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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

x | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2007

OR

¨ | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission File Number 1-16417

NUSTAR ENERGY L.P.

(Exact name of registrant as specified in its charter)

Delaware |  | 74-2956831
(State or other jurisdiction of incorporation or organization) |  | (I.R.S. Employer Identification No.)

2330 North Loop 1604 West San Antonio, Texas |  | 78248
(Address of principal executive offices) |  | (Zip Code)

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.

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TABLE OF CONTENTS

|  |  |  | Page
|  | PART I |  |
Items 1., 1A. & 2. |  | Business, Risk Factors and Properties |  | 3
|  | Recent Developments |  | 4
|  | Acquisitions and Dispositions |  | 4
|  | Organizational Structure |  | 5
|  | Segments |  | 7
|  | Employees |  | 20
|  | Rate Regulation |  | 20
|  | Environmental and Safety Regulation |  | 21
|  | Risk Factors |  | 23
|  | Properties |  | 34
Item 1B. |  | Unresolved Staff Comments |  | 35
Item 3. |  | Legal Proceedings |  | 35
Item 4. |  | Submission of Matters to a Vote of Security Holders |  | 36
|  | PART II |  |
Item 5. |  | Market for Registrant’s Common Units, Related Unitholder Matters and Issuer Purchases of Common Units |  | 37
Item 6. |  | Selected Financial Data |  | 39
Item 7. |  | Management’s Discussion and Analysis of Financial Condition and Results of Operations |  | 40
Item 7A. |  | Quantitative and Qualitative Disclosures About Market Risk |  | 64
Item 8. |  | Financial Statements and Supplementary Data |  | 66
Item 9. |  | Changes in and Disagreements with Accountants on Accounting and Financial Disclosure |  | 117
Item 9A. |  | Controls and Procedures |  | 117
Item 9B. |  | Other Information |  | 117
|  | PART III |  |
Item 10. |  | Directors and Executive Officers of the Registrant |  | 118
Item 11. |  | Executive Compensation |  | 121
Item 12. |  | Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters |  | 154
Item 13. |  | Certain Relationships and Related Transactions and Director Independence |  | 156
Item 14. |  | Principal Accountant Fees and Services |  | 159
|  | PART IV |  |
Item 15. |  | Exhibits and Financial Statement Schedules |  | 161
Signatures |  |  |  | 170

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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.”

ITEMS 1., 1A. and 2. BUSINESS, | RISK FACTORS AND PROPERTIES

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:

| • |  | 61 refined product terminal facilities providing approximately 58.5 million barrels of storage capacity and one crude oil terminal facility providing approximately 3.4 million barrels of storage capacity;

| • |  | 8,251 miles of refined product pipelines, including 2,000 miles of anhydrous ammonia pipelines, with 21 associated terminals providing storage capacity of 4.6 million barrels and two tank farms providing storage capacity of 1.2 million barrels;

| • |  | 812 miles of crude oil pipelines with 11 associated storage tanks providing storage capacity of 1.7 million barrels; and

| • |  | 60 crude oil storage tanks providing storage capacity of 12.5 million barrels.

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:

| • |  | tariffs for transporting crude oil, refined products and anhydrous ammonia through our pipelines;

| • |  | fees for the use of our terminals and crude oil storage tanks and related ancillary services;

| • |  | sales of bunker fuel to marine vessels;

| • |  | sales of heavy fuels, asphalt and refined products to third parties; and

| • |  | the mark-to-market impact of our limited trading program.

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

| • |  | continuous improvement of our operations by improving safety and environmental stewardship, cost controls and asset reliability and integrity;

| • |  | internal growth through enhancing the utilization of our existing assets by expanding our business with current and new customers as well as investments in strategic expansion projects;

| • |  | external growth from acquisitions that meet our financial and strategic criteria; and

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| • |  | complementary operations such as our product marketing and trading organization, which we created to capitalize on opportunities to optimize the use and profitability of our assets.

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:

| • |  | 52 terminals in the United States, with a total storage capacity of approximately 34.9 million barrels;

| • |  | A terminal on the island of St. Eustatius, Netherlands Antilles with a tank capacity of 13.0 million barrels and a transshipment facility;

| • |  | A terminal located in Point Tupper, Nova Scotia with a tank capacity of 7.4 million barrels and a transshipment facility;

| • |  | Six terminals located in the United Kingdom and one terminal located in Amsterdam, the Netherlands, having a total storage capacity of approximately 6.6 million barrels; and

| • |  | A terminal located in Nuevo Laredo, Mexico.

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:

Facility |  | Tank Capacity |  | Number of Tanks |  | Primary Products Handled
Major U.S. Terminals: |  |  |  |  |  |
Piney Point, MD |  | 5,404,000 |  | 28 |  | Petroleum products, asphalt
Linden, NJ (a) |  | 4,055,000 |  | 24 |  | Petroleum products
St. James, LA |  | 3,357,000 |  | 17 |  | Crude oil and feedstocks
Selby, CA |  | 2,829,000 |  | 22 |  | Petroleum products, ethanol
Jacksonville, FL |  | 2,057,000 |  | 30 |  | Petroleum products, asphalt
Texas City, TX |  | 2,131,000 |  | 103 |  | Chemicals, petrochemicals, petroleum products
Other U.S. Terminals: |  |  |  |  |  |
Montgomery, AL |  | 162,000 |  | 7 |  | Petroleum products
Moundville, AL |  | 310,000 |  | 6 |  | Petroleum products
Tucson, AZ (b) |  | 85,000 |  | 4 |  | Petroleum products
Los Angeles, CA |  | 606,000 |  | 19 |  | Petroleum products
Pittsburg, CA |  | 361,000 |  | 10 |  | Asphalt
Stockton, CA |  | 803,000 |  | 33 |  | Petroleum products, ethanol, fertilizer
Colorado Springs, CO |  | 320,000 |  | 7 |  | Petroleum products, ethanol
Denver, CO |  | 110,000 |  | 9 |  | Petroleum products, ethanol
Bremen, GA |  | 178,000 |  | 8 |  | Petroleum products
Brunswick, GA |  | 160,000 |  | 2 |  | Fertilizer, pulp liquor
Macon, GA |  | 307,000 |  | 10 |  | Petroleum products
Savannah, GA |  | 857,000 |  | 21 |  | Petroleum products, caustic
Blue Island, IL |  | 729,000 |  | 15 |  | Petroleum products, ethanol
Indianapolis, IN |  | 412,000 |  | 18 |  | Petroleum products
Westwego, LA |  | 852,000 |  | 53 |  | Molasses, caustic, chemicals, lube oil, fertilizer
Andrews AFB, MD |  | 72,000 |  | 3 |  | Petroleum products
Baltimore, MD |  | 837,000 |  | 49 |  | Chemicals, asphalt
Salisbury, MD |  | 177,000 |  | 14 |  | Petroleum products
Reno, NV |  | 98,000 |  | 7 |  | Petroleum products
Linden, NJ |  | 439,000 |  | 9 |  | Petroleum products
Paulsboro, NJ |  | 69,000 |  | 9 |  | Petroleum products
Alamogordo, NM |  | 120,000 |  | 5 |  | Petroleum products
Albuquerque, NM |  | 245,000 |  | 10 |  | Petroleum products, ethanol
Rosario, NM |  | 160,000 |  | 8 |  | Asphalt
Catoosa, OK |  | 340,000 |  | 24 |  | Asphalt
Portland, OR |  | 1,197,000 |  | 31 |  | Petroleum products, ethanol
Abernathy, TX |  | 155,000 |  | 7 |  | Petroleum products
Amarillo, TX |  | 255,000 |  | 8 |  | Petroleum products
Corpus Christi, TX |  | 357,000 |  | 11 |  | Petroleum products

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Facility |  | Tank Capacity |  | Number of Tanks |  | Primary Products Handled
Edinburg, TX |  | 267,000 |  | 6 |  | Petroleum products
El Paso, TX (b) |  | 343,000 |  | 12 |  | Petroleum products
Harlingen, TX |  | 315,000 |  | 7 |  | Petroleum products
Houston, TX (Hobby Airport) |  | 106,000 |  | 4 |  | Petroleum products
Houston, TX |  | 90,000 |  | 6 |  | Asphalt
Laredo, TX |  | 320,000 |  | 7 |  | Petroleum products
Placedo, TX |  | 97,000 |  | 4 |  | Petroleum products
San Antonio (east), TX |  | 148,000 |  | 5 |  | Petroleum products
San Antonio (south), TX |  | 215,000 |  | 5 |  | Petroleum products
Southlake, TX |  | 285,000 |  | 5 |  | Petroleum products, ethanol
Texas City, TX |  | 146,000 |  | 12 |  | Petroleum products
Dumfries, VA |  | 548,000 |  | 14 |  | Petroleum products, asphalt
Virginia Beach, VA |  | 41,000 |  | 2 |  | Petroleum products
Tacoma, WA |  | 359,000 |  | 14 |  | Petroleum products, ethanol
Vancouver, WA |  | 301,000 |  | 14 |  | Chemicals
Vancouver, WA |  | 408,000 |  | 7 |  | Petroleum products
Milwaukee, WI |  | 308,000 |  | 7 |  | Petroleum products, ethanol
Total U.S. Terminals |  | 34,903,000 |  | 772 |  |
Foreign Terminals: |  |  |  |  |  |
St. Eustatius, Netherlands Antilles |  | 12,997,000 |  | 58 |  | Petroleum products, crude oil
Point Tupper, Canada |  | 7,376,000 |  | 37 |  | Petroleum products, crude oil
Grays, England |  | 1,945,000 |  | 53 |  | Petroleum products
Eastham, England |  | 2,185,000 |  | 162 |  | Chemicals, petroleum products, animal fats
Runcorn, England |  | 146,000 |  | 4 |  | Molten sulfur
Grangemouth, Scotland |  | 530,000 |  | 46 |  | Petroleum products, chemicals and molasses
Glasgow, Scotland |  | 344,000 |  | 16 |  | Petroleum products
Belfast, Northern Ireland |  | 407,000 |  | 41 |  | Petroleum products
Amsterdam, the Netherlands |  | 1,024,000 |  | 24 |  | Petroleum products
Nuevo Laredo, Mexico |  | 34,000 |  | 5 |  | Petroleum products
Total Foreign Terminals |  | 26,827,000 |  | 446 |  |

(a) | We own 50% of this terminal through a joint venture.

(b) | We own a 66.67% undivided interest in the El Paso refined product terminal and a 50% undivided interest in the Tucson refined product terminal. The tankage capacity and number of tanks represent the proportionate share of capacity attributable to our ownership interest.

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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| • |  | 26 refined product pipelines with an aggregate length of 3,911 miles that connect Valero Energy’s McKee, Three Rivers, Corpus Christi and Ardmore refineries to certain of NuStar Energy’s terminals, or to interconnections with third-party pipelines or terminals for further distribution, including a 25-mile crude hydrogen pipeline (collectively, the Central West System);

| • |  | a 1,900-mile refined product pipeline originating in southern Kansas and terminating at Jamestown, North Dakota, with a western extension to North Platte, Nebraska and an eastern extension into Iowa (the East Pipeline);

| • |  | a 440-mile refined product pipeline originating at Tesoro Corporation’s Mandan, North Dakota refinery (the Tesoro Mandan refinery) and terminating in Minneapolis, Minnesota (the North Pipeline); and

| • |  | a 2,000-mile anhydrous ammonia pipeline originating at the Louisiana delta area that travels north through the midwestern United States forking east and west to terminate in Nebraska and Indiana (the Ammonia Pipeline).

We charge tariffs on a per barrel basis for transporting refined products 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:

|  |  |  |  |  |  |  |  |  |  | Year Ended December 31, 2007 |
Origin and Destination |  | Valero Energy Refinery |  | Length |  | Ownership |  |  | Capacity |  | Throughput |  | Capacity Utilization |
|  |  |  | (Miles) |  |  |  |  | (Barrels/Day) |  | (Barrels/Day) |  |  |
McKee to El Paso, TX |  | McKee |  | 408 |  | 67 | % |  | 40,000 |  | 28,436 |  | 71 | %
McKee to Colorado Springs, CO (a) |  | McKee |  | 256 |  | 100 | % |  | 38,000 |  | 11,559 |  | 63 | %
Colorado Springs, CO to Airport |  | McKee |  | 2 |  | 100 | % |  | 14,000 |  | 1,018 |  | 7 | %
Colorado Springs to Denver, CO |  | McKee |  | 101 |  | 100 | % |  | 32,000 |  | 13,058 |  | 41 | %
McKee to Denver, CO |  | McKee |  | 321 |  | 30 | % |  | 9,870 |  | 7,760 |  | 79 | %
McKee to Amarillo, TX (6”) (a)(b) |  | McKee |  | 49 |  | 100 | % |  | 51,000 |  | 17,837 |  | 42 | %
McKee to Amarillo, TX (8”) (a)(b) |  | McKee |  | 49 |  | 100 | % |  |  |  |  |  |  |
Amarillo to Abernathy, TX (a) |  | McKee |  | 102 |  | 67 | % |  | 11,733 |  | 4,633 |  | 46 | %
Amarillo, TX to Albuquerque, NM |  | McKee |  | 293 |  | 50 | % |  | 17,150 |  | 5,823 |  | 34 | %
Abernathy to Lubbock, TX (a) |  | McKee |  | 19 |  | 46 | % |  | 8,029 |  | 790 |  | 10 | %
McKee to Skellytown, TX |  | McKee |  | 53 |  | 100 | % |  | 52,000 |  | 5,053 |  | 10 | %
Skellytown to Mont Belvieu,TX |  | McKee |  | 572 |  | 50 | % |  | 26,000 |  | 11,750 |  | 45 | %
McKee to Southlake, TX |  | McKee |  | 375 |  | 100 | % |  | 27,300 |  | 9,956 |  | 36 | %
Three Rivers to San Antonio, TX |  | Three Rivers |  | 81 |  | 100 | % |  | 33,600 |  | 29,574 |  | 88 | %
Three Rivers to US/Mexico International Border near Laredo, TX |  | Three Rivers |  | 108 |  | 100 | % |  | 32,000 |  | 25,232 |  | 79 | %
Corpus Christi to Three Rivers, TX |  | Corpus Christi |  | 68 |  | 100 | % |  | 32,000 |  | 7,060 |  | 22 | %
Three Rivers to Corpus Christi, TX |  | Three Rivers |  | 72 |  | 100 | % |  | 15,000 |  | 10,886 |  | 73 | %
Three Rivers to Pettus to San Antonio, TX |  | Three Rivers |  | 103 |  | 100 | % |  | 30,000 |  | 24,272 |  | 81 | %
Three Rivers to Pettus to Corpus Christi, TX (c) |  | Three Rivers |  | 87 |  | 100 | % |  | 15,000 |  | — |  | 0 | %
Ardmore to Wynnewood, OK (d) |  | Ardmore |  | 31 |  | 100 | % |  | 84,000 |  | 59,692 |  | 66 | %
El Paso, TX to Kinder Morgan |  | McKee |  | 12 |  | 67 | % |  | 64,000 |  | 22,696 |  | 35 | %

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|  |  |  |  |  |  |  |  |  |  | Year Ended December 31, 2007 |
Origin and Destination |  | Valero Energy Refinery |  | Length |  | Ownership |  |  | Capacity |  | Throughput |  | Capacity Utilization |
|  |  |  | (Miles) |  |  |  |  | (Barrels/Day) |  | (Barrels/Day) |  |  |
Corpus Christi to Pasadena, TX |  | Corpus Christi |  | 208 |  | 100 | % |  | 105,000 |  | 87,344 |  | 83 | %
Corpus Christi to Brownsville, TX |  | Corpus Christi |  | 194 |  | 100 | % |  | 45,000 |  | 40,289 |  | 90 | %
US/Mexico International Border near Penitas, TX to Edinburg, TX |  | N/A |  | 33 |  | 100 | % |  | 24,000 |  | 6,157 |  | 26 | %
Clear Lake, TX to Texas City, TX |  | N/A |  | 25 |  | 100 | % |  | N/A |  | N/A |  | N/A |
Other refined product pipeline (e) |  | N/A |  | 289 |  | 50 | % |  | N/A |  | N/A |  | N/A |
Total |  |  |  | 3,911 |  |  |  |  | 806,682 |  | 430,875 |  |  |

(a) | This pipeline transports barrels relating to two tariff routes. The first route begins at this pipeline’s origin and ends at this pipeline’s destination. The second route is a longer tariff route with an origin or destination on another pipeline of ours that connects to this pipeline. Throughput disclosed above for this pipeline reflects only the barrels subject to the tariff route beginning at this pipeline’s origin and ending at this pipeline’s destination. To accurately determine the actual capacity utilization of the pipeline, as well as aggregate capacity utilization, all barrels passing through the pipeline have been taken into account.

(b) | The throughput, capacity and capacity utilization information disclosed above for the McKee to Amarillo, Texas 6-inch pipeline reflects both McKee to Amarillo, Texas pipelines on a combined basis.

(c) | The refined product pipeline from Three Rivers to Pettus to Corpus Christi, Texas is temporarily idled. In the fourth quarter of 2005, an eight-mile portion of this pipeline was permanently idled. As a result, we recorded an impairment charge of $2.1 million included in “Other income (expense), net” in the consolidated statements of income for the year ended December 31, 2005.

(d) | Included in this segment are two refined product storage tanks with a total capacity of 180,000 barrels located at Wynnewood, Oklahoma. Refined products may be stored and batched prior to shipment into a third party pipeline.

(e) | This category consists of the temporarily idled 6-inch Amarillo, Texas to Albuquerque, New Mexico refined product pipeline.

East Pipeline. The East Pipeline covers 1,900 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:

Location of Terminals |  | Tank Capacity |  | Number of Tanks |  | Related Pipeline System
Iowa: |  |  |  |  |  |
LeMars |  | 103,000 |  | 8 |  | East
Milford |  | 172,000 |  | 11 |  | East
Rock Rapids |  | 223,000 |  | 5 |  | East
Kansas: |  |  |  |  |  |
Concordia |  | 79,000 |  | 6 |  | East
Hutchinson |  | 115,000 |  | 5 |  | East
Salina |  | 86,000 |  | 8 |  | East
Minnesota: |  |  |  |  |  |
Moorhead |  | 518,000 |  | 10 |  | North
Sauk Centre |  | 116,000 |  | 7 |  | North
Roseville |  | 479,000 |  | 10 |  | North
Nebraska: |  |  |  |  |  |
Columbus |  | 171,000 |  | 8 |  | East
Geneva |  | 674,000 |  | 37 |  | East
Norfolk |  | 182,000 |  | 15 |  | East
North Platte |  | 247,000 |  | 23 |  | East
Osceola |  | 79,000 |  | 7 |  | East
North Dakota: |  |  |  |  |  |
Jamestown (North) |  | 139,000 |  | 6 |  | North
Jamestown (East) |  | 176,000 |  | 11 |  | East
South Dakota: |  |  |  |  |  |
Aberdeen |  | 181,000 |  | 12 |  | East
Mitchell |  | 63,000 |  | 6 |  | East
Sioux Falls |  | 381,000 |  | 12 |  | East
Wolsey |  | 148,000 |  | 20 |  | East
Yankton |  | 245,000 |  | 25 |  | East
Total |  | 4,577,000 |  | 252 |  |

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:

|  |  |  |  |  |  |  |  |  |  | Year Ended December 31, 2007 |
Origin and Destination |  | Valero Energy Refinery |  | Length |  | Ownership |  |  | Capacity |  | Throughput |  | Capacity Utilization |
|  |  |  | (Miles) |  |  |  |  | (Barrels/Day) |  | (Barrels/Day) |  |  |
Cheyenne Wells, CO to McKee |  | McKee |  | 210 |  | 100 | % |  | 17,500 |  | 7,041 |  | 40 | %
Dixon, TX to McKee |  | McKee |  | 44 |  | 100 | % |  | 45,000 |  | 35,661 |  | 79 | %
Hooker, OK to Clawson, TX (a) |  | McKee |  | 41 |  | 50 | % |  | 22,000 |  | 13,038 |  | 59 | %
Clawson, TX to McKee (b) |  | McKee |  | 31 |  | 100 | % |  | 36,000 |  | 17,502 |  | 85 | %
Wichita Falls, TX to McKee |  | McKee |  | 272 |  | 100 | % |  | 110,000 |  | 48,454 |  | 44 | %
Corpus Christi, TX to Three Rivers |  | Three Rivers |  | 70 |  | 100 | % |  | 120,000 |  | 81,466 |  | 68 | %
Ringgold, TX to Wasson, OK (b) |  | Ardmore |  | 44 |  | 100 | % |  | 90,000 |  | 58,894 |  | 65 | %
Healdton to Ringling, OK |  | Ardmore |  | 4 |  | 100 | % |  | 52,000 |  | 2,521 |  | 5 | %
Wasson, OK to Ardmore (8”-10”) (c) |  | Ardmore |  | 24 |  | 100 | % |  | 90,000 |  | 48,975 |  | 54 | %
Wasson, OK to Ardmore (8”) |  | Ardmore |  | 15 |  | 100 | % |  | 40,000 |  | 32,624 |  | 82 | %
Patoka, IL to Wood River, IL |  | N/A |  | 57 |  | 23.8 | % |  | 60,600 |  | 31,464 |  | 52 | %
Total |  |  |  | 812 |  |  |  |  | 683,100 |  | 377,640 |  |  |

(a) | We receive 50% of the tariff with respect to 100% of the barrels transported in the Hooker, Oklahoma to Clawson, Texas pipeline. Accordingly, the capacity, throughput and capacity utilization are given with respect to 100% of the pipeline.

(b) | This pipeline transports barrels relating to two tariff routes. The first route begins at the pipeline’s origin and ends at its destination. The second route begins with an origin or destination on another of our connecting pipelines. Throughput disclosed above for this pipeline reflects only the barrels subject to the tariff route beginning at this pipeline’s origin and ending at this pipeline’s destination. To accurately determine the actual capacity utilization of the pipeline, as well as aggregate capacity utilization, all barrels passing through the pipeline have been taken into account.

(c) | The Wasson, Oklahoma to Ardmore (8”- 10”) pipelines referred to above originate at Wasson as two pipelines but merge into one pipeline prior to reaching Ardmore.

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

Location |  | Valero Energy Refinery |  | Capacity |  | Number of Tanks |  | Mode of Receipt |  | Mode of Delivery |  | Throughput Year Ended December 31, 2007
|  |  |  | (Barrels) |  |  |  |  |  |  |  | (Barrels/Day)
Dixon, TX |  | McKee |  | 240,000 |  | 3 |  | pipeline |  | pipeline |  | 35,661
Ringgold, TX |  | Ardmore |  | 600,000 |  | 2 |  | pipeline |  | pipeline |  | 58,894
Wichita Falls, TX |  | McKee |  | 660,000 |  | 4 |  | pipeline |  | pipeline |  | 48,454
Wasson, OK |  | Ardmore |  | 225,000 |  | 2 |  | pipeline |  | pipeline |  | 81,599
Total |  |  |  | 1,725,000 |  | 11 |  |  |  |  |  | 244,608

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:

Location |  | Valero Energy Refinery |  | Capacity |  | Number of Tanks |  | Mode of Receipt |  | Mode of Delivery |  | Throughput Year Ended December 31, 2007
|  |  |  | (Barrels) |  |  |  |  |  |  |  | (Barrels/Day)
Benicia, CA |  | Benicia |  | 3,815,000 |  | 16 |  | marine/pipeline |  | pipeline |  | 136,729
Corpus Christi, TX |  | Corpus Christi |  | 4,023,000 |  | 26 |  | marine |  | pipeline |  | 152,442
Texas City, TX |  | Texas City |  | 3,087,000 |  | 14 |  | marine |  | pipeline |  | 187,605
Corpus Christi, TX (North Beach) |  | Three Rivers |  | 1,600,000 |  | 4 |  | marine |  | pipeline |  | 72,247
Total |  |  |  | 12,525,000 |  | 60 |  |  |  |  |  | 549,023

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:

| • |  | Heavy fuels, including bunker fuel used to supply marine vessels and refinery feedstocks;

| • |  | Refined products consisting primarily of gasoline and distillates; and

| • |  | Asphalt.

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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:

| • |  | the amount of crude oil and refined product transported in our pipelines;

| • |  | throughput volumes in our terminals and storage facilities;

| • |  | tariff rates and fees we charge and the margins we realize for our services;

| • |  | the results of our marketing, trading and hedging activities;

| • |  | the level of our operating costs;

| • |  | weather conditions;

| • |  | domestic and foreign governmental regulations and taxes;

| • |  | the effect of worldwide energy conservation measures; and

| • |  | prevailing economic conditions.

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

| • |  | our debt service requirements and restrictions on distributions contained in our current or future debt agreements;

| • |  | receipts or payments under interest rate swaps;

| • |  | the sources of cash used to fund our acquisitions;

| • |  | the level of capital expenditures we make;

| • |  | fluctuations in our working capital needs;

| • |  | issuances of debt and equity securities; and

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| • |  | adjustments in cash reserves made by our general partner in its discretion.

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

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 recession or other adverse economic condition that results in lower spending by consumers on gasoline, diesel and travel;

| • |  | higher fuel taxes or other governmental or regulatory actions that increase, directly or indirectly, the cost of gasoline;

| • |  | an increase in fuel economy, whether as a result of a shift by consumers to more fuel-efficient vehicles or technological advances by manufacturers;

| • |  | an increase in the market price of crude oil that leads to higher refined product prices, which may reduce demand for gasoline. Market prices for crude oil and refined products are subject to wide fluctuation in response to changes in global and regional supply that are beyond our control, and increases in the price of crude oil may result in a lower demand for refined products; and

| • |  | the increased use of alternative fuel sources, such as battery-powered engines. Several state and federal initiatives mandate this increased use. For example, the Energy Policy Act of 1992 requires 75% of new vehicles purchased by federal agencies since 1999, 75% of all new vehicles purchased by state governments since 2000, and 70% of all new vehicles purchased for private fleets in 2006 and thereafter to use alternative fuels.

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:

| • |  | scheduled upgrades or maintenance;

| • |  | unscheduled maintenance or catastrophic events, such as a fire, flood, explosion or power outage;

| • |  | labor difficulties that result in a work stoppage or slowdown;

| • |  | environmental proceedings or other litigation that require the halting of all or a portion of the operations of the refinery; or

| • |  | legislation or regulation that adversely impacts the economics of refinery operations.

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:

| • |  | a material decrease in the supply of crude oil;

| • |  | a material decrease in demand for refined products in the markets served by our pipelines and terminals;

| • |  | scheduled turnarounds or unscheduled maintenance;

| • |  | operational problems or catastrophic events at a refinery;

| • |  | environmental proceedings or other litigation that compel the cessation of all or a portion of the operations at a refinery;

| • |  | a decision by Valero Energy to redirect refined products transported in our pipelines to markets not served by our pipelines or to transport crude oil by means other than our pipelines;

| • |  | increasingly stringent environmental regulations; or

| • |  | a decision by Valero Energy to sell one or more of the refineries we serve to a purchaser that elects not to use our pipelines and terminals.

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:

| • |  | earnings volatility;

| • |  | additional working capital requirements; and

| • |  | the asphalt operations’ exposure to the volatility of the cost of crude oil and the price and volumes at which asphalt may be sold.

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:

| • |  | NuStar Energy’s general partner is allowed to take into account the interests of parties other than us, such as NuStar GP Holdings, in resolving conflicts of interest, which has the effect of limiting its fiduciary duty to the unitholders;

| • |  | NuStar Energy’s general partner may limit its liability and reduce its fiduciary duties, while also restricting the remedies available to unitholders. As a result of purchasing our common units, unitholders have consented to some actions and conflicts of interest that might otherwise constitute a breach of fiduciary or other duties under applicable state law;

| • |  | NuStar Energy’s general partner determines the amount and timing of asset purchases and sales, capital expenditures, borrowings, issuance of additional limited partner interests and reserves, each of which can affect the amount of cash that is paid to our unitholders;

| • |  | NuStar Energy’s general partner determines in its sole discretion which costs incurred by NuStar GP Holdings and its affiliates are reimbursable by us;

| • |  | NuStar Energy’s general partner may cause us to pay the general partner or its affiliates for any services rendered on terms that are fair and reasonable to us or enter into additional contractual arrangements with any of these entities on our behalf;

| • |  | NuStar Energy’s general partner decides whether to retain separate counsel, accountants, or others to perform services for us; and

| • |  | In some instances, NuStar Energy’s general partner may cause us to borrow funds in order to permit the payment of distributions.

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

TAX RISKS TO OUR UNITHOLDERS

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

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

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

Current law may change, causing us to be treated as a corporation for federal income tax purposes or otherwise subjecting us to entity-level taxation. In addition, because of widespread state budget deficits, several states are evaluating ways to subject partnerships to entity level taxation through the imposition of state income, franchise or other forms of taxation. 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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ITEM 1B. | UNRESOLVED STAFF COMMENTS

None.

ITEM 3. | LEGAL PROCEEDINGS

We are named as a defendant in litigation relating to our normal business operations, including regulatory and environmental matters. We are insured against various business risks to the extent we believe is prudent; however, we cannot assure you that the nature and amount of such insurance will be adequate, in every case, to 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.

ITEM 4. | SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

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

ITEM 5. | MARKET FOR REGISTRANT’S COMMON UNITS, RELATED UNITHOLDER MATTERS AND ISSUER PURCHASES OF COMMON UNITS

Market Information, Holders and Distributions

Our common units are listed and traded on the New York Stock Exchange under the symbol “NS.” At the close of business on February 7, 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:

|  | Price Range of Common Unit
|  | High |  | Low
Year 2007 |  |  |  |  |  |
4th Quarter |  | $ | 63.89 |  | $ | 51.80
3rd Quarter |  |  | 70.09 |  |  | 52.31
2nd Quarter |  |  | 71.50 |  |  | 61.83
1st Quarter |  |  | 68.00 |  |  | 54.11
Year 2006 |  |  |  |  |  |
4th Quarter |  | $ | 57.75 |  | $ | 49.05
3rd Quarter |  |  | 52.50 |  |  | 48.75
2nd Quarter |  |  | 54.00 |  |  | 48.82
1st Quarter |  |  | 54.70 |  |  | 49.75

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

|  | Record Date |  | Payment Date |  | Amount Per Unit
Year 2007 |  |  |  |  |  |  |
4th Quarter |  | February 7, 2008 |  | February 14, 2008 |  | $ | 0.985
3rd Quarter |  | November 8, 2007 |  | November 14, 2007 |  |  | 0.985
2nd Quarter |  | August 7, 2007 |  | August 14, 2007 |  |  | 0.950
1st Quarter |  | May 7, 2007 |  | May 14, 2007 |  |  | 0.915
Year 2006 |  |  |  |  |  |  |
4th Quarter |  | February 7, 2007 |  | February 14, 2007 |  | $ | 0.915
3rd Quarter |  | November 7, 2006 |  | November 14, 2006 |  |  | 0.915
2nd Quarter |  | August 7, 2006 |  | August 14, 2006 |  |  | 0.885
1st Quarter |  | May 5, 2006 |  | May 12, 2006 |  |  | 0.885

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:

|  | Percentage of Distribution |
Quarterly Distribution Amount per Unit |  | Unitholders |  |  | General Partner |
Up to $0.60 |  | 98 | % |  | 2 | %
Above $0.60 up to $0.66 |  | 90 | % |  | 10 | %
Above $0.66 |  | 75 | % |  | 25 | %

Our general partner’s incentive distributions for the years ended December 31, 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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ITEM 6. | SELECTED FINANCIAL DATA

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

|  | Year Ended December 31,
|  | 2007 |  | 2006 |  | 2005 (a) |  | 2004 |  | 2003 (b)
|  | (Thousands of Dollars, Except Per Unit Data)
Statement of Income Data: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Revenues |  | $ | 1,475,014 |  | $ | 1,137,261 |  | $ | 659,557 |  | $ | 220,792 |  | $ | 181,450
Operating income |  |  | 192,599 |  |  | 212,899 |  |  | 152,952 |  |  | 97,268 |  |  | 82,261
Income from continuing operations |  |  | 150,298 |  |  | 149,906 |  |  | 107,675 |  |  | 78,418 |  |  | 69,593
Income from continuing operations per unit applicable to limited partners (c) |  |  | 2.74 |  |  | 2.84 |  |  | 2.76 |  |  | 3.15 |  |  | 3.02
Cash distributions per unit applicable to limited partners |  |  | 3.835 |  |  | 3.600 |  |  | 3.365 |  |  | 3.20 |  |  | 2.95
|  | As of December 31,
|  | 2007 |  | 2006 |  | 2005 (a) |  | 2004 |  | 2003 (b)
|  | (Thousands of Dollars)
Balance Sheet Data: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Property and equipment, net |  | $ | 2,492,086 |  | $ | 2,345,135 |  | $ | 2,160,213 |  | $ | 784,999 |  | $ | 765,002
Total assets |  |  | 3,783,087 |  |  | 3,494,208 |  |  | 3,366,992 |  |  | 857,507 |  |  | 827,557
Long-term debt (less current portion) |  |  | 1,445,626 |  |  | 1,353,720 |  |  | 1,169,659 |  |  | 384,171 |  |  | 353,257
Partners’ equity |  |  | 1,994,832 |  |  | 1,875,681 |  |  | 1,900,779 |  |  | 438,311 |  |  | 438,163

(a) | The significant increase in revenues, operating income, income from continuing operations and balance sheet data are due primarily to the Kaneb Acquisition.

(b) | On March 18, 2003, Valero Energy contributed the South Texas Pipeline and Terminal Business and certain feedstock storage tanks to us for $350.3 million, including transaction costs.

(c) | Income from continuing operations per unit applicable to limited partners is computed by dividing income from continuing operations applicable to limited partners, after deduction of the general partner’s 2% interest and incentive distributions, by the weighted average number of limited partnership units outstanding for each class of unitholder. Basic and diluted income from continuing operations per unit applicable to limited partners is the same because we have no potentially dilutive securities outstanding.

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ITEM 7. | MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following review of our results of operations and financial condition should be read in conjunction with Items 1., 1A. and 2. “Business, Risk Factors and Properties,” and Item 8. “Financial Statements and Supplementary Data,” included in this report.

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

This Form 10-K contains certain estimates, predictions, projections, assumptions and other forward-looking statements that involve various risks and uncertainties. While these forward-looking statements, and any assumptions upon which they are based, are made in good faith and reflect our current judgment regarding the direction of our business, actual results will almost always vary, sometimes materially, from any estimates, predictions, projections, assumptions or other future performance suggested in this report. These forward-looking statements can generally be identified by the words “anticipates,” “believes,” “expects,” “plans,” “intends,” “estimates,” “forecasts,” “budgets,” “projects,” “will,” “could,” “should,” “may” and similar expressions. These statements reflect our current views with regard to future events and are subject to various risks, uncertainties and assumptions. Please read Item 1A. “Risk Factors” for a discussion of certain of those risks.

If one or more of these risks or uncertainties materialize, or if the underlying assumptions prove incorrect, our actual results may vary materially from those described in any forward-looking statement. Other unknown or unpredictable factors could also have material adverse effects on our future results. Readers are cautioned not to place undue reliance on this forward-looking information, which is as of the date of the Form 10-K. We do not intend to update these statements unless it is required by the securities laws to do so, and we undertake no obligation to publicly release the result of any revisions to any such forward-looking statements that may be made to reflect events or circumstances after the date of this report or to reflect the occurrence of unanticipated events.

Overview

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. On April 1, 2007, we changed our name to NuStar Energy L.P. (NuStar Energy) (NYSE: NS), and Valero GP Holdings, LLC, our general partner, changed its name to NuStar GP Holdings, LLC (NYSE: NSH).

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 either public offering, and Valero Energy’s ownership interest in NuStar GP Holdings was reduced to zero.

As used in this report, references to “we,” “us,” “our” or the “Partnership” collectively refer, depending on the context, to NuStar Energy or a wholly owned subsidiary of NuStar Energy.

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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 included 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 $600 million revolving credit agreement.

On March 30, 2006, we sold our Australia and New Zealand subsidiaries 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.

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.

Operations

We provide transportation, storage services and related services to our customers. Also, we purchase certain petroleum products for resale to third parties. The following factors affect the results of our operations:

| • |  | company-specific factors, such as integrity issues and maintenance requirements that impact the throughput rates of our assets;

| • |  | seasonal factors that affect the demand for refined products and fertilizers transported by and/or stored in our assets;

| • |  | industry factors, such as changes in the prices of petroleum products that affect demand and operations of our competitors;

| • |  | factors such as seasonal inventory levels, commodity price volatility and market structure that impact our marketing and trading organization; and

| • |  | other factors such as refinery utilization rates and maintenance turnaround schedules that impact the operations of refineries served by our assets.

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). 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 operations are divided into five reportable business segments: refined product terminals, refined product pipelines, crude oil pipelines, crude oil storage tanks and marketing.

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Refined Product Terminals. We own 52 terminals in the United States that provide storage and handling services on a fee basis for petroleum products, specialty chemicals and other liquids, including one that provides storage services for crude oil and other feedstocks. We also own international terminal operations on the island of St. Eustatius in the Caribbean, Point Tupper in Nova Scotia, Canada, the United Kingdom, the Netherlands and Nuevo Laredo in Mexico.

Refined Product Pipelines. We own common carrier pipelines in Texas, Oklahoma, Colorado, New Mexico, Kansas, Nebraska, Iowa, South Dakota, North Dakota and Minnesota covering approximately 6,251 miles, consisting of the Central West System, the East Pipeline and the North Pipeline. In addition, we own a 2,000 mile anhydrous ammonia pipeline located in Louisiana, Arkansas, Missouri, Illinois, Indiana, Iowa and Nebraska.

Crude Oil Pipelines. We own 755 miles of crude oil pipelines which transport 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 as well as associated crude oil storage facilities in Texas and Oklahoma that are located along the crude oil pipelines. We also own an interest in 57 miles of crude oil pipeline in Illinois, which serves ConocoPhillips’ Wood River refinery.

Crude Oil Storage Tanks. We own 60 crude oil and intermediate feedstock storage tanks and related assets that store and deliver crude oil and intermediate feedstock to Valero Energy’s refineries in Benicia, California and Corpus Christi and Texas City in Texas.

Marketing. During 2007 we expanded our product sales activities beyond the sale of bunker fuel to include the sale of other petroleum products such as asphalt, gasoline and distillates. The results of all of our product sales activities are now included in our marketing segment. Our marketing segment is meant to provide us the opportunity to generate additional margin while complementing the activities of our refined products terminals and refined product pipelines segments. However, these activities expose us to the risk of fluctuations in commodity prices, which directly impact the results of operations for the marketing segment. Since there are many factors that influence commodity prices, the results of our marketing segment may be more volatile than our other segments.

We enter into derivative contracts 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. Mark-to-market adjustments resulting from these derivative instruments are recorded in revenues.

Demand for certain of the products we market fluctuates seasonally. For example, demand for gasoline and asphalt is typically higher in the summer months than the winter months, whereas demand for heating oil is higher in the winter months than the summer months. Prices for these commodities generally are highest during those times of higher demand. In addition to purchasing inventory for immediate resale, we have and expect to continue to employ a strategy of purchasing inventory during times of lower demand and lower prices and storing that inventory until it can be sold at higher prices. We expect that our overall level of working capital will increase to support the operations of the marketing segment. Additionally, the level of working capital employed by the marketing segment will likely fluctuate seasonally. The absolute increase in the level of working capital as well as the seasonal fluctuations may require us to borrow additional amounts or utilize other sources of liquidity.

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Results of Operations

Year Ended December 31, 2007 Compared to Year Ended December 31, 2006

Financial Highlights

(Thousands of Dollars, Except Unit and Per Unit Data)

|  | Year Ended December 31, |  |  |  |
|  | 2007 |  |  | 2006 |  |  | Change |
Statement of Income Data: |  |  |  |  |  |  |  |  |  |  |  |
Revenues: |  |  |  |  |  |  |  |  |  |  |  |
Service revenues |  | $ | 696,623 |  |  | $ | 636,154 |  |  | $ | 60,469 |
Product sales |  |  | 778,391 |  |  |  | 501,107 |  |  |  | 277,284 |
Total revenues |  |  | 1,475,014 |  |  |  | 1,137,261 |  |  |  | 337,753 |
Costs and expenses: |  |  |  |  |  |  |  |  |  |  |  |
Cost of product sales |  |  | 742,972 |  |  |  | 466,276 |  |  |  | 276,696 |
Operating expenses |  |  | 357,235 |  |  |  | 312,604 |  |  |  | 44,631 |
General and administrative expenses |  |  | 67,915 |  |  |  | 45,216 |  |  |  | 22,699 |
Depreciation and amortization expense |  |  | 114,293 |  |  |  | 100,266 |  |  |  | 14,027 |
Total costs and expenses |  |  | 1,282,415 |  |  |  | 924,362 |  |  |  | 358,053 |
Operating income |  |  | 192,599 |  |  |  | 212,899 |  |  |  | (20,300 | )
Equity earnings from joint ventures |  |  | 6,833 |  |  |  | 5,882 |  |  |  | 951 |
Interest expense, net |  |  | (76,516 | ) |  |  | (66,266 | ) |  |  | (10,250 | )
Other income, net |  |  | 38,830 |  |  |  | 3,252 |  |  |  | 35,578 |
Income from continuing operations before income tax expense |  |  | 161,746 |  |  |  | 155,767 |  |  |  | 5,979 |
Income tax expense |  |  | 11,448 |  |  |  | 5,861 |  |  |  | 5,587 |
Income from continuing operations |  |  | 150,298 |  |  |  | 149,906 |  |  |  | 392 |
Loss from discontinued operations, net of income tax |  |  | — |  |  |  | (376 | ) |  |  | 376 |
Net income |  |  | 150,298 |  |  |  | 149,530 |  |  |  | 768 |
Less net income applicable to general partner |  |  | (21,063 | ) |  |  | (16,910 | ) |  |  | (4,153 | )
Net income applicable to limited partners |  | $ | 129,235 |  |  | $ | 132,620 |  |  | $ | (3,385 | )
Weighted average number of basic units outstanding |  |  | 47,158,790 |  |  |  | 46,809,749 |  |  |  | 349,041 |
Net income (loss) per unit applicable to limited partners: |  |  |  |  |  |  |  |  |  |  |  |
Continuing operations |  | $ | 2.74 |  |  | $ | 2.84 |  |  | $ | (0.10 | )
Discontinued operations |  |  | — |  |  |  | (0.01 | ) |  |  | 0.01 |
Net income |  | $ | 2.74 |  |  | $ | 2.83 |  |  | $ | (0.09 | )

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Segment Operating Highlights

(Thousands of Dollars, Except Barrel/Day Information)

|  | Year Ended December 31, |  |  |  |
|  | 2007 |  |  | 2006 |  |  | Change |
Refined Product Terminals: |  |  |  |  |  |  |  |  |  |  |  |
Throughput (barrels/day)(a)(b) |  |  | 251,309 |  |  |  | 272,054 |  |  |  | (20,745 | )
Throughput revenues |  | $ | 51,135 |  |  | $ | 50,264 |  |  | $ | 871 |
Storage lease revenues |  |  | 314,255 |  |  |  | 266,234 |  |  |  | 48,021 |
Total revenues |  |  | 365,390 |  |  |  | 316,498 |  |  |  | 48,892 |
Operating expenses |  |  | 221,890 |  |  |  | 191,698 |  |  |  | 30,192 |
Depreciation and amortization expense |  |  | 54,635 |  |  |  | 45,485 |  |  |  | 9,150 |
Segment operating income |  | $ | 88,865 |  |  | $ | 79,315 |  |  | $ | 9,550 |
Refined Product Pipelines: |  |  |  |  |  |  |  |  |  |  |  |
Throughput (barrels/day)(a) |  |  | 678,573 |  |  |  | 711,476 |  |  |  | (32,903 | )
Throughput revenues |  | $ | 243,828 |  |  | $ | 222,356 |  |  | $ | 21,472 |
Operating expenses |  |  | 105,010 |  |  |  | 94,326 |  |  |  | 10,684 |
Depreciation and amortization expense |  |  | 45,006 |  |  |  | 42,084 |  |  |  | 2,922 |
Segment operating income |  | $ | 93,812 |  |  | $ | 85,946 |  |  | $ | 7,866 |
Crude Oil Pipelines: |  |  |  |  |  |  |  |  |  |  |  |
Throughput (barrels/day) |  |  | 377,640 |  |  |  | 421,666 |  |  |  | (44,026 | )
Revenues |  | $ | 52,968 |  |  | $ | 58,654 |  |  | $ | (5,686 | )
Operating expenses |  |  | 15,332 |  |  |  | 16,825 |  |  |  | (1,493 | )
Depreciation and amortization expense |  |  | 4,940 |  |  |  | 5,061 |  |  |  | (121 | )
Segment operating income |  | $ | 32,696 |  |  | $ | 36,768 |  |  | $ | (4,072 | )
Crude Oil Storage Tanks: |  |  |  |  |  |  |  |  |  |  |  |
Throughput (barrels/day) |  |  | 549,023 |  |  |  | 502,689 |  |  |  | 46,334 |
Revenues |  | $ | 45,237 |  |  | $ | 46,915 |  |  | $ | (1,678 | )
Operating expenses |  |  | 11,785 |  |  |  | 10,108 |  |  |  | 1,677 |
Depreciation and amortization expense |  |  | 7,682 |  |  |  | 7,636 |  |  |  | 46 |
Segment operating income |  | $ | 25,770 |  |  | $ | 29,171 |  |  | $ | (3,401 | )
Marketing: |  |  |  |  |  |  |  |  |  |  |  |
Product sales |  | $ | 778,391 |  |  | $ | 501,107 |  |  | $ | 277,284 |
Cost of product sales |  |  | 750,120 |  |  |  | 471,576 |  |  |  | 278,544 |
Operating expenses |  |  | 6,737 |  |  |  | 2,616 |  |  |  | 4,121 |
Depreciation and amortization expense |  |  | 423 |  |  |  | — |  |  |  | 423 |
Segment operating income |  | $ | 21,111 |  |  | $ | 26,915 |  |  | $ | (5,804 | )
Consolidation and Intersegment Eliminations: |  |  |  |  |  |  |  |  |  |  |  |
Revenues |  | $ | (10,800 | ) |  | $ | (8,269 | ) |  | $ | (2,531 | )
Cost of product sales |  |  | (7,148 | ) |  |  | (5,300 | ) |  |  | (1,848 | )
Operating expenses |  |  | (3,519 | ) |  |  | (2,969 | ) |  |  | (550 | )
Depreciation and amortization expense |  |  | 1,607 |  |  |  | — |  |  |  | 1,607 |
Total |  | $ | (1,740 | ) |  | $ | — |  |  | $ | (1,740 | )

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Segment Operating Highlights

(Thousands of Dollars, Except Barrel/Day Information)

|  | Year Ended December 31, |  |  |
|  | 2007 |  | 2006 |  | Change |
Consolidated Information: |  |  |  |  |  |  |  |  |  |
Revenues |  | $ | 1,475,014 |  | $ | 1,137,261 |  | $ | 337,753 |
Cost of product sales |  |  | 742,972 |  |  | 466,276 |  |  | 276,696 |
Operating expenses |  |  | 357,235 |  |  | 312,604 |  |  | 44,631 |
Depreciation and amortization expense |  |  | 114,293 |  |  | 100,266 |  |  | 14,027 |
Segment operating income |  |  | 260,514 |  |  | 258,115 |  |  | 2,399 |
General and administrative expenses |  |  | 67,915 |  |  | 45,216 |  |  | 22,699 |
Consolidated operating income |  | $ | 192,599 |  | $ | 212,899 |  | $ | (20,300 | )

(a) | Throughput related to newly acquired assets included in the table above is calculated based on throughput for the period from the date of acquisition through December 31 of the year of acquisition divided by the number of days in the applicable year.

(b) | Excludes throughputs related to storage lease revenues.

Annual Highlights

Net income increased $0.8 million for the year ended December 31, 2007, compared to the year ended December 31, 2006, primarily due to a significant increase in other income and slightly higher segment operating income, partially offset by increased general and administrative expense, interest expense and income tax expense.

Total segment operating income increased $2.4 million for the year ended December 31, 2007, compared to the year ended December 31, 2006, primarily due to a $9.6 million increase in operating income for the refined product terminals segment and a $7.9 million increase in operating income for the refined product pipelines segment, partially offset by a $5.8 million decrease in operating income for the marketing segment, a $4.1 million decrease in operating income for the crude oil pipelines segment and a $3.4 million decrease in operating income for the crude oil storage tanks segment.

The throughputs on the refined product pipelines, the refined product terminals and the crude oil pipelines segments were affected by a fire at the McKee refinery in February 2007, which shut down the refinery through mid-April 2007. After the refinery restarted in mid-April 2007, its throughputs increased throughout the second quarter, and it was near capacity by July 2007.

Refined Product Terminals

Revenues increased by $48.9 million for the year ended December 31, 2007, compared to the year ended December 31, 2006, primarily due to an increase in storage lease revenues of $48.0 million due to the following:

| • |  | an increase of $19.2 million resulting from the St. James terminal acquisition in December 2006;

| • |  | an increase in storage lease terminal revenues of $24.7 million mainly due to additional customers, increased storage utilization and contract extensions by current customers, higher reimbursable project revenue and the effect of foreign exchange rates; and

| • |  | an increase in revenues of $4.1 million at our St. Eustatius facility due to leasing additional storage capacity that resulted from completed tank expansion projects.

Despite lower revenues and throughputs related to our terminals serving the McKee refinery, our throughput revenues increased $0.9 million primarily due to increased throughputs at our Laredo, Harlingen and Paulsboro terminals. The Laredo and Harlingen terminals experienced increased demand for refined products in 2007, and the Paulsboro terminal experienced lower throughput in 2006 due to a turnaround at the Paulsboro refinery in 2006.

Operating expenses increased $30.2 million for the year ended December 31, 2007, compared to the year ended December 31, 2006, primarily due to higher reimbursable project expenses. Reimbursable project expenses are charged back to our customers, and its increase is consistent with the increase in reimbursable project revenues. Operating expenses also increased due to higher maintenance and regulatory expenses, higher salaries and wages, the acquisition of the St. James terminal in December 2006, and higher marine expenses due to increased vessel calls at St. Eustatius and Point Tupper.

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Depreciation and amortization expense increased $9.2 million for the year ended December 31, 2007, compared to the year ended December 31, 2006, due to the acquisition of the St. James terminal in December 2006 and the completion of various capital projects, including two phases of the St. Eustatius tank expansion.

Refined Product Pipelines

Throughputs decreased 32,903 barrels per day for the year ended December 31, 2007, compared to the year ended December 31, 2006, primarily due to the impact of the McKee refinery fire, offset by increased throughputs on the East Pipeline, Ammonia Pipeline and Burgos Pipeline. Despite lower overall throughputs, revenues increased by $21.5 million for the year ended December 31, 2007, compared to the year ended December 31, 2006, primarily due to:

| • |  | higher tariff rates on virtually all of the refined product pipelines as the annual index adjustment was effective July 1, 2007;

| • |  | increased revenues and throughputs on the East Pipeline due to the closing of one of our competitor’s terminals in the second quarter of 2007 and increased throughputs to supply the Colorado market. The East Pipeline also experienced increased revenues due to a turnaround at the Ponca City refinery in prior year and increased long haul deliveries in 2007;

| • |  | increased revenues on the Ammonia Pipeline due to a record corn crop; and

| • |  | increased revenues on the Burgos pipeline due to our receipt of throughput deficiency payments in 2007. In addition, revenues increased due to a full year of operations of the Burgos pipeline, which commenced operations in the middle of the third quarter of 2006.

Operating expenses increased $10.7 million for the year ended December 31, 2007, compared to the year ended December 31, 2006, primarily due to higher maintenance and environmental costs and higher internal overhead costs mainly due to increased headcount.

Depreciation and amortization expense increased $2.9 million for the year ended December 31, 2007, compared to the year ended December 31, 2006, mainly due to increased amortization of deferred costs in connection with the throughput deficiency payments discussed above. In addition, depreciation and amortization expense increased due to the completion of various capital projects.

Crude Oil Pipelines

Throughputs decreased 44,026 barrels per day and revenues decreased $5.7 million for the year ended December 31, 2007, compared to the year ended December 31, 2006, primarily due to the impact of the McKee refinery fire.

Operating expenses decreased $1.5 million for the year ended December 31, 2007, compared to the year ended December 31, 2006, primarily due to decreased power costs resulting from the McKee refinery fire.

Crude Oil Storage Tanks

Throughputs increased 46,334 barrels per day for the year ended December 31, 2007, compared to the year ended December 31, 2006, primarily due to a change in the Corpus Christi (North Beach) crude oil storage tank agreement from a storage lease to a throughput fee agreement effective January 1, 2007. Throughputs for the Corpus Christi (North Beach) crude oil storage tanks were not reported prior to January 1, 2007. However, revenues decreased by $1.7 million for the year ended December 31, 2007, compared to the year ended December 31, 2006, primarily due to turnarounds at the Benicia, Three Rivers and Corpus Christi refineries and operating issues at the Texas City refinery in January and December 2007. The Corpus Christi refinery further experienced multiple operating issues during the first half of 2007.

Operating expenses increased by $1.7 million for the year ended December 31, 2007, compared to the year ended December 31, 2006, primarily due to higher wharfage and dockage costs related to the Corpus Christi (North Beach) crude oil facility.

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Marketing

Bunker fuel sales increased $171.5 million for the year ended December 31, 2007 compared to the year ended December 31, 2006 due to increased vessel calls at our St. Eustatius facility, partially offset by a decrease in bunker fuel sales of $10.9 million at our Point Tupper facility due to decreased vessel calls. Cost of product sales associated with bunker fuel sales also increased $159.8 million due to the increase in vessel calls.

Sales of refined products, heavy fuels and asphalt increased $115.4 million for the year ended December 31, 2007 compared to December 31, 2006 because those operations began in 2007. Cost of product sales related to the sales of refined products, heavy fuels and asphalt increased $121.3 million for the year ended December 31, 2007 compared to the year ended December 31, 2006. For the year ended December 31, 2007 cost of product sales related to the sale of refined products, heavy fuels and asphalt includes $7.5 million related to the change in fair value of certain derivative instruments. Operating expenses increased by $4.1 million for the year ended December 31, 2007, compared to the year ended December 31, 2006, primarily due to salaries and wages and terminal storage fees relating to our sales of refined products, heavy fuels and asphalt, which began in 2007.

General

General and administrative expenses increased by $22.7 million for the year ended December 31, 2007, compared to the year ended December 31, 2006, primarily due to the following:

| • |  | increased expenses associated with unit option and restricted unit compensation expense as a result of the increase in the number of awards outstanding, partially offset by a decrease in the NuStar Energy unit price;

| • |  | increased headcount primarily resulting from a reduction in administrative services received from Valero Energy and increased information systems costs as a result of the separation from Valero Energy;

| • |  | increased professional fees primarily related to external legal costs; and

| • |  | increased rent expense related to our new headquarters.

Interest expense increased by $10.3 million for the year ended December 31, 2007, compared to the year ended December 31, 2006, primarily due to higher average debt balances arising from borrowings used to fund the acquisition of the St. James crude oil storage facility in December 2006 and various terminal expansion projects combined with higher interest rates, partially offset by capitalized interest.

Other income increased by $35.6 million for the year ended December 31, 2007, compared to the year ended December 31, 2006, primarily due to a $13.0 million payment from Valero Energy for exercising its option to terminate the 2007 Services Agreement, business interruption insurance income of $12.5 million associated with the McKee refinery fire, the sale of a net profit interest in Wyoming coal properties for $7.3 million and a gain of $5.2 million related to a settlement for damages at our Westwego terminal. Partially offsetting these increases are foreign exchange losses totaling approximately $6.3 million primarily relating to our Canadian subsidiary.

Income tax expense increased $5.6 million for the year ended December 31, 2007, compared to the year ended December 31, 2006. Income tax expense was higher in 2007 primarily due to the impact of the Texas margin tax effective January 1, 2007, recording a valuation allowance related to a capital loss carryforward in Canada and other adjustments. These increases were partially offset by reductions in the United Kingdom and Canadian income tax rates in 2007.

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Year Ended December 31, 2006 Compared to Year Ended December 31, 2005

Financial Highlights

(Thousands of Dollars, Except Unit and Per Unit Data)

|  | Year Ended December 31, |  |  |  |
|  | 2006 |  |  | 2005 |  |  | Change |
Statement of Income Data: |  |  |  |  |  |  |  |  |  |  |  |
Revenues: |  |  |  |  |  |  |  |  |  |  |  |
Service revenue |  | $ | 636,154 |  |  | $ | 423,057 |  |  | $ | 213,097 |
Product sales |  |  | 501,107 |  |  |  | 236,500 |  |  |  | 264,607 |
Total revenues |  |  | 1,137,261 |  |  |  | 659,557 |  |  |  | 477,704 |
Costs and expenses: |  |  |  |  |  |  |  |  |  |  |  |
Cost of product sales |  |  | 466,276 |  |  |  | 229,806 |  |  |  | 236,470 |
Operating expenses |  |  | 312,604 |  |  |  | 185,351 |  |  |  | 127,253 |
General and administrative expenses |  |  | 45,216 |  |  |  | 26,553 |  |  |  | 18,663 |
Depreciation and amortization expense |  |  | 100,266 |  |  |  | 64,895 |  |  |  | 35,371 |
Total costs and expenses |  |  | 924,362 |  |  |  | 506,605 |  |  |  | 417,757 |
Operating income |  |  | 212,899 |  |  |  | 152,952 |  |  |  | 59,947 |
Equity earnings from joint ventures |  |  | 5,882 |  |  |  | 2,319 |  |  |  | 3,563 |
Interest expense, net |  |  | (66,266 | ) |  |  | (41,388 | ) |  |  | (24,878 | )
Other income (expense), net |  |  | 3,252 |  |  |  | (1,495 | ) |  |  | 4,747 |
Income from continuing operations before income tax expense |  |  | 155,767 |  |  |  | 112,388 |  |  |  | 43,379 |
Income tax expense |  |  | 5,861 |  |  |  | 4,713 |  |  |  | 1,148 |
Income from continuing operations |  |  | 149,906 |  |  |  | 107,675 |  |  |  | 42,231 |
Income (loss) from discontinued operations, net of income tax |  |  | (376 | ) |  |  | 3,398 |  |  |  | (3,774 | )
Net income |  |  | 149,530 |  |  |  | 111,073 |  |  |  | 38,457 |
Less net income applicable to the general partner |  |  | (16,910 | ) |  |  | (10,758 | ) |  |  | (6,152 | )
Net income applicable to limited partners |  | $ | 132,620 |  |  | $ | 100,315 |  |  | $ | 32,305 |
Weighted average number of basic and diluted units outstanding |  |  | 46,809,749 |  |  |  | 35,023,250 |  |  |  | 11,786,499 |
Net income (loss) per unit applicable to limited partners: |  |  |  |  |  |  |  |  |  |  |  |
Continuing operations |  | $ | 2.84 |  |  | $ | 2.76 |  |  | $ | 0.08 |
Discontinued operations |  |  | (0.01 | ) |  |  | 0.10 |  |  |  | (0.11 | )
Net income |  | $ | 2.83 |  |  | $ | 2.86 |  |  | $ | (0.03 | )

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Segment Operating Highlights

(Thousands of Dollars, Except Barrel/Day Information)

|  | Year Ended December 31, |  |  |  |
|  | 2006 |  |  | 2005 |  |  | Change |
Refined Product Terminals: |  |  |  |  |  |  |  |  |  |  |  |
Throughput (barrels/day)(a)(b) |  |  | 272,054 |  |  |  | 253,585 |  |  |  | 18,469 |
Throughput revenues |  | $ | 50,264 |  |  | $ | 44,400 |  |  | $ | 5,864 |
Storage lease revenues |  |  | 266,234 |  |  |  | 126,292 |  |  |  | 139,942 |
Total revenues |  |  | 316,498 |  |  |  | 170,692 |  |  |  | 145,806 |
Operating expenses |  |  | 191,698 |  |  |  | 94,307 |  |  |  | 97,391 |
Depreciation and amortization expense |  |  | 45,485 |  |  |  | 25,008 |  |  |  | 20,477 |
Segment operating income |  | $ | 79,315 |  |  | $ | 51,377 |  |  | $ | 27,938 |
Refined Product Pipelines: |  |  |  |  |  |  |  |  |  |  |  |
Throughput (barrels/day)(a) |  |  | 711,476 |  |  |  | 556,654 |  |  |  | 154,822 |
Throughput revenues |  | $ | 222,356 |  |  | $ | 149,853 |  |  | $ | 72,503 |
Operating expenses |  |  | 94,326 |  |  |  | 65,454 |  |  |  | 28,872 |
Depreciation and amortization expense |  |  | 42,084 |  |  |  | 27,778 |  |  |  | 14,306 |
Segment operating income |  | $ | 85,946 |  |  | $ | 56,621 |  |  | $ | 29,325 |
Crude Oil Pipelines: |  |  |  |  |  |  |  |  |  |  |  |
Throughput (barrels/day) |  |  | 421,666 |  |  |  | 358,965 |  |  |  | 62,701 |
Revenues |  | $ | 58,654 |  |  | $ | 51,429 |  |  | $ | 7,225 |
Operating expenses |  |  | 16,825 |  |  |  | 16,378 |  |  |  | 447 |
Depreciation and amortization expense |  |  | 5,061 |  |  |  | 4,612 |  |  |  | 449 |
Segment operating income |  | $ | 36,768 |  |  | $ | 30,439 |  |  | $ | 6,329 |
Crude Oil Storage Tanks: |  |  |  |  |  |  |  |  |  |  |  |
Throughput (barrels/day) |  |  | 502,689 |  |  |  | 517,409 |  |  |  | (14,720 | )
Revenues |  | $ | 46,915 |  |  | $ | 46,943 |  |  | $ | (28 | )
Operating expenses |  |  | 10,108 |  |  |  | 9,695 |  |  |  | 413 |
Depreciation and amortization expense |  |  | 7,636 |  |  |  | 7,497 |  |  |  | 139 |
Segment operating income |  | $ | 29,171 |  |  | $ | 29,751 |  |  | $ | (580 | )
Marketing: |  |  |  |  |  |  |  |  |  |  |  |
Product sales |  | $ | 501,107 |  |  | $ | 246,603 |  |  | $ | 254,504 |
Cost of product sales |  |  | 471,576 |  |  |  | 233,102 |  |  |  | 238,474 |
Operating expenses |  |  | 2,616 |  |  |  | 2,184 |  |  |  | 432 |
Depreciation and amortization expense |  |  | — |  |  |  | — |  |  |  | — |
Segment operating income |  | $ | 26,915 |  |  | $ | 11,317 |  |  | $ | 15,598 |
Consolidation and Intersegment Eliminations: |  |  |  |  |  |  |  |  |  |  |  |
Revenues |  | $ | (8,269 | ) |  | $ | (5,963 | ) |  | $ | (2,306 | )
Cost of product sales |  |  | (5,300 | ) |  |  | (3,296 | ) |  |  | (2,004 | )
Operating expenses |  |  | (2,969 | ) |  |  | (2,667 | ) |  |  | (302 | )
Depreciation and amortization expense |  |  | — |  |  |  | — |  |  |  | — |
Total |  | $ | — |  |  | $ | — |  |  | $ | — |

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##### Table of Contents

Segment Operating Highlights

(Thousands of Dollars, Except Barrel/Day Information)

|  | Year Ended December 31, |  |
|  | 2006 |  | 2005 |  | Change
Consolidated Information: |  |  |  |  |  |  |  |  |
Revenues |  | $ | 1,137,261 |  | $ | 659,557 |  | $ | 477,704
Cost of product sales |  |  | 466,276 |  |  | 229,806 |  |  | 236,470
Operating expenses |  |  | 312,604 |  |  | 185,351 |  |  | 127,253
Depreciation and amortization expense |  |  | 100,266 |  |  | 64,895 |  |  | 35,371
Segment operating income |  |  | 258,115 |  |  | 179,505 |  |  | 78,610
General and administrative expenses |  |  | 45,216 |  |  | 26,553 |  |  | 18,663
Consolidated operating income |  | $ | 212,899 |  | $ | 152,952 |  | $ | 59,947

(a) | Throughput related to newly acquired assets included in the table above is calculated based on throughput for the period from the date of acquisition through December 31 of the year of acquisition divided by the number of days in the applicable year.

(b) | Excludes throughputs related to storage lease revenues.

Annual Highlights

Net income increased $38.5 million for the year ended December 31, 2006, compared to the year ended December 31, 2005, due to higher segment operating income, partially offset by increased general and administrative expense, increased interest expense and increased income tax expense. All of these increases predominantly resulted from including the results of the Kaneb Acquisition for a full year in 2006 compared to six months in 2005.

Segment operating income increased $78.6 million for the year ended December 31, 2006, compared to the year ended December 31, 2005, primarily due to a $29.3 million increase in the refined product pipelines segment, a $27.9 million increase in the refined product terminals segment, a $15.6 million increase in the marketing segment and a $6.3 million increase in the crude oil pipelines segment. Increases in the marketing, refined product pipelines and refined product terminals segments relate primarily to the effect of the Kaneb Acquisition, while the crude oil pipelines segment increased due to the acquisition of our interest in the Capwood crude oil pipeline. Except for storage lease revenues and product sales, operating income for our segments depends upon the level of throughputs moving through our assets. In addition to the Kaneb Acquisition, which impacted the marketing, refined product pipelines and refined product terminals segments, all of our segments, except the marketing and crude oil storage tank segment, were affected by lower throughputs in 2005 resulting from scheduled maintenance turnarounds or other operational issues at the McKee, Three Rivers and Ardmore refineries.

Refined Product Terminals

Revenues increased $145.8 million for the year ended December 31, 2006, compared to the year ended December 31, 2005, primarily due to the following:

| • |  | the Kaneb Acquisition contributed $264.5 million of storage lease revenues for the year ended December 31, 2006 compared to $126.3 million of storage lease revenues for the period from July 1, 2005 to December 31, 2005;

| • |  | the acquisition of the St. James terminal in December of 2006 contributed $1.7 million to revenue;

| • |  | higher throughputs in 2006 as the McKee and Three Rivers refineries experienced scheduled turnarounds and unit downtime in 2005; and

| • |  | an increase in the fees charged at our terminals.

Partially offsetting the increases above were lower throughputs at our asphalt terminals due to a reduction in overall demand in 2006.

Operating expenses increased $97.4 million for the year ended December 31, 2006, compared to the year ended December 31, 2005, primarily due to the inclusion of a full year in 2006 of operating expenses related to the assets acquired in the Kaneb Acquisition.

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Depreciation and amortization expense increased $20.5 million for the year ended December 31, 2006, compared to the year ended December 31, 2005, primarily due to the inclusion of a full year in 2006 of depreciation and amortization expense related to our property and equipment acquired in the Kaneb Acquisition.

Refined Product Pipelines

Revenues increased $72.5 million for the year ended December 31, 2006, compared to the year ended December 31, 2005, primarily due to the following:

| • |  | the Kaneb Acquisition contributed $116.4 million of revenues for the year ended December 31, 2006 compared to $57.4 million of revenue for the period from July 1, 2005 to December 31, 2005;

| • |  | higher throughputs and revenues on the McKee to El Paso refined product pipeline system and the McKee to Denver refined product pipelines and higher throughputs in 2006 as the McKee and Three Rivers refineries experienced turnarounds and unit downtime in 2005; and

| • |  | the completion of the Burgos project, which commenced operations on the Edinburg to Harlingen segment in October 2005, the Harlingen to Brownsville segment in March 2006 and made its first delivery of naphtha from Penitas, TX, near the Mexico border, to Brownsville in the third quarter of 2006.

Operating expenses increased $28.9 million for the year ended December 31, 2006, compared to the year ended December 31, 2005, primarily due to the inclusion of a full year in 2006 of operating expenses related to the assets acquired in the Kaneb Acquisition.

Depreciation and amortization expense increased $14.3 million for the year ended December 31, 2006, compared to the year ended December 31, 2005, primarily due to the inclusion of a full year in 2006 of depreciation and amortization expense related to our property and equipment acquired in the Kaneb Acquisition and the completion of the Burgos project in 2006.

Crude Oil Pipelines

Revenues increased $7.2 million for the year ended December 31, 2006, compared to the year ended December 31, 2005, primarily due to higher throughputs in 2006 as the McKee, Three Rivers and Ardmore refineries experienced scheduled turnarounds and unit downtime in 2005. In addition, our acquisition of the Capwood pipeline on January 1, 2006, which increased throughputs by approximately 41,000 barrels per day, resulted in additional revenues of $2.3 million.

Crude Oil Storage Tanks

Despite comparable revenues for the year ended December 31, 2006 compared to the year ended December 31, 2005, throughputs decreased by approximately 15,000 barrels per day due to scheduled turnarounds at Valero Energy’s Benicia and Texas City refineries in 2006. The lower throughput and revenue at the Benicia and Texas City facilities were offset by higher revenue from the Corpus Christi (North Beach) facility, which did not report throughput barrels through December 31, 2006 as revenues for this facility are mainly based on a lease agreement with Valero Energy.

Marketing

Revenues increased $254.5 million for the year ended December 31, 2006, compared to the year ended December 31, 2005, primarily due to the Kaneb Acquisition. The Kaneb Acquisition contributed $494.1 million of bunkering revenues for the year ended December 31, 2006 compared to $246.6 million for the period from July 1, 2005 to December 31, 2005.

Cost of product sales totaled $471.6 million for the year ended December 31, 2006 and $233.1 million for the period from July 1, 2005 to December 31, 2005. Cost of product sales reflects the cost of bunker fuel sold to marine vessels at the St. Eustatius and Point Tupper, which we acquired as part of the Kaneb Acquisition.

General

General and administrative expenses increased $18.7 million for the year ended December 31, 2006 compared to the year ended December 31, 2005, due to increased headcount as a result of the Kaneb Acquisition and reduced services received from Valero Energy under the services agreement. This increase in general and administrative expenses was partially offset by a decrease of $5.0 million in the service fee charged to us under a services agreement with Valero Energy.

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Equity earnings from joint ventures increased $3.6 million for the year ended December 31, 2006, compared to the year ended December 31, 2005, primarily related to our 50% ownership in a terminal and storage facility in Linden, New Jersey, which was acquired in the Kaneb Acquisition.

Interest expense increased $24.9 million for the year ended December 31, 2006, compared to the year ended December 31, 2005, due to higher average debt balances resulting from debt assumed as part of the Kaneb Acquisition and debt incurred to fund the Kaneb Acquisition combined with higher interest rates in 2006.

Other income increased $4.7 million for the year ended December 31, 2006, compared to the year ended December 31, 2005, primarily due to an impairment charge of $2.1 million in 2005 as a portion of the Three Rivers to Pettus to Corpus Christi, Texas refined product pipeline was permanently idled.

Income tax expense increased $1.1 million for the year ended December 31, 2006, compared to the year ended December 31, 2005, primarily due to the inclusion of a full year in 2006 of income tax expense related to certain operations acquired in the Kaneb Acquisition.

Outlook

Our business primarily consists of transportation, storage, terminalling and marketing of crude oil and refined products and is subject to the demand for those commodities in the regions in which we operate. Our business is generally more defensive in nature than other companies during times of economic slowdowns since we largely operate a stable, cash-flowing business; however, a recession, widely predicted to occur in 2008 according to several economists and regulators, or other adverse economic conditions, could negatively impact our operations.

We expect to see relatively few maintenance turnarounds in 2008, particularly at the Valero Energy refineries we serve. Therefore, we expect throughputs and revenues on our pipeline, terminal and storage business segments to improve in 2008 versus 2007, especially since our throughputs were impacted by Valero Energy’s McKee refinery fire for part of 2007.

Longer term, we believe strong demand for more energy infrastructure in the U.S. and internationally, continued growth in product demand, a tight supply and demand balance and an expanding array of specialty products including renewable fuels will continue to drive the demand for our assets. High refinery utilization rates tend to be supportive of throughputs through our pipelines and terminals.

Crude Oil and Refined Product Pipelines Outlook

Overall demand for our pipeline services in 2008 should remain high, despite some indications of an economic slowdown. Turnarounds or outages at our customers’ refineries have a significant effect on our pipeline results, as do maintenance expenses and market conditions. Barring any major unplanned turnaround activity or significant adverse economic condition, we expect our refined product and crude oil pipeline throughputs will generally grow at a rate typical for the demand of refined products. Additionally, effective July 1 st, we expect the tariffs on our pipelines to increase, which will also positively impact our results.

Terminalling and Storage Outlook

We believe certain trends we see in the market are providing further terminalling opportunities for us for a number of reasons, including:

| • |  | high commodity prices, which in relative terms make logistics cheap compared to the value they deliver;

| • |  | volatility in the energy markets and the willingness of energy traders to take physical positions at storage facilities in order to enhance profits;

| • |  | growing governmental regulation mandating cleaner fuels, such as ethanol and biofuels, which provide logistical opportunities;

| • |  | strong refining fundamentals that are expected to remain good for some time;

| • |  | geopolitical factors, which cause concern over the security of supply; and

| • |  | arbitrage opportunities such as those between the gasoline short U.S. and diesel short Europe, which continue to enhance storage opportunities.

The markets where we are investing to increase storage are strategically located marine terminal facilities on the East, West and Gulf Coasts of the U.S. as well as internationally at our facilities in St. Eustatius in the Netherlands Antilles, Amsterdam and the United Kingdom.

During 2007, we completed key terminal expansion projects and we commenced construction on other significant terminal expansion projects, which we expect to positively impact our operations in 2008.

Marketing Outlook

In 2008, we plan to continue to increase our marketing segment activity, which we expect to positively affect our earnings. However, the operations of the marketing segment expose us to commodity price risk, which could increase the volatility of our earnings. In addition, we may experience additional volatility in our earnings and cash flows, as changes in the values of our derivative instruments may not completely offset changes in the values of our physical inventory.

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LIQUIDITY AND CAPITAL RESOURCES

General

Our primary cash requirements are for distributions to partners, working capital requirements, debt service, reliability and strategic and other capital expenditures, acquisitions and normal operating expenses. We typically generate sufficient cash from our current operations to fund day-to-day operating and general and administrative expenses, reliability capital expenditures and distribution requirements. We also have available borrowing capacity under our existing revolving credit facility and, to the extent necessary, we may raise additional funds through equity or debt offerings under our $3.0 billion shelf registration statement to fund strategic capital expenditures or other cash requirements not funded from operations. However, there can be no assurance regarding the availability of any additional funds or whether such additional funds can be provided on terms acceptable to us.

Cash Flows for the Year Ended December 31, 2007 and 2006

Net cash provided by operating activities for the year ended December 31, 2007 was $222.7 million compared to $250.8 million for the year ended December 31, 2006. The decrease in cash generated from operating activities is primarily due to a $21.3 million use of cash in 2007 from changes in working capital accounts compared to a $10.7 million source of cash in 2006 from changes in working capital accounts. Accounts receivable and inventory increased by $22.1 million and $71.5 million, respectively, compared to 2006 primarily due to the operations of the marketing segment, particularly an increase in inventory associated with marketing of asphalt, gasoline and distillates which began in 2007. Offsetting the increases in inventory and accounts receivable was an increase in accounts payable of $72.9 million, also primarily related to the marketing of asphalt, gasoline and distillates. Cash flows from operations for the year ended December 31, 2007 also includes proceeds from business interruption insurance of $12.5 million.

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

Net cash provided by operating activities for the year ended December 31, 2006, combined with available cash on hand, was used primarily to fund distributions to unitholders and the general partner in the aggregate amount of $183.3 million. Proceeds from long-term debt borrowings totaling $269.0 million, combined with the proceeds totaling $70.1 million from the sale of the Australia and New Zealand subsidiaries on March 30, 2006, were used to fund asset acquisitions of $154.5 million, repay long-term debt of $83.5 million and to fund capital expenditures and investment of other noncurrent assets of $124.0 million and $10.8 million, respectively.

Equity

Equity Offering. 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 total proceeds of $146.1 million, including a contribution of $3.0 million from our general partner, net of issuance costs. The proceeds were used to repay a portion of the outstanding principal balance under our $600 million revolving credit agreement.

Shelf Registration Statement. On May 18, 2007, the SEC declared effective our shelf registration statement on Form S-3, which permits us to offer and sell various types of securities, including NuStar Energy common units and debt securities of each NuStar Logistics and KPOP, having an aggregate value of up to $3.0 billion (the 2007 Shelf Registration Statement). We filed the 2007 Shelf Registration Statement to gain additional flexibility in accessing capital markets for, among other things, the repayment of outstanding indebtedness, working capital, capital expenditures and acquisitions. As of December 31, 2007, we had $2.85 billion remaining under the 2007 Shelf Registration Statement. The 2007 Shelf Registration Statement replaces our 2003 Shelf Registration Statement, which was effective October 2, 2003 and filed by us and NuStar Logistics to register $750.0 million of securities for potential future use.

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

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

|  | Year Ended December 31,
|  | 2007 |  | 2006 |  | 2005
|  | (Thousands of Dollars, Except Per Unit Data)
General partner interest |  | $ | 4,092 |  | $ | 3,742 |  | $ | 3,036
General partner incentive distribution |  |  | 18,426 |  |  | 14,778 |  |  | 10,259
Total general partner distribution |  |  | 22,518 |  |  | 18,520 |  |  | 13,295
Limited partners’ distribution |  |  | 182,076 |  |  | 168,515 |  |  | 138,500
Total cash distributions |  | $ | 204,594 |  | $ | 187,035 |  | $ | 151,795
Cash distributions per unit applicable to limited partners |  | $ | 3.835 |  | $ | 3.600 |  | $ | 3.365

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

On January 24, 2008, we declared a quarterly cash distribution of $0.985, which was paid on February 14, 2008 to unitholders of record on February 7, 2008. This distribution related to the fourth quarter of 2007 and totaled $55.0 million, of which $6.3 million represented the general partner’s share of such distribution. The general partner’s distribution included a $5.2 million incentive distribution.

Capital Requirements

The petroleum pipeline and terminalling industry is capital intensive, requiring significant investments to maintain, upgrade or enhance existing operations and to comply with environmental and safety laws and regulations. Our capital expenditures consist of:

| • |  | reliability capital expenditures, such as those required to maintain equipment reliability and safety and to address environmental and safety regulations; and

| • |  | strategic and other capital expenditures, such as those to expand and upgrade pipeline capacity and to construct new pipelines, terminals and storage tanks. In addition, expansion capital expenditures may include acquisitions of pipelines, terminals or storage tank assets.

During the year ended December 31, 2007, we incurred reliability capital expenditures of $40.3 million primarily related to system automation and maintenance upgrade projects at our terminals and pipelines, and strategic capital expenditures of $211.0 million primarily related to the Amsterdam, St. Eustatius and St. James tank expansions and other terminal expansion projects. Also, we incurred expenditures required as a result of our separation from Valero Energy, such as separating our information systems and improvements made to our new headquarters.

For 2008, we budgeted for $182.0 million of capital expenditures, including $53.0 million for reliability capital projects and $129.0 million for strategic and other capital projects. We continuously evaluate our capital budget and make changes as economic conditions warrant. If conditions warrant, our actual capital expenditures for 2008 may exceed the budgeted amounts. We believe cash generated from operations combined with other sources of liquidity previously described will be sufficient to fund our capital expenditures in 2008.

Long-Term Contractual Obligations

6.875% and 6.05% Senior Notes

On March 18, 2003, NuStar Logistics issued $250 million of 6.05% senior notes, maturing in 2013, with interest payable semi-annually in arrears on March 15 and September 15 of each year.

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On July 15, 2002, NuStar Logistics issued $100.0 million of 6.875% senior notes, maturing in 2012, with interest payable semi-annually in arrears on January 15 and July 15 of each year.

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

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

Due to the completed sale of Valero Energy’s remaining interests in NuStar GP Holdings on December 22, 2006, the change-in-control provision was triggered, and NuStar Logistics offered to purchase the senior notes at a price equal to 100% of their outstanding principal balance plus accrued interest through the date of purchase. This offer expired on January 23, 2007, with approximately $20.1 million of the 6.05% senior notes tendered to us for repurchase. We retired the senior notes that were tendered with borrowings under our $600 million revolving credit agreement on February 1, 2007. The retirement of those senior notes did not significantly affect either our financial position or results of operations.

7.75% and 5.875% Senior Notes

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

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

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

The senior notes issued by NuStar Logistics are fully and unconditionally guaranteed by NuStar Energy. In connection with the Kaneb Acquisition, NuStar Energy fully and unconditionally guaranteed the outstanding senior notes issued by KPOP. Additionally, effective July 1, 2005, both NuStar Logistics and KPOP fully and unconditionally guaranteed the outstanding senior notes of the other.

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2007 Revolving Credit Agreement

On December 10, 2007, NuStar Logistics replaced the existing $600 million revolving credit agreement with the $1.25 billion five-year revolving credit agreement (the 2007 Revolving Credit Agreement), which includes a Euro sub-limit of $250 million. 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 (Revolving Credit Agreement) and $525 million term loan agreement (Term Loan Agreement). Obligations under the 2007 Revolving Credit Agreement are guaranteed by NuStar Energy and KPOP. KPOP will be released from its guarantee of the 2007 Revolving Credit Agreement when it no longer guarantees NuStar Logistics public debt instruments.

As of December 31, 2007, we had $720.8 million available for borrowing under the 2007 Revolving Credit Agreement. The 2007 Revolving Credit Agreement bears interest based on either an alternative base rate or a LIBOR based rate, which was 5.7% as of December 31, 2007. The weighted-average interest rate related to outstanding borrowings under the 2007 Revolving Credit Agreement for the year ended December 31, 2007 was 5.7%.

The 2007 Revolving Credit Agreement requires that we maintain certain financial ratios and includes other restrictive covenants, including a prohibition on distributions if any defaults, as defined in the agreements, exist or would result from the distribution. The 2007 Revolving Credit Agreement also requires us to maintain, as of the end of each rolling period, consisting of any period of four consecutive fiscal quarters, a consolidated debt coverage ratio (consolidated indebtedness to consolidated EBITDA, as defined in the 2007 Revolving Credit Agreement) not to exceed 5.00-to-1.00; provided, that if at any time NuStar Energy or any of its restricted subsidiaries consummates an acquisition for an aggregate net consideration of at least $100 million, then for two rolling periods, the last day of which immediately follows the day on which such acquisition is consummated, the consolidated debt coverage ratio must not exceed 5.50-to-1.00. Management believes that we are in compliance with all ratios and covenants of the 2007 Revolving Credit Agreement as of December 31, 2007.

Term Loan Agreement

On July 1, 2005, we entered into the Term Loan Agreement, the majority of which was used to fund the Kaneb Acquisition. The weighted-average interest rate related to outstanding borrowings under the Term Loan Agreement for the year ended December 31, 2007 was 6.0%. The $225.0 million balance on the Term Loan Agreement was paid in full on December 10, 2007 with the proceeds from the 2007 Revolving Credit Agreement.

Revolving Credit Agreement

On July 1, 2005, we entered into the Revolving Credit Agreement. The weighted-average interest rate related to outstanding borrowings under the Revolving Credit Agreement for the year ended December 31, 2007 was 5.7%. The $303.4 million balance on the Revolving Credit Agreement was paid in full on December 10, 2007 with the proceeds from the 2007 Revolving Credit Agreement.

UK Term Loan

KPOP’s UK subsidiary, Kaneb Terminals Limited, is the borrower of £21 million ($41.6 million and $41.1 million as of December 31, 2007 and 2006, respectively). This amended and restated term loan agreement (the UK Term Loan) bears interest at 6.65% annually and matures on December 11, 2012.

In December 2007, the UK Term Loan was amended to be consistent with the covenants and provisions of the 2007 Revolving Credit Agreement. Management believes that we are in compliance with all ratios and covenants of the UK Term Loan as of December 31, 2007.

Port Authority of Corpus Christi Note Payable

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

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Interest Rate Swaps

We are party to certain interest rate swap agreements to manage our exposure to changes in interest rates. The interest rate swap agreements have an aggregate notional amount of $167.5 million, of which $60.0 million is tied to the maturity of the 6.875% senior notes and $107.5 million is tied to the maturity of the 6.05% senior notes. Under the terms of the interest rate swap agreements, we will receive a fixed rate (6.875% and 6.05% for the $60.0 million and $107.5 million of interest rate swap agreements, respectively) and will pay a variable rate based on LIBOR plus a percentage that varies with each agreement. The aggregate estimated fair value of the interest rate swaps included in the consolidated balance sheet was $2.2 million included in deferred charges and other assets, net as of December 31, 2007 and $4.9 million included in other long-term liabilities as of December 31, 2006.

The interest rate swap contracts qualify for the shortcut method of accounting prescribed by SFAS 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended (SFAS 133). As a result, changes in the fair value of the swaps will completely offset the changes in the fair value of the underlying hedged debt. As of December 31, 2007 and 2006, the weighted average effective interest rate for the interest rate swaps was 6.1% and 7.1%, respectively.

The following table presents our long-term contractual obligations and commitments and the related payments due, in total and by period, as of December 31, 2007.

|  | Payments Due by Period |  |  |  |
|  | 2008 |  | 2009 |  | 2010 |  | 2011 |  | 2012 |  | Thereafter |  | Total
|  | (Thousands of Dollars)
Long-term debt (stated maturities) |  | $ | 663 |  | $ | 713 |  | $ | 770 |  | $ | 832 |  | $ | 920,503 |  | $ | 482,163 |  | $ | 1,405,644
Operating leases |  |  | 11,034 |  |  | 7,650 |  |  | 7,099 |  |  | 6,557 |  |  | 6,394 |  |  | 102,368 |  |  | 141,102
Purchase obligations |  |  | 544,294 |  |  | 110,953 |  |  | 7,069 |  |  | 968 |  |  | 962 |  |  | 1,523 |  |  | 665,769

A purchase obligation is an enforceable and legally binding agreement to purchase goods or services that specifies significant terms, including (i) fixed or minimum quantities to be purchased, (ii) fixed, minimum or variable price provisions, and (iii) the approximate timing of the transaction. Our purchase obligations primarily relate to purchases of inventory for resale to our customers.

We do not have any long-term contractual obligations related to our investment in joint ventures, other than the requirement to operate the joint ventures on behalf of the members and to fund our 50% share of capital expenditures as they arise.

Related Party Transactions

Our operations are managed by the general partner of our general partner, NuStar GP, LLC. The employees of NuStar GP, LLC perform services for our U.S. operations. Certain of our wholly owned subsidiaries employ persons who perform services for our international operations. We reimburse NuStar GP, LLC for all costs related to its employees. We had a receivable of $0.8 million and a payable of $2.3 million, as of December 31, 2007 and December 31, 2006, respectively, to our general partner, with both amounts representing payroll and plan benefits, net of payments made by us. We also had a long-term payable as of December 31, 2007 and 2006 of $5.7 million to our general partner related to amounts payable for retiree medical benefits and other post-employment benefits.

Prior to December 22, 2006, Valero Energy controlled our general partner. We have transactions with Valero Energy for pipeline tariff, terminalling fee and crude oil storage tank fee revenues, certain employee costs, insurance costs, administrative costs and lease expense, which were reported as related party transactions in the consolidated statement of income. Due to Valero Energy’s sale of its interest in NuStar GP Holdings on December 22, 2006, we ceased reporting transactions with Valero Energy as related party transactions subsequent to that date.

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The following table summarizes information pertaining to related party transactions with NuStar GP, LLC for the year ended December 31, 2007 and with Valero Energy for the years ended December 31, 2006 and 2005:

|  | Year Ended December 31,
|  | 2007 |  | 2006 |  | 2005 (a)
|  | (Thousands of Dollars)
Revenues |  | $ | — |  | $ | 260,980 |  | $ | 234,485
Operating expenses |  |  | 93,211 |  |  | 94,587 |  |  | 60,921
General and administrative expenses |  |  | 37,702 |  |  | 32,183 |  |  | 19,356

(a) | The amounts reflected in the table include revenues and operating expenses of $1,867 and $1,850, respectively, which are included in income from discontinued operations in the consolidated statement of income.

Agreements with NuStar GP Holdings

Non-Compete Agreement

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

Agreements with Valero Energy

We have entered into a number of operating agreements with Valero Energy, which govern the required services provided to and received from Valero Energy. Most of the operating agreements include adjustment provisions, which allow us to increase the handling, storage and throughput fees we charge to Valero Energy based on a consumer price index. In addition, the pipeline tariffs charged by us are reviewed annually and adjusted based on an inflation index and may also be adjusted to take into consideration additional costs incurred to provide the transportation services. The following is a summary of the significant terms of the individual agreements.

Services Agreement

Prior to our separation from Valero Energy, the employees of NuStar GP, LLC were provided to us under the terms of various services agreements between us and Valero Energy. The terms of these services agreements generally provided that the costs of employees who performed services directly on our behalf, including salaries, wages and employee benefits, were charged directly to us. In addition, Valero Energy charged us a net administrative services fee, which was $1.8 million and $6.6 million for the years ended December 31, 2006 and 2005, respectively.

Although Valero Energy no longer provided employees to work directly on our behalf, Valero Energy continued to provide certain services to us under the terms of a services agreement dated December 22, 2006 (the 2007 Services Agreement). Under the 2007 Services Agreement, we paid Valero Energy approximately $1.1 million for the year ended December 31, 2007 for administrative services (primarily information system services and human resource services) and telecommunication services.

On April 16, 2007, Valero Energy exercised its option to terminate the 2007 Services Agreement. As a result, Valero Energy paid us a termination fee of $13.0 million in May 2007 in accordance with the terms of the 2007 Services Agreement. However, Valero Energy continued providing certain services over a period of time sufficient to allow us to assume those functions by the end of 2007.

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Omnibus Agreement

On March 31, 2006, we entered into an amended and restated omnibus agreement (the 2006 Omnibus Agreement) with Valero Energy, NuStar GP, LLC, Riverwalk Logistics, L.P., and NuStar Logistics. The 2006 Omnibus Agreement superseded the Omnibus Agreement among the parties dated effective April 16, 2001. The 2006 Omnibus Agreement governed potential competition between Valero Energy and us.

With the closing of Valero GP Holding’s secondary public offering on December 22, 2006, Valero Energy ceased to own 20% or more of us, which allows Valero Energy to compete with us.

Also under the 2006 Omnibus Agreement, Valero Energy agreed to indemnify us for environmental liabilities related to the assets transferred to us in connection with our initial public offering, provided that such liabilities arose prior to and are discovered within ten years after that date (excluding liabilities resulting from a change in law after April 16, 2001).

Pipelines and Terminals Usage Agreement—McKee, Three Rivers and Ardmore

Under the terms of the Pipelines and Terminals Usage Agreement dated April 16, 2001, we provide transportation services that support Valero Energy’s refining and marketing operations relating to the McKee, Three Rivers and Ardmore refineries. Pursuant to the agreement, Valero Energy has agreed through April 2008:

| • |  | to transport in our crude oil pipelines at least 75% of the aggregate volumes of crude oil shipped to the McKee, Three Rivers and Ardmore refineries;

| • |  | to transport in our refined product pipelines at least 75% of the aggregate volumes of refined products shipped from the McKee, Three Rivers and Ardmore refineries; and

| • |  | to use our refined product terminals for terminalling services for at least 50% of all refined products shipped from the McKee, Three Rivers and Ardmore refineries.

If market conditions change with respect to the transportation of crude oil or refined products, or to the end markets in which Valero Energy sells refined products, 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 that serve the McKee, Three Rivers and Ardmore refineries 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.

In the event Valero Energy does not transport in our pipelines or use our terminals to handle the minimum volume requirements and if its obligation has not been suspended under the terms of the agreement, Valero Energy will be required to make a cash payment determined by multiplying the shortfall in volume by the applicable weighted average pipeline tariff or terminal fee. For the years ended December 31, 2007, 2005 and 2004, Valero Energy exceeded its obligations under the Pipelines and Terminals Usage Agreement. Additionally, Valero Energy has agreed not to challenge, or cause others to challenge, our interstate or intrastate tariffs for the transportation of crude oil and refined products until at least April 2008.

Crude Oil Storage Tank Agreements

In conjunction with the acquisition of the Crude Oil Storage Tanks in March 2003, we entered into the following agreements with Valero Energy:

| • |  | Handling and Throughput Agreement, dated March 2003, pursuant to which Valero Energy agreed to pay us a fee for 100% of crude oil and certain other feedstocks delivered to each of the Corpus Christi West refinery, the Texas City refinery and the Benicia refinery and to use our logistic assets for handling all deliveries to these refineries. The throughput fees are adjustable annually, generally based on 75% of the regional consumer price index applicable to the location of each refinery. The initial term of the handling and throughput agreement is ten years, which may be extended by Valero Energy for up to an additional five years.

| • |  | Services and Secondment Agreements, dated March 2003, pursuant to which Valero Energy agreed to provide personnel to us who perform operating and routine maintenance services related to the crude oil storage tank operations. The annual reimbursement for those services is an aggregate $3.5 million. The initial term of the services and secondment agreements is ten years, which we may extend for an additional five years. In addition to the fees we have agreed to pay Valero Energy under the services and secondment agreements, we are responsible for operating expenses and specified capital expenditures related to the tank assets that are not addressed in the services and secondment agreements. These operating expenses and capital expenditures include tank safety inspections, maintenance and repairs, certain environmental expenses, insurance premiums and ad valorem taxes.

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| • |  | Lease and Access Agreements, dated March 2003, pursuant to which Valero Energy leases to us the land on which the crude oil storage tanks are located for an aggregate amount of $0.7 million per year. The initial term of each lease is 25 years, subject to automatic renewal for successive one-year periods thereafter. We may terminate any of these leases upon 30 days notice after the initial term or at the end of a renewal period. In addition, we may terminate any of these leases upon 180 days notice prior to the expiration of the current term if we cease to operate the crude oil storage tanks or cease business operations.

South Texas Pipelines and Terminals Agreements

In conjunction with the acquisition of the South Texas Pipelines and Terminals in March 2003, we entered into the following agreements with Valero Energy:

| • |  | Terminalling Agreement, dated March 2003, pursuant to which Valero Energy agreed, during the initial period of five years, to pay a terminalling fee for each barrel of refined product stored or handled by or on behalf of Valero Energy at the terminals, including an additive fee for gasoline additive blended at the terminals. At the Houston Hobby Airport terminal, Valero Energy agreed to pay a filtering fee for each barrel of jet fuel stored or handled at the terminal.

| • |  | Throughput Commitment Agreement, dated March 2003, pursuant to which Valero Energy agreed, for an initial period of seven years:

| - |  | to transport in the Houston and Valley pipeline systems an aggregate of 40% of the Corpus Christi refineries’ gasoline and distillate production but only if the combined throughput in these pipelines is less than 110,000 barrels per day;

| - |  | to transport in the Pettus to San Antonio refined product pipeline 25% of the Three Rivers refinery gasoline and distillate production and in the Pettus to Corpus Christi refined product pipeline 90% of the Three Rivers refinery raffinate production;

| - |  | to use the Houston asphalt terminal for an aggregate of 7% of the asphalt production of the Corpus Christi refineries;

| - |  | to use the Edinburg refined product terminal for an aggregate of 7% of the gasoline and distillate production of the Corpus Christi refineries, but only if the throughput at this terminal is less than 20,000 barrels per day; and

| - |  | to use the San Antonio East terminal for 75% of the throughput in the Pettus to San Antonio refined product pipeline.

In the event Valero Energy does not transport in our pipelines or use our terminals to handle the minimum volume requirements and if its obligation has not been suspended under the terms of the agreement, Valero Energy will be required to make a cash payment determined by multiplying the shortfall in volume by the applicable weighted average pipeline tariff or terminal fee. Valero Energy’s obligation to transport 90% of the Three Rivers refinery raffinate production in the Pettus to Corpus Christi refined product pipeline was suspended in the fourth quarter of 2005 due to the temporary idling of the pipeline in the fourth quarter of 2005.

St. James Terminalling Agreement

On December 1, 2006, we executed a terminal services agreement with Valero Energy for the St. James, Louisiana crude oil facility (the St. James Terminal Agreement). Pursuant to the St. James Terminal Agreement, we will provide crude oil storage and blending services to Valero Energy for a minimum throughput fee of $1.175 million per month, plus $0.08 per barrel throughput in excess of 4 million barrels per month and $0.03 per barrel blended. The St. James Terminal Agreement has an initial term of five years, with an option to extend for an additional five years, provided that Valero Energy provides notice of its intent to extend the term at least one year prior to the expiration of the initial term.

Corpus Christi North Beach Storage Facility

Effective January 1, 2007, we entered into a one-year terminal service agreement with Valero Energy for the 1.6 million barrels of capacity at our Corpus Christi North Beach storage facility. This agreement automatically renewed from year-to-year until either party elected to terminate upon 90-days written notice. This agreement was terminated on December 31, 2007.

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We entered into a five-year shell barrel capacity lease agreement with Valero Energy on January 1, 2008 for the 1.6 million barrels of capacity at our Corpus Christi North Beach storage facility for $0.56 million per month. This lease automatically renews for additional one-year terms after the initial term unless either party terminates it with a 90-day written notice. Pursuant to this agreement, Valero Energy has agreed to maintain an annual average throughput of at least 70,000 barrels per day. In the event Valero Energy does not maintain the minimum guaranteed annual volume, Valero Energy will be required to make a cash payment determined by multiplying the shortfall in volume by a per barrel rate.

Other Agreements

We have other minor storage and throughput contracts with Valero Energy.

Environmental, Health and Safety

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

The balance of and changes in our accruals for environmental matters as of and for the years ended December 31, 2007, 2006 and 2005 are included in Note 11 of Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplemental Data.” We believe that we have adequately accrued for our environmental exposures.

Other Contingencies

We are subject to certain loss contingencies, the outcome of which could have an effect on our cash flows and results of operations. Specifically, we may be required to make substantial payments to the U.S. Department of Justice for certain remediation costs as further disclosed in Note 12 of the Notes to Consolidated Financial Statements.

CRITICAL ACCOUNTING POLICIES

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

Depreciation

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

Impairment of Long-Lived Assets and Goodwill

We test long-lived assets for recoverability whenever events or changes in circumstances indicate that the carrying amount of the asset may not be recoverable. Goodwill must be tested for impairment annually or more frequently if events or changes in circumstances indicate that the related asset might be impaired. An impairment loss should be recognized only if the carrying amount of the asset/goodwill is not recoverable and exceeds its fair value.

In order to test for recoverability, management must make estimates of projected cash flows related to the asset which include, but are not limited to, assumptions about the use or disposition of the asset, estimated remaining life of the asset, and future expenditures necessary to maintain the asset’s existing service potential. In order to determine fair value, management must make certain estimates and assumptions including, among other things, an assessment of market conditions, projected cash flows, investment rates, interest/equity rates and growth rates, that could significantly impact the fair value of the long-lived asset or goodwill. Due to the subjectivity of the assumptions used to test for recoverability and to determine fair value, significant impairment charges could result in the future, thus affecting our future reported net income.

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Asset Retirement Obligations

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

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

We also have legal obligations in the form of leases and right of way agreements, which require us to remove certain of our assets upon termination of the agreement. However, these lease or right of way agreements generally contain automatic renewal provisions that extend our rights indefinitely or we have other legal means available to extend our rights. We have recorded a liability of approximately $0.8 million and $2.0 million as of December 31, 2007 and 2006, respectively, which is included in other long-term liabilities on the consolidated balance sheet, for conditional asset retirement obligations related to the retirement of terminal assets with lease and right of way agreements. Prior to 2006, we had not recorded a liability for asset retirement obligations.

Environmental Reserve

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

Contingencies

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

Derivative Financial Instruments

We are party to certain interest rate swap agreements for the purpose of hedging the interest rate risk associated with a portion of our fixed-rate senior notes. We account for the interest rate swaps as fair value hedges and recognize the fair value of each interest rate swap in the consolidated balance sheet as either an asset or liability. The interest rate swap contracts qualify for the shortcut method of accounting prescribed by SFAS 133. As a result, changes in the fair value of the derivatives will completely offset the changes in the fair value of the underlying hedged debt.

Since the operations of our marketing segment expose us to commodity price risk, we enter into derivatives instruments to mitigate the effect of commodity price fluctuations. The derivative instruments we use consist primarily of futures contracts and swaps traded on the NYMEX.

Derivative instruments designated and qualifying as fair value hedges under Statement of Financial Accounting Standards No. 133 (SFAS 133) (Fair Value Hedges) are recorded in the consolidated balance sheet at fair value with mark-to-market

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adjustments recorded in cost of sales. The offsetting gain or loss on the associated hedged physical inventory is recognized concurrently in cost of sales. We record derivative instruments that do not qualify for hedge accounting under SFAS 133 (Economic Hedges) in the consolidated balance sheet at fair value with mark-to-market adjustments recorded in cost of sales. The market fluctuations in inventory are not recognized until the physical sale takes place. Fair value is based on quoted market prices.

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 these derivatives in the consolidated balance sheet at fair value with mark-to-market adjustments recorded in revenues.

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ITEM 7A. | QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Interest Rate Risk

We manage our debt considering various financing alternatives available in the market and we manage our exposure to changing interest rates principally through the use of a combination of fixed-rate debt and variable-rate debt. In addition, we utilize interest rate swap agreements to manage a portion of the exposure to changing interest rates by converting certain fixed-rate debt to variable-rate debt. Borrowings under the 2007 Revolving Credit Agreement expose us to increases in the benchmark interest rate underlying these variable rate debt instruments.

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

|  | December 31, 2007 |
|  | Expected Maturity Dates |  |  |  |  |  |  |
|  | 2008 |  |  | 2009 |  |  | 2010 |  |  | 2011 |  |  | 2012 |  |  | Thereafter |  |  | Total |  |  | Fair Value |
|  | (Thousands of Dollars, Except Interest Rates) |
Long-term Debt: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Fixed rate |  | $ | 663 |  |  | $ | 713 |  |  | $ | 770 |  |  | $ | 832 |  |  | $ | 392,527 |  |  | $ | 482,163 |  |  | $ | 877,668 |  |  | $ | 927,234 |
Average interest rate |  |  | 8.0 | % |  |  | 8.0 | % |  |  | 8.0 | % |  |  | 8.0 | % |  |  | 7.4 | % |  |  | 6.0 | % |  |  | 6.6 | % |  |  |  |
Variable rate |  | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | 527,976 |  |  | $ | — |  |  | $ | 527,976 |  |  | $ | 527,976 |
Average interest rate |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 5.7 | % |  |  | — |  |  |  | 5.7 | % |  |  |  |
Interest Rate Swaps Fixed to Variable: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Notional amount |  | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | 60,000 |  |  | $ | 107,500 |  |  | $ | 167,500 |  |  | $ | 2,232 |
Average pay rate |  |  | 5.3 | % |  |  | 5.6 | % |  |  | 6.1 | % |  |  | 6.4 | % |  |  | 6.7 | % |  |  | 6.5 | % |  |  | 6.1 | % |  |  |  |
Average receive rate |  |  | 6.3 | % |  |  | 6.3 | % |  |  | 6.3 | % |  |  | 6.3 | % |  |  | 6.3 | % |  |  | 6.1 | % |  |  | 6.3 | % |  |  |  |
|  | December 31, 2006 |
|  | Expected Maturity Dates |  |  | Total |  |  | Fair Value |
|  | 2007 |  |  | 2008 |  |  | 2009 |  |  | 2010 |  |  | 2011 |  |  | Thereafter |  |  |
|  | (Thousands of Dollars, Except Interest Rates) |
Long-term Debt: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Fixed rate |  | $ | 647 |  |  | $ | 660 |  |  | $ | 713 |  |  | $ | 770 |  |  | $ | 41,950 |  |  | $ | 854,049 |  |  | $ | 898,789 |  |  | $ | 939,191 |
Average interest rate |  |  | 8.0 | % |  |  | 8.0 | % |  |  | 8.0 | % |  |  | 8.0 | % |  |  | 6.7 | % |  |  | 6.6 | % |  |  | 6.6 | % |  |  |  |
Variable rate |  | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | 415,526 |  |  | $ | — |  |  | $ | 415,526 |  |  | $ | 415,526 |
Average interest rate |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 6.1 | % |  |  | — |  |  |  | 6.1 | % |  |  |  |
Interest Rate Swaps Fixed to Variable: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Notional amount |  | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | 167,500 |  |  | $ | 167,500 |  |  | $ | (4,908 | )
Average pay rate |  |  | 7.0 | % |  |  | 6.7 | % |  |  | 6.7 | % |  |  | 6.8 | % |  |  | 6.9 | % |  |  | 6.8 | % |  |  | 6.8 | % |  |  |  |
Average receive rate |  |  | 6.3 | % |  |  | 6.3 | % |  |  | 6.3 | % |  |  | 6.3 | % |  |  | 6.3 | % |  |  | 6.2 | % |  |  | 6.3 | % |  |  |  |

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Commodity Price Risk

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. The derivative instruments we use consist primarily of futures contracts and swaps traded on the NYMEX.

We have a risk management group that has direct oversight responsibilities for our risk policies and our trading controls and procedures and certain aspects of risk management. Our risk management group also approves all new risk management strategies through a formal process.

Derivative instruments designated and qualifying as fair value hedges under Statement of Financial Accounting Standards No. 133 (SFAS 133) (Fair Value Hedges) are recorded in the consolidated balance sheet at fair value with mark-to-market adjustments recorded in cost of sales. The offsetting gain or loss on the associated hedged physical inventory is recognized concurrently in cost of sales. We record derivative instruments that do not qualify for hedge accounting under SFAS 133 (Economic Hedges) in the consolidated balance sheet at fair value with mark-to-market adjustments recorded in cost of sales. The market fluctuations in inventory are not recognized until the physical sale takes place. Fair value is based on quoted market prices.

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 these derivatives in the consolidated balance sheet at fair value with mark-to-market adjustments recorded in revenues.

The following table provides information about our derivative instruments:

|  | December 31, 2007 |
|  | Contract Volumes |  | Weighted Average |  | Fair Value of Current Asset (Liability) |
|  | Pay Price |  | Receive Price |
|  | (Thousands of Barrels) |  |  |  |  |  | (Thousands of Dollars) |
Fair Value Hedges: |  |  |  |  |  |  |  |  |  |  |  |
Futures – long: |  |  |  |  |  |  |  |  |  |  |  |
(refined products) |  | 68 |  | $ | 104.26 |  |  | N/A |  | $ | 460 |
Futures – short: |  |  |  |  |  |  |  |  |  |  |  |
(refined products) |  | 287 |  |  | N/A |  | $ | 103.78 |  |  | (1,942 | )
Economic Hedges: |  |  |  |  |  |  |  |  |  |  |  |
Futures – long: |  |  |  |  |  |  |  |  |  |  |  |
(refined products) |  | 60 |  | $ | 104.44 |  |  | N/A |  |  | 392 |
Futures – short: |  |  |  |  |  |  |  |  |  |  |  |
(crude oil and refined products) |  | 459 |  |  | N/A |  | $ | 99.01 |  |  | (3,001 | )
Total fair value of open positions |  |  |  |  |  |  |  |  |  | $ | (4,091 | )

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ITEM 8. | FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Management’s Report on Internal Control over Financial Reporting

Our management is responsible for establishing and maintaining effective internal control over financial reporting as defined in Rule 13a-15(f) under the Securities Exchange Act of 1934. Our management assessed the effectiveness of NuStar Energy L.P’s internal control over financial reporting as of December 31, 2007. In its evaluation, management used the criteria set forth by the Committee of Sponsoring Organization of the Treadway Commission (COSO) in Internal Control-Integrated Framework. Based on this assessment, management believes that, as of December 31, 2007, our internal control over financial reporting was effective based on those criteria.

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

The effectiveness of internal control over financial reporting as of December 31, 2007 has been audited by KPMG, the independent registered public accounting firm who audited our consolidated financial statements included in this Form 10-K. KPMG’s attestation on the effectiveness of our internal control over financial reporting appears on page 68.

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Report of Independent Registered Public Accounting Firm

The Board of Directors of NuStar GP, LLC

and Unitholders of NuStar Energy L.P.:

We have audited the accompanying consolidated balance sheets of NuStar Energy L.P. and subsidiaries (a Delaware limited partnership) (the Partnership) as of December 31, 2007 and 2006, and the related consolidated statements of income, partners’ equity and cash flows for each of the years in the three-year period ended December 31, 2007. These consolidated financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

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

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of NuStar Energy L.P. and subsidiaries as of December 31, 2007 and 2006, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2007, in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), NuStar Energy L.P.’s internal control over financial reporting as of December 31, 2007, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated February 28, 2008 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.

|  |  |  | /s/ KPMG LLP
San Antonio, Texas |  |  |  |
February 28, 2008 |  |  |  |

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Report of Independent Registered Public Accounting Firm

The Board of Directors of NuStar GP, LLC

and Unitholders of NuStar Energy L.P.:

We have audited NuStar Energy L.P. and subsidiaries (a Delaware limited partnership) (the Partnership) internal control over financial reporting as of December 31, 2007, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Partnership’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Partnership’s internal control over financial reporting based on our audit.

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

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

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

In our opinion, NuStar Energy L.P. and subsidiaries maintained, in all material respects, effective internal control over financial reporting as of December 31, 2007, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of NuStar Energy L.P. as of December 31, 2007 and 2006, and the related consolidated statements of operations, partners’ equity and cash flows for each of the years in the three-year period ended December 31, 2007, and our report dated February 28, 2008 expressed an unqualified opinion on those consolidated financial statements.

/S/ KPMG LLP

San Antonio, Texas

February 28, 2008

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NUSTAR ENERGY L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Thousands of Dollars, Except Unit Data)

|  | December 31, |
|  | 2007 |  |  | 2006 |
Assets |  |  |  |  |  |  |  |
Current assets: |  |  |  |  |  |  |  |
Cash and cash equivalents |  | $ | 89,838 |  |  | $ | 68,838 |
Accounts receivable, net of allowance for doubtful accounts of $365 and $1,220 as of December 31, 2007 and 2006, respectively |  |  | 130,354 |  |  |  | 105,976 |
Receivable from related party |  |  | 786 |  |  |  | — |
Inventories |  |  | 88,532 |  |  |  | 16,979 |
Other current assets |  |  | 37,624 |  |  |  | 21,205 |
Total current assets |  |  | 347,134 |  |  |  | 212,998 |
Property and equipment, at cost |  |  | 2,944,116 |  |  |  | 2,694,358 |
Accumulated depreciation and amortization |  |  | (452,030 | ) |  |  | (349,223 | )
Property and equipment, net |  |  | 2,492,086 |  |  |  | 2,345,135 |
Intangible assets, net |  |  | 47,762 |  |  |  | 53,532 |
Goodwill |  |  | 785,019 |  |  |  | 774,441 |
Investment in joint ventures |  |  | 80,366 |  |  |  | 74,077 |
Deferred income tax asset |  |  | 10,622 |  |  |  | 11,342 |
Deferred charges and other assets, net |  |  | 20,098 |  |  |  | 22,683 |
Total assets |  | $ | 3,783,087 |  |  | $ | 3,494,208 |
Liabilities and Partners’ Equity |  |  |  |  |  |  |  |
Current liabilities: |  |  |  |  |  |  |  |
Current portion of long-term debt |  | $ | 663 |  |  | $ | 647 |
Payable to related party |  |  | — |  |  |  | 2,315 |
Accounts payable |  |  | 163,309 |  |  |  | 86,307 |
Accrued interest payable |  |  | 17,725 |  |  |  | 17,528 |
Accrued liabilities |  |  | 47,189 |  |  |  | 37,651 |
Taxes other than income taxes |  |  | 10,157 |  |  |  | 10,219 |
Income taxes payable |  |  | 3,442 |  |  |  | 2,068 |
Total current liabilities |  |  | 242,485 |  |  |  | 156,735 |
Long-term debt, less current portion |  |  | 1,445,626 |  |  |  | 1,353,720 |
Long-term payable to related party |  |  | 5,684 |  |  |  | 5,749 |
Deferred income tax liability |  |  | 34,196 |  |  |  | 32,926 |
Other long-term liabilities |  |  | 60,264 |  |  |  | 69,397 |
Commitments and contingencies (Note 12) |  |  |  |  |  |  |  |
Partners’ equity: |  |  |  |  |  |  |  |
Limited partners (49,409,749 and 46,809,749 common units outstanding as of December 31, 2007 and 2006, respectively) |  |  | 1,926,126 |  |  |  | 1,830,047 |
General partner |  |  | 41,819 |  |  |  | 38,815 |
Accumulated other comprehensive income |  |  | 26,887 |  |  |  | 6,819 |
Total partners’ equity |  |  | 1,994,832 |  |  |  | 1,875,681 |
Total liabilities and partners’ equity |  | $ | 3,783,087 |  |  | $ | 3,494,208 |

See Notes to Consolidated Financial Statements.

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NUSTAR ENERGY L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

(Thousands of Dollars, Except Unit and Per Unit Data)

|  | Year Ended December 31, |
|  | 2007 |  |  | 2006 |  |  | 2005 |
Revenues: |  |  |  |  |  |  |  |  |  |  |  |
Services revenues: |  |  |  |  |  |  |  |  |  |  |  |
Third parties |  | $ | 696,623 |  |  | $ | 375,174 |  |  | $ | 190,439 |
Related party |  |  | — |  |  |  | 260,980 |  |  |  | 232,618 |
Total services revenues |  |  | 696,623 |  |  |  | 636,154 |  |  |  | 423,057 |
Product sales |  |  | 778,391 |  |  |  | 501,107 |  |  |  | 236,500 |
Total revenues |  |  | 1,475,014 |  |  |  | 1,137,261 |  |  |  | 659,557 |
Costs and expenses: |  |  |  |  |  |  |  |  |  |  |  |
Cost of product sales |  |  | 742,972 |  |  |  | 466,276 |  |  |  | 229,806 |
Operating expenses: |  |  |  |  |  |  |  |  |  |  |  |
Third parties |  |  | 264,024 |  |  |  | 218,017 |  |  |  | 126,280 |
Related party |  |  | 93,211 |  |  |  | 94,587 |  |  |  | 59,071 |
Total operating expenses |  |  | 357,235 |  |  |  | 312,604 |  |  |  | 185,351 |
General and administrative expenses: |  |  |  |  |  |  |  |  |  |  |  |
Third parties |  |  | 30,213 |  |  |  | 13,033 |  |  |  | 7,197 |
Related party |  |  | 37,702 |  |  |  | 32,183 |  |  |  | 19,356 |
Total general and administrative expenses |  |  | 67,915 |  |  |  | 45,216 |  |  |  | 26,553 |
Depreciation and amortization expense |  |  | 114,293 |  |  |  | 100,266 |  |  |  | 64,895 |
Total costs and expenses |  |  | 1,282,415 |  |  |  | 924,362 |  |  |  | 506,605 |
Operating income |  |  | 192,599 |  |  |  | 212,899 |  |  |  | 152,952 |
Equity earnings from joint ventures |  |  | 6,833 |  |  |  | 5,882 |  |  |  | 2,319 |
Interest expense, net |  |  | (76,516 | ) |  |  | (66,266 | ) |  |  | (41,388 | )
Other income (expense), net |  |  | 38,830 |  |  |  | 3,252 |  |  |  | (1,495 | )
Income from continuing operations before income tax expense |  |  | 161,746 |  |  |  | 155,767 |  |  |  | 112,388 |
Income tax expense |  |  | 11,448 |  |  |  | 5,861 |  |  |  | 4,713 |
Income from continuing operations |  |  | 150,298 |  |  |  | 149,906 |  |  |  | 107,675 |
Income (loss) from discontinued operations, net of income tax |  |  | — |  |  |  | (376 | ) |  |  | 3,398 |
Net income |  |  | 150,298 |  |  |  | 149,530 |  |  |  | 111,073 |
Less net income applicable to general partner |  |  | (21,063 | ) |  |  | (16,910 | ) |  |  | (10,758 | )
Net income applicable to limited partners |  | $ | 129,235 |  |  | $ | 132,620 |  |  | $ | 100,315 |
Income (loss) per unit applicable to limited partners: |  |  |  |  |  |  |  |  |  |  |  |
Continuing operations |  | $ | 2.74 |  |  | $ | 2.84 |  |  | $ | 2.76 |
Discontinued operations |  |  | — |  |  |  | (0.01 | ) |  |  | 0.10 |
Net income |  | $ | 2.74 |  |  | $ | 2.83 |  |  | $ | 2.86 |
Weighted average number of basic units outstanding |  |  | 47,158,790 |  |  |  | 46,809,749 |  |  |  | 35,023,250 |

See Notes to Consolidated Financial Statements.

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NUSTAR ENERGY L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Thousands of Dollars)

|  | Year Ended December 31, |
|  | 2007 |  |  | 2006 |  |  | 2005 |
Cash Flows from Operating Activities: |  |  |  |  |  |  |  |  |  |  |  |
Net income |  | $ | 150,298 |  |  | $ | 149,530 |  |  | $ | 111,073 |
Adjustments to reconcile net income to net cash provided by operating activities: |  |  |  |  |  |  |  |  |  |  |  |
Depreciation and amortization expense |  |  | 114,293 |  |  |  | 100,266 |  |  |  | 66,667 |
Amortization of debt related items |  |  | (5,516 | ) |  |  | (5,210 | ) |  |  | (2,669 | )
Other non-cash gains |  |  | (8,356 | ) |  |  | (388 | ) |  |  | 2,161 |
Provision (benefit) for deferred income taxes |  |  | 276 |  |  |  | (74 | ) |  |  | 4,283 |
Equity earnings from joint ventures |  |  | (6,833 | ) |  |  | (5,969 | ) |  |  | (2,499 | )
Distributions of equity earnings from joint ventures |  |  | 544 |  |  |  | 5,155 |  |  |  | 2,499 |
Changes in current assets and liabilities (Note 17) |  |  | (21,326 | ) |  |  | 10,695 |  |  |  | 64 |
Other, net |  |  | (708 | ) |  |  | (3,194 | ) |  |  | 4,851 |
Net cash provided by operating activities |  |  | 222,672 |  |  |  | 250,811 |  |  |  | 186,430 |
Cash Flows from Investing Activities: |  |  |  |  |  |  |  |  |  |  |  |
Reliability capital expenditures |  |  | (40,333 | ) |  |  | (33,952 | ) |  |  | (23,707 | )
Strategic and other capital expenditures |  |  | (210,918 | ) |  |  | (90,070 | ) |  |  | (44,379 | )
Kaneb acquisition, net of cash acquired |  |  | — |  |  |  | — |  |  |  | (500,973 | )
Other acquisitions |  |  | — |  |  |  | (154,474 | ) |  |  | — |
Investment in other noncurrent assets |  |  | (62 | ) |  |  | (10,820 | ) |  |  | (3,319 | )
Proceeds from sale of Held Separate Businesses, net |  |  | — |  |  |  | — |  |  |  | 454,109 |
Proceeds from dispositions of other assets |  |  | 12,667 |  |  |  | 71,396 |  |  |  | 26,836 |
Proceeds from insurance settlement |  |  | 250 |  |  |  | 3,661 |  |  |  | — |
Distributions in excess of equity earnings from joint ventures |  |  | — |  |  |  | 113 |  |  |  | 2,433 |
Other, net |  |  | — |  |  |  | 912 |  |  |  | — |
Net cash used in investing activities |  |  | (238,396 | ) |  |  | (213,234 | ) |  |  | (89,000 | )
Cash Flows from Financing Activities: |  |  |  |  |  |  |  |  |  |  |  |
Proceeds from issuance of common units, net of issuance costs |  |  | 143,083 |  |  |  | — |  |  |  | — |
Proceeds from long-term debt borrowings, net of issuance costs |  |  | 1,170,302 |  |  |  | 269,026 |  |  |  | 746,472 |
Long-term debt repayments |  |  | (1,077,975 | ) |  |  | (83,510 | ) |  |  | (735,064 | )
Proceeds from notes payable |  |  | 75,000 |  |  |  | — |  |  |  | — |
Repayments of notes payable |  |  | (82,353 | ) |  |  | — |  |  |  | — |
Distributions to unitholders and general partner |  |  | (197,333 | ) |  |  | (183,290 | ) |  |  | (127,789 | )
Contributions from general partner |  |  | 3,035 |  |  |  | 575 |  |  |  | 29,197 |
Increase (decrease) in cash book overdrafts |  |  | 3,676 |  |  |  | (6,305 | ) |  |  | 10,006 |
Other, net |  |  | (375 | ) |  |  | (395 | ) |  |  | — |
Net cash provided by (used in) financing activities |  |  | 37,060 |  |  |  | (3,899 | ) |  |  | (77,178 | )
Effect of foreign exchange rate changes on cash |  |  | (336 | ) |  |  | (894 | ) |  |  | (345 | )
Net increase in cash and cash equivalents |  |  | 21,000 |  |  |  | 32,784 |  |  |  | 19,907 |
Cash and cash equivalents as of the beginning of year |  |  | 68,838 |  |  |  | 36,054 |  |  |  | 16,147 |
Cash and cash equivalents as of the end of year |  | $ | 89,838 |  |  | $ | 68,838 |  |  | $ | 36,054 |

See Notes to Consolidated Financial Statements.

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NUSTAR ENERGY L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF PARTNERS’ EQUITY

Years Ended December 31, 2007, 2006 and 2005

(Thousands of Dollars, Except Unit Data)

|  | Limited Partners |  |  | General Partner |  |  | Accumulated Other Comprehensive Income (Loss) |  |  | Total Partners’ Equity |
| Common |  |  | Subordinated |  |  |  |
| Units |  | Amount |  |  | Units |  |  | Amount |  |  |  |
Balance as of January 1, 2005 |  | 13,442,072 |  | $ | 310,537 |  |  | 9,599,322 |  |  | $ | 117,968 |  |  | $ | 9,836 |  |  | $ | (30 | ) |  | $ | 438,311 |
Net income |  | — |  |  | 72,383 |  |  | — |  |  |  | 27,932 |  |  |  | 10,758 |  |  |  | — |  |  |  | 111,073 |
Other comprehensive loss – foreign currency translation |  | — |  |  | — |  |  | — |  |  |  | — |  |  |  | — |  |  |  | (1,238 | ) |  |  | (1,238 | )
Total comprehensive income |  | — |  |  | 72,383 |  |  | — |  |  |  | 27,932 |  |  |  | 10,758 |  |  |  | (1,238 | ) |  |  | 109,835 |
Cash distributions to partners |  | — |  |  | (85,138 | ) |  | — |  |  |  | (31,773 | ) |  |  | (10,878 | ) |  |  | — |  |  |  | (127,789 | )
Exchange of common units for all common units of KPP and related general partner interest contributions |  | 23,768,355 |  |  | 1,451,225 |  |  | — |  |  |  | — |  |  |  | 29,197 |  |  |  | — |  |  |  | 1,480,422 |
Balance as of December 31, 2005 |  | 37,210,427 |  |  | 1,749,007 |  |  | 9,599,322 |  |  |  | 114,127 |  |  |  | 38,913 |  |  |  | (1,268 | ) |  |  | 1,900,779 |
Net income |  | — |  |  | 123,180 |  |  | — |  |  |  | 9,440 |  |  |  | 16,910 |  |  |  | — |  |  |  | 149,530 |
Other comprehensive income – foreign currency translation |  | — |  |  | — |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 8,087 |  |  |  | 8,087 |
Total comprehensive income |  | — |  |  | 123,180 |  |  | — |  |  |  | 9,440 |  |  |  | 16,910 |  |  |  | 8,087 |  |  |  | 157,617 |
Cash distributions to partners |  | — |  |  | (149,004 | ) |  | — |  |  |  | (16,703 | ) |  |  | (17,583 | ) |  |  | — |  |  |  | (183,290 | )
General partner contribution |  | — |  |  | — |  |  | — |  |  |  | — |  |  |  | 575 |  |  |  | — |  |  |  | 575 |
Conversion of subordinated units to common units on May 8, 2006 |  | 9,599,322 |  |  | 106,864 |  |  | (9,599,322 | ) |  |  | (106,864 | ) |  |  | — |  |  |  | — |  |  |  | — |
Balance as of December 31, 2006 |  | 46,809,749 |  |  | 1,830,047 |  |  | — |  |  |  | — |  |  |  | 38,815 |  |  |  | 6,819 |  |  |  | 1,875,681 |
Net income |  | — |  |  | 129,235 |  |  | — |  |  |  | — |  |  |  | 21,063 |  |  |  | — |  |  |  | 150,298 |
Other comprehensive income – foreign currency translation |  | — |  |  | — |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 20,068 |  |  |  | 20,068 |
Total comprehensive income |  | — |  |  | 129,235 |  |  | — |  |  |  | — |  |  |  | 21,063 |  |  |  | 20,068 |  |  |  | 170,366 |
Cash distributions to partners |  | — |  |  | (176,239 | ) |  | — |  |  |  | — |  |  |  | (21,094 | ) |  |  | — |  |  |  | (197,333 | )
Issuance of 2,600,000 common units in November 2007 and related general partner interest contribution |  | 2,600,000 |  |  | 143,083 |  |  | — |  |  |  | — |  |  |  | 3,035 |  |  |  | — |  |  |  | 146,118 |
Balance as of December 31, 2007 |  | 49,409,749 |  | $ | 1,926,126 |  |  | — |  |  | $ | — |  |  | $ | 41,819 |  |  | $ | 26,887 |  |  | $ | 1,994,832 |

See Notes to Consolidated Financial Statements.

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NUSTAR ENERGY L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2007, 2006 and 2005

1. ORGANIZATION AND OPERATIONS

Organization

NuStar Energy L.P. (NYSE: NS), formerly Valero L.P., is 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. NuStar Energy L.P. also purchases certain petroleum products for resale to third parties. As used in this report, references to “we,” “us,” “our” or “the Partnership” collectively refer, depending on the context, to NuStar Energy L.P. or a wholly owned subsidiary of NuStar Energy L.P.

NuStar GP Holdings, LLC (NuStar GP Holdings) (NYSE: NSH) is our general partner, which is represented by a 2% general partner interest. NuStar GP Holdings, through various wholly owned subsidiaries, also owns limited partner units, resulting in a combined ownership of 22.3% of our partnership interests. The remaining 77.7% limited partnership interests are held by public unitholders.

NuStar GP Holdings, a publicly held Delaware limited liability company, was formed in June 2000 as UDS Logistics. Valero Energy Corporation (Valero Energy) (NYSE: VLO), a publicly held independent refining and marketing company, acquired UDS Logistics in connection with its December 31, 2001 acquisition (UDS Acquisition) of Ultramar Diamond Shamrock Corporation (UDS). UDS Logistics changed its name to Valero GP Holdings in January 2006. In two separate public offerings in 2006, Valero Energy sold 100% of their ownership interests in NuStar GP Holdings. In April 2007, Valero GP Holdings changed its name to NuStar GP Holdings, and we changed our name to NuStar Energy L.P. (NuStar Energy).

Operations

Our operations are managed by NuStar GP, LLC, formerly Valero GP, LLC, the general partner of Riverwalk Logistics, L.P., and a wholly owned subsidiary of NuStar GP Holdings.

We conduct our operations through our subsidiaries, primarily NuStar Logistics, L.P., formerly Valero Logistics Operations, L.P. (NuStar Logistics), and Kaneb Pipe Line Operating Partnership, L.P. (KPOP). 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. We have five business segments: refined product terminals, refined product pipelines, crude oil pipelines, crude oil storage tanks and marketing. As of December 31, 2007, our assets included:

| • |  | 61 refined product terminal facilities in the United States, the Netherlands Antilles, Canada, Mexico, the Netherlands and the United Kingdom providing approximately 58.5 million barrels of storage capacity and one crude oil terminal facility providing approximately 3.4 million barrels of storage capacity;

| • |  | 8,251 miles of refined product pipelines, including approximately 2,000 miles of anhydrous ammonia pipelines, with 21 associated terminals providing storage capacity of 4.6 million barrels and two tank farms providing storage capacity of 1.2 million barrels;

| • |  | 812 miles of crude oil pipelines with 11 associated storage tanks providing storage capacity of 1.7 million barrels; and

| • |  | 60 crude oil storage tanks providing storage capacity of 12.5 million barrels.

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.

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NUSTAR ENERGY L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Consolidation

The accompanying consolidated financial statements represent the consolidated operations of the Partnership and our controlled subsidiaries. Inter-partnership balances and transactions have been eliminated in consolidation. The operations of certain crude oil, refined product pipelines and refined product terminals in which we own an undivided interest, are proportionately consolidated in the accompanying consolidated financial statements. Investments in 50% or less owned entities are accounted for using the equity method of accounting.

Use of Estimates

The preparation of consolidated financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and accompanying notes. Actual results could differ from those estimates. On an ongoing basis, management reviews their estimates based on currently available information. Changes in facts and circumstances may result in revised estimates.

Cash and Cash Equivalents

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

Accounts Receivable

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

Inventories

Inventories consist of petroleum products purchased for resale and are valued at the lower of cost or market. Cost is determined using the weighted-average cost method.

Property and Equipment

Additions to property and equipment, including reliability and expansion capital expenditures and capitalized interest, are recorded at cost.

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

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

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NUSTAR ENERGY L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

Goodwill and Intangible Assets

Goodwill represents the excess of cost of an acquired entity over the fair value of net assets acquired less liabilities assumed. Intangible assets are assets that lack physical substance (excluding financial assets). Goodwill acquired in a business combination is not amortized. Intangible assets with finite useful lives are amortized on a straight-line basis over five to 47 years. Goodwill is tested for impairment annually or more frequently if events or changes in circumstances indicate the asset might be impaired. We use October 1 of each year as our annual valuation date for the impairment test. Based on the results of the impairment tests performed as of October 1, 2007, 2006 and 2005, no impairment had occurred.

Investment in Joint Ventures

Skelly-Belvieu Pipeline Company, LLC. Formed in 1993, the Skelly-Belvieu Pipeline Company, LLC (Skelly-Belvieu) owns a liquefied petroleum gas pipeline that begins in Skellytown, Texas and extends to Mont Belvieu, Texas near Houston. Skelly-Belvieu is owned 50% by the Partnership and 50% by ConocoPhillips. We account for this investment under the equity method of accounting.

ST Linden Terminals, LLC. Formed in 1998, the 44-acre facility provides us with deep-water terminalling capabilities at New York Harbor and primarily stores petroleum products, including gasoline, jet fuel and fuel oils. ST Linden Terminals, LLC (Linden) is owned 50% by the Partnership and 50% by NIC Holding Corp. We account for this investment under the equity method of accounting.

Deferred Charges and Other Assets

“Deferred charges and other assets, net” primarily include the following:

| • |  | deferred financing costs amortized over the life of the related debt obligation using the effective interest method;

| • |  | deferred costs incurred in connection with acquiring a customer contract, which is amortized over the life of the contract;

| • |  | deferred dry-docking costs incurred in connection with major maintenance activities on our marine vessels, which are amortized over the period of time estimated to lapse until the next dry-docking occurs; and

| • |  | the fair value of our interest rate swap agreements.

Impairment of Long-Lived Assets

Long-lived assets, including property and equipment and investment in joint ventures, are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. The evaluation of recoverability is performed using undiscounted estimated net cash flows generated by the related asset. If an asset is deemed to be impaired, the amount of impairment is determined as the amount by which the net carrying value exceeds discounted estimated net cash flows. We believe that the carrying amounts of our long-lived assets as of December 31, 2007 are recoverable.

Taxes Other than Income Taxes

Taxes other than income taxes include primarily liabilities for ad valorem taxes, franchise taxes, and value added taxes.

Income Taxes

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

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NUSTAR ENERGY L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

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

In June 2006, the FASB issued Interpretation No. 48, “Accounting for Uncertainty in Income Taxes—an interpretation of FASB Statement No. 109” (FIN 48). FIN 48 clarifies the accounting for uncertain income tax positions recognized in an enterprise’s financial statements in accordance with FASB Statement No. 109, “Accounting for Income Taxes,” by defining a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. In accordance with FIN 48, we recognize a tax position if it is more-likely-than-not that the tax position will be sustained, based on the technical merits of the position, upon examination. We record uncertain tax positions in the financial statements at the largest amount of benefit that is more-likely-than-not to be realized. We adopted FIN 48 effective January 1, 2007, which did not affect our financial position or results of operations. We had no unrecognized tax benefits as of January 1, 2007 or December 31, 2007.

NuStar Energy or certain of its subsidiaries file income tax returns in the U.S. federal jurisdiction and various state and foreign jurisdictions. For U.S. federal and state purposes, tax years subject to examination are 2003 through 2007 and for our major non-U.S. jurisdictions, tax years subject to examination are 2001 through 2007.

Asset Retirement Obligations

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

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

We also have legal obligations in the form of leases and right of way agreements, which require us to remove certain of our assets upon termination of the agreement. However, these lease or right of way agreements generally contain automatic renewal provisions that extend our rights indefinitely or we have other legal means available to extend our rights. We have recorded a liability of approximately $0.8 million and $2.0 million as of December 31, 2007 and 2006, respectively, which is included in “Other long-term liabilities” on the consolidated balance sheet, for conditional asset retirement obligations related to the retirement of terminal assets with lease and right of way agreements.

Environmental Remediation Costs

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

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NUSTAR ENERGY L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

Product Imbalances

Product imbalances occur when customers deliver more or less refined product volumes into our pipelines than they are entitled to receive. We value assets and liabilities related to product imbalances at current market prices. Product imbalance liabilities are included in “Accrued liabilities” on the consolidated balance sheet (see Note 9). Included in “Other current assets” are $13.6 million and $9.9 million of product imbalance assets as of December 31, 2007 and 2006, respectively.

Revenue Recognition

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, handling and filtering services. Our facilities at Point Tupper and St. Eustatius also charge fees to provide ancillary services such as pilotage, tug assistance, line handling, launch service, emergency response services and other ship services. Storage lease revenues are recognized when services are provided to the customer. Throughput revenues (based on a terminalling fee) are recognized as refined products are delivered out of our terminal. Revenues for ancillary services are recognized as those services are provided.

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

Crude oil storage tank revenues are recognized as crude oil and certain other refinery feedstocks are received by the related refinery.

Revenues from the sale of petroleum products, which are included in our marketing segment, are recognized when product is delivered to the customer and title and risk pass to the customer. Additionally, the revenues of our marketing segment include the mark-to-market impact of certain derivative instruments that are part of our limited trading program.

In June 2006, the FASB ratified its consensus on EITF Issue No. 06-3, “How Taxes Collected from Customers and Remitted to Governmental Authorities Should Be Presented in the Income Statement” (EITF No. 06-3). EITF 06-3 includes any tax assessed by a governmental authority that is directly imposed on a revenue-producing transaction between a seller and a customer and may include sales, use, value added, and some excise taxes. These taxes should be presented on either a gross or a net basis, and if reported on a gross basis, a company should disclose amounts of those taxes in interim and annual financial statements for each period for which an income statement is presented. We present taxes on a net basis in our consolidated financial statements.

Income Allocation

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

Net Income per Unit Applicable to Limited Partners

We have identified the general partner and the subordinated units as participating securities and use the two-class method when calculating the net income per unit applicable to limited partners, which is based on the weighted-average number of common and subordinated units outstanding during the period. Net income per unit applicable to limited partners is computed by dividing net income applicable to limited partners, after deducting the general partner’s 2% interest and incentive distributions, by the weighted-average number of limited partnership units outstanding. Basic and diluted net income per unit applicable to limited partners is the same because we have no potentially dilutive securities outstanding. The amount of net income per unit allocated to subordinated units was equal to the amount allocated to the common units for the periods prior to the conversion of the subordinated units into common units in May 2006.

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NUSTAR ENERGY L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

Comprehensive Income

Comprehensive income consists of net income and other gains and losses affecting partners’ equity that, under United States generally accepted accounting principles, are excluded from net income, such as foreign currency translation adjustments.

Derivative Financial Instruments

We are a party to certain interest rate swap agreements for the purpose of hedging the interest rate risk associated with a portion of our fixed-rate senior notes. We account for the interest rate swaps as fair value hedges and recognize the fair value of each interest rate swap in the consolidated balance sheet as either an asset or liability. The interest rate swap contracts qualify for the shortcut method of accounting prescribed by SFAS 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended (SFAS 133). As a result, changes in the fair value of the derivatives will completely offset the changes in the fair value of the underlying hedged debt.

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. The derivative instruments we use consist primarily of futures contracts and swaps traded on the NYMEX.

Derivative instruments designated and qualifying as fair value hedges under Statement of Financial Accounting Standards No. 133 (SFAS 133) are recorded in the consolidated balance sheet as assets or liabilities at fair value with mark-to-market adjustments recorded in “Cost of product sales.” The offsetting gain or loss on the associated hedged physical inventory is recognized concurrently in “Cost of product sales.” We record derivative instruments that do not qualify for hedge accounting under SFAS 133 in the consolidated balance sheet as assets or liabilities at fair value with mark-to-market adjustments recorded in “Cost of product sales.” Fair value is based on quoted market prices.

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 these derivatives in the consolidated balance sheet as assets or liabilities at fair value with mark-to-market adjustments recorded in “Revenues.”

Operating Leases

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

Stock-based Compensation

NuStar GP, LLC has adopted various long-term incentive plans, which provide employees and directors of NuStar GP, LLC providing services to NuStar Energy, with the right to receive NS common units. NuStar GP, LLC accounts for awards of NS unit options and restricted units at fair value in accordance with Emerging Issues Task Force Issue No. 02-08, “Accounting for Options Granted to Employee in Unrestricted, Publicly Traded Shares of an Unrelated Entity” (EITF 02-08). EITF 02-08 requires a company that grants its employees equity of an unrelated entity to account for such awards as a derivative, whereby a liability for the award is recorded at inception. Subsequent changes in the fair value of the award are included in the determination of net income. The fair value of NS unit options is determined using the Black-Scholes model at each reporting date. The fair value of NS restricted units equals the market price of NS common units at each reporting date. NuStar GP, LLC records compensation expense each reporting period such that the cumulative compensation expense recorded equals the current fair value and considering the percentage of the award that has vested. NuStar GP, LLC records compensation expense related to NS unit options until such options are exercised, and compensation expense related to NS restricted units until the date of vesting.

NuStar GP Holdings has adopted a long-term incentive plan that provides employees, consultants and directors of NuStar GP Holdings and its affiliates with rights to receive NuStar GP Holdings common units under specified conditions. NuStar GP Holdings accounts for awards of NSH restricted units and unit options granted to its directors or employees of NuStar GP, LLC at fair value in accordance with Financial Accounting Standards Board (FASB) Statement No. 123 (revised 2004), “Share-Based Payment.” The fair value of NSH unit options is determined using the Black-Scholes model at the grant date and the fair value of the NSH restricted unit equals the market price of NSH common units at the grant date. NuStar GP Holdings recognizes compensation expense for NSH restricted units and unit options ratably over the vesting period based on the fair value of the units at the grant date.

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NUSTAR ENERGY L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

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

Under these employee stock compensation plans, certain awards provide that employees vest in the award when they retire or will continue to vest in the award after retirement over the nominal vesting period established in the award. Through 2005, we accounted for such awards by recognizing compensation expense over the nominal vesting period. By analogy to the transition rules of SFAS No. 123R and the Securities and Exchange Commission’s (SEC) amended Rule 4-01(a) of Regulation S-X, we changed our method of recognizing compensation expense to the non-substantive vesting period approach for any awards granted after January 1, 2006. Under the non-substantive vesting period approach, compensation expense is recognized immediately for awards granted to retirement-eligible employees or over the period from the grant date to the date retirement eligibility is achieved if that date is expected to occur during the nominal vesting period.

Margin Deposits

Margin deposits relate to our exchange-traded derivative contracts and generally vary based on changes in the value of the contracts. Margin deposits totaling $8.6 million are included in “Other current assets” on the consolidated balance sheet as of December 31, 2007. Prior to 2007, we were not a party to any exchange-traded derivative contracts.

New Accounting Pronouncements

FASB Statement No. 157. In September 2006, the FASB issued Statement No. 157, “Fair Value Measurements.” Statement No. 157, as amended, defines fair value, establishes a framework for measuring fair value under GAAP, and expands disclosures about fair value measures. Statement No. 157 is effective for fiscal years beginning after November 15, 2007, with early adoption encouraged. The provisions of Statement No. 157 are to be applied on a prospective basis, with the exception of certain financial instruments for which retrospective application is required. The FASB deferred the effective date for one year for all nonfinancial assets and liabilities, except for those items that that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually). We will still need to apply the recognition and disclosure provisions of Statement No. 157 for financial assets and liabilities and for nonfinancial assets and liabilities that are re-measured at least annually. The adoption of Statement No. 157 effective January 1, 2008 has not materially affected our financial position or results of operations.

FASB Statement No. 159. In February 2007, the FASB issued Statement No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities.” Statement No. 159 creates a fair value option under which an entity may irrevocably elect fair value as the initial and subsequent measurement attribute for certain financial assets and financial liabilities on an instrument-by-instrument basis, with changes in fair value recognized in earnings as those changes occur. The adoption of Statement No. 159 effective January 1, 2008 has not affected our financial position or results of operations.

FASB Statement No. 141R. In December 2007, the FASB issued FASB Statement No. 141 (Revised 2007), Business Combinations. Statement 141R will significantly change the accounting for business combinations. Under Statement 141R, an acquiring entity will be required to recognize all the assets acquired and liabilities assumed in a transaction at the acquisition-date fair value with limited exceptions. Statement 141R will change the accounting treatment for certain specific items, such as acquisition costs, acquired contingent liabilities, restructuring costs, changes in deferred tax asset valuation allowances and other items. Statement 141R also includes a substantial number of new disclosure requirements. Statement 141R applies prospectively to business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008. Earlier adoption is prohibited. Accordingly, we will not adopt the provisions of Statement 141R until January 1, 2009.

Reclassifications

Certain previously reported amounts in the 2006 and 2005 consolidated financial statements have been reclassified to conform to the 2007 presentation.

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3. ACQUISITIONS

Completed During 2006

Capwood Pipeline

Effective January 1, 2006, we purchased a 23.77% interest in Capwood pipeline from Valero Energy for $12.8 million, which was paid from borrowings under our existing revolving credit agreement. The Capwood pipeline is a 57-mile crude oil pipeline that extends from Patoka, Illinois to Wood River, Illinois. Plains All American Pipeline L.P., the operator of the Capwood pipeline, owns the remaining 76.23% interest. Our financial statements include the results of operations of our interest in the Capwood pipeline in the crude oil pipelines segment for the years ended December 31, 2007 and 2006.

St. James Crude Facility

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 St. James Acquisition). The acquisition includes 17 crude oil tanks with a total capacity of approximately 3.3 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. The financial statements include the results of operations in the refined product terminal segment commencing on December 1, 2006.

The St. James Acquisition was accounted for using the purchase method. The purchase price and purchase price allocation were as follows (in thousands):

Cash paid for St. James Terminal |  | $ | 140,900
Transaction costs |  |  | 759
Total |  | $ | 141,659
Current assets |  | $ | 53
Property and equipment |  |  | 126,258
Goodwill |  |  | 13,898
Intangible assets |  |  | 1,450
Total |  | $ | 141,659

Since the effect of the St. James Acquisition was not significant, we have not presented pro forma financial information for the years ended December 31, 2006 and 2005 that give effect to the St. James Acquisition as of January 1, 2006 and 2005.

Completed During 2005

Kaneb Acquisition

On July 1, 2005, we completed our acquisition (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, which was primarily funded by borrowings under our $525 million term credit agreement. 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.

The financial statements include the results of operations of the Kaneb Acquisition commencing on July 1, 2005.

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Purchase Price Allocation

The Kaneb Acquisition was accounted for using the purchase method. The purchase price and final purchase price allocation were as follows (in thousands):

Cash paid for the outstanding equity securities of KSL |  | $ | 509,307
Value of NuStar Energy’s common units issued in exchange for KPP units |  |  | 1,451,249
Transaction costs |  |  | 9,505
Fair value of long-term debt assumed |  |  | 779,707
Fair value of other liabilities assumed |  |  | 179,864
Total |  | $ | 2,929,632
Current assets |  | $ | 605,721
Property and equipment |  |  | 1,429,652
Goodwill |  |  | 769,727
Intangible assets |  |  | 58,900
Other noncurrent assets |  |  | 65,632
Total |  | $ | 2,929,632

Unaudited Pro Forma Information

The unaudited pro forma financial information below includes the historical financial information of Kaneb and the Partnership for the periods indicated. This financial information assumes the following:

| • |  | we completed the Kaneb Acquisition on January 1, 2005;

| • |  | we borrowed $525.0 million to purchase all of the outstanding equity securities of KSL;

| • |  | we issued approximately 23.8 million common units in exchange for all of the outstanding common units of KPP;

| • |  | we received a contribution from our general partner of $29.2 million to maintain its 2% interest; and

| • |  | the results of operations of the Held Separate Businesses (as defined below in Note 4), Martin Oil LLC, (a marketing subsidiary of KSL) and the Australian and New Zealand subsidiaries are reported as discontinued operations.

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

|  | Year Ended December 31, 2005
|  | (Thousands of Dollars, Except Per Unit Data)
Revenues |  | $ | 1,005,662
Operating income |  |  | 130,347
Income from continuing operations |  | $ | 83,084
Income from discontinued operations |  |  | 9,853
Net income |  | $ | 92,937
Net income per unit applicable to limited partners: |  |  |
Continuing operations |  | $ | 1.48
Discontinued operations |  |  | 0.21
Net income |  | $ | 1.69

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4. DISPOSITIONS

Sale of Australia and New Zealand Subsidiaries

On March 30, 2006, we sold our Australia and New Zealand subsidiaries 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 approximately 1.1 million barrels. The results of operations for the Australia and New Zealand Subsidiaries for 2006 and 2005 have been included in income from discontinued operations. Revenues and pre-tax income related to the Australia and New Zealand Subsidiaries, included in income from discontinued operations, were $5.0 million and $0.6 million, respectively, for the year ended December 31, 2006 and were $10.1 million and $0.2 million, respectively, for the year ended December 31, 2005. Income tax expense associated with the Australia and New Zealand Subsidiaries totaled $0.3 million and $0.1 million for the years ended December 31, 2006 and 2005, respectively. Additionally, the income from discontinued operations includes interest expense of approximately $0.8 million and $1.5 million allocated to the Australia and New Zealand Subsidiaries for the years ended December 31, 2006 and 2005, respectively, which was based upon the expected proceeds and the interest rate applicable to our debt.

Sale of Held Separate Businesses

In conjunction with the Kaneb Acquisition, we agreed with the United States Federal Trade Commission to divest certain assets. These assets consisted of two California terminals handling refined products, blendstocks, and crude oil, three East Coast refined product terminals, and a 550-mile refined products pipeline with four truck terminals and storage in the U.S. Rocky Mountains (collectively, the Held Separate Businesses).

On September 30, 2005, we sold the Held Separate Businesses to Pacific Energy Partners, L.P. for approximately $455.0 million. Results of operations related to the Held Separate Businesses are classified as income from discontinued operations in the consolidated statement of income for the year ended December 31, 2005. Revenues and pre-tax income related to the Held Separate Businesses were $14.2 million and $3.2 million, respectively, for the year ended December 31, 2005. Income tax expense was not included in discontinued operations related to the Held Separate Businesses as they were owned by entities that were not subject to income tax. Additionally, interest expense of approximately $4.9 million was allocated to the Held Separate Businesses as certain of our debt agreements required us to use the proceeds from the sale of the Held Separate Businesses to repay outstanding debt.

Sale of Martin Oil LLC

In a separate transaction that occurred simultaneously with the closing of the Kaneb Acquisition, we sold all of our interest in Kaneb’s commodity trading business, Martin Oil LLC, to Valero Energy for approximately $26.8 million.

5. ALLOWANCE FOR DOUBTFUL ACCOUNTS

The changes in the allowance for doubtful accounts consisted of the following:

|  | Year Ended December 31, |
|  | 2007 |  |  | 2006 |
|  | (Thousands of Dollars) |
Balance as of beginning of year |  | $ | 1,220 |  |  | $ | 1,976 |
Decrease in allowance credited to expense |  |  | (544 | ) |  |  | (276 | )
Accounts charged against the allowance, net of recoveries |  |  | (324 | ) |  |  | (492 | )
Foreign currency translation |  |  | 13 |  |  |  | 12 |
Balance as of end of year |  | $ | 365 |  |  | $ | 1,220 |

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6. PROPERTY AND EQUIPMENT

Property and equipment, at cost, consisted of the following:

|  | Estimated Useful Lives |  | December 31, |
|  |  | 2007 |  |  | 2006 |
|  | (Years) |  | (Thousands of Dollars) |
Land |  | — |  | $ | 108,216 |  |  | $ | 93,929 |
Land and leasehold improvements |  | 10 - 35 |  |  | 75,013 |  |  |  | 59,043 |
Buildings |  | 15 - 40 |  |  | 39,789 |  |  |  | 37,533 |
Pipeline, storage and terminals and equipment |  | 20 - 35 |  |  | 2,435,381 |  |  |  | 2,327,129 |
Rights of way |  | 20 - 40 |  |  | 102,217 |  |  |  | 102,211 |
Construction in progress |  | — |  |  | 183,500 |  |  |  | 74,513 |
Total |  |  |  |  | 2,944,116 |  |  |  | 2,694,358 |
Less accumulated depreciation and amortization |  |  |  |  | (452,030 | ) |  |  | (349,223 | )
Property and equipment, net |  |  |  | $ | 2,492,086 |  |  | $ | 2,345,135 |

Capitalized interest costs included in property and equipment were $6.0 million, $1.8 million and $1.0 million for the years ended December 31, 2007, 2006 and 2005, respectively. Depreciation and amortization expense for property and equipment was $102.8 million, $92.5 million and $62.9 million for the years ended December 31, 2007, 2006 and 2005, respectively.

In the fourth quarter of 2005, a portion of the Three Rivers to Pettus to Corpus Christi refined product pipeline was permanently idled. As a result, we recorded an impairment charge of $2.1 million, included in “Other income (expense), net” in the accompanying consolidated statement of income for the year ended December 31, 2005.

7. INTANGIBLE ASSETS

Intangible assets consisted of the following:

|  | December 31, 2007 |  |  | December 31, 2006 |
|  | Cost |  | Accumulated Amortization |  |  | Cost |  | Accumulated Amortization |
|  | (Thousands of Dollars) |
Intangible assets subject to amortization: |  |  |  |  |  |  |  |  |  |  |  |  |  |
Customer relationships |  | $ | 58,900 |  | $ | (14,690 | ) |  | $ | 58,900 |  | $ | (8,795 | )
Non-compete agreements |  |  | 1,765 |  |  | (1,407 | ) |  |  | 1,765 |  |  | (1,054 | )
Terminaling agreement |  |  | 1,000 |  |  | (333 | ) |  |  | — |  |  | — |
Consulting agreements |  |  | — |  |  | — |  |  |  | 1,150 |  |  | (652 | )
Other |  |  | 2,809 |  |  | (282 | ) |  |  | 2,359 |  |  | (141 | )
Total |  | $ | 64,474 |  | $ | (16,712 | ) |  | $ | 64,174 |  | $ | (10,642 | )

All of our intangible assets are subject to amortization. Amortization expense for intangible assets was $7.2 million, $6.5 million and $3.5 million for the years ended December 31, 2007, 2006 and 2005, respectively. The estimated aggregate amortization expense is approximately $6.7 million for the year ending December 31, 2008, $6.4 million for the year ended December 31, 2009, $6.0 million for the years ending December 31, 2010 and 2011 and $5.9 million for the year ended December 31, 2012.

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8. INVESTMENT IN JOINT VENTURES

The following table presents summarized combined unaudited financial information related to our joint ventures as of December 31, 2007 and 2006 and for the years ended December 31, 2007, 2006 and 2005:

|  | December 31,
|  | 2007 |  | 2006
|  | (Thousands of Dollars)
Balance Sheet Information: |  |  |  |  |  |
Current assets |  | $ | 10,387 |  | $ | 8,622
Property, plant and equipment, net |  |  | 81,645 |  |  | 68,809
Total assets |  | $ | 92,032 |  | $ | 77,431
Current liabilities |  | $ | 6,328 |  | $ | 3,375
Members’ equity |  |  | 85,704 |  |  | 74,056
Total liabilities and members’ equity |  | $ | 92,032 |  | $ | 77,431

|  | Year Ended December 31,
|  | 2007 |  | 2006 |  | 2005 (a)
|  | (Thousands of Dollars)
Statement of Income Information: |  |  |  |  |  |  |  |  |
Revenues |  | $ | 31,502 |  | $ | 28,858 |  | $ | 28,008
Net income |  |  | 13,528 |  |  | 12,355 |  |  | 11,320
Our share of net income (b) |  |  | 6,833 |  |  | 5,969 |  |  | 2,499
Our share of distributions |  |  | 544 |  |  | 5,268 |  |  | 4,932

(a) | Revenues and net income reflect the amounts for the year ended December 31, 2005. Our share of net income and distributions related to investments in the joint ventures acquired as part of the Kaneb Acquisition reflect amounts for the six months ended December 31, 2005.

(b) | Our share of net income shown in the table includes $0.1 million and $0.2 million of income that is included in income from discontinued operations in the consolidated statement of income for the years ended December 31, 2006 and 2005, respectively.

Skelly-Belvieu Pipeline Company

Upon the formation of Skelly-Belvieu, we contributed certain equipment to Skelly-Belvieu in exchange for 50% of its members’ equity. Our investment in Skelly-Belvieu was recorded at the carrying amount of the contributed equipment. However, the financial statements of Skelly-Belvieu reflect these assets at fair value at the date of formation. As a result, our 50% share of Skelly-Belvieu’s members’ equity exceeds the carrying value of our investment. This excess, which totaled $7.1 million and $7.4 million as of December 31, 2007 and 2006, respectively, is being accreted into income over the average life of the assets held by Skelly-Belvieu, or 33 years.

ST Linden Terminals, LLC

As part of the Kaneb Acquisition, we acquired an investment in Linden. As part of the final allocation in 2006 of the purchase price of Kaneb, we recorded our investment in Linden at fair value. As a result, the carrying value of our investment in Linden exceeds our 50% share of its members’ equity. This excess totaled $44.5 million and $44.9 million as of December 31, 2007 and 2006, respectively, of which $8.0 million is being amortized into expense over the average life of the assets held by Linden, or 25 years. The balance not being amortized has been allocated to goodwill of Linden.

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9. ACCRUED LIABILITIES

Accrued liabilities consisted of the following:

|  | December 31,
|  | 2007 |  | 2006
|  | (Thousands of Dollars)
Employee wages and benefit costs |  | $ | 17,633 |  | $ | 12,093
Unearned income |  |  | 2,401 |  |  | 2,369
Environmental costs |  |  | 5,435 |  |  | 5,583
Product shortages |  |  | 10,513 |  |  | 7,796
Other |  |  | 11,207 |  |  | 9,810
Accrued liabilities |  | $ | 47,189 |  | $ | 37,651

10. LONG-TERM DEBT

Long-term debt consisted of the following:

|  | December 31, |
|  | 2007 |  |  | 2006 |
|  | (Thousands of Dollars) |
6.05% senior notes due 2013, net of unamortized discount of ($337) in 2007 and ($437) in 2006 and a fair value adjustment of $1,646 in 2007 and ($2,902) in 2006 |  | $ | 231,241 |  |  | $ | 246,662 |
6.875% senior notes due 2012, net of unamortized discount of ($143) in 2007 and ($174) in 2006 and a fair value adjustment of $586 in 2007 and ($2,006) in 2006 |  |  | 100,444 |  |  |  | 97,820 |
7.75% senior notes due 2012, including a fair value adjustment of $28,225 in 2007 and $33,328 in 2006 |  |  | 278,225 |  |  |  | 283,328 |
5.875% senior notes due 2013, including a fair value adjustment of $10,668 in 2007 and $12,243 in 2006 |  |  | 260,668 |  |  |  | 262,243 |
$1,250 million revolving credit agreement |  |  | 527,976 |  |  |  | — |
$525 million term credit agreement |  |  | — |  |  |  | 225,000 |
$600 million revolving credit agreement |  |  | — |  |  |  | 190,526 |
UK term loan |  |  | 41,628 |  |  |  | 41,118 |
Port Authority of Corpus Christi note payable |  |  | 6,107 |  |  |  | 7,670 |
Total debt |  |  | 1,446,289 |  |  |  | 1,354,367 |
Less current portion |  |  | (663 | ) |  |  | (647 | )
Long-term debt, less current portion |  | $ | 1,445,626 |  |  | $ | 1,353,720 |

The long-term debt repayments are due as follows (in thousands):

2008 |  | $ | 663
2009 |  |  | 713
2010 |  |  | 770
2011 |  |  | 832
2012 |  |  | 920,503
Thereafter |  |  | 482,163
Total repayments |  |  | 1,405,644
Net fair value adjustment and unamortized discount |  |  | 40,645
Total debt |  | $ | 1,446,289

Interest payments totaled $89.5 million, $75.0 million and $53.2 million for the years ended December 31, 2007, 2006 and 2005, respectively.

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6.875% and 6.05% Senior Notes

On March 18, 2003, NuStar Logistics issued $250 million of 6.05% senior notes, maturing in 2013, with interest payable semi-annually in arrears on March 15 and September 15 of each year.

On July 15, 2002, NuStar Logistics issued $100.0 million of 6.875% senior notes, maturing in 2012, with interest payable semi-annually in arrears on January 15 and July 15 of each year.

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

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

Due to the completed sale of Valero Energy’s remaining interests in NuStar GP Holdings on December 22, 2006, the change-in-control provision was triggered, and NuStar Logistics offered to purchase the senior notes at a price equal to 100% of their outstanding principal balance plus accrued interest through the date of purchase. This offer expired on January 23, 2007, with approximately $20.1 million of the 6.05% senior notes tendered to us for repurchase. We retired the senior notes that were tendered with borrowings under our $600 million revolving credit agreement on February 1, 2007. The retirement of those senior notes did not significantly affect either our financial position or results of operations.

7.75% and 5.875% Senior Notes

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

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

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

The senior notes issued by NuStar Logistics are fully and unconditionally guaranteed by NuStar Energy. In connection with the Kaneb Acquisition, NuStar Energy fully and unconditionally guaranteed the outstanding senior notes issued by KPOP. Additionally, effective July 1, 2005, both NuStar Logistics and KPOP fully and unconditionally guaranteed the outstanding senior notes of the other.

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2007 Revolving Credit Agreement

On December 10, 2007, NuStar Logistics replaced the existing $600 million revolving credit agreement with the $1.25 billion five-year revolving credit agreement (the 2007 Revolving Credit Agreement), which includes a Euro sub-limit $250 million. 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 (the Revolving Credit Agreement) and $525 million term loan agreement (the Term Loan Agreement). Obligations under the 2007 Revolving Credit Agreement are guaranteed by NuStar Energy and KPOP. KPOP will be released from its guarantee of the 2007 Revolving Credit Agreement when it no longer guarantees NuStar Logistics public debt instruments.

As of December 31, 2007, we had $720.8 million available for borrowing under the 2007 Revolving Credit Agreement. The 2007 Revolving Credit Agreement bears interest based on either an alternative base rate or a LIBOR based rate which was 5.7% as of December 31, 2007. The weighted-average interest rate related to outstanding borrowings under the 2007 Revolving Credit Agreement for the year ended December 31, 2007 was 5.7%.

The 2007 Revolving Credit Agreement requires that we maintain certain financial ratios and includes other restrictive covenants, including a prohibition on distributions if any defaults, as defined in the agreements, exist or would result from the distribution. The 2007 Revolving Credit Agreement also requires us to maintain, as of the end of each rolling period, consisting of any period of four consecutive fiscal quarters, a consolidated debt coverage ratio (consolidated indebtedness to consolidated EBITDA, as defined in the 2007 Revolving Credit Agreement) not to exceed 5.00-to-1.00; provided, that if at any time NuStar Energy or any of its restricted subsidiaries consummates an acquisition for an aggregate net consideration of at least $100 million, then for two rolling periods, the last day of which immediately follows the day on which such acquisition is consummated, the consolidated debt coverage ratio must not exceed 5.50-to-1.00. Management believes that we are in compliance with all ratios and covenants of the 2007 Revolving Credit Agreement as of December 31, 2007.

Term Loan Agreement

On July 1, 2005, we entered into the Term Loan Agreement, the majority of which was used to fund the Kaneb Acquisition. The weighted-average interest rate related to outstanding borrowings under the Term Loan Agreement for the year ended December 31, 2007 was 6.0%. The $225.0 million balance on the Term Loan Agreement was paid in full on December 10, 2007 with the proceeds from the 2007 Revolving Credit Agreement.

Revolving Credit Agreement

On July 1, 2005, we entered into the Revolving Credit Agreement. The weighted-average interest rate related to outstanding borrowings under the Revolving Credit Agreement for the year ended December 31, 2007 was 5.7%. The $303.4 million balance on the Revolving Credit Agreement was paid in full on December 10, 2007 with the proceeds from the 2007 Revolving Credit Agreement.

UK Term Loan

KPOP’s UK subsidiary, Kaneb Terminals Limited, is the borrower of £21 million ($41.6 million and $41.1 million as of December 31, 2007 and 2006, respectively). This amended and restated term loan agreement (the UK Term Loan) bears interest at 6.65% annually and matures on December 11, 2012.

In December 2007, the UK Term Loan contains was amended to be consistent with the covenants and provisions of the 2007 Revolving Credit Agreement. Management believes that we are in compliance with all ratios and covenants of the UK Term Loan as of December 31, 2007.

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Port Authority of Corpus Christi Note Payable

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

11. HEALTH, SAFETY AND ENVIRONMENTAL MATTERS

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.

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

We have adopted policies, practices and procedures in the areas of pollution control, pipeline integrity, operator qualifications, public relations and education, product safety, 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.

Valero Energy has agreed to indemnify us for a period of ten years from the date of acquisition for pre-acquisition environmental liabilities related to assets transferred or otherwise acquired by the Partnership from Valero Energy or UDS. Excluded from this indemnification are liabilities that result from a change in environmental law after the date of acquisition.

Additionally, Exxon Mobil Corporation (ExxonMobil) has agreed to indemnify us for pre-acquisition environmental liabilities in connection with off site disposal activities performed prior to September 4, 2003 related to the Paulsboro refined product terminal acquisition.

As an operator or owner of the assets, we could be held liable for pre-acquisition environmental liabilities should Valero Energy or ExxonMobil be unable to fulfill their obligations. However, we believe that such a situation is unlikely.

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

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

|  | December 31, |
|  | 2007 |  |  | 2006 |
|  | (Thousands of Dollars) |
Balance as of beginning of year |  | $ | 13,683 |  |  | $ | 17,509 |
Additions to accrual |  |  | 3,872 |  |  |  | 2,625 |
Amounts related to the Australia and New Zealand subsidiaries |  |  | — |  |  |  | (3,051 | )
Payments |  |  | (6,474 | ) |  |  | (3,541 | )
Foreign currency translation |  |  | 43 |  |  |  | 141 |
Balance as of end of year |  | $ | 11,124 |  |  | $ | 13,683 |

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

|  | December 31,
|  | 2007 |  | 2006
|  | (Thousands of Dollars)
Accrued liabilities |  | $ | 5,435 |  | $ | 5,583
Other long-term liabilities |  |  | 5,689 |  |  | 8,100
Accruals for environmental matters |  | $ | 11,124 |  | $ | 13,683

12. COMMITMENTS AND CONTINGENCIES

Contingencies

We have contingent liabilities resulting from various litigation, claims and commitments, the most significant of which are discussed below. We record accruals for loss contingencies when losses are considered probable and can be reasonably estimated. Legal fees associated with defending our self in legal matters are expensed as incurred. As of December 31, 2007, we have recorded $1.1 million of accruals related to settled matters and $47.5 million of accruals for contingent losses. The actual payment of any amounts accrued and the timing of such payments ultimately made is uncertain. 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 ultimately 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

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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.

Department of Justice Matter. 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 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.

EPA Investigation. On November 14, 2006, agents of 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.

Other

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 these 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.

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Commitments

Future minimum rental payments applicable to all noncancellable operating leases and purchase obligations as of December 31, 2007 are as follows:

|  | Operating Leases |  | Purchase Obligations
|  | (Thousands of Dollars)
2008 |  | $ | 11,034 |  | $ | 544,294
2009 |  |  | 7,650 |  |  | 110,953
2010 |  |  | 7,099 |  |  | 7,069
2011 |  |  | 6,557 |  |  | 968
2012 |  |  | 6,394 |  |  | 962
Thereafter |  |  | 102,368 |  |  | 1,523
Future minimum lease payments |  | $ | 141,102 |  | $ | 665,769

Rental expense for all operating leases totaled $21.0 million, $15.3 million and $8.9 million for the years ended December 31, 2007, 2006 and 2005, respectively.

The purchase obligations primarily relate to purchases of inventory for resale to our customers.

13. DERIVATIVES, FINANCIAL INSTRUMENTS AND RISK MANAGEMENT ACTIVITIES

We utilize various derivative instruments to: (i) manage our exposure to commodity price risk, (ii) engage in a trading program and (iii) manage our exposure to interest rate risk. Our risk management policies and procedures are designed to monitor interest rates, NYMEX and over-the-counter positions, as well as physical volumes, grades, locations and delivery schedules to help ensure that our hedging activities address our market risks. We have a risk management group that has direct oversight responsibilities for our risk policies and our trading controls and procedures and certain aspects of risk management. Our risk management group also approves all new risk management strategies through a formal process.

The fair values of our derivative instruments are included in the Consolidated Balance Sheets as follows:

|  | Year Ended December 31,
|  | 2007 |  | 2006
|  | (Thousands of Dollars)
Deferred charges and other assets, net |  | $ | 2,231 |  | $ | —
Accrued liabilities |  | $ | 4,622 |  | $ | —
Other long-term liabilities |  |  | — |  |  | 4,908
Total liability |  | $ | 4,622 |  | $ | 4,908

Commodity Price Risk

We are exposed to commodity price risk with respect to our product inventories and related firm commitments to purchase and/or sell such inventories. We utilize NYMEX futures to manage our exposure to changes in the fair value of our product inventories and related firm commitments.

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.

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The earnings impact of our derivative activity was as follows:

|  | Year Ended December 31, 2007 |
|  | Mark-to- market, net |  |  | Settled |  |  | Total |
|  | (Thousands of Dollars) |
Commodity price-risk hedging loss |  | $ | (3,017 | ) |  | $ | (4,519 | ) |  | $ | (7,536 | )
Trading gain (loss) |  |  | 3 |  |  |  | (2,332 | ) |  |  | (2,329 | )
Total |  | $ | (3,014 | ) |  | $ | (6,851 | ) |  | $ | (9,865 | )

During 2007, we recorded $1.6 million of income representing the change in fair value of inventories designated as the hedged item in qualifying fair value hedge relationships resulting in $0.1 million of income due to the ineffectiveness of our fair value hedges. The ineffectiveness is recorded in “Cost of product sales” in the consolidated statements of income. No component of the associated derivative instruments’ gains or losses was excluded from our assessment of hedge ineffectiveness.

Prior to 2007, we had not entered into any commodity derivatives with earnings impact.

Interest Rate Risk

We are a party to interest rate swap agreements to manage our exposure to changes in interest rates. The interest rate swap agreements have an aggregate notional amount of $167.5 million, of which $60.0 million is tied to the maturity of the 6.875% senior notes and $107.5 million is tied to the maturity of the 6.05% senior notes. Under the terms of the interest rate swap agreements, we will receive a fixed rate (6.875% and 6.05% for the $60.0 million and $107.5 million of interest rate swap agreements, respectively) and will pay a variable rate based on LIBOR plus a percentage that varies with each agreement. As of December 31, 2007 and 2006, the weighted average effective interest rate for the interest rate swaps was 6.1% and 7.1%, respectively.

The estimated fair value of our fixed-rate debt as of December 31, 2007 and 2006 was $927.2 million and $939.2 million, respectively, as compared to the carrying amount of $918.3 million and $938.8 million, respectively. These fair values were estimated using discounted cash flow analysis, based on our current incremental borrowing rates for similar types of borrowing arrangements. Interest rates on borrowings under the 2007 Revolving Credit Agreement float with market rates and thus the carrying amount approximates fair value.

Concentration of Credit Risk

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

For the years ended December 31, 2007, 2006 and 2005 we derived approximately 18%, 23% and 34%, respectively, of our revenues from Valero Energy and its subsidiaries, our largest customer. No other single customer accounted for more than 10% of our consolidated operating revenues. Valero Energy and its subsidiaries are investment grade customers; therefore, we do not believe that the trade receivable from Valero Energy represents a significant credit risk. However, the concentration of business with Valero Energy, which is a large refining and retail marketing company, has the potential to impact NuStar Energy, both positively and negatively, to changes in the refining and marketing industry.

14. RELATED PARTY TRANSACTIONS

Our operations are managed by the general partner of our general partner, NuStar GP, LLC. The employees of NuStar GP, LLC perform services for our U.S. operations. Certain of our wholly owned subsidiaries employ persons who perform services for our international operations. We reimburse NuStar GP, LLC for all costs related to its employees. We had a receivable of $0.8 million and a payable of $2.3 million, as of December 31, 2007 and December 31, 2006, respectively, to NuStar GP, LLC, with both amounts representing payroll and plan benefits, net of payments made by us. We also had a long-term payable as of December 31, 2007 and 2006 of $5.7 million to NuStar GP, LLC related to amounts payable for retiree medical benefits and other post-employment benefits.

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Prior to December 22, 2006, Valero Energy controlled our general partner. We have transactions with Valero Energy for pipeline tariff, terminalling fee and crude oil storage tank fee revenues, certain employee costs, insurance costs, administrative costs and lease expense, which were reported as related party transactions in the consolidated statement of income. Due to Valero Energy’s sale of its interest in NuStar GP Holdings on December 22, 2006, we ceased reporting transactions with Valero Energy as related party transactions subsequent to that date.

The following table summarizes information pertaining to related party transactions with NuStar GP, LLC for the year ended December 31, 2007 and with Valero Energy for the years ended December 31, 2006 and 2005:

|  | Year Ended December 31,
|  | 2007 |  | 2006 |  | 2005 (a)
|  | (Thousands of Dollars)
Revenues |  | $ | — |  | $ | 260,980 |  | $ | 234,485
Operating expenses |  |  | 93,211 |  |  | 94,587 |  |  | 60,921
General and administrative expenses |  |  | 37,702 |  |  | 32,183 |  |  | 19,356

(a) | The amounts reflected in the table include revenues and operating expenses of $1,867 and $1,850, respectively, which are included in income from discontinued operations in the consolidated statement of income.

Agreements with NuStar GP Holdings

Non-Compete Agreement

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

Agreements with Valero Energy

We have entered into a number of operating agreements with Valero Energy, which govern the required services provided to and received from Valero Energy. Most of the operating agreements include adjustment provisions, which allow us to increase the handling, storage and throughput fees we charge to Valero Energy based on a consumer price index. In addition, the pipeline tariffs charged by us are reviewed annually and adjusted based on an inflation index and may also be adjusted to take into consideration additional costs incurred to provide the transportation services. The following is a summary of the significant terms of the individual agreements.

Services Agreement

Prior to our separation from Valero Energy, the employees of NuStar GP, LLC were provided to us under the terms of various services agreements between us and Valero Energy. The terms of these services agreements generally provided that the costs of employees who performed services directly on our behalf, including salaries, wages and employee benefits, were charged directly to us. In addition, Valero Energy charged us a net administrative services fee, which was $1.8 million and $6.6 million for the years ended December 31, 2006 and 2005, respectively.

Although Valero Energy no longer provided employees to work directly on our behalf, Valero Energy continued to provide certain services to us under the terms of a services agreement dated December 22, 2006 (the 2007 Services Agreement). Under the 2007 Services Agreement, we paid Valero Energy approximately $1.1 million for the year ended December 31, 2007 for administrative services (primarily information system services and human resource services) and telecommunication services.

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On April 16, 2007, Valero Energy exercised its option to terminate the 2007 Services Agreement. As a result, Valero Energy paid us a termination fee of $13.0 million in May 2007 in accordance with the terms of the 2007 Services Agreement. However, Valero Energy continued providing certain services over a period of time sufficient to allow us to assume those functions by the end of 2007.

Omnibus Agreement

On March 31, 2006, we entered into an amended and restated omnibus agreement (the 2006 Omnibus Agreement) with Valero Energy, NuStar GP, LLC, Riverwalk Logistics, L.P., and NuStar Logistics. The 2006 Omnibus Agreement superseded the Omnibus Agreement among the parties dated effective April 16, 2001. The 2006 Omnibus Agreement governed potential competition between Valero Energy and us.

With the closing of NuStar GP Holding’s secondary public offering on December 22, 2006, Valero Energy ceased to own 20% or more of us, which allows Valero Energy to compete with us.

Also under the 2006 Omnibus Agreement, Valero Energy agreed to indemnify us for environmental liabilities related to the assets transferred to us in connection with our initial public offering, provided that such liabilities arose prior to and are discovered within ten years after that date (excluding liabilities resulting from a change in law after April 16, 2001).

Pipelines and Terminals Usage Agreement—McKee, Three Rivers and Ardmore

Under the terms of the Pipelines and Terminals Usage Agreement dated April 16, 2001, we provide transportation services that support Valero Energy’s refining and marketing operations relating to the McKee, Three Rivers and Ardmore refineries. Pursuant to the agreement, Valero Energy has agreed through April 2008:

| • |  | to transport in our crude oil pipelines at least 75% of the aggregate volumes of crude oil shipped to the McKee, Three Rivers and Ardmore refineries;

| • |  | to transport in our refined product pipelines at least 75% of the aggregate volumes of refined products shipped from the McKee, Three Rivers and Ardmore refineries; and

| • |  | to use our refined product terminals for terminalling services for at least 50% of all refined products shipped from the McKee, Three Rivers and Ardmore refineries.

If market conditions change with respect to the transportation of crude oil or refined products, or to the end markets in which Valero Energy sells refined products, 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 that serve the McKee, Three Rivers and Ardmore refineries 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.

In the event Valero Energy does not transport in our pipelines or use our terminals to handle the minimum volume requirements and if its obligation has not been suspended under the terms of the agreement, Valero Energy will be required to make a cash payment determined by multiplying the shortfall in volume by the applicable weighted average pipeline tariff or terminal fee. For the years ended December 31, 2007, 2006 and 2005, Valero Energy exceeded its obligations under the Pipelines and Terminals Usage Agreement. Additionally, Valero Energy has agreed not to challenge, or cause others to challenge, our interstate or intrastate tariffs for the transportation of crude oil and refined products until at least April 2008.

Crude Oil Storage Tank Agreements

In conjunction with the acquisition of the Crude Oil Storage Tanks in March 2003, we entered into the following agreements with Valero Energy:

| • |  | Handling and Throughput Agreement, dated March 2003, pursuant to which Valero Energy agreed to pay us a fee for 100% of crude oil and certain other feedstocks delivered to each of the Corpus Christi West refinery, the Texas City refinery and the Benicia refinery and to use our logistic assets for handling all deliveries to these refineries. The throughput fees are adjustable annually, generally based on 75% of the regional consumer price index applicable to the location of each refinery. The initial term of the handling and throughput agreement is ten years, which may be extended by Valero Energy for up to an additional five years.

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| • |  | Services and Secondment Agreements, dated March 2003, pursuant to which Valero Energy agreed to provide personnel to us who perform operating and routine maintenance services related to the crude oil storage tank operations. The annual reimbursement for those services is an aggregate $3.5 million. The initial term of the services and secondment agreements is ten years, which we may extend for an additional five years. In addition to the fees we have agreed to pay Valero Energy under the services and secondment agreements, we are responsible for operating expenses and specified capital expenditures related to the tank assets that are not addressed in the services and secondment agreements. These operating expenses and capital expenditures include tank safety inspections, maintenance and repairs, certain environmental expenses, insurance premiums and ad valorem taxes.

| • |  | Lease and Access Agreements, dated March 2003, pursuant to which Valero Energy leases to us the land on which the crude oil storage tanks are located for an aggregate amount of $0.7 million per year. The initial term of each lease is 25 years, subject to automatic renewal for successive one-year periods thereafter. We may terminate any of these leases upon 30 days notice after the initial term or at the end of a renewal period. In addition, we may terminate any of these leases upon 180 days notice prior to the expiration of the current term if we cease to operate the crude oil storage tanks or cease business operations.

South Texas Pipelines and Terminals Agreements

In conjunction with the acquisition of the South Texas Pipelines and Terminals in March 2003, we entered into the following agreements with Valero Energy:

| • |  | Terminalling Agreement, dated March 2003, pursuant to which Valero Energy agreed, during the initial period of five years, to pay a terminalling fee for each barrel of refined product stored or handled by or on behalf of Valero Energy at the terminals, including an additive fee for gasoline additive blended at the terminals. At the Houston Hobby Airport terminal, Valero Energy agreed to pay a filtering fee for each barrel of jet fuel stored or handled at the terminal.

| • |  | Throughput Commitment Agreement, dated March 2003, pursuant to which Valero Energy agreed, for an initial period of seven years:

| - |  | to transport in the Houston and Valley pipeline systems an aggregate of 40% of the Corpus Christi refineries’ gasoline and distillate production but only if the combined throughput in these pipelines is less than 110,000 barrels per day;

| - |  | to transport in the Pettus to San Antonio refined product pipeline 25% of the Three Rivers refinery gasoline and distillate production and in the Pettus to Corpus Christi refined product pipeline 90% of the Three Rivers refinery raffinate production;

| - |  | to use the Houston asphalt terminal for an aggregate of 7% of the asphalt production of the Corpus Christi refineries;

| - |  | to use the Edinburg refined product terminal for an aggregate of 7% of the gasoline and distillate production of the Corpus Christi refineries, but only if the throughput at this terminal is less than 20,000 barrels per day; and

| - |  | to use the San Antonio East terminal for 75% of the throughput in the Pettus to San Antonio refined product pipeline.

In the event Valero Energy does not transport in our pipelines or use our terminals to handle the minimum volume requirements and if its obligation has not been suspended under the terms of the agreement, Valero Energy will be required to make a cash payment determined by multiplying the shortfall in volume by the applicable weighted average pipeline tariff or terminal fee. Valero Energy’s obligation to transport 90% of the Three Rivers refinery raffinate production in the Pettus to Corpus Christi refined product pipeline was suspended in the fourth quarter of 2005 due to the temporary idling of the pipeline in the fourth quarter of 2005.

St. James Terminalling Agreement

On December 1, 2006, we executed a terminal services agreement with Valero Energy for the St. James, Louisiana crude oil facility (the St. James Terminal Agreement). Pursuant to the St. James Terminal Agreement, we will provide crude oil storage and blending services to Valero Energy for a minimum throughput fee of $1.175 million per month, plus $0.08 per barrel throughput in excess of 4 million barrels per month and $0.03 per barrel blended. The St. James Terminal Agreement has an initial term of five years, with an option to extend for an additional five years, provided that Valero Energy provides notice of its intent to extend the term at least one year prior to the expiration of the initial term.

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Corpus Christi North Beach Storage Facility

Effective January 1, 2007, we entered into a one-year terminal service agreement with Valero Energy for the 1.6 million barrels of capacity at our Corpus Christi North Beach storage facility. This agreement automatically renewed from year-to-year until either party elected to terminate upon 90-days written notice. This agreement was terminated on December 31, 2007.

We entered into a five-year shell barrel capacity lease agreement with Valero Energy on January 1, 2008 for the 1.6 million barrels of capacity at our Corpus Christi North Beach storage facility for $0.56 million per month. This lease automatically renews for additional one-year terms after the initial term unless either party terminates it with a 90-day written notice. Pursuant to this agreement, Valero Energy has agreed to maintain an annual average throughput of at least 70,000 barrels per day. In the event Valero Energy does not maintain the minimum guaranteed annual volume, Valero Energy will be required to make a cash payment determined by multiplying the shortfall in volume by a per barrel rate.

Other Agreements

We have other minor storage and throughput contracts with Valero Energy.

15. EMPLOYEE BENEFIT PLANS

We rely on employees of NuStar GP, LLC to provide the necessary services to conduct our U.S. operations. Prior to July 1, 2006, the employees of NuStar GP, LLC were included in the various employee benefit plans of Valero Energy, which included a defined benefit pension plan, a retiree welfare benefit plan, health and welfare benefits, a defined contribution retirement plan, equity incentive plans and nonqualified deferred compensation plans. On July 19, 2006, employees of NuStar GP, LLC began participating in newly enacted, comparable plans sponsored by NuStar GP, LLC as follows:

| • |  | The NuStar GP, LLC Thrift Plan (the Thrift Plan), is a qualified employee profit-sharing plan which became effective June 26, 2006. Participation in the Thrift Plan is voluntary and is open to substantially all of NuStar GP, LLC employees who become eligible to participate upon date of hire. Thrift Plan participants can make basic contributions from 1% up to 30% of their total annual compensation. The maximum match by NuStar GP, LLC is 75% of each participant’s basic contributions up to 8% based on the participant’s total annual compensation. Effective January 1, 2008, the Thrift Plan was amended to change the maximum match by NuStar GP, LLC to 100% of each participant’s total contribution up to 6% based on the participant’s total annual compensation.

| • |  | The NuStar GP, LLC Pension Plan (the Pension Plan), is a qualified non-contributory defined benefit plan which became effective July 6, 2006. The Pension Plan covers substantially all of NuStar GP, LLC’s employees and generally provides eligible employees with retirement income based on years of service and compensation during the period of service. Employees may become eligible to receive benefits after five years of service, including service recognized by Valero Energy for vesting purposes under the Valero Energy pension plan. All benefit obligations associated with service for certain employees who were participants in the Valero Energy pension plan through June 30, 2006, including the effect of future salary increases, are the responsibility of Valero Energy. All benefit obligations related to service by NuStar GP, LLC employees on or after July 1, 2006 will be covered by the Pension Plan. Effective January 1, 2008, the plan was amended to change the name of the plan to the NuStar Pension Plan.

| • |  | The NuStar GP, LLC Excess Thrift Plan (the Excess Thrift Plan), which became effective July 1, 2006, provides benefits to a select group of management or other highly compensated employees. The Excess Thrift Plan provides benefits to those employees of NuStar GP, LLC whose annual additions under the Thrift Plan are subject to the limitations on such annual additions as provided under §415 of the Internal Revenue Code of 1986, as amended (the Code), and/or who are constrained from making maximum contributions under the Thrift Plan by §401(a)(17) of the Code, which limits the amount of an employee’s annual compensation which may be taken into

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| account under that plan. The contribution to the Excess Thrift Plan is equivalent to the matching contributions that would have been credited to the employee’s qualified Thrift Plan account for matching contributions had the plan contributions not been impacted by various IRS limits. The Excess Thrift Plan is comprised of two separate components, consisting of (1) an “excess benefit plan” as defined under §3(36) of The Employee Retirement Income Security Act of 1974, as amended (ERISA) and (2) a plan that is unfunded and maintained primarily for the purpose of providing deferred compensation for a select group of management or highly compensated employees. Each component of the Excess Thrift Plan shall consist of a separate plan for purposes of Title I of ERISA.

| • |  | The NuStar GP, LLC Excess Pension Plan (the Excess Pension Plan) provides benefits to those employees of NuStar GP, LLC whose pension benefits under the Pension Plan and the Valero Energy pension plan (where applicable) are subject to limitations under the Code, or who are otherwise indirectly constrained by the Code from realizing the maximum benefit available to them under the terms of the Pension Plan and the Valero Energy pension plan (where applicable). Effective as of July 1, 2006, eligible NuStar GP, LLC employees ceased accruing additional benefits under Valero Energy’s excess pension plan (the Prior Excess Pension Plan). The Excess Pension Plan is an “excess benefit plan” as defined under §3(36) of ERISA, for those benefits provided in excess of Section 415 of the Code. Benefits provided as a result of other statutory limitations are limited to a select group of management or other highly compensated employees. The Excess Pension Plan provides a single, nonqualified defined benefit to those NuStar GP, LLC employees for their pre-July 1, 2006 benefit accruals under the Prior Excess Pension Plan and their post-July 1, 2006 benefit accruals under the Excess Pension Plan.

| • |  | The NuStar GP, LLC Supplemental Executive Retirement Plan (the SERP) provides those highly compensated, management personnel of NuStar GP, LLC who were accruing benefits under the Valero Energy supplemental executive retirement plan (Prior SERP) up until July 1, 2006, and those who may subsequently become eligible, with a supplement to the retirement benefit they may otherwise receive under the Pension Plan and the Valero Energy pension plan (where applicable). The SERP provides a single, nonqualified defined benefit to those NuStar GP, LLC employees for their pre-July 1, 2006 benefit accruals under the Prior SERP and their post-July 1, 2006 benefit accruals under the SERP.

| • |  | The NuStar GP, LLC Retiree Benefits Plan is a post-retirement medical benefits plan effective July 1, 2006 from which benefits became payable to eligible employees beginning January 1, 2007. NuStar GP, LLC retained the liabilities for the benefit obligations related to the postretirement medical benefits for those employees who are not “retirement eligible” (employees over 55 years old with five years of service and eligible to receive benefits under the Valero Energy pension plan) on July 19, 2006, and certain long-term disability benefits (LTD) under the Valero Energy flex benefits plan totaling $6.1 million and $0.7 million, respectively, as of July 1, 2006. Valero Energy retained the responsibility for the postretirement medical benefit obligation for employees who were retirement eligible on July 19, 2006, and those who subsequently become retirement eligible and elected to receive a benefit on or before December 31, 2006 under the Valero Energy pension plan.

None of the Excess Thrift Plan, the Excess Pension Plan or the SERP is intended to constitute either a qualified plan under the provisions of Section 401 of the Code or a funded plan subject to ERISA. All costs incurred by our general partner related to these employee benefit plans, excluding compensation expense related to the long-term incentive plans, were and will continue to be reimbursed by us at cost. Effective January 1, 2008, in compliance with recently issued section 409(a) of the Code, the Excess Pension Plan and the SERP were amended to provide that all benefits under those plans will be paid in a single lump-sum payment.

Long-Term Incentive Plans

Our general partner also sponsors the following:

| • |  | The Second Amended and Restated 2000 Long-Term Incentive Plan (the 2000 LTIP), under which NuStar GP, LLC may award up to 1,500,000 common units. Awards under the 2000 LTIP can include unit options, restricted units, performance awards, distribution equivalent rights (DERs) and contractual rights to receive common units. As of December 31, 2007, a total of 711,602 common units remained available to be awarded under the UIP.

| • |  | The 2003 Employee Unit Incentive Plan (the UIP) under which NuStar GP, LLC may award up to 500,000 NuStar Energy common units to employees of NuStar GP, LLC or its affiliates, excluding officers and directors of NuStar GP, LLC and its affiliates. Awards under the UIP can include unit options, restricted units and distribution equivalent rights (DERs). As of December 31, 2007, a total of 265,326 common units remained available to be awarded under the UIP.

| • |  | The 2002 Unit Option Plan (the UOP) under which NuStar GP, LLC may award up to 200,000 NuStar Energy unit options to officers and directors of NuStar GP, LLC or its affiliates, of which substantially all of the unit options have been awarded as of December 31, 2007.

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| • |  | The 2006 Long-Term Incentive Plan (the 2006 LTIP) under which NuStar GP Holdings may award up to 2,000,000 units to employees, consultants and directors of NuStar GP Holdings and its affiliates, including us. Awards under the 2006 LTIP can include unit options, performance units, restricted units, phantom units, unit grants and unit appreciation rights of NuStar GP Holdings, LLC. As of December 31, 2007, a total of 1,667,637 NuStar GP Holdings units remained available to be awarded under the 2006 LTIP.

Our share of compensation expense related to the various long term incentive plans described previously, except for grants to non-employee directors of NuStar GP Holdings, was $3.8 million, $2.4 million and $1.5 million, respectively, for the years ended December 31, 2007, 2006 and 2005. We record such amounts in “General and administrative expenses” in the consolidated statements of income for those years.

The number of awards granted under the above noted plans were as follows:

|  | Year Ended December 31,
|  | 2007 |  |  | 2006 |  | 2005
|  | Granted |  | Vesting |  |  | Granted |  | Vesting |  | Granted |  | Vesting
2000 LTIP: |  |  |  |  |  |  |  |  |  |  |  |  |
Performance awards |  | 10,840 |  | 1/3 per year |  |  | 8,940 |  | 1/3 per year |  | — |  | —
Unit options |  | 204,675 |  | 1/5 per year |  |  | 203,975 |  | 1/5 per year |  | 25,075 |  | 1/5 per year
Restricted units |  | 117,575 |  | 1/5 per year |  |  | 51,140 |  | 1/5 per year |  | 14,920 |  | 1/5 per year
Restricted units (grants to non-employee directors of NuStar GP, LLC) |  | 3,510 |  | 1/3 per year |  |  | 2,307 |  | 1/3 per year |  | 1,340 |  | 1/3 per year
UOP |  | — |  | — |  |  | — |  | — |  | 14,925 |  | 1/5 per year
UIP: |  |  |  |  |  |  |  |  |  |  |  |  |
Unit options |  | — |  | — |  |  | 15,200 |  | 1/5 per year |  | 128,300 |  | 1/5 per year
Restricted units |  | 12,730 |  | 1/5 per year |  |  | 9,740 |  | 1/5 per year |  | 31,800 |  | 1/5 per year
2006 LTIP: |  |  |  |  |  |  |  |  |  |  |  |  |
Unit options |  | 324,100 |  | (a | ) |  | — |  | — |  | — |  | —
Restricted units (grants to non-employee directors of NuStar GP Holdings) |  | 5,489 |  | 1/3 per year |  |  | 2,886 |  | 1/3 per year |  | — |  | —

(a) | Unit options granted under the 2006 LTIP vest in annual one-third increments beginning on the third anniversary of the grant date.

16. PARTNERS’ EQUITY, ALLOCATIONS OF NET INCOME AND CASH DISTRIBUTIONS

Partners’ Equity

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 July 1, 2005, we issued 23,768,355 of our common units valued at approximately $1.45 billion in exchange for all of the outstanding common units of KPP. In order to maintain a 2% general partner interest, Riverwalk Logistics, L.P. contributed $29.2 million to us.

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Subordinated Units

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. Riverwalk Holdings, LLC held the 9,599,322 subordinated units at the time of conversion.

Allocations of Net Income

Our partnership agreement, as amended, sets forth the calculation to be used to determine the amount and priority of cash distributions that the common unitholders, subordinated unitholders and general partner will receive. The partnership agreement also contains provisions for the allocation of net income and loss to the unitholders and the general partner. For purposes of maintaining partner capital accounts, the partnership agreement specifies that items of income and loss shall be allocated among the partners in accordance with their respective percentage interests. Normal allocations according to percentage interests are done after giving effect, if any, to priority income allocations in an amount equal to incentive cash distributions allocated 100% to the general partner.

During the year ended December 31, 2006, our general partner reimbursed us for certain charges we incurred related to services historically provided under our services agreement with Valero Energy. United States generally accepted accounting principles required us to record the charges as expenses and record the reimbursement as a capital contribution.

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

|  | Year Ended December 31, |
|  | 2007 |  |  | 2006 |  |  | 2005 |
|  | (Thousands of Dollars) |
Net income applicable to general partner and limited partners’ interest |  | $ | 150,298 |  |  | $ | 149,530 |  |  | $ | 111,073 |
Charges reimbursed by general partner |  |  | — |  |  |  | 575 |  |  |  | — |
Net income before charges reimbursed by general partner |  |  | 150,298 |  |  |  | 150,105 |  |  |  | 111,073 |
Less general partner incentive distribution |  |  | 18,426 |  |  |  | 14,778 |  |  |  | 8,711 |
Net income before charges reimbursed by general partner and after general partner incentive distribution |  |  | 131,872 |  |  |  | 135,327 |  |  |  | 102,362 |
General partner interest |  |  | 2 | % |  |  | 2 | % |  |  | 2 | %
General partner allocation of net income before charges reimbursed by general partner and after general partner incentive distribution |  |  | 2,637 |  |  |  | 2,707 |  |  |  | 2,047 |
Charges reimbursed by general partner |  |  | — |  |  |  | (575 | ) |  |  | — |
General partner incentive distribution |  |  | 18,426 |  |  |  | 14,778 |  |  |  | 8,711 |
Net income applicable to general partner |  | $ | 21,063 |  |  | $ | 16,910 |  |  | $ | 10,758 |

Cash Distributions

We make quarterly distributions of 100% of our available cash, generally defined as cash receipts less cash disbursements and cash reserves established by the general partner, in its sole discretion. These quarterly distributions are declared and paid within 45 days subsequent to each quarter-end. The limited partner unitholders are entitled to receive each quarter a

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minimum quarterly distribution of $0.60 per unit ($2.40 annualized). Our cash is first distributed 98% to the limited partners and 2% to the general partner until there has been distributed to the unitholders an amount equal to the minimum quarterly distribution and arrearages in the payment of the minimum quarterly distribution for any prior quarter. Thirdly, cash in excess of the minimum quarterly distributions is distributed to the unitholders and the general partner based on the percentages shown below.

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

Quarterly Distribution Amount per Unit |  | Percentage of Distribution |
| Unitholders |  |  | General Partner |
Up to $0.60 |  | 98 | % |  | 2 | %
Above $0.60 up to $0.66 |  | 90 | % |  | 10 | %
Above $0.66 |  | 75 | % |  | 25 | %

The table set forth below shows our cash distributions earned for the periods shown with respect to the general and limited partners:

|  | Year Ended December 31,
|  | 2007 |  | 2006 |  | 2005(a)
|  | (Thousands of Dollars, Except Per Unit Data)
General partner interest |  | $ | 4,092 |  | $ | 3,742 |  | $ | 3,036
General partner incentive distribution |  |  | 18,426 |  |  | 14,778 |  |  | 10,259
Total general partner distribution |  |  | 22,518 |  |  | 18,520 |  |  | 13,295
Limited partners’ distribution |  |  | 182,076 |  |  | 168,515 |  |  | 138,500
Total cash distributions |  | $ | 204,594 |  | $ | 187,035 |  | $ | 151,795
Cash distributions per unit applicable to limited partners |  | $ | 3.835 |  | $ | 3.600 |  | $ | 3.365

(a) | For the second quarter 2005, our net income allocation to general and limited partners reflected a total cash distribution based on the partnership interests outstanding as of June 30, 2005. On July 1, 2005, we issued approximately 23.8 million of our common units in exchange for all outstanding units of KPP in connection with the Kaneb Acquisition. Actual distribution payments are made within 45 days after the end of each quarter as of a record date that is set after the end of each quarter. As such, the actual cash payment made with respect to the second quarter 2005 included the distributions paid to former Kaneb unitholders. The general partner’s portion of the actual cash payment made with respect to the second quarter 2005 was higher than the net income allocation to the general partner as the units had increased prior to the record date. Therefore, the distribution paid related to the year ended December 31, 2005 is more than the amount allocated to the general partner in our net income allocation.

On January 24, 2008, we declared a quarterly cash distribution of $0.985 which was paid on February 14, 2008 to unitholders of record on February 7, 2008. This distribution related to the fourth quarter of 2007 and totaled $55.0 million, of which $6.3 million represented the general partner’s share of such distribution. The general partner’s distribution included a $5.2 million incentive distribution.

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17. STATEMENTS OF CASH FLOWS

Changes in current assets and current liabilities were as follows:

|  | Year Ended December 31, |
|  | 2007 |  |  | 2006 |  |  | 2005 |
|  | (Thousands of Dollars) |
Decrease (increase) in current assets: |  |  |  |  |  |  |  |  |  |  |  |
Accounts receivable notes receivable |  | $ | (22,079 | ) |  | $ | 27,307 |  |  | $ | (39,397 | )
Receivable from related party |  |  | (786 | ) |  |  | 1,168 |  |  |  | (2,678 | )
Inventories |  |  | (71,457 | ) |  |  | 257 |  |  |  | (6,042 | )
Other current assets |  |  | (8,603 | ) |  |  | 6,181 |  |  |  | (11,475 | )
Increase (decrease) in current liabilities: |  |  |  |  |  |  |  |  |  |  |  |
Payable to related party |  |  | (2,315 | ) |  |  | (9,493 | ) |  |  | 8,634 |
Accounts payable |  |  | 72,918 |  |  |  | (7,106 | ) |  |  | 58,920 |
Accrued interest payable |  |  | 182 |  |  |  | 1,135 |  |  |  | (259 | )
Accrued liabilities |  |  | 9,546 |  |  |  | (8,300 | ) |  |  | (3,782 | )
Taxes other than income taxes |  |  | 2 |  |  |  | 1,345 |  |  |  | (3,323 | )
Income taxes payable |  |  | 1,266 |  |  |  | (1,799 | ) |  |  | (534 | )
Changes in current assets and current liabilities |  | $ | (21,326 | ) |  | $ | 10,695 |  |  | $ | 64 |

Cash flows related to interest and income taxes were as follows:

|  | Year Ended December 31,
|  | 2007 |  | 2006 |  | 2005
|  | (Thousands of Dollars)
Cash paid for interest, net of amount capitalized |  | $ | 83,450 |  | $ | 73,206 |  | $ | 52,154
Cash paid for income taxes, net of tax refunds received |  | $ | 9,081 |  | $ | 7,234 |  | $ | 1,663

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

| • |  | adjustments to property and equipment, goodwill and intangible assets resulting from adjustments to the purchase price allocations related to the St. James Acquisition;

| • |  | acquisition of other current assets in exchange for a note payable; and

| • |  | adjustments to the fair value of our interest rate swap agreements.

Non-cash investing activities for the year ended December 31, 2006 included adjustments mainly to property and equipment and goodwill resulting from the final purchase price allocation related to the Kaneb Acquisition.

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18. OTHER INCOME

Other income consisted of the following:

|  | Year Ended December 31, |
|  | 2007 |  |  | 2006 |  | 2005 |
|  | (Thousands of Dollars) |
2007 Services Agreement termination fee (see Note 14) |  | $ | 13,000 |  |  | $ | — |  | $ | — |
Business interruption insurance |  |  | 12,492 |  |  |  | — |  |  | — |
Sale of net profit interest in coal mine |  |  | 7,250 |  |  |  | — |  |  | — |
Legal settlements |  |  | 5,758 |  |  |  | — |  |  | — |
Foreign exchange (losses) gains |  |  | (6,261 | ) |  |  | 1,011 |  |  | (139 | )
Other |  |  | 6,591 |  |  |  | 2,241 |  |  | (1,356 | )
Other income (expense), net |  | $ | 38,830 |  |  | $ | 3,252 |  | $ | (1,495 | )

The business interruption insurance amount consists of insurance proceeds related to lost earnings at our pipelines and terminals that serve Valero Energy’s McKee refinery, which experienced a fire in February 2007.

19. INCOME TAXES

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

|  | Year Ended December 31,
|  | 2007 |  |  | 2006 |  |  | 2005
|  | (Thousands of Dollars)
Current: |  |  |  |  |  |  |  |  |  |  |
U.S. |  | $ | 2,373 |  |  | $ | 245 |  |  | $ | —
Foreign |  |  | 8,799 |  |  |  | 5,690 |  |  |  | 430
Total current |  |  | 11,172 |  |  |  | 5,935 |  |  |  | 430
Deferred: |  |  |  |  |  |  |  |  |  |  |
U.S. |  |  | 827 |  |  |  | (3,681 | ) |  |  | 892
Foreign |  |  | (551 | ) |  |  | 3,607 |  |  |  | 3,391
Total deferred |  |  | 276 |  |  |  | (74 | ) |  |  | 4,283
Total income tax expense |  | $ | 11,448 |  |  | $ | 5,861 |  |  | $ | 4,713

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

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

|  | December 31, |
|  | 2007 |  |  | 2006 |
|  | (Thousands of Dollars) |
U.S.: |  |  |  |  |  |  |  |
Net operating losses |  | $ | 21,509 |  |  | $ | 19,257 |
Environmental and legal reserves |  |  | 14,611 |  |  |  | 14,699 |
Other |  |  | 784 |  |  |  | 377 |
Valuation allowance |  |  | (13,276 | ) |  |  | (9,744 | )
Deferred tax assets – U.S. |  |  | 23,628 |  |  |  | 24,589 |
Property and equipment |  |  | (13,006 | ) |  |  | (13,247 | )
Net deferred income tax asset – U.S. |  | $ | 10,622 |  |  | $ | 11,342 |
Foreign: |  |  |  |  |  |  |  |
Environmental and legal reserves |  | $ | — |  |  | $ | 338 |
Other |  |  | 1,057 |  |  |  | 142 |
Capital loss |  |  | 2,292 |  |  |  | — |
Valuation allowance |  |  | (1,977 | ) |  |  | — |
Deferred tax assets – foreign |  |  | 1,372 |  |  |  | 480 |
Property and equipment |  |  | (35,568 | ) |  |  | (33,406 | )
Net deferred income tax liability – foreign |  | $ | (34,196 | ) |  | $ | (32,926 | )

Our U.S. corporate operations have net operating loss carryforwards for tax purposes totaling approximately $61.5 million, which are subject to various limitations on use and expire in years 2008 through 2027.

As of December 31, 2007 and 2006, we have recorded a valuation allowance, substantially all of which was recorded in conjunction with the allocation of the purchase price of the Kaneb Acquisition, due to uncertainties related to our ability to utilize some of our deferred income tax assets, primarily consisting of certain federal net operating loss carryforwards, before they expire. The net change in the total valuation allowance for the year ended December 31, 2007 was an increase of $5.5 million. The valuation allowance is based on our estimates of taxable income in the various jurisdictions in which we operate and the period over which deferred income tax assets will be recoverable.

The realization of net deferred income tax assets recorded as of December 31, 2007 is dependent upon our ability to generate future taxable income in the United States. We believe it is more likely than not that the deferred income tax assets, net of the valuation allowance, as of December 31, 2007 will be realized, based on expected future taxable income and potential tax planning strategies.

St. Eustatius Tax Agreement

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

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

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

20. SEGMENT INFORMATION

Our operating segments consist of refined product terminals, refined product pipelines, crude oil pipelines, crude oil storage tanks and marketing. These reportable segments are strategic business units that offer different services and performance is evaluated based on operating income, before general and administrative expenses. General and administrative expenses are not allocated to the operating segments since those expenses relate primarily to the overall management at the entity level. Our principal services include providing pipeline transportation services, terminalling services, storage lease services and crude oil storage handling services. Product sales included in our marketing segment consist of sales of petroleum products 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 information such that all product sales and related costs and assets are included in the marketing segment. Previous periods have been restated to conform to this presentation. Intersegment revenues are derived from storage and throughput rates consistent with rates charged to third parties and pipeline tariffs based upon the published tariff applicable to all shippers.

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Results of operations for the reportable segments were as follows:

|  | Year Ended December 31, |
|  | 2007 |  |  | 2006 |  |  | 2005 |
|  | (Thousands of Dollars) |
Revenues: |  |  |  |  |  |  |  |  |  |  |  |
Refined product terminals: |  |  |  |  |  |  |  |  |  |  |  |
Third party revenues |  | $ | 354,821 |  |  | $ | 308,229 |  |  | $ | 164,729 |
Intersegment revenues |  |  | 10,569 |  |  |  | 8,269 |  |  |  | 5,963 |
Total refined product terminals |  |  | 365,390 |  |  |  | 316,498 |  |  |  | 170,692 |
Refined product pipelines: |  |  |  |  |  |  |  |  |  |  |  |
Third party revenues |  |  | 243,597 |  |  |  | 222,356 |  |  |  | 149,853 |
Intersegment revenues |  |  | 231 |  |  |  | — |  |  |  | — |
Total refined product pipelines |  |  | 243,828 |  |  |  | 222,356 |  |  |  | 149,853 |
Crude oil pipelines |  |  | 52,968 |  |  |  | 58,654 |  |  |  | 51,429 |
Crude oil storage tanks |  |  | 45,237 |  |  |  | 46,915 |  |  |  | 46,943 |
Marketing |  |  | 778,391 |  |  |  | 501,107 |  |  |  | 246,603 |
Consolidation and intersegment eliminations |  |  | (10,800 | ) |  |  | (8,269 | ) |  |  | (5,963 | )
Total revenues |  | $ | 1,475,014 |  |  | $ | 1,137,261 |  |  | $ | 659,557 |
Depreciation and amortization: |  |  |  |  |  |  |  |  |  |  |  |
Refined product terminals |  | $ | 54,635 |  |  | $ | 45,485 |  |  | $ | 25,008 |
Refined product pipelines |  |  | 45,006 |  |  |  | 42,084 |  |  |  | 27,778 |
Crude oil pipelines |  |  | 4,940 |  |  |  | 5,061 |  |  |  | 4,612 |
Crude oil storage tanks |  |  | 7,682 |  |  |  | 7,636 |  |  |  | 7,497 |
Marketing |  |  | 423 |  |  |  | — |  |  |  | — |
Consolidation and intersegment eliminations |  |  | 1,607 |  |  |  | — |  |  |  | — |
Total depreciation and amortization |  | $ | 114,293 |  |  | $ | 100,266 |  |  | $ | 64,895 |
Operating income: |  |  |  |  |  |  |  |  |  |  |  |
Refined product terminals |  | $ | 88,865 |  |  | $ | 79,315 |  |  | $ | 51,377 |
Refined product pipelines |  |  | 93,812 |  |  |  | 85,946 |  |  |  | 56,621 |
Crude oil pipelines |  |  | 32,696 |  |  |  | 36,768 |  |  |  | 30,439 |
Crude oil storage tanks |  |  | 25,770 |  |  |  | 29,171 |  |  |  | 29,751 |
Marketing |  |  | 21,111 |  |  |  | 26,915 |  |  |  | 11,317 |
Consolidation and intersegment eliminations |  |  | (1,740 | ) |  |  | — |  |  |  | — |
Total segment operating income |  |  | 260,514 |  |  |  | 258,115 |  |  |  | 179,505 |
Less general and administrative expenses |  |  | 67,915 |  |  |  | 45,216 |  |  |  | 26,553 |
Total operating income |  | $ | 192,599 |  |  | $ | 212,899 |  |  | $ | 152,952 |

Revenues by geographic area for the years ended December 31, 2007, 2006 and 2005 are shown in the table below. The geographic area is based on the location of our customer.

|  | Year Ended December 31,
|  | 2007 |  | 2006 |  | 2005
|  | (Thousands of Dollars)
United States |  | $ | 655,013 |  | $ | 501,756 |  | $ | 347,765
Netherlands Antilles |  |  | 719,084 |  |  | 537,626 |  |  | 255,893
Canada |  |  | 44,927 |  |  | 51,203 |  |  | 35,639
Other countries |  |  | 55,990 |  |  | 46,676 |  |  | 20,260
Consolidated revenues |  | $ | 1,475,014 |  | $ | 1,137,261 |  | $ | 659,557

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NUSTAR ENERGY L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

For the years ended December 31, 2007, 2006, and 2005, Valero Energy accounted for 18%, 23% and 34% of our consolidated revenues, respectively. No other single customer accounted for more than 10% of our consolidated revenues.

Revenues from Valero Energy by operating segment were as follows:

|  | Year Ended December 31,
|  | 2007 |  | 2006 |  | 2005
|  | (Thousands of Dollars)
Revenues: |  |  |  |  |  |  |  |  |
Refined product terminals |  | $ | 70,180 |  | $ | 53,154 |  | $ | 46,382
Refined product pipelines |  |  | 96,966 |  |  | 104,519 |  |  | 89,731
Crude oil pipelines |  |  | 50,631 |  |  | 56,392 |  |  | 51,429
Crude oil storage tanks |  |  | 45,237 |  |  | 46,915 |  |  | 46,943
Marketing |  |  | 7,426 |  |  | — |  |  | —
Total revenues |  | $ | 270,440 |  | $ | 260,980 |  | $ | 234,485

Long-lived assets include property, plant and equipment, intangible assets subject to amortization and certain long-lived assets included in “Deferred charges and other assets, net” on the consolidated balance sheets. Geographic information by country for long-lived assets consisted of the following:

|  | December 31,
|  | 2007 |  | 2006
|  | (Thousands of Dollars)
United States |  | $ | 2,109,594 |  | $ | 2,050,387
Netherlands Antilles |  |  | 252,024 |  |  | 240,323
Canada |  |  | 95,618 |  |  | 82,410
United Kingdom |  |  | 92,149 |  |  | 90,594
Netherlands |  |  | 90,157 |  |  | 20,903
Mexico |  |  | 11,392 |  |  | 22,152
Consolidated long-lived assets |  | $ | 2,650,934 |  | $ | 2,506,769

Total assets by reportable segment were as follows:

|  | December 31,
|  | 2007 |  | 2006
|  | (Thousands of Dollars)
Refined product terminals |  | $ | 1,925,592 |  | $ | 1,776,431
Refined product pipelines |  |  | 1,245,891 |  |  | 1,250,466
Crude oil pipelines |  |  | 127,706 |  |  | 132,407
Crude oil storage tanks |  |  | 190,876 |  |  | 197,902
Marketing |  |  | 171,028 |  |  | 54,153
Total segment assets |  |  | 3,661,093 |  |  | 3,411,359
Other partnership assets (including current assets and other noncurrent assets) |  |  | 121,994 |  |  | 82,849
Total consolidated assets |  | $ | 3,783,087 |  | $ | 3,494,208

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NUSTAR ENERGY L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

Changes in the carrying amount of goodwill were as follows:

|  | Refined Product Terminals |  |  | Refined Product Pipelines |  |  | Crude Oil Pipelines |  | Total |
|  | (Thousands of Dollars) |
Balance as of January 1, 2006 |  | $ | 569,745 |  |  | $ | 193,646 |  |  | $ | 4,196 |  | $ | 767,587 |
Kaneb Acquisition final purchase price allocation |  |  | 27,865 |  |  |  | (21,011 | ) |  |  | — |  |  | 6,854 |
Balance as of December 31, 2006 |  |  | 597,610 |  |  |  | 172,635 |  |  |  | 4,196 |  |  | 774,441 |
St. James Acquisition final purchase price allocation |  |  | 13,898 |  |  |  | — |  |  |  | — |  |  | 13,898 |
Other |  |  | (1,856 | ) |  |  | (1,464 | ) |  |  | — |  |  | (3,320 | )
Balance as of December 31, 2007 |  | $ | 609,652 |  |  | $ | 171,171 |  |  | $ | 4,196 |  | $ | 785,019 |

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

|  | Year Ended December 31,
|  | 2007 |  | 2006 |  | 2005
|  | (Thousands of Dollars)
Refined product terminals |  | $ | 202,208 |  | $ | 229,963 |  | $ | 761,099
Refined product pipelines |  |  | 25,120 |  |  | 41,739 |  |  | 748,392
Crude oil pipelines |  |  | 224 |  |  | 12,939 |  |  | 561
Crude oil storage tanks |  |  | 969 |  |  | 453 |  |  | 1,860
Marketing |  |  | 1,755 |  |  | — |  |  | —
Other partnership assets |  |  | 21,037 |  |  | 4,222 |  |  | 2,781
Total capital expenditures |  | $ | 251,313 |  | $ | 289,316 |  | $ | 1,514,693

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NUSTAR ENERGY L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

21. CONDENSED CONSOLIDATING FINANCIAL STATEMENTS

NuStar Energy has no operations and its assets consist mainly of its investments in NuStar Logistics and KPOP, both wholly-owned subsidiaries. The senior notes issued by NuStar Logistics and KPOP are fully and unconditionally guaranteed by NuStar Energy, and both NuStar Logistics and KPOP fully and unconditionally guarantee the outstanding senior notes of the other.

As a result, the following condensed consolidating financial statements are being presented as an alternative to providing separate financial statements for NuStar Logistics and KPOP.

Condensed Consolidating Balance Sheet

December 31, 2007

(Thousands of Dollars)

|  | NuStar Energy |  | NuStar Logistics |  | KPOP |  | Non- Guarantor Subsidiaries (a) |  | Eliminations |  |  | Consolidated
Assets |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Current assets |  | $ | 16 |  | $ | 80,362 |  | $ | 672,940 |  | $ | 279,412 |  | $ | (685,596 | ) |  | $ | 347,134
Property and equipment, net |  |  | — |  |  | 942,297 |  |  | 667,132 |  |  | 882,657 |  |  | — |  |  |  | 2,492,086
Intangible assets, net |  |  | — |  |  | 3,551 |  |  | — |  |  | 44,211 |  |  | — |  |  |  | 47,762
Goodwill |  |  | — |  |  | 18,613 |  |  | 170,652 |  |  | 595,754 |  |  | — |  |  |  | 785,019
Investment in wholly owned subsidiaries |  |  | 2,327,401 |  |  | 1,721 |  |  | 730,663 |  |  | 1,458,721 |  |  | (4,518,506 | ) |  |  | —
Investments in joint ventures |  |  | — |  |  | 16,640 |  |  | — |  |  | 63,726 |  |  | — |  |  |  | 80,366
Deferred income tax asset |  |  | — |  |  | — |  |  | — |  |  | 10,622 |  |  | — |  |  |  | 10,622
Deferred charges and other assets, net |  |  | 75 |  |  | 15,761 |  |  | 382 |  |  | 3,880 |  |  | — |  |  |  | 20,098
Total assets |  | $ | 2,327,492 |  | $ | 1,078,945 |  | $ | 2,241,769 |  | $ | 3,338,983 |  | $ | (5,204,102 | ) |  | $ | 3,783,087
Liabilities and Partners’ Equity |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Current liabilities Current liabilities |  | $ | 359,547 |  | $ | 53,665 |  | $ | 30,030 |  | $ | 484,764 |  | $ | (685,521 | ) |  | $ | 242,485
Long-term debt, less current portion |  |  | — |  |  | 865,105 |  |  | 538,893 |  |  | 41,628 |  |  | — |  |  |  | 1,445,626
Long-term payable to related party |  |  | — |  |  | — |  |  | — |  |  | 5,684 |  |  | — |  |  |  | 5,684
Deferred income tax liability |  |  | — |  |  | — |  |  | — |  |  | 34,196 |  |  | — |  |  |  | 34,196
Other long-term liabilities |  |  | — |  |  | 3,984 |  |  | 1,520 |  |  | 54,760 |  |  | — |  |  |  | 60,264
Total partners’ equity |  |  | 1,967,945 |  |  | 156,191 |  |  | 1,671,326 |  |  | 2,717,951 |  |  | (4,518,581 | ) |  |  | 1,994,832
Total liabilities and partners’ equity |  | $ | 2,327,492 |  | $ | 1,078,945 |  | $ | 2,241,769 |  | $ | 3,338,983 |  | $ | (5,204,102 | ) |  | $ | 3,783,087

(a) | Non-guarantor subsidiaries are wholly owned by NuStar Energy, NuStar Logistics or KPOP.

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NUSTAR ENERGY L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

Condensed Consolidating Balance Sheet

December 31, 2006

(Thousands of Dollars)

|  | NuStar Energy |  | NuStar Logistics |  | KPOP |  | Non- Guarantor Subsidiaries (a) |  | Eliminations |  |  | Consolidated
Assets |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Current assets |  | $ | 403 |  | $ | 115,210 |  | $ | 653,221 |  | $ | 145,807 |  | $ | (701,643 | ) |  | $ | 212,998
Property and equipment, net |  |  | — |  |  | 935,109 |  |  | 676,494 |  |  | 733,532 |  |  | — |  |  |  | 2,345,135
Intangible assets, net |  |  | — |  |  | 3,427 |  |  | — |  |  | 50,105 |  |  | — |  |  |  | 53,532
Goodwill |  |  | — |  |  | 4,715 |  |  | 172,116 |  |  | 597,610 |  |  | — |  |  |  | 774,441
Investment in wholly owned subsidiaries |  |  | 2,372,469 |  |  | 24,172 |  |  | 668,796 |  |  | 1,345,791 |  |  | (4,411,228 | ) |  |  | —
Investments in joint ventures |  |  | — |  |  | 15,902 |  |  | — |  |  | 58,175 |  |  | — |  |  |  | 74,077
Deferred income tax asset |  |  | — |  |  | — |  |  | — |  |  | 11,342 |  |  | — |  |  |  | 11,342
Deferred charges and other assets, net |  |  | 228 |  |  | 5,807 |  |  | 604 |  |  | 16,044 |  |  | — |  |  |  | 22,683
Total assets |  | $ | 2,373,100 |  | $ | 1,104,342 |  | $ | 2,171,231 |  | $ | 2,958,406 |  | $ | (5,112,871 | ) |  | $ | 3,494,208
Liabilities and Partners’ Equity |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Current liabilities |  | $ | 504,238 |  | $ | 44,397 |  | $ | 29,385 |  | $ | 280,358 |  | $ | (701,643 | ) |  | $ | 156,735
Long-term debt, less current portion |  |  | — |  |  | 767,031 |  |  | 545,571 |  |  | 41,118 |  |  | — |  |  |  | 1,353,720
Long-term payable to related party |  |  | — |  |  | — |  |  | — |  |  | 5,749 |  |  | — |  |  |  | 5,749
Deferred income tax liability |  |  | — |  |  | — |  |  | — |  |  | 32,926 |  |  | — |  |  |  | 32,926
Other long-term liabilities |  |  | — |  |  | 5,797 |  |  | 3,517 |  |  | 60,083 |  |  | — |  |  |  | 69,397
Total partners’ equity |  |  | 1,868,862 |  |  | 287,117 |  |  | 1,592,758 |  |  | 2,538,172 |  |  | (4,411,228 | ) |  |  | 1,875,681
Total liabilities and partners’ equity |  | $ | 2,373,100 |  | $ | 1,104,342 |  | $ | 2,171,231 |  | $ | 2,958,406 |  | $ | (5,112,871 | ) |  | $ | 3,494,208

(a) | Non-guarantor subsidiaries are wholly owned by NuStar Energy, NuStar Logistics or KPOP.

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NUSTAR ENERGY L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

Condensed Consolidating Statements of Income

For the Year Ended December 31, 2007

(Thousands of Dollars)

|  | NuStar Energy |  |  | NuStar Logistics |  |  | KPOP |  |  | Non- Guarantor Subsidiaries (a) |  | Eliminations |  |  | Consolidated |
Revenues |  | $ | — |  |  | $ | 274,001 |  |  | $ | 149,973 |  |  | $ | 1,059,813 |  | $ | (8,773 | ) |  | $ | 1,475,014 |
Costs and expenses |  |  | 1,966 |  |  |  | 170,961 |  |  |  | 108,277 |  |  |  | 1,009,913 |  |  | (8,702 | ) |  |  | 1,282,415 |
Operating income |  |  | (1,966 | ) |  |  | 103,040 |  |  |  | 41,696 |  |  |  | 49,900 |  |  | (71 | ) |  |  | 192,599 |
Equity earnings in subsidiaries |  |  | 152,264 |  |  |  | (12,500 | ) |  |  | 61,867 |  |  |  | 107,659 |  |  | (309,290 | ) |  |  | — |
Equity earnings from joint ventures |  |  | — |  |  |  | 738 |  |  |  | — |  |  |  | 6,095 |  |  | — |  |  |  | 6,833 |
Interest income (expense), net |  |  | — |  |  |  | (52,036 | ) |  |  | (25,173 | ) |  |  | 693 |  |  | — |  |  |  | (76,516 | )
Other income, net |  |  | — |  |  |  | 29,105 |  |  |  | 178 |  |  |  | 9,547 |  |  | — |  |  |  | 38,830 |
Income before income tax expense |  |  | 150,298 |  |  |  | 68,347 |  |  |  | 78,568 |  |  |  | 173,894 |  |  | (309,361 | ) |  |  | 161,746 |
Income tax expense |  |  | — |  |  |  | 2,026 |  |  |  | — |  |  |  | 9,422 |  |  | — |  |  |  | 11,448 |
Net income |  | $ | 150,298 |  |  | $ | 66,321 |  |  | $ | 78,568 |  |  | $ | 164,472 |  | $ | (309,361 | ) |  | $ | 150,298 |

(a) | Non-guarantor subsidiaries are wholly owned by NuStar Energy, NuStar Logistics or KPOP.

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NUSTAR ENERGY L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

Condensed Consolidating Statements of Income

For the Year Ended December 31, 2006

(Thousands of Dollars)

|  | NuStar Energy |  |  | NuStar Logistics |  |  | KPOP |  |  | Non- Guarantor Subsidiaries (a) |  |  | Eliminations |  |  | Consolidated |
Revenues |  | $ | — |  |  | $ | 261,929 |  |  | $ | 121,835 |  |  | $ | 754,509 |  |  | $ | (1,012 | ) |  | $ | 1,137,261 |
Costs and expenses |  |  | 2,260 |  |  |  | 145,453 |  |  |  | 89,984 |  |  |  | 687,677 |  |  |  | (1,012 | ) |  |  | 924,362 |
Operating income |  |  | (2,260 | ) |  |  | 116,476 |  |  |  | 31,851 |  |  |  | 66,832 |  |  |  | — |  |  |  | 212,899 |
Equity earnings in subsidiaries |  |  | 151,790 |  |  |  | 154 |  |  |  | 65,321 |  |  |  | 72,423 |  |  |  | (289,688 | ) |  |  | — |
Equity earnings from joint ventures |  |  | — |  |  |  | 815 |  |  |  | — |  |  |  | 5,067 |  |  |  | — |  |  |  | 5,882 |
Interest expense, net |  |  | — |  |  |  | (37,145 | ) |  |  | (25,093 | ) |  |  | (4,028 | ) |  |  | — |  |  |  | (66,266 | )
Other income, net |  |  | — |  |  |  | 1,242 |  |  |  | 19 |  |  |  | 1,991 |  |  |  | — |  |  |  | 3,252 |
Income from continuing operations before income tax expense |  |  | 149,530 |  |  |  | 81,542 |  |  |  | 72,098 |  |  |  | 142,285 |  |  |  | (289,688 | ) |  |  | 155,767 |
Income tax expense |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 5,861 |  |  |  | — |  |  |  | 5,861 |
Income from continuing operations |  |  | 149,530 |  |  |  | 81,542 |  |  |  | 72,098 |  |  |  | 136,424 |  |  |  | (289,688 | ) |  |  | 149,906 |
Income (loss) from discontinued operations |  |  | — |  |  |  | — |  |  |  | 317 |  |  |  | (693 | ) |  |  | — |  |  |  | (376 | )
Net income |  | $ | 149,530 |  |  | $ | 81,542 |  |  | $ | 72,415 |  |  | $ | 135,731 |  |  | $ | (289,688 | ) |  | $ | 149,530 |

(a) | Non-guarantor subsidiaries are wholly owned by NuStar Energy, NuStar Logistics or KPOP.

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NUSTAR ENERGY L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

Condensed Consolidating Statements of Income

For the Year Ended December 31, 2005

(Thousands of Dollars)

|  | NuStar Energy |  |  | NuStar Logistics |  |  | KPOP |  |  | Non- Guarantor Subsidiaries (a) |  |  | Eliminations |  |  | Consolidated |
Revenues |  | $ | — |  |  | $ | 234,444 |  |  | $ | 57,400 |  |  | $ | 368,495 |  |  | $ | (782 | ) |  | $ | 659,557 |
Costs and expenses |  |  | 2,752 |  |  |  | 134,039 |  |  |  | 44,152 |  |  |  | 326,444 |  |  |  | (782 | ) |  |  | 506,605 |
Operating income |  |  | (2,752 | ) |  |  | 100,405 |  |  |  | 13,248 |  |  |  | 42,051 |  |  |  | — |  |  |  | 152,952 |
Equity earnings in subsidiaries |  |  | 113,825 |  |  |  | (192 | ) |  |  | 38,462 |  |  |  | 40,392 |  |  |  | (192,487 | ) |  |  | — |
Equity earnings from joint ventures |  |  | — |  |  |  | 376 |  |  |  | — |  |  |  | 1,943 |  |  |  | — |  |  |  | 2,319 |
Interest expense, net |  |  | — |  |  |  | (25,770 | ) |  |  | (13,488 | ) |  |  | (2,130 | ) |  |  | — |  |  |  | (41,388 | )
Other expense, net |  |  | — |  |  |  | (1,358 | ) |  |  | — |  |  |  | (137 | ) |  |  | — |  |  |  | (1,495 | )
Income from continuing operations before income tax expense |  |  | 111,073 |  |  |  | 73,461 |  |  |  | 38,222 |  |  |  | 82,119 |  |  |  | (192,487 | ) |  |  | 112,388 |
Income tax expense |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 4,713 |  |  |  | — |  |  |  | 4,713 |
Income from continuing operations |  |  | 111,073 |  |  |  | 73,461 |  |  |  | 38,222 |  |  |  | 77,406 |  |  |  | (192,487 | ) |  |  | 107,675 |
Income from discontinued operations |  |  | — |  |  |  | — |  |  |  | 2,163 |  |  |  | 1,235 |  |  |  | — |  |  |  | 3,398 |
Net income |  | $ | 111,073 |  |  | $ | 73,461 |  |  | $ | 40,385 |  |  | $ | 78,641 |  |  | $ | (192,487 | ) |  | $ | 111,073 |

(a) | Non-guarantor subsidiaries are wholly owned by NuStar Energy, NuStar Logistics or KPOP.

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NUSTAR ENERGY L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

Condensed Consolidating Statement of Cash Flows

For the Year Ended December 31, 2007

(Thousands of Dollars)

|  | NuStar Energy |  |  | NuStar Logistics |  |  | KPOP |  |  | Non- Guarantor Subsidiaries (a) |  |  | Eliminations |  |  | Consolidated |
Cash flows from operating activities: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Net income |  | $ | 150,298 |  |  | $ | 66,321 |  |  | $ | 78,568 |  |  | $ | 164,472 |  |  | $ | (309,361 | ) |  | $ | 150,298 |
Adjustments to reconcile net income to net cash provided by (used in) operating activities: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Depreciation and amortization expense |  |  | — |  |  |  | 46,613 |  |  |  | 25,107 |  |  |  | 42,573 |  |  |  | — |  |  |  | 114,293 |
Equity earnings, net of distributions |  |  | 45,069 |  |  |  | 11,762 |  |  |  | (61,867 | ) |  |  | (113,190 | ) |  |  | 111,937 |  |  |  | (6,289 | )
Changes in operating assets and liabilities and other |  |  | 273 |  |  |  | 14,935 |  |  |  | (7,242 | ) |  |  | (43,667 | ) |  |  | 71 |  |  |  | (35,630 | )
Net cash provided by (used in) operating activities |  |  | 195,640 |  |  |  | 139,631 |  |  |  | 34,566 |  |  |  | 50,188 |  |  |  | (197,353 | ) |  |  | 222,672 |
Cash flows from investing activities: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Capital expenditures |  |  | — |  |  |  | (65,653 | ) |  |  | (15,689 | ) |  |  | (169,909 | ) |  |  | — |  |  |  | (251,251 | )
Proceeds from sale of assets |  |  | — |  |  |  | 66 |  |  |  | 15 |  |  |  | 12,586 |  |  |  | — |  |  |  | 12,667 |
Investment in other noncurrent assets |  |  | — |  |  |  | (58 | ) |  |  |  |  |  |  | (4 | ) |  |  | — |  |  |  | (62 | )
Other |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 250 |  |  |  | — |  |  |  | 250 |
Net cash provided by (used in) investing activities |  |  | — |  |  |  | (65,645 | ) |  |  | (15,674 | ) |  |  | (157,077 | ) |  |  | — |  |  |  | (238,396 | )
Cash flows from financing activities: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Proceeds from issuance of common units, net of issuance costs |  |  | 143,083 |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 143,083 |
Proceeds from long-term debt borrowings |  |  | — |  |  |  | 1,170,302 |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 1,170,302 |
Long-term debt repayments |  |  | — |  |  |  | (1,077,975 | ) |  |  | — |  |  |  | — |  |  |  | — |  |  |  | (1,077,975 | )
Distributions to unitholders and general partner |  |  | (197,333 | ) |  |  | (197,333 | ) |  |  | — |  |  |  | (20 | ) |  |  | 197,353 |  |  |  | (197,333 | )
Contributions from general partner |  |  | 3,035 |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 3,035 |
Net intercompany borrowings (repayments) |  |  | (144,555 | ) |  |  | 35,613 |  |  |  | (19,762 | ) |  |  | 128,704 |  |  |  | — |  |  |  | — |
Other |  |  | — |  |  |  | (3,144 | ) |  |  | — |  |  |  | (908 | ) |  |  | — |  |  |  | (4,052 | )
Net cash provided by (used in) financing activities |  |  | (195,770 | ) |  |  | (72,537 | ) |  |  | (19,762 | ) |  |  | 127,776 |  |  |  | 197,353 |  |  |  | 37,060 |
Effect of foreign exchange rate changes on cash |  |  | — |  |  |  | (1,510 | ) |  |  | — |  |  |  | 1,174 |  |  |  | — |  |  |  | (336 | )
Net increase in cash and cash equivalents |  |  | (130 | ) |  |  | (61 | ) |  |  | (870 | ) |  |  | 22,061 |  |  |  | — |  |  |  | 21,000 |
Cash and cash equivalents at the beginning of the period |  |  | 137 |  |  |  | 12,345 |  |  |  | 992 |  |  |  | 55,364 |  |  |  | — |  |  |  | 68,838 |
Cash and cash equivalents at the end of the period |  | $ | 7 |  |  | $ | 12,284 |  |  | $ | 122 |  |  | $ | 77,425 |  |  | $ | — |  |  | $ | 89,838 |

(a) | Non-guarantor subsidiaries are wholly owned by NuStar Energy, NuStar Logistics or KPOP.

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NUSTAR ENERGY L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

Condensed Consolidating Statement of Cash Flows

For the Year Ended December 31, 2006

(Thousands of Dollars)

|  | NuStar Energy |  |  | NuStar Logistics |  |  | KPOP |  |  | Non- Guarantor Subsidiaries (a) |  |  | Eliminations |  |  | Consolidated |
Cash flows from operating activities: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Net income |  | $ | 149,530 |  |  | $ | 81,542 |  |  | $ | 72,415 |  |  | $ | 135,731 |  |  | $ | (289,688 | ) |  | $ | 149,530 |
Adjustments to reconcile net income to net cash provided by (used in) operating activities: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Depreciation and amortization expense |  |  | — |  |  |  | 38,135 |  |  |  | 24,511 |  |  |  | 37,620 |  |  |  | — |  |  |  | 100,266 |
Equity earnings, net of distributions |  |  | 31,500 |  |  |  | (969 | ) |  |  | (65,321 | ) |  |  | (72,403 | ) |  |  | 106,379 |  |  |  | (814 | )
Changes in operating assets and liabilities and other |  |  | (2,343 | ) |  |  | (1,779 | ) |  |  | (13,613 | ) |  |  | 19,564 |  |  |  | — |  |  |  | 1,829 |
Net cash provided by (used in) operating activities |  |  | 178,687 |  |  |  | 116,929 |  |  |  | 17,992 |  |  |  | 120,512 |  |  |  | (183,309 | ) |  |  | 250,811 |
Cash flows from investing activities: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Capital expenditures |  |  | — |  |  |  | (33,939 | ) |  |  | (12,276 | ) |  |  | (77,807 | ) |  |  | — |  |  |  | (124,022 | )
Proceeds from sale of assets |  |  | — |  |  |  | 15 |  |  |  | 2 |  |  |  | 71,379 |  |  |  | — |  |  |  | 71,396 |
Acquisitions and investment in noncurrent assets |  |  | — |  |  |  | (156,275 | ) |  |  | (50 | ) |  |  | (8,969 | ) |  |  | — |  |  |  | (165,294 | )
Other |  |  | (77 | ) |  |  | (7,099 | ) |  |  | 27,112 |  |  |  | (22,527 | ) |  |  | 7,277 |  |  |  | 4,686 |
Net cash provided by (used in) investing activities |  |  | (77 | ) |  |  | (197,298 | ) |  |  | 14,788 |  |  |  | (37,924 | ) |  |  | 7,277 |  |  |  | (213,234 | )
Cash flows from financing activities: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Proceeds from long-term debt borrowings |  |  | — |  |  |  | 269,026 |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 269,026 |
Long-term debt repayments |  |  | — |  |  |  | (83,510 | ) |  |  | — |  |  |  | — |  |  |  | — |  |  |  | (83,510 | )
Distributions to unitholders and general partner |  |  | (183,290 | ) |  |  | (183,290 | ) |  |  | — |  |  |  | (19 | ) |  |  | 183,309 |  |  |  | (183,290 | )
Net intercompany borrowings (repayments) |  |  | 4,232 |  |  |  | 95,075 |  |  |  | (31,902 | ) |  |  | (67,405 | ) |  |  | — |  |  |  | — |
Other |  |  | 575 |  |  |  | (6,177 | ) |  |  | — |  |  |  | 6,754 |  |  |  | (7,277 | ) |  |  | (6,125 | )
Net cash provided by (used in) financing activities |  |  | (178,483 | ) |  |  | 91,124 |  |  |  | (31,902 | ) |  |  | (60,670 | ) |  |  | 176,032 |  |  |  | (3,899 | )
Effect of foreign exchange rate changes on cash |  |  | — |  |  |  | — |  |  |  | — |  |  |  | (894 | ) |  |  | — |  |  |  | (894 | )
Net increase in cash and cash equivalents |  |  | 127 |  |  |  | 10,755 |  |  |  | 878 |  |  |  | 21,024 |  |  |  | — |  |  |  | 32,784 |
Cash and cash equivalents at the beginning of the period |  |  | 10 |  |  |  | 1,590 |  |  |  | 114 |  |  |  | 34,340 |  |  |  | — |  |  |  | 36,054 |
Cash and cash equivalents at the end of the period |  | $ | 137 |  |  | $ | 12,345 |  |  | $ | 992 |  |  | $ | 55,364 |  |  | $ | — |  |  | $ | 68,838 |

(a) | Non-guarantor subsidiaries are wholly owned by NuStar Energy, NuStar Logistics or KPOP.

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NUSTAR ENERGY L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

Condensed Consolidating Statement of Cash Flows

For the Year Ended December 31, 2005

(Thousands of Dollars)

|  | NuStar Energy |  |  | NuStar Logistics |  |  | KPOP |  |  | Non - Guarantor Subsidiaries (a) |  |  | Eliminations |  |  | Consolidated |
Cash flows from operating activities: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Net income |  | $ | 111,073 |  |  | $ | 73,461 |  |  | $ | 40,385 |  |  | $ | 78,641 |  |  | $ | (192,487 | ) |  | $ | 111,073 |
Adjustments to reconcile net income to net cash provided by (used in) operating activities: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Depreciation and amortization expense |  |  | — |  |  |  | 34,828 |  |  |  | 12,073 |  |  |  | 19,766 |  |  |  | — |  |  |  | 66,667 |
Equity earnings, net of distributions |  |  | 13,964 |  |  |  | 192 |  |  |  | (38,462 | ) |  |  | (40,392 | ) |  |  | 64,698 |  |  |  | — |
Changes in operating assets and liabilities and other |  |  | 4,274 |  |  |  | 12,523 |  |  |  | 3,645 |  |  |  | (11,752 | ) |  |  | — |  |  |  | 8,690 |
Net cash provided by (used in) operating activities |  |  | 129,311 |  |  |  | 121,004 |  |  |  | 17,641 |  |  |  | 46,263 |  |  |  | (127,789 | ) |  |  | 186,430 |
Cash flows from investing activities: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Capital expenditures |  |  | — |  |  |  | (47,568 | ) |  |  | (3,492 | ) |  |  | (17,026 | ) |  |  | — |  |  |  | (68,086 | )
Proceeds from sale of assets |  |  | — |  |  |  | — |  |  |  | 85,466 |  |  |  | 395,479 |  |  |  | — |  |  |  | 480,945 |
Kaneb acquisition |  |  | (522,456 | ) |  |  | — |  |  |  | 850 |  |  |  | 20,633 |  |  |  | — |  |  |  | (500,973 | )
Other |  |  | — |  |  |  | (3,377 | ) |  |  | — |  |  |  | (1,472 | ) |  |  | 3,963 |  |  |  | (886 | )
Net cash provided by (used in) investing activities |  |  | (522,456 | ) |  |  | (50,945 | ) |  |  | 82,824 |  |  |  | 397,614 |  |  |  | 3,963 |  |  |  | (89,000 | )
Cash flows from financing activities: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Proceeds from long-term borrowings |  |  | — |  |  |  | 746,472 |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 746,472 |
Long-term debt repayments |  |  | — |  |  |  | (548,010 | ) |  |  | (123,668 | ) |  |  | (63,386 | ) |  |  | — |  |  |  | (735,064 | )
Distributions to unitholders and general partner |  |  | (127,789 | ) |  |  | (127,789 | ) |  |  | — |  |  |  | — |  |  |  | 127,789 |  |  |  | (127,789 | )
General partner contributions |  |  | 29,197 |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 29,197 |
Net intercompany borrowings (repayments) |  |  | 491,737 |  |  |  | (163,529 | ) |  |  | 23,317 |  |  |  | (351,525 | ) |  |  | — |  |  |  | — |
Other |  |  | — |  |  |  | 8,346 |  |  |  | — |  |  |  | 5,623 |  |  |  | (3,963 | ) |  |  | 10,006 |
Net cash provided by (used in) financing activities |  |  | 393,145 |  |  |  | (84,510 | ) |  |  | (100,351 | ) |  |  | (409,288 | ) |  |  | 123,826 |  |  |  | (77,178 | )
Effect of foreign exchange rate changes on cash |  |  | — |  |  |  | — |  |  |  | — |  |  |  | (345 | ) |  |  | — |  |  |  | (345 | )
Net increase in cash and cash equivalents |  |  | — |  |  |  | (14,451 | ) |  |  | 114 |  |  |  | 34,244 |  |  |  | — |  |  |  | 19,907 |
Cash and cash equivalents at the beginning of the period |  |  | 10 |  |  |  | 16,041 |  |  |  | — |  |  |  | 96 |  |  |  | — |  |  |  | 16,147 |
Cash and cash equivalents at the end of the period |  | $ | 10 |  |  | $ | 1,590 |  |  | $ | 114 |  |  | $ | 34,340 |  |  | $ | — |  |  | $ | 36,054 |

(a) | Non-guarantor subsidiaries are wholly owned by NuStar Energy, NuStar Logistics or KPOP.

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NUSTAR ENERGY L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

22. QUARTERLY FINANCIAL DATA (UNAUDITED)

|  | First Quarter |  | Second Quarter |  | Third Quarter |  | Fourth Quarter |  | Total
|  | (Thousands of Dollars, Except Per Unit Data)
2007: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Revenues |  | $ | 296,824 |  | $ | 321,032 |  | $ | 397,017 |  | $ | 460,141 |  | $ | 1,475,014
Operating income |  |  | 45,435 |  |  | 42,086 |  |  | 60,361 |  |  | 44,717 |  |  | 192,599
Net income |  |  | 31,123 |  |  | 39,697 |  |  | 51,213 |  |  | 28,265 |  |  | 150,298
Net income per unit applicable to limited partners |  |  | 0.57 |  |  | 0.74 |  |  | 0.97 |  |  | 0.47 |  |  | 2.74
Cash distributions per unit applicable to limited partners |  |  | 0.915 |  |  | 0.950 |  |  | 0.985 |  |  | 0.985 |  |  | 3.835
2006: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Revenues |  | $ | 274,004 |  | $ | 279,968 |  | $ | 292,299 |  | $ | 290,990 |  | $ | 1,137,261
Operating income |  |  | 55,967 |  |  | 47,316 |  |  | 55,656 |  |  | 53,960 |  |  | 212,899
Net income |  |  | 39,451 |  |  | 31,553 |  |  | 41,169 |  |  | 37,357 |  |  | 149,530
Net income per unit applicable to limited partners |  |  | 0.75 |  |  | 0.59 |  |  | 0.79 |  |  | 0.70 |  |  | 2.83
Cash distributions per unit applicable to limited partners |  |  | 0.885 |  |  | 0.885 |  |  | 0.915 |  |  | 0.915 |  |  | 3.600

Previously reported amounts of revenues and operating income, net have been increased by $2.5 million, $0.5 million and $1.3 million for the quarters ended September 30, 2007, June 30, 2007 and September 30, 2006, respectively, to conform to the revised presentation as of the fourth quarter of 2007.

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ITEM 9. | CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A. | CONTROLS AND PROCEDURES

DISCLOSURE CONTROLS AND PROCEDURES.

Our management has evaluated, with the participation of our principal executive officer and principal financial officer, the effectiveness of our disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934 (the Exchange Act)) as of the end of the period covered by this report, and has concluded that our disclosure controls and procedures were operating effectively as of December 31, 2007.

INTERNAL CONTROL OVER FINANCIAL REPORTING.

(a) Management’s Report on Internal Control over Financial Reporting.

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

(b) Attestation Report of the Registered Public Accounting Firm.

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

(c) Changes in Internal Controls over Financial Reporting.

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

ITEM 9B. | OTHER INFORMATION

None.

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PART III

ITEM 10. | DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

DIRECTORS AND EXECUTIVE OFFICERS OF NUSTAR GP, LLC

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

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

Name |  | Age |  | Position Held with NuStar GP, LLC
William E. Greehey |  | 71 |  | Chairman of the Board
Curtis V. Anastasio |  | 51 |  | President, CEO and Director
J. Dan Bates |  | 63 |  | Director
Dan J. Hill |  | 67 |  | Director
Stan McLelland |  | 62 |  | Director
Rodman D. Patton |  | 64 |  | Director
Bradley C. Barron |  | 42 |  | Senior Vice President, General Counsel and Secretary
Steven A. Blank |  | 53 |  | Senior Vice President, CFO and Treasurer
James R. Bluntzer |  | 53 |  | Senior Vice President-Operations
Mary F. Morgan |  | 55 |  | Senior Vice President-Marketing and Business Development
Thomas R. Shoaf |  | 49 |  | Vice President and Controller

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

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

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

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

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

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

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

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

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

Ms. Morgan became Senior Vice President-Marketing and Business Development in April 2007. Ms. Morgan served as Vice President-Marketing and Business Development of NuStar GP, LLC from July 2005 through April 2007. Ms. Morgan served as Vice President, Marketing and Business Development of Kaneb Pipe Line Company LLC from 2004 until July 2005. She served as Vice President, Marketing of Kinder Morgan Energy Partners, L.P. from 1998 until 2004.

Mr. Shoaf became Vice President and Controller of NuStar GP, LLC in July 2005. He has also served as Vice President and Controller of NuStar GP Holdings since March 2006. Mr. Shoaf served as Vice President-Structured Finance of Valero Corporate Services Company, a subsidiary of Valero Energy, from 2001 until his appointment with NuStar GP, LLC. From 2000 to 2001, Mr. Shoaf was Vice President-Finance of Valero Corporate Services Company.

COMPLIANCE WITH SECTION 16(a) OF THE EXCHANGE ACT

Section 16(a) of the Exchange Act requires directors, executive officers and persons who beneficially own more than 10% of NuStar Energy’s equity securities to file certain reports with the SEC and NYSE concerning their beneficial ownership of NuStar Energy’s equity securities within two business days. We believe that during the year ended December 31, 2007, all Section 16(a) reports applicable to our executive officers, directors and greater than 10% stockholders were timely filed, except for a Form 4 for J. Dan Bates, director, involving a purchase of 400 shares on August 1, 2007 (the transaction was reported on a Form 4 filed August 7, 2007).

CODE OF ETHICS OF SENIOR FINANCIAL OFFICERS

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

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AUDIT COMMITTEE

The Audit Committee reviews and reports to the Board on various auditing and accounting matters, including the quality, objectivity and performance of NuStar Energy’s internal and external accountants and auditors, the adequacy of its financial controls and the reliability of financial information reported to the public. The Audit Committee also monitors NuStar Energy’s efforts to comply with environmental laws and regulations. The Board has adopted a written charter for the Audit Committee. The members of the Audit Committee during 2007 were Rodman D. Patton (Chairman), J. Dan Bates, and Dan J. Hill. The Audit Committee met eight times in 2007. For further information, see the “Report of the Audit Committee” below.

The Board has determined that Mr. Patton is an “audit committee financial expert” (as defined by the SEC), and that he is “independent” as that term is used in Item 407(d)(5) of Regulation S-K under the Securities Exchange Act of 1934.

REPORT OF THE AUDIT COMMITTEE FOR FISCAL YEAR 2007

Management of NuStar GP, LLC is responsible for NuStar Energy’s internal controls and the financial reporting process. KPMG LLP, NuStar Energy’s independent registered public accounting firm for the year ended December 31, 2007, is responsible for performing an independent audit of NuStar Energy’s consolidated financial statements in accordance with the standards of the Public Company Accounting Oversight Board (PCAOB) and generally accepted auditing standards, and an audit of NuStar Energy’s internal control over financial reporting in accordance with the standards of the PCAOB, and issuing a report thereon. The Audit Committee monitors and oversees these processes and approves the selection and appointment of NuStar Energy’s independent registered public accounting firm and recommends the ratification of such selection and appointment to the Board.

The Audit Committee has reviewed and discussed NuStar Energy’s audited consolidated financial statements with management and KPMG. The Audit Committee has discussed with KPMG the matters required to be discussed by Statement on Auditing Standards No. 61, “Communications with Audit Committees.” The Audit Committee has received written confirmation of the firm’s independence from KPMG and has discussed with KPMG that firm’s independence.

Based on the foregoing review and discussions and such other matters the audit committee deemed relevant and appropriate, the audit committee recommended to the Board that the audited consolidated financial statements of NuStar Energy be included in NuStar Energy’s Annual Report on Form 10-K for the year ended December 31, 2007.

Members of the Audit Committee:

|  | Rodman D. Patton (Chairman)
|  | J. Dan Bates
|  | Dan J. Hill

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ITEM 11. | EXECUTIVE COMPENSATION

COMPENSATION COMMITTEE REPORT

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

Members of the Compensation Committee:
Dan J. Hill (Chairman)
J. Dan Bates
Rodman D. Patton

COMPENSATION DISCUSSION AND ANALYSIS

Executive Compensation Philosophy

Our philosophy for compensating our named executive officers is based on the belief that a significant portion of executive compensation should be incentive-based and determined by both NuStar Energy’s and the executive’s performance objectives. We believe that:

| • |  | executives’ base salaries should be established at levels to be competitive in the marketplace in which we compete for executive talent;

| • |  | annual incentive bonuses should be targeted to be competitive in the marketplace and should provide awards based on NuStar Energy’s achievement of performance goals established in the first quarter of the fiscal year and individual performance;

| • |  | long-term incentives, which can include a mix of performance units, restricted units and unit option awards, should (i) be targeted to be competitive in the marketplace, (ii) balance executive management focus between short- and long-term performance goals and (iii) provide capital accumulation linked directly to company performance; and

| • |  | we should encourage unit ownership among our executive management team, in order to align the interests of our executive officers with those of our unitholders.

Purpose of Executive Compensation Programs

Our executive compensation programs are designed to accomplish the following long-term objectives:

| • |  | create a strong performance alignment with unitholders, while practicing good corporate governance;

| • |  | support our business strategy and business plan by clearly communicating what is expected of executives with respect to goals and results;

| • |  | reward achievement; and

| • |  | provide market-competitive compensation and benefits to enable us to recruit, retain and motivate the executive talent necessary to be successful.

Administration of Executive Compensation Programs

Our executive compensation programs are administered by our Board’s Compensation Committee. The Compensation Committee is composed of three independent directors who are not participants in our executive compensation

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programs. In 2007, the policies adopted by the Compensation Committee were implemented by Valero Energy’s compensation and benefits staff, pursuant to the Services Agreement described in Note 14 of Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data.” Effective December 31, 2007, Valero Energy stopped providing human resource services, including compensation and benefits services, to us. In 2008, the adopted policies of the Committee will be administered by the compensation and benefits staff of NuStar GP, LLC.

During 2007, the Committee retained Compass Consulting & Benefits (Compass) as its independent compensation consultant with respect to executive compensation matters. In its role as advisor to the Committee, this consultant was retained directly by the Compensation Committee, which has the authority to select, retain and/or terminate its relationship with a consulting firm. In November 2007, BDO Seidman, LLP (BDO) acquired Compass’ executive compensation consulting practice, and the Compensation Committee entered into an agreement with BDO to continue its relationship with those former-Compass advisors. All references to BDO will refer to the Compensation Committee’s independent consultant, whether or not the services were provided prior to November 2007.

Selection of Compensation Comparative Data and Competitive Pay Benchmarking

In 2007, the Compensation Committee relied upon two primary sources of competitive compensation data in assessing the benchmark rates of base salary, annual incentive compensation, and long-term incentive compensation: a group of limited partnerships in our industry and broader survey data on comparably sized entities.

To establish compensation for the named executive officers, including the CEO, in 2007, we looked first at a specific group of 15 master limited partnerships to evaluate competitive rates of compensation (the Compensation Comparative Group). Each of these 15 organizations is in the products terminalling, storage and pipeline industry. The competitive data for these master limited partnerships is derived from their respective publicly filed annual proxy statements or annual reports on Form 10-K. For 2007, the data was compiled and analyzed by BDO.

In 2007, BDO advised us to increase the size of our comparative group from nine to 15, in order to expand the relatively small 2006 peer group to a more typical size. In addition, five of the nine organizations comprising the 2006 peer group are publicly traded subsidiaries of a larger unit, which, unlike “stand-alone” entities like ours, may tend to rely heavily on management support services provided by the parent organization. In 2007, the six entities we added are “stand-alone” pipeline master limited partnerships in order to make our Compensation Comparative Group a more accurate reflection our management’s responsibilities.

Company |  | Ticker
1. BUCKEYE PARTNERS LP |  | BPL
2. ENBRIDGE ENERGY PARTNERS LP |  | EEP
3. ENTERPRISE PRODUCT PARTNERS LP |  | EPD
4. KINDER MORGAN ENERGY LP |  | KMP
5. MAGELLAN MIDSTREAM PARTNERS LP |  | MMP
6. ONEOK PARTNERS, L.P. |  | OKS
7. PLAINS ALL AMERICAN PIPELINE LP |  | PAA
8. SUNOCO LOGISTICS PARTNERS LP |  | SXL
9. TEPPCO PARTNERS LP |  | TPP
10. ENERGY TRANSFER PARTNERS* |  | ETP
11. BOARDWALK PIPELINE PARTNERS* |  | BWP
12. COPANO ENERGY LLC* |  | CPNO
13. CROSSTEX ENERGY LP* |  | XTEX
14. MARK WEST ENERGY PARTNERS* |  | MWE
15. REGENCY ENERGY PARTNERS* |  | RGNC

* | Added in 2007.

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The Compensation Committee also reviewed survey data reported by BDO on a position-by-position basis to ascertain competitive rates of compensation. The survey data consists of general industry data for executive positions reported in the Towers Perrin Executive Compensation General Industry Database, a proprietary compensation database of an approximate 825 U.S. industrial companies that is updated each year. Where possible, the data analysis included the use of single regression analysis to correlate company size to reported pay rates for companies with an annual revenue size of approximately $1.2 billion. In those instances where regression analysis was not available for analysis purposes, BDO employed general tabular data from its survey sources based upon companies approximating $1.2 billion in annual revenues. We refer to the competitive survey data, together with the comparative group data, as the Compensation Comparative Data.

Timing of Compensation Decisions

In the first quarter of each fiscal year, the Committee reviews and establishes financial performance objectives applicable to the current fiscal year under our annual incentive bonus plan. Financial performance objectives are typically tied to the Company’s previously approved annual budget. At the same time, the Compensation Committee reviews performance against financial, operational and other goals for the prior year in order to determine annual bonuses earned under the NuStar GP, LLC Bonus Plan and payouts, if any, of performance units granted in prior years. In the third quarter of each fiscal year, the Committee reviews competitive market data for annual salary rates for executive officer positions for the current fiscal year and recommends salary increases to become effective in that quarter. In the fourth quarter of each fiscal year, the Committee establishes the target level of annual incentive and long-term incentive compensation opportunities for executives for the upcoming fiscal year, based upon its review of competitive market data and considers equity grants to officers and other leadership employees.

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

Event |  | Timing
Establishing company financial objectives for annual incentive bonus |  | First quarter
Review and certify financial performance for performance units granted in prior years; grant performance units |  | First quarter; three business days after fourth quarter earnings release
Review base salaries for executive officers for the current fiscal year |  | Third quarter
Grant of restricted unit and unit options to employees, officers and grant restricted units to directors |  | Fourth quarter; three business days after third quarter earnings releases
Setting meeting dates for action by the Compensation Committee for the upcoming year |  | Fourth quarter

The Committee may, however, review salaries or grant long-term incentive awards at other times during the year in the event of promotions, new appointments or other extraordinary circumstances. Additional information regarding the timing of performance unit, unit option and restricted unit grants is discussed below under “Long-Term Incentive Awards” and “Restricted Units/Unit Options.”

Elements of Executive Compensation

General

Our executive compensation programs consist of the following material elements:

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| • |  | base salaries;

| • |  | annual incentive bonuses;

| • |  | long-term equity-based incentives, including:

| • |  | performance units;

| • |  | restricted units;

| • |  | unit options; and

| • |  | medical and other insurance benefits, retirement benefits and other perquisites.

We chose these elements to remain competitive in attracting and retaining executive talent and to provide strong performance incentives that provide the potential for both current and long-term gains. We use base salary as the foundation for our executive compensation program. We believe that base salary should provide a fixed level of competitive pay that reflects the executive officer’s primary duties and responsibilities, as well as a foundation for incentive opportunities and benefit levels. Our annual incentive bonuses are designed to focus our executives on NuStar Energy’s attainment of key financial performance measures that we believe generate profitable annual operations and sustaining results. Our long-term equity incentive awards are designed to directly tie an executive’s financial reward opportunities with the rewards to unitholders, as measured by long-term unit price performance and payment of distributions.

Relative Size of Elements of Compensation

We evaluate total compensation of the executives at least annually. In setting executive compensation, the Committee considers the aggregate amount of compensation payable to an executive officer and the form of the compensation. The Committee seeks to achieve the appropriate balance between immediate cash rewards for the achievement of company and personal objectives and long-term incentives that align the interests of our executive officers with those of our unitholders. The size of each element determined with reference to market practice reported in the Compensation Comparative Data. The Compensation Committee may also decide, as appropriate, to modify the relative mix of compensation elements to best fit an executive officer’s specific circumstances.

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

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

The following table summarizes the relative size of base salary and incentive compensation targets for 2007 (which we call “total direct compensation”) for each of our named executive officers:

Name |  | Target Percentage of Total Direct Compensation |  |
|  | Base Salary |  | Annual Incentive Bonus |  | Long-Term Incentives |  | TOTAL
Curtis V. Anastasio |  | 35 |  | 21 |  | 44 |  | 100
Bradley C. Barron |  | 43 |  | 22 |  | 35 |  | 100
Steven A. Blank |  | 43 |  | 22 |  | 35 |  | 100
James R. Bluntzer |  | 43 |  | 22 |  | 35 |  | 100
Mary F. Morgan |  | 43 |  | 22 |  | 35 |  | 100

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Base Salaries

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

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

Beginning in July 2007, our named executive officers received the following adjustments to annualized base salaries, which represent a four percent (4%) increase to their prior annualized salaries and which the Compensation Committee considered necessary to achieve a reasonably competitive salary level in each case:

Name |  | Annualized Base Salary |  | July 2007 Increase to Prior Annualized Base Salary
Anastasio |  | $ | 436,800 |  | $ | 16,800
Barron |  |  | 234,000 |  |  | 9,000
Blank |  |  | 318,032 |  |  | 12,232
Bluntzer |  |  | 251,680 |  |  | 9,680
Morgan |  |  | 284,440 |  |  | 10,940

In addition, in May 2007, Mr. Barron had received a $25,000 salary increase in recognition of his promotion from Vice President, General Counsel and Secretary to Senior Vice President, General Counsel and Secretary.

Annual Incentive Bonus

Our named executive officers participate in a formal annual incentive plan in which all domestic company employees participate. The annual incentive plan, as it pertains to the named executive officers, is based upon the following principles:

| • |  | The establishment of a target annual incentive opportunity for each position based upon competitive compensation data and expressed as a percentage of the officer’s base salary;

| • |  | Our attainment of specific quantitative financial goals established by the Compensation Committee during the first quarter of the plan year; and

| • |  | A discretionary evaluation of both NuStar Energy’s performance and the individual executive’s performance by the Compensation Committee.

For the 2007 plan year, the named executive officers had annual incentive target bonus opportunities expressed as a percentage of their respective base salary rates as shown in the table below:

Name |  | Annual Incentive Bonus Target as a Percentage of Base Salary
Anastasio |  | 60
Barron |  | 50
Blank |  | 50
Bluntzer |  | 50
Morgan |  | 50

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Determination of Annual Incentive Target Opportunities

As stated above, each named executive officer has an annual incentive opportunity generally based on a stated percentage of his or her base salary. This is the target amount of annual incentive award and equals the payout for achieving a 100% score on our stated financial goal under the bonus plan. For example, Mr. Anastasio has a target annual incentive opportunity equal to 60% of his base annual salary. Mr. Anastasio’s annual salary rate for 2007 was $436,800, and therefore, his target annual incentive opportunity for a 100% score would have been $262,080. In addition, the plan allows for the upward or downward adjustment of awards, based upon attainment of the financial goal, equal to a range of 0% to 200% of the target award. If we failed to reach at least the threshold level of performance for our financial goal, the participant would have earned an incentive award of $0. Likewise, if we achieved the maximum level of performance for each of its financial goals, the participant could earn up to 200% of his target award.

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

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

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

Company Financial Goals

In prior years, our annual all-employee incentive plan established performance goals in three principal financial areas:

| • |  | NuStar Energy’s earnings per unit (EPU) compared to the target, threshold, and maximum performance levels, as established and approved by the Compensation Committee at the start of the plan year;

| • |  | NuStar Energy’s total unitholder return (TUR), expressed as the total return to unitholders based upon the growth in the unit price as well as cash distributions to unitholders during the plan year, either (a) our TUR compared to a peer group or (b) as compared to a target, threshold, and maximum TUR established and approved by the Compensation Committee at the start of the plan year; and

| • |  | NuStar Energy’s distributable cash flow (DCF per unit) compared to the target, threshold, and maximum performance levels, as established and approved by the Compensation Committee at the start of the plan year.

In 2007, the Compensation Committee adopted DCF per unit versus a target as the sole 2007 bonus metric, based on management’s recommendations and input from the Compensation Committee’s independent compensation consultant. In adopting this sole metric, the Compensation Committee considered (i) the nature of TUR as a long-term performance measure rather than as a bonus measure, (ii) the fact that management is already incentivized to focus on TUR through performance shares, and (iii) an acknowledgement that, in the master limited partnership investment community, DCF is widely regarded as a significant determinant of unit price.

For this financial goal, the Compensation Committee established a target level of performance for which 100% of the incentive opportunity would be paid, a threshold level of performance below which no incentive would be paid, and a maximum level of performance for which 200% of target incentive would be paid.

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Determination of Awards

For the 2007 annual incentive program, the Compensation Committee measured NuStar Energy’s DCF per unit against the established target to determine the amount of incentive award earned. The performance score equaled 129% of the target award amount.

Upon reviewing the 129% performance score, the Compensation Committee exercised its discretionary judgment regarding the plan and elected to provide a 16% positive adjustment to the annual award to all eligible employees, taken as a whole. This resulted in each named executive officer having a potential annual incentive award equal to 150% of his or her target award (129% performance score multiplied by an upward adjustment of 16% yields a final performance result of 150%). In making the 16% positive adjustment, the Compensation Committee considered a number of company achievements in 2007, including the fact that we successfully entered into a definitive purchase agreement for certain assets and operations of CITGO Asphalt Refining Company, completed a public offering of units, completed our separation from Valero Energy, improved our safety record, completed projects at our domestic and international properties and increased the cash distributions to unitholders.

Name |  | Bonuses Paid For 2007
Anastasio |  | $ | 393,120
Barron |  |  | 175,500
Blank |  |  | 238,524
Bluntzer |  |  | 195,000
Morgan |  |  | 195,000

Long-term Incentive Awards

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

Under the design of the long-term incentive plan, each plan participant, including the named executive officers, are designated a target long-term incentive award expressed as a percentage of base salary. This percentage is the expected fair value of the awards to be granted in aggregate each year. In determining the expected fair value, we engaged Towers Perrin to employ a valuation model to determine the value of long-term incentive grants. The model considers unit price volatility, distribution yield, unit price, vesting provisions and, when applicable, performance vesting contingencies.

For the named executive officers, the 2007 long-term incentive target percentages are established as follows.

Name |  | Long-Term Incentive Target Percentage
Anastasio |  | 125
Barron |  | 80
Blank |  | 80
Bluntzer |  | 80
Morgan |  | 80

These target levels are based upon competitive survey data provided by the Compensation Committee’s independent compensation consultant and upon the Compensation Committee’s strategic decisions to allocate a percentage of award value to performance-based awards and a percentage to awards that focus on retention and increasing ownership levels of executive officers. In 2007, the target levels were allocated in the following manner for each individual:

| • |  | 30% of the targeted long-term incentive dollar value is awarded to the executive in a grant of performance units. The number of performance units granted is based upon the expected fair value of a single performance unit at the time of grant; and

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| • |  | 70% of the targeted long-term incentive dollar value is awarded to the executive in the form of restricted units. The number of restricted units granted is based upon the expected fair value of a single performance unit at the time of grant.

In prior years, we also awarded unit options to named executive officers and allocated awards of long-term components in approximate one-third increments among the three forms of awards: unit options, performance units and restricted units. In 2007, however, the Compensation Committee eliminated the grant of NuStar Energy L.P. unit options as a long-term incentive component and increased the percentage of restricted units granted. The Compensation Committee based its decision on the results of a comparison study of peer companies performed by its independent compensation consultant, BDO. This study showed that the use of three different forms of award in the executive long-term incentive program is not consistent with peer practice and may dilute the effectiveness of each component. The comparison also showed that, although the use of restricted units and performance units is consistent with peer practices, the use of unit options is not common among NuStar Energy’s peers as a recurring component of a long-term incentive compensation.

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

Restricted Units/Unit Options

Name |  | Restricted Unit Grants in October 2007
Anastasio |  | 7,210
Barron |  | 3,000
Blank |  | 3,360
Bluntzer |  | 3,000
Morgan |  | 3,000

In 2007, the same number of restricted units were granted to officers with similar titles and responsibilities, with restricted units comprising approximately 70% of each executive’s total NuStar Energy long-term incentive target. The Compensation Committee presently expects to grant restricted units annually. Beginning in 2007, the executives’ long-term incentive targets did not include NuStar Energy L.P. unit options, and the Compensation Committee currently does not expect to grant NuStar Energy L.P. unit options as part of the named executive officer’s long-term incentive program in the future.

NuStar Energy L.P. unit options awarded in 2005 and 2006 have seven-year terms, and options awarded in prior years generally have ten-year terms. Awards of restricted units and unit options vest in equal installments over a period of five years, beginning on the first anniversary of the date of grant (awards in January 2003 and prior vested over three years). Grants and vesting of unit options and restricted units are not contingent upon achievement of any specified performance targets. Options and restricted units are subject to forfeiture if an executive terminates employment prior to vesting.

The exercise price for NuStar Energy L.P. unit options is the close price of NuStar Energy L.P. units on the grant date. The grant date of the restricted unit and unit option awards, until 2006, was the date on which options were approved by the Compensation Committee (except for grants to new hires, which have a grant date of the date on which the new

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employee commences employment). In 2007, the Compensation Committee adopted a policy that annual equity grants other than performance units would be effective three days after the third quarter earnings release, in this case, November 12, 2007. Because NuStar Energy subsequently determined to announce a public offering of its units on November 12, 2007, the Compensation Committee moved the grant date of the restricted units to November 16, 2007. The close price of the NuStar Energy L.P. units on the date of the meeting of the Compensation Committee on October 24, 2007 was $60.98; the close price on November 12, 2007 was $59.14; and the close price on November 16, 2007, the date of grant, was $57.05.

Performance Units

Name |  | Performance Unit Grants in 2007
Anastasio |  | 3,600
Barron |  | 680
Blank |  | 1,670
Bluntzer |  | 1,320
Morgan |  | 930

In 2007, performance units comprised approximately 30% of each of our named executive officers’ total NuStar Energy long-term incentive targets. 2006 was the first year the Compensation Committee awarded performance units, and for our current program, the Compensation Committee expects to award performance units annually. Performance units are earned only upon NuStar Energy’s achievement of an objective performance measure, TUR, as compared with a subset of the Compensation Comparative Group consisting of the first nine entities listed in the table above. These nine entities most closely track with our size and business, making their TUR performance most comparable with ours (the Peer Group). The Compensation Committee believes this type of incentive award strengthens the tie between the named executive’s pay and our financial performance.

Each award is subject to vesting in three annual increments, based upon our TUR during rolling three-year periods that end on December 31 of each year following the date of grant. At the end of each performance period, our TUR is compared to the Peer Group and ranked by quartile. Executives then earn 0%, 50%, 100% or 150% of that portion of the initial grant amount that is vesting, depending upon whether our TUR is in the last, 3rd, 2nd or 1st quartile, respectively, and they earn 200% if we rank highest in the group. Amounts not earned in a given performance period can be carried forward for one additional performance period and up to 100% of the carried amount can still be earned, depending upon the quartile achieved for that subsequent period. For the performance period ended December 31, 2007, our performance ranked tenth in the group, placing NuStar Energy in the fourth quartile of the group and resulting in vesting of eligible units at the 0% level.

Grant of NuStar GP Holdings Unit Options

Name |  | NuStar GP Holdings Unit Options Granted in 2007
Anastasio |  | 56,300
Barron |  | 35,000
Blank |  | 41,000
Bluntzer |  | 35,000
Morgan |  | 35,000

In 2007, at a joint meeting of the NuStar GP, LLC and the NuStar GP Holdings Compensation Committees, NuStar GP Holdings’ Compensation Committee approved a one-time unit option grant to certain officers of NuStar GP, LLC, as is permitted under NuStar GP Holdings’ long-term incentive plan, to encourage the officers to continue to devote their best efforts to advancing the business of NuStar GP Holdings and NuStar Energy.

The options to purchase NuStar GP Holdings, LLC units awarded to the named executive officers in 2007 have seven-year terms and vest in one-third installments beginning on the third anniversary of the grant date. Like prior grants of

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options of NuStar Energy L.P. units, grants and vesting of the options to purchase NuStar GP Holdings, LLC units are not contingent upon achievement of any specified performance targets. However, because the exercise price of options cannot be less than 100% of the fair market value of NuStar GP Holdings, LLC units on the date of grant, options will provide a benefit to the executive only to the extent that there is appreciation in the market price of NuStar GP Holdings, LLC units. The NuStar GP Holdings options are subject to forfeiture if an executive terminates employment prior to vesting. In 2007, the NuStar GP Holdings Compensation Committee adopted a policy that annual equity grants would have a grant date of three days after the third quarter earnings release, in this case, November 12, 2007. Because NuStar Energy subsequently determined to announce a public offering of its units on November 12, 2007, the NuStar GP Holdings Compensation Committee moved the grant date to November 16, 2007. The close price of the NuStar GP Holdings, LLC units on the date of the meeting of the NuStar GP Holdings Compensation Committee on October 24, 2007 was $30.39; the close price on November 12, 2007 was $31.55; and the close price on November 16, 2007, the date of grant, was $31.55.

Perquisites and Other Benefits

Perquisites

In 2007, we provided only minimal perquisites to our executive officers. Mr. Anastasio receives reimbursement for club membership dues. Mr. Anastasio and Mr. Blank receive federal income tax preparation services. Executives are eligible to receive liability insurance (personal liability insurance and coverage under NuStar Energy’s directors and officers liability insurance policies). For more information on perquisites, see the Summary Compensation Table and its footnotes.

Other Benefits

Our named executive officers are eligible for the same benefit plans provided to other employees, including insurance plans and supplemental plans chosen and paid for by employees who wish additional coverage.

Executive officers and other employees whose compensation exceeds certain limits are eligible to participate in non-qualified excess benefit programs whereby those executives can choose to make larger contributions than allowed under the qualified plan rules and receive correspondingly higher benefits. These plans are described below under “–Post-Employment Benefits.”

Post-Employment Benefits

Pension Plans

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

Nonqualified Deferred Compensation Plans

Excess Thrift Plan

The Excess Thrift Plan provides benefits to those employees of NuStar GP, LLC whose annual additions under the NuStar GP, LLC Thrift Plan are subject to the limitations on such annual additions as provided under §415 of the Internal Revenue Code of 1986, as amended (the Code), and/or who are constrained from making maximum contributions under the Thrift Plan by §401(a)(17) of the Code, which limits the amount of an employee’s annual compensation which may be taken into account under that plan. The Excess Thrift Plan is comprised of two separate components, consisting of (1) an “excess benefit plan” as defined under §3(36) of The Employee Retirement Income Security Act of 1974, as amended (ERISA) and (2) a plan that is unfunded and maintained primarily for the purpose of providing deferred compensation for a select group of management or highly compensated employees. Each component of the Excess Thrift Plan consists of a separate plan for purposes of Title I of ERISA. To the extent a participant’s annual total compensation exceeds the compensation limits for the calendar year under §401(a)(17) of the Code ($225,000 for 2007), the participant’s excess thrift plan account is credited with that number of hypothetical NuStar Energy L.P. units that could have been purchased with the difference between:

| • |  | The total company matching contributions that would have been credited to the participant’s account under the NuStar GP, LLC Thrift Plan had the participant’s contributions not been reduced pursuant to §401; and

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| • |  | The actual company matching contributions credited to such participant’s account.

Mr. Anastasio, Mr. Barron, Mr. Blank, Mr. Bluntzer and Ms. Morgan participated in the Excess Thrift Plan in 2007.

Frozen Nonqualified 401(k) Plan

Effective July 1, 2006, we established the NuStar GP, LLC Frozen Nonqualified 401(k) Plan for Former Employees of Ultramar Diamond Shamrock Corporation (the Frozen Plan). The Frozen Plan assumes and continues the frozen Ultramar Diamond Shamrock Corporation Nonqualified 401(k) Plan (the UDS Plan) with respect to the current NuStar GP, LLC employees who had accrued benefits under the UDS Plan. No additional benefits accrue under the Frozen Plan, and we make no contributions to the Frozen Plan. Mr. Anastasio and Mr. Blank have Frozen Plan accounts.

Severance Arrangements

We have entered into change of control agreements with each of the named executive officers. These agreements are intended to assure the continued availability of these executives in the event of certain transactions culminating in a “change of control” as defined in the agreements. The change of control employment agreements have three-year terms, which terms are automatically extended for one year upon each anniversary unless a notice not to extend is given by us. If a “change of control” (as defined in the agreements) occurs during the term of an agreement, then the agreement becomes operative for a fixed three-year period. The agreements provide generally that the executive’s terms and conditions of employment (including position, location, compensation and benefits) will not be adversely changed during the three-year period after a change of control of us. The agreements also provide that upon a change of control:

| • |  | all unit options held by the executive will vest and remain exercisable for the shorter of five years from the date of termination or the remainder of the original option term;

| • |  | the restrictions and deferral limitations applicable to any restricted unit awards held by the executive will lapse, and such restricted unit awards shall become fully vested; and

| • |  | all performance unit awards held by the executive will fully vest and be earned and payable based on the deemed achievement of performance at 200% of target level.

Particular payments under the agreements are triggered commensurate with the occurrence of any of the following: (i) termination of employment by the company other than for “cause” (as defined in the agreements) or disability, (ii) termination by the executive for “good reason” (as defined in the agreements), (iii) termination by the executive other than for “good reason,” and (iv) termination of employment because of death or disability. These triggers were designed to ensure the continued availability of the executives following a change of control, and to compensate the executives at appropriate levels if their employment is unfairly or prematurely terminated during the applicable term following a change of control. For more information regarding payment that may be made under our severance arrangements, see our disclosures below under the caption “Potential Payments upon Termination or Change-in-Control Payments.”

Impact of Accounting and Tax Treatments

Accounting Treatment

Our financial statements include the expense for awards of NuStar Energy L.P. unit options and restricted units to NuStar GP, LLC employees and directors and the expense for awards of NuStar GP Holdings, LLC unit options to NuStar GP, LLC employees, as we are obligated to pay for all costs of NuStar GP, LLC’s employees working on our behalf.

NuStar GP, LLC accounts for awards of NuStar Energy L.P. common units to NuStar GP, LLC’s employees and directors in accordance with Emerging Issues Task Force Issue No. 02-08, “Accounting for Options Granted to Employees in Unrestricted, Publicly Traded Shares of an Unrelated Entity” (EITF 02-08). EITF 02-08 requires a company that grants its employees equity of an unrelated entity to account for such awards as a derivative, whereby a liability for the award is recorded at inception. Subsequent changes in the fair value of the award are included in the determination of net income.

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Each month, NuStar GP, LLC determines the fair value of its liability for awards of NuStar Energy L.P. unit options and restricted units. The fair value of unit options is determined using the Black-Scholes model at each reporting date. The fair value of restricted units equals the market price of NuStar Energy L.P. common units at each reporting date. NuStar GP, LLC records compensation expense each reporting period such that the cumulative compensation expense recorded equals the current fair value, considering the percentage of the award that has vested to date. NuStar GP, LLC records compensation expense related to unit options until such options are exercised, and records compensation expense for restricted units until the date of vesting.

NuStar GP Holdings accounts for awards of unit options awarded to employees of NuStar GP, LLC at fair value in accordance with Financial Accounting Standards Board (FASB) Statement No. 123 (revised 2004), “Share-Based Payment” (FAS 123(R)). Under FAS 123(R), NuStar GP Holdings estimates the fair value of unit options at the grant date using the Black-Scholes model and the resulting compensation expense is recognized over the vesting period.

For certain awards, the terms of the stock compensation plans provide that employees vest in the award when they retire or will continue to vest in the award after retirement over the nominal vesting period established in the award. For any awards subsequent to January 1, 2006, we recognize compensation expense immediately for awards granted to retirement-eligible employees or over the period from the grant date to the date retirement eligibility is achieved if that date is expected to occur during the nominal vesting period. Employees are typically retirement eligible at age 55.

Tax Treatment

Under Section 162(m) of the Internal Revenue Code, publicly held corporations may not take a tax deduction for compensation in excess of $1 million paid to the CEO or the other four most highly compensated executive officers unless that compensation meets the Internal Revenue Code’s definition of “performance-based” compensation. Section 162(m) allows a deduction for compensation to a specified executive that exceeds $1 million only if it is paid (i) solely upon attainment of one or more performance goals, (ii) pursuant to a qualifying performance-based compensation plan adopted by the Compensation Committee, and (iii) the material terms, including the performance goals, of such plan are approved by the unitholders before payment of the compensation. The Compensation Committee considers deductibility under Section 162(m) with respect to compensation arrangements for executive officers. The Compensation Committee believes that it is in the best interest of NuStar Energy for the Compensation Committee to retain its flexibility and discretion to make compensation awards to foster achievement of performance goals established by the Compensation Committee (which may include performance goals defined in the Internal Revenue Code) and other corporate goals the Compensation Committee deems important to NuStar Energy’s success, such as encouraging employee retention, rewarding achievement of nonquantifiable goals and achieving progress with specific projects. NuStar Energy believes that unit options and performance unit grants qualify as performance-based compensation and are not subject to any deductibility limitations under Section 162(m). Grants of restricted units and other equity-based awards that are not subject to specific quantitative performance measures will likely not qualify as “performance-based” compensation and, in such event, would be subject to 162(m) deduction restrictions.

Compensation-Related Policies

Unit Ownership Guidelines

Our Board, the Compensation Committee and our executives recognize that ownership of NuStar Energy L.P. units is an effective means by which to align the interests of NuStar GP, LLC directors and executives with those of NuStar Energy’s unitholders. We have long emphasized and reinforced the importance of unit ownership among our executives and directors.

During 2006, the Compensation Committee worked with its independent compensation consultant to formalize unit ownership and retention guidelines for directors and NuStar GP, LLC officers to ensure continuation of our successful track record in aligning the interests of NuStar GP, LLC directors and officers with those of NuStar Energy’s unitholders through ownership of NuStar Energy L.P. units. The guidelines were approved by the Compensation Committee and the Board in March 2006. In February 2007, in view of the public offerings of NuStar GP Holdings in 2006, the Compensation Committee amended the guidelines to include ownership of either NuStar GP Holdings, LLC units or NuStar Energy L.P. units.

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Non-employee Director Unit Ownership Guidelines

Non-employee directors are expected to acquire and hold during their service as a NuStar GP, LLC board member NuStar Energy L.P. units and/or NuStar GP Holdings, LLC units with an aggregate value of at least $50,000. Directors have five years from their initial election to the Board to meet the target unit ownership guidelines, and they are expected to continuously own sufficient units to meet the guidelines once attained.

Executive Unit Ownership Guidelines

Unit ownership guidelines for officers of NuStar GP, LLC are as follows:

Officer |  | Value of NuStar Energy L.P. Units and/or NuStar GP Holdings, LLC Units Owned
President |  | 3.0x Base Salary
Senior Vice Presidents |  | 2.0x Base Salary
Vice Presidents |  | 1.0x Base Salary

Our officers are expected to meet the applicable guideline within five years and are expected to continuously own sufficient units to meet the guideline once attained.

Prohibition on Insider Trading and Speculation on NuStar Energy L.P. or NuStar GP Holdings, LLC Units

We have established policies prohibiting our officers, directors and employees from purchasing or selling either NuStar Energy L.P. or NuStar GP Holdings, LLC securities while in possession of material, nonpublic information, or otherwise using such information for their personal benefit or in any manner that would violate applicable laws and regulations. In addition, our policies prohibit our officers, directors and employees from speculating in the either NuStar Energy L.P. or NuStar GP Holdings, LLC units, which includes short selling (profiting if the market price of our units decreases), buying or selling publicly traded options (including writing covered calls), hedging or any other type of derivative arrangement that has a similar economic effect.

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EXECUTIVE COMPENSATION

The tables listed below, which appear in the following sections of this report, provide information required by the SEC regarding the compensation we paid for the years ended December 31, 2007 and December 31, 2006 to our President & CEO, CFO and our other most highly compensated executive officers (our named executive officers or NEOs). Except as noted below, we have used captions and heading in these tables in accordance with the SEC regulations requiring these disclosures. The footnotes to these tables provide important information to explain the values presented in the tables and are an important part of our disclosures related to our executive compensation.

| • |  | Summary Compensation Table*

| • |  | Grants of Plan-Based Awards*

| • |  | Outstanding Equity Awards

| • |  | Options Exercises and Stock Vested

| • |  | Pension Benefits

| • |  | Nonqualified Deferred Compensation

| • |  | Payments Under Change of Control Severance Agreements**

| • |  | Director Compensation

* | We are required to provide narrative disclosure of any material factors necessary to an understanding of the information disclosed in these two tables; we believe that this disclosure is provided in the footnotes to these tables and in the Compensation Disclosure and Analysis above in this item.

** | SEC regulations require disclosure of potential payments to an executive in connection with his or her termination or a change of control of NuStar Energy. We have elected to use the table listed above to disclose certain elements of the required disclosure.

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SUMMARY COMPENSATION TABLE

FOR FISCAL YEAR ENDED DECEMBER 31, 2007

The following table provides a summary of compensation paid for the years ended December 31, 2007 and December 31, 2006, to NuStar GP, LLC’s CEO, CFO and to its other most highly compensated executive officers. The table shows amounts earned by such persons for services rendered to NuStar GP, LLC in all capacities in which they served.

Name and Principal Position |  | Year |  | Salary ($) |  | Bonus ($)(1) |  | Unit Awards ($)(2) |  | Option Awards ($)(3) |  | Non-Equity Incentive Plan Compensation ($) |  | Change in Pension Value and Nonqualified Deferred Compensation Earnings ($) |  |  | All Other Compensation ($)(6) |  | Total ($)
Curtis V. Anastasio President and CEO |  | 2007 2006 |  | 428,400 385,000 |  | 393,120 320,000 |  | 168,408 165,754 |  | 14,646 250,737 |  | 0 0 |  | 46,806 338,020 | (4) (5) |  | 39,568 35,481 |  | 1,090,948 1,495,352
Bradley C. Barron Senior Vice President, General Counsel and Corporate Secretary |  | 2007 2006 |  | 221,167 178,196 |  | 175,500 102,400 |  | 23,222 19,601 |  | 7,903 6,474 |  | 0 0 |  | 13,771 24,511 | (4) (5) |  | 15,669 18,258 |  | 457,232 349,363
Steven A. Blank Senior Vice President, CFO and Treasurer |  | 2007 2006 |  | 311,916 299,900 |  | 238,524 195,172 |  | 93,718 91,387 |  | 18,724 96,103 |  | 0 0 |  | 36,731 303,953 | (4) (5) |  | 24,150 21,670 |  | 723,763 1,008,725
James R. Bluntzer Senior Vice President-Operations |  | 2007 2006 |  | 246,840 231,000 |  | 195,000 154,880 |  | 62,950 57,153 |  | 15,638 48,107 |  | 0 0 |  | 135,018 212,397 | (4) (5) |  | 20,208 19,683 |  | 675,654 723,100
Mary F. Morgan Senior Vice President- Marketing and Business Development |  | 2007 2006 |  | 278,970 265,971 |  | 195,000 140,032 |  | 248,169 84,827 |  | 263,640 8,223 |  | 0 0 |  | 31,628 44,719 | (4) (5) |  | 19,758 18,780 |  | 1,037,165 562,552

Footnotes appear on the following page.

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(1) | 2007 bonus amounts were paid in January 2008 with respect to 2007 performance. 2006 bonus amounts reported were paid in January 2007 with respect to 2006 performance. Bonuses were determined taking into consideration the individual executive’s targets, the executive’s performance and NuStar Energy’s performance in the applicable year, as described above under “Compensation Disclosure & Analysis- Annual Incentive Bonus.”

(2) | The amounts reported represent the dollar amounts recognized by NuStar Energy for financial statement reporting purposes for the fiscal year ended December 31, 2006 or December 31, 2007, as applicable. The amounts relate to our restricted units and performance units. Please see “Compensation Discussion and Analysis- Impact of Accounting and Tax Treatment- Accounting Treatment” above in this item for more information.

Since grants to officers who 55 or over are recognized immediately rather than over the course of the grant, the dollar amounts shown for those officers is much larger for than the dollar amounts shown for officers who are under 55, even for the same number of unit options granted.

(3) | The amounts reported represent the dollar amounts recognized by NuStar Energy for financial statement purposes for the fiscal year ended December 31, 2006 or December 31, 2007, as applicable. The amounts relate to grants of options to purchase NuStar Energy L.P. units and options to purchase NuStar GP Holdings, LLC units. Please see “Compensation Discussion and Analysis- Impact of Accounting and Tax Treatment- Accounting Treatment” above in this item for more information.

Since grants to officers who 55 or over are recognized immediately rather than over the course of the grant, the dollar amounts shown for those officers is much larger for than the dollar amounts shown for officers who are under 55, even for the same number of unit options granted.

(4) | For each of the NEOs, the following table identifies the separate amounts attributable to (A) the aggregate change in the actuarial present value of the NEO’s accumulated benefit under NuStar GP, LLC’s defined benefit and actuarial pension plans, including supplemental plans (but excluding tax-qualified defined contribution plans and nonqualified defined contribution plans), and (B) above-market or preferential earnings on compensation that is deferred on a basis that is not tax-qualified.

Name |  | (A) |  | (B) |  | TOTAL
Anastasio |  | $ | 46,806 |  | $ | 0 |  | $ | 46,806
Barron |  |  | 13,771 |  |  | 0 |  |  | 13,771
Blank |  |  | 36,731 |  |  | 0 |  |  | 36,731
Bluntzer |  |  | 135,019 |  |  | 0 |  |  | 135,019
Morgan |  |  | 31,628 |  |  | 0 |  |  | 31,628

(5) | For each of the NEOs, the following table identifies the separate amounts attributable to (A) the aggregate change in the actuarial present value of the NEO’s accumulated benefit under both Valero Energy’s and NuStar GP, LLC’s defined benefit and actuarial pension plans, including supplemental plans (but excluding tax-qualified defined contribution plans and nonqualified defined contribution plans), and (B) above-market or preferential earnings on compensation that is deferred on a basis that is not tax-qualified. Amounts included in column (A) below include the aggregate change in both the Valero Energy plans (for the period of January 1 through June 30, 2006) and the NuStar GP, LLC plans (for the period of July 1 through December 31, 2006).

Name |  | (A) |  | (B) |  | TOTAL
Anastasio |  | $ | 338,020 |  | $ | 0 |  | $ | 338,020
Barron |  |  | 24,511 |  |  | 0 |  |  | 24,511
Blank |  |  | 303,953 |  |  | 0 |  |  | 303,953
Bluntzer |  |  | 212,397 |  |  | 0 |  |  | 212,397
Morgan |  |  | 44,719 |  |  | 0 |  |  | 44,719

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(6) | The amounts reported in this column for 2007 consist of the following for each officer:

Name |  | Club Dues |  | Company Contribution to Thrift Plan |  | Company Contribution to Excess Thrift Plan |  | Tax Preparation |  | Personal Liability Insurance |  | Life Insurance Premiums |  |  | TOTAL
Anastasio |  | 7,681 |  | 13,500 |  | 12,204 |  | 785 |  | 2,122 |  | 3,276 |  |  | 39,568
Barron |  | — |  | 13,000 |  | 270 |  | — |  | 2,122 |  | 277 |  |  | 15,669
Blank |  | — |  | 13,500 |  | 5,215 |  | 785 |  | 2,122 |  | 2,528 | (a) |  | 24,150
Bluntzer |  | — |  | 13,500 |  | 1,310 |  | — |  | 2,122 |  | 3,276 |  |  | 20,208
Morgan |  | — |  | 13,500 |  | 3,238 |  | — |  | 2,122 |  | 898 |  |  | 19,758

(a) | The amount reported is the portion of a “split-dollar” life insurance policy premium paid by NuStar Energy in 2007 for the benefit of Mr. Blank. The policy was carried over by Valero Energy after its acquisition of Ultramar Diamond Shamrock Corporation (UDS) in 2001. Mr. Blank was an employee of UDS. Valero Energy turned over the premium to NuStar after the separation in 2006. NuStar and Mr. Blank paid the premium for the period of July 2007 through December 2007 ($2,528 and $691, respectively).

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GRANTS OF PLAN-BASED AWARDS

FOR FISCAL YEAR ENDED DECEMBER 31, 2007

The following table provides further information regarding the grants of plan-based awards to the named executive officers reflected in the Summary Compensation Table.

|  |  |  |  |  |  | Estimated Future Payouts Under Equity Incentive Plan Awards |  | All Other Unit Awards: Number of Units (#) |  | All Other Option Awards: Number of Securities Underlying Options (#) |  | Exercise or Base Price of Option Awards ($/Un) |  | Grant Date Fair Value of Unit and Unit Option Awards ($) |
Name |  | Grant Date |  |  | Date of approval by Comp Committee |  | Threshold (#) |  | Target (#) |  | Maximum (#) |  |  |  |
Anastasio |  | 01/25/07 | (1) |  | 01/25/07 |  | 0 |  | 3,600 |  | 7,200 |  | — |  | — |  | — |  | 208,836 | (4)
| 11/16/07 | (2) |  | 10/24/07 |  | — |  | — |  | — |  | — |  | 56,300 |  | 31.55 |  | 14,646 | (5)
| 11/16/07 | (3) |  | 10/24/07 |  | — |  | — |  | — |  | 7,210 |  | — |  | — |  | 411,331 | (6)
Barron |  | 01/25/07 | (1) |  | 01/25/07 |  | 0 |  | 680 |  | 1,360 |  | — |  | — |  | — |  | 39,447 | (4)
| 11/16/07 | (2) |  | 10/24/07 |  | — |  | — |  | — |  | — |  | 35,000 |  | 31.55 |  | 6,334 | (5)
| 11/16/07 | (3) |  | 10/24/07 |  | — |  | — |  | — |  | 3,000 |  | — |  | — |  | 171,150 | (6)
Blank |  | 01/25/07 | (1) |  | 01/25/07 |  | 0 |  | 1,670 |  | 3,340 |  | — |  | — |  | — |  | 96,877 | (4)
| 11/16/07 | (2) |  | 10/24/07 |  | — |  | — |  | — |  | — |  | 41,000 |  | 31.55 |  | 18,724 | (5)
| 11/16/07 | (3) |  | 10/24/07 |  | — |  | — |  | — |  | 3,360 |  | — |  | — |  | 191,688 | (6)
Bluntzer |  | 01/25/07 | (1) |  | 01/25/07 |  | 0 |  | 1,320 |  | 2,640 |  | — |  | — |  | — |  | 76,573 | (4)
| 11/16/07 | (2) |  | 10/24/07 |  | — |  | — |  | — |  | — |  | 35,000 |  | 31.55 |  | 15,638 | (5)
| 11/16/07 | (3) |  | 10/24/07 |  | — |  | — |  | — |  | 3,000 |  | — |  | — |  | 171,150 | (6)
Morgan |  | 01/25/07 | (1) |  | 01/25/07 |  | 0 |  | 930 |  | 1,860 |  | — |  | — |  | — |  | 53,949 | (4)
| 11/16/07 | (2) |  | 10/24/07 |  | — |  | — |  | — |  | — |  | 35,000 |  | 31.55 |  | 257,165 | (5)
| 11/16/07 | (3) |  | 10/24/07 |  | — |  | — |  | — |  | 3,000 |  | — |  | — |  | 171,150 | (6)

Footnotes:

(1) | Performance units were awarded by the Board on January 25, 2007. Each award is subject to vesting in three annual increments, based upon our TUR during rolling three-year periods that end on December 31 of each year following the date of grant. At the end of each performance period, our TUR is compared to the Peer Group and ranked by quartile. Executives then earn 0%, 50%, 100% or 150% of that portion of the initial grant amount that is vesting, depending upon whether our TUR is in the last, 3rd, 2nd or 1st quartile, respectively, and they earn 200% if we rank highest in the group. Amounts not earned in a given performance period can be carried forward for one additional performance period and up to 100% of the carried amount can still be earned, depending upon the quartile achieved for that subsequent period. For the performance period ended December 31, 2007, our performance ranked in the fourth quartile of the group and no eligible units were vested.

(2) | Options were approved by Compensation Committee of NuStar GP Holdings on October 24, 2007, and the grant dates for these options was set at that time for the date three days after NuStar Energy’s quarterly earning release, or November 12, 2007. However, since NuStar Energy subsequently determined to announce a public offer of 2,600,000 units on November 12, 2007, the Compensation Committee changed the date of grant to November 16, 2007. The market price on October 24, 2007 was $30.39, the market price on November 12, 2007 was $31.55, and the market price on November 16, 2007 was $31.55. The options vest 1/3 annually over three years beginning on the third anniversary of the grant date, and they expire on the seventh anniversary of the grant date.

(3) | Restricted units were granted by the Board, upon recommendation of the Compensation Committee, on October 24, 2007. The restricted units vest 1/5 annually over five years beginning on the first anniversary of the grant date, which was November 16, 2007.

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(4) | The grant date fair value for performance units was determined by multiplying the number of performance units that were granted by the NYSE closing unit price of our units on the date of grant.

(5) | The grant date fair value for unit options was determined by multiplying the number of unit options that were granted by the calculated Black-Scholes value at the date of grant. The estimated values grant date fair value were calculated using an expected average option life of five years, a risk-free interest rate of 3.29%, an expected volatility of 31.57% and an expected cash distribution yield of 4.69%. The actual value of unit options could be zero; realization of any positive value depends upon the actual future performance of our units and the continued employment of the unitholder. Accordingly, the values set forth in this table may not be achieved.

In addition, since the terms of NuStar GP, LLC’s unit plans provide that employees vest in the award when they retire or will continue to vest in the award after retirement over the nominal vesting period established in the award, we immediately recognize compensation expense for awards granted to retirement-eligible employees (or over the period from the grant date to the date retirement eligibility is achieved if that date is expected to occur during the nominal vesting period). Employees are typically retirement eligible at age 55. Since grants to officers who 55 or over are recognized immediately rather than over the course of the grant, the dollar amounts shown for those officers is much larger for than the dollar amounts shown for officers who are under 55, even for the same number of unit options granted

(6) | The grant date fair value for restricted units was determined by multiplying the number of restricted units that were granted by the NYSE closing unit price of our units on the date of grant.

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OUTSTANDING EQUITY AWARDS

AT DECEMBER 31, 2007

The following table provides further information regarding our named executive officers’ unexercised unit options, unvested restricted units and unvested performance units as of December 31, 2007. The value of restricted units reported below is equal to $53.30, the closing price on the New York Stock Exchange on December 31, 2007.

|  | Option Awards |  | Unit Awards
Name |  | Number of Securities Underlying Unexercised Options (#) Exercisable |  |  | Number of Securities Underlying Unexercised Options (#) Unexercisable |  |  | Equity Incentive Plan Awards: Number of Securities Underlying Unexercised Unearned Options (#) |  | Option Exercise Price ($) |  | Option Expiration Date |  | Number of Units That Have Not Vested (#) |  |  | Market Value of Units That Have Not Vested ($) |  | Equity Incentive Plan Awards: Number of Unearned Units or Other Rights That Have Not Vested (#) |  | Equity Incentive Plan Awards: Market or Payout Value of Unearned Units or Other Rights That Have Not Vested ($)
Anastasio |  | 14,000 | (1) |  | 0 |  |  | — |  | 38.22 |  | 03/22/2012 |  | — |  |  | — |  | — |  | —
| 10,000 | (2) |  | 0 |  |  | — |  | 36.30 |  | 09/23/2012 |  | — |  |  | — |  | — |  | —
| 9,440 | (3) |  | 2,360 |  |  | — |  | 45.35 |  | 10/29/2013 |  | — |  |  | — |  | — |  | —
| 5,775 | (4) |  | 3,850 |  |  | — |  | 56.51 |  | 10/28/2014 |  | — |  |  | — |  | — |  | —
| 5,380 | (5) |  | 8,070 |  |  | — |  | 57.51 |  | 10/27/2012 |  | — |  |  | — |  | — |  | —
| 2,200 | (6) |  | 8,800 |  |  | — |  | 55.92 |  | 11/02/2013 |  | — |  |  | — |  | — |  | —
| — |  |  | — |  |  | — |  | — |  | — |  | 14,872 | (7) |  | 792,678 |  | — |  | —
| — |  |  | — |  |  | — |  | — |  | — |  | 5,493 | (8) |  | 292,777 |  | — |  | —
| 0 |  |  | 56,300 | (9) |  | — |  | 31.55 |  | 11/16/2014 |  | — |  |  | — |  | — |  | —
Barron |  | 960 | (3) |  | 320 |  |  | — |  | 45.35 |  | 10/29/2013 |  | — |  |  | — |  | — |  | —
| 1,185 | (4) |  | 790 |  |  | — |  | 56.51 |  | 10/28/2014 |  | — |  |  | — |  | — |  | —
| 420 | (6) |  | 1,680 |  |  | — |  | 55.92 |  | 11/02/2013 |  | — |  |  | — |  | — |  | —
| — |  |  | — |  |  | — |  | — |  | — |  | 3,878 | (10) |  | 206,697 |  | — |  | —
| — |  |  | — |  |  | — |  | — |  | — |  | 1,040 | (11) |  | 55,432 |  | — |  | —
| 0 |  |  | 35,000 | (9) |  | — |  | 31.55 |  | 11/16/2014 |  | — |  |  | — |  | — |  | —
Blank |  | 3,333 | (1) |  | 0 |  |  | — |  | 38.22 |  | 03/22/2012 |  | — |  |  | — |  | — |  | —
| 3,333 | (2) |  | 0 |  |  | — |  | 36.30 |  | 09/23/2012 |  | — |  |  | — |  | — |  | —
| 6,960 | (3) |  | 1,740 |  |  | — |  | 45.35 |  | 10/29/2013 |  | — |  |  | — |  | — |  | —
| 4,125 | (4) |  | 2,750 |  |  | — |  | 56.51 |  | 10/28/2014 |  | — |  |  | — |  | — |  | —
| 2,890 | (5) |  | 4,335 |  |  | — |  | 57.51 |  | 10/27/2012 |  | — |  |  | — |  | — |  | —
| 1,025 | (6) |  | 4,100 |  |  | — |  | 55.92 |  | 11/02/2013 |  | — |  |  | — |  | — |  | —
| — |  |  | — |  |  | — |  | — |  | — |  | 7,524 | (12) |  | 401,029 |  | — |  | —
| — |  |  | — |  |  | — |  | — |  | — |  | 2,690 | (13) |  | 143,377 |  | — |  | —
| 0 |  |  | 41,000 | (9) |  | — |  | 31.55 |  | 11/16/2014 |  | — |  |  | — |  | — |  | —
Bluntzer |  | 4,500 | (1) |  | 0 |  |  | — |  | 38.22 |  | 03/22/2012 |  | — |  |  | — |  | — |  | —
| 2,140 | (3) |  | 535 |  |  | — |  | 45.35 |  | 10/29/2013 |  | — |  |  | — |  | — |  | —
| 1,485 | (4) |  | 990 |  |  | — |  | 56.51 |  | 10/28/2014 |  | — |  |  | — |  | — |  | —
| 2,160 | (5) |  | 3,240 |  |  | — |  | 57.51 |  | 10/27/2012 |  | — |  |  | — |  | — |  | —
| 810 | (6) |  | 3,240 |  |  | — |  | 55.92 |  | 11/02/2013 |  | — |  |  | — |  | — |  | —
| — |  |  | — |  |  | — |  | — |  | — |  | 5,832 | (14) |  | 310,846 |  | — |  | —
| — |  |  | — |  |  | — |  | — |  | — |  | 2,080 | (15) |  | 110,864 |  | — |  | —
| 0 |  |  | 35,000 |  |  | — |  | 31.55 |  | 11/16/2014 |  | — |  |  | — |  | — |  | —
Morgan |  | 1,760 | (16) |  | 2,640 |  |  | — |  | 60.25 |  | 07/01/2012 |  | — |  |  | — |  | — |  | —
| 1,620 | (5) |  | 2,430 |  |  | — |  | 57.51 |  | 10/27/2012 |  | — |  |  | — |  | — |  | —
| 575 | (6) |  | 2,300 |  |  | — |  | 55.92 |  | 11/02/2013 |  | — |  |  | — |  | — |  | —
| — |  |  | — |  |  | — |  | — |  | — |  | 5,882 | (17) |  | 313,511 |  | — |  | —
| — |  |  | — |  |  | — |  | — |  | — |  | 1,496 | (18) |  | 79,737 |  | — |  | —
| 0 |  |  | 35,000 |  |  | — |  | 31.55 |  | 11/16/2014 |  | — |  |  | — |  | — |  | —

Footnotes on following page.

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Footnotes:

(1) | Options granted March 22, 2002 vested in 1/3 increments over three years, beginning on the first anniversary of the date of grant.

(2) | Options granted September 23, 2002 vested in 1/3 increments over three years, beginning on the first anniversary of the date of grant.

(3) | Options granted October 29, 2003 vest in 1/5 increments over five years, beginning on the first anniversary of the date of grant.

(4) | Options granted on October 28, 2004 vest in 1/5 increments over five years, beginning on the first anniversary of the date of grant.

(5) | Options granted on October 27, 2005 vest in 1/5 increments over five years, beginning on the first anniversary of the date of grant.

(6) | Options granted on November 2, 2006 vest in 1/5 increments over five years, beginning on the first anniversary of the date of grant.

(7) | Mr. Anastasio’s restricted units consist of: 70 restricted units granted October 29, 2003; 1,540 restricted units granted October 28, 2004; 2,700 restricted units granted October 27, 2005; 3,352 restricted units granted November 2, 2006 and 7,210 restricted units granted November 16, 2007. All of Mr. Anastasio’s restricted units vest in 1/5 increments over five years, beginning on the first anniversary of the date of grant.

(8) | Mr. Anastasio’s unvested performance units were granted January 26, 2006 and January 25, 2007 and vest annually in 1/3 increments over three years beginning on the first anniversary of their grant date. The performance units are payable in NuStar Energy L.P.’s units. Upon vesting, the performance units are converted into a number of NuStar Energy L.P. units based on NuStar Energy’s TUR during rolling three-year periods that end of December 31 of each year following the date of grant. At the end of each performance period, NuStar Energy’s TUR is compared to the Peer Group and ranked by quartile. Holders of the performance units then earn 0%, 50%, 100% or 150% of that portion of the initial grant that is vesting, depending upon whether NuStar Energy’s TUR is in the last, third, second or first quartile, respectively; holders earn 200% if NuStar Energy is the highest ranking entity in the Peer Group. For the period ended December 31, 2006, NuStar Energy’s TUR was in the second quartile of it and the Peer Group, and Mr. Anastasio received 100% of 1/3 of his initial grant, or 947 units. For the period ended December 31, 2007, NuStar Energy’s TUR was in the fourth quartile of it and the Peer Group, and Mr. Anastasio received no vested performance units for the period.

(9) | Options of NuStar GP Holdings granted November 16, 2007 vest in 1/3 increments over three years, beginning on the third anniversary of the date of grant.

(10) | Mr. Barron’s restricted units consist of: 66 restricted units granted October 29, 2003; 172 restricted units granted October 28, 2004; 640 restricted units granted November 2, 2006 and 3,000 restricted units granted November 16, 2007. All of Mr. Barron’s restricted units vest in 1/5 increments over five years, beginning on the first anniversary of the date of grant.

(11) | Mr. Barron’s unvested performance units were granted January 26, 2006 and January 25, 2007 and vest in accordance with Footnote (8) above. For the period ended December 31, 2006, Mr. Barron received 100% of 1/3 of his initial grant, or 180 units. For the period ended December 31, 2007, NuStar Energy’s TUR was in the fourth quartile of it and the Peer Group, and Mr. Barron received no vested performance units for the period.

(12) | Mr. Blank’s restricted units consist of: 52 restricted units granted October 29, 2003; 1,100 restricted units granted October 28, 2004; 1,452 restricted units granted October 27, 2005; 1,560 restricted units granted November 2, 2006 and 3,360 restricted units granted November 16, 2007. All of Mr. Blank’s restricted units vest in 1/5 increments over five years, beginning on the first anniversary of the date of grant.

(13) | Mr. Blank’s unvested performance units were granted January 26, 2006 and January 25, 2007 and vest in accordance with the description in Footnote (8) above. For the period ended December 31, 2006, Mr. Blank received 100% of 1/3 of his initial grant, or 510 units. For the period ended December 31, 2007, NuStar Energy’s TUR was in the fourth quartile of it and the Peer Group, and Mr. Blank received no vested performance units for the period.

(14) | Mr. Bluntzer’s restricted units consist of: 110 restricted units granted October 29, 2003; 396 restricted units granted October 28, 2004; 1,086 restricted units granted October 27, 2005; 1,240 restricted units granted November 2, 2006 and 3,000 restricted units granted November 16, 2007. All of Mr. Bluntzer’s restricted units vest in 1/5 increments over five years, beginning on the first anniversary of the date of grant.

(15) | Mr. Bluntzer’s unvested performance units were granted January 26, 2006 and January 25, 2007 and vest in accordance with Footnote (8) above. For the period ended December 31, 2006, Mr. Bluntzer received 100% of 1/3 of his initial grant, or 380 units. For the period ended December 31, 2007, NuStar Energy’s TUR was in the fourth quartile of it and the Peer Group, and Mr. Bluntzer received no vested performance units for the period.

(16) | Options granted July 1, 2005 vest in 1/5 increments over five years, beginning on the first anniversary of the date of grant.

(17) | Ms. Morgan’s restricted units consist of: 1,200 restricted units granted July 1, 2005; 810 restricted units granted October 27, 2005; 872 restricted units granted November 2, 2006 and 3,000 restricted units granted November 16, 2007. All of Ms. Morgan’s restricted units vest in 1/5 increments over five years, beginning on the first anniversary of the date of grant.

(18) | Ms. Morgan’s unvested performance units were granted January 26, 2006 and January 27, 2007 and vest in accordance with Footnote (8) above. For the period ended December 31, 2006, Ms. Morgan received 100% of 1/3 of her initial grant, or 284 units. For the period ended December 31, 2007, NuStar Energy’s TUR was in the fourth quartile of it and the Peer Group, and Ms. Morgan received no vested performance units for the period.

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OPTION EXERCISES AND UNITS VESTED

IN YEAR ENDED DECEMBER 31, 2007

The following table provides further information regarding option exercises by our named executive officers, and the vesting of restricted units and performance units held by our named executive officers, during 2007.

|  | Option Awards(1) |  | Unit Awards(2)
Name |  | Number of Units Acquired on Exercise (#) |  | Value Realized on Exercise ($) |  | Number of Units Acquired on Vesting (#) |  |  | Value Realized on Vesting ($)(8)
Curtis V. Anastasio |  | — |  | — |  | 3,525 | (3) |  | 216,020
Bradley C. Barron |  | — |  | — |  | 492 | (4) |  | 29,884
Steven A. Blank |  | — |  | — |  | 1,986 | (5) |  | 121,893
James R. Bluntzer |  | — |  | — |  | 1,360 | (6) |  | 83,286
Mary F. Morgan |  | — |  | — |  | 1,172 | (7) |  | 74,513

Footnotes:

(1) | None of the NEOs exercised options in 2007.

(2) | Includes both performance and restricted unit vestings in 2007.

(3) | Mr. Anastasio’s units vested in 2007 as follows: 947 units on January 25, 2007; 900 units on October 27, 2007; 770 units on October 28, 2007, 70 units on October 29, 2007 and 838 units on November 2, 2007.

(4) | Mr. Barron’s units vested in 2007 as follows: 180 units on January 25, 2007; 86 units on October 28, 2007; 66 units on October 28, 2007 and 160 units on November 2, 2007.

(5) | Mr. Blank’s units vested in 2007 as follows: 510 units on January 25, 2007; 484 units on October 27, 2007; 550 units on October 28, 2007; 52 units on October 29, 2007 and 390 units on November 2, 2007.

(6) | Mr. Bluntzer’s units vested in 2007 as follows: 380 units on January 25, 2007; 362 units on October 27, 2007; 198 units on October 28, 2007; 110 units on October 29, 2007 and 310 units on November 2, 2007.

(7) | Ms. Morgan’s units vested in 2007 as follows: 284 units on January 25, 2007; 400 units on July 1, 2007; 270 units on October 27, 2007 and 218 units on November 2, 2007.

(8) | The value realized on vesting was calculated by multiplying the closing price of NuStar Energy L.P. units on the New York Stock Exchange on the date of vesting by the number of units vested. The closing prices of the applicable dates are as follows:

Vesting Date |  | Closing Price ($)
January 25, 2007 |  | 58.01
July 1, 2007 |  | 69.00
October 27, 2007 |  | 62.78
October 28, 2007 |  | 62.78
October 29, 2007 |  | 62.78
November 2, 2007 |  | 61.87

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POST-EMPLOYMENT COMPENSATION

PENSION BENEFITS

FOR YEAR ENDED DECEMBER 31, 2007

The following table provides information regarding the accumulated benefits of our named executive officer under NuStar GP, LLC’s during the year ended December 31, 2007.

Name |  | Plan Name |  | Number of Years Credited Service |  | Present Value of Accumulated Benefit($)(1) |  | Payments During Last Fiscal Year
Anastasio |  | NuStar GP, LLC Pension Plan |  | 1.5 |  | 26,074 |  | 0
| NuStar GP, LLC Excess Pension Plan |  | — |  | 53,934 |  | 0
| NuStar GP, LLC Supplemental Executive Retirement Plan |  | 6.0 |  | 226,356 |  | 0
Barron |  | NuStar GP, LLC Pension Plan |  | 1.5 |  | 13,932 |  | 0
| Excess Pension Plan |  | 7.0 |  | 17,869 |  | 0
| Supplemental Executive Retirement Plan |  | — |  | — |  | —
Blank |  | NuStar GP, LLC Pension Plan |  | 1.5 |  | 28,786 |  | 0
| Excess Pension Plan |  | — |  | — |  | 0
| Supplemental Executive Retirement Plan |  | 6.0 |  | 154,365 |  | 0
Bluntzer |  | NuStar GP, LLC Pension Plan |  | 1.5 |  | 28,629 |  | 0
| Excess Pension Plan |  | 31.7 |  | 388,279 |  | 0
| Supplemental Executive Retirement Plan |  | — |  | — |  | —
Morgan |  | NuStar GP, LLC Pension Plan |  | 1.5 |  | 33,762 |  | 0
| Excess Pension Plan |  | 2.5 |  | 35,354 |  | 0
| Supplemental Executive Retirement Plan |  | — |  | — |  | —

Footnotes:

(1) | The present values stated above were calculated using the same interest rate and mortality table that we use for valuations under FASB Statement No. 87 for financial reporting purpose. The present values as of December 31, 2007 were determined using: (a) a 6.82% discount rate, and (b) the plans’ earliest unreduced retirement age (i.e., age 62). The present values reflect postretirement mortality rates based on the RP2000 Combined Healthy Mortality Table Projected by Scale AA to 2015. No decrements were included for preretirement termination, mortality or disability. Where applicable, lump sums were determined based on a 6.07% interest rate and the mortality table prescribed by the Internal Revenue Service in Revenue Ruling 2007-67 for 2008 distributions.

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We maintain a noncontributory defined benefit pension plan in which most of our employees are eligible to participate and under which contributions by individual participants are neither required nor permitted. We also maintain a noncontributory, non-qualified excess pension plan and a non-qualified supplemental executive retirement plan, or SERP, which provide supplemental pension benefits to certain highly compensated employees. The excess pension plan and the SERP provide eligible employees with additional retirement savings opportunities that cannot be achieved with tax-qualified plans due to Internal Revenue Code of 1986, as amended (the Code) limits on (1) annual compensation that can be taken into account under qualified plans or (2) annual benefits that can be provided under qualified plans. Employees who are eligible for the excess pension plans and the SERP may participate in one or the other, but not both plans.

NuStar GP, LLC Pension Plan

The NuStar GP, LLC Pension Plan (the Pension Plan) is a traditional defined benefit pension plan established as of July 1, 2006 and designed to provide retirement benefits to our eligible employees based upon a specific formula. The formula used to calculate a pension benefit under the plan takes into consideration final average salary and total years of credited service. Certain participants who were participants in the Valero Energy Pension Plan prior to becoming eligible for participation in the Pension Plan received credit for their service recognized under the Valero Energy Pension Plan for purposes of vesting and eligibility under this plan.

Under an agreement between the companies, Valero Energy will pay pension benefits to eligible NuStar GP, LLC employees for their years of service with Valero Energy under the Valero Energy pension plan, and the employee’s highest annual salary will be determined with regard to service with NuStar GP, LLC after July 1, 2006 until the individual commences a benefit under the Valero Energy pension plan or terminates employment with NuStar GP, LLC. For more information about the Valero Energy Pension Plan, please see Valero Energy’s annual report on Form 10-K for the year ended December 31, 2007 and its 2008 annual proxy statement. The Pension Plan is intended to be a qualified plan under, and subject to, relevant provisions of the Code and the Employee Retirement Income Security Act of 1974, as amended (ERISA).

The Pension Plan (supplemented, as necessary, by the excess pension plan or the SERP described below) provides a monthly pension at normal retirement equal to 1.6% of the eligible employee’s average monthly compensation (based upon the eligible employee’s earnings during the three consecutive calendar years during the last ten years of the eligible employee’s credited service, including service with our former parent, Valero Energy, affording the highest such average) times the eligible employee’s years of credited service. Pension benefits are not subject to any deduction for social security or other offset amounts.

Eligible employees are NuStar GP, LLC employees, except for those employees who are nonresident aliens, who are U.S. citizens but being paid by a foreign affiliated employer (as defined in the plan), who are covered by a collective bargaining agreement (unless it expressly provides for the benefits provided under the plan), or who are not yet participating.

NuStar GP, LLC Excess Pension Plan

The NuStar GP, LLC Excess Pension Plan was established effective as of July 1, 2006 for the purpose of providing benefits to eligible employees of NuStar GP, LLC whose pension benefits under the NuStar GP, LLC Pension Plan and the Valero Energy Pension Plan, where applicable, are subject to limitations under the Code. The Excess Pension Plan is an excess benefit plan as contemplated under ERISA for those benefits provided in excess of Section 415 of the Code. Benefits provided as a result of other statutory limitations are limited to a select group of management or highly compensated employees. The Excess Pension Plan is not intended to constitute either a qualified plan under the Code or a funded plan subject to ERISA. For employees of NuStar GP, LLC who were eligible to receive a benefit under the Valero Energy Excess Pension Plan (the Predecessor Excess Pension Plan) as of July 1, 2006, the Excess Pension Plan assumed the liabilities of the Predecessor Excess Pension Plan and will provide a single, nonqualified defined benefit to eligible employees for their pre-July 1, 2006 benefit accruals under the Predecessor Excess Pension Plan and their post-July 1, 2006 benefit accruals under this Excess Pension Plan.

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An eligible employee’s monthly pension under the Excess Pension Plan will be equal to (i) 1.6% of the employee’s average monthly compensation multiplied by the employee’s years of service less (ii) the employee’s Pension Plan benefit. Mr. Barron, Mr. Bluntzer and Ms. Morgan participate in the Excess Pension Plan.

NuStar GP, LLC Supplemental Executive Retirement Plan

The SERP was established effective as of July 1, 2006 for the purpose of providing certain highly compensated, management personnel of NuStar GP, LLC and its subsidiaries a supplement to the retirement benefit they may otherwise receive under the Pension Plan and the Valero Energy Pension Plan, where applicable. The SERP is not intended to constitute either a qualified plan under the Code or a funded plan subject to ERISA. For employees of NuStar GP, LLC who were eligible to receive a benefit under the Valero Energy Supplemental Executive Retirement Plan (the Prior SERP) as of July 1, 2006, the SERP assumed the liabilities of the Prior SERP and shall provide a single, nonqualified defined benefit to eligible employees for their pre-July 1, 2006 benefit accruals under the Prior SERP and their post-July 1, 2006 benefit accruals under this SERP.

An eligible employee’s monthly pension under the SERP will be equal to:

| (i) | 1.6% of the employee’s average monthly compensation multiplied by the employee’s years of service; plus

| (ii) | 0.35% of the product of the employee’s years of service and the amount that the employee’s average monthly compensation exceeds the lesser of:

| a. | 1.25 multiplied by the employee’s monthly covered compensation and

| b. | the monthly FICA amount; minus

| (iii) | the employee’s Pension Plan benefit.

Mr. Anastasio and Mr. Blank participate in the SERP.

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NONQUALIFIED DEFERRED COMPENSATION

FOR YEAR ENDED DECEMBER 31, 2007

The following table provides additional information regarding contributions by NuStar GP, LLC and each of our named executive officers under our non-qualified defined contribution and other deferred compensation plans during the year ended December 31, 2007. The table also presents each named executive officer’s withdrawals, earnings and year-end balances in such plans. Please see the descriptions of our Excess Thrift Plan and the Frozen Nonqualified 401(k) Plan above in “Compensation Discussion and Analysis- Post-Employment Benefits.”

Name |  | Executive Contributions in 2007 ($)(1) |  | Registrant Contributions in 2007 ($)(2) |  | Aggregate Earnings in 2007 ($)(3) |  | Aggregate Withdrawals/ Distributions ($)(4) |  | Aggregate Balance at December 31, 2007 ($)(5)
Anastasio |  | 0 |  | 12,204 |  | 10,043 |  | 0 |  | 358,365
Barron |  | 0 |  | 270 |  | 0 |  | 0 |  | 206
Blank |  | 0 |  | 5,215 |  | 13,334 |  | 0 |  | 1,250,991
Bluntzer |  | 0 |  | 1,310 |  | 0 |  | 0 |  | 1,850
Morgan |  | 0 |  | 3,238 |  | 0 |  | 0 |  | 4,588

Footnotes:

(1) | The executives made no contributions to our plans in 2007.

(2) | Amounts reported represent our contributions to our Excess Thrift Plan. All of the amounts included in this column are included within the amounts reported as “All Other Compensation” for 2007 in the Summary Compensation Table.

(3) | Amounts include the earnings (excluding dividends, if any), if any, of the executives’ respective account in (as applicable) our Excess Thrift Plan and our Frozen Nonqualified 401(k) Plan.

(4) | The executives made no withdrawals from and received no distributions under our plans in 2007.

(5) | Amounts include the aggregate balance, if any, of the executives’ respective account in (as applicable) our Excess Thrift Plan and our Frozen Nonqualified 401(k) Plan.

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POTENTIAL PAYMENTS UPON TERMINATION OR CHANGE OF CONTROL

Each of our named executive officers has entered into a Change of Control Severance Agreement with NuStar Energy and NuStar GP, LLC. These agreements are intended to assure the continued availability of these executives in the event of a “change of control” (described below). The agreements have three-year terms, which are automatically extended for one year upon each anniversary unless a notice of nonrenewal is given to the executive. When a change of control occurs, the agreement becomes operative for a fixed three-year period. The agreements provide generally that the executive’s terms and conditions of employment (including position, location, compensation and benefits) will not be adversely changed during the three-year period after a change of control. In addition, outstanding unit options held by the executive will automatically vest, restrictions applicable to outstanding restricted units held by the executive will lapse, and all unvested performance units held by the executive will fully vest and become payable at 200% of target. In addition to the payments and benefits accruing to the executives under the various circumstances described in the agreements, the executives are entitled to receive a payment in an amount sufficient to make the executive whole for any excise tax on excess parachute payments imposed under Section 4999 of the Internal Revenue Code of 1986, as amended, if the amount of the payment exceeds the safe harbor limit by at least 110%. Each agreement subjects the executive to obligations of confidentiality, both during the term and after termination, for secret and confidential information relating to NuStar Energy, NuStar GP, LLC and their affiliates (as defined in the agreement) that the executive acquired during his or her employment.

For purposes of these agreements, a “change of control” means any of the following (subject to additional particulars as stated in the agreements):

| • |  | the acquisition by an individual, entity or group of beneficial ownership of 40% of NuStar GP Holdings’ voting interests;

| • |  | the failure of NuStar GP Holdings to control NuStar GP, LLC, NuStar Energy’s general partner, Riverwalk Logistics, L.P., or all of the general partner interests of NuStar Energy;

| • |  | Riverwalk Logistics, L.P. ceases to be NuStar Energy’s general partner or Riverwalk Logistics L.P. is no longer controlled by either NuStar GP, LLC or one of its affiliates;

| • |  | the acquisition of more than 50% of all voting interests of NuStar Energy then outstanding;

| • |  | certain consolidations or mergers of NuStar GP Holdings;

| • |  | certain consolidations or mergers of NuStar Energy;

| • |  | sale of all or substantially all of the assets of NuStar GP Holdings to anyone other than its affiliates;

| • |  | sale of all or substantially all of the assets of NuStar Energy to anyone other than its affiliates; or

| • |  | change in the composition of the NuStar GP Holdings board of directors so that fewer than a majority of those directors are “incumbent directors” as defined in the agreement.

In the agreements, “cause” is defined to mean, generally, the willful and continued failure of the executive to perform substantially the executive’s duties, or the willful engaging by the executive in illegal or gross misconduct that is materially and demonstrably injurious to the company. “Good reason” is defined to mean, generally:

| • |  | a diminution in the executive’s position, authority, duties and responsibilities,

| • |  | failure of NuStar Energy or NuStar GP, LLC (or of their respective successors) to comply with the provisions of the agreement,

| • |  | relocation of the executive or increased travel requirements, and

| • |  | termination of the executive’s employment other than as permitted by the agreement.

The following table discloses the amounts payable to our named executive officers under the different circumstances relating to a change of control; however, if the executive’s employment is terminated for “cause,” then the executive will not receive any benefits or compensation other than any accrued salary or vacation pay that remained unpaid through the date of termination, and, therefore, there is no presentation of termination for “cause” in the table below. Except as noted below, the table assumes that a change of control occurred on December 31, 2007, and that the executive’s employment was terminated on that date.

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PAYMENTS UNDER CHANGE OF CONTROL SEVERANCE AGREEMENTS

Executive Benefits and Payments |  | Termination of Employment by the Company Other Than for “Cause” or Disability, or by the Executive for “Good Reason” (2) |  |  | Termination of Employment because of Death or Disability (3) |  | Termination by the Executive Other Than for “Good Reason” (4) |  | Continued Employment Following Change of Control (5)
Salary (1) |  |  |  |  |  |  |  |  |  |  |  | (5)
Anastasio |  | $ | 1,310,400 |  |  | $ | 0 |  | $ | 0 |  |
Barron |  |  | 468,000 |  |  |  | 0 |  |  | 0 |  |
Blank |  |  | 636,064 |  |  |  | 0 |  |  | 0 |  |
Bluntzer |  |  | 505,360 |  |  |  | 0 |  |  | 0 |  |
Morgan |  |  | 568,880 |  |  |  | 0 |  |  | 0 |  |
Bonus (1) |  |  |  |  |  |  |  |  |  |  |  | (5)
Anastasio |  | $ | 1,179,360 |  |  | $ | 393,120 |  | $ | 393,120 |  |
Barron |  |  | 351,000 |  |  |  | 175,500 |  |  | 175,500 |  |
Blank |  |  | 477,048 |  |  |  | 238,524 |  |  | 238,524 |  |
Bluntzer |  |  | 390,000 |  |  |  | 195,000 |  |  | 195,000 |  |
Morgan |  |  | 390,000 |  |  |  | 195,000 |  |  | 195,000 |  |
Pension, Excess Pension, and SERP Benefits |  |  |  |  |  |  |  |  |  |  |  | (5)
Anastasio |  | $ | 544,851 |  |  | $ | 0 |  | $ | 0 |  |
Barron |  |  | 103,952 |  |  |  | 0 |  |  | 0 |  |
Blank |  |  | 207,491 |  |  |  | 0 |  |  | 0 |  |
Bluntzer |  |  | 385,750 |  |  |  | 0 |  |  | 0 |  |
Morgan |  |  | 189,963 |  |  |  | 0 |  |  | 0 |  |
Contributions under Defined Contribution Plans |  |  |  |  |  |  |  |  |  |  |  | (5)
Anastasio |  | $ | 172,973 |  |  | $ | 0 |  | $ | 0 |  |
Barron |  |  | 56,160 |  |  |  | 0 |  |  | 0 |  |
Blank |  |  | 76,328 |  |  |  | 0 |  |  | 0 |  |
Bluntzer |  |  | 60,403 |  |  |  | 0 |  |  | 0 |  |
Morgan |  |  | 68,266 |  |  |  | 0 |  |  | 0 |  |
Health and Welfare Plan Benefits |  |  | (6 | ) |  |  |  |  |  |  |  | (5)
Anastasio |  | $ | 60,525 |  |  | $ | 0 |  | $ | 0 |  |
Barron |  |  | 24,584 |  |  |  | 0 |  |  | 0 |  |
Blank |  |  | 40,350 |  |  |  | 0 |  |  | 0 |  |
Bluntzer |  |  | 28,882 |  |  |  | 0 |  |  | 0 |  |
Morgan |  |  | 40,350 |  |  |  | 0 |  |  | 0 |  |

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Executive Benefits and Payments |  | Termination of Employment by the Company Other Than for “Cause” or Disability, or by the Executive for “Good Reason” (2) |  | Termination of Employment because of Death or Disability (3) |  | Termination by the Executive Other Than for “Good Reason” (4) |  | Continued Employment Following Change of Control (5)
Accelerated Vesting of Unit Options (7) |  |  |  |  |  |  |  |  |  |  |  |
Anastasio |  | $ | 18,762 |  | $ | 18,762 |  | $ | 18,762 |  | $ | 18,762
Barron |  |  | 2,544 |  |  | 2,544 |  |  | 2,544 |  |  | 2,544
Blank |  |  | 13,833 |  |  | 13,833 |  |  | 13,833 |  |  | 13,833
Bluntzer |  |  | 4,253 |  |  | 4,253 |  |  | 4,253 |  |  | 4,253
Morgan |  |  | 0 |  |  | 0 |  |  | 0 |  |  | 0
Accelerated Vesting of Restricted Units (8) |  |  |  |  |  |  |  |  |  |  |  |
Anastasio |  | $ | 792,678 |  | $ | 792,678 |  | $ | 792,678 |  | $ | 792,678
Barron |  |  | 206,697 |  |  | 206,697 |  |  | 206,697 |  |  | 206,697
Blank |  |  | 401,029 |  |  | 401,029 |  |  | 401,029 |  |  | 401,029
Bluntzer |  |  | 310,846 |  |  | 310,846 |  |  | 310,846 |  |  | 310,846
Morgan |  |  | 313,511 |  |  | 313,511 |  |  | 313,511 |  |  | 313,511
Accelerated Vesting of Performance Units (9) |  |  |  |  |  |  |  |  |  |  |  |
Anastasio |  | $ | 585,554 |  | $ | 585,589 |  | $ | 585,589 |  | $ | 585,589
Barron |  |  | 110,864 |  |  | 110,864 |  |  | 110,864 |  |  | 110,864
Blank |  |  | 286,754 |  |  | 286,754 |  |  | 286,754 |  |  | 286,754
Bluntzer |  |  | 221,728 |  |  | 221,728 |  |  | 221,728 |  |  | 221,728
Morgan |  |  | 159,474 |  |  | 159,545 |  |  | 159,545 |  |  | 159,545
280G Tax Gross-Up (10) |  |  |  |  |  |  |  |  |  |  |  |
Anastasio |  | $ | 0 |  | $ | 0 |  | $ | 0 |  | $ | 0
Barron |  |  | 437,529 |  |  | 0 |  |  | 0 |  |  | 0
Blank |  |  | 0 |  |  | 0 |  |  | 0 |  |  | 0
Bluntzer |  |  | 627,558 |  |  | 0 |  |  | 0 |  |  | 0
Morgan |  |  | 0 |  |  | 0 |  |  | 0 |  |  | 0
Totals |  |  |  |  |  |  |  |  |  |  |  |
Anastasio |  | $ | 4,665,103 |  | $ | 1,790,149 |  | $ | 1,790,149 |  | $ | 1,397,029
Barron |  |  | 1,761,330 |  |  | 495,605 |  |  | 495,605 |  |  | 320,105
Blank |  |  | 2,138,897 |  |  | 940,140 |  |  | 940,140 |  |  | 701,616
Bluntzer |  |  | 2,534,780 |  |  | 731,827 |  |  | 731,827 |  |  | 536,827
Morgan |  |  | 1,730,444 |  |  | 668,056 |  |  | 668,056 |  |  | 473,056

Footnotes:

(1) | Per SEC regulations, for purposes of this analysis we assumed each executive’s compensation at the time of each triggering event to be as stated below. The listed salary is the executive’s actual annualized rate of pay as of December 31, 2007. The listed bonus amount represents the highest bonus earned by the executive in any of the fiscal years 2005, 2006 or 2007 (the three years prior to the assumed change of control):

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name |  | annual salary |  | bonus
Curtis V. Anastasio |  | $ | 436,800 |  | $ | 393,120
Bradley C. Barron |  |  | 234,000 |  |  | 175,500
Steven A. Blank |  |  | 318,032 |  |  | 238,524
James R. Bluntzer |  |  | 251,680 |  |  | 195,000
Mary F. Morgan |  |  | 284,440 |  |  | 195,000

(2) | Mr. Anastasio’s agreement provides that that if the company terminates his employment (other than for “cause,” death or “disability,” as defined in the agreement) or if he terminates his employment for “good reason,” as defined in the agreement, Mr. Anastasio is generally entitled to receive the following: (A) a lump sum cash payment equal to the sum of (i) accrued and unpaid compensation through the date of termination, including a pro-rata annual bonus (for this table, termination of employment was deemed to occur on the last day of the year; thus a full year’s bonus is shown for this element of compensation); (ii) three times the sum of Mr. Anastasio’s annual base salary plus Mr. Anastasio’s highest annual bonus from the past three years, (iii) the amount of the actuarial present value of the pension benefits (qualified and nonqualified) Mr. Anastasio would have received for an additional three years of service, and (iv) the equivalent of three years of employer contributions under NuStar GP, LLC’s tax-qualified and supplemental defined contribution plans; and (B) continued welfare benefits for three years.

Other than for Mr. Anastasio, the agreements generally provide that if the company terminates the executive’s employment (other than for “cause,” death or “disability,” as defined in the agreement) or if the executive terminates his or her employment for “good reason,” as defined in the agreement, the executive is generally entitled to receive the following: (A) a lump sum cash payment equal to the sum of (i) accrued and unpaid compensation through the date of termination, including a pro-rata annual bonus (for this table, termination of employment was deemed to occur on the last day of the year; thus a full year’s bonus is shown for this element of compensation); (ii) two times the sum of the executive’s annual base salary plus the executive’s highest annual bonus from the past three years, (iii) the amount of the actuarial present value of the pension benefits (qualified and nonqualified) the executive would have received for an additional two years of service, and (iv) the equivalent of two years of employer contributions under NuStar GP, LLC’s tax-qualified and supplemental defined contribution plans; and (B) continued welfare benefits for two years.

(3) | If the executive’s employment is terminated by reason of his death or disability, then his or her estate or beneficiaries will be entitled to receive a lump sum cash payment equal to any accrued and unpaid salary and vacation pay plus a bonus equal to the highest bonus earned by the executive in the prior three years (prorated to the date of termination). In this example, the termination of employment was deemed to occur on the last day of the year; thus a full year’s bonus is shown in the table. In addition, in the case of disability, the executive would be entitled to any disability and related benefits at least as favorable as those provided by NuStar GP, LLC under its plans and programs during the 120-days prior to the executive’s termination of employment.

(4) | If the executive voluntarily terminates his employment other than for “good reason,” then he or she will be entitled to a lump sum cash payment equal to any accrued and unpaid salary and vacation pay plus a bonus equal to the highest bonus earned by the executive in the prior three years (prorated to the date of termination). In this example, the termination of employment was deemed to occur on the last day of the year; thus a full year’s bonus is shown in the table.

(5) | The agreements provide for a three-year term of employment following a change of control. The agreements generally provide that the executive will continue to enjoy compensation and benefits on terms at least as favorable as in effect prior to the change of control. In addition, all outstanding equity incentive awards will automatically vest on the date of the change of control.

(6) | The executive is entitled to coverage under the welfare benefit plans (e.g., health, dental, etc.) for two years following the date of termination (three years for Mr. Anastasio).

(7) | The amounts stated in the table represent the gross value of previously unvested unit options derived by multiplying (x) the difference between the closing price of NuStar Energy L.P.’s units on the NYSE on December 31, 2007 and the options’ exercise prices, times (y) the number of unit options.

(8) | The amounts stated in the table represent the gross value of previously unvested restricted units, derived by multiplying (x) the number of units whose restrictions lapsed because of the change of control, and (y) the closing price of NuStar Energy L.P.’s units on the NYSE on December 31, 2007.

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(9) | The amounts stated in the table represent the product of (x) the number of performance units whose vesting was accelerated because of the change of control, times (y) the closing price of NuStar Energy L.P.’s units on the NYSE on December 31, 2007. Based upon 2007 performance, 0% of the performance units were awarded. For the remainder of the performance period, the 2008 and 2009 fiscal years, 200% of the performance units would be awarded because of the change of control assumed here.

(10) | If any payment or benefit is determined to be subject to an excise tax under Section 4999 of the Internal Revenue Code of 1986, as amended, the executive is entitled to receive an additional payment to adjust for the incremental tax cost of the payment or benefit. However, if the value of all parachute payments exceeds the safe harbor threshold by less than 110%, the amounts payable to an executive will be reduced so as to not exceed the safe harbor. The reduction will eliminate any excise tax under Section 4999.

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COMPENSATION OF DIRECTORS

DIRECTOR COMPENSATION (2007)

The following table provides a summary of compensation paid for the year ended December 31, 2007, to the Board. The table shows amounts earned by such persons for services rendered to NuStar GP, LLC in all capacities in which they served.

Name and Principal Position |  | Fees Earned or Paid in Cash ($)(1) |  |  | Unit Awards ($)(3) |  |  | Option Awards ($)(3) |  |  | Non-Equity Incentive Plan Compensation ($) |  |  | Change in Pension Value and Nonqualified Deferred Compensation Earnings ($) |  |  | All Other Compensation ($) |  |  | Total ($) |
William E. Greehey |  | 69,565 |  |  | 3,272 |  |  | — |  |  | — |  |  | — |  |  | 0 |  |  | 72,837 |
Curtis V. Anastasio |  | (2 | ) |  | (2 | ) |  | (2 | ) |  | (2 | ) |  | (2 | ) |  | (2 | ) |  | (2 | )
J. Dan Bates |  | 62,000 |  |  | 2,929 |  |  | — |  |  | — |  |  | — |  |  | — |  |  | 64,929 |
Dan J. Hill |  | 62,000 |  |  | 18,498 |  |  | — |  |  | — |  |  | — |  |  | — |  |  | 80,498 |
Stan L. McLelland |  | 36,000 |  |  | 9,293 |  |  | — |  |  | — |  |  | — |  |  | — |  |  | 45,293 |
Rodman D. Patton |  | 60,895 |  |  | 10,099 |  |  | — |  |  | — |  |  | — |  |  | — |  |  | 71,084 |

(1) | In addition to the fees paid according to the non-employee director compensation described below, the amounts disclosed in this column include reimbursement for expenses for transportation to and from Board meetings and lodging while attending meetings.

(2) | Mr. Anastasio is not compensated for his service as a director of NuStar GP, LLC. His compensation for his services as President and CEO are included above in the Summary Compensation Table.

(3) | Represents dollar amounts recognized by NuStar Energy for financial statement reporting purposes for the fiscal year ended December 31, 2007. Please see “Compensation Discussion and Analysis- Impact of Accounting and Tax Treatment- Accounting Treatment” above in this item for more information.

As of December 31, 2007, each director holds the following aggregate number of restricted unit and option awards:

Name |  | Aggregate # of Restricted Units |  | Aggregate # of Unit Options
William E. Greehey |  | 1,028 |  | —
Curtis V. Anastasio |  | * |  | *
J. Dan Bates |  | 1,056 |  | —
Dan J. Hill |  | 1,076 |  | —
Stan L. McLelland |  | 1,080 |  | —
Rodman D. Patton |  | 1,076 |  | —

* | Mr. Anastasio’s aggregate holdings are disclosed above in the Outstanding Equity Awards at December 31, 2007.

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During 2007, non-employee directors received a retainer fee of $35,000 per year, plus $1,000 for each Board and committee meeting attended in person and $500 for each Board and committee meeting attended telephonically. Directors who serve as chairperson of a committee receive an additional $10,000 annually. Each director is also reimbursed for expenses of meeting attendance. Directors who are employees of NuStar GP, LLC receive no compensation (other than reimbursement of expenses) for serving as directors. The Chairman of the Board receives an additional retainer fee of $30,000 per year. The Chairman of the Board receives no fees for attending committee meetings.

NuStar GP, LLC supplements the compensation paid to non-employee directors with an annual grant of restricted units valued at $40,000 that vests in equal annual installments over a three-year period. We believe this annual grant of restricted units increases the non-employee directors’ identification with the interests of NuStar Energy L.P.’s unitholders through ownership of NuStar Energy L.P. units. Upon a non-employee director’s initial election to the Board, the director will receive a grant of restricted units equal to the pro-rated amount of the annual grant of restricted units from the time of his or her election through the next annual grant of restricted units.

In the event of a “Change of Control” as defined in the 2000 LTIP, all unvested restricted units and unit options previously granted immediately become vested or exercisable. Each plan also contains anti-dilution provisions providing for an adjustment in the number of restricted units or unit options, respectively, that have been granted to prevent dilution of benefits in the event any change in the capital structure of NuStar Energy affects the NuStar Energy L.P. units.

Compensation Committee

The Compensation Committee reviews and reports to the Board on matters related to compensation strategies, policies and programs, including certain personnel policies and policy controls, management development, management succession and benefit programs. The Compensation Committee also approves and administers NuStar Energy’s equity compensation plans and incentive bonus plan. The Board has adopted a written charter for the Compensation Committee. The members of the Compensation Committee are Dan J. Hill (Chairman), J. Dan Bates and Rodman D. Patton, none of whom is a current or former employee or officer of NuStar GP, LLC. The Compensation Committee met five times in 2007.

Compensation Committee Interlocks and Insider Participation

There are no compensation committee interlocks. None of Dan J. Hill, J. Dan Bates or Rodman D. Patton has served as an officer or employee of NuStar GP, LLC. Furthermore, except for compensation arrangements disclosed in this annual report on Form 10-K, NuStar Energy has not participated in any contracts, loans, fees, awards or financial interests, direct or indirect, with any committee member, nor is NuStar Energy aware of any means, directly or indirectly, by which a committee member could receive a material benefit from NuStar Energy.

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ITEM 12. | SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED UNITHOLDER MATTERS

DIRECTORS AND EXECUTIVE OFFICERS

The following table sets forth ownership of NuStar Energy L.P. units and NuStar GP Holdings, LLC units by directors and executive officers of NuStar GP, LLC as of December 31, 2007. Unless otherwise indicated in the notes to the table, each of the named persons and members of the group has sole voting and investment power with respect to the units shown:

Name of Beneficial Owner (a) |  | Units Beneficially Owned (b)(c) |  | Units under Exercisable Options (d) |  | Percentage of Outstanding Units (c) |  |  | NuStar GP Holdings, LLC Units Beneficially Owned |  | NuStar GP Holdings, LLC Units under Exercisable Options |  | Percentage of Outstanding Units (e) |
William E. Greehey |  | 395,641 |  | 0 |  | * |  |  | 5,944,418 |  | 0 |  | 13.98 | %
Curtis V. Anastasio |  | 44,053 |  | 46,795 |  | * |  |  | 44,615 |  | 0 |  | * |
J. Dan Bates |  | 1,934 |  | 0 |  | * |  |  | 1,000 |  | 0 |  | * |
Dan J. Hill |  | 3,031 |  | 0 |  | * |  |  | 7,000 |  | 0 |  | * |
Stan McLelland |  | 3,443 |  | 0 |  | * |  |  | 12,230 |  | 0 |  | * |
Rodman D. Patton |  | 10,181 |  | 0 |  | * |  |  | 10,000 |  | 0 |  | * |
Bradley C. Barron |  | 4,959 |  | 2,565 |  | * |  |  | 3,800 |  | 0 |  | * |
Steven A. Blank |  | 23,551 |  | 21,666 |  | * |  |  | 37,000 |  | 0 |  | * |
James R. Bluntzer |  | 8,055 |  | 11,095 |  | * |  |  | 25,000 |  | 0 |  | * |
Mary F. Morgan |  | 10,268 |  | 3,955 |  | * |  |  | 500 |  | 0 |  | * |
Thomas R. Shoaf |  | 2,996 |  | 1,530 |  | * |  |  | 2,000 |  | 0 |  | * |
All directors and executive officers as a group (11 persons) |  | 508,112 |  | 87,606 |  | 1.20 | % |  | 6,087,563 |  |  |  | 14.32 | %

* | Indicates that the percentage of beneficial ownership does not exceed 1% of the class.

(a) | The business address for all beneficial owners listed above is 2330 North Loop 1604 West, San Antonio, Texas 78248.

(b) | As of December 31, 2007, 49,409,749 units were issued and outstanding. There are no classes of equity securities of NuStar Energy outstanding other than the units. The calculation for Percentage of Outstanding units includes units listed under the captions “Units Beneficially Owned” and “Units under Exercisable Options.”

(c) | Includes restricted units issued under NuStar Energy’s long-term incentive plans. Restricted units granted under NuStar GP, LLC’s long-term incentive plans may not be disposed of until vested. Does not include units that could be acquired under options, which information is set forth in the next column.

(d) | Consisting of units that may be acquired within 60 days of December 31, 2007 through the exercise of unit options.

(e) | As of December 31, 2007, 42,508,375 NuStar GP Holdings, LLC’s units were issued and outstanding. No executive officer or director owns any class of equity securities of NuStar GP Holdings other than common units. The calculation for Percentage of Outstanding Units includes units listed under the captions “NuStar GP Holdings, LLC Units Beneficially Owned” and “NuStar GP Holdings, LLC Units under Exercisable Options.”

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Except as otherwise indicated, the following table sets forth certain information as of December 31, 2007 with respect to each entity known to us to be the beneficial owner of more than 5% of our outstanding units.

Name and Address of Beneficial Owner |  | Units |  | Percentage of Units (b) |
NuStar GP Holdings(a) 2330 North Loop 1604 West San Antonio, Texas 78248 |  | 10,220,350 |  | 20.27 | %

(a) | NuStar GP Holdings owns the units through its wholly owned subsidiaries, NuStar GP, LLC and Riverwalk Holdings, LLC. NuStar GP Holdings controls voting and investment power of the units through these wholly owned subsidiaries.

(b) | Assumes 49,409,749 units outstanding.

EQUITY COMPENSATION PLAN INFORMATION

The following table sets forth information about NuStar GP, LLC’s equity compensation plans, which are described in further detail in Note 15 of Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data:”

Plan categories |  | Number of Securities to be issued upon exercise of outstanding unit options, warrants and rights |  | Weighted-Average exercise price of outstanding unit options, warrants and rights |  | Number of securities remaining for future issuance under equity compensation plans |
Equity Compensation Plans approved by security holders |  | 739,422 |  | 59.18 |  | 711,602 |
Equity Compensation Plans not approved by security holders |  | 453,965 |  | 50.76 |  | 266,091 | (a)

(a) | As of December 31, 2007, options to purchase 765 NuStar Energy L.P. units remained available for grant under the 2002 Unit Option Plan. As of December 31, 2007, 265,326 units remained available for grant under the 2003 Employee Unit Incentive Plan.

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ITEM 13. | CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE

TRANSACTIONS WITH MANAGEMENT AND OTHERS

In January 2007, our Board adopted a written related person transaction policy that codifies our prior practice. For purposes of the policy, a related person transaction is one that is not available to all employees generally or involving less than $10,000 when aggregated with similar transactions. The policy requires that any related person transaction between NuStar Energy or NuStar GP, LLC and: (i) any vice president, Section 16 officer or director, (ii) any 5% or greater unitholder of NuStar Energy, its controlled affiliates or NuStar GP Holdings, (iii) any immediate family member of any officer or director, or (iv) any entity controlled by any of (i), (ii) or (iii) (or in which any of (i), (ii) or (iii) owns more than 5%) must be approved by the disinterested members of the Board. In addition, the policy requires that the officers and directors have an affirmative obligation to inform our Corporate Secretary of his or her immediate family members, as well as any entities he or she controls or owns more than 5%.

Please see “Executive Compensation, Potential Payments upon Termination or Change in Control” for a discussion of NuStar Energy’s Change of Control Agreements with the named executive officers.

On December 10, 2007, NuStar Logistics, our wholly owned subsidiary, entered into a non-exclusive Aircraft Time Sharing Agreement (the Time Share Agreement) with William E. Greehey, Chairman of our Board. The Time Share Agreement provides that NuStar Logistics, L.P. will sublease the aircraft to Mr. Greehey on an “as needed and as available” basis, and will provide a fully qualified flight crew for all Mr. Greehey’s flights. Mr. Greehey will pay NuStar Logistics an amount equal to the maximum amount of expense reimbursement permitted in accordance with Section 91.501(d) of the Aeronautics Regulations of the Federal Aviation Administration and the Department of Transportation, which expenses include and are limited to: fuel oil, lubricants, and other additives; travel expenses of the crew, including food, lodging and ground transportation; hangar and tie down costs away from the aircraft’s base of operation; insurance obtained for the specific flight; landing fees, airport taxes and similar assessments; customs, foreign permit, and similar fees directly related to the flight; in-flight food and beverages; passenger ground transportation; flight planning and weather contract services; and an additional charge equal to 100% of the costs of the fuel oil, lubricants, and other additives. The Time Share Agreement has an initial term of two years, after which the Time Share Agreement will automatically renew for one-year terms until terminated by either party. The Time Share Agreement was approved by the disinterested members of the Board on December 5, 2007.

Effective on September 16, 2007, NuStar Logistics entered into an assignment and assumption agreement (the Assignment) with Valero Energy, pursuant to which NuStar Logistics, L.P. assumed certain of Valero Energy’s obligations under a letter agreement between Valero Energy and Mr. Greehey regarding his resignation from employment with Valero Energy (the Letter Agreement). Under the Letter Agreement, Valero Energy agreed to provide Mr. Greehey with “off-site office facilities and secretarial and other office services reasonably commensurate with Mr. Greehey’s position as retired Chief Executive Officer of Valero Energy (the Office Services). Since we moved our headquarters out of Valero Energy’s corporate headquarters in April 2007, we have provided office space for Mr. Greehey, the cost of which we billed to Valero Energy. In order to further simplify the relationship between us and Valero Energy, we assumed responsibility for the Office Services, for which Valero Energy paid us $1.2 million, the operating expense associated with providing Office Services to Mr. Greehey. The Conflicts Committee, consisting of the disinterested members of the Board, approved the Assignment on August 24, 2007.

RIGHTS OF NUSTAR GP HOLDINGS

Due to its ownership of NuStar GP, LLC and Riverwalk Holdings, LLC, NuStar GP Holdings indirectly owns:

| • |  | the 2% general partner interest in NuStar Energy, through its indirect 100% ownership interest in Riverwalk Logistics, L.P.;

| • |  | 100% of the incentive distribution rights issued by us, which entitles NuStar GP Holdings to receive increasing percentages of the cash we distribute, currently at the maximum percentage of 23%; and

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| • |  | 10,220,350 NuStar Energy L.P. units representing a 20.27% limited partner interest in NuStar Energy.

Certain of our officers are also officers of NuStar GP Holdings. Our Chairman, William E. Greehey, is also the Chairman of NuStar GP Holdings. NuStar GP Holdings appoints NuStar GP, LLC’s directors. NuStar GP, LLC’s board is responsible for overseeing NuStar GP, LLC’s role as the owner of the general partner of NuStar Energy, NuStar GP Holdings must also approve matters that have or would have reasonably expected to have a material effect on NuStar GP Holdings’ interests as one of our major unitholders.

NuStar Energy’s partnership agreement requires that NuStar GP, LLC maintain a Conflicts Committee, composed entirely of independent directors, to review and resolve certain potential conflicts of interest between Riverwalk Logistics, L.P. and its affiliates, on one hand, and NuStar Energy on the other hand.

DIRECTOR INDEPENDENCE

Our business is managed under the direction of the Board of NuStar GP, LLC, the general partner of Riverwalk Logistics, L.P., the general partner of NuStar Energy. The Board conducts its business through meetings of the Board and its committees. During 2007, the Board held eight meetings. No member of the Board attended less than 75% of the meetings of the Board and committees of which he was a member.

The Board has standing Audit and Compensation committees. Each committee has a written charter. The committees of the Board and the number of meetings held by the committees in 2007 are described below.

Independent Directors

The Board has one member of management, Curtis V. Anastasio, President and CEO, and five non-management directors. The Board has determined that three of five of its non-management directors meet the independence requirements of the NYSE listing standards as set forth in the NYSE Listed Company Manual. As a limited partnership, NuStar Energy is not required to have a majority of independent directors. The independent directors are: J. Dan Bates, Dan J. Hill and Rodman D. Patton.

William E. Greehey, Chairman of the Board, retired as CEO of Valero Energy at the end of 2005. He remained Chairman of Valero Energy’s board of directors until January 2007. Valero Energy is a customer of NuStar Energy L.P., accounting for approximately 18% of total revenues for the year ended December 31, 2007. Mr. Greehey also serves as the Chairman of the NuStar GP Holdings board of directors.

Curtis V. Anastasio has been President of NuStar GP, LLC since December 1999 and CEO since June 2000. As a member of management, Mr. Anastasio is not an independent director under the NYSE’s listing standards. Mr. Anastasio also serves as President and CEO of NuStar GP Holdings.

Stan L. McLelland has been a member of the Board since October 2005. In July 2006, Mr. McLelland also became a member of the board of directors of NuStar GP Holdings. Mr. McLelland stepped down from the Audit and Compensation Committees of NuStar GP, LLC when he joined the NuStar GP Holdings board of directors.

The Audit and Compensation committees of the Board are each composed entirely of directors who meet the independence requirements of the NYSE listing standards. Each member of the Audit Committee also meets the additional independence standards for Audit Committee members set forth in the regulations of the Securities and Exchange Commission (SEC).

Independence Determinations

Under the NYSE’s listing standards, no director qualifies as independent unless the Board affirmatively determines that the director has no material relationship with NuStar Energy. Based upon information requested from and provided by each director concerning their background, employment and affiliations, including commercial, industrial, banking, consulting, legal, accounting, charitable and familial relationships, the Board has determined that, other than being a director of NuStar GP, LLC and/or unitholder of NuStar Energy,

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each of the independent directors named above has either no relationship with NuStar Energy, either directly or as a partner, unitholder or officer of an organization that has a relationship with NuStar Energy, or has only immaterial relationships with NuStar Energy, and is therefore independent under the NYSE’s listing standards.

As provided for under the NYSE listing standards, the Board has adopted categorical standards or guidelines to assist the Board in making its independence determinations with respect to each director. Under the NYSE listing standards, immaterial relationships that fall within the guidelines are not required to be disclosed in this proxy statement.

A relationship falls within the guidelines adopted by the Board if it:

| • |  | is not a relationship that would preclude a determination of independence under Section 303A.02(b) of the NYSE Listed Company Manual;

| • |  | consists of charitable contributions by NuStar GP, LLC to an organization where a director is an executive officer and does not exceed the greater of $1 million or 2% of the organization’s gross revenue in any of the last three years;

| • |  | consists of charitable contributions to any organization with which a director, or any member of a director’s immediate family, is affiliated as an officer, director or trustee pursuant to a matching gift program of NuStar GP, LLC and made on terms applicable to employees and directors; or is in amounts that do not exceed $250,000 per year; and

| • |  | is not required to be, and it is not otherwise, disclosed in this annual report on Form 10-K.

NuStar GP, LLC’s Corporate Governance Guidelines contain the director qualification standards, including the guidelines listed above, and are available on NuStar Energy’s internet website at http://www.nustarenergy.com (in the Investor Relations section).

Presiding Director/Meetings of Non-Management Directors

The Board has designated Mr. Patton to serve as the Presiding Director for meetings of the non-management Board members outside the presence of management.

Communications with the Board, Non-Management Directors or Presiding Director

Unitholders and other interested parties may communicate with the Board, the non-management directors or the Presiding Director by sending a written communication in an envelope addressed to “Board of Directors,” “Non-Management Directors,” or “Presiding Director” in care of NuStar GP, LLC’s Corporate Secretary at the address indicated on the cover page of this annual report on Form 10-K.

Availability of Governance Documents

NuStar Energy has posted its Corporate Governance Guidelines, Code of Business Conduct and Ethics, Code of Ethics of Senior Financial Officers, the Audit Committee Charter and other governance documents on NuStar Energy’s internet website at http://www.nustarenergy.com (in the “Investor Relations” section). NuStar Energy’s governance documents are available in print to any unitholder of record who makes a written request to NuStar Energy. Requests must be directed to NuStar GP, LLC’s Corporate Secretary at the address indicated on the cover page of this annual report on Form 10-K.

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ITEM 14. | PRINCIPAL ACCOUNTANT FEES AND SERVICES

KPMG FEES FOR FISCAL YEAR 2007

Audit Fees

The aggregate fees for fiscal year 2007 for professional services rendered by KPMG for the audit of the annual financial statements for the year ended December 31, 2007 included in this Form 10-K, review of NuStar Energy’s interim financial statements included in NuStar Energy’s 2007 Forms 10-Q, the audit of the effectiveness of NuStar Energy’s internal control over financial reporting as of December 31, 2007 and related services that are normally provided by the principal auditor (e.g., comfort letters and assistance with review of documents filed with the SEC) were $1,743,930.

Audit-related Fees

The aggregate fees for the fiscal year 2007 for assurance and related services rendered by KPMG that are reasonably related to the performance of the audit or review of NuStar Energy’s financial statements and not reported in the preceding caption were $242,693. The fees related primarily to consultations for technical accounting issues and audit fees incurred for Kaneb benefit plans.

Tax Fees

The aggregate fees for the fiscal year 2007 for professional services rendered by KPMG for tax compliance, tax advice and tax planning were $0.

All Other Fees

The aggregate fees for the fiscal year 2007 for services rendered by KPMG, other than the services reported under the preceding captions, were $0.

KPMG FEES FOR FISCAL YEAR 2006

Audit Fees

The aggregate fees for fiscal year 2006 for professional services rendered by KPMG for the audit of the annual financial statements for the year ended December 31, 2006 included in this Form 10-K, review of NuStar Energy’s interim financial statements included in NuStar Energy’s 2006 Forms 10-Q, the audit of the effectiveness of NuStar Energy’s internal control over financial reporting as of December 31, 2006 and related services that are normally provided by the principal auditor (e.g., comfort letters and assistance with review of documents filed with the SEC) were $2,313,000.

Audit-related Fees

The aggregate fees for the fiscal year 2006 for assurance and related services rendered by KPMG that are reasonably related to the performance of the audit or review of NuStar Energy’s financial statements and not reported in the preceding caption were $112,720. The fees related primarily to consultations for technical accounting issues and audit fees incurred for Kaneb benefit plans.

Tax Fees

The aggregate fees for the fiscal year 2006 for professional services rendered by KPMG for tax compliance, tax advice and tax planning were $0.

All Other Fees

The aggregate fees for the fiscal year 2006 for services rendered by KPMG, other than the services reported under the preceding captions, were $0.

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AUDIT COMMITTEE PRE-APPROVAL POLICY

The audit committee has adopted a pre-approval policy to address the approval of services rendered to NuStar Energy by its independent auditors, which is filed herewith as Exhibit 99.01.

None of the services (described above) for 2006 or 2007 provided by KPMG were approved by the audit committee pursuant to paragraph (c)(7)(i)(C) of Rule 2-01 of Regulation S-X.

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PART IV

ITEM 15. | EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(a) |  | (1) |  | Financial Statements. The following consolidated financial statements of NuStar Energy L.P. and its subsidiaries are included in Part II, Item 8 of this Form 10-K:
|  |  |  | Management’s Report on Internal Control over Financial Reporting
|  |  |  | Reports of independent registered public accounting firm (KPMG LLP)
|  |  |  | Consolidated Balance Sheets as of December 31, 2007 and 2006
|  |  |  | Consolidated Statements of Income for the Years Ended December 31, 2007, 2006 and 2005
|  |  |  | Consolidated Statements of Cash Flows for the Years Ended December 31, 2007, 2006 and 2005
|  |  |  | Consolidated Statements of Partners’ Equity for the Years Ended December 31, 2007, 2006 and 2005
|  |  |  | Notes to Consolidated Financial Statements

| (2) | Financial Statement Schedules and Other Financial Information. No financial statement schedules are submitted because either they are inapplicable or because the required information is included in the consolidated financial statements or notes thereto.

| (3) | Exhibits

Filed as part of this Form 10-K are the following:

Exhibit Number |  | Description |  | Incorporated by Reference to the Following Document
2.01 |  | Agreement and Plan of Merger, dated as of October 31, 2004, by and among Valero L.P., Riverwalk Logistics, L.P., Valero GP, LLC, VLI Sub A LLC and Kaneb Services LLC |  | NuStar Energy L.P.’s Current Report on Form 8-K filed November 4, 2004 (File No. 001-16417), Exhibit 99.1
2.02 |  | Agreement and Plan of Merger, dated as of October 31, 2004, by and among Valero L.P., Riverwalk Logistics, L.P., Valero GP, LLC, VLI Sub B LLC and Kaneb Pipe Line Partners, L.P. and Kaneb Pipe Line Company LLC |  | NuStar Energy L.P.’s Current Report on Form 8-K filed November 4, 2004 (File No. 001-16417), Exhibit 99.2
3.01 |  | Certificate of Formation of UDS Logistics, LLC |  | NuStar GP Holdings, LLC’s Registration Statement on Form S-1 filed on March 31, 2006 (File No. 333-132917), Exhibit 3.01
3.02 |  | Certificate of Amendment to Certificate of Formation of UDS Logistics, LLC |  | NuStar GP Holdings, LLC’s Registration Statement on Form S-1 filed on March 31, 2006 (File No. 333-132917), Exhibit 3.03
3.03 |  | Amended and Restated Certificate of Limited Partnership of Valero L.P. |  | NuStar Energy L.P.’s Annual Report on Form 10-K for year ended December 31, 2001 (File No. 001-16417), Exhibit 3.3
3.04 |  | Amendment to Amended and Restated Certificate of Limited Partnership of Valero L.P., dated March 21, 2007 and effective April 1, 2007 |  | NuStar Energy L.P.’s Current Report on Form 8-K, filed March 27, 2007 (File No. 001-16417), Exhibit 3.01

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Exhibit Number |  | Description |  | Incorporated by Reference to the Following Document
3.05 |  | Third Amended and Restated Agreement of Limited Partnership of Valero L.P. |  | NuStar Energy L.P.’s Quarterly Report on Form 10-Q for quarter ended March 31, 2003 (File No. 001-16417), Exhibit 3.1
3.06 |  | First Amendment to Third Amended and Restated Agreement of Limited Partnership of Valero L.P. |  | NuStar Energy L.P.’s Annual Report on Form 10-K for year ended December 31, 2003 (File No. 001-16417), Exhibit 4.3
3.07 |  | Amendment No. 2 to Third Amended and Restated Agreement of Limited Partnership of Valero L.P., dated as of July 1, 2005 |  | NuStar Energy L.P.’s Quarterly Report on Form 10-Q for quarter ended June 30, 2005 (File No. 001-16417), Exhibit 4.01
3.08 |  | Certificate of Limited Partnership of Valero Logistics Operations, L.P. |  | NuStar Energy L.P.’s Registration Statement on Form S-1 (File No. 333-43668), Exhibit 3.4
3.09 |  | Certificate of Amendment to Certificate of Limited Partnership of Valero Logistics Operations, L.P. |  | NuStar Energy L.P.’s Registration Statement on Form S-1 (File No. 333-43668), Exhibit 3.5
3.10 |  | Certificate of Amendment to Certificate of Limited Partnership of Valero Logistics Operations, L.P., dated March 21, 2007 and effective April 1, 2007 |  | NuStar Energy L.P.’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2007, File No. 001-16417, Exhibit 3.03
3.11 |  | Second Amended and Restated Agreement of Limited Partnership of Valero Logistics Operations, L.P. |  | NuStar Energy L.P.’s Annual Report on Form 10-K for year ended December 31, 2001 (File No. 001-16417), Exhibit 3.9
3.12 |  | Second Amendment to Second Amended and Restated Agreement of Limited Partnership of Valero Logistics Operations, L.P. |  | NuStar Energy L.P.’s Annual Report on Form 10-K for year ended December 31, 2001 (File No. 001-16417), Exhibit 3.10
3.13 |  | Certificate of Limited Partnership of Riverwalk Logistics, L.P. |  | NuStar Energy L.P.’s Registration Statement on Form S-1 (File No. 333-43668), Exhibit 3.7
3.14 |  | First Amended and Restated Limited Partnership Agreement of Riverwalk Logistics, L.P. |  | NuStar Energy L.P.’s Annual Report on Form 10-K for the year ended December 31, 2001 (File No. 001-16417), Exhibit 3.16
3.15 |  | Certificate of Formation of Valero GP, LLC |  | NuStar Energy L.P.’s Registration Statement on Form S-1 (File No. 333-43668), Exhibit 3.9
3.16 |  | Amendment to Certificate of Formation of Valero GP, LLC, dated March 21, 2007 and effective April 1, 2007 |  | NuStar Energy L.P.’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2007, File No. 001-16417, Exhibit 3.02

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Exhibit Number |  | Description |  | Incorporated by Reference to the Following Document
3.17 |  | Certificate of Amendment to Certificate of Formation of Valero GP, LLC |  | NuStar Energy L.P.’s Annual Report on Form 10-K for year ended December 31, 2001 (File No. 001-16417), Exhibit 3.14
3.18 |  | First Amended and Restated LLC Agreement of Shamrock Logistics GP, LLC |  | NuStar Energy L.P.’s Registration Statement on Form S-1 (File No. 333-43668), Exhibit 3.10
3.19 |  | First Amendment to First Amended and Restated Limited Liability Company Agreement of Valero GP, LLC |  | NuStar Energy L.P.’s Annual Report on Form 10-K for year ended December 31, 2001 (File No. 001-16417), Exhibit 3.15
3.20 |  | First Amended and Restated Limited Partnership Agreement of Riverwalk Logistics, L.P. |  | NuStar Energy L.P.’s Annual Report on Form 10-K for year ended December 31, 2001 (File No. 001-16417), Exhibit 3.16
4.01 |  | Indenture, dated July 15, 2002, among Valero Logistics Operations, L.P., as Issuer, Valero L.P., as Guarantor, and The Bank of New York, as Trustee, relating to Senior Debt Securities |  | NuStar Energy L.P.’s Current Report on Form 8-K filed July 15, 2002 (File No. 001-16417), Exhibit 4.1
4.02 |  | First Supplemental Indenture, dated as of July 15, 2002, to Indenture dated July 15, 2002, in each case among Valero Logistics Operations, L.P., as Issuer, Valero L.P., as Guarantor, and The Bank of New York, as Trustee, relating to 6 7/8% Senior Notes Due 2012 |  | NuStar Energy L.P.’s Current Report on Form 8-K filed July 15, 2002 (File No. 001-16417), Exhibit 4.2
4.03 |  | Second Supplemental Indenture, dated as of March 18, 2003, to Indenture dated July 15, 2002, as amended and supplemented by a First Supplemental Indenture thereto dated as of July 15, 2002, in each case among Valero Logistics Operations, L.P., as Issuer, Valero L.P., as Guarantor, and The Bank of New York, as Trustee (including, form of global note representing $250,000,000 6.05% Senior Notes due 2013) |  | NuStar Energy L.P.’s Current Report on Form 8-K filed May 9, 2003 (File No. 001-16417), Exhibit 4.1
4.04 |  | Third Supplemental Indenture, dated as of July 1, 2005, to Indenture dated July 15, 2002, as amended and supplemented, among Valero Logistics Operations, L.P.; Valero L.P.; Kaneb Pipe Line Operating Partnership, L.P.; and The Bank of New York |  | NuStar Energy L.P.’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2005 (File No. 001-16417), Exhibit 4.02

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Exhibit Number |  | Description |  | Incorporated by Reference to the Following Document
4.05 |  | Indenture, dated as of February 21, 2002, between Kaneb Pipe Line Operating Partnership, L.P. and JPMorgan Chase Bank (Senior Debt Securities) |  | NuStar Energy L.P.’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2005 (File No. 001-16417), Exhibit 4.03
4.06 |  | First Supplemental Indenture, dated as of February 21, 2002, to Indenture dated as of February 21, 2002, between Kaneb Pipe Line Operating Partnership, L.P. and JPMorgan Chase Bank (including form of 7.750% Senior Unsecured Notes due 2012) |  | NuStar Energy L.P.’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2005 (File No. 001-16417), Exhibit 4.04
4.07 |  | Second Supplemental Indenture, dated as of August 9, 2002 and effective as of April 4, 2002, to Indenture dated as of February 21, 2002, as amended and supplemented, between Kaneb Pipe Line Operating Partnership, L.P.; Statia Terminals Canada Partnership; and JPMorgan Chase Bank |  | NuStar Energy L.P.’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2005 (File No. 001-16417), Exhibit 4.05
4.08 |  | Third Supplemental Indenture, dated and effective as of May 16, 2003, to Indenture dated as of February 21, 2002, as amended and supplemented, between Kaneb Pipe Line Operating Partnership, L.P.; Statia Terminals Canada Partnership; and JPMorgan Chase Bank |  | NuStar Energy L.P.’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2005 (File No. 001-16417), Exhibit 4.06
4.09 |  | Fourth Supplemental Indenture, dated and effective as of May 27, 2003, to Indenture dated as of February 21, 2002, as amended and supplemented, between Kaneb Pipe Line Operating Partnership, L.P. and JPMorgan Chase Bank (including form of 5.875% Senior Unsecured Notes due 2013) |  | NuStar Energy L.P.’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2005 (File No. 001-16417), Exhibit 4.07
4.10 |  | Fifth Supplemental Indenture, dated and effective as of July 1, 2005, to Indenture dated as of February 21, 2002, as amended and supplemented, among Kaneb Pipe Line Operating Partnership, L.P.; Valero L.P.; Valero Logistics Operations, L.P.; and JPMorgan Chase Bank |  | NuStar Energy L.P.’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2005 (File No. 001-16417), Exhibit 4.08
4.11 |  | Registration Rights Agreement, dated March 18, 2003, among Valero Logistics Operations, L.P., as Issuer, Valero L.P., as Guarantor, and the initial purchasers of Valero Logistics Operations, L.P. 6.05% Senior Notes due 2013 |  | NuStar Energy L.P.’s Quarterly Report on Form 10-Q for quarter ended March 31, 2003 (File No. 001-16417), Exhibit 10.10

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Exhibit Number |  | Description |  | Incorporated by Reference to the Following Document
10.01 |  | 5-Year Revolving Credit Agreement dated as of December 10, 2007 among NuStar Logistics, L.P., NuStar Energy L.P., the Lenders party thereto and JPMorgan Chase Bank, N.A., as Administrative Agent, Suntrust Bank, as Syndication Agent, and Barclays Bank PLC and Mizuho Corporate Bank Ltd., as Co-Documentation Agents |  | *
+10.02 |  | NuStar GP, LLC Amended and Restated 2003 Employee Unit Incentive Plan |  | NuStar Energy L.P.’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2007 (File No. 001-16417), Exhibit 10.03
+10.03 |  | Form of Unit Option Agreement under the Amended and Restated Employee Unit Incentive Plan |  | NuStar Energy L.P.’s Annual Report on Form 10-K for year ended December 31, 2006 (File No. 001-16417), Exhibit 10.18
+10.04 |  | NuStar GP, LLC Amended and Restated 2002 Unit Option Plan, amended and restated as of April 1, 2007 |  | NuStar Energy L.P.’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2007 (File No. 001-16417), Exhibit 10.02
+10.05 |  | NuStar GP, LLC Second Amended and Restated 2000 Long-Term Incentive Plan, amended and restated as of April 1, 2007 |  | NuStar Energy L.P.’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2007 (File No. 001-16417), Exhibit 10.01
+10.06 |  | Form of Restricted Unit Agreement under the NuStar GP, LLC Second Amended and Restated 2000 Long-Term Incentive Plan |  | NuStar Energy L.P.’s Current Report on Form 8-K dated October 24, 2007 and filed October 29, 2007 (File No. 001-16417), Exhibit 10.03
+10.07 |  | Form of Unit Option Award Agreement under the NuStar GP, LLC Second Amended and Restated 2000 Long-Term Incentive Plan |  | NuStar Energy L.P.’s Current Report on Form 8-K filed November 3, 2006 (File No. 001-16417), Exhibit 10.02
+10.08 |  | Form of Performance Unit Agreement under the NuStar GP, LLC Amended and Restated 2000 Long-Term Incentive Plan |  | NuStar Energy L.P.’s Current Report on Form 8-K filed January 26, 2006 (File No. 001-16417), Exhibit 10.02
+10.09 |  | Form of Non-employee Director Restricted Unit Agreement under the NuStar GP, LLC Second Amended and Restated 2000 Long-Term Incentive Plan |  | NuStar Energy L.P.’s Current Report on Form 8-K dated October 24, 2007 and filed October 29, 2007 (File No. 001-16417), Exhibit 10.02
+10.10 |  | NuStar Energy L.P. Bonus Plan |  | NuStar Energy L.P.’s Annual Report on Form 10-K for year ended December 31, 2006 (File No. 001-16417), Exhibit 10.18
+10.11 |  | Change of Control Severance Agreement by and among Valero GP, LLC, Valero L.P. and Curtis V. Anastasio, dated November 6, 2006. |  | NuStar Energy L.P.’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2006 (File No. 001-16417), Exhibit 10.05

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Exhibit Number |  | Description |  | Incorporated by Reference to the Following Document
+10.12 |  | Form of Change of Control Severance Agreement by and among Valero GP, LLC, Valero L.P. and each of the other executive officers of Valero GP, LLC |  | NuStar Energy L.P.’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2006 (File No. 001-16417), Exhibit 10.06
10.13 |  | Pipelines and Terminals Usage Agreement by and among Ultramar Diamond Shamrock Corporation, Shamrock Logistics Operations, L.P., Shamrock Logistics, L.P., Riverwalk Logistics, L.P. and Shamrock Logistics GP, LLC, dated April 16, 2001 |  | NuStar Energy L.P.’s Annual Report on Form 10-K for year ended December 31, 2001, Exhibit 10.6
10.14 |  | Fourth Amended and Restated Services Agreement among Diamond Shamrock Refining and Marketing Company, Valero L.P., Valero Logistics Operations, L.P., Riverwalk Logistics, L.P. and Valero GP, LLC, effective as of December 22, 2006 |  | NuStar Energy L.P.’s Current Report on Form 8-K filed December 22, 2006 (File No. 001-16417), Exhibit 10.01
10.15 |  | Operating Agreement by and between Shamrock Logistics Operations, L.P. and Valero Pipeline Company, dated January 1, 2002 |  | NuStar Energy L.P.’s Annual Report on Form 10-K for year ended December 31, 2001 (File No. 001-16417), Exhibit 10.13
10.16 |  | Contribution Agreement by and among Valero Refining Company–California, UDS Logistics, LLC, Valero L.P., Valero GP, Inc. and Valero Logistics Operations, L.P. dated as of March 6, 2003 |  | NuStar Energy L.P.’s Annual Report on Form 10-K for year ended December 31, 2002 (File No. 001-16417), Exhibit 10.13
10.17 |  | Contribution Agreement by and among Valero Refining Company–Texas, L.P., UDS Logistics, LLC, Valero L.P., Valero GP, Inc. and Valero Logistics Operations, L.P. dated as of March 6, 2003 |  | NuStar Energy L.P.’s Annual Report on Form 10-K for year ended December 31, 2002 (File No. 001-16417), Exhibit 10.14
10.18 |  | Contribution Agreement by and among Valero Pipeline Company, UDS Logistics, LLC, Valero L.P., Valero GP, Inc. and Valero Logistics Operations, L.P. dated as of March 6, 2003 |  | NuStar Energy L.P.’s Annual Report on Form 10-K for year ended December 31, 2002 (File No. 001-16417), Exhibit 10.15
10.19 |  | Handling and Throughput Agreement between Valero Marketing and Supply Company and Valero Logistics Operations, L.P., dated as of March 18, 2003 |  | NuStar Energy L.P.’s Quarterly Report on Form 10-Q for quarter ended March 31, 2003 (File No. 001-16417), Exhibit 10.1

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Exhibit Number |  | Description |  | Incorporated by Reference to the Following Document
10.20 |  | Amendment Number One to the Handling and Throughput Agreement between Valero Marketing and Supply Company and Valero Logistics Operations, L.P., effective as of April 27, 2004 |  | NuStar Energy L.P.’s Quarterly Report on Form 10-Q for quarter ended March 31, 2004 (File No. 001-16417), Exhibit 10.3
10.21 |  | Throughput Commitment Agreement by and among Valero Marketing and Supply Company, Valero Logistics Operations, L.P. and Valero L.P., dated as of March 18, 2003 |  | NuStar Energy L.P.’s Quarterly Report on Form 10-Q for quarter ended March 31, 2003 (File No. 001-16417), Exhibit 10.4
10.22 |  | Terminalling Agreement (Edinburg) between Valero Marketing and Supply Company and Valero Logistics Operations, L.P., dated as of March 18, 2003 |  | NuStar Energy L.P.’s Quarterly Report on Form 10-Q for quarter ended March 31, 2003 (File No. 001-16417), Exhibit 10.5
10.23 |  | Terminalling Agreement (Houston Asphalt) between Valero Marketing and Supply Company and Valero Logistics Operations, L.P., dated as of March 18, 2003 |  | NuStar Energy L.P.’s Quarterly Report on Form 10-Q for quarter ended March 31, 2003 (File No. 001-16417), Exhibit 10.6
10.24 |  | Terminalling Agreement (Hobby Airport) between Valero Marketing and Supply Company and Valero Logistics Operations, L.P., dated as of March 18, 2003 |  | NuStar Energy L.P.’s Quarterly Report on Form 10-Q for quarter ended March 31, 2003 (File No. 001-16417), Exhibit 10.7
10.25 |  | Terminalling Agreement (Placedo) between Valero Marketing and Supply Company and Valero Logistics Operations, L.P., dated as of March 18, 2003 |  | NuStar Energy L.P.’s Quarterly Report on Form 10-Q for quarter ended March 31, 2003 (File No. 001-16417), Exhibit 10.8
10.26 |  | Terminalling Agreement (San Antonio East) between Valero Marketing and Supply Company and Valero Logistics Operations, L.P., dated as of March 18, 2003 |  | NuStar Energy L.P.’s Quarterly Report on Form 10-Q for quarter ended March 31, 2003 (File No. 001-16417), Exhibit 10.9
10.27 |  | Terminal Storage and Throughput Agreement between Valero Marketing and Supply Company and Valero Logistics Operation, L.P. effective as of January 15, 2004 |  | NuStar Energy L.P.’s Quarterly Report on Form 10-Q for quarter ended March 31, 2004 (File No. 001-16417), Exhibit 10.2
10.28 |  | Terminal Agreement (Corpus Christi Crude Terminal) between Valero Marketing Supply Company and Valero Logistics Operation, L.P. effective as of January 1, 2004 |  | NuStar Energy L.P.’s Quarterly Report on Form 10-Q for quarter ended March 31, 2004 (File No. 001-16417), Exhibit 10.4

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Exhibit Number |  | Description |  | Incorporated by Reference to the Following Document
10.29 |  | Terminal Services Agreement executed September 20, 2006, between Valero Logistics Operations, L.P. and Valero Marketing and Supply Company |  | NuStar Energy L.P.’s Current Report on Form 8-K filed October 3, 2006 (File No. 001-16417), Exhibit 10.01
10.30 |  | Non-Compete Agreement between Valero GP Holdings, LLC, Valero L.P., Riverwalk Logistics, L.P. and Valero GP, LLC, effective as of July 19, 2006 |  | NuStar Energy L.P.’s Quarterly Report on Form 10-Q for quarter ended September 30, 2006 (File No. 001-16417), Exhibit 10.03
10.31 |  | Administration Agreement between Valero GP Holdings, LLC and Valero GP, LLC, effective as of July 19, 2006 |  | NuStar Energy L.P.’s Quarterly Report on Form 10-Q for quarter ended September 30, 2006 (File No. 001-16417), Exhibit 10.04
10.32 |  | NuStar GP, LLC Excess Pension Plan, effective July 1, 2006 |  | NuStar GP Holdings, LLC’s Quarterly Report on Form 10-Q for quarter ended June 30, 2006 (File No. 001-32940), Exhibit 10.10
10.33 |  | NuStar GP, LLC Excess Thrift Plan, effective July 1, 2006 |  | NuStar GP Holdings, LLC’s Quarterly Report on Form 10-Q for quarter ended June 30, 2006 (File No. 001-32940), Exhibit 10.11
10.34 |  | NuStar GP, LLC Supplemental Executive Retirement Plan, effective July 1, 2006 |  | NuStar GP Holdings, LLC’s Quarterly Report on Form 10-Q for quarter ended June 30, 2006 (File No. 001-32940), Exhibit 10.12
10.35 |  | NuStar GP, LLC Short-Term Incentive Plan |  | NuStar Energy L.P.’s Registration Statement on Form S-1 filed March 29, 2001 (File No. 333-43668), Exhibit 10.4
10.36 |  | NuStar GP, LLC Intermediate-Term Incentive Plan |  | NuStar Energy L.P.’s Registration Statement on Form S-1 filed March 29, 2001 (File No. 333-43668), Exhibit 10.9
10.37 |  | Sale and Purchase Agreement, dated as of November 5, 2007, by and between CITGO Asphalt Refining Company and NuStar Asphalt Refining, LLC |  | *
10.38 |  | Aircraft Time Sharing Agreement, dated December 10, 2007, between NuStar Logistics, L.P. and William E. Greehey |  | *
12.01 |  | Statement of Computation of Ratio of Earnings to Fixed Charges |  | *
14.01 |  | Code of Ethics for Senior Financial Officers |  | NuStar Energy L.P.’s Annual Report on Form 10-K for year ended December 31, 2003, Exhibit 14.1

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Exhibit Number |  | Description |  | Incorporated by Reference to the Following Document
21.01 |  | List of subsidiaries of NuStar Energy L.P. |  | *
23.01 |  | Consent of KPMG LLP, dated February , 2008 |  | *
24.01 |  | Powers of Attorney (included in signature page of this Form 10-K) |  | *
31.01 |  | Rule 13a-14(a) Certifications (under Section 302 of the Sarbanes-Oxley Act of 2002) |  | *
32.01 |  | Section 1350 Certifications (under Section 906 of the Sarbanes-Oxley Act of 2002) |  | *
99.01 |  | Audit Committee Pre-Approval Policy |  | *
99.02 |  | Report of Independent Registered Public Accountants, Balance Sheet—December 31, 2007 and Notes to Balance Sheet— December 31, 2007 of Riverwalk Logistics, L.P. |  | *

* | Filed herewith.

+ | Identifies management contracts or compensatory plans or arrangements required to be filed as an exhibit hereto pursuant to Item 15(c) of Form 10-K.

Copies of exhibits filed as a part of this Form 10-K may be obtained by unitholders of record at a charge of $0.15 per page, minimum $5.00 each request. Direct inquiries to Corporate Secretary, NuStar Energy L.P., 2330 North Loop 1604 West, San Antonio, Texas 78248.

Disclosures Required by Section 303A.12 of the NYSE Listed Company Manual. Section 303A.12 of the NYSE Listed Company Manual requires the CEO of each listed company to certify to the NYSE each year that he or she is not aware of any violation by the listed company of any of the NYSE corporate governance listing standards. The CEO of NuStar Energy L.P. submitted the required certification without qualification to the NYSE as of March 28, 2007. In addition, the CEO certification and the chief financial officer’s certification required by Section 302 of the Sarbanes-Oxley Act of 2002 (the SOX 302 Certifications) with respect to NuStar Energy L.P.’s disclosures in its Form 10-K for the year ended December 31, 2006 were filed as Exhibit 31.01 to NuStar Energy L.P.’s Form 10-K for the year ended December 31, 2006. The SOX 302 Certifications with respect to NuStar Energy L.P.’s disclosures in its Form 10-K for the year ended December 31, 2007 are being filed as Exhibit 31.01 to this Form 10-K.

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Exchange Act, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

NUSTAR ENERGY L.P.
(Registrant)
By: |  | Riverwalk Logistics, L.P., its general partner
|  | By: NuStar GP, LLC, its general partner
By: |  | /s/ Curtis V. Anastasio
|  | (Curtis V. Anastasio)
|  | President and Chief Executive Officer
|  | February 29, 2008
By: |  | /s/ Steven A. Blank
|  | (Steven A. Blank)
|  | Senior Vice President, Chief Financial Officer and Treasurer
|  | February 29, 2008
By: |  | /s/ Thomas R. Shoaf
|  | (Thomas R. Shoaf)
|  | Vice President and Controller
|  | February 29, 2008

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POWER OF ATTORNEY

KNOW ALL MEN BY THESE PRESENTS, that each person whose signature appears below hereby constitutes and appoints Curtis V. Anastasio, Steven A. Blank and Bradley C. Barron, or any of them, each with power to act without the other, his true and lawful attorney-in-fact and agent, with full power of substitution and resubstitution, for him and in his name, place and stead, in any and all capacities, to sign any or all subsequent amendments and supplements to this Annual Report on Form 10-K, and to file the same, or cause to be filed the same, with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission, granting unto each said attorney-in-fact and agent full power to do and perform each and every act and thing requisite and necessary to be done in and about the premises, as fully to all intents and purposes as he might or could do in person, hereby qualifying and confirming all that said attorney-in-fact and agent or his substitute or substitutes may lawfully do or cause to be done by virtue hereof.

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

Signature |  | Title |  | Date
/s/ William E. Greehey |  | Chairman of the Board |  | February 29, 2008
(William E. Greehey) |  |  |  |
/s/ Curtis V. Anastasio |  | President, Chief Executive |  | February 29, 2008
(Curtis V. Anastasio) |  | Officer and Director (Principal Executive Officer) |  |
/s/ Steven A. Blank |  | Senior Vice President, |  | February 29, 2008
(Steven A. Blank) |  | Chief Financial Officer and Treasurer (Principal Financial Officer) |  |
/s/ Thomas R. Shoaf |  | Vice President and Controller |  | February 29, 2008
(Thomas R. Shoaf) |  | (Principal Accounting Officer) |  |
/s/ J. Dan Bates |  | Director |  | February 29, 2008
(J. Dan Bates) |  |  |  |
/s/ Dan J. Hill |  | Director |  | February 29, 2008
(Dan J. Hill) |  |  |  |
/s/ Stan McLelland |  | Director |  | February 29, 2008
(Stan McLelland) |  |  |  |
/s/ Rodman D. Patton |  | Director |  | February 29, 2008
(Rodman D. Patton) |  |  |  |

171