-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, S5CvBYhF/LrNeUFuinPak0cDMDx4l84U6EaG+MFkRFCWJhk1yztcouWL4w7Opndm gRhcBlBkSSA31tKLoC7z+A== /in/edgar/work/20001102/0000950129-00-005204/0000950129-00-005204.txt : 20001106 0000950129-00-005204.hdr.sgml : 20001106 ACCESSION NUMBER: 0000950129-00-005204 CONFORMED SUBMISSION TYPE: 424B2 PUBLIC DOCUMENT COUNT: 1 FILED AS OF DATE: 20001102 FILER: COMPANY DATA: COMPANY CONFORMED NAME: NORTHERN BORDER PARTNERS LP CENTRAL INDEX KEY: 0000909281 STANDARD INDUSTRIAL CLASSIFICATION: [4922 ] IRS NUMBER: 931120873 STATE OF INCORPORATION: DE FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 424B2 SEC ACT: SEC FILE NUMBER: 333-72323 FILM NUMBER: 751412 BUSINESS ADDRESS: STREET 1: 1400 SMITH ST STREET 2: C/O ENRON BLDG CITY: HOUSTON STATE: TX ZIP: 77002 BUSINESS PHONE: 7138536161 MAIL ADDRESS: STREET 1: 1400 SMITH ST STREET 2: ENRON BUILDING RM 4524 CITY: HOUSTON STATE: TX ZIP: 77002 424B2 1 h81072b2e424b2.txt NORTHERN BORDER PARTNERS, L.P. - 424(B)(2) 1 FILED PURSUANT TO RULE 424(B)(2) REGISTRATION NO. 333-72323 PROSPECTUS SUPPLEMENT (TO PROSPECTUS DATED MARCH 3, 1999) 1,875,000 COMMON UNITS NORTHERN BORDER PARTNERS, L.P. REPRESENTING LIMITED PARTNER INTERESTS [NORTHERN BORDER PARTNERS, L.P. LOGO] ------------------------ We are offering 1,875,000 common units as described in this prospectus supplement and the accompanying prospectus. The common units represent limited partner interests in Northern Border Partners, L.P. Our common units are traded on the New York Stock Exchange under the symbol "NBP." On November 1, 2000, the last reported sale price of our common units on the New York Stock Exchange was $29.00 per common unit. ------------------------
Per Common Unit Total ----------- ----- Public offering price....................................... $29.00 $54,375,000 Underwriting discount and commissions....................... $ 1.23 $ 2,306,250 Proceeds, before expenses, to Northern Border Partners...... $27.77 $52,068,750
The underwriters may also purchase up to an additional 281,250 common units on the same terms described above within 30 days from the date of this prospectus supplement to cover over-allotments, if any. The underwriters are offering the common units subject to various conditions and may reject all or part of any order. The underwriters expect to deliver the common units to purchasers on November 7, 2000. Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or determined if this prospectus supplement or the accompanying prospectus are truthful or complete. Any representation to the contrary is a criminal offense. ------------------------ PAINEWEBBER INCORPORATED SALOMON SMITH BARNEY LEHMAN BROTHERS THE DATE OF THIS PROSPECTUS SUPPLEMENT IS NOVEMBER 1, 2000 2 TABLE OF CONTENTS
PROSPECTUS SUPPLEMENT PAGE NO. --------------------- -------- Northern Border Partners.................................... S-1 Recent Developments......................................... S-3 Ratio of Taxable Income to Distributions.................... S-4 Recent Tax Developments..................................... S-5 Use of Proceeds............................................. S-6 Price Range of Common Units and Distributions............... S-6 Capitalization.............................................. S-7 Underwriting................................................ S-8 Legal Matters............................................... S-9 Experts..................................................... S-9
PROSPECTUS ---------- The Offered Securities...................................... 2 Where You Can Find More Information......................... 2 Cautionary Statement Regarding Forward Looking Statements... 3 Our Business................................................ 4 Conflicts of Interest and Fiduciary Responsibilities........ 7 FERC Regulation............................................. 8 Environmental and Safety Costs and Liabilities.............. 11 Common Units................................................ 11 Debt Securities............................................. 12 Ratio of Earnings to Fixed Charges.......................... 15 Use of Proceeds............................................. 15 Tax Considerations.......................................... 15 Plan of Distribution........................................ 29 Legal Matters............................................... 30 Experts..................................................... 30
------------------------ IMPORTANT NOTICE ABOUT INFORMATION IN THIS PROSPECTUS SUPPLEMENT AND THE ACCOMPANYING PROSPECTUS This document is in two parts. The first part is the prospectus supplement, which describes our business and the specific terms of this common unit offering. The second part, the base prospectus, gives more general information, some of which may not apply to this offering. Generally, when we refer only to the "prospectus," we are referring to both parts combined. IF THE DESCRIPTION OF THE OFFERING VARIES BETWEEN THE PROSPECTUS SUPPLEMENT AND THE BASE PROSPECTUS, YOU SHOULD RELY ON THE INFORMATION IN THE PROSPECTUS SUPPLEMENT. FORWARD LOOKING STATEMENTS IN THIS PROSPECTUS SUPPLEMENT ARE SUBJECT TO THE RISKS AND UNCERTAINTIES DISCUSSED IN THE BASE PROSPECTUS UNDER "CAUTIONARY STATEMENT REGARDING FORWARD LOOKING STATEMENTS." YOU SHOULD RELY ONLY ON THE INFORMATION CONTAINED IN OR INCORPORATED BY REFERENCE IN THIS PROSPECTUS. WE HAVE NOT, AND THE UNDERWRITERS HAVE NOT, AUTHORIZED ANYONE TO PROVIDE YOU WITH DIFFERENT INFORMATION. WE ARE NOT MAKING AN OFFER OF THE COMMON UNITS IN ANY JURISDICTION WHERE THE OFFER IS NOT PERMITTED. YOU SHOULD NOT ASSUME THAT THE INFORMATION CONTAINED IN THIS PROSPECTUS OR IN THE DOCUMENTS INCORPORATED BY REFERENCE IN THIS PROSPECTUS IS ACCURATE AS OF ANY DATE OTHER THAN THE DATE ON THE FRONT OF THOSE DOCUMENTS. i 3 The information in this prospectus supplement is not complete. You should review carefully all of the detailed information appearing in this prospectus supplement, the accompanying prospectus, and the documents we have incorporated by reference before making any investment decision. Certain capitalized terms used but not defined in this prospectus supplement have the meanings assigned to them in the accompanying prospectus. NORTHERN BORDER PARTNERS We are a publicly traded limited partnership and a leading transporter of natural gas imported from Canada to the United States. Through our subsidiary limited partnership, Northern Border Intermediate Limited Partnership, we own a 70% general partner interest in Northern Border Pipeline Company. Northern Border Pipeline owns a 1,214-mile interstate pipeline system that transports natural gas from the Montana-Saskatchewan border to natural gas markets in the midwestern United States. This pipeline system connects with multiple pipelines that provide shippers with access to the various natural gas markets served by those pipelines. Our interest in Northern Border Pipeline represents the largest portion of our assets, earnings and cash flows. Northern Border Pipeline placed its pipeline system in service in 1982, and it completed expansions and/or extensions in 1991, 1992 and 1998. The most recent expansion and extension, called The Chicago Project, increased the pipeline system's ability to receive natural gas by 42% to its current capacity of 2,373 million cubic feet per day. In the year ended December 31, 1999, Northern Border Pipeline transported approximately 23% of the total amount of natural gas imported from Canada to the United States. Over the same period, approximately 91% of the natural gas transported by Northern Border Pipeline was produced in the western Canadian sedimentary basin located in the provinces of Alberta, British Columbia and Saskatchewan. The pipeline system serves more than 40 shippers with diverse operating and financial profiles. Based upon shippers' cost of service obligations, as of September 30, 2000, at least 97% of the pipeline capacity was contractually committed through mid-September 2003, and the weighted average contract life was over six years. Northern Border Pipeline does not own the gas that it transports, and therefore it does not assume the related natural gas commodity price risk. Through our wholly owned subsidiary, Crestone Energy Ventures, L.L.C., we also own interests in Bighorn Gas Gathering, L.L.C., Fort Union Gas Gathering, L.L.C. and Lost Creek Gathering, L.L.C., which own over 300 miles of gas gathering facilities in Wyoming. The gathering facilities interconnect to the interstate gas pipeline grid serving gas markets in the Rocky Mountains, the Midwest and California. The Bighorn and Fort Union systems gather coal seam methane gas produced in the Powder River basin in northeastern Wyoming. Bighorn's system is capable of gathering more than 250 million cubic feet per day of coal seam methane gas for delivery to the Fort Union gathering system, and Fort Union's system is capable of delivering more than 450 million cubic feet per day of coal seam methane gas into the interstate pipeline grid. Under various agreements, the majority of which are long term, producers have granted to Bighorn the exclusive right to gather coal seam methane gas produced in areas of Wyoming covering 800,000 acres. The Lost Creek system gathers natural gas produced from conventional gas wells in the Wind River basin and consists of 106 miles of gathering pipelines. The system is capable of delivering more than 275 million cubic feet per day of gas into the interstate pipeline grid. We also own Black Mesa Pipeline Holdings, Inc. which owns a 273-mile coal slurry pipeline originating at a coal mine in Kayenta, Arizona. The coal slurry pipeline transports crushed coal to the Mohave Power station in Laughlin, Nevada. The capacity of the pipeline is fully contracted to the coal supplier for the Mohave Power station through the year 2005. S-1 4 OUR STRATEGY Our strategy is to continue to own and manage Northern Border Pipeline as a highly utilized, low cost pipeline system and to increase the pipeline system's capacity though expansions or extensions, joint ventures, other alliances or selective acquisitions. In the near term, we plan to focus our efforts on obtaining extensions of the existing contracts with shippers and on opportunities to serve new electric generation facilities on the east end of the pipeline system. These opportunities may include looping, additional compression or extensions of the pipeline system. We will also explore opportunities to transport natural gas or maximize our shippers' ability to access markets outside the Chicago area. We are also focusing on acquisition opportunities involving energy businesses in North America. We hope to leverage our experience in energy transportation to enhance cash flow and earnings by acquiring other, primarily unregulated, transportation assets. We plan to pursue opportunities that involve fee-for-service income and little or no commodity price risk. We may acquire assets from affiliates of our general partners, although they have no obligation to offer us acquisition opportunities, except that Enron North America Corp., a subsidiary of Enron Corp., has an obligation to permit us to participate in gathering opportunities in specified areas of Wyoming and Montana. Through Crestone Energy Ventures, we plan to develop significant additional gathering systems and to explore other opportunities for expansion of our interests in Wyoming and for transportation of natural gas produced in the Powder River and Wind River basins. We intend to pursue only those expansion and acquisition opportunities that add to our cash flow over time. Our strategy will involve significant capital expenditures and other costs. Capital expenditures for Northern Border Pipeline for 2001 will be approximately $90 million, the majority of which will be for Project 2000, which is described below in "Recent Developments -- Project 2000". We have targeted significant additional gas gathering and other development projects in the Powder River and Wind River basins, and if all of these proceed as planned our share of capital expenditures for our interests in Wyoming will be $60 million to $70 million next year. We will finance these capital expenditures initially with debt, although we plan to issue additional common units as needed in order to maintain an appropriate capital structure. OUR STRUCTURE AND MANAGEMENT Our general partners are Northern Plains Natural Gas Company and Pan Border Gas Company, both subsidiaries of Enron, and Northwest Border Pipeline Company, a subsidiary of The Williams Companies, Inc. We are managed by or under the direction of our Partnership Policy Committee consisting of three members, each of whom has been appointed by one of our general partners. Management of Northern Border Pipeline is overseen by the Northern Border management committee, which is comprised of three of our representatives and one representative from TC PipeLines, LP, the owner of the remaining 30% general partner interest in Northern Border Pipeline. Voting power on the management committee is allocated among our three representatives in proportion to their general partner interests in us. As a result, Enron controls 57.75% of the voting power of the management committee. Northern Plains and NBP Services Corporation, each of which is a subsidiary of Enron, provide operating and administrative services for us and our subsidiaries under services and operating agreements. Northern Plains operates the Northern Border Pipeline system, and NBP Services provides administrative services for us and operating services for Crestone Energy Ventures and its subsidiaries. Approximately 215 individuals are involved in operating activities. None of these individuals is represented by a labor union or covered by a collective bargaining agreement. COMPETITION Northern Border Pipeline competes with other pipeline companies that transport gas from the western Canadian sedimentary basin or that transport gas to end-use markets in the Midwest. Its competitive position is affected by the availability of Canadian natural gas for export and demand for natural gas in the S-2 5 United States. Shippers of gas produced in the western Canadian sedimentary basin have other options to transport Canadian natural gas to the United States, including transportation on pipelines eastward in Canada or to markets on the West Coast. The Alliance Pipeline, which will transport natural gas from the western Canadian sedimentary basin to the midwestern United States, is under construction. Its sponsors have announced their plans for the Alliance Pipeline to be in service by late this year. Upon its completion, the Alliance Pipeline will compete directly with Northern Border Pipeline. As a consequence of the Alliance Pipeline, there may be a large increase in natural gas moving from the western Canadian sedimentary basin to Chicago. There are several additional projects proposed to transport natural gas from the Chicago area to growing eastern markets that would provide access to additional markets for the shippers. The proposed projects currently being pursued by third parties are targeting markets in eastern Canada and the northeast United States. These proposed projects are in various stages of regulatory approval. One such project, Vector Pipeline, is designed to transport western Canadian and United States sourced natural gas from the Chicago area to parts of Indiana and Michigan, and into Ontario, Canada, as well as provide access to markets and storage in the upper Midwest. Vector Pipeline is currently under construction and has a projected in-service date of December 1, 2000. Williams has a 14.6% interest in the Alliance Pipeline. TransCanada PipeLines Limited and other unaffiliated companies own and operate pipeline systems that transport natural gas from the same natural gas reserves in western Canada that supply Northern Border Pipeline's customers. RECENT DEVELOPMENTS INCREASE IN CASH DISTRIBUTIONS We recently announced an increase in our quarterly cash distribution to $0.70 from $0.65 per common unit. The indicated annual rate is now $2.80 per common unit. The increase becomes effective with the third quarter distribution payable on November 14, 2000 to unitholders of record as of October 31, 2000. Purchasers of common units in this offering will not be entitled to receive the third quarter distribution. This is the Partnership's fourth increase in the last three years. We announced this increase because of the continued strong performance of our core business, recent acquisitions and confidence in our strategy. THIRD QUARTER 2000 Our third quarter 2000 net income per unit was $0.66, or $20.3 million, compared to $0.65 per unit, or $19.4 million, in the third quarter of 1999. Our cash flows from operating activities increased from $50.6 million for the third quarter of 1999 to $51.7 million for the third quarter of 2000. Delivered volumes for Northern Border Pipeline increased during the third quarter of 2000 to 212,670 million cubic feet from 211,761 million cubic feet for the third quarter of 1999. Transportation units averaged 2,250 million dekatherm miles (MMdthm) in the third quarter of 2000 compared to 2,242 MMdthm in the third quarter of 1999. PROPOSED SETTLEMENT OF PENDING RATE CASE On September 26, 2000, Northern Border Pipeline filed a stipulation and agreement that documents the settlement of its pending rate case. The settlement will become effective if and when approved by the FERC. We anticipate the FERC will act on the settlement in the first quarter of 2001. Among the key provisions of the proposed settlement is the conversion of Northern Border Pipeline's form of tariff from cost of service to stated rates based on a straight-fixed variable rate design. If the proposed settlement is approved, shippers will pay stated transportation rates. Under the straight-fixed variable rate design, approximately 98% of the payments are attributed to demand charges, based upon contracted firm capacity, and 2% to commodity charges based on the volumes of gas actually transported on the system. S-3 6 On a per unit of transportation basis, the rates under the new tariff are approximately equal to the previous level. Under the proposed settlement, Northern Border Pipeline's earnings and cash flow will depend on its future costs, contracted capacity, the volumes of gas transported and its ability to recontract capacity at acceptable rates. The proposed settlement agreement has not been opposed by any of Northern Border Pipeline's shippers. Under Northern Border Pipeline's existing tariff, the amount that it may collect from customers generally declines as the rate base is recovered. Under its proposed tariff, Northern Border Pipeline will be entitled to collect based on stated rates until its next rate case, which will be filed November 1, 2005. It will, however, continue to depreciate its rate base at an annual depreciation rate on transmission plant in service of 2.25%, and its rate base in 2005 will be a factor in determining what it can charge when it files a new rate case at that time. In order to avoid an eventual decline in maximum rates it can charge its transmission customers, Northern Border Pipeline must maintain or increase its rate base by acquiring or constructing assets that replace or add to existing pipeline facilities or by adding new facilities. ACQUISITIONS In September 2000, we purchased interests in gas gathering businesses in the Powder River and Wind River basins in Wyoming for approximately $200 million from Enron North America. The transaction included the purchase of Enron Midstream Services, L.L.C., now known as Crestone Gathering Services, L.L.C., and ownership interests in Bighorn, Fort Union and Lost Creek. The transaction added to our previous ownership position in Bighorn. We previously purchased common and preferred shares of Bighorn for $52.7 million. As a result of these transactions, through Crestone Energy Ventures we own 100% of Crestone Gathering Services, a 49% ownership interest in Bighorn, a 33.33% interest in Fort Union and a 35% interest in Lost Creek. CMS Field Services, Inc. holds the remaining ownership interest in Bighorn. The remaining ownership interest in Fort Union is held in varying percentages by subsidiaries of CMS Energy Services, Western Gas Resources, Inc., Colorado Interstate Gas Company, and Barrett Resources Corporation. A subsidiary of Burlington Resources Inc. holds the remaining ownership interest in Lost Creek. PROJECT 2000 On March 16, 2000, the FERC issued an order granting Northern Border Pipeline's application for a certificate to construct and operate its proposed Project 2000 facilities. Project 2000 will expand and extend the pipeline system into Indiana. In addition to providing additional Canadian natural gas to United States markets, Project 2000 will afford shippers on the extended pipeline system access to industrial gas consumers in northern Indiana. The project has a targeted in-service date of November 2001. The capital expenditures for the project are estimated to be approximately $94 million. RATIO OF TAXABLE INCOME TO DISTRIBUTIONS We estimate that a purchaser of common units in this offering who holds them through the record date for the last quarter of 2003 will be allocated an amount of federal taxable income for the period 2000 through 2003 that will be less than 10% of the amount of cash distributed to such unitholder with respect to that period. The foregoing is based on certain assumptions regarding revenues, capital expenditures, anticipated cash distributions, amounts expended for Project 2000 and other factors. Although we believe that this estimate is reasonable, it is subject to uncertainties beyond our control, and we cannot assure you that this estimate will prove to be correct. Taxable income for the last month of 2000 will be allocated to purchasers of common units in this offering, but no cash distributions will be made on the common units purchased in this offering until the first quarter of 2001. S-4 7 RECENT TAX DEVELOPMENTS This section is a summary of certain recent federal income tax developments that may be relevant to you. The IRS has recently finalized regulations under Sections 743, 197, and 1223 of the Internal Revenue Code. Treasury Regulations under Section 743 require a portion of the Section 743(b) adjustment attributable to property subject to cost recovery deductions under Section 168 to be recovered over the remaining cost recovery period for the Section 704(c) built-in gain in such property. Recently finalized Treasury Regulations under Section 197 similarly require a portion of the Section 743(b) adjustment attributable to amortizable section 197 intangibles to be amortized over the remaining amortization period for the Section 704(c) built-in gain in such intangibles. These Regulations apply only to partnerships that have adopted the remedial method, which we may adopt. If a different method is adopted, the Section 743(b) adjustment attributable to property subject to cost recovery deductions under Section 168 or amortization under Section 197 must be taken into account as if it were newly-purchased property placed in service when the transfer giving rise to the Section 743(b) adjustment occurs. Regardless of the method adopted, Treasury Regulation Section 1.167(c)-1(a)(6) requires the portion of a Section 743(b) adjustment attributable to property subject to depreciation under Section 167 of the Internal Revenue Code to be depreciated using either the straight-line method or the 150% declining balance method. Under our partnership agreement, the general partner is authorized to adopt a convention to preserve the uniformity of common units even if that convention is not consistent with specified Treasury Regulations. Although our counsel is unable to opine as to the validity of such an approach, we intend to adopt a method to depreciate and amortize the Section 743(b) adjustment attributable to unrealized appreciation in the value of contributed property that will preserve the uniformity of common units. Regardless of the method we adopt, the ratio of federal taxable income allocated to unitholders for the period 2000 to 2003 to the amount of cash distributed to such unitholders with respect to that period is not expected to be materially affected. The method we adopt for amortizing and depreciating the Section 743(b) adjustment may be inconsistent with the Treasury Regulations. If the IRS successfully challenged our method for depreciating or amortizing the Section 743(b) adjustment, the uniformity of common units might be affected, and the gain realized by a partner from the sale of common units might be increased without the benefit of additional deductions. The IRS has ruled that a partner who acquires interests in a partnership in separate transactions must combine those interests and maintain a single adjusted basis for all those interests. Upon a sale or disposition of less than all of those interests, a portion of that basis must be allocated to the interests sold using an "equitable apportionment" method. The IRS has recently finalized regulations under Section 1223 of the Code that make it clear that this ruling applies to publicly traded partnerships such as us. These recently finalized regulations would, however, allow a selling unitholder who can identify the common units transferred with an ascertainable holding period to elect to use the actual holding period of the common units transferred. Thus, according to the ruling, a unitholder will be unable to select high or low basis common units to sell as would be the case with corporate stock, but, according to the regulations, may designate specific common units sold for purposes of determining the holding period of common units transferred. A unitholder electing to use the actual holding period of common units transferred must use that identification method for all subsequent sales or exchanges of common units. A unitholder considering the purchase of additional common units or a sale of common units purchased in separate transactions should consult his tax advisor as to the possible consequences of this ruling and application of the proposed regulations. To the extent set forth below and under "Tax Considerations -- Legal Opinions and Advice" in the accompanying prospectus, this section represents the opinion of Vinson & Elkins L.L.P. insofar as it relates to matters of law and legal conclusions. The opinion with respect to this section is subject to the same assumptions and limitations as the opinion of Vinson & Elkins L.L.P. described under "Tax Considerations" in the accompanying prospectus. S-5 8 USE OF PROCEEDS We estimate that the net proceeds of this offering will be approximately $52 million. We will use the proceeds, together with capital contributions from our general partners, to reduce the aggregate amount outstanding under our bank credit agreements entered into in June 2000. We used the funds borrowed under the credit agreements, along with the proceeds from senior notes, to acquire gas gathering businesses from Enron North America in September 2000. Borrowings under the credit agreements have a weighted average interest rate of 7.99%, and the average time to maturity is 2.5 years. PRICE RANGE OF COMMON UNITS AND DISTRIBUTIONS Our outstanding equity consists of general partner interests representing in the aggregate a 2% interest and 29,347,313 common units representing in the aggregate a 98% limited partner interest. The common units are traded on the NYSE under the symbol "NBP." As of October 18, 2000, there were approximately 1,500 holders of the common units and approximately 30,000 beneficial owners of the common units, including common units held in street name. The following table sets forth, for the periods indicated, the high and low sales prices for the common units, as reported on the NYSE Composite Transactions Tape, and quarterly declared cash distributions thereon. The last reported sale price of the common units on the NYSE on November 1, 2000 was $29.00 per common unit.
PRICE RANGE DISTRIBUTIONS ------------------- PER COMMON HIGH LOW UNIT(1) -------- -------- ------------- 1998 First Quarter............................................. $34.3125 $32.5000 $0.575 Second Quarter............................................ 35.0000 31.8125 0.575 Third Quarter............................................. 34.7500 31.1250 0.575 Fourth Quarter............................................ 36.1250 32.5000 0.610 1999 First Quarter............................................. $35.5000 $30.3750 $0.610 Second Quarter............................................ 33.5625 30.1875 0.610 Third Quarter............................................. 31.8750 28.0000 0.610 Fourth Quarter............................................ 29.5000 21.6250 0.650 2000 First Quarter............................................. $29.2500 $23.0000 $0.650 Second Quarter............................................ 28.1250 23.7500 0.650 Third Quarter............................................. 31.8750 27.2500 0.700 Fourth Quarter (through November 1, 2000)................. 33.6250 28.7500 (2)
- --------------- (1) The amounts shown reflect distributions made following the close of the quarter consisting of available cash for the quarter. We recently announced an increase in our cash distributions to $0.70 per common unit, effective with the third quarter distribution payable on November 14, 2000 to unitholders of record as of October 31, 2000. (2) We intend to continue to pay regular quarterly cash distributions, and we expect the distribution for the fourth quarter 2000 to be $0.70 per common unit. S-6 9 CAPITALIZATION The following table sets forth our unaudited historical and as adjusted capitalization as of September 30, 2000. The as adjusted information gives effect to: - the sale of common units in this offering and the application of the net proceeds (assuming the underwriters' over-allotment option is not exercised) to reduce amounts outstanding under our credit agreements, and - the capital contribution of our general partners to maintain their combined 2% general partner interest in us in connection with the issuance of additional common units. For a discussion of the application of these proceeds, see "Use of Proceeds." This table should be read in conjunction with our historical financial statements and the notes to those financial statements that are incorporated by reference in this prospectus supplement and the accompanying prospectus.
AS OF SEPTEMBER 30, 2000 ------------------------ ACTUAL AS ADJUSTED ---------- ----------- (IN THOUSANDS) Northern Border Pipeline Senior notes -- average 8.49%, due from 2001 to 2003...... $ 184,000 $ 184,000 Pipeline credit agreement Term loan, variable interest rate (6.92% at September 30, 2000), due 2002...................................... 484,000 484,000 Senior notes -- 7.75%, due 2009........................... 200,000 200,000 Unamortized proceeds from termination of interest rate forward agreements and unamortized debt discount, net.................................................... 10,565 10,565 Northern Border Partners, L.P. Senior notes -- 8.875%, due 2010.......................... 250,000 250,000 Partnership credit agreements Revolving credit, variable interest rate (average 7.99% at September 30, 2000), due 2003...................... 97,500 44,734 Unamortized premium on debt............................... 3,639 3,639 Black Mesa 10.7% note agreement, due quarterly to 2004............... 14,720 14,720 ---------- ---------- Total long-term debt.............................. 1,244,424 1,191,658 ---------- ---------- Minority interests in partners' capital..................... 248,736 248,736 ---------- ---------- Partners' capital General partners.......................................... 9,824 10,879 Common unitholders........................................ 481,380 533,091 ---------- ---------- Total partners' capital........................... 491,204 543,970 ---------- ---------- Total capitalization.............................. $1,984,364 $1,984,364 ---------- ----------
S-7 10 UNDERWRITING Under the terms and subject to the conditions stated in the underwriting agreement dated the date of this prospectus supplement, each underwriter named below has severally agreed to purchase from us, and we have agreed to sell to such underwriter, the number of common units set forth opposite the name of such underwriter.
NUMBER OF UNDERWRITER COMMON UNITS - ----------- ------------ PaineWebber Incorporated.............................. 625,000 Salomon Smith Barney Inc.............................. 625,000 Lehman Brothers Inc................................... 625,000 --------- Total....................................... 1,875,000 =========
The underwriters propose to offer the common units to the public at the public offering price set forth on the cover page of this prospectus supplement and to certain dealers at such public offering price less a selling concession not in excess of $0.74 per common unit. The underwriters may allow, and such dealers may reallow, a concession not in excess of $0.10 per common unit to certain other underwriters or to certain other brokers or dealers. After the initial offering of the units to the public, the offering price and other selling terms may from time to time be changed by the underwriters. The units are offered subject to receipt and acceptance by the underwriters, and to other conditions, including the right to reject orders in whole or in part. We have granted to the underwriters an option, exercisable for 30 days from the date of this prospectus supplement, to purchase up to 281,250 additional common units at the public offering price less the underwriting discount. The underwriters may exercise this option solely for the purpose of covering over-allotments, if any, in connection with this offering. To the extent this option is exercised, each underwriter will be committed, subject to certain conditions, to purchase a number of additional common units approximately proportionate to the underwriter's initial purchase commitment. We have agreed, with limited exceptions, not to directly or indirectly sell, offer to sell, grant any option for the sale of, or otherwise dispose of any common units, or securities convertible into or exercisable or exchangeable for common units or rights to acquire common units, for a period of 90 days after the date of this prospectus supplement, without the prior written consent of PaineWebber Incorporated. Our officers, general partners and PEC Midwest L.L.C., a subsidiary of Duke Energy Corporation, have entered into similar agreements. The underwriters may from time to time engage in transactions with and perform services for us in the ordinary course of their business. For this offering, the underwriters may purchase and sell common units in the open market. These transactions may include over-allotment and stabilizing transactions and purchases to cover syndicate short positions created for this offering. Stabilizing transactions consist of certain bids or purchases for the purpose of preventing or retarding a decline in the market price of the common units. Syndicate short positions involve the sale by the underwriters of a greater number of common units than they are required to purchase from us in this offering. The underwriters may also impose a penalty bid, whereby selling concessions allowed to syndicate members or other broker-dealers in respect of the common units sold in this offering for their account may be reclaimed by the syndicate if those common units are repurchased by the syndicate in stabilizing or covering transactions. These activities may stabilize, maintain or otherwise affect the market price of the common units, which may be higher than the price that might otherwise prevail in the open market, and these activities, if commenced, may be discontinued at any time without notice. These transactions may be effected on the New York Stock Exchange or otherwise. Neither the underwriters nor we make any representation or prediction as to the direction or magnitude of any effect that the transactions described above may have on the price of the common units. S-8 11 In addition, neither the underwriters nor we make any representation that the underwriters will engage in such transactions or that such transactions, once commenced, will not be discontinued without notice. The following table shows the underwriting discounts and commissions to be paid to the underwriters in connection with this offering. These amounts are shown assuming both no exercise and full exercise of the underwriters' option to purchase additional common units:
NO EXERCISE FULL EXERCISE ----------- ------------- Per common unit............................................. $ 1.23 $ 1.23 Total....................................................... $2,306,250 $2,652,188
We estimate that the total expenses of the offering, other than underwriting discounts and commissions, will be approximately $400,000. We have agreed to indemnify the underwriters against certain liabilities, including liabilities under the Securities Act, or to contribute to payments the underwriters may be required to make in respect thereof. Because the National Association of Securities Dealers, Inc. ("NASD") views the common units offered hereby as interests in a direct participation program, the offering is being made in compliance with Rule 2810 of the NASD's Conduct Rules. LEGAL MATTERS Vinson & Elkins L.L.P. will pass upon the validity of the common units offered by means of this prospectus. Andrews & Kurth L.L.P. will advise the underwriters about other issues relating to the offering. EXPERTS The consolidated financial statements and schedule included in our Annual Report on Form 10-K for the year ended December 31, 1999, incorporated by reference in this prospectus, have been audited by Arthur Andersen LLP, independent public accountants, as indicated in their reports with respect thereto, and are incorporated by reference herein in reliance upon the authority of said firm as experts in accounting and auditing in giving said reports. S-9 12 PROSPECTUS NORTHERN BORDER PARTNERS, L.P. COMMON UNITS DEBT SECURITIES ------------------------ We are a publicly-traded Delaware limited partnership that owns a 70% general partner interest in Northern Border Pipeline Company, a Texas general partnership ("Northern Border Pipeline"). Northern Border Pipeline is the largest transporter of natural gas from the Western Canadian Sedimentary Basin to the midwestern United States. Northern Border Pipeline owns a 1,214-mile interstate pipeline system that originates from the Canadian border and extends to natural gas markets in the midwestern United States currently terminating near Chicago, Illinois. Our interest in Northern Border Pipeline represents substantially all of our assets. This prospectus provides you with a general description of the Common Units and Debt Securities we may offer. Each time we sell securities we will provide a prospectus supplement that will contain specific information about the terms of that offering and the securities offered. The prospectus supplement may also add, update or change information contained in this prospectus. We currently have 29,347,313 Common Units outstanding. The Common Units are traded on the New York Stock Exchange under the symbol "NBP." We will provide information in the prospectus supplement for the expected trading market, if any, for Debt Securities that we offer. Throughout this prospectus we refer to ourselves, Northern Border Partners, L.P., as "we" or "us." ------------------------ WE WILL PROVIDE SPECIFIC TERMS OF THESE SECURITIES IN PROSPECTUS SUPPLEMENTS. YOU SHOULD READ THIS PROSPECTUS AND ANY SUPPLEMENT CAREFULLY BEFORE YOU INVEST. NEITHER THE SECURITIES AND EXCHANGE COMMISSION (THE "SEC") NOR ANY STATE SECURITIES COMMISSION HAS APPROVED OR DISAPPROVED THESE SECURITIES. THIS MEANS THAT NEITHER THE SEC NOR ANY STATE SECURITIES COMMISSION HAS PASSED UPON THE ACCURACY, ADEQUACY OR COMPLETENESS OF THIS PROSPECTUS. ANY REPRESENTATION TO THE CONTRARY IS A CRIMINAL OFFENSE. THE INFORMATION IN THIS PROSPECTUS IS NOT COMPLETE AND MAY BE CHANGED. THIS PROSPECTUS IS NOT AN OFFER TO SELL THESE SECURITIES, AND IT IS NOT SOLICITING AN OFFER TO BUY THESE SECURITIES, IN ANY STATE WHERE THE OFFER OR SALE IS NOT PERMITTED. TO UNDERSTAND US AND THE TERMS OF OUR SECURITIES, YOU SHOULD CAREFULLY READ THIS DOCUMENT TOGETHER WITH ANY AND ALL PROSPECTUS SUPPLEMENTS. TOGETHER THESE DOCUMENTS WILL PROVIDE YOU WITH THE SPECIFIC TERMS OF THE OFFERINGS. YOU SHOULD ALSO READ THE DOCUMENTS WE HAVE REFERRED YOU TO IN "WHERE YOU CAN FIND MORE INFORMATION" BELOW FOR INFORMATION ON US AND FOR OUR FINANCIAL STATEMENTS. THE DATE OF THIS PROSPECTUS IS MARCH 3, 1999. 13 TABLE OF CONTENTS
PAGE NO. -------- THE OFFERED SECURITIES...................................... 2 WHERE YOU CAN FIND MORE INFORMATION......................... 2 CAUTIONARY STATEMENT REGARDING FORWARD LOOKING STATEMENTS... 3 OUR BUSINESS................................................ 4 CONFLICTS OF INTEREST AND FIDUCIARY RESPONSIBILITIES........ 7 FERC REGULATION............................................. 8 ENVIRONMENTAL AND SAFETY COSTS AND LIABILITIES.............. 11 COMMON UNITS................................................ 11 DEBT SECURITIES............................................. 12 RATIO OF EARNINGS TO FIXED CHARGES.......................... 15 USE OF PROCEEDS............................................. 15 TAX CONSIDERATIONS.......................................... 15 PLAN OF DISTRIBUTION........................................ 29 LEGAL MATTERS............................................... 30 EXPERTS..................................................... 30
THE OFFERED SECURITIES This prospectus is part of a registration statement (No. 333-72323) that we filed with the SEC using a "shelf" registration process. Under this shelf process, we may offer from time to time up to an aggregate of $200,000,000 of the Common Units and Debt Securities. In this prospectus, we sometimes refer to the Common Units and Debt Securities collectively as the "securities." This prospectus provides you with a general description of the securities and of us. Each time we offer the securities, we will provide you with a prospectus supplement that will describe, among other things, the specific types, amounts and prices of the securities being offered and the terms of the offering. The prospectus supplement may also add, update or change information contained in this prospectus. Therefore, before you invest in the securities, you should read this prospectus, any prospectus supplements and all additional information referenced in the next section. WHERE YOU CAN FIND MORE INFORMATION We file annual, quarterly and current reports and other information with the SEC. You may read and copy any document we file at the SEC's public reference room at Room 1024, Judiciary Plaza, 450 Fifth Street, N.W., Washington, D.C. 20549 and at the SEC's public reference rooms in New York, New York and Chicago, Illinois. Please call the SEC at 1-800-SEC-0330 for further information on the public reference rooms. The SEC maintains a web site that contains reports, information statements and other information regarding issuers that file electronically. Our SEC filings are available on this web site at http://www.sec.gov. The SEC allows us to "incorporate by reference" the information we file with it into this prospectus, which means that we can disclose important information to you by referring you to those documents. The information we incorporate by reference is considered to be part of this prospectus, and later information that we file with the SEC will automatically update and supersede this information. Therefore, before you decide to invest in a particular offering under this registration statement, you should always check for SEC reports we may have filed after the date of this prospectus. We incorporate by reference the documents listed below and any future filings made with the SEC under Section 13(a), 13(c), 14 or 15(d) of the 2 14 Securities Exchange Act of 1934 (the "Exchange Act") until all offerings under this shelf registration are completed: - Annual Report on Form 10-K for the year ended December 31, 1997; and - Quarterly Reports on Form 10-Q for the quarters ended March 31, 1998, June 30, 1998 and September 30, 1998. You may request a copy of these filings at no cost, by making written or telephone requests for such copies to: Investor Relations Northern Border Partners, L.P. 1111 South 103rd Street, Omaha, Nebraska 68124 Telephone: 877-208-7318 You should rely only on the information incorporated by reference or provided in this prospectus or any prospectus supplement. We have not authorized anyone else to provide you with any information. You should not assume that the information in this prospectus or any prospectus supplement is accurate as of any date other than the date on the front of each document. CAUTIONARY STATEMENT REGARDING FORWARD LOOKING STATEMENTS This prospectus contains statements that constitute "forward looking statements" within the meaning of Section 27A of the Securities Act and Section 21E of the Exchange Act. In general, any statement other than a statement of historical fact is a forward looking statement. These statements appear in a number of places in this prospectus and include statements regarding our plans, beliefs and expectations with respect to, among other things: - Future acquisitions; - Expected future costs; - Future capital expenditures; - Trends affecting our future financial condition or results of operations; and - Our business strategy regarding future operations. Any such forward looking statements are not assurances of future performance and involve risks and uncertainties. Actual results may differ materially from anticipated results for a number of reasons, including: - Industry conditions; - Future demand for natural gas; - Availability of supplies of Canadian natural gas; - Political and regulatory developments that impact Federal Energy Regulatory Commission ("FERC") proceedings involving Northern Border Pipeline; - Northern Border Pipeline's ability to replace its rate base as it is depreciated and amortized; - Competitive developments by Canadian and other U.S. natural gas transmission companies; - Political and regulatory developments in the U.S. and in Canada; - Conditions of the capital markets; and - Our ability to implement our Year 2000 readiness program. 3 15 OUR BUSINESS We were formed in 1993 to acquire, own and participate in the management of pipeline and other energy assets through a subsidiary limited partnership, Northern Border Intermediate Limited Partnership. Northern Plains Natural Gas Company ("Northern Plains"), Pan Border Gas Company ("Pan Border") and Northwest Border Pipeline Company ("Northwest Border") serve as our general partners (collectively, the "General Partners"). Northern Plains and Pan Border are wholly-owned subsidiaries of Enron Corp. ("Enron"), and Northwest Border is a wholly-owned subsidiary of The Williams Companies, Inc. ("Williams"). The General Partners hold in us an aggregate 2% general partner interest and Common Units representing an aggregate 14.5% limited partner interest. The combined general and limited partner interests of the General Partners are: - Northern Plains -- 11.7%; - Pan Border -- 0.7%; and - Northwest Border -- 4.1%. We own a 70% general partner interest in Northern Border Pipeline. The remaining 30% general partner interests in Northern Border Pipeline are owned by subsidiaries of TransCanada PipeLines Limited (the "TransCanada Subsidiaries"). Following is a chart showing our organization, our structure and our interest in Northern Border Pipeline. NORTHERN BORDER PARTNERS, L.P. ORGANIZATION STRUCTURE GRAPHIC Our 70% interest in Northern Border Pipeline represents substantially all of our assets and the source of substantially all of our earnings and cash flow. Northern Border Pipeline owns a 1,214-mile United States interstate pipeline system (the "Pipeline System") that transports natural gas from the Montana- Saskatchewan border to natural gas markets in the midwestern United States. Northern Border Pipeline initially constructed this Pipeline System in 1982 with capacity additions to the Pipeline System in 1991, 1992 and 1998. A recent expansion, called The Chicago Project, was completed in late 1998, and increased the Pipeline System's capacity by 42% to its current capacity of 2,373 million cubic feet per day ("MMcfd"). The Northern Border Management Committee, which is comprised of three representatives selected by us (one designated by each General Partner) and one representative of the TransCanada Subsidiaries, 4 16 oversees the management of Northern Border Pipeline. Northern Plains operates the Pipeline System pursuant to an operating agreement. Northern Plains employs approximately 190 individuals located at its headquarters in Omaha, Nebraska, and at various locations along the pipeline route. Northern Border Pipeline transports gas for shippers under a tariff regulated by FERC. The tariff specifies the calculation of amounts to be paid by shippers and the general terms and conditions of transportation service on the Pipeline System. Northern Border Pipeline generates revenues from the receipt and delivery of gas at points along the Pipeline System according to individual transportation contracts with its shippers. Northern Border Pipeline does not own the gas that it transports, and therefore it does not assume the risk of loss from decreases in market prices for gas transported on the Pipeline System. We also own Black Mesa Holdings, Inc. Black Mesa Holdings, Inc., through its wholly-owned subsidiary, Black Mesa Pipeline, Inc., owns a 273-mile, 18-inch diameter coal slurry pipeline that originates at a coal mine in Kayenta, Arizona. The coal slurry pipeline transports crushed coal suspended in water. It traverses westward through northern Arizona to the 1,500 megawatt Mohave Power Station located in Laughlin, Nevada. The coal slurry pipeline is the sole source of fuel for the Mohave Power Station, which consumes an average of 4.8 million tons of coal annually. The capacity of the pipeline is fully contracted to the coal supplier for the Mohave Power Station through the year 2005. The pipeline is operated by Black Mesa Pipeline Operations, LLC, our wholly-owned subsidiary. Our cash flow from the coal slurry pipeline represents only about 2% of our total cash flow. The Pipeline System The Pipeline System has pipeline access to natural gas reserves in the Western Canadian Sedimentary Basin located in the Canadian provinces of Alberta, British Columbia and Saskatchewan, as well as the Williston Basin in the United States. The Pipeline System also has access to synthetic gas processed at the Dakota Gasification Plant in North Dakota. Interconnecting pipeline facilities provide Northern Border Pipeline shippers access to markets in the Midwest, including Chicago. Northern Border Pipeline shippers can arrange transportation, displacement and exchange arrangements with third parties to provide access beyond Chicago to markets throughout the United States. The Pipeline System consists of 822 miles of 42-inch diameter pipe designed to transport 2,373 MMcfd from the Canadian border to Ventura, Iowa; 30-inch diameter pipe and 36-inch diameter pipe, each approximately 147 miles in length, designed to transport 1,300 MMcfd from Ventura, Iowa to Harper, Iowa; and 226 miles of 36-inch diameter pipe and 19 miles of 30-inch diameter pipe designed to transport 645 MMcfd from Harper, Iowa to a terminus near Manhattan, Illinois (Chicago area). Along the pipeline there are fifteen compressor stations with total rated horsepower of 476,500 and measurement facilities to support the receipt and delivery of gas at various points. Other facilities include five field offices and a microwave communication system with fifty-one tower sites. Interconnects Interconnecting pipeline facilities provide Northern Border Pipeline's shippers with flexible access to natural gas markets. The Pipeline System interconnects with pipeline facilities of: - Northern Natural Gas Company, an Enron subsidiary, at Ventura, Iowa as well as multiple smaller interconnections in South Dakota, Minnesota and Iowa; - Natural Gas Pipeline Company of America at Harper, Iowa; - MidAmerican Energy Company at Iowa City and Davenport, Iowa; - Interstate Power Company at Prophetstown, Illinois; - Northern Illinois Gas Company at Troy Grove and Minooka, Illinois; - Midwestern Gas Transmission Company near Channahon, Illinois; and 5 17 - ANR Pipeline Company near Manhattan, Illinois; and - The Peoples Gas Light and Coke Company near Manhattan,Illinois (Chicago area) at the terminus of the Pipeline System. At its northern end, the Pipeline System is connected to the Foothills Pipe Lines (Sask.) Ltd. System in Canada, which in turn is connected to the pipeline systems of NOVA Gas Transmission Ltd. in Alberta and of Transgas Limited in Saskatchewan. The NOVA system gathers and transports a substantial portion of Canadian natural gas production. The Pipeline System also connects with the facilities of Williston Basin Interstate pipeline at Glen Ullin and Buford, North Dakota, facilities of Amerada Hess Corporation at Watford City, North Dakota and facilities of Dakota Gasification Company at Hebron, North Dakota in the northern portion of the system. Project 2000 In October 1998, Northern Border Pipeline filed a certificate application with FERC to seek approval of its Project 2000 that seeks to expand and extend the Pipeline System into Indiana by November 2000. In addition to providing additional Canadian natural gas to United States' markets, Project 2000 would afford shippers on the extended pipeline system access to industrial gas consumers in northern Indiana. Shippers The Pipeline System serves a number of shippers with diverse financial and business profiles. Based on shippers' cost of service obligations, 93% of the capacity is contracted by producers and marketers. The remaining capacity is contracted primarily by local distribution companies (5%) and interstate pipelines (2%). At present, the termination dates of these contracts range from October 31, 2001 to December 21, 2013. The weighted average contract life as of December 31, 1998 (based on shippers' cost of service obligations) is slightly under 8 years with 97% of capacity contracted through at least mid-September 2003. Northern Border Pipeline's largest shipper, Pan-Alberta Gas U.S., Inc. ("PAGUS"), currently holds 707 MMcfd, 26.5% of the capacity under three transportation contracts. An affiliate of Enron provides guaranties for 300 MMcfd of PAGUS' contractual obligations through October 31, 2001. In addition, PAGUS' remaining capacity is supported by various credit support arrangements including, among others, a letter of credit, a guaranty from an interstate pipeline company through October 31, 2001 for 150 MMcfd, an escrow account and an upstream capacity transfer agreement. In 1998, the Western Canadian Sedimentary Basin was the source of approximately 88% of the natural gas transported by the Pipeline System. We estimate that the Pipeline System's share of Canadian gas exported to the United States in January 1999, the first full month of operations of The Chicago Project, was nearly 24%. Competition Northern Border Pipeline competes with other pipeline companies that transport gas from the Western Canadian Sedimentary Basin or that transport gas to end-use markets in the Midwest. Its competitive position is affected by the availability of Canadian natural gas for export and demand for natural gas in the United States. Shippers of gas produced in the Western Canadian Sedimentary Basin have other options to transport Canadian natural gas to the United States, including transportation on pipelines eastward in Canada or to markets on the West Coast. The sponsors of the Alliance Pipeline project recently received Canadian and United States regulatory approvals for the construction of a new pipeline to originate in western Canada and terminate in the vicinity of Chicago, Illinois. These sponsors have announced their plans for the pipeline to be in service by October 2000. If constructed, the new pipeline would compete directly with Northern Border Pipeline by transporting gas from the Western Canadian Sedimentary Basin to the midwestern United States. Although there may be a large increase in natural gas moving from the Western Canadian Sedimentary 6 18 Basin into the Chicago market if the Alliance project is constructed, there are several additional projects proposed to transport natural gas from the Chicago area to growing eastern markets. The proposed projects, currently being pursued by unrelated third parties, are targeting markets in eastern Canada and the northeast United States. None of these proposed projects has received final regulatory approval. CONFLICTS OF INTEREST AND FIDUCIARY RESPONSIBILITIES Our business is managed by or under the direction of a three person Partnership Policy Committee, whose members are designated by our three General Partners. We have three representatives on the Northern Border Pipeline Management Committee, each of whom votes a portion of our 70% voting interest on the Northern Border Pipeline Management Committee. Our representatives on the Northern Border Pipeline Management Committee are also designated by our General Partners. Our interests could conflict with the interests of our General Partners or their affiliates, and in such case the members of our Partnership Policy Committee will generally have a fiduciary duty to resolve such conflicts in a manner that is in our best interest. Northern Border Pipeline's interests could conflict with our interest or the interests of the TransCanada Subsidiaries and their affiliates, and in such case our representatives on the Northern Border Pipeline Management Committee will generally have a fiduciary duty to resolve such conflicts in a manner that is in the best interest of Northern Border Pipeline. Our fiduciary duty as a general partner of Northern Border Pipeline may restrict us from taking actions that might be in our best interests but in conflict with the fiduciary duty that our representatives or we owe to the TransCanada Subsidiaries. Unless otherwise provided for in a partnership agreement, the laws of Delaware and Texas generally require a general partner of a partnership to adhere to fiduciary duty standards, under which it owes its partners the highest duties of good faith, fairness and loyalty. Similar rules apply to persons serving on our Partnership Policy Committee or the Northern Border Pipeline Management Committee. Because of the competing interests identified above, our Partnership Agreement and the partnership agreement for Northern Border Pipeline contain provisions that modify certain of these fiduciary duties. For example: - Our Partnership Agreement states that the General Partners, their affiliates and their officers and directors will not be liable for monetary damages to us, our limited partners or their assignees for errors of judgment or for any acts or omissions if the General Partners and such other persons acted in good faith. - Our Partnership Agreement allows the General Partners and our Partnership Policy Committee to take into account the interests of parties in addition to ours in resolving conflicts of interest. - Our Partnership Agreement provides that the General Partners will not be in breach of their obligations under our Partnership Agreement or their duties to us or our unitholders if the resolution of a conflict is fair and reasonable to us. The latitude given in our Partnership Agreement in connection with resolving conflicts of interest may significantly limit the ability of a unitholder to challenge what might otherwise be a breach of fiduciary duty. - Our Partnership Agreement provides that a purchaser of Common Units is deemed to have consented to certain conflicts of interest and actions of the General Partners and their affiliates that might otherwise be prohibited and to have agreed that such conflicts of interest and actions do not constitute a breach by the General Partners of any duty stated or implied by law or equity. - Our audit committee (which is composed of persons unaffiliated with any of the General Partners) will, at the request of a General Partner or a member of our Partnership Policy Committee, review conflicts of interest that may arise between a General Partner and its affiliates (or the member of our Partnership Policy Committee designated by it), on the one hand, and our unitholders or us, on the other. Any resolution of a conflict approved by our audit committee is conclusively deemed fair and reasonable to us. 7 19 - We have proposed to enter into an amendment to the partnership agreement for Northern Border Pipeline that relieves the TransCanada Subsidiaries, their affiliates and their transferees from any duty to offer business opportunities to Northern Border Pipeline, with certain exceptions. The proposed amendment would also relieve us from any duty to offer to Northern Border Pipeline certain business opportunities that come to our attention. We are required to indemnify the members of our Partnership Policy Committee and General Partners, their affiliates and their respective officers, directors, employees, agents and trustees to the fullest extent permitted by law against liabilities, costs and expenses incurred by any such person who acted in good faith and in a manner reasonably believed to be in, or (in the case of a person other than one of the General Partners) not opposed to, our best interests and, with respect to any criminal proceedings, had no reasonable cause to believe the conduct was unlawful. Some of our shippers are affiliated with our General Partners and the TransCanada Subsidiaries. Enron Capital & Trade Resources Corp., a subsidiary of Enron, and Transcontinental Gas Pipe Line Corporation, a subsidiary of Williams hold 6.1% of the capacity. TransCanada PipeLines Limited, an affiliate of the TransCanada Subsidiaries, holds 10.8% of the capacity. FERC REGULATION General FERC extensively regulates Northern Border Pipeline as a "natural gas company" under the Natural Gas Act (the "NGA"). Under the NGA and the Natural Gas Policy Act, FERC has jurisdiction over Northern Border Pipeline with respect to virtually all aspects of its business, including: - Transportation of natural gas; - Rates and charges; - Construction of new facilities; - Extension or abandonment of service and facilities; - Accounts and records; - Depreciation and amortization policies; - Acquisition and disposition of facilities; - Initiation and discontinuation of services; and - Certain other matters. Northern Border Pipeline, where required, holds certificates of public convenience and necessity issued by FERC covering its facilities, activities and services. Without these certificates, a pipeline company cannot legally do business. Under Section 8 of the NGA, FERC has the power to prescribe the accounting treatment for items for regulatory purposes. The Northern Border Pipeline books and records are periodically audited pursuant to Section 8. FERC regulates Northern Border Pipeline's rates and charges for transportation in interstate commerce. Natural gas companies may not charge rates exceeding rates deemed just and reasonable by FERC. In addition, FERC prohibits natural gas companies from unduly preferring or unreasonably discriminating against any person with respect to pipeline rates or terms and conditions of service. Certain types of rates may be discounted without further FERC authorization. 8 20 Cost of Service Tariff Northern Border Pipeline's firm transportation shippers contract to pay for an allocable share of the cost of service associated with the Pipeline System's capacity. During any given month, all such shippers pay a uniform mileage-based charge for the amount of capacity contracted, calculated under a cost of service tariff. The shippers are obligated to pay their allocable share of the cost of service regardless of the amount of gas they actually transport. The cost of service tariff is regulated by FERC and provides Northern Border Pipeline an opportunity to recover all operations and maintenance costs of the Pipeline System, taxes other than income taxes, interest, depreciation and amortization, an allowance for income taxes and a regulated equity return. Northern Border Pipeline may not charge or collect more than its cost of service pursuant to its tariff on file with FERC. Northern Border Pipeline's investment in the Pipeline System is reflected in various accounts referred to collectively as its regulated "rate base." The cost of service includes a return, with related income taxes, on the rate base. Over time the rate base declines as a result of, among other things, the monthly depreciation and amortization. The Northern Border Pipeline rate base includes, as an additional amount, a one-time ratemaking adjustment to reflect the receipt of a construction incentive on the original project. Since inception the rate base adjustment, called an incentive rate of return ("IROR"), has been amortized through monthly additions to the cost of service. As a result, our revenues and net income for 1998 included $9.9 million for such amortization along with related income taxes, net of the effect of minority interests. This impact on revenues and net income is expected to continue until November 2001 when the IROR is fully amortized. Northern Border Pipeline bills the cost of service on an estimated basis for a six-month cycle. Any net excess or deficiency resulting from the comparison of the actual cost of service determined for that period according to its FERC tariff to the estimated billing is accumulated, including carrying charges thereon, and is either billed to or credited back to the shippers' accounts. Northern Border Pipeline also provides interruptible transportation service. Interruptible transportation service is transportation in certain circumstances when capacity is available after satisfying firm service requests. The maximum rate charged to interruptible shippers is calculated from cost of service estimates on the basis of contracted capacity. Except for certain limited situations, Northern Border Pipeline credits back to the firm shippers all revenue from the interruptible transportation service. In its 1995 rate case, Northern Border Pipeline reached a settlement that was filed in a Stipulation and Agreement (the "Stipulation"). Although it was contested, it was approved by FERC on August 1, 1997. In the Stipulation, the depreciation rate was established at 2.5% from January 1, 1997 through the in-service date of The Chicago Project, and at that time it was reduced to 2%. Starting in the year 2000, the depreciation rate is scheduled to increase gradually on an annual basis until it reaches 3.2% in 2002. The Stipulation also determined several other cost of service parameters. In accordance with the effective tariff, Northern Border Pipeline's allowed equity rate of return is 12%. For at least seven years from the date The Chicago Project was completed, Northern Border Pipeline, under the terms of the Stipulation, may continue to calculate its allowance for income taxes as a part of its cost of service in the manner it has historically used. In addition, a settlement adjustment mechanism of $31 million was implemented, which effectively reduces the allowed return on rate base. Also as agreed to in the Stipulation, Northern Border Pipeline implemented a capital project cost containment mechanism ("PCCM"). The purpose of the PCCM was to limit Northern Border Pipeline's ability to include cost overruns on The Chicago Project in rate base and to provide incentives to Northern Border Pipeline for cost underruns. The PCCM amount is determined by comparing the final cost of The Chicago Project to the budgeted cost. If there is a cost overrun of $6 million or less, the shippers will bear the actual cost of the project through its inclusion in Northern Border Pipeline's rate base. If there is a cost savings of $6 million or less, the full budgeted cost will be included in the rate base. If there is a cost overrun or cost savings of more than $6 million but less than 5% of the budgeted cost, that amount will be allocated 50% to Northern Border Pipeline and 50% to its shippers (50% of the difference between 5% of 9 21 the budgeted cost and $6 million will be included in Northern Border pipeline's rate base, and 50% will be excluded). All cost overruns exceeding 5% of the budgeted cost are excluded from the rate base. The Stipulation required the budgeted cost for The Chicago Project, which had been initially filed with FERC for approximately $839 million, to be adjusted for the effects of inflation and project scope changes, as defined in the Stipulation. Such budgeted cost has been estimated as of the December 22, 1998 in-service date to be $889 million. Northern Border Pipeline's report to FERC and its shippers in late December 1998, reflected the conclusion that, based on information as of that date, once the budgeted cost has been established, there would be no adjustment to rate base as a result of the PCCM. Northern Border Pipeline is obligated by the Stipulation to update its calculation of the PCCM six months after the in-service date of The Chicago Project. The Stipulation requires the calculation of the PCCM to be reviewed by an independent national accounting firm. Several parties to the Stipulation advised FERC that they may have questions and desire further information about the report, and may possibly wish to test it (or the final report) and its conclusions in an appropriate proceeding in the future. The parties also stated that if it is determined that Northern Border Pipeline is not permitted to include certain claimed costs for The Chicago Project in its rate base, they reserve their rights to seek refunds, with interest, of any overcollections. Although we believe the initial computation has been made in accordance with the terms of the Stipulation, we are unable to make a definitive determination at this time whether any adjustments will be required. Should subsequent developments cause costs not to be recovered pursuant to the PCCM, a non-cash charge to write down transmission plant may result and such charge could be material to our operating results. Northern Border Pipeline is required by the terms of its tariff to file a rate case with FERC by no later than May 31, 1999 for a redetermination of its allowed equity rate of return. We cannot predict the impact, if any, of the outcome of the next rate case. Proposed Regulations In a Notice of Proposed Rulemaking ("NOPR") issued on July 29, 1998, FERC proposed changes to its regulations governing short-term transportation services. Among the proposals considered in the NOPR are: - Auctions for short-term capacity; - Removal of price caps for secondary market transactions; - Revisions to FERC's reporting requirements; - Revisions to tariff provisions governing imbalances; and - Negotiated services. In a companion Notice of Inquiry issued the same day, FERC requested industry comment on its pricing policies in the existing long-term market for transportation services and its pricing policies for new capacity. FERC also issued a NOPR to revise its procedures under which shippers or others may have complaints considered by FERC. We cannot assess the impact on Northern Border Pipeline of any final rules adopted by FERC as a result of these proceedings at this time. FERC also commenced proceedings to revise its pipeline construction regulations. On September 30, 1998, FERC issued a NOPR to amend its regulations to reflect current FERC policies governing the issuance of pipeline construction certificates and to codify the filing of certain related information. Also on September 30, 1998, FERC issued a NOPR that would give applicants seeking to construct, operate or abandon natural gas services or facilities the option of using a pre-filing collaborative process to resolve significant issues among parties and the pipeline. The NOPR also proposes that a significant portion of the environmental review process could be completed as part of the collaborative process. As part of the NOPR, FERC intends to examine existing landowner notification policies related to pipeline construction 10 22 and certain environmental and pipeline construction issues. We cannot assess the impact on Northern Border Pipeline of any final rules adopted by FERC as a result of these proceedings at this time. ENVIRONMENTAL AND SAFETY COSTS AND LIABILITIES Our operations are subject to federal and state laws and regulations relating to environmental protection and operational safety. Although we believe that our operations are in general compliance in all material respects with applicable environmental and safety regulations, risks of substantial costs and liabilities are inherent in pipeline operations, and we cannot give you any assurances that we will not incur such costs and liabilities. Moreover, it is possible that other developments, such as increasingly strict environmental and safety laws, regulations and enforcement policies thereunder, and claims for damages to property or persons resulting from our operations, could result in substantial costs and liabilities to us. If we are unable to recover such resulting costs, your cash distributions could be adversely affected. COMMON UNITS We currently have 29,347,313 Common Units outstanding, representing a 98% limited partner interest. Our Common Units are our only outstanding limited partner interests. Thus, our equity consists of general partner interests representing in the aggregate a 2% interest and Common Units representing in the aggregate a 98% limited partner interest. Prior to January 19, 1999, we had outstanding limited partner interests designated as Subordinated Units, but all of our outstanding Subordinated Units were converted to Common Units on that date. Distributions In general, the General Partners are entitled to 2% of all cash distributions, and the holders of Common Units are entitled to the remaining 98% of all cash distributions, except that the General Partners are entitled to incentive distributions if the amount distributed with respect to any quarter exceeds $0.605 per Common Unit ($2.42 annualized). Under the incentive distribution provisions, the General Partners are entitled to 15% of amounts distributed in excess of $0.605 per Common Unit, 25% of amounts distributed in excess of $0.715 per Common Unit ($2.86 annualized) and 50% of amounts distributed in excess of $0.935 per Common Unit ($3.74 annualized). We recently announced an increase in our distribution to $0.61 per Common Unit ($2.44 per Common Unit annualized), effective with the fourth quarter 1998 distribution to be paid on February 12, 1999. The amounts that trigger incentive distributions at various levels are subject to adjustment in certain events, as described in our Partnership Agreement. Voting Each holder of Common Units is entitled to one vote for each Common Unit on all matters submitted to a vote of the unitholders; provided that, if at any time any person or group owns beneficially 20% or more of all Common Units, such Common Units so owned may not be voted on any matter and may not be considered to be outstanding when sending notices of a meeting of unitholders (unless otherwise required by law), calculating required votes, determining the presence of a quorum or for other similar purposes under our Partnership Agreement. Listing Our outstanding Common Units are listed on the NYSE under the symbol "NBP." Any additional Common Units we issue will also be listed on the NYSE. Transfer Agent and Registrar Our transfer agent and registrar for the Common Units is First Chicago Trust Company of New York. 11 23 DEBT SECURITIES The Debt Securities may be: - Our unsecured general obligations; and - Either senior debt securities or subordinated debt securities. If we offer senior debt securities, we will issue them under a senior indenture. If we offer subordinated debt securities, we will issue them under a subordinated indenture. In this prospectus, we refer to the senior indenture and the subordinated indenture as an "Indenture" and collectively as the "Indentures." We will enter into the Indentures with a trustee that is qualified to act under the Trust Indenture Act of 1939, as amended (the "TIA") (together with any other trustee(s) chosen by us and appointed in a supplemental indenture with respect to a particular series of Debt Securities, the "Trustee"). We will identify the Trustee for each series of Debt Securities in the applicable prospectus supplement. We will file the forms of Indentures and any supplemental indentures from time to time by means of an exhibit to a Current Report on Form 8-K. These filings will be available for inspection at the corporate trust office of the Trustee, or as described above under "Where You Can Find More Information." The Indentures will be subject to, and governed by, the TIA. We will execute an Indenture and supplemental indenture if and when we issue any Debt Securities. Specific Terms of Each Series of Debt Securities in the Prospectus Supplement A prospectus supplement and a supplemental indenture relating to any series of Debt Securities being offered will include specific terms relating to such Debt Securities. These terms will include some or all of the following: - The form and title of the Debt Securities; - The total principal amount of the Debt Securities; - The portion of the principal amount that will be payable if the maturity of the Debt Securities is accelerated; - Any right we may have to defer payments of interest by extending the dates payments are due and whether interest on those deferred amounts will be payable as well; - The dates on which the principal of the Debt Securities will be payable; - The interest rate that the Debt Securities will bear and the interest payment dates for the Debt Securities; - Any conversion or exchange provisions; - Any optional redemption provisions; - Any sinking fund or other provisions that would obligate us to repurchase or otherwise redeem the Debt Securities; - Any Events of Default or covenants; and - Any other terms of the Debt Securities. Provisions Only in the Senior Indenture The senior debt securities will rank equally in right of payment with all of our other senior and unsubordinated debt and senior in right of payment to any of our subordinated debt (including the Subordinated Debt Securities). The senior indenture may contain provisions that: - Limit our ability to put liens on our principal assets; and - Limit our ability to sell and lease back our principal assets. 12 24 The Subordinated Indenture may not contain any similar provisions. We have described below these provisions and some of the defined terms used in them. Provisions Only in the Subordinated Indenture Subordinated Debt Securities Subordinated to Senior Debt The Subordinated Debt Securities will rank junior in right of payment to all of our Senior Debt. "Senior Debt" is defined to include all notes or other evidences of indebtedness, including our guarantees for money we borrowed, not expressed to be subordinate or junior in right of payment to any other of our indebtedness. Payment Blockages The Subordinated Indenture may provide that no payment of principal, interest and any premium on the Subordinated Debt Securities may be made in the event that we fail to pay when due any amounts on any Senior Debt and in other instances specified in the Indenture. No Limitation on Amount of Senior Debt The Subordinated Indenture will not limit the amount of Senior Debt that we may incur. Modification of Indentures Under each Indenture, generally the Trustee and we may modify our rights and obligations and the rights of the holders with the consent of the holders of a specified percentage of the outstanding holders of each series of debt affected by the modification. No modification of the principal or interest payment terms, and no modification reducing the percentage required for modifications, is effective against any holder without its consent. In addition, the Trustee and we may amend the Indentures without the consent of any holder of the Debt Securities to make certain technical changes. Events of Default and Remedies "Event of Default" will be defined in the Indenture. Registration of Notes We may issue Debt Securities of a series in registered, bearer, coupon or global form. No Personal Liability of the General Partners Unless otherwise stated in a prospectus supplement and supplemental indenture relating to a series of Debt Securities being offered, the General Partners and their directors, officers, employees and shareholders will not have any liability for our obligations under the Indentures or the Debt Securities. Each holder of Debt Securities by accepting a Debt Security waives and releases all such liability. The waiver and release are part of the consideration for the issuance of the Debt Securities. Book Entry, Delivery and Form The Debt Securities of a series may be issued in whole or in part in the form of one or more global certificates that will be deposited with a depositary identified in a prospectus supplement. Unless otherwise stated in any prospectus supplement, The Depository Trust Company, New York, New York ("DTC") will act as depositary. Book-entry notes of a series will be issued in the form of a global note that will be deposited with DTC. This means that we will not issue certificates to each holder. One global note will be issued to DTC who will keep a computerized record of its participants (for example, your broker) whose clients have purchased the notes. The participant will then keep a record of its clients who purchased the notes. Unless it is exchanged in whole or in part for a certificate note, a 13 25 global note may not be transferred; except that DTC, its nominees and their successors may transfer a global note as a whole to one another. Beneficial interests in global notes will be shown on, and transfers of global notes will be made only through, records maintained by DTC and its participants. DTC has provided us the following information: DTC is a limited-purpose trust company organized under the New York Banking Law, a "banking organization" within the meaning of the New York Banking Law, a member of the United States Federal Reserve System, a "clearing corporation" within the meaning of the New York Uniform Commercial Code and a "clearing agency" registered under the provisions of Section 17A of the Exchange Act. DTC holds securities that its participants ("Direct Participants") deposit with DTC. DTC also records the settlement among Direct Participants of securities transactions, such as transfers and pledges, in deposited securities through computerized records for Direct Participants' accounts. This eliminates the need to exchange certificates. Direct Participants include securities brokers and dealers, banks, trust companies, clearing corporations and certain other organizations. DTC's book-entry system is also used by other organizations such as securities brokers and dealers, banks and trust companies that work through a Direct Participant. The rules that apply to DTC and its participants are on file with the SEC. DTC is owned by a number of its Direct Participants and by the New York Stock Exchange, Inc., The American Stock Exchange, Inc. and the National Association of Securities Dealers, Inc. We will wire principal and interest payments to DTC's nominee. We and the Trustee will treat DTC's nominee as the owner of the global notes for all purposes. Accordingly, we, the Trustee and any paying agent will have no direct responsibility or liability to pay amounts due on the global notes to owners of beneficial interests in the global notes. It is DTC's current practice, upon receipt of any payment of principal or interest, to credit Direct Participants' accounts on the payment date according to their respective holdings of beneficial interests in the global notes as shown on DTC's records. In addition, it is DTC's current practice to assign any consenting or voting rights to Direct Participants whose accounts are credited with notes on a record date, by using an omnibus proxy. Payments by participants to owners of beneficial interests in the global notes, and voting by participants, will be governed by the customary practices between the participants and owners of beneficial interests, as is the case with notes held for the account of customers registered in "street name." However, payments will be the responsibility of the participants and not of DTC, the Trustee or us. Debt Securities represented by a global note will be exchangeable for certificated notes with the same terms in authorized denominations only if: - DTC notifies us that it is unwilling or unable to continue as depositary or if DTC ceases to be a clearing agency registered under applicable law and a successor depositary is not appointed by us within 90 days; or - We determine not to require all of the Debt Securities of a series to be represented by a global note and notify the Trustee of our decision. The Trustee The Trustee will have duties, responsibilities and rights as specified in the Indenture. 14 26 RATIO OF EARNINGS TO FIXED CHARGES
NINE MONTHS ENDED SEPTEMBER 30, YEAR ENDED DECEMBER 31, PRO FORMA* YEAR ------------- ------------------------- ENDED DECEMBER 31, 1998 1997 1997 1996 1995 1994 1993 ----- ----- ---- ---- ---- ---- ------------------ Ratio of earnings to Fixed Charges.... 3.1 3.2 3.2 3.2 3.1 3.0 2.8 === === === === === === ===
- --------------- * On October 1, 1993, we acquired a 70% general partner interest in Northern Border Pipeline. Prior to that date, we had no financial statements. The Pro Forma column represents the ratio calculated using data of Northern Border Pipeline, our predecessor company under SEC rules, for the nine months ended September 30, 1993, and our data for the three months ended December 31, 1993 with an estimate of our operating expenses for a full year. These computations include us, Northern Border Intermediate Limited Partnership, Northern Border Pipeline Company, and for the period owned, Black Mesa Pipeline, Inc., Black Mesa Holdings, Inc., Black Mesa Pipeline Operations, L.L.C., Williams Technologies, Inc. and WTS Technologies L.L.C. on a consolidated basis. For these ratios, "earnings" is the amount resulting from adding the following items: - Pre-tax income from continuing operations before adjustment for minority interests; and - Fixed charges. The term "fixed charges" means the sum of the following: - Interest expensed and capitalized; - Amortized premiums, discounts and capitalized expenses related to indebtedness; and - An estimate of the interest within rental expenses. USE OF PROCEEDS Unless otherwise indicated to the contrary in an accompanying prospectus supplement, the net proceeds we receive from the sale of newly issued securities will be available for general purposes including repayment of debt, future acquisitions, capital expenditures and working capital. TAX CONSIDERATIONS This section is a summary of certain federal income tax considerations that may be relevant to you and, to the extent set forth below under "Tax Considerations -- Legal Opinions and Advice," represents the opinion of our counsel, Vinson & Elkins L.L.P. ("Counsel"), insofar as it relates to matters of law and legal conclusions. This section is based upon current provisions of the Internal Revenue Code of 1986 (the "Code"), existing and proposed regulations thereunder and current administrative rulings and court decisions, all of which are subject to change. Subsequent changes may cause the tax consequences to vary substantially from the consequences described below. Unless the context otherwise requires, references in this section we make to ourselves are references to both Northern Border Partners, L.P. and the Northern Border Intermediate Limited Partnership. No attempt has been made in the following discussion to comment on all federal income tax matters affecting us or our unitholders. Moreover, the discussion focuses on our unitholders who are individual citizens or residents of the United States and has only limited application to corporations, estates, trusts or non-resident aliens. Accordingly, you should consult, and should depend on, your own tax advisor in analyzing the federal, state, local and foreign tax consequences of the purchase, ownership or disposition of Common Units. 15 27 Legal Opinions and Advice Counsel has expressed its opinion that, based on the representations and subject to the qualifications set forth in the detailed discussion that follows, for federal income tax purposes: - Northern Border Partners, L.P., Northern Border Intermediate Limited Partnership and Northern Border Pipeline each will be treated as a partnership; and - Owners of Common Units (with certain exceptions, as described in "Limited Partner Status" below) will be treated as partners of Northern Border Partners, L.P. (but not Northern Border Intermediate Limited Partnership). In addition, all statements as to matters of law and legal conclusions contained in this section, unless otherwise noted, reflect the opinion of Counsel. Counsel has also advised us that, based on current law, the following general description of the principal federal income tax consequences that should arise from the purchase, ownership and disposition of Common Units, insofar as it relates to matters of law and legal conclusions, addresses all material tax consequences to our unitholders who are individual citizens or residents of the United States. No ruling has been requested from the Internal Revenue Service (the "IRS") with respect to the foregoing issues or any other matter affecting us or our unitholders. An opinion of counsel represents only such counsel's best legal judgment and does not bind the IRS or the courts. Thus, no assurance can be provided that the opinions and statements set forth herein would be sustained by a court if contested by the IRS. The costs of any contest with the IRS will be borne directly or indirectly by our unitholders and the General Partners. Furthermore, no assurance can be given that our treatment or an investment in us will not be significantly modified by future legislative or administrative changes or court decisions. Any such modification may or may not be retroactively applied. Partnership Status A partnership is not a taxable entity and incurs no federal income tax liability. Instead, each partner is required to take into account his allocable share of items of our income, gain, loss, deduction and credit in computing his federal income tax liability, regardless of whether cash distributions are made. Distributions by a partnership to a partner are generally not taxable unless the amount of any cash distributed is in excess of the partner's adjusted basis in his partnership interest. Pursuant to Treasury Regulations 301.7701-1, 301.7702-1 and 301.7701-3, effective January 1, 1997 (the "Check-the-Box Regulations"), an entity in existence on January 1, 1997, will generally retain its current classification for federal income tax purposes. As of January 1, 1997, we and Northern Border Pipeline were each classified and taxed as a partnership. Pursuant to the Check-the-Box Regulations, this prior classification will be respected for all periods prior to January 1, 1997, if: - the entity had a reasonable basis for the claimed classification; - the entity recognized the federal tax consequences of any change in classification within five years prior to January 1, 1997; and - the entity was not notified prior to May 8, 1996 that the entity classification was under examination. Based on these regulations and the applicable federal income tax law, Counsel has opined that we and Northern Border Pipeline each have been and will be classified as a partnership for federal income tax purposes. In rendering its opinion, Counsel has relied on certain factual representations and covenants made by us and the General Partners, including: - Neither we nor Northern Border Pipeline will elect to be treated as an association taxable as a corporation; 16 28 - We have been and will be operated in accordance with all applicable partnership statutes and our Partnership Agreement and in the manner described herein; - Except as otherwise required by Section 704 of the Code and regulations promulgated thereunder, the General Partners have had and will have, in the aggregate, an interest in each material item of our income, gain, loss, deduction or credit equal to at least 1% at all times during our existence; - A representation and covenant of the General Partners that the General Partners have and will maintain, in the aggregate, a minimum capital account balance in us equal to 1% of our total positive capital account balances; - For each taxable year, less than 10% of our gross income has been and will be derived from sources other than (i) the exploration, development, production, processing, refining, transportation or marketing of any mineral or natural resource, including oil, gas or products thereof and naturally occurring carbon dioxide or (ii) other items of "qualifying income" within the meaning of Section 7704(d) of the Code; and - Northern Border Pipeline is organized and will be operated in accordance with the Texas Revised Uniform Partnership Act and the Northern Border Pipeline Partnership Agreement. Counsel's opinion as to our partnership classification in the event of a change in the General Partners is based upon the assumption that the new general partners will satisfy the foregoing representations and covenants. Section 7704 of the Code provides that publicly-traded partnerships will, as a general rule, be taxed as corporations. However, an exception (the "Natural Resource Exception") exists with respect to publicly-traded partnerships 90% or more of the gross income of which for every taxable year consists of "qualifying income." Qualifying income includes income and gains derived from the transportation of natural gas and coal. Other types of qualifying income include interest, dividends, gains from the sale of real property and gains from the sale or other disposition of capital assets held for the production of income that otherwise constitutes qualifying income. We have represented that in excess of 90% of our gross income has been and will be derived from fees and charges for transporting (through the Pipeline System) natural gas. Based upon that representation, Counsel is of the opinion that our gross income derived from these sources constitutes qualifying income. If we fail to meet the Natural Resource Exception (other than a failure determined by the IRS to be inadvertent that is cured within a reasonable time after discovery), we will be treated as if we had transferred all of our assets (subject to liabilities) to a newly-formed corporation (on the first day of the year in which we fail to meet the Natural Resource Exception) in return for stock in such corporation, and then distributed such stock to the partners in liquidation of their interests in us. This contribution and liquidation should be tax-free to our unitholders and us, so long as we, at such time, do not have liabilities in excess of the basis of our assets. Thereafter, we would be treated as a corporation for federal income tax purposes. If we were treated as an association or otherwise taxable as a corporation in any taxable year, as a result of a failure to meet the Natural Resource Exception or otherwise, our items of income, gain, loss, deduction and credit would be reflected only on our tax return rather than being passed through to our unitholders, and our net income would be taxed at the entity level at corporate rates. In addition, any distribution made to a unitholder would be treated as either taxable dividend income (to the extent of our current or accumulated earnings and profits), in the absence of earnings and profits as a nontaxable return of capital (to the extent of the unitholder's basis in his Common Units) or taxable capital gain (after the unitholder's basis in the Common Units is reduced to zero). Accordingly, our treatment as an association taxable as a corporation would result in a material reduction in a unitholder's cash flow and after-tax return. The discussion below is based on the assumption that we will be classified as a partnership for federal income tax purposes. 17 29 Limited Partner Status Our unitholders who have become limited partners will be treated as partners for federal income tax purposes. Moreover, the IRS has ruled that assignees of partnership interests who have not been admitted to a partnership as partners, but who have the capacity to exercise substantial dominion and control over the assigned partnership interests, will be treated as partners for federal income tax purposes. On the basis of this ruling, except as otherwise described herein, Counsel is of the opinion that (a) assignees who have executed and delivered Transfer Applications and are awaiting admission as limited partners and (b) our unitholders whose Common Units are held in street name or by another nominee and who have the right to direct the nominee in the exercise of all substantive rights attendant to the ownership of their Common Units will be treated as partners for federal income tax purposes. As this ruling does not extend, on its facts, to assignees of Common Units who are entitled to execute and deliver Transfer Applications and thereby become entitled to direct the exercise of attendant rights, but who fail to execute and deliver Transfer Applications, Counsel's opinion does not extend to these persons. Income, gain, deductions, losses or credits would not appear to be reportable by such a unitholder, and any cash distributions received by such a unitholder would therefore be fully taxable as ordinary income. These holders should consult their own tax advisors with respect to their status as partners for federal income tax purposes. A purchaser or other transferee of Common Units who does not execute and deliver a Transfer Application may not receive certain federal income tax information or reports furnished to record holders of Common Units unless the Common Units are held in a nominee or street name account and the nominee or broker has executed and delivered a Transfer Application with respect to such Common Units. A beneficial owner of Common Units whose Common Units have been transferred to a short seller to complete a short sale would appear to lose his status as a partner with respect to such Common Units for federal income tax purposes. See "Tax Considerations -- Tax Treatment of Operations -- Treatment of Short Sales." Tax Consequences of Common Unit Ownership Flow-Through of Taxable Income We will pay no federal income tax. Instead, each unitholder will be required to report on his income tax return his allocable share of our income, gains, losses and deductions without regard to whether corresponding cash distributions are received by such unitholder. Consequently, we may allocate income to a unitholder although he has not received a cash distribution in respect of such income. Treatment of Partnership Distributions Our distributions to a unitholder generally will not be taxable to the unitholder for federal income tax purposes to the extent of his basis in his Common Units immediately before the distribution. Cash distributions in excess of a Common Unitholder's basis generally will be considered to be gain from the sale or exchange of the Common Units, taxable in accordance with the rules described under "Tax Considerations -- Disposition of Common Units." Any reduction in a Common Unitholder's share of our liabilities for which no partner, including the General Partners, bears the economic risk of loss ("nonrecourse liabilities") will be treated as a distribution of cash to such unitholder. Basis of Common Units A unitholder's initial tax basis for his Common Units will be the amount paid for the Common Units plus his share of our nonrecourse liabilities. The initial tax basis for a Common Unit will be increased by the unitholder's share of our income and by any increase in the unitholder's share of our nonrecourse liabilities. The basis for a Common Unit will be decreased (but not below zero) by our distributions, including any decrease in the unitholder's share of our nonrecourse liabilities, by the unitholder's share of our losses and by the unitholder's share of our expenditures that are not deductible in computing his taxable income and are not required to be capitalized. A unitholder's share of our nonrecourse liabilities will be generally based on the unitholder's share of our profits. 18 30 Limitations on Deductibility of Our Losses To the extent we incur losses, a unitholder's share of deductions for the losses will be limited to the tax basis of the unitholder's Common Units or, in the case of an individual unitholder or a corporate unitholder if more than 50% of the value of his stock is owned directly or indirectly by five or fewer individuals or certain tax-exempt organizations, to the amount that the unitholder is considered to be "at risk" with respect to our activities, if that is less than the unitholder's basis. A unitholder must recapture losses deducted in previous years to the extent that our distributions cause the unitholder's at risk amount to be less than zero at the end of any taxable year. Losses disallowed to a unitholder or recaptured as a result of these limitations will carry forward and will be allowable to the extent that the unitholder's basis or at risk amount (whichever is the limiting factor) is increased. In general, a unitholder will be at risk to the extent of the purchase price of his Common Units, but this will be less than the unitholder's basis for his Common Units by the amount of the unitholder's share of any of our nonrecourse liabilities. A unitholder's at risk amount will increase or decrease as the basis of the unitholder's Common Units increases or decreases except that changes in our nonrecourse liabilities will not increase or decrease the at risk amount. The passive loss limitations generally provide that individuals, estates, trusts and certain closely held corporations and personal service corporations can deduct only losses from passive activities (generally, activities in which the taxpayer does not materially participate) that are not in excess of the taxpayer's income from such passive activities or investments. The passive loss limitations are to be applied separately with respect to each publicly-traded partnership. Consequently, the losses generated by us, if any, will be available only to offset future income that we generate and will not be available to offset income from other passive activities or investments (including other publicly-traded partnerships) or salary or active business income. Passive losses that are not deductible because they exceed the unitholder's income that we generate may be deducted in full when the unitholder disposes of his entire investment in a fully taxable transaction to an unrelated party. The passive activity loss rules are applied after other applicable limitations on deductions such as the at risk rules and the basis limitation. A unitholder's share of our net income may be offset by any of our suspended passive losses, but it may not be offset by any other current or carryover losses from other passive activities, including those attributable to other publicly-traded partnerships. The IRS has announced that Treasury Regulations will be issued that characterize net passive income from a publicly-traded partnership as investment income for purposes of the limitations on the deductibility of investment interest. Limitations on Interest Deductions The deductibility of a non-corporate taxpayer's "investment interest expense" is generally limited to the amount of such taxpayer's "net investment income." As noted, the net passive income a unitholder receives from us will be treated as investment income for this purpose. In addition, the unitholder's share of our portfolio income will be treated as investment income. Investment interest expense includes: - Interest on indebtedness properly allocable to property held for investment; - A partnership's interest expense attributed to portfolio income; and - The portion of interest expense incurred to purchase or carry an interest in a passive activity to the extent attributable to portfolio income. The computation of a unitholder's investment interest expense will take into account interest on any margin account borrowing or other loan incurred to purchase or carry a Common Unit to the extent attributable to his portfolio income. Net investment income includes gross income from property held for investment, gain attributable to the disposition of property held for investment and amounts treated as portfolio income pursuant to the passive loss rules less deductible expenses (other than interest) directly connected with the production of investment income. 19 31 Allocation of Our Income, Gain, Loss and Deduction Our Partnership Agreement provides that a capital account be maintained for each partner, that the capital accounts generally be maintained in accordance with the applicable tax accounting principles set forth in applicable Treasury Regulations and that all allocations to a partner be reflected by an appropriate increase or decrease in his capital account. Distributions upon our liquidation are generally to be made in accordance with positive capital account balances. In general, if we have a net profit, items of income, gain, loss and deduction will be allocated among the General Partners and our unitholders in accordance with their respective percentage interests in us. A class of our unitholders that receives more cash than another class, on a per unit basis, with respect to a year, will be allocated additional income equal to that excess. If we have a net loss, items of income, gain, loss and deduction will generally be allocated for both book and tax purposes (1) first, to the General Partners and our unitholders in accordance with their respective percentage interests to the extent of their positive capital accounts and (2) second, to the General Partners. Notwithstanding the above, as required by Section 704(c) of the Code, certain items of our income, deduction, gain and loss will be specially allocated to account for the difference between the tax basis and fair market value of property contributed to us ("Contributed Property"). In addition, certain items of recapture income will be allocated to the extent possible to the partner allocated the deduction giving rise to the treatment of such gain as recapture income in order to minimize the recognition of ordinary income by some of our unitholders, but these allocations may not be respected by the IRS or the courts. If these allocations of recapture income are not respected, the amount of the income or gain allocated to a unitholder will not change, but instead a change in the character of the income allocated to a unitholder would result. Finally, although we do not expect that our operations will result in the creation of negative capital accounts, if negative capital accounts nevertheless result, items of our income and gain will be allocated in an amount and manner sufficient to eliminate the negative balance as quickly as possible. Regulations provide that an allocation of items of our income, gain, loss, deduction or credit, other than an allocation required by Section 704(c) of the Code to eliminate the disparity between a partner's "book" capital account (credited with the fair market value of Contributed Property) and "tax" capital account (credited with the tax basis of Contributed Property) (the "Book-Tax Disparity"), will generally be given effect for federal income tax purposes in determining a partner's distributive share of an item of income, gain, loss or deduction only if the allocation has substantial economic effect. In any other case, a partner's distributive share of an item will be determined on the basis of the partner's interest in us, which will be determined by taking into account all the facts and circumstances, including the partner's relative contributions to us, the interests of the partners in economic profits and losses, the interests of the partners in cash flow and other non-liquidating distributions and rights of the partners to distributions of capital upon liquidation. Under the Code, the partners in a partnership cannot be allocated more depreciation, gain or loss than the total amount of any such item recognized by that partnership in a particular taxable period. This rule, often referred to as the "ceiling limitation," is not expected to have significant application to allocations with respect to Contributed Property and thus, is not expected to prevent our unitholders from receiving allocations of depreciation, gain or loss from such properties equal to that which they would have received had such properties actually had a basis equal to fair market value at the outset. However, to the extent the ceiling limitation is or becomes applicable, our Partnership Agreement requires that certain items of income and deduction be allocated in a way designed to effectively "cure" this problem and eliminate the impact of the ceiling limitations. Such allocations will not have substantial economic effect because they will not be reflected in the capital accounts of our unitholders. The legislative history of Section 704(c) states that Congress anticipated that Treasury Regulations would permit partners to agree to a more rapid elimination of Book-Tax Disparities than required provided there is no tax avoidance potential. Further, under recently enacted final Treasury Regulations under Section 704(c), allocations similar to the curative allocations would be allowed. However, since the final 20 32 Treasury Regulations are not applicable to us, Counsel is unable to opine on the validity of the curative allocations. Counsel is of the opinion that, with the exception of curative allocations and the allocation of recapture income discussed above, allocations under our Partnership Agreement will be given effect for federal income tax purposes in determining a partner's distributive share of an item of income, gain, loss or deduction. There are, however, uncertainties in the Treasury Regulations relating to allocations of partnership income, and investors should be aware that some of the allocations in our Partnership Agreement may be successfully challenged by the IRS. Tax Treatment of Our Operations Accounting Method and Taxable Year We use the calendar year as our taxable year and adopt the accrual method of accounting for federal income tax purposes. Initial Tax Basis, Depreciation and Amortization The tax basis established for our various assets will be used for purposes of computing depreciation and cost recovery deductions and, ultimately, gain or loss on the disposition of such assets. Our assets initially had an aggregate tax basis equal to the sum of each unitholder's tax basis in his Common Units or Subordinated Units (which were converted into Common Units on January 19, 1999) and the tax basis of the General Partners in their respective general partner interests. We allocated the aggregate tax basis among our assets based upon their relative fair market values. Any amount in excess of the fair market values of specific tangible and intangible assets will constitute goodwill, which is subject to amortization over 15 years. The IRS may (i) challenge either the fair market values or the useful lives assigned to such assets or (ii) seek to characterize intangible assets as goodwill. If any such challenge or characterization were successful, the deductions allocated to a Common Unitholder in respect of such assets would be reduced, and a unitholder's share of taxable income received from us would be increased accordingly. Any such increase could be material. To the extent allowable, the General Partners may elect to use the depreciation and cost recovery methods that will result in the largest depreciation deductions in our early years. Property that we subsequently acquire or construct may be depreciated using accelerated methods permitted by the Code. If we dispose of depreciable property by sale, foreclosure, or otherwise, all or a portion of any gain (determined by reference to the amount of depreciation previously deducted and the nature of the property) may be subject to the recapture rules and taxed as ordinary income rather than capital gain. Similarly, a partner who has taken cost recovery or depreciation deductions with respect to property owned by us may be required to recapture such deductions upon a sale of his interest. See "Tax Considerations -- Allocation of Our Income, Gain, Loss and Deduction" and "Tax Considerations -- Disposition of Common Units -- Recognition of Gain or Loss." Costs we incurred in organizing may be amortized over any period we select not shorter than 60 months. The costs incurred in promoting the issuance of units must be capitalized and cannot be deducted currently, ratably or upon our termination. There are uncertainties regarding the classification of costs as organization expenses, that may be amortized, and as syndication expenses which may not be amortized. Section 754 Election We previously made the election permitted by Section 754 of the Code. This election is irrevocable without the consent of the IRS. The election generally permits a purchaser of Common Units to adjust his share of the basis in our properties ("inside basis") pursuant to Section 743(b) of the Code to fair market 21 33 value (as reflected by his Common Unit price). See "Tax Considerations -- Allocation of Our Income, Gain, Loss and Deduction." The Section 743(b) adjustment is attributed solely to a purchaser of units and is not added to the basis of our assets associated with all of our unitholders. (For purposes of this discussion, a partner's inside basis in our assets will be considered to have two components: (1) his share of our actual basis in such assets (the "Common Basis"); and (2) his Section 743(b) adjustment allocated to each such asset.) Proposed Treasury Regulation Section 1.168-2(n) generally requires the Section 743(b) adjustment attributable to recovery property to be depreciated as if the total amount of such adjustment were attributable to newly-acquired recovery property placed in service when the transfer occurs. Similarly, the proposed Treasury Regulation Section 1.197-2(g)(3) generally requires that the 743(b) adjustment attributable to amortizable intangible assets under Section 197 should be treated as a newly-acquired asset placed in service in the month when the transfer occurs. Under Treasury Regulation Section 1.167(c)-1(a)(6), a Section 743(b) adjustment attributable to property subject to depreciation under Section 167 of the Code rather than cost recovery deductions under Section 168 is generally required to be depreciated using either the straight-line method or the 150% declining balance method. We intend to utilize the 150% declining balance method on such property. The depreciation method and useful lives associated with the Section 743(b) adjustment, therefore, may differ from the method and useful lives generally used to depreciate the Common Basis in such properties. Pursuant to our Partnership Agreement, the General Partners are authorized to adopt a convention to preserve the uniformity of Common Units even if such convention is not consistent with Treasury Regulation Section 1.167(c)-1(a)(6), Proposed Treasury Regulation Sections 1.168-2(n) or 1.197-2(g)(3). See "Tax Considerations -- Uniformity of Common Units." Although Counsel is unable to opine as to the validity of such an approach, we intend to depreciate the portion of a Section 743(b) adjustment attributable to unrealized appreciation in the value of Contributed Property (to the extent of any unamortized Book-Tax Disparity) using a rate of depreciation or amortization derived from the depreciation or amortization method and useful life applied to the Common Basis of such property, despite its inconsistency with proposed Treasury Regulation Section 1.168-2(n), Treasury Regulation Section 1.167(c)-1(a)(6) or Proposed Treasury Regulation Section 1.197-2(g)(3). If we determine that such position cannot reasonably be taken, we may adopt a depreciation or amortization convention under which all purchasers acquiring Common Units in the same month would receive depreciation or amortization, whether attributable to the Common Basis or the Section 743(b) basis, based upon the same applicable rate as if they had purchased a direct interest in our property. Such an aggregate approach may result in lower annual depreciation or amortization deductions than would otherwise be allowable to certain of our unitholders. See "Tax Considerations -- Uniformity of Common Units." The allocation of the Section 743(b) adjustment must be made in accordance with the principles of Section 1060 of the Code. Based on these principles, the IRS may seek to reallocate some or all of any Section 743(b) adjustment not so allocated by us to goodwill. Alternatively, it is possible that the IRS may seek to treat the portion of such Section 743(b) adjustment attributable to the Underwriter's discount as if allocable to a non-deductible syndication cost. A Section 754 election is advantageous if the transferee's basis in his Common Units is higher than such Common Units' share of the aggregate basis of our assets immediately prior to the transfer. In such case, pursuant to the election, the transferee would take a new and higher basis in his share of our assets for purposes of calculating, among other items, his depreciation deductions and his share of any gain or loss on a sale of our assets. Conversely, a Section 754 election is disadvantageous if the transferee's basis in such Common Units is lower than such Common Units' share of the aggregate basis of our assets immediately prior to the transfer. Thus, the amount that a unitholder will be able to obtain upon the sale of his Common Units may be affected either favorably or adversely by the election. The calculations involved in the Section 754 election are complex and we will make them on the basis of certain assumptions as to the value of our assets and other matters. There is no assurance that the 22 34 determinations we make will not be successfully challenged by the IRS and that the deductions attributable to them will not be disallowed or reduced. Should the IRS require a different basis adjustment to be made, and should, in the General Partners' opinion, the expense of compliance exceed the benefit of the election, the General Partners may seek permission from the IRS to revoke our Section 754 election. If such permission is granted, a purchaser of Common Units subsequent to such revocation probably will incur increased tax liability. Alternative Minimum Tax Each unitholder will be required to take into account his distributive share of any items of our income, gain or loss for purposes of the alternative minimum tax. A portion of our depreciation deductions may be treated as an item of tax preference for this purpose. A unitholder's alternative minimum taxable income derived from us may be higher than his share of our net income because we may use more accelerated methods of depreciation for purposes of computing federal taxable income or loss. The minimum tax rate for individuals is 26% on the first $175,000 of alternative minimum taxable income in excess of the exemption amount and to 28% on any additional alternative minimum taxable income. You should consult with your tax advisors as to the impact of an investment in Common Units on your liability under the alternative minimum tax. Valuation of Our Property The federal income tax consequences of the acquisition, ownership and disposition of Common Units will depend in part on our estimates of the relative fair market values, and determinations of the initial tax basis, of our assets. Although we may from time to time consult with professional appraisers with respect to valuation matters, many of the relative fair market value estimates will be made solely by us. These estimates are subject to challenge and will not be binding on the IRS or the courts. In the event the determinations of fair market value are subsequently found to be incorrect, the character and amount of items of income, gain, loss, deductions or credits previously reported by our unitholders might change, and our unitholders might be required to amend their previously filed tax returns or to file claims for refunds. Treatment of Short Sales A unitholder who engages in a short sale (or a transaction having the same effect) with respect to Common Units will be required to recognize the gain (but not the loss) inherent in such Common Units. See "Tax Considerations -- Disposition of Common Units." In addition, it would appear that a unitholder whose Common Units are loaned to a "short seller" to cover a short sale of Common Units would be considered as having transferred beneficial ownership of those Common Units and would, thus, no longer be a partner with respect to those Common Units during the period of the loan. As a result, during this period, any of our income, gain, deduction, loss or credit with respect to those Common Units would appear not to be reportable by the unitholder, any cash distributions received by the unitholder with respect to those Common Units would be fully taxable and all of such distributions would appear to be treated as ordinary income. The IRS may also contend that a loan of Common Units to a "short seller" constitutes a taxable exchange. If the IRS successfully made this contention, the lending unitholder may be required to recognize gain or loss. Unitholders desiring to assure their status as partners should modify their brokerage account agreements, if any, to prohibit their brokers from borrowing their Common Units. Disposition of Common Units Recognition of Gain or Loss Gain or loss will be recognized on a sale of Common Units equal to the difference between the amount realized and the unitholder's tax basis for the Common Units sold. A unitholder's amount realized will be measured by the sum of the cash or the fair market value of other property received plus his share of our nonrecourse liabilities. Since the amount realized includes a unitholder's share of our nonrecourse 23 35 liabilities, the gain recognized on the sale of Common Units may result in a tax liability in excess of any cash received from such sale. Gain or loss recognized by a unitholder (other than a "dealer" in Common Units) on the sale or exchange of a Common Unit held for more than twelve months will generally be taxable as long-term capital gain or loss. A substantial portion of this gain or loss, however, will be separately computed and taxed as ordinary income or loss under section 751 of the Code to the extent attributable to assets giving rise to depreciation recapture or other "unrealized receivables" or to inventory we owned. The term "unrealized receivables" includes potential recapture items, including depreciation recapture. Ordinary income attributable to unrealized receivables, inventory and deprecation recapture may exceed net taxable gain realized upon the sale of the Common Unit and may be recognized even if there is a net taxable gain realized upon the sale of the Common Unit. Any loss recognized on the sale of Common Units will generally be a capital loss. Thus, a unitholder may recognize both ordinary income and a capital loss upon a disposition of Common Units. Net capital loss may offset no more than $3,000 of ordinary income in the case of individuals and may only be used to offset capital gain in the case of a corporation. The IRS has ruled that a partner acquiring interests in a partnership in separate transactions at different prices must maintain an aggregate adjusted tax basis in a single partnership interest and that, upon sale or other disposition of some of the interests, a portion of such aggregate tax basis must be allocated to the interests sold on the basis of some equitable apportionment method. This ruling is unclear as to how the holding period is affected by this aggregation concept. If this ruling is applicable to you, the aggregation of your tax basis effectively prohibits you from choosing among Common Units with varying amounts of unrealized gain or loss as would be possible in a stock transaction. Thus, the ruling may result in an acceleration of gain or deferral of loss on a sale of a portion of your Common Units. It is not clear whether the ruling applies to publicly-traded partnerships, such as us, the interests in which are evidenced by separate interests, and accordingly Counsel is unable to opine as to the effect such ruling will have on you. If you are considering the purchase of additional Common Units or a sale of Common Units purchased at differing prices, you should consult your tax advisor as to the possible consequences of such ruling. Allocations Between Transferors and Transferees In general, our taxable income and losses will be determined annually and will be prorated on a monthly basis and subsequently apportioned among our unitholders in proportion to the number of Common Units they owned as of the close of business on the last day of the preceding month. However, gain or loss realized on a sale or other disposition of our assets other than in the ordinary course of business shall be allocated among our unitholders of record as of the opening of the New York Stock Exchange on the first business day of the month in which such gain or loss is recognized. As a result of this monthly allocation, a unitholder transferring Common Units in the open market may be allocated income, gain, loss, deduction, and credit accrued after the transfer. The use of the monthly conventions discussed above may not be permitted by existing Treasury Regulations and, accordingly, Counsel is unable to opine on the validity of the method of allocating income and deductions between the transferors and the transferees of Common Units. If a monthly convention is not allowed by the Treasury Regulations (or only applies to transfers of less than all of a unitholder's interest), our taxable income or losses might be reallocated among our unitholders. We are authorized to revise our method of allocation between transferors and transferees (as well as among partners whose interests otherwise vary during a taxable period) to conform to a method permitted by future Treasury Regulations. A unitholder who owns Common Units at any time during a quarter and who disposes of such Common Units prior to the record date set for a distribution with respect to such quarter will be allocated items of our income and gain attributable to such quarter during which such Common Units were owned but will not be entitled to receive such cash distribution. 24 36 Notification Requirements A unitholder who sells or exchanges Common Units is required to notify us in writing of such sale or exchange within 30 days of the sale or exchange and, in any event, no later than January 15 of the year following the calendar year that the sale or exchange occurred. We are required to notify the IRS of such transaction and to furnish certain information to the transferor and transferee. However, these reporting requirements do not apply with respect to a sale by an individual who is a citizen of the United States and who effects such sale through a broker. Additionally, a transferor and a transferee of a Common Unit will be required to furnish statements to the IRS, filed with their income tax returns for the taxable year in which the sale or exchange occurred, that set forth the amount of the consideration received for such Common Unit that is allocated to our goodwill or going concern value. Failure to satisfy such reporting obligations may lead to the imposition of substantial penalties. Constructive Termination Both we and Northern Border Intermediate Limited Partnership will be considered to be terminated if there is a sale or exchange of 50% or more of the total interests in partnership capital and profits within a 12-month period. A constructive termination results in the closing of a partnership's taxable year for all partners. Such a termination could result in the non-uniformity of Common Units for federal income tax purposes. Our constructive termination will cause a termination of Northern Border Intermediate Limited Partnership. Such a termination could also result in penalties or loss of basis adjustments under Section 754 of the Code if we were unable to determine that the termination had occurred. In the case of a unitholder reporting on a fiscal year other than a calendar year, the closing of our tax year may result in more than 12 months of our taxable income or loss being includable in our taxable income for the year of termination. In addition, each unitholder will realize taxable gain to the extent that any money constructively distributed to him (including any net reduction in his share of partnership nonrecourse liabilities) exceeds the adjusted basis on his Common Units. New tax elections we are required to make, including a new election under Section 754 of the Code, must be made subsequent to the constructive termination. A constructive termination would also result in a deferral of our deductions for depreciation. In addition, a termination might either accelerate the application of or subject us to any tax legislation enacted with effective dates after the closing of the offering made hereby. Entity-Level Collections If we are required under applicable law to pay any federal, state or local income tax on behalf of any unitholder, any General Partner or any former unitholder, our Partnership Policy Committee is authorized to pay such taxes from our funds. Such payments, if made, will be deemed current distributions of cash to our unitholders and the General Partners. The General Partners are authorized to amend our Partnership Agreement in the manner necessary to maintain uniformity of intrinsic tax characteristics of Common Units and to adjust subsequent distributions so that after giving effect to such deemed distributions, the priority and characterization of distributions otherwise applicable under our Partnership Agreement is maintained as nearly as is practicable. Such payments could give rise to an overpayment of tax on behalf of an individual partner in which event the partner could file a claim for credit or refund. Uniformity of Common Units Since we cannot match transferors and transferees of Common Units, uniformity of the economic and tax characteristics of the Common Units to a purchaser of such Common Units must be maintained. In the absence of uniformity, compliance with a number of federal income tax requirements, both statutory and regulatory, could be substantially diminished. A lack of uniformity can result from a literal application of Proposed Treasury Regulation Section 1.168-2(n) and Treasury Regulation Section 1.167(c)-1(a)(6) or Proposed Treasury Regulation Section 1.197-2(g)(3) and from the application of the "ceiling limitation" on our ability to make allocations to eliminate Book-Tax Disparities attributable to Contributed Properties and our property that has been revalued and reflected in the partners' capital accounts 25 37 ("Adjusted Properties"). Any such non-uniformity could have a negative impact on the value of a unitholder's interest in us. We intend to depreciate the portion of a Section 743(b) adjustment attributable to unrealized appreciation in the value of Contributed Property or Adjusted Property (to the extent of any unamortized Book-Tax Disparity) using the rate of depreciation derived from the depreciation method and useful life applied to the Common Basis of such property, despite its inconsistency with Proposed Treasury Regulation Section 1.168-2(n) and Treasury Regulation Section 1.167(c)-1(a)(6) or Proposed Treasury Regulation Section 1.197-2(g)(3). See "Tax Considerations -- Tax Treatment of Operations -- Section 754 Election." If we determine that such a position cannot reasonably be taken, we may adopt depreciation and amortization conventions under which all purchasers acquiring Common Units in the same month would receive depreciation and amortization deductions, whether attributable to the Common Basis or the Section 743(b) basis, based upon the same applicable rate as if they had purchased a direct interest in our property. If such an aggregate approach is adopted, it may result in lower annual depreciation and amortization deductions than would otherwise be allowable to certain of our unitholders and risk the loss of depreciation and amortization deductions not taken in the year that such deductions are otherwise allowable. We will not adopt this convention if we determine that the loss of depreciation and amortization deductions will have a material adverse effect on our unitholders. If we choose not to utilize this aggregate method, we may use any other reasonable depreciation and amortization convention to preserve the uniformity of the intrinsic tax characteristics of any Common Units that would not have a material adverse effect on our unitholders. The IRS may challenge any method of depreciating or amortizing the Section 743(b) adjustment described in this paragraph. If such a challenge was sustained, the uniformity of Common Units might be affected. Items of income and deduction will be specially allocated in a manner that is intended to preserve the uniformity of intrinsic tax characteristics among all Common Units, despite the application of the "ceiling limitation" to Contributed Properties and Adjusted Properties. Such special allocations will be made solely for federal income tax purposes. See "Tax Considerations-Tax Consequences of Common Unit Ownership" and "Tax Considerations-Allocation of Our Income, Gain, Loss and Deduction." Tax-Exempt Organizations and Certain Other Investors Ownership of Common Units by employee benefit plans, other tax-exempt organizations, non-resident aliens, foreign corporations, other foreign persons and regulated investment companies raises issues unique to such persons and, as described below, may have substantially adverse tax consequences. Employee benefit plans and most other organizations exempt from federal income tax (including individual retirement accounts and other retirement plans) are subject to federal income tax on unrelated business taxable income. Virtually all of the taxable income derived by such an organization from the ownership of a Common Unit will be unrelated business taxable income, and thus will be taxable to such a unitholder. Regulated investment companies are required to derive 90% or more of their gross income from interest, dividends, gains from the sale of stocks or securities or foreign currency or certain related sources. It is not anticipated that any significant amount of our gross income will qualify as such income. Non-resident aliens and foreign corporations, trusts or estates that acquire Common Units will be considered to be engaged in business in the United States on account of their ownership of Common Units, and as a consequence they will be required to file federal tax returns in respect of their distributive shares of our income, gain, loss deduction or credit and pay federal income tax at regular rates on such income. Generally, a partnership is required to pay a withholding tax on the portion of the Partnership's income that is effectively connected with the conduct of a United States trade or business and which is allocable to the foreign partners, regardless of whether any actual distributions have been made to such partners. However, under rules applicable to publicly-traded partnerships, we will withhold at the rate of 39.6% on actual cash distributions made quarterly to foreign unitholders. Each foreign unitholder must obtain a taxpayer identification number from the IRS and submit that number to our Transfer Agent on a 26 38 Form W-8 in order to obtain credit for the taxes withheld. Subsequent adoption of Treasury Regulations or the issuance of other administrative pronouncements may require us to change these procedures. Because a foreign corporation that owns Common Units will be treated as engaged in a United States trade or business, such a unitholder may be subject to United States branch profits tax at a rate of 30%, in addition to regular federal income tax, on its allocable share of our earnings and profits (as adjusted for changes in the foreign corporation's "U.S. net equity") that are effectively connected with the conduct of a United States trade or business. Such a tax may be reduced or eliminated by an income tax treaty between the United States and the country with respect to which the foreign corporate unitholder is a "qualified resident." Assuming that the Common Units are regularly traded on an established securities market, a foreign unitholder who sells or otherwise disposes of a Common Unit and who has not held more than 5% in value of the Common Units at any time during the five-year period ending on the date of the disposition will not be subject to federal income tax on gain realized on the disposition that is attributable to real property held by us, but (regardless of a foreign unitholder's percentage interest in us or whether Common Units are regularly traded) such unitholder may be subject to federal income tax on any gain realized on the disposition that is treated as effectively connected with a United States trade or business of the foreign unitholder. A foreign unitholder will be subject to federal income tax on gain attributable to real property held by us if the holder held more than 5% in value of the Common Units during the five-year period ending on the date of the disposition or if the Common Units were not regularly traded on an established securities market at the time of the disposition. Administrative Matters Our Information Returns and Audit Procedures We intend to furnish to each of our unitholders within 90 days after the close of each taxable year, certain tax information, including a Schedule K-1, that sets forth each of our unitholders' allocable shares of our income, gain, loss, deduction and credit. In preparing this information that will generally not be reviewed by Counsel, we will use various accounting and reporting conventions, some of which have been mentioned in the previous discussion, to determine the respective unitholders' allocable share of income, gain, loss, deduction and credits. There is no assurance that any such conventions will yield a result that conforms to the requirements of the Code, regulations or administrative interpretations of the IRS. We cannot assure prospective unitholders that the IRS will not successfully contend in court that such accounting and reporting conventions are impermissible. The federal income tax information returns we filed may be audited by the IRS. Adjustments resulting from any such audit may require some or all of our unitholders to file amended tax returns, and possibly may result in an audit of such unitholders' own returns. Any audit of a unitholder's return could result in adjustments of non-partnership as well as partnership items. Partnerships generally are treated as separate entities for purposes of federal tax audits, judicial review of administrative adjustments by the IRS and tax settlement proceedings. The tax treatment of partnership items of income, gain, loss, deduction and credit are determined at the partnership level in a unified partnership proceeding rather than in separate proceedings with the partners. The Code provides for one partner to be designated as the "Tax Matters Partner" for these purposes. Our Partnership Agreement appoints Northern Plains as the Tax Matters Partner. The Tax Matters Partner will make certain elections on our behalf and our unitholders' behalf and can extend the statute of limitations for assessment of tax deficiencies against our unitholders with respect to our items. The Tax Matters Partner may bind a unitholder with less than a 1% profits interest in us to a settlement with the IRS unless such unitholder elects, by filing a statement with the IRS, not to give such authority to the Tax Matters Partner. The Tax Matters Partner may seek judicial review (to which all of our unitholders are bound) of a final partnership administrative adjustment and, if the Tax Matters Partner fails to seek judicial review, such review may be sought by any of our unitholders having at least 1% 27 39 interest in our profits and by our unitholders having in the aggregate at least a 5% profits interest. However, only one action for judicial review will go forward, and each unitholder with an interest in the outcome may participate. A unitholder must file a statement with the IRS identifying the treatment of any item on his federal income tax return that is not consistent with the treatment of the item on our return to avoid the requirement that all items be treated consistently on both returns. Intentional or negligent disregard of the consistency requirement may subject a unitholder to substantial penalties. Nominee Reporting Each person who holds an interest in us as a nominee for another person is required to furnish to us: - The name, address and taxpayer identification number of the beneficial owner and the nominee; - Whether the beneficial owner is (i) a person that is not a United States person, (ii) a foreign government, an international organization or any wholly-owned agency or instrumentality of either of the foregoing or (iii) a tax-exempt entity; - The amount and description of Common Units held, acquired or transferred for the beneficial owner; and - Certain information including the dates of acquisitions and transfers, means of acquisitions and transfers and acquisition cost for purchases, as well as the amount of net proceeds from sales. Brokers and financial institutions are required to furnish additional information, including whether they are United States persons and certain information on Common Units they acquire, hold or transfer for their own account. A penalty of $50 per failure (up to a maximum of $100,000 per calendar year) is imposed by the Code for failure to report such information to us. The nominee is required to supply the beneficial owner of the Common Units with the information furnished to us. Registration as a Tax Shelter The Code requires that "tax shelters" be registered with the Secretary of the Treasury. The temporary Treasury Regulations interpreting the tax shelter registration provisions of the Code are extremely broad. It is arguable that we are not subject to the registration requirement on the basis that (i) we do not constitute a tax shelter or (ii) we constitute a projected income investment exempt from registration. However, we have registered as a tax shelter with the IRS because of the absence of assurance that we will not be subject to tax shelter registration and in light of the substantial penalties that might be imposed if registration is required and not undertaken. ISSUANCE OF THE REGISTRATION NUMBER DOES NOT INDICATE THAT AN INVESTMENT IN US OR THE CLAIMED TAX BENEFITS HAVE BEEN REVIEWED, EXAMINED OR APPROVED BY THE IRS. Our tax shelter registration number is 93271000031. A unitholder who sells or otherwise transfers a Common Unit in a subsequent transaction must furnish the registration number to the transferee. The penalty for failure of the transferor of a Common Unit to furnish such registration number to the transferee is $100 for each such failure. The unitholders must disclose our tax shelter registration number on Form 8271 to be attached to the tax return on which any deduction, loss, credit or other benefit we generate is claimed or income received from us is included. A unitholder who fails to disclose the tax shelter registration number on his return, without reasonable cause for such failure, will be subject to a $50 penalty for each such failure. Any penalties discussed herein are not deductible for federal income tax purposes. Accuracy-Related Penalties An additional tax equal to 20% of the amount of any portion of an underpayment of tax that is attributable to one or more of certain listed causes, including substantial understatements of income tax and substantial valuation misstatements, is imposed by the Code. No penalty will be imposed, however, 28 40 with respect to any portion of an underpayment if it is shown that there was a reasonable cause for such portion and that the taxpayer acted in good faith with respect to such portion. A substantial understatement of income tax in any taxable year exists if the amount of the understatement exceeds the greater of 10% of the tax required to be shown on the return for the taxable year or $5,000 ($10,000 for most corporations). The amount of any understatement subject to penalty generally is reduced if any portion is attributable to a position adopted on the return (i) with respect to which there is, or was, "substantial authority" or (ii) as to which there is a reasonable basis and the pertinent facts of such position are disclosed on the return. Certain more stringent rules apply to "tax shelters," a term that does not appear to include us. If any item of our income, gain, loss, deduction or credit included in the distributive shares of our unitholders might result in such an "understatement" of income for which no substantial authority exists, we must disclose the pertinent facts on our return. In addition, we will make a reasonable effort to furnish sufficient information for our unitholders to make adequate disclosure on their returns to avoid liability for this penalty. A substantial valuation misstatement exists if the value of any property (or the adjusted basis of any property) claimed on a tax return is 200% or more of the amount determined to be the correct amount of such valuation or adjusted basis. No penalty is imposed unless the portion of the underpayment attributable to a substantial valuation misstatement exceeds $5,000 ($10,000 for most corporations). If the valuation claimed on a return is 400% or more than the correct valuation, the penalty imposed increases to 40%. Other Taxes You should consider state and local tax consequences of purchasing our Common Units. We own property or are doing business in Arizona, Illinois, Iowa, Minnesota, Montana, Nebraska, North Dakota, Oklahoma, South Dakota and Texas. You will likely be required to file state income tax returns and/or to pay taxes in most of these states and may be subject to penalties for failure to comply with such requirements. Some of these states require that a partnership withhold a percentage of income from amounts that are to be distributed to a partner that is not a resident of the state. The amounts withheld, which may be greater or less than a particular partner's income tax liability to the state, generally do not relieve the non-resident partner from the obligation to file a state income tax return. Amounts withheld will be treated as if distributed to our unitholders for purposes of determining the amounts distributed by us. Based on current law and its estimate of our future operations, we anticipate that any amounts required to be withheld will not be material. In addition, an obligation to file tax returns or to pay taxes may arise in other states. It is your responsibility to investigate the legal and tax consequences, under the laws of pertinent states or localities, of your investment in us. Further, it is your responsibility to file all state and local, as well as federal, tax returns that may be required of you. Counsel has not rendered an opinion on the state and local tax consequences of an investment in us. PLAN OF DISTRIBUTION Under this prospectus, we intend to offer the securities to the public through one or more broker-dealers, underwriters, or directly to investors. We will fix a price or prices, but we may change the price, of the securities offered from time to time at market prices prevailing at the time of any sale under this shelf registration, prices related to such market prices, or negotiated prices. We will pay or allow distributors' or sellers' commissions that will not exceed those customary in the types of transactions involved. Broker-dealers may act as agent or may purchase the securities as principal and thereafter resell such securities from time to time in or through one or more transactions (which may involve crosses and block transactions) or distributions on the New York Stock Exchange, in the over-the-counter market, in private transactions. 29 41 Broker-dealers or underwriters may receive compensation in the form of underwriting discounts or commissions and may receive commissions from purchasers of the securities for whom they may act as agents. If any broker-dealer purchases the securities as principal, it may effect resales of the securities from time to time to or through other broker-dealers, and other broker-dealers may receive compensation in the form of concessions or commissions from the purchasers of the securities for whom they may act as agents. To the extent required, the names of the specific managing underwriter or underwriters, if any, as well as other important information, will be set forth in a prospectus supplement. In such event, the discounts and commissions we will allow or pay to the underwriters, if any, and the discounts and commissions we may allow or pay to dealers or agents, if any, will be set forth in, or may be calculated from, the prospectus supplement. Any underwriters, brokers, dealers and agents who participate in any sale of the securities may also be customers of, engage in transactions with, or perform services for us or our affiliates in the ordinary course of business. IN CONNECTION WITH THIS OFFERING, UNDERWRITERS, BROKERS OR DEALERS PARTICIPATING IN THE OFFERING MAY OVER-ALLOT OR EFFECT TRANSACTIONS THAT STABILIZE OR MAINTAIN THE MARKET PRICE OF THE COMMON UNITS OR DEBT SECURITIES AT LEVELS ABOVE THOSE WHICH MIGHT OTHERWISE PREVAIL IN THE OPEN MARKET. SUCH TRANSACTIONS MAY BE EFFECTED ON THE NEW YORK STOCK EXCHANGE, IN THE OVER-THE-COUNTER MARKET OR OTHERWISE. SUCH STABILIZING, IF COMMENCED, MAY BE DISCONTINUED AT ANY TIME. LEGAL MATTERS Vinson & Elkins L.L.P., Austin, Texas, will pass upon the validity of the securities offered in this prospectus and the material federal income tax considerations regarding the securities. The underwriter's own legal counsel will advise them about other issues relating to any offering. EXPERTS The consolidated financial statements and schedule included in our Annual Report on Form 10-K for the year ended December 31, 1997, incorporated by reference in this prospectus, have been audited by Arthur Andersen LLP, independent public accountants, as indicated in their reports. Our consolidated financial statements and schedule referred to above and Arthur Andersen's reports have been incorporated by reference herein in reliance upon their authority as experts in accounting and auditing in giving said reports. 30 42 - -------------------------------------------------------------------------------- - -------------------------------------------------------------------------------- WE HAVE NOT AUTHORIZED ANYONE TO PROVIDE INFORMATION DIFFERENT FROM THAT CONTAINED IN THIS PROSPECTUS SUPPLEMENT AND THE ACCOMPANYING PROSPECTUS. NEITHER THE DELIVERY OF THIS PROSPECTUS SUPPLEMENT AND THE ACCOMPANYING PROSPECTUS NOR THE SALE OF COMMON UNITS MEANS THAT THE INFORMATION CONTAINED IN THIS PROSPECTUS SUPPLEMENT AND THE ACCOMPANYING PROSPECTUS IS CORRECT AFTER THE DATES OF THIS PROSPECTUS AND THE ACCOMPANYING PROSPECTUS. THIS PROSPECTUS SUPPLEMENT AND THE ACCOMPANYING PROSPECTUS ARE NOT AN OFFER TO SELL OR A SOLICITATION OF AN OFFER TO BUY THESE COMMON UNITS IN ANY CIRCUMSTANCES UNDER WHICH THE OFFER OR SOLICITATION IS UNLAWFUL. ------------------------ TABLE OF CONTENTS
PAGE ---- PROSPECTUS SUPPLEMENT Northern Border Partners.............. S-1 Recent Developments................... S-3 Ratio of Taxable Income to Distributions....................... S-4 Recent Tax Developments............... S-5 Use of Proceeds....................... S-6 Price Range of Common Units and Distributions....................... S-6 Capitalization........................ S-7 Underwriting.......................... S-8 Legal Matters......................... S-9 Experts............................... S-9 PROSPECTUS The Offered Securities................ 2 Where You Can Find More Information... 2 Cautionary Statement Regarding Forward Looking Statements.................. 3 Our Business.......................... 4 Conflicts of Interest and Fiduciary Responsibilities.................... 7 FERC Regulation....................... 8 Environmental and Safety Costs and Liabilities......................... 11 Common Units.......................... 11 Debt Securities....................... 12 Ratio of Earnings to Fixed Charges.... 15 Use of Proceeds....................... 15 Tax Considerations.................... 15 Plan of Distribution.................. 29 Legal Matters......................... 30 Experts............................... 30
- -------------------------------------------------------------------------------- - -------------------------------------------------------------------------------- - -------------------------------------------------------------------------------- - -------------------------------------------------------------------------------- 1,875,000 COMMON UNITS NORTHERN BORDER PARTNERS, L.P. REPRESENTING LIMITED PARTNER INTERESTS ------------------------ PROSPECTUS SUPPLEMENT ------------------------ PAINEWEBBER INCORPORATED SALOMON SMITH BARNEY LEHMAN BROTHERS ------------------------ NOVEMBER 1, 2000 - -------------------------------------------------------------------------------- - -------------------------------------------------------------------------------- -----END PRIVACY-ENHANCED MESSAGE-----