Form 10-K
Table of Contents

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 


FORM 10-K

 


 

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

For the fiscal year ended December 31, 2006

OR

 

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

For the transition period from              to             

Commission File Number 1-16417

 


VALERO 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.)

 

One Valero Way

San Antonio, Texas

  78249
(Address of principal executive offices)   (Zip Code)

Registrant’s telephone number, including area code (210) 345-2000

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, or a non-accelerated filer (as defined in Rule12b-2 of the Act).

Large accelerated filer  x    Accelerated filer  ¨    Non-accelerated filer  ¨

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 $1,806 million based on the last sales price quoted as of June 30, 2006, the last business day of the registrant’s most recently completed second quarter.

The number of common units outstanding as of February 1, 2007 was 46,809,749.

 



Table of Contents

TABLE OF CONTENTS

 

          Page
   PART I   

Items 1., 1A. & 2.

   Business, Risk Factors and Properties    3
  

Recent Developments

   4
  

Segments

   4
  

Employees

   17
  

Rate Regulation

   17
  

Environmental and Safety Regulation

   18
  

Risk Factors

   20
  

Properties

   28

Item 1B.

   Unresolved Staff Comments    28

Item 3.

   Legal Proceedings    28

Item 4.

   Submission of Matters to a Vote of Security Holders    30
   PART II   

Item 5.

  

Market for Registrant’s Common Units, Related Unitholder Matters and Issuer Purchases of Common Units

   31

Item 6.

   Selected Financial Data    33

Item 7.

   Management’s Discussion and Analysis of Financial Condition and Results of Operations    34

Item 7A.

   Quantitative and Qualitative Disclosures About Market Risk    56

Item 8.

   Financial Statements and Supplementary Data    57

Item 9.

   Changes in and Disagreements with Accountants on Accounting and Financial Disclosure    103

Item 9A.

   Controls and Procedures    103

Item 9B.

   Other Information    103
   PART III   

Item 10.

   Directors and Executive Officers of the Registrant    104

Item 11.

   Executive Compensation    107

Item 12.

  

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

   136

Item 13.

   Certain Relationships and Related Transactions and Director Independence    138

Item 14.

   Principal Accountant Fees and Services    140
   PART IV   

Item 15.

   Exhibits and Financial Statement Schedules    142

Signatures

      152

 

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PART I

Unless otherwise indicated, the terms “Valero L.P.,” “the Partnership,” “we,” “our” and “us” are used in this report to refer to Valero 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 34 of this report under the heading: “CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION.”

 

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

OVERVIEW

Valero L.P. is a Delaware limited partnership formed in 1999 that 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 “VLI.” Our principal executive offices are located at One Valero Way, San Antonio, Texas 78249 and our telephone number is (210) 345-2000.

Our operations are managed by Valero GP, LLC, the general partner of Riverwalk Logistics, L.P., our general partner. Valero GP, LLC is a wholly owned subsidiary of Valero GP Holdings, LLC (Valero GP Holdings).

We conduct our operations through our wholly owned subsidiaries, primarily Valero Logistics Operations, L.P. (Valero Logistics) and Kaneb Pipe Line Operating Partnership, L.P. (KPOP). We have four business segments: refined product terminals, refined product pipelines, crude oil pipelines and crude oil storage tanks. As of December 31, 2006, our assets included:

 

   

65 refined product terminal facilities providing approximately 57.5 million barrels of storage capacity and one crude oil terminal facility providing approximately 3.3 million barrels of storage capacity;

 

   

8,259 miles of refined product pipelines, including 2,000 miles of anhydrous ammonia pipelines, with 21 associated terminals providing storage capacity of 4.8 million barrels;

 

   

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

 

   

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

We generate revenues by:

 

   

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

 

   

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

 

   

selling bunker fuel to marine vessels.

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; and

 

   

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

Our largest customer is Valero Energy, which accounted for 23% and 34% of our revenues for the years ended December 31, 2006 and 2005, respectively. Please read the disclosure contained in Note 14 of Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for additional information.

 

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Our internet website address is http://www.valerolp.com. Information contained on our website is not part of this report on Form 10-K. Our annual reports on Form 10-K, quarterly reports on Form 10-Q and current reports on Form 8-K filed with (or furnished to) the Securities and Exchange Commission (SEC) are available on our internet website (in the “Investor Relations” section), free of charge, as soon as reasonably practicable after we file or furnish such material. We also post our corporate governance guidelines, code of business conduct and ethics, code of ethics for senior financial officers and the charters of our board’s committees in the same website location. Our governance documents are available in print to any unitholder that makes a written request to Corporate Secretary, Valero L.P., P.O. Box 696000, San Antonio, Texas 78269-0600.

The term “throughput” as used in this document generally refers to the crude oil or refined product barrels or tons of ammonia, as applicable, that pass through each pipeline, terminal or storage tank.

RECENT DEVELOPMENTS

On February 16, 2007, we announced that we would change our name to NuStar Energy, L.P. (NYSE: NS). Also, Valero GP Holdings, LLC, our general partner, announced it would change its name to NuStar GP Holdings, LLC (NYSE: NGP). Both name changes are expected to be effective April 1, 2007.

On December 1, 2006, we acquired a crude oil storage and blending facility in St. James, Louisiana from Koch Supply and Trading, L.P. for approximately $141.7 million. The acquisition includes 17 crude oil tanks with a total capacity of approximately 3.3 million barrels. Additionally, the facility has 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. We funded the acquisition with borrowings under our revolving credit agreement.

On July 19, 2006, certain subsidiaries of Valero Energy Corporation (Valero Energy) sold 17,250,000 units of Valero GP Holdings (NYSE: VEH) in an initial public offering (IPO) for a price to the public of $22.00 per unit. On December 22, 2006, Valero Energy sold their remaining ownership interest in Valero GP Holdings in a secondary public offering. The 25,250,000 units representing limited liability company interests of Valero GP Holdings sold at a price of $21.62 per unit. Included in the 25,250,000 units sold were 4,700,000 unregistered units sold to Mr. William Greehey, Chairman of our board of directors, at a price of $21.62 per unit. Valero GP Holdings did not receive any proceeds from the IPO or the secondary public offering, and Valero Energy’s indirect ownership interest in Valero GP Holdings has been reduced to zero.

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

Effective January 1, 2006, we purchased a 23.77% interest in the Capwood pipeline from Valero Energy for $12.8 million. The Capwood pipeline is a 57-mile crude oil pipeline that extends from Patoka, Illinois to Wood River, Illinois. Plains All American Pipeline L.P., the operator of the Capwood pipeline, owns the remaining 76.23% interest.

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

SEGMENTS

Our four reportable business segments are refined product terminals, refined product pipelines, crude oil pipelines and crude oil storage tanks. Detailed financial information about our segments is included in Note 18 in the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data.”

 

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REFINED PRODUCT TERMINALS

Our terminal facilities provide storage and handling services on a fee basis for petroleum products, specialty chemicals, crude oil and other liquids. In addition, our terminals located on the island of St. Eustatius, Netherlands Antilles and in Point Tupper, Nova Scotia sell bunker fuel and provide ancillary services, such as pilotage, tug assistance, line handling, launch service, emergency response services and other ship services. As of December 31, 2006, we owned and operated:

 

   

56 terminals in the United States, with a total storage capacity of approximately 35.2 million barrels;

 

   

A terminal on the island of St. Eustatius, Netherlands Antilles with a tank capacity of 11.3 million barrels and a transshipment facility;

 

   

A terminal located in Point Tupper, Nova Scotia with a tank capacity of 7.6 million barrels and a transshipment facility;

 

   

Six terminals located in the United Kingdom and one terminal located in Amsterdam, the Netherlands, having a total storage capacity of approximately 6.7 million barrels; and

 

   

A terminal located in Nuevo Laredo, Mexico.

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

Description of Largest Terminal Facilities

St. Eustatius, Netherlands Antilles. We own and operate an 11.3 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 51 tanks. The fuel oil and petroleum product facilities have in-tank and in-line blending capabilities, while the crude tanks have tank-to-tank blending capability as well as in-tank mixers. In addition to the storage and blending services at St. Eustatius, this facility sells bunker fuel to marine vessels, and 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.

In 2006, we began construction on a 1.7 million barrel expansion project consisting of six storage tanks at our St. Eustatius facility, which we expect to increase the storage capacity by 0.5 million barrels in the 2nd quarter of 2007, 0.5 million barrels in the 3rd quarter of 2007 and 0.7 million barrels in the 2nd quarter of 2008.

Point Tupper, Nova Scotia. We own and operate a 7.6 million barrel terminalling and storage facility located at Point Tupper on the Strait of Canso, near Port Hawkesbury, Nova Scotia, which is located approximately 700 miles from New York City and 850 miles from Philadelphia. This facility is the deepest independent, ice-free marine terminal on the North American Atlantic coast, with access to the East Coast and Canada as well as the Midwestern United States via the St. Lawrence Seaway and the Great Lakes system. With one of the premier jetty facilities in North America, the Point Tupper facility can accommodate substantially all of the world’s largest, fully laden very large crude carriers and ultra large crude carriers for loading and discharging crude oil, petroleum products and petrochemicals. Crude oil and petroleum product movements at the terminal are fully automated. Separate fees apply for the use of the jetty facility as well as associated services, including pilotage, tug assistance, line handling, launch service, spill response services and other ship services. We also charter tugs, mooring launches and other vessels to assist with the movement of vessels through the Strait of Canso and the safe berthing of vessels at the terminal facility.

Piney Point, Maryland. Our terminal and storage facility in Piney Point, Maryland is located on approximately 400 acres on the Potomac River. The Piney Point terminal has approximately 5.4 million barrels of storage capacity in 28 tanks and is the closest deep-water facility to Washington, D.C. This terminal competes with other large petroleum terminals in the East Coast water-borne market extending from New York Harbor to Norfolk, Virginia. The terminal currently stores

 

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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 3.8 million barrels in 22 tanks, can receive products via ship, barge and pipeline and delivers product by ship, barge, pipeline and truck. The terminal includes two docks and leases a third with draft limits of 35, 24 and 24 feet, respectively.

In 2006, we began an expansion project that will add approximately 250 thousand barrels of capacity and improve pipeline connections to the Linden terminal with estimated completion in fourth quarter 2007.

St. James, Louisiana. Our terminal has 17 crude oil storage tanks with a total capacity of approximately 3.3 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.

We expect to start construction of four crude oil storage tanks with capacity of approximately 1.5 million barrels at our St. James facility in the first quarter 2007, with completion estimated by mid-2008.

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

 

Facility

  

Tank

Capacity

  

Number of

Tanks

  

Primary Products Handled

Major U.S. Terminals:

        

Piney Point, MD

   5,404,000    28    Petroleum, asphalt

Linden, NJ (a)

   3,797,000    22    Petroleum

St. James, LA

   3,345,000    17    Crude oil and feedstocks

Selby, CA

   3,042,000    23    Petroleum, ethanol

Jacksonville, FL

   2,072,000    31    Petroleum

Texas City, TX

   2,003,000    117    Chemicals, petrochemicals, petroleum

Other U.S. Terminals:

        

Montgomery, AL

   162,000    7    Petroleum

Moundville, AL

   310,000    6    Petroleum

Tucson, AZ (b)

   85,000    4    Petroleum

Los Angeles, CA

   606,000    19    Petroleum

Pittsburg, CA

   361,000    10    Asphalt

Stockton, CA

   692,000    31    Petroleum, ethanol, fertilizer

Colorado Springs, CO

   320,000    7    Petroleum

Denver, CO

   110,000    9    Petroleum

Bremen, GA

   178,000    8    Petroleum

Brunswick, GA

   310,000    3    Fertilizer, pulp liquor

Columbus, GA

   171,000    20    Petroleum, chemicals, caustic

Macon, GA

   307,000    10    Petroleum

Savannah, GA

   910,000    23    Petroleum, caustic

Blue Island, IL

   749,000    19    Petroleum, ethanol

Peru, IL (c)

   221,000    8    Fertilizer

Indianapolis, IN

   412,000    18    Petroleum

Westwego, LA

   852,000    53    Molasses, caustic, chemicals, lube oil, fertilizer

Andrews AFB Pipeline, MD

   72,000    3    Petroleum

Baltimore, MD

   837,000    49    Chemicals, asphalt

Salisbury, MD

   177,000    14    Petroleum

Winona, MN

   270,000    8    Fertilizer

Reno, NV

   107,000    7    Petroleum

 

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Facility

  

Tank

Capacity

  

Number of

Tanks

  

Primary Products Handled

Linden, NJ

   445,000    10    Petroleum

Paulsboro, NJ

   69,000    9    Petroleum

Alamogordo, NM

   120,000    5    Petroleum

Albuquerque, NM

   245,000    10    Petroleum

Rosario, NM

   160,000    8    Asphalt

Catoosa, OK

   340,000    24    Asphalt

Portland, OR

   1,039,000    29    Petroleum, ethanol

Abernathy, TX

   165,000    9    Petroleum

Almeda, TX (c)

   105,000    4    Petroleum

Amarillo, TX

   265,000    10    Petroleum

Corpus Christi, TX

   357,000    11    Petroleum

Edinburg, TX

   187,000    5    Petroleum

El Paso, TX (b)

   343,000    12    Petroleum

Harlingen, TX

   315,000    7    Petroleum

Houston, TX (Hobby Airport)

   106,000    4    Petroleum

Houston, TX

   90,000    6    Asphalt

Laredo, TX

   320,000    7    Petroleum

Placedo, TX

   97,000    4    Petroleum

San Antonio (east), TX

   148,000    5    Petroleum

San Antonio (south), TX

   215,000    5    Petroleum

Southlake, TX

   285,000    5    Petroleum

Texas City, TX

   146,000    12    Petroleum

Dumfries, VA

   548,000    14    Petroleum, asphalt

Virginia Beach, VA

   41,000    2    Petroleum

Tacoma, WA

   364,000    14    Petroleum, ethanol

Vancouver, WA

   198,000    13    Chemicals

Vancouver, WA

   304,000    6    Petroleum

Milwaukee, WI

   308,000    7    Petroleum, ethanol
            

Total U.S. Terminals

   35,207,000    831   
            

Foreign Terminals:

        

St. Eustatius, Netherlands Antilles

   11,315,000    51    Petroleum, crude oil

Point Tupper, Canada

   7,555,000    37    Petroleum, crude oil

Grays, England

   1,945,000    53    Petroleum

Eastham, England

   2,185,000    162    Chemicals, petroleum, animal fats

Runcorn, England

   146,000    4    Molten sulfur

Grangemouth, Scotland

   530,000    46    Petroleum, chemicals and molasses

Glasgow, Scotland

   344,000    16    Petroleum

Belfast, Northern Ireland

   407,000    41    Petroleum

Amsterdam, the Netherlands

   1,129,000    40    Petroleum

Nuevo Laredo, Mexico

   34,000    5    Petroleum
            

Total Foreign Terminals

   25,590,000    455   
            

(a) We own 50% of this terminal through a joint venture.
(b) We own a 66.67% undivided interest in the El Paso refined product terminal and a 50% undivided interest in the Tucson refined product terminal. The tankage capacity and number of tanks represent the proportionate share of capacity attributable to our ownership interest.
(c) Terminal is temporarily idled.

Terminal Operations

Revenues for the refined product terminals segment include fees for tank storage agreements, whereby a customer agrees to pay for a certain amount of storage in a tank over a period of time (storage lease revenues), and throughput agreements, whereby a customer pays a fee per barrel for volumes moving through our terminals (throughput revenues). Our terminals also provide blending, handling and filtering services. Revenues for the refined product terminals segment also include the sale of bunker fuel to marine vessels, at Point Tupper in Nova Scotia, Canada and St. Eustatius, Netherland Antilles in

 

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the Caribbean for which we earn revenues based upon a price per metric ton applied to the number of metric tons delivered to our customer. Our facilities at Point Tupper and St. Eustatius also charge fees to provide ancillary services such as pilotage, tug assistance, line handling, launch service, emergency response services and other ship services.

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 fluctuate as demand for refined petroleum products fluctuates. The factor that most affects demand for refined petroleum products is the general condition of the economy, with demand increasing in times when the economy is strong.

Customers

We provide terminalling services for crude oil and refined petroleum products to many of the world’s largest producers of crude oil, integrated oil companies, chemical companies, oil traders and refiners. The largest customer of our refined product terminals segment is Valero Energy, which accounted for $53.2 million, or 6.6% of the total revenues of the segment, for the year ended December 31, 2006. No other customer accounted for more than 10% of the revenues of the segment for this period. Our crude oil transshipment customers include an oil producer that leases and utilizes 5.0 million barrels of storage at St. Eustatius and a major international oil company which leases and utilizes 3.6 million barrels of storage at Point Tupper, both of which have long-term contracts with us. In addition, two different international oil companies each lease and utilize more than 1.0 million barrels of clean products storage at St. Eustatius and Point Tupper. Also in Canada, a consortium consisting of major oil companies sends natural gas liquids via pipeline to certain processing facilities on land leased from us. After processing, certain products are stored at the Point Tupper facility under a long-term contract. In addition, our blending capabilities have attracted customers who have leased capacity primarily for blending purposes and who have contributed to our bunker fuel and bulk product sales.

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

 

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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.

In the sale of bunker fuel, we compete with ports offering bunker fuels to which, or from which, each vessel travels or are along the route of travel of the vessel. We also compete with bunker fuel delivery locations around the world. In the Western Hemisphere, alternative bunker fuel locations include ports on the U.S. East Coast and Gulf Coast and in Panama, Puerto Rico, the Bahamas, Aruba, Curacao and Halifax, Nova Scotia.

REFINED PRODUCT PIPELINES

Our refined product pipelines operations consist primarily of the transportation of refined petroleum products as a common carrier in Texas, Oklahoma, Colorado, New Mexico, Kansas, Nebraska, Iowa, South Dakota, North Dakota and Minnesota covering approximately 6,259 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, 2006, we owned and operated:

 

   

26 refined product pipelines with an aggregate length of 3,919 miles that connect Valero Energy’s McKee, Three Rivers, Corpus Christi and Ardmore refineries to certain of Valero L.P.’s terminals, or to interconnections with third-party pipelines for further distribution, including a 25-mile crude hydrogen pipeline (collectively, the Central West System);

 

   

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

 

   

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

 

   

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

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

Description of Pipelines

Central West System. The pipelines included in the Central West System were constructed to support the refineries to which they are connected. These pipelines are physically integrated with and principally serve refineries owned by Valero Energy. We have entered into various agreements with Valero Energy governing the usage of these pipelines. Please read the disclosure contained in Note 14 of Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for additional information.

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

 

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

 

                         

Year Ended

December 31, 2006

 

Origin and Destination

  

Valero Energy

Refinery

   Length    Ownership     Capacity    Throughput   

Capacity

Utilization

 
          (Miles)          (Barrels/Day)    (Barrels/Day)       

McKee to El Paso, TX

   McKee    408    67 %   40,000    36,997    92 %

McKee to Colorado Springs, CO (a)

   McKee    256    100 %   38,000    13,137    80 %

Colorado Springs, CO to Airport

   McKee    2    100 %   14,000    1,109    8 %

Colorado Springs to Denver, CO

   McKee    101    100 %   32,000    17,782    56 %

McKee to Denver, CO

   McKee    321    30 %   9,870    8,332    84 %

McKee to Amarillo, TX (6”) (a)(b)

   McKee    49    100 %   51,000    35,750    70 %

McKee to Amarillo, TX (8”) (a)(b)

   McKee    49    100 %        

Amarillo to Abernathy, TX (a)

   McKee    102    67 %   11,733    6,802    69 %

Amarillo, TX to Albuquerque, NM

   McKee    293    50 %   17,150    8,987    52 %

Abernathy to Lubbock, TX (a)

   McKee    19    46 %   8,029    1,279    16 %

McKee to Skellytown, TX

   McKee    53    100 %   52,000    7,605    15 %

Skellytown to Mont Belvieu,TX

   McKee    572    50 %   26,000    10,756    41 %

McKee to Southlake, TX

   McKee    375    100 %   27,300    18,563    68 %

Three Rivers to San Antonio, TX

   Three Rivers    81    100 %   33,600    31,781    95 %

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

   Three Rivers    108    100 %   32,000    23,049    72 %

Corpus Christi to Three Rivers, TX

   Corpus Christi    68    100 %   32,000    7,173    22 %

Three Rivers to Corpus Christi, TX

   Three Rivers    72    100 %   15,000    12,024    80 %

Three Rivers to Pettus to San Antonio, TX

   Three Rivers    103    100 %   24,000    24,184    101 %

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

   Three Rivers    95    100 %   15,000    —      0 %

Ardmore to Wynnewood, OK (d)

   Ardmore    31    100 %   90,000    57,818    64 %

El Paso, TX to Kinder Morgan

   McKee    12    67 %   40,000    29,622    74 %

Corpus Christi to Pasadena, TX

   Corpus Christi    208    100 %   105,000    92,342    88 %

Corpus Christi to Brownsville, TX

   Corpus Christi    194    100 %   27,100    40,522    150 %

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

   N/A    33    100 %   24,000    2,232    9 %

Clear Lake, TX to Texas City, TX

   N/A    25    100 %   N/A    N/A    N/A  

Other refined product pipeline (e)

   N/A    289    50 %   N/A    N/A    N/A  
                      

Total

      3,919      764,782    487,846   
                      

(a) This pipeline transports barrels relating to two tariff routes. The first route begins at this pipeline’s origin and ends at this pipeline’s destination. The second route is a longer tariff route with an origin or destination on another pipeline of ours that connects to this pipeline. Throughput disclosed above for this pipeline reflects only the barrels subject to the tariff route beginning at this pipeline’s origin and ending at this pipeline’s destination. To accurately determine the actual capacity utilization of the pipeline, as well as aggregate capacity utilization, all barrels passing through the pipeline have been taken into account.
(b) The throughput, capacity and capacity utilization information disclosed above for the McKee to Amarillo, Texas 6-inch pipeline reflects both McKee to Amarillo, Texas pipelines on a combined basis.
(c) The refined product pipeline from Three Rivers to Pettus to Corpus Christi, Texas is temporarily idled. In the fourth quarter of 2005, an eight-mile portion of this pipeline was permanently idled. As a result, we recorded an impairment charge of $2.1 million included in “interest and other expenses, net” in the consolidated statements of income for the year ended December 31, 2005.
(d) Included in this segment are two refined product storage tanks with a total capacity of 180,000 barrels located at Wynnewood, Oklahoma. Refined products may be stored and batched prior to shipment into a third party pipeline.

 

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(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 from south to north in pipelines ranging in size from 6 inches to 16 inches. The East Pipeline system also includes 22 product tanks with total storage capacity of approximately 1.2 million barrels at our tank farm installations 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 51.3 million barrels for the year ended December 31, 2006.

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 exclusively by the Tesoro Mandan refinery, it is capable of delivering or receiving products to or from the East Pipeline. The North Pipeline transported approximately 16.7 million barrels for the year ended December 31, 2006.

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

The following table shows the number of tanks we own as of December 31, 2006 at each of the 21 refined petroleum product terminals connected to the East or North Pipelines, the storage capacity in barrels and the pipeline to which each such terminal was connected.

 

Location of Terminals

   Tank Capacity   

Number of

Tanks

  

Related Pipeline

System

Iowa:

        

LeMars

   103,000    8    East

Milford

   172,000    11    East

Rock Rapids

   357,000    9    East

Kansas:

        

Concordia

   79,000    6    East

Hutchinson

   161,000    7    East

Salina

   96,000    10    East

Minnesota:

        

Moorhead

   518,000    10    North

Sauk Centre

   116,000    7    North

Roseville

   479,000    10    North

Nebraska:

        

Columbus

   190,000    9    East

Geneva

   674,000    37    East

Norfolk

   187,000    16    East

North Platte

   247,000    23    East

Osceola

   79,000    7    East

North Dakota:

        

Jamestown (North)

   139,000    6    North

Jamestown (East)

   188,000    13    East

 

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Location of Terminals

   Tank
Capacity
  

Number of

Tanks

  

Related Pipeline

System

South Dakota:

        

Aberdeen

   181,000    12    East

Mitchell

   63,000    6    East

Sioux Falls

   381,000    12    East

Wolsey

   148,000    21    East

Yankton

   245,000    25    East
            

Total

   4,803,000    265   
            

Ammonia Pipeline. The 2,000 mile pipeline originates in the Louisiana delta area, where it has access to three marine terminals 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 plants in Louisiana and foreign-source product delivered through the marine terminals. Anhydrous ammonia is primarily used as agricultural fertilizer through direct application. It is also used as a component of various types of dry fertilizer, explosives and as a cleaning agent in power plant scrubbers. The Ammonia Pipeline transported approximately 11.7 million barrels (converted from tons) for the year ended December 31, 2006.

Other Systems

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

Pipeline Operations

Revenues for the Central West System are based upon throughput volumes traveling through our system and the related tariffs.

Revenues for the East Pipeline, North Pipeline and Ammonia Pipeline are based upon volumes and the distance the product is shipped and the related tariffs.

Pipelines are generally the lowest cost method for intermediate and long-haul overland transportation of refined petroleum products. 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. Petroleum shippers are generally invoiced by us immediately upon the product entering one of our pipelines.

The Ammonia Pipeline receives product from anhydrous ammonia plants or from the marine terminals for imported product. Tariffs for transportation are charged to shippers based upon transportation from the origination point on the pipeline to the point of delivery.

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

Except for three single-use pipelines and certain ethanol facilities, all of our pipeline operations constitute common carrier operations and are subject to federal tariff regulation. We are authorized by the FERC to adopt market-based rates in approximately one-half of our markets on the East Pipeline system. 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, Louisiana, 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, rather than the FERC, and state regulation by the Louisiana Public Service Commission.

 

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

Demand for and Sources of Refined Products

The operations of our Central West, East and North Pipelines depend in large part on the level of demand for refined products in the markets served by the pipelines and the ability and willingness of refiners and marketers having access to the pipelines to supply such demand by deliveries through the pipelines.

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

The majority of the refined products delivered through the North Pipeline are delivered to the Minneapolis, Minnesota metropolitan area and consist primarily of gasoline and diesel fuel. Demand for those products fluctuates based on general economic conditions and with changes in the weather as more people tend to 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 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 are connected to refineries owned by Valero Energy and generally are subject to long-term throughput agreements with Valero Energy. Valero Energy’s refineries connected directly to our pipelines obtain crude oil from a variety of foreign and domestic sources. The refineries connected directly to the East Pipeline obtain crude oil from producing fields located primarily in Kansas, Oklahoma and Texas, and, to a much lesser extent, from other domestic or foreign sources. In addition, refineries in Kansas, Oklahoma and Texas are also connected to the East Pipeline through other pipelines. These refineries obtain their supplies of crude oil from a variety of sources. The pipelines in our Central West System are dependent upon the refineries owned by Valero Energy to which they connect. If operations at one of these refineries were discontinued or reduced, it could have a material adverse effect on our operations, although we would endeavor to minimize the impact by seeking alternative customers for those pipelines. The North Pipeline is heavily dependent on the Tesoro Mandan refinery, which primarily operates on North Dakota crude oil although it has the ability to access other crude oils. If operations at the Tesoro Mandan refinery were interrupted, it could have a material effect on our operations. Other than the refineries owned by Valero Energy to which our pipelines connect 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 by other sources.

Virtually all of the refined products transported through the pipelines in the Central West System are produced by refineries owned by Valero Energy. The majority of the refined products transported through the East Pipeline are

 

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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 McPherson, Kansas refinery operated by NCRA accounted for approximately 30.7% of the total amount of product shipped over the East Pipeline in 2006. The East Pipeline also has direct access by third party pipelines to four other refineries in Kansas, Oklahoma and Texas and to Gulf Coast supplies of products through connecting pipelines that receive products from pipelines originating on the Gulf Coast.

Demand for and Sources of Anhydrous Ammonia

The Ammonia Pipeline is one of two major anhydrous ammonia pipelines in the United States and the only one that has the capability of receiving foreign production directly into the system and transporting anhydrous ammonia into the nation’s corn belt. This ability to receive either domestic or foreign anhydrous ammonia is a competitive advantage over the next largest ammonia system, which originates in Oklahoma and Texas, then extends into Iowa.

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

Corn producers have several fertilizer alternatives such as liquid, dry or Direct Application. Liquid and dry fertilizers are both upgrades of anhydrous ammonia and therefore are generally more costly but are less sensitive to weather conditions during application. Direct Application is the cheapest method of fertilizer application.

Customers

The largest customer of our refined product pipeline segment was Valero Energy, which accounted for $104.5 million, or 45.9% of the total segment revenues, for the year ended December 31, 2006. In addition to Valero Energy, we had a total of approximately 56 shippers for the year ended December 31, 2006, including integrated oil companies, refining companies, farm cooperatives and a railroad. No other customer accounted for a significant portion of the total revenues of the refined product pipeline segment for the year ended December 31, 2006.

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 provided our pipelines have available capacity to satisfy demand and our tariffs remain at reasonable levels.

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

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

The East and North Pipelines compete with an independent, regulated common carrier pipeline system owned by Magellan Midstream Partners, L.P. (Magellan), formerly the Williams Companies, Inc., that operates approximately 100 miles east

 

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of and parallel to the East Pipeline and in close proximity to the North Pipeline. The Magellan system is a substantially more extensive system than the East and North Pipelines. Competition with Magellan is based primarily on transportation charges, quality of customer service and proximity to end users. In addition, refined product pricing at either the origin or terminal point on a pipeline may outweigh transportation costs. Certain of the East Pipeline’s and the North Pipeline’s delivery terminals are in direct competition with Magellan’s terminals.

Competitors of the Ammonia Pipeline include another anhydrous ammonia pipeline that originates in Oklahoma and Texas, and terminates in Iowa. The competitor pipeline has the same Direct Application demand and weather issues as the Ammonia Pipeline but is restricted to domestically produced anhydrous ammonia. Midwest production barges and railroads represent other forms of direct competition to the pipeline under certain market conditions.

CRUDE OIL PIPELINES

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

As of December 31, 2006, we had an ownership interest in eleven crude oil pipelines with an aggregate length of 854 miles. We charge tariffs on a per barrel basis for transporting crude oil and other feedstocks in our crude oil pipelines.

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

 

                         

Year Ended

December 31, 2006

 

Origin and Destination

  

Valero

Energy

Refinery

   Length    Ownership     Capacity    Throughput   

Capacity

Utilization

 
          (Miles)          (Barrels/Day)    (Barrels/Day)       

Cheyenne Wells, CO to McKee

   McKee    252    100 %   17,500    9,912    57 %

Dixon, TX to McKee

   McKee    44    100 %   85,000    39,128    46 %

Hooker, OK to Clawson, TX (a)

   McKee    41    50 %   22,000    18,749    85 %

Clawson, TX to McKee (b)

   McKee    31    100 %   36,000    16,443    98 %

Wichita Falls, TX to McKee

   McKee    272    100 %   110,000    68,957    63 %

Corpus Christi, TX to Three Rivers

   Three Rivers    70    100 %   120,000    80,916    67 %

Ringgold, TX to Wasson, OK (b)

   Ardmore    44    100 %   90,000    59,150    66 %

Healdton to Ringling, OK

   Ardmore    4    100 %   52,000    2,844    5 %

Wasson, OK to Ardmore (8”-10”) (c)

   Ardmore    24    100 %   90,000    52,222    58 %

Wasson, OK to Ardmore (8”)

   Ardmore    15    100 %   40,000    32,036    80 %

Patoka, IL to Wood River, IL

   N/A    57    23.8 %   60,600    41,309    68 %
                      

Total

      854      723,100    421,666   
                      

(a) We receive 50% of the tariff with respect to 100% of the barrels transported in the Hooker, Oklahoma to Clawson, Texas pipeline. Accordingly, the capacity, throughput and capacity utilization are given with respect to 100% of the pipeline.
(b) This pipeline transports barrels relating to two tariff routes. The first route begins at the pipeline’s origin and ends at its destination. The second route begins with an origin or destination on another connecting Partnership pipeline. Throughput disclosed above for this pipeline reflects only the barrels subject to the tariff route beginning at this pipeline’s origin and ending at this pipeline’s destination. To accurately determine the actual capacity utilization of the pipeline, as well as aggregate capacity utilization, all barrels passing through the pipeline have been taken into account.

 

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

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

 

Location

  

Valero
Energy

Refinery

   Capacity   

Number

of Tanks

  

Mode of

Receipt

  

Mode of

Delivery

  

Throughput

Year Ended

December 31,

2006

          (Barrels)                   (Barrels/Day)

Dixon, TX

   McKee    240,000    3    pipeline    pipeline    39,128

Ringgold, TX

   Ardmore    600,000    2    pipeline    pipeline    59,150

Wichita Falls, TX

   McKee    660,000    4    pipeline    pipeline    68,957

Wasson, OK

   Ardmore    225,000    2    pipeline    pipeline    84,258
                       

Total

      1,725,000    11          251,493
                       

The primary customer of our crude oil pipeline segment is Valero Energy, which accounted for $56.4 million, or 96.1% of the total revenues of the segment, for the year ended December 31, 2006.

Competition and Business Considerations

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

CRUDE OIL STORAGE TANKS

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

At December 31, 2006 we owned 60 crude oil and intermediate feedstock storage tanks and related assets with aggregate storage capacity of approximately 12.5 million barrels. The land underlying these tanks is subject to long-term operating leases. We charge a fee for each barrel of crude oil and certain other feedstocks that we deliver to Valero Energy’s Benicia, Corpus Christi West and Texas City refineries.

 

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

 

Location

  

Valero

Energy

Refinery

   Capacity    Number of
Tanks
  

Mode of

Receipt

  

Mode

of

Delivery

  

Throughput

Year Ended

December 31,

2006

          (Barrels)                   (Barrels/Day)

Benicia, CA

   Benicia    3,815,000    16    marine/pipeline    pipeline    146,186

Corpus Christi, TX

   Corpus Christi    4,023,000    26    marine    pipeline    153,561

Texas City, TX

   Texas City    3,087,000    14    marine    pipeline    202,942

Corpus Christi, TX (North Beach)(a)

   Three Rivers    1,600,000    4    marine    pipeline    —  
                       

Total

      12,525,000    60          502,689
                       

(a) Through December 31, 2006, we did not report throughput for the Corpus Christi North Beach storage facility, as revenues for this facility were mainly based on a lease agreement with Valero Energy. Effective January 1, 2007, revenues for this facility will be based on a throughput agreement. Please read disclosure contained in Note 14 of Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data” for additional information.

Principal Customers

For the year ended December 31, 2006, Valero Energy accounted for 100% of the crude oil storage tanks segment revenues.

Competition and Business Considerations

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

EMPLOYEES

Valero L.P. has no employees. Valero GP, LLC, the general partner of our general partner, manages our operations with its employees. As of December 31, 2006, Valero GP, LLC had 1,305 employees. Valero GP, LLC believes that its relationship with its employees is satisfactory.

RATE REGULATION

Several of our petroleum pipelines are interstate common carrier pipelines, which are subject to regulation by the FERC under the October 1, 1977 version of the ICA and the Energy Policy Act of 1992 (the EP Act). The ICA and its implementing regulations give the FERC authority to regulate the rates charged for service on interstate common carrier pipelines and generally require the rates and practices of interstate oil pipelines to be just and reasonable and nondiscriminatory. The ICA also requires tariffs to be maintained on file with the FERC that set forth the rates it charges for providing transportation services on its interstate common carrier liquids pipelines as well as the rules and regulations governing these services. The EP Act deemed certain rates in effect prior to its passage to be just 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.

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

 

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Additionally, the rates and practices for our intrastate common carrier pipelines are subject to regulation by state commissions in Colorado, Kansas, Louisiana, North Dakota, Oklahoma 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 reasonable and nondiscriminatory. Shippers may also challenge our intrastate tariff rates and practices on our pipelines.

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

ENVIRONMENTAL AND SAFETY REGULATION

Our operations are subject to extensive federal, state and local environmental laws and regulations, including those relating to the discharge of materials into the environment, waste management and pollution prevention measures. Our operations are also subject to extensive federal and state health and safety laws and regulations, including those relating to pipeline safety. The principal environmental and safety risks associated with our operations relate to unauthorized emissions into the air, unauthorized releases into soil, surface water or groundwater and personal injury and property damage. Compliance with these environmental and safety laws, regulations and permits increases our capital expenditures and our overall cost of business, and violations of these laws, regulations and/or permits can result in significant civil and criminal liabilities, injunctions or other penalties.

We have adopted policies, practices and procedures in the areas of pollution control, pipeline integrity, operator qualifications, public relations and education, product safety, occupational health and the handling, storage, use and disposal of hazardous materials that are designed to prevent material environmental or other damage, to ensure the safety of our pipelines, our employees, the public and the environment and to limit the financial liability that could result from such events. Future governmental action and regulatory initiatives could result in changes to expected operating permits and procedures, additional remedial actions or increased capital expenditures and operating costs that cannot be assessed with certainty at this time. In addition, contamination resulting from spills of crude oil and refined products occurs within the industry. Risks of additional costs and liabilities are inherent within the industry, and there can be no assurances that significant costs and liabilities will not be incurred in the future.

 

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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.

AIR EMISSIONS

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

The Kyoto Protocol to the United Nations Framework Convention on Climate Change became effective February 2005. Under the Protocol, participating nations are required to implement programs to reduce emissions of certain gases, generally referred to as greenhouse gases, which are suspected of contributing to global warming. The United States is not currently a participant in the Protocol, and Congress has not actively considered recent proposed legislation directed at reducing greenhouse gas emissions. However, the state of California recently adopted legislation, referred to as the California Global Warming Solutions Act of 2006, which requires a 25% reduction in greenhouse gas emissions by 2020. This legislation requires the California Air Resources Board to adopt regulations by 2012 that limit emissions until an overall reduction of 25% from all omission sources in California is achieved by 2020. Other states, including New Jersey, have also adopted legislation addressing greenhouse gas emissions from various sources, primarily power plants. The oil and natural gas industry is a direct source of greenhouse gas emissions, namely carbon dioxide and methane, and future restrictions on such emissions could have an impact on our future operations. It is not possible, at this time to estimate accurately how regulations to be adopted by the California Air Resources Board in 2012 or that may be adopted by other states to address greenhouse gas emissions would affect our business.

SOLID WASTE

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

 

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HAZARDOUS SUBSTANCES

The Comprehensive Environmental Response, Compensation and Liability Act, referred to as CERCLA and also known as Superfund, and analogous or more stringent state laws, imposes liability, without regard to fault or the legality of the original act, on some classes of persons that contributed to the release of a “hazardous substance” into the environment. These persons include the owner or operator of the site and entities that disposed or arranged for the disposal of the hazardous substances found at the site. CERCLA also authorizes the EPA and, in some instances, third parties to act in response to threats to the public health or the environment and to seek recovery from the responsible classes of persons for the costs that they incur. In the course of our ordinary operations, we may generate waste that falls within CERCLA’s definition of a “hazardous substance.”

We currently own or lease, and have in the past owned or leased, properties where hydrocarbons are being or have been handled. Although we have utilized operating and disposal practices that were standard in the industry at the time, hydrocarbons or other wastes may have been disposed of or released on or under the properties owned or leased by us or on or under other locations where these wastes have been taken for disposal. In addition, many of these properties have been operated by third parties whose treatment and disposal or release of hydrocarbons or other wastes was not under our control. These properties and wastes disposed thereon may be subject to CERCLA, RCRA and analogous state laws. Under these laws, we could be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators), to clean up contaminated property (including contaminated groundwater) or to perform remedial operations to prevent future contamination. In addition, we may be exposed to joint and several liability under CERCLA for all or part of the costs required to clean up sites at which hazardous substances may have been disposed of or released into the environment.

Remediation of subsurface contamination is in process at many of our pipeline and terminal sites. Based on current investigative and remedial activities, we believe that the cost of these activities will not materially affect our financial condition or results of operations. Such costs, however, are often unpredictable and, therefore, there can be no assurances that the future costs will not become material.

PIPELINE INTEGRITY AND SAFETY

Our pipelines are subject to extensive federal and state laws and regulations governing pipeline integrity and safety. The federal Pipeline Safety Improvement Act of 2002 and its implementing regulations (collectively, PSIA) generally require pipeline operators to maintain qualification programs for key pipeline operating personnel, to review and update their existing pipeline safety public education programs, to provide information for the National Pipeline Mapping System, to maintain spill response plans, to conduct spill response training and to implement integrity management programs for pipelines that could affect high consequence areas (i.e., areas with concentrated populations, navigable waterways and other unusually sensitive areas). While compliance with PSIA and analogous or more stringent state laws may affect our capital expenditures and operating expenses, we believe that the cost of such compliance will not materially affect our competitive position and will not have a material effect on our financial condition or results of operations.

RISK FACTORS

RISKS RELATED TO OUR BUSINESS

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

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

 

   

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

 

   

throughput volumes in our terminals and storage facilities;

 

   

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

 

   

the level of our operating costs;

 

   

weather conditions;

 

   

domestic and foreign governmental regulations and taxes;

 

   

the effect of worldwide energy conservation measures; and

 

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prevailing economic conditions.

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

 

   

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

 

   

receipts or payments under interest rate swaps;

 

   

the sources of cash used to fund our acquisitions;

 

   

the level of capital expenditures we make;

 

   

fluctuations in our working capital needs;

 

   

issuances of debt and equity securities; and

 

   

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.

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

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

 

   

scheduled upgrades or maintenance;

 

   

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

 

   

labor difficulties that result in a work stoppage or slowdown;

 

   

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

 

   

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

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

As of December 31, 2006, our consolidated debt was approximately $1.4 billion. Among other things, this amount of debt may be viewed negatively by credit rating agencies, which could result in increased costs for us to access the capital markets. Valero Logistics and KPOP have senior unsecured ratings of Baa3 with Moody’s Investor Service and BBB minus with Standard & Poors and Fitch, all with a stable outlook. Any future downgrade of the debt held by these wholly owned subsidiaries could significantly increase our capital costs or adversely affect our ability to raise capital in the future.

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

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.

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

 

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We continue to rely on Valero Energy for a significant portion of our revenues. For the year ended December 31, 2006, Valero Energy accounted for approximately 23% of our revenues. While some of our relationships with Valero Energy are subject to long-term contracts, we may be unable to negotiate extensions or replacements of these contracts on favorable terms, if at all. For example, the Pipelines and Terminals Usage Agreement with respect to the crude oil processed and the refined products produced at Valero Energy’s Ardmore, McKee and Three Rivers refineries expire on April 16, 2008, and Valero Energy may elect not to renew such agreement or only agree to renew it at substantially less favorable terms.

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

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

 

   

a material decrease in the supply of crude oil;

 

   

a material increase in the price of crude oil;

 

   

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

 

   

scheduled turnarounds or unscheduled maintenance;

 

   

operational problems or catastrophic events at a refinery;

 

   

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

 

   

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

 

   

increasingly stringent environmental regulations; or

 

   

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

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

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

If market conditions with respect to the transportation of crude oil or refined products or with respect to the end markets in which Valero Energy sells refined products change in a material manner such that Valero Energy would suffer a material adverse effect if it were to continue to use our pipelines and terminals at the required levels, Valero Energy’s obligation to us will be suspended during the period of the change in market conditions to the extent required to avoid the material adverse effect. Any suspension of Valero Energy’s obligation could adversely affect throughputs in our pipelines and terminals and therefore our ability to make distributions to our unitholders.

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

Power costs constitute a significant portion of our operating expenses. Power costs represented approximately 13.3% of our operating expenses for the year ended December 31, 2006. We use mainly electric power at our pipeline pump stations and terminals and such electric power is furnished by various utility companies that use primarily natural gas to generate electricity. Accordingly, our power costs typically fluctuate with natural gas prices. Increases in natural gas prices may cause our power costs to increase further. If natural gas prices remain high or increase further, our cash flows may be adversely affected, which could adversely affect our ability to make distributions to our unitholders.

 

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Valero Energy’s divestiture of its ownership interest in Valero GP Holdings in December 2006 has caused and will continue to cause an increase in our administrative costs and expenses and capital expenditures, which will continue to reduce the cash available for distribution to our partners

We have historically benefited from common overhead infrastructure with Valero Energy- primarily in the areas of information technology systems and employee benefit plan and payroll administration. Over time, we expect to continue to separate our administrative functions from Valero Energy and absorb the functions currently provided by Valero Energy under the Services Agreement. As a result, we will incur additional expenses and capital expenditures for either obtaining personnel or third-party providers to perform services now provided by Valero Energy. These additional expenses and capital expenditures will reduce the cash available for distribution to our unitholders.

Our cash distribution policy may limit our growth

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

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

Our operations are subject to increasingly strict environmental and safety laws and regulations. The transportation and storage of petroleum and other products, such as specialty liquids, produces a risk that these products may be suddenly released into the environment, potentially causing substantial expenditures for a response action, significant government penalties, liability to government agencies for natural resources damages, personal injury or property damages to private parties and significant business interruption. We own or lease a number of properties that have been used to store or distribute refined products for many years. Many of these properties, such as the assets acquired from Kaneb in 2005, were operated by third parties whose handling, disposal, or release of hydrocarbons and other wastes was not under our control. If we were to incur a significant liability pursuant to environmental or safety laws or regulations, such a liability could have a material adverse effect on our financial position, our ability to make distributions to our unitholders and our ability to meet our debt service requirements. Please read Item 3. “Legal Proceedings” and Note 12 of Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data.”

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, 2006, we had approximately $1.4 billion of consolidated debt, of which $0.8 billion was at fixed interest rates and $0.6 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.

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

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

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

Our operations are subject to operational hazards and unforeseen interruptions such as natural disasters, adverse weather, accidents, fires, explosions, hazardous materials releases, mechanical failures and other events beyond our control. These

 

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

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

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

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

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

 

   

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

 

   

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

 

   

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

 

   

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

 

   

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

We may not be able to integrate effectively and efficiently with Kaneb or any future businesses or operations we may acquire. Any future acquisitions may substantially increase the levels of our indebtedness and contingent liabilities

We continue to integrate our operations with those of Kaneb. Such integration of operations is a complex, time-consuming and costly process. We may not be able to realize the operating efficiencies, cost savings and other benefits expected. In addition, the costs we incur in implementing these efficiencies, cost savings and other benefits may be greater than expected.

Part of our business strategy includes acquiring additional pipelines and terminalling and storage facilities 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,

 

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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.

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

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

Valero 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

Valero GP Holdings currently indirectly owns an aggregate 21.4% limited partner interest in us and owns Valero L.P.’s general partner. Conflicts of interest may arise between Valero GP Holdings and its affiliates, including Valero L.P.’s general partner, on the one hand, and Valero L.P. and its 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:

 

   

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

 

   

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

 

   

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

 

   

Valero L.P.’s general partner determines in its sole discretion which costs incurred by Valero GP Holdings and its affiliates are reimbursable by us;

 

   

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

 

   

Valero L.P.’s general partner decides whether to retain separate counsel, accountants, or others to perform services for us; and

 

   

In some instances, Valero L.P.’s general partner may cause us to borrow funds in order to permit the payment of distributions.

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

The rates that we may charge on our interstate pipelines are subject to regulation by various federal and state agencies, such as the FERC and the STB

Pursuant to the Interstate Commerce Act, or ICA, the Federal Energy Regulatory Commission, or the FERC, regulates the tariff rates for our interstate common carrier pipeline operations. Under the ICA, tariff rates must be published, just and reasonable and not unduly discriminatory. Shippers may protest or challenge, and the FERC may investigate, the lawfulness of any existing, new or changed tariff rates. The FERC can suspend new or changed tariff rates for up to seven months. The FERC can also require refunds of amounts collected under rates ultimately found to be unlawful.

 

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We use various FERC-authorized rate methodologies for our interstate pipelines, including 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 increase its rates by a percentage equal to the producer price index for finished goods. If the index results in a negative adjustment, we will typically be required to reduce any rates that exceed the new maximum allowable rate. In addition, changes in the index might not be large enough to fully reflect actual increases in our costs. The FERC’s authorized rate-making methodologies may also delay the use or implementation of rates that reflect increased costs. If the FERC’s rate-making methodologies change, any such change or new methodologies could result in rates that generate lower revenues and cash flow and could adversely affect our ability to make distributions to our unitholders and to meet our debt service requirements. Any of the foregoing would adversely affect our revenues and cash flow and could 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.

Other federal regulatory bodies, including the STB, impose additional rate regulations on our operations and typically require that our rates be just and reasonable and non-discriminatory.

Our pipeline operations are subject to FERC rate-making principles that could have an adverse impact on our ability to recover the full cost of operating our pipeline facilities and our ability to make distributions to our unitholders

In a decision issued in 2004 involving an oil pipeline limited partnership, BP West Coast Products, LLC v. FERC, the United States Court of Appeals for the District of Columbia Circuit rejected the FERC’s Lakehead policy. Under that policy, the FERC had allowed an oil pipeline limited partnership to include in its cost of service an income tax allowance to the extent that its unitholders were corporations. In May 2005, the FERC issued a new Policy Statement on Income Tax Allowances (Policy Statement), stating that a pipeline organized as a tax pass-through entity may include in its cost of service-based rates an income tax allowance to reflect actual or potential tax liability on its public utility income attributable to all entities or individuals owning public utility assets, if the pipeline proves that the ultimate owner of the interest has an actual or potential income tax liability on such income. The Policy Statement also provides that 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. In August 2005, the FERC also dismissed requests for rehearing of its new Policy Statement. Since June 2005, the FERC has also issued several orders applying its new policy on income tax allowance, two of which involved the remanded BP West Coast case. Although the new policy affords pipelines organized as pass-through entities an opportunity to recover a tax allowance, these recent orders vary with regard to the type of evidence or related burden of proof necessary to establish whether an actual or potential income tax liability exists for all owners. Application of the Policy Statement in these and other individual cases will also be subject to further FERC action and/or review in the appropriate Court of Appeals. In addition, multiple petitions for review of the Policy Statement and the FERC’s application of the Policy Statement on remand of the BP West Coast decision have already been filed at the United States Court of Appeals for the District of Columbia Circuit. Therefore, the ultimate outcome of these proceedings is not certain and could result in changes to the FERC’s treatment of income tax allowances in cost of service. If we were to file for a cost of service-based rate increase, we would likely be permitted to include an income tax allowance in such rates only to the extent we could show, pursuant to the Policy Statement, that the ultimate owners of our units have actual or potential income tax liability on our income. There is not yet a definitive ruling from FERC concerning the type of evidence we would have to produce to prevail on a request to include a tax allowance. If the FERC were to disallow a substantial portion of our income tax allowance, it is likely that the maximum rates that could be charged could decrease from current levels.

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

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

 

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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. The value of an investment in us depends largely on our being treated as a partnership for federal income tax purposes.

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, will also generally be subject to a state-level tax imposed on Texas source revenues beginning in 2008. Specifically, the Texas margin tax will be imposed at a maximum effective tax rate of 0.7% of our gross revenue 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.

Valero Energy sold its remaining interest in Valero GP Holdings on December 22, 2006. While more than 50% ownership of Valero GP Holdings changed hands during a 12-month period, we are not considered to have terminated our partnership for federal income tax purposes due to normal trading activity in our units and the fact Valero Energy disposed of 100% of Valero GP Holdings in the sales in 2006.

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 Valero L.P. unitholder would be allocated an increased amount of federal taxable income for the year in which the partnership is considered terminated and the subsequent years as a percentage of the cash distributed to the unitholder with respect to that period.

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

If a unitholder sells units, the unitholder will recognize gain or loss equal to the difference between the amount realized and that unitholder’s tax basis in those units. Prior distributions to the unitholder in excess of the total net taxable income

 

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the unitholder was allocated for a unit, which decreased the tax basis in that unit, will, in effect, become taxable income to the unitholder if the unit is sold at a price greater than the tax basis in that unit, even if the price the unitholder receives is less than the original cost. A substantial portion of the amount realized, whether or not representing gain, may be ordinary income to the selling unitholder.

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

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

PROPERTIES

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

 

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

 

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

GRACE ENERGY CORPORATION MATTER

In 1997, Grace Energy Corporation (Grace Energy) sued subsidiaries of Kaneb in Texas state court. The complaint sought recovery of the cost of remediation of fuel leaks in the 1970s from a pipeline that had once connected a former Grace Energy terminal with Otis Air Force Base (Otis AFB) in Massachusetts. Grace Energy alleges the Otis AFB pipeline and related environmental liabilities had been transferred in 1978 to an entity that was part of Kaneb’s acquisition of Support Terminal Services, Inc. and its subsidiaries from Grace Energy in 1993. Kaneb contends that it did not acquire the Otis AFB pipeline and never assumed any responsibility for any associated environmental damage.

In 2000, the court entered final judgment that: (i) Grace Energy could not recover its own remediation costs of $3.5 million, (ii) Kaneb owned the Otis AFB pipeline and its related environmental liabilities and (iii) Grace Energy was awarded $1.8 million in attorney costs. Both Kaneb and Grace Energy appealed the trial court’s final judgment to the Texas Court of Appeals in Dallas. In 2001, Grace Energy filed a petition in bankruptcy, which created an automatic stay of actions against Grace Energy. Once that stay is lifted, we intend to resume vigorous prosecution of the appeal.

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

PORT OF VANCOUVER MATTER

We own a chemical and refined product terminal on property owned by the Port of Vancouver, and we lease the land under the terminal from the Port of Vancouver. Under an Agreed Order entered into with the Washington Department of Ecology when Kaneb purchased the terminal in 1998, Kaneb agreed to investigate and remediate groundwater contamination by the terminal’s previous owner and operator originating from the terminal. Investigation and remediation at the terminal are ongoing in compliance with the Agreed Order. In April 2006, the Washington Department of Ecology commented on our site investigation work plan and asserted that the groundwater contamination at the terminal was commingled with a groundwater contamination plume under other property owned by the Port of Vancouver. We dispute this assertion. No lawsuits have been filed against us in this matter. Factors that could affect estimated remediation costs include whether Kaneb will have ultimate responsibility for some portion of the allegedly commingled plume, the Port of Vancouver’s contribution to the remediation effort and the amount the Port of Vancouver actually receives from other potentially responsible parties.

ENVIRONMENTAL AND SAFETY COMPLIANCE MATTERS

With respect to the environmental proceedings listed below, if any one or more of them were decided against us, we believe that it would not have a material effect on our consolidated financial position. However, it is not possible to predict the ultimate outcome of any these proceedings or whether such ultimate outcome may have a material effect of our consolidated financial position. We report these proceedings to comply with Securities and Exchange Commission regulations, which require us to disclose proceedings arising under federal, state or local provisions regulating the discharge of materials into the environment or protecting the environment if we reasonably believe that such proceedings will result in monetary sanctions of $100,000 or more.

In particular, the Illinois State Attorney General’s Office has proposed penalties totaling $133,000 related to a pipeline leak at a storage terminal in Chillicothe, Illinois that we owned through a joint venture with Center Oil Company until we

 

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sold our interest in October 2006. The Pipeline and Hazardous Materials Safety Agency has proposed penalties totaling $255,000 based on alleged violations of various pipeline safety requirements in the McKee System. We are currently in settlement negotiations with these government agencies to resolve these matters.

We are also a party to additional claims and legal proceedings arising in the ordinary course of business. We believe the possibility is remote that the final outcome of any of the claims or proceedings to which we are a party would have a material adverse effect on our financial position, results of operations or liquidity; however, due to the inherent uncertainty of litigation, there can be no assurance that the resolution of any particular claim or proceeding would not have a material adverse effect on our results of operations, financial position or liquidity.

 

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

No matters were submitted to a vote of the unitholders, through solicitation of proxies or otherwise, during the fourth quarter of the year ended December 31, 2006.

 

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PART II

 

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

Market Information, Holders and Distributions

Our common units are listed and traded on the New York Stock Exchange under the symbol “VLI.” At the close of business on February 7, 2007, we had 873 holders of record of our common units. The high and low sales prices (composite transactions) by quarter for the years ended December 31, 2006 and 2005 were as follows:

 

    

Price Range of

Common Unit

     High    Low

Year 2006

     

4th Quarter

   $ 57.75    $ 49.05

3rd Quarter

     52.50      48.75

2nd Quarter

     54.00      48.82

1st Quarter

     54.70      49.75

Year 2005

     

4th Quarter

   $ 59.00    $ 50.15

3rd Quarter

     60.80      53.50

2nd Quarter

     64.20      59.25

1st Quarter

     62.90      58.10

The cash distributions applicable to each of the quarters in the years ended December 31, 2006 and 2005 were as follows:

 

     Record Date    Payment Date   

Amount

Per Unit

Year 2006

        

4th Quarter

   February 7, 2007    February 14, 2007    $ 0.915

3rd Quarter

   November 7, 2006    November 14, 2006      0.915

2nd Quarter

   August 7, 2006    August 14, 2006      0.885

1st Quarter

   May 5, 2006    May 12, 2006      0.885

Year 2005

        

4th Quarter

   February 7, 2006    February 14, 2006    $ 0.855

3rd Quarter

   November 7, 2005    November 14, 2005      0.855

2nd Quarter

   August 5, 2005    August 12, 2005      0.855

1st Quarter

   May 6, 2005    May 13, 2005      0.800

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

 

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The general partner, Riverwalk Logistics, L.P., 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 %

The general partner’s incentive distributions for the years ended December 31, 2006 and 2005 totaled $14.8 million and $10.3 million, respectively. The general partner’s share of our distributions for the years ended December 31, 2006 and 2005 was 9.9% and 8.8%, respectively, due to the impact of the incentive distributions.

Effective March 11, 2004, our partnership agreement was amended to lower the general partner’s incentive distribution rights with respect to distributions of available cash from 48% to 23% of the amount of any quarterly distribution that exceeds $0.90 per unit. The general partner will continue to receive 2% of the distributions with respect to its general partner interest.

 

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ITEM 6. SELECTED FINANCIAL DATA

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

 

     Year Ended December 31,
   2006    2005 (a)    2004    2003 (b)    2002
   (Thousands of Dollars, Except Per Unit Data)

Statement of Income Data:

              

Revenues

   $ 1,135,674    $ 659,557    $ 220,792    $ 181,450    $ 118,458

Operating income

     211,312      152,952      97,268      82,261      56,320

Income from continuing operations

     149,906      107,675      78,418      69,593      55,143

Basic and diluted income from continuing operations per unit applicable to limited partners (c)

     2.84      2.76      3.15      3.02      2.72

Cash distributions per unit applicable to limited partners

     3.600      3.365      3.20      2.95      2.75

 

     As of December 31,
     2006    2005 (a)    2004    2003 (b)    2002
     (Thousands of Dollars)

Balance Sheet Data:

              

Property and equipment, net

   $ 2,345,135    $ 2,160,213    $ 784,999    $ 765,002    $ 349,276

Total assets

     3,482,866      3,366,992      857,507      827,557      415,508

Long-term debt (less current portion)

     1,353,720      1,169,659      384,171      353,257      108,911

Partners’ equity

     1,875,681      1,900,779      438,311      438,163      293,895

(a) The significant increase in revenues, operating income, income from continuing operations and balance sheet data are due primarily to the Kaneb Acquisition.
(b) On March 18, 2003, Valero Energy contributed the South Texas Pipeline and Terminal Business and certain feedstock storage tanks to us for $350.3 million, including transaction costs.
(c) Income from continuing operations per unit applicable to limited partners is computed by dividing income from continuing operations applicable to limited partners, after deduction of the general partner’s 2% interest and incentive distributions, by the weighted average number of limited partnership units outstanding for each class of unitholder. Basic and diluted income from continuing operations per unit applicable to limited partners is the same because we have no potentially dilutive securities outstanding.

 

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

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

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

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

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

Recent Developments

On February 16, 2007, we announced that we would change our name to NuStar Energy, L.P. (NYSE: NS). Also, Valero GP Holdings, LLC, our general partner, announced it would change its name to NuStar GP Holdings, LLC (NYSE: NGP). Both name changes are expected to be effective April 1, 2007.

On December 1, 2006, we acquired a crude oil storage and blending facility in St. James, Louisiana from Koch Supply and Trading, L.P. for approximately $141.7 million. The acquisition includes 17 crude oil tanks with a total capacity of approximately 3.3 million barrels. Additionally, the facility has 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. We funded the acquisition with borrowings under our revolving credit agreement.

On July 19, 2006, certain subsidiaries of Valero Energy Corporation (Valero Energy) sold 17,250,000 units of Valero GP Holdings (NYSE: VEH) in an initial public offering (IPO) for a price to the public of $22.00 per unit. On December 22, 2006, Valero Energy sold their remaining ownership interest in Valero GP Holdings in a secondary public offering. The 25,250,000 units representing limited liability company interests of Valero GP Holdings sold at a price of $21.62 per unit. Included in the 25,250,000 units sold were 4,700,000 unregistered units sold to Mr. William Greehey, Chairman of our board of directors, at a price of $21.62 per unit. Valero GP Holdings did not receive any proceeds from the IPO or the secondary public offering, and Valero Energy’s indirect ownership interest in Valero GP Holdings has been reduced to zero.

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

Effective January 1, 2006, we purchased a 23.77% interest in Capwood pipeline from Valero Energy for $12.8 million. The Capwood pipeline is a 57-mile crude oil pipeline that extends from Patoka, Illinois to Wood River, Illinois. Plains All American Pipeline L.P., the operator of the Capwood pipeline, owns the remaining 76.23% interest. The results of operations of our interest in the Capwood pipeline are included in the crude oil pipeline segment for the year ended December 31, 2006.

 

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

Overview

Valero L.P. is a publicly traded Delaware limited partnership formed in 1999 engaged in the crude oil and refined product transportation, terminalling and storage business. Valero L.P. has terminal facilities in 28 U.S. states, Canada, Mexico, the Netherlands Antilles, the United Kingdom and the Netherlands.

As a result of the Kaneb Acquisition, our business changed significantly. Geographically, we expanded from operating primarily in Texas and bordering states, to operating across the United States and internationally. Additionally, prior to the Kaneb Acquisition we relied on Valero Energy almost exclusively for our revenues and cash flows. The Kaneb Acquisition greatly increased our volume from customers other than Valero Energy and consequently reduced our dependence on that one customer. Also in connection with the Kaneb Acquisition, we began selling bunker fuel from certain facilities that we acquired. Principally as a result of including the results from the Kaneb Acquisition for a full year in 2006 compared to six months in 2005, our revenues increased to $1,135.7 million for the year ended December 31, 2006 compared to $659.6 million for the year ended December 31, 2005. Also, our net income increased to $149.5 million for 2006, compared to $111.1 million for 2005. Our debt-to-capitalization ratio was 41.9% as of December 31, 2006 compared to 38.1% as of December 31, 2005.

We conduct our operations through our wholly owned subsidiaries, primarily Valero Logistics Operations, L.P. (Valero Logistics) and Kaneb Pipe Line Operating Partnership, L.P. (KPOP). Our operations are divided into four reportable business segments: refined product terminals, refined product pipelines, crude oil pipelines and crude oil storage tanks.

Refined Product Terminals. We own 56 terminals in the United States that provide storage and handling services on a fee basis for petroleum products, specialty chemicals and other liquids, including one that provides storage services for crude oil and other feedstocks. We also own international terminal operations on the island of St. Eustatius in the Caribbean, Point Tupper in Nova Scotia, Canada, the United Kingdom, the Netherlands and Nuevo Laredo in Mexico. We sold eight terminals located in Australia and New Zealand on March 30, 2006.

Refined Product Pipelines. We own common carrier pipelines in Texas, Oklahoma, Colorado, New Mexico, Kansas, Nebraska, Iowa, South Dakota, North Dakota and Minnesota covering approximately 6,259 miles, consisting of the Central West System which is connected to Valero Energy refineries and the East Pipeline and the North Pipeline which we acquired from Kaneb. In addition, we own a 2,000 mile anhydrous ammonia pipeline located in Louisiana, Arkansas, Missouri, Illinois, Indiana, Iowa and Nebraska.

Crude Oil Pipelines. We own 797 miles of crude oil pipelines which transport crude oil and other feedstocks, such as gas oil, from various points in Texas, Oklahoma, Kansas and Colorado to Valero Energy’s McKee, Three Rivers and Ardmore refineries as well as associated crude oil storage facilities in Texas and Oklahoma that are located along the crude oil pipelines. We also own an interest in 57 miles of crude oil pipeline in Illinois, which serves ConocoPhillips’ Wood River refinery.

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

 

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We provide transportation, storage services and ancillary services to our customers, including Valero Energy, which prior to December 22, 2006, indirectly owned our general partner. Factors that affect the results of our operations include:

 

   

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

 

   

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

 

   

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

 

   

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

 

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Results of Operations

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

Financial Highlights

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

 

     Year Ended December 31,        
     2006     2005     Change  

Statement of Income Data:

      

Revenues:

      

Service revenues

   $ 624,701     $ 407,194     $ 217,507  

Product sales

     510,973       252,363       258,610  
                        

Total revenues

     1,135,674       659,557       476,117  

Costs and expenses:

      

Cost of product sales

     466,276       229,806       236,470  

Operating expenses

     312,604       185,351       127,253  

General and administrative expenses

     45,216       26,553       18,663  

Depreciation and amortization

     100,266       64,895       35,371  
                        

Total costs and expenses

     924,362       506,605       417,757  
                        

Operating income

     211,312       152,952       58,360  

Equity earnings from joint ventures

     5,882       2,319       3,563  

Interest and other expense, net

     (61,427 )     (42,883 )     (18,544 )
                        

Income from continuing operations before income tax expense

     155,767       112,388       43,379  

Income tax expense

     5,861       4,713       1,148  
                        

Income from continuing operations

     149,906       107,675       42,231  

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

     (376 )     3,398       (3,774 )
                        

Net income

     149,530       111,073       38,457  

Less net income applicable to general partner

     (16,910 )     (10,758 )     (6,152 )
                        

Net income applicable to limited partners

   $ 132,620     $ 100,315     $ 32,305  
                        

Weighted average number of basic and diluted units outstanding

     46,809,749       35,023,250       11,786,499  
                        

Net income per unit applicable to limited partners:

      

Continuing operations

   $ 2.84     $ 2.76     $ 0.08  

Discontinued operations

     (0.01 )     0.10       (0.11 )
                        

Net income

   $ 2.83     $ 2.86     $ (0.03 )
                        

 

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Segment Operating Highlights

(Thousands of Dollars, Except Barrel/Day Information)

 

     Year Ended December 31,       
     2006    2005    Change  

Refined Product Terminals:

        

Throughput (barrels/day)(a)(b)

     262,560      245,084      17,476  

Throughput revenues

   $ 49,252    $ 43,617    $ 5,635  

Storage lease revenues

     247,524      115,352      132,172  

Product sales (bunkering)

     505,531      252,363      253,168  
                      

Total revenues

     802,307      411,332      390,975  

Cost of product sales

     462,029      229,806      232,223  

Operating expenses

     192,357      94,607      97,750  

Depreciation and amortization

     45,485      25,008      20,477  
                      

Segment operating income

   $ 102,436    $ 61,911    $ 40,525  
                      

Refined Product Pipelines:

        

Throughput (barrels/day)(a)

     711,476      556,654      154,822  

Throughput revenues

   $ 222,356    $ 149,853    $ 72,503  

Product sales

     5,442      —        5,442  
                      

Total revenues

     227,798      149,853      77,945  

Cost of product sales

     4,247      —        4,247  

Operating expenses

     93,314      64,671      28,643  

Depreciation and amortization

     42,084      27,778      14,306  
                      

Segment operating income

   $ 88,153    $ 57,404    $ 30,749  
                      

Crude Oil Pipelines:

        

Throughput (barrels/day)

     421,666      358,965      62,701  

Revenues

   $ 58,654    $ 51,429    $ 7,225  

Operating expenses

     16,825      16,378      447  

Depreciation and amortization

     5,061      4,612      449  
                      

Segment operating income

   $ 36,768    $ 30,439    $ 6,329  
                      

Crude Oil Storage Tanks:

        

Throughput (barrels/day)

     502,689      517,409      (14,720 )

Revenues

   $ 46,915    $ 46,943    $ (28 )

Operating expenses

     10,108      9,695      413  

Depreciation and amortization

     7,636      7,497      139  
                      

Segment operating income

   $ 29,171    $ 29,751    $ (580 )
                      

Consolidated Information:

        

Revenues

   $ 1,135,674    $ 659,557    $ 476,117  

Cost of product sales

     466,276      229,806      236,470  

Operating expenses

     312,604      185,351      127,253  

Depreciation and amortization

     100,266      64,895      35,371  
                      

Segment operating income

     256,528      179,505      77,023  

General and administrative expenses

     45,216      26,553      18,663  
                      

Consolidated operating income

   $ 211,312    $ 152,952    $ 58,360  
                      

(a) Throughput related to newly acquired assets included in the table above is calculated based on throughput for the period from the date of acquisition through December 31 of the year of acquisition divided by the number of days in the applicable year.
(b) Excludes throughputs related to the storage lease and bunkering revenues.

 

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Annual Highlights

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

Segment operating income for the year ended December 31, 2006 increased $77.0 million compared to the year ended December 31, 2005, primarily due to a $40.5 million increase in the refined product terminals segment, a $30.7 million increase in the refined product pipelines segment and a $6.3 million increase in the crude oil pipelines segment. Increases in the refined product terminals and refined product pipeline segments relate primarily to the effect of the Kaneb Acquisition, while the crude oil pipelines segment increased due to the acquisition of our interest in the Capwood crude oil pipeline. Except for storage lease revenues and bunker sales, operating income for our segments depends upon the level of throughputs moving through our assets. In addition to the Kaneb Acquisition, which impacted only the refined product terminals and refined product pipelines segments, all of our segments, except the crude oil storage tank segment, were affected by lower throughputs in 2005 resulting from scheduled maintenance turnarounds or other operational issues at Valero Energy’s McKee, Three Rivers and Ardmore refineries.

Refined Product Terminals

Revenues increased by $391.0 million for the year ended December 31, 2006, compared to the year ended December 31, 2005, primarily due to the following:

 

   

the Kaneb Acquisition contributed $505.5 million of bunkering revenues and $247.5 million of storage lease revenues for the year ended December 31, 2006 compared to $252.4 million of bunkering revenues and $115.4 million of storage lease revenues for the period from July 1, 2005 to December 31, 2005;

 

   

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

 

   

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

 

   

an increase in the fees charged at our terminals.

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

Cost of product sales totaled $462.0 million for the year ended December 31, 2006 and $229.8 million for the period from July 1, 2005 to December 31, 2005. Cost of product sales reflects the cost of bunker fuel sold to marine vessels at our two facilities we acquired as part of the Kaneb Acquisition.

Operating expenses increased $97.8 million for the year ended December 31, 2006, compared to the year ended December 31, 2005, primarily due to the inclusion of a full year in 2006 of operating expenses related to the assets acquired in the Kaneb Acquisition.

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

Refined Product Pipelines

Revenues increased by $77.9 million for the year ended December 31, 2006, compared to the year ended December 31, 2005, primarily due to the following:

 

   

the Kaneb Acquisition contributed $121.8 million of revenues for the year ended December 31, 2006 compared to $57.4 million of revenue for the period from July 1, 2005 to December 31, 2005;

 

   

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

 

   

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

 

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Operating expenses increased by $28.6 million for the year ended December 31, 2006, compared to the year ended December 31, 2005, primarily due to the inclusion of a full year in 2006 of operating expenses related to the assets acquired in the Kaneb Acquisition.

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

Crude Oil Pipelines

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

Crude Oil Storage Tanks

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

General

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

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

Interest and other expense, net increased by $18.5 million for the year ended December 31, 2006 compared to the year ended December 31, 2005, due to higher average debt balances resulting from debt assumed as part of the Kaneb Acquisition and debt incurred to fund the Kaneb Acquisition combined with higher interest rates in 2006. Partially offsetting this increase was an impairment charge of $2.1 million in 2005 as a portion of the Three Rivers to Pettus to Corpus Christi, Texas refined product pipeline was permanently idled.

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

 

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Year Ended December 31, 2005 Compared to Year Ended December 31, 2004

Financial Highlights

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

 

     Year Ended December 31,        
     2005     2004     Change  

Statement of Income Data:

      

Revenues:

      

Service revenue

   $ 407,194     $ 220,792     $ 186,402  

Product sales

     252,363       —         252,363  
                        

Total revenues

     659,557       220,792       438,765  

Costs and expenses:

      

Cost of product sales

     229,806       —         229,806  

Operating expenses

     185,351       79,054       106,297  

General and administrative expenses

     26,553       11,321       15,232  

Depreciation and amortization

     64,895       33,149       31,746  
                        

Total costs and expenses

     506,605       123,524       383,081  
                        

Operating income

     152,952       97,268       55,684  

Equity earnings from joint ventures

     2,319       1,344       975  

Interest and other expense, net

     (42,883 )     (20,194 )     (22,689 )
                        

Income from continuing operations before income tax expense

     112,388       78,418       33,970  

Income tax expense

     4,713       —         4,713  
                        

Income from continuing operations

     107,675       78,418       29,257  

Income from discontinued operations, net of income tax

     3,398       —         3,398  
                        

Net income

     111,073       78,418       32,655  

Less net income applicable to the general partner

     (10,758 )     (5,927 )     (4,831 )
                        

Net income applicable to limited partners

   $ 100,315     $ 72,491     $ 27,824  
                        

Weighted average number of basic and diluted units outstanding

     35,023,250       23,041,394       11,981,856  
                        

Net income per unit applicable to limited partners:

      

Continuing operations

   $ 2.76     $ 3.15     $ (.39 )

Discontinued operations

     0.10       —         0.10  
                        

Net income

   $ 2.86     $ 3.15     $ (.29 )
                        

 

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Segment Operating Highlights

(Thousands of Dollars, Except Barrel/Day Information)

 

     Year Ended December 31,       
     2005    2004    Change  

Refined Product Terminals:

        

Throughput (barrels/day)(a)(b)

     245,084      256,576      (11,492 )

Throughput revenues

   $ 43,617    $ 39,984    $ 3,633  

Storage lease revenues

     115,352      —        115,352  

Product sales (bunkering)

     252,363      —        252,363  
                      

Total revenues

     411,332      39,984      371,348  

Cost of product sales

     229,806      —        229,806  

Operating expenses

     94,607      18,365      76,242  

Depreciation and amortization

     25,008      6,471      18,537  
                      

Segment operating income

   $ 61,911    $ 15,148    $ 46,763  
                      

Refined Product Pipelines:

        

Throughput (barrels/day)(a)

     556,654      442,596      114,058  

Revenues

   $ 149,853    $ 86,418    $ 63,435  

Operating expenses

     64,671      37,332      27,339  

Depreciation and amortization

     27,778      14,715      13,063  
                      

Segment operating income

   $ 57,404    $ 34,371    $ 23,033  
                      

Crude Oil Pipelines:

        

Throughput (barrels/day)

     358,965      381,358      (22,393 )

Revenues

   $ 51,429    $ 52,462    $ (1,033 )

Operating expenses

     16,378      15,468      910  

Depreciation and amortization

     4,612      4,499      113  
                      

Segment operating income

   $ 30,439    $ 32,495    $ (2,056 )
                      

Crude Oil Storage Tanks:

        

Throughput (barrels/day)

     517,409      473,714      43,695  

Revenues

   $ 46,943    $ 41,928    $ 5,015  

Operating expenses

     9,695      7,889      1,806  

Depreciation and amortization

     7,497      7,464      33  
                      

Segment operating income

   $ 29,751    $ 26,575    $ 3,176  
                      

Consolidated Information:

        

Revenues

   $ 659,557    $ 220,792    $ 438,765  

Cost of product sales

     229,806      —        229,806  

Operating expenses

     185,351      79,054      106,297  

Depreciation and amortization

     64,895      33,149      31,746  
                      

Segment operating income

     179,505      108,589      70,916  

General and administrative expenses

     26,553      11,321      15,232  
                      

Consolidated operating income

   $ 152,952    $ 97,268    $ 55,684  
                      

(a) Throughput related to newly acquired assets included in the table above is calculated based on throughput for the period from the date of acquisition through December 31 of the year of acquisition divided by the number of days in the applicable year.
(b) Excludes throughputs related to the storage lease and bunkering revenues.

 

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Annual Highlights

Net income for the year ended December 31, 2005 increased $32.7 million compared to the year ended December 31, 2004 due to higher segmental operating income, partially offset by increased general and administrative expense, increased interest expense and increased income tax expense. All of these increases predominantly resulted from the Kaneb Acquisition.

Segment operating income for the year ended December 31, 2005 increased $70.9 million compared to the year ended December 31, 2004, primarily due to a $46.8 million increase in operating income for the refined product terminals segment and a $23.0 million increase in operating income for the refined product pipelines segment. These increases relate primarily to the effect of the Kaneb Acquisition. Except for storage lease revenues and bunker sales, operating income for our segments depends upon the level of throughputs moving through our assets. In addition to the Kaneb Acquisition, which impacted only the refined product terminals and refined product pipelines segments, all of our segments were affected by lower throughputs in 2005 resulting from scheduled maintenance turnarounds or other operational issues at Valero Energy’s McKee, Three Rivers and Ardmore refineries.

Refined Product Terminals

Revenues increased by $371.3 million for the year ended December 31, 2005, compared to the year ended December 31, 2004, primarily due to the following:

 

   

the Kaneb Acquisition, which contributed $115.4 million of storage lease revenues and $252.4 million of bunkering revenues; and

 

   

higher throughputs at our asphalt terminals, which charge a higher terminalling fee than our other refined product terminals, resulting in increased revenues of $3.1 million.

Partially offsetting the increases above were lower throughputs resulting from the McKee refinery turnaround, coupled with downtime of a unit at the McKee refinery.

Cost of sales was $229.8 million for the year ended December 31, 2005. Cost of sales reflects the cost of bunker fuel sold to marine vessels at our facilities at St. Eustatius, Netherlands Antilles and Point Tupper, Nova Scotia, which we acquired as part of the Kaneb Acquisition.

Operating expenses increased $76.2 million for the year ended December 31, 2005, compared to the year ended December 31, 2004, primarily due to the inclusion in 2005 of operating expenses related to the assets acquired in the Kaneb Acquisition. Operating expenses further increased compared to 2004 due to increased regulatory and maintenance expense and increased internal overhead expense resulting from increased headcount.

Depreciation and amortization expense increased by $18.5 million primarily due to an increase in our property and equipment related to the Kaneb Acquisition.

Refined Product Pipelines

Revenues increased by $63.4 million for the year ended December 31, 2005, compared to the year ended December 31, 2004, primarily due to increased throughputs due to the following:

 

   

the Kaneb Acquisition, which increased throughputs by 115,096 barrels per day, resulting in additional revenues of $57.4 million;

 

   

the Dos Laredos pipeline system, which only operated for part of 2004, contributed $3.4 million of additional revenue since it operated for a full year in 2005 and due to a change in the contract terms with Petroleos Mexicanos (PEMEX), allowing for an increase in volumes from 5,000 barrels per day to 10,000 barrels per day;

 

   

the supply dynamics in the Denver market resulted in increased throughputs transported on the McKee to Denver refined product pipeline, a high tariff rate pipeline, resulting in higher revenues of $3.3 million, despite the McKee turnaround; and

 

   

the expansion of the Corpus Christi to Harlingen to Edinburg refined product pipeline, which commenced operations in October 2005, increased revenue by $0.9 million.

Partially offsetting the increases above were lower throughputs in the refined product pipelines that support Valero Energy’s Ardmore and Three Rivers refineries, which experienced maintenance turnarounds during 2005.

 

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Operating expenses increased by $27.3 million for the year ended December 31, 2005, compared to the year ended December 31, 2004, primarily due to the inclusion in 2005 of operating expenses related to the assets acquired in the Kaneb Acquisition. Operating expenses also increased due to higher regulatory and maintenance expenses related to repairs on the McKee to Denver and Houston pipelines.

Depreciation and amortization expense increased $13.1 million for the year ended December 31, 2005, compared to the year ended December 31, 2004, due to increases in our property and equipment related to the following:

 

   

the Kaneb Acquisition, which contributed depreciation and amortization expense of $12.1 million;

 

   

the expansion of the Corpus Christi to Harlingen to Edinburg refined product pipeline, which commenced operations in October 2005, resulting in additional depreciation expense of $0.5 million; and

 

   

the Dos Laredos pipeline system, which only operated for part of 2004, resulted in higher depreciation expense of $0.2 million for the full year of 2005.

Crude Oil Pipelines

Revenues decreased $1.0 million for the year ended December 31, 2005, compared to the year ended December 31, 2004. Decreased revenues resulted primarily from lower throughputs, due to the scheduled turnarounds at the Three Rivers and McKee refineries, coupled with separate downtime of a unit at the McKee refinery. Revenues increased on the Ringgold to Wasson crude oil pipeline, despite lower overall throughputs to the Ardmore refinery, due to increased throughput in this higher tariff rate pipeline.

Operating expenses increased by $0.9 million for the year ended December 31, 2005, compared to the year ended December 31, 2004 primarily due to higher maintenance expense on the Wasson to Ardmore and the Wichita Falls crude oil pipelines, partially offset by decreased power costs after idling several pump stations on the Wichita Falls pipeline as part of the power optimization program.

Crude Oil Storage Tanks

Revenues increased $5.0 million for the year ended December 31, 2005 compared to the year ended December 31, 2004, primarily due to a lack of significant operating downtime at the Texas City refinery or the Benicia refinery during 2005, resulting in increased throughput in our crude oil storage tanks.

Operating expenses increased by $1.8 million for the year ended December 31, 2005 compared to the year ended December 31, 2004, due to higher regulatory and maintenance expense on the Corpus Christi and Texas City crude oil storage tanks.

General

General and administrative expenses increased by $15.2 million for the year ended December 31, 2005 compared to the year ended December 31, 2004, partially due to increased headcount as a result of the Kaneb Acquisition. Additionally, on July 1, 2005, we amended the service agreement with Valero Energy to reflect the increased level of service resulting from the addition of Kaneb, which increased our annual fee to Valero Energy.

Interest and other expense, net increased by $22.7 million for the year ended December 31, 2005 compared to the year ended December 31, 2004, due to higher average debt balances resulting from debt assumed as part of the Kaneb Acquisition and debt incurred to fund the Kaneb Acquisition combined with higher interest rates in 2005. Additionally, in the fourth quarter of 2005, a portion of the Three Rivers to Pettus to Corpus Christi, Texas refined product pipeline was permanently idled. As a result, we recorded an impairment charge of $2.1 million included in “interest and other expense, net.”

Income tax expense was $4.7 million for the year ended December 31, 2005, all of which related to certain operations acquired in the Kaneb Acquisition that are conducted through separate taxable wholly owned corporate subsidiaries.

 

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Outlook

Turnarounds or outages at our customers’ refineries have a significant effect on our earnings, as do maintenance expenses and market conditions. We expect several of the refineries that we serve to undergo turnaround activity in 2007. In addition, Valero Energy’s McKee refinery, which several of our pipelines and terminals serve, experienced a fire on February 16, 2007, which shut down the refinery. We do not know how long the McKee refinery will remain shut down, however we expect the impact to our earnings to be somewhat mitigated by business interruption insurance.

For 2007, we expect general and administrative expenses, mainly related to information system, human resources and telecommunications, to increase due to our separation from Valero Energy.

Overall, the outlook for 2007 remains positive. During 2006, we completed key expansion projects and we commenced construction on other significant expansion projects, which we expect to start contributing to our earnings in 2007. We should benefit from higher revenues in the latter half of 2007 as a result of these investments. Additionally, effective July 1st, we expect the tariffs on our pipelines to increase, which will also positively impact our results.

LIQUIDITY AND CAPITAL RESOURCES

General

Our primary cash requirements are for distributions to partners, debt service, reliability and expansion capital expenditures, acquisitions and normal operating expenses. We typically generate sufficient cash from our current operations to fund day-to-day operating and general and administrative expenses, reliability capital expenditures and distribution requirements. We also have available borrowing capacity under our existing revolving credit facility and, to the extent necessary, we may raise additional funds through equity or debt offerings under our $750 million universal shelf registration statement to fund strategic capital expenditures or other cash requirements not funded from operations. However, there can be no assurance regarding the availability of any additional funds or whether such additional funds can be provided on terms acceptable to us.

Cash Flows for the Year Ended December 31, 2006 and 2005

Net cash provided by operating activities for the year ended December 31, 2006 was $250.8 million compared to $186.4 million for the year ended December 31, 2005. The increase in cash generated from operating activities is primarily due to higher net income and depreciation expense.

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

Net cash provided by operating activities for the year ended December 31, 2005 was $186.4 million. The net cash provided by operations, combined with available cash on hand, was used primarily to fund distributions to unitholders and the general partner in the aggregate amount of $127.8 million. Additionally, we used cash from those sources in combination with long-term debt borrowings totaling $746.5 million, combined with proceeds from the general partner contribution totaling $29.2 million and proceeds received from the sale of Martin Oil LLC to a subsidiary of Valero Energy totaling $26.8 million to fund the Kaneb Acquisition, repay certain outstanding indebtedness of Kaneb and to fund capital expenditures and investment of other noncurrent assets of $68.1 million and $3.3 million, respectively. Proceeds received from the sale of the Held Separate Businesses on September 30, 2005 were used to repay debt outstanding under the Revolving Credit Agreement and the Term Credit Agreement, which was incurred to partially finance the Kaneb Acquisition.

Equity

Shelf Registration Statement. On October 2, 2003, the United States Securities and Exchange Commission (the SEC) declared effective a shelf registration statement on Form S-3 filed by us and Valero Logistics to register $750.0 million of securities for potential future issuance. We may, in one or more offerings, offer and sell common units representing

 

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limited partner interests in the Partnership. Valero Logistics may, in one or more offerings, offer and sell debt securities, which will be fully and unconditionally guaranteed by us. The full balance of the $750.0 million universal shelf registration statement is available as of December 31, 2006.

Subordinated Units. Effective April 1, 2006, we satisfied all the conditions included in our partnership agreement for the subordination period to end. Accordingly, all 9,599,322 subordinated units converted into common units on a one-for-one basis on May 8, 2006, the first business day after the record date for the distribution related to the first quarter earnings of 2006. Riverwalk Holdings, LLC held the 9,599,322 subordinated units at the time of conversion.

Distributions. Valero L.P.’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 is entitled to incentive distributions, as defined below, if the amount we distribute with respect to any quarter exceeds $0.60 per unit. Effective March 11, 2004, Valero L.P.’s partnership agreement was amended to lower the general partner’s incentive distribution rights with respect to distributions of available cash from 48% to 23% of the amount of any quarterly distribution that exceeds $0.90 per unit. The general partner will continue to receive a 2% distribution with respect to its general partner interest. 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,
   2006    2005 (a)    2004
   (Thousands of Dollars, Except Per Unit Data)

General partner interest

   $ 3,742    $ 3,036    $ 1,595

General partner incentive distribution

     14,778      10,259      4,449
                    

Total general partner distribution

     18,520      13,295      6,044

Limited partners’ distribution

     168,515      138,500      73,733
                    

Total cash distributions

   $ 187,035    $ 151,795    $ 79,777
                    

Cash distributions per unit applicable to limited partners

   $ 3.600    $ 3.365    $ 3.200
                    

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

On January 25, 2007, we declared a quarterly distribution of $0.915 per unit, which was paid on February 14, 2007 to unitholders of record on February 7, 2007. This distribution, related to the fourth quarter of 2006, totaled $47.7 million, of which $4.9 million represented the general partner’s share, including a $3.9 million incentive distribution.

Capital Requirements

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

 

   

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

 

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

During the year ended December 31, 2006, we incurred reliability capital expenditures of $34.0 million primarily related to system automation and maintenance upgrade projects at our terminals and pipelines, and expansion capital expenditures of $90.1 million primarily related to the construction of 110 miles of new pipeline in the northeastern Mexico and South Texas regions (Burgos Project) and the St. Eustatius and Amsterdam terminal expansion projects.

For 2007, we expect to incur approximately $255.0 million of capital expenditures, including $45.0 million for reliability capital projects and $210.0 million for expansion capital projects and capital expenditures required as a result of our separation from Valero Energy. We continuously evaluate our capital budget and make changes as economic conditions warrant. If conditions warrant, our actual capital expenditures for 2007 may exceed the budgeted amounts. We believe cash generated from operations combined with other sources of liquidity previously described will be sufficient to fund our capital expenditures in 2007.

Long-Term Contractual Obligations

6.05% Senior Notes

On March 18, 2003, Valero Logistics completed the sale of $250 million of 6.05% senior notes, maturing in 2013, issued in a private placement to institutional investors, for net proceeds of $247.3 million. Interest on the 6.05% senior notes is payable semi-annually in arrears on March 15 and September 15 of each year. Although the 6.05% senior notes were not initially registered under the Securities Act of 1933 or any other securities laws, in July 2003, we exchanged the outstanding $250.0 million 6.05% senior notes that were not registered for $250.0 million of 6.05% senior notes that have been registered under the Securities Act of 1933.

6.875% Senior Notes

On July 15, 2002, we completed the sale of $100.0 million of 6.875% senior notes, maturing in 2012, for net proceeds of $98.2 million. The net proceeds were used to repay the $91.0 million then outstanding under the revolving credit facility. Interest on the 6.875% senior notes is payable semi-annually in arrears on January 15 and July 15 of each year.

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

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

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

7.75% and 5.875% Senior Notes

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

 

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

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

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

Term Loan Agreement

The $525 million term loan agreement dated July 1, 2005 (the Term Loan Agreement) matures on July 1, 2010 and bears interest based on either an alternative base rate or LIBOR, which was 6.0% as of December 31, 2006. The weighted-average interest rate related to outstanding borrowings under the Term Loan Agreement for the year ended December 31, 2006 was 5.8%. As of December 31, 2006 and 2005, our outstanding balance under the Term Loan Agreement was $225.0 million. No additional funds may be borrowed under the Term Loan Agreement.

Revolving Credit Agreement

The revolving credit agreement (the Revolving Credit Agreement), dated effective December 20, 2004 as amended on June 30, 2005, bears interest based on either an alternative base rate or LIBOR, which was 6.1% as of December 31, 2006. As of December 31, 2006 and 2005, we had $408.6 million and $395.1 million, respectively, available for borrowing under the Revolving Credit Agreement. The weighted-average interest rate related to outstanding borrowings under the Revolving Credit Agreement for the year ended December 31, 2006 was 5.8%.

UK Term Loan

As a result of the Kaneb Acquisition, on July 1, 2005, we amended and restated a term loan agreement of Kaneb’s UK subsidiary dated January 29, 1999 (the UK Term Loan), and assumed the outstanding obligation of 21,000,000 Pounds Sterling ($41.1 million and $36.1 million as of December 31, 2006 and 2005, respectively). The UK Term Loan bears interest at 6.65% annually.

Credit Agreement Provisions

The Term Loan Agreement, the Revolving Credit Agreement and the UK Term Loan all require that we maintain certain financial ratios and include other restrictive covenants, including a prohibition on distributions if any defaults, as defined in the agreements, exists or would result from the distribution. Management believes that we are in compliance with all ratios and covenants of the Term Loan Agreement, the Revolving Credit Agreement and the UK Term Loan as of December 31, 2006.

Credit Agreement Amendments

On June 6, 2006, we completed certain amendments to our Term Loan Agreement and our Revolving Credit Agreement. Both agreements were amended to (i) eliminate the provision that the failure of Valero Energy to own or control the general partner of Valero L.P. constitutes a “change of control”; (ii) extend the maturities of the agreements to 2011; (iii) include certain material construction projects in the definition of “Consolidated EBITDA”; and (iv) eliminate the requirement that we maintain a minimum consolidated interest coverage ratio. Additionally, the amendments reduced the applicable margin on LIBOR loans to vary from 0.40% to 0.95% for the Term Loan Agreement and 0.27% to 0.70% for the Revolving Credit Agreement, depending upon Valero L.P.’s credit rating. Additionally, the UK Term Loan was amended to (i) extend the maturity to 2011; (ii) include certain material construction projects in the definition of “Consolidated EBITDA”; and (iii) eliminate the requirement that we maintain a minimum consolidated interest coverage ratio.

 

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On November 30, 2006, we further amended our Term Loan Agreement, our Revolving Credit Agreement and our UK Term Loan. All the agreements listed above were amended (i) to remove the requirement that the lenders approve in advance the amount of pro forma EBITDA associated with certain material construction projects used in the calculation of consolidated EBITDA, a component of the consolidated debt coverage ratio required by the covenants of the agreements, and (ii) to exclude from the agreements’ definition of Indebtedness the aggregate principal amount of hybrid equity securities, as defined in the amendment, that is treated as equity by Standard & Poors and Moody’s based on the classifications of these hybrid equity securities issued by Standard & Poors and Moody’s.

Our Revolving Credit Agreement was further amended to allow for borrowings denominated in Euros, up to the equivalent of $100 million. Also effective on November 30, 2006, the lenders agreed to our request to increase the total commitments under the Revolving Credit Agreement from $400 million to $600 million.

Port Authority of Corpus Christi Note Payable

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

Interest Rate Swaps

During 2003, we entered into 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, 2006 and 2005, the aggregate estimated fair value of the interest rate swaps included in other long-term liabilities in the consolidated balance sheet was $4.9 million and $4.0 million, respectively.

The interest rate swap contracts qualified for the shortcut method of accounting prescribed by SFAS 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended. As a result, changes in the fair value of the derivatives will completely offset the changes in the fair value of the underlying hedged items. As of December 31, 2006 and 2005, the weighted average effective interest rate for the interest rate swaps was 7.1% and 6.6%, respectively.

The following table presents our long-term contractual obligations and commitments and the related payments due, in total and by period, as of December 31, 2006.

 

     Payments Due by Period          
   2007    2008    2009    2010    2011    Thereafter    Total
   (Thousands of Dollars)

Long-term debt (stated maturities)

   $ 647    $ 660    $ 713    $ 770    $ 457,476    $ 854,049    $ 1,314,315

Operating leases

     7,979      7,737      6,570      6,394      5,900      104,269      138,849

Purchase obligations

     217,539      196,413      1,773      837      752      2,248      419,562

A purchase obligation is an enforceable and legally binding agreement to purchase goods or services that specifies significant terms, including (i) fixed or minimum quantities to be purchased, (ii) fixed, minimum or variable price provisions, and (iii) the approximate timing of the transaction. Our purchase obligations consist mainly of a bunker fuel purchase agreement with minimum volume requirements, which is based on market prices. We entered into this agreement to support our operations at St. Eustatius whereby we purchase bunker fuel for resale to our customers.

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

 

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On April 13, 2006, we entered into an agreement to purchase three 30,000 barrel and two 52,000 barrel tank barges over the next two years for our St. Eustatius facility. The contract price is $34.1 million, which is subject to adjustment based on the actual cost incurred for the steel. In January of 2007, we assigned this purchase agreement to another company, which eliminates our obligation. In addition, we have signed an agreement to lease the constructed barges effective when the first barge is completed and delivered, which is estimated to be in third quarter 2007.

Related Party Transactions

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. Under the terms of various services agreements with Valero Energy (described below), we reimbursed Valero Energy for payroll costs of employees working on our behalf. Additionally, Valero Energy charged us an administrative service fee. Due to Valero Energy’s sale of its interest in Valero GP Holdings on December 22, 2006, the receivable from Valero Energy and payable to Valero Energy are not separately presented in the consolidated balance sheet as of December 31, 2006 as related party balances. The Receivable from Valero Energy as of December 31, 2005 represented amounts due for pipeline tariff, terminalling fee and crude oil storage tank fee revenues and the payable to Valero Energy as of December 31, 2006 represented amounts due for employee costs, insurance costs, operating expenses, administrative costs and lease expense.

The following table summarizes information pertaining to transactions with Valero Energy:

 

     Year Ended December 31,
     2006    2005 (a)    2004
     (Thousands of Dollars)

Revenues

   $ 260,980    $ 234,485    $ 217,608

Operating expenses

     94,587      60,921      31,960

General and administrative expenses

     32,183      19,356      10,539

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

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

Services Agreement

Because we do not have any employees, we have relied upon employees of Valero GP, LLC. Prior to our separation from Valero Energy, these employees were provided to us under the terms of various services agreements between us and Valero Energy. The terms of these services agreements generally provided that the costs of employees who performed services directly on our behalf, including salaries, wages and employee benefits, were charged directly to us. In addition, Valero Energy charged us an administrative services fee, which was $1.6 million, $6.6 million and $2.2 million for the years ended December 31, 2006, 2005 and 2004, respectively.

Due to Valero Energy’s sale of its remaining interest in Valero GP Holdings on December 22, 2006, Valero GP, LLC ceased being an indirect subsidiary of Valero Energy. Accordingly, Valero Energy no longer provides employees that work directly on our behalf. Instead, Valero GP, LLC provides those employees, and we reimburse Valero GP Holdings, which owns Valero GP, LLC for those employee costs. However, Valero Energy continues to provide certain services to us under the terms of a services agreement dated December 22, 2006 (the 2007 Services Agreement). Beginning January 1, 2007, under the 2007 Services Agreement, we pay Valero Energy approximately $97,000 per month for administrative services (primarily information system services and human resource services) and approximately $93,000 per month for telecommunication services.

 

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The 2007 Services Agreement terminates on December 31, 2010. We have the right to reduce the administrative or telecommunications services provided under the agreement at any time with 60 days notice. Valero Energy has the option to terminate the Services Agreement prior to December 31, 2010 if it provides us with written notice of its intention to do so. However, the administrative services performed by Valero Energy cannot be terminated prior to various optional termination dates specified in the Services Agreement and Valero Energy must continue to provide human resource services for six months subsequent to such notice. If Valero Energy elects to terminate the 2007 Services Agreement prior to December 31, 2010, they agreed to pay us a termination fee of $13.0 million.

If Valero Energy exercises its termination option and we are not able to perform those services ourselves or find another third party provider, we can request Valero Energy to continue to perform those services at a monthly fee significantly in excess of the current fees described above. If we are able to perform those services ourselves or engage another third party to provide them, our costs may exceed the amounts charged by Valero Energy.

Omnibus Agreement

On March 31, 2006, we entered into an amended and restated omnibus agreement (the 2006 Omnibus Agreement) with Valero Energy, Valero GP, LLC, Riverwalk Logistics, L.P., and Valero Logistics. The 2006 Omnibus Agreement supersedes the Omnibus Agreement among the parties dated effective April 16, 2001. The 2006 Omnibus Agreement governs potential competition between Valero Energy and us. Under the 2006 Omnibus Agreement, Valero Energy has agreed, and will cause its controlled affiliates to agree, for so long as Valero Energy owns 20% or more of us, not to engage in the business of transporting crude oil and other feedstocks or refined products, including petrochemicals, or operating crude oil storage facilities or refined product terminalling assets in the United States. This restriction does not apply to:

 

   

any business retained by Ultramar Diamond Shamrock Corporation (UDS) as of April 16, 2001, the closing of Valero L.P.’s initial public offering, or any business owned by Valero Energy at the date of its acquisition of UDS on December 31, 2001;

 

   

any business with a fair market value of less than $10 million;

 

   

any business acquired by Valero Energy in the future that constitutes less than 50% of the fair market value of a larger acquisition, provided Valero L.P. has been offered and declined the opportunity to purchase the business; and

 

   

any newly constructed pipeline, terminalling or storage assets that we have not offered to purchase at fair market value within one year of construction.

With the closing of Valero GP Holding’s secondary public offering on December 22, 2006, Valero Energy no longer owns 20% or more of us, which allows Valero Energy to compete with us.

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

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

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

 

   

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

 

   

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

 

   

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

If market conditions change with respect to the transportation of crude oil or refined products, or to the end markets in which Valero Energy sells refined products, in a material manner such that Valero Energy would suffer a material adverse effect if it were to continue to use our pipelines and terminals that serve the McKee, Three Rivers and Ardmore refineries at the required levels, Valero Energy’s obligation to us will be suspended during the period of the change in market conditions to the extent required to avoid the material adverse effect.

 

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In the event Valero Energy does not transport in our pipelines or use our terminals to handle the minimum volume requirements and if its obligation has not been suspended under the terms of the agreement, Valero Energy will be required to make a cash payment determined by multiplying the shortfall in volume by the applicable weighted average pipeline tariff or terminal fee. For the years ended December 31, 2006, 2005 and 2004, Valero Energy exceeded its obligations under the Pipelines and Terminals Usage Agreement. Additionally, Valero Energy has agreed not to challenge, or cause others to challenge, our interstate or intrastate tariffs for the transportation of crude oil and refined products until at least April 2008.

Crude Oil Storage Tank Agreements

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

 

   

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

 

   

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

 

   

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

South Texas Pipelines and Terminals Agreements

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

 

   

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

 

   

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

 

  -  

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

 

  -  

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

 

  -  

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

 

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  -  

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

 

  -  

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

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

Non-Compete Agreement

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

Administration Agreement

On July 19, 2006, in connection with Holdings’ initial public offering, Valero GP, LLC entered into an administration agreement with Holdings (the Administration Agreement). The Administration Agreement provides, among other things, that all of Holdings’ employees will be employees of Valero GP, LLC. Valero GP, LLC will provide all executive management, accounting, legal, cash management, corporate finance and other administrative services to Holdings. Under the Administration Agreement, Holdings will pay Valero GP, LLC $0.5 million annually. This fee will be increased annually to reflect Valero GP, LLC’s annual merit increases. Holdings will also reimburse Valero GP, LLC for all direct public company costs and any other direct costs, such as outside legal and accounting fees, that Valero GP, LLC incurs while providing services to Holdings pursuant to the Administration Agreement. The Administration Agreement will terminate on December 31, 2011, with automatic two-year renewals unless terminated by either party on six months’ written notice. Holdings may cancel or reduce the services provided by Valero GP, LLC under the Administration Agreement on 60 days’ written notice. The Administration Agreement will terminate upon a change of control of either Holdings or Valero GP, LLC.

St. James Terminalling agreement

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

Hydrogen Tolling Agreement

A hydrogen tolling agreement, which provides that Valero Energy will pay us minimum annual revenues of $1.4 million for transporting crude hydrogen from the BOC Group’s chemical facility in Clear Lake, Texas to Valero Energy’s Texas City refinery.

Pittsburgh Asphalt Terminal Throughput Agreement

A terminal storage and throughput agreement related to the Pittsburgh asphalt terminal, which provides that Valero Energy will pay us a monthly lease fee of $0.2 million, a minimum annual throughput fee of $0.4 million and will reimburse us for utility costs.

 

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Royal Trading Throughput Agreement

In conjunction with the Royal Trading acquisition, we entered into a five-year terminal storage and throughput agreement with Valero Energy. The agreement provides a base throughput and blending fee schedule with volume incentive discounts once certain thresholds are met. In addition, Valero Energy has agreed to utilize the acquired terminals for a minimum of 18.5% of the combined McKee and Ardmore refineries’ asphalt production.

Corpus Christi North Beach Storage Facility

We entered into a one-year shell barrel capacity lease agreement with Valero Energy on January 1, 2004 for the 1.6 million barrels of capacity at our Corpus Christi North Beach storage facility. This lease automatically renews for additional one-year terms unless either party terminates it with a 90-day written notice. This lease was terminated on December 31, 2006.

Effective January 1, 2007, we entered into a one-year terminal service agreement with Valero Energy for the 1.6 million barrels of capacity at our Corpus Christi North Beach storage facility. This agreement will automatically renew from year-to-year unless either party terminates it with a 90-day written notice.

Office Rental Agreement Termination

In January of 2006, we entered into an Office Rental Agreement (the Rental Agreement) with Valero Energy whereby we agreed to lease approximately 65,000 square feet of office space at an annual cost of approximately $1.6 million per year. Rental payments were scheduled to commence upon the completion of a new office facility presently being constructed by Valero Energy. Effective December 22, 2006, the Rental Agreement was terminated by the parties. No early termination penalties were incurred by any of the parties to the agreement.

Other Agreements

We have other minor storage and throughput contracts with Valero Energy resulting from the Kaneb Acquisition.

Environmental, Health and Safety

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

The balance of and changes in our accruals for environmental matters as of and for the years ended December 31, 2006, 2005 and 2004 are included in Note 11 of Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplemental Data.” We believe that we have adequately accrued for our environmental exposures.

CRITICAL ACCOUNTING POLICIES

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

Depreciation

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

 

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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 $2.0 million, which is included in other long-term liabilities on the consolidated balance sheet, for conditional asset retirement obligations related to the retirement of terminal assets with lease and right of way agreements as of December 31, 2006. Prior to the Kaneb Acquisition, we had not recorded a liability for asset retirement obligations.

Environmental Reserve

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

Contingencies

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

 

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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The principal market risk (i.e., the risk of loss arising from adverse changes in market rates and prices) to which we are exposed is interest rate risk on our debt. Additionally, we are exposed to exchange rate fluctuations on transactions related to our foreign operations.

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 revolving credit agreement expose us to increases in the benchmark interest rate underlying our variable rate revolving credit agreement.

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, 2006  
   Expected Maturity Dates              
   2007     2008     2009     2010     2011     Thereafter     Total     Fair Value  
     (Thousands of Dollars, Except Interest Rates)  

Long-term Debt:

                

Fixed rate

   $ 647     $ 660     $ 713     $ 770     $ 41,950     $ 854,048     $ 898,789     $ 939,191  

Average interest rate

     8.0 %     8.0 %     8.0 %     8.0 %     6.7 %     6.6 %     6.6 %  

Variable rate

   $ —       $ —       $ —       $ —       $ 415,526     $ —       $ 415,526     $ 415,526  

Average interest rate

     —         —         —         —         6.1 %     —         6.1 %  

Interest Rate Swaps Fixed to Variable:

                

Notional amount

   $ —       $ —       $ —       $ —       $ —       $ 167,500     $ 167,500     $ (4,908 )

Average pay rate

     7.0 %     6.7 %     6.7 %     6.8 %     6.9 %     6.8 %     6.8 %  

Average receive rate

     6.3 %     6.3 %     6.3 %     6.3 %     6.3 %     6.2 %     6.3 %  

 

     December 31, 2005  
     Expected Maturity Dates              
     2006     2007     2008     2009     2010     Thereafter     Total     Fair Value  
     (Thousands of Dollars, Except Interest Rates)  

Long-term Debt:

                

Fixed rate

   $ 1,046     $ 611     $ 660     $ 713     $ 36,901     $ 854,881     $ 894,812     $ 954,039  

Average interest rate

     8.0 %     8.0 %     8.0 %     8.0 %     6.7 %     6.6 %     6.6 %  

Variable rate

   $ —       $ —       $ —       $ —       $ 229,000     $ —       $ 229,000     $ 229,000  

Average interest rate

     —         —         —         —         5.2 %     —         5.2 %  

Interest Rate Swaps Fixed to Variable:

                

Notional amount

   $ —       $ —       $ —       $ —       $ —       $ 167,500     $ 167,500     $ (4,002 )

Average pay rate

     6.6 %     6.6 %     6.6 %     6.6 %     6.7 %     6.6 %     6.6 %  

Average receive rate

     6.3 %     6.3 %     6.3 %     6.3 %     6.3 %     6.3 %     6.3 %  

 

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Management’s Report on Internal Control over Financial Reporting

Our management is responsible for establishing and maintaining adequate “internal control over financial reporting” (as defined in Rule 13a-15(f) under the Securities Exchange Act of 1934) for Valero L.P. Our management evaluated the effectiveness of Valero L.P.’s internal control over financial reporting as of December 31, 2006. In its evaluation, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control-Integrated Framework. Management believes that as of December 31, 2006, our internal control over financial reporting was effective based on those criteria.

KPMG LLP, our independent registered public accounting firm has issued an attestation report on management’s assessment of our internal control over financial reporting, which begins on page 59 of this Form 10-K.

 

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Report of Independent Registered Public Accounting Firm

The Board of Directors of Valero GP, LLC

and Unitholders of Valero L.P.:

We have audited the accompanying consolidated balance sheets of Valero L.P. and subsidiaries (a Delaware limited partnership) (the Partnership) as of December 31, 2006 and 2005, 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, 2006. 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) (PCAOB). 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 Valero L.P. and subsidiaries as of December 31, 2006 and 2005, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2006, in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the PCAOB, the effectiveness of Valero L.P. and subsidiaries’ internal control over financial reporting as of December 31, 2006, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated February 28, 2007 expressed an unqualified opinion on management’s assessment of, and the effective operation of, internal control over financial reporting.

 

    /s/ KPMG LLP
San Antonio, Texas    
February 28, 2007    

 

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Report of Independent Registered Public Accounting Firm

The Board of Directors of Valero GP, LLC

And Unitholders of Valero L.P.:

We have audited management’s assessment, included in the accompanying Management’s Report on Internal Control over Financial Reporting (page 57), that Valero L.P. and subsidiaries (the Partnership) maintained effective internal control over financial reporting as of December 31, 2006, 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. Our responsibility is to express an opinion on management’s assessment and an opinion on the effectiveness of 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) (the PCAOB). 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, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and 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, management’s assessment that Valero L.P. and subsidiaries maintained effective internal control over financial reporting as of December 31, 2006, is fairly stated, in all material respects, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Also, in our opinion, Valero L.P. and subsidiaries maintained, in all material respects, effective internal control over financial reporting as of December 31, 2006, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

We also have audited, in accordance with the standards of the PCAOB, the consolidated balance sheets of Valero L.P. and subsidiaries as of December 31, 2006 and 2005, and the related consolidated statements of operations, partners’ equity and cash flows for each of the years in the three-year period ended December 31, 2006, and our report dated February 28, 2007 expressed an unqualified opinion on those consolidated financial statements.

 

/s/ KPMG LLP

San Antonio, Texas

February 28, 2007

 

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VALERO L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Thousands of Dollars, Except Unit Data)

 

     December 31,  
     2006     2005  

Assets

    

Current assets:

    

Cash and cash equivalents

   $ 68,838     $ 36,054  

Receivable from related party

     —         21,873  

Accounts receivable, net of allowance for doubtful accounts of $1,220 and $1,976 as of December 31, 2006 and 2005, respectively

     105,976       110,066  

Inventories

     16,979       17,473  

Other current assets

     21,205       30,138  

Assets of businesses held for sale

     —         79,807  
                

Total current assets

     212,998       295,411  
                

Property and equipment, at cost

     2,694,358       2,417,529  

Accumulated depreciation and amortization

     (349,223 )     (257,316 )
                

Property and equipment, net

     2,345,135       2,160,213  

Intangible assets, net

     53,532       59,159  

Goodwill

     774,441       767,587  

Investment in joint ventures

     74,077       73,986  

Deferred charges and other assets, net

     22,683       10,636  
                

Total assets

   $ 3,482,866     $ 3,366,992  
                

Liabilities and Partners’ Equity

    

Current liabilities:

    

Current portion of long-term debt

   $ 647     $ 1,046  

Payable to related party

     2,315       12,800  

Accounts payable

     86,307       104,320  

Accrued interest payable

     17,528       16,391  

Accrued liabilities

     37,651       46,917  

Taxes other than income taxes

     10,219       9,013  

Income taxes payable

     2,068       4,001  

Liabilities of businesses held for sale

     —         11,100  
                

Total current liabilities

     156,735       205,588  
                

Long-term debt, less current portion

     1,353,720       1,169,659  

Long-term payable to Valero GP Holdings, LLC

     5,749       —    

Long-term payable to Valero Energy

     —         5,507  

Deferred income taxes

     21,584       13,576  

Other long-term liabilities

     69,397       71,883  

Commitments and contingencies (Note 12)

    

Partners’ equity:

    

Common units

     1,830,047       1,749,007  

Subordinated units

     —         114,127  

General partner’s equity

     38,815       38,913  

Accumulated other comprehensive income (loss)

     6,819       (1,268 )
                

Total partners’ equity

     1,875,681       1,900,779  
                

Total liabilities and partners’ equity

   $ 3,482,866     $ 3,366,992  
                

See Notes to Consolidated Financial Statements.

 

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VALERO L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

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

 

     Year Ended December 31,  
     2006     2005     2004  

Revenues:

      

Services revenues:

      

Third parties

   $ 363,721     $ 174,576     $ 3,184  

Valero Energy

     260,980       232,618       217,608  
                        

Total services revenues

     624,701       407,194       220,792  

Product sales

     510,973       252,363       —    
                        

Total revenues

     1,135,674       659,557       220,792  
                        

Costs and expenses:

      

Cost of product sales

     466,276       229,806       —    

Operating expenses:

      

Third parties

     218,017       126,280       47,094  

Valero Energy

     94,587       59,071       31,960  
                        

Total operating expenses

     312,604       185,351       79,054  

General and administrative expenses:

      

Third parties

     13,033       7,197       782  

Valero Energy

     32,183       19,356       10,539  
                        

Total general and administrative expenses

     45,216       26,553       11,321  

Depreciation and amortization

     100,266       64,895       33,149  
                        

Total costs and expenses

     924,362       506,605       123,524  
                        

Operating income

     211,312       152,952       97,268  

Equity earnings from joint ventures

     5,882       2,319       1,344  

Interest and other expense, net

     (61,427 )     (42,883 )     (20,194 )
                        

Income from continuing operations before income tax expense

     155,767       112,388       78,418  

Income tax expense

     5,861       4,713       —    
                        

Income from continuing operations

     149,906       107,675       78,418  

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

     (376 )     3,398       —    
                        

Net income

     149,530       111,073       78,418  

Less net income applicable to general partner

     (16,910 )     (10,758 )     (5,927 )
                        

Net income applicable to limited partners

   $ 132,620     $ 100,315     $ 72,491  
                        

Net income per unit applicable to limited

partners:

      

Continuing operations

   $ 2.84     $ 2.76     $ 3.15  

Discontinued operations

     (0.01 )     0.10       —    
                        

Net income

   $ 2.83     $ 2.86     $ 3.15  
                        

Weighted average number of basic and diluted units outstanding

     46,809,749       35,023,250       23,041,394  
                        

See Notes to Consolidated Financial Statements.

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VALERO L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Thousands of Dollars)

 

     Year Ended December 31,  
     2006     2005     2004  

Cash Flows from Operating Activities:

      

Net income

   $ 149,530     $ 111,073     $ 78,418  

Adjustments to reconcile net income to net cash provided by operating activities:

      

Depreciation and amortization

     100,266       66,667       33,149  

(Benefit) provision for deferred income taxes

     (74 )     4,283       —    

Equity earnings from joint ventures

     (5,969 )     (2,499 )     (1,344 )

Distributions of equity earnings from joint ventures

     5,155       2,499       1,344  

Changes in operating assets and liabilities:

      

Decrease (increase) in receivable from Valero Energy

     1,168       (2,678 )     (3,414 )

Decrease (increase) in accounts receivable

     27,307       (39,397 )     1,938  

Decrease (increase) in inventories

     257       (6,042 )     —    

Decrease (increase) in other current assets

     6,181       (11,475 )     (260 )

Increase in payable to Valero Holdings GP, LLC

     2,315       —         —    

(Decrease) increase in payable to Valero Energy

     (11,808 )     8,634       (5,683 )

Increase (decrease) in accrued interest payable

     1,135       (259 )     47  

(Decrease) increase in accounts payable and other accrued liabilities

     (17,205 )     54,604       3,339  

Increase (decrease) in taxes other than income taxes

     1,345       (3,323 )     264  

Other, net

     (8,792 )     4,343       705  
                        

Net cash provided by operating activities

     250,811       186,430       108,503  
                        

Cash Flows from Investing Activities:

      

Reliability capital expenditures

     (33,952 )     (23,707 )     (9,701 )

Expansion capital expenditures

     (90,070 )     (44,379 )     (19,702 )

Kaneb acquisition, net of cash acquired

     —         (500,973 )     (1,098 )

Other acquisitions

     (154,474 )     —         (28,085 )

Investment in other noncurrent assets

     (10,820 )     (3,319 )     —    

Proceeds from sale of Held Separate Businesses, net

     —         454,109       —    

Proceeds from dispositions of other assets

     71,396       26,836       46  

Proceeds from insurance settlement

     3,661       —         —    

Distributions in excess of equity earnings from joint ventures

     113       2,433       29  

Other, net

     912       —         —    
                        

Net cash used in investing activities

     (213,234 )     (89,000 )     (58,511 )
                        

Cash Flows from Financing Activities:

      

Proceeds from long-term debt borrowings, net of issuance costs

     269,026       746,472       43,000  

Repayment of long-term debt

     (83,510 )     (735,064 )     (15,468 )

Distributions to unitholders and general partner

     (183,290 )     (127,789 )     (78,240 )

General partner contributions

     575       29,197       —    

(Decrease) increase in cash book overdrafts

     (6,305 )     10,006       1,118  

Other, net

     (395 )     —         —    
                        

Net cash used in financing activities

     (3,899 )     (77,178 )     (49,590 )
                        

Effect of foreign exchange rate changes on cash

     (894 )     (345 )     —    

Net increase in cash and cash equivalents

     32,784       19,907       402  

Cash and cash equivalents as of the beginning of year

     36,054       16,147       15,745  
                        

Cash and cash equivalents as of the end of year

   $ 68,838     $ 36,054     $ 16,147  
                        

Supplemental cash flow information:

      

Cash paid for interest

   $ 74,964     $ 53,162     $ 24,120  
                        

Cash paid for income taxes

   $ 7,234     $ 1,663     $ —    
                        

See Notes to Consolidated Financial Statements.

 

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VALERO L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF PARTNERS’ EQUITY

Years Ended December 31, 2006, 2005 and 2004

(Thousands of Dollars, Except Unit Data)

 

     Limited Partners    

General

Partner

   

Accumulated
Other

Comprehensive

Income (Loss)

   

Total
Partners’

Equity

 
   Common     Subordinated        
     Units    Amount     Units     Amount        

Balance as of January 1, 2004

   13,442,072    $ 310,589     9,599,322     $ 118,005     $ 9,569     $ —       $ 438,163  

Net income

   —        42,290     —         30,201       5,927       —         78,418  

Other comprehensive loss – foreign currency translation

   —        —       —         —         —         (30 )     (30 )
                                                   

Total comprehensive income

   —        42,290     —         30,201       5,927       (30 )     78,388  
                                                   

Cash distributions to partners

   —        (42,342 )   —         (30,238 )     (5,660 )     —         (78,240 )
                                                   

Balance as of December 31, 2004

   13,442,072      310,537     9,599,322       117,968       9,836       (30 )     438,311  

Net income

   —        72,383     —         27,932       10,758       —         111,073  

Other comprehensive loss – foreign currency translation

   —        —       —         —         —         (1,238 )     (1,238 )
                                                   

Total comprehensive income

   —        72,383     —         27,932       10,758       (1,238 )     109,835  
                                                   

Cash distributions to partners

   —        (85,138 )   —         (31,773 )     (10,878 )     —         (127,789 )

Exchange of 23,768,355 common units for all common units of KPP in July 2005 and related general partner interest contributions

   23,768,355      1,451,225     —         —         29,197       —         1,480,422  
                                                   

Balance as of December 31, 2005

   37,210,427      1,749,007     9,599,322       114,127       38,913       (1,268 )     1,900,779  

Net income

   —        123,180     —         9,440       16,910       —         149,530  

Other comprehensive income – foreign currency translation

   —        —       —         —         —         8,087       8,087  
                                                   

Total comprehensive income

   —        123,180     —         9,440       16,910       8,087       157,617  
                                                   

Cash distributions to partners

   —        (149,004 )   —         (16,703 )     (17,583 )     —         (183,290 )

Cash contributions from general partner

   —        —       —         —         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  
                                                   

See Notes to Consolidated Financial Statements.

 

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VALERO L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended December 31, 2006, 2005 and 2004

1. ORGANIZATION AND OPERATIONS

Organization

Valero L.P. (NYSE: VLI) is a Delaware limited partnership formed in 1999 that completed its initial public offering of common units in April 16, 2001. Valero L.P. is engaged in the crude oil and refined product transportation, terminalling and storage business in the United States, the Netherland Antilles, Canada, Mexico, the Netherlands and the United Kingdom.

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

Riverwalk Logistics, L.P., a wholly owned subsidiary of Valero GP Holdings, LLC (Valero GP Holdings) (NYSE: VEH), is our general partner, which is represented by a 2% general partner interest. Valero GP Holdings, through various affiliates, also owns limited partner units, resulting in a combined partnership ownership of 23.4%. The remaining 76.6% limited partnership interests are held by public unitholders.

Valero GP Holdings, a publicly held Delaware limited liability company, was formed in June 2000 as UDS Logistics. Valero Energy Corporation (Valero Energy) (NYSE: VLO), a publicly held independent refining and marketing company, acquired UDS Logistics in connection with its December 31, 2001 acquisition (UDS Acquisition) of Ultramar Diamond Shamrock Corporation (UDS). UDS Logistics changed its name to Valero GP Holdings in January 2006.

On July 19, 2006, Valero GP Holdings completed its initial public offering of 17.25 million units representing limited liability company interests at $22.00 per unit. In addition, on December 22, 2006, Valero GP Holdings completed its secondary public offering of 25.3 million units representing limited liability company interests at $21.62 per unit. As a result of these offerings, Valero Energy no longer owns any interest in Valero GP Holdings or us.

On February 16, 2007, we announced that we would change our name to NuStar Energy, L.P. (NYSE: NS). Also, Valero GP Holdings, LLC, our general partner, announced it would change its name to NuStar GP Holdings, LLC (NYSE: NGP). Both name changes are expected to be effective April 1, 2007.

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

Operations

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

We conduct our operations through our subsidiaries, primarily Valero Logistics Operations, L.P. (Valero Logistics) and Kaneb Pipe Line Operating Partnership, L.P. (KPOP). We have four business segments: refined product terminals, refined product pipelines, crude oil pipelines and crude oil storage tanks. As of December 31, 2006, our assets included:

 

   

65 refined product terminal facilities providing approximately 57.5 million barrels of storage capacity and one crude oil terminal facility providing approximately 3.3 million barrels of storage capacity;

 

   

8,259 miles of refined product pipelines, including approximately 2,000 miles of anhydrous ammonia pipelines, with 21 associated terminals providing storage capacity of 4.8 million barrels;

 

   

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

 

   

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

 

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We have terminal facilities in the United States, the Netherlands Antilles, Canada, Mexico, the Netherlands and the United Kingdom. Our largest customer is Valero Energy, which accounted for 23%, 34% and 99% of our consolidated revenues for the years ended December 31, 2006, 2005 and 2004, respectively (See Note 14. Related Party Transactions).

Valero Energy, an independent refining and marketing company, owns and operates 18 refineries with a combined total throughput capacity as of December 31, 2006 of approximately 3.3 million barrels per day. Valero Energy’s refining operations rely on various logistics assets (pipelines, terminals, marine dock facilities, bulk storage facilities, refinery delivery racks and rail car loading equipment) that support its refining and retail operations, including the logistics assets we own and operated.

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Consolidation

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

Use of Estimates

The preparation of consolidated financial statements in conformity with accounting principles generally accepted in the United States of America 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, net

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 collectibility at the time of their review.

Inventories

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

Property and Equipment

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

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

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

 

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Goodwill and Intangible Assets

Goodwill represents the excess of cost of an acquired entity over the fair value of net assets acquired less liabilities assumed. Intangible assets are assets that lack physical substance (excluding financial assets). Goodwill acquired in a business combination is not amortized. Intangible assets with finite useful lives are amortized on a straight-line basis over five to 47 years. Goodwill and intangible assets not subject to amortization are tested for impairment annually or more frequently if events or changes in circumstances indicate the asset might be impaired. We use October 1 of each year as our annual valuation date for the impairment test. Based on the results of the impairment tests performed as of October 1, 2006, 2005 and 2004, no impairment had occurred.

Investment in Joint Ventures

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

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

Deferred Charges and Other Assets

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

 

   

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

 

   

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

 

   

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

Impairment of Long-Lived Assets

Long-lived assets, including property and equipment and investment in joint ventures, are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. The evaluation of recoverability is performed using undiscounted estimated net cash flows generated by the related asset. If an asset is deemed to be impaired, the amount of impairment is determined as the amount by which the net carrying value exceeds discounted estimated net cash flows. We believe that the carrying amounts of our long-lived assets as of December 31, 2006 are recoverable.

Taxes Other than Income Taxes

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

Income Taxes

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

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

 

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Asset Retirement Obligations

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

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

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

Environmental Remediation Costs

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

Product Imbalances

Product imbalances occur when customers deliver more or less refined product volumes into our pipelines than they are entitled to receive. We value assets and liabilities related to product imbalances at current market prices. Product imbalance liabilities are included in accrued liabilities on the consolidated balance sheet. Included in other current assets are $9.9 million and $20.0 million of product imbalance assets as of December 31, 2006 and 2005, respectively.

Revenue Recognition

Revenues for the refined product terminals segment include fees for tank storage agreements, whereby a customer agrees to pay for a certain amount of storage in a tank over a period of time (storage lease revenues), and throughput agreements, whereby a customer pays a fee per barrel for volumes moving through our terminals (throughput revenues). Our terminals also provide blending, handling and filtering services. Revenues for the refined product terminals segment also include the sale of bunker fuel to marine vessels, at Point Tupper in Nova Scotia, Canada and St. Eustatius, Netherland Antilles in the Caribbean for which we earn revenues based upon a price per metric ton applied to the number of metric tons delivered to our customer. Our facilities at Point Tupper and St. Eustatius also charge fees to provide ancillary services such as pilotage, tug assistance, line handling, launch service, emergency response services and other ship services.

Throughput revenues (based on a terminalling fee) are recognized as refined products are delivered out of our terminal. Storage lease revenues are recognized when services are provided to the customer. Product revenues are recognized when product is sold and title and risk pass to the customer. Revenues for ancillary services are recognized as those services are provided.

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

 

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

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

Income Allocation

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

Net Income per Unit Applicable to Limited Partners

We have identified the general partner and the subordinated units as participating securities and use the two-class method when calculating the net income per unit applicable to limited partners, which is based on the weighted-average number of common and subordinated units outstanding during the period. Net income per unit applicable to limited partners is computed by dividing net income applicable to limited partners, after deducting the general partner’s 2% interest and incentive distributions, by the weighted-average number of limited partnership units outstanding. Basic and diluted net income per unit applicable to limited partners is the same because we have no potentially dilutive securities outstanding. The general partner’s incentive distribution allocation for the years ended December 31, 2006, 2005 and 2004 was $14.8 million, $8.7 million and $4.4 million, respectively. The amount of net income per unit allocated to common units was equal to the amount allocated to the subordinated units for the years presented.

Comprehensive Income

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

Risk Management Activities

Beginning in 2003, we entered into 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 qualified for the shortcut method of accounting prescribed by SFAS 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended. As a result, changes in the fair value of the derivatives will completely offset the changes in the fair value of the underlying hedged items.

Operating Leases

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

Stock-based Compensation

Valero GP Holdings has adopted various long-term incentive plans, which provide employees and directors of Valero GP, LLC and, previously, certain corporate officers of Valero Energy, with the right to receive common units of Valero L.P. under specified conditions. Valero GP Holdings accounts for awards of unit options and restricted units of Valero L.P. at fair value and considering the percentage of the award that has vested. Valero GP Holdings records compensation expense related to unit options until such options are exercised, and records compensation expense for restricted units until the date of vesting. We reimburse Valero GP Holdings completely for the expense resulting from awards to employees and directors of Valero GP, LLC. We include such compensation expense in general and administrative expenses on the consolidated statements of income.

New Accounting Pronouncements

FASB Statement 153. In December 2004, the FASB issued Statement No. 153, “Exchanges of Nonmonetary Assets,” which addresses the measurement of exchanges of nonmonetary assets. Statement No. 153 eliminates the exception from fair value measurement for nonmonetary exchanges of similar productive assets, which was previously provided by APB Opinion No. 29, “Accounting for Nonmonetary Transactions,” and replaces it with an exception for exchanges that do not

 

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have commercial substance. Statement No. 153 specifies that a nonmonetary exchange has commercial substance if the future cash flows of the entity are expected to change significantly as a result of the exchange. Statement No. 153 was effective for nonmonetary asset exchanges occurring in the fiscal periods beginning after June 15, 2005. The adoption of Statement No. 153 did not affect our financial position or results of operations.

FASB Interpretation No. 48. In June 2006, the FASB issued Interpretation No. 48, “Accounting for Uncertainty in Income Taxes—an interpretation of FASB Statement No. 109” (FIN 48). FIN 48 clarifies the accounting for uncertain income tax positions recognized in an enterprise’s financial statements in accordance with FASB Statement No. 109, “Accounting for Income Taxes,” by defining a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. An enterprise recognizes a tax position if it is more-likely-than-not that the tax position will be sustained, based on the technical merits of the position, upon examination. An uncertain tax position is measured in the financial statements at the largest amount of benefit that is more-likely-than-not to be realized. FIN 48 is effective for fiscal years beginning after December 15, 2006 and we do not expect it to significantly affect our financial position or results of operations.

EITF Issue No. 06-3. In June 2006, the FASB ratified its consensus on EITF Issue No. 06-3, “How Taxes Collected from Customers and Remitted to Governmental Authorities Should Be Presented in the Income Statement” (EITF No. 06-3). EITF 06-3 includes any tax assessed by a governmental authority that is directly imposed on a revenue-producing transaction between a seller and a customer and may include sales, use, value added, and some excise taxes. These taxes should be presented on either a gross or a net basis, and if reported on a gross basis, a company should disclose amounts of those taxes in interim and annual financial statements for each period for which an income statement is presented. The guidance in EITF No. 06-3 is effective for all periods beginning after December 15, 2006 and is not expected to significantly affect our financial position or results of operations.

FASB Statement No. 157. In September 2006, the FASB issued Statement No. 157, “Fair Value Measurements.” Statement No. 157 defines fair value, establishes a framework for measuring fair value under GAAP, and expands disclosures about fair value measures. Statement No. 157 is effective for fiscal years beginning after November 15, 2007, with early adoption encouraged. The provisions of Statement No. 157 are to be applied on a prospective basis, with the exception of certain financial instruments for which retrospective application is required. The adoption of Statement No. 157 is not expected to materially affect our financial position or results of operations.

Reclassifications

Certain previously reported amounts in the 2005 and 2004 consolidated financial statements have been reclassified to conform to the 2006 presentation.

3. ACQUISITIONS

Completed During 2006

Capwood Pipeline

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

St. James Crude Facility

On December 1, 2006, we acquired a crude oil storage and blending facility in St. James, Louisiana from Koch Supply and Trading, L.P. for approximately $141.7 million. The acquisition includes 17 crude oil tanks with a total capacity of approximately 3.3 million barrels. Additionally, the facility has three docks with barge and ship access. The facility is located on 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. We funded the acquisition with borrowings under our revolving credit agreement. The financial statements include the results of operations in the refined product terminal segment commencing on December 1, 2006.

 

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The acquisition of the St. James crude facility was accounted for using the purchase method. The purchase price has been preliminarily allocated to property and equipment pending completion of an independent appraisal. Pro forma financial information for the years ended December 31, 2006 and 2005 that give effect to the St. James acquisition as of January 1, 2006 and 2005 are not presented as the effect is not significant.

Completed During 2005

Kaneb Acquisition

On July 1, 2005, we completed the Kaneb Acquisition. We acquired all of KSL’s outstanding equity securities for approximately $509 million in cash, which was primarily funded by borrowings under our $525 million term credit agreement. Additionally, we issued approximately 23.8 million of our common units valued at approximately $1.45 billion in exchange for all of the outstanding common units of KPP.

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

Purchase Price Allocation

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

 

Cash paid for the outstanding equity securities of KSL

   $ 509,307

Value of Valero L.P.’s common units issued in exchange for KPP units

     1,451,249

Transaction costs

     9,505

Fair value of long-term debt assumed

     779,707

Fair value of other liabilities assumed

     179,864
      

Total

   $ 2,929,632
      

Current assets

   $ 605,721

Property and equipment

     1,429,652

Goodwill

     769,727

Intangible assets

     58,900

Other noncurrent assets

     65,632
      

Total

   $ 2,929,632
      

Unaudited Pro Forma Information

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

 

   

we completed the Kaneb Acquisition on January 1, 2004;

 

   

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

 

   

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

 

   

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

 

   

the results of operations of the Held Separate Businesses, Martin Oil LLC, (a marketing subsidiary of KSL) and the Australian and New Zealand subsidiaries are reported as discontinued operations.

 

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

 

     Year Ended December 31,
     2005    2004
     (Thousands of Dollars,
Except Per Unit Data)

Revenues

   $ 1,005,662    $ 787,475

Operating income

     130,347      179,936

Income from continuing operations

   $ 83,084    $ 132,374

Income from discontinued operations

     9,853      13,985
             

Net income

   $ 92,937    $ 146,359
             

Net income per unit applicable to limited partners:

     

Continuing operations

   $ 1.48    $ 2.52

Discontinued operations

     0.21      0.29
             

Net income

   $ 1.69    $ 2.81
             

Completed During 2004

Royal Trading Asphalt Terminals

On February 20, 2004, we acquired two asphalt terminals, one in Catoosa, Oklahoma near Tulsa and one in Rosario, New Mexico near Santa Fe, from Royal Trading Company (Royal Trading) for $28.1 million. These terminals have an aggregate storage capacity of 500,000 barrels in 32 tanks and six loading stations. The purchase price was allocated to the individual tangible and identifiable intangible assets acquired based on their fair values as determined by an independent appraisal. In conjunction with the Royal Trading acquisition, we entered into an agreement with Valero Energy (See Note 14. Related Party Transactions).

The results of operations for these two terminals are included in the consolidated statements of income commencing on February 20, 2004. The pro forma financial information for the years ended December 31, 2004 and 2003 that give effect to the acquisition of Royal Trading as of January 1, 2004 and 2003 have not been disclosed, as the effect is not significant.

4. DISPOSITIONS AND ASSETS AND LIABILITIES OF BUSINESSES HELD FOR SALE

Sale of Held Separate Businesses

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

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

Sale of Martin Oil LLC

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

 

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Assets and Liabilities of Businesses Held for Sale

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

As a result, the assets and liabilities of the Australia and New Zealand Subsidiaries were classified as assets and liabilities of businesses held for sale in the accompanying consolidated balance sheet as of December 31, 2005. The results of operations for the Australia and New Zealand Subsidiaries for 2006 and 2005 have been included in income from discontinued operations. Revenues and pre-tax income related to the Australia and New Zealand Subsidiaries, included in income from discontinued operations, were $5.0 million and $0.6 million, respectively, for the year ended December 31, 2006 and were $10.1 million and $0.2 million, respectively, for the year ended December 31, 2005. Income tax expense associated with the Australia and New Zealand Subsidiaries totaled $0.3 million and $0.1 million for the years ended December 31, 2006 and 2005, respectively. Additionally, the income from discontinued operations includes interest expense of approximately $0.8 million and $1.5 million allocated to the Australia and New Zealand Subsidiaries for the years ended December 31, 2006 and 2005, respectively, which was based upon the expected proceeds and the interest rate applicable to our debt.

Assets and liabilities of businesses held for sale consisted of the following:

 

     December 31, 2005
     (Thousand of Dollars)

Current assets

   $ 8,047

Property and equipment, net

     68,726

Other assets

     3,034
      

Assets of businesses held for sale

     79,807
      

Current liabilities

     3,606

Deferred income taxes

     3,604

Other liabilities

     3,890
      

Liabilities of businesses held for sale

   $ 11,100
      

5. ALLOWANCE FOR DOUBTFUL ACCOUNTS

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

 

     Year Ended December 31,  
     2006     2005  
     (Thousands of Dollars)  

Balance as of beginning of year

   $ 1,976     $ —    

Decrease in allowance charged to expense

     (276 )     —    

Accounts charged against the allowance, net of recoveries

     (492 )     (289 )

Fair value of amounts acquired in the Kaneb Acquisition

     —         2,265  

Foreign currency translation

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