SEC Filing | NuStar Energy L.P.

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Form 10-K

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, 2008

[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF

THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from _______________________ to __________________________

Commission File Number 1-16417

NUSTAR ENERGY L.P.

(Exact name of registrant as specified in its charter)


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

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

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

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

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

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.

Yes [X] No [ ]

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

Yes [ ] No [X]

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

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-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 $2,097 million based on the last sales price quoted as of June 30, 2008, the last business day of the registrant’s most recently completed second quarter.

The number of common units outstanding as of February 1, 2009 was 54,460,549.

TABLE OF CONTENTS


PART I
Items 1., 1A. & 2.	Business, Risk Factors and Properties	3
	Recent Developments	4
	Organizational Structure	4
	Segments	6
	Employees	19
	Rate Regulation	20
	Environmental and Safety Regulation	20
	Risk Factors	24
	Properties	33

Item 1B.	Unresolved Staff Comments	34

Item 3.	Legal Proceedings	34

Item 4.	Submission of Matters to a Vote of Security Holders	35

PART II
Item 5.	Market for Registrant’s Common Units, Related Unitholder Matters and Issuer Purchases of Common Units	36

Item 6.	Selected Financial Data	37

Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	38

Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	58

Item 8.	Financial Statements and Supplementary Data	61

Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	111

Item 9A.	Controls and Procedures	111

Item 9B.	Other Information	111

PART III
Item 10.	Directors and Executive Officers of the Registrant	112

Item 11.	Executive Compensation	115

Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters	150

Item 13.	Certain Relationships and Related Transactions and Director Independence	152

Item 14.	Principal Accountant Fees and Services	155

PART IV
Item 15.	Exhibits and Financial Statement Schedules	157

Signatures		166

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 38 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, 2008, our assets included:

•

58 refined product terminal facilities providing approximately 61.2 million barrels of storage capacity and one crude oil terminal facility providing 4.8 million barrels of storage capacity;

•

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

•

5,679 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 4.7 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.

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

On April 4, 2008, NuStar Logistics issued $350.0 million of 7.65% senior notes for net proceeds of $346.2 million. The net proceeds were used to repay a portion of the outstanding principal balance under our revolving credit agreement.

On December 1, 2008, we agreed to dispose of our interest in the Skelly-Belvieu Pipeline Company, LLC, which owns a liquefied petroleum gas pipeline in Texas, for $36.0 million to Enterprise Products Operating LLC.

ORGANIZATIONAL STRUCTURE

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

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

The following chart depicts our organizational structure at December 31, 2008.

LOGO

SEGMENTS

Beginning in the second quarter of 2008, we revised the manner in which we internally evaluate our segment performance and made certain organizational changes. As a result, we have changed the way we report our segmental results. All product sales and related costs, including those associated with the East Coast Asphalt Operations, are included in the asphalt and fuels marketing segment. Also, the refined product terminals and crude oil storage tanks segments have been combined into the storage segment and the refined products pipelines and crude oil pipelines have been combined into the transportation segment. Previous periods have been restated to conform to this presentation.

Detailed financial information about our segments is included in Note 24 in the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data.”

The following map depicts our operations at December 31, 2008.

LOGO

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, 2008, we owned and operated:

•

49 terminals in the United States, with a total storage capacity of approximately 36.3 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 9.3 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 Netherlands Antilles island of St. Eustatius, which is located at a point of minimal deviation from major shipping routes. This facility is capable of handling a wide range of petroleum products, including crude oil and refined products, and it can accommodate the world’s largest tankers for loading and discharging crude oil and other petroleum products. A two-berth jetty, a two-berth monopile with platform and buoy systems, a floating hose station and an offshore single point mooring buoy with loading and unloading capabilities serve the terminal’s customers’ vessels. The St. Eustatius facility has a total of 58 tanks. The fuel oil and petroleum product facilities have in-tank and in-line blending capabilities, while the crude tanks have tank-to-tank blending capability 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.

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.

St. James, Louisiana. Our St. James terminal has 21 crude oil storage tanks with a total capacity of approximately 4.8 million barrels. Additionally, the facility has a rail-loading facility and three docks with barge and ship access. The facility is located on approximately 220 acres of land on the west bank of the Mississippi River approximately 60 miles west of New Orleans and has an additional 675 acres of undeveloped land.

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
Linden, NJ (a)	3,957,000	24	Petroleum products
St. James, LA	4,807,000	21	Crude oil and feedstocks
Selby, CA	2,829,000	22	Petroleum products, ethanol
Jacksonville, FL	2,505,000	34	Petroleum products, asphalt
Texas City, TX	2,736,000	103	Chemicals, petrochemicals, petroleum products

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	802,000	33	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	729,000	15	Petroleum products, ethanol
Indianapolis, IN	366,000	18	Petroleum products
Andrews AFB, MD (b)	72,000	3	Petroleum products
Baltimore, MD	825,000	49	Chemicals, asphalt
Salisbury, MD	177,000	14	Petroleum products
Wilmington, NC	206,000	8	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	352,000	11	Petroleum products
Edinburg, TX	267,000	6	Petroleum products
El Paso, TX (c)	343,000	12	Petroleum products
Harlingen, TX	315,000	7	Petroleum products
Houston, TX (Hobby Airport)	106,000	4	Petroleum products
Houston, TX	90,000	6	Asphalt
Laredo, TX	320,000	7	Petroleum products
Placedo, TX	97,000	4	Petroleum products
San Antonio (east), TX	148,000	5	Petroleum products
San Antonio (south), TX	215,000	5	Petroleum products
Southlake, TX	575,000	12	Petroleum products, ethanol
Texas City, TX	125,000	10	Petroleum products


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

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	36,313,000	756


Foreign Terminals:
St. Eustatius, Netherlands Antilles	12,996,000	58	Petroleum products, crude oil
Point Tupper, Canada	7,364,000	37	Petroleum products, crude oil
Grays, England	1,945,000	53	Petroleum products
Eastham, England	2,185,000	162	Chemicals, petroleum products, animal fats
Runcorn, England	146,000	4	Molten sulfur
Grangemouth, Scotland	530,000	46	Petroleum products, chemicals and molasses
Glasgow, Scotland	344,000	16	Petroleum products
Belfast, Northern Ireland	407,000	41	Petroleum products
Amsterdam, the Netherlands	3,713,000	42	Petroleum products
Nuevo Laredo, Mexico	34,000	5	Petroleum products

Total Foreign Terminals	29,664,000	464

(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.

During 2008, we sold four of our refined product terminals in Westwego, Louisiana, Tucson, Arizona, Milwaukee, Wisconsin and Reno, Nevada with an aggregate storage capacity of approximately 1.3 million barrels for total proceeds of approximately $9.9 million.

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’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.

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 26% of the total revenues of the segment for the year ended December 31, 2008. No other customer accounted for more than 10% of the revenues of the segment for this period. Our crude oil transshipment customers include an oil producer that leases and utilizes 5.0 million barrels of storage at St. Eustatius and a major international oil company that leases and utilizes 3.6 million barrels of storage at Point Tupper, both of which have long-term contracts with us. In addition, two different international oil companies each lease and utilize more than 1.0 million barrels of clean products storage at St. Eustatius and Point Tupper. Also, in Canada, a consortium consisting of major oil companies sends natural gas liquids via pipeline to certain processing facilities on land leased from us. After processing, certain products are stored at the Point Tupper facility under a long-term contract. In addition, our blending capabilities 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 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. Please read the disclosure contained

in Note 18 of Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for additional information regarding agreements with Valero Energy.

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 5,679 miles. In addition, we own a 2,000 mile anhydrous ammonia pipeline located in Louisiana, Arkansas, Missouri, Illinois, Indiana, Iowa and Nebraska. As of December 31, 2008, we owned and operated:

•

25 refined product pipelines with an aggregate length of 3,339 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 1,900-mile refined product pipeline originating in southern Kansas and terminating at Jamestown, North Dakota, with a western extension to North Platte, Nebraska and an eastern extension into Iowa (the East Pipeline);

•

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

•

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

As of December 31, 2008, 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 (such as propane and butane), 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 164.9 million barrels for the year ended December 31, 2008.

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 Skellytown, TX	McKee	53	100%	52,000
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%	15,000
Ardmore to Wynnewood, OK (d)	Ardmore	31	100%	84,000
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 (e)	N/A	289	50%	N/A

Total		3,339		782,282

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

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

East Pipeline. The East Pipeline covers 1,900 miles and moves refined products north in pipelines ranging in size from 6 inches to 16 inches. The East Pipeline system also includes 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 to our terminals along the system and to receiving pipeline connections in Kansas. Shippers on the East Pipeline obtain refined petroleum products from refineries in southeast Kansas connected to the East Pipeline or through other pipelines directly connected to the pipeline system. The East Pipeline transported approximately 51.9 million barrels for the year ended December 31, 2008.

North Pipeline. The North Pipeline runs from west to east approximately 440 miles from its origin at the Tesoro Mandan refinery to the Minneapolis, Minnesota area. The North Pipeline crosses our East Pipeline near Jamestown, North Dakota where the two pipelines are connected. While the North Pipeline is currently supplied primarily by the Tesoro Mandan

refinery, it is capable of delivering or receiving products to or from the East Pipeline. The North Pipeline transported approximately 16.4 million barrels for the year ended December 31, 2008.

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 the tanks we own as of December 31, 2008 at each of our refined petroleum 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 1.5 million tons (or approximately 13.4 million barrels) for the year ended December 31, 2008.

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 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, Rawlings, Wyoming and Pasco, Washington, each of which supplies diesel fuel to a railroad fueling facility.

Pipeline Operations

Revenues for the refined product pipelines in the Central West System and the crude oil pipelines are based upon throughput volumes traveling through our pipelines and the related tariffs. Revenues for the East Pipeline, the North Pipeline and the Ammonia Pipeline are based on how much and how far the product is shipped and the associated tariffs.

In general, a shipper on one of our refined petroleum product pipelines delivers products to the pipeline from refineries or third-party pipelines that connect to the pipelines. Each shipper transporting product on a pipeline is required to supply us with a notice of shipment indicating sources of products and destinations. All shipments are tested or receive refinery certifications to ensure compliance with our specifications. Refined product shippers are generally invoiced by us upon delivery for the Central West System and the North and Ammonia Pipelines and upon the product entering our East Pipeline. Tariffs for transportation are charged to shippers based upon transportation from the origination point on the pipeline to the point of delivery.

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

Demand for and Sources of Refined Products

The operations of our Central West 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 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.

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

Our refined product pipelines are also dependent upon adequate levels of production of refined products by refineries connected to the pipelines, directly or through connecting pipelines. The refineries are, in turn, dependent upon adequate supplies of suitable grades of crude oil. The pipelines in the Central West System and our crude oil pipelines are connected to refineries owned by Valero Energy, and certain pipelines are subject to long-term throughput agreements with Valero Energy. Valero Energy’s 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 the Tesoro Mandan refinery, which primarily runs North Dakota crude oil (although it has the ability to run other crude oils). If operations at the Tesoro Mandan refinery were interrupted, it could have a material effect on our operations. Other than the Valero Energy refineries described above and the Tesoro Mandan refinery, if operations at any one refinery were discontinued, we believe (assuming unchanged demand for refined products in markets served by the refined product pipelines) that the effects thereof would be short-term in nature and our business would not be materially adversely affected over the long term because such discontinued production could be replaced by other refineries or other sources.

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 Refining 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 practice, 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. However, 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 51% of the total segment revenues for the year ended December 31, 2008. In addition to Valero Energy, we had a total of approximately 65 shippers for the year ended December 31, 2008, including integrated oil companies, refining companies, farm cooperatives and a railroad. No other customer accounted for greater than 11% 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.

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.

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. Certain pipelines are subject to long-term throughput agreements with 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. Please read the disclosure contained in Note 18 of Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for additional information on our agreements with Valero Energy.

The East and North Pipelines compete with an independent 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 Iowa. The competing pipeline has the same Direct Application demand and weather issues as the Ammonia Pipeline but is restricted to domestically produced anhydrous ammonia. Midwest production 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, 2008:


Facility	Production Capacity	Tank Capacity	Number of Tanks
	(Barrels Per Day)	(Barrels)
Savannah, GA	30,000	1,195,000	21
Paulsboro, NJ	74,000	3,523,000	21

Total	104,000	4,718,000	42

The following table lists the throughputs and percentages of yields for each refinery for the period from March 20, 2008, the date of acquisition, through December 31, 2008:


	Volumes	Percentage
	(barrels per day)
Savannah:
Crude oil throughput	25,092
Yields:
Asphalt	18,643	74%
Naphtha	952	4%
Light marine gas oil	5,466	22%

Paulsboro:
Crude oil throughput	55,973
Yields:
Asphalt	38,066	68%
Naphtha	1,390	3%
Marine diesel oil	9,447	17%
Vacuum gas oil	6,723	12%

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 eight asphalt terminals in the southeastern United States. These asphalt terminals 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.

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 nine asphalt terminals in the northeastern United States. These asphalt terminals 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.

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. Approximately 50% of these customers serve the private commercial sector by building residential roads, parking lots, asphalt paths and courts. The other half serves the public sector by building highways and transportation infrastructure for the various state Departments of Transportation. We also have a small number of customers who manufacture residential asphalt roofing shingles and building materials.

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

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

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

Fuels Marketing Operations

Our fuels marketing operations provide us the opportunity to generate additional 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, and offer for sale to wholesale customers through approximately 50 terminals, approximately 45% of which are owned by NuStar Energy. The remaining 55% is sold through third-party-leased facilities. The margin we generate reflects the wholesale uplift above spot market prices less terminaling 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.

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. Fuel 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 to which, or from which, each vessel travels or 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.

EMPLOYEES

Our operations are managed by NuStar GP, LLC. As of December 31, 2008, NuStar GP, LLC had 1,340 employees performing services for our U.S. operations. Certain of our wholly owned subsidiaries had 344 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 just, reasonable and nondiscriminatory.

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

Shippers may challenge tariff rates and practices on our pipelines. There are no pending challenges or complaints regarding our tariff rates. We do not currently believe that it is likely that there will be a challenge to the tariffs on our petroleum products or crude oil pipelines by a current shipper that would materially affect our revenues or cash flows. 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 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 2008, our capital expenditures attributable to compliance with environmental regulations were $4.8 million, and are currently estimated to be approximately $12.0 million for 2009 and approximately $3.5 million for 2010. The estimates for 2009 and 2010 do 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 have the impact over time of offsetting projected increases or reducing 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.

Congress is currently considering proposed legislation directed at reducing “greenhouse gas emissions.” The state of California adopted the California Global Warming Solutions Act of 2006, which requires a 25% reduction in greenhouse gas emissions by 2020. This legislation requires the California Air Resources Board to adopt regulations by 2012 that limit emissions until an overall reduction of 25% from all emission sources in California is to be achieved by 2020. Recently, the California Air Resources Board announced its intention to have a proposed draft of its greenhouse gas mandatory reporting regulation by mid-2009. New Jersey has adopted legislation addressing greenhouse gas emissions from various sources, primarily power plants. The oil and natural gas industry is a direct source of greenhouse gas emissions and future restrictions on such emissions could have an impact on our future operations. It is not possible at this time to estimate accurately how future laws or regulations to address greenhouse gas emissions would affect our business.

SOLID WASTE

We generate non-hazardous and minimal quantities of hazardous solid wastes that are subject to the requirements of the federal Resource Conservation and Recovery Act (RCRA) and analogous or more stringent state statutes. We are not currently required to comply with a substantial portion of RCRA requirements because our operations generate minimal quantities of hazardous wastes. However, it is possible that additional wastes, which could include wastes currently generated during operations, will also be designated as “hazardous wastes.” Hazardous wastes are subject to more rigorous and costly disposal requirements than are non-hazardous wastes.

HAZARDOUS SUBSTANCES

The Comprehensive Environmental Response, Compensation and Liability Act, referred to as CERCLA and also known as Superfund, and analogous or more stringent state laws, imposes liability, without regard to fault or the legality of the original act, on some classes of persons that contributed to the release of a “hazardous substance” into the environment. These persons include the owner or operator of the site and entities that disposed or arranged for the disposal of the hazardous substances found at the site. CERCLA also authorizes the Environmental Protection Agency (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.

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:

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the amount of crude oil, refined product and anhydrous ammonia transported in our pipelines;

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throughput volumes in our terminals and storage facilities;

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

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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;

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demand for crude oil, refined products and anhydrous ammonia;

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the effect of worldwide energy conservation measures;

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our operating costs;

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weather conditions;

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domestic and foreign governmental regulations and taxes; and

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prevailing economic conditions.

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

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

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the sources of cash used to fund our acquisitions;

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our capital expenditures;

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fluctuations in our working capital needs;

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issuances of debt and equity securities; and

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

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

Reduced demand for refined products, including asphalt, or anhydrous ammonia could affect our results of operations and ability to make distributions to our unitholders.

Any sustained decrease in demand for refined products, including asphalt, 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:

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

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

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a decrease in spending by federal or state governments on road paving and maintenance;

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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;

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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;

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

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the increased use of alternative fuel sources, such as battery-powered engines. Several state and federal initiatives mandate this increased use. For example, the Energy Policy Act of 1992 requires 75% of new vehicles

purchased by federal agencies since 1999, 75% of all new vehicles purchased by state governments since 2000, and 70% of all new vehicles purchased for private fleets in 2006 and thereafter to use alternative fuels.

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

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

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a material decrease in the supply of crude oil;

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

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scheduled refinery turnarounds or unscheduled refinery maintenance;

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operational problems or catastrophic events at a refinery;

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

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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;

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increasingly stringent environmental regulations; or

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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.

We may not be able to effectively integrate the East Coast Asphalt Operations.

We continue to face certain challenges as we work to integrate the asphalt operations into our business. In particular, the acquisition of the East Coast Asphalt Operations, by adding two refineries, expanded our operations, geographic scope and the types of businesses in which we engage, thereby presenting us with significant challenges as we work to manage the increase in scale resulting from the acquisition. Further, the asphalt operations may not perform in accordance with our expectations, and our expectations with regards to integration and synergies may not be fully realized. Our failure to realize the anticipated benefits of the acquisition, could adversely affect our operating and financial results.

The East Coast Asphalt Operations are dependent upon a steady supply of crude oil from PDVSA, the national oil company of Venezuela, and 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.

The terms of the acquisition of the East Coast Asphalt Operations include commitments, over a minimum seven-year period, to purchase from PDVSA an annual average of 75,000 barrels per day of crude oil and provide us with a right of first offer to purchase up to 4,000,000 barrels of paving grade asphalt and 4,750,000 barrels of roofing flux asphalt each year for marketing and sale. In December 2008, OPEC, which includes Venezuela, agreed to decrease production by 2.2 million barrels of crude oil per day and we received notice from PDVSA that it would cut two 300,000 barrel Boscán cargoes in February 2009 and two in March. To date, 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 have 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.

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

A large portion of our earnings subsequent to acquiring the East Coast 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 the East Coast 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 the East Coast Asphalt Operations is marketed to satisfy governmental contracts. The governmental agencies with which we or our customers contract may have budgetary constraints that limit their ability to absorb higher 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 to the same degree as the price of crude oil. Our increased exposure to unstable commodity prices will increase the volatility of our earnings.

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

Revenues of the East Coast Asphalt Operations result from the refining of crude oil into asphalt and other products and the sale of those products. The price and market value of crude oil and refined products is volatile. Our revenues will be adversely affected by this volatility during periods of decreasing prices because of the reduction in the value and resale price of our inventory. Future price volatility could have an adverse impact on our results of operations, cash flow and ability to make distributions to our unitholders.

Our 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 refining and marketing segment, including the East Coast Asphalt Operations, we may engage in crude oil and refined product hedges, typically exchange-traded futures contracts. While intended to reduce the effects of volatile crude oil and refined product prices, such transactions, depending on the hedging instrument used, may limit our potential gains if crude oil and refined product prices were to rise substantially over the price established by the hedge. In addition, such transactions may expose us to the risk of financial loss in certain circumstances, including instances in which:

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production is substantially less than expected;

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

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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 always 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.

The operating results for the East Coast 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 may be lower than those for the second and third calendar quarters of each year as a result of this seasonality.

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 and diminish our ability to make distributions to unitholders.

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

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

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

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

Our future financial and operating flexibility may be adversely affected by our significant leverage, the significant working capital needs associated with the East Coast Asphalt Operations, restrictions in our debt agreements and recent disruptions in the financial markets.

As of December 31, 2008, our consolidated debt was $1.9 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 & Poors and Fitch, all with a negative outlook. The negative outlook was assigned by the credit rating agencies as a result of our acquisition of the East Coast Asphalt Operations. 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 operate the East Coast Asphalt Operations. In particular, we use working capital to make purchases of crude oil and maintain necessary seasonal inventories at the East Coast 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 on commercially reasonable terms. In addition, in the event our access to capital resources is significantly reduced, we may not be able to adequately fund our working capital needs for those assets.

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 indebtedness. We believe that we are in compliance with all ratios and covenants in the 2007 Revolving Credit Agreement as of December 31, 2008.

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

As of December 31, 2008, we had $610.7 million available for borrowing under the 2007 Revolving Credit Agreement, which assumes no remaining available commitment from Lehman Brothers Bank, FSB (LB Bank), a subsidiary of Lehman Brothers Holdings Inc. (Lehman). As a result of Lehman’s bankruptcy filing, LB Bank has elected not to fund its pro rata share of any future borrowings we request, which reduces the total commitment under the 2007 Revolving Credit Agreement to approximately $1.2 billion. If other lenders under the 2007 Revolving Credit Agreement file for bankruptcy or experience severe financial hardship due to recent disruptions and steep declines in the global financial markets and generally severely tightening credit supply, they may not honor their pro rata share of our borrowing requests, 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, 2008, we had approximately $1.9 billion of consolidated debt, of which $1.1 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 may not be able to integrate effectively and efficiently with any future businesses or operations we may acquire. Any future acquisitions may substantially increase the levels of our indebtedness and contingent liabilities.

Part of our business strategy includes acquiring additional assets that complement our existing asset base and distribution capabilities or provide entry into new markets. We may not be able to identify suitable acquisitions, or we may not be able to purchase or finance any acquisitions on terms that we find acceptable. Additionally, we compete against other companies for acquisitions, and we cannot assure unitholders that we will be successful in the acquisition of any assets or businesses appropriate for our growth strategy. Our capitalization and results of operations may change significantly as a result of future acquisitions, and unitholders will not have the opportunity to evaluate the economic, financial and other relevant information that we will consider in connection with any future acquisitions. Unexpected costs or challenges may arise whenever businesses with different operations and management are combined. For example, the incurrence of

substantial unforeseen environmental and other liabilities, including liabilities arising from the operation of an acquired business or asset prior to our acquisition for which we are not indemnified or for which indemnity is inadequate, may adversely affect our ability to realize the anticipated benefit from an acquisition. Inefficiencies and difficulties may arise because of unfamiliarity with new assets and new geographic areas of any acquired businesses. Successful business combinations will require our management and other personnel to devote significant amounts of time to integrating the acquired businesses with our existing operations. These efforts may temporarily distract their attention from day-to-day business, the development or acquisition of new properties and other business opportunities. If we do not successfully integrate any past or future acquisitions, or if there is any significant delay in achieving such integration, our business and financial condition could be adversely affected.

Our 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 petroleum and 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 natural resources damages, personal injury or property damages to private parties and significant business interruption. We own or lease a number of properties that have been used to store or distribute refined products for many years. Many of these properties were operated by third parties whose handling, disposal or release of hydrocarbons and other wastes was not under our control.

If we were to incur a significant liability pursuant to environmental or safety laws or regulations, such a liability could have a material adverse effect on our financial position, our ability to make distributions to our unitholders and our ability to meet our debt service requirements. Please read Item 3. “Legal Proceedings” and Note 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 under the ICA.

Under the ICA, common carrier pipelines must maintain tariffs on file with the FERC. These tariffs include the rates we charge for providing transportation services on our common carrier pipelines as well as the rules and regulations governing these services. The ICA requires, among other things, that such rates on interstate common carrier pipelines be “just and reasonable” and nondiscriminatory.

The EPAct, among other things, deems “just and reasonable,” within the meaning of the ICA, any oil pipeline rate in effect for the 365-day period ending on the date of the enactment of EPAct if the rate in effect was not subject to protest, investigation or complaint during such 365-day period. Essentially, any such rates are “grandfathered in” by the EPAct. The EPAct further protects any rate meeting this requirement from complaint unless the complainant can show a substantial change occurred after the enactment of EPAct in the economic circumstances of the oil pipeline that were the basis or in the nature of the services provided that were bases for the rate.

The ICA permits persons with a substantial economic interest in any new tariff filing to challenge a tariff publication. The FERC will determine whether to suspend the tariff for a period of up to seven months and initiate a formal investigation. If, upon completion of an investigation, the FERC finds that the new or changed rate is unlawful, it is authorized to require the carrier to refund the revenues in excess of the prior tariff collected during the pendency of the investigation. The FERC may also investigate, upon complaint or on its own motion, rates that are already in effect and order a carrier to change its rates prospectively. Upon an appropriate showing, a shipper may obtain reparations for damages sustained during the two years prior to the filing of a complaint.

We use various FERC-authorized rate change methodologies for our interstate pipelines, including indexing, cost-of-service rates, market-based rates and settlement rates. Typically, we annually adjust our rates in accordance with FERC indexing methodology, which currently allows a pipeline to change their rates within prescribed ceiling levels that are tied to an inflation index. 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 will typically be required to reduce any rates that exceed the new maximum allowable rate. In addition, changes in the index might not be large enough to fully reflect actual increases in our costs. 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 the new policy is generally favorable for pipelines that are organized as pass-through entities, it still entails rate risk due to the case-by-case review requirement. The new tax allowance policy and the FERC’s application of that policy were appealed to the U.S. Court of Appeals for the District of Columbia Circuit (D.C. Court), and, on May 29, 2007, the D.C. Court issued an opinion upholding the FERC’s tax allowance policy. Because the extent to which an interstate oil pipeline is entitled to an income tax allowance is subject to a case-by-case review at the FERC, the level of income tax allowance to which we will ultimately be entitled is not certain. If the FERC were to disallow a substantial portion of our income tax allowance, it is possible that the maximum rates that could be charged could decrease from current levels.

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

The STB, a part of the U.S. Department of Transportation, has jurisdiction over interstate pipeline transportation and rate regulations of anhydrous ammonia. Transportation rates must be reasonable, and a pipeline carrier may not unreasonably discriminate among its shippers. If the STB finds that a carrier’s rates violate these statutory commands, it may prescribe a reasonable rate. In determining a reasonable rate, the STB will consider, among other factors, the effect of the rate on the volumes transported by that carrier, the carrier’s revenue needs and the availability of other economic transportation alternatives. The STB does not provide rate relief unless shippers lack effective competitive alternatives. If the STB determines that effective competitive alternatives are not available and we hold market power, then we may be required to show that our rates are reasonable.

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

Power costs constitute a significant portion of our operating expenses. For the year ended December 31, 2008, our power costs equaled approximately $61.9 million, or 14.0% of our operating expenses for the year. In addition, $31.3 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 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 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 an aggregate 18.5% 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;

•

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. For example, the State of New Jersey imposes a state level tax which we currently pay at the maximum amount of $250,000. Partnerships and limited liability companies, unless specifically exempted, are also subject to a state-level tax imposed on Texas source revenues. Specifically, the Texas margin tax is imposed at a maximum effective tax rate of 0.7% of our gross revenue or 1% of our gross margin that is apportioned to Texas. Imposition of any entity-level tax on us by Texas, or additional states, will reduce the cash available for distribution to our unitholders.

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

The IRS may adopt positions that differ from the positions we take, even positions taken with the advice of counsel. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take. A court

may not agree with all of the positions we take. Any contest with the IRS may materially and adversely impact the market for our units and the prices at which they trade. In addition, the costs of any contest between us and the IRS will result in a reduction in cash available for distribution to our unitholders. Moreover, the costs of any contest between us and the IRS will result in a reduction in cash available for distribution to our unitholders and thus will be borne indirectly by our unitholders and our general partner.

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

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

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

A termination would, among other things, result in the closing of our taxable year for all unitholders and would result in a deferral of depreciation and cost recovery deductions allowable in computing our taxable income. If our partnership were terminated for federal income tax purposes, a NuStar Energy unitholder would be allocated an increased amount of federal taxable income for the year in which the partnership is considered terminated and the subsequent years as a percentage of the cash distributed to the unitholder with respect to that period.

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

If a unitholder sells units, the unitholder will recognize gain or loss equal to the difference between the amount realized and that unitholder’s tax basis in those units. Prior distributions to the unitholder in excess of the total net taxable income the unitholder was allocated for a unit, which decreased the tax basis in that unit, will, in effect, become taxable income to the unitholder if the unit is sold at a price greater than the tax basis in that unit, even if the price the unitholder receives is less than the original cost. A substantial portion of the amount realized, whether or not representing gain, may be ordinary income to the selling unitholder.

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

Investment in units by tax-exempt entities, such as individual retirement accounts (known as IRAs) and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to organizations exempt from federal income tax, including individual retirement accounts and other retirement plans, will be unrelated business taxable income and will be taxable to them. Distributions to non-U.S. persons will be reduced by withholding taxes at the highest applicable effective tax rate, and non-U.S. persons will be required to file U.S. federal income tax returns and pay tax on their share of our taxable income.

We will treat each purchaser of our units as having the same tax benefits without regard to the units purchased. The IRS may challenge this treatment, which could adversely affect the value of our units.

Because we cannot match transferors and transferees of units, we will adopt depreciation and amortization positions that may not conform to all aspects of existing Treasury regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to unitholders. It also could affect the timing of these tax benefits or the amount of gain from any sale of units and could have a negative impact on the value of our units or result in audit adjustments to a unitholder’s tax returns.

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

In addition to federal income taxes, unitholders will likely be subject to other taxes, such as state and local income taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by various jurisdictions in which we do business or own property. Unitholders will likely be required to file state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions. Further, unitholders may be subject to penalties for failure to comply with those requirements. We may own property or conduct business in other states or foreign countries in the future. It is each unitholder’s responsibility to file all federal, state or local tax returns.

We have adopted certain valuation methodologies that may result in a shift of income, gain, loss and deduction between the general partner and the unitholders. The IRS may challenge this treatment, which could adversely affect the value of our common units.

When we issue additional units or engage in certain other transactions, we determine the fair market value of our assets and allocate any unrealized gain or loss attributable to our assets to the capital accounts of our unitholders and our general partner. Our methodology may be viewed as understating the value of our assets. In that case, there may be a shift of income, gain, loss and deduction between certain unitholders and the general partner, which may be unfavorable to such unitholders. Moreover, under our current valuation methods, subsequent purchasers of common units may have a greater portion of their Internal Revenue Code Section 743(b) adjustment allocated to our tangible assets and a lesser portion allocated to our intangible assets. The IRS may challenge our valuation methods, our methods, allocation of the Section 743(b) adjustment attributable to our tangible and intangible assets, and allocations of income, gain, loss and deduction between the general partner and certain of our unitholders.

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

PROPERTIES

Our principal properties are described above under the caption “Segments,” and that information is incorporated herein by reference. We believe that we have satisfactory title to all of our assets. Although title to these properties is subject to encumbrances in some cases, such as customary interests generally retained in connection with acquisition of real property, liens related to environmental liabilities associated with historical operations, liens for current taxes and other burdens and easements, restrictions and other encumbrances to which the underlying properties were subject at the time of acquisition by us or our predecessors, we believe that none of these burdens will materially detract from the value of these properties or from our interest in these properties or will materially interfere with their use in the operation of our business. In addition, we believe that we have obtained sufficient right-of-way grants and permits from public authorities and private parties for us to operate our business in all material respects as described in this report. We perform scheduled maintenance on all of our 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.

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. We have sought relief from the bankruptcy stay in order to pursue our appellate rights.

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.

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 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. CARCO has demanded that NuStar Asphalt and NuStar Marketing defend and indemnify it against Eres’ claims and has filed a lawsuit in the Harris County District Court, Harris County, Texas, seeking to recover on its indemnity claim. This lawsuit has been removed and is currently pending in the U.S. District Court for the Southern District of Texas. In connection with the demand for arbitration, Eres filed a complaint in the U.S. District Court for the Southern District of New York (SDNY) seeking to require the Defendants to arbitrate the dispute and seeking to attach the banking funds of CARCO and NuStar Asphalt (including cash, escrow funds, credits, debts, wire transfers, electronic funds transfers, accounts, letters of credit, freights and charter hire) within the SDNY in amounts of approximately $78.1 million pending resolution of arbitration between Eres and the Defendants. To date, no funds of NuStar Asphalt have been attached. We intend to vigorously defend against these claims.

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 December 2005, the U.S. Department of Transportation, Office of Pipeline Safety (OPS) proposed penalties totaling $255,000 based on alleged violations of various pipeline safety requirements in the McKee System. We are currently in settlement negotiations with OPS to resolve this matter.

In November 2006, agents of the U.S. Environmental Protection Agency (the EPA) presented a search warrant issued by a U.S. District Court at one of our terminals. Since then, we have been served with additional subpoenas. The search warrant and subpoenas all sought information regarding allegations of potential illegal conduct by us, certain of our subsidiaries and/or our employees concerning compliance with certain environmental and safety laws and regulations. We have cooperated fully with the U.S. Attorney and the EPA in producing documents in response to the subpoenas. Although the U.S. Attorney has indicated that they intend to seek criminal penalties and fines as a result of alleged violations of environmental laws at the terminal, we are currently in negotiations with the U.S. Attorney and the EPA to resolve this matter. There can be no assurances that the conclusion of the U.S. Attorney’s and the EPA’s investigation will not result in a determination that we violated applicable laws. If we are found to have violated such laws, we could be subject to fines, civil penalties and criminal penalties. A final determination that we violated applicable laws could, among other things, result in our debarment from future federal government contracts.

In February 2008, the DOJ advised us that the EPA has requested that the DOJ initiate a lawsuit against us 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.

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.

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, 2008.

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, 2009, we had 857 holders of record of our common units. The high and low sales prices (composite transactions) by quarter for the years ended December 31, 2008 and 2007 were as follows:


	Price Range of Common Unit
	High		Low
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

Year 2007
4th Quarter	$	63.89	$	51.80
3rd Quarter		70.09		52.31
2nd Quarter		71.50		61.83
1st Quarter		68.00		54.11

The cash distributions applicable to each of the quarters in the years ended December 31, 2008 and 2007 were as follows:


	Record Date	Payment Date	Amount Per Unit
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

Year 2007
4th Quarter	February 7, 2008	February 14, 2008	$	0.9850
3rd Quarter	November 8, 2007	November 14, 2007		0.9850
2nd Quarter	August 7, 2007	August 14, 2007		0.9500
1st Quarter	May 7, 2007	May 14, 2007		0.9150

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, 2008 and 2007 totaled $25.3 million and $18.4 million, respectively. The general partner’s share of our distributions for the years ended December 31, 2008 and 2007 was 12.0% and 11.0%, respectively, due to the impact of the incentive distributions.

ITEM 6. SELECTED FINANCIAL DATA

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


	Year Ended December 31,
	2008 (a)		2007		2006		2005 (b)		2004
	(Thousands of Dollars, Except Per Unit Data)
Statement of Income Data:
Revenues	$	4,828,770	$	1,475,014	$	1,137,261	$	659,557	$	220,792
Operating income		310,073		192,599		212,899		152,952		97,268
Income from continuing operations		254,018		150,298		149,906		107,675		78,418
Income from continuing operations per unit applicable to limited partners (c)		4.22		2.74		2.84		2.76		3.15
Cash distributions per unit applicable to limited partners		4.085		3.835		3.600		3.365		3.20


	December 31,
	2008 (a)		2007		2006		2005 (b)		2004
	(Thousands of Dollars)
Balance Sheet Data:
Property, plant and equipment, net	$	2,941,824	$	2,492,086	$	2,345,135	$	2,160,213	$	784,999
Total assets		4,459,597		3,783,087		3,494,208		3,366,992		857,507
Long-term debt (less current portion)		1,872,015		1,445,626		1,353,720		1,169,659		384,171
Partners’ equity		2,206,997		1,994,832		1,875,681		1,900,779		438,311

(a)	The significant increase in revenues, operating income, income from continuing operations and balance sheet data are primarily due to our acquisition of the East Coast Asphalt Operations.

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

(c)

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

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 a 20.5% total interest in us. 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

•

Critical Accounting Policies

Recent Developments

On March 20, 2008, we acquired CITGO Asphalt Refining Company’s asphalt operations and assets (the East Coast Asphalt Operations) for approximately $838.5 million. The East Coast Asphalt Operations include a 74,000 barrels-per-day (BPD) asphalt refinery in Paulsboro, New Jersey, a 30,000 BPD asphalt refinery in Savannah, Georgia and three asphalt terminals. The facilities located in Paulsboro, New Jersey, Savannah, Georgia and Wilmington, North Carolina have storage capacities of 3.5 million barrels, 1.2 million barrels and 0.2 million barrels, respectively. We funded the acquisition with proceeds from our common unit offerings in November 2007 and April 2008, related contributions from our general partner to maintain its 2% interest, proceeds from our issuance of $350.0 million of senior notes and borrowings under our revolving credit agreement. See Liquidity and Capital Resources below for a discussion of our common unit offerings, issuance of senior notes and our revolving credit agreement.

On December 1, 2008, we agreed to dispose of our interest in the Skelly-Belvieu Pipeline Company, LLC, which owns a liquefied petroleum gas pipeline in Texas, to Enterprise Products Operating LLC. We received proceeds of $36.0 million and recognized a gain of $18.9 million on this sale.

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)

Storage. We own refined product terminals in the United States, the Netherland Antilles, Canada, Mexico, the Netherlands and the United Kingdom providing approximately 61.2 million barrels of storage capacity and one crude oil storage facility providing approximately 4.8 million barrels of storage capacity. We also own 60 crude oil and intermediate feedstock storage tanks and related assets that store and deliver crude oil and intermediate feedstocks to Valero Energy’s refineries in Benicia, California, Corpus Christi, Texas and Texas City, 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 5,679 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. 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.

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

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.

RESULTS OF OPERATIONS

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,
	2008			2007			Change
Statement of Income Data:
Revenues:
Service revenues	$	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
Less net income applicable to general partner		(29,350	)		(21,063	)		(8,287	)

Net income applicable to limited partners	$	224,668		$	129,235		$	95,433

Net income per unit applicable to limited partners	$	4.22		$	2.74		$	1.48

Weighted average number of basic 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 $126.0 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 product 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. Currently, we do not have any derivative contracts related to inventories of the East Coast Asphalt Operations, and we manage our commodity risk by managing those physical inventory volumes. We continue to monitor our exposure to commodity prices and may, if conditions warrant, hedge the inventories of the East Coast Asphalt Operations in the future.

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	)
Depreciation and amortization expense		3,520			1,607			1,913

Total	$	(2,168	)	$	(1,740	)	$	(428	)

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		135,709			114,293			21,416

Segment operating income		386,503			260,514			125,989
General and administrative expenses		76,430			67,915			8,515

Consolidated operating income	$	310,073		$	192,599		$	117,474

(a)	Excludes throughputs related to storage lease revenues.

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 more product was exported by one of our customers instead of shipped 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.

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.

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. Depreciation and amortization expense relates to corporate assets.

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.

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

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

Financial Highlights

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


	Year Ended December 31,						Change
	2007			2006			Change
Statement of Income Data:
Revenues:
Service revenue	$	696,623		$	636,154		$	60,469
Product sales		778,391			501,107			277,284

Total revenues		1,475,014			1,137,261			337,753

Costs and expenses:
Cost of product sales		742,972			466,276			276,696
Operating expenses		357,235			312,604			44,631
General and administrative expenses		67,915			45,216			22,699
Depreciation and amortization expense		114,293			100,266			14,027

Total costs and expenses		1,282,415			924,362			358,053


Operating income		192,599			212,899			(20,300	)
Equity earnings from joint ventures		6,833			5,882			951
Interest expense, net		(76,516	)		(66,266	)		(10,250	)
Other income (expense), net		38,830			3,252			35,578

Income from continuing operations before income tax expense		161,746			155,767			5,979
Income tax expense		11,448			5,861			5,587

Income from continuing operations		150,298			149,906			392

Income (loss) from discontinued operations, net of income tax		-			(376	)		376


Net income		150,298			149,530			768
Less net income applicable to the general partner		(21,063	)		(16,910	)		(4,153	)

Net income applicable to limited partners	$	129,235		$	132,620		$	(3,385	)


Net income (loss) per unit applicable to limited partners:
Continuing operations	$	2.74		$	2.84		$	(0.10	)
Discontinued operations		-			(0.01	)		0.01

Net income	$	2.74		$	2.83		$	(0.09	)


Weighted average number of basic and diluted units outstanding		47,158,790			46,809,749			349,041

Annual Highlights

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

Total segment operating income increased $2.4 million for the year ended December 31, 2007, compared to the year ended December 31, 2006, primarily due to a $6.1 million increase in operating income for the storage segment and a $3.8 million increase in operating income for the transportation segment, partially offset by a $5.8 million decrease in operating income for the asphalt and fuels marketing segment.

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

Segment Operating Highlights

(Thousands of Dollars, Except Barrel/Day Information)


	Year Ended December 31,						Change
	2007			2006			Change
Storage:
Throughput (barrels/day)(a)		800,332			774,743			25,589
Throughput revenues	$	96,372		$	97,179		$	(807	)
Storage lease revenues		314,255			266,234			48,021

Total revenues		410,627			363,413			47,214
Operating expenses		233,675			201,806			31,869
Depreciation and amortization expense		62,317			53,121			9,196

Segment operating income	$	114,635		$	108,486		$	6,149


Transportation:
Refined products pipelines throughput (barrels/day)		678,573			711,476			(32,903	)
Crude oil pipelines throughput (barrels/day)		377,640			421,666			(44,026	)

Total throughput (barrels/day)		1,056,213			1,133,142			(76,929	)
Throughput revenues	$	296,796		$	281,010		$	15,786
Operating expenses		120,342			111,151			9,191
Depreciation and amortization expense		49,946			47,145			2,801

Segment operating income	$	126,508		$	122,714		$	3,794


Asphalt and Fuels Marketing:
Product sales	$	778,391		$	501,107		$	277,284
Cost of product sales		750,120			471,576			278,544
Operating expenses		6,737			2,616			4,121
Depreciation and amortization expense		423			-			423

Segment operating income	$	21,111		$	26,915		$	(5,804	)


Consolidation and Intersegment Eliminations:
Revenues	$	(10,800	)	$	(8,269	)	$	(2,531	)
Cost of product sales		(7,148	)		(5,300	)		(1,848	)
Operating expenses		(3,519	)		(2,969	)		(550	)
Depreciation and amortization expense		1,607			-			1,607

Total	$	(1,740	)	$	-		$	(1,740	)


Consolidated Information:
Revenues	$	1,475,014		$	1,137,261		$	337,753
Cost of product sales		742,972			466,276			276,696
Operating expenses		357,235			312,604			44,631
Depreciation and amortization expense		114,293			100,266			14,027

Segment operating income		260,514			258,115			2,399
General and administrative expenses		67,915			45,216			22,699

Consolidated operating income	$	192,599		$	212,899		$	(20,300	)

(a)	Excludes throughputs related to storage lease revenues.

Storage

Throughputs increased 25,589 barrels per day for the year ended December 31, 2007, compared to the year ended December 31, 2006, primarily due to a change in the Corpus Christi (North Beach) crude oil storage tank agreement from a storage lease to a throughput fee agreement effective January 1, 2007. Throughputs for the Corpus Christi (North Beach) crude oil storage tanks were not reported prior to January 1, 2007. This increase was partially offset by decreased throughputs related to terminals serving the McKee refinery. In spite of the increased throughputs, throughput revenues decreased by $0.8 million for the year ended December 31, 2007, compared to the year ended December 31, 2006, primarily due to lower revenues at our terminals serving the McKee refinery and turnarounds and operating issues at the refineries served by our crude oil storage tanks.

Storage lease revenues increased by $48.0 million for the year ended December 31, 2007, compared to the year ended December 31, 2006, primarily due to:

•

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

•

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

•

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

Operating expenses increased $31.9 million for the year ended December 31, 2007, compared to the year ended December 31, 2006, primarily due to higher reimbursable project expenses. Reimbursable project expenses are charged back to our customers, and its increase is consistent with the increase in reimbursable project revenues. Operating expenses also increased due to higher maintenance and regulatory expenses, higher salaries and wages, the acquisition of the St. James terminal in December 2006, and higher marine expenses due to increased vessel calls at St. Eustatius and Point Tupper.

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

Transportation

Throughputs decreased 76,929 barrels per day for the year ended December 31, 2007, compared to the year ended December 31, 2006, primarily due to the impact of the McKee refinery fire, offset by increased throughputs on the East Pipeline, Ammonia Pipeline and Burgos Pipeline. Despite lower overall throughputs, revenues increased by $15.8 million for the year ended December 31, 2007, compared to the year ended December 31, 2006, primarily due to:

•

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

•

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

•

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

•

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

Operating expenses increased $9.2 million for the year ended December 31, 2007, compared to the year ended December 31, 2006, primarily due to higher maintenance and environmental costs and higher internal overhead costs mainly due to increased headcount. These increases were partially offset by decreased power costs due to downtime from the McKee refinery fire.

Depreciation and amortization expense increased $2.8 million for the year ended December 31, 2007, compared to the year ended December 31, 2006, mainly due to increased amortization of deferred costs in connection with the throughput deficiency payments discussed above. In addition, depreciation and amortization expense increased due to the completion of various capital projects.

Asphalt and Fuels Marketing

Sales and cost of product sales increased $277.3 million and $278.5 million, respectively, during the year ended December 31, 2007, compared to the year ended December 31, 2006, mainly due to:

•

an increase of $115.4 million and $121.3 million in sales and cost of product sales, respectively, associated with certain marketing operations that began in the second quarter of 2007. For the year ended December 31, 2007, cost of product sales includes $7.5 million related to the change in fair value of certain derivative instruments; and

•

an increase of $171.5 million and $159.8 million for sales and cost of sales, respectively, associated with our bunker fuel operations primarily due to increased vessel calls at our St. Eustatius facility, partially offset by a decrease in bunker fuel sales of $10.9 million at our Point Tupper facility due to decreased vessel calls.

Operating expenses increased by $4.1 million for the year ended December 31, 2007, compared to the year ended December 31, 2006, primarily due to salaries and wages and terminal storage fees relating to the marketing operations that began in 2007.

General

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

•

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

•

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

•

increased professional fees primarily related to external legal costs; and

•

increased rent expense related to our new headquarters.

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

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

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

OUTLOOK

Transportation Segment

For the first quarter of 2009, we expect a heavy planned refinery maintenance schedule, primarily at the Valero Energy refineries we serve, to negatively affect our pipeline throughputs. Revenues generated from our pipelines depend upon the amount of throughputs. When refineries undergo maintenance, generally they also curtail production, which lowers throughputs for crude oil and refined products causing our throughputs and revenues to decline. For the full year of 2009, we expect a lighter refinery maintenance schedule, additional shippers and the completion of a pipeline expansion project will offset the effects of the recession and the weak first quarter described above. Thus, barring any major unplanned turnaround activity, we expect overall pipeline throughputs in 2009 to be comparable to 2008. Additionally, we expect to increase the tariffs on our pipelines effective July 1, 2009, which should have a positive effect on our revenues and results of operations.

Storage Segment

For the first quarter of 2009, we expect our terminal throughputs to decline due to heavy planned refinery maintenance primarily at the Valero Energy refineries we serve. Several of the assets included in the storage segment store crude oil and refined products for refineries owned by Valero Energy. Revenues for these assets depend upon throughputs rather than fixed rental fees, so when the refineries undergo maintenance our throughputs and related revenues decline. However, we do not expect these lower throughputs to significantly impact our revenues or results of operations for the full year of 2009 because most of our revenues result from long-term storage lease contracts, which are not throughput dependent. Of our storage lease contracts, approximately 70% have remaining terms between one and ten years. For the 30% of our storage contracts expiring within the next year, we believe we can renew these contracts at similar or better terms provided the present contango markets continue to drive demand for storage. Additionally, we expect our revenues and results of operations for 2009 to benefit from annual index increases to storage fee rates on most of our multi-year contracts and a full year’s contribution of key terminal expansion projects completed in 2008 and 2009.

Asphalt and Fuels Marketing Segment

The earnings of the asphalt and fuels marketing segment largely depend upon the margin earned by the East Coast 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 the East Coast Asphalt Operations fluctuate in response to many factors, such as changes in supply, demand, seasonality, market uncertainties and other factors.

In the first quarter of 2009, we expect our asphalt sales and margins to remain low due to typical seasonal factors including decreased road construction during colder months. For the full year of 2009, we expect our results to be higher than 2008. Last year asphalt demand remained below 2007 levels; however, lower supply resulting from fewer imports and reduced domestic production more than offset the effects of lower demand and resulted in higher prices and higher margins. We expect many of the same factors present in 2008 that contributed positively to our results of operations to continue in 2009. Additionally, on February 17, 2009, The American Recovery and Reinvestment Act of 2009 was signed into law, which includes funding for transportation infrastructure that could increase asphalt demand in 2009 and beyond. Longer term, we believe additional refinery coker expansions will continue to tighten asphalt markets resulting in better-than-historic margins.

In recent months, the Organization of the Petroleum Exporting Countries announced its intention to reduce crude oil production in response to dramatically lower demand for refined products. As a result, we received notice in January 2009 that our scheduled deliveries of Boscan crude oil would be reduced by 600,000 barrels in February and March from the amounts specified in our crude supply agreement with an affiliate of Petroleos de Venezuela S.A (PDVSA). To date, we have replaced the volumes lost from PDVSA with alternative grades of crude oil purchased on the spot market. We have not received notification of any further supply reductions from PDVSA. If the supply reductions extend beyond March at their current levels, we believe we can continue to replace that supply with other asphaltic crudes without a material impact to our results of operations. However, in the event PDVSA further reduces the deliveries of Boscan crude oil, we may experience reduced refinery run rates and reduced production that could negatively impact our results of operations and our cash flows.

Overall, we expect our results for the full year of 2009 to improve compared to 2008. However, depending on the severity and duration of this recession, or other adverse economic conditions, our operations could be negatively impacted.

LIQUIDITY AND CAPITAL RESOURCES

General

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

volatility of the capital and credit markets could affect our cost of capital and ability to access the capital and credit markets.

Cash Flows for the Years Ended December 31, 2008, 2007 and 2006

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


	Year Ended December 31,
	2008			2007			2006
	(Thousands of Dollars)
Net cash provided by (used in):
Operating activities	$	485,181		$	222,672		$	250,811
Investing activities		(956,517	)		(238,396	)		(213,234	)
Financing activities		440,063			37,060			(3,899	)
Effect of foreign exchange rate changes on cash		(13,190	)		(336	)		(894	)

Net increase in cash and cash equivalents	$	(44,463	)	$	21,000		$	32,784

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 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, primarily due to the operations of the asphalt and fuels marketing segment. We obtained inventory with our acquisition of the East Coast Asphalt Operations, and the inventory balance declined with the seasonality of the asphalt operations. However, an increase in accounts receivable of $52.4 million, also primarily related to the asphalt and fuels marketing segment, partially offset the inventory decrease. 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 $222.7 million compared to $250.8 million for the year ended December 31, 2006 primarily due changes in working capital accounts. Working capital increased $21.3 million in 2007 providing a decrease in cash, whereas working capital decreased $10.7 million in 2006. Within working capital, accounts receivable and inventory increased by $22.1 million and $71.5 million, respectively, compared to 2006 primarily due to the operations of the asphalt and fuels marketing segment, particularly an increase in inventory associated with marketing of asphalt, gasoline and distillates which began in 2007. Offsetting the increases in inventory and accounts receivable was an increase in accounts payable of $72.9 million, also primarily related to the marketing of asphalt, gasoline and distillates. Cash flows from operations for the year ended December 31, 2007 also includes proceeds from business interruption insurance of $12.5 million.

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

2007 Revolving Credit Agreement

Our five-year revolving credit agreement (the 2007 Revolving Credit Agreement) is diversified with 24 participating banks. However, the participating banks 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 we had $17.0 million outstanding as of December 31, 2008. As a result of Lehman’s bankruptcy filing, LB Bank has elected not to fund its pro rata share of any future borrowings we request, which reduces the total commitment under the 2007 Revolving Credit Agreement to

approximately $1.2 billion. Excluding LB Bank’s participation, we had $610.7 million available for borrowing under the 2007 Revolving Credit Agreement as of December 31, 2008. If other lenders under the 2007 Revolving Credit Agreement file for bankruptcy or experience severe financial hardship due to recent disruptions and steep declines in the global financial markets and generally severely tightening credit supply, they may not honor their pro rata share of our borrowing requests.

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, 2008, we had $2.3 billion available under our $3.0 billion shelf registration statement.

If the volatility of the capital markets continues, 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.

NuStar Logistics’ 7.65% Senior Notes. On April 4, 2008, NuStar Logistics issued $350.0 million of 7.65% senior notes under our $3.0 billion shelf registration statement for net proceeds of $346.2 million. The net proceeds were used to repay a portion of the outstanding principal balance under our 2007 Revolving Credit Agreement, which was used to fund our acquisition of the East Coast Asphalt Operations. Please refer to Note 13 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for a more detailed discussion of 7.65% senior note offering.

Equity Offerings. In April 2008, we issued 5,050,800 common units representing limited partner interests at a price of $48.75 per unit. We received net proceeds of $236.2 million and a contribution of $5.0 million from our general partner to maintain its 2% general partner interest. The proceeds were used to repay the $124.0 million balance under our then-active term loan agreement and a portion of the outstanding principal balance under our 2007 Revolving Credit Agreement. See Notes Payable below for discussion on our term loan agreement.

On November 19, 2007, we issued 2,600,000 common units representing limited partner interests at a price of $57.20 per unit. We received net proceeds of $143.1 million and a contribution of $3.0 million from our general partner to maintain its 2% general partner interest. The proceeds were used to repay a portion of the outstanding principal balance under our then-active $600 million 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 and other 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.

During the year ended December 31, 2008, we incurred reliability capital expenditures of $55.7 million, primarily related to maintenance upgrade projects at our terminals and pipelines. Strategic and other capital expenditures for the year ended December 31, 2008 of $146.5 million primarily related to the Amsterdam, St. James, Texas City and Jacksonville tank expansions and other terminal expansion projects.

For 2009, we budgeted approximately $147.0 million of capital expenditures, including approximately $67.0 million for reliability capital projects and $80.0 million for strategic projects, which is lower than 2008 in light of the current economic environment and capital market conditions. We continue to evaluate our capital budget and make changes as

economic conditions warrant. If conditions warrant, our actual capital expenditures for 2009 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 2009, and our internal growth projects can be accelerated or scaled back depending on the capital markets.

Working Capital Requirements

The asphalt and fuels marketing segment requires us to make substantial investments in inventory. Increases in commodity prices could cause our working capital requirements to increase, which could affect our liquidity. Our working capital requirements will vary with the seasonal nature of asphalt demand as we build and store inventories during periods of lower demand in order to sell it during periods of higher demand. This seasonal nature of demand will also affect the accounts receivable and accounts payable balances, which will vary depending on timing of payments.

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,
	2008		2007		2006
	(Thousands of Dollars, Except Per Unit Data)
General partner interest	$	5,058	$	4,092	$	3,742
General partner incentive distribution		25,294		18,426		14,778

Total general partner distribution		30,352		22,518		18,520
Limited partners’ distribution		222,470		182,076		168,515

Total cash distributions	$	252,822	$	204,594	$	187,035

Cash distributions per unit applicable to limited partners	$	4.085	$	3.835	$	3.600

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 2009, we declared a quarterly cash distribution of $1.0575 that was paid on February 12, 2009 to unitholders of record on February 5, 2009. This distribution related to the fourth quarter of 2008 and totaled $65.8 million, of which $8.2 million represented the general partner’s share of such distribution. The general partner’s distribution included a $6.9 million incentive distribution.

Long-Term Debt Obligations

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

•

NuStar Logistics’ 7.65% senior notes due April 15, 2018 with a face value of $350.0 million, 6.05% senior notes due March 15, 2013 with a face value of $229.9 million and 6.875% senior notes due July 15, 2012 with a face value of $100.0 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 2007 Revolving Credit Agreement due December 10, 2012;

•

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

•

the $56.2 million revenue bonds due June 1, 2038 associated with the St. James terminal expansion (Gulf Opportunity Zone Revenue Bonds); 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 associated with the construction of a crude oil storage facility in Corpus Christi, Texas (Port Authority of Corpus Christi Note Payable).

Please refer to Note 13 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.

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, 2008 and 2007, the aggregate fair value of our interest rate swaps included in “Other long-term assets, net” in our consolidated balance sheets was $15.3 million and $2.2 million, respectively.

The interest rate swap contracts qualify for the shortcut method of accounting prescribed by SFAS 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended (SFAS 133). As a result, changes in the fair value of the swaps will completely offset the changes in the fair value of the underlying hedged debt. As of December 31, 2008 and 2007, the weighted average effective interest rate for the interest rate swaps was 3.0% and 6.1%, respectively.

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, 2008:


	Standard & Poor’s	Moody’s	Fitch
Outlook	Negative	Negative	Negative (a)
NuStar Logistics, L.P	BBB-	Baa3	BBB-
NuStar Pipeline Operating Partnership L.P	BBB-	Baa3	BBB-

(a)

On February 20, 2009, Fitch revised its outlook to stable from negative.

Notes Payable

Term Loan Agreement. In March 2008, we closed on a $124.0 million term loan agreement (the Term Loan Agreement), all of which was used to fund a portion of our acquisition of the East Coast Asphalt Operations. The $124.0 million balance on the Term Loan Agreement was paid in full in April 2008 with the proceeds from our equity offering (see Equity Offerings section above).

Lines of Credit. As of December 31, 2008, we had one short-term line of credit with an uncommitted borrowing capacity of up to $20.0 million. Please refer to Note 12 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for a more detailed discussion on our short-term debt agreements.

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, 2008:


	Payments Due by Period										Thereafter		Total
	2009		2010		2011		2012		2013		Thereafter		Total
	(Thousands of Dollars)
Long-term debt maturities	$	713	$	770	$	832	$	936,941	$	480,902	$	406,827	$	1,826,985
Interest payments		105,827		105,770		105,708		94,611		42,596		151,764		606,276
Operating leases		40,151		30,970		27,428		23,853		21,008		153,403		296,813
Purchase obligations:
Crude oil		901,995		901,995		901,995		901,995		901,995		1,127,494		5,637,469
Other purchase obligations		64,224		20,521		16,520		1,398		962		743		104,368

We have long-term debt obligations and interest payments due under our senior notes, our 2007 Revolving Credit Agreement, our UK Term Loan, our Gulf Opportunity Zone Revenue Bonds and our Port of Corpus Christi Note Payable. Amounts in the table represent our scheduled future maturities of long-term debt principal for the periods indicated. The interest payment calculated for our 2007 Revolving Credit Agreement is based on the outstanding borrowings as of December 31, 2008 and the weighted-average interest rate paid for the year ended December 31, 2008.

Our operating leases consist primarily of leases for tug and barges utilized at our St. Eustatius facility, leases related to our acquisition of the East Coast Asphalt Operations for storage capacity at third-party terminals and land leases at terminal facilities. We are a party to a ten-year lease commitment of approximately $89.0 million for tugs and barges to be utilized at our St. Eustatius facility.

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 value of the crude oil purchase obligation based on market prices as of December 31, 2008.

We have other purchase obligations mainly related to the purchase of petroleum products for resale to our customers.

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 18 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data”. We had a payable of $3.4 million and a receivable of $0.8 million, as of December 31, 2008 and 2007, 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, 2008 and 2007 of $6.6 million and $5.7 million, respectively, to NuStar GP, LLC related to amounts payable for retiree medical benefits and other post-employment benefits.

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

The following table summarizes information pertaining to related party transactions with NuStar GP, LLC for the years ended December 31, 2008 and 2007 and with Valero Energy for the year ended December 31, 2006:


	Year Ended December 31,
	2008		2007		2006
	(Thousands of Dollars)
Revenues	$	-	$	-	$	260,980
Operating expenses		115,291		93,211		94,587
General and administrative expenses		44,988		37,702		32,183

Agreements with NuStar GP Holdings

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 18 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.

Agreements with Valero Energy

We are a party to a number of agreements with Valero Energy, which was a related party during 2006, that govern the required services provided to and received from Valero Energy. Most of the operating agreements include adjustment provisions, which allow us to increase the handling, storage and throughput fees we charge to Valero Energy based on a consumer price index. In addition, we review our pipeline tariffs, which are adjusted annually based on an inflation index and may also be adjusted to take into consideration additional costs incurred to provide the transportation services. Please refer to Note 18 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for a more detailed discussion of agreements with Valero Energy.

Services Agreement. Prior to our separation from Valero Energy, the employees of NuStar GP, LLC were provided to us under the terms of various services agreements between us and Valero Energy. Although Valero Energy no longer provided employees to work directly on our behalf, Valero Energy continued to provide certain services to us under the terms of a services agreement dated December 22, 2006 (the 2007 Services Agreement). On April 16, 2007, Valero Energy exercised its option to terminate the 2007 Services Agreement and paid us a termination fee of $13.0 million in May 2007 in accordance with the terms of the 2007 Services Agreement.

Omnibus Agreement. On March 31, 2006, we entered into an amended and restated omnibus agreement (the 2006 Omnibus Agreement) with Valero Energy, NuStar GP, LLC, Riverwalk Logistics, L.P. and NuStar Logistics. The 2006 Omnibus Agreement governed potential competition between Valero Energy and us until the closing of NuStar GP Holdings’ second offering on December 2, 2006, when Valero Energy ceased to own 20% or more of us, and Valero Energy agreed to indemnify us for certain environmental liabilities.

Operating Agreements. The following are the primary operating agreements with Valero Energy:

•

Crude Oil Storage Tank Agreements relating to the Corpus Christi West, Texas City and Benicia refineries;

•

South Texas Pipelines and Terminals Agreements related to certain pipelines and terminals acquired from Valero Energy in March 2003; and

•

St. James Terminalling Agreement.

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

The balance of and changes in our accruals for environmental matters as of and for the years ended December 31, 2008 and 2007 are included in Note 14 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.

Contingencies

We are subject to certain loss contingencies, the outcome of which could have an adverse effect on our cash flows and results of operations, as further disclosed in Note 15 of the Notes to Consolidated Financial Statements.

CRITICAL ACCOUNTING POLICIES

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

Depreciation

We calculate depreciation expense using the straight-line method over the estimated useful lives of our property, plant and equipment. Because of the expected long useful lives of the 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 the 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.

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 respect to certain of our assets due to various legal obligations to clean and/or dispose of those assets at the time they are retired. However, these assets can be used for extended and indeterminate period of time as long as they are properly maintained and/or upgraded. It is our practice and current intent to maintain

our assets and continue making improvements to those assets based on technological advances. As a result, we believe that our assets have indeterminate lives for purposes of estimating asset retirement obligations because dates or ranges of dates upon which we would retire these assets cannot reasonably be estimated at this time. When a date or range of dates can reasonably be estimated for the retirement of any asset, we estimate the cost of performing the retirement activities and record a liability for the fair value of that cost using established present value techniques.

We also have legal obligations in the form of leases and right-of-way agreements, which require us to remove certain of our assets upon termination of the agreement. However, these lease or right-of-way agreements generally contain automatic renewal provisions that extend our rights indefinitely or we have other legal means available to extend our rights. We have recorded a liability of approximately $0.6 million and $0.8 million as of December 31, 2008 and 2007, respectively, 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.

Derivative Financial Instruments

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

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

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

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

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Interest Rate Risk

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

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, 2008
	Expected Maturity Dates
	2009		2010		2011		2012		2013		Thereafter		Total		Fair Value
	(Thousands of Dollars, Except Interest Rates)
Long-term Debt:
Fixed rate	$	713	$	770	$	832	$	381,647	$	480,902	$	350,627	$	1,215,491	$	1,157,470
Average interest rate		8.0%		8.0%		8.0%		7.4%		6.0%		7.7%		6.9%
Variable rate	$	-	$	-	$	-	$	555,294	$	-	$	56,200		611,494	$	611,494
Average interest rate		-		-		-		1.9%		-		0.9%		1.8%

Interest Rate Swaps Fixed to Variable:
Notional amount	$	-	$	-	$	-	$	60,000	$	107,500	$	-	$	167,500	$	15,284
Average pay rate		3.2%		3.9%		4.3%		4.5%		4.3%		-		4.0%
Average receive rate		6.3%		6.3%		6.3%		6.3%		6.1%		-		6.3%

	December 31, 2007
	Expected Maturity Dates
	2008		2009		2010		2011		2012		Thereafter		Total		Fair Value
	(Thousands of Dollars, Except Interest Rates)
Long-term Debt:
Fixed rate	$	663	$	713	$	770	$	832	$	392,527	$	482,163	$	877,668	$	927,234
Average interest rate		8.0%		8.0%		8.0%		8.0%		7.4%		6.0%		6.6%
Variable rate	$	-	$	-	$	-	$	-	$	527,976	$	-		527,976	$	527,976
Average interest rate		-		-		-		-		5.7%		-		5.7%

Interest Rate Swaps Fixed to Variable:
Notional amount	$	-	$	-	$	-	$	-	$	60,000	$	107,500	$	167,500	$	2,232
Average pay rate		5.3%		5.6%		6.1%		6.4%		6.7%		6.5%		6.1%
Average receive rate		6.3%		6.3%		6.3%		6.3%		6.3%		6.1%		6.3%

Commodity Price Risk

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

We have a risk management committee that oversees our trading controls and procedures and certain aspects of commodity and trading risk management. Our risk management committee also approves all new commodity and trading risk management strategies in accordance with our Risk Management Policy, as approved by our board of directors.

Derivative instruments designated and qualifying as fair value hedges under FASB Statement No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended (Statement No. 133) (Fair Value Hedges) are recorded in the consolidated balance sheets as assets or liabilities at fair value, with related mark-to-market adjustments recorded in “Cost of product sales.” The offsetting gain or loss on the associated hedged physical inventory or firm commitment, together with the resulting hedge ineffectiveness, is recognized concurrently in “Cost of product sales.” We record derivative instruments that do not qualify for hedge accounting under Statement No. 133 (Economic Hedges) in the consolidated balance sheets as assets or liabilities at fair value with mark-to-market adjustments recorded in “Cost of product sales.” Fair value is based on quoted market prices.

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

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


	December 31, 2008
	Contract Volumes	Weighted Average				Fair Value of Current Asset (Liability)
	Contract Volumes	Pay Price		Receive Price		Fair Value of Current Asset (Liability)
	(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						$ (4,847	)


	December 31, 2007
	Contract Volumes	Weighted Average				Fair Value of Current Asset (Liability)
	Contract Volumes	Pay Price		Receive Price		Fair Value of Current Asset (Liability)
	(Thousands of Barrels)					(Thousands of Dollars)
Fair Value Hedges:
Futures – long:
(refined products)	68	$	104.26		N/A	$ 460
Futures – short:
(refined products)	287		N/A	$	103.78	(1,942	)

Economic Hedges:
Futures – long:
(refined products)	60	$	104.44		N/A	392
Futures – short:
(crude oil and refined products)	459		N/A	$	99.01	(3,001	)


Total fair value of open positions						$ (4,091	)

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, 2008. 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, 2008, 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, 2008 has been audited by KPMG, the independent registered public accounting firm who audited our consolidated financial statements included in this Form 10-K. KPMG’s attestation on the effectiveness of our internal control over financial reporting appears on page 63.

Report of Independent Registered Public Accounting Firm

The Board of Directors of NuStar GP, LLC

and Unitholders of NuStar Energy L.P.:

We have audited the accompanying consolidated balance sheets of NuStar Energy L.P. and subsidiaries (a Delaware limited partnership) (the Partnership) as of December 31, 2008 and 2007, 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, 2008. 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, 2008 and 2007, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2008, 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, 2008, 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 27, 2009 expressed an unqualified opinion on the effectiveness of the Partnership’s internal control over financial reporting.



				/s/ KPMG LLP
San Antonio, Texas February 27, 2009

Report of Independent Registered Public Accounting Firm

The Board of Directors of

NuStar GP, LLC and Unitholders of NuStar Energy L.P.:

We have audited NuStar Energy L.P. and subsidiaries’ (a Delaware limited partnership) (the Partnership) internal control over financial reporting as of December 31, 2008, 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, 2008, 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, 2008 and 2007, 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, 2008, and our report dated February 27, 2009 expressed an unqualified opinion on those consolidated financial statements.



				/s/ KPMG LLP
San Antonio, Texas
February 27, 2009

NUSTAR ENERGY L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Thousands of Dollars, Except Unit Data)


	December 31,
	2008			2007
Assets
Current assets:
Cash and cash equivalents	$	45,375		$	89,838
Accounts receivable, net of allowance for doubtful accounts of $1,174 and $365 as of December 31, 2008 and 2007, respectively		178,216			130,354
Receivable from related party		-			786
Inventories		220,574			88,532
Other current assets		42,321			37,624

Total current assets		486,486			347,134


Property, plant and equipment, at cost		3,507,573			2,944,116
Accumulated depreciation and amortization		(565,749	)		(452,030	)

Property, plant and equipment, net		2,941,824			2,492,086
Intangible assets, net		51,704			47,762
Goodwill		806,330			785,019
Investment in joint ventures		68,813			80,366
Deferred income tax asset		12,427			10,622
Other long-term assets, net		92,013			20,098

Total assets	$	4,459,597		$	3,783,087


Liabilities and Partners’ Equity
Current liabilities:
Current portion of long-term debt	$	713		$	663
Accounts payable		145,963			163,309
Payable to related party		3,441			-
Notes payable		22,120			-
Accrued interest payable		22,496			17,725
Accrued liabilities		37,454			47,189
Taxes other than income taxes		15,333			10,157
Income taxes payable		4,504			3,442

Total current liabilities		252,024			242,485


Long-term debt, less current portion		1,872,015			1,445,626
Long-term payable to related party		6,645			5,684
Deferred income tax liability		27,370			34,196
Other long-term liabilities		94,546			60,264
Commitments and contingencies (Note 15)

Partners’ equity:
Limited partners (54,460,549 and 49,409,749 common units outstanding as of December 31, 2008 and 2007, respectively)		2,173,462			1,926,126
General partner		47,801			41,819
Accumulated other comprehensive income		(14,266	)		26,887

Total partners’ equity		2,206,997			1,994,832

Total liabilities and partners’ equity	$	4,459,597		$	3,783,087

See Notes to Consolidated Financial Statements.

NUSTAR ENERGY L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

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


	Year Ended December 31,
	2008			2007			2006
Revenues:
Services revenues:
Third parties	$	740,630		$	696,623		$	375,174
Related party		-			-			260,980

Total services revenues		740,630			696,623			636,154
Product sales		4,088,140			778,391			501,107

Total revenues		4,828,770			1,475,014			1,137,261


Costs and expenses:
Cost of product sales		3,864,310			742,972			466,276
Operating expenses:
Third parties		326,957			264,024			218,017
Related party		115,291			93,211			94,587

Total operating expenses		442,248			357,235			312,604
General and administrative expenses:
Third parties		31,442			30,213			13,033
Related party		44,988			37,702			32,183

Total general and administrative expenses		76,430			67,915			45,216
Depreciation and amortization expense		135,709			114,293			100,266

Total costs and expenses		4,518,697			1,282,415			924,362


Operating income		310,073			192,599			212,899
Equity earnings from joint ventures		8,030			6,833			5,882
Interest expense, net		(90,818	)		(76,516	)		(66,266	)
Other income, net		37,739			38,830			3,252


Income from continuing operations before income tax expense		265,024			161,746			155,767
Income tax expense		11,006			11,448			5,861

Income from continuing operations		254,018			150,298			149,906

Loss from discontinued operations, net of income tax		-			-			(376	)


Net income		254,018			150,298			149,530
Less net income applicable to general partner		(29,350	)		(21,063	)		(16,910	)

Net income applicable to limited partners	$	224,668		$	129,235		$	132,620


Income (loss) per unit applicable to limited partners:
Continuing operations	$	4.22		$	2.74		$	2.84
Discontinued operations		-			-			(0.01	)

Net income	$	4.22		$	2.74		$	2.83


Weighted average number of basic units outstanding		53,182,741			47,158,790			46,809,749

See Notes to Consolidated Financial Statements.

NUSTAR ENERGY L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Thousands of Dollars)


	Year Ended December 31,
	2008			2007			2006
Cash Flows from Operating Activities:
Net income	$	254,018		$	150,298		$	149,530
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization expense		135,709			114,293			100,266
Amortization of debt related items		(6,447	)		(5,516	)		(5,210	)
Gain on sale or disposition of assets		(26,456	)		(8,356	)		(388	)
Provision (benefit) for deferred income taxes		37			276			(74	)
Equity earnings from joint ventures		(8,030	)		(6,833	)		(5,969	)
Distributions of equity earnings from joint ventures		2,835			544			5,155
Changes in current assets and current liabilities (Note 22)		133,017			(21,326	)		10,695
Other, net		498			(708	)		(3,194	)

Net cash provided by operating activities		485,181			222,672			250,811


Cash Flows from Investing Activities:
Reliability capital expenditures		(55,669	)		(40,333	)		(33,952	)
Strategic and other capital expenditures		(146,474	)		(210,918	)		(90,070	)
East Coast Asphalt Operations acquisition		(803,184	)		-			-
Other acquisitions		(7,027	)		-			(154,474	)
Investment in other long-term assets		-			(62	)		(10,820	)
Proceeds from sale or disposition of assets		50,813			12,667			71,396
Proceeds from insurance settlement		5,000			250			3,661
Other, net		24			-			1,025

Net cash used in investing activities		(956,517	)		(238,396	)		(213,234	)


Cash Flows from Financing Activities:
Proceeds from long-term debt borrowings		2,108,775			1,170,302			269,026
Proceeds from short-term debt borrowings		746,800			75,000			-
Proceeds from senior note offering, net of issuance costs		346,224			-			-
Long-term debt repayments		(2,025,784	)		(1,077,975	)		(83,510	)
Short-term debt repayments		(736,037	)		(82,353	)		-
Proceeds from issuance of common units, net of issuance costs		236,215			143,083			-
Contributions from general partner		5,025			3,035			575
Distributions to unitholders and general partner		(241,940	)		(197,333	)		(183,290	)
Increase (decrease) in cash book overdrafts		945			3,676			(6,305	)
Other, net		(160	)		(375	)		(395	)

Net cash provided by (used in) financing activities		440,063			37,060			(3,899	)


Effect of foreign exchange rate changes on cash		(13,190	)		(336	)		(894	)

Net (decrease) increase in cash and cash equivalents		(44,463	)		21,000			32,784
Cash and cash equivalents as of the beginning of year		89,838			68,838			36,054

Cash and cash equivalents as of the end of year	$	45,375		$	89,838		$	68,838

See Notes to Consolidated Financial Statements.

NUSTAR ENERGY L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF PARTNERS’ EQUITY

Years Ended December 31, 2008, 2007 and 2006

(Thousands of Dollars, Except Unit Data)


											General Partner			Accumulated Other Comprehensive Income (Loss)			Total Partners’ Equity
	Limited Partners
	Common					Subordinated
	Units		Amount			Units		Amount
Balance as of January 1, 2006		37,210,427	$	1,749,007		9,599,322		$	114,127		$	38,913		$	(1,268	)	$	1,900,779

Net income		-		123,180		-			9,440			16,910			-			149,530
Other comprehensive income – foreign currency translation		-		-		-			-			-			8,087			8,087

Total comprehensive income		-		123,180		-			9,440			16,910			8,087			157,617

Cash distributions to partners		-		(149,004	)	-			(16,703	)		(17,583	)		-			(183,290	)
General partner contribution		-		-		-			-			575			-			575
Conversion of subordinated units to common units on May 8, 2006		9,599,322		106,864		(9,599,322	)		(106,864	)		-			-			-

Balance as of December 31, 2006		46,809,749		1,830,047		-			-			38,815			6,819			1,875,681


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

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

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

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


Net income		-		224,668		-			-			29,350			-			254,018
Other comprehensive loss – foreign currency translation		-		-		-			-			-			(41,153	)		(41,153	)

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

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

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

See Notes to Consolidated Financial Statements.

NUSTAR ENERGY L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2008, 2007 and 2006

1. ORGANIZATION AND OPERATIONS

Organization

NuStar Energy L.P. (NuStar Energy) (NYSE: NS) is engaged in the terminalling and storage of petroleum products, the transportation of petroleum products and anhydrous ammonia and asphalt and fuels marketing. Unless otherwise indicated, the terms “NuStar Energy L.P.,” “the Partnership,” “we,” “our” and “us” are used in this report to refer to NuStar Energy L.P., to one or more of our consolidated subsidiaries or to all of them taken as a whole. NuStar GP Holdings, LLC (NuStar GP Holdings) (NYSE: NSH) wholly owns our general partner, Riverwalk Logistics, L.P., and owns a 20.5% total interest in us.

Operations

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

Storage. We own refined product terminals in the United States, the Netherland Antilles, Canada, Mexico, the Netherlands and the United Kingdom providing approximately 61.2 million barrels of storage capacity and one crude oil storage facility providing approximately 4.8 million barrels of storage capacity. Our terminals in the United States provide storage and handling services on a fee basis for petroleum products, specialty chemicals and other liquids, including one that provides storage services for crude oil and other feedstocks. We also own 60 crude oil and intermediate feedstock storage tanks and related assets that store and deliver crude oil and intermediate feedstocks to Valero Energy Corporation’s (Valero Energy) refineries in California and Texas providing 12.5 million barrels of storage capacity.

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 5,679 miles, consisting of the Central West System, the East Pipeline and the North Pipeline. The East and North Pipelines also include 21 terminals providing storage capacity of 4.6 million barrels, and the East Pipeline includes two tank farms providing storage capacity of 1.2 million barrels. In addition, we own a 2,000 mile anhydrous ammonia pipeline located in Louisiana, Arkansas, Missouri, Illinois, Indiana, Iowa and Nebraska. We also own 812 miles of crude oil pipelines in Texas, Oklahoma, Kansas, Colorado and Illinois, as well as associated crude oil storage facilities providing storage capacity of 1.9 million barrels in Texas and Oklahoma that are located along the crude oil pipelines. We charge tariffs on a per barrel basis for transporting refined products, crude oil and other feedstocks in our refined product and crude oil pipelines and on a per ton basis for transporting anhydrous ammonia in our ammonia pipeline.

Asphalt and Fuels Marketing. Our asphalt and fuels marketing segment includes our asphalt refining operations and our fuels marketing operations. We refine crude oil to produce asphalt and certain other refined products from our asphalt operations. Our asphalt operations include two asphalt refineries with a combined throughput capacity of 104,000 barrels per day and related terminal facilities. Additionally, we purchase gasoline and other refined petroleum products for resale.

The activities of the asphalt and fuels marketing segment expose us to the risk of fluctuations in commodity prices, which directly impact the results of operations for the asphalt and fuels marketing segment. We enter into derivative contracts to mitigate the effect of commodity price fluctuations.

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Consolidation

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

NUSTAR ENERGY L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Use of Estimates

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

Cash and Cash Equivalents

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

Accounts Receivable

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

Inventories

Inventories consist of crude oil and refined petroleum products. All inventories are valued at the lower of cost or market and cost is determined using the weighted-average cost method.

Property, Plant and Equipment

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

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

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

Goodwill and Intangible Assets

Goodwill represents the excess of cost of an acquired entity over the fair value of assets acqu