<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, 2006

                                       or

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

     For the transition period from _______ to ________.

                        Commission File Number: 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 a large accelerated filer, an
accelerated filer, or a non-accelerated filer. See definition of "accelerated
filer and large accelerated filer" in Rule 12b-2 of the Exchange Act. (Check
one):

Large accelerated filer [ ]   Accelerated filer [ ]   Non-accelerated filer [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, 2006, 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..................................................       4
            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..................................................      15
Item 3.  Legal Proceedings...........................................      15
Item 4.  Submission of Matters to a Vote of Security Holders.........      15

                                     PART II

Item 5.  Market for Registrant's Common Equity, Related Stockholder
            Matters and Issuer Purchases of Equity Securities........      15
Item 6.  Selected Financial Data.....................................      16
Item 7.  Management's Discussion and Analysis of Financial Condition
            and Results of Operations
            Executive Summary........................................      17
            Critical Accounting Estimates............................      19
            Results of Operations....................................      19
            Liquidity and Capital Resources..........................      21
            Recent Accounting Pronouncements.........................      24
            Forward-Looking Statements...............................      24
Item 7A. Quantitative and Qualitative Disclosures about Market Risk..      25
Item 8.  Financial Statements and Supplementary Data.................      27
Item 9.  Changes in and Disagreements with Accountants on Accounting
            and Financial Disclosure.................................      43
Item 9A. Controls and Procedures.....................................      43
Item 9B. Other Information...........................................      44

                                    PART III

Item 10. Directors, Executive Officers and Corporate Governance......      44
Item 11. Executive Compensation......................................      46
Item 12. Security Ownership of Certain Beneficial Owners and
            Management and Related Stockholder Matters...............      54
Item 13. Certain Relationships and Related Transactions, and Director
            Independence.............................................      54
Item 14. Principal Accounting Fees and Services......................      57

                                     PART IV

Item 15. Exhibits and Financial Statement Schedules..................      57
</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
Design capacity.................   Pipeline capacity available to transport
                                   natural gas based on system facilities and
                                   design conditions
Dth.............................   Dekatherm
EBITDA..........................   Net income plus interest, income taxes and
                                   depreciation and amortization
EIA.............................   Energy Information Administration
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............................   U.S. generally accepted accounting principles
LIBOR...........................   London Interbank Offered Rate
LNG.............................   Liquefied natural gas
MMcf/d..........................   Million cubic feet per day
Northern Border Pipeline........   Northern Border Pipeline Company
NYSE............................   New York Stock Exchange
ONEOK...........................   ONEOK, Inc.
ONEOK Energy....................   ONEOK Energy Services Company, LP
ONEOK Partners..................   ONEOK Partners, L.P. and ONEOK Partners
                                   Intermediate Limited Partnership (formerly
                                   known as Northern Border Partners, L.P. and
                                   Northern Border Intermediate Limited
                                   Partnership, respectively)
ONEOK Partners Intermediate.....   ONEOK Partners Intermediate Limited
                                   Partnership (formerly known as Northern
                                   Border Intermediate Limited Partnership)
ONEOK Partners GP...............   ONEOK Partners GP, L.L.C. (formerly known as
                                   Northern Plains Natural Gas Company, LLC), a
                                   ONEOK subsidiary and our operator until
                                   March 31, 2007
Pan Border......................   Pan Border Gas Company, LLC, a ONEOK
                                   subsidiary
SAB.............................   SEC Staff Accounting Bulletin
SEC.............................   Securities and Exchange Commission
SFAS............................   Statement of Financial Accounting Standards
TC PipeLines....................   TC PipeLines, LP and TC PipeLines
                                   Intermediate Limited Partnership
TC PipeLines Intermediate.......   TC PipeLines Intermediate Limited Partnership
TransCan........................   TransCan Northwest Border Ltd., an affiliate
                                   of TransCanada and our operator effective
                                   April 1, 2007
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

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

OVERVIEW

We are a Texas general partnership that was formed in 1978. We provide natural
gas transportation services and are a leading transporter of natural gas
imported from Canada into the U.S. ONEOK Partners, through its subsidiary ONEOK
Partners Intermediate, and TC PipeLines, through its subsidiary TC PipeLines
Intermediate, each own a 50 percent interest in us. ONEOK Partners and TC
PipeLines are publicly-traded master limited partnerships. The general partner
of ONEOK Partners is ONEOK Partners GP, a subsidiary of ONEOK. TC PipeLines GP,
Inc., a subsidiary of TransCanada, is the general partner of TC PipeLines.

We are managed by a Management Committee that consists of four members. Each
partner designates two members and TC PipeLines designates one of its members as
Chairman. At December 31, 2006, each partner held a 50 percent voting interest
on the Management Committee.

The day-to-day management of our affairs is the responsibility of ONEOK Partners
GP until March 31, 2007, pursuant to an operating agreement between us and ONEOK
Partners GP. We are charged by ONEOK Partners GP for the salaries, benefits and
expenses of ONEOK Partners GP attributable to our operations. ONEOK Partners
also utilizes ONEOK and its affiliates for management services related to us.
Effective April 1, 2007, TransCan will become our operator.

BUSINESS STRATEGY

We focus on safe, efficient and reliable operations of our pipeline system and
providing attractive services for our customers. We intend to continue to
cost-effectively transport Canadian and U.S. natural gas to the Midwestern U.S.
We seek growth of our interstate natural gas pipeline through incremental
projects.

RECENT DEVELOPMENTS

The following is a summary of our significant developments during 2006.
Additional information regarding most of these items may be found elsewhere in
this annual report or in previous reports filed with the SEC.

Purchase and Sale of Partnership Interest - In April 2006, ONEOK Partners sold a
20 percent partnership interest in us to TC PipeLines. ONEOK Partners and TC
PipeLines each own a 50 percent interest in us.

Amended and Restated Partnership Agreement - In April 2006, we amended and
restated our General Partnership Agreement as a result of the ownership interest
change. Under our First Amended and Restated General Partnership Agreement:

     -    The Management Committee consists of four members. Each partner
          designates two members and TC PipeLines designates one of its members
          as chairman.

     -    The Management Committee designates the members of the Audit
          Committee, which consists of three members. One member is selected by
          the members of the Management Committee designated by the partner
          whose affiliate is the operator and two members are selected by the
          members of the Management Committee designated by the other partner.

     -    ONEOK Partners GP will be our operator until March 31, 2007. Effective
          April 1, 2007, TransCan will become our operator under a new operating
          agreement.

Operating Agreement - In April 2006, we entered into an operating agreement with
TransCan. Under the new operating agreement, TransCan will become our operator
effective April 1, 2007.

Chicago III Expansion Project - In April 2006, the Chicago III Expansion Project
was placed into service as planned, adding approximately 130 MMcf/d of
transportation capacity on the eastern portion of our pipeline into the Chicago
market area.


                                       4

<PAGE>

Settlement of Rate Case -In September 2006, we filed a stipulation and agreement
which documented the settlement of our rate case. The settlement was reached
between us and our participant customers and was supported by the FERC trial
staff. In November 2006, the FERC approved the uncontested settlement of our
rate case. We refunded $10.8 million to our customers in the fourth quarter of
2006. Additional information about our regulatory proceedings is included in
this section of this report under "Description of the Business - Government
Regulation."

DESCRIPTION OF BUSINESS

OVERVIEW

We transport natural gas along 1,249 miles of pipeline with the largest segment
of the pipeline having a design capacity of approximately 2.4 Bcf/d. Our
transportation system 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.
Additionally, we transport natural gas produced in the Williston Basin of
Montana and North Dakota and the Powder River Basin of Wyoming and Montana and
synthetic gas produced at the Dakota Gasification plant in North Dakota.

Our operating revenue is derived from the transportation of natural gas. The
maximum transportation rates that we may charge are established in a FERC
proceeding known as a rate case. Our tariff specifies the maximum rates 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 the maximum rates permissible for
transportation service that include the recovery of our 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
maximum rates are set in a rate case, we are not permitted to adjust our rates
to reflect changes in costs or contract demand until a new rate case is filed
and approved by the FERC. As a result, our earnings and cash flow depend on
costs incurred, contracted capacity and transportation path, the volume of gas
transported and our ability to sell available capacity based on current
market conditions.

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 reservation 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 mileage and the volume of natural gas they transport. Our firm
contracts have terms ranging from one day to nine years. 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 based on mileage
and the volume of natural gas they transport. For the year ended December 31,
2006, approximately 96 percent of our transportation revenue was derived from
reservation charges and the remaining 4 percent 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 to 42 inches and a design
capacity on the largest segment of the pipeline of 2,374 MMcf/d. Along the
pipeline are 17 compressor stations with a total of 515,000 horsepower,
measurement facilities to support the receipt and delivery of gas at 10 receipt
and 48 delivery points, 4 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, 2001 and 2006. In April 2006, the
Chicago III Expansion Project went into service, adding approximately 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. This
expansion is fully subscribed by four shippers under long-term firm service
transportation agreements with terms ranging from five and one-half to ten
years.

TITLE TO PROPERTIES

We hold all rights, titles and interests 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,


                                       5

<PAGE>

easements, rights-of-way, permits and licenses from landowners or governmental
authorities permitting land use for construction and operation of our pipeline.

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 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 a 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.

SUPPLY

Our customers' primary source of natural gas is the Western Canada Sedimentary
Basin. In 2006, approximately 85 percent 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.

The amount of Canadian natural gas available for export is a major factor
affecting the volume of Canadian natural gas transported by our pipeline. The
amount of Canadian natural gas available for export is determined by:

     -    Canadian natural gas production levels;

     -    consumption of natural gas in Canada; and

     -    storage capacity and inventory levels for Canadian natural gas.

The extent to which Canadian natural gas available for export will be
transported on our system is affected by:

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

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

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

     -    the 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 Midwestern U.S.

Natural gas produced in the Williston Basin of Montana and North Dakota and the
Powder River Basin of Wyoming and Montana accounted for approximately 9 percent
of the natural gas we transported in 2006. The remaining 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;

     -    the availability and price of alternative energy sources;

     -    fuel conservation measures;

     -    technological advances in fuel economy and energy generation devices;

     -    new demands for natural gas, such as consumption in ethanol
          production; and

     -    the price of natural gas.

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

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


                                       6

<PAGE>

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 through March. Summer season
is considered to be April through October. The peak summer season for electric
power generation is generally during 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 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 peak winter heating demand
loads. Moderate winter and summer temperatures can lead to the decline in the
demand for our service due to reduced demand for natural gas.

Our pipeline capacity that is contracted under long-term firm service
transportation agreements is not impacted by seasonal throughput variations. The
portion of our capacity that is contracted under short-term (less than one year)
transportation agreements is subject to seasonal variations. Our rate case
settlement established seasonal rates for short-term service of less than one
year, and provides for higher maximum rates during anticipated peak usage
periods, and lower maximum rates during anticipated periods of reduced demand.
Approximately 40 percent of our design capacity was contracted on a short-term
basis in 2006.

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. We do not own any natural gas storage facilities. According to
the EIA, in 2006, residential, commercial and electric power generation users
consumed 67 percent of the total natural gas volume delivered. Industrial users,
who consumed the remaining 33 percent, 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 Midwestern U.S. markets for customers located throughout North America.
Our customers include natural gas producers, marketers, industrial facilities,
local distribution companies and electric power generating plants.

For the year ended December 31, 2006, two customers accounted for more than 10
percent of our revenue as follows:

<TABLE>
<CAPTION>
                                     PERCENT OF
CUSTOMER                           TOTAL REVENUE
--------                           -------------
<S>                                <C>
BP Canada Energy Marketing Corp.         21
Cargill Inc.                             14
</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 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 the markets we serve with access to natural gas storage facilities,
alternate sources of supply, such as the Rockies, the Mid-Continent, the Permian
Basin and the Gulf Coast, and LNG.


                                       7

<PAGE>

CONTRACTING

We contracted 97 percent of our design capacity on a firm basis in 2006, some of
which was sold at a discount to maximize overall revenue on the Port of Morgan,
Montana to Harper, Iowa portion of the pipeline. As of January 31, 2007, 72
percent of our design capacity was contracted on a firm basis through December
31, 2007. The weighted average life of our contracts was 1.8 years as of January
31, 2007.

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;

     -    extension or abandonment of service and facilities;

     -    accounts and records;

     -    depreciation and amortization policies;

     -    acquisition and disposition of facilities;

     -    initiation and discontinuation of services; and

     -    standards of conduct governing relationships with certain affiliates.

Rate Case - As required by the provisions of the settlement of our 1999 rate
case, on November 1, 2005, we filed a rate case with the FERC. In December 2005,
the FERC issued an order that identified issues that were raised in the
proceeding and accepted the proposed rates, but suspended their effectiveness
until May 1, 2006. The new rates were collected subject to refund from May 1,
2006 through September 30, 2006. Based on the settlement discussed below, we
refunded $10.8 million to our customers in the fourth quarter of 2006.

On September 18, 2006, we filed a stipulation and agreement which documented the
settlement reached between us and our participant customers and was supported by
the FERC trial staff. The uncontested settlement was approved by the FERC on
November 21, 2006.

The settlement established maximum long-term mileage-based rates and charges for
transportation on our system. Beginning in 2007, overall rates were reduced,
compared with rates prior to the filing, by approximately 5 percent. For the
full transportation route from Port of Morgan, Montana to the Chicago area, the
previous charge of approximately $0.46 per Dth is now approximately $0.44 per
Dth, which is comprised of a reservation rate, commodity rate and a compressor
usage surcharge. The factors used in calculating depreciation expense for
transmission plant increased from 2.25 percent to 2.40 percent. The settlement
also provided for seasonal rates for short-term transportation services.
Seasonal maximum rates vary on a monthly basis from approximately $0.54 per Dth
to approximately $0.29 per Dth for the full transportation route from Port of
Morgan, Montana to the Chicago area. The settlement included a three-year
moratorium on filing rate cases and participants challenging these rates, and
requires that we file a rate case within six years.

Income Tax Allowance - 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 (the December 16 Order) in its first
case-specific review of the income tax allowance issue, reaffirming its 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 Court 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 in future proceedings.

Creditworthiness Standards - In June 2005, the FERC adopted a new policy
detailing creditworthiness 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 constructions,
the FERC will continue its policy of


                                       8

<PAGE>

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 was voluntarily remanded to the
FERC for further consideration. In an Order on Voluntary Remand issued in
November 2006, the FERC reaffirmed its finding that interstate pipelines should
not be allowed to require more than three months security from shippers.

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 tariff
rate revenue cap, in determining negotiated rates. The use of basis
differentials for negotiated rates was previously prohibited because the FERC
believed that such a pricing mechanism could give pipelines an incentive to
withhold capacity and manipulate the natural gas markets by widening the basis
between indexes. The FERC found this 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. In March 2006, the FERC dismissed the
requests for rehearing and denied the requests for clarification.

Natural Gas Quality and Interchangeability - In June 2006, the FERC issued a
policy statement detailing its policy on natural gas quality and
interchangeability. The FERC adopted a relatively flexible policy that promotes
case-by-case negotiation. The FERC's policy embodies five principles: 1) only
natural gas quality and interchangeability specifications contained in a
FERC-approved gas tariff can be enforced; 2) pipeline tariff provisions on gas
quality and interchangeability need to be flexible to allow pipelines to balance
safety and reliability concerns with the importance of maximizing supply, as
well as recognizing the evolving nature of the science underlying gas quality
and interchangeability specifications; 3) pipelines and their customers should
develop gas quality and interchangeability specifications based on technical
requirements; 4) in negotiating technically based solutions, pipelines and their
customers are strongly encouraged to use the Natural Gas Council Plus interim
guidelines as a common reference point for resolving gas quality and
interchangeability issues; and 5) to the extent pipelines and their customers
cannot resolve disputes over gas quality and interchangeability, those disputes
can be brought before the FERC to be resolved on a case-by-case basis.

Energy Policy Act of 2005 - In August 2005, the Energy Policy Act of 2005 was
signed into law addressing a wide range of issues, including many that impact
the oil and gas industry. The Energy Policy Act of 2005: 1) provides that the
FERC will be the lead agency and creates a common record for review of federal
permitting decisions associated with interstate 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 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 to up to $1 million per violation, and increases
civil penalties under the Natural Gas Act to up to $1 million per day for
violations as long as they continue. In October 2006, the FERC issued Order No.
687 that implements the provisions of the Energy Policy Act of 2005 requiring
the FERC to coordinate environmental reviews and the issuance of all federal
authorizations for natural gas infrastructure proposals with other federal and
state agencies, and to maintain a consolidated federal record for judicial
appeal and review. Under the final rule, which was effective December 28, 2006,
the FERC will act as lead agency for environmental reviews and will establish a
schedule pursuant to which federal agencies, as well as state agencies acting
under federally delegated authority, will reach final regulatory decisions
necessary for the approval of natural gas infrastructure projects under Section
7 of the Natural Gas Act. The deadline for agencies' final decisions will be 90
days after the FERC staff issues either an environmental assessment or an
environmental impact statement. The 90 day deadline will not apply if an
agency's deadline is otherwise determined by federal law.

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. Subsidiaries of ONEOK Partners and ONEOK,
including ONEOK Energy, and subsidiaries of TransCanada were deemed to be our
energy affiliates under the standards of conduct in effect for the majority of
2006. In November 2006, the United States Court of Appeals for the District of
Columbia vacated the FERC's order regarding standards of conduct for energy
affiliates of natural gas pipelines and remanded the matter back to the FERC. On
January 9, 2007, the FERC issued Order No. 690, Standards of Conduct for
Transmission Providers (the Interim Rule) as the Commission's interim


                                       9

<PAGE>
response to the Appeals Court decision. The Interim Rule reduced the
application of the standards of conduct for interstate natural gas pipelines to
the relationship between the pipelines and their marketing affiliates as defined
in the FERC's rules that were in effect prior to the current regulations and
made certain other revisions that were subject to the appeal. Requests for
clarifications and in the alternative rehearing of the Interim Rule have been
filed. On January 18, 2007, the FERC issued a Notice of Proposed Rulemaking,
which if accepted as the final rule, will make permanent the Interim Rule's
applicability of the standards of conduct to govern the relationship between
interstate natural gas pipelines and their marketing affiliates.

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.

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 effect on our financial position or results of operations.

PIPELINE SAFETY

We are subject to U.S. Department of Transportation pipeline 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 percent of the highest priority high
consequence areas by the end of 2007.

AIR AND WATER EMISSIONS

The federal Clean Air Act, the federal Clean Water Act and analogous state laws
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. ONEOK Partners GP will continue to provide
administrative, operating and management services to us under an operating
agreement through March 31, 2007. ONEOK Partners GP also operates other
interstate natural gas pipelines, including Midwestern Gas Transmission Company,
Viking Gas Transmission Company and Guardian Pipeline, L.L.C. As of December 31,
2006, ONEOK Partners GP had 324 employees. ONEOK Partners GP's employees are not
represented by a labor union nor covered by a collective bargaining agreement.
Effective April 1, 2007, TransCan will become our operator under a new operating
agreement. TransCanada has advised us that it has retained approximately 135
individuals who currently operate our pipeline system or provide administrative
and management services and will continue to operate us as employees of
TransCanada beginning April 1, 2007.


                                       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/OR 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 natural gas primarily
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/or 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.

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

Our pipeline competes with other pipelines for Canadian natural gas supplies
delivered to U.S. markets. As a result of this competition, we may have
significant levels of uncontracted capacity on our pipeline, 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. Under our rate case
settlement, there is a three-year moratorium on filing rate cases and
participants challenging our rates, and a requirement that we file a rate case
within six years. As a result, we would not be able to file a new rate case to
mitigate a potentially significant increase in costs or reduction in revenues
until the expiration of the moratorium. Action by the FERC on currently pending
matters as well as matters arising in the future could adversely affect our
ability to establish rates, or to charge rates that would cover future increases
in our costs, or even to continue to collect rates that cover current costs,
including a reasonable return. We cannot assure you that we will be able to
recover all of our costs through existing or future rates.

OUR BUSINESS PRACTICES ARE SUBJECT TO REVIEW UNDER THE NATURAL GAS ACT AND THE
NATURAL GAS POLICY ACT OF 1978 AND AS A RESULT, WE ARE SUBJECT TO POSSIBLE
ADJUSTMENTS AND/OR PENALTIES FOR NON-COMPLIANCE BY FEDERAL REGULATORS.

The FERC may from time to time conduct audits of a pipeline's business practices
to ensure compliance with the Natural Gas Act and the Natural Gas Policy Act of
1978. To the extent a pipeline is not found to be in compliance, the FERC has
the authority under the Energy Policy Act of 2005 to recommend and enforce
changes, and has procedures for administering civil and criminal penalties. As a
result, we are exposed to possible adjustments and penalties for non-compliance
by federal regulators.


                                       11

<PAGE>

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

Accounting policies for FERC-regulated companies permit certain assets that
result from the regulated ratemaking process to be recorded on our balance sheet
that could 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.

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 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 that impose
          obligations related to air emissions;

     -    the federal Clean Water Act and analogous state laws that regulate
          discharge of wastewaters from our facilities into 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 to make repairs
or take remediation, preventative or mitigating actions that are determined to
be necessary.


                                       12

<PAGE>

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 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 contract for fixed-rate swap agreements to hedge variable-rate
instruments and the variable rate falls below the fixed rate.

OUR OPERATIONS ARE SUBJECT TO OPERATIONAL HAZARDS AND UNFORESEEN INTERRUPTIONS,
INCLUDING TERRORIST ATTACKS, WHICH COULD ADVERSELY AFFECT OUR BUSINESS AND FOR
WHICH WE MAY NOT BE ADEQUATELY INSURED.

Our operations are subject to operational hazards and unforeseen interruptions
such as natural disasters, adverse weather, accidents, fires, explosions,
hazardous materials releases, and other events beyond our control. Since the
attacks of September 11, 2001, the U.S. government has issued warnings that
energy assets, specifically our nation's pipeline infrastructure, may be the
future target of terrorist organizations. These developments have subjected our
operations to increased risks. Any future terrorist attack on our facilities,
those of our customers and, in some cases, those of other pipelines, may
adversely affect our business.

These events might result in a loss of equipment or life, injury, or extensive
property damage, as well as an interruption in our operations. We may not be
able to maintain or obtain insurance of the type and amount desired at
reasonable rates. As a result of market conditions, premiums and deductibles for
certain insurance policies have increased substantially, and could escalate
further. In some instances, certain insurance could become unavailable or
available only for reduced amounts of coverage. For example, insurance carriers
are now requiring broad exclusions for losses due to war risk and terrorist
acts. If we were to incur a significant liability for which we were not fully
insured, it could result in a material loss to us.

WE DO NOT OWN ALL OF THE LAND ON WHICH OUR PIPELINES AND FACILITIES ARE LOCATED,
WHICH COULD DISRUPT OUR OPERATIONS.

We do not own all of the land on which our pipelines and facilities are located,
and we are therefore subject to the risk of increased costs to maintain
necessary land use. We obtained some of our rights to construct and operate our
pipeline and related facilities on land owned by third parties, governmental
agencies and with an Indian reservation for a specific period of time. Our loss
of these rights, through our inability to renew right-of-way contracts or
otherwise, or increased costs to renew such rights, could have a material
adverse effect on our operations.


                                       13

<PAGE>

RISKS INHERENT IN AN INVESTMENT IN US

WE DO NOT OPERATE 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 currently rely on ONEOK Partners GP, a subsidiary of ONEOK, to provide us
with administrative, operating and management services, which services will be
provided by TransCan effective April 1, 2007 pursuant to a new Operating
Agreement. 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. ONEOK Partners GP or TransCan 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 ONEOK Partners GP or TransCan 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 ONEOK Partners GP, TransCan and third-party providers
with which they contract, together with our limited ability to control certain
costs, could harm our business and results of operations.

We also have limited ability to control the transfer of our administrative,
operating and management services from ONEOK Partners GP to TransCan. We may
incur unanticipated costs related to the transfer and there may be increased
costs associated with the services provided by TransCan, which 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. IN ADDITION, EACH OF OUR GENERAL PARTNERS OWNS A 50
PERCENT INTEREST IN US AND HAS EQUAL VOTING RIGHTS.

ONEOK Partners and TC PipeLines each own a 50 percent general partnership
interest in us. 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 in resolving
          conflicts of interest, which has the effect of limiting their
          fiduciary duty to us;

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

     -    our partnership agreement limits the liability and reduces the
          fiduciary duties of the members of the Management Committee and of our
          general partners and also restricts 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 and determines whether they are maintenance capital
          expenditures or growth capital expenditures, which 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;

     -    our partnership agreement does not restrict the members of 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.


                                       14

<PAGE>

ITEM 2. PROPERTIES

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

ITEM 3. LEGAL PROCEEDINGS

NOTICE OF RATE CHANGE OF NORTHERN BORDER PIPELINE COMPANY, FEDERAL ENERGY
REGULATORY COMMISSION, DOCKET NO. RP06-72-000. As required by the provisions of
the settlement of our 1999 rate case, on November 1, 2005, we filed a rate case
with the FERC. On September 18, 2006, we filed a stipulation and agreement which
documented the settlement reached between us and our participant customers and
was supported by the FERC trial staff. The uncontested settlement was approved
by the FERC on November 21, 2006. We refunded $10.8 million to our customers
during the fourth quarter of 2006.

The settlement established maximum long-term mileage-based rates and charges for
transportation on our system. Beginning in 2007, overall rates were reduced,
compared with rates prior to the filing, by approximately 5 percent. For the
full transportation route from Port of Morgan, Montana to the Chicago area, the
previous charge of approximately $0.46 per Dth is now approximately $0.44 per
Dth, which is comprised of a reservation rate, commodity rate and a compressor
usage surcharge. The factors used in calculating depreciation expense for
transmission plant increased from 2.25 percent to 2.40 percent. The settlement
also provided for seasonal rates for short-term transportation services.
Seasonal maximum rates vary on a monthly basis from approximately $0.54 per Dth
to approximately $0.29 per Dth for the full transportation route from Port of
Morgan, Montana to the Chicago area. The settlement included a three-year
moratorium on filing rate cases and participants challenging these rates, and
requires that we file a rate case within six years.

OTHER

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. SUBMISSION 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.


                                       15
<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,
                                            --------------------------------------------------------------
                                               2006         2005         2004         2003         2002
                                            ----------   ----------   ----------   ----------   ----------
                                               (In thousands, except other financial and operating data)
<S>                                         <C>          <C>          <C>          <C>          <C>
Income data:
   Operating revenue, net                   $  310,900   $  321,651   $  329,115   $  324,185   $  321,050
   Operations and maintenance                   49,500       39,506       33,763       43,791       41,442
   Depreciation and amortization                58,721       58,052       58,375       57,779       58,714
   Taxes other than income                      31,541       31,345       29,368       29,634       28,436
                                            ----------   ----------   ----------   ----------   ----------
      Operating income                         171,138      192,748      207,609      192,981      192,458
   Interest expense, net                        43,081       42,635       41,356       44,857       51,525
   Other income, net                             1,788        2,133          524           76        1,786
                                            ----------   ----------   ----------   ----------   ----------
      Net income to partners                $  129,845   $  152,246   $  166,777   $  148,200   $  142,719
                                            ==========   ==========   ==========   ==========   ==========

Cash flow data:
   Net cash provided by operating
      activities                            $  185,326   $  206,461   $  206,149   $  193,270   $  224,356
   Capital expenditures                         20,857       28,555       10,569       12,918        9,243
   Distributions to partners                   178,841      202,901      205,635      153,978      164,126
   Equity contributions from partners           10,330           --      205,000           --           --

Balance sheet data:
   Property, plant and equipment, net       $1,475,641   $1,516,075   $1,545,473   $1,591,755   $1,635,961
   Total assets                              1,544,691    1,604,698    1,624,988    1,691,309    1,740,037
   Long-term debt, including current
      maturities                               599,844      601,916      603,860      690,498      759,906
   Partners' equity                            875,035      914,985      967,140      802,438      809,772

Other financial data:
   Ratio of earnings to fixed charges (1)          4.0          4.5          5.0          4.3          3.8

Operating data:
   MMcf delivered                              799,301      807,531      844,963      849,920      838,736
   MMcf/d average throughput                     2,246        2,277        2,377        2,396        2,369
</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.


                                       16

<PAGE>

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

The following discussion and analysis should be read in conjunction with our
financial statements and accompanying notes included under Item 8, "Financial
Statements and Supplementary Data."

EXECUTIVE SUMMARY

OVERVIEW

We are a Texas general partnership formed in 1978. ONEOK Partners and TC
PipeLines each own a 50 percent interest in us. We provide natural gas
transportation services and are a leading transporter of natural gas imported
from Canada to the U.S.

Our operating revenue is derived from transportation of natural gas. Customers
with firm service transportation agreements pay a fee known as a reservation
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 mileage and 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 based on mileage and the volume of natural gas they transport. In 2006,
96 percent of our transportation revenue was derived from reservation charges.

Information about our business, properties and strategy can be found under Item
1, "Business," and a discussion of certain risks affecting us and our business
can be found under Item 1A, "Risk Factors."

OUR BUSINESS ENVIRONMENT

Supply

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 percent of the natural gas we transport is produced in the
Western Canada Sedimentary Basin. We estimate that our pipeline transported
approximately 20 percent of Canada's natural gas export volume in 2006. In 2006,
Canadian natural gas supplies available for export were relatively flat compared
with prior years.

Canadian natural gas export volumes may decrease in 2007 as compared to 2006.
Some industry analysts are predicting a decline in Canadian natural gas supply
available for export by as much as 1 Bcf/d, or approximately 11 percent, as
drilling activity slows and natural gas demand in Canada grows. In the fourth
quarter of 2006 it was reported that active drilling rigs declined by over 20
percent as compared to the same period in 2005. For 2007, it has been reported
that Canadian producers have made significant reductions to their capital
programs due to rising service costs and lower gas prices. Demand for natural
gas in Canada is expected to increase due to increased natural gas consumption
associated with the development and production of oil sand reserves. Increased
production of crude oil from oil sand reserves in Canada could reduce natural
gas available for export to the U.S. if oil production and the related demand
for natural gas are greater than supply growth. A reduction in the amount of
available supply for export is a negative development for all U.S. pipelines
that import natural gas from Canada, but the impact on us will depend upon
competitive factors and prevailing market conditions.

Additional Canadian natural gas supply sources for us may result in the future
if new pipeline projects associated with the Mackenzie Delta in Northern Canada
and Alaska are constructed. In addition, increased drilling and production
activity in the Powder River Basin may present opportunities for us to pursue
additional connections with this supply area.

Demand

The EIA reported that U.S. demand for natural gas in 2006 was approximately
1 percent less than 2005 levels, primarily as a result of warmer-than-average
temperatures in the first quarter of 2006. The EIA is forecasting U.S. gas
consumption to increase approximately 3 percent in 2007 from 2006 levels.
Current weather forecasts for colder winter and cooler summer months in 2007
compared with 2006 indicate increased residential and commercial natural gas
demand for heating offset by lower natural gas demand for electric generation
needed to power air conditioners in the summer.


                                       17

<PAGE>

We serve natural gas markets in the Midwestern U.S. through major interconnects
with Northern Natural Gas (NNG), the largest at Ventura, Iowa, and with
utilities in Iowa. We provide our customers with access to the Chicago market
area, which is the third largest market area hub in North America. NNG is
experiencing demand growth on its system related to new power generation and new
ethanol plant demand. NNG has a proposed pipeline expansion project that is
expected to be in service by November 2007 and will add approximately 0.4
million Dth/d of incremental capacity, which could increase demand for
transportation on our system.

Natural gas storage is essential to balance natural gas supply with
temperature-driven seasonal demand. In 2006, new storage facilities were placed
into service in Western Canada. Increased storage capacity may reduce demand for
our transportation services during certain periods of the year. The level of
price spreads between supply areas and market areas may be diminished with the
addition of storage capacity.

Competition

Supply competition from other natural gas sources can adversely impact demand
for transportation on our pipeline. Recent growth in supplies available from the
Rocky Mountain and Texas regions has reduced prices for natural gas delivered to
some of our Midwestern markets relative to other market regions. The Rockies
Express Pipeline, a proposed 1,663 mile pipeline system from Rio Blanco County,
Colorado to Monroe County, Ohio, may also increase supply competition in
Midwestern markets. The western segment of the Rockies Express Pipeline, a 713
mile pipeline from Colorado to Missouri, is anticipated to be placed in service
by 2008, and initially is expected to add more supply competition in markets
served by us. The eastern segment of the Rockies Express Pipeline, a 622 mile
pipeline from Missouri to Ohio, is expected to be placed in service by 2009, and
is anticipated to move natural gas further east, potentially mitigating any
excess supply in our market region. Also, ongoing pipeline projects to transport
growing East Texas production to markets in the eastern U.S. may reverse the
trend of this incremental production flowing into the markets we serve.

Seasonality

As more of our capacity is contracted on a short term basis, weather related
demand in various regions of the country that can be served by Western Canadian
supply, along with our market area, will have a more significant impact on us.
For example, high temperatures in the summer combined with low hydroelectric
generation capability can increase demand for Canadian natural gas in the
Western U.S. and shift supply away from our pipeline.

Effect of Rate Case

Revenues for 2007, as compared to 2006, are expected to be lower due to the
reduction of long-term rates effective January 1, 2007, pursuant to the rate
case settlement discussed under "Description of Business - Government
Regulation" in Item 1 of this report. In addition, quarterly revenues may be
more variable in 2007 due to the implementation of seasonal rates included in
the rate case settlement. In 2007, we expect to continue discounting
transportation capacity to optimize revenue.

YEAR IN REVIEW

In 2006, the trend toward shorter term contracts and discounted transportation
rates continued on our system. The weighted average life of our contracts
declined from 2.2 years at December 31, 2005 to 1.8 years at December 31, 2006.
As long-term contracts expired, the amount of available capacity to sell
increased. This resulted in the sale of more short-term contracts and a greater
amount of capacity sold at discounted rates.

In April 2006, ONEOK Partners sold a 20 percent partnership interest in us to TC
PipeLines. We amended and restated our General Partnership Agreement as a result
of this ownership interest change. In addition, we entered into an operating
agreement with TransCan. Under the new operating agreement, TransCan will become
our operator effective April 1, 2007. Further information about these
transactions can be found under Item 1, "Business."

In April 2006, the Chicago III Expansion Project went into service as planned,
adding 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. This expansion is fully subscribed by four shippers under long-term
firm service transportation agreements with terms ranging from five and one-half
to ten years and provided additional revenues of $4.0 million in 2006.


                                       18

<PAGE>

On November 21, 2006 the FERC approved the uncontested settlement of our rate
case. The settlement was reached between us and our participant customers and
was supported by the FERC trial staff. The settlement established maximum
long-term mileage-based rates and charges for transportation on our system.
Beginning in 2007, overall rates were reduced, compared with rates prior to the
filing, by approximately 5 percent. For the full transportation route from Port
of Morgan, Montana to the Chicago area, the previous charge of approximately
$0.46 per Dth is now approximately $0.44 per Dth, which is comprised of a
reservation rate, commodity rate and a compressor usage surcharge. The factors
used in calculating depreciation expense for transmission plant were increased
from 2.25 percent to 2.40 percent. The settlement also provided for seasonal
rates for short-term transportation services. Seasonal maximum rates vary on a
monthly basis from approximately $0.54 per Dth to approximately $0.29 per Dth
for the full transportation route from Port of Morgan, Montana to the Chicago
area. The settlement included a three-year moratorium on filing rate cases and
participants challenging these rates, and requires that we file a rate case
within six years.

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. Our priorities in 2007 include marketing our available
transportation capacity and actively pursuing potential pipeline projects to
access new supply areas and markets.

CRITICAL ACCOUNTING ESTIMATES

The preparation of financial statements in accordance with 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 and assumptions are reasonable, actual results could
differ from our estimates and assumptions. The following summarizes our critical
accounting estimates, which should be read in conjunction with Note 2 of the
Financial Statements.

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,
2006, we reflected regulatory assets of $19.1 million on the balance sheet.
These assets are being amortized as directed by the FERC in our current or
previous regulatory proceedings 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 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, 2006, WITH YEAR ENDED DECEMBER 31,
2005

Net income decreased $22.4 million, or 15 percent, in 2006 compared with 2005
primarily due to decreased operating revenues and increased operations and
maintenance expense.


                                       19

<PAGE>

Operating revenue decreased $10.8 million in 2006 compared with 2005 primarily
due to the following:

     -    a one-time increase in revenue in the third quarter of 2005 of $9.4
          million due to the recognition of the sale of our bankruptcy claims
          for transportation contracts and associated guarantees held against
          Enron and Enron North America; and

     -    decreased firm demand revenue and commodity charges of $5.5 million as
          a result of discounted transportation rates, transportation capacity
          that was sold for shorter transportation paths and unsold capacity;
          partially offset by

     -    additional revenue of $4.0 million from transportation contracts
          related to the Chicago III Expansion Project.

Operations and maintenance expense increased $10.0 million in 2006 compared with
2005 primarily a result of increased general and administrative expenses of $6.9
million and electric compression charges associated with the Chicago III
Expansion Project of $3.1 million. The increase to general and administrative
expenses was primarily related to increased salaries, benefits and expenses of
our operator and its affiliates attributable to our operations.

The remaining decrease in net income of $1.6 million in 2006 compared with 2005
was due to increased depreciation and amortization, taxes other than income and
interest expense and decreased net other income.

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

Net income decreased $14.5 million, or 9 percent, 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 in 2005. 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 a 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.


                                       20

<PAGE>

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 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 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 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, 2006, our outstanding borrowings under our credit
agreement were $20 million and we were in compliance with the covenants of our
agreement. The average interest rate on our credit agreement at December 31,
2006 was 6.33 percent.

EQUITY CONTRIBUTIONS

We received equity contributions from our partners of $10.3 million during the
first quarter of 2006 to fund approximately 50 percent of the Chicago III
Expansion Project capital costs. 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.

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
percent, 7.75 percent and 7.50 percent, 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. We
anticipate expanding our capacity under our credit agreement and utilizing
borrowings under this agreement as well as equity contributions from our
partners to


                                       21

<PAGE>

repay our senior notes due May 1, 2007. At December 31, 2006, the aggregate fair
value of our senior notes was approximately $623 million. In 2006, 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 $185.3 million in 2006 compared with
$206.5 million in 2005. The net decrease to cash provided by operating
activities was primarily due to the following:

     -    cash received in 2005 of $11.1 million related to our Enron and Enron
          North America bankruptcy claims;

     -    increased cash paid to our operator of $7.5 million for
          administrative, operating and management services;

     -    increased expenditures to support our 2005 rate case of $0.7 million;

     -    increased cash paid for interest of $1.1 million; and

     -    decreased cash received from customers of $1.9 million as a result of
          decreased operating revenues.

Cash provided by operating activities was $206.5 million in 2005 compared with
$206.1 million in 2004. In 2005, net cash inflows increased as a result of the
following:

     -    cash received of $11.1 million related to our Enron and Enron North
          America bankruptcy claims in 2005;

     -    decreased cash received from customers of $16.0 million in 2005 as a
          result of decreased operating revenues;

     -    increased cash paid for interest of $3.0 million; 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.


INVESTING ACTIVITIES

We fund our investing activities primarily with operating cash, borrowings under
our credit facilities and equity contributions from our partners. In 2006, 2005
and 2004, capital expenditures for maintenance of existing facilities and growth
projects were as follows:

<TABLE>
<CAPTION>
CAPITAL EXPENDITURES    2006    2005    2004
--------------------   -----   -----   -----
                           (In millions)
<S>                    <C>     <C>     <C>
Maintenance            $10.4   $18.3   $12.6
Growth                  10.5    10.3    (2.0)
                       -----   -----   -----
   Total               $20.9   $28.6   $10.6
</TABLE>

Maintenance capital expenditures decreased $7.9 million in 2006 compared with
2005 due to a decrease in expenditures related to compressor station overhauls.
Growth expenditures in 2006 and 2005 were primarily related to spending for the
Chicago III Expansion project.

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 used in financing activities was $175.5 million in 2006 compared with
$176.2 million in 2005. We received equity contributions of $10.3 million in
2006 to fund approximately 50 percent of our expenditures for the Chicago III
Expansion Project. Distributions to partners, which are calculated using
operating results from the preceding quarter, decreased $24.1 million, primarily
due to lower net income. In 2006, our net payments of debt were $7.0 million
compared with net borrowings of $27.0 million in 2005.


                                       22

<PAGE>

Cash used in 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, a $2.7 million decrease from distributions paid in 2004.

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.

CAPITAL EXPENDITURES

In 2007, we expect to invest approximately $13 million for maintenance capital
expenditures. Our capital expenditure estimate includes renewals and
replacements of existing facilities. No significant growth capital expenditures
are planned for 2007.

COMMITMENTS

CONTRACTUAL OBLIGATIONS

Our contractual obligations related to debt, operating leases and other
long-term obligations as of December 31, 2006, included the following:

<TABLE>
<CAPTION>
                                                     PAYMENTS DUE BY PERIOD
                                   ----------------------------------------------------------
                                                LESS THAN                           MORE THAN
                                      TOTAL       1 YEAR    1-3 YEARS   4-5 YEARS    5 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                       20,000      20,000          --         --           --
Interest payments on debt             320,681      37,506      63,595     37,549      182,031
Operating leases                       74,568       2,511       5,022      4,075       62,960
Other long-term obligations             5,200       1,040       2,080      2,080           --
                                   ----------    --------    --------    -------     --------
   Total contractual obligations   $1,020,449    $211,057    $270,697    $43,704     $494,991
                                   ==========    ========    ========    =======     ========
</TABLE>

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

Other - We are required to make future payments of approximately $1.0 million
per year for five years under a transition services agreement between ONEOK
Partners GP and TransCan for previously agreed to obligations related to the
reimbursement for shared equipment and furnishings acquired by ONEOK Partners
and previously used to support our operations. Information about the transition
services agreement and transition related costs can be found under Item 13,
"Certain Relationships and Related Transactions, and Director Independence."

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 a
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.

Our Management Committee changed our cash distribution policy effective in
January 2004 to distribute 100 percent 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
percent partnership interest, our Management Committee


                                       23

<PAGE>

adopted certain changes to our cash distribution policy related to financial
ratio targets and capital contributions. The change was to define minimum equity
to total capitalization ratios to be used by the Management Committee to
establish the timing and amount of required capital contributions. In addition,
any shortfall due to the inability to refinance maturing debt will be funded by
capital contributions.

On February 1, 2007, a cash distribution of approximately $44.4 million was
declared and paid for the fourth quarter of 2006.

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. On November 21, 2006 the FERC
approved the uncontested settlement of our rate case. 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

In September 2006, the FASB issued SFAS No. 157, "Fair Value Measurements" (SFAS
No. 157), which establishes a framework for measuring fair value and requires
additional disclosures about fair value measurements. SFAS No. 157 is effective
for our fiscal year beginning January 1, 2008. We are currently reviewing the
applicability of SFAS No. 157 to our results of operations and financial
position.

In September 2006, the SEC staff issued SAB Topic 1N, "Financial Statements -
Considering the Effects of Prior Year Misstatements When Quantifying
Misstatements in Current Year Financial Statements" (SAB No. 108), which
addresses how to quantify the effect of an error on the financial statements.
SAB No. 108 was effective for our fiscal year ended December 31, 2006. The
adoption of SAB No. 108 did not have a material impact on our results of
operations or financial position.

In December 2004, the FASB issued SFAS No. 123R, "Share-Based Payment" (SFAS No.
123R), which requires companies to expense the fair value of share-based
payments and includes changes related to the expense calculation for share-based
payments. ONEOK Partners GP adopted SFAS No. 123R as of January 1, 2006, and
charges us for our proportionate share of the expense recorded by ONEOK Partners
GP. The adoption of SFAS No. 123R by ONEOK Partners GP did not have a material
impact on our results of operations or financial position.

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
contemplated 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


                                       24

<PAGE>

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

     -    performance of contractual obligations by our customers;

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

     -    developments in pending FERC proceedings that impact pipelines'
          ability to recover income taxes in their rates;

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

     -    our 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 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 could
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 do not own the
gas that we transport, and therefore we do not assume the related natural gas
commodity risk.

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


                                       25

<PAGE>

million that we entered into in May 2002. As of December 31, 2006, 97 percent of
our outstanding debt was at fixed rates and there were no interest rate swap
agreements outstanding. In 2007, we expect our variable-rate debt will increase
as we plan to expand our capacity under our credit agreement and utilize
borrowings under this agreement to partially fund the repayment of fixed-rate
debt of $150 million due May 1, 2007.

If interest rates hypothetically increased 1 percent compared with rates in
effect as of December 31, 2006, our annual interest expense would increase and
our net income would decrease by approximately $0.2 million.


                                       26

<PAGE>

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

             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, 2006 and 2005, 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, 2006.
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, 2006 and 2005, and the results of its operations and
its cash flows for each of the years in the three-year period ended December 31,
2006, in conformity with U.S. generally accepted accounting principles.

/s/ KPMG LLP

Omaha, Nebraska
February 27, 2007


                                       27
<PAGE>

NORTHERN BORDER PIPELINE COMPANY
BALANCE SHEETS

<TABLE>
<CAPTION>
                                                               DECEMBER 31,
                                                         -----------------------
                                                            2006         2005
                                                         ----------   ----------
                                                              (In thousands)
<S>                                                      <C>          <C>
ASSETS
Current assets:
   Cash and cash equivalents                             $   10,997   $   22,039
   Accounts receivable                                       30,073       38,252
   Related party receivables                                    355        2,294
   Materials and supplies, at cost                            3,970        3,566
   Prepaid expenses and other                                 1,118        1,540
                                                         ----------   ----------
      Total current assets                                   46,513       67,691
                                                         ----------   ----------
Property, plant and equipment:
   In service natural gas transmission plant              2,488,765    2,463,555
   Construction work in progress                              2,522       13,260
                                                         ----------   ----------
   Total property, plant and equipment                    2,491,287    2,476,815
   Less: Accumulated provision for depreciation and
      amortization                                        1,015,646      960,740
                                                         ----------   ----------
      Property, plant and equipment, net                  1,475,641    1,516,075
                                                         ----------   ----------
Other assets:
   Regulatory assets (Note 2)                                19,144       17,422
   Unamortized debt expense                                   3,284        3,434
   Other                                                        109           76
                                                         ----------   ----------
      Total other assets                                     22,537       20,932
                                                         ----------   ----------
         Total assets                                    $1,544,691   $1,604,698
                                                         ==========   ==========
LIABILITIES AND PARTNERS' EQUITY
Current liabilities:
   Current maturities of long-term debt (Note 7)         $  150,000   $       --
   Notes payable (Note 6)                                    20,000       27,000
   Accounts payable                                           4,577       10,550
   Related party payables                                     2,539        3,555
   Accrued taxes other than income                           27,571       27,637
   Accrued interest                                          11,515       11,525
   Other                                                      1,511        2,755
                                                         ----------   ----------
      Total current liabilities                             217,713       83,022
                                                         ----------   ----------
Long-term debt, net of current maturities (Note 7)          449,844      601,916
                                                         ----------   ----------
Reserves and deferred credits                                 2,099        4,775
                                                         ----------   ----------
Commitments and contingencies (Note 9)
Partners' equity:
   Partners' capital                                        874,057      912,723
   Accumulated other comprehensive income                       978        2,262
                                                         ----------   ----------
      Total partners' equity                                875,035      914,985
                                                         ----------   ----------
         Total liabilities and partners' equity          $1,544,691   $1,604,698
                                                         ==========   ==========
</TABLE>

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


                                       28

<PAGE>

NORTHERN BORDER PIPELINE COMPANY
STATEMENTS OF INCOME

<TABLE>
<CAPTION>
                                                         YEARS ENDED DECEMBER 31,
                                                      ------------------------------
                                                        2006       2005       2004
                                                      --------   --------   --------
                                                              (In thousands)
<S>                                                   <C>        <C>        <C>
Operating revenue                                     $310,900   $321,651   $329,115
                                                      --------   --------   --------
Operating expenses
   Operations and maintenance                           49,500     39,506     33,763
   Depreciation and amortization                        58,721     58,052     58,375
   Taxes other than income                              31,541     31,345     29,368
                                                      --------   --------   --------
      Operating expenses                               139,762    128,903    121,506
                                                      --------   --------   --------
Operating income                                       171,138    192,748    207,609
                                                      --------   --------   --------
Interest expense
   Interest expense                                     43,218     42,792     41,374
   Interest expense capitalized                           (137)      (157)       (18)
                                                      --------   --------   --------
      Interest expense, net                             43,081     42,635     41,356
                                                      --------   --------   --------
Other income (expense)
   Allowance for equity funds used during
      construction                                         192        269         31
   Other income (Note 12)                                2,218      2,396      2,552
   Other expense (Note 12)                                (622)      (532)    (2,059)
                                                      --------   --------   --------
      Other income, net                                  1,788      2,133        524
                                                      --------   --------   --------
Net income to partners                                $129,845   $152,246   $166,777
                                                      ========   ========   ========
</TABLE>

NORTHERN BORDER PIPELINE COMPANY
STATEMENTS OF COMPREHENSIVE INCOME

<TABLE>
<CAPTION>
                                                         YEARS ENDED DECEMBER 31,
                                                      ------------------------------
                                                        2006       2005       2004
                                                      --------   --------   --------
                                                              (In thousands)
<S>                                                   <C>        <C>        <C>
Net income to partners                                $129,845   $152,246   $166,777
Other comprehensive income:
   Changes associated with current period hedging
      transactions                                      (1,284)    (1,500)    (1,440)
                                                      --------   --------   --------
Total comprehensive income                            $128,561   $150,746   $165,337
                                                      ========   ========   ========
</TABLE>

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


                                       29

<PAGE>

NORTHERN BORDER PIPELINE COMPANY
STATEMENTS OF CASH FLOWS

<TABLE>
<CAPTION>
                                                           YEARS ENDED DECEMBER 31,
                                                      ---------------------------------
                                                         2006        2005        2004
                                                      ---------   ---------   ---------
                                                                (In thousands)
<S>                                                   <C>         <C>         <C>
CASH FLOW FROM OPERATING ACTIVITIES
   Net income to partners                             $ 129,845   $ 152,246   $ 166,777
                                                      ---------   ---------   ---------
   Adjustments to reconcile net income to partners
      to net cash provided by operating activities:
      Depreciation and amortization                      59,325      58,404      58,740
      Allowance for equity funds used during
         construction                                      (192)       (269)        (31)
      Changes in components of working capital            1,827        (127)    (12,611)
      Other                                              (5,479)     (3,793)     (6,726)
                                                      ---------   ---------   ---------
         Total adjustments                               55,481      54,215      39,372
                                                      ---------   ---------   ---------
      Net cash provided by operating activities         185,326     206,461     206,149
                                                      ---------   ---------   ---------
CASH FLOW FROM INVESTING ACTIVITIES
   Capital expenditures for property, plant and
      equipment, net                                    (20,857)    (28,555)    (10,569)
                                                      ---------   ---------   ---------
CASH FLOW FROM FINANCING ACTIVITIES
   Equity contributions from partners                    10,330          --     205,000
   Distributions to partners                           (178,841)   (202,901)   (205,635)
   Issuance of debt                                     105,000     136,000     107,000
   Retirement of debt                                  (112,000)   (109,000)   (313,000)
   Proceeds upon termination of derivatives                  --          --       7,575
   Debt reacquisition costs                                  --          --      (4,897)
   Long-term debt financing costs                            --        (321)         --
                                                      ---------   ---------   ---------
      Net cash used in financing activities            (175,511)   (176,222)   (203,957)
                                                      ---------   ---------   ---------
Net change in cash and cash equivalents                 (11,042)      1,684      (8,377)
Cash and cash equivalents at beginning of year           22,039      20,355      28,732
                                                      ---------   ---------   ---------
Cash and cash equivalents at end of year              $  10,997   $  22,039   $  20,355
                                                      =========   =========   =========
Supplemental disclosures for cash flow information:
Cash paid for interest, net of amount capitalized     $  45,170   $  44,067   $  41,098
                                                      =========   =========   =========
Changes in components of working capital:
   Accounts receivable and related party
      receivables                                     $  10,118   $  (6,677)  $  (2,969)
   Materials and supplies                                  (404)       (157)        697
   Prepaid expenses and other                               422         149         578
   Accounts payable and other current liabilities        (8,233)      5,874      (9,731)
   Accrued taxes other than income                          (66)        524      (1,834)
   Accrued interest                                         (10)        160         648
                                                      ---------   ---------   ---------
      Total                                           $   1,827   $    (127)  $ (12,611)
                                                      =========   =========   =========
</TABLE>

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


                                       30

<PAGE>

NORTHERN BORDER PIPELINE COMPANY
STATEMENTS OF CHANGES IN PARTNERS' EQUITY

<TABLE>
<CAPTION>
                                                               ONEOK
                                            TC PIPELINES     PARTNERS      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, 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
   Net income to partners                       57,452         72,393             --        129,845
   Changes associated with current period
      hedging transactions                          --             --         (1,284)        (1,284)
   Equity contributions received                 3,099          7,231             --         10,330
   Distributions paid                          (80,420)       (98,421)            --       (178,841)
   Ownership change                            183,080       (183,080)            --             --
                                              --------      ---------        -------      ---------
Partners' equity at December 31, 2006         $437,029      $ 437,028        $   978      $ 875,035
                                              ========      =========        =======      =========
</TABLE>

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


                                       31
<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. 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.
In April 2006, ONEOK Partners completed the sale of a 20 percent partnership
interest in us to TC PipeLines. ONEOK Partners and TC PipeLines each own a 50
percent interest in us. As a result of the transaction, our General Partnership
Agreement was amended and restated effective April 6, 2006.

The ownership percentages of our partners at December 31, 2006 and 2005 are as
follows:

<TABLE>
<CAPTION>
                   OWNERSHIP AND
                 VOTING PERCENTAGE
                 -----------------
PARTNER            2006      2005
-------          -------   -------
<S>              <C>       <C>
ONEOK Partners     50%       70%
TC PipeLines       50%       30%
</TABLE>

We are managed by a Management Committee that consists of four members. Each
partner designates two members, and TC PipeLines designates one of its members
as chairman. The Management Committee designates the members of the Audit
Committee, which consists of three members. One member is selected by the
members of the Management Committee designated by the partner whose affiliate is
the operator and two members are selected by the members of the Management
Committee designated by the other partner.

The day-to-day management of our affairs is the responsibility of ONEOK Partners
GP until March 31, 2007, pursuant to an operating agreement between us and ONEOK
Partners GP. ONEOK Partners GP also utilizes ONEOK and its affiliates for
management services related to us. We are charged for the salaries, benefits and
expenses of ONEOK Partners GP, ONEOK and its affiliates attributable to our
operations. For the years ended December 31, 2006, 2005, and 2004, our charges
from ONEOK Partners GP and its current and former affiliates totaled
approximately $26.2 million, $20.1 million and $18.3 million, respectively.
Effective April 1, 2007, TransCan will become our operator under a new operating
agreement.

See Note 13 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 GAAP requires
management to make assumptions and use estimates that affect the reported
amounts of assets, 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 FERC. Our accounting policies conform to
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 sheets as regulatory assets.

At December 31, 2006 and 2005, we have reflected regulatory assets of
approximately $19.1 million and $17.4 million, respectively, on the balance
sheets. These assets are being amortized as directed by the FERC in our current
or previous regulatory proceedings over varying time periods up to 44 years.


                                       32

<PAGE>

The following table presents a summary of regulatory assets, net of
amortization, at December 31, 2006, and 2005.

<TABLE>
<CAPTION>
                                         DECEMBER 31,
                                      -----------------
                                        2006      2005
                                      -------   -------
                                        (In thousands)
<S>                                   <C>       <C>
Fort Peck lease option                $ 9,507   $ 7,971
Pipeline extension project              6,920     7,106
Unamortized loss on reacquired debt       376     1,503
Deferred rate case expenditures         2,341       842
                                      -------   -------
   Total regulatory assets            $19,144   $17,422
                                      =======   =======
</TABLE>

We continually assess the potential recovery of our regulatory assets 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 maximum rates we may charge 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
reservation charge regardless of whether they actually utilize their reserved
capacity. Firm service transportation customers also pay a fee known as a
commodity charge that is based on the mileage and 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 based on mileage and the volume of natural gas they transport. An
allowance for doubtful accounts is recorded in situations where collectibility
is not reasonably assured. We had no allowance for doubtful accounts at December
31, 2006 and 2005. 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. Our FERC tariff, through December 31, 2006,
established the method of accounting for and calculating 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 Partners' capital for
regulatory accounting purposes, it is reduced by the amount equivalent to the
net accumulated deferred income taxes. Such amounts were approximately $365
million and $360 million at December 31, 2006, and 2005, respectively, and are
primarily related to accelerated depreciation and other plant-related
differences. Pursuant to the terms of the settlement of our 2005 rate case,
during the time period that the rates effective January 1, 2007 are in effect,
the treatment historically accorded deferred income taxes will be observed by us
for regulatory accounting purposes.

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 or systems.


                                       33

<PAGE>

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 was 2.25 percent for 2004, 2005, and 2006. Composite rates
are applied to all other functional groups of property having similar economic
characteristics. See Note 4 for changes to our depreciation rate effective
January 1, 2007.

NATURAL GAS IMBALANCES

Natural gas imbalances occur when the actual amount of natural gas delivered or
received by a pipeline system or storage facility differs from the contractual
amount of natural gas scheduled 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 sheets as accounts
receivable. Imbalances owed to others are reported on the balance sheets as
accounts payable. 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 sheets 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 8 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 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.

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. These reclassifications did
not impact previously reported net income or partners' equity.


                                       34

<PAGE>

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 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 of natural gas 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 1999 rate case, on
November 1, 2005 we filed a rate case with the FERC. In December 2005, the FERC
issued an order that identified issues that were raised in the proceeding and
accepted the proposed rates, but suspended their effectiveness until May 1,
2006. Beginning May 1, 2006, the new rates were collected subject to refund
through September 30, 2006. Based on the settlement, discussed below, we
refunded $10.8 million to our customers in the fourth quarter of 2006.

On September 18, 2006, we filed a stipulation and agreement which documented the
settlement reached between us and our participant customers and supported by the
FERC trial staff. The uncontested settlement was approved by the FERC on
November 21, 2006.

The settlement established maximum long-term mileage-based rates and charges for
transportation on our system. Beginning in 2007, overall rates were reduced,
compared with rates prior to the filing, by approximately 5 percent. For the
full transportation route from Port of Morgan, Montana to the Chicago area, the
previous charge of approximately $0.46 per Dth is now approximately $0.44 per
Dth, which is comprised of a reservation rate, commodity rate and a compressor
usage surcharge. The factors used in calculating depreciation expense for
transmission plant were increased from 2.25 percent to 2.40 percent. The
settlement also provided for seasonal rates for short-term transportation
services. Seasonal maximum rates vary on a monthly basis from approximately
$0.54 per Dth to approximately $0.29 per Dth for the full transportation route
from Port of Morgan, Montana to the Chicago area. The settlement included a
three-year moratorium on filing rate cases and participants challenging these
rates, and requires that we file a rate case within six years.

5. TRANSPORTATION SERVICE AGREEMENTS

Operating revenues are collected pursuant to the FERC tariff through
transportation service agreements. Our firm service agreements at December 31,
2006, extend for various terms with termination dates that range from December
2006 to May 2016. 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 under firm contracts
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, 2006, our largest shippers, Nexen Marketing, U.S.A. Inc.
(Nexen), BP Canada Energy Marketing Corp. (BP Canada) and Cargill Inc. (Cargill)
were obligated for approximately 16 percent, 16 percent and 14 percent


                                       35

<PAGE>

of design capacity, respectively. The Nexen, BP Canada and Cargill firm service
agreements extend for various terms with termination dates ranging from December
2006 to December 2013, December 2006 to April 2014 and February 2007 to December
2008, respectively.

For the year ended December 31, 2006, shippers providing significant operating
revenues were BP Canada and Cargill with revenues of $66.7 million and $43.0
million, respectively. For the year ended December 31, 2005, shippers providing
significant operating revenues were BP Canada, Nexen, EnCana Marketing (USA)
Inc. (EnCana) and 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.

At December 31, 2006, 2005 and 2004, we had contracted firm capacity held by one
shipper affiliated with one of our general partners. ONEOK Energy, a subsidiary
of ONEOK, holds firm service agreements representing approximately 1 percent of
design capacity at December 31, 2006. The firm service agreements with ONEOK
Energy extend for various terms with termination dates that range from March
2007 to November 2011. ONEOK Energy became affiliated with us on November 17,
2004 in connection with ONEOK's purchase of ONEOK Partners GP. Revenue from
ONEOK Energy for 2006, 2005 and the period from the date of affiliation to
December 31, 2004 was $7.0 million, $7.7 million and $1.1 million, respectively.
At December 31, 2006 and 2005, we had outstanding receivables from ONEOK Energy
of $0.3 million and $0.9 million, respectively.

6. CREDIT FACILITIES

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 agreement
(the 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 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. At December 31, 2006 and 2005,
amounts outstanding under the 2005 Pipeline Credit Agreement were $20 million at
an interest rate of 6.33 percent and $27 million at an interest rate of 5.11
percent, respectively. Borrowings under the 2005 Pipeline Credit Agreement are
included in notes payable on the balance sheets.

Under the 2005 Pipeline Credit Agreement, we are required to comply with certain
financial, operational and legal covenants. The 2005 Pipeline Credit Agreement
requires the maintenance of a ratio of EBITDA to interest expense of greater
than 3 to 1. It 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, 2006, we were in compliance with our financial
covenants.


                                       36

<PAGE>

7. LONG-TERM DEBT

Detailed information on long-term debt is as follows:

<TABLE>
<CAPTION>
                                                   DECEMBER 31,
                                               --------------------
                                                  2006       2005
                                               ---------   --------
                                                  (In thousands)
<S>                                            <C>         <C>
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 (discount) premium                 (156)     1,916
Current maturities                              (150,000)        --
                                               ---------   --------
   Long-term debt                              $ 449,844   $601,916
                                               =========   ========
</TABLE>

On December 1, 2004, we redeemed $75 million of the 6.25 percent Senior Notes
due 2007 (the 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 8). 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, 2006, 2005 and 2004, we amortized approximately $1.1 million, $1.1
million and $0.1 million, respectively, to interest expense. At December 31,
2006, and 2005, the net unamortized loss on reacquired debt was $0.4 million and
$1.5 million, respectively, which is recorded in regulatory assets on the
balance sheets.

Aggregate required repayments of long-term debt for the next five years are $150
million in 2007 and $200 million in 2009. Aggregate required repayments of
long-term debt thereafter total $250 million. There are no required repayment
obligations for 2008, 2010 or 2011. We anticipate expanding the capacity of the
2005 Pipeline Credit Agreement and utilizing borrowings under this agreement as
well as equity contributions from our partners to repay our senior notes due May
1, 2007.

Certain of our long-term debt 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 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 $623 million and $637 million at
December 31, 2006, and 2005, 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 the 2005
Pipeline Credit Agreement (Note 6) approximates the carrying value since the
interest rates are periodically adjusted to reflect current market conditions.

8. 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 hedged 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.

During the years ended December 31, 2006, 2005, and 2004, respectively, we
amortized approximately $1.3 million, $1.5 million, and $1.4 million related to
the terminated interest rate swap agreements as a reduction to interest


                                       37

<PAGE>

expense from accumulated other comprehensive income. We expect to amortize
approximately $1.6 million as a reduction to interest expense in 2007.

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 7). 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, 2006, 2005,
and 2004, we amortized approximately $2.1 million, $2.1 million and $0.2
million, respectively, as a reduction to interest expense. We expect to amortize
approximately $0.7 million as a reduction of interest expense in 2007 for these
agreements.

9. 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>
                           (In thousands)
                           --------------
<S>                        <C>
Year ending December 31,
   2007                       $ 2,511
   2008                         2,511
   2009                         2,511
   2010                         2,186
   2011                         1,889
   Thereafter                  62,960
                              -------
                              $74,568
                              =======
</TABLE>

Expenses incurred related to these lease obligations for the years ended
December 31, 2006, 2005 and 2004 were $0.7 million, $0.6 million, and $0.6
million, respectively.

TRANSITION RELATED COSTS

ONEOK Partners GP and TransCan entered into a transition services agreement for
the transfer of the operator responsibilities effective April 1, 2007. As a part
of the agreement, we will pay ONEOK Partners an amount of approximately $1.0
million per year for five years for previously agreed to obligations related to
the reimbursement for shared equipment and furnishings acquired by ONEOK
Partners and previously used to support our operations. In addition, we
agreed to transfer certain identified assets of immaterial value to ONEOK
Partners at either no cost or net book value as defined in the agreement.

ENVIRONMENTAL MATTERS

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

OTHER

On July 31, 2001, the Assiniboine and Sioux Tribes of the Fort Peck Indian
Reservation (the 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 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 regulatory assets on the balance sheets.


                                       38

<PAGE>

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.

10. 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 2004 and $90 million in 2007; (ii) fund future growth
capital expenditures with 50 percent equity capital contributions from our
partners; and (iii) change our cash distribution policy. Effective January 1,
2004, cash distributions are equal to 100 percent 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. Upon closing the sale of the 20 percent partnership
interest by ONEOK Partners to TC Pipelines, our Management Committee adopted
certain changes to our cash distribution policy related to financial ratio
targets and capital contributions. The change was to define minimum equity to
total capitalization ratios to be used by the Management Committee to establish
the timing and amount of required capital contributions. In addition, any
shortfall due to the inability to refinance maturing debt will be funded by
capital contributions.

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.

11. QUARTERLY FINANCIAL DATA (Unaudited)

<TABLE>
<CAPTION>
                                            NET
                 OPERATING   OPERATING   INCOME TO
                  REVENUE      INCOME     PARTNERS
                 ---------   ---------   ---------
                             (In thousands)
<S>              <C>         <C>         <C>
2006
First Quarter     $79,827     $47,697     $37,353
Second Quarter     71,441      35,996      25,406
Third Quarter      80,267      43,683      33,682
Fourth Quarter     79,365      43,762      33,404

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
</TABLE>


                                       39
<PAGE>

12. 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, 2006, 2005 and 2004,
other income (expense) included:

<TABLE>
<CAPTION>
                                        YEARS ENDED DECEMBER 31,
                                       -------------------------
                                        2006     2005      2004
                                       ------   ------   -------
                                            (In thousands)
<S>                                    <C>      <C>      <C>
Other income
   Investment income                   $1,086   $1,134   $ 1,111
   Nonoperating revenue                   627      487       329
   Interconnects constructed              126      164       681
   Bad debt expense adjustment             --      408        --
   Other                                  379      203       431
                                       ------   ------   -------
      Other income                     $2,218   $2,396   $ 2,552
                                       ======   ======   =======
Other expense
   Depreciation and amortization for
      non-regulated property           $ (604)  $ (351)  $  (351)
   Reserves                                --      (28)     (645)
   Bad debt expense                        --      (78)     (522)
   Other                                  (18)     (75)     (541)
                                       ------   ------   -------
      Other expense                    $ (622)  $ (532)  $(2,059)
                                       ======   ======   =======
</TABLE>

13. 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. ONEOK
Partners GP was affiliated with Enron until November 2004.

Enron North America, a wholly owned subsidiary of Enron in bankruptcy, was a
party to transportation contracts, which obligated Enron North America to pay
for 3.5 percent of our capacity. Enron had also guaranteed these obligations to
us. In 2002, we had fully reserved for amounts invoiced to Enron North America.
We filed claims in the bankruptcy proceedings and 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 sold our settled bankruptcy claims
to a third party. 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.

Under the operating agreement with ONEOK Partners GP, termination costs related
to Enron Corp.'s Cash Balance Plan could have been Northern Border Pipeline's
responsibility. As of December 31, 2003, we accrued $3.1 million, an amount
estimated as our responsibility under our operating agreement for reimbursement
of a proportionate share of termination costs for certain Enron defined benefit
plans. In 2004, we were advised that no claim for reimbursement of the
termination costs would be made, resulting in an adjustment in reserves during
2004 of $3.1 million for the termination costs.

14. ACCOUNTING PRONOUNCEMENTS

In September 2006, the FASB issued SFAS No. 157, "Fair Value Measurements" (SFAS
No. 157), which establishes a framework for measuring fair value and requires
additional disclosures about fair value measurements. SFAS No. 157 is effective
for our fiscal year beginning January 1, 2008. We are currently reviewing the
applicability of SFAS No. 157 to our results of operations and financial
position.


                                       40

<PAGE>

In September 2006, the SEC staff issued SAB Topic 1N, "Financial Statements -
Considering the Effects of Prior Year Misstatements When Quantifying
Misstatements in Current Year Financial Statements" (SAB No. 108), which
addresses how to quantify the effect of an error on the financial statements.
SAB No. 108 was effective for our fiscal year ended December 31, 2006. The
adoption of SAB No. 108 did not have a material impact on our results of
operations or financial position.

In December 2004, the FASB issued SFAS No. 123R, "Share-Based Payment" (SFAS No.
123R), which requires companies to expense the fair value of share-based
payments and includes changes related to the expense calculation for share-based
payments. ONEOK Partners GP adopted SFAS No. 123R as of January 1, 2006, and
charges us for our proportionate share of the expense recorded by ONEOK Partners
GP. The adoption of SFAS No. 123R by ONEOK Partners GP did not have a material
impact on our results of operations or financial position.

15. SUBSEQUENT EVENTS

We make distributions to our general partners approximately one month following
the end of the quarter. A cash distribution of approximately $44.4 million was
declared and paid on February 1, 2007 for the fourth quarter of 2006.


                                       41

<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, 2006 and 2005 and for each of the years in the three-year period
ended December 31, 2006 included in this Form 10-K, and have issued our report
thereon dated February 27, 2007.

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
February 27, 2007


                                       42

<PAGE>

NORTHERN BORDER PIPELINE COMPANY
SCHEDULEII - 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>
Reserves:
   2006                      $  630        $ --        $10,787        $10,787          $  630
   2005                       1,955          25             --          1,350             630
   2004                       6,315         640             --          5,000           1,955
Allowance for doubtful
   accounts:
   2006                      $   --        $ --        $    --        $    --          $   --
   2005                       4,208         171             --          4,379              --
   2004                       4,815         523             --          1,130           4,208
</TABLE>

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

None.

ITEM 9A. CONTROLS AND PROCEDURES

EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES - As of the end of the period
covered by this report, the officers of ONEOK Partners GP, who are the
equivalent of our principal executive officer and principal financial officer,
evaluated the effectiveness of our disclosure controls and procedures as defined
in Rules 13a-15(e) and 15d-15(e) of the Exchange Act. Based on their evaluation,
they concluded that as of December 31, 2006, our disclosure controls and
procedures were effective in ensuring that the information required to be
disclosed by us in the reports that we file or submit under the Exchange Act is
recorded, processed, summarized and reported within the time periods specified
in the SEC's rules and forms and that information required to be disclosed by us
in the reports that we file or submit under the Exchange Act is accumulated and
communicated to the management of ONEOK Partners GP, including the officers of
ONEOK Partners GP who are the equivalent of our principal executive and
principal financial officers, as appropriate to allow timely decisions regarding
required disclosure.

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.

BILLING SYSTEM MODIFICATIONS - In May 2006, we implemented system modifications
to meet new transaction billing requirements in conjunction with our recently
concluded rate case, which caused changes to our internal control over financial
reporting during the second quarter of 2006. In anticipation of the approval of
the settlement of the rate case as filed in September 2006, we made interim
adjustments to our billing system in the fourth quarter of 2006. Upon FERC
approval of the rate case settlement in November 2006, final changes to our
billing system were completed and implemented on January 1, 2007. We do not
expect that these changes will materially affect our internal control over
financial reporting in the first quarter.

CHANGE OF OPERATOR - In connection with the change of operator from ONEOK
Partners GP to TransCan, there will be changes to certain critical business
systems, including information technology applications, third party software
licenses and computer and communication hardware, supporting our financial
accounting and reporting systems that are currently owned and operated by ONEOK.
The transfer of our operations from the systems owned and operated

                                       43

<PAGE>

by ONEOK to the systems owned and operated by TransCanada will cause changes to
our internal control over financial reporting. These changes are anticipated to
be implemented starting in the first quarter of 2007 and completed in the second
quarter of 2007.

Additionally, we continue to rely on the employees of the affiliates of ONEOK
Partners GP to facilitate the transition and provide for our day-to-day business
operations. Loss of employees providing key services that support our day-to-day
operations before our operations are transitioned to TransCan could have a
material affect on our internal control over financial reporting.

ITEM 9B. OTHER INFORMATION

None.

                                    PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

MANAGEMENT COMMITTEE

We are overseen by the Management Committee. We do not compensate members of the
Management Committee for their services. Each partner designates two members and
TC PipeLines designates one of its members as Chairman. The members serve on the
Management Committee until a partner designates a new member to replace them.

<TABLE>
<CAPTION>
        NAME           AGE          POSITION
--------------------   ---   ----------------------
<S>                    <C>   <C>
Craig R. Frew          56    Chairman
                             Audit Committee Member

William R. Cordes      58    Member

John W. Gibson         54    Member

Mark A. P. Zimmerman   42    Member
</TABLE>

Craig R. Frew was designated by TC PipeLines Intermediate as Chairman of our
Management Committee effective August 2006. He was also designated as a member
of our Audit Committee. Mr. Frew has been Vice President, U.S. Pipelines for
TransCanada since May 2006. Mr. Frew started with TransCanada in 1976 and was
first named an officer of TransCanada PipeLines in 1984. From 1994 until 2003 he
served as President, Iroquois Pipeline Operating Company, and in 2003 he was
named Vice President, Gas Transmission East for TransCanada PipeLines.

William R. Cordes was re-designated by ONEOK Partners Intermediate as a member
of our Management Committee in April 2006. Mr. Cordes has been President,
Northern Border Pipeline for ONEOK Partners GP since May 2006. Previously he was
chief executive officer of ONEOK Partners, L.P. and chairman of our Management
Committee from 2000 until April 2006. He served as chairman of the Partnership
Policy Committee of ONEOK Partners from 2000 until 2004. Mr. Cordes was
appointed president of ONEOK Partners GP and Pan Border in 2000 and president of
NBP Services, LLC 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. Mr. Cordes will retire from ONEOK Partners GP effective
April 1, 2007. Mr. Cordes is a director and member of the audit committee of
Boardwalk Pipeline Partners, L.P.

John W. Gibson was designated by ONEOK Partners Intermediate as a member of the
Management Committee effective April 2006. Mr. Gibson is president and chief
executive officer of ONEOK Partners and chief executive officer of ONEOK, Inc.
Previously, he served as the president and chief operating officer of ONEOK
Partners from May through December 2006. From 2005 until May 2006 he was
president of ONEOK Energy Companies, which included ONEOK's gathering and
processing, natural gas liquids, pipelines and storage and energy services
business


                                       44
<PAGE>

segments. He was president, Energy of ONEOK from 2000 to 2005. Mr. Gibson is
also a director of ONEOK, Inc. and ONEOK Partners.

Mark A. P. Zimmerman was designated by TC PipeLines Intermediate as a member of
our Management Committee effective August 2006. Mr. Zimmerman is president of TC
PipeLines, L.P. and has been, vice president, commercial transactions for
TransCanada since June 2006. Mr. Zimmerman started with TransCanada in September
1997 and from September 1999 to September 2003 was director, corporate
evaluation and planning for TransCanada PipeLines Ltd. From September 2003 until
June 2006 he was director, project finance for TransCanada.

OFFICERS

The following individuals, as well as Mr. Cordes, whose information is provided
above, are officers of ONEOK Partners GP who are deemed to be executive officers
of the partnership. Mr. Cordes and Mr. Peters are the equivalent of our
principal executive and principal financial officers, respectively.

<TABLE>
<CAPTION>
NAME                AGE   POSITION
----                ---   --------
<S>                 <C>   <C>
William R. Cordes    58   President - Northern Border Pipeline

Paul F. Miller       40   Vice President - Commercial

Michel E. Nelson     59   Senior Vice President - Natural Gas Pipelines

Raymond D. Neppl     62   Vice President, Regulatory Affairs and Market Services

Jerry L. Peters      49   Senior Vice President - Chief Accounting Officer

Janet K. Place       57   Vice President, Associate General Counsel, Assistant Secretary
                          and General Counsel - Northern Border Pipeline
</TABLE>

Paul F. Miller has been vice president - commercial for ONEOK Partners GP since
October 2006. He served as president, Midwestern Gas Transmission, Viking Gas
Transmission and Guardian Pipeline for ONEOK Partners GP for a portion of 2006.
From February 2005 to May 2006, he was vice president and general manager of
Northern Border Pipeline for ONEOK Partners GP. From 2002 until February 2005,
Mr. Miller was vice president of marketing for ONEOK Partners GP. Mr. Miller
previously served as account executive and director, marketing from 1998 until
2002. Mr. Miller joined ONEOK Partners GP in 1990.

Michel E. Nelson has been senior vice president - natural gas pipelines for
ONEOK Partners GP since October 2006. He served as vice president, operations
for ONEOK Partners GP from 2004 to October 2006. 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 ONEOK Partners
GP.

Raymond D. Neppl has been vice president, regulatory affairs and market
services, for ONEOK Partners GP since October 2006. Mr. Neppl was first
appointed vice president for ONEOK Partners GP in 1991. Mr. Neppl joined
Northern Natural Gas Company, formerly affiliated with ONEOK Partners GP, in
1975 and transferred to ONEOK Partners GP in 1980.

Jerry L. Peters is senior vice president -chief accounting officer for ONEOK
Partners GP. Mr. Peters has held several management positions with ONEOK
Partners GP 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 ONEOK Partners GP: 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


                                       45

<PAGE>

from November 2001 to May 2002. Prior to joining ONEOK Partners GP in 1985, Mr.
Peters was employed as a certified public accountant by KPMG LLP.

Janet K. Place is vice president, associate general counsel, assistant secretary
and general counsel - Northern Border Pipeline for ONEOK Partners GP. Ms. Place
has served as our general counsel since 1993 and as a vice president of our
operator since 1994.

MANAGEMENT CHANGES

TransCan has advised us that effective April 1, 2007, it has retained Paul F.
Miller as vice-president and general manager of TransCan and Patricia M.
Wiederholt as controller, Northern Border Pipeline for TransCan. Mr. Miller will
have overall operational and financial performance responsibility for TransCan's
operation of us and will be the equivalent of our principal executive officer.
He is currently vice president - commercial, Northern Border Pipeline for ONEOK
Partners GP. Ms. Wiederholt is currently partnership controller for ONEOK
Partners GP. As controller of Northern Border Pipeline for TransCan, Ms.
Wiederholt will be the equivalent of our principal financial officer.

Our current operating agreement with ONEOK Partners GP will terminate on March
31, 2007. As a result, William R. Cordes, president - Northern Border Pipeline
for ONEOK Partners GP, and Jerry L. Peters, senior vice president - chief
accounting officer for ONEOK Partners GP, will no longer serve as the equivalent
of our principal executive officer and principal financial officer, respectively
after March 31, 2007. Additionally, Michel E. Nelson, Raymond D. Neppl and Janet
Place will no longer be deemed executive officers of us.

AUDIT COMMITTEE

Under our partnership agreement, our Audit Committee consists of three members
appointed by the Management Committee. The Audit Committee oversees the annual
audit process and confers with KPMG LLP, our independent auditors. The members
of the Management Committee appointed by the partner whose affiliate is not the
operator appoint two of the members of our Audit Committee. TC PipeLines has
appointed Ms. Amy Leong, principal financial officer and controller of TC
PipeLines, LP, and Mr. Frew, vice president, U. S. pipelines for TransCanada, to
the Audit Committee. Ms. Caron Lawhorn, senior vice president and chief
accounting officer for ONEOK, Inc. is the ONEOK Partners designee to the Audit
Committee. The Management Committee has determined that Ms. Leong and Ms.
Lawhorn are "audit committee financial experts," as defined by the rules and
regulations of the SEC. Our Audit Committee members are not independent and are
not required to be independent because we do not have securities that are listed
on a national securities exchange or association.

CODE OF ETHICS

The Management Committee adopted an Accounting and Financial Reporting Code of
Ethics for those officers of ONEOK Partners GP 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 ONEOK Partners GP 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

COMPENSATION DISCUSSION AND ANALYSIS

We do not directly employ any of the persons responsible for managing or
operating our business. ONEOK Partners GP provides administrative, operating and
management services to us under an operating agreement. Certain officers of
ONEOK Partners GP are deemed to be executive officers of us. Please read
"Certain Relationships and Related Party Transactions, and Director
Independence--Operating Agreement" for a description of the Operating Agreement.

We do not have a compensation committee. The compensation of those officers
deemed to be officers of us is set by the Executive Compensation Committee of
the Board of Directors of ONEOK. A discussion of the objectives of, and other
matters related to, ONEOK's compensation programs is included in ONEOK's
compensation discussion


                                       46

<PAGE>

and analysis and other disclosure related to ONEOK executive compensation
contained in ONEOK's 2007 Proxy Statement as filed with the SEC (ONEOK 2007
Proxy Statement), a copy of which is provided on, and may be copied from,
ONEOK's website at www.oneok.com and is available free of charge from the
secretary of ONEOK Partners GP upon request.

Under our Operating Agreement with ONEOK Partners GP, a portion of the total
compensation expense for our named executive officers is allocated by ONEOK to
us. The compensation amounts shown in the following table are that portion of
the named executive officer's total compensation, which is allocated to and paid
by us under the Operating Agreement.

The following table summarizes the compensation allocated to and paid by us in
2006 for our principal executive officer, principal financial officer and the
three other most highly compensated executive officers of ONEOK Partners GP,
which we collectively refer to as the "named executive officers."

                 SUMMARY COMPENSATION TABLE FOR FISCAL YEAR 2006

<TABLE>
<CAPTION>
                                                                                 CHANGE IN
                                                                                  PENSION
                                                                                 VALUE AND
                                                                 NON-EQUITY    NONQUALIFIED
                                                                  INCENTIVE      DEFERRED
                                                      STOCK         PLAN       COMPENSATION     ALL OTHER
            NAME AND                       SALARY     AWARDS    COMPENSATION     EARNINGS     COMPENSATION      TOTAL
       PRINCIPAL POSITION          YEAR      ($)      ($)(1)       ($)(2)         ($)(3)         ($)(4)          ($)
       ------------------          ----   --------   --------   ------------   ------------   ------------   ----------
<S>                                <C>    <C>        <C>        <C>            <C>            <C>            <C>
William R. Cordes                  2006   $277,083   $814,876     $304,792       $148,202        $34,422     $1,579,375
   President - Northern Border
   Pipeline

Jerry L. Peters                    2006   $145,438   $111,365     $ 81,250       $ 21,267        $13,006     $  372,326
   Senior Vice President - Chief
   Accounting Officer

Paul F. Miller                     2006   $120,750   $ 80,934     $ 96,000       $ 10,795        $12,602     $  321,081
   Vice President - Commercial

Raymond D. Neppl                   2006   $113,313   $ 47,200     $ 61,189       $ 33,697        $10,503     $  265,902
   Vice President, Regulatory
   Affairs and Market Services

Janet K. Place                     2006   $140,000   $ 84,096     $ 87,500       $ 36,359        $ 9,610     $  357,565
   Vice President, General
   Counsel - Northern Border
   Pipeline
</TABLE>

----------

(1)  The amounts included in the table reflect the expense allocated to and
     recognized by us in 2006 for restricted stock, restricted stock incentive
     units, and performance units granted under the ONEOK Long-Term Incentive
     Plan ("LTI Plan") and the ONEOK Equity Compensation Plan, the value of
     which was determined in accordance with SFAS No. 123 (revised 2004),
     "Share-Based Payments" (SFAS No. 123R). Assumptions used in the calculation
     of the value of these equity grants are included in Note P to the ONEOK
     audited financial statements for the year ended December 31, 2006, included
     in the ONEOK 2006 Annual Report on Form 10-K filed with the SEC.

     Restricted stock and restricted stock incentive units vest three years from
     the date of grant. Because no shares of ONEOK common stock are issued under
     a restricted stock incentive unit until the unit vests, no dividends are
     payable with respect to restricted stock incentive units. The performance
     units vest three years from the date of grant at which time the holder is
     entitled to receive a percentage (0 percent to 200 percent in increments of
     50 percent) of the performance units granted based on ONEOK's total
     shareholder return over the performance cycle compared to the total
     shareholder return of a peer group of 20 other energy companies. Grants of
     restricted stock, restricted stock incentive units, and performance units
     made in 2006 are payable in shares of ONEOK common stock upon vesting.
     Grants of restricted stock incentive units and performance units made in
     2004 or 2005 are payable one-third in cash and two-thirds in shares upon
     vesting. The fair value of restricted stock and restricted stock incentive
     units, for the purposes of SFAS No. 123R, was determined on the date of
     grant based on the closing stock price of ONEOK common stock on the grant
     date adjusted for the current dividend yield. The fair value of performance
     units granted in 2004 and 2005 for the purposes of SFAS No. 123R was
     determined on the date of grant based on the closing stock price of ONEOK
     common stock on the grant date adjusted for the current dividend yield.
     With respect to the performance units granted in 2006, the


                                       47

<PAGE>

     fair value for the purposes of SFAS No. 123R was determined using a
     valuation model that considers the market condition (total shareholder
     return), using assumptions developed from historical information of ONEOK
     and a group of 20 peer companies of ONEOK.

(2)  Reflects the amounts allocated to and to be paid by us under the ONEOK 2006
     annual officer incentive plan. The plan provides that ONEOK officers may
     receive annual cash incentive awards based on the performance and
     profitability of ONEOK, the performance of particular business units of
     ONEOK, and individual performance. The corporate and business unit criteria
     and individual performance criteria are established annually by the
     Executive Compensation Committee of the ONEOK Board of Directors. The
     Committee also establishes annual target awards for each ONEOK officer. For
     a discussion of the performance criteria established by the ONEOK Executive
     Compensation Committee for awards under the 2006 annual officer incentive
     plan, see "Components of Compensation - Annual Cash Compensation" in the
     ONEOK 2007 Proxy Statement.

(3)  Reflects the portion of the aggregate current year change in pension values
     allocated to us for each named executive officer is based on the change of
     the present value of the benefit. The present value is based on the
     earliest age for which an unreduced benefit is available (age 62) and
     assumptions from the September 30, 2005 and 2006 financial reporting dates
     for the ONEOK pension plan. For a discussion of ONEOK's pension plan,
     please see the discussion contained in the ONEOK's 2007 Proxy Statement. In
     the Summary Compensation Table above, there were no above market earnings
     to report.

(4)  Reflects the portion allocated to us of the amounts paid as ONEOK's match
     under the ONEOK Employee Nonqualified Deferred Compensation Plan, as
     ONEOK's match under the Thrift Plan for Employees of ONEOK; and amounts
     paid as tax reimbursements for employee stock awards under the ONEOK
     Employee Stock Award Program, as follows:

<TABLE>
<CAPTION>
                               ONEOK
                           NONQUALIFIED
                             DEFERRED      MATCH UNDER   EMPLOYEE
                           COMPENSATION   ONEOK THRIFT     STOCK         TAX
       NAME         YEAR       PLAN           PLAN         AWARD    REIMBURSEMENT
       ----         ----   ------------   ------------   --------   -------------
<S>                 <C>    <C>            <C>            <C>        <C>
William R. Cordes   2006      $23,513        $10,450       $286         $173
Jerry L. Peters     2006      $ 4,079        $ 8,580       $235         $112
Paul F. Miller      2006      $ 4,365        $ 7,920       $217         $100
Raymond D. Neppl    2006      $ 2,095        $ 8,085       $221         $102
Janet K. Place      2006      $    --        $ 9,240       $253         $117
</TABLE>

     The Thrift Plan for Employees of ONEOK, Inc. is a tax qualified plan which
     covers substantially all ONEOK employees. Employee contributions are
     discretionary. Subject to certain limits, ONEOK matches employee
     contributions to the plan up to a maximum of 6 percent.

     For additional information on the ONEOK Nonqualified Deferred Compensation
     Plan, see "Long-Term Compensation Plans - Nonqualified Deferred
     Compensation Plan" in the ONEOK 2007 Proxy Statement.

     Under the ONEOK 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 of ONEOK common stock on the NYSE was for the first time
     at or above $26 per share. Nine shares were issued to each named executive
     officer under this program in 2006.

     The named executive officers did not receive perquisites or other personal
     benefits with an aggregate value of $10,000 or more.


                                       48
<PAGE>

POTENTIAL POST-EMPLOYMENT PAYMENTS AND PAYMENTS UPON A CHANGE IN CONTROL

SEVERANCE PLANS

     ONEOK Partners GP Severance Pay Plan provides for the payment of benefits
to employees who are terminated due to reorganization or similar business
circumstances. There are no severance benefits for performance related
terminations. For those terminated as the result of reorganization or similar
business circumstances, the benefit is based on length of service and amount of
pay with a minimum benefit of eight weeks of base 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.

     Mr. Cordes, Mr. Neppl and Ms. Place will retire as of April 1, 2007. They
will each receive an additional payment, and the amount that will be allocated
to us related to this additional payment is $157,500, $32,500, and $52,500,
respectively.

PAYMENTS MADE UPON ANY TERMINATION

     Regardless of the manner in which a named executive officer's employment
terminates, he is entitled to receive amounts earned during his term of
employment. Such amounts include:

     -    accrued but unpaid salary;

     -    amounts contributed under the ONEOK Thrift Plan and the ONEOK Employee
          Nonqualified Deferred Compensation Plan; and

     -    amounts accrued and vested through the ONEOK retirement plan and
          supplemental executive retirement plan (SERP).

PAYMENTS MADE UPON RETIREMENT

     In the event of the retirement of a named executive officer, in addition to
the items identified above, such named executive officer will:

     -    be entitled to receive a prorated portion of each outstanding
          performance unit granted under the ONEOK LTI Plan and Equity
          Compensation Plan upon the completion of the performance cycle;

     -    be entitled to receive a prorated portion of each outstanding
          restricted stock incentive unit granted under the ONEOK LTI Plan and
          Equity Compensation Plan upon completion of the restricted cycle;

     -    if eligible, continue to receive ONEOK health and welfare benefits and
          receive ONEOK health and welfare benefits for his dependents, as
          applicable; and

     -    if eligible, continue to receive ONEOK life insurance benefits until
          death.

PAYMENTS MADE UPON DEATH OR DISABILITY

     In the event of the death or disability of a named executive officer, in
addition to the benefits listed under the headings "Payments Made Upon Any
Termination" and "Payments Made Upon Retirement" above, the named executive
officer will receive benefits under ONEOK's disability plan or payments under
ONEOK's life insurance plan, as appropriate.

PAYMENTS MADE UPON A CHANGE IN CONTROL


                                       49

<PAGE>

     Effective January 2005, ONEOK entered into amended and restated termination
agreements with each of our named executive officers. Each termination agreement
has an initial two-year term from the date the agreement was entered into and is
automatically extended in one-year increments after the expiration of the
initial term unless ONEOK provides notice of non-renewal to the officer, or the
officer provides notice of non-renewal to ONEOK, at least 90 days before the
January 1 preceding any termination date of the agreement. 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, all change in control benefits are
"double trigger." Payments and benefits under these termination agreements 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 following
a change in control. In general, severance payments and benefits include a lump
sum payment in an amount equal to the sum of (1) for Mr. Cordes, three times,
and for Messrs. Peters, Miller, and Neppl and Ms. Place, two times, the
aggregate of the officer's annual salary as then in effect, plus the greater of
either the amount of the officer's bonus received in the prior year or the
officer's target bonus for the then current period, and (2) a prorated portion
of the officer's target short-term incentive compensation. Mr. Cordes would also
be entitled to continuation of health and welfare benefits for 36 months and
accelerated benefits under the ONEOK SERP. Messrs. Peters, Miller, and Neppl and
Ms. Place would be entitled to continuation of health and welfare benefits for
24 months. For Messrs. Cordes, Peters, Miller, and Neppl and Ms. Place,
severance payments will be reduced if the net after-tax benefit to such named
executive officer exceeds the net after-tax benefit if such reduction were not
made.

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

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

     -    the current members of the ONEOK Board, and any new director approved
          by a vote of at least two-thirds of the ONEOK Board, cease for any
          reason to constitute at least a majority of the ONEOK Board, 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, as a result of the transaction, own, directly or
          indirectly, at least 50 percent of the combined voting power of the
          voting securities of the company resulting from the transaction, (b)
          the members of the ONEOK Incumbent Board after the execution of the
          transaction agreement 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 percent or more of ONEOK's outstanding voting securities, has
          beneficial ownership of 30 percent or more of the outstanding voting
          securities of the company resulting from the transaction; or

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

     For the purposes of these agreements, "just cause" means the executive's
     conviction in a court of law of a felony, or any crime or offense in a
     court of law of a felony, or any crime or offense involving misuse or
     misappropriation of money or property; the executive's violation of any
     covenant, agreement or obligation not to disclose confidential information
     regarding ONEOK's business; any violation by the executive of any covenant
     not to compete with ONEOK; any act of dishonesty by the executive which
     adversely affects ONEOK's business; any willful or intentional act of the
     executive which adversely affects ONEOK's business, or reflects unfavorably
     on ONEOK's reputation; the executive's use of alcohol or drugs which
     interferes with the executive's performance of duties as ONEOK's employee;
     or the executive's failure or refusal to perform the specific directives of
     ONEOK's Board of Directors or its officers, which directives are consistent
     with the scope and nature of the executive's duties and responsibilities.
     The existence and occurrence of all of such causes are to be determined by
     ONEOK, in ONEOK's sole


                                       50

<PAGE>

     discretion, provided, that nothing contained in these provisions of these
     agreements are to be deemed to interfere in any way with ONEOK's right to
     terminate the executive's employment at any time without cause.

     For the purposes of these agreements, "good reason" means a demotion, loss
     of title or significant authority or responsibility of the executive with
     respect to the executive's employment with ONEOK from those in effect on
     the date of a change in control, a reduction of salary of the executive
     from that received from ONEOK immediately prior to the date of a change in
     control, a reduction in short-term and/or long-term incentive targets from
     those applicable to the executive immediately prior to the date of a change
     in control, the relocation of ONEOK's principal executive offices to a
     location outside the metropolitan area of Tulsa, Oklahoma, or ONEOK's
     requiring a relocation of principal place of employment of the executive,
     or the failure of a successor corporation to explicitly assume the
     termination agreement.

The following tables reflect estimates of the amount of incremental compensation
due to each named executive officer in the event of such executive's voluntary
termination of employment, or termination of employment for cause, by reason of
death, disability or retirement, without cause or following a change in control.
The amounts shown assume that such termination was effective as of December 31,
2006, and are estimates of the amounts which would be paid out to the executives
upon such termination. The actual amounts to be paid out can only be determined
at the time of such executive's separation from the company.

In addition to the amounts set forth in the following tables, in the event of
termination of employment for any of the reasons set forth in the tables, each
of the named executive officers would receive the following payments on
benefits: William R. Cordes, $217,333 in pension and SERP benefits, and $72,793
in nonqualified deferred compensation; Jerry L. Peters, $33,753 in pension and
SERP benefits, and $10,554 in nonqualified deferred compensation; Paul F.
Miller, $17,103 in pension and SERP benefits, and $31,943 in nonqualified
deferred compensation; Raymond D. Neppl, $55,704 in pension and SERP benefits,
and $42,578 in nonqualified deferred compensation; and Janet K. Place, $57,961
in pension and SERP benefits.

<TABLE>
<CAPTION>
                                           TERMINATION     TERMINATION
                                            UPON DEATH,   FOR CAUSE OR                      TERMINATION
                                          RETIREMENT OR     VOLUNTARY     TERMINATION    UPON A CHANGE IN
WILLIAM R. CORDES                           DISABILITY     TERMINATION   WITHOUT CAUSE      CONTROL (1)
-----------------                         -------------   ------------   -------------   ----------------
<S>                                       <C>             <C>            <C>             <C>
INCREMENTAL COMPENSATION
(payment contingent on termination)
Cash Severance                              $       --      $     --       $  277,083       $1,698,125
Equity
   Restricted Stock/Units                   $  197,526      $     --       $  197,526       $  409,640
   Phantom Units (2)                        $  687,975      $     --       $  687,975       $  687,975
   Performance Shares/Units                 $  345,646      $     --       $       --       $  716,870
   Total                                    $1,231,147      $     --       $  885,501       $1,814,485
Other Benefits
   Health & Welfare                         $       --      $     --       $       --       $   17,395
   Total                                    $       --      $     --       $       --       $   17,395
Total                                       $1,231,147      $     --       $1,162,584       $3,530,005
</TABLE>

(1)  Amounts in this column were calculated using 2004 and 2005 compensation
     data only, as the appropriate compensation data for 2001-2003 was not
     available. As a result, the amounts in this column may be overstated.

(2)  Includes our allocated portion of the market value of unvested phantom
     units held by Mr. Cordes under the Amended and Restated Northern Border
     Phantom Unit Plan dated November 1, 2001, which will vest upon his
     retirement on April 1, 2007.


                                       51

<PAGE>

<TABLE>
<CAPTION>
                                           TERMINATION     TERMINATION
                                           UPON DEATH,    FOR CAUSE OR                      TERMINATION
                                          RETIREMENT OR     VOLUNTARY     TERMINATION    UPON A CHANGE IN
JERRY L. PETERS                             DISABILITY     TERMINATION   WITHOUT CAUSE      CONTROL (1)
---------------                           -------------   ------------   -------------   ----------------
<S>                                       <C>             <C>            <C>             <C>
INCREMENTAL COMPENSATION
(payment contingent on termination)
Cash Severance                               $     --        $    --        $117,469         $472,875
Equity
   Restricted Stock/Units                    $ 76,629        $    --        $ 76,629         $154,154
   Phantom Units                             $     --        $    --        $     --         $     --
   Performance Shares/Units                  $117,213        $    --        $     --         $238,238
   Total                                     $193,841        $    --        $ 76,629         $392,392
Other Benefits
   Health & Welfare                          $     --        $    --        $     --         $ 12,169
   Total                                     $     --        $    --        $     --         $ 12,169
Total                                        $193,841        $    --        $194,098         $877,436
</TABLE>

(1)  Amounts in this column were calculated using 2004 and 2005 compensation
     data only, as the appropriate compensation data for 2001-2003 was not
     available. As a result, the amounts in this column may be overstated.

<TABLE>
<CAPTION>
                                           TERMINATION     TERMINATION
                                           UPON DEATH,    FOR CAUSE OR                      TERMINATION
                                          RETIREMENT OR     VOLUNTARY      TERMINATION   UPON A CHANGE IN
PAUL F. MILLER                              DISABILITY     TERMINATION   WITHOUT CAUSE      CONTROL (1)
---------------                           -------------   ------------   -------------   ----------------
<S>                                       <C>             <C>            <C>             <C>
INCREMENTAL COMPENSATION
(payment contingent on termination)
Cash Severance                               $     --        $    --        $ 74,308         $295,306
Equity
   Restricted Stock/Units                    $ 54,202        $    --        $ 54,202         $103,488
   Phantom Units                             $     --        $    --        $     --         $     --
   Performance Shares/Units                  $ 87,545        $    --        $     --         $168,168
   Total                                     $141,747        $    --        $ 54,202         $271,656
Other Benefits
   Health & Welfare                          $     --        $    --        $     --         $ 11,663
   Total                                     $     --        $    --        $     --         $ 11,663
Total                                        $141,747        $    --        $128,510         $578,625
   </TABLE>


                                       52

<PAGE>

(1)  Amounts in this column were calculated using 2004 and 2005 compensation
     data only, as the appropriate compensation data for 2001-2003 was not
     available. As a result, the amounts in this column may be overstated.

<TABLE>
<CAPTION>
                                           TERMINATION     TERMINATION
                                           UPON DEATH,    FOR CAUSE OR                      TERMINATION
                                          RETIREMENT OR     VOLUNTARY     TERMINATION    UPON A CHANGE IN
RAYMOND D. NEPPL                           DISABILITY     TERMINATION   WITHOUT CAUSE      CONTROL (1)
----------------                          -------------   ------------   -------------   ----------------
<S>                                       <C>             <C>            <C>             <C>
INCREMENTAL COMPENSATION
(payment contingent on termination)
Cash Severance                               $     --        $    --        $113,313         $309,864
Equity
   Restricted Stock/Units                    $ 31,957        $    --        $ 31,957         $ 59,437
   Phantom Units                             $     --        $    --        $     --         $     --
   Performance Shares/Units                  $ 51,170        $    --        $     --         $ 92,439
   Total                                     $ 83,127        $    --        $ 31,957         $151,876
Other Benefits
   Health & Welfare                          $     --        $    --        $     --         $  8,227
   Total                                     $     --        $    --        $     --         $  8,227
Total                                        $ 83,127        $    --        $145,270         $469,967
</TABLE>

(1)  Amounts in this column were calculated using 2004 and 2005 compensation
     data only, as the appropriate compensation data for 2001-2003 was not
     available. As a result, the amounts in this column may be overstated.



                                       53

<PAGE>

<TABLE>
<CAPTION>
                                           TERMINATION     TERMINATION
                                           UPON DEATH,    FOR CAUSE OR                      TERMINATION
                                          RETIREMENT OR     VOLUNTARY     TERMINATION    UPON A CHANGE IN
JANET K. PLACE                              DISABILITY     TERMINATION   WITHOUT CAUSE      CONTROL (1)
--------------                            -------------   ------------   -------------   ----------------
<S>                                       <C>             <C>            <C>             <C>
INCREMENTAL COMPENSATION
(payment contingent on termination)
Cash Severance                               $     --        $    --        $140,000         $443,465
Equity
   Restricted Stock/Units                    $ 53,456        $    --        $ 53,456         $105,644
   Phantom Units                             $     --        $    --        $     --         $     --
   Performance Shares/Units                  $ 92,324        $    --        $     --         $181,104
   Total                                     $145,780        $    --        $ 53,456         $286,748
Other Benefits
   Health & Welfare                          $     --        $    --        $     --         $ 13,607
   Total                                     $     --        $    --        $     --         $ 13,607
Total                                        $145,780        $    --        $193,456         $743,820
</TABLE>

(1)  Amounts in this column were calculated using 2004 and 2005 compensation
     data only, as the appropriate compensation data for 2001-2003 was not
     available. As a result, the amounts in this column may be overstated.

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, 2006. There are no limited partnership
interests.

<TABLE>
<CAPTION>
NAME OF BENEFICIAL OWNER                 ADDRESS             GENERAL PARTNERSHIP INTEREST
------------------------      ----------------------------   ----------------------------
<S>                           <C>                            <C>
ONEOK Partners Intermediate   100 West Fifth Street                       50%
   Limited Partnership        Tulsa, OK  74103-4298
TC PipeLines Intermediate     110 Turnpike Road, Suite 203                50%
   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
ONEOK Partners sold a 20 percent partnership interest in us to TC PipeLines
Intermediate is included under Item 1, "Business-General."

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR
     INDEPENDENCE

RELATIONSHIP WITH ONEOK PARTNERS

At December 31, 2006, ONEOK Partners owned a 50 percent partnership interest in
us through its subsidiary, ONEOK Partners Intermediate. The general partner of
ONEOK Partners is ONEOK Partners GP. ONEOK Partners GP is a subsidiary of ONEOK.
In 2006, we paid ONEOK Partners cash distributions of $98.4 million and received
cash contributions of $7.2 million.


                                       54
<PAGE>

RELATIONSHIP WITH TC PIPELINES INTERMEDIATE

At December 31, 2006, TC PipeLines Intermediate owned a 50 percent 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 2006, we paid TC PipeLines Intermediate cash
distributions of $80.4 million and received cash contributions of $3.1 million.

RELATIONSHIP WITH ONEOK

OPERATING AGREEMENT

ONEOK Partners GP provides certain administrative, operating and management
services to us through an operating agreement. ONEOK Partners GP has acted and
will continue to act as the operator of our pipeline system under the terms of
the operating agreement through March 31, 2007. TransCan will become our
operator effective April 1, 2007. Additional information about the change in
operator is included under Item 1, "Business-General."

ONEOK Partners GP is entitled to reimbursement for all reasonable costs,
including overhead and administrative expenses, incurred by it, ONEOK and their
affiliates in connection with the performance of its responsibilities as
operator. Under our partnership agreement, we also agreed to indemnify our
operator against any claims or liabilities arising out of our operator's good
faith performance of its responsibilities, to the extent we believe our operator
is acting within the scope of its authority and in the course of our business.
In 2006, 2005 and 2004, the amount charged by ONEOK Partners GP and its
affiliates for their services as operator was $26.2 million, $20.1 million and
$18.3 million, respectively. In 2007, we will be charged for services provided
by ONEOK Partners GP and its affiliates as operator through March 31, 2007 on a
basis consistent with previous years.

TRANSPORTATION AGREEMENTS

ONEOK Energy is a subsidiary of ONEOK. In 2006, 2 percent of our design capacity
was contracted on a firm basis with ONEOK Energy. Revenue from ONEOK Energy for
2006 and 2005 was $7.0 million and $7.7 million, respectively. As of December
31, 2006, approximately 1 percent of our design capacity was contracted on a
firm basis with ONEOK Energy for 2007.

TRANSITION RELATED COSTS

ONEOK Partners GP and TransCan entered into a transition services agreement for
the transfer of the operator responsibilities effective April 1, 2007. As a part
of the agreement, we will pay ONEOK Partners an amount of approximately $1.0
million per year for five years for previously agreed to obligations related to
the reimbursement for shared equipment and furnishings acquired by ONEOK
Partners and previously used to support our operations. In addition, we agreed
to transfer certain identified assets of immaterial value to ONEOK Partners at
either no cost or net book value as defined in the agreement.

RELATIONSHIP WITH TRANSCANADA

OPERATING AGREEMENT

In April 2006, we entered into an operating agreement with TransCan. Under the
new operating agreement TransCan will become our operator effective April 1,
2007 and will provide the services we currently receive from ONEOK Partners GP.
TransCan will be entitled to reimbursement for all reasonable costs, including
overhead and administrative expenses, incurred by it and its affiliates in
connection with the performance of its responsibilities as our operator. Under
our partnership agreement, we also agreed to indemnify our operator against any
claims or liabilities arising out of our 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. We will be charged for
services provided by TransCan and its affiliates as operator beginning April 1,
2007 on a basis consistent with and not materially different from charges we
received from ONEOK Partners GP and its affiliates.

CONFLICTS OF INTEREST

Our general partners, which are affiliates 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


                                       55

<PAGE>

in our best interest. However, the Boards of Directors of ONEOK and TransCanada
have a fiduciary duty to manage our general partners in a manner beneficial to
ONEOK and TransCanada, respectively.

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 ONEOK Partners GP, 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 ONEOK Partners and TC PipeLines,
          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.

RELATED PARTY TRANSACTIONS

Our Management Committee recognizes that transactions between us and related
persons (our partners, their subsidiaries and affiliates and their and our
executive officers, committee members, and their immediate family members) can
present potential or actual conflicts of interest and create the appearance that
decisions are based on considerations other than our best interests.
Accordingly, as a general matter, it is our preference to avoid related party
transactions. Nevertheless, we recognize that there are situations where related
party transactions may be in, or may not be inconsistent with, our best
interests, including, but not limited to, situations where we acquire products
or services from related persons on an arm's length basis on terms comparable to
those provided to unrelated third parties.

In the event we enter into a transaction in which one of our partners, its
subsidiaries, its affiliates or its executive officers (other than an employment
relationship), directors, or members of their immediate family has a direct or
indirect material interest, the transaction is presented to our Management
Committee for review to determine if the transaction creates a conflict of
interest and is otherwise fair to us. This review does not apply to transactions
with related parties for our transportation services on our existing pipeline
system, as those transactions are governed by our FERC regulated tariff.

We require each executive officer and Management and Audit Committee member to
annually provide us written disclosure of any transaction between the officer or
Management or Audit Committee member and us. These procedures are not in writing
but are evidenced through the meeting agendas of our Management Committee.

INDEPENDENCE OF MANAGEMENT AND AUDIT COMMITTEE MEMBERS

We are not a listed issuer and are not subject to the listing standards of the
New York Stock Exchange (the NYSE) or any other securities exchange or
association because we do not have any securities listed on the NYSE or any such
other securities exchange or association. If we were subject to the listing
standards of the NYSE, a majority of the members of our Management Committee
would be required to be independent, as defined by the NYSE, and we would be
required to have a nominating and corporate governance committee, compensation
committee and audit


                                       56

<PAGE>

committee comprised entirely of independent members. None of the members of our
Management Committee or Audit Committee is independent as defined by the NYSE
because each of them is an employee of an affiliate of our partners, nor do we
have a nominating and corporate governance committee or compensation committee.

ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

The fees for the years ended December 31, 2006, and 2005 for professional
services provided by KPMG LLP were as follows:

<TABLE>
<CAPTION>
                     FOR THE YEARS ENDED
                         DECEMBER 31,
                     -------------------
                       2006       2005
                     --------   --------
<S>                  <C>        <C>
Audit fees           $200,200   $339,900
Audit-related fees         --         --
Tax fees                   --         --
All other fees             --         --
                     --------   --------
   Total             $200,200   $339,900
                     ========   ========
</TABLE>

AUDIT FEES

Audit fees include fees for the audits of the annual GAAP and regulatory basis
financial statements and reviews of the related quarterly financial statements.

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.

                                     PART IV

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES

<TABLE>
<CAPTION>
                                                                        Page No.
                                                                        --------
<S>                                                                     <C>
(A)(1) FINANCIAL STATEMENTS

(a)  Report of Independent Registered Public Accounting Firm                 27

(b)  Balance Sheets as of December 31, 2006, and 2005                        28

(c)  Statements of Income for the years ended
     December 31, 2006, 2005 and 2004                                        29

(d)  Statements of Comprehensive Income for the years ended
     December 31, 2006, 2005 and 2004                                        29

(e)  Statements of Cash Flows for the years ended
     December 31, 2006, 2005 and 2004                                        30

(f)  Statements of Changes in Partners' Equity for the years ended
     December 31, 2006, 2005 and 2004                                        31

(g)  Notes to Financial Statements                                        32-41
</TABLE>

<TABLE>
<CAPTION>
                                                                        Page No.
                                                                        --------
<S>                                                                     <C>
(A)(2) FINANCIAL STATEMENT SCHEDULES

(a)  Report of Independent Registered Public Accounting Firm on
     Schedule                                                                42

(b)  Schedule II - Valuation and Qualifying Accounts                         43
</TABLE>


                                       57

<PAGE>

     All other schedules are omitted because they are not applicable, or the
     required information is disclosed in the financial statements or
     accompanying notes.

(A)(3) EXHIBITS

<TABLE>
<S>      <C>
*3.1     First Amended and Restated General Partnership Agreement of Northern
         Border Pipeline Company dated April 6, 2006, by and between Northern
         Border Intermediate Limited Partnership and TC Pipelines Intermediate
         Limited Partnership (incorporated by reference to Exhibit 3.1 to
         Northern Border Pipeline Company's Form 8-K filed April 12, 2006 (File
         No. 333-87753)).

*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 the Company's Registration Statement on Form S-4 filed on
         October 7, 1999 (Registration No. 333-88577)).

*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 the Company's Registration
         Statement on Form S-4 filed on November 13, 2001 (Registration No.
         333-73282)).

*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) (File 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 Northern Border Partners,
         L.P.'s Form S-1 Registration Statement filed on July 16, 1993 (File No.
         33-66158)("Northern Border Partners' Form S-1")).

*10.2    Consent and Amendment to Operating Agreement dated April 6, 2006, by
         and between Northern Border Pipeline Company and Northern Plains
         Natural Gas Company, LLC (incorporated by reference to Exhibit 10.1 to
         the Company's Form 8-K filed April 12, 2006 (File No. 333-88577)).

*10.3    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)).

*10.4    The First Amendment to Revolving Credit Agreement dated March 29, 2006,
         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; and Harris Nesbit
         Financing, Inc., Barclays Bank PLC, and Citibank, N.A., as
         co-documentation agents (incorporated by reference to Exhibit 10.1 to
         the Company's Form 8-K filed April 4, 2006 (File No. 333-88577)).

*10.5    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 Northern Border Partners' Form S-1).

*10.6    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")).
</TABLE>


                                       58

<PAGE>

<TABLE>
<S>      <C>
*10.7    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)).

*10.8    Operating Agreement dated April 6, 2006, by and between Northern Border
         Pipeline Company and TransCan Northwest Border Ltd. (incorporated by
         reference to Exhibit 10.2 to the Company's Form 8-K filed April 12,
         2006 (File No. 333-88577)).

12.1     Statement re computation 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   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.

#    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.


                                       59

<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 28th day of
February, 2007.

                                        NORTHERN BORDER PIPELINE COMPANY
                                        (A Texas General partnership)

                                        By: ONEOK Partners GP, L.L.C., Operator


                                        By: /s/ Jerry L. Peters
                                            ------------------------------------
                                            Jerry L. Peters
                                            Senior Vice President -- Chief
                                            Accounting  Officer

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 Border Pipeline Company,         February 28, 2007
------------------------------   ONEOK Partners GP, L.L.C.
William R. Cordes                (functional equivalent to the registrant's principal
                                 executive officer) and Management Committee Member


/s/ Jerry L. Peters              Senior Vice President -- Chief Accounting Officer,     February 28, 2007
------------------------------   ONEOK Partners GP, L.L.C.
Jerry L. Peters                  (functional equivalent to the registrant's principal
                                 financial and accounting officer)


/s/ Craig R.Frew                 Management Committee, Chairman                         February 28, 2007
------------------------------
Craig R. Frew


/s/ John W. Gibson               Management Committee Member                            February 28, 2007
------------------------------
John W. Gibson


/s/ Mark A.P. Zimmerman          Management Committee Member                            February 28, 2007
------------------------------
Mark A.P. Zimmerman
</TABLE>


                                       60
<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.


                                       61

<PAGE>

                                  EXHIBIT INDEX

EXHIBITS

<TABLE>
<S>      <C>
*3.1     First Amended and Restated General Partnership Agreement of Northern
         Border Pipeline Company dated April 6, 2006, by and between Northern
         Border Intermediate Limited Partnership and TC Pipelines Intermediate
         Limited Partnership (incorporated by reference to Exhibit 3.1 to
         Northern Border Pipeline Company's Form 8-K filed April 12, 2006 (File
         No. 333-87753)).

*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 the Company's Registration Statement on Form S-4 filed on
         October 7, 1999 (Registration No. 333-88577)).

*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 the Company's Registration
         Statement on Form S-4 filed on November 13, 2001 (Registration No.
         333-73282)).

*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) (File 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 Northern Border Partners,
         L.P.'s Form S-1 Registration Statement filed on July 16, 1993 (File No.
         33-66158)("Northern Border Partners' Form S-1")).

*10.2    Consent and Amendment to Operating Agreement dated April 6, 2006, by
         and between Northern Border Pipeline Company and Northern Plains
         Natural Gas Company, LLC (incorporated by reference to Exhibit 10.1 to
         the Company's Form 8-K filed April 12, 2006 (File No. 333-88577)).

*10.3    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)).

*10.4    The First Amendment to Revolving Credit Agreement dated March 29, 2006,
         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; and Harris Nesbit
         Financing, Inc., Barclays Bank PLC, and Citibank, N.A., as
         co-documentation agents (incorporated by reference to Exhibit 10.1 to
         the Company's Form 8-K filed April 4, 2006 (File No. 333-88577)).
</TABLE>

<PAGE>

<TABLE>
<S>      <C>
*10.5    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 Northern Border Partners' Form S-1).

*10.6    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")).

*10.7    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)).

*10.8    Operating Agreement dated April 6, 2006, by and between Northern Border
         Pipeline Company and TransCan Northwest Border Ltd. (incorporated by
         reference to Exhibit 10.2 to the Company's Form 8-K filed April 12,
         2006 (File No. 333-88577)).

12.1     Statement re computation 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   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.

#    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.