Form 10-K
Table of Contents

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

 

FORM 10-K

 

 

 

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

For the fiscal year ended December 31, 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.

 

 

 


Table of Contents

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.

LOGO

 

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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.

LOGO

 

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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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Table of Contents
                          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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Table of Contents

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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Table of Contents

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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Table of Contents

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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Table of Contents

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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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 1st, 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