<PAGE>

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

                                    FORM 10-Q

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

     For the quarterly period ended MARCH 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: 1-12202

                         NORTHERN BORDER PARTNERS, L.P.
             (Exact name of registrant as specified in its charter)

<TABLE>
<S>                                                       <C>
                DELAWARE                                        93-1120873
     (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)

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 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 [X] Accelerated filer [ ] Non-accelerated filer [ ]

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

Indicate the number of shares outstanding of each of the issuer's classes of
common stock, as of the latest practicable date.

<TABLE>
<CAPTION>
    CLASS                                             OUTSTANDING AT MAY 1, 2006
-------------                                         --------------------------
<S>                                                   <C>
Common units                                               46,397,214 units
Class B units                                              36,494,126 units
</TABLE>

<PAGE>

                 NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES
                          QUARTERLY REPORT ON FORM 10-Q

                                TABLE OF CONTENTS

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

Item 1.  Financial Statements
            Consolidated Statement of Income - Three Months Ended
               March 31, 2006, and 2005..............................       4
            Consolidated Statement of Comprehensive Income -
               Three Months Ended March 31, 2006, and 2005...........       5
            Consolidated Balance Sheet - March 31, 2006, and
               December 31, 2005.....................................       6
            Consolidated Statement of Cash Flows - Three Months Ended
               March 31, 2006, and 2005..............................       7
            Consolidated Statement of Changes in Partners' Equity -
               Three Months Ended March 31, 2006.....................       8
            Notes to Consolidated Financial Statements...............       9
Item 2.  Management's Discussion and Analysis of Financial Condition
          and Results of Operations
            Executive Summary........................................      15
            Critical Accounting Estimates............................      17
            Results of Operations....................................      18
            Liquidity and Capital Resources..........................      22
            Recent Accounting Pronouncements.........................      25
            Forward-Looking Statements...............................      25
Item 3.  Quantitative and Qualitative Disclosures about Market Risk..      26
Item 4.  Controls and Procedures.....................................      28

                           PART II - OTHER INFORMATION

Item 1.  Legal Proceedings...........................................      28
Item 1A. Risk Factors................................................      29
Item 6.  Exhibits....................................................      33
         Signature...................................................      35
</TABLE>

The statements in this quarterly 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 in this quarterly
report under Item 1A, "Risk Factors," and under Item 1A, "Risk Factors," in our
annual report on Form 10-K for the year ended December 31, 2005.


                                        2

<PAGE>

GLOSSARY

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

<TABLE>
<S>                              <C>
Bbl...........................   Barrels, equivalent to 42 United States gallons
Bbl/d.........................   Barrels per day
Bear Paw Energy...............   Bear Paw Energy, LLC
Bighorn Gas Gathering.........   Bighorn Gas Gathering, L.L.C.
Black Mesa....................   Black Mesa Pipeline, Inc.
Crestone Energy...............   Crestone Energy Ventures, L.L.C.
Exchange Act..................   Securities Exchange Act of 1934, as amended
FASB..........................   Financial Accounting Standards Board
FERC..........................   Federal Energy Regulatory Commission
Fort Union Gas Gathering......   Fort Union Gas Gathering, L.L.C.
GAAP..........................   Generally accepted accounting principles
Guardian Pipeline.............   Guardian Pipeline, L.L.C.
Lost Creek Gathering..........   Lost Creek Gathering Company, L.L.C.
Midwestern Gas Transmission...   Midwestern Gas Transmission Company
MMBtu.........................   Million British thermal units
MMcf/d........................   Million cubic feet per day
NBP Services..................   NBP Services, LLC, a ONEOK subsidiary
Northern Border Pipeline......   Northern Border Pipeline Company
Northern Plains...............   Northern Plains Natural Gas Company, LLC, a
                                    ONEOK subsidiary
Northwest Border..............   Northwest Border Pipeline Company,
                                    a ONEOK subsidiary
NYMEX.........................   New York Mercantile Exchange
NYSE..........................   New York Stock Exchange
ONEOK.........................   ONEOK, Inc.
Partnership...................   Northern Border Partners, L.P., Northern Border
                                    Intermediate Limited Partnership and its
                                    subsidiaries
SEC...........................   Securities and Exchange Commission
SFAS..........................   Statement of Financial Accounting Standards
TC PipeLines..................   TC PipeLines Intermediate Limited Partnership,
                                    a subsidiary of TC PipeLines, LP
TransCanada...................   TransCanada Corporation
Trunk gathering system........   Large diameter pipeline running through a
                                    production area to which smaller individual
                                    gathering systems are connected
U.S...........................   United States
Viking Gas Transmission.......   Viking Gas Transmission Company
</TABLE>


                                        3
<PAGE>

                         PART I - FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF INCOME
(UNAUDITED)

<TABLE>
<CAPTION>
                                                  THREE MONTHS ENDED
                                                      MARCH 31,
                                                 -------------------
                                                   2006       2005
                                                 --------   --------
                                                    (In thousands
                                                   except per unit
                                                       amounts)
<S>                                              <C>        <C>
Operating revenue                                $170,799   $160,379
                                                 --------   --------
Operating expenses:
   Product purchases                               44,021     32,465
   Operations and maintenance                      31,643     33,172
   Depreciation and amortization                   21,294     21,392
   Taxes other than income                         10,178      9,812
                                                 --------   --------
      Operating expenses                          107,136     96,841
                                                 --------   --------
Operating income                                   63,663     63,538
                                                 --------   --------
Interest expense                                   22,704     21,166
                                                 --------   --------
Other income (expense):
   Equity earnings in unconsolidated
    affiliates                                      6,163      4,477
   Other income                                       950        741
   Other expense                                     (162)      (223)
                                                 --------   --------
      Other income, net                             6,951      4,995
                                                 --------   --------
Minority interest in net income                    11,206     12,189
                                                 --------   --------
Income from continuing operations before
 income taxes                                      36,704     35,178
Income taxes                                        2,027        899
                                                 --------   --------
Income from continuing operations                  34,677     34,279
Discontinued operations, net of tax                     9        390
                                                 --------   --------
Net income to partners                           $ 34,686   $ 34,669
                                                 ========   ========
Calculation of limited partners' interest in
 net income:
   Net income to partners                        $ 34,686   $ 34,669
   Less: General partners' interest in net
    income                                          3,822      2,683
                                                 --------   --------
      Limited partners' interest in net income   $ 30,864   $ 31,986
                                                 ========   ========
Limited partners' per unit net income:
   Income from continuing operations             $   0.67   $   0.68
   Discontinued operations, net of tax                 --       0.01
                                                 --------   --------
      Net income                                 $   0.67   $   0.69
                                                 ========   ========
Number of units used in computation                46,397     46,397
                                                 ========   ========
</TABLE>

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


                                        4

<PAGE>

NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME
(UNAUDITED)

<TABLE>
<CAPTION>
                                               THREE MONTHS
                                             ENDED MARCH 31,
                                            -----------------
                                              2006      2005
                                            -------   -------
                                              (In thousands)
<S>                                         <C>       <C>
Net income to partners                      $34,686   $34,669
Other comprehensive income:
   Changes associated with current period
      hedging transactions                    5,000    (2,725)
   Changes associated with current period
      foreign currency translation               (4)      (21)
                                            -------   -------
Total comprehensive income                  $39,682   $31,923
                                            =======   =======
</TABLE>

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


                                        5

<PAGE>

NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEET (UNAUDITED)

<TABLE>
<CAPTION>
                                                                       MARCH 31,   DECEMBER 31,
                                                                         2006          2005
                                                                      ----------   ------------
                                                                            (In thousands)
<S>                                                                   <C>          <C>
ASSETS
Current assets:
   Cash and cash equivalents                                          $   18,730    $   43,090
   Accounts receivable, net of allowance for doubtful accounts of
    $18 at March 31, 2006, and December 31, 2005                          64,832        82,848
   Materials and supplies, at cost                                         7,543         7,273
   Prepaid expenses and other                                              5,168         5,211
   Derivative financial instruments                                        2,073            --
                                                                      ----------    ----------
      Total current assets                                                98,346       138,422
                                                                      ----------    ----------
Property, plant and equipment:
   Interstate natural gas pipeline                                     2,677,529     2,668,645
   Natural gas gathering and processing                                  289,188       284,199
   Other                                                                  51,878        47,876
                                                                      ----------    ----------
      Total property, plant and equipment                              3,018,595     3,000,720
      Less: Accumulated provision for depreciation and amortization    1,102,751     1,082,210
                                                                      ----------    ----------
      Property, plant and equipment, net                               1,915,844     1,918,510
                                                                      ----------    ----------
Investments and other assets:
   Investment in unconsolidated affiliates                               288,402       290,756
   Goodwill                                                              152,782       152,782
   Regulatory assets                                                      18,621        14,153
   Other                                                                  14,363        13,143
                                                                      ----------    ----------
      Total investments and other assets                                 474,168       470,834
                                                                      ----------    ----------
         Total assets                                                 $2,488,358    $2,527,766
                                                                      ==========    ==========
LIABILITIES AND PARTNERS' EQUITY
Current liabilities:
   Current maturities of long-term debt                               $  238,000    $  233,194
   Derivative financial instruments                                        1,264         4,571
   Accounts payable                                                       34,326        53,706
   Accrued taxes other than income                                        31,819        33,081
   Accrued interest                                                       21,925        17,446
                                                                      ----------    ----------
      Total current liabilities                                          327,334       341,998
                                                                      ----------    ----------
Long-term debt, net of current maturities                              1,090,905     1,121,777
                                                                      ----------    ----------
Minority interests in partners' equity                                   275,196       274,510
                                                                      ----------    ----------
Reserves and deferred credits:
   Deferred income taxes                                                  12,502        10,311
   Derivative financial instruments                                        5,058         2,362
   Regulatory liabilities                                                  2,681         2,591
   Other                                                                   9,317         8,628
                                                                      ----------    ----------
      Total reserves and deferred credits                                 29,558        23,892
                                                                      ----------    ----------
Commitments and contingencies (Note 7)
Partners' equity:
   General partners                                                       18,375        17,341
   Common units: 46,397,214 units issued and outstanding at
    March 31, 2006, and December 31, 2005                                743,947       750,201
   Accumulated other comprehensive income (loss)                           3,043        (1,953)
                                                                      ----------    ----------
      Total partners' equity                                             765,365       765,589
                                                                      ----------    ----------
         Total liabilities and partners' equity                       $2,488,358    $2,527,766
                                                                      ==========    ==========
</TABLE>

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


                                        6
<PAGE>

NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF CASH FLOWS (Unaudited)

<TABLE>
<CAPTION>
                                                                       THREE MONTHS ENDED
                                                                            MARCH 31,
                                                                      --------------------
                                                                         2006       2005
                                                                      ---------   --------
                                                                         (In thousands)
<S>                                                                   <C>         <C>
CASH FLOW FROM OPERATING ACTIVITIES
Net income to partners                                                $  34,686   $ 34,669
                                                                      ---------   --------
Adjustments to reconcile net income to partners to net cash
 provided by operating activities:
   Depreciation and amortization                                         21,386     21,482
   Minority interests in net income                                      11,206     12,189
   Reserves and deferred credits                                            689       (340)
   Equity earnings in unconsolidated affiliates                          (6,163)    (4,477)
   Distributions received from unconsolidated affiliates                  9,203      1,187
   Changes in components of working capital                               1,626      3,726
   Non-cash losses (gains) from derivative financial instruments            (21)        40
   Other                                                                 (2,398)    (1,406)
                                                                      ---------   --------
      Total adjustments                                                  35,528     32,401
                                                                      ---------   --------
   Net cash provided by operating activities                             70,214     67,070
                                                                      ---------   --------

CASH FLOW FROM INVESTING ACTIVITIES
Investment in unconsolidated affiliates                                    (605)    (1,454)
Capital expenditures for property, plant and equipment                  (17,806)    (9,846)
                                                                      ---------   --------
   Net cash used in investing activities                                (18,411)   (11,300)
                                                                      ---------   --------

CASH FLOW FROM FINANCING ACTIVITIES
Cash distributions:
   General and limited partners                                         (39,906)   (39,906)
   Minority interests                                                   (13,502)   (16,229)
Equity contributions from minority interests                              3,099         --
Issuance of long-term debt                                              258,000     13,000
Debt reacquisition costs                                                 (3,628)        --
Long-term debt financing costs                                             (179)        --
Retirement of long-term debt                                           (280,047)    (9,302)
                                                                      ---------   --------
   Net cash used in financing activities                                (76,163)   (52,437)
                                                                      ---------   --------
Net change in cash and cash equivalents                                 (24,360)     3,333
Cash and cash equivalents at beginning of period                         43,090     33,980
                                                                      ---------   --------
Cash and cash equivalents at end of period                            $  18,730   $ 37,313
                                                                      =========   ========

Supplemental disclosures of cash flow information:
Cash paid for interest, net of amount capitalized                     $  19,475   $ 16,294
                                                                      =========   ========
Cash paid for income taxes                                            $     143   $    151
                                                                      =========   ========
Changes in components of working capital:
   Accounts receivable                                                $  18,016   $  3,663
   Materials and supplies, prepaid expenses and other                      (228)       877
   Accounts payable                                                     (19,379)    (6,492)
   Accrued taxes other than income                                       (1,262)      (401)
   Accrued interest                                                       4,479      6,079
                                                                      ---------   --------
      Total                                                           $   1,626   $  3,726
                                                                      =========   ========
</TABLE>

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


                                        7

<PAGE>

NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF CHANGES IN PARTNERS' EQUITY
(UNAUDITED)

<TABLE>
<CAPTION>
                                                                   ACCUMULATED
                                                                      OTHER         TOTAL
                                             GENERAL    COMMON    COMPREHENSIVE   PARTNERS'
                                            PARTNERS     UNITS    INCOME (LOSS)     EQUITY
                                            --------   --------   -------------   ---------
                                                             (In thousands)
<S>                                         <C>        <C>        <C>             <C>
Partners' equity at December 31, 2005       $17,341    $750,201      $(1,953)     $765,589
   Net income to partners                     3,822      30,864           --        34,686
   Changes associated with current
      period hedging transactions                --          --        5,000         5,000
   Changes associated with current
      period foreign currency translation        --          --           (4)           (4)
   Distribution to partners                  (2,788)    (37,118)          --       (39,906)
                                            -------    --------      -------      --------
Partners' equity at March 31, 2006          $18,375    $743,947      $ 3,043      $765,365
                                            =======    ========      =======      ========
</TABLE>

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


                                        8

<PAGE>

NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1.   BASIS OF PRESENTATION

In this report, references to "we," "us," "our" or the "Partnership"
collectively refer to Northern Border Partners, L.P. and our subsidiary,
Northern Border Intermediate Limited Partnership and its subsidiaries.

We prepared the consolidated financial statements included herein without audit
pursuant to the rules and regulations of the Securities and Exchange Commission.
The consolidated financial statements reflect all normal and recurring
adjustments that are, in the opinion of management, necessary for a fair
presentation of the financial results for the interim periods presented. Certain
information and notes normally included in financial statements prepared in
accordance with U.S. generally accepted accounting principles (U.S. GAAP) are
condensed or omitted pursuant to such rules and regulations. However, we believe
that the disclosures are adequate to make the information presented not
misleading. These consolidated financial statements should be read in
conjunction with the consolidated financial statements and the notes thereto
included in our annual report on Form 10-K for the year ended December 31, 2005.

The preparation of financial statements in conformity with U.S. GAAP requires
management to make assumptions and use estimates that affect the reported amount
of the 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.

At March 31, 2006, we owned a 70% general partner interest in Northern Border
Pipeline Company (see Note 9-Subsequent Events). Our significant wholly owned
subsidiaries are: Crestone Energy Ventures, L.L.C.; Bear Paw Energy, LLC;
Midwestern Gas Transmission Company; Viking Gas Transmission Company; and Black
Mesa Pipeline, Inc. We also own a 49% common membership interest in Bighorn Gas
Gathering, L.L.C.; a 37% interest in Fort Union Gas Gathering, L.L.C.; a 35%
interest in Lost Creek Gathering Company, L.L.C.; and a 33-1/3% interest in
Guardian Pipeline, L.L.C. (see Note 9-Subsequent Events).

Certain reclassifications were made to the 2005 financial statements to conform
to the current year presentation.

2.   CREDIT FACILITIES AND LONG-TERM DEBT

In March 2006, we entered into a five-year $750 million amended and restated
revolving credit agreement (2006 Partnership Credit Agreement) with certain
financial institutions and terminated our $500 million revolving credit
agreement. The weighted average interest rate on amounts outstanding under these
agreements during the first quarter of 2006 was 5.40%.

On March 31, 2006, Viking Gas Transmission redeemed its four series of senior
notes outstanding. In connection with the redemption, Viking Gas Transmission
paid a premium of $3.6 million. The net loss from the redemption, including
unamortized debt costs associated with the debt, will be amortized to interest
expense over the remaining life of the Viking Gas Transmission senior notes. At
March 31, 2006, the unamortized loss on reacquired debt was $3.8 million and is
included in regulatory assets on the consolidated balance sheet.

3.   DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

We utilize financial instruments to reduce our market risk exposure to interest
rate and commodity price fluctuations and achieve a more predictable cash flow.
We follow established policies and procedures to assess risk and approve,
monitor and report our financial instrument activities. We do not use these
instruments for trading purposes.

We record in accumulated other comprehensive income amounts related to
terminated interest rate swap agreements for cash flow hedges and amortize these
amounts to interest expense over the term of the hedged debt. During the three
months ended March 31, 2006, we amortized approximately $0.4 million related to
the terminated interest rate


                                        9

<PAGE>

swap agreements as a reduction to interest expense from accumulated other
comprehensive income. We expect to amortize approximately $0.2 million in each
of the remaining quarters of 2006.

Our outstanding interest rate swap agreements, with notional amounts totaling
$150 million, expire in March 2011. Under these agreements, we make payments to
counterparties at variable rates based on the London Interbank Offered Rate and
receive payments based on a 7.10% fixed rate. As of March 31, 2006, the average
effective interest rate on our interest rate swap agreements was 7.62%. Our
interest rate swap agreements are designated as fair value hedges as they hedge
the fluctuations in the market value of the senior notes issued by us in 2001.
As of March 31, 2006, the accompanying consolidated balance sheet reflects
long-term derivative financial liabilities of $5.1 million with a decrease in
long-term debt related to our fair value hedges.

We record in long-term debt amounts received or paid related to terminated or
amended interest rate swap agreements for fair value hedges and amortize these
amounts to interest expense over the remaining life of the interest rate swap
agreement. During the three months ended March 31, 2006, we amortized
approximately $1.3 million as a reduction to interest expense and expect to
amortize approximately $0.8 million in each of the remaining quarters of 2006.

Bear Paw Energy periodically enters into commodity derivative contracts and
fixed-price physical contracts. Bear Paw Energy primarily utilizes price swaps,
which are designated as cash flow hedges, to hedge its exposure to natural gas
and natural gas liquids price volatility. During the three months ended March
31, 2006, Bear Paw Energy recognized gains of $0.8 million from the settlement
of derivative contracts. As of March 31, 2006, the consolidated balance sheet
reflected an unrealized loss of approximately $1.3 million in current derivative
financial instrument liabilities and an unrealized gain of approximately $2.1
million in current derivative financial instrument assets. If prices remain at
current levels, Bear Paw Energy expects to reclassify approximately $0.3
million, $0.2 million and $0.3 million from accumulated other comprehensive
income as an increase to operating revenue in the second, third and fourth
quarters of 2006, respectively. However, this increase would be offset with
decreased operating revenue due to the lower prices assumed.

4.   BUSINESS SEGMENT INFORMATION

Our business is divided into two reportable segments, defined as components of
the enterprise about which financial information is available and evaluated
regularly by our management and the Partnership Policy Committee. Our reportable
segments are strategic business units that offer different services. Each
segment is managed separately because each business requires a different
marketing strategy. These segments are as follows: the Interstate Natural Gas
Pipeline segment, which provides interstate natural gas transportation services,
and the Natural Gas Gathering and Processing segment, which provides services
for the gathering, treating, processing and compression of natural gas and the
fractionation of natural gas liquids.


                                       10
<PAGE>

BUSINESS SEGMENT DATA

<TABLE>
<CAPTION>
                                   INTERSTATE     NATURAL GAS
THREE MONTHS ENDED                NATURAL GAS   GATHERING AND
MARCH 31, 2006                     PIPELINE       PROCESSING    OTHER (a)     TOTAL
------------------                -----------   -------------   ---------   --------
                                                    (In thousands)
<S>                               <C>           <C>             <C>         <C>
Revenue from external customers     $95,642        $73,513       $ 1,644    $170,799
Operating income (loss)              55,325         13,991        (5,653)     63,663
EBITDA                               73,193         23,876        (5,303)     91,766
</TABLE>

<TABLE>
<CAPTION>
THREE MONTHS ENDED
MARCH 31, 2005
------------------
<S>                                 <C>            <C>           <C>        <C>
Revenue from external customers     $96,645        $57,573       $ 6,161    $160,379
Operating income (loss)              55,638          9,502        (1,602)     63,538
EBITDA                               72,823         17,706           143      90,672
</TABLE>

(a)  Includes other items not allocable to segments. In 2005, our coal slurry
     operation was shown as a separate reportable segment. Our coal slurry
     transportation contract was terminated at December 31, 2005, therefore our
     coal slurry business is included in Other.

TOTAL ASSETS BY SEGMENT

<TABLE>
<CAPTION>
                                        MARCH 31,   DECEMBER 31,
                                          2006          2005
                                       ----------   ------------
                                             (In thousands)
<S>                                    <C>          <C>
Interstate natural gas pipeline        $1,873,387    $1,888,980
Natural gas gathering and processing      589,143       594,379
Other (a)                                  25,828        44,407
                                       ----------    ----------
   Total assets                        $2,488,358    $2,527,766
                                       ==========    ==========
</TABLE>

(a)  Includes other items not allocable to segments.

We evaluate performance based on EBITDA (earnings before interest, taxes,
depreciation and amortization and allowance for equity funds used during
construction (AFUDC)). Management uses EBITDA to compare the financial
performance of our segments and to internally manage those business segments.
Management believes that EBITDA provides useful information to investors as a
measure of comparability to peer companies. EBITDA should not be considered an
alternative to, or more meaningful than, net income or cash flow as determined
in accordance with U.S. GAAP. EBITDA calculations may vary from company to
company; therefore our computation of EBITDA may not be comparable to a
similarly titled measure of another company.


                                       11

<PAGE>

RECONCILIATION OF NET INCOME (LOSS) TO EBITDA

<TABLE>
<CAPTION>
                                 INTERSTATE    NATURAL GAS
THREE MONTHS ENDED              NATURAL GAS   GATHERING AND
MARCH 31, 2006                    PIPELINE      PROCESSING    OTHER (a)    TOTAL
------------------              -----------   -------------   ---------   -------
                                                  (In thousands)
<S>                             <C>           <C>             <C>         <C>
Net income (loss)                 $31,920        $19,565      $(16,799)   $34,686
Minority interest                  11,206             --            --     11,206
Interest expense, net              11,249             (2)       11,457     22,704
Depreciation and amortization      16,908          4,306           172     21,386
Income tax                          2,157              7          (133)     2,031
AFUDC                                (247)            --            --       (247)
                                  -------        -------      --------    -------
EBITDA                            $73,193        $23,876      $ (5,303)   $91,766
                                  =======        =======      ========    =======
</TABLE>

<TABLE>
<CAPTION>
THREE MONTHS ENDED
MARCH 31, 2005
------------------
<S>                               <C>            <C>          <C>         <C>
Net income (loss)                 $32,149        $13,690      $(11,170)   $34,669
Minority interest                  12,189             --            --     12,189
Interest expense, net              11,204             54         9,908     21,166
Depreciation and amortization      16,569          3,958           955     21,482
Income tax                            730              4           450      1,184
AFUDC                                 (18)            --            --        (18)
                                  -------        -------      --------    -------
EBITDA                            $72,823        $17,706      $    143    $90,672
                                  =======        =======      ========    =======
</TABLE>

(a)  Includes other items not allocable to segments.

5.   NET INCOME PER UNIT

Net income per unit is computed by dividing net income, after deduction of the
general partners' allocation, by the weighted average number of outstanding
common units. The general partners' allocation is equal to an amount based upon
their collective 2% general partner interest, adjusted for incentive
distributions. The incentive distribution allocated to the general partners
totaled $3.1 million for the first quarter of 2006, which will be paid to the
general partners during the second quarter. The amount of distribution to
partners shown on the accompanying consolidated statement of changes in
partners' equity included incentive distributions paid to the general partners
in the first quarter of 2006 of approximately $2.0 million.

On April 18, 2006, we declared a cash distribution of $0.88 per unit ($3.52 per
unit on an annualized basis) for the first quarter ended March 31, 2006. The
distribution is payable on May 15, 2006, to unitholders of record on April 28,
2006.

6.   RATES AND REGULATORY ISSUES

As required by the provisions of the settlement of Northern Border Pipeline's
last rate case, on November 1, 2005, we filed a rate case with the Federal
Energy Regulatory Commission (FERC). In December 2005, the FERC issued an order
that identified issues that were raised in the proceeding, accepted the proposed
rates but suspended their effectiveness until May 1, 2006, at which time the new
rates will be collected subject to refund until final resolution of the rate
case. Information about our regulatory proceedings is included in Note 6 of the
Financial Statements in our annual report on Form 10-K for the year ended
December 31, 2005.


                                       12

<PAGE>

7.   COMMITMENTS AND CONTINGENCIES

BLACK MESA

On December 31, 2005, we shut down our coal slurry pipeline operation. The
Mohave Generating Station co-owners, Navajo Nation, Hopi Tribe, Peabody Western
Coal Company and other interested parties continue to negotiate water source and
coal supply issues and Black Mesa is working to resolve coal slurry
transportation issues so that operations may resume in the future. If there are
successful resolutions of these issues and the project receives a favorable
Environmental Impact Statement, Black Mesa will reconstruct the coal slurry
pipeline in late 2008 and 2009 for an anticipated in service date during 2010.

If the pipeline is reconstructed, we anticipate Black Mesa's capital
expenditures for the project will be in the range of $175 million to $200
million, supported by revenue from a new transportation contract. If the Mohave
Generating Station is permanently closed, we expect to incur pipeline removal
and remediation costs of approximately $1 million to $2 million, net of salvage,
and a non-cash impairment charge of approximately $10 million related to the
remaining undepreciated cost of the pipeline assets and goodwill.

We expect to incur approximately $2 million to $4 million of operations and
maintenance expense in 2006 primarily related to employee standby costs.
Negotiations continue with various parties that may result in recovery of some
of these standby costs. We may be required to take an impairment charge in
accordance with Statement of Financial Accounting Standards (SFAS) No. 142 and
SFAS No. 144 prior to final resolution of the issues concerning the Mohave
Generating Station even though the project may ultimately proceed.

LEGAL PROCEEDINGS

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.

ENVIRONMENTAL LIABILITIES

We are subject to federal, state and local environmental laws and regulations.
Also, it is possible that other developments, such as increasingly stringent
environmental laws, regulations and enforcement policies could result in
substantial costs and liabilities to us.

8.   ACCOUNTING PRONOUNCEMENTS

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

9.   SUBSEQUENT EVENTS

ONEOK TRANSACTIONS

In April 2006, under the Contribution Agreement, we acquired all of ONEOK's
gathering and processing and pipelines and storage assets for approximately 36.5
million Class B units. The Class B limited partner units and the related general
partner interest contribution were valued at approximately $1.65 billion. The
assets will be recorded at historical cost rather than at fair value since these
transactions were between affiliates under common control. ONEOK now owns
approximately 37.0 million of our limited partner units, which when combined
with its general partner interest, increases its total interest in us to 45.7%.
Under the ONEOK Purchase and Sale Agreement, we purchased all of ONEOK's natural
gas liquids assets for $1.35 billion in cash. We used $1.05 billion drawn under
the Bridge Facility, coupled with the proceeds from the sale of the 20%
partnership interest in Northern Border Pipeline Company, to finance the
transaction.


                                       13

<PAGE>

DISPOSITION OF 20% INTEREST IN NORTHERN BORDER PIPELINE

In April 2006, under the Partnership Interest Purchase and Sale Agreement dated
as of December 31, 2005, we completed the sale of a 20% partnership interest in
Northern Border Pipeline to TC PipeLines for approximately $297 million. We and
TC PipeLines each now own a 50% interest in Northern Border Pipeline, with an
affiliate of TransCanada becoming operator of the pipeline effective April 1,
2007. Beginning in the second quarter, we will no longer consolidate Northern
Border Pipeline, effective as of January 1, 2006. Instead, our ownership of
Northern Border Pipeline will be reported as investment in unconsolidated
affiliates on our balance sheet. Our share of Northern Border Pipeline's
operating results will be reported as equity earnings in unconsolidated
affiliates on our statement of income.

BRIDGE FACILITY

On April 6, 2006, we entered into a $1.1 billion 364-day credit agreement with a
syndicate of banks and borrowed $1.05 billion to complete the ONEOK
Transactions. Until May 6, 2006, we can make one additional borrowing under the
Bridge Facility of up to $50 million for purposes of making payments related to
the ONEOK Transactions. Additionally, we must make mandatory prepayments with
the net cash proceeds of any asset disposition in excess of $10 million, or from
the net cash proceeds received from any issuance of equity or of debt having a
term greater than one year. Amounts outstanding under the Bridge Facility must
be repaid on or before April 5, 2007. The interest rate applied to amounts
outstanding under the Bridge Facility may, at our option, be the lender's base
rate or an adjusted London Interbank Offered Rate plus a spread that is based
upon our long-term unsecured debt ratings.

Under the Bridge Facility, we are required to comply with certain financial,
operational and legal covenants. Among other things, we are required to maintain
a ratio of EBITDA (net income plus minority interests in net income, interest
expense, income taxes and depreciation and amortization) to interest expense of
greater than 3 to 1. We are also required to maintain a ratio of indebtedness to
adjusted EBITDA (EBITDA adjusted for pro forma operating results of acquisitions
made during the year) of no more than 4.75 to 1. If we consummate one or more
acquisitions in which the aggregate purchase price is $25 million or more, the
allowable ratio of indebtedness to adjusted EBITDA will be temporarily increased
to 5.25 to 1. Upon any breach of these covenants, amounts outstanding under the
Bridge Facility may become immediately due and payable.

ACQUISITION OF GUARDIAN PIPELINE INTERESTS

In April 2006, we executed a Purchase and Sale Agreement and acquired 66-2/3%
interest in Guardian Pipeline not owned by us for approximately $77 million. We
used borrowings from our credit facility to fund our acquisition of the
additional interest in Guardian Pipeline. We will begin consolidating Guardian
Pipeline in the second quarter, effective January 1, 2006, instead of being
reflected as investment in unconsolidated affiliates on our balance sheet and
equity earnings in unconsolidated affiliates on our statement of income.

ROCKY MOUNTAIN NATURAL GAS LIQUIDS PIPELINE JOINT VENTURE

In May 2006, we entered into an agreement with a subsidiary of Williams to form
a joint venture called Overland Pass Pipeline Company, LLC. The joint-venture
company will build a 750-mile natural gas liquids pipeline that will transport
up to 110,000 barrels per day of unprocessed natural gas liquids from Opal,
Wyoming to Conway, Kansas, one of the nation's primary natural gas liquids
supply and storage hubs. Additional pump facilities would increase the capacity
to 150,000 barrels per day. Initially, we will own 99% of the joint venture and
Williams will own the remaining 1%. Williams will have the option to increase
its ownership to 50% and become operator within two years of the pipeline
becoming operational. As part of a long-term agreement, Williams will dedicate
its natural gas liquids production from two of its gas processing plants in
Wyoming to the joint-venture company. We will provide downstream fractionation
and transportation services. The natural gas liquids pipeline project is
estimated to cost approximately $450 million. We plan to invest approximately
$160 million to expand our existing fractionation capabilities and capacity of
our natural gas liquids distribution pipelines. Financing for both projects may
include a combination of short- or long-term debt or equity. Pending all
necessary approvals, the target in-service date for the natural gas liquids
pipeline is early 2008.


                                       14

<PAGE>

ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
        OF OPERATIONS

The following discussion and analysis should be read in conjunction with our
unaudited consolidated financial statements and notes to consolidated financial
statements included under Item 1.

In this report, references to "we," "us," "our" or the "Partnership"
collectively refer to Northern Border Partners, L.P., our subsidiary, Northern
Border Intermediate Limited Partnership, and its subsidiaries.

EXECUTIVE SUMMARY

OVERVIEW

Northern Border Partners is a publicly traded Delaware limited partnership that
was formed in 1993. Our common units are listed on the NYSE under the trading
symbol "NBP." For the first quarter ended March 31, 2006, our operations were
conducted through the following two business segments:

     -    Interstate Natural Gas Pipeline, which provides natural gas
          transportation services; and

     -    Natural Gas Gathering and Processing, which gathers, processes and
          compresses natural gas, and fractionates natural gas liquids.

RECENT DEVELOPMENTS

The following is a summary of our significant developments since December 31,
2005:

Guardian Pipeline Revenue and Cost Study - In February 2006, the FERC issued an
order accepting Guardian Pipeline's revenue and cost study that requested
approval of a settlement agreement to re-establish the rates initially approved
by the FERC and to reduce the depreciation rate from 3.33% to 2.0%, effective
January 1, 2005.

Guardian Pipeline II Project - In February 2006, Guardian Pipeline announced
that it signed precedent agreements with two major Wisconsin utility companies
to expand its existing natural gas pipeline system in eastern Wisconsin. The
proposed project will expand and extend the existing pipeline approximately 106
miles from its current terminus near Ixonia, Wisconsin to the Green Bay area,
adding approximately 537 MMcf/d of capacity. Guardian Pipeline's capital costs
for the project are estimated to range between $220 million and $240 million.
Pending all necessary approvals, the target in-service date is November 2008.

Midwestern Gas Transmission Eastern Extension Project - In March 2006,
Midwestern Gas Transmission accepted the certificate of public convenience and
necessity issued by the FERC for its Eastern Extension Project. The Eastern
Extension Project will add 31 miles of natural gas pipeline with approximately
120 MMcf/d of transportation capacity. It is estimated that the project will
cost approximately $28 million. Due to the delay in obtaining the FERC
certificate, the Eastern Extension Project's proposed in-service date of
November 2006 will likely also be delayed.

Amended and Restated Credit Agreement - In March 2006, we entered into a $750
million amended and restated revolving credit agreement and terminated our
existing $500 million revolving credit agreement.

Acquisition of ONEOK Assets - In April 2006, under the Contribution Agreement,
we acquired all of ONEOK's gathering and processing and pipelines and storage
assets for approximately 36.5 million Class B units. The Class B limited partner
units and the related general partner interest contribution were valued at
approximately $1.65 billion. ONEOK now owns approximately 37.0 million of our
limited partner units, which when combined with its general partner interest,
increases its total interest in us to 45.7%. Under the ONEOK Purchase and Sale
Agreement, we purchased all of ONEOK's natural gas liquids assets for $1.35
billion in cash. We used $1.05 billion drawn under our $1.1 billion, 364-day
credit agreement coupled with the proceeds from the sale of the 20% partnership
interest in Northern Border Pipeline Company to finance the transaction.


                                       15

<PAGE>

Our Audit Committee, which consists solely of independent members, determined
that the ONEOK transactions were fair and reasonable to us and in the interests
of our unitholders. The Audit Committee engaged independent legal counsel and an
independent financial adviser to assist in its determination.

Disposition of 20% Interest in Northern Border Pipeline - In April 2006, we
completed the sale of a 20% partnership interest in Northern Border Pipeline to
TC PipeLines under the Partnership Interest Purchase and Sale Agreement dated as
of December 31, 2005, for approximately $297 million. We and TC PipeLines each
now own a 50% interest in Northern Border Pipeline. As a result of the sale,
Northern Border Pipeline will no longer be consolidated in our financial
statements. Instead, our interest in Northern Border Pipeline will be reflected
as investment in unconsolidated affiliates on our balance sheet and equity
earnings in unconsolidated affiliates on our statement of income, effective
January 1, 2006.

As a result of the transaction, the General Partnership Agreement for Northern
Border Pipeline was amended and restated, effective April 6, 2006. The major
provisions adopted or changed included the following:

     -    The Management Committee of Northern Border Pipeline will consist of
          four members. Each partner will designate two members and TC PipeLines
          will designate one of its members as chairman.

     -    The Management Committee will designate the members of the Audit
          Committee, which will consist of three members. One member will be
          selected by the partner whose affiliate is the operator and two
          members will be selected by the other partner.

     -    Northern Plains will operate Northern Border Pipeline until April 1,
          2007. Effective April 1, 2007, an affiliate of TransCanada will become
          the operator.

Our Audit Committee determined that the disposition of the 20% interest in
Northern Border Pipeline was fair and reasonable to us and in the interests of
our unitholders. The Audit Committee engaged independent legal counsel and an
independent financial adviser to assist in its determination.

Purchase and Sale of General Partner Interest - In April 2006, under the
Purchase and Sale Agreement between ONEOK and an affiliate of TransCanada, ONEOK
acquired Northwest Border, an affiliate of TransCanada that held a 0.35% general
partner interest in us. As a result, ONEOK owns our entire 2% general partner
interest.

Change of Directors and Officers - In April 2006, concurrent with the completion
of ONEOK's purchase of Northwest Border, Paul E. Miller resigned as a member of
our Partnership Policy Committee and John W. Gibson was appointed by Northwest
Border to replace him. In addition, several appointments of our principal
officers were announced, effective April 7, 2006, which included:

     -    David Kyle, chairman and chief executive officer of ONEOK, was
          appointed our chairman and chief executive officer;

     -    John W. Gibson, formerly president of ONEOK Energy Companies, was
          appointed our president and chief operating officer;

     -    James C. Kneale, executive vice president, Finance and Administration
          and chief financial officer of ONEOK, was appointed our chief
          financial officer;

     -    Jerry L. Peters, formerly our chief financial officer, was appointed
          our senior vice president, chief accounting officer and treasurer;

     -    John R. Barker, senior vice president and general counsel of ONEOK,
          was appointed our executive vice president, general counsel and
          secretary;

     -    William R. Cordes, formerly our chief executive officer, was appointed
          president of Northern Border Pipeline; and

     -    Janet K. Place, was appointed our vice president, associate general
          counsel and assistant secretary, and general counsel of Northern
          Border Pipeline.

Bridge Facility - In April 2006, we entered into a $1.1 billion 364-day credit
agreement with several financial institutions to complete the ONEOK
Transactions. Amounts outstanding under the agreement must be repaid on or
before April 5, 2007.


                                       16

<PAGE>

Increased Cash Distribution - In April 2006, we increased our cash distribution
by $0.08 per unit to $0.88 per unit for the first quarter of 2006, payable on
May 15, 2006, to unitholders of record as of April 28, 2006.

Northern Border Pipeline Chicago III Expansion Project - In April 2006, the
Chicago III Expansion Project went into service as planned, adding 130 MMcf/d of
transportation capacity on the eastern portion of the pipeline into the Chicago
area.

Acquisition of Guardian Pipeline Interests - In April 2006, we executed a
Purchase and Sale Agreement and acquired 66-2/3% interest in Guardian Pipeline
not owned by us for approximately $77 million. As a result of the acquisition,
Guardian Pipeline will be consolidated in our financial statements and reported
in our Interstate Natural Gas Pipeline segment instead of reflected as
investment in unconsolidated affiliates on our balance sheet and equity earnings
in unconsolidated affiliates on our statement of income.

Rocky Mountain Natural Gas Liquids Pipeline Joint Venture - In May 2006, we
entered into an agreement with a subsidiary of Williams to form a joint venture
called Overland Pass Pipeline Company, LLC. The joint-venture company will build
a 750-mile natural gas liquids pipeline that will transport up to 110,000
barrels per day of unprocessed natural gas liquids from Opal, Wyoming to Conway,
Kansas, one of the nation's primary natural gas liquids supply and storage hubs.
Additional pump facilities would increase the capacity to 150,000 barrels per
day. Initially, we will own 99% of the joint venture and Williams will own the
remaining 1%. Williams will have the option to increase its ownership to 50% and
become operator within two years of the pipeline becoming operational. As part
of a long-term agreement, Williams will dedicate its natural gas liquids
production from two of its gas processing plants in Wyoming to the joint-venture
company. We will provide downstream fractionation and transportation services.
The natural gas liquids pipeline project is estimated to cost approximately $450
million. We plan to invest approximately $160 million to expand our existing
fractionation capabilities and capacity of our natural gas liquids distribution
pipelines. Financing for both projects may include a combination of short- or
long-term debt or equity. Pending all necessary approvals, the target in-service
date for the natural gas liquids pipeline is early 2008.

CRITICAL ACCOUNTING ESTIMATES

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

There has been no change to our critical accounting estimates during the first
quarter ended March 31, 2006. Information about our critical accounting
estimates is included under Item 7, "Management's Discussion and Analysis of
Financial Condition and Results of Operations-Critical Accounting Estimates," in
our annual report on Form 10-K for the year ended December 31, 2005.


                                       17

<PAGE>

RESULTS OF OPERATIONS

SELECTED FINANCIAL AND OPERATING RESULTS BY SEGMENT

The following table summarizes financial and operating results by segment for
the three months ended March 31, 2006, and 2005:

<TABLE>
<CAPTION>
                                                 THREE MONTHS ENDED
                                                     MARCH 31,
                                                -------------------
                                                  2006       2005
                                                --------   --------
                                                   (In thousands,
                                                  except operating
                                                       data)
<S>                                             <C>        <C>
Operating revenue:
   Interstate natural gas pipeline              $ 95,642   $ 96,645
   Natural gas gathering and processing           73,513     57,573
   Other                                           1,644      6,161
                                                --------   --------
      Total operating revenue                    170,799    160,379
                                                --------   --------
Operating income (loss):
   Interstate natural gas pipeline                55,325     55,638
   Natural gas gathering and processing           13,991      9,502
   Other                                          (5,653)    (1,602)
                                                --------   --------
      Total operating income                      63,663     63,538
                                                --------   --------
Income (loss) from continuing operations:
   Interstate natural gas pipeline                31,920     32,149
   Natural gas gathering and processing           19,565     13,690
   Other                                         (16,808)   (11,560)
                                                --------   --------
      Total income from continuing operations     34,677     34,279
                                                --------   --------
Discontinued operations, net of tax                    9        390
                                                --------   --------
Net income                                      $ 34,686   $ 34,669
                                                ========   ========
Operating data by segment (1):
   Interstate natural gas pipeline:
      MMcf delivered                             305,280    306,692
      MMcf/d average throughput                    3,468      3,501
   Natural gas gathering and processing:
      MMcf/d gathered                              1,095      1,049
      MMcf/d processed                                65         60
</TABLE>

(1)  Operating data includes 100% of the volumes for joint venture investments
     as well as for wholly owned subsidiaries.

CONSOLIDATED OPERATING RESULTS

Operating revenue increased $10.4 million, or 6%, for the first quarter of 2006
compared with the same quarter of 2005 due to higher Natural Gas Gathering and
Processing segment revenue which offset the slightly lower Interstate Natural
Gas Pipeline segment revenue and the loss of coal slurry pipeline revenue
resulting from the shut down of Black Mesa on December 31, 2005. The coal slurry
pipeline results are not reported as a discontinued operation because we believe
that the coal slurry pipeline operation is likely to resume in the future.
Additional information about our coal slurry pipeline operation is included in
this section under "Other" and Item 7, "Management's Discussion and Analysis of
Financial Condition and Results of Operations-Executive Summary," in our annual
report on Form 10-K for the year ended December 31, 2005.

Operating income was flat for the first quarter of 2006 compared with the same
quarter last year. The increased contribution of the Natural Gas Gathering and
Processing segment was offset by due diligence, legal and other expenses related
to the ONEOK and TransCanada transactions described in this section under
"Recent Developments."


                                       18

<PAGE>

Income from continuing operations was also flat for the first quarter of 2006
compared with the same quarter last year. Increased interest and income tax
expense were offset by higher equity earnings in unconsolidated affiliates.

INTERSTATE NATURAL GAS PIPELINE SEGMENT

OVERVIEW

The Interstate Natural Gas Pipeline segment transports natural gas primarily
from the Western Canada Sedimentary Basin to the Midwestern U.S. At March 31,
2006, the Interstate Natural Gas Pipeline segment consisted of the following:

     -    70% general partnership interest in Northern Border Pipeline;

     -    Midwestern Gas Transmission;

     -    Viking Gas Transmission; and

     -    33-1/3% interest in Guardian Pipeline.

In April 2006, we completed the sale of a 20% partnership interest in Northern
Border Pipeline to TC PipeLines. We and TC PipeLines each now own a 50% interest
in Northern Border Pipeline. In addition, we acquired 66-2/3% interest in
Guardian Pipeline not owned by us. Additional information about these
transactions is included in this section under "Recent Developments."

KNOWN TRENDS AND UNCERTAINTIES

We continue to expect that Canadian natural gas export volumes in 2006 will
remain near 2005 levels despite increased production in Canada as a result of
the greater number of Canadian drilling rigs in operation. We also continue to
expect U.S. demand for natural gas in 2006 to be similar to 2005 levels.
Residential demand for natural gas fell below normal levels during the 2005-2006
heating season as a result of warm temperatures in January and relatively normal
temperatures in February. However, the Energy Information Administration
projects that increased industrial demand in 2006 will offset the reduced demand
of residential users.

We continue to expect that Northern Border Pipeline revenue in 2006 will be
comparable with 2005 revenue, although market conditions have changed. In April
and May of 2005, we did not sell all of our firm transportation capacity on
Northern Border Pipeline due to decreased demand for Canadian natural gas as a
result of greater supply competition in the Midwestern U.S. and increased
natural gas storage injections. When storage levels approached full capacity and
summer temperatures were higher than normal during the third quarter of 2005,
demand for the pipeline's transportation capacity increased. Natural gas storage
levels in Western Canada were higher during the first quarter of 2006 compared
with the first quarter of 2005 and the five-year average for the same period as
a result of relatively warm winter temperatures. Increased natural gas
throughput on the TransCanada pipeline system to Eastern markets, due in part to
greater demand for Canadian natural gas supply as a result of lingering supply
disruptions related to Hurricanes Katrina and Rita, is expected to slow storage
injection activity in Western Canada during the second quarter of 2006. In
addition, Western U.S. demand for Canadian natural gas is expected to modestly
decline in 2006 compared with 2005 due to the return of normal snowpack in the
region that will cause gas-fired electric generation to be displaced with
hydroelectric generation.

OPERATING RESULTS

The Interstate Natural Gas Pipeline segment reported income from continuing
operations of $31.9 million for the first quarter ended March 31, 2006, which
was relatively flat compared with $32.1 million for the same quarter of 2005. A
modest decline in Northern Border Pipeline revenue was offset by increased
Midwestern Gas Transmission revenue.

Operating revenue decreased slightly for the first quarter ended March 31, 2006,
compared with the same quarter of 2005. Northern Border Pipeline operating
revenue decreased $3.0 million for the first quarter of 2006 compared with the
same quarter last year primarily as a result of discounted transportation rates,
transportation capacity that was sold for shorter transportation paths and some
unsold firm transportation capacity in March 2006. Midwestern Gas Transmission
partially offset this decrease primarily with additional revenue generated from
the Southbound Expansion, which went into service in November 2005.


                                       19

<PAGE>

Operations and maintenance expense decreased $1.6 million for the first quarter
ended March 31, 2006, compared with the same quarter of 2005. Viking Gas
Transmission recorded an unfavorable gas imbalance adjustment of $1.4 million
during the first quarter of 2005.

Equity earnings of unconsolidated affiliates represent earnings from our
one-third interest in Guardian Pipeline.

Minority interests in net income represent the 30% minority interest in Northern
Border Pipeline.

NATURAL GAS GATHERING AND PROCESSING SEGMENT

OVERVIEW

The Natural Gas Gathering and Processing segment gathers natural gas from
producers' wells and central delivery points in three producing basins: the
Williston Basin, which spans portions of Montana, North Dakota and the Canadian
province of Saskatchewan, and the Powder River and Wind River Basins of Wyoming.

Our Williston Basin facilities compress and transport raw natural gas, primarily
associated with oil production, through pipelines to our processing facilities
where water and other contaminants are removed and valuable natural gas liquids
are extracted. We separate the natural gas liquids into marketable components
utilizing a distillation process known as fractionation and sell the components
to refineries or local markets. We compress the remaining residue gas,
consisting primarily of methane, and deliver it to interstate natural gas
pipelines.

Our Powder River Basin facilities compress and transport coalbed methane gas
primarily to the Bighorn Gas Gathering and Fort Union Gas Gathering trunk
gathering systems for transport and delivery to interstate natural gas
pipelines.

Our Wind River Basin facilities consist of an interest in a trunk gathering
system that receives natural gas from pipeline interconnections with
producer-owned gathering systems and processing plants. The natural gas is
processed as necessary and delivered to interstate natural gas pipelines.

At March 31, 2006, the Natural Gas Gathering and Processing segment consisted of
the following subsidiaries:

     -    Bear Paw Energy, with operations in the Williston and Powder River
          Basins; and

     -    Crestone Energy, which owns:

          -    49% interest in Bighorn Gas Gathering, with operations in the
               Powder River Basin;

          -    37% interest in Fort Union Gas Gathering, with operations in the
               Powder River Basin; and

          -    35% interest in Lost Creek Gathering, with operations in the Wind
               River Basin.

KNOWN TRENDS AND UNCERTAINTIES

Relatively strong natural gas and crude oil prices continued to drive increased
production in the Williston and Power River Basins during the first quarter of
2006. In the Williston Basin, we established a record number of well connections
during the first quarter of 2006 as a result of increased drilling activity.
Transportation and refining capacity constraints for crude oil only moderately
impacted natural gas production in the Williston Basin as expected. Further
development of the Big George coals, located in the center of the Powder River
Basin, resulted in increased volumes during the first quarter of 2006 compared
with the same quarter last year for our joint venture interests in Bighorn Gas
Gathering and Fort Union Gas Gathering.

OPERATING RESULTS

The Natural Gas Gathering and Processing segment reported income from continuing
operations of $19.6 million for the first quarter ended March 31, 2006, an
increase of $5.9 million, or 43%, compared with $13.7 million for the same
quarter of 2005 primarily as a result of the following:

     -    increased gathering and processing volumes in the Williston Basin; and

     -    higher commodity prices realized on equity natural gas and natural gas
          liquids derived from percentage-of-proceeds contracts.


                                       20

<PAGE>

Operating revenue increased $15.9 million, or 28%, for the first quarter ended
March 31, 2006, compared with the same quarter of 2005 due to increased revenue
from our Williston Basin operations, which is derived primarily from the sale of
natural gas and natural gas liquids gathered and processed under
percentage-of-proceeds contracts. This increase more than offset decreased
gathered volumes for our wholly owned Powder River Basin operations.

Williston Basin inlet volumes increased 4 MMcf/d, or 7%, as a result of growth
projects that were completed during the second and third quarters of 2005.
Optimization projects completed during the fourth quarter of 2005 resulted in
improved natural gas liquids recoveries. This, in turn, resulted in higher
natural gas liquids sales volume of 32.6 million gallons for the first quarter
of 2006, an increase of 3.7 million gallons, or 13%, compared with 28.9 million
gallons for the same quarter last year.

Volumes at our wholly owned Powder River Basin operations declined 32 MMcf/d, or
15%, for the first quarter of 2006 compared with the same quarter of 2005 due to
the diversion of 45 MMcf/d of low margin gathered gas by one producer to its own
system during the second quarter of 2005. However, volumes remained relatively
flat for the first quarter of 2006 compared with the fourth quarter of 2005. We
anticipate an increase in our wholly owned Powder River volumes during the
second quarter of 2006 as a result of several system expansions that are
currently underway.

Better prices were realized on our sales of natural gas and natural gas liquids
retained through percentage-of-proceeds contracts, which, in addition to higher
processing volumes, contributed to the segment's increased operating revenue.
The weighted average price of natural gas realized, net of the effects of
hedging, was $8.01 per MMBtu for the first quarter of 2006 compared with $6.65
per MMBtu for the first quarter of 2005. The weighted average price of natural
gas liquids realized, net of the effects of hedging, was $1.11 per gallon for
the first quarter of 2006 compared with $0.88 per gallon for the first quarter
of 2005.

Product purchases, which reflect the amounts we paid to producers for raw
natural gas, increased $11.6 million for the first quarter ended March 31, 2006,
compared with the same quarter of 2005. Product purchases represented 60% of
operating revenue for the first quarter of 2006 compared with 56% of operating
revenue for the same quarter of 2005 due to declining percentage-of-proceeds
contract margins as a result of increased competition.

Equity earnings of unconsolidated affiliates increased $1.4 million for the
first quarter ended March 31, 2006, compared with the same quarter of 2005,
primarily due to increased volumes in the Powder River Basin, which were
partially offset by decreased volumes in the Wind River Basin. In addition,
since August 2005, we increased our interest in Fort Union Gas Gathering to 37%
compared with 33.3% during the first quarter of 2005.

OTHER

On December 31, 2005, Black Mesa's transportation contract with the coal
supplier of the Mohave Generating Station expired and our coal slurry pipeline
operations were shut down as expected. Under a consent decree, the Mohave
Generating Station must complete significant pollution control investments to
operate in the future. In addition, issues surrounding the use of an alternative
water source for the coal slurry pipeline must be resolved. Black Mesa is
working to resolve coal slurry transportation issues and interested parties
continue to negotiate water and coal supply issues so that operations may resume
in the future. If these issued are resolved and the project receives a favorable
Environmental Impact Statement, portions of the pipeline would be modified or
reconstructed beginning in late 2008 and 2009, supported by revenue from a new
transportation contract, for an anticipated in-service date during 2010.

Black Mesa reported an operating loss of $0.1 million for the first quarter
ended March 31, 2006, compared with operating income of $0.9 million for the
same quarter of 2005. We expect the impact associated with the shutdown will be
a reduction of net income of approximately $6 million in 2006 compared with
2005, which includes approximately $2 million to $4 million of operations and
maintenance expense we expect to incur related to standby costs. Negotiations
continue with various parties that may result in the recovery of some of these
standby costs.


                                       21
<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 limited and general partners primarily with
operating cash flow. Capital resources for acquisitions and maintenance and
growth expenditures are funded by a variety of sources, including cash generated
from operating activities, borrowings under bank credit facilities, issuance of
senior unsecured notes or sale of additional limited partner interests. Our
ability to access capital markets for debt and equity financing under reasonable
terms depends on our financial condition, credit ratings and market conditions.
We believe that our ability to obtain financing at reasonable rates and our
history of consistent cash flow from operating activities provide a solid
foundation to meet our future liquidity and capital resource requirements.

DEBT AND CREDIT FACILITIES

The following table summarizes our and Northern Border Pipeline's debt and
credit facilities outstanding as of March 31, 2006:

<TABLE>
<CAPTION>
                                                          PAYMENTS DUE BY PERIOD
                                                          ----------------------
                                                          LESS THAN    LONG-TERM
                                                TOTAL      ONE YEAR     PORTION
                                             ----------   ---------   ----------
                                                          (In thousands)
<S>                                          <C>          <C>         <C>
Northern Border Pipeline:
   $175 million credit agreement due 2010,   $    7,000    $  7,000   $       --
      average 5.16% (a)
   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
Northern Border Partners:
   $750 million credit agreement due 2011,
      average 7.75% (a)                         231,000     231,000           --
   8.875% senior notes due 2010                 250,000          --      250,000
   7.10% senior notes due 2011                  225,000          --      225,000
                                             ----------    --------   ----------
         Total                               $1,313,000    $238,000   $1,075,000
                                             ==========    ========   ==========
</TABLE>

(a)  Northern Border Partners and Northern Border Pipeline are each required to
     pay a facility fee of 0.125% and 0.075%, respectively, on the principal
     commitment amount of their credit agreements.

REVOLVING CREDIT AGREEMENTS

In March 2006, we entered into a $750 million amended and restated revolving
credit agreement with certain financial institutions and terminated our existing
$500 million revolving credit agreement. The weighted average interest rate on
amounts outstanding under these agreements during the first quarter of 2006 was
5.40%. At our option, the interest rate applied to the amounts outstanding under
the credit agreement may be the lender's base rate or an adjusted London
Interbank Offered Rate (LIBOR) plus a spread that is based on our long-term
unsecured debt ratings. We are required to pay interest on the outstanding
amounts periodically. The term of the agreement is five years, at which time we
are required to pay off all outstanding amounts.

We are required to comply with certain financial, operational and legal
covenants, including the maintenance of an EBITDA (net income plus minority
interests in net income, interest expense, income taxes and depreciation and
amortization) to interest expense ratio of greater than 3 to 1 and a debt to
adjusted EBITDA (EBITDA adjusted for pro forma operating results of acquisitions
made during the year) ratio of no more than 4.75 to 1. If we consummate one or
more acquisitions in which the aggregate purchase price is $25 million or more,
the allowable ratio of debt to adjusted EBITDA will be increased to 5.25 to 1
for two calendar quarters following the acquisition. If we breach any of these
covenants, amounts outstanding may become due and payable immediately.


                                       22

<PAGE>

At March 31, 2006, we had outstanding borrowings of $231 million under our $750
million revolving credit agreement and were in compliance with its covenants. On
April 6, 2006, we borrowed an additional $75 million to fund working capital
related to certain of the businesses acquired pursuant to the ONEOK transactions
described in this section under "Recent Developments." At May 4, 2006, we had
outstanding borrowings of $306 million and a $15 million letter of credit under
our agreement. We may from time to time draw on the amended and restated credit
agreement to meet working capital requirements, which borrowings are intended to
be repaid with cash generated from operations.

As of March 31, 2006, Northern Border Pipeline had outstanding borrowings of
$7.0 million under its $175 million revolving credit agreement and was in
compliance with its covenants. The weighted average interest rate related to the
borrowings on Northern Border Pipeline's credit agreement was 5.16% at March 31,
2006.

BRIDGE FACILITY

In April 2006, we entered into, and borrowed $1.05 billion under a $1.1 billion,
364-day credit agreement with several financial institutions to complete the
transactions with ONEOK described in this section under "Recent Developments."
At our option, the interest rate applied to amounts outstanding under the bridge
facility may be the lender's base rate or an adjusted LIBOR plus a spread that
is based on our long-term unsecured debt ratings. We must make mandatory
prepayments with the net cash proceeds of any asset disposition in excess of $10
million or from the net cash proceeds received from any issuance of equity or
debt having a term greater than one year. Amounts outstanding under the
agreement must be repaid on or before April 5, 2007.

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 ratio of no more than 4.75 to
1. If we consummate one or more acquisitions in which the aggregate purchase
price is $25 million or more, the allowable ratio of debt to adjusted EBITDA
will be increased to 5.25 to 1 for two calendar quarters following the
acquisition. If we breach any of these covenants, amounts outstanding under the
bridge facility may become immediately due and payable.

DEBT SECURITIES

In March 2006, we redeemed all of the outstanding Viking Gas Transmission Series
A, B, C and D senior notes, due in 2008 through 2014, at a premium of $3.6
million.

In April 2006, we acquired the remaining interest and now own 100% of Guardian
Pipeline. As of May 4, 2006, Guardian Pipeline had approximately $155 million of
senior notes outstanding; interest on the notes range from 7.61% to 8.27%, with
an average rate of 7.85%.

We anticipate issuing fixed-rate senior notes to repay borrowings under our $1.1
billion, 364-day credit facility prior to the April 2007 termination date of the
credit agreement.

EQUITY ISSUANCES

In April 2006, we amended our Partnership Agreement to provide for the issuance
of Class B units and issued 36,494,126 Class B units to ONEOK in exchange for
all of its gathering and processing and pipelines and storage assets in a
transaction described in this section under "Recent Developments." The new class
of equity securities is entitled to the same distribution rights as our
outstanding common units, but has limited voting rights and will be subordinated
to the common units with respect to the minimum quarterly distribution. The
number of Class B units issued was determined by using the average closing price
of our common units for the 20 trading days prior to the signing of the
Contribution Agreement between ONEOK and us.

We will hold a special election for holders of common units as soon as
practical, but within 12 months of issuing the Class B units, to approve the
conversion of the Class B units into common units and certain amendments to our
Partnership Agreement. The proposed amendments grant voting rights for common
units held by our general partner if a vote is held to remove our general
partner and require fair market value compensation for the general partner
interest if the general partner is removed.

If the common unitholders do not approve the conversion and the amendments, the
Class B unit distribution rights will increase to 115% of the distribution paid
on the common units. If the conversion and the amendments are approved by the
common unitholders, the Class B units will convert into common units on a
one-for-one basis.


                                       23

<PAGE>

CASH FLOW FROM OPERATING, INVESTING AND FINANCING ACTIVITIES

OPERATING ACTIVITIES

Cash provided by operating activities was $70.2 million for the three months
ended March 31, 2006, compared with $67.1 million for the same quarter of 2005.
Cash provided by operating activities increased during the first quarter of 2006
primarily as a result of the following:

     -    increased cash receipts from our natural gas gathering and processing
          operations as a result of higher operating revenue during the quarter;
          and

     -    increased distributions received from unconsolidated affiliates of
          $8.0 million, $5.5 million of which we received from Lost Creek
          Gathering to true-up our throughput volume allocation.

The increased cash provided by operating activities during the first quarter of
2006 was partially offset by the following:

     -    reduced cash flow of $3.2 million related to the shutdown of our coal
          slurry operations on December 31, 2005; and

     -    increased interest expense of $3.2 million primarily due to higher
          interest rates.

INVESTING ACTIVITIES

Cash used in investing activities was $18.4 million for the three months ended
March 31, 2006, compared with $11.3 million for the same quarter last year. The
increased use of cash during the first quarter of 2006 was primarily due to
higher growth capital expenditures of $8.3 million by the Interstate Natural Gas
Pipeline segment, $6.7 million of which was related to the Northern Border
Pipeline Chicago III Expansion Project and $2.4 million of which was related to
the Midwestern Gas Transmission Eastern Extension Project. Lower Interstate
Natural Gas Pipeline segment maintenance expenditures and investments in
unconsolidated affiliates during the first quarter of 2006 compared with the
same quarter last year partially offset the Interstate Natural Gas Pipeline
segment's increased growth expenditures.

During the first quarter of 2006, we also used operating cash, borrowings from
our credit facility and equity contributions from our minority interest holder
to fund our investing activities.

FINANCING ACTIVITIES

Cash used in financing activities was $76.2 million for the three months ended
March 31, 2006, compared with $52.4 million for the same quarter of 2005.

Distributions to minority interests during the first quarter ended March 31,
2006, decreased $2.7 million compared with the same quarter of 2005 primarily
due to Northern Border Pipeline's lower net income in the fourth quarter of
2005. Northern Border Pipeline received equity contributions of $3.1 million
from its minority interest holder during the first quarter of 2006 for its share
of the equity funding related to the Chicago III Expansion Project.

The net change in our long-term borrowings was a repayment of $22.0 million for
the first quarter of 2006 compared with net borrowings of $3.7 million for the
same quarter last year. We borrowed $197 million to pay the outstanding balance
of our existing $500 million revolving credit agreement and terminated that
agreement. We borrowed an additional $33 million under our amended and restated
revolving credit agreement and redeemed all of the outstanding Viking Gas
Transmission Series A, B, C and D senior notes and paid a premium of $3.6
million.

COMMITMENTS AND CONTINGENCIES

CASH DISTRIBUTIONS

We distribute 100% of our available cash, which generally consists of all cash
receipts less adjustments for cash disbursements and net change to reserves, to
our general and limited partners. Our income is allocated to the general
partners and limited partners according to their partnership percentages of 2%
and 98%, respectively, after the effect of any incremental income allocations
for incentive distributions to the general partners.


                                       24

<PAGE>

In April 2006, we increased our cash distribution by $0.08 per unit to $0.88 per
unit for the first quarter of 2006, payable on May 15, 2006, to unitholders of
record as of April 28, 2006.

LEGAL

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.

ENVIRONMENTAL

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. We believe that the resolution of various
environmental issues that have arisen in the ordinary course of business will
not materially impact our results of operations.

RECENT ACCOUNTING PRONOUNCEMENTS

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

FORWARD-LOOKING STATEMENTS

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

     -    the effects of weather and other natural phenomena on our operations,
          demand for our services and energy prices;

     -    competition from other U.S. and Canadian energy suppliers and
          transporters as well as alternative forms of energy;

     -    the timing and extent of changes in commodity prices for natural gas,
          natural gas liquids, electricity and crude oil;

     -    impact on drilling and production by factors beyond our control,
          including the demand for natural gas and refinery-grade crude oil;
          producers' desire and ability to obtain necessary permits; reserve
          performance; and capacity constraints on the pipelines that transport
          natural gas, crude oil and natural gas liquids from producing areas
          and our facilities;

     -    risks of trading and hedging activities as a result of changes in
          energy prices or the financial condition of our counterparties;

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

     -    the timely receipt of approval by the FERC for construction and
          operation of our interstate natural gas pipeline projects and required
          regulatory clearances; our ability to acquire all necessary
          rights-of-way and obtain agreements for interconnects in a timely
          manner, and our ability to promptly obtain all necessary materials and
          supplies required for construction;

     -    the impact of unsold and discounted capacity on Northern Border
          Pipeline being greater than expected;

     -    the ability to market pipeline capacity on favorable terms;

     -    orders by the FERC related to Northern Border Pipeline's November 2005
          rate case which are significantly different than our assumptions;


                                       25

<PAGE>

     -    risks associated with adequate supply to our gathering, processing,
          fractionation and pipeline facilities, including production declines
          which outpace new drilling;

     -    impact of a potential impairment charge if we are unable to renew our
          coal slurry pipeline contract;

     -    the effects of changes in governmental policies and regulatory
          actions, including changes with respect to income taxes, environmental
          compliance, authorized rates or recovery of gas costs;

     -    the results of administrative proceedings and litigation, regulatory
          actions and receipt of expected clearances involving regulatory
          authorities or any other local, state or federal regulatory body,
          including the FERC;

     -    actions by rating agencies concerning our credit ratings;

     -    the impact of unforeseen changes in interest rates, equity markets,
          inflation rates, economic recession and other external factors over
          which we have no control, including the effect on pension expense and
          funding resulting from changes in stock and bond market returns;

     -    our ability to access capital at competitive rates or on terms
          acceptable to us;

     -    demand for our services in the proximity of our facilities;

     -    the profitability of assets or businesses acquired by us;

     -    the risk that material weaknesses or significant deficiencies in our
          internal control over financial reporting could emerge or that minor
          problems could become significant;

     -    the impact and outcome of pending and future litigation;

     -    our ability to successfully integrate the operations of the assets
          acquired from ONEOK with our current operations;

     -    performance of contractual obligations by our customers;

     -    ability to control operating costs; and

     -    acts of nature, sabotage, terrorism or other similar acts that cause
          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 in this quarterly report under Item 1A, "Risk Factors," and under Item
1A, "Risk Factors," in our annual report on Form 10-K for the year ended
December 31, 2005. 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 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

OVERVIEW

Our exposure to market risk discussed below includes forward-looking statements
and represents an estimate of possible changes in future earnings that would
occur assuming hypothetical future movements in interest rates or commodity
prices. 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 or commodity prices and
the timing of transactions.

We are exposed to market risk due to interest rate and commodity price
volatility. Market risk is the risk of loss arising from adverse changes in
market rates and prices. We utilize financial instruments, including forwards,
swaps, collars and futures, 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 and natural gas and natural gas liquids marketing activities to
ensure our hedging activities mitigate market risks. We do not use financial
instruments for trading purposes.


                                       26

<PAGE>

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 facilities. We regularly assess the
impact of interest rate fluctuations on future cash flows and evaluate hedging
opportunities to mitigate our interest rate risk. As of March 31, 2006, we and
Northern Border Pipeline had $388 million of variable-rate debt outstanding,
$150 million of which we converted from fixed-rate to variable-rate debt through
interest rate swap agreements. Primarily as a result of the transactions
described in this section under "Recent Developments," our variable-rate debt
outstanding increased to $1,506 million as of May 1, 2006, $150 million of which
we converted from fixed-rate to variable-rate debt through interest rate swap
agreements.

If interest rates increased 1% on our borrowings outstanding as of May 1, 2006,
our annual consolidated interest expense would increase and our projected
consolidated income before income taxes would decrease by approximately $15
million.

COMMODITY PRICE RISK

Our Interstate Natural Gas Pipeline segment and the recently acquired pipelines
and storage assets are exposed to commodity price risk because our interstate
and intrastate pipelines collect natural gas from their customers as part of
their fee for services provided. When the amount of natural gas utilized in
operations by these pipelines differs from the amount provided by their
customers, the pipelines must buy or sell natural gas, or use natural gas from
inventory, and are exposed to commodity price risk. We have not entered into any
hedges with respect to our interstate and intrastate pipeline operations.

Our recently acquired natural gas liquids assets are exposed to commodity price
risk primarily as a result of natural gas liquids in storage, spread risk
associated with the relative values of the various components of the natural gas
liquids stream and the relative value of natural gas liquids purchases at one
location and sale at another location, known as basis risk. We have not entered
into any hedges with respect to our natural gas liquids marketing activities.

Our Natural Gas Gathering and Processing segment receives a significant portion
of its revenue from the sale of commodities in exchange for gathering and
processing services and is exposed to market risk due to changes in natural gas
and natural gas liquids prices. To minimize earnings volatility related to
natural gas and natural gas liquids price fluctuations, we may enter into
commodity financial instruments, including NYMEX contracts, fixed price swaps
and collars, which are all designated as cash flow hedges.

As of March 31, 2006, we hedged a portion of our projected natural gas and
natural gas liquids volumes for the remainder of 2006 as follows:

<TABLE>
<CAPTION>
                                                    NINE MONTHS ENDED       WEIGHTED
                                                    DECEMBER 31, 2006    AVERAGE HEDGE
HEDGED COMMODITY                    INSTRUMENT        HEDGED VOLUME      PRICE PER UNIT
----------------                 ----------------   -----------------   ---------------
<S>                              <C>                <C>                 <C>
Natural Gas (in MMBtu/d)         Collar                   5,236          $6.15 - $11.00
Natural Gas (in MMBtu/d)         Fixed Price Swap         7,000                   $7.87
Natural Gas Liquids (in Bbl/d)   Collar                     818         $52.08 - $60.06
Natural Gas Liquids (in Bbl/d)   Fixed Price Swap         1,354                  $43.81
</TABLE>

Our commodity price market risk, excluding the effects of hedging, is estimated
as a hypothetical decrease in the price of natural gas and natural gas liquids
at March 31, 2006. We estimate that a $1.00 per MMBtu decrease in the weighted
average price of natural gas would increase annual net income by approximately
$11 million. We estimate that a $0.10 per gallon decrease in the weighted
average price of natural gas liquids would decrease annual net income by
approximately $30 million.


                                       27

<PAGE>

ITEM 4. CONTROLS AND PROCEDURES

EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES

As of the end of the period covered by this report, our chief executive officer
and chief 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 March 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.

CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING

There were no changes in our internal control over financial reporting that
occurred during the first quarter ended March 31, 2006, that have materially
affected, or are reasonably likely to materially affect, our internal control
over financial reporting.

In May 2006, Northern Border Pipeline is implementing system modifications to
meet new transaction billing requirements in conjunction with its rate case.
This activity will cause changes to Northern Border Pipeline's internal control
over financial reporting during the second quarter of 2006.

During the fourth quarter of 2005, we began implementing a new contracting and
billing system to support the Natural Gas Gathering and Processing segment. The
new system will automate certain transactional processes, including scheduling,
plant allocations and invoicing, that are currently handled manually.
Implementation is scheduled to take place during the third quarter of 2006, at
which time we will have changes to our internal control over financial
reporting.

In April 2006, we entered into a services agreement with ONEOK and also acquired
all of ONEOK's gas gathering and processing, natural gas liquids and pipeline
and storage assets. In addition, ONEOK now owns 100% of our general partnership
interest. As a result of these activities and the integration of the operations
of the ONEOK acquired assets with our existing operations, there could be
changes to our internal control over financial reporting.

                           PART II - OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

WILL PRICE, ET AL. V. GAS PIPELINES, ET AL. (F/K/A QUINQUE OPERATING COMPANY, ET
AL. V. GAS PIPELINES, ET AL.), 26TH JUDICIAL DISTRICT, DISTRICT COURT OF STEVENS
COUNTY, KANSAS, CIVIL DEPARTMENT, CASE NO. 99C30 (PRICE I).

Plaintiffs brought suit on May 28, 1999, against MidContinent Market Center,
Inc., ONEOK Field Services Company, ONEOK WesTex Transmission, L.P., and ONEOK
Hydrocarbon, L.P. (formerly Koch Hydrocarbon, LP), all of which were recently
acquired by us, as well as approximately 225 other defendants. Plaintiffs sought
class certification for their claims that the defendants had underpaid gas
producers and royalty owners throughout the United States by intentionally
understating both the volume and the heating content of purchased gas. After
extensive briefing and a hearing, the court refused to certify the class sought
by the plaintiffs. Plaintiffs then filed an amended petition limiting the
purported class to gas producers and royalty owners in Kansas, Colorado and
Wyoming and limiting the claim to under measurement of volumes. Oral argument on
the plaintiffs' motion to certify this suit as a class action was conducted on
April 1, 2005. The court has not yet ruled on the class certification issue.


                                       28

<PAGE>

WILL PRICE AND STIXON PETROLEUM, ET AL. V. GAS PIPELINES, ET AL., 26TH JUDICIAL
DISTRICT, DISTRICT COURT OF STEVENS COUNTY, KANSAS, CIVIL DEPARTMENT, CASE NO.
03C232 (PRICE II).

This action was filed by the plaintiffs on May 12, 2003, after the court had
denied class status in Price I. Plaintiffs claim that 21 groups of defendants,
including MidContinent Market Center, Inc., ONEOK Field Services Company, ONEOK
WesTex Transmission, L.P., and ONEOK Hydrocarbon, L.P. (formerly Koch
Hydrocarbon, LP), all of which were recently acquired by us, intentionally
underpaid gas producers and royalty owners by understating the heating content
of purchased gas in Kansas, Colorado and Wyoming. Price II has been consolidated
with Price I for the determination of whether either or both cases may properly
be certified as class actions. Oral argument on the plaintiffs' motion to
certify this suit as a class action was conducted on April 1, 2005. The court
has not yet ruled on the class certification issue.

PRAXAIR, INC. V. ONEOK FIELD SERVICES COMPANY, ET AL., DISTRICT COURT OF
ELLSWORTH COUNTY, KANSAS, CASE NO. 04-C-17.

Plaintiff is alleging that ONEOK Field Services Company and ONEOK Bushton
Processing, Inc. wrongfully declared force majeure under its agreement with
Plaintiff for delivery of helium. Plaintiff's initial petition filed in March
2004 claimed damages for breach of contract and breach of good faith and fair
dealing in excess of $20 million. Discovery phase of the proceeding is still
underway. In late March 2006, the plaintiff increased its damage claim to $41.5
million. Trial is scheduled to begin October 10, 2006.

ITEM 1A. RISK FACTORS

The following new or modified risk factors, most of which relate to the assets
and businesses acquired from ONEOK, should be read in conjunction with the risk
factors disclosed in our annual report on Form 10-K for the year ended December
31, 2005:

RISKS INHERENT IN OUR BUSINESS

THE VOLATILITY OF NATURAL GAS AND NATURAL GAS LIQUIDS PRICES COULD ADVERSELY
AFFECT OUR CASH FLOW.

A significant portion of our natural gas gathering and processing revenue is
derived from the sale of commodities we retain for our gathering and processing
services. Additionally, certain of our gas gathering and processing assets
recently acquired in Oklahoma and Kansas have "keep whole" processing contracts,
under which we extract natural gas liquids and return to the producer volumes of
merchantable natural gas containing the same amount of Btus that were removed as
natural gas liquids. This type of contract exposes us to the keep whole spread,
or gross processing spread, which is the relative difference in the prices of
natural gas liquids and natural gas on a Btu basis. As a result, we are
sensitive to natural gas and natural gas liquids price fluctuations. Natural gas
and natural gas liquids prices have been and are likely to continue to be
volatile in the future. The recent record high natural gas and natural gas
liquids prices may not continue and could drop precipitously in a short period
of time. The prices of natural gas and natural gas liquids are subject to wide
fluctuations in response to a variety of factors beyond our control, including
the following:

     -    relatively minor changes in the supply of, and demand for, domestic
          and foreign natural gas and natural gas liquids;

     -    market uncertainty;

     -    availability and cost of transportation capacity;

     -    the level of consumer product demand;

     -    political conditions in international natural gas-producing regions;

     -    weather conditions;

     -    domestic and foreign governmental regulations and taxes;

     -    the price and availability of alternative fuels;

     -    speculation in the commodity futures markets;

     -    overall domestic and global economic conditions;

     -    the price of natural gas and natural gas liquids imports; and

     -    the effect of worldwide energy conservation measures.


                                       29

<PAGE>

These external factors and the volatile nature of the energy markets make it
difficult to reliably estimate future prices of natural gas and natural gas
liquids. As natural gas and natural gas liquids prices decline, we are paid less
for our commodities, thereby reducing our cash flow. In addition, production and
related volumes could also decline.

WE DO NOT FULLY HEDGE AGAINST PRICE CHANGES IN COMMODITIES. THIS COULD RESULT IN
DECREASED REVENUES AND INCREASED COSTS, THEREBY RESULTING IN LOWER MARGINS AND
ADVERSELY AFFECTING OUR RESULTS OF OPERATIONS.

Our businesses are exposed to market risk and the impact of market fluctuations
in natural gas, natural gas liquids, crude oil and power prices. Market risk
refers to the risk of loss in cash flows and future earnings arising from
adverse changes in commodity energy prices. Our primary exposure arises from
natural gas liquids in storage utilized by our natural gas liquids operations
and the difference between natural gas and natural gas liquids prices with
respect to our keep whole processing agreements. To minimize the risk from
market fluctuations in natural gas, natural gas liquids and crude oil prices, we
use commodity derivative instruments such as futures contracts, swaps and
options to manage the market risk of existing or anticipated purchases and sales
of natural gas, natural gas liquids and crude oil. However, we do not fully
hedge against commodity price changes and we therefore retain some exposure to
market risk. We adhere to policies and procedures that limit our exposure to
market risk from open positions and that monitor our market risk exposure.

IF THE LEVEL OF DRILLING AND PRODUCTION IN OKLAHOMA, KANSAS, THE PANHANDLE OF
TEXAS AND THE WILLISTON, POWDER RIVER AND WIND RIVER BASINS SUBSTANTIALLY
DECLINES, OUR GATHERING AND PROCESSING VOLUMES AND REVENUE COULD DECLINE.

Our ability to maintain or expand our natural gas gathering and processing
business depends largely on the level of drilling and production in the areas
where our gathering and processing facilities are located, which include
Oklahoma, Kansas, the panhandle of Texas and the Williston, Powder River and
Wind River Basins. Drilling and production are impacted by factors beyond our
control, including:

     -    demand for natural gas and refinery-grade crude oil;

     -    producers' desire and ability to obtain necessary permits in a timely
          and economic manner;

     -    natural gas field characteristics and production performance;

     -    surface access and infrastructure issues; and

     -    capacity constraints on natural gas, crude oil and natural gas liquids
          pipelines that transport gas from the producing areas and our
          facilities.

In addition, drilling and production in the Powder River Basin are impacted by
environmental regulations governing water discharge associated with coalbed
methane production. If the level of drilling and production in these areas
substantially declines, our gathering and processing volumes and revenue could
be reduced.

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


                                       30

<PAGE>

A DOWNGRADE OF OUR CREDIT RATING MAY REQUIRE US TO OFFER TO REPURCHASE OUR
SENIOR NOTES OR IMPAIR OUR ABILITY TO ACCESS CAPITAL.

We could be required to offer to repurchase certain of our senior notes at par
value, plus any associated penalties and premiums, if Moody's Investor Services
or Standard & Poor's Rating Services rate our senior notes below investment
grade. We may not have sufficient cash on hand to repurchase the senior notes at
par value, which may cause us to borrow money under our credit facilities or
seek alternative financing sources to finance the repurchase. We could also face
difficulties accessing capital or our borrowing costs could increase, impacting
our ability to obtain financing for acquisitions or capital expenditures and to
refinance indebtedness, including refinancing the amount outstanding under our
364-day credit agreement used to purchase the assets from ONEOK.

WE MAY NOT BE ABLE TO SUCCESSFULLY INTEGRATE THE OPERATIONS OF THE ONEOK
SUBSIDIARIES THAT WE ACQUIRED WITH OUR CURRENT OPERATIONS.

The integration of the operations of the ONEOK subsidiaries that we recently
acquired with our current operations will be a complex, time-consuming and
costly process. Failure to timely and successfully integrate the operations of
the ONEOK subsidiaries may have a material adverse effect on our business,
financial condition and results of operations. Integrating the ONEOK operations
will present challenges to our management, including:

     -    operating a significantly larger combined company with operations in
          new geographic areas;

     -    managing relationships with new customers for whom we have not
          previously provided services;

     -    integrating personnel with diverse backgrounds and organizational
          cultures;

     -    experiencing operational interruptions or the loss of key employees,
          customers or suppliers;

     -    inefficiencies and complexities that may arise due to unfamiliarity
          with the new operations and the businesses associated with them,
          including with their markets;

     -    assimilating the operations, technologies, services and products of
          the acquired operations;

     -    incurring additional costs related to reorganization, severance, and
          relocation of employees;

     -    assessing the internal controls and procedures for the combined entity
          that we are required to maintain under the Sarbanes-Oxley Act of 2002;
          and

     -    consolidating other corporate and administrative functions.

We will also be exposed to risks that are commonly associated with transactions
similar to this acquisition, such as unanticipated liabilities and costs, some
of which may be material, and diversion of management's attention. As a result,
the anticipated benefits of the acquisition may not be fully realized, if at
all.

THE ISSUANCE OF CLASS B UNITS TO ONEOK IN CONNECTION WITH THE ACQUISITION OF
CERTAIN OF ITS SUBSIDIARIES WILL DILUTE OUR CURRENT UNITHOLDERS' OWNERSHIP
INTERESTS UPON THE CONVERSION OF THE CLASS B UNITS TO COMMON UNITS.

In connection with the acquisition of certain ONEOK subsidiaries, we issued
approximately 36.5 million Class B units representing limited partner interests
in us to ONEOK. The Class B units will convert to common units on a one-for-one
basis at the holder's option upon the requisite approval of such conversion by
our unitholders at a special meeting of unitholders, or automatically upon the
requisite approval of both the conversion and certain amendments to our
partnership agreement by our unitholders at a special meeting of unitholders.
The conversion of the Class B units will have the following effects:

     -    our unitholders' proportionate ownership interest in us will decrease;

     -    the distributions on each common unit may decrease;

     -    the relative voting strength of each previously outstanding common
          unit may be diminished; and

     -    the market price of the common units may decline.

In addition, ONEOK may, from time to time, sell all or a portion of its common
units. Sales of substantial amounts of their common units, or the anticipation
of such sales, could lower the market price of our common units and may make it
more difficult for us to sell our equity securities in the future at a time and
price that we deem appropriate.


                                       31

<PAGE>

RISKS INHERENT IN AN INVESTMENT IN US

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

We rely on ONEOK, Northern Plains and NBP Services to provide us with
administrative, operating and management services. We have a limited ability to
control our operations or the associated costs of such operations. The success
of these operations depends on a number of factors that are outside our control,
including the competence and financial resources of the provider. ONEOK,
Northern Plains and NBP Services 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, Northern
Plains or NBP Services 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,
Northern Plains, NBP Services and the third-party providers with which they
contract, together with our limited ability to control certain costs, could harm
our business and results of operations.

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

ONEOK owns 100% of our general partner interests and a 43.7% limited partner
interest in us. Although ONEOK, through the Partnership Policy Committee, has a
fiduciary duty to manage us in a manner beneficial to us and our unitholders,
the board of directors of ONEOK has a fiduciary duty to manage our general
partners in a manner beneficial to ONEOK. Some members of our Partnership Policy
Committee are also members of ONEOK's board of directors. Conflicts of interest
may arise between our general partners and their affiliates and us and our
unitholders. In resolving these conflicts, our general partners may favor their
own interests and the interests of their respective affiliates over the
interests of our unitholders. These conflicts include, among others, the
following situations:

     -    the Partnership Policy Committee and our general partners, which are
          owned by ONEOK, 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 our unitholders;

     -    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 Partnership Policy Committee
          and of our general partners and also restricts the remedies available
          to our unitholders for actions that, without the limitations, might
          constitute breaches of fiduciary duty;

     -    the Partnership Policy Committee determines the amount and timing of
          our cash reserves, asset purchases and sales, capital expenditures,
          borrowings and issuances of additional partnership securities, each of
          which can affect the amount of cash that is distributed to our
          unitholders;

     -    the Partnership Policy 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 to our unitholders;

     -    the Partnership Policy Committee may cause us to borrow funds in order
          to permit the payment of cash distributions, even if the purpose or
          effect of the borrowing is to make incentive distributions;

     -    the Partnership Policy 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
          Partnership Policy 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;

     -    our general partners may exercise their limited right to call and
          purchase common units if they and their respective affiliates own more
          than 80% of the common units; and

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


                                       32

<PAGE>

OUR GENERAL PARTNERS AND THEIR AFFILIATES MAY COMPETE DIRECTLY WITH US AND HAVE
NO OBLIGATION TO PRESENT BUSINESS OPPORTUNITIES TO US.

ONEOK and their affiliates are not prohibited from owning assets or engaging in
businesses that compete directly or indirectly with us. ONEOK may acquire,
construct or dispose of additional midstream or other assets in the future
without any obligation to offer us the opportunity to purchase or construct any
of those assets. In addition, under our partnership agreement, the doctrine of
corporate opportunity, or any analogous doctrine, will not apply to ONEOK and
its affiliates. As a result, neither ONEOK nor any of its affiliates has any
obligation to present business opportunities to us.

ITEM 6. EXHIBITS

The following exhibits are filed as part of this quarterly report on Form 10-Q:

#2.1 Contribution Agreement by and among ONEOK, Inc., Northern Border Partners,
     L.P. and Northern Border Intermediate Limited Partnership dated February
     14, 2006 (incorporated by reference to Exhibit 2.1 to Northern Border
     Partners, L.P.'s Form 10-K filed on March 7, 2006 (File No. 1-12202)).

#2.2 First Amendment to Contribution Agreement by and among ONEOK, Inc.,
     Northern Border Partners, L.P. and Northern Border Intermediate Limited
     Partnership dated April 6, 2006 (incorporated by reference to Exhibit 2.2
     to Northern Border Partners, L.P.'s Form 8-K filed on April 12, 2006 (File
     No. 1-12202)).

#2.3 Purchase and Sale Agreement by and between ONEOK, Inc. and Northern Border
     Partners, L.P. dated February 14, 2006 (incorporated by reference to
     Exhibit 2.2 to Northern Border Partners, L.P.'s Form 10-K filed on March 7,
     2006 (File No. 1-12202)).

#2.4 First Amendment to Purchase and Sale Agreement by and between ONEOK, Inc.
     and Northern Border Partners, L.P. dated April 6, 2006 (incorporated by
     reference to Exhibit 2.4 to Northern Border Partners, L.P.'s Form 8-K filed
     on April 12, 2006 (File No. 1-12202)).

#2.5 Partnership Interest Purchase and Sale Agreement by and between Northern
     Border Intermediate Limited Partnership and TC Pipeline Intermediate
     Limited Partnership dated as of December 31, 2005 (incorporated by
     reference to Exhibit 2.3 to Northern Border Partners, L.P.'s Form 10-K
     filed on March 7, 2006 (File No. 1-12202)).

#2.6 Purchase and Sale Agreement by and among Wisconsin Energy Corporation and
     WPS Investments, LLC and Northern Border Intermediate Limited Partnership
     dated as of March 30, 2006 (incorporated by reference to Exhibit 2.1 to
     Northern Border Partners, L.P. Form 8-K filed March 30, 2006 (File No.
     1-2202)).

3.1  Amended and Restated Agreement of Limited Partnership of Northern Border
     Partners, L.P. dated October 1, 1993 (incorporated by reference to Exhibit
     3.2 to Northern Border Partners, L.P.'s Form 10-K for the year ended
     December 31, 2004 (File No. 1-12202)).

3.2  Amendment No. 1 to Amended and Restated Agreement of Limited Partnership of
     Northern Border Partners, L.P. dated April 6, 2006.

4.1  Form of Class B unit certificate (incorporated by reference to Exhibit 4.1
     to Northern Border Partners, L.P.'s Form 8-K filed on April 12, 2006 (File
     No. 1-12202)).

10.1 364-Day Credit Agreement dated April 6, 2006, by and among Northern Border
     Partners, L.P., the several banks and other financial institutions and
     lenders from time to time party hereto, SunTrust Bank, as Administrative
     Agent, Citicorp North America, Inc., as Syndication Agent and Bank of
     Montreal (doing business as Harris Nesbitt), UBS Loan Finance LLC, and
     Wachovia Bank, National Association, as Co-Documentation Agents
     (incorporated by reference to Exhibit 10.1 to Northern Border Partners,
     L.P.'s Form 8-K filed on April 12, 2006 (File No. 1-12202)).

10.2 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)).


                                       33

<PAGE>

10.3 Services Agreement dated April 6, 2006, by and among ONEOK, Inc., Northern
     Plains Natural Gas Company, LLC, NBP Services, LLC, Northern Border
     Partners, L.P. and Northern Border Intermediate Limited Partnership
     (incorporated by reference to Exhibit 10.3 to Northern Border Partners,
     L.P.'s Form 8-K filed on April 12, 2006 (File No. 1-12202)).

10.4 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 10.2 to Northern Border
     Pipeline Company's Form 8-K filed April 12, 2006 (File No. 333-87753)).

10.5 Operating Agreement dated April 6, 2006, by and between Northern Border
     Pipeline Company and TransCan Northwest Border Ltd. (incorporated by
     reference to Exhibit 10.3 to Northern Border Pipeline Company's Form 8-K
     filed April 12, 2006 (File No. 333-87753)).

10.6 Amended and Restated Revolving Credit Agreement dated March 30, 2006, among
     Northern Border Partners, L.P., the lenders from time to time party
     thereto; SunTrust Bank, as administrative agent; Wachovia Bank, National
     Association, as Syndication Agent; Harris Nesbit Financing, Inc., Barclays
     Bank PLC and Citibank, N.A., as Co-Documentation Agents. (incorporated by
     reference to Exhibit 10.1 to Northern Border Partners, L.P. Form 8-K filed
     March 31, 2006 (File No. 1-2202)).

10.7 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 Northern Border Pipeline
     Company's Form 8-K filed April 4, 2006 (File No. 333-87753)).

+31.1 Rule 13a-14(a)/15d-14(a) Certification of Chief Executive Officer.

+31.2 Rule 13a-14(a)/15d-14(a) Certification of Chief Financial Officer.

+32.1 Section 1350 Certification of Chief Executive Officer.

+32.2 Section 1350 Certification of Chief Financial Officer.

The total amount of securities of the Partnership authorized under any
instrument with respect to long-term debt not filed as an exhibit does not
exceed 10% of the total assets of the Partnership and its subsidiaries on a
consolidated basis. The Partnership agrees, upon request of the Securities and
Exchange Commission, to furnish copies of any or all of such instruments to the
Securities and Exchange Commission.

#    Northern Border Partners agrees to furnish supplementally to the SEC, 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.

+    Filed herewith


                                       34

<PAGE>

                                    SIGNATURE

Pursuant to the requirements 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.

                                        NORTHERN BORDER PARTNERS, L.P.
                                        (A Delaware Limited Partnership)


Date: May 4, 2006                       By: /s/ Jim Kneale
                                            ------------------------------------
                                            Jim Kneale
                                            Chief Financial Officer
                                            (Signing on behalf of the Registrant
                                            and as Chief Financial Officer)


                                       35

<PAGE>

                                  EXHIBIT INDEX

<TABLE>
<CAPTION>
EXHIBIT NO.                         DESCRIPTION OF EXHIBIT
-----------                         ----------------------
<S>           <C>
#2.1          Contribution Agreement by and among ONEOK, Inc., Northern Border
              Partners, L.P. and Northern Border Intermediate Limited
              Partnership dated February 14, 2006 (incorporated by reference to
              Exhibit 2.1 to Northern Border Partners, L.P.'s Form 10-K filed on
              March 7, 2006 (File No. 1-12202)).

#2.2          First Amendment to Contribution Agreement by and among ONEOK,
              Inc., Northern Border Partners, L.P. and Northern Border
              Intermediate Limited Partnership dated April 6, 2006 (incorporated
              by reference to Exhibit 2.2 to Northern Border Partners, L.P.'s
              Form 8-K filed on April 12, 2006 (File No. 1-12202)).

#2.3          Purchase and Sale Agreement by and between ONEOK, Inc. and
              Northern Border Partners, L.P. dated February 14, 2006
              (incorporated by reference to Exhibit 2.2 to Northern Border
              Partners, L.P.'s Form 10-K filed on March 7, 2006 (File No.
              1-12202)).

#2.4          First Amendment to Purchase and Sale Agreement by and between
              ONEOK, Inc. and Northern Border Partners, L.P. dated April 6, 2006
              (incorporated by reference to Exhibit 2.4 to Northern Border
              Partners, L.P.'s Form 8-K filed on April 12, 2006 (File No.
              1-12202)).

#2.5          Partnership Interest Purchase and Sale Agreement by and between
              Northern Border Intermediate Limited Partnership and TC Pipeline
              Intermediate Limited Partnership dated as of December 31, 2005
              (incorporated by reference to Exhibit 2.3 to Northern Border
              Partners, L.P.'s Form 10-K filed on March 7, 2006 (File No.
              1-12202)).

#2.6          Purchase and Sale Agreement by and among Wisconsin Energy
              Corporation and WPS Investments, LLC and Northern Border
              Intermediate Limited Partnership dated as of March 30, 2006
              (incorporated by reference to Exhibit 2.1 to Northern Border
              Partners, L.P. Form 8-K filed March 30, 2006 (File No. 1-2202)).

3.1           Amended and Restated Agreement of Limited Partnership of Northern
              Border Partners, L.P. dated October 1, 1993 (incorporated by
              reference to Exhibit 3.2 to Northern Border Partners, L.P.'s Form
              10-K for the year ended December 31, 2004 (File No. 1-12202)).

3.2           Amendment No. 1 to Amended and Restated Agreement of Limited
              Partnership of Northern Border Partners, L.P. dated April 6, 2006.

4.1           Form of Class B unit certificate (incorporated by reference to
              Exhibit 4.1 to Northern Border Partners, L.P.'s Form 8-K filed on
              April 12, 2006 (File No. 1-12202)).

10.1          364-Day Credit Agreement dated April 6, 2006, by and among
              Northern Border Partners, L.P., the several banks and other
              financial institutions and lenders from time to time party hereto,
              SunTrust Bank, as Administrative Agent, Citicorp North America,
              Inc., as Syndication Agent and Bank of Montreal (doing business as
              Harris Nesbitt), UBS Loan Finance LLC, and Wachovia Bank, National
              Association, as Co-Documentation Agents (incorporated by reference
              to Exhibit 10.1 to Northern Border Partners, L.P.'s Form 8-K filed
              on April 12, 2006 (File No. 1-12202)).

10.2          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)).

10.3          Services Agreement dated April 6, 2006, by and among ONEOK, Inc.,
              Northern Plains Natural Gas Company, LLC, NBP Services, LLC,
              Northern Border Partners, L.P. and Northern Border Intermediate
              Limited Partnership (incorporated by reference to Exhibit 10.3 to
              Northern Border Partners, L.P.'s Form 8-K filed on April 12, 2006
              (File No. 1-12202)).

10.4          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 10.2 to Northern Border Pipeline Company's Form 8-K filed
              April 12, 2006 (File No. 333-87753)).
</TABLE>


                                       36

<PAGE>

<TABLE>
<C>           <S>
10.5          Operating Agreement dated April 6, 2006, by and between Northern
              Border Pipeline Company and TransCan Northwest Border Ltd.
              (incorporated by reference to Exhibit 10.3 to Northern Border
              Pipeline Company's Form 8-K filed April 12, 2006 (File No.
              333-87753)).

10.6          Amended and Restated Revolving Credit Agreement dated March 30,
              2006, among Northern Border Partners, L.P., the lenders from time
              to time party thereto; SunTrust Bank, as administrative agent;
              Wachovia Bank, National Association, as Syndication Agent; Harris
              Nesbit Financing, Inc., Barclays Bank PLC and Citibank, N.A., as
              Co-Documentation Agents. (incorporated by reference to Exhibit
              10.1 to Northern Border Partners, L.P. Form 8-K filed March 31,
              2006 (File No. 1-2202)).

10.7          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 Northern Border Pipeline Company's Form 8-K filed
              April 4, 2006 (File No. 333-87753)).

+31.1         Rule 13a-14(a)/15d-14(a) Certification of Chief Executive Officer.

+31.2         Rule 13a-14(a)/15d-14(a) Certification of Chief Financial Officer.

+32.1         Section 1350 Certification of Chief Executive Officer.

+32.2         Section 1350 Certification of Chief Financial Officer.
</TABLE>

#    Northern Border Partners agrees to furnish supplementally to the SEC, 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.

+    Filed herewith


                                       37