<PAGE>
                                  UNITED STATES
                       SECURITIES AND EXCHANGE COMMISSION
                             Washington, D.C. 20549

                                    FORM 10-K

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

     For the fiscal year ended DECEMBER 31, 2005

                                       or

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

     For the transition period from _______ to ________.

                        Commission File Number: 333-88577

                        NORTHERN BORDER PIPELINE COMPANY
             (Exact name of registrant as specified in its charter)

<TABLE>
<S>                                                       <C>
                  TEXAS                                         74-2684967
     (State or other jurisdiction of                         (I.R.S. Employer
     incorporation or organization)                       Identification Number)
</TABLE>

<TABLE>
<S>                                                             <C>
            13710 FNB PARKWAY
             OMAHA, NEBRASKA                                    68154-5200
(Address of principal executive offices)                        (Zip code)
</TABLE>

                                 (402) 492-7300
              (Registrant's telephone number, including area code)

        Securities registered pursuant to Section 12(b) of the Act: None

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

Indicate by check mark if the registrant is a well-known seasoned issuer, as
defined in Rule 405 of the Securities Act.                       Yes [ ]  No [X]

Indicate by check mark if the registrant is not required to file reports
pursuant to Section 13 or Section 15(d) of the Act.              Yes [ ]  No [X]

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

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

Indicate by check mark whether the registrant is an accelerated filer (as
defined in Rule 12b-2 of the Act).                                Yes [ ] No [X]

Indicate by check mark whether the registrant is a shell company (as defined in
Rule 12b-2 of the Act).                                           Yes [ ] No [X]

The aggregate market value of the voting and non-voting common equity held by
non-affiliates of the registrant as of June 30, 2005, was $0.

                       DOCUMENTS INCORPORATED BY REFERENCE
                                      None

<PAGE>

                        NORTHERN BORDER PIPELINE COMPANY
                           ANNUAL REPORT ON FORM 10-K

                                TABLE OF CONTENTS

<TABLE>
<CAPTION>
                                                                        Page No.
                                                                        --------
<S>                                                                     <C>
                                     PART I

Item 1.  Business
            General Development of Business..........................       4
            Narrative Description of Business........................       5
            Environmental and Safety Matters.........................      10
            Employees................................................      10
Item 1A. Risk Factors................................................      11
Item 1B. Unresolved Staff Comments...................................      14
Item 2.  Properties..................................................      14
Item 3.  Legal Proceedings...........................................      14
Item 4.  Submission of Matters to a Vote of Security Holders.........      14

                                     PART II

Item 5.  Market for Registrant's Common Equity, Related Stockholder
            Matters and Issuer Purchases of Equity Securities........      14
Item 6.  Selected Financial Data.....................................      15
Item 7.  Management's Discussion and Analysis of Financial Condition
            and Results of Operations
            Executive Summary........................................      16
            Critical Accounting Estimates............................      18
            Results of Operations....................................      19
            Liquidity and Capital Resources..........................      20
            Recent Accounting Pronouncements.........................      23
            Forward-Looking Statements...............................      23
Item 7A. Quantitative and Qualitative Disclosures about Market Risk..      24
Item 8.  Financial Statements and Supplementary Data.................      24
Item 9.  Changes in and Disagreements with Accountants on Accounting
            and Financial Disclosure.................................      24
Item 9A. Controls and Procedures.....................................      24
Item 9B. Other Information...........................................      25

                                    PART III

Item 10. Directors and Executive Officers of the Registrant..........      25
Item 11. Executive Compensation......................................      27
Item 12. Security Ownership of Certain Beneficial Owners and
            Management and Related Stockholder Matters...............      34
Item 13. Certain Relationships and Related Transactions..............      34
Item 14. Principal Accounting Fees and Services......................      36

                                     PART IV

Item 15. Exhibits and Financial Statement Schedules..................      36
</TABLE>


                                        2

<PAGE>

GLOSSARY

The abbreviations, acronyms, and industry terminology used in this annual report
are defined as follows:

<TABLE>
<S>                              <C>
Bcf/d.........................   Billion cubic feet per day
Btu/cf........................   British thermal units per cubic feet
CCE Holdings..................   CCE Holdings, LLC, a Southern Union Company
                                    and GE Commercial Finance Energy Financial
                                    joint venture
Design capacity...............   Pipeline capacity available to transport
                                    natural gas based on system facilities and
                                    design conditions
Enron.........................   Enron Corp.
Enron North America...........   Enron North America Corp.
Exchange Act..................   Securities Exchange Act of 1934
FASB..........................   Financial Accounting Standards Board
FERC..........................   Federal Energy Regulatory Commission
GAAP..........................   Generally accepted accounting principles
MMcf/d........................   Million cubic feet per day
NBP Services..................   NBP Services, LLC, a ONEOK subsidiary
NOAA..........................   National Oceanic and Atmospheric Administration
Northern Border Partners......   Northern Border Partners, L.P. and Northern
                                    Border Partners Intermediate Limited
                                    Partnership
Northern Border Pipeline......   Northern Border Pipeline Company
Northern Plains...............   Northern Plains Natural Gas Company, LLC, a
                                    ONEOK subsidiary
Northwest Border..............   Northwest Border Pipeline Company, a subsidiary
                                    of TransCanada PipeLines Limited
NYSE..........................   New York Stock Exchange
ONEOK.........................   ONEOK, Inc.
ONEOK Energy..................   ONEOK Energy Services Company, LP,
                                    a ONEOK subsidiary
Pan Border....................   Pan Border Gas Company, LLC, a ONEOK subsidiary
SEC...........................   Securities and Exchange Commission
SFAS..........................   Statement of Financial Accounting Standards
TC PipeLines Intermediate.....   TC PipeLines Intermediate Limited Partnership,
                                    a subsidiary of TC PipeLines, LP
TransCanada...................   TransCanada Corporation
U.S...........................   United States
</TABLE>

The statements in this annual report that are not historical information,
including statements concerning plans and objectives of management for future
operations, economic performance or related assumptions, are forward-looking
statements within the meaning of Section 27A of the Securities Act of 1933 and
Section 21E of the Securities Exchange Act of 1934. Forward-looking statements
may include words such as "anticipate," "estimate," "expect," "project,"
"intend," "plan," "believe," "should" and other words and terms of similar
meaning. Although we believe that our expectations regarding future events are
based on reasonable assumptions, we can give no assurance that our goals will be
achieved. Important factors that could cause actual results to differ materially
from those in the forward-looking statements are described under Item 1A, "Risk
Factors."


                                        3

<PAGE>

                                     PART I

ITEM 1. BUSINESS

GENERAL DEVELOPMENT OF BUSINESS

In this report, references to "we," "us" or "our" collectively refer to Northern
Border Pipeline Company.

OVERVIEW

Northern Border Pipeline is a Texas general partnership formed in 1978. Northern
Border Partners owns a 70% general partner interest and TC PipeLines
Intermediate owns the remaining 30%. Northern Border Partners is a
publicly-traded partnership. We provide natural gas transportation services and
are a leading transporter of natural gas imported from Canada into the U.S.

PARTNERSHIP STRUCTURE

The general partners of Northern Border Partners and its subsidiary limited
partnership, Northern Border Intermediate Limited Partnership, are Northern
Plains, Pan Border and Northwest Border. Northern Plains and Pan Border are
subsidiaries of ONEOK. Northwest Border is a subsidiary of TransCanada PipeLines
Limited, a subsidiary of TransCanada.

We are managed by a management committee that consists of four members: one
representative designated by each of Northern Border Partners' three general
partners and one representative designated by TC PipeLines Intermediate. TC
PipeLines Intermediate is a subsidiary of TC PipeLines, LP, a publicly-traded
partnership. The general partner of TC PipeLines, LP is TC PipeLines GP, Inc.,
which is a subsidiary of TransCanada.

On February 14, 2006, our general partners entered into a Partnership Interest
Purchase and Sale Agreement dated as of December 31, 2005, under which Northern
Border Partners agreed to sell a 20% partnership interest in us to TC PipeLines
Intermediate. Information about the proposed transaction is included under
"Recent Developments-Proposed Transaction" of this section.

At December 31, 2005, the voting interests of the Management Committee were as
follows:

<TABLE>
<CAPTION>
MEMBER DESIGNATED BY        VOTING INTEREST
--------------------        ---------------
<S>                         <C>
Northern Plains                     35%
Pan Border                       22.75%
Northwest Border                 12.25%
TC PipeLines Intermediate           30%
</TABLE>

BUSINESS STRATEGY

We focus on safe, efficient and reliable operations and further development of
our pipeline. We intend to continue to cost-effectively transport Canadian
natural gas to the Midwestern U.S. We seek growth of our interstate natural gas
pipeline through incremental projects that access new market areas and are
supported by long-term transportation contracts. Our priorities in 2006 include:
marketing our available transportation capacity, actively processing our current
rate case before the FERC and placing the Chicago III Expansion Project into
service.

RECENT DEVELOPMENTS

The following is a summary of our significant developments during 2005.
Additional information regarding most of these items may be found elsewhere in
this annual report or in previous reports filed with the SEC.

Contracting - During 2005, short-term firm service transportation contracts
partially replaced expired contracts and continued to expose us to seasonal
demand. As a result, we did not sell all of our available capacity and firm
transportation revenue decreased 5% compared with 2004 when our transportation
capacity was sold out at maximum rates. To maximize overall revenue, we
discounted transportation rates during certain periods of the year.


                                        4

<PAGE>

Credit Agreement - In May 2005, we entered into a five-year, $175 million
revolving credit agreement. We terminated our previously existing $175 million
credit facility in conjunction with the execution of the new agreement.

Bankruptcy Claims - In June 2005, we executed term sheets with a third party for
the sale of our bankruptcy claims against Enron and Enron North America.
Proceeds from the sale of the claims were $11.1 million.

Chicago III Expansion Project - In September 2005, we accepted the FERC's
certificate of public convenience and necessity for the Chicago III Expansion
Project. This project will add 130 MMcf/d of transportation capacity on the
eastern portion of the pipeline into the Chicago area. It is estimated that the
project will cost approximately $21 million and the target in-service date is
April 2006.

Rate Case - On November 1, 2005, we filed a rate case with the FERC as required
by the provisions of the settlement of our last rate case. The rate case filing
proposes, among other things, a 7.8% increase in our revenue requirement; a
change to our rate design approach with a supply zone and market area utilizing
a fixed rate per dekatherm and a dekatherm-mile rate, respectively; an increase
in the depreciation rate for transmission plant; the implementation of a
short-term rate structure on a prospective basis; and the continued inclusion of
income taxes in the rate calculation. In December 2005, the FERC issued an order
that identified issues that were raised in the proceeding, accepted the proposed
rates but suspended their effectiveness until May 1, 2006, at which time the new
rates will be collected subject to refund until final resolution of the rate
case. The FERC also issued a procedural schedule which set a hearing
commencement date of October 4, 2006, with an initial decision scheduled for
February 2007, unless a settlement of the issues is reached with the FERC and a
majority of our customers.

Proposed Transaction - On February 14, 2006, our general partners entered into a
Partnership Interest Purchase and Sale Agreement (PIPA) dated as of December 31,
2005, under which Northern Border Partners agreed to sell a 20% partnership
interest in us to TC PipeLines Intermediate in exchange for an aggregate cash
amount of $300 million and the assumption of certain liabilities and
obligations. The PIPA contains customary and other closing conditions that, if
not satisfied or waived, would result in the sale not occurring, including:
continued accuracy of the representations and warranties contained in the
agreements; performance by each party of its obligations under the PIPA;
consummation of ONEOK's purchase of Northwest Border from TransCanada;
consummation of the acquisition of certain ONEOK business segments by Northern
Border Partners; and the absence of any decree, order, injunction or law that
prohibits, restricts or substantially delays the transaction or makes the
transaction unlawful.

Upon closing of the sale of the 20% partnership interest, several things will
occur, including:

     -    our general partners will amend our partnership agreement, the
          Northern Border Pipeline Company General Partnership Agreement, to
          modify certain governance and operating terms;

     -    TC PipeLines Intermediate will appoint a new Management Committee
          chairman and other members of the Management Committee may change;

     -    we will enter into a pipeline operating agreement with an affiliate of
          TransCanada, under which the affiliate of TransCanada will become our
          operator, effective April 1, 2007;

     -    our current operator, Northern Plains or one of its affiliates, will
          enter into a transition services agreement with TransCanada or one of
          its affiliates, for reimbursement of all transitional support expenses
          incurred; and

     -    we will adopt certain changes to our cash distribution policy related
          to financial ratio targets and capital contributions.

NARRATIVE DESCRIPTION OF BUSINESS

OVERVIEW

We transport natural gas along 1,249 miles of pipeline with a design capacity of
approximately 2.4 Bcf/d. Our transportation network provides pipeline access to
the Midwestern U.S. from natural gas reserves in the Western Canada Sedimentary
Basin, which is located in the Canadian provinces of Alberta, British Columbia
and Saskatchewan.

                                        5

<PAGE>

Operating revenue is derived from transportation contracts at rates that are
included in our tariff. Transportation rates are established in a FERC
proceeding known as a rate case. Our tariff specifies the maximum rates we can
charge our customers and the general terms and conditions for natural gas
transportation service on our pipeline. During a rate case, a determination is
reached by the FERC, either through a hearing or a settlement, on maximum rates
permissible for interstate natural gas transportation service that include the
recovery of our prudent cost-based investment, operating expenses and a
reasonable return for our investors. Our tariff also allows for services to be
provided under negotiated and discounted rates. Once rates are set in a rate
case, we are not permitted to increase rates if costs increase or contract
demand decreases, nor are we required to reduce rates based on cost savings
until a new rate case is filed and completed. As a result, our earnings and cash
flow depend on costs incurred, contracted capacity, the volume of gas
transported and our ability to recontract capacity at acceptable rates.

Our transportation contracts include specifications regarding the receipt and
delivery of natural gas at points along the pipeline system. The type of
transportation contract, either firm or interruptible service, determines the
basis by which each customer is charged. Customers with firm service
transportation agreements pay a fee known as a demand charge to reserve pipeline
capacity, regardless of use, for the term of their contracts. Firm service
transportation customers also pay a fee known as a commodity charge that is
based on the volume of natural gas they transport. Customers with interruptible
service transportation agreements may utilize available capacity on our
pipelines after firm service transportation requests are satisfied.
Interruptible service customers are assessed commodity charges only. For the
year ended December 31, 2005, approximately 97% of our revenue was derived from
demand charges and the remaining 3% was attributable to commodity charges.

PIPELINE SYSTEM

We transport natural gas from the Montana-Saskatchewan border near Port of
Morgan, Montana to a terminus near North Hayden, Indiana. The system consists of
1,249 miles of pipeline with diameters ranging from 30 inches to 42 inches and a
design capacity of 2,374 MMcf/d. Along the pipeline are 16 compressor stations
with a total of 499,000 horsepower, measurement facilities to support the
receipt and delivery of gas at various points, four field offices and a
microwave communication system with 50 tower sites.

Construction of our pipeline was initially completed in 1982 followed by
expansions or extensions in 1991, 1992, 1998 and 2001. We filed an application
for a certificate of public convenience and necessity with the FERC for the
Chicago III Expansion Project in March 2005, which the FERC issued in September
2005. The Chicago III Expansion Project will add 130 MMcf/d of transportation
capacity from Harper, Iowa to the Chicago market area with the construction of a
new 16,000-horsepower compressor station in Iowa and minor modifications to two
other compressor stations in Iowa and Illinois. We estimate that the project
will cost approximately $21 million and the target in-service date is April
2006. This expansion is fully subscribed by four shippers under long-term firm
service transportation agreements with terms ranging from five and one-half
years to ten years.

TITLE TO PROPERTIES

We hold the right, title and interest in our pipeline system. With respect to
real property, we own sites for compressor stations, meter stations, pipeline
field offices and microwave towers, and derive interests from leases, easements,
rights-of-way, permits and licenses from landowners or governmental authorities
permitting land use for construction and operation of our pipelines.

Approximately 90 miles of our system are located within the boundaries of the
Fort Peck Indian Reservation in Montana. In 1980, we entered into a pipeline
right-of-way lease with the Fort Peck Tribal Executive Board on behalf of the
Assiniboine and Sioux Tribes of the Fort Peck Indian Reservation. This pipeline
right-of-way lease granted us the right and privilege to construct and operate
our pipeline on certain tribal lands. The pipeline right-of-way lease expires in
2011, although we have an option to renew the pipeline right-of-way lease
through 2061. In conjunction with obtaining right-of-way across tribal lands
located within the exterior boundaries of the Fort Peck Indian Reservation, we
also obtained right-of-way across allotted lands located within the reservation
boundaries. Most of the allotted lands are subject to a perpetual easement
granted by the Bureau of Indian Affairs for and on behalf of the individual
Indian owners or obtained through condemnation. Several tracts are subject to a
right-of-way grant that expires in 2015.


                                        6

<PAGE>

SUPPLY

Our primary source of natural gas is the Western Canada Sedimentary Basin. In
2005, approximately 85% of the natural gas we transported was produced in
Canada. For this reason, the continuous supply of Canadian natural gas is
crucial to our long-term financial condition.

Significant factors that can impact the supply of Canadian natural gas
transported by our pipeline include:

     -    Canadian natural gas available for export;

     -    transportation capacity and related market pricing options on other
          pipelines;

     -    storage capacity for Canadian natural gas and demand for storage
          injection;

     -    natural gas from other supply sources that can be transported to the
          Midwestern U.S.;

     -    demand for Canadian natural gas in other U.S. consumer markets; and

     -    natural gas market price spread between Alberta, Canada and the
          Midwestern U.S., which reflects the relative supply and demand for
          Canadian natural gas in Canada and in the U.S.

The composition of natural gas can impact transportation capacity on our
pipeline. If the energy content of natural gas declines, more natural gas must
be transported to meet the energy equivalent specified in our transportation
contracts. This in turn reduces the available transportation capacity and
negatively impacts revenue. Since 2004, Canadian natural gas transported by us
has maintained an average of 1,005 Btu/cf.

Natural gas produced in the Williston Basin of Montana, North Dakota and the
Canadian province of Saskatchewan and the Powder River Basin of Wyoming
accounted for 9% of the natural gas we transported in 2005. The remaining 6% of
the natural gas we transported was synthetic gas produced at the Dakota
Gasification plant in North Dakota.

DEMAND

Demand for natural gas transportation service on our pipeline is directly
related to demand for natural gas in the markets that our customers serve.
Factors that may impact demand for natural gas include:

     -    weather conditions;

     -    economic conditions;

     -    government regulation;

     -    availability and price of alternative energy sources;

     -    fuel conservation measures; and

     -    technological advances in fuel economy and energy generation devices.

Furthermore, factors that may impact demand for natural gas transportation
service on our pipeline include:

     -    the ability and willingness of natural gas shippers to utilize our
          pipeline over alternative pipelines;

     -    transportation rates; and

     -    volume of natural gas delivered to Midwestern U.S. markets from other
          supply sources and storage facilities.

Our primary exposure to market risk occurs when existing transportation
contracts expire and are subject to renegotiation. Customers with competitive
alternatives analyze the market price spread or basis differential between
receipt and delivery points along the pipeline to determine their expected gross
margin. The anticipated margin and its variability are important determinants of
the transportation rate customers are willing to pay. In addition to general
demand for natural gas, regional economic conditions, climate, trends in
production, available pipeline capacity and natural gas storage inventories in
each market area can also impact the basis differential and affect demand for
transportation service on our pipeline.

SEASONALITY

Demand for natural gas is seasonal. In the natural gas industry, winter season
is considered to be during the months of November to March. Summer season is
considered to be the remaining months. Peak summer season for electric power
generation includes July, August and September.

Weather conditions throughout the U.S. can significantly impact regional natural
gas supply and demand. The Western U.S. market is sensitive to precipitation
levels which impact hydroelectric power generation. During the summer, high
temperatures combined with low hydroelectric power generation levels can
increase demand for


                                        7

<PAGE>

Canadian natural gas in the Western U.S. markets and shift supply away from our
pipeline. In the Midwestern U.S., the current pipeline infrastructure is
designed to meet the region's winter heating demand loads. Moderate winter
temperatures can lead to the decline in the value of our service due to reduced
demand for our transportation service.

To the extent that our pipeline capacity is contracted under firm service
transportation agreements, a significant portion of our revenue, which is
generated from demand charges, is not impacted by seasonal throughput
variations. However, when transportation agreements expire, seasonal demand can
impact our ability to recontract firm service transportation capacity.
Accordingly, throughput on our pipeline may experience seasonal fluctuations and
discounting of rates may be required to maximize revenue.

Natural gas storage is necessary to balance the relatively steady natural gas
supply with the seasonal demand of residential, commercial and electric power
generation users. In 2004, residential, commercial and electric power generation
users consumed 65% of the total natural gas volume delivered that year
according to the Energy Information Administration. Industrial users, who
consumed the remaining 35% of the total natural gas volume delivered, demand a
steady load of natural gas to operate their facilities but will turn to
alternative energy sources when it is not economical to use natural gas.

CUSTOMERS

We serve customers in North and South Dakota, Minnesota, Iowa, Illinois and
Indiana. Our customers include natural gas producers, marketers, industrial
facilities, local distribution companies and electric power generating plants.

For the year ended December 31, 2005, four customers each accounted for more
than 10% of our revenue as follows:

<TABLE>
<CAPTION>
                                     PERCENT OF
CUSTOMER                           TOTAL REVENUE
--------                           -------------
<S>                                <C>
BP Canada Energy Marketing Corp.        17%
Nexen Marketing U.S.A. Inc.             12
EnCana Marketing (USA) Inc.             12
Cargill Inc.                            11
</TABLE>

Additional information about these customers is included in Note 5 of the
Financial Statements.

COMPETITION

Competition among natural gas pipelines is based primarily on transportation
charges and proximity to natural gas supply areas and markets. Our interstate
natural gas pipeline competes with other pipelines that transport Western
Canadian natural gas to markets in the West, Midwest and East in North America,
including TransCanada Pipeline and Alliance Pipeline. We also compete with other
pipelines that provide access to natural gas storage facilities, alternate
supply basins, such as the Rockies, Mid-Continent, the Permian Basin and the
Gulf Coast, and liquefied natural gas.

CONTRACTING

We contracted 97% of our design capacity on a firm basis in 2005, some of which
was sold at a discount to maximize overall revenue on the Port of Morgan,
Montana to Ventura, Iowa portion of the pipeline. As of January 31, 2006, 73% of
our design capacity was contracted on a firm basis through December 31, 2006.
The weighted average life of these contracts is approximately two years.

GOVERNMENT REGULATION

Our interstate natural gas pipeline is regulated under the Natural Gas Act and
Natural Gas Policy Act, which gives the FERC jurisdiction to regulate virtually
all aspects of our business, including:

     -    transportation of natural gas;

     -    rates and charges;

     -    terms of service, including creditworthiness requirements;

     -    construction of new facilities;


                                        8

<PAGE>

     -    extension or abandonment of service and facilities;

     -    accounts and records;

     -    depreciation and amortization policies;

     -    acquisition and disposition of facilities; and

     -    initiation and discontinuation of services.

Rate Case - On November 1, 2005, we filed a rate case with the FERC as required
by the provisions of the settlement of our 1999 rate case. The rate case filing
proposes a 7.8% increase to our revenue requirement; a change to our rate design
approach with a supply zone and market area utilizing a fixed rate per dekatherm
and a dekatherm-mile rate, respectively; a compressor usage surcharge primarily
to recover costs related to powering electric compressors; and the
implementation of a short-term rate structure on a prospective basis.

The filing also incorporates an overall cost of capital of 10.56% based on a
rate of return on equity of 14.20%, an increase in the depreciation rate for
transmission plant from 2.25% to 2.84%, the institution of a negative salvage
rate of 0.59% and a decrease in billing determinants. Also included in the
filing is the continued inclusion of income taxes in the rate calculation.

In December 2005, the FERC issued an order that identified issues that were
raised in the proceeding, accepted the proposed rates but suspended their
effectiveness until May 1, 2006, at which time the new rates will be collected
subject to refund until final resolution of the rate case. The FERC also issued
a procedural schedule which set a hearing commencement date of October 4, 2006,
with an initial decision scheduled for February 2007, unless a settlement of the
issues is reached with the FERC and a majority of our customers.

Income Tax Allowance - In our 1995 and 1999 rate cases, the FERC addressed the
federal income tax allowance included in our proposed cost of service. In
previous FERC rulings involving other companies, interstate pipelines were not
entitled to an income tax allowance for income attributable to limited
partnership interests held by individuals. The settlements of our 1995 and 1999
rate cases provided that we could continue to calculate the allowance for income
taxes in the manner used historically until December 2005. In May 2005, the FERC
issued a policy statement permitting the inclusion of an income tax allowance in
the rates for partnership interests held by partners with an actual or potential
income tax liability. On December 16, 2005, the FERC issued an order (December
16 Order) in its first case-specific review of the income tax allowance issue,
reaffirming its new tax allowance policy and directing the pipeline to provide
certain evidence necessary to determine the income tax allowance. The FERC's new
policy and the December 16 Order have been appealed to the D.C. Circuit and
rehearing requests have been filed with respect to the December 16 Order. The
ultimate outcome of these proceedings could impact how the policy statement is
applied to us. Our present rates and recent rate case filing reflect an
allowance for income taxes in accordance with the provisions of our tariff.

Energy Affiliates - In November 2003, the FERC adopted revised standards of
conduct which govern the relationships between regulated interstate natural gas
pipelines and their energy affiliates. The new standards of conduct were
designed to prevent interstate natural gas pipelines from giving any undue
preference to their energy affiliates and ensure that transmission service is
provided on a nondiscriminatory basis. Bear Paw Energy, LLC, subsidiaries of
ONEOK, including ONEOK Energy, and subsidiaries of TransCanada are our energy
affiliates.

Selective Discounting - In May 2005, the FERC issued an order reaffirming
existing discount regulations that permit pipelines to discount transportation
rates to meet gas-on-gas competition. The FERC found that its current policy on
selective discounting is an integral and essential part of its policies to
further develop a competitive natural gas transportation market.

Creditworthiness Standards - In June 2005, the FERC adopted a new policy
detailing credit standards for interstate pipelines. The FERC's policy states
that pipelines must use objective criteria to determine a shipper's
creditworthiness utilizing a standard set of documents that shippers are
required to provide. For current shippers on existing facilities, the FERC
reiterated its traditional policy of permitting no more than the equivalent of
three months of reservation charges as security. For new mainline construction,
the FERC will continue its policy of permitting larger security requirements
that reasonably reflect the risk of the project. The issue of whether a pipeline
may justify security in an amount greater than three months of reservation
charges has recently been voluntarily remanded to the FERC for further
consideration.


Energy Policy Act of 2005 - In August 2005, the Energy Policy Act of 2005 was
signed into law addressing a wide range of energy issues, including many that
impact the oil and gas industries. The Energy Policy Act of 2005 directs federal
agencies to implement certain provisions. Significant provisions affecting the
interstate natural gas industry: (1) provides for the FERC to be the lead agency
and creates a common record for review of federal permitting decisions
associated with interstate natural gas pipeline projects authorized under the
Natural Gas Act, (2) makes it unlawful to engage in market manipulation under
the Natural Gas Act; (3) authorizes the FERC to issue market transparency rules
that will provide greater information about natural gas prices, and (4)
increases criminal penalties that may be assessed under the Natural Gas Act and
the Natural Gas Policy Act up to $1 million per violation, increases civil
penalties under the Natural Gas Policy Act up to $1 million per day per
violation, and creates new civil penalties under the Natural Gas Act up to $1
million per day for violations as long as they continue.


                                        9

<PAGE>
Market Manipulation - In January 2006, the FERC issued a final rule making it
unlawful for any entity subject to its jurisdiction that directly or indirectly
purchases or sells natural gas, transportation services or electric energy to
defraud, using any device, scheme or artifice; make untrue statements of a
material fact or omit a material fact; or engage in any act, practice or course
of business that operates as a fraud. The maximum civil penalty under these
statutes is $1 million per day, per violation.

Negotiated Rate Policy - In January 2006, the FERC issued an order revising its
negotiated rate policy to allow the use of basis differentials without a revenue
cap in determining negotiated rates. The use of basis differentials for
negotiated rates was previously banned because the FERC believed that such
mechanism could give pipelines an incentive to withhold capacity and manipulate
the natural gas markets by widening the basis between indexes. The FERC found
such policy to be overly restrictive, given the benefits that such a pricing
mechanism yields. Since negotiated rate transactions must be filed and approved
by the FERC and such filings give all parties an opportunity to comment, any
allegations of attempted manipulation would be investigated. Comments were filed
seeking clarification or conditions to the implementation of this policy.

ENVIRONMENTAL AND SAFETY MATTERS

Our operations are subject to extensive federal, state and local laws and
regulations governing the discharge of materials into the environment or
otherwise relating to the protection of the environment. Failure to comply with
these laws and regulations can result in substantial penalties, enforcement
actions and remedial liabilities. Although we believe our operations and
facilities are in compliance in all material respects with applicable
environmental laws and safety regulations, we cannot provide any assurances that
compliance with current and future laws and regulations will not have a material
adverse affect on our financial position or results of operations.

PIPELINE SAFETY

We are subject to U.S. Department of Transportation integrity management
regulations. The Pipeline Safety Improvement Act requires pipeline companies to
perform integrity assessments on pipeline segments that exist in densely
populated areas or near specifically identified sites that are designated as
high consequence areas. Pipeline companies are required to perform the integrity
assessments within ten years of the date of enactment and perform subsequent
integrity assessments on a seven-year cycle. We are on schedule to meet the
required assessment of 50% of the highest priority high consequence areas by
2007.

AIR AND WATER EMISSIONS

The Clean Air Act and the Clean Water Act impose restrictions and controls
regarding the discharge of pollutants into the air and water in the U.S. Under
the Clean Air Act, a federal operating permit is required for sources of
significant air emissions. We may be required to incur certain capital
expenditures for air pollution control equipment in connection with obtaining or
maintaining permits and approvals for sources of air emissions. The Clean Water
Act imposes substantial potential liability for the removal and remediation of
pollutants discharged in U.S. water. Although we cannot provide any assurances,
we believe that we are in compliance with state and federal requirements related
to these regulations.

EMPLOYEES

We do not directly employ any of the persons responsible for managing or
operating the partnership or for providing us with services related to our
day-to-day business affairs. Northern Plains provides administrative, operating
and management services to us under an operating agreement. Northern Plains also
operates other interstate natural gas pipelines, including Midwestern Gas
Transmission, Viking Gas Transmission and Guardian Pipeline. As of January 31,
2006, Northern Plains had 336 employees. Northern Plains' employees are not
represented by a labor union nor covered by a collective bargaining agreement.


                                       10

<PAGE>

ITEM 1A. RISK FACTORS

The following risk factors should be carefully considered together with all of
the other information included in this annual report when evaluating our
business. If any of the following risks were to actually occur, our business,
results of operations and financial condition could be materially adversely
affected.

RISKS INHERENT IN OUR BUSINESS

IF PRODUCTION FROM THE WESTERN CANADA SEDIMENTARY BASIN REMAINS FLAT OR DECLINES
AND DEMAND FOR NATURAL GAS FROM THE WESTERN CANADA SEDIMENTARY BASIN IS GREATER
IN MARKET AREAS OTHER THAN THE MIDWESTERN U.S., DEMAND FOR OUR TRANSPORTATION
SERVICES COULD SIGNIFICANTLY DECREASE.

We depend on natural gas supply from the Western Canada Sedimentary Basin
because our interstate natural gas pipeline transports primarily Canadian
natural gas from the Western Canada Sedimentary Basin to the Midwestern U.S.
market area. If demand for natural gas increases in Canada or other markets not
served by our pipeline and production remains flat or declines, demand for
transportation service on our interstate natural gas pipeline could decrease
significantly, which could adversely impact our results of operations.

OUR INTERSTATE NATURAL GAS PIPELINE'S TRANSPORTATION RATES ARE SUBJECT TO REVIEW
AND POSSIBLE ADJUSTMENT BY FEDERAL REGULATORS.

Our interstate natural gas pipeline is subject to extensive regulation by the
FERC, which regulates most aspects of our pipeline business, including our
transportation rates. Under the Natural Gas Act, interstate transportation rates
must be just and reasonable and not unduly discriminatory. In November 2005, we
filed a rate case with the FERC as required by the provisions of the settlement
of our last rate case. If the increased rates that we are seeking to collect are
ultimately lowered by the FERC, on its own initiative, or as a result of
challenges raised by our customers or third parties, the FERC could require
refunds of amounts collected under rates that it finds unlawful. In addition, an
adverse decision by the FERC in our rate case could result in reductions to our
regulated rates on a prospective basis, which could adversely affect our cash
flow.

IF WE ARE UNABLE TO COMPETE FOR CUSTOMERS, WE MAY HAVE SIGNIFICANT LEVELS OF
UNCONTRACTED OR DISCOUNTED TRANSPORTATION CAPACITY ON OUR INTERSTATE NATURAL GAS
PIPELINE.

Our interstate natural gas pipeline competes with other pipelines for Canadian
natural gas supplies delivered to U.S. markets. If we do not successfully
compete with the other natural gas pipelines, we may have significant levels of
uncontracted or discounted capacity on our pipeline, which could adversely
impact our results of operations.

WE HAVE RECORDED CERTAIN ASSETS THAT MAY NOT BE RECOVERABLE FROM OUR CUSTOMERS.

Accounting policies for FERC-regulated companies permit certain assets to be
recorded that result from the regulated ratemaking process that would not be
recorded under GAAP for nonregulated entities. We consider factors such as
regulatory changes and the impact of competition to determine the probability of
future recovery of these assets. If we determine future recovery is no longer
probable, we would be required to write off the regulatory assets at that time.

THE COMPOSITION OF NATURAL GAS RECEIVED BY OUR PIPELINE COULD REDUCE OUR
AVAILABLE TRANSPORTATION CAPACITY.

If the energy content of the natural gas received by our pipeline is below the
energy equivalent specified under our transportation contracts, we must
transport additional natural gas to meet our contractual committments. The
transportation of this additional natural gas reduces the available
transportation capacity on our pipeline and would negatively impact our
operating revenue.

OUR OPERATIONS ARE SUBJECT TO FEDERAL AND STATE LAWS AND REGULATIONS RELATING TO
THE PROTECTION OF THE ENVIRONMENT, WHICH MAY EXPOSE US TO SIGNIFICANT COSTS AND
LIABILITIES.

The risk of incurring substantial environmental costs and liabilities is
inherent in the performance of our operations. Our operations are subject to
extensive federal, state and local laws and regulations governing the discharge
of


                                       11

<PAGE>

materials into the environment or otherwise relating to the protection of the
environment. These laws include, for example:

     -    the federal Clean Air Act and analogous state laws, which impose
          obligations related to air emissions;

     -    the federal Water Pollution Control Act of 1972, as renamed and
          amended as the Clean Water Act and analogous state laws, which
          regulate discharge of wastewaters from our facilities to state and
          federal waters;

     -    the federal Comprehensive Environmental Response, Compensation and
          Liability Act and analogous state laws that regulate the cleanup of
          hazardous substances that may have been released at properties
          currently or previously owned or operated by us or locations to which
          we have sent wastes for disposal; and

     -    the federal Resource Conservation and Recovery Act and analogous state
          laws that impose requirements for the handling and discharge of solid
          and hazardous waste from our facilities.

Various governmental authorities, including the U.S. EPA, have the power to
enforce compliance with these laws and regulations and the permits issued under
them. Violators are subject to administrative, civil and criminal penalties,
including civil fines, injunctions or both. Joint and several, strict liability
may be incurred without regard to fault under the Comprehensive Environmental
Response, Compensation and Liability Act, Resource Conservation and Recovery
Act and analogous state laws for the remediation of contaminated areas.

There is inherent risk of the incurrence of environmental costs and liabilities
in our business due to our handling of the products we transport, air emissions
related to our operations, historical industry operations and waste disposal
practices, some of which may be material. Private parties, including the owners
of properties through which our pipeline systems pass, may have the right to
pursue legal actions to enforce compliance as well as to seek damages for
non-compliance with environmental laws and regulations or for personal injury or
property damage arising from our operations. In addition, increasingly strict
laws, regulations and enforcement policies could significantly increase our
compliance costs and the cost of any remediation that may become necessary, some
of which may be material.

Our insurance may not cover all environmental risks and costs or may not provide
sufficient coverage in the event an environmental claim is made against us. Our
business may be adversely affected by increased costs due to stricter pollution
control requirements or liabilities resulting from non-compliance with required
operating or other regulatory permits. New environmental regulations might also
adversely affect our activities and federal and state agencies could impose
additional safety requirements, all of which could materially affect our
profitability.

PIPELINE INTEGRITY PROGRAMS AND REPAIRS MAY IMPOSE SIGNIFICANT COSTS AND
LIABILITIES.

In December 2003, the U.S. Department of Transportation issued a final rule
requiring pipeline operators to develop integrity management programs for
pipelines located near "high consequence areas," where a leak or rupture could
do the most harm. The final rule requires operators to perform ongoing
assessments of pipeline integrity; identify and characterize applicable threats
to pipeline segments that could impact a high consequence area; improve data
collection, integration and analysis; repair and remediate the pipeline as
necessary; and implement preventive and mitigating actions. The final rule
incorporates the requirements of the Pipeline Safety Improvement Act of 2002 and
became effective in January 2004. The results of these testing programs could
cause us to incur significant capital and operating expenditures in response to
repair, remediation, preventative or mitigating actions that are determined to
be necessary.

WE ARE EXPOSED TO THE CREDIT RISK OF OUR CUSTOMERS AND OUR CREDIT RISK
MANAGEMENT MAY NOT BE ADEQUATE TO PROTECT AGAINST SUCH RISK.

We are subject to the risk of loss resulting from nonpayment and/or
nonperformance by our customers. Our customers are predominantly natural gas
producers and marketers that may experience deterioration of their


                                       12

<PAGE>

financial condition as a result of changing market conditions or financial
difficulties that could impact their creditworthiness or ability to pay us for
our services. We have obtained the maximum security allowed under the FERC
creditworthiness policy. If we fail to adequately assess the creditworthiness of
existing or future customers, unanticipated deterioration in their
creditworthiness and any resulting nonpayment and/or nonperformance could
adversely impact our results of operations. In addition, if any of our customers
filed for bankruptcy protection, we may not be able to recover amounts owed or
resell the capacity held by such customer, which would negatively impact our
results of operations.

OUR USE OF FINANCIAL INSTRUMENTS TO HEDGE MARKET RISK MAY RESULT IN REDUCED
INCOME.

We utilize financial instruments to mitigate our exposure to interest rate
fluctuations. These hedging arrangements could expose us to risk of financial
loss where we have contracted for variable-rate swap instruments to hedge
fixed-rate instruments and the variable rate exceeds the fixed rate. In
addition, these hedging arrangements may limit the benefit we would otherwise
receive if we have contracted for fixed-rate swap agreements to hedge
variable-rate instruments and the variable rate falls below the fixed rate.

RISKS INHERENT IN AN INVESTMENT IN US

WE DO NOT OPERATE ALL OF OUR ASSETS NOR DO WE DIRECTLY EMPLOY ANY OF THE PERSONS
RESPONSIBLE FOR PROVIDING US WITH ADMINISTRATIVE, OPERATING AND MANAGEMENT
SERVICES. THIS RELIANCE ON OTHERS TO OPERATE OUR ASSETS AND TO PROVIDE OTHER
SERVICES COULD ADVERSELY AFFECT OUR BUSINESS AND OPERATING RESULTS.

We rely on Northern Plains to provide us with administrative, operating and
management services. We have a limited ability to control our operations or the
associated costs of such operations. The success of these operations depends on
a number of factors that are outside our control, including the competence and
financial resources of the operator. Northern Plains may outsource some or all
of these services to third parties, and a failure to perform by these
third-party providers could lead to delays in or interruptions of these
services. Should Northern Plains not perform their respective contractual
obligations, we may have to contract elsewhere for these services, which may
cost more than we are currently paying. In addition, we may not be able to
obtain the same level or kind of service or retain or receive the services in a
timely manner, which may impact our ability to perform under our transportation
contracts and negatively affect our business and operating results. Our reliance
on Northern Plains and third-party providers with which it contracts, together
with our limited ability to control certain costs, could harm our business and
results of operations.

THE MANAGEMENT COMMITTEE, OUR GENERAL PARTNERS AND THEIR AFFILIATES HAVE
CONFLICTS OF INTEREST AND LIMITED FIDUCIARY DUTIES, WHICH MAY PERMIT THEM TO
FAVOR THEIR OWN INTERESTS.

Although our general partners, through the Management Committee, have a
fiduciary duty to manage us in a manner beneficial to us, the owners of our
general partners have a fiduciary duty to manage our general partners in a
manner beneficial to their respective owners. Conflicts of interest may arise
between our general partners and their affiliates and us. In resolving these
conflicts, our general partners may favor their own interests and the interests
of their respective affiliates over our interests. These conflicts include,
among others, the following situations:

     -    the Management Committee and our general partners are allowed to take
          into account the interests of parties other than us, such as Northern
          Border Partners and TC PipeLines Intermediate, in resolving conflicts
          of interest, which has the effect of limiting its fiduciary duty to
          us;

     -    the respective affiliates of our general partners may engage in
          competition with us;

     -    the Management Committee and our general partners have limited their
          liability and reduced their fiduciary duties, and have also restricted
          the remedies available to us for actions that, without the
          limitations, might constitute breaches of fiduciary duty;

     -    the Management Committee approves the amount and timing of any capital
          expenditures. The nature of the capital expenditure, whether it is a
          maintenance capital expenditure or a growth capital expenditure, can
          affect the amount of cash that is distributed;

     -    the Management Committee determines which costs incurred by them, our
          general partners and their respective affiliates are reimbursable by
          us;


                                       13

<PAGE>

     -    our partnership agreement does not restrict the Management Committee
          from causing us to pay them, our general partners or their respective
          affiliates for any services rendered to us or entering into additional
          contractual arrangements with any of these entities on our behalf; and

     -    the Management Committee decides whether to retain separate counsel,
          accountants or others to perform services for us.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

ITEM 2. PROPERTIES

See Item 1, "Business-Narrative Description of Business," for a description of
our properties, their utilization, and how each property is held.

ITEM 3. LEGAL PROCEEDINGS

RATE CASE

On November 1, 2005, as required by the provisions of the settlement of our 1999
rate case, we filed a rate case with the FERC. The rate case filing proposes a
7.8% increase to our revenue requirement; a change to our rate design approach
with a supply zone and market area utilizing a fixed rate per dekatherm and a
dekatherm-mile rate, respectively; a compressor usage surcharge primarily to
recover costs related to powering electric compressors; and the implementation
of a short-term rate structure on a prospective basis. The filing also
incorporates an overall cost of capital of 10.56% based on a rate of return on
equity of 14.20%, an increase in the depreciation rate for transmission plant
from 2.25% to 2.84%, the institution of a negative salvage rate of 0.59% and a
decrease in billing determinants. Also included in the filing is the continued
inclusion of income taxes in the rate calculation. In December 2005, the FERC
issued an order that identified the issues raised in the proceeding and accepted
the proposed rates but suspended their effectiveness until May 1, 2006, at which
time the new rates will be collected subject to refund until final resolution of
the rate case. A procedural schedule was established setting a hearing
commencement date of October 4, 2006, with an initial decision scheduled for
February 2007, unless a settlement of the issues is reached with the FERC and a
majority of our customers.

Various other legal actions that have arisen in the ordinary course of business
are pending. We believe that the resolution of these issues will not have a
material adverse impact on our results of operations or financial position.

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

Not applicable.

                                     PART II

ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS
        AND ISSUER PURCHASES OF EQUITY SECURITIES

Our general partner interests are not traded in an established public trading
market.

In December 2003, the Management Committee voted to: issue equity cash calls to
our partners in the total amount of $130 million in early 2004 and $90 million
in 2007; fund half of our future growth capital expenditures with equity
contributions from our partners; and change the cash distribution policy. In
January and May 2004, we received the approved equity contributions of $130
million from our partners. In December 2004, we received an additional equity
contribution of $75 million, which reduced the previously approved 2007 equity
cash call from $90 million to $15 million. Additional information is included
under Item 7, "Management's Discussion and Analysis of Financial Condition and
Results of Operations-Liquidity and Capital Resources," and Note 9 of the
Financial Statements.


                                       14

<PAGE>

ITEM 6. SELECTED FINANCIAL DATA

The following table sets forth our selected financial data for each of the
periods indicated.

<TABLE>
<CAPTION>
                                                              YEARS ENDED DECEMBER 31,
                                           --------------------------------------------------------------
                                              2005         2004         2003         2002         2001
                                           ----------   ----------   ----------   ----------   ----------
                                              (In thousands, except other financial and operating data)
<S>                                        <C>          <C>          <C>          <C>          <C>
Income data:
   Operating revenue, net                  $  321,651   $  329,115   $  324,185   $  321,050   $  313,088
   Operations and maintenance                  39,506       33,763       43,791       41,442       33,695
   Depreciation and amortization               58,052       58,375       57,779       58,714       57,516
   Taxes other than income                     31,345       29,368       29,634       28,436       25,636
                                           ----------   ----------   ----------   ----------   ----------
      Operating income                        192,748      207,609      192,981      192,458      196,241
Interest expense, net                          42,635       41,356       44,857       51,525       55,351
Other income (expense), net                     2,133          524           76        1,786         (432)
                                           ----------   ----------   ----------   ----------   ----------
      Net income to partners               $  152,246   $  166,777   $  148,200   $  142,719   $  140,458
                                           ==========   ==========   ==========   ==========   ==========

Cash flow data:
   Net cash provided by operating
      activities                           $  206,461   $  206,149   $  193,270   $  224,356   $  197,322
   Capital expenditures                        28,555       10,569       12,918        9,243       54,659
   Distributions to partners                  202,901      205,635      153,978      164,126      143,032
   Equity contributions from partners              --      205,000           --           --           --

Balance sheet data:
   Property, plant and equipment, net      $1,516,075   $1,545,473   $1,591,755   $1,635,961   $1,685,665
   Total assets                             1,604,698    1,624,988    1,691,309    1,740,037    1,751,869
   Long-term debt, including current
      maturities                              628,916      603,860      821,498      848,906      863,666
   Partners equity                            914,985      967,140      802,438      809,772      833,594

Other financial data:
   Ratio of earnings to fixed charges(1)          4.5          5.0          4.3          3.8          3.5

Operating data by segment:
   Interstate natural gas pipeline:
      MMcf delivered                          807,531      844,963      849,920      838,736      820,851
      MMcf/d average throughput                 2,277        2,377        2,396        2,369        2,312
</TABLE>

(1)  Earnings are the sum of pre-tax income from continuing operations and fixed
     charges. Fixed charges are the sum of interest expensed and capitalized;
     amortized premiums, discounts and capitalized expenses related to
     indebtedness; and an estimate of interest within rental expenses.


                                       15

<PAGE>

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

The following discussion and analysis should be read in conjunction with our
financial statements and accompanying notes included under Item 15, "Exhibits
and Financial Statement Schedules."

EXECUTIVE SUMMARY

OVERVIEW

Northern Border Pipeline is a Texas general partnership formed in 1978. Northern
Border Partners owns a 70% general partner interest and TC PipeLines
Intermediate owns the remaining 30%. We provide natural gas transportation
services and are a leading transporter of natural gas imported from Canada to
the U.S.

Operating revenue is derived from transportation contracts under a
FERC-regulated tariff. Customers with firm service transportation agreements pay
a fee known as a demand charge to reserve pipeline capacity, regardless of use,
for the term of their contracts. Firm service transportation customers also pay
a fee known as a commodity charge that is based on the volume of natural gas
they transport. Customers with interruptible service transportation agreements
may utilize available capacity on our pipeline after firm service transportation
requests are satisfied. Interruptible service customers are assessed commodity
charges only. In 2005, 97% of our revenue was derived from demand charges.

Information about our business, properties and strategy can be found under Item
1, "Business," and a description of our risk factors can be found under Item 1A,
"Risk Factors."

OUR BUSINESS ENVIRONMENT

A healthy long-term natural gas supply outlook is critical for our operations.
Western Canada supply trends are particularly important to us because
approximately 85% of the natural gas we transport is produced in the Western
Canada Sedimentary Basin. We estimate that our pipeline transported
approximately 20% of Canada's natural gas export volume in 2005. In 2005,
Canadian natural gas supplies available for export were relatively flat compared
with prior years.

Canadian natural gas supplies available for export could be impacted by the
development of oil sand reserves due to increased natural gas consumption
associated with production. Increased production of crude oil from oil sand
reserves in Canada could reduce natural gas available for export to the U.S. if
production and the related demand for natural gas are significantly greater than
supply growth. Despite this possibility, we anticipate that Canadian natural gas
supplies available for export in 2006 will be similar to 2005. Once new pipeline
projects associated with the Mackenzie Delta in Northern Canada and Alaska are
constructed, we could have access to new supply sources.

We serve natural gas markets in the Midwestern U.S. and provide our customers
with access to the Chicago market area, which is the third largest market area
hub in North America. Although domestic demand for natural gas is expected to
remain near 2005 levels in 2006, relatively high prices may significantly impact
natural gas supply and demand. Strong natural gas prices may lead to increased
production, supply source and market competition, and demand destruction and
volatility.

Supply competition from other sources of natural gas can adversely impact demand
for transportation on our pipeline. New supply from the Rocky Mountain region
transported by a competitor impacted demand for service on our pipeline at
certain times during 2005 and will continue to put pressure on us when market
demand is light. In August 2005, Kinder Morgan Energy Partners, L.P. (Kinder
Morgan) and Sempra Pipelines & Storage proposed to construct a natural gas
pipeline that would transport natural gas from the Rocky Mountain region to the
upper Midwestern and Eastern U.S. In February 2006, Kinder Morgan announced that
the 1.8 Bcf/d, 1,323-mile Rockies Express Pipeline was fully subscribed. The
proposed project's interim service to the Mid-Continent region, anticipated to
begin in late 2008, may adversely impact the value of transportation service on
our pipeline which serves the Midwestern U.S. markets.

Temperatures in the U.S. were above normal averages from December 2004 through
November 2005, according to the NOAA National Climate Data Center. During the
first half of 2005, the market responded by increasing natural gas storage
injection activity, which resulted in natural gas in storage at levels greater
than the five-year average.


                                       16

<PAGE>

With ample natural gas already in storage and the U.S. experiencing higher than
normal summer temperatures during the third quarter of 2005, demand for Canadian
natural gas increased to meet demand for electricity. In addition, demand for
transportation capacity from the Chicago market area increased as a result of
decreased production in the Gulf Coast region due to infrastructure disruptions
following Hurricanes Katrina and Rita. December 2005 began with unusually cold
conditions across the U.S. that retreated in the last two weeks of the year and
above normal temperatures resumed in January 2006.

Natural gas storage is essential to balance natural gas supply with
temperature-driven seasonal demand. As the market gains the ability to better
align its demand with supply by utilizing natural gas storage, we anticipate
demand for transportation services will become increasingly volatile. With new
Canadian storage projects expected to go in service during 2006, we anticipate
that increased storage may reduce demand for our transportation capacity during
the spring and early summer months and increase demand during the winter months.

YEAR IN REVIEW

In 2005, net income of $152.2 million was lower than 2004 net income by 9%
primarily due to decreased demand for transportation capacity. During the second
quarter of 2005, increased storage injection activity of Canadian natural gas
negatively impacted demand for our firm service transportation when several
contracts expired. In order to maximize revenue, we discounted transportation
rates primarily on a short-term basis. As Western Canadian working gas in
storage rose to high levels and summer temperatures were higher than normal,
demand for our transportation capacity also increased. While we anticipate that
demand for transportation capacity in 2006 will be similar to 2005 demand based
on our expectations of Canadian natural gas supply and demand for natural gas in
the Midwestern U.S., the level of discounting in the future may vary from 2005
depending upon transient market conditions, which are difficult to predict.

The outcome of our rate case filed in November 2005 could have a significant
impact on our financial results because the resulting tariff will specify the
maximum rates we can charge our customers for natural gas transportation
service. In December 2005, the FERC identified the issues raised in the
proceeding and accepted the proposed rates but suspended their effectiveness
until May 1, 2006. At that time, we will collect the new rates, which will be
subject to refund until final resolution of the rate case following hearings
conducted by the FERC or by settlement. A change in our rates will not affect
earnings until final resolution with the FERC staff and a majority of our
customers is reached and subsequently approved by the FERC, which may not occur
until 2007.

We continue to seek internal growth opportunities to expand our business. We
commenced construction on our Chicago III Expansion Project in 2005. In
September, the FERC issued a certificate of public convenience and necessity for
the project which will increase our transportation capacity from Harper, Iowa to
the Chicago market area by 130 MMcf/d to 974 MMcf/d. The additional capacity is
fully subscribed for five and one-half years to ten years. The Chicago III
Expansion Project is expected to be in service in April 2006.

During 2005, several events marked the end of our relationship with Enron. In
May, Northern Border Partners' transition from CCE Holdings, through which Enron
provided certain services to ONEOK was completed. In June, we sold our unsecured
claims against Enron and Enron North America to a third party, which sale is
reflected in our operating results. In addition, Enron was the grantor of the
Enron Gas Pipeline Employee Benefit Trust (Trust), which when taken together
with the Enron Corp. Medical Plan for Inactive Participants (Medical Plan)
constituted a "voluntary employees' beneficiary association" or VEBA under the
Internal Revenue Code. The Trust was established as a result of a regulatory
requirement for the inclusion of certain costs for post-employment medical
benefits in the rates established for the affected pipelines, including ours. In
2002, Enron began the necessary steps to partition the assets of the Trust and
the related liabilities of the Medical Plan among all of the participating
employers of the Trust, including Northern Plains, and requested the enrolled
actuary to prepare an analysis and recommendation for the allocation of the
Trust's assets and associated liabilities. In June 2005, Enron filed an amended
motion in bankruptcy court seeking approval to terminate the Trust and to
distribute its assets among certain identified companies. If Enron's relief is
granted as requested, Northern Plains would assume retiree benefit liabilities,
estimated as of November 17, 2004, of approximately $2.3 million and Trust
assets of approximately $1.7 million. Northern Natural Gas Company, a
participating employer of the Trust through June 30, 2002, along with other
parties filed a motion alleging that the


                                       17

<PAGE>

allocation of assets and liabilities of the Trust should be decided in a pending
lawsuit filed in the U.S. District Court for the District of Nebraska and not in
bankruptcy court. The lawsuit filed in Nebraska was dismissed.

On February 14, 2006, our general partners entered into a Partnership Interest
Purchase and Sale Agreement (PIPA) dated as of December 31, 2005, under which
Northern Border Partners agreed to sell a 20% partnership interest in us to TC
PipeLines Intermediate for $300 million and the assumption of certain
liabilities and obligations. The PIPA contains customary and other closing
conditions that, if not satisfied or waived, would result in the sale not
occurring. Upon closing the sale of the 20% partnership interest, several things
will occur, including: our general partners will amend our partnership agreement
to modify certain governance and operating terms; TC PipeLines Intermediate will
appoint a new Management Committee chairman and other members of the Management
Committee may change; we will enter into a pipeline operating agreement with an
affiliate of TC PipeLines Intermediate, under which the affiliate of TC
PipeLines Intermediate will become our operator, effective April 1, 2007; our
current operator, Northern Plains or one of its affiliates, will enter into a
transition services agreement with TransCanada or one of its affiliates; and we
will adopt certain changes to our cash distribution policy relating to financial
ratio targets and capital contributions.

The natural gas industry continues to be a critical component of the energy
infrastructure in the U.S. Our commitment to providing safe, cost-effective and
reliable natural gas transportation service will continue to be the foundation
upon which we will strive to grow our business and provide consistent cash flow
to our partners.

CRITICAL ACCOUNTING ESTIMATES

The preparation of financial statements in accordance with U.S. GAAP requires us
to make estimates and assumptions, with respect to values or conditions which
cannot be known with certainty, that affect the reported amount of assets and
liabilities and the disclosure of contingent assets and liabilities at the date
of the financial statements. Such estimates and assumptions also affect the
reported amounts of revenue and expenses during the reporting period. Although
we believe these estimates are reasonable, actual results could differ from our
estimates. The following summarizes our critical accounting estimates, which
should be read in conjunction with Note 2 of the Financial Statements.

IMPAIRMENT OF LONG-LIVED ASSETS

Long-lived assets, such as property and equipment, are reviewed for impairment
when events or changes in circumstances indicate that their carrying amount may
exceed their fair value. We assess our long-lived assets for impairment based on
SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets."
Fair values are based on the sum of the undiscounted future cash flow expected
to result from the use and eventual disposition of the assets. If the
undiscounted future cash flow is less than the carrying value of the asset, we
calculate an impairment loss. The impairment loss calculation compares the
carrying value of the asset to the asset's estimated fair value, which is based
on future discounted cash flow. If we recognize an impairment loss, the
adjusted carrying amount of the asset will be its new cost basis. For a
depreciable long-lived asset, the new cost basis will be depreciated over the
remaining useful life of that asset. Restoration of a previously recognized
impairment loss is prohibited.

We will prepare a fair value analysis when events or changes in circumstances
indicate that the carrying amount of our long-lived assets may exceed the fair
value. Management reviews our assets at the end of each reporting period to
determine if any events that would trigger asset impairment have occurred. This
type of analysis requires us to make assumptions and estimates regarding
industry economic factors and the profitability of future business strategies.
Our assumptions and estimates are based on our current business strategy, taking
into consideration present industry and economic conditions as well as our
analysis of future expectations. Using the impairment review methodology
described herein, we determined there was no asset impairment in 2005.

If actual results differ from our assumptions and judgments used in estimating
future cash flow and asset fair values, we may be exposed to impairment losses
that could be material to our results of operations.

REGULATORY ASSETS

Our accounting policies conform to SFAS No. 71, "Accounting for the Effects of
Certain Types of Regulation." We consider several factors to evaluate our
continued application of the provisions of SFAS No. 71 such as potential
deregulation of our pipeline; anticipated changes from cost-based ratemaking to
another form of regulation; increasing competition that limits our ability to
recover costs; and regulatory actions that limit rate relief to a level
insufficient to recover costs. Certain assets that result from the ratemaking
process are reflected on our balance sheet as regulatory assets. If we determine
future recovery of these assets is no longer probable as a result of
discontinuing application of SFAS No. 71 or other regulatory actions, we would
be required to write off the regulatory assets at that time. As of December 31,
2005, we reflected regulatory assets of $13.9 million that we expect to recover
from our customers over varying time periods up to 44 years.

CONTINGENCIES

Our accounting for contingencies covers a variety of business activities,
including contingencies for legal and environmental liabilities. We accrue these
contingencies when our assessments indicate that it is probable that a


                                       18

<PAGE>
liability has been incurred or an asset will not be recovered and an amount can
be reasonably estimated in accordance with SFAS No. 5, "Accounting for
Contingencies." We base our estimates on currently available facts and our
estimates of the ultimate outcome or resolution. Actual results may differ from
our estimates resulting in an impact, positive or negative, on earnings.

RESULTS OF OPERATIONS

COMPARISON OF THE YEAR ENDED DECEMBER 31, 2005, WITH YEAR ENDED DECEMBER 31,
2004

Net income decreased $14.5 million, or 9%, in 2005 compared with 2004 primarily
as a result of the following:

     -    unsold transportation capacity;

     -    discounted transportation rates; and

     -    increased operations and maintenance expense and taxes other than
          income; partially offset by

     -    the sale of bankruptcy claims against Enron and Enron North America.

Operating revenue decreased $7.5 million in 2005 compared with 2004. During the
second quarter of 2005, contracts for 800 MMcf/d of transportation capacity on
the Port of Morgan, Montana to Ventura, Iowa portion of the pipeline expired.
Some of this firm transportation capacity was not sold. To maximize revenue, we
discounted transportation rates primarily on a short-term basis and sold most of
our remaining capacity in 2005. Revenue from firm service transportation
decreased $16.2 million as a result of uncontracted and discounted capacity.
Partially offsetting this decrease, we recognized revenue of $9.4 million from
the sale of our bankruptcy claims for transportation contracts and associated
guarantees against Enron and Enron North America. In 2004, we recognized revenue
of $0.9 million due to an additional day of transportation service because of
the leap year.

Operations and maintenance expense increased $5.7 million in 2005 compared with
2004 primarily due to the settlement or anticipated settlement of several
outstanding issues related to Enron which reduced expenses in 2004. The
resolution of our potential obligation for costs related to the termination of
Enron's cash balance plan, the settlement for certain administrative expenses
for 2002 and 2003, and an adjustment to our allowance for doubtful accounts
related to bankruptcy claims reduced expenses by $5.9 million in 2004.

Taxes other than income increased $2.0 million in 2005 compared with 2004 due to
increased tax expense related to the Minnesota compressor fuel tax and increased
property taxes. In July 2005, the Minnesota legislature passed an omnibus tax
bill, which included a provision restoring sales tax on pipeline fuel and
equipment purchases that had been struck down by the Minnesota Supreme Court in
2002. The provision became effective for purchases made after July 31, 2005. As
a result, we are taxed on the value of the gas provided in-kind and used in the
operation of our compressor stations.

Interest expense increased $1.3 million in 2005 compared with 2004 as a result
of higher average interest rates partially offset by decreased average debt
outstanding.

Net other income increased $1.6 million in 2005 compared with 2004 primarily due
to adjustments to our allowance for doubtful accounts which increased net other
income in 2005. Non-recurring expenses incurred in 2004 related to business
development reduced net other income.

COMPARISON OF THE YEAR ENDED DECEMBER 31, 2004, WITH YEAR ENDED DECEMBER 31,
2003

Net income increased $18.6 million, or 13%, in 2004 compared with 2003 primarily
as a result of the following:

     -    increased revenue;

     -    decreased operations and maintenance expense; and

     -    decreased interest expense.

Operating revenue increased $4.9 million in 2004 compared with 2003 as a result
of expired regulatory conditions under our previous rate case settlement, which
enabled us to generate and retain $2.0 million from the sale of short-term firm
capacity and $2.0 million from new service revenue. We also recognized revenue
of $0.9 million due to an additional day of transportation service because of
the leap year.


                                       19

<PAGE>

Operations and maintenance expense decreased $10.0 million in 2004 compared with
2003 primarily due to the resolution of costs related to the termination of
Enron's cash balance plan of $3.1 million. When compared with the impact of the
charges recorded in 2003, this represented a $6.2 million decrease in expense
between 2004 and 2003. In addition, the settlement for certain administrative
expenses for 2002 and 2003 of $1.7 million and an adjustment to our allowance
for doubtful accounts related to our bankruptcy claims of $1.1 million reduced
expenses in 2004.

Interest expense decreased $3.5 million in 2004 compared with 2003 due to
decreased average debt outstanding as a result of equity contributions from our
partners that were used to repay outstanding indebtedness.

LIQUIDITY AND CAPITAL RESOURCES

OVERVIEW

Our principal sources of liquidity include cash generated from operating
activities and bank credit facilities. We fund our operating expenses, debt
service and cash distributions to partners primarily with operating cash flow.

Capital resources for maintenance and growth expenditures are funded by a
variety of sources, including cash generated from operating activities,
borrowings under bank credit facilities, issuance of senior unsecured notes or
equity contributions from our partners. Our ability to access capital markets
for debt under reasonable terms depends on our financial condition, credit
ratings and market conditions.

We believe that our ability to obtain financing at reasonable rates and our
history of consistent cash flow from operating activities provide a solid
foundation to meet our future liquidity and capital resource requirements.

SHORT-TERM LIQUIDITY

We use cash from operating activities, bank credit facilities and equity
contributions from our partners as our primary sources of short-term liquidity.

CREDIT FACILITY

In May 2005, we entered into a $175 million five-year revolving credit agreement
with certain financial institutions. Under this agreement, we borrowed $29
million to pay the outstanding balance on our existing $175 million revolving
credit agreement and terminated that agreement. We may select the lender's base
rate or the LIBOR plus a spread that is based on our long-term unsecured debt
rating as the interest rate on the loan. We are required to comply with certain
financial, operational and legal covenants, including the maintenance of an
EBITDA (net income plus interest expense, income taxes and depreciation and
amortization) to interest expense ratio of greater than 3 to 1 and a debt to
adjusted EBITDA (EBITDA adjusted for pro forma operating results of acquisitions
made during the year) ratio of no more than 4.5 to 1. If we consummate one or
more acquisitions that exceed $25 million in total purchase price, the allowable
ratio of debt to adjusted EBITDA is increased to 5 to 1 for two calendar
quarters following the acquisition. If we breach any of these covenants, the
amount outstanding may become due and payable immediately.

The fair value of our variable rate debt is approximately the carrying value
since the interest rates are periodically adjusted to reflect current market
conditions. As of December 31, 2005, our outstanding borrowings under our credit
agreement were $27 million and we were in compliance with the covenants of our
agreement. The average interest rate on our debt at December 31, 2005, was
5.11%.

EQUITY CONTRIBUTIONS

In January, May and December 2004, we received equity contributions from our
partners of $65 million, $65 million and $75 million, respectively, to repay
existing bank debt. The $75 million equity contribution in December 2004 reduces
the previously approved 2007 equity cash call from $90 million to $15 million.

LONG-TERM FINANCING

DEBT SECURITIES

We periodically issue long-term debt securities to meet our capital resource
requirements. All of our outstanding debt securities are senior unsecured notes
with similar terms except for interest rates, maturity dates and prepayment
premiums.


                                       20

<PAGE>

Our senior notes issuances of $150 million due in 2007, $200 million due in 2009
and $250 million due in 2021 are borrowed at fixed interest rates of 6.25%,
7.75% and 7.50%, respectively. We intend to maintain the current schedule of
maturities, which will result in no gains or losses on their respective
repayments. The indentures of the notes do not limit the amount of unsecured
debt we may incur but contain material financial covenants, including the
restriction of secured indebtedness. In 2004, we redeemed $75 million of the
$225 million principal amount outstanding of our senior notes due in 2007. At
December 31, 2005, the aggregate fair value of our senior notes was
approximately $637 million. In 2005, interest expense related to our senior
notes was $43.6 million.

CASH FLOW FROM OPERATING, INVESTING AND FINANCING ACTIVITIES

OPERATING ACTIVITIES

Cash provided by operating activities was flat year over year. In 2005, cash
inflows increased as a result of the following:

     -    sale of bankruptcy claims against Enron and Enron North America; and

     -    decreased payment in 2005 compared with 2004 related to our settlement
          with respect to right-of-way lease and taxation issues with the Fort
          Peck Tribes. We paid the Fort Peck Tribes $7.4 million as part of the
          settlement in 2004 and an option payment of approximately $1.5 million
          in 2005.

These increases were offset by the following outflows in 2005:

     -    decreased revenue as a result of unsold and discounted transportation
          capacity; and

     -    increased interest expense.

Cash provided by operating activities increased $12.9 million, or 7%, in 2004
compared with 2003 due to higher operating revenue and lower interest expense,
partially offset by our initial payment of $7.4 million in 2004 related to the
settlement with respect to right-of-way lease and taxation issues with the Fort
Peck Tribes.

INVESTING ACTIVITIES

Cash used for investing activities increased significantly in 2005 compared with
2004 due to increased capital expenditures in 2005. We fund our investing
activities primarily with operating cash and borrowings under our credit
facilities. In 2005 and 2004, maintenance and growth capital expenditures were
as follows:

<TABLE>
<CAPTION>
CAPITAL EXPENDITURES ($ MILLIONS)    2005    2004
---------------------------------   -----   -----
<S>                                 <C>     <C>
Maintenance                         $18.3   $12.6
Growth                               10.3    (2.0)
                                    -----   -----
   Total                            $28.6   $10.6
                                    =====   =====
</TABLE>

Maintenance expenditures increased $5.8 million in 2005 compared with 2004
primarily due to pipeline replacements and compressor station overhauls. Growth
expenditures increased $12.3 million in 2005 compared with 2004 primarily due to
spending related to the Chicago III Expansion Project.

In 2004, cash reimbursements related to pipeline interconnections more than
offset growth capital expenditures, resulting in a net cash inflow of $2.0
million. Maintenance expenditures were primarily related to compressor station
overhauls.

FINANCING ACTIVITIES

Cash provided by financing activities was $176.2 million in 2005 compared with
$204.0 million in 2004. In 2005, borrowings under our revolving credit agreement
were used primarily to repay the amount borrowed under our previously existing
credit agreement. Total borrowings were $136.0 million and total repayments were
$109.0 million. We paid cash distributions of $202.9 million to our partners in
2005.

In 2004, we borrowed $107.0 million under our credit agreement and received
equity contributions of $205 million from our partners. We also terminated
interest rate swap agreements with a total notional amount of $225 million and
received $7.6 million. We used the borrowings and equity contributions to repay
$313.0 million of debt, which included the $75 million redemption of our senior
notes due in 2007, and the related $4.8 million premium. In 2004, our Management
Committee approved a change to our cash distribution policy to equal 100% of our
distributable


                                       21


<PAGE>

cash flow based on earnings before interest, taxes, depreciation and
amortization less interest expense and maintenance capital expenditures
which increased distributions to partners by $51.7 million compared with 2003.

In 2003, we borrowed $142.0 million under our credit agreement and paid $165.0
million of debt.

CAPITAL EXPENDITURES

We will continue to make capital expenditures for maintenance and growth
activities. We intend to finance half of our future growth capital expenditures
with equity contributions from our partners.

In 2006, we expect to invest approximately $11 million and $12 million for
maintenance and growth capital expenditures, respectively. Our growth capital
expenditure estimate includes approximately $10 million related to the Chicago
III Expansion Project.

COMMITMENTS

CONTRACTUAL OBLIGATIONS

Our contractual obligations related to debt, operating leases and other
long-term obligations as of December 31, 2005, included the following:

<TABLE>
<CAPTION>
                                                       PAYMENTS DUE BY PERIOD
                                   --------------------------------------------------------------
                                                LESS THAN 1                           MORE THAN 5
                                      TOTAL         YEAR      1-3 YEARS   4-5 YEARS      YEARS
                                   ----------   -----------   ---------   ---------   -----------
                                                           (In thousands)
<S>                                <C>          <C>           <C>         <C>         <C>
6.25% senior notes due 2007        $  150,000     $    --      $150,000    $     --     $     --
7.75% senior notes due 2009           200,000          --            --     200,000           --
7.50% senior notes due 2021           250,000          --            --          --      250,000
Credit Agreement due 2010              27,000          --            --      27,000           --
Interest payments on
   long-term debt                     364,437      43,756        71,887      48,013      200,781
Operating leases                       77,079       2,511         5,022       4,697       64,849
                                   ----------     -------      --------    --------     --------
   Total contractual obligations   $1,068,516     $46,267      $226,909    $279,710     $515,630
                                   ==========     =======      ========    ========     ========
</TABLE>

Operating Leases - We are required to make future minimum payments for office
space and rights-of-way under non-cancelable operating leases.

CASH DISTRIBUTIONS

Distributions to partners are made on a pro rata basis according to each
partner's capital account balance approximately one month following the end of
the quarter. Our Management Committee determines the amount and timing of such
distributions. Any changes to, or suspension of, our cash distribution policy
requires the unanimous approval of our Management Committee.

The Management Committee changed its cash distribution policy effective in
January 2004 to distribute 100% of the distributable cash flow based on earnings
before interest, taxes, depreciation and amortization less interest expense and
maintenance capital expenditures. Upon closing the sale of the 20% partnership
interest, we will adopt certain changes to our cash distribution policy related
to financial ratio targets and capital contributions. Additional information is
included under Item 1, "Business-General Development of Business."

On February 1, 2006, a cash distribution of approximately $45.0 million was
declared and paid for the fourth quarter of 2005.


                                       22

<PAGE>

CONTINGENCIES

LEGAL

On November 1, 2005, as required by the provisions of the settlement of our 1999
rate case, we filed a rate case with the FERC. Information about the rate case
is included under Item 3, "Legal Proceedings."

ENVIRONMENTAL

We are not aware of any material contingent liabilities with respect to
compliance with applicable environmental laws and regulations.

RECENT ACCOUNTING PRONOUNCEMENTS

The FASB recently issued SFAS No. 123R, "Share-Based Payment" and Interpretation
47, "Accounting for Conditional Asset Retirement Obligations-an interpretation
of FASB Statement No. 143." In addition, the FERC issued guidance related to
accounting for pipeline integrity costs. Additional information about these
accounting pronouncements is included in Notes 3 and 13 of the Financial
Statements.

FORWARD-LOOKING STATEMENTS

The statements in this annual report that are not historical information,
including statements concerning plans and objectives of management for future
operations, economic performance or related assumptions, are forward-looking
statements within the meaning of Section 27A of the Securities Act of 1933 and
Section 21E of the Exchange Act. Forward-looking statements may include words
such as "anticipate," "estimate," "expect," "project," "intend," "plan,"
"believe," "should" and other words and terms of similar meaning. Although we
believe that our expectations regarding future events are based on reasonable
assumptions, we can give no assurance that our goals will be achieved. Important
factors that could cause actual results to differ materially from those in the
forward-looking statements include:

     -    the impact of unsold capacity being greater or less than expected;

     -    the ability to market pipeline capacity on favorable terms, which is
          affected by:

          -    future demand for and prices of natural gas;

          -    competitive conditions in the overall natural gas and electricity
               markets;

          -    availability of supplies of Canadian and U.S. natural gas;

          -    availability of additional storage capacity;

          -    weather conditions; and

          -    competitive developments by Canadian and U.S. natural gas
               transmission peers;

     -    final orders by the FERC which adversely impact changes requested in
          our November 2005 rate case;

     -    performance of contractual obligations by our customers;

     -    performance of contractual obligations by our operator and a
          transition from our current operator to an affiliate of TransCanada;

     -    the ability to recover operating costs, costs of property, plant and
          equipment and regulatory assets in our FERC-regulated rates;

      -   developments in the December 2, 2001, filing by Enron of a voluntary
          petition for bankruptcy protection under Chapter 11 of the U.S.
          Bankruptcy Code affecting our settled claims;

     -    ability to control operating costs;

     -    conditions in the capital markets and our ability to access the
          capital markets;

     -    risks inherent in the use of information systems in our respective
          businesses, implementation of new software and hardware, and the
          impact on the timeliness of information for financial reporting; and

     -    acts of nature, sabotage, terrorism or other similar acts causing
          damage to our facilities or our suppliers' or shippers' facilities.

These factors are not necessarily all of the important factors that could cause
actual results to differ materially from those expressed in any of our
forward-looking statements. Other factors could also have material adverse
effects on our future results. These and other risks are described in greater
detail under Item 1A, "Risk Factors." All forward-looking statements
attributable to us or persons acting on our behalf are expressly qualified in
their entirety by these


                                       23

<PAGE>

factors. Other than as required under securities laws, we undertake no
obligation to update publicly any forward-looking statement whether as a result
of new information, subsequent events or change in circumstances, expectations
or otherwise.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

OVERVIEW

Our exposure to market risk discussed below includes forward-looking statements
and represents an estimate of possible changes in future earnings that would
occur assuming hypothetical future movements in interest rates. Our views on
market risk are not necessarily indicative of actual results that may occur and
do not represent the maximum possible gains and losses that may occur, since
actual gains and losses will differ from those estimated, based on actual
fluctuations in interest rates and the timing of transactions.

We are exposed to market risk due to interest rate fluctuations. Market risk is
the risk of loss arising from adverse changes in market rates. We utilize
financial instruments to manage the risks of certain identifiable or anticipated
transactions and achieve a more predictable cash flow. Our risk management
function follows established policies and procedures to monitor interest rates
to ensure our hedging activities mitigate market risks. We do not use financial
instruments for trading purposes.

In accordance with SFAS No. 133, "Accounting for Derivative Instruments and
Hedging Activities," we record financial instruments on the balance sheet as
assets and liabilities based on fair value. We estimate the fair value of
financial instruments using available market information and appropriate
valuation techniques. Changes in financial instruments' fair value are
recognized in earnings unless the instrument qualifies as a hedge under SFAS No.
133 and meets specific hedge accounting criteria. Qualifying financial
instruments' gains and losses may offset the hedged items' related results in
earnings for a fair value hedge or be deferred in accumulated other
comprehensive income for a cash flow hedge.

INTEREST RATE RISK

We utilize both fixed- and variable-rate debt and are exposed to market risk due
to the floating interest rates on our credit facility. We regularly assess the
impact of interest rate fluctuations on future cash flows and evaluate hedging
opportunities to mitigate our interest rate risk.

We maintain a significant portion of our debt at fixed rates to reduce our
sensitivity to interest rate fluctuations and utilize interest rate swap
agreements to convert fixed-rate debt to variable-rate debt to manage interest
expense. In November 2004, we terminated our outstanding interest rate swap
agreements with notional amounts of $225 million that we entered into in May
2002. As of December 31, 2005, 96% of our outstanding debt was at fixed rates
and there were no interest rate swap agreements outstanding.

If interest rates hypothetically increased 1% compared with rates in effect as
of December 31, 2005, our annual interest expense would increase and our net
income would decrease by approximately $0.3 million.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

The information required hereunder is included in this report as set forth in
the "Index to Financial Statements" on page F-1.

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
        FINANCIAL DISCLOSURE

None.

ITEM 9A. CONTROLS AND PROCEDURES

CONCLUSION REGARDING THE EFFECTIVENESS OF DISCLOSURE CONTROLS AND PROCEDURES

The equivalent of our principal executive officer and principal financial
officer evaluated the effectiveness of the our "disclosure controls and
procedures" (as such term is defined in Exchange Act Rule 13a-15(e) or
15d-15(e)) as of


                                       24

<PAGE>

the end of the period covered by this annual report. Based upon their
evaluation, the equivalent of our principal executive officer and principal
financial officer concluded that our disclosure controls and procedures are
effective.

CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING

There were no changes in our internal control over financial reporting that
occurred during our last fiscal quarter that have materially affected, or are
reasonably likely to materially affect, our internal control over financial
reporting. However, in conjunction with our rate case, we are completing system
modifications to meet proposed new transaction billing requirements.
Implementation is scheduled for May 2006. This activity will cause changes to
our internal control over financial reporting.

ITEM 9B. OTHER INFORMATION

On January 19, 2006, the Board of Directors of ONEOK granted restricted stock
units and performance units under ONEOK's Equity Compensation Plan to William R.
Cordes and Jerry L. Peters, officers of Northern Plains, our operator, and the
equivalent of our chief executive officer, and our chief financial and
accounting officer, as well as with the following officers of Northern Plains:
Paul F. Miller, Michel E. Nelson, Raymond D. Neppl, Janet K. Place, Fred G.
Rimington, and Christopher R Skoog. The restricted stock units vest three years
from the date of grant at which time the grantee is entitled to shares of ONEOK
common stock. The performance units granted vest three years from the date of
grant at which time the holder is entitled to receive a percentage (0% to 200%)
of the performance shares granted based on ONEOK's total shareholder return over
the period January 19, 2006, to January 19, 2009, compared to the total
shareholder return of a peer group of 20 other companies. The grant is payable
in shares of ONEOK common stock. In addition, our operator's executive officers
participate in the ONEOK Employee Stock Purchase Plan. These plans and form of
award agreements are filed as exhibits to this Form 10-K and their terms and
provisions are incorporated herein by reference, as follows: ONEOK's Equity
Compensation Plan - Exhibit 10.12; ONEOK, Inc. Form of Restricted Unit Award
Agreement under Equity Compensation Plan - Exhibit 10.14; ONEOK, Inc. Form of
Performance Unit Award Agreement under Equity Compensation Plan - Exhibit 10.15;
and ONEOK, Inc. Employee Stock Purchase Plan, as amended February 17, 2005 -
Exhibit 10.13.

On February 15, 2006, Northern Border Partners, L.P. and ONEOK, Inc. issued a
joint press release announcing certain transactions relating to (1) the sale of
certain assets by ONEOK to Northern Border Partners, (2) the increase of ONEOK's
general partnership interest in Northern Border Partners to 100% and (3) the
sale by Northern Border Partners of 20% of its interest in Northern Border
Pipeline Company to TC PipeLines, LP. (collectively, the "Transactions").

On March 2, 2006, a holder of limited partnership units of Northern Border
Partners, L.P. filed a class action and derivative complaint, Civil Action No.
1973-N, in the New Castle County Chancery Court in the State of Delaware, on
behalf of a putative class of all holders of limited partnership units against
Northern Border Partners, ONEOK, Northern Plains Natural Gas Company, LLC, and
related entities involved in the Transactions. The plaintiff claims the
Transactions will constitute a breach of Northern Border Partners' partnership
agreement and a breach of defendants' fiduciary duties. The plaintiff seeks to
enjoin the Transactions or to rescind the Transactions if the Transactions are
completed prior to entry of a final judgment in the case. The Plaintiff also
seeks to recover on behalf of the class damages for the profits and any special
benefits obtained by the defendants, as well as interest, costs, and attorney
and expert fees.

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

MANAGEMENT COMMITTEE

We do not compensate members of the Management Committee for their services. We
are overseen by the Management Committee consisting of the following
individuals:

<TABLE>
<CAPTION>
NAME                AGE   POSITION
----                ---   --------
<S>                 <C>   <C>
William R. Cordes    57   Chairman
Max Feldman          57   Member
David L. Kyle        53   Member
Paul E. Miller       47   Member
</TABLE>

William R. Cordes was named chief executive officer of the Northern Border
Partners and chairman of our Management Committee in 2000. He served as chairman
of the Partnership Policy Committee of Northern Border Partners from 2000 until
2004. Mr. Cordes was appointed president of Northern Plains and Pan Border in
2000 and president of NBP Services in 2004. In 1970, he started his career with
Northern Natural Gas Company, an Enron subsidiary until 2002, where he worked in
several management positions. From 1993 until 2000, he was president of Northern
Natural Gas Company, and from 1996 until 2000, he was also president of
Transwestern Pipeline, a subsidiary of Enron.

Max Feldman was designated by TC PipeLines Intermediate as a member of our
Management Committee in 2003. Mr. Feldman was named vice president, Gas
Transmission West of TransCanada in 2003. Mr. Feldman was named an officer of TC
PipeLines LP in 2003. From 1999 to 2003, he was senior vice president, Customer
Sales and Service, and from 1995 to 1999, Mr. Feldman held several vice
president positions in the operations, customer service and marketing areas of
TransCanada PipeLines Limited.

David L. Kyle was designated a member of our Management Committee and named
chairman of the Partnership Policy Committee of Northern Border Partners in
2004. Mr. Kyle is chairman and chief executive officer of Northern Plains, Pan
Border and NBP Services. Mr. Kyle is also the chairman of the board, president,
and chief executive officer of ONEOK. He was employed by Oklahoma Natural Gas
Company in 1974 as an engineer trainee. He served in a number of positions prior
to being elected vice president of Gas Supply in 1986 and executive vice
president in 1990. He was elected president of Oklahoma Natural Gas Company in
1994. He was elected president of ONEOK in 1997, and elected chairman of the
board and appointed the chief executive officer of ONEOK in 2000. Mr. Kyle is a
member of the board of directors of Bank of Oklahoma Financial Corporation.

Paul E. Miller was designated by TransCanada as Northwest Border's
representative on our Management Committee and its member on the Partnership
Policy Committee of Northern Border Partners in 2003. Mr. Miller


                                       25

<PAGE>

serves as director, Corporate Development of TransCanada, a position he has held
since 2003. From 1998 to 2003, Mr. Miller was director, Finance of TransCanada.
Prior to 1998, Mr. Miller was manager, Finance of TransCanada.

OFFICERS

The following individuals are officers of Northern Plains who are deemed to be
executive officers of the partnership:

<TABLE>
<CAPTION>
NAME                  AGE       POSITION
----                  ---       --------
<S>                   <C>       <C>
Paul F. Miller         39       Vice President and General Manager
                                Northern Border Pipeline
Michel E. Nelson       58       Vice President, Operations, Interstate Pipelines
Raymond D. Neppl       61       Vice President, Regulatory Affairs and
                                Market Services, Interstate Pipelines
Jerry L. Peters        48       Chief Financial and Accounting Officer
Janet K. Place         57       Vice President, General Counsel and Secretary
Fred G. Rimington      55       Vice President, Administration, Northern Plains
Christopher R Skoog    42       Executive Vice President
</TABLE>

Paul F. Miller was elected vice president and general manager of Northern Border
Pipeline by Northern Plains in January 2005. From 2002 until January 2005, Mr.
Miller was vice president of Marketing for Northern Plains. Mr. Miller was
previously account executive, Marketing from 1998 until 2000, when he was
promoted to director, Marketing. Mr. Miller joined Northern Plains in 1990.

Michel E. Nelson was elected vice president, Operations for Northern Plains in
2004. Mr. Nelson was previously vice president of Operations and Support
Services for CrossCountry Energy, LLC, an Enron subsidiary, from 2002 to 2004.
From 1997 to 2002, Mr. Nelson held various positions for Enron Transportation
Services with responsibility for pipeline operations. Mr. Nelson started his
pipeline operations career with Northern Natural Gas Company in 1968.
CrossCountry Energy, Enron Transportation Services and Northern Natural Gas
Company were formerly affiliated with Northern Plains.

Raymond D. Neppl is vice president, Regulatory Affairs and Market Services, a
position he has held since 1994. Mr. Neppl was previously vice president of
Regulatory Affairs from 1991 to 1994. Mr. Neppl joined Northern Natural Gas
Company, formerly affiliated with Northern Plains, in 1975 and transferred to
Northern Plains in 1980.

Jerry L. Peters was named chief financial and accounting officer in 1994. Mr.
Peters has held several management positions with Northern Plains since 1985 and
was elected vice president of Finance in 1994 and treasurer in 1998. Mr. Peters
was also elected vice president of Finance for NBP Services in 2004. Mr. Peters
was vice president, Finance of the following former affiliates of Northern
Plains: Florida Gas Transmission Company from February 2001 to May 2002;
Transportation Trading Services Company from September 2001 to July 2002; Citrus
Corp. from October 2001 to July 2002; and Transwestern Pipeline Company from
November 2001 to May 2002. Prior to joining Northern Plains in 1985, Mr. Peters
was employed as a certified public accountant by KPMG LLP.

Janet K. Place is vice president, general counsel and secretary of Northern
Plains. Ms. Place was elected as vice president in 1994 and secretary in 2004.
She was also elected vice president, general counsel and secretary of NBP
Services in 2004. In 1993, Ms. Place was named general counsel. Ms. Place joined
Northern Plains in 1980 as an attorney.

Fred G. Rimington was elected vice president, Administration of Northern Plains
and NBP Services in February 2005. He was appointed president of Black Mesa
Pipeline, Inc. in 2000. Mr. Rimington was director, Business Development from
1994 to 1999 for Northern Plains. Mr. Rimington joined Northern Plains in 1980.


                                       26

<PAGE>

Christopher R Skoog was appointed executive vice president of Northern Plains
and NBP Services in February 2005. Mr. Skoog is responsible for all commercial,
operational and regulatory functions of our natural gas businesses and
coordinates our business development initiatives. From 1999 to January 2005, Mr.
Skoog served as president of ONEOK Energy Services Company, II. From 1995 to
1999, he was vice president of ONEOK Gas Marketing Company.

AUDIT COMMITTEE

Under our partnership agreement, our Audit Committee is to consist of members
appointed by the Management Committee. There are currently two members on the
Audit Committee since, as also directed in our partnership agreement, if
Northern Plains or its affiliates serve as operator, it may not designate a
member of the committee and no member of the committee can be affiliated as an
employee, officer or director with Northern Plains. The Audit Committee,
consisting of Mr. Hobbs, vice president and controller of TransCanada, and Mr.
Feldman, vice president, Gas Transmission West of TransCanada, oversees the
annual audit process and confers with KPMG LLP, our independent auditors. The
Management Committee has determined that Mr. Hobbs is an "audit committee
financial expert," as defined by the rules and regulations of the SEC. Our Audit
Committee financial expert is not independent and is not required to be
independent because we do not have securities that are listed on a national
exchange or national securities association.

CODE OF ETHICS

The Management Committee adopted an Accounting and Financial Reporting Code of
Ethics for those officers of Northern Plains that are the equivalent of our
principal executive officer and principal financial and accounting officer. The
code of ethics is posted on the "Other Postings" section of our website,
www.nbpl.nborder.com, and we intend to post on our website any amendment to, or
waiver from, any provision of our Accounting and Financial Reporting Code of
Ethics that applies to those officers of Northern Plains that are the equivalent
of our principal executive officer and principal financial and accounting
officer within four business days following such amendment or waiver, in
accordance with SEC rules.

ITEM 11. EXECUTIVE COMPENSATION

The following table summarizes the compensation paid for the last three years to
the chief executive officer and the four most highly compensated executive
officers of the operator during 2005, which we collectively refer to as the
"named executive officers." From January 1, 2003, through November 17, 2004,
compensation plans were administered by Enron. Beginning November 18, 2004,
compensation plans are administered by ONEOK.


                                       27

<PAGE>

SUMMARY COMPENSATION TABLE

<TABLE>
<CAPTION>
                                                ANNUAL COMPENSATION                 LONG-TERM
                                     -----------------------------------------     COMPENSATION
                                                                OTHER ANNUAL     ----------------
                                                              COMPENSATION (1)      RESTRICTED       ALL OTHER
NAME AND PRINCIPAL POSITION   YEAR   SALARY ($)   BONUS ($)          ($)         STOCK AWARDS ($)   COMPENSATION ($)
---------------------------   ----   ----------   ---------   ----------------   ----------------   ----------------
<S>                           <C>    <C>          <C>         <C>                <C>                <C>
William R. Cordes             2005    $330,000     $365,000      $    --            $111,760(5)        $21,607(6)
Chief Executive Officer       2004     325,000      175,000           --                  --             4,908
                              2003     324,583      200,000           --              99,972(4)          3,000

Jerry L. Peters               2005     190,000      140,000           --              55,880(5)         13,616(7)
Chief Financial and           2004     171,380      110,000           --                  --             5,658
   Accounting Officer         2003     163,324      107,500           --                  --            76,386

Christopher R Skoog (2)       2005     315,000      300,000       71,981(3)           83,820(5)         43,294(8)
Executive Vice President

Janet K. Place                2005     185,000      135,000           --              37,253(5)         13,475(9)
Vice President, General       2004     182,552      115,000           --                  --             8,675
   Counsel and Secretary      2003     177,592      110,000           --                  --             6,233

Paul F. Miller                2005     175,000      140,000           --              46,566(5)         12,594(10)
Vice President and General    2004     153,298      118,000           --                  --             5,335
   Manager for Northern       2003     148,958      111,000           --                  --            90,325
   Border Pipeline
</TABLE>

(1)  Except as specifically noted below, with respect to Mr. Skoog, the named
     executive officers did not receive any annual compensation not properly
     categorized as salary or bonus, except for certain perquisites and other
     personal benefits, which include vehicle allowances and country club dues.
     The aggregate amount of such perquisites and other personal benefits, if
     any, for the named executive officers during the fiscal year did not exceed
     the lesser of $50,000 or 10% of total salary and bonus reported for such
     named executive officer. The aggregate amount of perquisites and other
     personal benefits received in the last fiscal year, for the named executive
     officers other than Mr. Skoog, were as follows: Mr. Cordes, $26,340; Mr.
     Peters, $14,400; Ms. Place, $14,400; and Mr. Miller, $14,400.


(2)  Mr. Skoog was appointed as executive vice president of Northern Plains in
     February 2005.

(3)  Includes $52,500 in relocation expenses under ONEOK's relocation plan,
     which plan is available generally to all salaried employees, $18,000
     vehicle allowance and $1,481 physical examination cost.

(4)  On June 1, 2003, 669 Northern Border Partners' phantom units valued at
     $149.4346 per unit were granted in accordance with Mr. Cordes' employment
     agreement. The phantom units vest on the fifth anniversary of the date of
     each grant. As of December 31, 2005, Mr. Cordes held 4,162 phantom units
     valued at $643,397 ($154.5885 per unit). Distributions accrued on the
     phantom units as of December 31, 2005, were $198,336.

(5)  Represents restricted stock incentive units granted under ONEOK's Long-Term
     Incentive Plan. The market value of restricted stock incentive unit awards
     is based on the closing market price of a share of ONEOK common stock on
     the NYSE on the date of grant. Each grant vests three years from the date
     of grant at which time the grantee is entitled to receive two-thirds of the
     grant in shares of ONEOK common stock and one-third of the grant in cash.
     Since no shares of ONEOK common stock are issued under a restrictive stock
     incentive unit until the unit vests, no dividends are payable with respect
     to restricted stock incentive units. The aggregate number of restricted
     stock incentive units  (excluding fractional shares) held by the named
     executive officers at December 31, 2005, and the market value of these
     restricted stock incentive units as of that date are indicated in the table
     below. In addition to Restricted Stock Incentive Units, Mr. Skoog holds
     12,274 aggregate shares (excluding fractional shares) of restricted stock
     with a market value of $326,857 as of December 31, 2005. Restricted stock
     is granted under ONEOK's Long Term Incentive Plan. Each grant vests three
     years from the date of grant. Dividends are paid on unvested shares of
     restricted stock and reinvested in additional shares of restricted stock at
     the average of the high and low trading prices of a share of ONEOK's common
     stock on the New York Stock Exchange on the date the dividend is paid.
     Restricted stock acquired as a result of the reinvestment of dividends
     vests at the same time as the restricted stock with respect to which the
     dividend was paid vests. The market value was determined based on a per
     share price for ONEOK common stock of $26.63, which reflects the closing
     market price of ONEOK common stock on the NYSE on December 30, 2005.


                                       28

<PAGE>

<TABLE>
<CAPTION>
                                  AGGREGATE NUMBER OF             MARKET VALUE OF RESTRICTED
                            RESTRICTED STOCK INCENTIVE UNITS     STOCK INCENTIVE UNITS HELD AT
      NAME                     HELD AT DECEMBER 31, 2005               DECEMBER 31, 2005
      ----                  --------------------------------     -----------------------------
      <S>                   <C>                                  <C>
      William R. Cordes                 6,000                            $159,780
      Christopher R Skoog              16,000                             426,080
      Jerry L. Peters                   3,000                              79,890
      Janet K. Place                    2,000                              53,260
      Paul F. Miller                    2,500                              66,575
</TABLE>

(6)  Amount includes: (i) $7,402 paid as a company match under ONEOK's
     Non-Qualified Deferred Compensation Plan; (ii) $12,600 paid as a company
     match under the Thrift Plan for Employees of ONEOK, Inc. and Subsidiaries;
     (iii) $1,276 paid as a service award; and (iv) $329 representing the value
     of ONEOK shares received under ONEOK's Employee Stock Award Program based
     on the closing market price of ONEOK's common stock on the NYSE on the date
     of issue.

(7)  Amount includes: (i) $12,485 paid as a company match under the Thrift Plan
     for Employees of ONEOK, Inc. and Subsidiaries; (ii) $802 paid as a service
     award; and (iii) $329 representing the value of ONEOK shares received under
     ONEOK's Employee Stock Award Program based on the closing market price of
     ONEOK's common stock on the NYSE on the date of issue.

(8)  Amount includes: (i) $30,000 paid as a company match under ONEOK's
     Non-Qualified Deferred Compensation Plan; (ii) $12,600 paid as a company
     match under the Thrift Plan for Employees of ONEOK, Inc. and Subsidiaries;
     (iii) $365 paid as a service award; and (iv) $329 representing the value of
     ONEOK shares received under ONEOK's Employee Stock Award Program based on
     the closing market price of ONEOK's common stock on the NYSE on the date of
     issue.

(9)  Amount includes: (i) $12,234 paid as a company match under the Thrift Plan
     for Employees of ONEOK, Inc. and Subsidiaries; (ii) $912 paid as a service
     award; and (iii) $329 representing the value of ONEOK shares received under
     ONEOK's Employee Stock Award Program based on the closing market price of
     ONEOK's common stock on the NYSE on the date of issue.

(10) Amount includes: (i) $11,664 paid as a company match under the Thrift Plan
     for Employees of ONEOK, Inc. and Subsidiaries; (ii) $601 paid as a service
     award; and (iii) $329 representing the value of ONEOK shares received under
     ONEOK's Employee Stock Award Program based on the closing market price of
     ONEOK's common stock on the NYSE on the date of issue.

For 1999, 2000 and 2001, employees of Northern Plains were able to elect to
receive Northern Border phantom units, Enron phantom stock, and/or Enron stock
options in lieu of all or a portion of an annual bonus payment. Mr. Cordes, Mr.
Peters, Ms. Place and Mr. Miller elected to receive Northern Border phantom
units under the Northern Border Phantom Unit Plan in lieu of a portion of the
cash bonus payment. As a result of this deferral, Mr. Cordes received 1,914
units in 2001; Mr. Peters received 1,532 units in 1999, 1,450 units in 2000 and
842 units in 2001; Ms. Place received 901 units in 1999 and 240 units in 2001;
and Mr. Miller received 137 units in 1999, 123 units in 2000 and 230 units in
2001. In each case, units will be released based upon the holding period
selected by the participant. For the release in January 2004, Mr. Peters
received 4,727 common units and $2,234 in cash and he received 6,734 common
units for the release in January 2005. For the release in January 2003, Ms.
Place received 1,091 common units and for the release in January 2004, she
elected a redemption payment in cash of $83,232. For the release in January
2003, Mr. Miller received 329 common units and for the release in January 2004,
he elected a redemption payment in cash of $25,283. As of December 31, 2005, Mr.
Peters held 842 phantom units valued at $130,164 ($154.5885 per unit).
Distributions accrued on Mr. Peters' phantom units as of December 31, 2005, were
$46,760. As of December 31, 2005, Ms. Place held 230 phantom units valued at
$35,555 ($154.5885 per unit). Distributions accrued on Ms. Place's phantom units
as of December 31, 2005, were $12,773. As of December 31, 2005, Mr. Miller held
115 phantom units valued at $17,778 ($154.5885 per unit). Distributions accrued
on Mr. Miller's phantom units as of December 31, 2005, were $6,387. Mr. Cordes'
information is included above in footnote 5 to the Summary Compensation Table.

On January 19, 2006, the Board of Directors of ONEOK granted restricted stock
units and performance units under ONEOK's Equity Compensation Plan to the named
executive officers as follows: (i) Mr. Cordes, 6,000 restricted stock units and
10,500 performance units; Mr. Skoog, 2,500 restricted stock units and 4,000
performance units; Mr. Peters, 2,500 restricted stock units and 4,000
performance units; Ms. Place 1,500 restricted stock units and 2,500


                                       29

<PAGE>

performance units; and Mr. Miller 1,500 restricted stock units and 2,500
performance units. The restricted stock units vest three years from the date of
grant at which time the grantee is entitled to shares of ONEOK common stock. The
performance units granted vest three years from the date of grant at which time
the holder is entitled to receive a percentage (0% to 200%) of the performance
shares granted based on ONEOK's total shareholder return over the period January
19, 2006, to January 19, 2009, compared to the total shareholder return of a
peer group of 20 other companies. The grant is payable in shares of ONEOK common
stock.

LONG-TERM INCENTIVE PLANS - AWARDS IN LAST FISCAL YEAR

The following table sets forth certain information concerning performance share
units granted in 2005 to the named executive officers under ONEOK's Long-Term
Incentive Plan.

PERFORMANCE SHARE GRANTS

<TABLE>
<CAPTION>
                                                               ESTIMATED FUTURE PAYOUTS UNDER
                        NUMBER OF     PERFOMANCE OR             NON-STOCK PRICE-BASED PLANS
                      SHARES, UNITS    OTHER PERIOD   -----------------------------------------------
                         OR OTHER         UNTIL                        TARGET            MAXIMUM
                      RIGHTS (1)(2)   MATURATION OR   THRESHOLD   ---------------   -----------------
NAME                       (#)            PAYOUT       ($ OR #)    (#)     ($)(3)    (#)      ($)(3)
----                  -------------   -------------   ---------   -----   -------   ------   --------
<S>                   <C>             <C>             <C>         <C>     <C>       <C>      <C>
William R. Cordes         10,500         3 Years          --      7,000   $93,205   14,000   $186,410
Christopher R Skoog        9,000         3 Years          --      6,000    79,890   12,000    159,780
Jerry L. Peters            4,500         3 Years          --      3,000    39,945    6,000     79,890
Janet K. Place             3,500         3 Years          --      2,333    31,077    4,666     62,154
Paul F. Miller             4,000         3 Years          --      2,666    35,524    5,333     71,022
</TABLE>

(1)  Restricted stock incentive units granted under ONEOK's Long-Term Incentive
     Plan in 2005 are set forth in the Summary Compensation Table above.

(2)  Reflects performance share units granted which vest three years from the
     date of grant. Upon vesting, a holder of performance share units is
     entitled to receive a number of shares of ONEOK common stock equal to a
     percentage (0% to 200%) of the performance share units granted based on
     ONEOK's total shareholder return over the period January 20, 2005, to
     January 20, 2008, compared to the total shareholder return of a peer group
     of 20 other energy companies over the same period. Upon vesting, if any,
     the performance share awards are payable two-thirds in shares of ONEOK
     common stock and one-third in cash.

(3)  The value for the one-third of the grant payable in cash was determined
     based on a per share price for ONEOK common stock of $26.63, which reflects
     the closing market price of ONEOK common stock on the NYSE on December 30,
     2005.

TERMINATION AGREEMENT

ONEOK has entered into termination agreements with each of our named executive
officers. Each termination agreement has an initial term of one year and is
automatically extended in one-year increments after the expiration of the
initial term unless ONEOK provides notice to the officer or the officer provides
notice to ONEOK at least 90 days before January 1, preceding the initial or any
subsequent termination date of the agreement that the party providing notice
does not wish to extend the term. If a "change in control" of ONEOK occurs, the
term of each termination agreement will not expire for at least three years
after the change in control.

Under the termination agreements, severance payments and benefits are payable if
the officer's employment is terminated by ONEOK without "just cause" or by the
officer for "good reason" at any time during the three years after a change in
control. In general, severance payments and benefits include a lump sum payment
in an amount equal to (1) two times (three times, in the case of William Cordes)
the officer's annual compensation and (2) a prorated portion of the officer's
targeted short-term incentive compensation. The officer would also be entitled
to an accelerated vesting of retirement and other benefits under the
Supplemental Executive Retirement Plan (discussed below) and continuation of
welfare benefits for 24 months (36 months in case of Mr. Cordes). Severance
payments will be reduced if the net after-tax benefit to such officer exceeds
the net after-tax benefit if such reduction were not made. Gross up payments
will be made to such officers only if the severance payments, as reduced, are
subsequently deemed to constitute excess parachute payments.


                                       30

<PAGE>

For purposes of these agreements, a change in control generally means any of the
following events:

     -    an acquisition of voting securities of ONEOK by any person that
          results in the person having beneficial ownership of 20% or more of
          the combined voting power of ONEOK's outstanding voting securities,
          other than an acquisition directly from ONEOK;

     -    the current members of ONEOK's Board of Directors, and any new
          director approved by a vote of at least two-thirds of ONEOK's Board of
          Directors, cease for any reason to constitute at least a majority of
          ONEOK's Board of Directors, other than in connection with an actual or
          threatened proxy contest (collectively, the "Incumbent Board");

     -    a merger, consolidation or reorganization with ONEOK or in which ONEOK
          issues securities, unless (a) ONEOK's shareholders immediately before
          the transaction do not, as a result of the transaction, own, directly
          or indirectly, at least 50% of the combined voting power of the voting
          securities of the company resulting from the transaction; (b) members
          of ONEOK's Incumbent Board after the execution of the transaction
          agreement do not constitute at least a majority of the members of the
          Board of the company resulting from the transaction; or (c) no person
          other than persons who, immediately before the transaction owned 30%
          or more of ONEOK's outstanding voting securities, has beneficial
          ownership of 30% or more of the outstanding voting securities of the
          company resulting from the transaction; or

     -    ONEOK's complete liquidation or dissolution or the sale or other
          disposition of all or substantially all of their assets.

ENRON CASH BALANCE PLAN

Enron maintained the Enron Corp. Cash Balance Plan (Cash Balance Plan), which
was a noncontributory defined benefit pension plan to provide retirement income
for employees of Enron and its subsidiaries. Participants in the Cash Balance
Plan with five years or more of service were entitled to retirement benefits in
the form of an annuity based on a formula that uses a percentage of final
average pay and years of service. Enron's Board of Directors voted to terminate
the Cash Balance Plan effective May 31, 2004. The process of terminating the
Cash Balance Plan involved a series of governmental filings seeking approval for
the termination and notices to participants and beneficiaries. Upon termination,
all employees became fully vested in the Cash Balance Plan. In 2005,
participants' cash balance accruals and accumulated interest credits were
distributed as either lump sum or monthly annuities, depending upon a
participant's election and particular circumstances. Lump sum payments could be
rolled over to other qualified retirement plans or IRAs, or received in cash.
The named executive officers received the following approximate payout amounts
in 2005 pursuant to the terms of the Cash Balance Plan termination: Mr. Cordes,
$77,144; Mr. Peters, $64,285; Ms. Place, $69,492; and Mr. Miller, $40,600.

PENSION PLAN - ONEOK

ONEOK's retirement plan is a tax-qualified, defined-benefit pension plan under
both the Internal Revenue Code of 1986, as amended, and the Employee Retirement
Income Security Act of 1974, as amended. The following table sets forth the
estimated annual retirement benefits payable to a non-bargaining unit plan
participant based upon the final average pay formulas under ONEOK's retirement
plan for employees in the compensation and years-of-service classifications
specified. The estimates assume that benefits are received in the form of a
single life annuity.


                                       31

<PAGE>

PENSION PLAN TABLE

<TABLE>
<CAPTION>
                                 YEARS OF SERVICE
               ----------------------------------------------------
REMUNERATION      15         20         25         30         35
------------   --------   --------   --------   --------   --------
<S>             <C>        <C>        <C>        <C>        <C>
$125,000       $ 32,119   $ 42,825   $ 53,531   $ 64,238   $ 74,944
 150,000         39,244     52,325     65,406     78,488     91,569
 175,000         46,369     61,825     77,281     92,738    108,194
 200,000         53,494     71,325     89,156    106,988    124,819
 225,000         60,619     80,825    101,031    121,238    141,444
 250,000         67,744     90,325    112,906    135,488    158,069
 300,000         81,994    109,325    136,656    163,988    191,319
 400,000        110,494    147,325    184,156    220,988    257,819
 450,000        124,744    166,325    207,906    249,488    291,069
 500,000        138,994    185,325    231,656    277,988    324,319
</TABLE>

Benefits under the ONEOK retirement plan become vested and non-forfeitable after
completion of five years of continuous employment. A vested participant receives
the monthly retirement benefit at normal retirement age under the retirement
plan, unless an early retirement benefit is elected under the plan, in which
case the retirement benefit is actuarially reduced for early commencement.
Benefits are calculated at retirement date based on a participant's credited
service, limited to a maximum of 35 years and final average earnings. The
credited year(s) of service under this plan for the named executive officers,
other than Mr. Skoog was one year and one month. As of December 31, 2005, Mr.
Skoog had 10 years and five months of credited service.

For purposes of the table, the annual social security covered compensation
benefit of $48,696 was used in the excess benefit calculation. Benefits payable
under ONEOK's retirement plan are not offset by social security benefits.

Under the Internal Revenue Code, the annual compensation of each employee to be
taken into account under ONEOK's retirement plan for 2005 cannot exceed
$210,000.

Amounts shown in the table are estimates only and are subject to adjustment
based on rules and regulations applicable to the method of distribution and
survivor benefit options selected by the retiree.

The compensation covered by the retirement plan benefit formula for
non-bargaining unit employees is the base salary and bonus paid to an employee
within the employee's final average earnings. Final average earnings mean the
employee's highest earnings during any 60 consecutive months during the last 120
months of employment. For any named executive officer who retires with vested
benefits under the plan, the compensation shown as "Salary" and "Bonus" in the
Summary Compensation Table could be considered covered compensation in
determining benefits, except that the plan benefit formula takes into account
only a fixed percentage of final average earnings which is uniformly applied to
all employees. The amount of covered compensation that may be considered in
calculating retirement benefits is also subject to limitations in the Internal
Revenue Code of 1986, as amended, applicable to the plan.

SUPPLEMENTAL EXECUTIVE RETIREMENT

ONEOK maintains a Supplemental Executive Retirement Plan (SERP) for certain of
its elected or appointed officers, and certain other employees in a select group
of management and highly compensated employees. Participants are selected by
ONEOK's chief executive officer, or, in the case of ONEOK's chief executive
officer, by ONEOK's Board of Directors. All of our named officers participate in
the SERP.

Benefits payable under the SERP are based upon a specified percentage (reduced
for early retirement) of the highest 36 consecutive months' compensation of the
employee's last 60 months of service. The SERP will, in any case, pay a benefit
at least equal to the benefit which would be payable to the participant under
ONEOK's retirement plan if limitations imposed by the Internal Revenue Code were
not applicable, less the benefit payable under ONEOK's retirement plan with such
limitations. Benefits under the SERP are paid concurrently with the payment of
benefits under ONEOK's retirement plan or as ONEOK's Administrative Committee
may determine. SERP benefits are offset by benefits payable under ONEOK's
retirement plan, but are not offset by social security benefits. ONEOK's


                                       32

<PAGE>

board may amend or terminate the SERP at any time, provided that accrued
benefits to current participants may not be reduced.

The following table sets forth the estimated supplemental retirement benefits
payable under ONEOK's SERP based on the covered participant's age at retirement.
The estimates assume that a covered participant is fully vested. The amounts
shown would be reduced for commencement of payments prior to age 60.

SUPPLEMENTAL EXECUTIVE RETIREMENT PLAN TABLE

<TABLE>
<CAPTION>
                 ESTIMATED ANNUAL BENEFITS AT INDICATED AGE OF RETIREMENT
               -----------------------------------------------------------
REMUNERATION   50 AND UNDER      55         60         62      65 AND OVER
------------   ------------   --------   --------   --------   -----------
<S>            <C>             <C>        <C>        <C>       <C>
$100,000         $ 50,000     $ 55,000   $ 59,000   $ 60,000    $ 60,000
 150,000           75,000       82,500     88,500     90,000      90,000
 200,000          100,000      110,000    118,000    120,000     120,000
 250,000          125,000      137,500    147,500    150,000     150,000
 300,000          150,000      165,000    177,000    180,000     180,000
 350,000          175,000      192,500    206,500    210,000     210,000
 400,000          200,000      220,000    236,000    240,000     240,000
 450,000          225,000      247,500    265,500    270,000     270,000
 500,000          250,000      275,000    295,000    300,000     300,000
 550,000          275,000      302,500    324,500    330,000     330,000
 600,000          300,000      330,000    354,000    360,000     360,000
 650,000          325,000      357,500    383,500    390,000     390,000
 700,000          350,000      385,000    413,000    420,000     420,000
 750,000          375,000      412,500    442,500    450,000     450,000
</TABLE>

ONEOK'S EMPLOYEE NON-QUALIFIED DEFERRED COMPENSATION PLAN

The named executive officers are also eligible to participate in ONEOK's
Non-Qualified Deferred Compensation Plan. ONEOK's Non-Qualified Deferred
Compensation Plan provides select employees, as approved by the Board of
Directors of ONEOK, with the option to defer portions of their compensation and
provides non-qualified deferred compensation benefits which are not otherwise
available due to limitations on employer and employee contributions to qualified
defined contribution plans under the federal tax laws. Under the plan,
participants have the option to defer their salary and/or bonus compensation to
a short-term deferral account, which pays out a minimum of five years from
commencement, or to a long-term deferral account, which pays out at retirement
or termination of the employment of the participant. Participants are
immediately 100% vested. Short-term deferral accounts are credited with a deemed
investment return based on the five-year Treasury bond fund. Long-term deferral
accounts are credited with a deemed investment return based on various
investment options, which do not include an option to invest in ONEOK common
stock. At the distribution date, cash is distributed to participants based on
the fair market value of the deemed investment of the participant at that date.

ONEOK EMPLOYEE STOCK AWARD PROGRAM

Under ONEOK's Employee Stock Award Program, ONEOK issued, for no consideration,
to all eligible employees (all full-time employees and employees on short-term
disability) one share of ONEOK common stock when the closing price on the NYSE
was for the first time at or above each one dollar increment above $26 per
share. The total number of shares of ONEOK common stock available for issuance
under this program is 100,000 shares.

SEVERANCE PLANS

Northern Plains' and NBP Services' Severance Pay Plans provide for the payment
of benefits to employees who are terminated for failing to meet performance
objectives or standards or who are terminated due to reorganization or similar
business circumstances. The amount of benefits payable for performance related
terminations is based on length of service and may not exceed eight weeks' pay.
For those terminated as the result of reorganization or similar business
circumstances, the benefit is based on length of service and amount of pay up to
a maximum payment of 52 weeks of base pay. The employee must sign a Waiver and
Release of Claims Agreement in order to receive any severance benefit.


                                       33

<PAGE>

COMPENSATION OF COMMITTEE MEMBERS

The members of the Management Committee and Audit Committee receive no
management fee or other remuneration for serving on the committee; however, they
are reimbursed for their expenses related to their attendance at committee
meetings. Our partnership agreement provides that we indemnify the members of
our Management Committee against all actions if such actions were in good faith
and within the scope of their authority in the course of our business. It also
provides that such persons will not be liable for any liabilities incurred by us
as a result of such acts.

COMPENSATION COMMITTEE INTERLOCKS AND INSIDER PARTICIPATION

We do not have a Compensation Committee. During 2005, the compensation of our
named executive officers was determined by ONEOK's Compensation Committee
consisting of the following ONEOK Board Members: James C. Day, William L. Ford,
Bert H. Mackie, and Douglas Ann Newsom. No member of ONEOK's Compensation
Committee is, or was formerly, an officer or employee of our operator or any if
its subsidiaries. We reimburse ONEOK for the direct and indirect compensation
costs of our named executive officers.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND
         RELATED STOCKHOLDER MATTERS

The following table sets forth the beneficial ownership of our general
partnership interests as of December 31, 2005. There are no limited partnership
interests.

<TABLE>
<CAPTION>
NAME OF BENEFICIAL OWNER       ADDRESS                        GENERAL PARTNERSHIP INTEREST
------------------------       -------                        ----------------------------
<S>                            <C>                            <C>
Northern Border Intermediate   13710 FNB Parkway                           70%
   Limited Partnership         Omaha, NE 68154-5200
TC PipeLines Intermediate      110 Turnpike Road, Suite 203                30%
   Limited Partnership         Westborough, MA 01581
</TABLE>

Additional information about our general partners and the voting interest of the
Management Committee is included under Item 1, "Business-Partnership Structure."
Information about the agreement between our general partners pursuant to which
Northern Border Partners agreed to sell a 20% partnership interest in us to TC
PipeLines Intermediate is included under Item 1, "Business-General Development
of Business."

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

RELATIONSHIP WITH NORTHERN BORDER PARTNERS

At December 31, 2005, Northern Border Partners owned a 70% partnership interest
in us. The general partners of Northern Border Partners and its subsidiary
limited partnership, Northern Border Intermediate Limited Partnership, are
Northern Plains, Pan Border and Northwest Border. Northern Plains and Pan Border
are subsidiaries of ONEOK. Northwest Border is a subsidiary of TransCanada. In
2005, we paid Northern Border Partners cash distributions of $142.0 million.

RELATIONSHIP WITH TC PIPELINES INTERMEDIATE

At December 31, 2005, TC PipeLines Intermediate owned a 30% partnership interest
in us. TC PipeLines Intermediate is a subsidiary of TC PipeLines, LP. The
general partner of TC PipeLines, LP is TC PipeLines GP, Inc., which is a
subsidiary of TransCanada. In 2005, we paid TC PipeLines Intermediate cash
distributions of $60.9 million.

RELATIONSHIP WITH ONEOK

Transition Services Agreement - Upon the sale of Northern Plains by CCE Holdings
to ONEOK in November 2004, CCE Holdings and ONEOK entered into a transition
services agreement. This transition services agreement provided for the
continuation of certain services, data applications, systems and infrastructure
relied on by Northern Plains in performing under the operating agreement. The
cost of the transition services was $2.3 million for the full term of the
agreement, which expired on May 17, 2005, and was not extended.


                                       34

<PAGE>

Operating Agreement - Northern Plains provides certain administrative, operating
and management services to us through an operating agreement. Northern Plains
has acted and will continue to act as the operator of our pipeline system under
the terms of the operating agreement through April 1, 2007, at which time the
operating services are expected to be transitioned to an affiliate of
TransCanada. We and an affiliate of TC PipeLines Intermediate will enter into a
pipeline operating agreement whereby the TC PipeLines Intermediate affiliate
will provide the services we currently receive from Northern Plains. It is
anticipated that Northern Plains will enter into a transition services agreement
with TransCanada or one of its affiliates, under which Northern Plains will be
reimbursed for all transitional support expenses. Additional information about
the proposed transaction is included under Item 1, "Business-General Development
of Business."

The operator is entitled to reimbursement for all reasonable costs, including
overhead and administrative expenses, incurred by it, ONEOK and its affiliates
in connection with the performance of its responsibilities as operator. Under
our partnership agreement, we also agreed to indemnify the operator against any
claims or liabilities arising out of the operator's good faith performance of
its responsibilities, to the extent we believe the operator is acting within the
scope of its authority and in the course of our business. In 2005, 2004 and
2003, the amount charged by Northern Plains and its affiliates for their
services as operator was $20.1 million, $18.3 million and $25.6 million,
respectively. In 2005 and 2004, $1.9 million and $0.4 million, respectively,
were related to transition services.

Transportation Agreements - ONEOK Energy, a subsidiary of ONEOK, became
affiliated with us in November 2004 in connection with ONEOK's purchase of
Northern Plains. In 2005, 2% of our design capacity was contracted on a firm
basis with ONEOK Energy. Revenue from ONEOK Energy for 2005 was $7.7 million. As
of January 31, 2006, 1% of our design capacity was contracted on a firm basis
with ONEOK Energy for 2006. In addition, ONEOK Energy entered into a precedent
agreement for transportation capacity on our Chicago III Expansion Project for
25 MMcf/d of capacity for five and one-half years.

CONFLICTS OF INTEREST

Our general partners, which are subsidiaries of ONEOK and TransCanada, and their
respective affiliates currently engage or may engage in the businesses in which
we engage or in which we may engage in the future. As a result, conflicts of
interest may arise between our general partners and their affiliates, and us. If
such conflicts arise, the members of the Management Committee generally have a
fiduciary duty to resolve such conflicts in a manner that is in our best
interest.

Unless otherwise provided for in a partnership agreement, the laws of 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 the Management
Committee. Because of the competing interests identified above, our partnership
agreement contains provisions that modify certain of these fiduciary duties. For
example:

     -    Our partnership agreement provides that we indemnify the members of
          our Management Committee and Northern Plains, as the operator, against
          all liabilities and losses arising out of their actions if such
          actions were in good faith and within the scope of their authority in
          the course of our business. It also provides that such persons will
          not be liable for any liabilities incurred by us as a result of such
          acts.

     -    Our partnership agreement states that our general partners will not be
          liable to third persons for our losses, deficits, liabilities or
          obligations (unless our assets have been exhausted). Debt is
          nonrecourse to our general partners.

     -    Our partnership agreement requires that any contract entered into on
          our behalf must contain a provision limiting the claims of persons to
          our assets and expressly waiving any rights of such persons to proceed
          against our general partners individually.

     -    Our partnership agreement relieves Northern Border Partners and TC
          PipeLines Intermediate, their affiliates and their transferees from
          any duty to offer business opportunities to us, except that neither
          our general partners nor their affiliates may pursue any opportunity
          relating to expansion or improvements of our pipeline system as it
          existed on January 15, 1999.


                                       35

<PAGE>

ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

The fees for the years ended December 31, 2005, and 2004 for professional
services provided by KPMG LLP were as follows:

<TABLE>
<CAPTION>
                     FOR THE YEARS ENDED DECEMBER 31,
                     --------------------------------
                             2005       2004
                           --------   --------
<S>                  <C>              <C>
Audit fees                 $339,900   $412,790
Audit-related fees               --         --
Tax fees                         --         --
All other fees                   --         --
                           --------   --------
   Total                   $339,900   $412,790
                           ========   ========
</TABLE>

AUDIT FEES

Audit fees include fees for the audit of annual financial statements, reviews of
the related quarterly financial statements and related consents and comfort
letters for documents filed with the SEC.

Before our independent principal accountant is engaged each year for the annual
audit and other audit and any non-audit services, these services and fees are
reviewed and approved by our Audit Committee and recommended to our Management
Committee for approval.

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(A) (1) AND (2) FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULES

See "Index to Financial Statements" on page F-1.

(A) (3) EXHIBITS

<TABLE>
<S>       <C>
*3.1      Northern Border Pipeline Company General Partnership Agreement between
          Northern Plains Natural Gas Company, Northwest Border Pipeline
          Company, Pan Border Gas Company, TransCanada Border Pipeline Ltd. and
          TransCan Northern Ltd., effective March 9, 1978, as amended
          (incorporated by reference to Exhibit 10.2 to Northern Border
          Partners, L.P.'s Form S-1 Registration Statement filed on July 16,
          1993, (Registration No. 33-66158) ("Form S-1")).

*3.2      Seventh Supplement Amending Northern Border Pipeline Company General
          Partnership Agreement dated September 23, 1993 (incorporated by
          reference to Exhibit 10.15 to Form S-1).

*3.3      Eighth Supplement Amending Northern Border Pipeline Company General
          Partnership Agreement dated May 21, 1999 (incorporated by reference to
          Exhibit 10.15 to the Company's Form S-4 Registration Statement filed
          on October 7, 1999 (Registration No. 333-88577) ("Form S-4").

*3.4      Ninth Supplement Amending Northern Border Pipeline Company General
          Partnership Agreement dated July 16, 2001 (incorporated by reference
          to Exhibit 10.37 to the Company's Registration Statement on Form S-4
          filed on November 13, 2001 (Registration No. 333-73282) ("2001 Form
          S-4").

*3.5      Tenth Supplement Amending Northern Border Pipeline Company General
          Partnership Agreement dated March 3, 2005 (incorporated by reference
          to Exhibit 3.5 to the Company's Form 10-K for the year ended December
          31, 2004 filed on March 14, 2005 (File No. 333-88577)).

*4.1      Indenture, dated as of August 17, 1999, between Northern Border
          Pipeline Company and Bank One Trust Company, NA, successor to The
          First National Bank of Chicago, Trustee (incorporated by reference to
          Exhibit 4.1 to Form S-4).

*4.2      Indenture, dated as of September 17, 2001, between Northern Border
          Pipeline Company and Bank One Trust Company, N.A., Trustee
          (incorporated by reference to Exhibit 4.2 to 2001 Form S-4).

*4.3      Indenture, dated as of April 29, 2002, between Northern Border
          Pipeline Company and Bank One Trust Company, N.A., Trustee
          (incorporated by reference to Exhibit 4.1 to the Company's Form 10-Q
          for the quarter ended March 31, 2002) (Filed No. 333-88577).
</TABLE>


                                       36

<PAGE>

<TABLE>
<S>       <C>
*10.1     Operating Agreement between Northern Border Pipeline Company and
          Northern Plains Natural Gas Company, dated February 28, 1980
          (incorporated by reference to Exhibit 10.3 to Form S-1).

*10.2     Revolving Credit Agreement, dated as of May 16, 2005, among Northern
          Border Pipeline Company, the lenders from time to time party thereto,
          Wachovia Bank, National Association, as administrative agent, SunTrust
          Bank, as syndication agent, Harris Nesbit Financing, Inc., Barclays
          Bank PLC and Citibank, N.A., as co-documentation agents, and Wachovia
          Capital Markets, LLC and SunTrust Capital Markets, Inc., as co-lead
          arrangers and book managers (incorporated by reference to Exhibit 10.1
          to the Company's current report on Form 8-K filed on May 20, 2005
          (File No. 333-88577)).

*10.3     Form of Conveyance, Contribution and Assumption Agreement among
          Northern Plains Natural Gas Company, Northwest Border Pipeline
          Company, Pan Border Gas Company, Northern Border Partners, L.P., and
          Northern Border Intermediate Limited Partnership (incorporated by
          reference to Exhibit 10.16 to Form S-1).

*10.4     Form of Contribution, Conveyance and Assumption Agreement among TC
          PipeLines, LP and certain other parties (incorporated by reference to
          Exhibit 10.2 to Amendment No. 3 to TC PipeLines, LP's Form
          S-1 Registration Statement filed on May 3, 1999, (Registration No.
          333-69947) ("TC Form S-1")).

+*10.5    Form of Termination Agreement with ONEOK dated as of January 5, 2005
          (incorporated by reference to Exhibit 99.1 to Northern Border
          Partners, L.P.'s current report on Form 8-K filed on January 11, 2005
          (File No. 1-12201)).

+*10.6    ONEOK, Inc. 2005 Supplemental Executive Retirement Plan. (incorporated
          by reference to Exhibit 99.2 to Northern Border Partners, L.P.'s
          current report on Form 8-K filed on January 11, 2005 (File No.
          1-12201)).

+*10.7    ONEOK, Inc. Long-Term Incentive Plan (incorporated by reference to
          Exhibit 10(a) to ONEOK's Form 10-K for the year ended December 31,
          2001 (File No. 1-13643)).

+*10.8    ONEOK, Inc. Form of Restricted Stock Incentive Award (incorporated by
          reference to Exhibit 10.4 to ONEOK's Form 10-Q for the quarter ended
          September 30, 2004 (File No. 1-13643)).

+*10.9    ONEOK, Inc. Form of Performance Shares Award (incorporated by
          reference to Exhibit 10.5 to ONEOK's Form 10-Q for the quarterly
          period ended September 30, 2004 (File No. 1-13643)).

+*10.10   ONEOK, Inc. Employee Non-Qualified Deferred Compensation Plan, as
          amended, dated February 10, 2001 (incorporated by reference to Exhibit
          10(g) to ONEOK's Form 10-K for the year ended December 31, 2001 (File
          No. 1-13643)).

+*10.11   ONEOK, Inc. Annual Officer Incentive Plan (incorporated by reference
          to Exhibit 10(f) to ONEOK's Form 10-K for the year ended December 31,
          2001 (File No. 1-13643)).

+*10.12   ONEOK, Inc. Equity Compensation Plan (incorporated by reference to
          Exhibit 10.1 to ONEOK's current report on Form 8-K filed on February
          23, 2005 (File No. 1-13643)).

+*10.13   ONEOK, Inc. Employee Stock Purchase Plan, as amended February 17, 2005
          (incorporated by reference to Exhibit 10.2 to ONEOK's current report
          on Form 8-K filed on February 23, 2005 (File No. 1-13643)).

+*10.14   ONEOK, Inc. Form of Restricted Unit Award Agreement (incorporated by
          reference to Exhibit 10.21 to Northern Border Partners, L.P.'s Form
          10-K for the year ended December 31, 2005 (File No. 1-12201) ("NBP
          2005 Form 10-K")).

+*10.15   ONEOK, Inc. Form of Performance Unit Award Agreement (incorporated by
          reference to Exhibit 10.22 to the NBP 2005 Form 10-K).

*10.16    Northern Border Pipeline Company Agreement among Northern Plains
          Natural Gas Company, Pan Border Gas Company, Northwest Border Pipeline
          Company, TransCanada Border PipeLine Ltd., TransCan Northern Ltd.,
          Northern Border Intermediate Limited Partnership, Northern Border
          Partners, L.P., and the Management Committee of Northern Border
          Pipeline, dated as of March 17, 1999 (incorporated by reference to
          Exhibit 10.21 to Northern Border Partners, L.P.'s Form 10-K/A for the
          year ended December 31, 1998 (File No. 1-12202)).

12.1      Statement recomputation of ratios.

31.1      Rule 13a-14(a)/15d-14(a) Certification of principal executive officer.

31.2      Rule 13a-14(a)/15d-14(a) Certification of principal financial officer.

32.1      Section 1350 Certification of principal executive officer.

32.2      Section 1350 Certification of principal financial officer.

+*99.1    Northern Border Phantom Unit Plan ( incorporated by reference to
          Exhibit 99.1 to Amendment No. 1 to Northern Border Partners, L.P.'s
          Form S-8, Registration No. 333-66949 and Exhibit 99.1 to Northern
          Border Partners, L.P.'s Registration No. 333-72696).
</TABLE>


                                       37

<PAGE>

<TABLE>
<S>       <C>
#*99.2    Partnership Interest Purchase and Sale Agreement by and between
          Northern Border Intermediate Limited Partnership and TC PipeLines
          Intermediate Limited Partnership dated as of December 31, 2005 (PIPA)
          (incorporated by reference to Exhibit 2.3 to the NBP 2005 Form 10-K).
</TABLE>

*    Indicates exhibits incorporated by reference as indicated; all other
     exhibits are filed herewith.

+    Management contract, compensatory plan or arrangement.

#    The Company agrees to furnish supplementally to the Securities and Exchange
     Commission, upon request, any schedules and exhibits to this agreement, as
     set forth in the Table of Contents of the agreement, that have not been
     filed herewith pursuant to Item 601(b)(2) of Regulation S-K.


                                       38

<PAGE>

                                   SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange
Act of 1934, the registrant has duly caused this report to be signed on its
behalf by the undersigned, thereunto duly authorized on this 6th day of March,
2006.

                                        NORTHERN BORDER PIPELINE COMPANY
                                        (A Texas General partnership)

                                        By: Northern Plains Natural Gas Company,
                                            as Operator


                                        By: /s/ Jerry L. Peters
                                            ------------------------------------
                                            Jerry L. Peters
                                            Vice President,
                                            Finance and Treasurer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report
has been signed below by the following persons in the capacities and on the
dates indicated.

<TABLE>
<CAPTION>
SIGNATURE                   TITLE                                                       DATE
---------                   -----                                                       ----
<S>                         <C>                                                    <C>


/s/ William R. Cordes       President, Northern Plains Natural Gas Company         March 6, 2006
-------------------------   (functional equivalent to the registrant's principal
William R. Cordes           executive officer) and Management Committee Member


/s/ Jerry L. Peters         Vice President, Finance and Treasurer,                 March 6, 2006
-------------------------   Northern Plains Natural Gas Company (functional
Jerry L. Peters             equivalent to the registrant's principal financial
                            and accounting officer)


/s/ David L. Kyle           Management Committee Member                            March 6, 2006
-------------------------
David L. Kyle


/s/ Max Feldman             Management Committee Member                            March 6, 2006
-------------------------
Max Feldman


/s/ Paul E. Miller          Management Committee Member                            March 6, 2006
-------------------------
Paul E. Miller
</TABLE>


                                       39

<PAGE>

SUPPLEMENTAL INFORMATION TO BE FURNISHED WITH REPORTS FILED PURSUANT TO SECTION
15(D) OF THE ACT BY REGISTRANTS WHICH HAVE NOT REGISTERED SECURITIES PURSUANT TO
SECTION 12 OF THE ACT

No annual report to security holders covering our last fiscal year has been sent
to our security holders and no proxy statement, form of proxy or other proxy
soliciting material has been sent to more than ten of our security holder's with
respect to any annual or other meeting of security holders. No such report or
proxy material is expected to be furnished to security holders subsequent to the
filing of this annual report on Form 10-K.


                                       40

<PAGE>

                        NORTHERN BORDER PIPELINE COMPANY
                           ANNUAL REPORT ON FORM 10-K

                          INDEX TO FINANCIAL STATEMENTS

<TABLE>
<CAPTION>
                                                                       Page No.
                                                                       ---------
<S>                                                                  <C>
Financial Statements

   Report of Independent Registered Public Accounting Firm........           F-2
   Balance Sheet - December 31, 2005, and 2004....................           F-3
   Statement of Income - Years Ended December 31, 2005, 2004 and
      2003........................................................           F-4
   Statement of Comprehensive Income - Years Ended
      December 31, 2005, 2004 and 2003............................           F-4
   Statement of Cash Flows - Years Ended December 31, 2005, 2004
      and 2003....................................................           F-5
   Statement of Changes in Partners' Equity - Years Ended
      December 31, 2005, 2004 and 2003............................           F-6
   Notes to Financial Statements..................................   F-7 to F-16

Financial Statements Schedule

   Report of Independent Registered Public Accounting Firm on
      Schedule....................................................           S-1
   Schedule II - Valuation and Qualifying Accounts................           S-2
</TABLE>


                                      F-1

<PAGE>

             REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Northern Border Pipeline Company:

We have audited the accompanying balance sheets of Northern Border Pipeline
Company (the Company) as of December 31, 2005 and 2004, and the related
statements of income, comprehensive income, cash flows, and changes in partners'
equity for each of the years in the three-year period ended December 31, 2005.
These financial statements are the responsibility of the Company's management.
Our responsibility is to express an opinion on these financial statements based
on our audits.

We conducted our audits in accordance with generally accepted auditing standards
as established by the Auditing Standards Board (United States) and in accordance
with the auditing standards of the Public Company Accounting Oversight Board
(United States). Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether the financial statements are free of
material misstatement. The Company is not required to have, nor were we engaged
to perform, an audit of its internal control over financial reporting. Our audit
included consideration of internal control over financial reporting as a basis
for designing audit procedures that are appropriate in the circumstances, but
not for the purpose of expressing an opinion of the effectiveness of the
Company's internal control over financial reporting. Accordingly, we express no
such opinion. An audit also includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements, assessing
the accounting principles used and significant estimates made by management, as
well as evaluating the overall financial statement presentation. We believe that
our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in
all material respects, the financial position of Northern Border Pipeline
Company as of December 31, 2005 and 2004, and the results of its operations and
its cash flows for each of the years in the three-year period ended December 31,
2005, in conformity with U.S. generally accepted accounting principles.


/s/ KPMG LLP

Omaha, Nebraska
March 2, 2006


                                      F-2

<PAGE>

NORTHERN BORDER PIPELINE COMPANY
BALANCE SHEET

<TABLE>
<CAPTION>
                                                               DECEMBER 31,
                                                         -----------------------
                                                            2005         2004
                                                         ----------   ----------
                                                              (In thousands)
<S>                                                      <C>          <C>
ASSETS
Current assets:
   Cash and cash equivalents                             $   22,039   $   20,355
   Accounts receivable, net of allowance for doubtful
      accounts of $4,208 in 2004                             38,252       32,559
   Related party receivables                                  2,294        1,311
   Materials and supplies, at cost                            3,566        3,409
   Prepaid expenses and other                                 1,540        1,688
                                                         ----------   ----------
      Total current assets                                   67,691       59,322
                                                         ----------   ----------
Property, plant and equipment:
   In service natural gas transmission plant              2,463,555    2,446,369
   Construction work in progress                             13,260        2,768
                                                         ----------   ----------
   Total property, plant and equipment                    2,476,815    2,449,137
   Less: Accumulated provision for depreciation and
      amortization                                          960,740      903,664
                                                         ----------   ----------
      Property, plant and equipment, net                  1,516,075    1,545,473
                                                         ----------   ----------
Other assets:
   Unamortized debt expense                                   3,434        3,837
   Regulatory assets                                         13,853       11,807
   Other                                                      3,645        4,549
                                                         ----------   ----------
     Total other assets                                      20,932       20,193
                                                         ----------   ----------
         Total assets                                    $1,604,698   $1,624,988
                                                         ==========   ==========
LIABILITIES AND PARTNERS' EQUITY
Current liabilities:
   Accounts payable                                      $   10,550   $    4,058
   Related party payables                                     3,555        5,286
   Accrued taxes other than income                           27,637       27,113
   Accrued interest                                          11,525       11,365
   Other                                                      2,755        1,640
                                                         ----------   ----------
      Total current liabilities                              56,022       49,462
                                                         ----------   ----------
Long-term debt                                              628,916      603,860
                                                         ----------   ----------
Reserves and deferred credits                                 4,775        4,526
                                                         ----------   ----------
Commitments and contingencies (Note 8)
Partners' equity:
   Partners' capital                                        912,723      963,378
   Accumulated other comprehensive income                     2,262        3,762
                                                         ----------   ----------
      Total partners' equity                                914,985      967,140
                                                         ----------   ----------
         Total liabilities and partners' equity          $1,604,698   $1,624,988
                                                         ==========   ==========
</TABLE>

   The accompanying notes are an integral part of these financial statements.


                                      F-3

<PAGE>

NORTHERN BORDER PIPELINE COMPANY
STATEMENT OF INCOME

<TABLE>
<CAPTION>
                                                              YEARS ENDED DECEMBER 31,
                                                           ------------------------------
                                                             2005       2004       2003
                                                           --------   --------   --------
                                                                   (In thousands)

<S>                                                        <C>        <C>        <C>
Operating revenue                                          $321,651   $329,115   $324,185
                                                           --------   --------   --------
Operating expenses
   Operations and maintenance                                39,506     33,763     43,791
   Depreciation and amortization                             58,052     58,375     57,779
   Taxes other than income                                   31,345     29,368     29,634
                                                           --------   --------   --------
      Operating expenses                                    128,903    121,506    131,204
                                                           --------   --------   --------
Operating income                                            192,748    207,609    192,981
                                                           --------   --------   --------
Interest expense
   Interest expense                                          42,792     41,374     44,903
   Interest expense capitalized                                (157)       (18)       (46)
                                                           --------   --------   --------
      Interest expense, net                                  42,635     41,356     44,857
                                                           --------   --------   --------
Other income (expense)
   Allowance for equity funds used during construction          269         31         53
   Other income                                               2,396      2,552      1,373
   Other expense                                               (532)    (2,059)    (1,350)
                                                           --------   --------   --------
      Other income, net                                       2,133        524         76
                                                           --------   --------   --------
Net income to partners                                     $152,246   $166,777   $148,200
                                                           ========   ========   ========
</TABLE>

NORTHERN BORDER PIPELINE COMPANY
STATEMENT OF COMPREHENSIVE INCOME

<TABLE>
<CAPTION>
                                                                    YEARS ENDED DECEMBER 31,
                                                                 -----------------------------
                                                                   2005       2004      2003
                                                                 --------   --------  --------
                                                                         (In thousands)
<S>                                                              <C>        <C>       <C>
Net income to partners
Other comprehensive income:                                      $152,246   $166,777  $148,200
   Changes associated with current period hedging transactions     (1,500)    (1,440)   (1,556)
                                                                 --------   --------  --------
Total comprehensive income                                       $150,746   $165,337  $146,644
                                                                 ========   ========  ========
</TABLE>

   The accompanying notes are an integral part of these financial statements.


                                      F-4

<PAGE>

NORTHERN BORDER PIPELINE COMPANY
STATEMENT OF CASH FLOWS

<TABLE>
<CAPTION>
                                                           YEARS ENDED DECEMBER 31,
                                                      ---------------------------------
                                                         2005        2004        2003
                                                      ---------   ---------   ---------
                                                                (In thousands)
<S>                                                   <C>         <C>         <C>
CASH FLOW FROM OPERATING ACTIVITIES
   Net income to partners                             $ 152,246   $ 166,777   $ 148,200
                                                      ---------   ---------   ---------
   Adjustments to reconcile net income to partners
      to net cash provided by operating activities:
      Depreciation and amortization                      58,404      58,740      58,144
      Provisions for regulatory refunds                      --          --         261
      Regulatory refunds paid                                --          --     (10,261)
      Allowance for equity funds used during
      construction                                         (269)        (31)        (53)
      Reserves and deferred credits                        (665)       (546)      1,001
      Changes in components of working capital             (127)    (12,611)     (3,551)
      Other                                              (3,128)     (6,180)       (471)
                                                      ---------   ---------   ---------
         Total adjustments                               54,215      39,372      45,070
                                                      ---------   ---------   ---------
      Net cash provided by operating activities         206,461     206,149     193,270
                                                      ---------   ---------   ---------
CASH FLOW FROM INVESTING ACTIVITIES
   Capital expenditures for property, plant and
      equipment, net                                    (28,555)    (10,569)    (12,918)
                                                      ---------   ---------   ---------
CASH FLOW FROM FINANCING ACTIVITIES
   Equity contributions from partners                        --     205,000          --
   Distributions to partners                           (202,901)   (205,635)   (153,978)
   Issuance of long-term debt                           136,000     107,000     142,000
   Retirement of long-term debt                        (109,000)   (313,000)   (165,000)
   Proceeds upon termination of derivatives                  --       7,575          --
   Debt reacquisition costs                                  --      (4,897)         --
   Long-term debt financing costs                          (321)         --          --
                                                      ---------   ---------   ---------
      Net cash used in financing activities            (176,222)   (203,957)   (176,978)
                                                      ---------   ---------   ---------
Net change in cash and cash equivalents                   1,684      (8,377)      3,374
Cash and cash equivalents at beginning of year           20,355      28,732      25,358
                                                      ---------   ---------   ---------
Cash and cash equivalents at end of year              $  22,039   $  20,355   $  28,732
                                                      =========   =========   =========
Changes in components of working capital:
   Accounts receivable                                $  (6,677)  $  (2.969)  $  (4,908)
   Materials and supplies                                  (157)        697         (97)
   Prepaid expenses and other                               149         578        (422)
   Accounts payable and other current liabilities         5,874      (9,731)      3,758
   Accrued taxes other than income                          524      (1,834)        573
   Accrued interest                                         160         648      (2,455)
                                                      ---------   ---------   ---------
      Total                                           $    (127)  $ (12,611)  $  (3,551)
                                                      =========   =========   =========
</TABLE>

   The accompanying notes are an integral part of these financial statements.


                                       F-5

<PAGE>

NORTHERN BORDER PIPELINE COMPANY
STATEMENT OF CHANGES IN PARTNERS' EQUITY

<TABLE>
<CAPTION>
                                                             NORTHERN
                                            TC PIPELINES      BORDER       ACCUMULATED
                                            INTERMEDIATE   INTERMEDIATE       OTHER         TOTAL
                                               LIMITED        LIMITED     COMPREHENSIVE   PARTNERS'
                                             PARTNERSHIP    PARTNERSHIP       INCOME        EQUITY
                                            ------------   ------------   -------------   ---------
                                                                 (In thousands)
<S>                                         <C>            <C>            <C>             <C>
Partners' equity at December 31, 2002         $ 240,904      $ 562,110       $ 6,758      $ 809,772
   Net income to partners                        44,460        103,740            --        148,200
   Changes associated with current period
      hedging transactions                           --             --        (1,556)        (1,556)
   Distributions paid                           (46,193)      (107,785)           --       (153,978)
                                              ---------      ---------       -------      ---------
Partners' equity at December 31, 2003           239,171        558,065         5,202        802,438
   Net income to partners                        50,033        116,744            --        166,777
   Changes associated with current period
      hedging transactions                           --             --        (1,440)        (1,440)
   Equity contributions received                 61,500        143,500            --        205,000
   Distributions paid                           (61,690)      (143,945)           --       (205,635)
                                              ---------      ---------       -------      ---------
Partners' equity at December 31, 2004           289,014        674,364         3,762        967,140
   Net income to partners                        45,674        106,572            --        152,246
   Changes associated with current period
      hedging transactions                           --             --        (1,500)        (1,500)
   Distributions paid                           (60,870)      (142,031)           --       (202,901)
                                              ---------      ---------       -------      ---------
Partners' equity at December 31, 2005         $ 273,818      $ 638,905       $ 2,262      $ 914,985
                                              =========      =========       =======      =========
</TABLE>

   The accompanying notes are an integral part of these financial statements.


                                       F-6

<PAGE>

NORTHERN BORDER PIPELINE COMPANY
NOTES TO FINANCIAL STATEMENTS

1.   ORGANIZATION AND MANAGEMENT

In this report, references to "we, "us" or "our" collectively refer to Northern
Border Pipeline Company.

We are a Texas general partnership formed in 1978. The ownership percentages of
our partners at December 31, 2005 and 2004 are as follows:

<TABLE>
<CAPTION>
PARTNER                                               OWNERSHIP PERCENTAGE
-------                                               --------------------
<S>                                                   <C>
Northern Border Intermediate Limited Partnership...            70%
TC PipeLines Intermediate Limited Partnership......            30%
</TABLE>

We own a 1,249-mile natural gas transmission pipeline system extending from the
United States-Canadian border near Port of Morgan, Montana, to a terminus near
North Hayden, Indiana.

We are managed by a Management Committee that includes three representatives
from Northern Border Intermediate Limited Partnership (Northern Border ILP) and
one representative from TC PipeLines Intermediate Limited Partnership (TC
PipeLines). Northern Border ILP's representatives are selected by its general
partners, Northern Plains Natural Gas Company, LLC (Northern Plains), a
wholly-owned subsidiary of ONEOK, Inc. (ONEOK), Pan Border Gas Company, LLC (Pan
Border), a wholly-owned subsidiary of Northern Plains, and Northwest Border
Pipeline Company (Northwest Border), a wholly-owned subsidiary of TransCanada
PipeLines Limited, which is a subsidiary of TransCanada Corporation
(TransCanada), an affiliate of TC PipeLines, and have 35%, 22.75% and 12.25%,
respectively, of the voting interest on the Management Committee. The
representative designated by TC PipeLines votes the remaining 30% interest.

In November 2004, ONEOK purchased Northern Plains and Pan Border from CCE
Holdings, LLC (CCE Holdings). CCE Holdings, a joint venture between Southern
Union Company and GE Commercial Finance Energy Financial, purchased Northern
Plains and Pan Border as part of its acquisition of CrossCountry Energy, LLC
(CrossCountry) from Enron Corp.

On March 31, 2004, Enron Corp. (Enron) transferred its ownership interest in
Northern Plains and Pan Border to CrossCountry. In addition, CrossCountry and
Enron entered into a transition services agreement pursuant to which Enron would
provide to CrossCountry, on an interim, transitional basis, various services,
including but not limited to (i) information technology services, (ii)
accounting system usage rights and administrative support and (iii) payroll,
employee benefits and administrative services. In turn, these services are
provided to us through Northern Plains.

The day-to-day management of our affairs is the responsibility of Northern
Plains, as defined by an operating agreement between us and Northern Plains. We
are charged for the salaries, benefits and expenses of Northern Plains. As part
of the closing, ONEOK and CCE Holdings entered into a transition services
agreement referred to as the "Northern Border Transition Services Agreement"
covering certain transition services by and among ONEOK, CCE Holdings and Enron
for a period of six months. Certain of the services previously provided by Enron
are now being provided by ONEOK. For the years ended December 31, 2005, 2004,
and 2003, our charges from Northern Plains and its affiliates totaled
approximately $20.1 million, $18.3 million and $25.6 million, respectively. See
Note 12 for a discussion of our previous relationships with Enron and
developments involving Enron.

2.   SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

USE OF ESTIMATES

The preparation of financial statements in conformity with U.S. generally
accepted accounting principles requires management to make assumptions and use
estimates that affect the reported amounts of assets,


                                       F-7

<PAGE>

liabilities, revenue and expenses as well as the disclosure of contingent assets
and liabilities during the reporting period. Actual results could differ from
these estimates if the underlying assumptions are incorrect.

GOVERNMENT REGULATION

We are subject to regulation by the Federal Energy Regulatory Commission (FERC).
Our accounting policies conform to Statement of Financial Accounting Standards
(SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation."
Accordingly, certain assets that result from the regulated ratemaking process
are reflected on the balance sheet as regulatory assets.

At December 31, 2005 and 2004, we have reflected regulatory assets, which are
currently being recovered or are expected to be recovered from our shippers, of
approximately $13.9 million and $11.8 million, respectively, on the balance
sheet. We are recovering these regulatory assets from our shippers over varying
time periods up to 44 years.

The following table presents a summary of regulatory assets, net of
amortization, at December 31, 2005, and 2004.

<TABLE>
<CAPTION>
                                         DECEMBER 31,
                                      -----------------
                                        2005      2004
                                      -------   -------
                                        (In thousands)
<S>                                   <C>       <C>
Fort Peck lease option                $ 4,402   $ 1,887
Unamortized loss on reacquired debt     1,503     2,630
Pipeline extension project              7,106     7,290
Other                                     842        --
                                      -------   -------
   Total regulatory assets            $13,853   $11,807
                                      =======   =======
</TABLE>

We continually assess the potential recovery of our regulatory assts based on
such factors as regulatory changes and the impact of competition to determine
the probability of future recovery of these assets. We believe the recovery of
the existing regulatory assets is probable. If we determine future recovery is
no longer probable, we would be required to write off the regulatory assets at
that time.

REVENUE RECOGNITION

We transport gas for shippers under a tariff regulated by the FERC. The tariff
specifies the calculation of amounts to be paid by shippers and the general
terms and conditions of transportation service on our pipeline system. We
recognize revenue according to each transportation contract for transportation
service that is provided to our customers. Customers with firm service
transportation agreements pay a reservation fee for capacity on the pipeline
system known as a demand charge regardless of whether the shipper actually
utilizes its reserved capacity. Firm service transportation customers also pay a
fee based on the volume of natural gas transported. Customers with interruptible
service transportation agreements may utilize available capacity on our pipeline
system; however, service is subject to interruption if capacity is required for
customers with firm service transportation agreements. Interruptible service
customers are assessed a fee based only on the volume of natural gas
transported. An allowance for doubtful accounts is recorded in situations where
collectibility is not reasonably assured. We do not own the gas that we
transport, and therefore we do not assume the related natural gas commodity
risk.

INCOME TAXES

Income taxes are the responsibility of our partners and are not reflected in
these financial statements. However, our FERC tariff establishes the method of
accounting for and calculating income taxes and requires us to reflect in our
rates the income taxes which would have been paid or accrued if we were
organized during the period as a corporation. As a result, for purposes of
determining transportation rates in calculating the return allowed by the FERC,
Partners' capital and rate base are reduced by the amount equivalent to the net
accumulated deferred income taxes. Such amounts were approximately $360 million
and $355 million at December 31, 2005, and 2004, respectively, and are primarily
related to accelerated depreciation and other plant-related differences.


                                      F-8

<PAGE>

CASH AND CASH EQUIVALENTS

Cash equivalents consist of highly liquid investments with original maturities
of three months or less. The carrying amount of cash and cash equivalents
approximates fair value due to the short maturity of these investments.

PROPERTY, PLANT AND EQUIPMENT AND RELATED DEPRECIATION AND AMORTIZATION

Property, plant and equipment is stated at original cost. During periods of
construction, we are permitted to capitalize an allowance for funds used during
construction, which represents the estimated costs of funds used for
construction purposes. The original cost of property retired is charged to
accumulated depreciation and amortization, net of salvage and cost of removal.
No retirement gain or loss is included in income except in the case of
retirements or sales of entire regulated operating units.

Maintenance and repairs are charged to operations in the period incurred. The
provision for depreciation and amortization of the transmission line is an
integral part of our FERC tariff. The effective depreciation rate applied to our
transmission plant is 2.25%. Composite rates are applied to all other functional
groups of property having similar economic characteristics.

NATURAL GAS IMBALANCES

Natural gas imbalances occur when the actual amount of natural gas delivered
from or received by a pipeline system or storage facility differs from the
contractual amount of natural gas to be delivered or received. We value these
imbalances due to or from shippers and operators at an appropriate index price.
Imbalances are made up in-kind, subject to the terms of our tariff.

Imbalances due from others are reported on the balance sheet as accounts
receivable. Imbalances owed to others are reported on the balance sheet as
accounts payable. In addition, all imbalances are classified as current.

RISK MANAGEMENT

We use financial instruments in the management of our interest rate exposure. A
control environment has been established which includes policies and procedures
for risk assessment and the approval, reporting and monitoring of financial
instrument activities. We do not use these instruments for trading purposes.
SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities," as
amended by SFAS No. 137 and SFAS No. 138, requires that all derivative
instruments (including certain derivative instruments embedded in other
contracts) be recorded on the balance sheet as either an asset or liability
measured at their fair value. We determine the fair value of a derivative
instrument by the present value of its future cash flows based on market prices
from third party sources. We record changes in the derivative's fair value
currently in earnings unless specific hedge accounting criteria are met.
Accounting for qualifying hedges allows a derivative's gains and losses to
offset related results on the hedged item in the income statement, and requires
us to formally document, designate and assess the effectiveness of transactions
that receive hedge accounting. See Note 7 for a discussion of our derivative
instruments and hedging activities.

UNAMORTIZED DEBT PREMIUM, DISCOUNT AND EXPENSE

We amortize premiums, discounts and expenses incurred in connection with the
issuance of long-term debt consistent with the terms of the respective debt
instrument.

OPERATING LEASES

We have non-cancelable operating leases for office space and rights-of-way. We
record rent expense over the lease term as it becomes payable. If operating
leases include escalating rental payments, we determine the cumulative rental
payments anticipated and recognize rent expense on a straight-line basis over
the term of the lease.

IMPAIRMENT OF LONG-LIVED ASSETS

We assess our long-lived assets for impairment based on SFAS No. 144,
"Accounting for the Impairment or Disposal of Long-Lived Assets." A long-lived
asset is tested for impairment whenever events or changes in circumstances
indicate that its carrying amount may exceed its fair value. Fair values are
based on the sum of the undiscounted future cash flows expected to result from
the use and eventual disposition of the assets.


                                      F-9

<PAGE>

CONTINGENCIES

Our accounting for contingencies covers a variety of business activities
including contingencies for legal exposures and environmental exposures. We
accrue these contingencies when our assessments indicate that it is probable
that a liability has been incurred or an asset will not be recovered and an
amount can be reasonably estimated in accordance with SFAS No. 5, "Accounting
for Contingencies." We base our estimates on currently available facts and our
estimates of the ultimate outcome or resolution. Actual results may differ from
our estimates resulting in an impact, positive or negative, on earnings.

RECLASSIFICATIONS

Certain reclassifications have been made to the financial statements for prior
years to conform to the current year presentation.

3.   ASSET RETIREMENT OBLIGATIONS

Effective January 1, 2003, we adopted SFAS No. 143, "Accounting for Asset
Retirement Obligations." SFAS No. 143 requires entities to record the fair value
of a liability for an asset retirement obligation during the period in which the
liability is incurred, if a reasonable estimate of fair value can be made.
Effective December 31, 2005, we adopted FASB Interpretation (FIN) 47,
"Accounting for Conditional Asset Retirement Obligations - an
interpretation of SFAS No. 143." FIN 47 clarifies the term
"conditional asset retirement obligation," as used in SFAS No. 143 and
the circumstances under which an entity would have sufficient information to
reasonably estimate the fair value of an asset retirement obligation. We have
determined that asset retirement obligations exist for certain of our
transmission assets; however, the fair value of the obligations cannot be
determined because the end of the transmission system life is not determinable
with the degree of accuracy necessary to currently establish a liability for the
obligations.

4.   RATES AND REGULATORY ISSUES

The FERC regulates the rates and charges for transportation in interstate
commerce. Natural gas companies may not charge rates that have been determined
to be unjust and unreasonable by the FERC. Generally, rates for interstate
pipelines are based on the cost of service including recovery of and a return on
the pipeline's actual prudent historical cost investment. The rates and terms
and conditions for service are found in each pipeline's FERC-approved tariff.
Under its tariff, an interstate pipeline is allowed to charge for its services
on the basis of stated transportation rates. Transportation rates are
established periodically in FERC proceedings known as rate cases. The tariff
also allows the interstate pipeline to provide services under negotiated and
discounted rates.

As required by the provisions of the settlement of our last rate case, on
November 1, 2005, we filed a rate case with the FERC. The rate case filing
proposes, among other things, a 7.8% increase in our revenue requirement; a
change to our rate design approach with a supply zone and market area utilizing
a fixed rate and a dekatherm-mile rate, respectively; a compressor usage
surcharge primarily to recover costs and implementation of a short-term,
firm-service rate structure on a prospective basis. Also included in the filing
is the continuation of the inclusion of income taxes in the calculation of our
rates.

In December 2005, the FERC issued an order that identified issues that were
raised in the proceeding, accepted the proposed rates but suspended their
effectiveness until May 1, 2006, at which time the new rates will be collected
subject to refund until final resolution of the rate case. The FERC also issued
a procedural schedule which set a hearing commencement date of October 4, 2006,
with an initial decision scheduled for February 2007, unless a settlement of the
issues is reached with the FERC and a majority of our customers.

In February 2003, we filed to amend our FERC tariff to clarify the definition of
company use gas, which is gas supplied by our shippers for our operations. We
have included in our retention of company use gas, quantities that were
equivalent to the cost of electric power at our electric-driven compressor
stations during the period of June 2001 through January 2003. On March 27, 2003,
the FERC issued an order rejecting our proposed tariff sheet revision and
requiring refunds with interest within 90 days of the order. We made refunds to
our shippers of $10.3 million in May 2003.


                                      F-10

<PAGE>

5.   TRANSPORTATION SERVICE AGREEMENTS

Operating revenues are collected pursuant to the FERC tariff through firm
transportation service agreements. The firm service agreements extend for
various terms with termination dates that range from December 2005 to December
2013. We also have interruptible transportation service agreements and other
transportation service agreements with numerous shippers. Under the capacity
release provisions of our FERC tariff, shippers are allowed to release all or
part of their capacity either permanently for the full term of the contract or
temporarily. A temporary capacity release does not relieve the original contract
shipper from its payment obligations if the replacement shipper fails to pay for
the capacity temporarily released to it.

At December 31, 2005, our largest shippers, BP Canada Energy Marketing Corp. (BP
Canada) and Nexen Marketing, U.S.A. Inc. (Nexen), were obligated for
approximately 20% and 12% of design capacity, respectively. The BP Canada and
Nexen firm service agreements extend for various terms with termination dates
from March 2006 to February 2012 and December 2005 to December 2013,
respectively.

For the year ended December 31, 2005, shippers providing significant operating
revenues were BP Canada, Nexen, EnCana Marketing (USA) Inc. (EnCana) and Cargill
Inc. (Cargill) with revenues of $56.1 million, $38.1 million, $37.9 million and
$34.1 million, respectively. For the year ended December 31, 2004, shippers
providing significant operating revenues were BP Canada and EnCana with revenues
of $65.6 million and $56.3 million, respectively. For the year ended December
31, 2003, our significant shippers were BP Canada, EnCana, and Pan-Alberta Gas
(U.S.) Inc. with operating revenues of $54.7 million, $32.9 million and $45.5
million, respectively.

At December 31, 2005 and 2004, we had contracted firm capacity held by one
shipper affiliated with one of our general partners. ONEOK Energy Services
Company LP (ONEOK Energy Services), a subsidiary of ONEOK, holds firm service
agreements representing approximately 3% of design capacity at December 31,
2005. The firm service agreements with ONEOK Energy Services extend for various
terms with termination dates that range from February 2006 to March 2009. ONEOK
Energy Services became affiliated with us on November 17, 2004, in connection
with ONEOK'S purchase of Northern Plains. Revenue from ONEOK Energy Services for
2005 and the period from the date of affiliation to December 31, 2004, was $7.7
million and $1.1 million, respectively. At December 31, 2005, and 2004, we had
outstanding receivables from ONEOK Energy Services of $0.9 million and $0.8
million, respectively. In 2003, there was no operating revenue from affiliates.

6.   CREDIT FACILITIES AND LONG-TERM DEBT

Detailed information on long-term debt is as follows:

<TABLE>
<CAPTION>
                                                     DECEMBER 31,
                                                 -------------------
                                                   2005       2004
                                                 --------   --------
                                                    (In thousands)
<S>                                              <C>        <C>
2005 Pipeline Credit Agreement - average 5.11%
   at December 31, 2005, due 2010                $ 27,000   $     --
1999 Pipeline Senior Notes - 7.75%, due 2009      200,000    200,000
2001 Pipeline Senior Notes - 7.50%, due 2021      250,000    250,000
2002 Pipeline Senior Notes - 6.25%, due 2007      150,000    150,000
Unamortized debt premium                            1,916      3,860
                                                 --------   --------
   Long-term debt                                $628,916   $603,860
                                                 ========   ========
</TABLE>

We have entered into revolving credit facilities that are used for capital
expenditures, acquisitions and general business purposes and for refinancing
existing indebtedness. We entered into a $175 million five-year credit


                                      F-11

<PAGE>

agreement (2005 Pipeline Credit Agreement) with certain financial institutions
in May 2005. At our option, the interest rate on the outstanding borrowings may
be the lender's base rate or the London Interbank Offered Rate (LIBOR) plus a
spread that is based on our long-term unsecured debt ratings. The 2005 Pipeline
Credit Agreement permits us to specify the portion of the borrowings to be
covered by specific interest rate options and to specify the interest rate
period. We are required to pay a fee on the principal commitment amount of $175
million.

On December 1, 2004, we redeemed $75 million of the 6.25% Senior Notes due 2007
(2002 Pipeline Senior Notes). In connection with the redemption, we were
required to pay a premium of $4.8 million, incurred a $0.4 million loss related
to the unamortized debt costs and discount associated with the debt and received
$2.5 million from the termination of interest rate swaps associated with the
debt (see Note 7). The net loss of $2.7 million from the redemption is recorded
as a loss on reacquired debt and amortized to interest expense over the
remaining life of the 2002 Pipeline Senior Notes. During the years ended
December 31, 2005, and 2004, we amortized approximately $1.1 million and $0.1
million, respectively, to interest expense. At December 31, 2005, and 2004, the
net unamortized loss on reacquired debt was $1.5 million and $2.6 million,
respectively, which is recorded in regulatory assets on the balance sheet.

Interest paid, net of amounts capitalized, during the years ended December 31,
2005, 2004 and 2003 was $44.1 million, $41.1 million and $47.8 million,
respectively.

Aggregate required repayments of long-term debt for the next five years are $150
million in 2007, $200 million in 2009 and $27 million in 2010. Aggregate
required repayments of long-term debt thereafter total $250 million. There are
no required repayment obligations for 2006 or 2008.

Certain of our long-term debt and credit arrangements contain requirements as to
the maintenance of minimum partners' capital and debt to capitalization ratios,
leverage ratios and interest coverage ratios that restrict the incurrence of
other indebtedness by us and also place certain restrictions on distributions to
our partners. The 2005 Pipeline Credit Agreement requires the maintenance of a
ratio of EBITDA (net income plus interest expense, income taxes and depreciation
and amortization) to interest expense of greater than 3 to 1. The 2005 Pipeline
Credit Agreement also requires the maintenance of the ratio of indebtedness to
adjusted EBITDA (EBITDA adjusted for pro forma operating results of acquisitions
made during the year) of no more than 4.5 to 1. Pursuant to the 2005 Pipeline
Credit Agreement, if one or more acquisitions are consummated in which the
aggregate purchase price is $25 million or more, the allowable ratio of
indebtedness to adjusted EBITDA is increased to 5 to 1 for two calendar quarters
following the acquisition. Upon any breach of these covenants, amounts
outstanding under the 2005 Pipeline Credit Agreement may become due and payable
immediately. At December 31, 2005, we were in compliance with our financial
covenants.

The following estimated fair values of financial instruments represent the
amount at which each instrument could be exchanged in a current transaction
between willing parties. Based on quoted market prices for similar issues with
similar terms and remaining maturities, the estimated fair value of the
aggregate of the 1999 Pipeline Senior Notes, 2001 Pipeline Senior Notes and 2002
Pipeline Senior Notes was approximately $637 million and $652 million at
December 31, 2005, and 2004, respectively. We presently intend to maintain the
current schedule of maturities for the 1999 Pipeline Senior Notes, the 2001
Pipeline Senior Notes and the 2002 Pipeline Senior Notes, which will result in
no gains or losses on their respective repayments. The fair value of our
variable rate debt approximates the carrying value since the interest rates are
periodically adjusted to reflect current market conditions.

7.   DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

Prior to the anticipated issuance of fixed rate debt, we entered into forward
starting interest rate swap agreements. The interest rate swap agreements were
designated as cash flow hedges as they hedge the fluctuations in Treasury rates
and spreads between the execution date of the swap agreements and the issuance
of the fixed rate debt. The notional amount of the interest rate swap agreements
did not exceed the expected principal amount of fixed rate debt to be issued.
Upon issuance of the fixed rate debt, the swap agreements were terminated and
the proceeds received or amounts paid to terminate the swap agreements were
recorded in accumulated other comprehensive income and amortized to interest
expense over the term of the debt.


                                      F-12

<PAGE>

During the years ended December 31, 2005, 2004, and 2003, respectively, we
amortized approximately $1.5 million, $1.4 million, and $1.6 million related to
the terminated interest rate swap agreements as a reduction to interest expense
from accumulated other comprehensive income. We expect to amortize approximately
$1.6 million as a reduction to interest expense in 2006.

In November 2004, we terminated our interest rate swap agreements with notional
amounts of $225 million and received $7.5 million. Of the total proceeds, $2.5
million related to the redemption of $75 million of the 2002 Pipeline Senior
Notes (see Note 6). The remaining $5.0 million is recorded in long-term debt
with such amount amortized to interest expense over the remaining life of the
interest rate swap agreements. During the years ended December 31, 2005, and
2004, we amortized approximately $2.1 million and $0.2 million, respectively, as
a reduction to interest expense. We expect to amortize approximately $2.1
million as a reduction of interest expense in 2006 for these agreements.

8.   COMMITMENTS AND CONTINGENCIES

OPERATING LEASES

Future minimum lease payments under non-cancelable operating leases on office
space and rights-of-way are as follows (in thousands):

<TABLE>
<CAPTION>
Year ending December 31,   (In thousands)
------------------------   --------------
<S>                        <C>
2006                           $ 2,511
2007                             2,511
2008                             2,511
2009                             2,511
2010                             2,186
Thereafter                      64,849
                               -------
                               $77,079
                               =======
</TABLE>

Expenses incurred related to these lease obligations for the years ended
December 31, 2005, 2004 and 2003 were $0.6 million, $0.6 million, and $0.7
million, respectively.

CASH BALANCE PLAN

As further discussed in Note 12, on December 31, 2003, Enron filed a motion
seeking approval of the Bankruptcy Court to provide additional funding to, and
for authority to terminate the Enron Corp. Cash Balance Plan and certain other
defined benefit plans. We recorded estimated charges associated with the
termination of the Cash Balance Plan of $3.1 million in 2003. In 2004, we
reduced our expense by $3.1 million, since we determined we are no longer liable
for termination costs of the Cash Balance Plan.

CAPITAL EXPENDITURES

Total capital expenditures for 2006 are estimated to be $23 million. Funds
required to meet the capital expenditures for 2006 are anticipated to be
provided primarily by borrowings under the 2005 Pipeline Credit Agreement,
contributions from our partners and operating cash flows.

ENVIRONMENTAL MATTERS

We are not aware of any material contingent liabilities with respect to
compliance with applicable environmental laws and regulations.


                                      F-13

<PAGE>

OTHER

On July 31, 2001, the Assiniboine and Sioux Tribes of the Fort Peck Indian
Reservation (Tribes) filed a lawsuit in Tribal Court against us to collect more
than $3 million in back taxes, together with interest and penalties. The lawsuit
related to a utilities tax on certain of our properties within the Fort Peck
Indian Reservation. The Tribes and we, through a mediation process, reached a
settlement with respect to pipeline right-of-way lease and taxation issues
documented through an Option Agreement and Expanded Facilities Lease executed in
August 2004. The settlement grants to us, among other things: (i) an option to
renew the pipeline right-of-way lease upon agreed terms and conditions on or
before April 1, 2011, for a term of 25 years with a renewal right for an
additional 25 years; (ii) a right to use additional tribal lands for expanded
facilities; and (iii) release and satisfaction of all tribal taxes against us.
In consideration of this option and other benefits, we paid a lump sum amount of
$7.4 million and will make additional annual option payments of approximately
$1.5 million thereafter through March 31, 2011. Of the amount paid in 2004, $1.0
million was determined to be a settlement of previously accrued property taxes.
The remainder has been recorded in other assets on the balance sheet. We are to
seeking regulatory recovery from the settlement in our pending rate case.

Various legal actions that have arisen in the ordinary course of business are
pending. We believe that the resolution of these issues will not have a material
adverse impact on our results of operations or financial position.

9.   CASH DISTRIBUTION POLICY

Our partnership agreement provides that distributions to our partners are to be
made on a pro rata basis according to each partner's capital account balance.
Our Management Committee determines the amount and timing of such distributions.
Any changes to, or suspension of, our cash distribution policy requires the
unanimous approval of our Management Committee. In December 2003, our Management
Committee voted to (i) issue equity cash calls to our partners in the total
amount of $130 million in early 2004 and $90 million in 2007; (ii) fund future
growth capital expenditures with 50% equity capital contributions from our
partners; and (iii) change our cash distribution policy. Effective January 1,
2004, cash distributions are equal to 100% of distributable cash flow as
determined from our financial statements based upon earnings before interest,
taxes, depreciation and amortization less interest expense and maintenance
capital expenditures.

On November 30, 2004, we issued an equity cash call to our partners in the total
amount of $75 million, which was utilized to repay existing bank debt. This
equity contribution will reduce the previously approved 2007 equity cash call
from $90 million to $15 million.

10.  QUARTERLY FINANCIAL DATA (Unaudited)

<TABLE>
<CAPTION>
                 OPERATING   OPERATING   NET INCOME TO
                  REVENUE      INCOME       PARTNERS
                 ---------   ---------   -------------
                             (In thousands)
<S>              <C>         <C>         <C>
     2005
First Quarter     $82,825     $51,035       $40,631
Second Quarter     69,786      38,781        28,763
Third Quarter      89,008      55,767        46,177
Fourth Quarter     80,032      47,165        36,675

     2004

First Quarter     $83,307     $51,819       $41,757
Second Quarter     81,532      50,836        41,597
Third Quarter      81,609      47,894        37,580
Fourth Quarter     82,667      57,060        46,143
</TABLE>


                                      F-14

<PAGE>

11.  OTHER INCOME (EXPENSE)

Other income (expense) on the statement of income includes such items as
investment income, nonoperating revenues and expenses, and nonrecurring other
income and expense items. For the years ended December 31, 2005, 2004 and 2003,
other income included income from interconnections constructed of $0.2 million,
$0.7 million and $0.1 million, respectively. Other income for 2005 also included
adjustments to the allowance for doubtful accounts of $0.4 million. Other income
for 2004 also included an adjustment to reserves previously established of $0.4
million. Other expense for the year ended December 31, 2004, included
approximately $0.6 million due to reserves established for costs associated with
a potential future project and $0.5 million of bad debt expense. For the year
ended December 31, 2003, other expense included $0.6 million for a repayment of
amounts previously received for vacated microwave frequency bands.

12.  RELATIONSHIPS WITH ENRON

In December 2001, Enron and certain of its subsidiaries filed voluntary
petitions for Chapter 11 reorganization with the U.S. Bankruptcy Court. Until
November 17, 2004, Northern Plains and Pan Border were subsidiaries of Enron.
Northern Plains and Pan Border were not among the Enron companies filing for
Chapter 11 protection.

Enron North America Corp. (Enron North America), a wholly owned subsidiary of
Enron that is in bankruptcy, was a party to transportation contracts which
obligated Enron North America to pay for 3.5% of our capacity. Through the
bankruptcy proceeding in 2002, Enron North America rejected and terminated all
of its firm transportation contracts on our pipeline. We had previously fully
reserved for amounts invoiced to Enron North America. Since Enron guaranteed the
obligations of Enron North America under those contracts, we filed claims
against both Enron North America and Enron for damages in the bankruptcy
proceedings. As a result of a settlement agreement between Enron North America,
Enron and us, each of Enron North America and Enron agreed to allow our claim of
approximately $20.6 million. In 2004, we adjusted our allowance for doubtful
accounts to reflect an estimated recovery of $1.1 million for the claims. In
June 2005, we executed term sheets with a third party for the sale of our
bankruptcy claims for transportation contracts and associated guarantees held
against Enron Corp. and Enron North America. Proceeds from the sale of the
claims were $11.1 million. In the second quarter of 2005, we made an adjustment
to our allowance for doubtful accounts of $0.6 million to reflect the agreements
for the sale. In the third quarter of 2005, we recognized revenue of $9.4
million as a result of the sale.

On December 31, 2003, Enron filed a motion seeking approval of the Bankruptcy
Court to provide additional funding to, and for authority to terminate, the
Enron Corp. Cash Balance Plan and certain other defined benefit plans of Enron's
affiliates (the Plans) in 'standard terminations' within the meaning of Section
4041 of the Employee Retirement Income Security Act of 1974, as amended (ERISA).

Northern Plains was considered a member of Enron's ERISA controlled group of
corporations. As of December 31, 2003, approximately $3.1 million was estimated
for Northern Border Pipeline's proportionate allocation of Northern Plains'
proportionate share of the up to $200 million estimated termination costs for
the Plans authorized by the Bankruptcy Court order. Since under the operating
agreement with Northern Plains, these costs could be the Northern Border
Pipeline's responsibility, $3.1 million was accrued to satisfy claims of
reimbursement for these termination costs.

As a result of further evaluation and negotiation of Enron's proposed allocation
of the termination costs, Northern Plains advised us that no claim of
reimbursement of the termination costs would be made, resulting in an adjustment
in reserves during 2004 of $3.1 million for the termination costs. Pursuant to
the agreement whereby ONEOK purchased Northern Plains and NBP Services, the
purchase price under the agreements was deemed to include all contributions
which otherwise would have been allocable to Northern Plains.


                                      F-15

<PAGE>

13.  ACCOUNTING PRONOUNCEMENTS

In December 2004, the Financial Accounting Standards Board (FASB) issued SFAS
No. 123R, "Share-Based Payment" which requires companies to expense the fair
value of share-based payments and includes changes related to the expense
calculation for share-based payments. Northern Plains adopted SFAS No. 123R as
of January 1, 2006, and will charge us for our proportionate share of the
expense recorded by Northern Plains. The impact of adopting SFAS No. 123R does
not have a material impact on our results of operations or financial position.

In June 2005, the FERC issued guidance describing how FERC-regulated companies
should account for costs associated with implementing the pipeline integrity
management requirements of the U.S. Department of Transportation's Office of
Pipeline Safety. Under the guidance, costs to 1) prepare a plan to implement the
program, 2) identify high consequence areas, 3) develop and maintain a record
keeping system and 4) inspect, test and report on the condition of affected
pipeline segments to determine the need for repairs or replacements, are
required to be expensed. Costs of modifying pipelines to permit in-line
inspections, certain costs associated with developing or enhancing computer
software and costs associated with remedial and mitigation actions to correct an
identified condition can be capitalized. The guidance is effective January 1,
2006, to be applied prospectively. The effect of adopting this order is not
expected to be material to our results of operations or financial position.

14.  SUBSEQUENT EVENTS

We make distributions to our general partners approximately one month following
the end of the quarter. A cash distribution of approximately $45.0 million was
declared and paid on February 1, 2006, for the fourth quarter of 2005.

On February 14, 2006, our general partners entered into a Partnership Interest
Purchase and Sale Agreement (PIPA) dated as of December 31, 2005, under which
Northern Border Partners, L.P. (Northern Border Partners), parent company of
Northern Border ILP, agreed to sell a 20% partnership interest in us to TC
PipeLines in exchange for an aggregate cash amount of $300 million and the
assumption of certain liabilities and obligations. The PIPA contains customary
and other closing conditions that, if not satisfied or waived, would result in
the sale not occurring. Upon closing of the sale of the 20% partnership interest
several things will occur including: (1) our general partners will amend our
partnership agreement, the Northern Border Pipeline Company General Partnership
Agreement, to modify certain governance and operating terms; (2) TC PipeLines
will appoint a new Management Committee chairman and other members of the
Management Committee may change; (3) our current operator, Northern Plains or
one of its affiliates, will enter into a transition services agreement with
TransCanada or one of its affiliates, for reimbursement of all transitional
support expenses incurred for the period from closing until April 1, 2007; (4)
we will enter into a pipeline operating agreement with an affiliate of
TransCanada, under which the affiliate of TransCanada will become our operator;
and (5) we will adopt certain changes to our cash distribution policy related to
financial ratio targets and capital contributions.


                                      F-16

<PAGE>

       REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM ON SCHEDULE

Northern Border Pipeline Company:

We have audited in accordance with generally accepted auditing standards as
established by the Auditing Standards Board (United States) and in accordance
with the auditing standards of the Public Company Accounting Oversight Board
(United States), the financial statements of Northern Border Pipeline Company as
of December 31, 2005 and 2004 and for each of the years in the three-year period
ended December 31, 2005 included in this Form 10-K, and have issued our report
thereon dated March 2, 2006.

Our audits were made for the purpose of forming an opinion on the basic
financial statements taken as a whole. The schedule of Northern Border Pipeline
Company listed in Item 15 of Part IV of this Form 10-K is the responsibility of
the Company's management and is presented for purposes of complying with the
Securities and Exchange Commission's rules and is not part of the basic
financial statements. This schedule has been subjected to the auditing
procedures applied in the audits of the basic financial statements and, in our
opinion, fairly states, in all material respects, the financial data required to
be set forth therein in relation to the basic financial statements taken as a
whole.


/s/ KPMG LLP

Omaha, Nebraska
March 2, 2006


                                       S-1

<PAGE>

NORTHERN BORDER PIPELINE COMPANY
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS

<TABLE>
<CAPTION>
                                               ADDITIONS          DEDUCTIONS FOR
                                        -----------------------     PURPOSE FOR
                          BALANCE AT    CHARGED TO   CHARGED TO        WHICH
                         BEGINNING OF    COSTS AND      OTHER      RESERVES WERE   BALANCE AT END
                             YEAR        EXPENSES     ACCOUNTS        CREATED          OF YEAR
                         ------------   ----------   ----------   --------------   --------------
                                                      (In thousands)
<S>                      <C>            <C>          <C>          <C>              <C>
Reserve for regulatory
   issues:
2005                        $ 1,955       $   25         $--          $ 1,350          $  630
2004                          6,315          640          --            5,000           1,955
2003                         12,294        4,282          --           10,261           6,315

Allowance for doubtful
   accounts:
2005                        $ 4,208       $  171         $--          $ 4,379          $   --
2004                          4,815          523          --            1,130           4,208
2003                          4,805           10          --               --           4,815
</TABLE>


                                       S-2

<PAGE>

                                 Exhibit Index

<TABLE>
<S>       <C>
*3.1      Northern Border Pipeline Company General Partnership Agreement between
          Northern Plains Natural Gas Company, Northwest Border Pipeline
          Company, Pan Border Gas Company, TransCanada Border Pipeline Ltd. and
          TransCan Northern Ltd., effective March 9, 1978, as amended
          (incorporated by reference to Exhibit 10.2 to Northern Border
          Partners, L.P.'s Form S-1Registration Statement filed on July 16,
          1993, (Registration No. 33-66158) ("Form S-1")).

*3.2      Seventh Supplement Amending Northern Border Pipeline Company General
          Partnership Agreement dated September 23, 1993 (incorporated by
          reference to Exhibit 10.15 to Form S-1).

*3.3      Eighth Supplement Amending Northern Border Pipeline Company General
          Partnership Agreement dated May 21, 1999 (incorporated by reference to
          Exhibit 10.15 to the Company's Form S-4 Registration Statement filed
          on October 7, 1999 (Registration No. 333-88577) ("Form S-4").

*3.4      Ninth Supplement Amending Northern Border Pipeline Company General
          Partnership Agreement dated July 16, 2001 (incorporated by reference
          to Exhibit 10.37 to the Company's Registration Statement on Form S-4
          filed on November 13, 2001 (Registration No. 333-73282) ("2001 Form
          S-4").

*3.5      Tenth Supplement Amending Northern Border Pipeline Company General
          Partnership Agreement dated March 3, 2005 (incorporated by reference
          to Exhibit 3.5 to the Company's Form 10-K for the year ended December
          31, 2004 filed on March 14, 2005 (File No. 333-88577)).

*4.1      Indenture, dated as of August 17, 1999, between Northern Border
          Pipeline Company and Bank One Trust Company, NA, successor to The
          First National Bank of Chicago, Trustee (incorporated by reference to
          Exhibit 4.1 to Form S-4).

*4.2      Indenture, dated as of September 17, 2001, between Northern Border
          Pipeline Company and Bank One Trust Company, N.A., Trustee
          (incorporated by reference to Exhibit 4.2 to 2001 Form S-4).

*4.3      Indenture, dated as of April 29, 2002, between Northern Border
          Pipeline Company and Bank One Trust Company, N.A., Trustee
          (incorporated by reference to Exhibit 4.1 to the Company's Form 10-Q
          for the quarter ended March 31, 2002) (Filed No. 333-88577).

*10.1     Operating Agreement between Northern Border Pipeline Company and
          Northern Plains Natural Gas Company, dated February 28, 1980
          (incorporated by reference to Exhibit 10.3 to Form S-1).

*10.2     Revolving Credit Agreement, dated as of May 16, 2005, among Northern
          Border Pipeline Company, the lenders from time to time party thereto,
          Wachovia Bank, National Association, as administrative agent, SunTrust
          Bank, as syndication agent, Harris Nesbit Financing, Inc., Barclays
          Bank PLC and Citibank, N.A., as co-documentation agents, and Wachovia
          Capital Markets, LLC and SunTrust Capital Markets, Inc., as co-lead
          arrangers and book managers (incorporated by reference to Exhibit 10.1
          to the Company's current report on Form 8-K filed on May 20, 2005
          (File No. 333-88577)).

*10.3     Form of Conveyance, Contribution and Assumption Agreement among
          Northern Plains Natural Gas Company, Northwest Border Pipeline
          Company, Pan Border Gas Company, Northern Border Partners, L.P., and
          Northern Border Intermediate Limited Partnership (incorporated by
          reference to Exhibit 10.16 to Form S-1).

*10.4     Form of Contribution, Conveyance and Assumption Agreement among TC
          PipeLines, LP and certain other parties (incorporated by reference to
          Exhibit 10.2 to Amendment No. 3 to TC PipeLines, LP's Form
          S-1Registration Statement filed on May 3, 1999, (Registration No.
          333-69947) ("TC Form S-1")).

+*10.5    Form of Termination Agreement with ONEOK dated as of January 5, 2005
          (incorporated by reference to Exhibit 99.1 to Northern Border
          Partners, L.P.'s current report on Form 8-K filed on January 11, 2005
          (File No. 1-12201)).

+*10.6    ONEOK, Inc. 2005 Supplemental Executive Retirement Plan. (incorporated
          by reference to Exhibit 99.2 to Northern Border Partners, L.P.'s
          current report on Form 8-K filed on January 11, 2005 (File No.
          1-12201)).

+*10.7    ONEOK, Inc. Long-Term Incentive Plan (incorporated by reference to
          Exhibit 10(a) to ONEOK's Form 10-K for the year ended December 31,
          2001 (File No. 1-13643)).

+*10.8    ONEOK, Inc. Form of Restricted Stock Incentive Award (incorporated by
          reference to Exhibit 10.4 to ONEOK's Form 10-Q for the quarter ended
          September 30, 2004 (File No. 1-13643)).

+*10.9    ONEOK, Inc. Form of Performance Shares Award (incorporated by
          reference to Exhibit 10.5 to ONEOK's Form 10-Q for the quarterly
          period ended September 30, 2004 (File No. 1-13643)).

+*10.10   ONEOK, Inc. Employee Non-Qualified Deferred Compensation Plan, as
          amended, dated February 10, 2001 (incorporated by reference to Exhibit
          10(g) to ONEOK's Form 10-K for the year ended December 31, 2001 (File
          No. 1-13643)).
</TABLE>

<PAGE>

<TABLE>
<S>       <C>
+*10.11   ONEOK, Inc. Annual Officer Incentive Plan (incorporated by reference
          to Exhibit 10(f) to ONEOK's Form 10-K for the year ended December 31,
          2001 (File No. 1-13643)).

+*10.12   ONEOK, Inc. Equity Compensation Plan (incorporated by reference to
          Exhibit 10.1 to ONEOK's current report on Form 8-K filed on February
          23, 2005 (File No. 1-13643)).

+*10.13   ONEOK, Inc. Employee Stock Purchase Plan, as amended February 17, 2005
          (incorporated by reference to Exhibit 10.2 to ONEOK's current report
          on Form 8-K filed on February 23, 2005 (File No. 1-13643)).

+*10.14   ONEOK, Inc. Form of Restricted Unit Award Agreement (incorporated by
          reference to Exhibit 10.21 to Northern Border Partners, L.P.'s Form
          10-K for the year ended December 31, 2005 (File No. 1-12201) ("NBP
          2005 Form 10-K")).

+*10.15   ONEOK, Inc. Form of Performance Unit Award Agreement (incorporated by
          reference to Exhibit 10.22 to the NBP 2005 Form 10-K).

*10.16    Northern Border Pipeline Company Agreement among Northern Plains
          Natural Gas Company, Pan Border Gas Company, Northwest Border Pipeline
          Company, TransCanada Border PipeLine Ltd., TransCan Northern Ltd.,
          Northern Border Intermediate Limited Partnership, Northern Border
          Partners, L.P., and the Management Committee of Northern Border
          Pipeline, dated as of March 17, 1999 (incorporated by reference to
          Exhibit 10.21 to Northern Border Partners, L.P.'s Form 10-K/A for the
          year ended December 31, 1998 (File No. 1-12202)).

12.1      Statement recomputation of ratios.

31.1      Rule 13a-14(a)/15d-14(a) Certification of principal executive officer.

31.2      Rule 13a-14(a)/15d-14(a) Certification of principal financial officer.

32.1      Section 1350 Certification of principal executive officer.

32.2      Section 1350 Certification of principal financial officer.

+*99.1    Northern Border Phantom Unit Plan (incorporated by reference to
          Exhibit 99.1 to Amendment No. 1 to Northern Border Partners, L.P.'s
          Form S-8, Registration No. 333-66949 and Exhibit 99.1 to Northern
          Border Partners, L.P.'s Registration No. 333-72696).

#*99.2    Partnership Interest Purchase and Sale Agreement by and between
          Northern Border Intermediate Limited Partnership and TC PipeLines
          Intermediate Limited Partnership dated as of December 31, 2005 (PIPA)
          (incorporated by reference to Exhibit 2.3 to the NBP 2005 Form 10-K).
</TABLE>

*    Indicates exhibits incorporated by reference as indicated; all other
     exhibits are filed herewith.

+    Management contract, compensatory plan or arrangement.

#    The Company agrees to furnish supplementally to the Securities and Exchange
     Commission, upon request, any schedules and exhibits to this agreement, as
     set forth in the Table of Contents of the agreement, that have not been
     filed herewith pursuant to Item 601(b)(2) of Regulation S-K.