<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 JUNE 30, 2005

                                       or

[ ]      Transition Report pursuant to Section 13 or 15(d) of the Securities
         Exchange Act of 1934
         For the transition period from _______ to ________.


                         Commission File Number: 1-12202

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


                   Delaware                                93-1120873
   ----------------------------------------     -------------------------------
         (State or other jurisdiction           (I.R.S. Employer Identification
       of incorporation or organization)                      Number)

             13710 FNB Parkway
               Omaha, Nebraska                             68154-5200
   ----------------------------------------     -------------------------------
   (Address of principal executive offices)                (Zip code)


                                 (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 an accelerated filer (as
defined in Rule 12b-2 of the Exchange Act). Yes [X] No [ ]

The number of common units outstanding as of August 1, 2005 was 46,397,214.


                                       1
<PAGE>


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

                                TABLE OF CONTENTS

<Table>
<Caption>
                                                                              Page No.
                                                                              --------
<S>           <C>                                                             <C>
PART I.       FINANCIAL INFORMATION

Item 1.       Financial Statements

              Consolidated Statement of Income -
                  Three Months Ended June 30, 2005 and 2004 and
                  Six Months Ended June 30, 2005 and 2004 .........................3
              Consolidated Statement of Comprehensive Income -
                  Three Months Ended June 30, 2005 and 2004 and
                  Six Months Ended June 30, 2005 and 2004 .........................4
              Consolidated Balance Sheet -
                  June 30, 2005 and December 31, 2004 .............................5
              Consolidated Statement of Cash Flows -
                  Six Months Ended June 30, 2005 and 2004 .........................6
              Consolidated Statement of Changes in Partners' Equity -
                  Six Months Ended June 30, 2005 ..................................7
              Notes to Consolidated Financial Statements .......................8-12

Item 2.       Management's Discussion and Analysis of Financial Condition
                  and Results of Operations ...................................13-27

Item 3.       Quantitative and Qualitative Disclosures About Market Risk .........27

Item 4.       Controls and Procedures ............................................28

PART II.      OTHER INFORMATION

Item 5.       Other Information ..................................................28

Item 6.       Exhibits ........................................................28-29

Signature ........................................................................30
</Table>


                                       2
<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          SIX MONTHS ENDED
                                                            JUNE 30,                    JUNE 30,
                                                    ------------------------   -------------------------
                                                       2005          2004          2005          2004
                                                    ----------    ----------    ----------    ----------
                                                           (IN THOUSANDS EXCEPT PER UNIT AMOUNTS)
<S>                                                 <C>           <C>           <C>           <C>
OPERATING REVENUE                                   $  149,417    $  142,476    $  309,796    $  286,249
                                                    ----------    ----------    ----------    ----------
OPERATING EXPENSES
   Product purchases                                    35,466        23,468        67,931        44,881
   Operations and maintenance                           30,042        28,998        63,214        58,397
   Depreciation and amortization                        21,456        21,318        42,848        42,824
   Taxes other than income                               8,989         8,097        18,801        17,791
                                                    ----------    ----------    ----------    ----------
      Operating expenses                                95,953        81,881       192,794       163,893
                                                    ----------    ----------    ----------    ----------
OPERATING INCOME                                        53,464        60,595       117,002       122,356
                                                    ----------    ----------    ----------    ----------
INTEREST EXPENSE                                        21,372        18,534        42,538        37,102
                                                    ----------    ----------    ----------    ----------
OTHER INCOME (EXPENSE)
   Equity earnings in unconsolidated affiliates          4,418         3,602         8,895         9,965
   Other income                                          1,082         1,331         1,823         1,852
   Other expense                                          (234)         (474)         (457)         (609)
                                                    ----------    ----------    ----------    ----------
      Other income, net                                  5,266         4,459        10,261        11,208
                                                    ----------    ----------    ----------    ----------
MINORITY INTEREST IN NET INCOME                          8,629        12,389        20,818        24,916
                                                    ----------    ----------    ----------    ----------
INCOME FROM CONTINUING OPERATIONS
  BEFORE INCOME TAXES                                   28,729        34,131        63,907        71,546
INCOME TAXES                                               997         1,259         1,896         2,822
                                                    ----------    ----------    ----------    ----------
INCOME FROM CONTINUING OPERATIONS                       27,732        32,872        62,011        68,724
DISCONTINUED OPERATIONS, NET OF TAX                        358           393           748         1,156
                                                    ----------    ----------    ----------    ----------
NET INCOME TO PARTNERS                              $   28,090    $   33,265    $   62,759    $   69,880
                                                    ==========    ==========    ==========    ==========

CALCULATION OF LIMITED PARTNERS'
  INTEREST IN NET INCOME:
   Net income to partners                           $   28,090    $   33,265    $   62,759    $   69,880
   Less: General partners' interest in net income        2,552         2,655         5,235         5,377
                                                    ----------    ----------    ----------    ----------
   Limited partners' interest in net income         $   25,538    $   30,610    $   57,524    $   64,503
                                                    ==========    ==========    ==========    ==========

LIMITED PARTNERS' PER UNIT NET INCOME:
   Income from continuing operations                $     0.54    $     0.65    $     1.22    $     1.37
   Discontinued operations, net of tax                    0.01          0.01          0.02          0.02
                                                    ----------    ----------    ----------    ----------
   Net income                                       $     0.55    $     0.66    $     1.24    $     1.39
                                                    ==========    ==========    ==========    ==========
NUMBER OF UNITS USED IN COMPUTATION                     46,397        46,397        46,397        46,397
                                                    ==========    ==========    ==========    ==========
</Table>

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

                                       3
<PAGE>

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

<Table>
<Caption>
                                               THREE MONTHS ENDED           SIX MONTHS ENDED
                                                    JUNE 30,                      JUNE 30,
                                            ------------------------    ------------------------
                                               2005          2004          2005         2004
                                            ----------    ----------    ----------    ----------
                                                               (IN THOUSANDS)
<S>                                         <C>           <C>           <C>           <C>
Net income to partners                      $   28,090    $   33,265    $   62,759    $   69,880
Other comprehensive income:
   Changes associated with current period
     hedging transactions                       (2,483)          711        (5,208)        1,190
   Changes associated with current period
     foreign currency translation                 (424)         (433)         (445)         (733)
                                            ----------    ----------    ----------    ----------
Total comprehensive income                  $   25,183    $   33,543    $   57,106    $   70,337
                                            ==========    ==========    ==========    ==========
</Table>


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

                                       4
<PAGE>

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

<Table>
<Caption>
                                                                      JUNE 30,     DECEMBER 31,
                                                                        2005           2004
                                                                    ------------   ------------
                                                                           (IN THOUSANDS)
<S>                                                                 <C>            <C>
ASSETS
CURRENT ASSETS
   Cash and cash equivalents                                        $      9,283   $     33,980
   Accounts receivable, net of allowance for doubtful accounts
    of $7,442 and $9,175 at June 30, 2005, and December 31, 2004,
    respectively                                                          62,572         70,007
   Materials and supplies, at cost                                         4,754          5,654
   Prepaid expenses and other                                              6,764          5,650
   Derivative financial instruments                                          429          1,996
                                                                    ------------   ------------
      Total current assets                                                83,802        117,287
                                                                    ------------   ------------
PROPERTY, PLANT AND EQUIPMENT
   Property, plant and equipment                                       2,962,667      2,939,465
   Less: Accumulated provision for depreciation and amortization       1,044,891      1,002,041
                                                                    ------------   ------------
      Property, plant and equipment, net                               1,917,776      1,937,424
                                                                    ------------   ------------
INVESTMENTS AND OTHER ASSETS
   Investment in unconsolidated affiliates                               281,442        273,202
   Goodwill                                                              152,782        152,782
   Derivative financial instruments                                        2,639          2,555
   Other                                                                  27,320         27,306
                                                                    ------------   ------------
      Total investments and other assets                                 464,183        455,845
                                                                    ------------   ------------
      Total assets                                                  $  2,465,761   $  2,510,556
                                                                    ============   ============
LIABILITIES AND PARTNERS' EQUITY
CURRENT LIABILITIES
   Current maturities of long-term debt                             $      3,656   $      5,126
   Accounts payable                                                       26,638         35,095
   Accrued taxes other than income                                        27,713         32,563
   Accrued interest                                                       16,766         16,530
   Derivative financial instruments                                        1,204             --
                                                                    ------------   ------------
      Total current liabilities                                           75,977         89,314
                                                                    ------------   ------------
LONG-TERM DEBT, NET OF CURRENT MATURITIES                              1,328,460      1,325,232
                                                                    ------------   ------------
MINORITY INTERESTS IN PARTNERS' EQUITY                                   278,797        290,142
                                                                    ------------   ------------
RESERVES AND DEFERRED CREDITS
   Deferred income taxes                                                   8,136          7,186
   Derivative financial instruments                                          131            840
   Other                                                                   7,632          8,508
                                                                    ------------   ------------
      Total reserves and deferred credits                                 15,899         16,534
                                                                    ------------   ------------
COMMITMENTS AND CONTINGENCIES (Note 6)

PARTNERS' EQUITY
   General partners                                                       15,262         15,603
   Common units: 46,397,214 units issued and outstanding
    at June 30, 2005, and December 31, 2004                              747,838        764,550
   Accumulated other comprehensive income                                  3,528          9,181
                                                                    ------------   ------------
      Total partners' equity                                             766,628        789,334
                                                                    ------------   ------------
      Total liabilities and partners' equity                        $  2,465,761   $  2,510,556
                                                                    ============   ============
</Table>


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


                                       5
<PAGE>

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

<Table>
<Caption>
                                                                 SIX MONTHS ENDED
                                                                      JUNE 30,
                                                              ------------------------
                                                                 2005          2004
                                                              ----------    ----------
                                                                   (IN THOUSANDS)
<S>                                                           <C>           <C>
CASH FLOW FROM OPERATING ACTIVITIES:
   Net income to partners                                     $   62,759    $   69,880
                                                              ----------    ----------
   Adjustments to reconcile net income to partners
    to net cash provided by operating activities:
      Depreciation and amortization                               43,023        43,219
      Minority interests in net income                            20,818        24,916
      Reserves and deferred credits                                 (858)       (1,657)
      Equity earnings in unconsolidated affiliates                (8,895)       (9,965)
      Distributions received from unconsolidated affiliates        2,653         7,519
      Changes in components of working capital                    (5,861)         (608)
      Other                                                       (2,332)       (3,490)
                                                              ----------    ----------
         Total adjustments                                        48,548        59,934
                                                              ----------    ----------
      Net cash provided by operating activities                  111,307       129,814
                                                              ----------    ----------
CASH FLOW FROM INVESTING ACTIVITIES:
   Sale of gathering and processing assets                            --           512
   Investment in unconsolidated affiliates                        (1,454)           --
   Capital expenditures for property, plant and equipment        (23,161)       (9,531)
                                                              ----------    ----------
      Net cash used in investing activities                      (24,615)       (9,019)
                                                              ----------    ----------
CASH FLOW FROM FINANCING ACTIVITIES:
   Cash distributions:
      General and limited partners                               (79,812)      (79,812)
      Minority interests                                         (31,943)      (31,318)
   Equity contributions from minority interests                       --        39,000
   Issuance of long-term debt                                     86,000        90,000
   Long-term debt financing costs                                 (1,327)           --
   Retirement of long-term debt                                  (81,653)     (134,841)
   Payments upon termination of derivatives                       (2,654)           --
                                                              ----------    ----------
      Net cash used in financing activities                     (111,389)     (116,971)
                                                              ----------    ----------

NET CHANGE IN CASH AND CASH EQUIVALENTS                          (24,697)        3,824
Cash and cash equivalents-beginning of period                     33,980        35,895
                                                              ----------    ----------
Cash and cash equivalents-end of period                       $    9,283    $   39,719
                                                              ==========    ==========
--------------------------------------------------------------------------------------
Supplemental Disclosures of Cash Flow Information:
   Cash paid for interest, net of amount capitalized          $   44,341    $   39,642
                                                              ==========    ==========
   Changes in components of working capital:
      Accounts receivable                                     $    8,149    $   (1,065)
      Materials and supplies, prepaid expenses and other            (214)        3,539
      Accounts payable                                            (9,182)        2,240
      Accrued taxes other than income                             (4,850)       (5,150)
      Accrued interest                                               236          (172)
                                                              ----------    ----------
         Total                                                $   (5,861)   $     (608)
                                                              ==========    ==========
</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 CHANGES IN PARTNERS' EQUITY
(UNAUDITED)

<Table>
<Caption>
                                                                            ACCUMULATED
                                                                               OTHER           TOTAL
                                            GENERAL          COMMON        COMPREHENSIVE      PARTNERS'
                                            PARTNERS          UNITS            INCOME          EQUITY
                                         -------------    -------------    -------------    -------------
                                                                       (IN THOUSANDS)

<S>                                      <C>              <C>              <C>              <C>
Balance at December 31, 2004             $      15,603    $     764,550    $       9,181    $     789,334

Net income to partners                           5,235           57,524               --           62,759

Changes associated with current
   period hedging transactions                      --               --           (5,208)          (5,208)

Changes associated with current
   period foreign currency translation              --               --             (445)            (445)

Distribution to partners                        (5,576)         (74,236)              --          (79,812)
                                         -------------    -------------    -------------    -------------
Balance at June 30, 2005                 $      15,262    $     747,838    $       3,528    $     766,628
                                         =============    =============    =============    =============
</Table>


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

                                       7
<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 have 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)
have been 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, 2004.

The preparation of financial statements in conformity with U.S. GAAP requires
management to make assumptions that affect the reported amounts of assets and
liabilities, disclosure of contingent assets and liabilities at the date of the
financial statements, and the reported amounts of revenue and expenses during
the reporting period. Actual results could differ from those estimates.

We own a 70% general partner interest in Northern Border Pipeline Company. Our
wholly-owned subsidiaries are: Crestone Energy Ventures, L.L.C.; Bear Paw
Energy, L.L.C.; Border Midstream Services, Ltd.; Midwestern Gas Transmission
Company; Viking Gas Transmission Company; and Black Mesa Pipeline, Inc. We also
own a 49% common membership interest and a 100% preferred A share interest in
Bighorn Gas Gathering, L.L.C.; a 33.33% interest in Fort Union Gas Gathering,
L.L.C.; a 35% interest in Lost Creek Gathering, L.L.C.; and a 33-1/3% interest
in Guardian Pipeline, L.L.C.

2. CREDIT FACILITIES

The Partnership and Northern Border Pipeline entered into revolving credit
facilities, which are to be used for capital expenditures, acquisitions, general
business purposes and refinancing existing indebtedness. Northern Border
Pipeline entered into a $175 million five-year credit agreement (2005 Pipeline
Credit Agreement) with certain financial institutions in May 2005. We entered
into a $500 million five-year credit agreement (2005 Partnership Credit
Agreement) with certain financial institutions in May 2005. Both of the
revolving credit facilities permit the Partnership and Northern Border Pipeline
to choose the lender's base rate or the London Interbank Offered Rate (LIBOR)
plus a spread that is based on each of our long-term unsecured debt ratings as
the interest rate on our outstanding borrowings, specify the portion of the
borrowings to be covered by specific interest rate options and to specify the
interest rate period. Both the Partnership and Northern Border Pipeline are
required to pay a fee on the principal commitment amounts. As of June 30, 2005,
there was $198 million outstanding under the 2005 Partnership Credit Agreement
and no amounts outstanding under the 2005 Pipeline Credit Agreement.

Each of the 2005 Partnership and Pipeline Credit Agreements require the
Partnership and Northern Border Pipeline to comply with certain financial,
operational and legal covenants. The agreements require, among other things,
that the Partnership and Northern Border Pipeline maintain ratios 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. The
agreements also require the maintenance of the ratio of indebtedness to adjusted
EBITDA (EBITDA adjusted for pro forma operating results of acquisitions made
during the year) of no more than 4.75 to 1 for the Partnership and 4.50 to 1 for
Northern Border Pipeline. Pursuant to the credit agreements, if one or more
acquisitions are consummated in which the aggregate purchase price is $25
million or more, the allowable ratio of indebtedness to adjusted EBITDA is
increased to 5.25 to 1 for the Partnership and to 5 to 1 for Northern Border
Pipeline for two calendar quarters following the acquisition. Upon any breach of
these covenants, amounts outstanding under the 2005 Partnership and Pipeline
Credit Agreements may become immediately due and payable. As of June 30, 2005,
the Partnership and Northern Border Pipeline were in compliance with these
covenants.


                                       8
<PAGE>

3. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

We use financial instruments in the management of our interest rate and
commodity price exposure. A control environment has been established which
includes policies and procedures for risk assessment as well as the approval,
reporting and monitoring of financial instrument activities.

On December 9, 2004, we entered into forward-starting interest rate swap
agreements with a total notional amount of $100 million in anticipation of a
ten-year senior note issuance. These swap agreements expired in late May and
early June of 2005, which resulted in the Partnership paying $2.7 million to the
counterparties. In June 2005, we entered into a Treasury lock interest rate
agreement with a total notional amount of $200 million in anticipation of a
ten-year senior note issuance in 2005. In July 2005, the Partnership paid $0.1
million to the counterparty at expiration of the Treasury lock interest rate
agreement. In the third quarter of 2005, we will commence amortization of
amounts related to the termination of the forward-starting interest rate swaps
and the Treasury lock as an increase to interest expense.

We record in accumulated other comprehensive income amounts related to
terminated interest rate swap agreements for cash flow hedges with such amounts
amortized to interest expense over the term of the hedged debt. During the three
and six months ended June 30, 2005, we amortized approximately $0.5 million and
$1.0 million, respectively, related to the terminated interest rate swap
agreements as a reduction to interest expense from accumulated other
comprehensive income and expect to amortize approximately $0.5 million in each
of the remaining quarters of 2005.

We have outstanding interest rate swap agreements with notional amounts totaling
$150 million that expire in March 2011. Under these agreements, we make payments
to counterparties at variable rates based on the London Interbank Offered Rate
and in return receive payments based on a 7.10% fixed rate. As of June 30, 2005,
the average effective interest rate on our interest rate swap agreements was
5.80%. Our interest rate swap agreements have been designated as fair value
hedges as they hedge the fluctuations in the market value of the senior notes
issued by us in 2001. The accompanying consolidated balance sheet at June 30,
2005, reflects long-term derivative financial instrument assets of $2.6 million
with a corresponding increase in long-term debt related to our fair value
hedges.

The Partnership and Northern Border Pipeline record in long-term debt amounts
received or paid related to terminated or amended interest rate swap agreements
for fair value hedges with such amounts amortized to interest expense over the
remaining life of the interest rate swap agreement. The Partnership and Northern
Border Pipeline amortized approximately $1.3 million and $2.6 million as a
reduction to interest expense in the three and six months ended June 30, 2005,
respectively, and expect to amortize approximately $1.3 million in each of the
remaining quarters of 2005.

Bear Paw Energy periodically enters into commodity derivative contracts and
fixed-price physical contracts. Bear Paw Energy primarily utilizes price swaps
and collars, which have been designated as cash flow hedges, to hedge its
exposure to natural gas and natural gas liquids price volatility. During the
three months and six months ended June 30, 2005, Bear Paw Energy recognized
losses of $0.1 million and gains of $1.2 million, respectively, from the
settlement of derivative contracts. As of June 30, 2005, the consolidated
balance sheet reflected an unrealized gain of $0.4 million in current derivative
financial instrument assets and an unrealized loss of approximately $1.2 million
in current derivative financial instrument liabilities with a corresponding
offset to accumulated other comprehensive income. If prices remain at current
levels, Bear Paw Energy expects to reclassify approximately $0.7 million from
accumulated other comprehensive income as a decrease to operating revenues in
the remaining quarters of 2005. However, this decrease would be offset with
increased operating revenues due to the higher prices assumed.

4. BUSINESS SEGMENT INFORMATION

Our business is divided into three 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 natural gas transportation services; 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; and the Coal Slurry Pipeline segment,
which transports crushed coal suspended in water.


                                       9
<PAGE>

BUSINESS SEGMENT DATA
(IN THOUSANDS)

<Table>
<Caption>
                                        NATURAL GAS
                          INTERSTATE    GATHERING
THREE MONTHS ENDED        NATURAL GAS       AND       COAL SLURRY
  JUNE 30, 2005             PIPELINE    PROCESSING     PIPELINE       OTHER(a)        TOTAL
------------------        -----------   -----------   -----------   -----------    -----------
<S>                       <C>           <C>           <C>           <C>            <C>
Revenue from external
   customers              $    82,541   $    61,039   $     5,837   $        --    $   149,417
Operating income (loss)        43,915        10,841         1,252        (2,544)        53,464
EBITDA                         61,234        19,133         2,215        (2,097)        80,485

THREE MONTHS ENDED
  JUNE 30, 2004
------------------
Revenue from external
   customers              $    94,517   $    42,585   $     5,374   $        --    $   142,476
Operating income (loss)        56,667         4,351         1,022        (1,445)        60,595
EBITDA                         74,030        11,708         1,888          (570)        87,056

 SIX MONTHS ENDED
  JUNE 30, 2005
------------------

Revenue from external
   customers              $   179,186   $   118,612    $   11,998    $       --    $   309,796
Operating income (loss)        99,553        20,343         2,178        (5,072)       117,002
EBITDA                        134,057        36,839         4,080        (3,819)       171,157

  SIX MONTHS ENDED
   JUNE 30, 2004
------------------
Revenue from external
   customers              $   192,143   $    83,326    $   10,780   $        --    $   286,249
Operating income (loss)       115,241         9,161         1,716        (3,762)       122,356
EBITDA                        149,869        26,089         3,858        (1,454)       178,362
</Table>

(a) Includes other items not allocable to segments.


TOTAL ASSETS BY SEGMENT
(IN THOUSANDS)

<Table>
<Caption>
                                          JUNE 30,    DECEMBER 31,
                                            2005          2004
                                        -----------   ------------
<S>                                     <C>           <C>
Interstate Natural Gas Pipeline         $ 1,852,747   $  1,900,555
Natural Gas Gathering and Processing        576,160        570,101
Coal Slurry Pipeline                         15,779         18,268
Other (a)                                    21,075         21,632
                                        -----------   ------------
   Total assets                         $ 2,465,761   $  2,510,556
                                        ===========   ============
</Table>

(a) Includes other items not allocable to segments.


We evaluate performance based on EBITDA (earnings before interest, taxes,
depreciation and amortization) less the 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.


                                       10
<PAGE>
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.

RECONCILIATION OF NET INCOME (LOSS) TO EBITDA
(IN THOUSANDS)

<Table>
<Caption>

                                               NATURAL GAS
                                INTERSTATE      GATHERING
THREE MONTHS ENDED              NATURAL GAS        AND       COAL SLURRY
  JUNE 30, 2005                  PIPELINE       PROCESSING     PIPELINE     OTHER (a)        TOTAL
------------------              -----------    -----------   -----------   -----------    -----------
<S>                             <C>            <C>           <C>           <C>            <C>
Net income (loss)               $    24,048    $    15,110   $     1,109   $   (12,177)   $    28,090
Minority interest                     8,629             --            --            --          8,629
Interest expense, net                11,228             40            --        10,104         21,372
Depreciation and amortization        16,598          3,978           965            --         21,541
Income tax                              849              5           141           (24)           971
AFUDC                                  (118)            --            --            --           (118)
                                -----------    -----------   -----------   -----------    -----------
EBITDA                          $    61,234    $    19,133   $     2,215   $    (2,097)   $    80,485
                                ===========    ===========   ===========   ===========    ===========

 THREE MONTHS ENDED
   JUNE 30, 2004
-------------------
Net income (loss)               $    33,195    $     7,849   $       865   $    (8,644)   $    33,265
Minority interest                    12,389             --            --            --         12,389
Interest expense, net                10,562            108             2         7,862         18,534
Depreciation and amortization        16,807          3,745           858           105         21,515
Income tax                            1,090              6           163           107          1,366
AFUDC                                   (13)            --            --            --            (13)
                                -----------    -----------   -----------   -----------    -----------
EBITDA                          $    74,030    $    11,708   $     1,888   $      (570)   $    87,056
                                ===========    ===========   ===========   ===========    ===========

  SIX MONTHS ENDED
   JUNE 30, 2005
-------------------
Net income (loss)               $    56,197    $    28,800   $     1,854   $   (24,092)   $    62,759
Minority interest                    20,818             --            --            --         20,818
Interest expense, net                22,432             94            --        20,012         42,538
Depreciation and amortization        33,167          7,936         1,920            --         43,023
Income tax                            1,579              9           306           261          2,155
AFUDC                                  (136)            --            --            --           (136)
                                -----------    -----------   -----------   -----------    -----------
EBITDA                          $   134,057    $    36,839   $     4,080   $    (3,819)   $   171,157
                                ===========    ===========   ===========   ===========    ===========

  SIX MONTHS ENDED
   JUNE 30, 2004
-------------------
Net income (loss)               $    67,445    $    18,475   $     1,539   $   (17,579)   $    69,880
Minority interest                    24,916             --            --            --         24,916
Interest expense, net                21,444            214            11        15,433         37,102
Depreciation and amortization        33,484          7,387         2,136           212         43,219
Income tax                            2,637             13           172           480          3,302
AFUDC                                   (57)            --            --            --            (57)
                                -----------    -----------   -----------   -----------    -----------
EBITDA                          $   149,869    $    26,089   $     3,858   $    (1,454)   $   178,362
                                ===========    ===========   ===========   ===========    ===========
</Table>

(a) Includes other items not allocable to segments.


                                       11
<PAGE>


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 distribution to partners amount shown on the accompanying
consolidated statement of changes in partners' equity included incentive
distributions to the general partners of approximately $4.0 million.

On July 19, 2005, the Partnership declared a cash distribution of $0.80 per unit
($3.20 per unit on an annualized basis) for the quarter ended June 30, 2005. The
distribution is payable on August 12, 2005, to unitholders of record at July 29,
2005.

6. COMMITMENTS AND CONTINGENCIES

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.

7. RELATIONSHIPS WITH ENRON

In June 2005, Northern Border Pipeline Company, Crestone Gathering Services, a
wholly-owned subsidiary of Crestone Energy Ventures, and Bear Paw Energy, LLC
executed term sheets with a third party for the sale of their unsecured claims
held against Enron Corp. and Enron North America Corp. Proceeds from the sale
are expected to be $14.6 million. In 2004, we adjusted our allowance for
doubtful accounts to reflect an estimated $3.4 million ($3.0 million, net to the
Partnership) recovery for our claims. In the second quarter of 2005, we made an
adjustments to our allowance for doubtful accounts of approximately $1.8 million
($1.6 million, net to the Partnership) to reflect the agreements for the sales.
As a result of the sale, Northern Border Pipeline anticipates recognizing
additional income of $9.4 million ($6.6 million, net to the Partnership) later
in 2005.

8. ACCOUNTING PRONOUNCEMENTS

In March 2005, the Financial Accounting Standards Board (FASB) issued
Interpretation (FIN) 47, "Accounting for Conditional Asset Retirement
Obligations - an interpretation of FASB Statement (SFAS)No. 143." The statement
clarifies the term conditional asset retirement obligation, as used in SFAS
No. 143, and when an entity would have sufficient information to reasonably
estimate the fair value of an asset retirement obligation. The effective date of
this interpretation is no later than the end of the fiscal year ending after
December 15, 2005. The effect of adopting FIN 47 is not expected to be material
to our results of operations or financial position.

9. SUBSEQUENT EVENTS

In July 2005, Crestone Energy Ventures executed a purchase and sale agreement to
acquire an additional 3.7% interest of Fort Union Gas Gathering, L.L.C.,
bringing its total interest to approximately 37%, for $5.3 million, subject to
normal closing adjustments. We expect to close the transaction in August of
2005.

In July 2005, we negotiated a settlement agreement with our partner in Bighorn
Gas Gathering related to provisions of the joint venture agreement that provided
for cash flow incentives based on well connections. These incentives were
provided to us through our ownership of preferred A shares in Bighorn Gas
Gathering. Due to the settlement agreement, we anticipate recognizing $5.4
million of equity earnings associated with incentives due to us for 2004 and
2005. The settlement agreement also eliminates any future incentives. Therefore,
our preferred A shares have been cancelled and effectively redeemed and capital
accounts adjusted accordingly.


                                       12
<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 included in Item 1 of this
quarterly report on Form 10-Q.

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.

EXECUTIVE SUMMARY

OVERVIEW

Northern Border Partners, L.P. is a publicly-traded limited partnership listed
on the New York Stock Exchange under the symbol "NBP." Formed in 1993, our
purpose is to acquire, own and manage pipeline and other midstream energy
assets. We are a leading transporter of natural gas imported from Canada into
the United States. We conduct our operations through three business segments.
Our business segments and the proportionate share of identifiable assets of
each, as of June 30, 2005, are:

         o        the interstate natural gas pipeline segment, which provides
                  natural gas transportation services, accounting for 76% of our
                  identifiable assets;

         o        the natural gas gathering and processing segment, which
                  gathers, treats, processes and compresses natural gas as well
                  as fractionates natural gas liquids, accounting for 23% of our
                  identifiable assets; and

         o        the coal slurry pipeline segment, which transports crushed
                  coal suspended in water, accounting for 1% of our identifiable
                  assets.

RECENT DEVELOPMENTS

NORTHERN BORDER PIPELINE CONTRACTING - During the second quarter ended June 30,
2005, Northern Border Pipeline Company had available capacity on the Port of
Morgan, Montana to Ventura, Iowa portion of the pipeline which remained
uncontracted. Northern Border Pipeline discounted transportation rates on a
short-term basis to maximize overall revenue, and has since contracted all of
its available capacity based on summer design on the Port of Morgan, Montana to
Ventura, Iowa portion of the pipeline through September of 2005. Currently, we
expect Northern Border Pipeline's revenue for 2005 will be $15 million to $18
million ($11 million to $13 million, net to the Partnership), lower than 2004
revenue which generally reflected contracting nearly all capacity at maximum
rate levels.

CREDIT AGREEMENTS - In May 2005, we entered into a five-year $500 million
revolving credit agreement and Northern Border Pipeline entered into a five-year
$175 million revolving credit agreement. We terminated our existing $275 million
credit facility and Northern Border Pipeline terminated its existing $175
million credit facility in conjunction with the execution of the new agreements.
Please read "Liquidity and Capital Resources - Debt and Credit Facilities" in
this section for more information.

TRANSITION - In May 2005, the transition, from CCE Holdings to ONEOK, Inc., of
services provided to us was completed.

MIDWESTERN GAS TRANSMISSION'S EASTERN EXTENSION PROJECT - In June 2005,
Midwestern Gas Transmission filed an application for the Eastern Extension
Project with the Federal Energy Regulatory Commission (FERC). This project is
expected to cost $22 million to $25 million and will add 30 miles of pipeline
with 120 million cubic feet per day (mmcfd) of transportation capacity from
Portland, Tennessee to planned interconnections with Columbia Gulf Transmission
Company and East Tennessee Pipeline Company.


                                       13
<PAGE>


BANKRUPTCY CLAIMS - In June 2005, Northern Border Pipeline Company, Crestone
Gathering Services, a wholly-owned subsidiary of Crestone Energy Ventures, and
Bear Paw Energy, LLC executed term sheets with a third party for the sale of
their unsecured claims held against Enron Corp. and Enron North America Corp.
Proceeds from the sale are expected to be $14.6 million. In 2004, we adjusted
our allowance for doubtful accounts to reflect an estimated $3.4 million ($3.0
million, net to the Partnership) recovery for our claims. In the second quarter
of 2005, we made favorable adjustments to our allowance for doubtful accounts of
approximately $1.8 million ($1.6 million, net to the Partnership) to reflect the
agreements for the sales. As a result of the sale, Northern Border Pipeline
anticipates recognizing additional income of $9.4 million ($6.6 million, net to
the Partnership) later in 2005.

INTEREST IN FORT UNION GAS GATHERING - In July 2005, Crestone Energy Ventures
executed a purchase and sale agreement to acquire an additional 3.7% interest of
Fort Union Gas Gathering, L.L.C., bringing its total interest to approximately
37%, for $5.3 million, subject to normal closing adjustments. We expect to close
the transaction in August of 2005.

BIGHORN GAS GATHERING PREFERRED A SETTLEMENT - In July 2005, we negotiated a
settlement agreement with our partner in Bighorn Gas Gathering related to
provisions of the joint venture agreement that provided for cash flow incentives
based on well connections. These incentives were provided to us through our
ownership of preferred A shares in Bighorn Gas Gathering. Due to the settlement
agreement, we anticipate recognizing $5.4 million of equity earnings associated
with incentives due to us for 2004 and 2005. The settlement agreement also
eliminates any future incentives. Therefore, our preferred A shares have been
cancelled and effectively redeemed and capital accounts adjusted accordingly.

MINNESOTA FUEL TAX - In July 2005, the Minnesota legislature passed an omnibus
tax bill, which included a provision restoring the sales tax on pipeline fuel
and equipment purchases. The provision is effective for purchases made after
July 31, 2005. As a result, the value of the gas provided in-kind and used in
the operation of Northern Border Pipeline and Viking Gas Transmission's
compressor stations will be taxed. We estimate that this additional tax will be
approximately $2.3 million to $3.0 million per year. We are evaluating whether
there is a legal basis for challenging the imposition of this tax on our
operations.


RECENT ACCOUNTING PRONOUNCEMENTS

The Financial Accounting Standards Board (FASB) recently issued FASB
Interpretation (FIN) 47, "Accounting for Conditional Asset Retirement
Obligations - an interpretation of FASB Statement No. 143." For more information
about this recent accounting pronouncement and how it may affect our future
financial statements, please refer to Note 8 of the Notes to Consolidated
Financial Statements included in Item 1 of this quarterly report on Form 10-Q.


CRITICAL ACCOUNTING POLICIES AND ESTIMATES

In our financial reporting process, we make assumptions and use estimates that
affect the reported amount of the assets and liabilities, disclosure of
contingent assets and liabilities, and the reported amount of revenue and
expenses during the reporting period. Actual results could differ from these
estimates if the underlying assumptions are incorrect. Any effects on our
financial position or results of operations resulting from revisions to these
estimates are recorded in the period during which the facts that gave rise to
the revision become known. Key estimates used by management include:

         o        the economic useful life of our assets used to determine
                  depreciation and amortization;

         o        the fair value used to determine possible asset impairment
                  charges;

         o        the fair value used to record derivative assets and
                  liabilities;

         o        the fair value of assets acquired; and

         o        the amount of expense accruals.


                                       14
<PAGE>

In general, there have been no significant changes in our critical accounting
policies since December 31, 2004. For a detailed discussion of these policies,
please refer to Note 2 of the Notes to Consolidated Financial Statements -
Summary of Significant Accounting Policies, in our annual report on Form 10-K
for the year ended December 31, 2004. Details of our most significant accounting
policies are noted as follows:

REGULATORY ASSETS

The interstate natural gas pipeline segment's accounting policies conform to
SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation."
Accordingly, assets that result from the ratemaking process are reflected on the
balance sheet as regulatory assets. We consider factors such as regulatory
changes and the impact of competition to determine the probability of future
recovery of these assets. If we determine future recovery is no longer probable,
we would be required to write off the regulatory assets at that time. As of June
30, 2005, the interstate natural gas pipeline segment reflected regulatory
assets of $12.8 million that we expect to recover from our customers over
varying time periods up to 44 years.

ESTIMATED USEFUL LIVES OF PROPERTY, PLANT AND EQUIPMENT AND DEPRECIATION METHODS

Our long-lived assets are recorded at original cost. We estimate the economic
useful lives of our assets based on historical experience and make adjustments
when changes in planned use, technological advances, or other factors show that
a different life is more appropriate. The depreciation rates for our regulated
interstate natural gas pipelines are determined by the FERC's ratemaking
process. Revisions to the estimated economic useful lives of our assets would
impact our depreciation and amortization expense in future periods.

RECOVERABILITY OF LONG-LIVED ASSETS

We review our long-lived assets for impairment according to SFAS No. 144,
"Accounting for the Impairment or Disposal of Long-Lived Assets," when events or
changes in circumstances indicate that the value of our assets on the balance
sheet may not be recoverable. We compare our asset's book value to its expected
future net cash flow to determine recoverability. If an asset is considered to
be impaired, an impairment charge equal to the difference between the fair value
of the asset and its book value would be recognized.

GOODWILL

Our accounting for goodwill is in accordance with SFAS No. 142, "Goodwill and
Other Intangible Assets." We have selected the fourth quarter to perform our
annual testing.

DERIVATIVE INSTRUMENTS

We use derivative instruments to mitigate commodity price exposure in our
natural gas gathering and processing segment and interest rate risk related to
our financing activities. We record our derivatives at fair value according to
SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities."
The fair value of a derivative instrument is determined by the present value of
its future cash flows, based on market prices from third party sources. The
accounting treatment for changes in the derivative's fair value depends on
whether it has been designated and qualifies as part of a hedge relationship. If
specific hedge criteria are met, the derivative's gains and losses may offset
the hedged item's related results in the income statement. As of June 30, 2005,
the consolidated balance sheet included assets from derivative financial
instruments of $3.1 million and liabilities from derivative financial
instruments of $1.3 million.

REVENUE RECOGNITION

For the interstate natural gas pipeline segment, we recognize revenue when
transportation service is provided to our customers according to each
transportation contract. Under our firm transportation agreements, our customers
are obligated to pay a fee for capacity on our pipelines, regardless of how much
natural gas is actually transported. For the natural gas gathering and
processing segment, we record operating revenue when gas is processed in or
transported through our facilities. Revenue from cash payments received from
producers prior to providing gathering services are deferred and recognized
based on the depletion of the natural gas reserves associated with the gathering
system. For the coal slurry pipeline segment, revenue is recognized based on a
contracted demand payment, actual tons of coal transported and direct
reimbursement of certain other expenses.


                                       15
<PAGE>


RESULTS OF OPERATIONS

SELECTED FINANCIAL AND OPERATING RESULTS

The following table summarizes financial and operating results for the three and
six months ended June 30, 2005, and 2004 by segment (in thousands, unless
otherwise noted):

<Table>
<Caption>
                                                   THREE MONTHS ENDED           SIX MONTHS ENDED
                                                         JUNE 30,                   JUNE 30,
                                                ------------------------    ------------------------
                                                   2005          2004          2005          2004
                                                ----------    ----------    ----------    ----------
<S>                                             <C>           <C>           <C>           <C>
Operating revenue:
   Interstate Natural Gas Pipeline              $   82,541    $   94,517    $  179,186    $  192,143
   Natural Gas Gathering and Processing             61,039        42,585       118,612        83,326
   Coal Slurry Pipeline                              5,837         5,374        11,998        10,780
                                                ----------    ----------    ----------    ----------
      Total operating revenue                      149,417       142,476       309,796       286,249
                                                ----------    ----------    ----------    ----------

Operating income (loss):
   Interstate Natural Gas Pipeline                  43,915        56,667        99,553       115,241
   Natural Gas Gathering and Processing             10,841         4,351        20,343         9,161
   Coal Slurry Pipeline                              1,252         1,022         2,178         1,716
   Other                                            (2,544)       (1,445)       (5,072)       (3,762)
                                                ----------    ----------    ----------    ----------
      Total operating income                        53,464        60,595       117,002       122,356
                                                ----------    ----------    ----------    ----------

Income (loss) from continuing operations:
   Interstate Natural Gas Pipeline                  24,048        33,195        56,197        67,445
   Natural Gas Gathering and Processing             15,110         7,849        28,800        18,475
   Coal Slurry Pipeline                              1,109           865         1,854         1,539
   Other                                           (12,535)       (9,037)      (24,840)      (18,735)
                                                ----------    ----------    ----------    ----------
      Total income from continuing operations       27,732        32,872        62,011        68,724
                                                ----------    ----------    ----------    ----------

Discontinued operations, net of tax                    358           393           748         1,156
                                                ----------    ----------    ----------    ----------

Net income                                      $   28,090    $   33,265    $   62,759    $   69,880
                                                ==========    ==========    ==========    ==========

Operating data (1):
   Interstate Natural Gas Pipeline:
      Million cubic feet per day ( mmcfd)          257,171       272,763       563,864       575,578
      Average daily throughput (mmcfd)               2,889         3,065         3,193         3,237
   Natural Gas Gathering and Processing:
      Gathering (mmcfd)                              1,005         1,020         1,029           998
      Processing (mmcfd)                                63            56            62            53
   Coal Slurry Pipeline:
      Thousands of tons of coal shipped              1,102           975         2,384         2,129
</Table>


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


                                       16
<PAGE>


CONSOLIDATED OPERATING RESULTS

Our income from continuing operations was $27.7 million for the second quarter
of 2005, or $0.54 per unit, compared with $32.9 million in 2004, or $0.65 per
unit, for the same quarter last year. This $5.2 million, or 16%, decrease is
largely attributable to the revenue impact of the uncontracted capacity on
Northern Border Pipeline and higher interest expense offset by improved results
from our natural gas gathering and processing segment due to increased prices of
natural gas and natural gas liquids and increased volumes processed.

For the six months ended June 30, 2005, income from continuing operations was
$62.0 million, or $1.22 per unit, compared with $68.7 million, or $1.37 per
unit, for the six months ended June 30, 2004. This $6.7 million, or 10%,
decrease was primarily the result of the revenue impact of Northern Border
Pipeline's uncontracted capacity as well as increased interest expense for the
six months ended June 30, 2005, offset by improved results from our gas
gathering and processing segment due to increased commodity prices realized and
volumes processed.


INTERSTATE NATURAL GAS PIPELINE SEGMENT

OVERVIEW

Our interstate natural gas pipeline segment transports natural gas for its
customers. Operating revenue is derived from transportation contracts under
tariffs regulated by the FERC. The tariffs specify the maximum rate we can
charge our customers, which is determined through a ratemaking process. During
this process, which is called a rate case in the industry, a determination is
reached by the FERC, either through a hearing or a settlement on a just maximum
rate that includes recovery of our prudent cost-based investment and a
reasonable return for our investors. Our firm transportation customers are
obligated to pay a fee for capacity on our pipelines, regardless of how much
natural gas they actually transport, in addition to a fee based on the volume of
natural gas transported. Our interruptible transportation customers pay a fee
based only on the volume of natural gas transported.

Our interstate natural gas pipeline segment is made up of the following
subsidiaries:

         o        a 70% general partnership interest in Northern Border Pipeline
                  Company;

         o        Midwestern Gas Transmission Company; and

         o        Viking Gas Transmission Company, which includes a 33-1/3%
                  interest in Guardian Pipeline, L.L.C.

For the six months ended June 30, 2005, Northern Border Pipeline accounted for
85% of our interstate natural gas pipeline segment revenue, Midwestern Gas
Transmission accounted for 6%, and Viking Gas Transmission accounted for 9%.


MARKET CONDITIONS

As of December 31, 2004, approximately 88% of the natural gas we transported on
Northern Border Pipeline was produced in the Western Canada Sedimentary Basin.
Therefore, the continuous supply of Canadian natural gas is crucial to our
long-term financial condition. Of equal importance is the demand for natural gas
in the Midwestern United States markets that we serve, including in the Chicago
market area, which is served directly by Northern Border Pipeline and Midwestern
Gas Transmission. Some of the significant factors that may impact our customer's
desire to move natural gas on our interstate pipelines include:

         o        the amount of Canadian natural gas available for export, which
                  is impacted by Canadian supply and demand;

         o        the ability to transport Canadian gas on other pipelines;

         o        the amount of storage capacity for Canadian gas and demand for
                  storage injection;

         o        the availability of natural gas from other supply sources that
                  could be transported to the Midwestern United States;

         o        the demand for natural gas in other markets, which may affect
                  the supply in the Midwestern United States, primarily as a
                  result of temperature and/or hydro electric generation levels;
                  and

         o        the natural gas market price spread between Alberta, Canada
                  and the Midwestern United States.

For a discussion about market factors that may impact supply and demand for
natural gas, please read "Business - Demand for Interstate Pipeline
Transportation Capacity" in our annual report on Form 10-K for the year ended
December 31, 2004.


                                       17
<PAGE>


KNOWN TRENDS AND UNCERTAINTIES

CANADIAN SUPPLY - Our projections assume that Canadian supply will remain fairly
stable and import levels will be flat in 2005.

NATURAL GAS STORAGE LEVELS - We observed rising demand for storage of Canadian
natural gas during the second quarter ended June 30, 2005, and believe this may
be primarily due to an increased price differential between summer natural gas
prices in the United States compared with projected natural gas prices for the
coming winter season. The changing mix of natural gas users may also be a factor
in the growing demand for storage, from the steady demand of industrial users to
temperature-sensitive residential, commercial, and electric generation users. We
anticipate additional storage projects in Alberta, Canada to be in service in
2006.

SEASONALITY - Supply and demand in the various geographic regions of the United
States as a result of weather conditions can significantly affect one another as
the market attempts to balance each region's natural gas needs. In addition to
traditional winter heating demand load, Canadian supply helps serve western
United States' summer demand for natural gas for electric generation. This
market may be sensitive to precipitation levels that affect the supply of hydro
electric generation. During the summer, in the Western United States, the
effects of low hydro electric generation levels combined with high temperature
demand loads impact Canadian natural gas pricing. In the Midwestern United
States, pipeline infrastructure is designed to meet winter heating demand load.
During the summer when there may be excess pipeline capacity, there is greater
competition from other supply sources. Winter season is considered to be
November to March, and summer season is considered to be the remaining months.
Peak summer season for electric generation includes July, August and September.
During the second quarter ended June 30, 2005, we observed weakened demand for
natural gas consistent with typical seasonal demand factors.

COMPETITION - In 2005, new supply from the Rockies via Cheyenne Plains Pipeline
as well as natural gas from the San Juan and Permian Basins has been redirected
from Western United States markets into the Mid-continent region creating
greater supply competition in the Midwestern United States market. Cheyenne
Plains is expected to complete an expansion project that will increase its
pipeline capacity by 170 million dekatherms per day by early 2006.

CONTRACTING RISK - Natural gas supply and demand may significantly impact our
business; however, a significant portion of our revenue is generated from
long-term firm transportation contracts. As long as our pipeline capacity is
fully contracted, under normal circumstances, we can expect to collect operating
revenue regardless of short-term market dynamics that may impact natural gas
flows. When we are not fully contracted, we are directly affected by the current
market fundamentals and are most sensitive to changes in supply and demand for
natural gas which impact the demand for our capacity.

As previously disclosed, Northern Border Pipeline had uncontracted capacity
during the second quarter ended June 30, 2005, on its Port of Morgan, Montana to
Ventura, Iowa portion of pipeline. Expiring long-term transportation contracts
were replaced with primarily short-term contracts. When demand is light relative
to supply, our customers may not want to commit for long periods to a certain
rate if they believe the cost supported by the market will be lower. Seasonal
demand suggests that this situation is more likely to impact our revenue at
certain times of the year. Accordingly, we believe throughput on our system may
be more seasonal in the future and some discounting may be required to maximize
revenue.

GROWTH PROJECTS - We are focused on modifying our existing systems to meet
market demand (organic growth) in addition to seeking new pipeline development
projects. Organic growth projects currently underway include:

         o        Chicago III Expansion - Northern Border Pipeline

         o        Eastern Extension - Midwestern Gas Transmission

         o        Southbound Expansion - Midwestern Gas Transmission

For the Chicago III Expansion, a proposed expansion of Northern Border
Pipeline's system into the Chicago market area, Northern Border Pipeline has
filed its application for a certificate of public convenience and necessity for
the construction and operation of the facilities. Northern Border Pipeline
anticipates the issuance of a certificate by the FERC during the third quarter
of 2005. This project is fully subscribed and estimated to cost approximately
$21 million. It will add 130 mmcfd of transportation capacity from Harper, Iowa
to Chicago, Illinois.


                                       18
<PAGE>


In June 2005, Midwestern Gas Transmission filed an application for a certificate
of public convenience and necessity for the Eastern Extension Project with the
FERC. This project is expected to cost $22 million to $25 million and will add
30 miles of pipeline with 120 mmcfd of transportation capacity from Portland,
Tennessee to planned interconnections with Columbia Gulf Transmission Company
and East Tennessee Pipeline Company.

Midwestern Gas Transmission's Southbound Expansion will increase its pipeline's
southbound capacity by 86,000 dekatherms per day. This fully-subscribed
expansion project is expected to go into service in November of 2005.

Please refer to "Management's Discussion and Analysis of Financial Condition and
Results of Operations - Interstate Natural Gas Pipeline Segment" in our annual
report on Form 10-K for the year ended December 31, 2004, for more information
about our expansion projects.

REGULATORY DEVELOPMENTS

RATE CASE - Under the terms of Northern Border Pipeline's 1999 rate case,
Northern Border Pipeline must file a new rate case on November 1, 2005. Elements
to be decided in the rate case include billing units, rate base, our
depreciation rate on transmission plant, return on equity, rate design and
issues related to the inclusion of an income tax allowance. We believe the new
rate would take effect on May 1, 2006. The resulting rate may be subject to
reduction based upon FERC's review. The outcome will be finally determined by
FERC approval of a settlement or decided by the FERC based on hearings.

INCOME TAX ALLOWANCE - In May 2005, the FERC issued a policy statement
permitting the inclusion in rates of an income tax allowance for partnership
interests if the partners have an actual or potential income tax liability on
that income. Northern Border Pipeline's present rates reflect an allowance for
income taxes. More information regarding our upcoming rate case and income tax
allowance can be found in "Business - Interstate Pipeline Regulation" in our
annual report on Form 10-K for the year ended December 31, 2004.

INTERSTATE NATURAL GAS PIPELINE SEGMENT OPERATING RESULTS

The interstate natural gas pipeline segment reported net income of $24.0 million
for the second quarter ended June 30, 2005, compared with $33.2 million for the
second quarter ended June 30, 2004. The $9.2 million, or 28%, decline for the
second quarter ended June 30, 2005, was primarily due to the revenue impact from
uncontracted and discounted capacity in 2005 on Northern Border Pipeline on the
Port of Morgan, Montana to Ventura, Iowa portion of the pipeline. For the six
months ended June 30, 2005, net income was $56.2 million compared with $67.4
million for the six months ended June 30, 2004. The $11.2 million, or 17%,
decrease for the six months ended June 30, 2005, was primarily the result of the
second quarter revenue impact from uncontracted and discounted capacity on
Northern Border Pipeline.

Operating revenue decreased $12.0 million, or 13%, for the second quarter ended
June 30, 2005, compared with the same quarter last year primarily impacted by
$13.0 million decreased revenue associated with the uncontracted and discounted
transportation capacity for Northern Border Pipeline, partially offset by $1.3
million increased short-term and other transportation service revenue for
Northern Border Pipeline.

Operating revenue decreased $13.0 million, or 7%, for the six months ended
June 30, 2005, compared with the same period in 2004, reflecting the impact
of the second quarter ended June 30, 2005, items and one additional day of
transportation revenue in the first quarter ended March 31, 2004, due to
leap year.

Operations and maintenance expense increased slightly by $0.2 million for the
second quarter ended June 30, 2005, compared with the same quarter last year.
The quarter ended June 30, 2005, included a reduction of Northern Border
Pipeline's allowance for doubtful accounts of approximately $0.6 million related
to bankruptcy claims against Enron and Enron North America. The second quarter
ended June 30, 2004, included a credit of approximately $1.2 million to true up
previously recorded corporate charges which was partially offset by $0.7 million
of amortization expense for the renewal of a right-of-way easement.


                                       19
<PAGE>


Operations and maintenance expense increased $2.3 million for the six months
ended June 30, 2005, compared with the same period last year primarily as a
result of adjustments recorded in 2005 and 2004 for operational gas volume
imbalances on Viking Gas Transmission.

Interest expense increased $0.7 million for the second quarter ended June 30,
2005, and $1.0 million for the six months ended June 30, 2005, compared with the
same periods last year as a result of higher average interest rates that were
partially offset by lower average debt outstanding.


NATURAL GAS GATHERING AND PROCESSING SEGMENT

OVERVIEW

Our natural gas gathering and processing segment accepts delivery of raw gas
from natural gas wells and central collection points located primarily in the
Powder River Basin in Wyoming and the Williston Basin in Montana and North
Dakota. Our pipelines gather the wellhead production and transport the raw gas
to central collection points where it is processed and compressed for entry into
the transmission pipeline grid. Revenue is derived primarily from two types of
gathering and processing agreements based on volumetric fees or
percentage-of-proceeds (POP) contracts. We are sensitive to fluctuations in the
price of natural gas and natural gas liquids because a significant portion of
this segment's revenue is from POP agreements. Under these agreements, we retain
a percentage of the commodities as payment for our services, which we sell in
the open market. We use derivative instruments to mitigate our commodity price
exposure.

Our natural gas gathering and processing segment is made up of the following
subsidiaries:

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

         o        Crestone Energy Ventures, which owns:

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

                  -        a 33.33% interest in Fort Union Gas Gathering,
                           L.L.C., with operations in the Powder River Basin;
                           and

                  -        a 35% interest in Lost Creek Gathering, L.L.C., with
                           operations in the Wind River Basin, located in
                           Wyoming.

In July 2005, Crestone Energy Ventures executed a purchase and sale agreement to
acquire an additional 3.7% interest of Fort Union Gas Gathering, L.L.C.,
bringing its total interest to approximately 37%, for $5.3 million, subject to
normal closing adjustments. We expect to close the transaction in August of
2005.

MARKET CONDITIONS

Key factors that may impact Bear Paw Energy and our joint venture interests are:

         o        the pace of reserve development by producers, which is
                  affected by:

                  -        a producer's ability to obtain drilling and
                           production permits in a timely and economic manner;

                  -        reserve characteristics and performance;

                  -        surface access and infrastructure issues;

                  -        significant volumes of water associated with coalbed
                           methane production;

                  -        environmental issues;

         o        the decline rate of existing wells;

         o        the composition of the gathered raw gas stream; and

         o        the value of natural gas and natural gas liquids.

For a more detailed discussion of market factors that may impact our gathering
and processing segment, please read "Business - Future Demand and Competition"
in our annual report on Form 10-K for the year ended December 31, 2004.


                                       20
<PAGE>


KNOWN TRENDS AND UNCERTAINTIES

NATURAL GAS AND NATURAL GAS LIQUIDS PRICING - Our financial performance in the
gathering and processing segment may be significantly impacted by the price of
natural gas and natural gas liquids, particularly for the Williston Basin
operations which involve primarily POP contracts. In the second quarter ended
June 30, 2005, realized commodity prices, net of the effects of hedging,
continued to increase: the weighted average price per gallon of natural gas
liquids increased 50%, to $0.87 for the second quarter ended June 30, 2005,
compared with $0.58 for the same period last year; the weighted average price
per million British thermal units (mmBtu) of natural gas increased 23%, to $6.15
for the second quarter ended June 30, 2005, compared with $5.00 for the same
period last year.

RAW GAS COMPOSITION - Changes in the raw gas composition may impact our
operating margins. Most of the wells connected to our Williston Basin facilities
produce casinghead gas, which is significantly higher in energy content
(measured in Btu) than coalbed methane gas that is produced in the Powder River
Basin. Although generally the value of natural gas and natural gas liquids is
related to the Btu content, certain products have greater value per Btu than
others.

GATHERING VOLUMES - Our financial performance in the gathering and processing
segment may be impacted by the volume and pressure of gas gathered, particularly
in the Powder River Basin. These contracts are primarily volumetric fee-based
contracts. We provide two different levels of service depending on gas pressure.
Our processing margins are higher for low pressure gas gathered compared with
high pressure gas because of the amount of compression required to transport gas
in our gathering system and into the interstate pipeline grid. As a result of
these different services, the revenue impact from changes in our processing
volumes does not change proportionately.

POWDER RIVER BASIN DEVELOPMENT - The development of new facilities is based on
well growth, field production, economics, permit considerations, and other
factors that impact producers' decision to drill and produce coalbed methane
gas. In the Powder River Basin, we believe drilling activity for the remainder
of 2005 will be similar to that in 2004. Production is shifting westward in the
basin toward the Big George Coal where dewatering times are lengthier but
production volume is greater than in the eastern part of the basin.

WILLISTON BASIN DEVELOPMENT - Bear Paw Energy owns and operates the Grasslands,
Baker, Marmarth, Little Beaver and Lignite gathering and processing facilities.
As a result of increased drilling and development in the Williston Basin, we
expect continued growth in this area. We are selectively expanding our
facilities and systems to enhance our financial performance. At current oil
prices, we expect casinghead gas volume to increase at least through 2006. Due
to additional land dedication in the Bakken Play, a second phase of expansion
was initiated and completed in the second quarter ended June 30, 2005. A
separate expansion is also under way in the Beaver Creek area.

NATURAL GAS GATHERING AND PROCESSING SEGMENT OPERATING RESULTS

The natural gas gathering and processing segment reported net income of $15.1
million for the second quarter ended June 30, 2005, compared with $7.8 million
for the second quarter ended June 30, 2004. Net income was $28.8 million for the
six months ended June 30, 2005, compared with $18.5 million for the same period
last year. The increase of $7.3 million, or 94%, and $10.3 million, or 56%, for
the three and six months ended June 30, 2005, respectively, as compared with the
prior year, were largely attributable to favorable pricing for natural gas and
natural gas liquids and increased processing volumes.

Operating revenue increased $18.4 million, or 43%, in the second quarter ended
June 30, 2005, compared with the second quarter ended June 30, 2004. Of this
amount, $19.0 million was due to increased revenue realized in the Williston
Basin as a result of increased natural gas and natural gas liquids prices and
volumes, which were partially offset by lower volumes in the Powder River Basin.
Operating revenue increased $35.3 million, or 42%, for the six months ended June
30, 2005, compared with the same period last year. Of this amount, $37.0 million
was due to increased revenue realized in the Williston Basin, partially offset
by $1.7 million decreased revenue realized in the Powder River Basin due a
decline of our low margin gathering volumes.

Product purchases were $35.5 million for the second quarter ended June 30, 2005,
compared with $23.5 million for the same period last year. Product purchases
were $67.9 million for the six months ended June 30, 2005, compared with $44.9
million for the six months ended June 30, 2004. Product purchases increased due
to increased commodity prices and volumes processed.


                                       21
<PAGE>
Operations and maintenance expense decreased $0.4 million for the second quarter
ended June 30, 2005, compared with the second quarter ended June 30, 2004,
primarily due to a $1.2 million reduction of our allowance for doubtful accounts
reflecting the agreements for the sale of the bankruptcy claims held against
Enron and Enron North America, partially offset by increased expenses of $0.2
million related to the Charlie Creek expansion and increased general expenses of
$0.2 million. Operations and maintenance expense increased $0.3 million for the
six months ended June 30, 2005, which included increased operating expense
related to the Charlie Creek expansion of $0.8 million.

Equity earnings increased $0.8 million, or 24%, for the second quarter ended
June 30, 2005, compared with the same period last year due to the overall growth
in the Powder and Wind River Basins that resulted in higher volumes at Fort
Union and Lost Creek. Equity earnings for the six months ended June 30, 2005,
decreased $1.1 million compared with the same period in 2004 as a result of the
Bighorn Gas Gathering preferred A cash flow incentives of $2.7 million
recognized in 2004. For the six months ended June 30, 2005, equity earnings for
Fort Union and Lost Creek increased $1.7 million compared with the same period
last year due to the overall growth in the Powder and Wind River Basins.


COAL SLURRY PIPELINE SEGMENT

OVERVIEW

Our coal slurry pipeline segment, which includes Black Mesa Pipeline Company,
transports crushed coal suspended in water. Revenue is derived from a
transportation contract with the sole supplier of coal to the Mohave Generating
Station in Nevada. This contract generates fee-for-service revenue through
December 31, 2005.

KNOWN TRENDS AND UNCERTAINTIES

Upon expiration of our transportation contract at the end of this year, we
expect Black Mesa Pipeline to be temporarily shut down. Interested parties are
working to resolve water supply, coal supply and transportation contracting
issues in order for operations to resume. In addition, a final Environmental
Impact Statement for the project must be issued which is anticipated in late
2006. We believe that successful resolution of these issues should result in the
modification and reconstruction of our coal slurry pipeline in late 2008 and
2009. If these issues are not resolved and the Mohave Generating Station is
permanently closed, we expect to incur shut down costs related to our pipeline
of approximately $5 million to $7 million, and to have a non-cash charge of
approximately $12 million related to goodwill and the remaining undepreciated
cost of the pipeline.

For more information about the environmental issues surrounding our coal slurry
pipeline, please read "Business - Coal Slurry Pipeline Segment" in our annual
report on Form 10-K for the year ended December 31, 2004.

OPERATING RESULTS

The coal slurry pipeline segment reported net income of $1.1 million for the
second quarter ended June 30, 2005, compared with $0.9 million for the same
period last year. Second quarter 2005 results include increased electricity
costs of $0.3 million that were charged to the customer and recovered through
operating revenue.

Net income was $1.9 million for the six months ended June 30, 2005, compared
with $1.5 million for the same period last year. Operating revenue increased
$1.2 million and operating expense increased $0.9 million due to increased
electricity costs.


                                       22
<PAGE>

OTHER

Items that are not attributable to any segment included certain of our general
and administrative expenses, interest expense on our debt and other income and
expense items. For the second quarter ended June 30, 2005, interest expense not
allocated to any segment increased $2.2 million as compared with the second
quarter ended June 30, 2004, due to higher average debt outstanding and
increased average interest rates. For the second quarter ended June 30, 2005,
operations and maintenance expense increased $1.0 million as compared with the
second quarter ended June 30, 2004. Operations and maintenance expense for 2005
included $0.4 million of expenses that will be allocated to our segments.
Expenses in 2004 included a $0.5 million credit for previously accrued corporate
charges. For the six months ended June 30, 2005, interest expense not allocated
to any segment increased $4.6 million due to higher average debt outstanding and
increased average interest rates. Operations and maintenance expense for the six
months ended June 30, 2005, increased $1.3 million which included $0.8 million
of relocation charges and other expenses that will be allocated to our segments.


LIQUIDITY AND CAPITAL RESOURCES

OVERVIEW

We believe our liquidity is adequate to fund future recurring operating
activities and investments. We rely on our operating cash flow and the credit
facilities listed in the following table to meet our short-term liquidity needs.
We expect to meet our other liquidity needs by issuing long-term debt and/or
additional limited partner interests. The timing and our ability to complete
such offerings will depend on various factors, including:

         o        the prevailing market conditions;

         o        interest rates;

         o        our financial condition; and

         o        our credit rating.

DEBT AND CREDIT FACILITIES

The Partnership's debt and credit facilities outstanding as of June 30, 2005,
are as follows (in thousands):

<Table>
<Caption>
                                                              Payments Due by Period
                                                             -----------------------
                                                              Current
                                                              Portion      Long-Term
                                                  Total       < 1 Year      Portion
                                                ----------   ----------   ----------
<S>                                             <C>          <C>          <C>
Northern Border Pipeline:
   $175 million credit agreement due 2010 (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
Viking Gas Transmission:
   Series A, B, C, and D senior notes
      due 2008 to 2014 average 7.46%                30,053        2,133       27,920
Northern Border Partners, L.P.:
   $500 million credit agreement
      due 2010 (a), average 3.75%                  198,000           --      198,000
   8.875% senior notes due 2010                    250,000           --      250,000
   7.10% senior notes due 2011                     225,000           --      225,000
                                                ----------   ----------   ----------
      Total                                     $1,303,053   $    2,133   $1,300,920
                                                ==========   ==========   ==========
</Table>

(a)      Northern Border Partners, L.P. 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.


                                       23
<PAGE>
On May 16, 2005, we entered into a five-year $500 million revolving credit
agreement with several financial institutions. Under this agreement, we borrowed
$186 million to pay the entire balance of our existing $275 million revolving
credit agreement and terminated that agreement. At our option, the interest rate
on the outstanding borrowings may be the lender's base rate or the London
Interbank Offered Rate (LIBOR) plus a spread that is based on our long-term
unsecured debt ratings. We are required to comply with certain financial,
operational, and legal covenants, including the maintenance of EBITDA to
interest expense ratio of greater than 3 to 1 and debt to EBITDA ratio of no
more than 4.75 to 1. If we consummate one or more acquisitions in which the
total purchase price exceeds $25 million, the allowable ratio of debt to
adjusted EBITDA is increased to 5.25 to 1 for two calendar quarters following
the acquisition. If we breach any of these covenants, the balance outstanding
may become due and payable immediately.

Also on May 16, 2005, Northern Border Pipeline Company entered into a five-year
$175 million revolving credit agreement with several financial institutions.
Under this agreement, Northern Border Pipeline borrowed $29 million to pay the
entire balance on its existing $175 million revolving credit agreement and
terminated that agreement. The borrowings of $29 million were subsequently
repaid in the second quarter ended June 30, 2005. Similar to the Partnership's
revolving credit agreement, Northern Border Pipeline may select the lender's
base rate or the LIBOR plus a spread that is based on Northern Border Pipeline's
long-term unsecured debt ratings as its interest rate on the borrowings.
Northern Border Pipeline is required to comply with certain financial,
operational, and legal covenants, including the maintenance of EBITDA to
interest expense ratio of greater than 3 to 1 and debt to EBITDA ratio of no
more than 4.50 to 1. If Northern Border Pipeline consummates one or more
acquisitions in which the total purchase price exceeds $25 million, the
allowable ratio of debt to adjusted EBITDA is increased to 5 to 1 for two
calendar quarters following the acquisition. If Northern Border Pipeline
breaches any of these covenants, the balance outstanding may become due and
payable immediately.

As of June 30, 2005, the Partnership and Northern Border Pipeline were in
compliance with the covenants of their respective credit agreements.

DEBT SECURITIES

We anticipate issuing ten-year fixed rate senior notes during 2005 to reduce
amounts drawn under our $500 million revolving credit agreement.

HEDGING ACTIVITIES

In 2004, we entered into forward-starting interest rate swap agreements with a
total notional amount of $100 million in anticipation of a ten-year fixed rate
senior notes issuance. The forward-starting interest rate agreements expired in
late May and early June of 2005, which resulted in the Partnership paying $2.7
million to counterparties. In June 2005, we entered into a Treasury lock
interest rate agreement with a total notional amount of $200 million in
anticipation of a ten-year senior note issuance. In July 2005, we paid $0.1
million to the counterparty upon expiration of the June 2005 Treasury lock
interest rate agreement.

Our outstanding interest rate swap agreements with notional amounts totaling
$150 million are due to expire in March of 2011. Under these agreements, we make
payments to counterparties at variable rates based on LIBOR and receive payments
based on a 7.10% fixed rate of return. As of June 30, 2005, the average
effective interest rate on our interest rate swap agreements was 5.80%.

OPERATING ACTIVITIES

Net cash provided by operating activities decreased $18.5 million for the six
months ended June 30, 2005, compared with the same period last year, as a result
of decreased net income, which is discussed in the "Results of Operations"
section of this quarterly report. Other factors were a $4.9 million decrease in
distributions received from unconsolidated affiliates related to payments
received in 2004 for our Bighorn Gas Gathering preferred A cash flow incentives
and a net decrease in working capital of $5.9 million for the six months ended
June 30, 2005, compared with a net decrease in working capital of $0.6 million
for the same period in 2004.


                                       24
<PAGE>


INVESTING ACTIVITIES

Net cash used in investing activities increased $15.6 million for six months
ended June 30, 2005, as compared with the same period in 2004 primarily due to
increased capital expenditures. Our investment in unconsolidated affiliates was
$1.5 million for the six months ended June 30, 2005, representing contributions
made to Bighorn Gas Gathering for its capital expenditures.

Capital expenditures were $23.2 million for the six months ended June 30, 2005,
including $13.0 million for the interstate natural gas pipeline segment and $9.6
million for the natural gas gathering and processing segment. For the interstate
natural gas pipeline segment, approximately $1.6 million of the capital
expenditures is related to Northern Border Pipeline's Chicago III Expansion
Project and $2.1 million is related to Midwestern Gas Transmission's growth
projects. The remaining capital expenditures for the six months ended June 30,
2005, were primarily related to renewals and replacements of existing
facilities. For the natural gas gathering and processing segment, the capital
expenditures for the six months ended June 30, 2005, were primarily related to
the Partnership's expansions in the Williston Basin. Capital expenditures in the
six months ended June 30, 2004, were $9.5 million which included $5.6 million
for the interstate natural gas pipeline segment, $2.4 million for the natural
gas gathering and processing segment and $1.5 million for the coal slurry
pipeline segment.

Total capital expenditures for 2005 are estimated to be approximately $87
million, which includes $55 million for the interstate natural gas pipeline
segment. Of the $55 million projected expenditures for the interstate natural
gas pipeline segment, approximately $12 million relates to Northern Border
Pipeline's Chicago III Expansion Project, $8 million to $9 million relates to
Midwestern Gas Transmission's Eastern Extension Project, and $2 million relates
to Midwestern Gas Transmission's Southbound Expansion Project. Capital
expenditures for the natural gas gathering and processing segment are estimated
to be $28 million for 2005 primarily for growth capital expenditures. Funds
required to meet our capital expenditure requirements for 2005 are anticipated
to be provided from our credit facility and operating cash flow. Northern Border
Pipeline currently anticipates funding its 2005 capital expenditures primarily
by borrowing on its credit facility and using operating cash flow.

FINANCING ACTIVITIES

Net cash used in financing activities decreased $5.6 million for the six months
ended June 30, 2005, compared with the same period in 2004.

In the six months ended June 30, 2004, Northern Border Pipeline received equity
contributions from its general partners which included $39 million from its
minority interest holder that was used to repay existing debt.

Borrowings on long-term debt for the six months ended June 30, 2005, were $86.0
million compared with $90.0 million for the six months ended June 30, 2004. Debt
repayments for the six months ended June 30, 2005, were $81.7 million and $134.8
million for the six months ended June 30, 2004.

Payments for the termination of derivative instruments were $2.7 million for the
six months ended June 30, 2005.


THE IMPACT OF ENRON'S CHAPTER 11 FILING ON OUR BUSINESS

In June 2005, Northern Border Pipeline Company, Crestone Gathering Services and
Bear Paw Energy, LLC executed term sheets with a third party for the sale of
their unsecured claims held against Enron and Enron North America. Proceeds from
the sale are expected to be $14.6 million. In 2004, we adjusted our allowance
for doubtful accounts to reflect an estimated $3.4 million ($3.0 million, net to
the Partnership) recovery for our claims. In the second quarter of 2005, we made
an adjustment to our allowance for doubtful accounts of approximately $1.8
million ($1.6 million, net to the Partnership) to reflect the agreements for the
sales. As a result of the sale, Northern Border Pipeline anticipates recognizing
additional income of $9.4 million ($6.6 million, net to the Partnership) later
in 2005.


                                       25
<PAGE>


In June 2005, Enron filed an amended motion in the bankruptcy court seeking
approval to terminate the Enron Gas Pipeline Employee Benefit Trust (Trust) and
to distribute its assets among certain identified companies, one being Northern
Border Pipeline's operator, Northern Plains Natural Gas Company, LLC. If Enron's
relief is granted as requested, Northern Plains would assume retiree benefit
liabilities, estimated as of November 17, 2004, of approximately $2.3 million
with an asset allocation of approximately $1.7 million. Northern Natural Gas
Company, a participant in the Trust through June 30, 2002, along with other
parties have filed a motion to strike Enron's amended motion alleging that
allocation of the assets and liabilities of the Trust should be decided in a
pending lawsuit filed in the United States District Court for the District of
Nebraska and not in the bankruptcy court.

For more information about the bankruptcy claims held by us against Enron and
Enron North America, please refer to "Management's Discussion and Analysis of
Financial Condition and Results of Operations - Update on the Impact of Enron's
Chapter 11 Filing on our Business" in our annual report on Form 10-K for the
year ended December 31, 2004, and our quarterly report on Form 10-Q for the
first quarter ended March 31, 2005.


FORWARD-LOOKING STATEMENTS AND RISK FACTORS

The statements in this quarterly report that are not historical information 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. 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 following:

Interstate Natural Gas Pipeline Segment:

         o        the impact of uncontracted capacity on Northern Border
                  Pipeline being greater than expected;

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

                  -        future demand for and prices of natural gas;

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

                  -        availability of supplies of Canadian natural gas;

                  -        availability of additional storage capacity;

                  -        weather conditions; and

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

         o        performance of contractual obligations by the shippers;

         o        political and regulatory developments that impact FERC
                  proceedings involving interstate pipelines and the interstate
                  pipelines' success in sustaining their positions in such
                  proceedings;

         o        the ability to recover costs in our rates;

Natural Gas Gathering and Processing Segment:

         o        the rate of development, gas quality, and competitive
                  conditions in gas fields near our natural gas gathering
                  systems in the Powder River and Williston Basins and our
                  investments in the Powder River and Wind River Basins;

         o        prices of natural gas and natural gas liquids;

         o        the composition and quality of the natural gas we gather and
                  process in our plants;

         o        the efficiency of our processing plants in extracting natural
                  gas and natural gas liquids;

Coal Slurry Pipeline Segment:

         o        renewal of the coal slurry transportation contract under
                  favorable terms;

General:

         o        developments in the December 2, 2001, filing by Enron of a
                  voluntary petition for bankruptcy protection under Chapter 11
                  of the United States Bankruptcy Code affecting our settled
                  claims;

         o        regulatory actions and receipt of expected regulatory
                  clearances;

         o        actions by rating agencies;

         o        the ability to control operating costs;

         o        conditions in the capital markets and the ability to access
                  the capital markets; and

         o        acts of nature, sabotage, terrorism or other similar acts
                  causing damage to our facilities.


                                       26
<PAGE>

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 future results.

These and other risks are described in greater detail in the section entitled
"Management's Discussion and Analysis of Financial Condition and Results of
Operations - Risk Factors and Information Regarding Forward-Looking Statements"
included in our annual report on Form 10-K for the year ended December 31, 2004.
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 the securities laws, we undertake no obligation to update
publicly any forward-looking statement whether as a result of new information,
subsequent events or changes in circumstances, changes in expectations or
otherwise.


ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

OVERVIEW

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

INTEREST RATE RISK

Our interest rate exposure is a result of variable rate borrowings. To reduce
our sensitivity to interest rate fluctuations, we may maintain a portion of our
consolidated debt portfolio in fixed-rate debt. We may also use interest rate
swap agreements to manage interest expense by converting a portion of fixed-rate
debt to variable-rate debt. As of June 30, 2005, we had $348 million of
variable-rate debt outstanding, $150 million of which we converted from
fixed-rate to variable-rate debt through interest rate swap agreements.
Approximately 73% of our debt portfolio was fixed-rate debt as of June 30, 2005.

To summarize our sensitivity to interest rate fluctuations, if interest rates on
average change by one percent versus rates that were in effect as of June 30,
2005, consolidated annual interest expense would change by approximately $3.5
million. The impact of the hypothetical interest rates on our variable rate
borrowings outstanding was determined as of the end of the second quarter ended
June 30, 2005.

COMMODITY PRICE RISK

Bear Paw Energy's natural gas gathering and processing contracts are sensitive
to the price of natural gas and natural gas liquids because a significant
portion of its revenue is from the sale of commodities received from POP
agreements. As of June 30, 2005, approximately 67% of our commodity
price-sensitive revenue for the remainder of 2005, based on our projected
throughput volume, was hedged. Considering the effects of hedging, each $0.10
per mmBtu change in natural gas price will have an approximate $0.2 million
impact to revenue, and each $0.01 per gallon change in natural gas liquids price
will have an approximate $0.2 million impact to revenue for 2005. We analyze our
sensitivity based on hypothetical commodity prices on our projected gathering
and processing volumes for the remainder of 2005. This analysis may be impacted
by changes in our projected throughput volumes.

We hedged approximately 23% of our commodity price-sensitive revenue for
2006 as of the end of the second quarter ended June 30, 2005. Considering the
effects of hedging, each $0.10 per mmBtu change in natural gas price will have
an approximate $0.3 million impact to revenue for 2006, and each $0.01 per
gallon change in natural gas liquids price will have an approximate $0.4 million
impact to revenue for 2006.


                                       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 and accounting officer have evaluated the effectiveness of
our disclosure controls and procedures as defined in Rules 13a-15(e) and
15d-15(e) of the Securities Exchange Act of 1934, as amended. Based on their
evaluation, they have concluded that as of June 30, 2005, 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 Securities
Exchange Act of 1934, as amended, is recorded, processed, summarized, and
reported within the time periods specified in the Securities and Exchange
Commission's rules and forms.

CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING

There were no changes in our internal control over financial reporting during
the quarter ended June 30, 2005, that have materially affected, or are
reasonably likely to materially affect, our internal control over financial
reporting.

In March 2004, Enron transferred its ownership interests in Northern Plains and
NBP Services to CrossCountry Energy, LLC. In November 2004, ONEOK purchased
Northern Plains and NBP Services. Transition services agreements were entered
into to provide to Northern Plains and NBP Services on an interim, transitional
basis, various services, including but not limited to (i) information technology
services, (ii) accounting system usage rights and administrative support and
(iii) payroll, employee benefits and administrative services. In turn, these
services are provided to us and our subsidiaries through Northern Plains and NBP
Services. During the second quarter of 2005, the transition of these services to
ONEOK or us was completed and in the review process it was determined that there
were no material changes to our internal controls over financial reporting.


PART II OTHER INFORMATION

ITEM 5. OTHER INFORMATION

On July 1, 2005, ONEOK announced the appointment of Pierce H. Norton as senior
vice president of ONEOK's gathering and processing segment. Mr. Norton remains
president of Bear Paw Energy, a subsidiary of the Partnership and vice president
and general manager for midstream businesses for NBP Services, LLC, having been
appointed to these positions in 2003.


ITEM 6. EXHIBITS

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

<Table>
<S>      <C>
10.1     Revolving Credit Agreement, dated as of May 16, 2005, 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, and
         SunTrust Capital Markets, Inc and Wachovia Capital Markets, LLC, as
         co-lead arrangers and book managers (incorporated by reference to
         Exhibit 10.1 to the Partnership's current report on Form 8-K (File No.
         1-12202) filed on May 20, 2005).

+10.2    First Amendment to Revolving Credit Agreement, effective June 13, 2005,
         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.

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


                                       28
<PAGE>

<Table>
<S>      <C>
+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 and
         Accounting Officer.

+32.1    Section 1350 Certification of Chief Executive Officer.

+32.2    Section 1350 Certification of Chief Financial and Accounting Officer.
</Table>


---------

+Filed herewith


                                       29
<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: August 8, 2005                  By: /s/ Jerry L. Peters
                                          --------------------------------------
                                          Jerry L. Peters
                                          Chief Financial and Accounting Officer


                                       30
<PAGE>


                                  EXHIBIT INDEX

<Table>
<Caption>
Exhibit No.       Description
-----------       -----------
<S>               <C>

 10.1             Revolving Credit Agreement, dated as of May 16, 2005, 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, and SunTrust Capital
                  Markets, Inc and Wachovia Capital Markets, LLC, as co-lead
                  arrangers and book managers (incorporated by reference to
                  Exhibit 10.1 to the Partnership's current report on Form 8-K
                  (File No. 1-12202) filed on May 20, 2005).

+10.2             First Amendment effective June 13, 2005 to Revolving Credit
                  Agreement dated as of May 16, 2005, among Northern Border
                  Partners, L.P., and the lenders named therein,

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

+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 and
                  Accounting Officer.

+32.1             Section 1350 Certification of Chief Executive Officer.

+32.2             Section 1350 Certification of Chief Financial and Accounting
                  Officer.
</Table>

------------------
+ Filed herewith.


                                       31