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EX-23.01 - CONSENT OF KPMG LLP - NuStar Energy L.P.dex2301.htm
EX-99.01 - AUDIT COMMITTEE PRE-APPROVAL POLICY - NuStar Energy L.P.dex9901.htm
EX-10.24 - AIRCRAFT TIME SHARING AGREEMENT - NuStar Energy L.P.dex1024.htm
EX-99.02 - REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTANTS - NuStar Energy L.P.dex9902.htm
EX-10.11 - PERFORMANCE UNIT AGREEMENT - NuStar Energy L.P.dex1011.htm
EX-21.01 - LIST OF SUBSIDIARIES OF NUSTAR ENERGY L.P. - NuStar Energy L.P.dex2101.htm
EX-32.01 - SECTION 906 CERTIFICATIONS - NuStar Energy L.P.dex3201.htm
EX-31.01 - SECTION 302 CERTIFICATIONS - NuStar Energy L.P.dex3101.htm
EX-12.01 - STATEMENT OF COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES - NuStar Energy L.P.dex1201.htm
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, 2009

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

LOGO

NUSTAR ENERGY L.P.

(Exact name of registrant as specified in its charter)

 

Delaware   74-2956831

(State or other jurisdiction of

incorporation or organization)

 

(I.R.S. Employer

Identification No.)

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

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

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

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

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

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.

Yes [    ] No [X]

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes [    ] No [    ]

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [    ]

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule12b-2 of the Exchange Act (Check one):

 

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 $2,389 million based on the last sales price quoted as of June 30, 2009, the last business day of the registrant’s most recently completed second quarter.

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

 

 

 


Table of Contents

TABLE OF CONTENTS

 

PART I

Items 1., 1A. & 2.

   Business, Risk Factors and Properties    3
  

Recent Developments

   4
  

Organizational Structure

   4
  

Segments

   6
  

Employees

   20
  

Rate Regulation

   20
  

Environmental and Safety Regulations

   20
  

Risk Factors

   23
  

Properties

   33

Items 1B.

   Unresolved Staff Comments    34

Item 3.

   Legal Proceedings    34

Item 4.

   Submission of Matters to a Vote of Security Holders    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    38

Item 7.

   Management’s Discussion and Analysis of Financial Condition and Results of Operations    39

Item 7A.

   Quantitative and Qualitative Disclosure About Market Risk    57

Item 8.

   Financial Statements and Supplementary Data    60

Item 9.

   Changes in and Disagreements with Accountants on Accounting and Financial Disclosure    109

Item 9A.

   Controls and Procedures    109

Item 9B.

   Other Information    109
PART III

Item 10.

   Directors, Executive Officers and Corporate Governance    110

Item 11.

   Executive Compensation    114

Item 12.

   Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters    148

Item 13.

   Certain Relationships and Related Transactions and Director Independence    150

Item 14.

   Principal Accountant Fees and Services    153
PART IV

Item 15.

   Exhibits and Financial Statement Schedules    155

Signatures

   162

 

2


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

ITEM 1. BUSINESS, RISK FACTORS AND PROPERTIES

OVERVIEW

NuStar Energy L.P. (NuStar Energy), a Delaware limited partnership, completed its initial public offering of common units on April 16, 2001. Our common units are traded on the New York Stock Exchange (NYSE) under the symbol “NS.” Our principal executive offices are located at 2330 North Loop 1604 West, San Antonio, Texas 78248 and our telephone number is (210) 918-2000.

We are engaged in the terminalling and storage of petroleum products, the transportation of petroleum products and anhydrous ammonia, and asphalt and fuels marketing. We manage our operations through the following three operating segments: storage, transportation, and asphalt and fuels marketing. As of December 31, 2009, our assets included:

 

   

58 refined product terminal facilities providing approximately 61.4 million barrels of storage capacity and one crude oil terminal facility providing 4.9 million barrels of storage capacity;

 

   

60 crude oil storage tanks providing storage capacity of 12.5 million barrels;

 

   

5,605 miles of refined product 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;

 

   

2,000 miles of anhydrous ammonia pipelines;

 

   

812 miles of crude oil pipelines with 16 associated storage tanks providing storage capacity of 1.9 million barrels; and

 

   

two asphalt refineries with a combined throughput capacity of 104,000 barrels per day and two associated terminal facilities with a combined storage capacity of 5.0 million barrels.

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

 

   

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

 

   

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

 

   

sales of asphalt and other refined petroleum products.

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

 

   

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

 

   

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

 

   

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

 

   

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; and

 

   

growth and improvement of our asphalt operations to benefit from anticipated decreases in overall asphalt supply and higher asphalt margins.

 

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The term “throughput” as used in this document generally refers to the crude oil or refined product barrels or tons of ammonia, as applicable, that pass through our pipelines, terminals, storage tanks or refineries.

Our internet website address is http://www.nustarenergy.com. Information contained on our website is not part of this report. Our annual reports on Form 10-K, quarterly reports on Form 10-Q and current reports on Form 8-K filed with (or furnished to) the Securities and Exchange Commission (SEC) are available on our internet website, free of charge, as soon as reasonably practicable after we file or furnish such material (select the “Investors” link, then the “Financial Reports SEC Filings” link). We also post our corporate governance guidelines, code of business conduct and ethics, code of ethics for senior financial officers and the charters of our board’s committees on our internet website free of charge (select the “Investors” link, then the “Corporate Governance” link). Our governance documents are available in print to any unitholder that makes a written request to Corporate Secretary, NuStar Energy L.P., 2330 North Loop 1604 West, San Antonio, Texas 78248.

RECENT DEVELOPMENTS

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

ORGANIZATIONAL STRUCTURE

Our operations are managed by NuStar GP, LLC, the general partner of our general partner. NuStar GP, LLC, a Delaware limited liability company, is a consolidated subsidiary of NuStar GP Holdings, LLC (NuStar GP Holdings) (NYSE: NSH).

 

4


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The following chart depicts our organizational structure at December 31, 2009.

LOGO

 

5


Table of Contents

SEGMENTS

Our three reportable business segments are storage, transportation, and asphalt and fuels marketing. Detailed financial information about our segments is included in Note 22 in the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data.”

The following map depicts our operations at December 31, 2009.

LOGO

 

6


Table of Contents

STORAGE

Our storage segment includes terminal facilities that provide storage and handling services on a fee basis for petroleum products, specialty chemicals, crude oil and other liquids and crude oil storage tanks used to store and deliver crude oil. In addition, our terminals located on the island of St. Eustatius, the Netherlands Antilles and Point Tupper, Nova Scotia provide services such as pilotage, tug assistance, line handling, launch service, emergency response services and other ship services. As of December 31, 2009, we owned and operated:

 

   

49 terminals in the United States, with a total storage capacity of approximately 36.4 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 9.5 million barrels;

 

   

A terminal located in Nuevo Laredo, Mexico; and

 

   

60 crude oil and intermediate feedstock storage tanks and related assets in Texas and California with aggregate storage capacity of approximately 12.5 million barrels.

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 island of St. Eustatius, the Netherlands Antilles, which is located at a point of minimal deviation from major shipping routes. This facility is capable of handling a wide range of petroleum products, including crude oil and refined products, and it can accommodate the world’s largest tankers for loading and discharging crude oil and other petroleum products. A two-berth jetty, a two-berth monopile with platform and buoy systems, a floating hose station and an offshore single point mooring buoy with loading and unloading capabilities serve the terminal’s customers’ vessels. The St. Eustatius facility has a total of 58 tanks. The fuel oil and petroleum product facilities have in-tank and in-line blending capabilities, while the crude tanks have tank-to-tank blending capability and in-tank mixers. In 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, Canada and the Midwestern United States via the St. Lawrence Seaway and the Great Lakes system. With one of the premier jetty facilities in North America, the Point Tupper facility can accommodate substantially all of the world’s largest, fully laden very large crude carriers and ultra large crude carriers for loading and discharging crude oil, petroleum products and petrochemicals. Crude oil and petroleum product movements at the terminal are fully automated. Separate fees apply for the use of the jetty facility, as well as associated services, including pilotage, tug assistance, line handling, launch service, spill response services and other ship services. We also charter tugs, mooring launches and other vessels to assist with the movement of vessels through the Strait of Canso and the safe berthing of vessels at the terminal facility.

Piney Point, Maryland. Our terminal and storage facility in Piney Point, 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.

 

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St. James, Louisiana. Our St. James terminal has 29 crude oil storage tanks with a total capacity of approximately 4.9 million barrels. Additionally, the facility has a rail-loading facility and three docks with barge and ship access. The facility is located on almost 900 acres of land, some of which is undeveloped land.

Linden, New Jersey. We own 50% of ST Linden Terminal LLC, which owns a terminal and storage facility in Linden, New Jersey. The terminal is located on a 44-acre facility that provides it with deep-water terminalling capabilities at New York Harbor. This terminal primarily stores petroleum products, including gasoline, jet fuel and fuel oils. The facility has a total capacity of approximately 4.0 million barrels in 24 tanks and can receive and deliver products via ship, barge and pipeline. The terminal includes two docks and leases a third with draft limits of 36, 26 and 20 feet, respectively.

Terminal Facilities and Crude Oil Storage Tanks

The following table sets forth information about our terminal facilities:

 

Facility   

Tank

Capacity

  

Number of

Tanks

   Primary Products Handled
   (Barrels)            
Major U.S. Terminals:               
Piney Point, MD    5,404,000       28       Petroleum products, asphalt
St. James, LA    4,880,000       29       Crude oil and feedstocks
Linden, NJ (a)    3,957,000       24       Petroleum products
Selby, CA    2,829,000       22       Petroleum products, ethanol
Texas City, TX    2,731,000       73       Chemicals, petrochemicals, petroleum products
Jacksonville, FL    2,505,000       34       Petroleum products, asphalt
Other U.S. Terminals:               
Montgomery, AL    162,000       7       Petroleum products
Moundville, AL    310,000       6       Petroleum products
Los Angeles, CA    606,000       19       Petroleum products
Pittsburg, CA    361,000       10       Asphalt
Stockton, CA    764,000       29       Petroleum products, ethanol, fertilizer
Colorado Springs, CO    320,000       7       Petroleum products, ethanol
Denver, CO    100,000       8       Petroleum products, ethanol
Bremen, GA    178,000       8       Petroleum products
Brunswick, GA    160,000       2       Fertilizer, pulp liquor
Macon, GA (b)    307,000       10       Petroleum products
Savannah, GA    857,000       21       Petroleum products, caustic
Blue Island, IL    719,000       14       Petroleum products, ethanol
Indianapolis, IN    366,000       18       Petroleum products
Andrews AFB, MD (b)    72,000       3       Petroleum products
Baltimore, MD    814,000       47       Chemicals, asphalt, petroleum products
Salisbury, MD    177,000       14       Petroleum products
Wilmington, NC    304,000       12       Asphalt
Linden, NJ    353,000       9       Petroleum products
Paulsboro, NJ    69,000       9       Petroleum products
Alamogordo, NM (b)    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    1,203,000       32       Petroleum products, ethanol
Abernathy, TX    155,000       7       Petroleum products
Amarillo, TX    255,000       8       Petroleum products
Corpus Christi, TX    327,000       10       Petroleum products
Edinburg, TX    267,000       6       Petroleum products
El Paso, TX (c)    343,000       12       Petroleum products, ethanol
Harlingen, TX    315,000       7       Petroleum products
Houston, TX (Hobby Airport)    106,000       4       Petroleum products
Houston, TX    85,000       5       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

 

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Facility   

Tank

Capacity

  

Number of

Tanks

   Primary Products Handled
   (Barrels)            

Southlake, TX

   575,000       12       Petroleum products, ethanol

Texas City, TX

   125,000       10       Petroleum products

Dumfries, VA

   548,000       14       Petroleum products, asphalt

Virginia Beach, VA (b)

   41,000       2       Petroleum products

Tacoma, WA

   359,000       14       Petroleum products, ethanol

Vancouver, WA

   328,000       48       Chemicals

Vancouver, WA

   408,000       7       Petroleum products
                  

Total U.S. Terminals

   36,390,000       729      
                  

Foreign Terminals:

              

St. Eustatius, Netherlands Antilles

   12,996,000       58       Petroleum products, crude oil and feedstocks

Point Tupper, Canada

   7,354,000       37       Petroleum products, crude oil and feedstocks

Grays, England

   1,956,000       53       Petroleum products

Eastham, England

   2,156,000       162       Chemicals, petroleum products, animal fats

Runcorn, England

   145,000       4       Molten sulfur

Grangemouth, Scotland

   565,000       47       Petroleum products, chemicals

Glasgow, Scotland

   360,000       16       Petroleum products

Belfast, Northern Ireland

   440,000       41       Petroleum products

Amsterdam, the Netherlands

   3,848,000       44       Petroleum products

Nuevo Laredo, Mexico

   34,000       5       Petroleum products
                  

Total Foreign Terminals

   29,854,000       467      
                  

 

(a) We own 50% of this terminal through a joint venture.
(b) Terminal facility also includes pipelines to U.S. government military base locations.
(c) We own a 66.67% undivided interest in the El Paso refined product terminal. The tankage capacity and number of tanks represent the proportionate share of capacity attributable to our ownership interest.

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

 

Location    Capacity   Number of Tanks   

Mode of

Receipt

   Mode of

Delivery

   (Barrels)              

Benicia, CA

   3,815,000      16       marine/pipeline    pipeline

Corpus Christi, TX

   4,023,000      26       marine    pipeline

Texas City, TX

   3,087,000      14       marine    pipeline

Corpus Christi, TX (North Beach)

   1,600,000      4       marine    pipeline
                    

Total

   12,525,000      60         
                    

The land underlying these crude oil storage tanks is subject to long-term operating leases.

Storage Operations

Revenues for the storage segment include fees for tank storage agreements, in which a customer agrees to pay for a certain amount of storage in a tank over a period of time (storage lease revenues), and throughput agreements, in which a customer pays a fee per barrel for volumes moving through our terminals (throughput revenues). Our terminals also provide blending, additive injections, handling and filtering services. We charge a fee for each barrel of crude oil and certain other feedstocks that we deliver to Valero Energy Corporation (Valero Energy)’s Benicia, Corpus Christi West and Texas City refineries from our crude oil storage tanks. Our facilities at Point Tupper and St. Eustatius charge fees to provide services such as pilotage, tug assistance, line handling, launch service, 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 storage and terminalling services for crude oil and refined petroleum products to many of the world’s largest producers of crude oil, integrated oil companies, chemical companies, oil traders and refiners. The largest customer of our storage segment is Valero Energy, which accounted for approximately 22% of the total revenues of the segment for the year ended December 31, 2009. No other customer accounted for more than 10% of the revenues of the segment for this period. Our customers include a major international oil company that leases and utilizes 4.1 million barrels of storage at Point Tupper under a long-term contract with us. During 2009, an oil producer leased and utilized 5.0 million barrels of storage at St. Eustatius. Beginning in 2010, we agreed to a long-term agreement to lease those 5.0 million barrels of storage to a national sponsored oil company, replacing the lease with the oil producer. In addition, our blending capabilities in our storage assets have attracted customers who have leased capacity primarily for blending purposes.

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 from larger vessels to smaller vessels, usually while at sea. The price differential between lightering and terminalling is primarily driven by the charter rates for vessels of various sizes. Lightering generally takes significantly longer than discharging at a terminal. Depending on charter rates, the longer charter period associated with lightering is generally offset by various costs associated with terminalling, including storage costs, dock charges and spill response fees. However, terminalling is generally safer and reduces the risk of environmental damage associated with lightering, provides more flexibility in the scheduling of deliveries and allows our customers to deliver their products to multiple locations. Lightering in U.S. territorial waters creates a risk of liability for owners and shippers of oil under the U.S. Oil Pollution Act of 1990 and other state and federal legislation. In Canada, similar liability exists under the Canadian Shipping Act. Terminalling also provides customers with the ability to access value-added terminal services.

Our crude oil storage tanks are physically integrated with and serve refineries owned by Valero Energy. Additionally, we have entered into various agreements with Valero Energy governing the usage of these tanks. As a result, we believe that we will not face significant competition for our services provided to those refineries.

TRANSPORTATION

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

 

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pipeline located in Louisiana, Arkansas, Missouri, Illinois, Indiana, Iowa and Nebraska. As of December 31, 2009, we owned and operated:

 

   

23 refined product pipelines with an aggregate length of 3,255 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 hydrogen pipeline (collectively, the Central West System);

 

   

a 1,910-mile refined product pipeline originating in southern Kansas and terminating at Jamestown, North Dakota, with a western extension to North Platte, Nebraska and an eastern extension into Iowa (the East Pipeline);

 

   

a 440-mile refined product pipeline originating at Tesoro Corporation’s Mandan, North Dakota refinery (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).

As of December 31, 2009, we also had an ownership interest in eleven crude oil pipelines in Texas, Oklahoma, Kansas, Colorado and Illinois with an aggregate length of 812 miles and crude oil storage facilities providing 1.9 million barrels of storage capacity in Texas, Oklahoma and Colorado that are located along the crude oil pipelines.

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

Description of Pipelines

Central West System. The Central West System was constructed to support the refineries to which they are connected. These pipelines are physically integrated with and principally serve refineries owned by Valero Energy. The refined products transported in these pipelines include gasoline, distillates (including diesel and jet fuel), natural gas liquids, crude oil, blendstocks and other products produced primarily by Valero Energy’s McKee, Three Rivers, Corpus Christi and Ardmore refineries. These pipelines connect the Valero Energy refineries to key markets in Texas, New Mexico and Colorado. The Central West System transported approximately 130.8 million barrels for the year ended December 31, 2009.

 

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

 

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

McKee to El Paso, TX

   McKee       408         67%       40,000   

McKee to Colorado Springs, CO

   McKee       256       100%       38,000   

Colorado Springs, CO to Airport

   McKee       2       100%       14,000   

Colorado Springs to Denver, CO

   McKee       101       100%       32,000   

McKee to Denver, CO

   McKee       321       30%       9,870   

McKee to Amarillo, TX (6”) (a)

   McKee       49       100%       51,000   

McKee to Amarillo, TX (8”) (a)

   McKee       49       100%         

Amarillo to Abernathy, TX

   McKee       102         67%       11,733   

Amarillo, TX to Albuquerque, NM (b)

   McKee       293         50%       17,150   

Abernathy to Lubbock, TX

   McKee       19         46%       8,029   

McKee to Southlake, TX

   McKee       375       100%       27,300   

Three Rivers to San Antonio, TX

   Three Rivers       81       100%       33,600   

Three Rivers to US/Mexico International Border near Laredo, TX

   Three Rivers       108       100%       32,000   

Corpus Christi to Three Rivers, TX

   Corpus Christi       68       100%       32,000   

Three Rivers to Corpus Christi, TX

   Three Rivers       72       100%       15,000   

Three Rivers to Pettus to San Antonio, TX

   Three Rivers       103       100%       30,000   

Three Rivers to Pettus to Corpus Christi, TX (c)

   Three Rivers       87       100%      

N/A

  

El Paso, TX to Kinder Morgan

   McKee       12         67%       65,600   

Corpus Christi to Pasadena, TX

   Corpus Christi       208       100%       105,000   

Corpus Christi to Brownsville, TX

   Corpus Christi       194       100%       45,000   

US/Mexico International Border near Penitas, TX to Edinburg, TX

   N/A       33       100%       24,000   

Clear Lake, TX to Texas City, TX

   N/A       25       100%       N/A   

Other refined product pipeline (d)

   N/A       289         50%       N/A   
                           

Total

         3,255            

631,282

  
                           

 

(a) The capacity information disclosed above for the McKee to Amarillo, Texas 6-inch pipeline reflects both McKee to Amarillo, Texas pipelines on a combined basis.
(b) Included in this segment are three refined product tanks with a total capacity of 114,000 barrels located at Tucamcari, New Mexico along the 10-inch Amarillo, Texas to Albequerque, New Mexico refined product pipeline.
(c) The refined product pipeline from Three Rivers to Pettus to Corpus Christi, Texas is temporarily idled.
(d) This category consists of the temporarily idled 6-inch Amarillo, Texas to Albuquerque, New Mexico refined product pipeline.

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

East Pipeline. The East Pipeline covers 1,910 miles and moves refined products and natural gas liquids north in pipelines ranging in diameter from 6 inches to 16 inches. The East Pipeline system also includes 21 product tanks with total storage capacity of approximately 1.2 million barrels at our two tanks farms at McPherson and El Dorado, Kansas. The East Pipeline transports refined petroleum products and natural gas liquids to our terminals along the system and to receiving pipeline connections in Kansas. Shippers on the East Pipeline obtain refined petroleum products from refineries in Kansas connected to the East Pipeline and through other pipelines directly connected to the pipeline system. The East Pipeline transported approximately 49.8 million barrels for the year ended December 31, 2009.

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

 

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Pipeline-Related Terminals. The East and North Pipelines also include 21 truck-loading terminals through which refined petroleum products are delivered to storage tanks and then loaded into petroleum product transport trucks. Revenues earned at these terminals relate solely to the volumes transported on the pipeline. Separate fees are not charged for the use of these terminals. Instead, the terminalling fees are a portion of the transportation rate included in the pipeline tariff. As a result, these terminals are included in this segment instead of the storage segment.

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

 

Location of Terminals   

Tank Capacity

   Number of Tanks    Related Pipeline
System
   (Barrels)            

Iowa:

                    

LeMars

      103,000          8       East

Milford

      172,000          11       East

Rock Rapids

      223,000          5       East

Kansas:

                    

Concordia

      79,000          6       East

Hutchinson

      114,000          5       East

Salina

      86,000          8       East

Minnesota:

                    

Moorhead

      518,000          10       North

Sauk Centre

      116,000          7       North

Roseville

      479,000          10       North

Nebraska:

                    

Columbus

      171,000          8       East

Geneva

      674,000          37       East

Norfolk

      182,000          15       East

North Platte

      247,000          23       East

Osceola

      79,000          7       East

North Dakota:

                    

Jamestown (North)

      139,000          6       North

Jamestown (East)

      176,000          11       East

South Dakota:

                    

Aberdeen

      181,000          12       East

Mitchell

      63,000          6       East

Sioux Falls

      381,000          12       East

Wolsey

      148,000          20       East

Yankton

      245,000          25       East
                        

Total

      4,576,000          252      
                        

Ammonia Pipeline. The 2,000 mile pipeline originates in the Louisiana delta area, where it has access to three marine terminals and three anhydrous ammonia plants on the Mississippi River. It runs north through Louisiana and Arkansas into Missouri, where at Hermann, Missouri, one branch splits and goes east into Illinois and Indiana, while the other branch continues north into Iowa and then turns west into Nebraska. The Ammonia Pipeline is connected to multiple third-party-owned terminals, which include industrial facility delivery locations. Product is supplied to the pipeline from anhydrous ammonia plants in Louisiana and imported product delivered through the marine terminals. Anhydrous ammonia is primarily used as agricultural fertilizer. It is also used as a feedstock to produce other nitrogen derivative fertilizers and explosives. The Ammonia Pipeline transported approximately 1.2 million tons (or approximately 11.0 million barrels) for the year ended December 31, 2009.

 

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Crude Oil Pipelines. Our crude oil pipelines primarily transport crude oil and other feedstocks from various points in Texas, Oklahoma, Kansas and Colorado to Valero Energy’s McKee, Three Rivers and Ardmore refineries. Also, we can use our crude oil storage facilities in Texas, Oklahoma and Colorado, located along the crude oil pipelines, to store and batch crude oil prior to shipment in the crude oil pipelines. The crude pipelines transported approximately 128.4 million barrels for the year ended December 31, 2009.

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

 

Origin and Destination

  

Refinery

  

Length

  

Ownership

 

Capacity

      (Miles)      (Barrels/Day)

Cheyenne Wells, CO to McKee

   McKee       210       100%      17,500   

Dixon, TX to McKee

   McKee       44       100%      63,600   

Hooker, OK to Clawson, TX (a)

   McKee       41       50%      22,000   

Clawson, TX to McKee

   McKee       31       100%      36,000   

Wichita Falls, TX to McKee

   McKee       272       100%      110,000   

Corpus Christi, TX to Three Rivers

   Three Rivers       70       100%      120,000   

Ringgold, TX to Wasson, OK

   Ardmore       44       100%      90,000   

Healdton to Ringling, OK

   Ardmore       4       100%      52,000   

Wasson, OK to Ardmore (8”-10”) (b)

   Ardmore       24       100%      90,000   

Wasson, OK to Ardmore (8”)

   Ardmore       15       100%      40,000   

Patoka, IL to Wood River, IL

   Wood River       57         24%      60,600   
                          

Total

         812            701,700   
                          

 

(a) We receive 50% of the tariff with respect to 100% of the barrels transported in the Hooker, Oklahoma to Clawson, Texas pipeline. Accordingly, the capacity is given with respect to 100% of the pipeline.
(b) The Wasson, Oklahoma to Ardmore (8”- 10”) pipelines referred to above originate at Wasson as two pipelines but merge into one pipeline prior to reaching Ardmore.

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

 

Location

  

Refinery

  

Capacity

  

Number
of Tanks

  

Mode of

Receipt

  

Mode of

Delivery

    
      (Barrels)                  

Dixon, TX

   McKee       240,000          3       pipeline    pipeline   

Ringgold, TX

   Ardmore       600,000          2       pipeline    pipeline   

Wichita Falls, TX

   McKee       660,000          4       pipeline    pipeline   

Wasson, OK

   Ardmore       225,000          2       pipeline    pipeline   

Clawson, TX

   McKee       65,000          2       pipeline    pipeline   

Other (a)

   McKee       67,000          3       pipeline    pipeline   
                                 

Total

         1,857,000          16            
                                 

 

(a) This category includes crude oil tanks along the Cheyenne Wells, Colorado to McKee crude oil pipelines located at Carlton, Colorado, Sturgis, Oklahoma, and Stratford, Texas.

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

Pipeline Operations

Revenues for the pipelines are based upon origin-to-destination throughput volumes traveling through our pipelines and 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 our 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. We charge our shippers tariffs based on transportation from

 

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the origination point on the pipeline to the point of delivery. We invoice our refined product shippers upon delivery for our Central West System and our North and Ammonia Pipelines, and we invoice our shippers on our East Pipeline when their product enters the line.

Shippers on our crude oil pipelines deliver crude oil to the pipelines for transport to refineries that connect to the pipelines. The costs associated with the crude oil storage facilities located along the crude oil pipelines are considered in establishing the tariffs charged for transporting crude oil from the crude oil storage facilities to the refineries.

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

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 our pipelines. The system monitors quantities of products injected in and delivered through the pipelines and automatically signals the appropriate personnel upon deviations from normal operations that require attention.

Demand for and Sources of Refined Products

The operations of our Central West System and the East and North Pipelines depend 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.

The majority of the refined products delivered through the pipelines in the Central West System are gasoline and diesel fuel that originate at refineries owned by Valero Energy. Demand for these products fluctuates as prices for these products fluctuate. Prices fluctuate for a variety of reasons including the overall balance in supply and demand, which is affected by general economic conditions and affects refinery utilization rates, among other factors. Prices for gasoline and diesel fuel tend to increase in the warm weather months when people tend to drive automobiles more often and further distances.

The majority of the refined products delivered through the North Pipeline are delivered to the Minneapolis, Minnesota metropolitan area and consist of gasoline and diesel fuel. Demand for those products fluctuates based on general economic conditions and with changes in the weather as more people drive during the warmer months.

Much of the refined products and natural gas liquids delivered through the East Pipeline and volumes on the North Pipeline that are not delivered to Minneapolis are ultimately used as fuel for railroads, ethanol denaturant or in agricultural operations, including fuel for farm equipment, irrigation systems, trucks used for transporting crops and crop-drying facilities. Demand for refined products for agricultural use, and the relative mix of products required, is affected by weather conditions in the markets served by the East and North Pipelines. The agricultural sector is also affected by government agricultural policies and crop prices. Although periods of drought suppress agricultural demand for some refined products, particularly those used for fueling farm equipment, the demand for fuel for irrigation systems often increases during such times. The mix of refined products delivered for agricultural use varies seasonally, with gasoline demand peaking in early summer, diesel fuel demand peaking in late summer and propane demand higher in the fall. In addition, weather conditions in the areas served by the East Pipeline affect the mix of the refined products delivered through the East Pipeline, although historically any overall impact on the total volumes shipped has not been significant.

Our refined product pipelines are also dependent upon adequate levels of production of refined products by refineries connected to the pipelines, directly or through connecting pipelines. The refineries are, in turn, dependent upon adequate

 

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supplies of suitable grades of crude oil. The pipelines in the Central West System and our crude oil pipelines are connected to refineries owned by Valero Energy, and certain pipelines are subject to long-term throughput agreements with Valero Energy. Valero Energy refineries connected directly to our pipelines obtain crude oil from a variety of foreign and domestic sources. If operations at one of these refineries were discontinued or significantly reduced, it could have a material adverse effect on our operations, although we would endeavor to minimize the impact by seeking alternative customers for those pipelines.

The North Pipeline is heavily dependent on Tesoro’s Mandan, North Dakota refinery, which primarily runs North Dakota crude oil (although it has the ability to process other crude oils). If operations at the Tesoro refinery were interrupted, it could have a material effect on our operations. Other than the Valero Energy refineries described above and the Tesoro refinery, if operations at any one refinery were discontinued, we believe (assuming unchanged demand for refined products in markets served by the refined product pipelines) that the effects thereof would be short-term in nature and our business would not be materially adversely affected over the long term because such discontinued production could be replaced by other refineries or other sources.

The refineries connected directly to the East Pipeline obtain crude oil from producing fields located primarily in Kansas, Oklahoma and Texas, and, to a much lesser extent, from other domestic or foreign sources. In addition, refineries in Kansas, Oklahoma and Texas are also connected to the East Pipeline by third party pipelines. These refineries obtain their supplies of crude oil from a variety of sources. The majority of the refined products transported through the East Pipeline are produced at three refineries located at McPherson and El Dorado, Kansas and Ponca City, Oklahoma, which are operated by the National Cooperative Refining Association (NCRA), Frontier Oil Corporation and ConocoPhillips Company, respectively. The NCRA and Frontier Oil Corporation refineries are connected directly to the East Pipeline. The East Pipeline also has access to Gulf Coast supplies of products through third party connecting pipelines that receive products originating on the Gulf Coast.

Demand for and Sources of Anhydrous Ammonia

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

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

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

Customers

The largest customer of our transportation segment was Valero Energy, which accounted for approximately 49% of the total segment revenues for the year ended December 31, 2009. In addition to Valero Energy, we had a total of approximately 70 shippers for the year ended December 31, 2009, including integrated oil companies, refining companies, farm cooperatives, railroads and others. No other customer accounted for greater than 10% of the total revenues of transportation segment for the year ended December 31, 2008.

Competition and Business Considerations

Because pipelines are generally the lowest-cost method for intermediate and long-haul movement of refined petroleum products, our more significant competitors are common carrier and proprietary pipelines owned and operated by major integrated and large independent oil companies and other companies in the areas where we deliver products. Competition between common carrier pipelines is based primarily on transportation charges, quality of customer service and proximity to end users. We believe high capital costs, tariff regulation, environmental considerations and problems in acquiring rights-of-way make it unlikely that other competing pipeline systems comparable in size and scope to our pipelines will be built in the near future, as long as our pipelines have available capacity to satisfy demand and our tariffs remain at economically reasonable levels.

 

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The costs associated with transporting products from a loading terminal to end users limit the geographic size of the market that can be served economically by any terminal. Transportation to end users from our loading terminals is conducted primarily by trucking operations of unrelated third parties. Trucks may competitively deliver products in some of the areas served by our pipelines. However, trucking costs render that mode of transportation uncompetitive for longer hauls or larger volumes. We do not believe that trucks are, or will be, effective competition to our long-haul volumes over the long-term.

Most of our refined product pipelines within the Central West System and our crude oil pipelines are physically integrated with and principally serve refineries owned by Valero Energy. As the pipelines are physically integrated with Valero Energy’s refineries, we believe that we will not face significant competition for transportation services provided to the Valero Energy refineries we serve.

The East and North Pipelines compete with an independent common carrier pipeline system owned by Magellan Midstream Partners, L.P. (Magellan) that operates approximately 100 miles east of and parallel to the East Pipeline and in close proximity to the North Pipeline. The Magellan system is a more extensive system than the East and North Pipelines. Competition with Magellan is based primarily on transportation charges, quality of customer service and proximity to end users. In addition, refined product pricing at either the origin or terminal point on a pipeline may outweigh transportation costs. Certain of the East Pipeline’s and the North Pipeline’s delivery terminals are in direct competition with Magellan’s terminals.

Competitors of the Ammonia Pipeline include another anhydrous ammonia pipeline that originates in Oklahoma and Texas and terminates in Minnesota. The competing pipeline has the same Direct Application demand and weather issues as the Ammonia Pipeline but is restricted to domestically produced anhydrous ammonia. Midwest production facilities, nitrogen fertilizer substitutes and barge and railroad transportation represent other forms of direct competition to the pipeline under certain market conditions.

ASPHALT AND FUELS MARKETING

Our asphalt and fuels marketing segment includes our asphalt refining operations and our fuels marketing operations. We refine crude oil to produce asphalt and certain other refined products from our asphalt operations. Additionally, we purchase gasoline and other refined petroleum products for resale. The results of operations for the asphalt and fuels marketing segment depend largely on the margin between our cost and the sales price of the products we market. Therefore, the results of operations for this segment are more sensitive to changes in commodity prices compared to the operations of the storage and transportation segments.

Asphalt Refining and Marketing Operations

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

 

Facility

  

Production

Capacity

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

Paulsboro, NJ

      74,000          3,640,000          24   

Savannah, GA

      30,000          1,359,000          25   
                                

Total

      104,000          4,999,000          49   
                                

Paulsboro Refinery. The Paulsboro refinery is located in Paulsboro, New Jersey on the Delaware River. The refinery consists of two petroleum refining units, a liquid storage terminal for petroleum and chemical products, three marine docks, a polymer-modified asphalt production facility and a testing laboratory. The Paulsboro refinery supplies various asphalt grades and intermediate products by ship, barge, railcar and tanker trucks to a network of 11 asphalt terminals in the northeastern United States. These asphalt terminals provide us with an aggregate storage capacity of 3.8 million barrels and are either leased from third parties or owned by us. The Paulsboro refinery’s location on the Delaware River allows for direct access of receipts and shipments.

 

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Savannah Refinery. The Savannah refinery is located in Savannah, Georgia adjacent to the Savannah River and is the only asphalt producer on the United States southeastern seaboard. The refinery includes two atmospheric towers, a tank farm, a marine dock, a polymer modified asphalt production facility, a testing laboratory and processing areas. The Savannah refinery supplies various asphalt grades by truck, rail and marine vessel to a network of 11 asphalt terminals in the southeastern United States. These asphalt terminals provide us with an aggregate storage capacity of 1.9 million barrels and are either leased from third parties or owned by us. The Savannah refinery’s location on the Savannah River allows for direct access of receipts and shipments.

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

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

 

    

Volumes

 

Percentage

   (barrels per day)  

Paulsboro:

    

Crude oil throughput

   45,025  

Yields:

    

Asphalt

   27,103   61%

Naphtha

     1,267     3%

Marine diesel oil

     6,786   15%

Vacuum gas oil

     3,651     8%

HS fuel oil

     5,982   13%

Savannah:

    

Crude oil throughput

   17,991  

Yields:

    

Asphalt

   13,362   75%

Naphtha

        591     3%

Light marine gas oil

      3,995   22%

Customers. We produce several grades of asphalt products for various applications. The asphalt we produce is for hot mix paving, which is used in road construction, roofing shingles for housing, asphalt emulsions and asphalt cutbacks used for street maintenance, as well as polymer-modified asphalt, which is a premium asphalt cement used for roads with heavy traffic in harsh weather conditions. The majority of our asphalt customers are road and bridge construction companies who operate asphalt hot mix plants that combine rock aggregate with asphalt to make road pavements. Our customers serve the private commercial sector by building residential roads, parking lots, asphalt paths and courts as well as the public sector by building highways and transportation infrastructure for the various state Departments of Transportation.

Crude Supply. Simultaneously with the acquisition of our asphalt operations, Petróleos de Venezuela S. A. (PDVSA), the national oil company of Venezuela, agreed to supply us with Boscan and Bachaquero BCF-13 crude oil as feedstocks for our refineries. Our cost of crude oil purchased under the supply agreement fluctuates based upon a market-based pricing formula using published market indices, subject to adjustment, based on the price of Mexican Maya crude. Our refineries are optimized to process Boscan and Bachaquero BCF-13 crude oil and doing so typically results in the best economic return. However, the refineries can also process alternative asphaltic crudes and other feedstocks.

Competition and Business Considerations. The asphalt industry is highly fragmented and regional in nature. Our competitors range in size from major oil companies and independent refiners to small family-owned businesses. It is considered a niche business with few integrated, asphalt-focused refiners that have production, logistics and wholesale and marketing capabilities. The top asphalt producers in the U.S. are refiners that produce asphalt as a by-product.

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

 

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

Fuels Marketing Operations

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

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

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

Since the operations of our asphalt and fuels marketing segment expose us to commodity price risk, we sometimes enter into derivative instruments to mitigate the effect of commodity price fluctuations on our operations. The derivative instruments we use consist primarily of futures contracts and swaps traded on the NYMEX for the purposes of hedging the outright price risk of our physical inventory.

Customers. Fuels marketing customers include major integrated refiners and trading companies, as well as various wholesale suppliers, unbranded retailers and large high volume retailers. Customers for our bunker fuel sales are ship owners, including cruise line companies.

Competition and Business Considerations. Our fuels marketing operations have numerous competitors, including large integrated refiners, marketing affiliates of other partnerships in our industry, as well as various international and domestic trading companies. In the sale of bunker fuel, we compete with ports offering bunker fuels that are along the route of travel of the vessel. We also compete with bunker fuel delivery locations around the world. In the Western Hemisphere, alternative bunker fuel locations include ports on the U.S. East Coast and Gulf Coast and in Panama, Puerto Rico, the Bahamas, Aruba, Curacao and Halifax, Nova Scotia.

 

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EMPLOYEES

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

RATE REGULATION

Several of our petroleum pipelines are interstate common carrier pipelines, which are subject to regulation by the FERC under the Interstate Commerce Act (ICA) and the Energy Policy Act of 1992 (the EP Act). The ICA and its implementing regulations give the FERC authority to regulate the rates charged for service on interstate common carrier pipelines and generally require the rates and practices of interstate oil pipelines to be just, reasonable and nondiscriminatory. The ICA also requires tariffs that set forth the rates a common carrier pipeline charges for providing transportation services on its interstate common carrier liquids pipelines, as well as the rules and regulations governing these services, to be maintained on file with the FERC. The EP Act deemed certain rates in effect prior to its passage to be just and reasonable and limited the circumstances under which a complaint can be made against such “grandfathered” rates. The EP Act and its implementing regulations also allow interstate common carrier oil pipelines to annually index their rates up to a prescribed ceiling level. In addition, the FERC retains cost-of-service ratemaking, market-based rates and settlement rates as alternatives to the indexing approach.

The Ammonia Pipeline is subject to regulation by the STB under the current version of the ICA. The ICA and its implementing regulations give the STB authority to regulate the rates we charge for service on the Ammonia Pipeline and generally require that our rates and practices be reasonable and nondiscriminatory.

Additionally, the rates and practices for our intrastate common carrier pipelines are subject to regulation by state commissions in Colorado, Kansas, Louisiana, North Dakota and Texas. Although the applicable state statutes and regulations vary, they generally require that intrastate pipelines publish tariffs setting forth all rates, rules and regulations applying to intrastate service, and generally require that pipeline rates and practices be just, reasonable and nondiscriminatory.

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

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, process safety management, occupational health and the handling, storage, use and disposal of hazardous materials that are designed to prevent material environmental or other damage, to ensure the safety of our pipelines, our employees, the public and the environment and to limit the financial liability that could result from such events. Future governmental action and regulatory initiatives could result in changes to expected operating permits and procedures, additional remedial actions or increased capital expenditures and operating costs that cannot be assessed with certainty at this time. In addition, contamination resulting from spills of crude oil and

 

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refined products occurs within the industry. Risks of additional costs and liabilities are inherent within the industry, and there can be no assurances that significant costs and liabilities will not be incurred in the future.

Capital Expenditures Attributable to Compliance with Environmental Regulations. In 2009, our capital expenditures attributable to compliance with environmental regulations were $9.1 million, and are currently estimated to be approximately $12.0 million for 2010. The estimates for 2010 does not include amounts related to capital investments at our facilities that management has deemed to be strategic investments rather than expenditures relating to environmental regulatory compliance.

RENEWABLE ENERGY AND ALTERNATIVE FUEL MANDATES

Several federal and state programs require the purchase and use of renewable energy and alternative fuels, such as battery-powered engines, biodiesel, wind energy, and solar energy. These mandates could impact the demand for refined petroleum products. In December 2007, Congress enacted the Energy Independence and Security Act of 2007, which, among things, mandated annually increasing levels for the use of renewable fuels such as ethanol, commencing in 2008 and escalating for 15 years, as well as increasing energy efficiency goals, including higher fuel economy standards for motor vehicles, among other steps. These statutory mandates may over time offset projected increases or reduce the demand for refined petroleum products, particularly gasoline, in certain markets. The increased production and use of biofuels may also create opportunities for additional pipeline transportation and additional blending opportunities within the terminals division, although that potential cannot be quantified at present. Other legislative changes may similarly alter the expected demand and supply projections for refined petroleum products in ways that cannot be predicted.

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. Violations of any of these statutes and the related regulations could result in significant costs and liabilities.

AIR EMISSIONS

Our operations are subject to the Federal Clean Air Act, as amended, and analogous or more stringent state and local statutes. These laws and regulations regulate emissions of air pollutants from various industrial sources, including some of our operations, and also impose various monitoring and reporting requirements. Such laws and regulations may require a facility to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce air emissions or result in the increase of existing air emissions, and obtain and strictly comply with the provisions of any air permits. It is possible that these statutes and the related regulations may be revised to be more restrictive in the future, necessitating additional capital expense to ensure our operations are in compliance. We are unable to estimate the effect on our financial condition or results of operations or the amount and timing of such required expenditures.

SOLID WASTE

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

 

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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.”

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 facilities. 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 or have a material effect on our financial condition or results of operations.

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

 

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RISK FACTORS

RISKS RELATED TO OUR BUSINESS

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

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

 

   

throughput volumes transported in our pipelines;

 

   

lease renewals or throughput volumes in our terminals and storage facilities;

 

   

tariff rates and fees we charge and the returns we realize for our services;

 

   

the results of our marketing, trading and hedging activities, which fluctuate depending upon the relationship between refined product prices and prices of crude oil and other feedstocks;

 

   

demand for crude oil, refined products and anhydrous ammonia;

 

   

the effect of worldwide energy conservation measures;

 

   

our operating costs;

 

   

weather conditions;

 

   

domestic and foreign governmental regulations and taxes; and

 

   

prevailing economic conditions.

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

 

   

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

 

   

the sources of cash used to fund our acquisitions;

 

   

our capital expenditures;

 

   

fluctuations in our working capital needs;

 

   

issuances of debt and equity securities; and

 

   

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

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

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

Any sustained decrease in demand for refined products in the markets served by our pipelines, terminals or refineries could result in a significant reduction in throughputs in our pipelines, storage in our terminals or sales of asphalt and other refined products, which would reduce our cash flow and our ability to make distributions to our unitholders. Factors that could lead to a decrease in market demand include:

 

   

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

 

   

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

 

   

a decrease in spending on construction projects, including road paving and maintenance;

 

   

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

 

   

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

 

   

a decrease in corn acres planted, which may reduce demand for anhydrous ammonia; and

 

   

the increased use of alternative fuel sources, such as battery-powered engines.

 

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A decrease in lease renewals or throughputs in our assets would cause our revenues to decline and could adversely affect our ability to make cash distributions to our unitholders.

A decrease in lease renewals or throughputs in our assets would cause our revenues to decline and could adversely affect our ability to make cash distributions to our unitholders. Such a decrease could result from either a customer’s failure to renew a lease or a temporary or permanent decline in the amount of crude oil or refined products stored at and transported from the refineries we serve and own. Factors that could result in such a decline include:

 

   

a material decrease in the supply of crude oil;

 

   

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

 

   

scheduled refinery turnarounds or unscheduled refinery maintenance;

 

   

operational problems or catastrophic events at a refinery;

 

   

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

 

   

a decision by our current customers to redirect refined products transported in our pipelines to markets not served by our pipelines or to transport crude oil or refined products by means other than our pipelines;

 

   

increasingly stringent environmental regulations; or

 

   

a decision by our current customers to sell one or more of the refineries we serve to a purchaser that elects not to use our pipelines and terminals.

Our asphalt refineries are dependent upon a steady supply of crude oil from PDVSA, the national oil company of Venezuela, and decisions of the Organization of Petroleum Exporting Countries (OPEC) to decrease production of crude oil, as well as the Venezuelan economic and political environment, may disrupt our supply of crude oil.

We have an agreement with PDVSA, pursuant to which PDVSA agrees to sell and we agree to purchase an annual average of 75,000 barrels per day of crude oil. In December 2008, OPEC, which includes Venezuela, agreed to decrease production by 2.2 million barrels of crude oil per day and PDVSA reduced contractual deliveries by two 300,000 barrel Boscán cargoes in February 2009 and one in March 2009. These production decreases have not had a material impact on our financial results. Additional OPEC cuts, coupled with Venezuela’s recent political, economic and social turmoil could have a severe impact on PDVSA’s production or delivery of crude oil. In the event PDVSA further reduces its production or delivery of Boscán or Bachaquero BCF-13, the crude oil for which our refineries are currently optimized, we will be forced to replace all or a portion of the crude oil we would normally have purchased under our PDVSA crude oil supply contract with purchases of crude oil on the spot market, potentially at a price less favorable than we would have obtained under the PDVSA crude oil supply contract. While we found satisfactory replacement crudes for the February and March 2009 cuts, it is possible that processing a more significant proportion of alternate crudes could result in reduced refinery run rates, significantly reduced production and additional capital expenditures, which could be material. Accordingly, any major disruption of our supply of crude oil from Venezuela could result in substantially lower revenues and additional volatility in our earnings and cash flow.

Our operations are subject to operational hazards and unforeseen interruptions, and we do not insure against all potential losses. Therefore, we could be seriously harmed by unexpected liabilities.

Our operations are subject to operational hazards and unforeseen interruptions such as natural disasters, adverse weather, accidents, fires, explosions, hazardous materials releases, mechanical failures and other events beyond our control. These events might result in a loss of equipment or life, injury or extensive property damage, as well as an interruption in our operations. In the event any of our facilities are forced to shut down for a significant period of time, it may have a material adverse effect on our earnings, our other results of operations and our financial condition as a whole.

We may not be able to maintain or obtain insurance of the type and amount we desire at reasonable rates. As a result of market conditions, premiums and deductibles for certain of our insurance policies have increased substantially and could escalate further. Certain insurance coverage could become unavailable or available only for reduced amounts of coverage and at higher rates. For example, our insurance carriers require broad exclusions for losses due to terrorist acts. If we were to incur a significant liability for which we are not fully insured, such a liability could have a material adverse effect on our financial position and our ability to make distributions to our unitholders and to meet our debt service requirements.

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

Revenues associated with our asphalt operations result from the refining of crude oil into asphalt and other products and the sale of those products. The price and market value of crude oil and refined products is volatile. Our revenues will be

 

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adversely affected by this volatility during periods of decreasing prices because of the reduction in the value and resale price of our inventory. Future price volatility could have an adverse impact on our results of operations, cash flow and ability to make distributions to our unitholders.

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

A large portion of our earnings from our asphalt operations are affected by the relationship, or margin, between asphalt and other intermediate product prices and the prices for crude oil and other feedstocks. Our cost to acquire feedstocks and the price at which we can ultimately sell asphalt and other intermediate products depend upon several factors beyond our control, including regional and global supply of and demand for crude oil, asphalt and other feedstocks and intermediate and refined products. These in turn depend on, among other things, the availability and quantity of imports, the production levels of domestic and foreign suppliers, levels of intermediate and refined product inventories, U.S. relationships with foreign governments, political affairs and the extent of governmental regulation.

Additionally, crude oil prices and prices for the asphalt and intermediate products produced by our asphalt operations may not fluctuate consistently. Typically, increases in the prices of asphalt and intermediate products lag behind increases in the price of crude oil. Furthermore, much of the asphalt produced by our asphalt operations is marketed to satisfy governmental contracts. The governmental agencies with which we or our customers contract may have budgetary or other constraints that limit their ability to absorb increases to asphalt prices. Our results of operations in our asphalt and fuels marketing segment will suffer if the market prices of asphalt and intermediate products do not increase as much as the price of crude oil. Our increased exposure to unstable commodity prices will increase the volatility of our earnings.

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

The selling prices of asphalt products we produce are seasonal. Asphalt demand is generally lower in the first and fourth quarters of the year as compared to the second and third quarters, due to the seasonality of road construction. In addition, our natural gas costs can be higher during the winter months. Our operating results for the first and fourth calendar quarters will likely be lower than those for the second and third calendar quarters of each year as a result of this seasonality.

Competition in the asphalt industry is intense, and such competition in the markets in which we sell our asphalt products could adversely affect our earnings and ability to make distributions to our unitholders.

Our asphalt operations compete with other refiners and with regional and national asphalt marketing companies. Many of these competitors are larger, more diverse companies with greater resources, providing them advantages in obtaining crude oil and other blendstocks and in competing through bidding process for asphalt supply contracts.

Our marketing and trading of refined products may expose us to trading losses and hedging losses, and non-compliance with our risk management policies could result in significant financial losses.

Our marketing and trading of refined products may expose us to price volatility risk for the purchase and sale of crude oil and petroleum products, including gasoline, distillates, fuel oil and asphalt. We attempt to mitigate this volatility risk through hedging, but we are still exposed to basis risk. We may also be exposed to inventory and financial liquidity risk due to the inability to trade certain products on demand or rising costs of carrying some inventories. Further, our marketing and trading activities, including any hedging activities, may cause volatility in our earnings. In addition, we will be exposed to credit risk in the event of non-performance by counterparties.

Our risk management policies may not eliminate all price risk since open trading positions will expose us to price volatility. Further, there is a risk that our risk management policies will not be complied with. Although we have designed procedures to anticipate and detect non-compliance, we cannot assure you that these steps will detect and prevent all violations of our trading policies and procedures, particularly if deception and other intentional misconduct are involved.

As a result of the risks described above, the activities associated with our marketing and trading business may expose us to volatility in earnings and financial losses, which may adversely affect our financial condition and our ability to distribute cash to our unitholders.

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

In order to manage our exposure to commodity price fluctuations associated with our asphalt and fuels marketing segment, we may engage in crude oil and refined product hedges. While intended to reduce the effects of volatile crude oil

 

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and refined product prices, such transactions, depending on the hedging instrument used, may limit our potential gains if crude oil and refined product prices were to rise substantially over the price established by the hedge. In addition, such transactions may expose us to the risk of financial loss in certain circumstances, including instances in which:

 

   

production is substantially less than expected;

 

   

the counterparties to our futures contracts fail to perform under the contracts; or

 

   

there is a change in the expected differential between the underlying price in the hedging agreement and the actual prices received.

The accounting standards regarding hedge accounting are complex, and even when we engage in hedging transactions that are effective economically, these transactions may not be considered effective for accounting purposes. Accordingly, our financial statements will reflect increased volatility due to these hedges, even when there is no underlying economic impact at that point. In addition, it is not possible for us to engage in a hedging transaction that completely mitigates our exposure to commodity prices. Our financial statements may reflect a gain or loss arising from an exposure to commodity prices for which we are unable to enter into an effective hedge.

We are exposed to counterparty credit risk. Nonpayment and nonperformance by our customers, vendors or derivative counterparties could reduce our revenues, increase our expenses or otherwise negatively impact our operating results, cash flows and ability to make distributions to our unitholders.

We are subject to risks of loss resulting from nonpayment or nonperformance by our customers to whom we extend credit. In addition, nonperformance by vendors who have committed to provide us with products or services could result in higher costs or interfere with our ability to successfully conduct our business. Furthermore, nonpayment by the counterparties to our interest rate and commodity derivatives could expose us to additional interest rate or commodity price risk. Weak economic conditions and widespread financial stress could reduce the liquidity of our customers, vendors or counterparties, making it more difficult for them to meet their obligations to us. Any substantial increase in the nonpayment and nonperformance by our customers, vendors or counterparties could have a material adverse effect on our results of operations and cash flows.

Our future financial and operating flexibility may be adversely affected by our significant leverage, our significant working capital needs, restrictions in our debt agreements and disruptions in the financial markets.

As of December 31, 2009, our consolidated debt was $1.8 billion. Among other things, our significant leverage may be viewed negatively by credit rating agencies, which could result in increased costs for us to access the capital markets. NuStar Logistics and NuPOP have senior unsecured ratings of Baa3 with Moody’s Investor Service and BBB minus with Standard & Poor’s and Fitch. Fitch, Moody’s and Standard & Poor’s have assigned NuStar Logistics and NuPOP a stable outlook. Any future downgrade of the debt issued by these wholly owned subsidiaries could significantly increase our capital costs and adversely affect our ability to raise capital in the future. Additionally, any further ratings downgrade on the debt issued by NuStar Logistics could result in an adjustment to the interest rates on the bonds issued by NuStar Logistics in April 2008, which would significantly increase our capital costs and adversely affect our ability to raise capital in the future.

We require significant amounts of working capital to make purchases of crude oil and maintain necessary seasonal inventories to support our asphalt operations. We believe that our current sources of capital are adequate to meet our working capital needs. However, if our working capital needs increase more than anticipated, we may be forced to seek additional sources of capital, which may not be available or available on commercially reasonable terms.

Our five-year revolving credit agreement (the 2007 Revolving Credit Agreement) contains restrictive covenants, including a requirement that, as of the end of each rolling period, which consists of any period of four consecutive fiscal quarters, we maintain a consolidated debt coverage ratio (consolidated indebtedness to consolidated EBITDA, as defined in the 2007 Revolving Credit Agreement) not to exceed 5.00-to-1.00. Failure to comply with any of the restrictive covenants in the 2007 Revolving Credit Agreement will result in a default under the terms of our credit agreement and could result in acceleration of this and possibly other indebtedness.

Debt service obligations, restrictive covenants in our credit facilities and the indentures governing our outstanding senior notes and maturities resulting from this leverage may adversely affect our ability to finance future operations, pursue acquisitions and fund other capital needs and our ability to pay cash distributions to unitholders. In addition, this leverage may make our results of operations more susceptible to adverse economic or operating conditions. For example, during an

 

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

If our lenders file for bankruptcy or experience severe financial hardship, they may not honor their pro rata share of our borrowing requests under the 2007 Revolving Credit Agreement, which may significantly reduce our available borrowing capacity and, as a result, materially adversely affect our financial condition and ability to pay distributions to unitholders.

Additionally, we may not be able to access the capital markets in the future at economically attractive terms, which may adversely affect our future financial and operating flexibility and our ability to pay cash distributions at current levels.

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

We have significant exposure to increases in interest rates. At December 31, 2009, we had approximately $1.8 billion of consolidated debt, of which $1.0 billion was at fixed interest rates and $0.8 billion was at variable interest rates after giving effect to interest rate swap agreements. Our results of operations, cash flows and financial position could be materially adversely affected by significant increases in interest rates above current levels. Further, the trading price of our units is sensitive to changes in interest rates and any rise in interest rates could adversely impact such trading price.

We could be subject to damages based on claims brought against us by our customers or lose customers as a result of the failure of our products to meet certain quality specifications.

Our specialty asphalt products are produced to precise customer specifications. If a product fails to perform in a manner consistent with the detailed quality specifications required by the customer, the customer could seek replacement of the product or damages for costs incurred as a result of the product failing to perform as guaranteed. A successful claim or series of claims against us could result in a loss of one or more customers.

If we are unable to complete capital projects at their expected costs and/or in a timely manner, or if the market conditions assumed in our project economics deteriorate, our financial condition, results of operations, or cash flows could be affected materially and adversely.

Delays or cost increases related to capital spending programs involving construction of new facilities (or improvements and repairs to our existing facilities) could adversely affect our ability to achieve forecasted operating results. Although we evaluate and monitor each capital spending project and try to anticipate difficulties that may arise, such delays or cost increases may arise as a result of factors that are beyond our control, including:

 

   

denial or delay in issuing requisite regulatory approvals and/or permits;

 

   

unplanned increases in the cost of construction materials or labor;

 

   

disruptions in transportation of modular components and/or construction materials;

 

   

severe adverse weather conditions, natural disasters, or other events (such as equipment malfunctions explosions, fires, spills) affecting our facilities, or those of vendors and suppliers;

 

   

shortages of sufficiently skilled labor, or labor disagreements resulting in unplanned work stoppages;

 

   

market-related increases in a project’s debt or equity financing costs; and/or

 

   

nonperformance by, or disputes with, vendors, suppliers, contractors, or sub-contractors involved with a project.

Our forecasted operating results also are based upon our projections of future market fundamentals that are not within our control, including changes in general economic conditions, availability to our customers of attractively priced alternative supplies of crude oil and refined products and overall customer demand.

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

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

Acquisitions and business expansions involve numerous risks, including difficulties in the assimilation of the assets and operations of the acquired businesses, inefficiencies and difficulties that arise because of unfamiliarity with new assets and the businesses associated with them and new geographic areas. Further, unexpected costs and challenges may arise whenever businesses with different operations or management are combined and we may experience unanticipated delays in realizing the benefits of an acquisition. In some cases, we have indemnified the previous owners and operators of acquired assets.

 

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

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

Recent scientific studies have suggested that emissions of certain gases, commonly referred to as “greenhouse gases” and including carbon dioxide and methane, may be contributing to warming of the Earth’s atmosphere. In response to such studies, the U.S. Congress is actively considering legislation to reduce emissions of greenhouse gases. In addition, at least one-third of the states, either individually or through multi-state regional initiatives, have already taken legal measures to reduce emissions of greenhouse gases, primarily through the planned development of greenhouse gas emission inventories and/or greenhouse gas cap and trade programs. As an alternative to reducing emission of greenhouse gases under cap and trade programs, Congress may consider the implementation of a program to tax the emission of carbon dioxide and other greenhouse gases. In December 2009, the EPA issued an endangerment finding that greenhouse gases may reasonably be anticipated to endanger public health and welfare and are a pollutant to be regulated under the Clean Air Act. Passage of climate change legislation or other regulatory initiatives by Congress or various states of the U.S. or the adoption of regulations by the EPA or analogous state agencies that regulate or restrict emissions of greenhouse gases in areas in which we conduct business, could result in changes to the demand for the products we store, transport and sell, and could increase the costs of our operations, including costs to operate and maintain our facilities, install new emission controls on our facilities, acquire allowances to authorize our greenhouse gas emissions, pay any taxes related to our greenhouse gas emissions and administer and manage a greenhouse gas emissions program. We may be unable to recover any such lost revenues or increased costs in the rates we charge our customers, and any such recovery may depend on events beyond our control, including the outcome of future rate proceedings before the FERC and the provisions of any final legislation or regulations. Reductions in our revenues or increases in our expenses as a result of climate control initiatives could have adverse effects on our business, financial position, results of operations and prospects.

We may have liabilities from our assets that pre-exist our acquisition of those assets, but that may not be covered by indemnification rights we will have against the sellers of the assets.

Some of our assets have been used for many years to refine, transport and store crude oil and refined products. Releases may have occurred in the past that could require costly future remediation. If a significant release or event occurred in the past, the liability for which was not retained by the seller, or for which indemnification from the seller is not available, it could adversely affect our financial position and results of operations.

Our operations are subject to federal, state and local laws and regulations relating to environmental protection and operational safety that could require us to make substantial expenditures.

Our operations are subject to increasingly stringent environmental and safety laws and regulations. Refining, transporting and storing petroleum and other products, such as specialty liquids, produces a risk that these products may be released into the environment, potentially causing substantial expenditures for a response action, significant government penalties, liability to government agencies for damages to natural resources, personal injury or property damages to private parties and significant business interruption. We own or lease a number of properties that have been used to store or distribute refined products for many years. Many of these properties were operated by third parties whose handling, disposal or release of hydrocarbons and other wastes was not under our control.

If we were to incur a significant liability pursuant to environmental or safety laws or regulations, such a liability could have a material adverse effect on our financial position, our ability to make distributions to our unitholders and our ability to meet our debt service requirements. Please read Item 3. “Legal Proceedings” and Note 15 of Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data.”

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

The FERC regulates the tariff rates for interstate oil movements on our common carrier pipelines. Shippers may protest our pipeline tariff filings, and the FERC may investigate new or changed tariff rates. Further, other than for rates set under market-based rate authority, the FERC may order refunds of amounts collected under newly filed rates that are determined by the FERC to be in excess of a just and reasonable level when taking into consideration our pipeline system’s cost of service. In addition, shippers may challenge by complaint the lawfulness of tariff rates that have become final and effective. The FERC may also investigate such rates absent shipper complaint. If existing rates challenged by complaint are determined by the FERC to be in excess of a just and reasonable level when taking into consideration our pipeline

 

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

We use various FERC-authorized rate change methodologies for our interstate pipelines, including indexing, cost-of-service rates, market-based rates and settlement rates. Typically, we annually adjust our rates in accordance with FERC indexing methodology, which currently allows a pipeline to change their rates within prescribed ceiling levels that are tied to an inflation index. The current index (which runs through June 30, 2011) is measured by the year-over-year change in the Bureau of Labor’s producer price index for finished goods, plus 1.3%. Shippers may protest rate increases made within the ceiling levels, but such protests must show that the portion of the rate increase resulting from application of the index is substantially in excess of the pipeline’s increase in costs from the previous year. However, if the index results in a negative adjustment, we are required to reduce any rates that exceed the new maximum allowable rate. In addition, changes in the index might not be large enough to fully reflect actual increases in our costs. If the FERC’s rate-making methodologies change, any such change or new methodologies could result in rates that generate lower revenues and cash flow and could adversely affect our ability to make distributions to our unitholders and to meet our debt service requirements. Additionally, competition constrains our rates in various markets. As a result, we may from time to time be forced to reduce some of our rates to remain competitive.

Changes to FERC rate-making principles could have an adverse impact on our ability to recover the full cost of operating our pipeline facilities and our ability to make distributions to our unitholders.

In May 2005, the FERC issued a statement of general policy stating it will permit pipelines to include in cost of service a tax allowance to reflect actual or potential tax liability on their public utility income attributable to all partnership or limited liability company interests, if the ultimate owner of the interest has an actual or potential income tax liability on such income. Whether a pipeline’s owners have such actual or potential income tax liability will be reviewed by the FERC on a case-by-case basis. Although this policy is generally favorable for pipelines that are organized as pass-through entities, it still entails rate risk due to the case-by-case review requirement. This tax allowance policy and the FERC’s application of that policy were appealed to the 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.

In December 2006, the FERC issued an order addressing income tax allowance in rates, in which it reaffirmed prior statements regarding its income tax allowance policy, but raised a new issue regarding the implications of the FERC’s policy statement for publicly traded partnerships. The FERC noted that the tax deferral features of a publicly traded partnership may cause some investors to receive, for some indeterminate duration, cash distributions in excess of their taxable income, creating an opportunity for those investors to earn additional return, funded by ratepayers. Responding to this concern, FERC adjusted the equity rate of return of the pipeline at issue downward based on the percentage by which the publicly traded partnership’s cash flow exceeded taxable income. Requests for rehearing of the order are currently pending before the FERC.

Because the extent to which an interstate oil pipeline is entitled to an income tax allowance is subject to a case-by-case review at the FERC, the level of income tax allowance to which we will ultimately be entitled is not certain. Although the FERC’s current income tax allowance policy is generally favorable for pipelines that are organized as pass-through entities, it still entails rate risks due to the case-by-case review requirement. How the FERC’s policy statement is applied in practice to pipelines owned by publicly traded partnerships could impose limits on our ability to include a full income tax allowance in cost of service.

The FERC instituted a rulemaking proceeding in July 2007 to determine whether any changes should be made to the FERC’s methodology for determining pipeline equity returns to be included in cost-of-service based rates. The FERC determined that it would retain its current methodology for determining return on equity but that, when stock prices and cash distributions of tax pass-through entities are used in the return on equity calculations, the growth forecasts for those entities should be reduced by 50%. Despite the FERC’s determination, some complainants in rate proceedings have advocated that the FERC disallow the full use of cash distributions in the return on equity calculation. If the FERC were to disallow the use of full cash distributions in the return on equity calculation, such a result might adversely affect our ability to achieve a reasonable return.

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

The STB, a part of DOT, has jurisdiction over interstate pipeline transportation and rate regulations of anhydrous ammonia. Transportation rates must be reasonable, and a pipeline carrier may not unreasonably discriminate among its shippers. If the STB finds that a carrier’s rates violate these statutory commands, it may prescribe a reasonable rate. In

 

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determining a reasonable rate, the STB will consider, among other factors, the effect of the rate on the volumes transported by that carrier, the carrier’s revenue needs and the availability of other economic transportation alternatives. The STB does not provide rate relief unless shippers lack effective competitive alternatives. If the STB determines that effective competitive alternatives are not available and we hold market power, then we may be required to show that our rates are reasonable.

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

Power costs constitute a significant portion of our operating expenses. For the year ended December 31, 2009, our power costs equaled approximately $48.1 million, or 10% of our operating expenses for the year. In addition, $17.7 million of power costs were capitalized into inventory related to our asphalt refineries, which will be expensed into cost of product sales as the inventory is sold. We use mainly electric power at our pipeline pump stations, terminals and refineries, and such electric power is furnished by various utility companies that use primarily natural gas to generate electricity. Accordingly, our power costs typically fluctuate with natural gas prices. Increases in natural gas prices may cause our power costs to increase further. If natural gas prices increase, our cash flows may be adversely affected, which could adversely affect our ability to make distributions to our unitholders.

Terrorist attacks and the threat of terrorist attacks have resulted in increased costs to our business. Continued hostilities in the Middle East or other sustained military campaigns may adversely impact our results of operations.

Increased security measures we have taken as a precaution against possible terrorist attacks have resulted in increased costs to our business. Uncertainty surrounding continued hostilities in the Middle East or other sustained military campaigns may affect our operations in unpredictable ways, including disruptions of crude oil supplies and markets for refined products, the possibility that infrastructure facilities could be direct targets of, or indirect casualties of, an act of terror and instability in the financial markets that could restrict our ability to raise capital.

Our cash distribution policy may limit our growth.

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

NuStar GP Holdings may have conflicts of interest and limited fiduciary responsibilities, which may permit it to favor its own interests to the detriment of our unitholders.

NuStar GP Holdings currently indirectly owns our general partner and as of December 31, 2009, an aggregate 16.7% limited partner interest in us. Conflicts of interest may arise between NuStar GP Holdings and its affiliates, including our general partner, on the one hand, and us and our limited partners, on the other hand. As a result of these conflicts, the general partner may favor its own interests and the interests of its affiliates over the interests of the unitholders. These conflicts include, among others, the following situations:

 

   

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

 

   

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

 

   

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

 

   

Our general partner determines in its sole discretion which costs incurred by NuStar GP Holdings and its affiliates are reimbursable by us;

 

   

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

 

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Our general partner decides whether to retain separate counsel, accountants or others to perform services for us; and

 

   

In some instances, our general partner may cause us to borrow funds in order to permit the payment of distributions.

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

TAX RISKS TO OUR UNITHOLDERS

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

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

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

Current law may change, causing us to be treated as a corporation for federal income tax purposes or otherwise subjecting us to entity-level taxation. In addition, because of widespread state budget deficits, several states are evaluating ways to subject partnerships to entity level taxation through the imposition of state income, franchise or other forms of taxation. Partnerships and limited liability companies, unless specifically exempted, are also subject to a state-level tax imposed on revenues. Imposition of any entity-level tax on us by states we operate in will reduce the cash available for distribution to our unitholders.

A successful IRS contest of the federal income tax positions we take may adversely impact the market for our units, and the costs of any contest will reduce cash available for distribution to our unitholders.

The IRS may adopt positions that differ from the positions we take, even positions taken with the advice of counsel. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take. A court may not agree with all of the positions we take. Any contest with the IRS may materially and adversely impact the market for our units and the prices at which they trade. In addition, the costs of any contest between us and the IRS will result in a reduction in cash available for distribution to our unitholders. Moreover, the costs of any contest between us and the IRS will result in a reduction in cash available for distribution to our unitholders and thus will be borne indirectly by our unitholders and our general partner.

Even if unitholders do not receive any cash distributions from us, they will be required to pay taxes on their respective share of our taxable income.

Unitholders will be required to pay federal income taxes and, in some cases, state and local income taxes on the unitholder’s respective share of our taxable income, whether or not such unitholder receives cash distributions from us. Unitholders may not receive cash distributions from us equal to the unitholder’s respective share of our taxable income or even equal to the actual tax liability that results from the unitholder’s respective share of our taxable income.

The sale or exchange of 50% or more of our capital and profits interests, within a 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

 

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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.

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.

 

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PROPERTIES

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

 

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ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

ITEM 3. LEGAL PROCEEDINGS

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

GRACE ENERGY CORPORATION MATTER

In 1997, Grace Energy Corporation (Grace Energy) sued subsidiaries of Kaneb Pipe Line Partners, L.P. (KPP) and Kaneb Services LLC (KSL and, collectively with KPP and their respective subsidiaries, 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 in Massachusetts (Otis AFB). Grace Energy alleges the Otis AFB pipeline and related environmental liabilities had been transferred in 1978 to an entity that was part of Kaneb’s acquisition of Support Terminal Services, Inc. and its subsidiaries from Grace Energy in 1993. Kaneb contends that it did not acquire the Otis AFB pipeline and never assumed any responsibility for any associated environmental damage.

In 2000, the court entered final judgment that: (i) Grace Energy could not recover its own remediation costs of $3.5 million, (ii) Kaneb owned the Otis AFB pipeline and its related environmental liabilities and (iii) Grace Energy was awarded $1.8 million in attorney costs. Both Kaneb and Grace Energy appealed the final judgment of the trial court to the Texas Court of Appeals in Dallas. In 2001, Grace Energy filed a petition in bankruptcy, which created an automatic stay of actions against Grace Energy. In September 2008, Grace Energy filed its Joint Plan of Reorganization and Disclosure Statement.

The Otis AFB is a part of a Superfund Site pursuant to the Comprehensive Environmental Response Compensation and Liability Act (CERCLA). The site contains a number of groundwater contamination plumes, two of which are allegedly associated with the Otis AFB pipeline. Relying on the final judgment of the Texas state court assigning ownership of the Otis AFB pipeline to Kaneb, the U.S. Department of Justice (the DOJ) advised Kaneb in 2001 that it intends to seek reimbursement from Kaneb for the remediation costs associated with the two plumes. In November 2008, the DOJ forwarded information to us indicating that the past and estimated future remediation expenses associated with one plume are $71.9 million. The DOJ has indicated that they will not seek recovery of remediation costs for the second plume. The DOJ has not filed a lawsuit against us related to this matter, and we have not made any payments toward costs incurred by the DOJ. We are currently in settlement discussions with other potentially responsible parties and the DOJ and a change in our estimate of this liability may occur in the near term. However, any settlement agreement that is reached must be approved by multiple parties and requires the approval of the bankruptcy court and the federal district court. We cannot currently estimate when or if a settlement will be finalized.

ERES MATTER

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

 

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

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

In addition, our wholly owned subsidiary, Shore Terminals LLC (Shore) owns a refined product terminal in Portland, Oregon located adjacent to the Portland Harbor. The EPA has classified portions of the Portland Harbor, including the portion adjacent to our terminal, as a federal “Superfund” site due to sediment contamination (the Portland Harbor Site). Portland Harbor is contaminated with metals (such as mercury), pesticides, herbicides, polynuclear aromatic hydrocarbons, polychlorinated byphenyls, semi-volatile organics and dioxin/furans. Shore and more than 80 other parties have received a “General Notice” of potential liability from the EPA relating to the Portland Harbor Site. The letter advised Shore that it may be liable for the costs of investigation and remediation (which liability may be joint and several with other potentially responsible parties), as well as for natural resource damages resulting from releases of hazardous substances to the Portland Harbor Site. We have agreed to work with more than 65 other potentially responsible parties to attempt to negotiate an agreed method of allocating costs associated with the cleanup. The precise nature and extent of any clean-up of the Portland Harbor Site, the parties to be involved, the process to be followed for any clean-up and the allocation of any costs for the clean-up among responsible parties have not yet been determined. It is unclear to what extent, if any, we will be liable for environmental costs or damages associated with the Portland Harbor Site. It is also unclear to what extent natural resource damage claims or third party contribution or damage claims will be asserted against Shore.

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

We are also a party to additional claims and legal proceedings arising in the ordinary course of business. Due to the inherent uncertainty of litigation, there can be no assurance that the resolution of any particular claim or proceeding would not have a material adverse effect on our results of operations, financial position or liquidity. It is possible that if one or more of the matters described in Item 3. were decided against us, the effects could be material to our results of operations in the period in which we would be required to record or adjust the related liability and could also be material to our cash flows in the periods we would be required to pay such liability.

 

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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, 2009

 

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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 5, 2010, we had 792 holders of record of our common units. The high and low sales prices (composite transactions) by quarter for the years ended December 31, 2009 and 2008 were as follows:

 

    

Price Range of

Common Unit

    
    

High

       

Low

  

Year 2009

           

4th Quarter

   $  57.34       $  50.54   

3rd Quarter

     57.20         50.51   

2nd Quarter

     57.68         45.51   

1st Quarter

     50.88         40.45   

 

Year 2008

           

4th Quarter

   $ 46.89       $ 27.00   

3rd Quarter

     50.45         40.00   

2nd Quarter

     54.90         47.00   

1st Quarter

     57.15         47.76   

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

 

    

Record Date

  

Payment Date

  

Amount
Per Unit

    

Year 2009

           

4th Quarter

   February 5, 2010    February 12, 2010    $ 1.0650   

3rd Quarter

   November 5, 2009    November 12, 2009      1.0650   

2nd Quarter

   August 6, 2009    August 13, 2009      1.0575   

1st Quarter

   May 8, 2009    May 15, 2009      1.0575   

 

Year 2008

           

4th Quarter

   February 5, 2009    February 12, 2009    $ 1.0575   

3rd Quarter

   November 5, 2008    November 12, 2008      1.0575   

2nd Quarter

   August 6, 2008    August 13, 2008      0.9850   

1st Quarter

   May 7, 2008    May 14, 2008      0.9850   

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

 

    

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, 2009 and 2008 totaled $28.7 million and $25.3 million, respectively. The general partner’s share of our distributions for the years ended December 31, 2009 and 2008 was 12.6% and 12.0%, 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,

  

2009

  

2008 (a)

  

2007

  

2006

  

2005

   (Thousands of Dollars, Except Per Unit Data)

Statement of Income Data:

              

Revenues

   $  3,855,871    $  4,828,770    $  1,475,014    $  1,137,261    $ 659,557

Operating income

     273,316      310,073      192,599      212,899      152,952

Income from continuing operations

     224,875      254,018      150,298      149,906      107,675

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

     3.47      4.22      2.73      2.82      2.76

Cash distributions per unit applicable to limited partners

     4.245      4.085      3.835      3.600      3.365
    

December 31,

    

2009

  

2008 (a)

  

2007

  

2006

  

2005

     (Thousands of Dollars)

Balance Sheet Data:

              

Property, plant and equipment, net

   $ 3,028,196    $ 2,941,824    $ 2,492,086    $ 2,345,135    $ 2,160,213

Total assets

     4,774,673      4,459,597      3,783,087      3,494,208      3,366,992

Long-term debt (less current portion)

     1,828,993      1,872,015      1,445,626      1,353,720      1,169,659

Partners’ equity

     2,484,968      2,206,997      1,994,832      1,875,681      1,900,779

 

(a) The significant increase in revenues, operating income, income from continuing operations and balance sheet data are primarily due to the acquisition of our asphalt operations in March 2008.
(b) In 2008, the Financial Accounting Standards Board provided additional guidance regarding the application of the two-class method to calculate earnings per unit for master limited partnerships, which was effective January 1, 2009. As a result, income from continuing operations per unit applicable to limited partners for the years ended December 31, 2007 and 2006 changed from $2.74 and $2.84, respectively, previously reported.

 

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

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

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

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

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

OVERVIEW

NuStar Energy L.P. (NuStar Energy) (NYSE: NS) is engaged in the terminalling and storage of petroleum products, the transportation of petroleum products and anhydrous ammonia, and asphalt and fuels marketing. Unless otherwise indicated, the terms “NuStar Energy L.P.,” “the Partnership,” “we,” “our” and “us” are used in this report to refer to NuStar Energy, to one or more of our consolidated subsidiaries or to all of them taken as a whole. NuStar GP Holdings, LLC (NuStar GP Holdings) (NYSE: NSH) wholly owns our general partner, Riverwalk Logistics, L.P., and owns an 18.7% total interest in us as of December 31, 2009. Our Management’s Discussion and Analysis of Financial Condition and Results of Operations is presented in five sections:

 

   

Overview

 

   

Results of Operations

 

   

Outlook

 

   

Liquidity and Capital Resources

 

   

Related Party Transactions

 

   

Critical Accounting Policies

Acquisition

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

Operations

We conduct our operations through our wholly owned subsidiaries, primarily NuStar Logistics, L.P. (NuStar Logistics) and NuStar Pipeline Operating Partnership L.P. (NuPOP). Our operations are divided into three reportable business segments: storage, transportation, and asphalt and fuels marketing. For a more detailed description of our segments, please refer to Segments under Item 1. “Business.”

 

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

Transportation. We own common carrier refined product pipelines in Texas, Oklahoma, Colorado, New Mexico, Kansas, Nebraska, Iowa, South Dakota, North Dakota and Minnesota covering approximately 5,605 miles, consisting of the Central West System, the East Pipeline and the North Pipeline. In addition, we own a 2,000 mile anhydrous ammonia pipeline located in Louisiana, Arkansas, Missouri, Illinois, Indiana, Iowa and Nebraska. We also own 812 miles of crude oil pipelines in Texas, Oklahoma, Kansas, Colorado and Illinois, as well as associated crude oil storage facilities providing storage capacity of 1.9 million barrels in Texas and Oklahoma that are located along the crude oil pipelines.

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

We enter into derivative contracts to mitigate the effect of commodity price fluctuations. The derivative instruments we use consist primarily of futures contracts and swaps traded on the NYMEX for the purposes of hedging the price risk of our physical inventory. Not all of our derivative instruments qualify for hedge accounting treatment under United States generally accepted accounting principles. In such cases, we record the changes in the fair values of these derivative instruments in cost of product sales. The changes in the fair values of these derivative instruments generally are offset, at least partially, by changes in the values of the hedged physical inventory. However, we do not recognize those changes in the value of the hedged inventory until the physical sale of such inventory takes place. Therefore, our earnings for a period may include the gain or loss related to derivative instruments without including the offsetting effect of the hedged item, which could result in greater earnings volatility.

In addition, we value our inventory at the lower of cost or market. If changes in commodity prices result in market prices below the cost of our inventory, we may be required to reduce the value of our inventory to market.

Demand for certain of the products we market fluctuates seasonally. For example, demand for gasoline and asphalt is typically higher in the summer months than the winter months, whereas demand for heating oil is higher in the winter months than the summer months. Prices for these commodities generally are highest during those times of higher demand. In addition to purchasing inventory for immediate resale, we have and expect to continue to employ a strategy of purchasing inventory during times of lower demand and lower prices and storing that inventory until it can be sold at higher prices. We expect that our overall level of working capital will continue to increase to support the operations of the asphalt and fuels marketing segment. Additionally, the level of working capital employed by the asphalt and fuels 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.

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 products transported by and/or stored in our assets and the demand for products we sell, particularly asphalt;

 

   

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

 

   

factors such as commodity price volatility and market structure that impact our asphalt and fuels marketing segment; and

 

   

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

 

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RESULTS OF OPERATIONS

Year Ended December 31, 2009 Compared to Year Ended December 31, 2008

Financial Highlights

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

 

   

Year Ended December 31,

       
        2009             2008             Change  
                   

Statement of Income Data:

               

Revenues:

               

Service revenues

  $     745,349        $     740,630        $     4,719   

Product sales

    3,110,522          4,088,140          (977,618
                           

Total revenues

    3,855,871          4,828,770          (972,899
                           

Costs and expenses:

               

Cost of product sales

    2,883,187          3,864,310          (981,123

Operating expenses

    458,892          442,248          16,644   

General and administrative expenses

    94,733          76,430          18,303   

Depreciation and amortization expense

    145,743          135,709          10,034   
                           

Total costs and expenses

    3,582,555          4,518,697          (936,142
                           

Operating income

    273,316          310,073          (36,757

Equity earnings from joint ventures

    9,615          8,030          1,585   

Interest expense, net

    (79,384       (90,818       11,434   

Other income, net

    31,859          37,739          (5,880
                           

Income before income tax expense

    235,406          265,024          (29,618

Income tax expense

    10,531          11,006          (475
                           

Net income

  $     224,875        $     254,018        $     (29,143
                           

Net income per unit applicable to limited partners

  $     3.47        $     4.22        $     (0.75
                           

Weighted average limited partner units outstanding

    55,232,467          53,182,741          2,049,726   
                           

Annual Highlights

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

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

 

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Segment Operating Highlights

(Thousands of Dollars, Except Barrel/Day Information)

 

   

Year Ended December 31,

       
        2009             2008             Change  
                   

Storage:

               

Throughput (barrels/day)(a)

    667,169          742,599          (75,430

Throughput revenues

  $     78,353        $     90,918        $     (12,565

Storage lease revenues

    409,219          363,171          46,048   
                           

Total revenues

    487,572          454,089          33,483   

Operating expenses

    245,439          246,304          (865

Depreciation and amortization expense

    70,888          66,706          4,182   
                           

Segment operating income

  $     171,245        $     141,079        $     30,166   
                           

Transportation:

               

Refined products pipelines throughput (barrels/day)

    573,778          673,687          (99,909

Crude oil pipelines throughput (barrels/day)

    351,888          392,110          (40,222
                           

Total throughput (barrels/day)

    925,666          1,065,797          (140,131

Throughput revenues

  $     302,070        $     317,778        $     (15,708

Operating expenses

    111,673          131,943          (20,270

Depreciation and amortization expense

    50,528          50,749          (221
                           

Segment operating income

  $     139,869        $     135,086        $     4,783   
                           

Asphalt and Fuels Marketing:

               

Product sales

  $     3,110,522        $     4,088,169        $     (977,647

Cost of product sales

    2,899,457          3,880,796          (981,339

Operating expenses

    130,973          80,133          50,840   

Depreciation and amortization expense

    19,463          14,734          4,729   
                           

Segment operating income

  $     60,629        $     112,506        $     (51,877
                           

Consolidation and Intersegment Eliminations:

               

Revenues

  $     (44,293     $     (31,266     $     (13,027

Cost of product sales

    (16,270       (16,486       216   

Operating expenses

    (29,193       (16,132       (13,061
                           

Total

  $     1,170        $     1,352        $     (182
                           

Consolidated Information:

               

Revenues

  $     3,855,871        $     4,828,770        $     (972,899

Cost of product sales

    2,883,187          3,864,310          (981,123

Operating expenses

    458,892          442,248          16,644   

Depreciation and amortization expense

    140,879          132,189          8,690   
                           

Segment operating income

    372,913          390,023          (17,110

General and administrative expenses

    94,733          76,430          18,303   

Other depreciation and amortization expense

    4,864          3,520          1,344   
                           

Consolidated operating income

  $     273,316        $     310,073        $     (36,757
                           

 

(a) Excludes throughputs related to storage lease revenues.

 

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Storage

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

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

 

   

an increase of $20.0 million due to completed tank expansion projects at our Amsterdam, St. James, Texas City and Jacksonville terminals;

 

   

an increase of $6.7 million at certain of our domestic terminals resulting from an increase in product throughput and associated handling fees;

 

   

an increase of $4.3 million mainly at our west coast terminals primarily due to higher negotiated storage rates; and

 

   

an increase of $3.1 million at our asphalt terminals primarily due to new storage-based contracts with the asphalt and fuels marketing segment.

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

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

Transportation

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

 

   

lower throughputs of 42,246 barrels per day and a decrease in revenues of $7.0 million on our pipelines serving the McKee refinery primarily due to a turnaround in May 2009 and lower overall demand resulting from the economic downturn. In addition, throughputs and revenues decreased due to a shipper using alternate pipelines in the third and fourth quarters of 2009, and a shipper acquiring our joint venture partner’s interest in a pipeline and shipping product on its purchased space rather than our space. These decreases were partially offset by higher revenue related to a new shipper with a minimum throughput agreement that began in late 2008;

 

   

a decrease in throughputs of 6,568 barrels per day and a decrease in revenues of $4.4 million on the Ammonia Pipeline due to high inventory levels of ammonia in the Midwest that carried over from the fall of 2008 and unseasonably wet and cold weather in the first half of 2009;

 

   

a decrease in throughputs of 28,132 barrels per day and a decrease in revenues of $1.7 million due to the sale of the Ardmore-Wynnewood pipeline in June 2009;

 

   

a decrease in throughputs of 14,651 barrels per day and a decrease in revenues of $1.0 million on our pipelines serving the Ardmore refinery due to operational issues at the refinery during the second and third quarters of 2009 and a refinery shut down in the third quarter of 2009 following a lightning strike;

 

   

a decrease in throughputs of 15,615 barrels per day on our pipelines serving the Three Rivers refinery due to a scheduled turnaround during the third quarter of 2009 and reduced crude run rates resulting from the economic downturn; and

 

   

a decrease of 11,338 barrels per day due to the sale of the Skelly-Belvieu pipeline in December 2008.

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

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

 

   

a decrease of $9.5 million due to a reduction in our product imbalance liability resulting from lower commodity prices associated with our product imbalances on the East Pipeline, partially offset by a hedging loss;

 

   

a decrease of $8.6 million in power costs resulting from lower throughputs and lower natural gas prices; and

 

   

a decrease of $1.5 million in maintenance and contractor expenses on certain of the refined product pipelines resulting from fewer repair projects in 2009.

 

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Asphalt and Fuels Marketing

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

 

   

an increase of $6.7 million from our asphalt operations mainly due to higher volumes sold and a slightly higher gross margin per barrel of $6.37 compared to $6.22. The gross margin per barrel for 2008 includes the negative impact of a $61.0 million hedging loss; and

 

   

a decrease of $3.0 million related to our fuels marketing operations mainly due to higher hedging losses, which were partially offset by increased volumes from entering new markets and increased bunker fuel sales.

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

 

   

an increase of $35.8 million mainly due to a full year of expenses related to the acquisition of our asphalt operations, which occurred in March 2008, the amortization of deferred maintenance costs, higher idle capacity costs and increased asphalt terminal rentals;

 

   

an increase of $5.9 million related to increased tug and barge costs associated with new vessels being received at our St. Eustatius facility throughout 2008 and 2009 and the addition of bunkering activities at certain domestic terminals; and

 

   

an increase of $4.4 million due to increased storage costs resulting from additional tank rentals.

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

Consolidation and Intersegment Eliminations

Revenue, cost of product sales and operating expense eliminations primarily relate to storage and transportation fees charged to the asphalt and fuels marketing segment by the transportation and storage segments. In 2009, the asphalt and fuels marketing segment utilized more terminal capacity from our storage segment, resulting in higher revenue and operating expense eliminations.

General

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

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

Other income, net consisted of the following:

 

     

Year Ended December 31,

     

2009

   

2008

     (Thousands of Dollars)

Gain from sale or disposition of assets

   $      21,320      $      26,456

Gain from insurance proceeds

      9,382         3,504

Foreign exchange (losses) gains

      (5,118      5,888

Other

      6,275         1,891
                

Other income, net

   $      31,859      $      37,739
                

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

 

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Year Ended December 31, 2008 Compared to Year Ended December 31, 2007

Financial Highlights

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

 

       

Year Ended December 31,

        

Change

 
       

2008

       

2007

      

Statement of Income Data:

            

Revenues:

            

Service revenue

  $   740,630      $   696,623      $    44,007   

Product sales

    4,088,140        778,391         3,309,749   
                        

Total revenues

    4,828,770        1,475,014         3,353,756   
                        

Costs and expenses:

            

Cost of product sales

    3,864,310        742,972         3,121,338   

Operating expenses

    442,248        357,235         85,013   

General and administrative expenses

    76,430        67,915         8,515   

Depreciation and amortization expense

    135,709        114,293         21,416   
                        

Total costs and expenses

    4,518,697        1,282,415         3,236,282   
                        

Operating income

    310,073        192,599         117,474   

Equity earnings from joint ventures

    8,030        6,833         1,197   

Interest expense, net

    (90,818     (76,516      (14,302

Other income , net

    37,739        38,830         (1,091
                        

Income before income tax expense

    265,024        161,746         103,278   

Income tax expense

    11,006        11,448         (442
                        

Net income

  $   254,018      $   150,298      $    103,720   
                        

Net income per unit applicable to limited partners

  $   4.22      $   2.73      $    1.49   
                        

Weighted average limited partner units outstanding

    53,182,741        47,158,790         6,023,951   
                        

Annual Highlights

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

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

 

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Segment Operating Highlights

(Thousands of Dollars, Except Barrel/Day Information)

 

   

Year Ended December 31,

       
   

2008

   

2007

   

Change

 

Storage:

           

Throughput (barrels/day)(a)

    742,599        800,332        (57,733

Throughput revenues

  $     90,918      $     96,372      $     (5,454

Storage lease revenues

    363,171        314,255        48,916   
                       

Total revenues

    454,089        410,627        43,462   

Operating expenses

    246,304        233,675        12,629   

Depreciation and amortization expense

    66,706        62,317        4,389   
                       

Segment operating income

  $     141,079      $     114,635      $     26,444   
                       

Transportation:

           

Refined products pipelines throughput (barrels/day)

    673,687        678,573        (4,886

Crude oil pipelines throughput (barrels/day)

    392,110        377,640        14,470   
                       

Total throughput (barrels/day)

    1,065,797        1,056,213        9,584   

Throughput revenues

  $     317,778      $     296,796      $     20,982   

Operating expenses

    131,943        120,342        11,601   

Depreciation and amortization expense

    50,749        49,946        803   
                       

Segment operating income

  $     135,086      $     126,508      $     8,578   
                       

Asphalt and Fuels Marketing:

           

Product sales

  $     4,088,169      $     778,391      $     3,309,778   

Cost of product sales

    3,880,796        750,120        3,130,676   

Operating expenses

    80,133        6,737        73,396   

Depreciation and amortization expense

    14,734        423        14,311   
                       

Segment operating income

  $     112,506      $     21,111      $     91,395   
                       

Consolidation and Intersegment Eliminations:

           

Revenues

  $     (31,266   $     (10,800   $     (20,466

Cost of product sales

    (16,486     (7,148     (9,338

Operating expenses

    (16,132     (3,519     (12,613
                       

Total

  $     1,352      $     (133   $     1,485   
                       

Consolidated Information:

           

Revenues

  $     4,828,770      $     1,475,014      $     3,353,756   

Cost of product sales

    3,864,310        742,972        3,121,338   

Operating expenses

    442,248        357,235        85,013   

Depreciation and amortization expense

    132,189        112,686        19,503   
                       

Segment operating income

    390,023        262,121        127,902   

General and administrative expenses

    76,430        67,915        8,515   

Other depreciation and amortization expense

    3,520        1,607        1,913   
                       

Consolidated operating income

  $     310,073      $     192,599      $     117,474   
                       

 

(a) Excludes throughputs related to storage lease revenues.

 

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Storage

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

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

 

   

an increase of $20.7 million due to completed tank expansion projects at our St. Eustatius, Amsterdam, St. James, Vancouver, Portland and Jacksonville terminals;

 

   

an increase of $9.9 million mainly due to increased throughput and new customer contracts at our UK terminal facilities, increased throughputs and product handling revenues at our Amsterdam facility, as well as the effect of foreign exchange rates at our UK and Amsterdam facilities;

 

   

an increase of $9.4 million due to a change in our Corpus Christi (North Beach) crude oil storage tank agreement from a throughput fee agreement to a storage lease agreement effective January 1, 2008;

 

   

an increase of $2.8 million due to our acquisition of the Wilmington asphalt terminal; and

 

   

an increase of $2.7 million at our Point Tupper facility due to increased throughputs, handling charges, reimbursable revenues and dock activity.

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

 

   

higher salaries and wages of $4.0 million resulting primarily from increased headcount and foreign currency fluctuations;

 

   

increased power costs of $3.3 million mainly due to increased fuel consumption at our St. Eustatius and Pt. Tupper facilities, increased costs at our Amsterdam facility and our acquisition of the Wilmington asphalt terminal;

 

   

increased costs of $2.9 million primarily at our Texas City terminal related to Hurricane Ike, which made landfall in September 2008; and

 

   

an increase of $2.5 million in environmental expense related to an ongoing investigation at one of our refined product terminals.

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

Transportation

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

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

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

 

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Asphalt and Fuels Marketing

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

 

   

an increase of $2,496.3 million and $2,347.5 million in sales and cost of product sales, respectively, from our acquisition of the East Coast Asphalt Operations in March 2008. Cost of product sales for the year ended December 31, 2008 includes the $61.0 million hedging loss discussed in the Annual Highlights above;

 

   

an increase of $585.7 million and $576.0 million in sales and cost of product sales, respectively, associated with our fuels marketing operations that began in the second quarter of 2007; and

 

   

an increase of $233.0 million and $210.8 million for sales and cost of product sales, respectively, associated with our bunker fuel operations due to an increase in the market price per metric ton at our St. Eustatius facility and increased sales at our Point Tupper facility, which resumed the sale of bunker fuel in the second quarter of 2008. Cost of sales includes a hedge gain of $28.1 million primarily associated with bunker fuel sales at our Point Tupper facility.

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

 

   

an increase of $58.3 million from our acquisition of the East Coast Asphalt Operations in March 2008; and

 

   

an increase of $13.9 million related to marine expenses mainly due to increased tug and barge rental costs as agreements for new tugs and barges at St. Eustatius were effective January 1, 2008.

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

General

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

Other depreciation and amortization expense relates to corporate assets.

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

Other income, net consisted of the following:

 

    

Year Ended December 31,

     
    

2008

  

2007

   
     (Thousands of Dollars)    

Sale of interest in Skelly-Belvieu

   $      18,867    $      -     

Sale or disposal of fixed assets

      7,589       7,869     

Business interruption insurance

      3,504       12,492     

2007 Services Agreement termination fee

      -       13,000     

Legal settlements

      -       5,758     

Foreign exchange gains (losses)

      5,888       (6,261  

Other

      1,891       5,972     
                   

Other income, net

   $      37,739    $      38,830     
                   

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

 

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OUTLOOK

Overall, we expect our results for 2010 to improve compared to 2009. However, the outlook on our operations could change depending on the pace of the economic recovery and other economic conditions.

Transportation Segment

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

Storage Segment

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

Asphalt and Fuels Marketing Segment

The earnings of the asphalt and fuels marketing segment largely depend upon the margin earned by our asphalt operations. Our margin results from the difference between the sales prices of our products and the purchase prices of our raw materials, principally crude oil. The prices of crude oil and the products produced by our asphalt operations fluctuate in response to many factors, such as changes in supply, demand, seasonality, market uncertainties and other factors.

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

LIQUIDITY AND CAPITAL RESOURCES

General

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

 

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

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

 

    

Year Ended December 31,

 
    

2009

   

2008

   

2007

 
     (Thousands of Dollars)  

Net cash provided by (used in):

               

Operating activities

   $      180,582      $      485,181      $      222,672   

Investing activities

      (167,705      (956,517      (238,396

Financing activities

      (2,672      440,063         37,060   

Effect of foreign exchange rate changes on cash

      6,426         (13,190      (336
                           

Net increase (decrease) in cash and cash equivalents

   $      16,631      $      (44,463   $      21,000   
                           

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

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

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

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

 

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2007 Revolving Credit Agreement

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

The 2007 Revolving Credit Agreement requires that we maintain certain financial ratios and includes other restrictive covenants, including a prohibition on distributions if any defaults, as defined in the agreements, exist or would result from the distribution. The 2007 Revolving Credit Agreement requires us to maintain, as of the end of each four consecutive fiscal quarters, a consolidated debt coverage ratio (consolidated indebtedness to consolidated EBITDA, as defined in the 2007 Revolving Credit Agreement) not to exceed 5.00-to-1.00, which may restrict the amount we can borrow without exceeding the maximum allowed limit to an amount less than the total amount available for borrowing. As of December 31, 2009, the consolidated debt coverage ratio was 4.1x.

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

Shelf Registration Statement

Our shelf registration statement on Form S-3 permits us to offer and sell various types of securities, including NuStar Energy L.P. common units and debt securities of NuStar Logistics and NuPOP, having an aggregate value of up to $3.0 billion (the 2007 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, 2009, we have issued approximately $1.0 billion under our $3.0 billion shelf registration statement.

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

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

Capital Requirements

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

 

   

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

 

   

strategic capital expenditures, such as those to expand and upgrade pipeline capacity or asphalt refinery operations and to construct new pipelines, terminals and storage tanks. In addition, strategic capital expenditures may include acquisitions of pipelines, terminals or storage tank assets, as well as certain capital expenditures related to support functions.

During the year ended December 31, 2009, we incurred reliability capital expenditures of $45.0 million, primarily related to maintenance upgrade projects at our terminals and pipelines. Strategic capital expenditures for the year ended December 31, 2009 of $163.6 million primarily related to a pipeline expansion on the southern end of the East Pipeline and projects at our Texas City terminal.

 

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For 2010, we expect to incur approximately $375.0 to $400.0 million of capital expenditures, including approximately $55.0 to $60.0 million for reliability capital projects and $320.0 to $340.0 million for strategic capital expenditures. We continue to evaluate our capital budget and make changes as economic conditions warrant. Depending upon current economic conditions, our actual capital expenditures for 2010 may exceed or be lower than the budgeted amounts. We believe cash generated from operations, combined with other sources of liquidity previously described, will be sufficient to fund our capital expenditures in 2010, and our internal growth projects can be accelerated or scaled back depending on the capital markets.

Working Capital Requirements

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

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

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

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.”

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,

   

2009

 

2008

 

2007

    (Thousands of Dollars, Except Per Unit Data)

General partner interest

  $     5,430   $     5,058   $     4,092

General partner incentive distribution

    28,712     25,294     18,426
                 

Total general partner distribution

    34,142     30,352     22,518

Limited partners’ distribution

    237,308     222,470     182,076
                 

Total cash distributions

  $     271,450   $     252,822   $     204,594
                 

Cash distributions per unit applicable to limited partners

  $     4.245   $     4.085   $     3.835
                 

 

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

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

Long-Term Debt Obligations

We are a party to the following long-term debt agreements:

 

   

the 2007 Revolving Credit Agreement due December 10, 2012, with a balance of $525.1 million as of December 31, 2009;

 

   

NuStar Logistics’ 6.875% senior notes due July 15, 2012 with a face value of $100.0 million, 6.05% senior notes due March 15, 2013 with a face value of $229.9 million and 7.65% senior notes due April 15, 2018 with a face value of $350.0 million;

 

   

NuPOP’s 7.75% senior notes due February 15, 2012 and 5.875% senior notes due June 1, 2013 with an aggregate face value of $500.0 million;

 

   

the $56.2 million revenue bonds due June 1, 2038 associated with the St. James terminal expansion (Gulf Opportunity Zone Revenue Bonds);

 

   

the £21 million term loan due December 11, 2012 (UK Term Loan); and

 

   

the $12.0 million note payable in annual installments through December 31, 2015 to the Port of Corpus Christi Authority of Nueces County, Texas, with a balance of $3.5 million as of December 31, 2009, associated with the construction of a crude oil storage facility in Corpus Christi, Texas (Port Authority of Corpus Christi Note Payable).

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

Credit Ratings

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

 

     Standard &
Poor’s
   Moody’s    Fitch

Outlook

   Stable    Stable    Stable

Ratings

   BBB-    Baa3    BBB-

Interest Rate Swaps

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

The interest rate swap contracts qualify for the shortcut method of accounting. 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, 2009 and 2008, the weighted average effective interest rate for the interest rate swaps was 2.3% and 3.0%, respectively.

 

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Line of Credit

As of December 31, 2009, we had one short-term line of credit with an uncommitted borrowing capacity of up to $20.0 million. Please refer to Note 11 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for a more detailed discussion on our line of credit.

Long-Term Contractual Obligations

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

 

    

Payments Due by Period

         
    

2010

  

2011

  

2012

  

2013

  

2014

  

There-
after

  

Total

     (Thousands of Dollars)

Long-term debt maturities

   $ 770    $ 832    $ 909,942    $ 480,902    $ 67    $   406,200    $ 1,798,713

Interest payments

     89,804      89,742      79,501      41,597      27,220      100,150      428,014

Operating leases

     51,734      60,808      44,415      41,453      37,760      187,638      423,808

Purchase obligations:

                    

Crude oil

     1,943,668      1,943,668      1,943,668      1,943,668      1,943,670      485,917      10,204,259

Other purchase obligations

     23,561      18,329      2,197      1,036      744      -      45,867

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

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

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

Our crude oil purchase obligations result from a crude supply agreement (CSA) we entered into simultaneously with the acquisition of the East Coast Asphalt Operations. Under the CSA, we committed to purchase an annual average of 75,000 barrels per day of crude oil over a minimum seven-year period from PDVSA. The value of this commitment fluctuates according to a market-based pricing formula using published market indices, subject to adjustment based on the price of Mexican Maya crude. We estimated the annual payments due under the CSA based on market prices as of December 31, 2009.

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 more stringent environmental and safety laws and regulations are continuously being enacted or proposed, the level of future expenditures required for environmental, health and safety matters is expected to increase.

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

 

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Contingencies

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

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. We reimburse NuStar GP, LLC for all costs related to its employees, other than costs associated with NuStar GP Holdings under the services agreement described below and in Note 16 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data.” We had a payable of $10.6 million and $3.4 million, as of December 31, 2009 and 2008, respectively, with both amounts representing payroll and benefit plan costs, net of payments made by us. We also had a long-term payable as of December 31, 2009 and 2008 of $7.7 million and $6.6 million, respectively, related to amounts for retiree medical benefits and other post-employment benefits.

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

 

    

Year Ended December 31,

     
    

2009

  

2008

  

2007

  
     (Thousands of Dollars)   

Operating expenses

   $   124,827    $   115,291    $   93,211   

General and administrative expenses

     58,878      44,988      37,702   

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

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

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. The goodwill impairment test is performed for each reporting unit to which goodwill has been allocated, consisting of the following:

 

   

crude oil pipelines;

 

   

refined product pipelines;

 

   

refined product terminals, excluding our St. Eustatius and Point Tupper facilities;

 

   

St. Eustatius and Point Tupper terminal operations;

 

   

bunkering activity at our St. Eustatius and Point Tupper facilities; and

 

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asphalt operations.

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.

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

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

Environmental 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. Due to the inherent uncertainty of litigation, actual amounts paid may differ from amounts estimated, and such differences will be charged to income in the period when final determination is made.

 

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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Interest Rate Risk

We manage our debt by considering various financing alternatives available in the market and we manage our exposure to changing interest rates principally through the use of a combination of fixed-rate debt and variable-rate debt. In addition, we utilize 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.

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, 2009
       

Expected Maturity Dates

       

Total

       

Fair
Value

       

2010

       

2011

       

2012

       

2013

       

2014

       

There-

after

         
        (Thousands of Dollars, Except Interest Rates)

Long-term Debt:

                               

Fixed rate

  $     770      $     832      $     384,816      $     480,902      $     67      $     350,000      $     1,217,387      $     1,306,301

Average interest rate

    8.0     8.0     7.4     6.0     8.0     7.7     6.9    

Variable rate

  $     -      $     -      $     525,126      $     -      $     -      $     56,200      $     581,326      $     551,072

Average interest rate

    -        -        1.0     -        -        0.2     0.9    

Interest Rate Swaps Fixed to Variable:

                               

Notional amount

  $     -      $     -      $     60,000      $     107,500      $     -      $     -      $     167,500      $     8,623

Average pay rate

    3.4     4.8     5.8     5.6     -        -        4.3    

Average receive rate

    6.3     6.3     6.3     6.1     -        -        6.3    
        December 31, 2008
       

Expected Maturity Dates

       

Total

       

Fair
Value

       

2009

       

2010

       

2011

       

2012

       

2013

       

There-

after

         
        (Thousands of Dollars, Except Interest Rates)

Long-term Debt:

                               

Fixed rate

  $     713      $     770      $     832      $     381,647      $     480,902      $     350,627      $     1,215,491      $     1,157,470

Average interest rate

    8.0     8.0     8.0     7.4     6.0     7.7     6.9    

Variable rate

  $     -      $     -      $     -      $     555,294      $     -      $     56,200      $     611,494      $     611,494

Average interest rate

    -        -        -        1.9     -        0.9     1.8    

Interest Rate Swaps Fixed to Variable:

                               

Notional amount

  $     -      $     -      $     -      $     60,000      $     107,500      $     -      $     167,500      $     15,284

Average pay rate

    3.2     3.9     4.3     4.5     4.3     -        4.0    

Average receive rate

    6.3     6.3     6.3     6.3     6.1     -        6.3    

 

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Commodity Price Risk

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

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

The following tables provide information about our derivative instruments, the fair value of which will fluctuate with changes in commodity prices:

 

     December 31, 2009    
    

Contract
Volumes

  

Weighted Average

  

Fair Value of
Current
Asset (Liability)

 
     

Pay Price

  

Receive Price

    
     (Thousands
of Barrels)
             (Thousands of
Dollars)
 

Fair Value Hedges:

               

Futures – short:

               

(refined products)

   1,184          N/A    $ 79.89      $ (9,528    

Cash Flow Hedges:

               

Futures – short:

               

(refined products)

   230          N/A    $ 94.13        (240    

Economic Hedges:

               

Futures – long:

               

(crude oil and refined products)

   454        $ 81.46      N/A        2,327       

Futures – short:

               

(crude oil and refined products)

   745          N/A    $ 72.90        (10,692    

Swaps – long:

               

(crude oil and refined products)

   200        $ 70.34      N/A        398       

Swaps – short:

               

(crude oil and refined products)

   600          N/A    $ 70.16        (1,316    
                     

Total fair value of open positions exposed to commodity price risk

            $ (19,051    
                     

 

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     December 31, 2008
    

Contract
Volumes

  

Weighted Average

  

Fair Value of
Current
Asset (Liability)

     

Pay Price

  

Receive Price

  
     (Thousands
of Barrels)
             (Thousands of
Dollars)

Fair Value Hedges:

             

Futures – short:

             

(refined products)

   445          N/A    $ 43.88      $ (2,370  

Economic Hedges:

             

Futures – long:

             

(crude oil and refined products)

   119        $ 39.92      N/A        654     

Futures – short:

             

(crude oil and refined products)

   754          N/A    $ 48.95        (3,131  
                   

Total fair value of open positions exposed to commodity price risk

            $ (4,847  
                   

 

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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, 2009. In its evaluation, management used the criteria set forth by the Committee of Sponsoring Organization of the Treadway Commission (COSO) in Internal Control-Integrated Framework. Based on this assessment, management believes that, as of December 31, 2009, our internal control over financial reporting was effective based on those criteria.

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

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

 

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

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

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

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

/s/ KPMG LLP

San Antonio, Texas

February 26, 2010

 

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

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

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

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

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

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

/s/ KPMG LLP

San Antonio, Texas

February 26, 2010

 

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NUSTAR ENERGY L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Thousands of Dollars, Except Unit Data)

 

   

December 31,

 
   

2009

   

2008

 
Assets        

Current assets:

       

Cash and cash equivalents

  $     62,006      $     45,375   

Accounts receivable, net of allowance for doubtful accounts of $1,351 and $1,174 as of December 31, 2009 and 2008, respectively

    211,797        178,216   

Inventories

    377,230        220,574   

Other current assets

    83,686        42,321   
               

Total current assets

    734,719        486,486   
               

Property, plant and equipment, at cost

    3,721,904        3,507,573   

Accumulated depreciation and amortization

    (693,708     (565,749
               

Property, plant and equipment, net

    3,028,196        2,941,824   

Intangible assets, net

    44,127        51,704   

Goodwill

    807,742        806,330   

Investment in joint ventures

    68,728        68,813   

Deferred income tax asset

    13,893        12,427   

Other long-term assets, net

    77,268        92,013   
               

Total assets

  $     4,774,673      $     4,459,597   
               
Liabilities and Partners’ Equity        

Current liabilities:

       

Current portion of long-term debt

  $     770      $     713   

Accounts payable

    205,605        145,963   

Payable to related party

    10,639        3,441   

Notes payable

    20,000        22,120   

Accrued interest payable

    21,529        22,496   

Accrued liabilities

    64,651        37,454   

Taxes other than income tax

    15,534        15,333   

Income tax payable

    26        4,504   
               

Total current liabilities

    338,754        252,024   
               

Long-term debt, less current portion

    1,828,993        1,872,015   

Long-term payable to related party

    7,663        6,645   

Deferred income tax liability

    26,909        27,370   

Other long-term liabilities

    87,386        94,546   

Commitments and contingencies (Note 13)

       

Partners’ equity:

       

Limited partners (60,210,549 and 54,460,549 common units outstanding as of December 31, 2009 and 2008, respectively)

    2,423,689        2,173,462   

General partner

    53,469        47,801   

Accumulated other comprehensive income (loss)

    7,810        (14,266
               

Total partners’ equity

    2,484,968        2,206,997   
               

Total liabilities and partners’ equity

  $     4,774,673      $     4,459,597   
               

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,

 
        

2009

        

2008

        

2007

 

Revenues:

              

Services revenues

  $      745,349      $