424B3 1 h86564b3e424b3.txt NORTHERN BORDER PARTNERS, L.P. 1 Filed Pursuant to Rule 424(b)(3) File Nos. 333-40601, 333-72323, 333-72351 THIS PROSPECTUS SUPPLEMENT RELATES TO EFFECTIVE REGISTRATION STATEMENTS UNDER THE SECURITIES ACT OF 1933, BUT IS NOT COMPLETE AND MAY BE CHANGED. THIS PROSPECTUS SUPPLEMENT 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. SUBJECT TO COMPLETION DATED MAY 8, 2001. PROSPECTUS SUPPLEMENT (TO PROSPECTUS DATED DECEMBER 5, 1997 AND PROSPECTUSES DATED MARCH 3, 1999) [NORTHERN BORDER PARTNERS, L.P. LOGO] 4,455,218 COMMON UNITS NORTHERN BORDER PARTNERS, L.P. REPRESENTING LIMITED PARTNER INTERESTS $ PER COMMON UNIT ------------------ We are selling 4,000,000 common units as described in this prospectus supplement and the accompanying prospectuses. The selling unitholder named in this prospectus supplement is also selling 455,218 common units as described in this prospectus supplement and the accompanying prospectus. The underwriters named in this prospectus supplement may purchase up to 668,282 additional common units from the selling unitholder under certain circumstances. We will not receive any of the proceeds from the common units sold by the selling unitholder. Our common units are traded on the New York Stock Exchange under the symbol "NBP." On May 7, 2001, the last reported sale price of our common units on the New York Stock Exchange was $39.66 per common unit. 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 prospectuses are truthful or complete. Any representation to the contrary is a criminal offense.
PER COMMON UNIT TOTAL ----------- -------- Public Offering Price $ $ Underwriting Discount $ $ Proceeds to Northern Border Partners, L.P. (before expenses) $ $ Proceeds to the Selling Unitholder (before expenses) $ $
The underwriters are offering the common units subject to various conditions. The underwriters expect to deliver the common units to purchasers on or about May , 2001. ------------------ SALOMON SMITH BARNEY UBS WARBURG BANC OF AMERICA SECURITIES LLC A.G. EDWARDS & SONS, INC. DAIN RAUSCHER WESSELS FIRST UNION SECURITIES, INC. May , 2001 2 TABLE OF CONTENTS PROSPECTUS SUPPLEMENT Prospectus Supplement Summary............................... S-1 Factors Affecting the Results of Our Strategy............... S-7 Use of Proceeds............................................. S-7 Capitalization.............................................. S-8 Distributions............................................... S-9 Selected Historical Consolidated Financial Data............. S-10 Our Business................................................ S-11 Our Management.............................................. S-16 Principal and Selling Unitholders........................... S-18 Recent Tax Developments..................................... S-19 Underwriting................................................ S-21 Legal Matters............................................... S-23 Experts..................................................... S-23 Forward Looking Statements.................................. S-23 1999 PROSPECTUS The Offered Securities...................................... A-2 Where You Can Find More Information......................... A-2 Cautionary Statement Regarding Forward Looking Statements... A-3 Our Business................................................ A-4 Conflicts of Interest and Fiduciary Responsibilities........ A-7 FERC Regulation............................................. A-8 Environmental and Safety Costs and Liabilities.............. A-11 Common Units................................................ A-11 Debt Securities............................................. A-12 Ratio of Earnings to Fixed Charges.......................... A-15 Use of Proceeds............................................. A-15 Tax Considerations.......................................... A-15 Plan of Distribution........................................ A-29 Legal Matters............................................... A-30 Experts..................................................... A-30 SELLING UNITHOLDER PROSPECTUS The Offered Securities...................................... B-2 Where You Can Find More Information......................... B-2 Cautionary Statement Regarding Forward Looking Statements... B-3 Our Business................................................ B-4 Conflicts of Interest and Fiduciary Responsibilities........ B-7 FERC Regulation............................................. B-8 Environmental and Safety Costs and Liabilities.............. B-11 Common Units................................................ B-11 Use of Proceeds............................................. B-12 Tax Considerations.......................................... B-12 Offering Unitholders........................................ B-26 Plan of Distribution........................................ B-27 Legal Matters............................................... B-27 Experts..................................................... B-27
i 3 1997 PROSPECTUS Available Information....................................... C-2 Incorporation of Certain Documents by Reference............. C-3 Information Regarding Forward Looking Statements............ C-3 Business.................................................... C-4 Use of Proceeds............................................. C-7 Description of the Units.................................... C-7 Tax Considerations.......................................... C-9 Plan of Distribution........................................ C-24 Validity of Common Units.................................... C-25 Experts..................................................... C-25
YOU SHOULD RELY ON THE INFORMATION CONTAINED IN THIS PROSPECTUS SUPPLEMENT, THE ACCOMPANYING PROSPECTUSES AND THE DOCUMENTS WE HAVE INCORPORATED BY REFERENCE. 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 OR SALE IS NOT PERMITTED. YOU SHOULD NOT ASSUME THAT THE INFORMATION PROVIDED BY THIS PROSPECTUS SUPPLEMENT OR THE ACCOMPANYING PROSPECTUSES, AS WELL AS THE INFORMATION WE HAVE PREVIOUSLY FILED WITH THE SECURITIES AND EXCHANGE COMMISSION THAT IS INCORPORATED BY REFERENCE HEREIN, IS ACCURATE AS OF ANY DATE OTHER THAN ITS RESPECTIVE DATE. 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 IS THE BASE PROSPECTUSES (THE "1999 PROSPECTUS," THE "SELLING UNITHOLDER PROSPECTUS" AND THE "1997 PROSPECTUS"), WHICH GIVE 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 PROSPECTUSES, YOU SHOULD RELY ON THE INFORMATION IN THE PROSPECTUS SUPPLEMENT. ii 4 PROSPECTUS SUPPLEMENT SUMMARY This summary highlights some basic information from this prospectus supplement and the accompanying prospectuses to help you understand the common units. It likely does not contain all the information that is important to you. You should carefully read the entire prospectus supplement, the accompanying prospectuses and the other documents incorporated by reference to understand fully the terms of the common units, as well as the tax and other considerations that are important to you in making your investment decision. For purposes of this prospectus supplement and the accompanying prospectuses, unless the context otherwise indicates, when we refer to "us," "we," "our," "ours" or "Northern Border," we are describing ourselves, Northern Border Partners, L.P., together with our subsidiaries. NORTHERN BORDER PARTNERS, L.P. WHO WE ARE Northern Border Partners was formed in 1993 to acquire, own and manage pipeline and other midstream energy assets. Today, we are one of the largest publicly-traded limited partnerships and a leading transporter of natural gas imported from Canada to the United States. We own a 70% interest in Norther Border Pipeline Company, which owns and manages a 1,214-mile regulated natural gas pipeline system that transported over one-fifth of all natural gas imported from Canada to the United States in 2000. Our interest in Northern Border Pipeline currently represents over 70% of our assets and provides us with stable, fixed-rate cash flows. We recently completed the acquisition of Midwestern Gas Transmission Company, which owns a 350-mile regulated natural gas pipeline system. In addition, we have significantly expanded our non-regulated midstream energy operations through recent acquisitions in the United States and Canada. We believe these businesses position us with another important platform for expansion. Strategically, we will focus on maintaining the current high utilization of our interstate pipeline assets and acquiring additional natural gas-related assets that generate relatively stable cash flow and offer the potential for future growth. The Northern Border Pipeline system transports natural gas from the Canadian border at Port of Morgan, Montana to important end markets in the midwestern United States. Approximately 90% of the natural gas transported by Northern Border Pipeline during 2000 was produced in the reserve-rich western Canadian sedimentary basin located in the provinces of Alberta, British Columbia and Saskatchewan. Just under 99% of the pipeline's capacity is contractually committed to more than 50 shippers through mid-September 2003 with a weighted average contract life of approximately six years. Northern Border Pipeline does not own the natural gas that it transports, and therefore it does not assume the related natural gas commodity price risk. Northern Border Pipeline has completed a number of expansions and extensions to its pipeline system and is in the process of completing another growth project, Project 2000. The Chicago Project, our most recently completed expansion, successfully increased the pipeline system's capacity by 42% to 2.4 billion cubic feet per day on the 822-mile segment of the pipeline and expanded its delivery service to the Chicago market area. As a result of the project, Northern Border Pipeline is able to deliver to Chicago 645 million cubic feet per day, an amount equal to approximately 20% of the natural gas baseload of the local natural gas distribution companies in the Chicago area. Project 2000 will expand and extend the pipeline system into Indiana. The expansion affords shippers on the pipeline system access to industrial gas consumers in northern Indiana and is expected to be in service by November 2001. We also own various interests in entities that own and operate an aggregate of approximately 4,000 miles of gas gathering facilities in the Williston Basin in Montana and North Dakota and the Powder River and Wind River Basins in Wyoming. The gathering facilities connect to the interstate gas pipeline grid serving the natural gas markets in the Rocky Mountains, the Midwest and California. These assets diversify our business mix by allowing us access to new producing areas with growth potential and S-1 5 by allowing us to apply our knowledge of interstate pipeline operations to the less regulated gathering and processing components of the natural gas business. OUR GENERAL PARTNERS Our general partners are subsidiaries of Enron Corp. and The Williams Companies, Inc. We are managed by our partnership policy committee consisting of three members appointed by our three general partners. Control of Northern Border Pipeline is overseen by its management committee, which consists of three of our representatives and one from TC PipeLines, LP, the owner of the remaining 30% interest in Northern Border Pipeline. TC PipeLines, LP is a publicly traded partnership whose general partner is a subsidiary of TransCanada PipeLines Limited. Through its general partner interests in us, Enron effectively controls a majority of the voting power on our partnership policy committee and on the Northern Border Pipeline management committee. Enron is one of the world's leading electricity, natural gas and communications companies. Enron produces electricity and natural gas, develops, constructs and operates energy facilities worldwide and delivers both physical commodities and financial and risk management services to customers. Enron is also developing an intelligent network platform to provide bandwidth management services and the delivery of high bandwidth communication applications. Williams, through its subsidiaries, connects businesses to energy, delivering innovative, reliable products and services. Williams' primary businesses include natural gas pipeline transportation, energy marketing and trading, natural gas gathering and processing, natural gas liquids pipelines, petroleum products pipeline and terminaling, two refineries, exploration and production, ethanol production and international operations and investments. Williams' operations span North America, South America and Europe. OUR BUSINESS STRATEGY Our objective is to continue to be a leading, growth-oriented master limited partnership with a goal of increasing our cash flow and distributions to unitholders. We intend to execute our business strategy by: - Maintaining the current high utilization of our regulated, interstate pipeline assets, by: - Continuing to develop superior market access for shippers in the regions that we serve - Aggressively pursuing service to new electric generation facilities - Creating and delivering new value-added services beneficial to our customers - Increasing the capacity and efficiency of our pipeline, gathering and processing assets, by: - Targeting pipeline expansions supported by long-term, fee-based or fixed-rate contracts - Aggressively controlling operating costs - Acquiring additional natural gas-related assets with relatively stable cash flow characteristics and potential for future growth in the United States and Canada - Maintaining our strong financial position and our ability to access capital to fund future growth prospects RECENT STRATEGIC DEVELOPMENTS Acquisition of Bear Paw Energy On March 30, 2001, we completed a $382 million acquisition of Bear Paw Energy, LLC. The purchase price consisted of approximately half cash and half common units. Bear Paw Energy has extensive gathering and processing operations in the Powder River Basin in Wyoming and the Williston Basin in Montana and North Dakota. Bear Paw Energy has approximately 226,000 acres under dedication S-2 6 and 600 miles of gathering lines in the Powder River Basin. In the Williston Basin, Bear Paw Energy has over 2,800 miles of gathering lines and four gas processing plants with 90 million cubic feet per day of capacity. Acquisition of Canadian Midstream Assets by Border Midstream Services On April 4, 2001, we completed a Cdn.$70 million cash acquisition of the Mazeppa and Gladys sour gas processing plants, gas gathering systems and a minority interest in the Gregg Lake/Obed Pipeline from Dynegy Canada, Inc. The Mazeppa and Gladys plants, which are located near Calgary, Alberta, have a combined capacity of 87 million cubic feet per day. The Gregg Lake/Obed Pipeline system, which is located near Edmonton, Alberta, is comprised of 85 miles of gathering lines with a capacity of approximately 150 million cubic feet per day. We believe that these assets will provide an important platform for future growth in the region. Acquisition of Midwestern Gas Transmission Company On April 30, 2001, we acquired Midwestern from El Paso Corporation for approximately $100 million in cash. The Midwestern system is a 350-mile interstate natural gas pipeline extending from Portland, Tennessee to Joliet, Illinois with a capacity of 650 million cubic feet per day. Midwestern connects to seven other major interstate pipeline systems, including Northern Border Pipeline. The acquisition of Midwestern extends our market reach south and east of the Chicago hub and provides additional opportunities to serve the growing electric generation markets in this region. RECENT FINANCIAL DEVELOPMENTS Increase in Cash Distributions Effective with the first quarter 2001 distribution, we increased our quarterly cash distribution to $0.7625 from $0.70 per common unit. The indicated annual distribution is now $3.05 per common unit. This was our fifth increase in cash distributions in four years and the second in the past six months. This increase reflects the continued successful execution of our strategy through the strong performance of our core businesses and recent accretive acquisitions. Refinancing of Revolving Credit Facility On March 21, 2001, we entered into a $200 million revolving credit facility with a group of commercial lenders. The new credit facility has a term of three years and replaces the revolving credit facilities we entered into in June 2000. Issuance of Senior Notes On March 21, 2001, we issued $225 million of our 7.10% Senior Notes due 2011 in a Rule 144A offering. The notes are our senior unsecured obligations and were rated Baa1 by Moody's Investor Services and BBB+ by Standard & Poor's Rating Services. Net proceeds from the offering were used to fund a portion of the Bear Paw Energy acquisition and to reduce outstanding indebtedness. Issuance of Common Units On April 11, 2001, we sold 407,550 common units to a money manager, on behalf of its clients, in a direct placement. The money manager purchased the common units for accounts over which it has discretionary investment authority. The net proceeds from the sale, together with the general partners' capital contribution, were approximately $15 million. S-3 7 OUR STRUCTURE The following chart depicts our organization, our structure and our interests in Northern Border Pipeline, Bear Paw Energy, Crestone Energy Ventures, Midwestern, Border Midstream Services and Black Mesa Holdings. [CHART] --------------- (1) Represents ownership interest after giving effect to the offering. (2) Northern Plains, Pan Border and Northwest Border serve as our general partners. Northern Plains and Pan Border are subsidiaries of Enron, and Northwest Border is a subsidiary of Williams. Prior to the consummation of this offering, the general partners hold in us a combined general and limited partner interest as follows: Northern Plains -- 9.4%; Pan Border -- 0.6%; and Northwest Border -- 3.3%. (3) Represents ownership interest after giving effect to the offering, assuming the underwriters do not exercise their over-allotment option. If the underwriters' over-allotment option is exercised in full, Northwest Border's ownership interest will be 0.3%, which represents its general partner interest. (4) Prior to the consummation of this offering, the general partners have a combined 11.3% limited partner interest and the remaining limited partner interest is held publicly. None of the general partner percentage interests will change as a result of the offering. S-4 8 THE OFFERING Securities offered by us............ 4,000,000 common units Securities offered by the selling unitholder.......................... 455,218 common units(1) Total securities offered............ 4,455,218 common units(1) Price............................... $ per common unit Units to be outstanding after the offering............................ 41,623,014 common units Use of proceeds..................... We estimate that we will receive approximately $ million from the sale of the common units, after deducting underwriting discounts and commissions and offering expenses. We will not receive any proceeds from any common units sold by the selling unitholder, including any common units sold by the selling unitholder if the underwriters exercise their over-allotment option. We plan to use our net proceeds from this offering, together with capital contributions from our general partners, to reduce indebtedness under our revolving credit facility. We may reborrow funds available under our revolving credit facility in the future for capital investments, acquisitions and general business purposes. New York Stock Exchange symbol...... NBP --------------- (1) If the underwriters exercise their over-allotment option in full, the selling unitholder will sell an additional 668,282 common units, but the total amount of common units outstanding after the offering will remain 41,623,014. S-5 9 TAX CONSIDERATIONS The tax consequences to you of an investment in common units will depend in part on your own tax circumstances. For a discussion of the principal federal income tax considerations associated with our operations and the purchase, ownership and disposition of units, please read "Tax Considerations" beginning on page A-15 of the 1999 prospectus, page B-12 of the selling unitholder prospectus and page C-9 of the 1997 prospectus. You should consult your own tax advisor about the federal, state and local tax consequences peculiar to your circumstances. For a description of recent federal income tax developments, please read "Recent Tax Developments" in this prospectus supplement. We estimate that a purchaser of common units in this offering who holds them through 2004 will be allocated an amount of federal taxable income for the period 2001 through 2004 that will be less than 10% of the amount of cash distributed to such unitholder with respect to that period. This estimate is based on certain assumptions regarding revenues, capital expenditures, anticipated cash distributions, amounts expended for Project 2000 and other factors. The Internal Revenue Service could disagree with our tax reporting positions, including estimates of the relative fair market values of our assets and the validity of curative allocations. 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. The actual percentage of distributions that will constitute taxable income could be higher or lower, and any differences could be material. Taxable income will be allocated to purchasers of common units in this offering from the date of purchase, but cash distributions will not be made on the common units purchased in this offering until August 15, 2001, the distribution date for the second quarter 2001. Ownership of common units by tax-exempt entities, regulated investment companies and foreign investors raises issues unique to such persons. Please read "Tax Considerations -- Tax-Exempt Organizations and Certain Other Investors" in the accompanying prospectuses. S-6 10 FACTORS AFFECTING THE RESULTS OF OUR STRATEGY Part of our business strategy is to expand existing assets and acquire additional assets and businesses that will allow us to increase our cash flow and distributions to unitholders. Recently, we have made several acquisitions that significantly increased our asset base and expanded our business beyond interstate natural gas pipeline operations. Unexpected costs or challenges may arise whenever we acquire new assets or businesses. Unlike our regulated interstate natural gas pipeline operations, which provide relatively stable cash flows, the cash flows from our recent acquisitions and other future acquisitions may be less predictable, which could in turn affect the amount of cash we have available for distribution. Successful acquisitions require management and other personnel to devote significant amounts of time to new businesses or integrating the acquired assets with existing businesses. These efforts may temporarily distract management's attention from day-to-day business, the development or acquisition of new assets or businesses and other opportunities. Our ability to expand our midstream gas gathering businesses will depend in large part on the pace of drilling and production activity in the Powder River, Wind River and Williston Basins. Drilling and production activity will be impacted by a number of factors beyond our control, including demand for and prices of natural gas, the ability of producers to obtain necessary permits and capacity constraints on natural gas transmission pipelines that transport gas from the producing areas to the Rocky Mountain, Midwest and California markets. If drilling and production activity proceeds at levels that are lower than those projected at the time of the acquisitions, we may not realize the expected increases in income and cash flow. Although our business strategy is to pursue fee-based and fixed-rate contracts, some of our gas processing facilities are subject to certain contracts that give us quantities of natural gas and natural gas liquids as payment for our processing services. The income and cash flow from these contracts will be impacted directly by changes in these commodity prices. We have hedged a substantial portion of our commodity price risk under these contracts for 2001 and approximately one-fourth of our commodity price risk for 2002. We may need new capital to finance future acquisitions and expansions. If our access to capital is limited, this will impair our ability to execute our growth strategy. As we acquire new businesses and make additional investments in existing businesses, we may need to increase borrowings and issue additional equity in order to maintain an appropriate capital structure. This may impact the market value of our common units. USE OF PROCEEDS We expect the net proceeds of the offering to be approximately $ million, after deducting underwriting discounts and commissions and offering expenses. We will not receive any proceeds from any common units sold by the selling unitholder, including any common units sold by the selling unitholder if the underwriters exercise their over-allotment option. We expect to use our net proceeds from this offering, together with capital contributions from our general partners, to reduce the amount of indebtedness outstanding under our revolving credit facility entered into in March 2001. We may reborrow funds available under our revolving credit facility in the future for capital investments, acquisitions and general business purposes. As of April 30, 2001, we had $162 million outstanding under our revolving credit facility bearing interest at an average floating rate of 5.52% per annum with a final maturity of March 2004. Since entering into our revolving credit facility in March 2001, we have used the funds borrowed under it for general business purposes, including the Border Midstream acquisition of Canadian assets, the acquisition of Midwestern and, together with the proceeds from the senior notes issued in March 2001, the acquisition of Bear Paw Energy. S-7 11 CAPITALIZATION The following table sets forth our unaudited historical, pro forma and as adjusted capitalization as of March 31, 2001. The pro forma information gives effect to: (1) the issuance of 407,550 common units on April 11, 2001 to a money manager, on behalf of its clients; and (2) additional borrowings under our revolving credit facility related to the acquisition of Midwestern on April 30, 2001. The as adjusted information gives effect to: (1) the sale of common units in this offering, assuming an issue price of $39.66, the last reported sale price of the common units on the New York Stock Exchange on May 7, 2001, and the application of the net proceeds to reduce amounts outstanding under our credit facility; and (2) 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.
AS OF MARCH 31, 2001 ------------------------------------ PRO AS ACTUAL FORMA ADJUSTED ---------- ---------- ---------- (IN THOUSANDS) Northern Border Partners, L.P. Senior notes -- 8.875%, due 2010....................... $ 250,000 $ 250,000 $ 250,000 Credit agreement -- revolving credit, variable interest rate (average 6.35% at March 31, 2001), due 2004(1)............................................. 73,000 162,000 7,364 Senior notes -- 7.10%, due 2011........................ 225,000 225,000 225,000 Unamortized debt premium, net.......................... 3,156 3,156 3,156 Northern Border Pipeline Senior notes -- average 8.49%, due from 2001 to 2003... 184,000 184,000 184,000 Pipeline credit agreement Term loan, variable interest rate (5.42% at March 31, 2001), due 2002............................... 414,000 414,000 414,000 Revolving credit facility, variable interest rate (5.73% at March 31, 2001), due 2002................. 62,000 62,000 62,000 Senior notes -- 7.75%, due 2009........................ 200,000 200,000 200,000 Unamortized debt discount.............................. (816) (816) (816) Black Mesa 10.7% note agreement, due quarterly to 2004............ 13,078 13,078 13,078 ---------- ---------- ---------- Total long-term debt (including current maturities).................................. 1,423,418 1,512,418 1,357,782 ---------- ---------- ---------- Minority interests in partners' equity................... 253,281 253,281 253,281 Accumulated other comprehensive income................... 19,168 19,168 19,168 Partners' capital General partners....................................... 15,081 15,375 18,468 Common unitholders..................................... 738,963 753,350 904,893 ---------- ---------- ---------- Total partners' capital........................ 754,044 768,725 923,361 ---------- ---------- ---------- Total capitalization........................... $2,449,911 $2,553,592 $2,553,592 ========== ========== ==========
--------------- (1) We entered into a $200 million revolving credit facility with a group of lenders on March 21, 2001. The new credit facility has a term of three years and replaces the revolving credit facilities entered into in June 2000. S-8 12 DISTRIBUTIONS The following table sets forth quarterly declared cash distributions on our common units for the quarter with respect to which they are payable:
DISTRIBUTIONS DECLARED PER COMMON UNIT ---------------------- 2001 First Quarter................................... $0.7625(1) 2000 Fourth Quarter.................................. $0.7000 Third Quarter................................... 0.7000 Second Quarter.................................. 0.6500 First Quarter................................... 0.6500 1999 Fourth Quarter.................................. $0.6500 Third Quarter................................... 0.6100 Second Quarter.................................. 0.6100 First Quarter................................... 0.6100 1998 Fourth Quarter.................................. $0.6100 Third Quarter................................... 0.5750 Second Quarter.................................. 0.5750 First Quarter................................... 0.5750
--------------- (1) Effective with the first quarter 2001 distribution, we increased our quarterly cash distribution to $0.7625 from $0.70 per common unit. The first quarter 2001 distribution is payable May 15, 2001 to unitholders of record on April 30, 2001. S-9 13 SELECTED HISTORICAL CONSOLIDATED FINANCIAL DATA
THREE MONTHS ENDED MARCH 31, YEAR ENDED DECEMBER 31, ----------------------- -------------------------------------------------------------- 2001 2000 2000 1999 1998 1997 1996 ---------- ---------- ---------- ---------- ---------- ---------- ---------- (UNAUDITED) (IN THOUSANDS, EXCEPT PER UNIT DATA) INCOME DATA: Operating revenues, net.............. $ 87,960 $ 81,517 $ 339,732 $ 318,963 $ 217,592 $ 198,574 $ 201,943 Operations and maintenance........... 16,017 12,874 62,097 53,451 44,770 37,418 28,366 Depreciation and amortization........ 15,694 15,589 60,699 54,842 43,885 40,332 46,979 Taxes other than income.............. 4,093 7,883 28,634 30,952 22,012 22,836 24,390 Regulatory credit.................... -- -- -- -- (8,878) -- -- ---------- ---------- ---------- ---------- ---------- ---------- ---------- Operating income..................... 52,156 45,171 188,302 179,718 115,803 97,988 102,208 Interest expense, net................ 21,696 18,691 81,495 67,709 30,922 30,860 32,670 Other income (expense)............... (1,720) 109 8,032 4,562 13,208 8,149 2,900 Minority interests in net income..... 10,767 8,623 38,119 35,568 30,069 22,253 22,153 ---------- ---------- ---------- ---------- ---------- ---------- ---------- Net income to partners............... $ 17,973 $ 17,966 $ 76,720 $ 81,003 $ 68,020 $ 53,024 $ 50,285 ========== ========== ========== ========== ========== ========== ========== Net income per unit.................. $ 0.54 $ 0.59 $ 2.50 $ 2.70 $ 2.27 $ 1.97 $ 1.88 ========== ========== ========== ========== ========== ========== ========== Number of units used in computation........................ 31,565 29,347 29,665 29,347 29,345 26,392 26,200 ========== ========== ========== ========== ========== ========== ========== CASH DISTRIBUTIONS DECLARED PER UNIT: Common unit(1)....................... $ 0.76 $ 0.65 $ 2.70 $ 2.48 $ 2.34 $ 2.23 $ 2.20 ========== ========== ========== ========== ========== ========== ========== BALANCE SHEET DATA (AT END OF PERIOD): Property, plant and equipment, net... $1,742,353 $1,726,933 $1,732,076 $1,745,356 $1,730,476 $1,118,364 $ 937,859 Total assets......................... 2,508,126 1,876,174 2,082,720 1,863,437 1,825,766 1,266,917 1,016,484 Long-term debt, including current maturities......................... 1,423,418 1,050,939 1,171,962 1,031,986 976,832 481,355 377,500 Minority interests in partners' equity............................. 253,281 249,812 248,098 250,450 253,031 174,424 158,089 Partners' capital.................... 754,044 513,564 572,274 515,269 507,426 500,728 410,586 OTHER FINANCIAL DATA: EBITDA(2)............................ 67,702 61,037 259,274 239,122 172,896 146,469 152,087 Net cash provided by operating activities......................... 39,226 37,387 169,615 173,368 103,849 119,621 137,534 Net cash used in investing activities......................... 227,211 2,489 257,992 134,165 652,194 149,870 23,393 Net cash provided by (used in) financing activities............... 219,694 (9,782) 100,813 (57,318) 482,630 95,616 (112,169) Capital expenditures................. 25,391 380 19,721 102,270 652,194 152,658 18,597 Acquisition of businesses............ 198,659 -- 229,505 31,895 -- -- --
--------------- (1) Amounts shown represent declared cash distributions on our common units for the period with respect to which they are payable. (2) EBITDA is defined for this purpose as: net income before minority interests; interest expense; and depreciation and amortization, including goodwill amortization, which is netted against equity earnings of unconsolidated affiliates. S-10 14 OUR BUSINESS OVERVIEW Northern Border Partners was formed in 1993 to acquire, own and manage pipeline and other midstream energy assets. Today, we are one of the largest publicly-traded limited partnerships and a leading transporter of natural gas imported from Canada to the United States. We own a 70% interest in Northern Border Pipeline Company, which owns and manages a 1,214-mile regulated natural gas pipeline system that transported over one-fifth of all natural gas imported from Canada to the United States in 2000. Our interest in Northern Border Pipeline currently represents over 70% of our assets and provides us with stable, fixed-rate cash flows. We recently completed the acquisition of Midwestern, which owns a 350-mile regulated natural gas pipeline system. In addition, we have significantly expanded our non-regulated midstream energy operations through recent acquisitions in the United States and Canada. We believe these businesses position us with another important platform for expansion. Strategically, we will focus on maintaining the current high utilization of our interstate pipeline assets and acquiring additional natural gas-related assets that generate relatively stable cash flow and offer the potential for future growth. OUR BUSINESSES AND ASSETS Interstate Natural Gas Pipeline Systems Northern Border Pipeline System. Northern Border Pipeline originally placed its interstate pipeline system in service in 1982 with capacity additions to the pipeline system in 1991 and 1992 and most recently completed The Chicago Project expansion in late 1998. The Northern Border 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. Northern Border Pipeline provides its shippers access to markets in the Midwest through interconnecting pipeline facilities, as well as direct access to the Chicago markets. 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 2.4 billion cubic feet per day 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 1.3 billion cubic feet per day 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 million cubic feet per day from Harper, Iowa to a terminus near Manhattan, Illinois, which is located in the 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 natural gas at various points. Other facilities include four field offices and a communication system. In March 2000, the Federal Energy Regulatory Commission 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. Project 2000 will afford shippers on the expanded and extended pipeline system access to industrial natural gas consumers in northern Indiana through an interconnect with Northern Indiana Public Service Company, a major Midwest local distribution company at the terminus near North Hayden, Indiana. The project has a targeted in-service date of November 2001. Capital expenditures are estimated to be $94 million, of which approximately $11 million had been expended as of December 31, 2000. Proposed facilities include approximately 34 miles of 30-inch pipeline, new equipment and modifications at three compressor stations resulting in a net increase of 22,500 compressor horsepower and one meter station. As a result of the Project 2000 expansion, the pipeline system will have the ability to transport 1.5 billion cubic feet per day from Ventura, Iowa to Harper, Iowa, 844 million cubic feet per day from Harper, Iowa to Manhattan, Illinois S-11 15 and 544 million cubic feet per day on the new extension from Manhattan, Illinois to North Hayden, Indiana. Interconnecting pipeline facilities provide Northern Border Pipeline's shippers with flexible access to natural gas markets. The Northern Border Pipeline system interconnects with pipeline facilities of: - Northern Natural Gas, an Enron subsidiary, at Ventura, Iowa, as well as multiple smaller interconnections in South Dakota, Minnesota and Iowa; - Natural Gas Pipeline at Harper, Iowa; - MidAmerican Energy at Iowa City and Davenport, Iowa and Cordova, Illinois; - Alliant Power at Prophetstown, Illinois; - Northern Illinois Gas at Troy Grove and Minooka, Illinois; - Midwestern near Channahon, Illinois; - ANR Pipeline near Manhattan, Illinois; - Vector Pipeline near Manhattan, Illinois; and - The Peoples Gas Light and Coke near Manhattan, Illinois (Chicago area) at the terminus of the pipeline system. At its northern end, the Northern Border Pipeline system is connected to TransCanada's majority-owned Foothills Pipe Lines (Sask.) Ltd. system in Canada, which is connected to the Alberta pipeline system, owned by TransCanada, and the pipeline system owned by Transgas Limited in Saskatchewan. The Alberta pipeline system gathers and transports approximately 18% of the North American natural gas production and approximately 74% of the natural gas produced in the western Canadian sedimentary basin. The Northern Border 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. In December 2000, the FERC approved the settlement of Northern Border Pipeline's 1999 rate case. One of the important elements of the settlement was 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. Under the former cost of service tariff, the firm transportation shippers contracted to pay for a proportionate share of the pipeline system's cost of service, regardless of the amount of natural gas they actually transported. In addition, Northern Border Pipeline could not charge or collect more than the cost of service. Under Northern Border Pipeline's new form of tariff, shippers pay Northern Border Pipeline on the basis of stated transportation rates. Under the new tariff, approximately 98% of the agreed upon revenue level is attributed to demand charges. The firm shippers are obligated to pay a monthly demand charge, regardless of the amount of natural gas they actually transport, for the term of their contracts. The remaining 2% of the agreed upon revenue level is attributed to the commodity charge based on the volumes of gas actually transported. On a per unit of transportation basis, the rates under the new tariff are approximately equal to the cost of service on a per unit basis charged prior to December 1, 1999. The settlement also provides that neither Northern Border Pipeline nor its existing shippers can seek changes in Northern Border Pipeline's base rates until November 1, 2005, at which time Northern Border Pipeline must file a new rate case. Prior to the new rate case, Northern Border Pipeline will not be permitted to increase rates if its costs increase, nor will it be required to reduce rates based on cost savings. 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. Midwestern Gas Transmission Pipeline System. The Midwestern pipeline system consists of 350 miles of natural gas transmission pipeline and 70,170 compressor horsepower with forward haul design capacity of 650 million cubic feet per day and backhaul capacity of 350 million cubic feet per day. The S-12 16 system consists of a single 30-inch mainline extending from an interconnection with Tennessee Gas Pipeline at Portland, Tennessee to its terminus at Joliet, Illinois. Midwestern serves both the Chicago market as well as markets in Kentucky, southern Illinois and Indiana, including the rapidly growing power generation segment in these areas. Midwestern's pipeline system directly connects to seven local distribution companies and three power plant end-users. Interconnecting pipeline facilities provide Midwestern's shippers with direct access to Tennessee Gas Pipeline, Natural Gas Pipeline, ANR Pipeline, Alliance Pipeline, Northern Border Pipeline, Trunkline Gas and Texas Gas Transmission, which serve markets in the eastern United States and the Midwest. In addition, Guardian Pipeline has requested an interconnection with Midwestern, which is anticipated to be in place by November 2002. Gas Gathering and Processing Through our wholly-owned subsidiary, Crestone Energy Ventures, we own 100% of Crestone Gathering Services, a 49% interest in Bighorn Gas Gathering, a 33.33% interest in Fort Union Gas Gathering and a 35% interest in Lost Creek Gathering. 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. Crestone Gathering, Bighorn, Fort Union and Lost Creek collectively own almost 600 miles of natural gas gathering facilities in Wyoming. The gathering facilities interconnect to the interstate gas pipeline grid serving natural gas markets in the Rocky Mountains, the Midwest and California. - Crestone Gathering has more than 90,000 leasehold production acres under dedication, 139 miles of gathering lines and 37,389 compressor horsepower in the Powder River Basin. The Crestone Gathering system connects into Fort Union directly and through third party gathering systems. - Fort Union gathers coal seam methane gas produced in the Powder River Basin in northeastern Wyoming. Fort Union's system, which consists of 106 miles of gathering lines, is capable of delivering more than 450 million cubic feet per day of coal seam methane gas into the interstate gas pipeline grid. Fort Union has commenced construction of an expansion to increase its system's capacity to 634 million cubic feet per day that is expected to be in service by October 2001. - Bighorn gathers coal seam methane gas produced in the Powder River Basin in northeastern Wyoming. Bighorn's system, which consists of 188 miles of gathering lines, 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. Under various agreements, the majority of which are long term, producers have dedicated their reserves to Bighorn, giving Bighorn the right to gather coal seam methane gas produced in areas of Wyoming covering 800,000 acres. - Lost Creek gathers natural gas produced from conventional natural gas wells in the Wind River Basin in central Wyoming and has approximately 160 miles of gathering lines. The system is capable of delivering more than 275 million cubic feet per day of natural gas into the interstate gas pipeline grid. - Bear Paw Energy has extensive gathering and processing operations in the Powder River Basin in Wyoming and the Williston Basin in Montana and North Dakota. Bear Paw Energy has approximately 226,000 leasehold production acres under dedication and over 600 miles of gathering lines in the Powder River Basin. In the Williston Basin, Bear Paw Energy has over 2,800 miles of gathering lines and four natural gas processing plants with 90 million cubic feet per day of capacity. - Our Canadian assets include the Mazeppa and Gladys plants, gas gathering systems and a minority interest in the Gregg Lake/Obed Pipeline. The Mazeppa plant is a sour gas processing plant with 82 million cubic feet per day of combined capacity and associated gathering lines. The Gladys plant is a sour gas processing plant with 5 million cubic feet per day of capacity. The Gregg Lake/Obed S-13 17 Pipeline is comprised of 85 miles of gathering lines with a capacity of 150 million cubic feet per day. Other Assets We also own Black Mesa 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 suspended in water to the Mohave Generating Station in Laughlin, Nevada. The capacity of the pipeline is fully contracted to the coal supplier for the Mohave Generating Station through the year 2005. The pipeline is operated by Black Mesa Pipeline Operations, LLC, our wholly-owned subsidiary. Black Mesa accounts for an immaterial portion of our assets, income and cash flow. Operating and Administrative Services Northern Plains and NBP Services Corporation, wholly-owned subsidiaries 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 Midwestern, and NBP Services provides administrative services for us and administrative and operating services for Crestone Energy Ventures, Bear Paw Energy and other subsidiaries. Black Mesa's operating services are provided by its own employees. Northern Plains and NBP Services have approximately 320 individuals involved in operating activities. In consideration for their services, NBP Services and Northern Plains are reimbursed for their direct and indirect costs and expenses, including an allocated portion of employee time and Enron's overhead costs. The only individuals that are represented by a labor union or covered by a collective bargaining agreement are approximately 26 of the 58 employees of Black Mesa, who are represented by the United Mine Workers. The operations of the Canadian assets are outsourced to an unaffiliated third party. SHIPPERS The Northern Border Pipeline system serves more than 50 shippers with diverse operating and financial profiles. Based upon shippers' contractual obligations, as of December 31, 2000, 92% of the firm capacity is contracted by producers and marketers. The remaining firm capacity is contracted to local distribution companies (5%), interstate pipelines (2%) and end-users (1%). As of December 31, 2000, the termination dates of these contracts ranged from October 31, 2001 to December 21, 2013 and the weighted average contract life was approximately six years with just under 99% of capacity contracted through mid-September 2003. Contracts for approximately 44% of the capacity will expire between mid-September 2003 and the end of October 2005. COMPETITION Northern Border Pipeline competes with other pipeline companies that transport natural gas from the western Canadian sedimentary basin or that transport natural gas to end-use markets in the Midwest. Its competitive position is affected by the availability of Canadian natural gas for export, the availability of other sources of natural gas and demand for natural gas in the United States. Demand for transportation services on Northern Border Pipeline's system is affected by the relative prices of natural gas imported from the western Canadian sedimentary basin and natural gas shipped from producing areas in the United States. Shippers of natural gas produced in the western Canadian sedimentary basin also 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 was placed in service in December 2000, competes directly with Northern Border Pipeline in the transportation of natural gas from the western Canadian sedimentary basin to the Chicago area. Since the Alliance Pipeline was placed in service there has been an increase in natural gas moving from the western Canadian sedimentary basin to Chicago. Because it transports liquids-rich natural gas, the Alliance Pipeline has no interconnections with other pipelines upstream of its S-14 18 extraction facilities, which are located near Chicago. This contrasts with Northern Border Pipeline, which serves various markets through interconnections with other pipelines along its route. The competitive impact of the Alliance Pipeline has been mitigated by the continuing development of additional capacity to ship natural gas from the Chicago area to other markets in the United States. Vector Pipeline, L.P., which interconnects with the Alliance Pipeline and transports natural gas eastward to a terminus in eastern Canada, commenced operations in December 2000. There are several additional projects proposed to transport natural gas from the Chicago area that would provide access to additional markets for the shippers. The proposed projects currently being pursued by third parties are targeting markets in northern Illinois, Wisconsin and the northeast United States. These proposed projects are in various stages of regulatory approval. 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 western Canada to markets that are served by Northern Border Pipeline's shippers. Crestone Energy Ventures competes with other natural gas gathering and pipeline companies to carry natural gas from the production area of the Powder River and Wind River Basins of Wyoming to the major interstate transmission pipelines in the Rocky Mountain region. Crestone Energy Ventures' competitive position is affected by the pace of natural gas drilling, natural gas production rates, natural gas reserves and the demand for and prices of natural gas in the Rocky Mountain, Midwest and California markets served by the interstate gas pipeline grid. Bear Paw Energy competes with other natural gas gathering and processing companies within the Williston Basin of Montana and North Dakota. Natural gas and natural gas liquids production within the Williston Basin primarily comes from natural gas associated with oil production. Bear Paw Energy's competitive position is affected by the pace of oil drilling, the natural gas liquids production rates and demand for and prices of natural gas and natural gas liquids in the Rocky Mountain and Midwest markets. In providing natural gas gathering services, Crestone Gathering Services and Bear Paw Energy compete with other natural gas gathering and producing companies to provide wellhead gathering and compression service. Crestone Gathering Services and Bear Paw Energy may require acreage dedication and/or volume commitments from natural gas producers. Development of future natural gas gathering systems will be staged to reflect the growth in number of wells and field production. S-15 19 OUR MANAGEMENT We are managed by or under the direction of the partnership policy committee consisting of three members, each of which has been appointed by one of the general partners. The members appointed by Northern Plains, Pan Border and Northwest Border have 50%, 32.5% and 17.5%, respectively, of the voting power. Set forth below is certain information concerning the members of the partnership policy committee, our representatives on the Northern Border Pipeline management committee and the persons designated by the partnership policy committee as our executive officers and as audit committee members. All members of the partnership policy committee and our representatives on the Northern Border Pipeline management committee serve at the discretion of the general partner that appointed them. The persons designated as executive officers serve in that capacity at the discretion of the partnership policy committee. The audit committee members are elected, and may be removed, by the partnership policy committee.
NAME AGE POSITIONS ---- --- --------- Executive Officers: William R. Cordes................... 52 Chief Executive Officer Jerry L. Peters..................... 43 Chief Financial and Accounting Officer Members of Partnership Policy Committee and our Representatives on Northern Border Pipeline Management Committee: William R. Cordes................... 52 Chairman Stanley C. Horton................... 51 Member Cuba Wadlington, Jr. ............... 57 Member Members of Audit Committee: Daniel P. Whitty.................... 69 Chairman Daniel Dienstbier................... 60 Member Gerald B. Smith..................... 50 Member
William R. Cordes was named our Chief Executive Officer and Chairman of the partnership policy committee in October 2000. Mr. Cordes is the President of Northern Plains, an Enron subsidiary, having been appointed to that position on October 1, 2000, and is a director of Northern Plains. Mr. Cordes was named Chairman of the Northern Border Pipeline management committee on October 1, 2000. He started his career with another Enron company, Northern Natural Gas Company, in 1970 and has worked in several management positions at Northern Natural. In June of 1993, he was named President of Northern Natural and added the position of President of Transwestern Pipeline in May of 1996. Jerry L. Peters was named our Chief Financial and Accounting Officer in July 1994. Mr. Peters has held several management positions with Northern Plains since 1985 and was elected Vice President of Finance for Northern Plains in July 1994, a director of Northern Plains in August 1994 and Treasurer in October 1998. Mr. Peters was also named Vice President, Finance of Enron Transportation Services Company, formerly the Enron Gas Pipeline Group, in February 2001. Prior to joining Northern Plains in 1985, Mr. Peters was employed as a Certified Public Accountant by KPMG Peat Marwick, LLP. Stanley C. Horton was appointed to the partnership policy committee and to the Northern Border Pipeline management committee in December 1998. Mr. Horton is the Chairman and Chief Executive Officer of Enron Transportation Services Company and has held that position since January 1997. From February 1996 to January 1997, he was Co-Chairman and Chief Executive Officer of Enron Operations Corp. From June 1993 to February 1996, he was President and Chief Operating Officer of Enron Operations Corp. He is a director, Chairman of the Board and Chief Executive Officer of EOTT Energy Corp., the general partner of EOTT Energy Partners, L.P. Cuba Wadlington, Jr. was named to the partnership policy committee and to the Northern Border Pipeline management committee on December 1, 1999. On March 14, 2001, Mr. Wadlington was named S-16 20 executive vice president of Williams. On January 4, 2000, Mr. Wadlington was named President and Chief Executive Officer of Williams Gas Pipeline Company, LLC, a Williams subsidiary. Previously, he had served as Executive Vice President and Chief Operating Officer of Williams Gas Pipeline Company, LLC since July 1999. Mr. Wadlington joined Transco in 1995 when Williams acquired Transco Energy Company. From 1995 to 1999, he served as senior vice president and general manager of Transcontinental Gas Pipeline Corporation. From 1988 to 1995, he served as senior vice president and general manager of Williams Western Pipeline Company, executive vice president of Kern River Gas Transmission Company and director of Northwest Pipeline Corporation and Williams Western Pipeline, all affiliates or subsidiaries of Williams. Mr. Wadlington serves on the Board of Directors of Sterling Bancshares Inc. Daniel P. Whitty was appointed to the audit committee in December 1993. Mr. Whitty is an independent financial consultant. He is a director of Enron Funding Corp., Enron Equity Corp. and EOTT Energy Corp., all subsidiaries of Enron, and the latter of which is the general partner of EOTT Energy Partners, L.P. He has served as a member of the Board of Directors of Methodist Retirement Communities Inc. and a Trustee of the Methodist Retirement Trust. Mr. Whitty was a partner at Arthur Andersen & Co. until his retirement on January 31, 1988. Daniel Dienstbier was appointed to the audit committee effective February 1, 2001. Mr. Dienstbier is currently a member of the Board of Directors of Dynegy Corporation and has served on that board since 1995. At the time of his retirement in 1994, he was the President and Chief Operating Officer of American Oil & Gas Company. He also serves on arbitration panels involving energy contract disputes. From 1965 through mid-1988, Mr. Dienstbier held various positions with Northern Natural. From 1985 to 1988, he was the President of Enron's Gas Pipeline Group, which included Enron's interest in Northern Border Pipeline. Gerald B. Smith was appointed to the audit committee in April 1994. He is Chairman and Chief Executive Officer and co-founder of Smith, Graham & Company Investment Advisors, a fixed income investment management firm, which was founded in 1990. He has served as a director of that company since December 1998 and is a member of the audit committee and executive committee of the board. He is also a director of Pennzoil-Quaker States, Charles Schwab Family of Funds, Cooper Industries and Rorento N.V. (Netherlands). From 1988 to 1990, he served as Senior Vice President and Director of Fixed Income and Chairman of the Executive Committee of Underwood Neuhaus & Co. S-17 21 PRINCIPAL AND SELLING UNITHOLDERS The following table sets forth the beneficial ownership of our common units by certain beneficial owners as of April 30, 2001 and as adjusted to give effect to this offering. Other than as set forth below, no person is known by the general partners to own beneficially more than 5% of our common units. All common units involve sole voting and investment power. Northwest Border, the selling unitholder, is a subsidiary of Williams and is one of our three general partners.
BENEFICIAL OWNERSHIP BENEFICIAL OWNERSHIP BEFORE THIS OFFERING AFTER THIS OFFERING(1) ---------------------- ---------------------- COMMON COMMON UNITS SOLD COMMON PRINCIPAL AND SELLING UNITHOLDERS UNITS PERCENTAGE IN THIS OFFERING(1) UNITS PERCENTAGE --------------------------------- --------- ---------- ------------------- --------- ---------- Cub Investment, LLC(2)................ 3,578,779 9.5% -- 3,578,779 8.6% 1221 Avenue of the Americas New York, NY 10020 Enron Corp.(3)........................ 3,215,452 8.5% -- 3,215,452 7.7% 1400 Smith Street Houston, TX 77002 Duke Energy Corp.(4).................. 2,086,500 5.5% -- 2,086,500 5.0% 422 So. Church Street Charlotte, NC 88242-0011 The Williams Companies, Inc.(5)....... 1,123,500 3.0% 455,218 668,282 1.6% One Williams Center Tulsa, OK 74172 Haddington/Chase Energy Partners (Bear Paw) LP(2).......................... 837,395 2.2% -- 837,395 2.0% 2603 Augusta, Suite 1130 Houston, TX 77057
--------------- (1) If the underwriters exercise their over-allotment option in full, the selling unitholder will sell an additional 668,282 common units in this offering and will own no common units after this offering is completed. Please read "Underwriting" for a discussion of the underwriters' over-allotment option. The selling unitholder's general partner interest will not change as a result of this offering. (2) The managing members of Cub Investment are J.P. Morgan Partners and Haddington Energy Partners LP. The general partner of Haddington Energy Partners is Haddington Ventures, L.L.C. Haddington Ventures is also the general partner of Haddington/Chase Energy Partners. J.P. Morgan Partners is a limited partner of Haddington/Chase Energy Partners. The information provided is based on the Schedule 13G filed with the Securities and Exchange Commission by both Cub Investment and Haddington/Chase Energy Partners dated April 6, 2001. (3) Indirect ownership through Northern Plains and Pan Border. (4) Indirect ownership through PEC Midwest L.L.C. (5) Indirect ownership through Northwest Border. Each of the principal and selling unitholders has 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 from the date of this prospectus supplement, without the prior written consent of Salomon Smith Barney Inc. As partial consideration for the acquisition of Bear Paw Energy, we issued 5.7 million common units to the sellers in a private placement. This includes the common units listed above for Cub Investment and Haddington/Chase Energy Partners. We granted the sellers certain registration rights relating to the S-18 22 common units issued, including the right to participate in future offerings. Within 30 days after we complete this offering, we are obligated to file a registration statement with the Securities and Exchange Commission registering the resale of the common units issued to the Bear Paw Energy sellers. The holders of substantially all of the common units issued in the Bear Paw Energy acquisition, including Cub Investment and Haddington/Chase Energy Partners, have agreed that in any event they will not sell their common units prior to the expiration of 90 days from the date of this prospectus supplement. 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. To the extent set forth below and under "Tax Considerations -- Legal Opinions and Advice" in the accompanying prospectuses, 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 prospectuses. 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 partners are 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 734(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 2001 to 2004 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 S-19 23 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. S-20 24 UNDERWRITING Under the terms and 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 and the selling unitholder have agreed to sell to such underwriter, the number of common units set forth opposite the name of such underwriter.
NUMBER OF UNDERWRITERS COMMON UNITS ------------ ------------ Salomon Smith Barney Inc. ............................. UBS Warburg LLC........................................ Banc of America Securities LLC......................... A.G. Edwards & Sons, Inc. ............................. Dain Rauscher Incorporated............................. First Union Securities, Inc. .......................... --------- Total........................................ 4,455,218 =========
The underwriting agreement provides that the obligations of the several underwriters to purchase the common units included in this offering are subject to approval of certain legal matters by counsel and to certain other conditions. The underwriters are obligated to purchase all the common units offered (other than those covered by the over-allotment option described below) if they purchase any of the common units offered. The underwriters propose to offer some of the common units directly to the public at the public offering price set forth on the cover page of this prospectus supplement and some of the units to certain dealers at the public offering price less a concession not in excess of $ per common unit. The underwriters may allow, and such dealers may reallow, a concession not in excess of $ per common unit on sales to certain other dealers. If all of the units are not sold at the initial offering price, the underwriters may change the public offering price and the other selling terms. The selling unitholder has granted to the underwriters an option, exercisable for 30 days from the date of this prospectus supplement, to purchase up to 668,282 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 must purchase a number of additional common units approximately proportionate to the underwriter's initial purchase commitment. The selling unitholder will receive the net proceeds of any sale of common units if the underwriters exercise their right to purchase additional common units under the over-allotment option. 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 from the date of this prospectus supplement, without the prior written consent of Salomon Smith Barney Inc. Our officers, general partners, PEC Midwest, a subsidiary of Duke Energy Corporation, and certain sellers of Bear Paw Energy have entered into similar agreements. Salomon Smith Barney Inc. in its sole discretion may release any of the common units subject to these lock-up agreements at any time without notice. S-21 25 The common units are listed on the New York Stock Exchange under the symbol "NBP." The following table shows the per common unit and total underwriting discounts and commissions to be paid to the underwriters by us and the selling unitholder in connection with this offering. The amounts shown for the selling unitholder assume both no exercise and full exercise of the underwriters' option to purchase additional common units.
PAID BY SELLING UNITHOLDER --------------------------- PAID BY NO NORTHERN BORDER PARTNERS EXERCISE FULL EXERCISE ------------------------ ----------- ------------- Per common unit......................... $ $ $ Total................................... $ $ $
In connection with this offering, Salomon Smith Barney Inc., on behalf of the underwriters, may purchase and sell common units in the open market. These transactions may include over-allotment, syndicate covering transactions and stabilizing transactions. Over-allotment involves syndicate sales of common units in excess of the number of shares to be purchased by the underwriters in the offering, which creates a syndicate short position. Syndicate covering transactions involve purchases of the common units in the open market after the distribution has been completed in order to cover syndicate short positions. Stabilizing transactions consist of certain bids or purchases of common units made for the purpose of preventing or retarding a decline in the market price of the common units while the offering is in progress. The underwriters may also impose a penalty bid. Penalty bids permit the underwriters to reclaim a selling concession from a syndicate member when Salomon Smith Barney Inc., in covering syndicate short positions or making stabilizing purchases, repurchases common units originally sold by that syndicate member. Any of these activities by the underwriters may cause the price of the common units to be higher than the price that otherwise would exist in the open market in the absence of such transactions. These transactions may be effected on the New York Stock Exchange or in the over-the-counter market, or otherwise and, if commenced, may be discontinued by the underwriters at any time. The underwriters have performed certain investment banking and advisory services for us from time to time for which they have received customary fees and expenses. The underwriters may, from time to time, engage in transactions with and perform services for us in the ordinary course of their business. First Union Securities, Inc. is an affiliate of First Union National Bank, Dain Rauscher Incorporated is an affiliate of Royal Bank of Canada, and Banc of America Securities LLC is an affiliate of Bank of America, N.A. First Union Securities, Inc., Dain Rauscher Incorporated and Banc of America Securities LLC will participate in the distribution of the common units offered by this prospectus supplement, and First Union National Bank, Royal Bank of Canada and Bank of America, N.A. are lenders under our credit facility, and we will use the net proceeds of this offering to repay indebtedness outstanding under our credit facility. We estimate that our portion of the total expenses of the offering, excluding underwriting discounts and commissions, will be approximately $500,000. 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 of any of those liabilities. Because the National Association of Securities Dealers, Inc. 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. S-22 26 LEGAL MATTERS Vinson & Elkins L.L.P. will pass upon the validity of the common units being offered and certain federal income tax matters related to the common units. Certain legal matters with respect to the common units will be passed upon for the underwriters by Andrews & Kurth L.L.P. EXPERTS The consolidated financial statements and schedule included in our Annual Report on Form 10-K for the year ended December 31, 2000, incorporated by reference in this prospectus supplement and the accompanying prospectuses, 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. FORWARD LOOKING STATEMENTS This prospectus supplement contains statements that constitute "forward looking statements" within the meaning of Section 27A of the Securities Act and Section 21E of the Securities 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 supplement 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 in the markets served by our pipelines; - availability of supplies of Canadian natural gas and the rate of progress of developing those supplies; - availability and prices of supplies of natural gas in the Powder River, Wind River and Williston Basins and the rate of progress of developing those supplies and developing additional transportation capacity out of the Powder River and Wind River Basins; - political and regulatory developments that impact FERC proceedings involving Northern Border Pipeline and Midwestern; - competitive developments by Canadian and other U.S. natural gas transmission companies; - political and regulatory developments in the United States and in Canada; and - conditions of the capital markets. S-23 27 PROSPECTUS [NORTHERN BORDER PARTNERS LOGO] 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. 28 TABLE OF CONTENTS
PAGE NO. -------- THE OFFERED SECURITIES...................................... A-2 WHERE YOU CAN FIND MORE INFORMATION......................... A-2 CAUTIONARY STATEMENT REGARDING FORWARD LOOKING STATEMENTS... A-3 OUR BUSINESS................................................ A-4 CONFLICTS OF INTEREST AND FIDUCIARY RESPONSIBILITIES........ A-7 FERC REGULATION............................................. A-8 ENVIRONMENTAL AND SAFETY COSTS AND LIABILITIES.............. A-11 COMMON UNITS................................................ A-11 DEBT SECURITIES............................................. A-12 RATIO OF EARNINGS TO FIXED CHARGES.......................... A-15 USE OF PROCEEDS............................................. A-15 TAX CONSIDERATIONS.......................................... A-15 PLAN OF DISTRIBUTION........................................ A-29 LEGAL MATTERS............................................... A-30 EXPERTS..................................................... A-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 A-2 29 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. A-3 30 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, A-4 31 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 A-5 32 - 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 A-6 33 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. A-7 34 - 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. A-8 35 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 A-9 36 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 A-10 37 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. A-11 38 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. A-12 39 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 A-13 40 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. A-14 41 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. A-15 42 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; A-16 43 - 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. A-17 44 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. A-18 45 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. A-19 46 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 A-20 47 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 A-21 48 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 A-22 49 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 A-23 50 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. A-24 51 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 A-25 52 ("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 A-26 53 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% A-27 54 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, A-28 55 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. A-29 56 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. A-30 57 PROSPECTUS 3,210,000 COMMON UNITS NORTHERN BORDER PARTNERS, L.P. REPRESENTING LIMITED PARTNER INTERESTS [NORTHERN BORDER PARTNERS LOGO] ------------------------ 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 our Common Units that may be offered by the offering unitholders. Each time these Common Units are offered by the offering unitholders, we will provide you a prospectus supplement that will contain specific information about the terms of the offering. The prospectus supplement may also add, update or change information in the prospectus. We will not receive any of the proceeds from the sale of Common Units by the offering unitholders. 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 SPECIFIC TERMS OF OFFERINGS 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 COMMON UNITS. 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 COMMON UNITS, AND IT IS NOT SOLICITING AN OFFER TO BUY THESE COMMON UNITS, IN ANY STATE WHERE THE OFFER OR SALE IS NOT PERMITTED. TO UNDERSTAND US AND THE TERMS OF OUR COMMON UNITS, 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. 58 TABLE OF CONTENTS
PAGE NO. ---- THE OFFERED SECURITIES...................................... B-2 WHERE YOU CAN FIND MORE INFORMATION......................... B-2 CAUTIONARY STATEMENT REGARDING FORWARD LOOKING STATEMENTS... B-3 OUR BUSINESS................................................ B-4 CONFLICTS OF INTEREST AND FIDUCIARY RESPONSIBILITIES........ B-7 FERC REGULATION............................................. B-8 ENVIRONMENTAL AND SAFETY COSTS AND LIABILITIES.............. B-11 COMMON UNITS................................................ B-11 USE OF PROCEEDS............................................. B-12 TAX CONSIDERATIONS.......................................... B-12 OFFERING UNITHOLDERS........................................ B-26 PLAN OF DISTRIBUTION........................................ B-27 LEGAL MATTERS............................................... B-27 EXPERTS..................................................... B-27
THE OFFERED SECURITIES This prospectus is part of a registration statement (No. 333-72351) that we filed with the SEC using a "shelf" registration process. Under this shelf process, Northwest Border Pipeline Company and Panhandle Eastern Pipe Line Company (together the "offering unitholders") may offer from time to time up to 3,210,000 Common Units representing limited partner interests. Each time the Common Units are offered, we will provide you with a prospectus supplement that will describe, among other things, the specific amounts and prices of the Common Units 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 Common Units, 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. SEC filings are also 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 B-2 59 Securities Exchange Act of 1934 (the "Exchange Act") until all offerings under this registration statement 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: Secretary Division Northern Border Partners, L.P. 1400 Smith Street, Houston, Texas 77002 Telephone: 713-853-6161 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 operation; 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. B-3 60 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"). B-4 61 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, 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 2373 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 1300 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; B-5 62 - Midwestern Gas Transmission Company near Channahon, Illinois; and - 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 B-6 63 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 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. B-7 64 - 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. - 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 B-8 65 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. 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 B-9 66 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 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 B-10 67 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 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. B-11 68 Transfer Agent and Registrar Our transfer agent and registrar for the Common Units is First Chicago Trust Company of New York. USE OF PROCEEDS Unless otherwise indicated to the contrary in an accompanying prospectus supplement, the net proceeds to be received by the offering unitholders from the sale of the common units will be used by each offering unitholder within its sole discretion. 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. 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 B-12 69 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; - 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. B-13 70 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. 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. B-14 71 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 Unit 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. 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 only deduct losses from passive activities (generally, activities in which the taxpayer does not materially participate) that are not in excess of the taxpayer's B-15 72 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 only be available 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. 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 B-16 73 by some of our unitholders, but these allocations may not be respected. 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 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 B-17 74 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 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 B-18 75 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 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. B-19 76 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 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 B-20 77 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. 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 B-21 78 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 ("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 B-22 79 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 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 B-23 80 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% 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 Persons who hold an interest in us as a nominee for another person are required to furnish to us: - The name, address and taxpayer identification number of the beneficial owners 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; B-24 81 - 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, 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 B-25 82 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. OFFERING UNITHOLDERS The table below sets forth the following information with respect to each offering unitholder: (1) the number of Common Units and the percentage of the outstanding Common Units owned of record; (2) the number of Common Units being offered hereby; and (3) the number of Common Units to be owned of record upon completion of the offerings under this registration statement.
OWNERSHIP AFTER OWNERSHIP BEFORE OFFERING OFFERING ------------------ ------------------- UNITS TO NAME UNITS PERCENT BE SOLD SHARES ---- --------- ------- --------- ------ Panhandle Eastern Pipe Line Company(1)................. 2,086,500 7.1 2,086,500 -- Northwest Border Pipe Line Company(2)(3)............... 1,123,500 3.8 1,123,500 --
--------------- (1) Panhandle Eastern Pipe Line Company has provided a guaranty for 150 MMcfd of PAGUS' contracted capacity through October 31, 2001. (2) Northwest Border Pipeline Company, a wholly-owned subsidiary of The Williams Companies, Inc., serves as one of our three General Partners as described above under "Our Business." (3) Transcontinental Gas Pipe Line Corporation, a subsidiary of The Williams Companies, Inc., is one of our shippers. See "Conflicts of Interest and Fiduciary Responsibilities." B-26 83 PLAN OF DISTRIBUTION Under this prospectus, the offering unitholders intend to offer Common Units to the public through one or more broker-dealers, through underwriters, or directly to investors. The offering unitholders will fix a price or prices, and they may change the price of the Common Units 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. The offering unitholders 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 Common Units as principal and thereafter resell such Common Units 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, or in private transactions. Broker-dealers or underwriters may receive compensation in the form of underwriting discounts or commissions and may receive commissions from purchasers of the Common Units for whom they may act as agents. If any broker-dealer purchases the Common Units as principal, it may effect resales of the Common Units 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 Common Units 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 that the offering unitholders will allow or pay to the underwriters, if any, and the discounts and commissions that the underwriters 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 Common Units may also be customers of, engage in transactions with, or perform services for the offering unitholders or their affiliates or us 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 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. will pass upon the validity of the Common Units offered in this prospectus and the material federal income tax considerations regarding the Common Units. 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. B-27 84 PROSPECTUS NORTHERN BORDER PARTNERS, L.P. COMMON UNITS REPRESENTING LIMITED PARTNER INTERESTS ------------------------ This Prospectus relates to Common Units representing limited partner interests in Northern Border Partners, L.P., a Delaware limited partnership (the "Partnership"), which may be offered from time to time by the Partnership at prices and on terms to be determined at the time of each offering hereunder and to be set forth in a supplement to this Prospectus (a "Prospectus Supplement"). The Common Units may be offered through underwriters, brokers or dealers, or directly to investors at a fixed price or prices, which may be changed from time to time, at market prices prevailing at the time of such sale, at prices related to such market prices or at negotiated prices, and in connection therewith distributors' or sellers' commissions may be paid or allowed, which will not exceed those customary in the types of transactions involved. Brokers or dealers may act as agent for the Partnership, or may purchase Common Units from the Partnership as principal and thereafter resell such units from time to time in or through transactions or distributions (which may involve crosses and block transactions) on the New York Stock Exchange or other United States or foreign stock exchanges where unlisted trading privileges are available, in the over-the-counter market, in private transactions or in some combination of the foregoing. The Partnership will receive the net proceeds of any such sale which will be set forth in the Prospectus Supplement. See "Plan of Distribution." The Partnership's Common Units are listed on the New York Stock Exchange under the symbol "NBP". On December 1, 1997, the last reported sales price of the Common Units on the New York Stock Exchange was $34.375 per Common Unit. ------------------------ THESE SECURITIES HAVE NOT BEEN APPROVED OR DISAPPROVED BY THE SECURITIES AND EXCHANGE COMMISSION OR ANY STATE SECURITIES COMMISSION NOR HAS THE SECURITIES AND EXCHANGE COMMISSION OR ANY STATE SECURITIES COMMISSION PASSED UPON THE ACCURACY OR ADEQUACY OF THIS PROSPECTUS. ANY REPRESENTATION TO THE CONTRARY IS A CRIMINAL OFFENSE. ------------------------ THE DATE OF THIS PROSPECTUS IS DECEMBER 5, 1997. 85 NO DEALER, SALESMAN OR OTHER PERSON HAS BEEN AUTHORIZED TO GIVE ANY INFORMATION OR TO MAKE ANY REPRESENTATION NOT CONTAINED IN, OR INCORPORATED BY REFERENCE IN, THIS PROSPECTUS, AND, IF GIVEN OR MADE, SUCH INFORMATION OR REPRESENTATION MUST NOT BE RELIED UPON AS HAVING BEEN AUTHORIZED BY THE PARTNERSHIP. THIS PROSPECTUS DOES NOT CONSTITUTE AN OFFER TO SELL OR A SOLICITATION OF AN OFFER TO BUY ANY OF THE SECURITIES OFFERED HEREBY IN ANY JURISDICTION TO ANY PERSON TO WHOM IT IS UNLAWFUL TO MAKE SUCH OFFER OR SOLICITATION IN SUCH JURISDICTION. NEITHER THE DELIVERY OF THIS PROSPECTUS NOR ANY SALE MADE HEREUNDER SHALL, UNDER ANY CIRCUMSTANCES, CREATE ANY IMPLICATION THAT THE INFORMATION HEREIN IS CORRECT AS OF ANY TIME SUBSEQUENT TO THE DATE HEREOF OR THAT THERE HAS BEEN NO CHANGE IN THE AFFAIRS OF THE PARTNERSHIP SINCE SUCH DATE. AVAILABLE INFORMATION The Partnership is subject to the informational requirements of the Securities Exchange Act of 1934 (the "Exchange Act"), and in accordance therewith files reports, proxy statements and other information with the Securities and Exchange Commission (the "Commission"). Such reports, proxy statements and other information can be inspected and copied at the public reference facilities maintained by the Commission at Room 1024, 450 Fifth Street, N.W., Washington, D.C. 20549; and at the following Regional Offices of the Commission: Midwest Regional Office, 500 West Madison Street, Suite 1400, Chicago, Illinois 60661; and Northeast Regional Office, 7 World Trade Center, Suite 1300, New York, New York 10048. Copies of such material can also be obtained from the Public Reference Section of the Commission at 450 Fifth Street, N.W., Room 1024, Washington, D.C. 20549, at prescribed rates or from the site maintained by the Commission on the Internet World Wide Web at http://www.sec.gov. The Partnership's Common Units are listed on the New York Stock Exchange, and reports, proxy statements and other information concerning the Partnership can be inspected and copied at the offices of such exchange at 20 Broad Street, New York, New York 10005. This Prospectus constitutes a part of a Registration Statement on Form S-3 (together with all amendments and exhibits thereto, the "Registration Statement") filed by the Partnership with the Commission under the Securities Act of 1933 (the "Securities Act") with respect to the Common Units offered hereby. This Prospectus does not contain all of the information set forth in such Registration Statement, certain parts of which are omitted in accordance with the rules and regulations of the Commission. Reference is made to such Registration Statement and to the exhibits relating thereto for further information with respect to the Partnership and the Common Units offered hereby. Any statements contained herein concerning the provisions of any document filed as an exhibit to the Registration Statement or otherwise filed with the Commission or incorporated by reference herein are not necessarily complete, and in each instance reference is made to the copy of such document so filed for a more complete description of the matter involved. Each such statement is qualified in its entirety by such reference. IN CONNECTION WITH THIS OFFERING, UNDERWRITERS, BROKERS OR DEALERS PARTICIPATING IN THE OFFERING MAY OVER-ALLOT OR EFFECT TRANSACTIONS WHICH STABILIZE OR MAINTAIN THE MARKET PRICE OF THE COMMON UNITS 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. C-2 86 INCORPORATION OF CERTAIN DOCUMENTS BY REFERENCE The following documents filed with the Commission by the Partnership (File No. 1-12202) pursuant to Section 13(a) of the Exchange Act are incorporated herein by reference as of their respective dates: (a) Annual Report on Form 10-K for the year ended December 31, 1996; and (b) Quarterly Reports on Form 10-Q for the quarters ended March 31, 1997, June 30, 1997, and September 30, 1997. Each document filed by the Partnership pursuant to Section 13(a), 13(c), 14 or 15(d) of the Exchange Act subsequent to the date of this Prospectus and prior to the termination of the offering of the Common Units pursuant hereto shall be deemed to be incorporated herein by reference and to be a part hereof from the date of filing of such document. Any statement contained herein or in a document all or a portion of which is incorporated or deemed to be incorporated by reference herein shall be deemed to be modified or superseded for purposes of this Prospectus to the extent that a statement contained herein or in any other subsequently filed document which also is or is deemed to be incorporated by reference herein modifies or supersedes such statement. Any statement so modified or superseded shall not be deemed, except as so modified or superseded, to constitute a part of this Prospectus. The Partnership will provide without charge to each person to whom a copy of this Prospectus is delivered, on the request of any such person, a copy of any or all of the foregoing documents incorporated herein by reference other than exhibits to such documents (unless such exhibits are specifically incorporated by reference into the documents that this Prospectus incorporates). Written or telephone requests for such copies should be directed to Secretary Division, Northern Border Partners, L.P., at its principal executive offices, 1400 Smith Street, Houston, Texas 77002 (telephone: 713-853-6161). INFORMATION REGARDING FORWARD LOOKING STATEMENTS The statements in this Prospectus that are not historical are forward looking statements within the meaning of Section 27A of the Securities Act and Section 21E of the Exchange Act. Such forward looking statements include the discussions in "The Chicago Project", "Demand For Transportation Capacity" and "Description of Units". Although the Partnership believes that its expectations regarding future events are based on reasonable assumptions within the bounds of its knowledge of its business, it can give no assurance that its goals will be achieved or that its expectations regarding future expansions and distribution increases will be realized. Important factors that could cause actual results to differ materially from those in the forward looking statements herein include political and regulatory developments that impact the Federal Energy Regulatory Commission (the "FERC") and state utility commission proceedings, success of Northern Border Pipeline Company ("Northern Border Pipeline") in sustaining its positions in such proceedings or the success of intervenors in opposing Northern Border Pipeline's positions, Northern Border Pipeline's timely completion and start of operations with no significant cost overruns for The Chicago Project, competitive developments by Canadian and other U.S. natural gas transmission companies, political and regulatory developments in Canada and conditions of the capital markets and equity markets during the periods covered by the forward looking statements. C-3 87 BUSINESS GENERAL Northern Border Partners, L.P. through a subsidiary limited partnership, Northern Border Intermediate Limited Partnership, collectively referred to herein as "Partnership", owns a 70% general partner interest in Northern Border Pipeline, a Texas general partnership. The remaining general partner interests in Northern Border Pipeline are owned by TransCanada Border PipeLine Ltd. (6%) and TransCan Northern Ltd. (24%), both of which are wholly-owned subsidiaries of TransCanada PipeLines Limited ("TransCanada"). Northern Plains Natural Gas Company ("Northern Plains"), Pan Border Gas Company ("Pan Border") and Northwest Border Pipeline Company ("Northwest Border") serve as the general partners (the "General Partners") of the Partnership. Northern Plains is a wholly-owned subsidiary of Enron Corp., Pan Border is a wholly-owned subsidiary of Duke Energy Corporation, and Northwest Border is a wholly-owned subsidiary of The Williams Companies, Inc. The General Partners hold an aggregate 2% general partner interest in the Partnership. The General Partners also own in the aggregate an effective 24% subordinated limited partner interest ("Subordinated Units") in the Partnership. The combined general and limited partner interests in the Partnership of Northern Plains, Pan Border and Northwest Border are 13.0%, 8.5% and 4.5%, respectively. Northern Border Pipeline owns a 969-mile U.S. interstate pipeline system (the "Pipeline System") that transports natural gas from the Montana-Saskatchewan border near Port of Morgan, Montana, to interconnecting pipelines in the state of Iowa. The Pipeline System has pipeline access to natural gas reserves in the provinces of Alberta, British Columbia and Saskatchewan, as well as the Williston Basin in the United States. The Pipeline System also has access to production of synthetic gas from the Dakota Gasification Plant in North Dakota. Management of Northern Border Pipeline is overseen by the Northern Border Management Committee, which is comprised of three representatives from the Partnership (one selected by each General Partner) and one representative from the TransCanada subsidiaries. The Pipeline System is operated by Northern Plains pursuant to an operating agreement. Northern Plains employs approximately 185 individuals. These employees are located at the operating headquarters in Omaha, Nebraska, and at locations along the pipeline route. Northern Border Pipeline's revenues are derived from agreements for the receipt and delivery of gas at points along the Pipeline System as specified in each shipper's individual transportation contract. Northern Border Pipeline transports gas for shippers under a tariff regulated by the FERC. As a result of acquisitions during 1996 and 1997, the Partnership has an ownership position of 71.75% in Black Mesa Holdings, Inc. Black Mesa Holdings, Inc., through its wholly-owned subsidiary, Black Mesa Pipeline Company, owns a 273-mile, 18-inch diameter coal slurry pipeline which originates at a coal mine in Kayenta, Arizona. The pipeline traverses westward through northern Arizona to the 1,500 megawatt Mohave Power Station located in Laughlin, Nevada. The pipeline is operated by Williams Technologies, Inc., a wholly-owned subsidiary of the Partnership, that was acquired in May 1997. C-4 88 Following is a chart showing the organization and structure of the Partnership and its interest in Northern Border Pipeline. NORTHERN BORDER PARTNERS, L.P. ORGANIZATION STRUCTURE GRAPHIC THE PIPELINE SYSTEM The 822-mile portion of the Pipeline System from the Canadian border to Ventura, Iowa was completed and placed in service in 1982. It was built to transport large quantities of natural gas through large diameter, high operating pressure pipe. In 1992, a 30-inch diameter pipeline, approximately 147 miles in length, was acquired and placed in service. This pipeline interconnects with the original system near Ventura, Iowa and terminates near Harper, Iowa where it interconnects with the facilities of Natural Gas Pipeline Company of America ("NGPL"). There are seven existing compressor stations on the Pipeline System. Other facilities include three pipeline field offices and warehouses, five measurement stations and 39 microwave tower sites. The throughput capacity of the Pipeline System is 1,675 million cubic feet per day ("MMCFD"). 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 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. The Pipeline System interconnects at multiple points with the pipeline facilities of an Enron subsidiary, Northern Natural Gas Company. At its southern end, the Pipeline System interconnects with the pipeline facilities of NGPL near Harper, Iowa. THE CHICAGO PROJECT Northern Border Pipeline has commenced construction pursuant to a certificate of public convenience and necessity issued by the FERC on August 1, 1997 authorizing the construction and operation of facilities ("The Chicago Project") to extend and expand its existing system. The estimated cost of the facilities to be constructed is approximately $839 million. New transportation contracts provide for receipts into the Pipeline System of 700 MMCFD with 648 MMCFD to be transported through the pipeline extension and 516 MMCFD to be delivered at Harper, Iowa for transport by NGPL on its pipeline. Requests for rehearing of the August 1, 1997 order were filed by five parties requesting the FERC to reconsider the determination of how the rates and charges for the extension of the pipeline from Harper, Iowa to Chicago, Illinois will be calculated and the determination of certain locations of the pipeline route. On November 17, 1997, the FERC issued an order which denied all rehearing requests. A petition, filed C-5 89 by NGPL, for review of the August order is pending in the United States Court of Appeals for the District of Columbia. Any petitions for judicial review of the November 17, 1997 order must be filed within 60 days of the date of the order. NGPL received a companion certificate of public convenience and necessity from the FERC on August 1, 1997 to construct and operate certain facilities to increase its pipeline system capacity to accommodate the new deliveries at Harper, Iowa from Northern Border Pipeline. Funds required to meet The Chicago Project capital expenditures for 1997 and 1998 are expected to be provided primarily by a $750 million revolving credit facility of Northern Border Pipeline, capital contributions from the Partnership and the TransCanada subsidiaries and internal sources. The Partnership capital contributions will be funded through an interim credit facility of $175 million and proceeds of offerings pursuant to the registration statement of which this prospectus is a part. DEMAND FOR TRANSPORTATION CAPACITY Based upon existing contracts and capacity, 100% of the Pipeline System's firm capacity (at current compression) is contractually committed through October 2001. In conjunction with a settlement of a rate issue on an upstream pipeline, Northern Border Pipeline's largest shipper, Pan-Alberta Gas (U.S.) Inc., has indicated its intent to enter into a two year extension of its transportation contracts covering 741 MMCFD of capacity. If these contract extensions are implemented, the term of the contracts would be extended to October 31, 2003. At the present time, 6% of the firm capacity (based on annual cost of service obligations) is contracted by interstate pipelines, 91% by producers/marketers, and 3% by local distribution companies. In 1996, approximately 87% of the natural gas transported by the Pipeline System was produced in the Western Canadian Sedimentary Basin located in the provinces of Alberta, British Columbia and Saskatchewan. The Pipeline System's share of Canadian gas exported to the United States was approximately 20% in 1996. On November 17, 1997 Northern Border Pipeline announced to its customers the commencement of an open season during which customers may submit requests for capacity on a new expansion of the Pipeline System. If sufficient requests are submitted, a specific project may be proposed with a targeted in-service date of November 1, 2000. The results of this open season should be known at the end of January 1998, unless the open season is further extended. It is within Northern Border Pipeline's discretion to determine the scope of and to design the proposed project and Northern Border Pipeline intends to limit the size of this project, if necessary, in order to maintain its competitive rates and a high level of contracted capacity. Currently two potentially competitive natural gas pipeline projects are pending regulatory approval, financing and construction. If either or both of these projects were to be authorized, financed and constructed they would directly compete with Northern Border Pipeline in the transportation of natural gas from the Western Canadian Sedimentary Basin to markets in the United States. The first proposed project, known as the Alliance Pipeline, received preliminary, non-environmental approval from the FERC in August 1997. The FERC determination was subject to final environmental analysis and approval and the receipt by Alliance Pipeline of regulatory approval from the National Energy Board of Canada (the "NEB"). Requests for rehearing of the FERC's preliminary order are currently pending before the FERC. Regulatory proceedings before the NEB have commenced; however a decision from the NEB is not expected before the second quarter of 1998. Environmental analysis of the Alliance Pipeline is ongoing at the FERC and will likely be completed in 1998. The second competitive proposal is known as Transvoyageur-Viking-Voyageur project. The application for this project was filed at the FERC in November 1997. Project sponsors have indicated that the application for the Canadian segment of this project is expected to be filed with the NEB in 1998. Both Alliance Pipeline and the Transvoyageur-Viking-Voyageur project proposed to originate their respective pipelines in western Canada and terminate in the vicinity of Chicago, Illinois. Either of these projects could be in-service by the year 2000 if timely regulatory approvals are received and if other conditions are satisfied. C-6 90 FERC REGULATION General Northern Border Pipeline is subject to extensive regulation by the FERC as a "natural gas company" under the Natural Gas Act (the "NGA"). Under the NGA and the Natural Gas Policy Act, the FERC has jurisdiction over Northern Border Pipeline with respect to virtually all aspects of its business, including transportation of gas, rates and charges, construction of new facilities, extension or abandonment of service and facilities, accounts and records, depreciation and amortization policies, the acquisition and disposition of facilities, the initiation and discontinuation of services, and certain other matters. 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 charge per dekatherm-mile of capacity contracted, calculated under a cost of service tariff. Similarly during any given month, the shippers' obligations to pay their allocable share of the cost of service is not dependent upon the percentage of available capacity actually used. Northern Border Pipeline may not charge or collect more than its cost of service determined pursuant to its tariff on file with the FERC. Northern Border Pipeline also provides interruptible transportation service. The maximum rate charged to interruptible shippers is calculated from cost of service estimates on the basis of contracted capacity. All revenue from the interruptible transportation service is credited to the cost of service. In November 1995, Northern Border Pipeline filed a rate case in compliance with its FERC tariff for the determination of its allowed equity rate of return. In this proceeding, Northern Border Pipeline reached a settlement accord with shippers holding in excess of 90% of the aggregate contracted firm capacity as of October 15, 1996 (the "Shippers") and filed for FERC approval of a Stipulation and Agreement ("Stipulation") to settle its rate case. The Stipulation was approved by the FERC in August 1997. The Stipulation allows Northern Border Pipeline to retain its 12.75% equity rate of return through September 30, 1996, and a 12% rate beginning October 1, 1996. In addition, the depreciation rates applied to Northern Border Pipeline's gross transmission plant were reduced effective June 1, 1996, from 3.6% to 2.7%. Beginning January 1, 1997, the depreciation rate is reduced to 2.5%. Under the Stipulation, the Shippers agreed that for at least seven years following the completion of The Chicago Project, Northern Border Pipeline may continue to calculate its allowance for income taxes as a part of its cost of service in the manner it has historically used. Also, under the Stipulation, in connection with the completion of The Chicago Project, Northern Border Pipeline will implement a new depreciation schedule with an extended depreciable life, a capital project cost containment mechanism and a $31 million settlement adjustment mechanism. The settlement adjustment mechanism would effectively reduce the allowed return on rate base. In October 1997, Northern Border Pipeline made refunds to its shippers in the amount of $52.6 million reflected as an accumulated provision for rate refund in the September 30, 1997 consolidated balance sheet drawing on an existing $750 million revolving credit facility and utilizing cash on hand. USE OF PROCEEDS Unless otherwise indicated in an accompanying Prospectus Supplement, the net proceeds to be received by the Partnership from the sale of the Common Units will be available for capital contribution to Northern Border Pipeline by the Partnership for The Chicago Project and for general business purposes and may be used for repayment of debt, future acquisitions, capital expenditures and working capital. DESCRIPTION OF THE UNITS Generally, the Common Units and the Subordinated Units represent limited partner interests in the Partnership, which entitle the holders thereof to participate in Partnership distributions and exercise the rights or privileges available to limited partners under the Amended and Restated Partnership Agreement of the Partnership. The Subordinated Units are a separate class of interests in the Partnership, and their rights to participate in distributions differ from those rights of the holders of Common Units. C-7 91 The primary objective of the Partnership is to generate cash from Partnership operations and to distribute Available Cash to its partners in the manner described herein. "Available Cash" generally means, with respect to any calendar quarter, the sum of all of the cash received by the Partnership from all sources, adjusted for cash disbursements and net changes to cash reserves. The Partnership Policy Committee's decisions regarding amounts to be placed in or released from cash reserves will have a direct impact on the amount of Available Cash because increases and decreases in cash reserves are taken into account in computing Available Cash. The Partnership Policy Committee may, in its reasonable discretion (subject to certain limits), determine the amounts to be placed in or released from cash reserves each quarter. Cash distributions will be characterized as either distributions of Cash from Operations or Cash from Interim Capital Transactions. This distinction affects the amounts distributed to Unitholders relative to the General Partners, and under certain circumstances it determines whether holders of Subordinated Units receive any distributions. Cash from Operations generally refers to the cash balance of the Partnership on the date the Partnership commenced operations, plus all cash generated by the operations of the Partnership's businesses (which consists primarily of cash distributions to the Partnership by Northern Border Pipeline attributable to operations of the Pipeline System), after deducting related cash expenditures, cash reserves, debt service and certain other items. For any given quarter, Available Cash will be distributed to the General Partners and to the holders of Common Units, and it may also be distributed to the holders of Subordinated Units depending upon the amount of Available Cash for the quarter, amounts distributed in prior quarters and other factors discussed below. The Partnership will make distributions to its partners with respect to each calendar quarter prior to liquidation of the Partnership in an amount equal to 100% of its Available Cash for such quarter. The distribution of Available Cash that constitutes Cash from Operations with respect to each calendar quarter during the Subordination Period is subject to the rights of the holders of the Common Units to receive the Minimum Quarterly Distribution ($0.55 per Unit), plus any Common Unit Arrearages, prior to any distribution of Available Cash to holders of Subordinated Units with respect to such quarter. The terms "Subordination Period" and "Common Unit Arrearages" are defined in the Amended and Restated Agreement of Limited Partnership. Common Units will not accrue Common Unit Arrearages for any quarter after the Subordination Period, and Subordinated Units will not accrue any arrearages with respect to distributions for any quarter. On November 19 ,1997, the Partnership announced its intention to increase its quarterly cash distribution by $0.05 per Unit by the fourth quarter 1998, with half of this increase effected with the fourth quarter, 1997 distribution payable in February 1998. The Partnership anticipates the increase will result from the effects of The Chicago Project and will be dependent upon its timely completion with no significant cost overruns. The indicated annual rate would increase from $2.20 to $2.40. The Subordination Period extends from October 1, 1993 until the Conversion Date. The "Conversion Date" is the date on which the first of any one of the following occurs: the first day of any calendar quarter that occurs on or after January 1, 1999 and prior to January 1, 2004 and on which both of the following tests are met: (i) cumulative capital expenditures by the Partnership (directly or through its 70% interest in Northern Border Pipeline) subsequent to October 1, 1993 and prior to such day equal or exceed $248 million, and (ii) the Partnership has distributed the Minimum Quarterly Distribution on all Common Units and Subordinated Units for each of the eight consecutive calendar quarters immediately prior to such day; the first day of any calendar quarter that occurs on or after January 1, 2004 and on which the following tests are met: (i) cumulative capital expenditures by the Partnership (directly or C-8 92 through its 70% interest in Northern Border Pipeline) subsequent to October 1, 1993 and prior to such day equal or exceed $248 million and (ii) there are no Common Unit Arrearages; and the first day of any calendar quarter that occurs on or after January 1, 2004 and on which the following test is met: the Partnership has distributed the Minimum Quarterly Distribution on all Common Units and Subordinated Units for each of the 20 consecutive calendar quarters immediately prior to such day. In addition, the Partnership Agreement contains provisions intended to discourage a person or group from attempting to remove the General Partners as general partners of the Partnership or otherwise change management of the Partnership. Among them is a provision that if a General Partner is removed other than for cause the Subordination Period will end. As of the end of the Subordination Period, each Subordinated Unit will convert into a Common Unit and will participate pro rata with other outstanding Common Units in all cash distributions on Common Units. The transfer agent and registrar for the Common Units is First Chicago Trust Company of New York. TAX CONSIDERATIONS This section is a summary of certain federal income tax considerations that may be relevant to prospective Unitholders and, to the extent set forth below under "Tax Considerations -- Legal Opinions and Advice," represents the opinion of Vinson & Elkins L.L.P., counsel to the Partnership ("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, as amended ("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 to "Partnership" are references to both the Partnership and the Northern Border Intermediate Limited Partnership (The "Intermediate Partnership"). No attempt has been made in the following discussion to comment on all federal income tax matters affecting the Partnership or the Unitholders. Moreover, the discussion focuses on 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, each prospective Unitholder should consult, and should depend on, his own tax advisor in analyzing the federal, state, local and foreign tax consequences of the purchase, ownership or disposition of Common Units. 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 (i) the Partnership (including the Intermediate Partnership) and Northern Border Pipeline each will be treated as a partnership, and (ii) owners of Common Units (with certain exceptions, as described in "Limited Partner Status" below) will be treated as partners of the Partnership (but not the Intermediate 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 the Partnership 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 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 the Partnership or the Unitholders. An opinion of counsel C-9 93 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 the Unitholders and the General Partners. Furthermore, no assurance can be given that the treatment of the Partnership or an investment therein will not be significantly modified by future legislative or administrative changes or court decisions. Any such modification may or may not be retroactively applied. RECENT TAX LEGISLATION Congress recently enacted, and the President signed into law on August 5, 1997, the Taxpayer Relief Act of 1997 (the "TRA of 1997"). The new legislation contains several provisions which have an impact on the Partnership and its Partners. The TRA of 1997 generally reduces the maximum capital gains rate for an individual from 28% to 20% for capital assets held at least eighteen months. In addition, the TRA of 1997 would alter the tax reporting system and the deficiency collection system applicable to large partnerships and would make certain additional changes to the treatment of large partnerships, such as the Partnership. These provisions are intended to simplify the administration of the tax rules governing such entities. The application of some of these new provisions are optional and the Partnership Policy Committee has not determined whether the Partnership will elect to have these provisions apply to the Partnership and its Partners. 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 income, gain, loss, deduction and credit of the Partnership 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, the Partnership 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 (1) the entity had a reasonable basis for the claimed classification; (2) the entity recognized the federal tax consequences of any change in classification within five years prior to January 1, 1997; and (3) 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 the Partnership 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 the Partnership and the General Partners, including: (a) Neither the Partnership nor Northern Border Pipeline will elect to be treated as an association taxable as a corporation; (b) A representation and covenant of the Partnership that, the Partnership has been and will be operated in accordance with all applicable partnership statutes and the Partnership Agreement and in the manner described herein; (c) A representation and covenant of the Partnership that, 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 income, gain, loss, deduction or credit of the Partnership and the Intermediate Partnership equal to at least 1% at all times during the existence of the Partnership and the Intermediate Partnership; C-10 94 (d) 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 the Partnership and in the Intermediate Partnership equal to 1% of the total positive capital account balances of the Partnership and the Intermediate Partnership; (e) A representation and covenant of the Partnership that, for each taxable year, less than 10% of the gross income of the Partnership 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 (f) A representation and covenant of the Partnership that Northern Border Pipeline is organized and will be operated in accordance with the Texas Uniform Partnership Act and the Northern Border Pipeline Partnership Agreement. Counsel's opinion as to the partnership classification of the Partnership 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." The Partnership has represented that in excess of 90% of its 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 the Partnership's gross income derived from these sources constitutes "qualifying income." If the Partnership fails to meet the Natural Resource Exception (other than a failure determined by the IRS to be inadvertent which is cured within a reasonable time after discovery), the Partnership will be treated as if it had transferred all of its assets (subject to liabilities) to a newly-formed corporation (on the first day of the year in which it fails 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 the Partnership. This contribution and liquidation should be tax-free to Unitholders and the Partnership, so long as the Partnership, at such time, does not have liabilities in excess of the basis of its assets. Thereafter, the Partnership would be treated as a corporation for federal income tax purposes. If the Partnership 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, its items of income, gain, loss, deduction and credit would be reflected only on its tax return rather than being passed through to the Unitholders, and its 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 the Partnership's 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, treatment of either the Partnership or the Intermediate Partnership 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 the Partnership will be classified as a partnership for federal income tax purposes. C-11 95 LIMITED PARTNER STATUS Unitholders who have become limited partners will be treated as partners of the Partnership 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) 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 of the Partnership 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 in the Partnership 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 UNIT OWNERSHIP Flow-through of Taxable Income No federal income tax will be paid by the Partnership. Instead, each Unitholder will be required to report on his income tax return his allocable share of the income, gains, losses and deductions of the Partnership without regard to whether corresponding cash distributions are received by such Unitholder. Consequently, a Unitholder may be allocated income from the Partnership although he has not received a cash distribution in respect of such income. Treatment of Partnership Distributions Distributions by the Partnership 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 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 Unitholder's share of the Partnership's 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 Unit plus his share of Partnership nonrecourse liabilities. The initial tax basis for a Common Unit will be increased by the Unitholder's share of Partnership income and by any increase in the Unitholder's share of Partnership nonrecourse liabilities. The basis for a Common Unit will be decreased (but not below zero) by distributions from the Partnership, including any decrease in the Unitholder's share of Partnership nonrecourse liabilities, by the Unitholder's share of Partnership losses and by the Unitholder's share of C-12 96 expenditures of the Partnership that are not deductible in computing its taxable income and are not required to be capitalized. A Unitholder's share of nonrecourse liabilities will be generally based on the Unitholder's share of the Partnership's profits. Limitations on Deductibility of Partnership Losses To the extent losses are incurred by the Partnership, a Unitholder's share of deductions for the losses will be limited to the tax basis of the Unitholder's Units or, in the case of an individual Unitholder or a corporate Unitholder if more than 50% in the value of its stock is owned directly or indirectly by five or fewer individuals or certain taxexempt organizations, to the amount which the Unitholder is considered to be "at risk" with respect to the Partnership's activities, if that is less than the Unitholder's basis. A Unitholder must recapture losses deducted in previous years to the extent that Partnership 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 Units, but this will be less than the Unitholder's basis for his Units by the amount of the Unitholder's share of any nonrecourse liabilities of the Partnership. A Unitholder's at risk amount will increase or decrease as the basis of the Unitholder's Units increases or decreases except that changes in nonrecourse liabilities of the Partnership 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 only deduct 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 the Partnership, if any, will only be available to offset future income generated by the Partnership 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 which are not deductible because they exceed the Unitholder's income generated by the Partnership may be deducted in full when the Unitholder disposes of his entire investment in the Partnership 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 net income from the Partnership may be offset by any suspended passive losses from the Partnership, 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 which 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, a Unitholder's net passive income from the Partnership will be treated as investment income for this purpose. In addition, the Unitholder's share of the Partnership's portfolio income will be treated as investment income. Investment interest expense includes (i) interest on indebtedness properly allocable to property held for investment, (ii) a partnership's interest expense attributed to portfolio income and (iii) 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 Unit to the extent attributable to portfolio income of the Partnership. Net investment income includes gross income from property held for C-13 97 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. ALLOCATION OF PARTNERSHIP INCOME, GAIN, LOSS AND DEDUCTION The 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 liquidation of the Partnership generally are to be made in accordance with positive capital account balances. In general, if the Partnership has a net profit, items of income, gain, loss and deduction will be allocated among the General Partners and the Unitholders in accordance with their respective percentage interests in the Partnership. A class of 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 the Partnership has 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 the 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 Partnership 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 the Partnership ("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 Unitholders, but these allocations may not be respected. 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 the Partnership does not expect that its operations will result in the creation of negative capital accounts, if negative capital accounts nevertheless result, items of Partnership 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 partnership 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 the partnership, which will be determined by taking into account all the facts and circumstances, including the partner's relative contributions to the partnership, 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 the 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, the Partnership Agreement requires that certain items of income and deduction be allocated in a way designed to effectively "cure" this problem and eliminate the C-14 98 impact of the ceiling limitations. Such allocations will not have substantial economic effect because they will not be reflected in the capital accounts of the Unitholders. The legislative history of Section 704(c) states that Congress anticipated that 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 Regulations under Section 704(c), allocations similar to the curative allocations would be allowed. However, since the final Regulations are not applicable to the Partnership, 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 the 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 Regulations relating to allocations of partnership income, and investors should be aware that some of the allocations in the Partnership Agreement may be successfully challenged by the IRS. TAX TREATMENT OF OPERATIONS Accounting Method and Taxable Year The Partnership will use the calendar year as its taxable year and will adopt the accrual method of accounting for federal income tax purposes. Initial Tax Basis, Depreciation and Amortization The tax basis established for the various assets of the Partnership will be used for purposes of computing depreciation and cost recovery deductions and, ultimately, gain or loss on the disposition of such assets. The Partnership assets initially had an aggregate tax basis equal to the sum of each Unitholder's tax basis in his Units and the tax basis of the General Partners in their respective general partner interests and Subordinated Units. The Partnership allocated the aggregate tax basis among the Partnership's 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 Unitholder in respect of such assets would be reduced, and a Unitholder's share of taxable income from the Partnership 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 the early years of the Partnership. Property subsequently acquired or constructed by the Partnership may be depreciated using accelerated methods permitted by the Code. If the Partnership disposes 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 the Partnership may be required to recapture such deductions upon a sale of his interest in the Partnership. See "Tax Considerations -- Allocation of Partnership Income, Gain, Loss and Deduction" and "Tax Considerations -- Disposition of Common Units -- Recognition of Gain or Loss." Costs incurred in organizing the Partnership may be amortized over any period selected by the Partnership 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 termination of the Partnership. There are C-15 99 uncertainties regarding the classification of costs as organization expenses, which may be amortized, and as syndication expenses which may not be amortized. Section 754 Election The Partnership previously made the election permitted by Section 754 of the Code, which 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 the Partnership's properties ("inside basis") pursuant to Section 743(b) of the Code to fair market value (as reflected by his Unit price). See "Tax Considerations -- Allocation of Partnership Income, Gain, Loss and Deduction." The Section 743(b) adjustment is attributed solely to a purchaser of Common Units and is not added to the bases of the Partnership's assets associated with all of the Unitholders. (For purposes of this discussion, a partner's inside basis in the Partnership's assets will be considered to have two components: (1) his share of the Partnership's actual basis in such assets ("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 regulations under Section 197 indicate 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. The Partnership intends 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 Bases in such properties. Pursuant to the Partnership Agreement, the General Partners are authorized to adopt a convention to preserve the uniformity of 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 Units." Although Counsel is unable to opine as to the validity of such an approach, the Partnership intends 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 the Partnership determines that such position cannot reasonably be taken, the Partnership may adopt a depreciation or amortization convention under which all purchasers acquiring Units in the same month would receive depreciation or amortization, whether attributable to Common Basis or Section 743(b) basis, based upon the same applicable rate as if they had purchased a direct interest in the Partnership's property. Such an aggregate approach may result in lower annual depreciation or amortization deductions than would otherwise be allowable to certain Unitholders. See "Tax Considerations -- Uniformity of 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 the Partnership 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 Units is higher than such Units' share of the aggregate basis to the Partnership of the Partnership's 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 the C-16 100 Partnership's assets for purposes of calculating, among other items, his depreciation deductions and his share of any gain or loss on a sale of the Partnership's assets. Conversely, a Section 754 election is disadvantageous if the transferee's basis in such Units is lower than such Units' share of the aggregate basis of the Partnership's assets immediately prior to the transfer. Thus, the amount which 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 will be made by the Partnership on the basis of certain assumptions as to the value of Partnership assets and other matters. There is no assurance that the determinations made by the Partnership 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 the Section 754 election for the Partnership. If such permission is granted, a purchaser of 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 Partnership income, gain or loss for purposes of the alternative minimum tax. A portion of the Partnership's depreciation deductions may be treated as an item of tax preference for this purpose. A Unitholder's alternative minimum taxable income derived from the Partnership may be higher than his share of Partnership net income because the Partnership 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. Prospective Unitholders should consult with their tax advisors as to the impact of an investment in Common Units on their liability of the alternative minimum tax. Valuation of Partnership Property The federal income tax consequences of the acquisition, ownership and disposition of Units will depend in part on estimates by the Partnership of the relative fair market values, and determinations of the initial tax basis, of the assets of the Partnership. Although the Partnership 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 the Partnership. 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 Unitholders might change, and Unitholders might be required to amend their previously filed tax returns or to file claims for refunds. Treatment of Short Sales Under the TRA of 1997, a Unitholder who engages in a short sale (or a transaction having the same effect) with respect to Units will be required to recognize the gain (but not the loss) inherent in such Units. See "Tax Considerations -- Disposition of Common Units". In addition, it would appear that a Unitholder whose Units are loaned to a "short seller" to cover a short sale of Units would be considered as having transferred beneficial ownership of those Units and would, thus, no longer be a partner with respect to those Units during the period of the loan. As a result, during this period, any Partnership income, gain, deduction, loss or credit with respect to those Units would appear not to be reportable by the Unitholder, any cash distributions received by the Unitholder with respect to those 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 Units to a "short seller" constitutes a taxable exchange. If this contention were successfully made, the lending Unitholder may be required to recognize gain or loss. Unitholders desiring to assure their C-17 101 status as partners should modify their brokerage account agreements, if any, to prohibit their brokers from borrowing their Units. DISPOSITION OF COMMON UNITS Recognition of Gain or Loss Gain or loss will be recognized on a sale of Units equal to the difference between the amount realized and the Unitholder's tax basis for the 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 Partnership nonrecourse liabilities. Since the amount realized includes a Unitholder's share of Partnership nonrecourse liabilities, the gain recognized on the sale of 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 Units) on the sale or exchange of a 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 owned by the Partnership. 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 Unit and may be recognized even if there is a net taxable gain realized upon the sale of the Unit. Any loss recognized on the sale of units will generally be a capital loss. Thus, a Unitholder may recognize both ordinary income and a capital loss upon a disposition of 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. The ruling is unclear as to how the holding period is affected by this aggregation concept. If this ruling is applicable to the holders of Common Units, the aggregation of tax bases of a Common Unitholder effectively prohibits him 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 a Unitholder's Common Units. It is not clear whether the ruling applies to publicly-traded partnerships, such as the Partnership, 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 the Unitholders. A Unitholder considering the purchase of additional Common Units or a sale of Common Units purchased at differing prices should consult his tax advisor as to the possible consequences of such ruling. Allocations between Transferors and Transferees In general, the Partnership's taxable income and losses will be determined annually and will be prorated on a monthly basis and subsequently apportioned among the Unitholders in proportion to the number of Units owned by them 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 Partnership assets other than in the ordinary course of business shall be allocated among the 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 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 the C-18 102 Unitholder's interest), taxable income or losses of the Partnership might be reallocated among the Unitholders. The Partnership is authorized to revise its 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 Units at any time during a quarter and who disposes of such Units prior to the record date set for a distribution with respect to such quarter will be allocated items of Partnership income and gain attributable to such quarter during which such Units were owned but will not be entitled to receive such cash distribution. Notification Requirements A Unitholder who sells or exchanges Units is required to notify the Partnership 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 in which the sale or exchange occurred. The Partnership is 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 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, which set forth the amount of the consideration received for such Unit that is allocated to goodwill or going concern value of the Partnership. Failure to satisfy such reporting obligations may lead to the imposition of substantial penalties. Constructive Termination The Partnership and the Intermediate Partnership will be considered to have been 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 Units for federal income tax purposes. A constructive termination of the Partnership will cause a termination of the Intermediate Partnership. Such a termination could also result in penalties or loss of basis adjustments under Section 754 of the Code if the Partnership 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 a tax year of the Partnership may result in more than 12 months' taxable income or loss of the Partnership being includable in its 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 Units. New tax elections required to be made by the Partnership, 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 Partnership deductions for depreciation. In addition, a termination might either accelerate the application of or subject the Partnership to any tax legislation enacted with effective dates after the closing of the offering made hereby. Entity-Level Collections If the Partnership is 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, the Partnership Policy Committee is authorized to pay such taxes from Partnership funds. Such payments, if made, will be deemed current distributions of cash to the Unitholders and the General Partners. The General Partners are authorized to amend the Partnership Agreement in the manner necessary to maintain uniformity of intrinsic tax characteristics of Units and to adjust subsequent distributions so that after giving effect to such deemed distributions, the priority and characterization of distributions otherwise applicable under the Partnership Agreement is maintained as nearly as is practicable. Payments by the Partnership as described C-19 103 above 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 UNITS Since the Partnership 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 the Partnership's ability to make allocations to eliminate Book-Tax Disparities attributable to Contributed Properties and Partnership property that has been revalued and reflected in the partners' capital accounts ("Adjusted Properties"). Any such non-uniformity could have a negative impact on the value of a Unitholder's interest in the Partnership. The Partnership intends 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 the Partnership determines that such a position cannot reasonably be taken, the Partnership 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 common basis or Section 743(b) basis, based upon the same applicable rate as if they had purchased a direct interest in the Partnership's 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 Unitholders and risk the loss of depreciation and amortization deductions not taken in the year that such deductions are otherwise allowable. This convention will not be adopted if the Partnership determines that the loss of depreciation and amortization deductions will have a material adverse effect on the Unitholders. If the Partnership chooses not to utilize this aggregate method, the Partnership 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 the Unitholders. The IRS may challenge any method of depreciating or amortizing the Section 743(b) adjustment described in this paragraph. If such a challenge were to be 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 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 Unit Ownership" and "Tax Considerations -- Allocation of Partnership Income, Gain, Loss and Deduction." The capital accounts underlying the Common Units will likely differ, perhaps materially, from the capital accounts underlying the Subordinated Units. The Partnership Agreement contains a method by which the Partnership may cause the capital accounts underlying the Common Units to equal the capital accounts underlying the Subordinated Units following the end of the Subordination Period. The Partnership must be reasonably assured, based on advice of counsel, that the Common Units and Subordinated Units share the same intrinsic economic and federal income tax characteristics in all material respects, before the Subordinated Units and Common Units will be treated as a single class of Units. C-20 104 TAX-EXEMPT ORGANIZATIONS AND CERTAIN OTHER INVESTORS Ownership of Units by employee benefit plans, other tax-exempt organizations, nonresident 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 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 the Partnership's gross income will qualify as such income. Non-resident aliens and foreign corporations, trusts or estates which acquire Units will be considered to be engaged in business in the United States on account of ownership of Units and as a consequence will be required to file federal tax returns in respect of their distributive shares of Partnership 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 which 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, the Partnership 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 the Transfer Agent of the Partnership on a 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 the Partnership to change these procedures. Because a foreign corporation which owns 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 the Partnership's earnings and profits (as adjusted for changes in the foreign corporation's "U.S. net equity") which 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 Units are regularly traded on an established securities market, a foreign Unitholder who sells or otherwise disposes of a Unit and who has not held more than 5% in value of the 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 the Partnership, but (regardless of a foreign Unitholder's percentage interest in the Partnership or whether 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 the Partnership if the holder held more than 5% in value of the Units during the five-year period ending on the date of the disposition or if the Units were not regularly traded on an established securities market at the time of the disposition. ADMINISTRATIVE MATTERS Partnership Information Returns and Audit Procedures The Partnership intends to furnish to each Unitholder within 90 days after the close of each Partnership taxable year, certain tax information, including a Schedule K-1, which sets forth each C-21 105 Unitholder's allocable share of the Partnership's income, gain, loss, deduction and credit. In preparing this information, which will generally not be reviewed by counsel, the Partnership 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 which conforms to the requirements of the Code, regulations or administrative interpretations of the IRS. The Partnership 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 filed by the Partnership may be audited by the IRS. Adjustments resulting from any such audit may require each Unitholder to file an amended tax return, and possibly may result in an audit of the Unitholder's own return. 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. The Partnership Agreement appoints Northern Plains as the Tax Matters Partner. The Tax Matters Partner will make certain elections on behalf of the Partnership and Unitholders and can extend the statute of limitations for assessment of tax deficiencies against Unitholders with respect to Partnership items. The Tax Matters Partner may bind a Unitholder with less than a 1% profits interest in the Partnership 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 the 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 Unitholder having at least 1% interest in the profits of the Partnership and by the 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 its federal income tax return that is not consistent with the treatment of the item on the Partnership's 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. Under the TRA of 1997, partners in electing large partnerships would be required to treat all partnership items in a manner consistent with the partnership return. Under the TRA of 1997, each partner of an electing large partnership must take into account separately his share of the following items, determined at the partnership level: (1) taxable income or loss from passive loss limitation activities; (2) taxable income or loss from other activities (such as portfolio income or loss); (3) net capital gains to the extent allocable to passive loss limitation activities and other activities; (4) a net alternative minimum tax adjustment separately computed for passive loss limitation activities and other activities; (5) general credits; (6) low-income housing credit; (7) rehabilitation credit; (8) tax-exempt interest; (9) foreign income taxes; (10) credit for producing fuel from a nonconventional source and (11) any other items the Secretary of the Treasury deems appropriate. The TRA of 1997 also made a number of changes to the tax compliance and administrative rules relating to electing large partnerships. One provision requires that each partner in an electing large partnership take into account his share of any adjustments to partnership items in the year such adjustments are made. If the election is not made, adjustments relating to partnership items for a previous taxable year are taken into account by those persons who were partners in the previous taxable year. Alternatively, under the TRA of 1997 a partnership could elect to or, in some circumstances, could be required to, directly pay the tax resulting from any such adjustments. In either case, therefore, Unitholders C-22 106 could bear significant economic burdens associated with tax adjustments relating to periods predating their acquisition of Units. Although the Partnership Policy Committee is weighing the advantages and disadvantages to the Partnership and the Partners of the Partnership's being treated as an "electing large partnership" under the TRA of 1997, no decision has been made at this time. Nominee Reporting Persons who hold an interest in the Partnership as a nominee for another person are required to furnish to the Partnership (a) the name, address and taxpayer identification number of the beneficial owners and the nominee; (b) 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; (c) the amount and description of Units held, acquired or transferred for the beneficial owners; and (d) 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 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 the Partnership. The nominee is required to supply the beneficial owner of the Units with the information furnished to the Partnership. 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 the Partnership is not subject to the registration requirement on the basis that (i) it does not constitute a tax shelter or (ii) it constitutes a projected income investment exempt from registration. However, the Partnership has registered as a tax shelter with the IRS because of the absence of assurance that the Partnership will not be subject to tax shelter registration and in light of the substantial penalties which might be imposed if registration is required and not undertaken. ISSUANCE OF THE REGISTRATION NUMBER DOES NOT INDICATE THAT AN INVESTMENT IN THE PARTNERSHIP OR THE CLAIMED TAX BENEFITS HAVE BEEN REVIEWED, EXAMINED OR APPROVED BY THE IRS. The Partnership's tax shelter registration number is 93271000031. A Unitholder who sells or otherwise transfers a 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 the tax shelter registration number of the Partnership on Form 8271 to be attached to the tax return on which any deduction, loss, credit or other benefit generated by the Partnership is claimed or income of the Partnership 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 which 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, 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 C-23 107 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 the Partnership. If any Partnership item of income, gain, loss, deduction or credit included in the distributive shares of Unitholders might result in such an "understatement" of income for which no "substantial authority" exists, the Partnership must disclose the pertinent facts on its return. In addition, the Partnership will make a reasonable effort to furnish sufficient information for 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 Prospective investors should consider state and local tax consequences of an investment in the Partnership. The Partnership owns property or is doing business in Arizona, Illinois, Iowa, Minnesota, Montana, Nebraska, North Dakota, Oklahoma, South Dakota and Texas. A Unitholder will likely be required to file state income tax returns and/or to pay such taxes in most of such states and may be subject to penalties for failure to comply with such requirements. Some of the 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 Unitholders for purposes of determining the amounts distributed by the Partnership. Based on current law and its estimate of future Partnership operations, the Partnership anticipates 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 the responsibility of each prospective Unitholder to investigate the legal and tax consequences, under the laws of pertinent states or localities, of his investment in the Partnership. Further, it is the responsibility of each Unitholder to file all state and local, as well as federal, tax returns that may be required of such Unitholder. Counsel has not rendered an opinion on the state and local tax consequences of an investment in the Partnership. PLAN OF DISTRIBUTION The Common Units may be offered through one or more broker-dealers, through underwriters, or directly to investors, at a fixed price or prices, which may be changed from time to time, at market prices prevailing at the time of such sale, at prices related to such market prices or at negotiated prices, and in connection therewith distributors' or sellers' commissions may be paid or allowed, which will not exceed those customary in the types of transactions involved. Broker-dealers may act as agent for the Partnership, or may purchase Common Units from the Partnership as principal and thereafter resell such Common Units 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 or in some combination of the foregoing. Any such broker-dealer or underwriter may receive compensation in the form of underwriting discounts or commissions and may receive commissions from purchasers of the Common Units for whom they may act as agents. If any such broker-dealer purchases the Common Units as principal, it may effect resales of the Common Units from time to time to or through other broker-dealers, and such other broker-dealers may receive compensation in the form of concessions or commissions from the purchasers of Common Units for whom they may act as agents. C-24 108 To the extent required, the names of the specific managing underwriter or underwriters, if any, as well as certain other information, will be set forth in a Prospectus Supplement. In such event, the discounts and commissions to be allowed or paid to the underwriters, if any, and the discounts and commissions to be allowed or paid 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 such sale may also be customers of, engage in transactions with, or perform services for the Partnership or its affiliates in the ordinary course of business. VALIDITY OF COMMON UNITS The validity of the Common Units offered hereby will be passed upon for the Partnership by Vinson & Elkins L.L.P. EXPERTS The consolidated financial statements included in the Partnership's Annual Report on Form 10-K for the year ended December 31, 1996, incorporated by reference in this Prospectus, have been audited by Arthur Andersen LLP, independent public accountants, as indicated in their report with respect thereto. The consolidated financial statements referred to above and such report have been incorporated by reference herein in reliance upon the authority of said firm as experts in accounting and auditing in giving said report. C-25 109 -------------------------------------------------------------------------------- -------------------------------------------------------------------------------- [NORTHERN BORDER PARTNERS, L.P. LOGO] 4,455,218 COMMON UNITS NORTHERN BORDER PARTNERS, L.P. REPRESENTING LIMITED PARTNER INTERESTS ------------ PROSPECTUS SUPPLEMENT MAY , 2001 (INCLUDING PROSPECTUS DATED DECEMBER 5, 1997 AND PROSPECTUSES DATED MARCH 3, 1999) ------------ SALOMON SMITH BARNEY UBS WARBURG BANC OF AMERICA SECURITIES LLC A.G. EDWARDS & SONS, INC. DAIN RAUSCHER WESSELS FIRST UNION SECURITIES, INC. -------------------------------------------------------------------------------- --------------------------------------------------------------------------------