<PAGE> 1
FILED PURSUANT TO RULE 424(B)(2)
REGISTRATION NO. 333-72323
PROSPECTUS SUPPLEMENT
(TO PROSPECTUS DATED MARCH 3, 1999)
1,875,000 COMMON UNITS
NORTHERN BORDER PARTNERS, L.P.
REPRESENTING LIMITED PARTNER INTERESTS
[NORTHERN BORDER PARTNERS, L.P. LOGO]
------------------------
We are offering 1,875,000 common units as described in this prospectus
supplement and the accompanying prospectus. The common units represent limited
partner interests in Northern Border Partners, L.P. Our common units are traded
on the New York Stock Exchange under the symbol "NBP." On November 1, 2000, the
last reported sale price of our common units on the New York Stock Exchange was
$29.00 per common unit.
------------------------
<TABLE>
<CAPTION>
Per
Common Unit Total
----------- -----
<S> <C> <C>
Public offering price....................................... $29.00 $54,375,000
Underwriting discount and commissions....................... $ 1.23 $ 2,306,250
Proceeds, before expenses, to Northern Border Partners...... $27.77 $52,068,750
</TABLE>
The underwriters may also purchase up to an additional 281,250 common units
on the same terms described above within 30 days from the date of this
prospectus supplement to cover over-allotments, if any. The underwriters are
offering the common units subject to various conditions and may reject all or
part of any order. The underwriters expect to deliver the common units to
purchasers on November 7, 2000.
Neither the Securities and Exchange Commission nor any state securities
commission has approved or disapproved of these securities or determined if this
prospectus supplement or the accompanying prospectus are truthful or complete.
Any representation to the contrary is a criminal offense.
------------------------
PAINEWEBBER INCORPORATED
SALOMON SMITH BARNEY
LEHMAN BROTHERS
THE DATE OF THIS PROSPECTUS SUPPLEMENT IS NOVEMBER 1, 2000
<PAGE> 2
TABLE OF CONTENTS
<TABLE>
<CAPTION>
PROSPECTUS SUPPLEMENT PAGE NO.
--------------------- --------
<S> <C>
Northern Border Partners.................................... S-1
Recent Developments......................................... S-3
Ratio of Taxable Income to Distributions.................... S-4
Recent Tax Developments..................................... S-5
Use of Proceeds............................................. S-6
Price Range of Common Units and Distributions............... S-6
Capitalization.............................................. S-7
Underwriting................................................ S-8
Legal Matters............................................... S-9
Experts..................................................... S-9
</TABLE>
<TABLE>
<CAPTION>
PROSPECTUS
----------
<S> <C>
The Offered Securities...................................... 2
Where You Can Find More Information......................... 2
Cautionary Statement Regarding Forward Looking Statements... 3
Our Business................................................ 4
Conflicts of Interest and Fiduciary Responsibilities........ 7
FERC Regulation............................................. 8
Environmental and Safety Costs and Liabilities.............. 11
Common Units................................................ 11
Debt Securities............................................. 12
Ratio of Earnings to Fixed Charges.......................... 15
Use of Proceeds............................................. 15
Tax Considerations.......................................... 15
Plan of Distribution........................................ 29
Legal Matters............................................... 30
Experts..................................................... 30
</TABLE>
------------------------
IMPORTANT NOTICE ABOUT INFORMATION IN THIS
PROSPECTUS SUPPLEMENT AND THE ACCOMPANYING PROSPECTUS
This document is in two parts. The first part is the prospectus supplement,
which describes our business and the specific terms of this common unit
offering. The second part, the base prospectus, gives more general information,
some of which may not apply to this offering. Generally, when we refer only to
the "prospectus," we are referring to both parts combined.
IF THE DESCRIPTION OF THE OFFERING VARIES BETWEEN THE PROSPECTUS SUPPLEMENT
AND THE BASE PROSPECTUS, YOU SHOULD RELY ON THE INFORMATION IN THE PROSPECTUS
SUPPLEMENT. FORWARD LOOKING STATEMENTS IN THIS PROSPECTUS SUPPLEMENT ARE SUBJECT
TO THE RISKS AND UNCERTAINTIES DISCUSSED IN THE BASE PROSPECTUS UNDER
"CAUTIONARY STATEMENT REGARDING FORWARD LOOKING STATEMENTS."
YOU SHOULD RELY ONLY ON THE INFORMATION CONTAINED IN OR INCORPORATED BY
REFERENCE IN THIS PROSPECTUS. WE HAVE NOT, AND THE UNDERWRITERS HAVE NOT,
AUTHORIZED ANYONE TO PROVIDE YOU WITH DIFFERENT INFORMATION. WE ARE NOT MAKING
AN OFFER OF THE COMMON UNITS IN ANY JURISDICTION WHERE THE OFFER IS NOT
PERMITTED. YOU SHOULD NOT ASSUME THAT THE INFORMATION CONTAINED IN THIS
PROSPECTUS OR IN THE DOCUMENTS INCORPORATED BY REFERENCE IN THIS PROSPECTUS IS
ACCURATE AS OF ANY DATE OTHER THAN THE DATE ON THE FRONT OF THOSE DOCUMENTS.
i
<PAGE> 3
The information in this prospectus supplement is not complete. You should
review carefully all of the detailed information appearing in this prospectus
supplement, the accompanying prospectus, and the documents we have incorporated
by reference before making any investment decision. Certain capitalized terms
used but not defined in this prospectus supplement have the meanings assigned to
them in the accompanying prospectus.
NORTHERN BORDER PARTNERS
We are a publicly traded limited partnership and a leading transporter of
natural gas imported from Canada to the United States. Through our subsidiary
limited partnership, Northern Border Intermediate Limited Partnership, we own a
70% general partner interest in Northern Border Pipeline Company. Northern
Border Pipeline owns a 1,214-mile interstate pipeline system that transports
natural gas from the Montana-Saskatchewan border to natural gas markets in the
midwestern United States. This pipeline system connects with multiple pipelines
that provide shippers with access to the various natural gas markets served by
those pipelines. Our interest in Northern Border Pipeline represents the largest
portion of our assets, earnings and cash flows.
Northern Border Pipeline placed its pipeline system in service in 1982, and
it completed expansions and/or extensions in 1991, 1992 and 1998. The most
recent expansion and extension, called The Chicago Project, increased the
pipeline system's ability to receive natural gas by 42% to its current capacity
of 2,373 million cubic feet per day. In the year ended December 31, 1999,
Northern Border Pipeline transported approximately 23% of the total amount of
natural gas imported from Canada to the United States. Over the same period,
approximately 91% of the natural gas transported by Northern Border Pipeline was
produced in the western Canadian sedimentary basin located in the provinces of
Alberta, British Columbia and Saskatchewan.
The pipeline system serves more than 40 shippers with diverse operating and
financial profiles. Based upon shippers' cost of service obligations, as of
September 30, 2000, at least 97% of the pipeline capacity was contractually
committed through mid-September 2003, and the weighted average contract life was
over six years. Northern Border Pipeline does not own the gas that it
transports, and therefore it does not assume the related natural gas commodity
price risk.
Through our wholly owned subsidiary, Crestone Energy Ventures, L.L.C., we
also own interests in Bighorn Gas Gathering, L.L.C., Fort Union Gas Gathering,
L.L.C. and Lost Creek Gathering, L.L.C., which own over 300 miles of gas
gathering facilities in Wyoming. The gathering facilities interconnect to the
interstate gas pipeline grid serving gas markets in the Rocky Mountains, the
Midwest and California. The Bighorn and Fort Union systems gather coal seam
methane gas produced in the Powder River basin in northeastern Wyoming.
Bighorn's system is capable of gathering more than 250 million cubic feet per
day of coal seam methane gas for delivery to the Fort Union gathering system,
and Fort Union's system is capable of delivering more than 450 million cubic
feet per day of coal seam methane gas into the interstate pipeline grid. Under
various agreements, the majority of which are long term, producers have granted
to Bighorn the exclusive right to gather coal seam methane gas produced in areas
of Wyoming covering 800,000 acres. The Lost Creek system gathers natural gas
produced from conventional gas wells in the Wind River basin and consists of 106
miles of gathering pipelines. The system is capable of delivering more than 275
million cubic feet per day of gas into the interstate pipeline grid.
We also own Black Mesa Pipeline Holdings, Inc. which owns a 273-mile coal
slurry pipeline originating at a coal mine in Kayenta, Arizona. The coal slurry
pipeline transports crushed coal to the Mohave Power station in Laughlin,
Nevada. The capacity of the pipeline is fully contracted to the coal supplier
for the Mohave Power station through the year 2005.
S-1
<PAGE> 4
OUR STRATEGY
Our strategy is to continue to own and manage Northern Border Pipeline as a
highly utilized, low cost pipeline system and to increase the pipeline system's
capacity though expansions or extensions, joint ventures, other alliances or
selective acquisitions. In the near term, we plan to focus our efforts on
obtaining extensions of the existing contracts with shippers and on
opportunities to serve new electric generation facilities on the east end of the
pipeline system. These opportunities may include looping, additional compression
or extensions of the pipeline system. We will also explore opportunities to
transport natural gas or maximize our shippers' ability to access markets
outside the Chicago area.
We are also focusing on acquisition opportunities involving energy
businesses in North America. We hope to leverage our experience in energy
transportation to enhance cash flow and earnings by acquiring other, primarily
unregulated, transportation assets. We plan to pursue opportunities that involve
fee-for-service income and little or no commodity price risk. We may acquire
assets from affiliates of our general partners, although they have no obligation
to offer us acquisition opportunities, except that Enron North America Corp., a
subsidiary of Enron Corp., has an obligation to permit us to participate in
gathering opportunities in specified areas of Wyoming and Montana.
Through Crestone Energy Ventures, we plan to develop significant additional
gathering systems and to explore other opportunities for expansion of our
interests in Wyoming and for transportation of natural gas produced in the
Powder River and Wind River basins.
We intend to pursue only those expansion and acquisition opportunities that
add to our cash flow over time. Our strategy will involve significant capital
expenditures and other costs. Capital expenditures for Northern Border Pipeline
for 2001 will be approximately $90 million, the majority of which will be for
Project 2000, which is described below in "Recent Developments -- Project 2000".
We have targeted significant additional gas gathering and other development
projects in the Powder River and Wind River basins, and if all of these proceed
as planned our share of capital expenditures for our interests in Wyoming will
be $60 million to $70 million next year. We will finance these capital
expenditures initially with debt, although we plan to issue additional common
units as needed in order to maintain an appropriate capital structure.
OUR STRUCTURE AND MANAGEMENT
Our general partners are Northern Plains Natural Gas Company and Pan Border
Gas Company, both subsidiaries of Enron, and Northwest Border Pipeline Company,
a subsidiary of The Williams Companies, Inc. We are managed by or under the
direction of our Partnership Policy Committee consisting of three members, each
of whom has been appointed by one of our general partners. Management of
Northern Border Pipeline is overseen by the Northern Border management
committee, which is comprised of three of our representatives and one
representative from TC PipeLines, LP, the owner of the remaining 30% general
partner interest in Northern Border Pipeline. Voting power on the management
committee is allocated among our three representatives in proportion to their
general partner interests in us. As a result, Enron controls 57.75% of the
voting power of the management committee.
Northern Plains and NBP Services Corporation, each of which is a subsidiary
of Enron, provide operating and administrative services for us and our
subsidiaries under services and operating agreements. Northern Plains operates
the Northern Border Pipeline system, and NBP Services provides administrative
services for us and operating services for Crestone Energy Ventures and its
subsidiaries. Approximately 215 individuals are involved in operating
activities. None of these individuals is represented by a labor union or covered
by a collective bargaining agreement.
COMPETITION
Northern Border Pipeline competes with other pipeline companies that
transport gas from the western Canadian sedimentary basin or that transport gas
to end-use markets in the Midwest. Its competitive position is affected by the
availability of Canadian natural gas for export and demand for natural gas in
the
S-2
<PAGE> 5
United States. Shippers of gas produced in the western Canadian sedimentary
basin have other options to transport Canadian natural gas to the United States,
including transportation on pipelines eastward in Canada or to markets on the
West Coast.
The Alliance Pipeline, which will transport natural gas from the western
Canadian sedimentary basin to the midwestern United States, is under
construction. Its sponsors have announced their plans for the Alliance Pipeline
to be in service by late this year. Upon its completion, the Alliance Pipeline
will compete directly with Northern Border Pipeline.
As a consequence of the Alliance Pipeline, there may be a large increase in
natural gas moving from the western Canadian sedimentary basin to Chicago. There
are several additional projects proposed to transport natural gas from the
Chicago area to growing eastern markets that would provide access to additional
markets for the shippers. The proposed projects currently being pursued by third
parties are targeting markets in eastern Canada and the northeast United States.
These proposed projects are in various stages of regulatory approval. One such
project, Vector Pipeline, is designed to transport western Canadian and United
States sourced natural gas from the Chicago area to parts of Indiana and
Michigan, and into Ontario, Canada, as well as provide access to markets and
storage in the upper Midwest. Vector Pipeline is currently under construction
and has a projected in-service date of December 1, 2000.
Williams has a 14.6% interest in the Alliance Pipeline. TransCanada
PipeLines Limited and other unaffiliated companies own and operate pipeline
systems that transport natural gas from the same natural gas reserves in western
Canada that supply Northern Border Pipeline's customers.
RECENT DEVELOPMENTS
INCREASE IN CASH DISTRIBUTIONS
We recently announced an increase in our quarterly cash distribution to
$0.70 from $0.65 per common unit. The indicated annual rate is now $2.80 per
common unit. The increase becomes effective with the third quarter distribution
payable on November 14, 2000 to unitholders of record as of October 31, 2000.
Purchasers of common units in this offering will not be entitled to receive the
third quarter distribution. This is the Partnership's fourth increase in the
last three years. We announced this increase because of the continued strong
performance of our core business, recent acquisitions and confidence in our
strategy.
THIRD QUARTER 2000
Our third quarter 2000 net income per unit was $0.66, or $20.3 million,
compared to $0.65 per unit, or $19.4 million, in the third quarter of 1999. Our
cash flows from operating activities increased from $50.6 million for the third
quarter of 1999 to $51.7 million for the third quarter of 2000. Delivered
volumes for Northern Border Pipeline increased during the third quarter of 2000
to 212,670 million cubic feet from 211,761 million cubic feet for the third
quarter of 1999. Transportation units averaged 2,250 million dekatherm miles
(MMdthm) in the third quarter of 2000 compared to 2,242 MMdthm in the third
quarter of 1999.
PROPOSED SETTLEMENT OF PENDING RATE CASE
On September 26, 2000, Northern Border Pipeline filed a stipulation and
agreement that documents the settlement of its pending rate case. The settlement
will become effective if and when approved by the FERC. We anticipate the FERC
will act on the settlement in the first quarter of 2001. Among the key
provisions of the proposed settlement is the conversion of Northern Border
Pipeline's form of tariff from cost of service to stated rates based on a
straight-fixed variable rate design. If the proposed settlement is approved,
shippers will pay stated transportation rates. Under the straight-fixed variable
rate design, approximately 98% of the payments are attributed to demand charges,
based upon contracted firm capacity, and 2% to commodity charges based on the
volumes of gas actually transported on the system.
S-3
<PAGE> 6
On a per unit of transportation basis, the rates under the new tariff are
approximately equal to the previous level. Under the proposed settlement,
Northern Border Pipeline's earnings and cash flow will depend on its future
costs, contracted capacity, the volumes of gas transported and its ability to
recontract capacity at acceptable rates. The proposed settlement agreement has
not been opposed by any of Northern Border Pipeline's shippers.
Under Northern Border Pipeline's existing tariff, the amount that it may
collect from customers generally declines as the rate base is recovered. Under
its proposed tariff, Northern Border Pipeline will be entitled to collect based
on stated rates until its next rate case, which will be filed November 1, 2005.
It will, however, continue to depreciate its rate base at an annual depreciation
rate on transmission plant in service of 2.25%, and its rate base in 2005 will
be a factor in determining what it can charge when it files a new rate case at
that time. In order to avoid an eventual decline in maximum rates it can charge
its transmission customers, Northern Border Pipeline must maintain or increase
its rate base by acquiring or constructing assets that replace or add to
existing pipeline facilities or by adding new facilities.
ACQUISITIONS
In September 2000, we purchased interests in gas gathering businesses in
the Powder River and Wind River basins in Wyoming for approximately $200 million
from Enron North America. The transaction included the purchase of Enron
Midstream Services, L.L.C., now known as Crestone Gathering Services, L.L.C.,
and ownership interests in Bighorn, Fort Union and Lost Creek. The transaction
added to our previous ownership position in Bighorn. We previously purchased
common and preferred shares of Bighorn for $52.7 million.
As a result of these transactions, through Crestone Energy Ventures we own
100% of Crestone Gathering Services, a 49% ownership interest in Bighorn, a
33.33% interest in Fort Union and a 35% interest in Lost Creek. CMS Field
Services, Inc. holds the remaining ownership interest in Bighorn. The remaining
ownership interest in Fort Union is held in varying percentages by subsidiaries
of CMS Energy Services, Western Gas Resources, Inc., Colorado Interstate Gas
Company, and Barrett Resources Corporation. A subsidiary of Burlington Resources
Inc. holds the remaining ownership interest in Lost Creek.
PROJECT 2000
On March 16, 2000, the FERC issued an order granting Northern Border
Pipeline's application for a certificate to construct and operate its proposed
Project 2000 facilities. Project 2000 will expand and extend the pipeline system
into Indiana. In addition to providing additional Canadian natural gas to United
States markets, Project 2000 will afford shippers on the extended pipeline
system access to industrial gas consumers in northern Indiana. The project has a
targeted in-service date of November 2001. The capital expenditures for the
project are estimated to be approximately $94 million.
RATIO OF TAXABLE INCOME TO DISTRIBUTIONS
We estimate that a purchaser of common units in this offering who holds
them through the record date for the last quarter of 2003 will be allocated an
amount of federal taxable income for the period 2000 through 2003 that will be
less than 10% of the amount of cash distributed to such unitholder with respect
to that period. The foregoing is based on certain assumptions regarding
revenues, capital expenditures, anticipated cash distributions, amounts expended
for Project 2000 and other factors. Although we believe that this estimate is
reasonable, it is subject to uncertainties beyond our control, and we cannot
assure you that this estimate will prove to be correct. Taxable income for the
last month of 2000 will be allocated to purchasers of common units in this
offering, but no cash distributions will be made on the common units purchased
in this offering until the first quarter of 2001.
S-4
<PAGE> 7
RECENT TAX DEVELOPMENTS
This section is a summary of certain recent federal income tax developments
that may be relevant to you. The IRS has recently finalized regulations under
Sections 743, 197, and 1223 of the Internal Revenue Code.
Treasury Regulations under Section 743 require a portion of the Section
743(b) adjustment attributable to property subject to cost recovery deductions
under Section 168 to be recovered over the remaining cost recovery period for
the Section 704(c) built-in gain in such property. Recently finalized Treasury
Regulations under Section 197 similarly require a portion of the Section 743(b)
adjustment attributable to amortizable section 197 intangibles to be amortized
over the remaining amortization period for the Section 704(c) built-in gain in
such intangibles. These Regulations apply only to partnerships that have adopted
the remedial method, which we may adopt. If a different method is adopted, the
Section 743(b) adjustment attributable to property subject to cost recovery
deductions under Section 168 or amortization under Section 197 must be taken
into account as if it were newly-purchased property placed in service when the
transfer giving rise to the Section 743(b) adjustment occurs. Regardless of the
method adopted, Treasury Regulation Section 1.167(c)-1(a)(6) requires the
portion of a Section 743(b) adjustment attributable to property subject to
depreciation under Section 167 of the Internal Revenue Code to be depreciated
using either the straight-line method or the 150% declining balance method.
Under our partnership agreement, the general partner is authorized to adopt
a convention to preserve the uniformity of common units even if that convention
is not consistent with specified Treasury Regulations. Although our counsel is
unable to opine as to the validity of such an approach, we intend to adopt a
method to depreciate and amortize the Section 743(b) adjustment attributable to
unrealized appreciation in the value of contributed property that will preserve
the uniformity of common units. Regardless of the method we adopt, the ratio of
federal taxable income allocated to unitholders for the period 2000 to 2003 to
the amount of cash distributed to such unitholders with respect to that period
is not expected to be materially affected.
The method we adopt for amortizing and depreciating the Section 743(b)
adjustment may be inconsistent with the Treasury Regulations. If the IRS
successfully challenged our method for depreciating or amortizing the Section
743(b) adjustment, the uniformity of common units might be affected, and the
gain realized by a partner from the sale of common units might be increased
without the benefit of additional deductions.
The IRS has ruled that a partner who acquires interests in a partnership in
separate transactions must combine those interests and maintain a single
adjusted basis for all those interests. Upon a sale or disposition of less than
all of those interests, a portion of that basis must be allocated to the
interests sold using an "equitable apportionment" method. The IRS has recently
finalized regulations under Section 1223 of the Code that make it clear that
this ruling applies to publicly traded partnerships such as us. These recently
finalized regulations would, however, allow a selling unitholder who can
identify the common units transferred with an ascertainable holding period to
elect to use the actual holding period of the common units transferred. Thus,
according to the ruling, a unitholder will be unable to select high or low basis
common units to sell as would be the case with corporate stock, but, according
to the regulations, may designate specific common units sold for purposes of
determining the holding period of common units transferred. A unitholder
electing to use the actual holding period of common units transferred must use
that identification method for all subsequent sales or exchanges of common
units. A unitholder considering the purchase of additional common units or a
sale of common units purchased in separate transactions should consult his tax
advisor as to the possible consequences of this ruling and application of the
proposed regulations.
To the extent set forth below and under "Tax Considerations -- Legal
Opinions and Advice" in the accompanying prospectus, this section represents the
opinion of Vinson & Elkins L.L.P. insofar as it relates to matters of law and
legal conclusions. The opinion with respect to this section is subject to the
same assumptions and limitations as the opinion of Vinson & Elkins L.L.P.
described under "Tax Considerations" in the accompanying prospectus.
S-5
<PAGE> 8
USE OF PROCEEDS
We estimate that the net proceeds of this offering will be approximately
$52 million. We will use the proceeds, together with capital contributions from
our general partners, to reduce the aggregate amount outstanding under our bank
credit agreements entered into in June 2000. We used the funds borrowed under
the credit agreements, along with the proceeds from senior notes, to acquire gas
gathering businesses from Enron North America in September 2000. Borrowings
under the credit agreements have a weighted average interest rate of 7.99%, and
the average time to maturity is 2.5 years.
PRICE RANGE OF COMMON UNITS AND DISTRIBUTIONS
Our outstanding equity consists of general partner interests representing
in the aggregate a 2% interest and 29,347,313 common units representing in the
aggregate a 98% limited partner interest. The common units are traded on the
NYSE under the symbol "NBP." As of October 18, 2000, there were approximately
1,500 holders of the common units and approximately 30,000 beneficial owners of
the common units, including common units held in street name.
The following table sets forth, for the periods indicated, the high and low
sales prices for the common units, as reported on the NYSE Composite
Transactions Tape, and quarterly declared cash distributions thereon. The last
reported sale price of the common units on the NYSE on November 1, 2000 was
$29.00 per common unit.
<TABLE>
<CAPTION>
PRICE RANGE DISTRIBUTIONS
------------------- PER COMMON
HIGH LOW UNIT(1)
-------- -------- -------------
<S> <C> <C> <C>
1998
First Quarter............................................. $34.3125 $32.5000 $0.575
Second Quarter............................................ 35.0000 31.8125 0.575
Third Quarter............................................. 34.7500 31.1250 0.575
Fourth Quarter............................................ 36.1250 32.5000 0.610
1999
First Quarter............................................. $35.5000 $30.3750 $0.610
Second Quarter............................................ 33.5625 30.1875 0.610
Third Quarter............................................. 31.8750 28.0000 0.610
Fourth Quarter............................................ 29.5000 21.6250 0.650
2000
First Quarter............................................. $29.2500 $23.0000 $0.650
Second Quarter............................................ 28.1250 23.7500 0.650
Third Quarter............................................. 31.8750 27.2500 0.700
Fourth Quarter (through November 1, 2000)................. 33.6250 28.7500 (2)
</TABLE>
---------------
(1) The amounts shown reflect distributions made following the close of the
quarter consisting of available cash for the quarter. We recently announced
an increase in our cash distributions to $0.70 per common unit, effective
with the third quarter distribution payable on November 14, 2000 to
unitholders of record as of October 31, 2000.
(2) We intend to continue to pay regular quarterly cash distributions, and we
expect the distribution for the fourth quarter 2000 to be $0.70 per common
unit.
S-6
<PAGE> 9
CAPITALIZATION
The following table sets forth our unaudited historical and as adjusted
capitalization as of September 30, 2000. The as adjusted information gives
effect to:
- the sale of common units in this offering and the application of the net
proceeds (assuming the underwriters' over-allotment option is not
exercised) to reduce amounts outstanding under our credit agreements, and
- the capital contribution of our general partners to maintain their
combined 2% general partner interest in us in connection with the
issuance of additional common units.
For a discussion of the application of these proceeds, see "Use of Proceeds."
This table should be read in conjunction with our historical financial
statements and the notes to those financial statements that are incorporated by
reference in this prospectus supplement and the accompanying prospectus.
<TABLE>
<CAPTION>
AS OF SEPTEMBER 30, 2000
------------------------
ACTUAL AS ADJUSTED
---------- -----------
(IN THOUSANDS)
<S> <C> <C>
Northern Border Pipeline
Senior notes -- average 8.49%, due from 2001 to 2003...... $ 184,000 $ 184,000
Pipeline credit agreement
Term loan, variable interest rate (6.92% at September
30,
2000), due 2002...................................... 484,000 484,000
Senior notes -- 7.75%, due 2009........................... 200,000 200,000
Unamortized proceeds from termination of interest rate
forward agreements and unamortized debt discount,
net.................................................... 10,565 10,565
Northern Border Partners, L.P.
Senior notes -- 8.875%, due 2010.......................... 250,000 250,000
Partnership credit agreements
Revolving credit, variable interest rate (average 7.99%
at September 30, 2000), due 2003...................... 97,500 44,734
Unamortized premium on debt............................... 3,639 3,639
Black Mesa
10.7% note agreement, due quarterly to 2004............... 14,720 14,720
---------- ----------
Total long-term debt.............................. 1,244,424 1,191,658
---------- ----------
Minority interests in partners' capital..................... 248,736 248,736
---------- ----------
Partners' capital
General partners.......................................... 9,824 10,879
Common unitholders........................................ 481,380 533,091
---------- ----------
Total partners' capital........................... 491,204 543,970
---------- ----------
Total capitalization.............................. $1,984,364 $1,984,364
---------- ----------
</TABLE>
S-7
<PAGE> 10
UNDERWRITING
Under the terms and subject to the conditions stated in the underwriting
agreement dated the date of this prospectus supplement, each underwriter named
below has severally agreed to purchase from us, and we have agreed to sell to
such underwriter, the number of common units set forth opposite the name of such
underwriter.
<TABLE>
<CAPTION>
NUMBER OF
UNDERWRITER COMMON UNITS
----------- ------------
<S> <C>
PaineWebber Incorporated.............................. 625,000
Salomon Smith Barney Inc.............................. 625,000
Lehman Brothers Inc................................... 625,000
---------
Total....................................... 1,875,000
=========
</TABLE>
The underwriters propose to offer the common units to the public at the
public offering price set forth on the cover page of this prospectus supplement
and to certain dealers at such public offering price less a selling concession
not in excess of $0.74 per common unit. The underwriters may allow, and such
dealers may reallow, a concession not in excess of $0.10 per common unit to
certain other underwriters or to certain other brokers or dealers. After the
initial offering of the units to the public, the offering price and other
selling terms may from time to time be changed by the underwriters. The units
are offered subject to receipt and acceptance by the underwriters, and to other
conditions, including the right to reject orders in whole or in part.
We have granted to the underwriters an option, exercisable for 30 days from
the date of this prospectus supplement, to purchase up to 281,250 additional
common units at the public offering price less the underwriting discount. The
underwriters may exercise this option solely for the purpose of covering
over-allotments, if any, in connection with this offering. To the extent this
option is exercised, each underwriter will be committed, subject to certain
conditions, to purchase a number of additional common units approximately
proportionate to the underwriter's initial purchase commitment.
We have agreed, with limited exceptions, not to directly or indirectly
sell, offer to sell, grant any option for the sale of, or otherwise dispose of
any common units, or securities convertible into or exercisable or exchangeable
for common units or rights to acquire common units, for a period of 90 days
after the date of this prospectus supplement, without the prior written consent
of PaineWebber Incorporated. Our officers, general partners and PEC Midwest
L.L.C., a subsidiary of Duke Energy Corporation, have entered into similar
agreements.
The underwriters may from time to time engage in transactions with and
perform services for us in the ordinary course of their business.
For this offering, the underwriters may purchase and sell common units in
the open market. These transactions may include over-allotment and stabilizing
transactions and purchases to cover syndicate short positions created for this
offering. Stabilizing transactions consist of certain bids or purchases for the
purpose of preventing or retarding a decline in the market price of the common
units. Syndicate short positions involve the sale by the underwriters of a
greater number of common units than they are required to purchase from us in
this offering. The underwriters may also impose a penalty bid, whereby selling
concessions allowed to syndicate members or other broker-dealers in respect of
the common units sold in this offering for their account may be reclaimed by the
syndicate if those common units are repurchased by the syndicate in stabilizing
or covering transactions. These activities may stabilize, maintain or otherwise
affect the market price of the common units, which may be higher than the price
that might otherwise prevail in the open market, and these activities, if
commenced, may be discontinued at any time without notice. These transactions
may be effected on the New York Stock Exchange or otherwise.
Neither the underwriters nor we make any representation or prediction as to
the direction or magnitude of any effect that the transactions described above
may have on the price of the common units.
S-8
<PAGE> 11
In addition, neither the underwriters nor we make any representation that the
underwriters will engage in such transactions or that such transactions, once
commenced, will not be discontinued without notice.
The following table shows the underwriting discounts and commissions to be
paid to the underwriters in connection with this offering. These amounts are
shown assuming both no exercise and full exercise of the underwriters' option to
purchase additional common units:
<TABLE>
<CAPTION>
NO EXERCISE FULL EXERCISE
----------- -------------
<S> <C> <C>
Per common unit............................................. $ 1.23 $ 1.23
Total....................................................... $2,306,250 $2,652,188
</TABLE>
We estimate that the total expenses of the offering, other than
underwriting discounts and commissions, will be approximately $400,000.
We have agreed to indemnify the underwriters against certain liabilities,
including liabilities under the Securities Act, or to contribute to payments the
underwriters may be required to make in respect thereof.
Because the National Association of Securities Dealers, Inc. ("NASD") views
the common units offered hereby as interests in a direct participation program,
the offering is being made in compliance with Rule 2810 of the NASD's Conduct
Rules.
LEGAL MATTERS
Vinson & Elkins L.L.P. will pass upon the validity of the common units
offered by means of this prospectus. Andrews & Kurth L.L.P. will advise the
underwriters about other issues relating to the offering.
EXPERTS
The consolidated financial statements and schedule included in our Annual
Report on Form 10-K for the year ended December 31, 1999, incorporated by
reference in this prospectus, have been audited by Arthur Andersen LLP,
independent public accountants, as indicated in their reports with respect
thereto, and are incorporated by reference herein in reliance upon the authority
of said firm as experts in accounting and auditing in giving said reports.
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<PAGE> 12
PROSPECTUS
NORTHERN BORDER PARTNERS, L.P.
COMMON UNITS
DEBT SECURITIES
------------------------
We are a publicly-traded Delaware limited partnership that owns a 70%
general partner interest in Northern Border Pipeline Company, a Texas general
partnership ("Northern Border Pipeline"). Northern Border Pipeline is the
largest transporter of natural gas from the Western Canadian Sedimentary Basin
to the midwestern United States. Northern Border Pipeline owns a 1,214-mile
interstate pipeline system that originates from the Canadian border and extends
to natural gas markets in the midwestern United States currently terminating
near Chicago, Illinois. Our interest in Northern Border Pipeline represents
substantially all of our assets.
This prospectus provides you with a general description of the Common Units
and Debt Securities we may offer. Each time we sell securities we will provide a
prospectus supplement that will contain specific information about the terms of
that offering and the securities offered. The prospectus supplement may also
add, update or change information contained in this prospectus.
We currently have 29,347,313 Common Units outstanding. The Common Units are
traded on the New York Stock Exchange under the symbol "NBP." We will provide
information in the prospectus supplement for the expected trading market, if
any, for Debt Securities that we offer.
Throughout this prospectus we refer to ourselves, Northern Border Partners,
L.P., as "we" or "us."
------------------------
WE WILL PROVIDE SPECIFIC TERMS OF THESE SECURITIES IN PROSPECTUS
SUPPLEMENTS.
YOU SHOULD READ THIS PROSPECTUS AND ANY SUPPLEMENT CAREFULLY BEFORE YOU
INVEST.
NEITHER THE SECURITIES AND EXCHANGE COMMISSION (THE "SEC") NOR ANY STATE
SECURITIES COMMISSION HAS APPROVED OR DISAPPROVED THESE SECURITIES. THIS MEANS
THAT NEITHER THE SEC NOR ANY STATE SECURITIES COMMISSION HAS PASSED UPON THE
ACCURACY, ADEQUACY OR COMPLETENESS OF THIS PROSPECTUS. ANY REPRESENTATION TO THE
CONTRARY IS A CRIMINAL OFFENSE.
THE INFORMATION IN THIS PROSPECTUS IS NOT COMPLETE AND MAY BE CHANGED. THIS
PROSPECTUS IS NOT AN OFFER TO SELL THESE SECURITIES, AND IT IS NOT SOLICITING AN
OFFER TO BUY THESE SECURITIES, IN ANY STATE WHERE THE OFFER OR SALE IS NOT
PERMITTED.
TO UNDERSTAND US AND THE TERMS OF OUR SECURITIES, YOU SHOULD CAREFULLY READ
THIS DOCUMENT TOGETHER WITH ANY AND ALL PROSPECTUS SUPPLEMENTS. TOGETHER THESE
DOCUMENTS WILL PROVIDE YOU WITH THE SPECIFIC TERMS OF THE OFFERINGS. YOU SHOULD
ALSO READ THE DOCUMENTS WE HAVE REFERRED YOU TO IN "WHERE YOU CAN FIND MORE
INFORMATION" BELOW FOR INFORMATION ON US AND FOR OUR FINANCIAL STATEMENTS.
THE DATE OF THIS PROSPECTUS IS MARCH 3, 1999.
<PAGE> 13
TABLE OF CONTENTS
<TABLE>
<CAPTION>
PAGE
NO.
--------
<S> <C>
THE OFFERED SECURITIES...................................... 2
WHERE YOU CAN FIND MORE INFORMATION......................... 2
CAUTIONARY STATEMENT REGARDING FORWARD LOOKING STATEMENTS... 3
OUR BUSINESS................................................ 4
CONFLICTS OF INTEREST AND FIDUCIARY RESPONSIBILITIES........ 7
FERC REGULATION............................................. 8
ENVIRONMENTAL AND SAFETY COSTS AND LIABILITIES.............. 11
COMMON UNITS................................................ 11
DEBT SECURITIES............................................. 12
RATIO OF EARNINGS TO FIXED CHARGES.......................... 15
USE OF PROCEEDS............................................. 15
TAX CONSIDERATIONS.......................................... 15
PLAN OF DISTRIBUTION........................................ 29
LEGAL MATTERS............................................... 30
EXPERTS..................................................... 30
</TABLE>
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
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<PAGE> 14
Securities Exchange Act of 1934 (the "Exchange Act") until all offerings under
this shelf registration are completed:
- Annual Report on Form 10-K for the year ended December 31, 1997; and
- Quarterly Reports on Form 10-Q for the quarters ended March 31, 1998,
June 30, 1998 and September 30, 1998.
You may request a copy of these filings at no cost, by making written or
telephone requests for such copies to:
Investor Relations
Northern Border Partners, L.P.
1111 South 103rd Street, Omaha, Nebraska 68124
Telephone: 877-208-7318
You should rely only on the information incorporated by reference or
provided in this prospectus or any prospectus supplement. We have not authorized
anyone else to provide you with any information. You should not assume that the
information in this prospectus or any prospectus supplement is accurate as of
any date other than the date on the front of each document.
CAUTIONARY STATEMENT REGARDING FORWARD LOOKING STATEMENTS
This prospectus contains statements that constitute "forward looking
statements" within the meaning of Section 27A of the Securities Act and Section
21E of the Exchange Act. In general, any statement other than a statement of
historical fact is a forward looking statement. These statements appear in a
number of places in this prospectus and include statements regarding our plans,
beliefs and expectations with respect to, among other things:
- Future acquisitions;
- Expected future costs;
- Future capital expenditures;
- Trends affecting our future financial condition or results of operations;
and
- Our business strategy regarding future operations.
Any such forward looking statements are not assurances of future
performance and involve risks and uncertainties. Actual results may differ
materially from anticipated results for a number of reasons, including:
- Industry conditions;
- Future demand for natural gas;
- Availability of supplies of Canadian natural gas;
- Political and regulatory developments that impact Federal Energy
Regulatory Commission ("FERC") proceedings involving Northern Border
Pipeline;
- Northern Border Pipeline's ability to replace its rate base as it is
depreciated and amortized;
- Competitive developments by Canadian and other U.S. natural gas
transmission companies;
- Political and regulatory developments in the U.S. and in Canada;
- Conditions of the capital markets; and
- Our ability to implement our Year 2000 readiness program.
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<PAGE> 15
OUR BUSINESS
We were formed in 1993 to acquire, own and participate in the management of
pipeline and other energy assets through a subsidiary limited partnership,
Northern Border Intermediate Limited Partnership. Northern Plains Natural Gas
Company ("Northern Plains"), Pan Border Gas Company ("Pan Border") and Northwest
Border Pipeline Company ("Northwest Border") serve as our general partners
(collectively, the "General Partners"). Northern Plains and Pan Border are
wholly-owned subsidiaries of Enron Corp. ("Enron"), and Northwest Border is a
wholly-owned subsidiary of The Williams Companies, Inc. ("Williams"). The
General Partners hold in us an aggregate 2% general partner interest and Common
Units representing an aggregate 14.5% limited partner interest. The combined
general and limited partner interests of the General Partners are:
- Northern Plains -- 11.7%;
- Pan Border -- 0.7%; and
- Northwest Border -- 4.1%.
We own a 70% general partner interest in Northern Border Pipeline. The
remaining 30% general partner interests in Northern Border Pipeline are owned by
subsidiaries of TransCanada PipeLines Limited (the "TransCanada Subsidiaries").
Following is a chart showing our organization, our structure and our
interest in Northern Border Pipeline.
NORTHERN BORDER PARTNERS, L.P.
ORGANIZATION STRUCTURE
GRAPHIC
Our 70% interest in Northern Border Pipeline represents substantially all
of our assets and the source of substantially all of our earnings and cash flow.
Northern Border Pipeline owns a 1,214-mile United States interstate pipeline
system (the "Pipeline System") that transports natural gas from the Montana-
Saskatchewan border to natural gas markets in the midwestern United States.
Northern Border Pipeline initially constructed this Pipeline System in 1982 with
capacity additions to the Pipeline System in 1991, 1992 and 1998. A recent
expansion, called The Chicago Project, was completed in late 1998, and increased
the Pipeline System's capacity by 42% to its current capacity of 2,373 million
cubic feet per day ("MMcfd").
The Northern Border Management Committee, which is comprised of three
representatives selected by us (one designated by each General Partner) and one
representative of the TransCanada Subsidiaries,
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<PAGE> 16
oversees the management of Northern Border Pipeline. Northern Plains operates
the Pipeline System pursuant to an operating agreement. Northern Plains employs
approximately 190 individuals located at its headquarters in Omaha, Nebraska,
and at various locations along the pipeline route.
Northern Border Pipeline transports gas for shippers under a tariff
regulated by FERC. The tariff specifies the calculation of amounts to be paid by
shippers and the general terms and conditions of transportation service on the
Pipeline System. Northern Border Pipeline generates revenues from the receipt
and delivery of gas at points along the Pipeline System according to individual
transportation contracts with its shippers. Northern Border Pipeline does not
own the gas that it transports, and therefore it does not assume the risk of
loss from decreases in market prices for gas transported on the Pipeline System.
We also own Black Mesa Holdings, Inc. Black Mesa Holdings, Inc., through
its wholly-owned subsidiary, Black Mesa Pipeline, Inc., owns a 273-mile, 18-inch
diameter coal slurry pipeline that originates at a coal mine in Kayenta,
Arizona. The coal slurry pipeline transports crushed coal suspended in water. It
traverses westward through northern Arizona to the 1,500 megawatt Mohave Power
Station located in Laughlin, Nevada. The coal slurry pipeline is the sole source
of fuel for the Mohave Power Station, which consumes an average of 4.8 million
tons of coal annually. The capacity of the pipeline is fully contracted to the
coal supplier for the Mohave Power Station through the year 2005. The pipeline
is operated by Black Mesa Pipeline Operations, LLC, our wholly-owned subsidiary.
Our cash flow from the coal slurry pipeline represents only about 2% of our
total cash flow.
The Pipeline System
The Pipeline System has pipeline access to natural gas reserves in the
Western Canadian Sedimentary Basin located in the Canadian provinces of Alberta,
British Columbia and Saskatchewan, as well as the Williston Basin in the United
States. The Pipeline System also has access to synthetic gas processed at the
Dakota Gasification Plant in North Dakota. Interconnecting pipeline facilities
provide Northern Border Pipeline shippers access to markets in the Midwest,
including Chicago. Northern Border Pipeline shippers can arrange transportation,
displacement and exchange arrangements with third parties to provide access
beyond Chicago to markets throughout the United States.
The Pipeline System consists of 822 miles of 42-inch diameter pipe designed
to transport 2,373 MMcfd from the Canadian border to Ventura, Iowa; 30-inch
diameter pipe and 36-inch diameter pipe, each approximately 147 miles in length,
designed to transport 1,300 MMcfd from Ventura, Iowa to Harper, Iowa; and 226
miles of 36-inch diameter pipe and 19 miles of 30-inch diameter pipe designed to
transport 645 MMcfd from Harper, Iowa to a terminus near Manhattan, Illinois
(Chicago area). Along the pipeline there are fifteen compressor stations with
total rated horsepower of 476,500 and measurement facilities to support the
receipt and delivery of gas at various points. Other facilities include five
field offices and a microwave communication system with fifty-one tower sites.
Interconnects
Interconnecting pipeline facilities provide Northern Border Pipeline's
shippers with flexible access to natural gas markets. The Pipeline System
interconnects with pipeline facilities of:
- Northern Natural Gas Company, an Enron subsidiary, at Ventura, Iowa as
well as multiple smaller interconnections in South Dakota, Minnesota and
Iowa;
- Natural Gas Pipeline Company of America at Harper, Iowa;
- MidAmerican Energy Company at Iowa City and Davenport, Iowa;
- Interstate Power Company at Prophetstown, Illinois;
- Northern Illinois Gas Company at Troy Grove and Minooka, Illinois;
- Midwestern Gas Transmission Company near Channahon, Illinois; and
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<PAGE> 17
- ANR Pipeline Company near Manhattan, Illinois; and
- The Peoples Gas Light and Coke Company near Manhattan,Illinois (Chicago
area) at the terminus of the Pipeline System.
At its northern end, the Pipeline System is connected to the Foothills Pipe
Lines (Sask.) Ltd. System in Canada, which in turn is connected to the pipeline
systems of NOVA Gas Transmission Ltd. in Alberta and of Transgas Limited in
Saskatchewan. The NOVA system gathers and transports a substantial portion of
Canadian natural gas production. The Pipeline System also connects with the
facilities of Williston Basin Interstate pipeline at Glen Ullin and Buford,
North Dakota, facilities of Amerada Hess Corporation at Watford City, North
Dakota and facilities of Dakota Gasification Company at Hebron, North Dakota in
the northern portion of the system.
Project 2000
In October 1998, Northern Border Pipeline filed a certificate application
with FERC to seek approval of its Project 2000 that seeks to expand and extend
the Pipeline System into Indiana by November 2000. In addition to providing
additional Canadian natural gas to United States' markets, Project 2000 would
afford shippers on the extended pipeline system access to industrial gas
consumers in northern Indiana.
Shippers
The Pipeline System serves a number of shippers with diverse financial and
business profiles. Based on shippers' cost of service obligations, 93% of the
capacity is contracted by producers and marketers. The remaining capacity is
contracted primarily by local distribution companies (5%) and interstate
pipelines (2%). At present, the termination dates of these contracts range from
October 31, 2001 to December 21, 2013. The weighted average contract life as of
December 31, 1998 (based on shippers' cost of service obligations) is slightly
under 8 years with 97% of capacity contracted through at least mid-September
2003.
Northern Border Pipeline's largest shipper, Pan-Alberta Gas U.S., Inc.
("PAGUS"), currently holds 707 MMcfd, 26.5% of the capacity under three
transportation contracts. An affiliate of Enron provides guaranties for 300
MMcfd of PAGUS' contractual obligations through October 31, 2001. In addition,
PAGUS' remaining capacity is supported by various credit support arrangements
including, among others, a letter of credit, a guaranty from an interstate
pipeline company through October 31, 2001 for 150 MMcfd, an escrow account and
an upstream capacity transfer agreement.
In 1998, the Western Canadian Sedimentary Basin was the source of
approximately 88% of the natural gas transported by the Pipeline System. We
estimate that the Pipeline System's share of Canadian gas exported to the United
States in January 1999, the first full month of operations of The Chicago
Project, was nearly 24%.
Competition
Northern Border Pipeline competes with other pipeline companies that
transport gas from the Western Canadian Sedimentary Basin or that transport gas
to end-use markets in the Midwest. Its competitive position is affected by the
availability of Canadian natural gas for export and demand for natural gas in
the United States. Shippers of gas produced in the Western Canadian Sedimentary
Basin have other options to transport Canadian natural gas to the United States,
including transportation on pipelines eastward in Canada or to markets on the
West Coast.
The sponsors of the Alliance Pipeline project recently received Canadian
and United States regulatory approvals for the construction of a new pipeline to
originate in western Canada and terminate in the vicinity of Chicago, Illinois.
These sponsors have announced their plans for the pipeline to be in service by
October 2000. If constructed, the new pipeline would compete directly with
Northern Border Pipeline by transporting gas from the Western Canadian
Sedimentary Basin to the midwestern United States. Although there may be a large
increase in natural gas moving from the Western Canadian Sedimentary
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<PAGE> 18
Basin into the Chicago market if the Alliance project is constructed, there are
several additional projects proposed to transport natural gas from the Chicago
area to growing eastern markets. The proposed projects, currently being pursued
by unrelated third parties, are targeting markets in eastern Canada and the
northeast United States. None of these proposed projects has received final
regulatory approval.
CONFLICTS OF INTEREST AND FIDUCIARY RESPONSIBILITIES
Our business is managed by or under the direction of a three person
Partnership Policy Committee, whose members are designated by our three General
Partners. We have three representatives on the Northern Border Pipeline
Management Committee, each of whom votes a portion of our 70% voting interest on
the Northern Border Pipeline Management Committee. Our representatives on the
Northern Border Pipeline Management Committee are also designated by our General
Partners.
Our interests could conflict with the interests of our General Partners or
their affiliates, and in such case the members of our Partnership Policy
Committee will generally have a fiduciary duty to resolve such conflicts in a
manner that is in our best interest. Northern Border Pipeline's interests could
conflict with our interest or the interests of the TransCanada Subsidiaries and
their affiliates, and in such case our representatives on the Northern Border
Pipeline Management Committee will generally have a fiduciary duty to resolve
such conflicts in a manner that is in the best interest of Northern Border
Pipeline. Our fiduciary duty as a general partner of Northern Border Pipeline
may restrict us from taking actions that might be in our best interests but in
conflict with the fiduciary duty that our representatives or we owe to the
TransCanada Subsidiaries.
Unless otherwise provided for in a partnership agreement, the laws of
Delaware and Texas generally require a general partner of a partnership to
adhere to fiduciary duty standards, under which it owes its partners the highest
duties of good faith, fairness and loyalty. Similar rules apply to persons
serving on our Partnership Policy Committee or the Northern Border Pipeline
Management Committee. Because of the competing interests identified above, our
Partnership Agreement and the partnership agreement for Northern Border Pipeline
contain provisions that modify certain of these fiduciary duties. For example:
- Our Partnership Agreement states that the General Partners, their
affiliates and their officers and directors will not be liable for
monetary damages to us, our limited partners or their assignees for
errors of judgment or for any acts or omissions if the General Partners
and such other persons acted in good faith.
- Our Partnership Agreement allows the General Partners and our Partnership
Policy Committee to take into account the interests of parties in
addition to ours in resolving conflicts of interest.
- Our Partnership Agreement provides that the General Partners will not be
in breach of their obligations under our Partnership Agreement or their
duties to us or our unitholders if the resolution of a conflict is fair
and reasonable to us. The latitude given in our Partnership Agreement in
connection with resolving conflicts of interest may significantly limit
the ability of a unitholder to challenge what might otherwise be a breach
of fiduciary duty.
- Our Partnership Agreement provides that a purchaser of Common Units is
deemed to have consented to certain conflicts of interest and actions of
the General Partners and their affiliates that might otherwise be
prohibited and to have agreed that such conflicts of interest and actions
do not constitute a breach by the General Partners of any duty stated or
implied by law or equity.
- Our audit committee (which is composed of persons unaffiliated with any
of the General Partners) will, at the request of a General Partner or a
member of our Partnership Policy Committee, review conflicts of interest
that may arise between a General Partner and its affiliates (or the
member of our Partnership Policy Committee designated by it), on the one
hand, and our unitholders or us, on the other. Any resolution of a
conflict approved by our audit committee is conclusively deemed fair and
reasonable to us.
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<PAGE> 19
- We have proposed to enter into an amendment to the partnership agreement
for Northern Border Pipeline that relieves the TransCanada Subsidiaries,
their affiliates and their transferees from any duty to offer business
opportunities to Northern Border Pipeline, with certain exceptions. The
proposed amendment would also relieve us from any duty to offer to
Northern Border Pipeline certain business opportunities that come to our
attention.
We are required to indemnify the members of our Partnership Policy
Committee and General Partners, their affiliates and their respective officers,
directors, employees, agents and trustees to the fullest extent permitted by law
against liabilities, costs and expenses incurred by any such person who acted in
good faith and in a manner reasonably believed to be in, or (in the case of a
person other than one of the General Partners) not opposed to, our best
interests and, with respect to any criminal proceedings, had no reasonable cause
to believe the conduct was unlawful.
Some of our shippers are affiliated with our General Partners and the
TransCanada Subsidiaries. Enron Capital & Trade Resources Corp., a subsidiary of
Enron, and Transcontinental Gas Pipe Line Corporation, a subsidiary of Williams
hold 6.1% of the capacity. TransCanada PipeLines Limited, an affiliate of the
TransCanada Subsidiaries, holds 10.8% of the capacity.
FERC REGULATION
General
FERC extensively regulates Northern Border Pipeline as a "natural gas
company" under the Natural Gas Act (the "NGA"). Under the NGA and the Natural
Gas Policy Act, FERC has jurisdiction over Northern Border Pipeline with respect
to virtually all aspects of its business, including:
- Transportation of natural gas;
- Rates and charges;
- Construction of new facilities;
- Extension or abandonment of service and facilities;
- Accounts and records;
- Depreciation and amortization policies;
- Acquisition and disposition of facilities;
- Initiation and discontinuation of services; and
- Certain other matters.
Northern Border Pipeline, where required, holds certificates of public
convenience and necessity issued by FERC covering its facilities, activities and
services. Without these certificates, a pipeline company cannot legally do
business. Under Section 8 of the NGA, FERC has the power to prescribe the
accounting treatment for items for regulatory purposes. The Northern Border
Pipeline books and records are periodically audited pursuant to Section 8.
FERC regulates Northern Border Pipeline's rates and charges for
transportation in interstate commerce. Natural gas companies may not charge
rates exceeding rates deemed just and reasonable by FERC. In addition, FERC
prohibits natural gas companies from unduly preferring or unreasonably
discriminating against any person with respect to pipeline rates or terms and
conditions of service. Certain types of rates may be discounted without further
FERC authorization.
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<PAGE> 20
Cost of Service Tariff
Northern Border Pipeline's firm transportation shippers contract to pay for
an allocable share of the cost of service associated with the Pipeline System's
capacity. During any given month, all such shippers pay a uniform mileage-based
charge for the amount of capacity contracted, calculated under a cost of service
tariff. The shippers are obligated to pay their allocable share of the cost of
service regardless of the amount of gas they actually transport. The cost of
service tariff is regulated by FERC and provides Northern Border Pipeline an
opportunity to recover all operations and maintenance costs of the Pipeline
System, taxes other than income taxes, interest, depreciation and amortization,
an allowance for income taxes and a regulated equity return. Northern Border
Pipeline may not charge or collect more than its cost of service pursuant to its
tariff on file with FERC.
Northern Border Pipeline's investment in the Pipeline System is reflected
in various accounts referred to collectively as its regulated "rate base." The
cost of service includes a return, with related income taxes, on the rate base.
Over time the rate base declines as a result of, among other things, the monthly
depreciation and amortization. The Northern Border Pipeline rate base includes,
as an additional amount, a one-time ratemaking adjustment to reflect the receipt
of a construction incentive on the original project. Since inception the rate
base adjustment, called an incentive rate of return ("IROR"), has been amortized
through monthly additions to the cost of service. As a result, our revenues and
net income for 1998 included $9.9 million for such amortization along with
related income taxes, net of the effect of minority interests. This impact on
revenues and net income is expected to continue until November 2001 when the
IROR is fully amortized.
Northern Border Pipeline bills the cost of service on an estimated basis
for a six-month cycle. Any net excess or deficiency resulting from the
comparison of the actual cost of service determined for that period according to
its FERC tariff to the estimated billing is accumulated, including carrying
charges thereon, and is either billed to or credited back to the shippers'
accounts.
Northern Border Pipeline also provides interruptible transportation
service. Interruptible transportation service is transportation in certain
circumstances when capacity is available after satisfying firm service requests.
The maximum rate charged to interruptible shippers is calculated from cost of
service estimates on the basis of contracted capacity. Except for certain
limited situations, Northern Border Pipeline credits back to the firm shippers
all revenue from the interruptible transportation service.
In its 1995 rate case, Northern Border Pipeline reached a settlement that
was filed in a Stipulation and Agreement (the "Stipulation"). Although it was
contested, it was approved by FERC on August 1, 1997. In the Stipulation, the
depreciation rate was established at 2.5% from January 1, 1997 through the
in-service date of The Chicago Project, and at that time it was reduced to 2%.
Starting in the year 2000, the depreciation rate is scheduled to increase
gradually on an annual basis until it reaches 3.2% in 2002.
The Stipulation also determined several other cost of service parameters.
In accordance with the effective tariff, Northern Border Pipeline's allowed
equity rate of return is 12%. For at least seven years from the date The Chicago
Project was completed, Northern Border Pipeline, under the terms of the
Stipulation, may continue to calculate its allowance for income taxes as a part
of its cost of service in the manner it has historically used. In addition, a
settlement adjustment mechanism of $31 million was implemented, which
effectively reduces the allowed return on rate base.
Also as agreed to in the Stipulation, Northern Border Pipeline implemented
a capital project cost containment mechanism ("PCCM"). The purpose of the PCCM
was to limit Northern Border Pipeline's ability to include cost overruns on The
Chicago Project in rate base and to provide incentives to Northern Border
Pipeline for cost underruns. The PCCM amount is determined by comparing the
final cost of The Chicago Project to the budgeted cost. If there is a cost
overrun of $6 million or less, the shippers will bear the actual cost of the
project through its inclusion in Northern Border Pipeline's rate base. If there
is a cost savings of $6 million or less, the full budgeted cost will be included
in the rate base. If there is a cost overrun or cost savings of more than $6
million but less than 5% of the budgeted cost, that amount will be allocated 50%
to Northern Border Pipeline and 50% to its shippers (50% of the difference
between 5% of
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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
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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.
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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.
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<PAGE> 24
The Subordinated Indenture may not contain any similar provisions. We have
described below these provisions and some of the defined terms used in them.
Provisions Only in the Subordinated Indenture
Subordinated Debt Securities Subordinated to Senior Debt
The Subordinated Debt Securities will rank junior in right of payment to
all of our Senior Debt. "Senior Debt" is defined to include all notes or other
evidences of indebtedness, including our guarantees for money we borrowed, not
expressed to be subordinate or junior in right of payment to any other of our
indebtedness.
Payment Blockages
The Subordinated Indenture may provide that no payment of principal,
interest and any premium on the Subordinated Debt Securities may be made in the
event that we fail to pay when due any amounts on any Senior Debt and in other
instances specified in the Indenture.
No Limitation on Amount of Senior Debt
The Subordinated Indenture will not limit the amount of Senior Debt that we
may incur.
Modification of Indentures
Under each Indenture, generally the Trustee and we may modify our rights
and obligations and the rights of the holders with the consent of the holders of
a specified percentage of the outstanding holders of each series of debt
affected by the modification. No modification of the principal or interest
payment terms, and no modification reducing the percentage required for
modifications, is effective against any holder without its consent. In addition,
the Trustee and we may amend the Indentures without the consent of any holder of
the Debt Securities to make certain technical changes.
Events of Default and Remedies
"Event of Default" will be defined in the Indenture.
Registration of Notes
We may issue Debt Securities of a series in registered, bearer, coupon or
global form.
No Personal Liability of the General Partners
Unless otherwise stated in a prospectus supplement and supplemental
indenture relating to a series of Debt Securities being offered, the General
Partners and their directors, officers, employees and shareholders will not have
any liability for our obligations under the Indentures or the Debt Securities.
Each holder of Debt Securities by accepting a Debt Security waives and releases
all such liability. The waiver and release are part of the consideration for the
issuance of the Debt Securities.
Book Entry, Delivery and Form
The Debt Securities of a series may be issued in whole or in part in the
form of one or more global certificates that will be deposited with a depositary
identified in a prospectus supplement.
Unless otherwise stated in any prospectus supplement, The Depository Trust
Company, New York, New York ("DTC") will act as depositary. Book-entry notes of
a series will be issued in the form of a global note that will be deposited with
DTC. This means that we will not issue certificates to each holder. One global
note will be issued to DTC who will keep a computerized record of its
participants (for example, your broker) whose clients have purchased the notes.
The participant will then keep a record of its clients who purchased the notes.
Unless it is exchanged in whole or in part for a certificate note, a
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<PAGE> 25
global note may not be transferred; except that DTC, its nominees and their
successors may transfer a global note as a whole to one another.
Beneficial interests in global notes will be shown on, and transfers of
global notes will be made only through, records maintained by DTC and its
participants.
DTC has provided us the following information: DTC is a limited-purpose
trust company organized under the New York Banking Law, a "banking organization"
within the meaning of the New York Banking Law, a member of the United States
Federal Reserve System, a "clearing corporation" within the meaning of the New
York Uniform Commercial Code and a "clearing agency" registered under the
provisions of Section 17A of the Exchange Act. DTC holds securities that its
participants ("Direct Participants") deposit with DTC. DTC also records the
settlement among Direct Participants of securities transactions, such as
transfers and pledges, in deposited securities through computerized records for
Direct Participants' accounts. This eliminates the need to exchange
certificates. Direct Participants include securities brokers and dealers, banks,
trust companies, clearing corporations and certain other organizations.
DTC's book-entry system is also used by other organizations such as
securities brokers and dealers, banks and trust companies that work through a
Direct Participant. The rules that apply to DTC and its participants are on file
with the SEC.
DTC is owned by a number of its Direct Participants and by the New York
Stock Exchange, Inc., The American Stock Exchange, Inc. and the National
Association of Securities Dealers, Inc.
We will wire principal and interest payments to DTC's nominee. We and the
Trustee will treat DTC's nominee as the owner of the global notes for all
purposes. Accordingly, we, the Trustee and any paying agent will have no direct
responsibility or liability to pay amounts due on the global notes to owners of
beneficial interests in the global notes.
It is DTC's current practice, upon receipt of any payment of principal or
interest, to credit Direct Participants' accounts on the payment date according
to their respective holdings of beneficial interests in the global notes as
shown on DTC's records. In addition, it is DTC's current practice to assign any
consenting or voting rights to Direct Participants whose accounts are credited
with notes on a record date, by using an omnibus proxy. Payments by participants
to owners of beneficial interests in the global notes, and voting by
participants, will be governed by the customary practices between the
participants and owners of beneficial interests, as is the case with notes held
for the account of customers registered in "street name." However, payments will
be the responsibility of the participants and not of DTC, the Trustee or us.
Debt Securities represented by a global note will be exchangeable for
certificated notes with the same terms in authorized denominations only if:
- DTC notifies us that it is unwilling or unable to continue as depositary
or if DTC ceases to be a clearing agency registered under applicable law
and a successor depositary is not appointed by us within 90 days; or
- We determine not to require all of the Debt Securities of a series to be
represented by a global note and notify the Trustee of our decision.
The Trustee
The Trustee will have duties, responsibilities and rights as specified in
the Indenture.
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RATIO OF EARNINGS TO FIXED CHARGES
<TABLE>
<CAPTION>
NINE MONTHS
ENDED
SEPTEMBER 30, YEAR ENDED DECEMBER 31, PRO FORMA* YEAR
------------- ------------------------- ENDED DECEMBER 31,
1998 1997 1997 1996 1995 1994 1993
----- ----- ---- ---- ---- ---- ------------------
<S> <C> <C> <C> <C> <C> <C> <C>
Ratio of earnings to Fixed Charges.... 3.1 3.2 3.2 3.2 3.1 3.0 2.8
=== === === === === === ===
</TABLE>
---------------
* 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.
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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;
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<PAGE> 28
- We have been and will be operated in accordance with all applicable
partnership statutes and our Partnership Agreement and in the manner
described herein;
- Except as otherwise required by Section 704 of the Code and regulations
promulgated thereunder, the General Partners have had and will have, in
the aggregate, an interest in each material item of our income, gain,
loss, deduction or credit equal to at least 1% at all times during our
existence;
- A representation and covenant of the General Partners that the General
Partners have and will maintain, in the aggregate, a minimum capital
account balance in us equal to 1% of our total positive capital account
balances;
- For each taxable year, less than 10% of our gross income has been and
will be derived from sources other than (i) the exploration, development,
production, processing, refining, transportation or marketing of any
mineral or natural resource, including oil, gas or products thereof and
naturally occurring carbon dioxide or (ii) other items of "qualifying
income" within the meaning of Section 7704(d) of the Code; and
- Northern Border Pipeline is organized and will be operated in accordance
with the Texas Revised Uniform Partnership Act and the Northern Border
Pipeline Partnership Agreement.
Counsel's opinion as to our partnership classification in the event of a
change in the General Partners is based upon the assumption that the new general
partners will satisfy the foregoing representations and covenants.
Section 7704 of the Code provides that publicly-traded partnerships will,
as a general rule, be taxed as corporations. However, an exception (the "Natural
Resource Exception") exists with respect to publicly-traded partnerships 90% or
more of the gross income of which for every taxable year consists of "qualifying
income." Qualifying income includes income and gains derived from the
transportation of natural gas and coal. Other types of qualifying income include
interest, dividends, gains from the sale of real property and gains from the
sale or other disposition of capital assets held for the production of income
that otherwise constitutes qualifying income. We have represented that in excess
of 90% of our gross income has been and will be derived from fees and charges
for transporting (through the Pipeline System) natural gas. Based upon that
representation, Counsel is of the opinion that our gross income derived from
these sources constitutes qualifying income.
If we fail to meet the Natural Resource Exception (other than a failure
determined by the IRS to be inadvertent that is cured within a reasonable time
after discovery), we will be treated as if we had transferred all of our assets
(subject to liabilities) to a newly-formed corporation (on the first day of the
year in which we fail to meet the Natural Resource Exception) in return for
stock in such corporation, and then distributed such stock to the partners in
liquidation of their interests in us. This contribution and liquidation should
be tax-free to our unitholders and us, so long as we, at such time, do not have
liabilities in excess of the basis of our assets. Thereafter, we would be
treated as a corporation for federal income tax purposes.
If we were treated as an association or otherwise taxable as a corporation
in any taxable year, as a result of a failure to meet the Natural Resource
Exception or otherwise, our items of income, gain, loss, deduction and credit
would be reflected only on our tax return rather than being passed through to
our unitholders, and our net income would be taxed at the entity level at
corporate rates. In addition, any distribution made to a unitholder would be
treated as either taxable dividend income (to the extent of our current or
accumulated earnings and profits), in the absence of earnings and profits as a
nontaxable return of capital (to the extent of the unitholder's basis in his
Common Units) or taxable capital gain (after the unitholder's basis in the
Common Units is reduced to zero). Accordingly, our treatment as an association
taxable as a corporation would result in a material reduction in a unitholder's
cash flow and after-tax return.
The discussion below is based on the assumption that we will be classified
as a partnership for federal income tax purposes.
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<PAGE> 29
Limited Partner Status
Our unitholders who have become limited partners will be treated as
partners for federal income tax purposes. Moreover, the IRS has ruled that
assignees of partnership interests who have not been admitted to a partnership
as partners, but who have the capacity to exercise substantial dominion and
control over the assigned partnership interests, will be treated as partners for
federal income tax purposes. On the basis of this ruling, except as otherwise
described herein, Counsel is of the opinion that (a) assignees who have executed
and delivered Transfer Applications and are awaiting admission as limited
partners and (b) our unitholders whose Common Units are held in street name or
by another nominee and who have the right to direct the nominee in the exercise
of all substantive rights attendant to the ownership of their Common Units will
be treated as partners for federal income tax purposes. As this ruling does not
extend, on its facts, to assignees of Common Units who are entitled to execute
and deliver Transfer Applications and thereby become entitled to direct the
exercise of attendant rights, but who fail to execute and deliver Transfer
Applications, Counsel's opinion does not extend to these persons. Income, gain,
deductions, losses or credits would not appear to be reportable by such a
unitholder, and any cash distributions received by such a unitholder would
therefore be fully taxable as ordinary income. These holders should consult
their own tax advisors with respect to their status as partners for federal
income tax purposes. A purchaser or other transferee of Common Units who does
not execute and deliver a Transfer Application may not receive certain federal
income tax information or reports furnished to record holders of Common Units
unless the Common Units are held in a nominee or street name account and the
nominee or broker has executed and delivered a Transfer Application with respect
to such Common Units.
A beneficial owner of Common Units whose Common Units have been transferred
to a short seller to complete a short sale would appear to lose his status as a
partner with respect to such Common Units for federal income tax purposes. See
"Tax Considerations -- Tax Treatment of Operations -- Treatment of Short Sales."
Tax Consequences of Common Unit Ownership
Flow-Through of Taxable Income
We will pay no federal income tax. Instead, each unitholder will be
required to report on his income tax return his allocable share of our income,
gains, losses and deductions without regard to whether corresponding cash
distributions are received by such unitholder. Consequently, we may allocate
income to a unitholder although he has not received a cash distribution in
respect of such income.
Treatment of Partnership Distributions
Our distributions to a unitholder generally will not be taxable to the
unitholder for federal income tax purposes to the extent of his basis in his
Common Units immediately before the distribution. Cash distributions in excess
of a Common Unitholder's basis generally will be considered to be gain from the
sale or exchange of the Common Units, taxable in accordance with the rules
described under "Tax Considerations -- Disposition of Common Units." Any
reduction in a Common Unitholder's share of our liabilities for which no
partner, including the General Partners, bears the economic risk of loss
("nonrecourse liabilities") will be treated as a distribution of cash to such
unitholder.
Basis of Common Units
A unitholder's initial tax basis for his Common Units will be the amount
paid for the Common Units plus his share of our nonrecourse liabilities. The
initial tax basis for a Common Unit will be increased by the unitholder's share
of our income and by any increase in the unitholder's share of our nonrecourse
liabilities. The basis for a Common Unit will be decreased (but not below zero)
by our distributions, including any decrease in the unitholder's share of our
nonrecourse liabilities, by the unitholder's share of our losses and by the
unitholder's share of our expenditures that are not deductible in computing his
taxable income and are not required to be capitalized. A unitholder's share of
our nonrecourse liabilities will be generally based on the unitholder's share of
our profits.
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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.
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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
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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
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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
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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
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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.
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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
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("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
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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%
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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,
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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.
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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.
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WE HAVE NOT AUTHORIZED ANYONE TO PROVIDE INFORMATION DIFFERENT FROM THAT
CONTAINED IN THIS PROSPECTUS SUPPLEMENT AND THE ACCOMPANYING PROSPECTUS. NEITHER
THE DELIVERY OF THIS PROSPECTUS SUPPLEMENT AND THE ACCOMPANYING PROSPECTUS NOR
THE SALE OF COMMON UNITS MEANS THAT THE INFORMATION CONTAINED IN THIS PROSPECTUS
SUPPLEMENT AND THE ACCOMPANYING PROSPECTUS IS CORRECT AFTER THE DATES OF THIS
PROSPECTUS AND THE ACCOMPANYING PROSPECTUS. THIS PROSPECTUS SUPPLEMENT AND THE
ACCOMPANYING PROSPECTUS ARE NOT AN OFFER TO SELL OR A SOLICITATION OF AN OFFER
TO BUY THESE COMMON UNITS IN ANY CIRCUMSTANCES UNDER WHICH THE OFFER OR
SOLICITATION IS UNLAWFUL.
------------------------
TABLE OF CONTENTS
<TABLE>
<CAPTION>
PAGE
----
<S> <C>
PROSPECTUS SUPPLEMENT
Northern Border Partners.............. S-1
Recent Developments................... S-3
Ratio of Taxable Income to
Distributions....................... S-4
Recent Tax Developments............... S-5
Use of Proceeds....................... S-6
Price Range of Common Units and
Distributions....................... S-6
Capitalization........................ S-7
Underwriting.......................... S-8
Legal Matters......................... S-9
Experts............................... S-9
PROSPECTUS
The Offered Securities................ 2
Where You Can Find More Information... 2
Cautionary Statement Regarding Forward
Looking Statements.................. 3
Our Business.......................... 4
Conflicts of Interest and Fiduciary
Responsibilities.................... 7
FERC Regulation....................... 8
Environmental and Safety Costs and
Liabilities......................... 11
Common Units.......................... 11
Debt Securities....................... 12
Ratio of Earnings to Fixed Charges.... 15
Use of Proceeds....................... 15
Tax Considerations.................... 15
Plan of Distribution.................. 29
Legal Matters......................... 30
Experts............................... 30
</TABLE>
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1,875,000 COMMON UNITS
NORTHERN BORDER
PARTNERS, L.P.
REPRESENTING
LIMITED PARTNER INTERESTS
------------------------
PROSPECTUS SUPPLEMENT
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PAINEWEBBER INCORPORATED
SALOMON SMITH BARNEY
LEHMAN BROTHERS
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NOVEMBER 1, 2000
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