 2007 and 2006 totaled $18.4 million and $14.8 million, respectively. The general partner’s share of our distributions for the years ended December 31, 2007 and 2006 was 11.0% and 9.9%, respectively, due to the impact of the incentive distributions.

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