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

                                   ----------

                                    FORM 10-K

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

For the fiscal year ended December 31, 2004

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

For the transition period from _________ to _________

                         Commission file number: 1-12202

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

<TABLE>
<S>                                                          <C>
          DELAWARE                                                93-1120873
(State or other jurisdiction of                                (I.R.S. Employer
 incorporation or organization)                              Identification No.)
</TABLE>

                  13710 FNB PARKWAY, OMAHA, NEBRASKA 68154-5200
               (Address of principal executive offices) (Zip Code)

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

                                   ----------

           SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:

<TABLE>
<CAPTION>
Title of each class                    Name of each exchange on which registered
-------------------                    -----------------------------------------
<S>                                    <C>
   Common Units                                 New York Stock Exchange
</TABLE>

           SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT:
                                      None

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

     Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [X]
<PAGE>
     Indicate by check mark whether the registrant is an accelerated filer (as
defined in Rule 12b-2 of the Act). Yes [X] No [ ]

     Aggregate market value of the Common Units held by non-affiliates of the
registrant, based on closing prices in the daily composite list for transactions
on the New York Stock Exchange on June 30, 2004, was approximately
$1,832,811,558.

     As of March 3, 2005, 46,397,214 Common Units were outstanding.

                       DOCUMENTS INCORPORATED BY REFERENCE

None.


                                       ii
<PAGE>
                         NORTHERN BORDER PARTNERS, L.P.
                                TABLE OF CONTENTS

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<CAPTION>
                                                                        PAGE NO.
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<S>       <C>                                                           <C>
                                     PART I

Item 1.    Business                                                         1
Item 2.    Properties                                                      20
Item 3.    Legal Proceedings                                               21
Item 4.    Submission of Matters to a Vote of Security Holders             21

                                     PART II

Item 5.    Market for Registrant's Common Equity, Related
              Stockholder Matters and Issuer Purchases of Equity
              Securities                                                   22
Item 6.    Selected Financial Data                                         24
Item 7.    Management's Discussion and Analysis of Financial
              Condition and Results of Operations                          26
Item 7A.   Quantitative and Qualitative Disclosures About Market
              Risk                                                         53
Item 8.    Financial Statements and Supplementary Data                     54
Item 9.    Changes in and Disagreements With Accountants on
              Accounting and Financial Disclosure                          54
Item 9A.   Controls and Procedures                                         57
Item 9B.   Other Information

                                    PART III

Item 10.   Directors and Executive Officers of the Registrant              58
Item 11.   Executive Compensation                                          66
Item 12.   Security Ownership of Certain Beneficial Owners
              and Management and Related Stockholder Matters               73
Item 13.   Certain Relationships and Related Transactions                  74
Item 14.   Principal Accounting Fees and Services                          76

                                     PART IV

Item 15.   Exhibits and Financial Statement Schedules                      78
</TABLE>


                                        i
<PAGE>
                                     PART I

ITEM 1. BUSINESS.

GENERAL

     We are a publicly-traded limited partnership formed in 1993 and a leading
transporter of natural gas imported from Canada to the United States. Our
business operations are comprised of the following segments:

          -    Interstate Natural Gas Pipeline

          -    Natural Gas Gathering and Processing

          -    Coal Slurry Pipeline

     Our interstate natural gas pipelines segment includes companies that
provide natural gas transmission services in the midwestern United States. The
companies in this segment transport gas for shippers under tariffs regulated by
the Federal Energy Regulatory Commission ("FERC"). The interstate pipelines'
revenues are derived from agreements for the receipt and delivery of gas at
points along the pipeline systems as specified in each shipper's individual
transportation contract.

     Our gas gathering and processing segment provides services for the
gathering, treating, processing and compression of natural gas and the
fractionation of natural gas liquids ("NGLs") for third parties. We do not
explore for, or produce, crude oil or natural gas, and do not own crude oil or
natural gas reserves. We have extensive natural gas gathering, processing and
fractionation operations in the Williston Basin in Montana and North Dakota as
well as gas gathering operations in the Powder River Basin and Wind River Basin
in Wyoming. In December 2004, we sold our interest in the Gregg/Lake Obed
Pipeline in Alberta, Canada.

     Our coal slurry pipeline segment is comprised of our ownership of Black
Mesa Pipeline, Inc. The 273-mile pipeline is the only coal slurry pipeline in
operation in the United States. The coal slurry pipeline transports crushed coal
suspended in water from a coal mine in Kayenta, Arizona to the Mohave Generating
Station in Laughlin, Nevada.

     We are managed under the direction of a partnership policy committee
(similar to a board of directors). The partnership policy committee consists of
three members, each of whom has been appointed by one of our general partners.
Our general partners and the general partners of our subsidiary limited
partnership, Northern Border Intermediate Limited Partnership, are Northern
Plains Natural Gas Company, LLC ("Northern Plains") and Pan Border Gas Company,
LLC, ("Pan Border") both subsidiaries of ONEOK, Inc. ("ONEOK"), and Northwest
Border Pipeline Company, a subsidiary of TransCanada PipeLines Limited which is
a subsidiary of TransCanada Corporation, collectively referred to as
"TransCanada". In November 2004, ONEOK purchased Northern Plains, Pan Border and
NBP Services, LLC from CCE Holdings, LLC ("CCE Holdings"). CCE Holdings, a joint
venture between Southern Union Company and GE Commercial Finance Energy
Financial purchased Northern Plains, Pan Border and NBP Services, LLC as part of
its acquisition of CrossCountry Energy, LLC ("CrossCountry"). See Item 7.
"Management's Discussion and Analysis of Financial Condition and Results of
Operations - The Impact Of Enron's Chapter 11 Filing On Our Business."


                                        2
<PAGE>
     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.

     Our general partners hold an aggregate 2% general partner interest in the
Partnership. Northern Plains also owns common units representing a 1.06% limited
partner interest. See Item 12. "Security Ownership of Certain Beneficial Owners
and Management." The combined general and limited partner interests in the
Partnership held by ONEOK and TransCanada are 2.71% and 0.35%, respectively.

     NBP Services, LLC, a ONEOK subsidiary ("NBP Services"), provides
administrative services for us and our subsidiaries and operating services for
our natural gas gathering and processing segment. NBP Services has approximately
130 employees located in Denver, Colorado and at various locations at or near
our gathering and processing facilities and also utilizes employees and
information technology systems of its affiliates to provide these services.
Northern Plains provides operating services to our interstate pipelines pursuant
to operating agreements. Northern Plains employs approximately 310 individuals
located at our headquarters in Omaha, Nebraska, and at various locations near
the pipelines and also utilizes employees and information technology systems of
its affiliates to provide these services. NBP Services' and Northern Plains'
employees are not represented by any labor union and are not covered by any
collective bargaining agreements.

     For financial information about each of our business segments, see Note 16
to Consolidated Financial Statements included elsewhere in this report.

AVAILABLE INFORMATION

     We make available free of charge, through our website,
www.northernborderpartners.com, (a) our annual reports on Form 10-K, quarterly
reports on Form 10-Q, current reports on Form 8-K and amendments to those
reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange
Act as soon as reasonably practicable after we electronically file such material
with, or furnish it to, the Securities and Exchange Commission ("SEC"), (b) our
Governance Guidelines, (c) our Code of Conduct, (d) our Accounting and Financial
Reporting Code of Ethics, (e) our Partnership Agreement and (f) the written
charter of the Audit Committee. The Partnership's documents filed with, or
furnished to, the SEC are also available at the SEC's website at www.sec.gov.
Additionally, you can request a copy of these documents, excluding exhibits, at
no cost, by contacting Investor Relations Department, Northern Border Partners,
L.P., P.O. Box 542500, Omaha, NE 68154-8500.

INTERSTATE NATURAL GAS PIPELINE SEGMENT

     Our interstate natural gas pipeline segment provides natural gas
transmission services in the midwestern United States. Our interstate pipelines
transport gas for shippers under tariffs regulated by the FERC. The tariffs
specify the maximum and minimum transportation rates and the general terms and
conditions of transportation service on the pipeline systems. Our interstate
pipelines' revenues are derived from agreements for the receipt and delivery of
gas at points along the pipeline systems as specified in each shipper's
individual transportation contract. Generally, firm shippers are obligated to
pay a monthly demand charge, regardless of the amount of natural gas they
actually transport, for the term of their contracts. For our wholly-owned
interstate pipelines, approximately 98% of the revenue generated is attributed
to demand charges. The remaining 2% is attributed to commodity charges based on
the volumes of gas actually transported. Our


                                        3
<PAGE>
interstate pipelines do not own the gas that they transport for others and
therefore do not assume natural gas commodity price risk for quantities
transported. Any exposure to commodity risk for imbalances on the pipeline
systems that may result from under or over deliveries to customers or
interconnecting pipelines is either recovered through provisions in the tariffs
or is immaterial. Our interstate pipelines own the line pack, which is the
amount of gas necessary to maintain efficient operations of the pipeline.
Shippers on each system are responsible to provide fuel gas necessary for the
operation of the gas compressor stations on the pipelines. For Northern Border
Pipeline Company and Viking Gas Transmission Company, the fuel gas collected
from shippers is adjusted periodically to track the gas consumed. On Midwestern
Gas Transmission Company, a fixed amount of fuel gas is collected. As a result,
if the amount provided by shippers does not equal the amount consumed in its
operations, Midwestern Gas Transmission is required to buy or sell natural gas.
For 2004, Northern Border Pipeline Company, Midwestern Gas Transmission Company
and Viking Gas Transmission Company accounted for 86%, 6% and 8%, respectively
of the revenues in the interstate pipeline segment. Also reported in this
segment is Guardian Pipeline, L.L.C. ("Guardian Pipeline") for which we own a
one-third interest.

     NORTHERN BORDER PIPELINE SYSTEM

     We own a 70% general partnership interest in Northern Border Pipeline
Company, a Texas general partnership ("Northern Border Pipeline"). Northern
Border Pipeline owns a 1,249-mile interstate pipeline system that transports
natural gas from the Montana-Saskatchewan border near Port of Morgan, Montana to
natural gas markets in the midwestern United States. Construction of the
pipeline was initially completed in 1982. The pipeline system was expanded
and/or extended in 1991, 1992, 1998 and 2001. This pipeline system connects
directly and through multiple pipelines to various natural gas markets in the
United States. For the year ended December 31, 2004, we estimate that Northern
Border Pipeline transported approximately 22% of the total amount of natural gas
imported from Canada to the United States. Over the same period, approximately
88% of the natural gas transported by Northern Border Pipeline was produced in
the western Canadian sedimentary basin located in the provinces of Alberta,
British Columbia and Saskatchewan.

     Our interest in Northern Border Pipeline represents the largest proportion
of our assets, earnings and cash flows. The remaining 30% general partner
interest in Northern Border Pipeline is owned by TC PipeLines Intermediate
Limited Partnership, a subsidiary limited partnership of TC PipeLines, LP, a
publicly-traded partnership ("TC PipeLines"). The general partner of TC
PipeLines and its subsidiary limited partnership is TC PipeLines GP, Inc., which
is a subsidiary of TransCanada.

     Management of Northern Border Pipeline is overseen by the Northern Border
Management Committee, which is comprised of three representatives from the
Partnership (one designated by each of our general partners) and one
representative from TC PipeLines. Voting power on the management committee is
allocated among Northern Border Partners' three representatives in proportion to
their general partner interests in Northern Border Partners. As a result, the
70% voting power of our three representatives on the management committee is
allocated as follows: 35% to the representative designated by Northern Plains,
22.75% to the representative designated by Pan Border and 12.25% to the
representative designated by Northwest Border. Therefore, ONEOK controls 57.75%
of the voting power of the management committee and has the right to select two
of its members. For a discussion of specific relationships with affiliates,
refer to Item 13. "Certain Relationships and Related Transactions."


                                        4
<PAGE>
     The Northern Border Pipeline system consists of: (i) 822 miles of 42-inch
diameter pipe from the Canadian border to Ventura, Iowa, capable of transporting
on a summer design basis a total of 2,374 million cubic feet per day ("mmcfd");
(ii) 30-inch diameter pipe and 36-inch diameter pipe, each approximately 147
miles in length, capable of transporting 1,484 mmcfd in total from Ventura, Iowa
to Harper, Iowa; (iii) 224 miles of 36-inch diameter pipe and 21 miles of
30-inch diameter pipe capable of transporting 844 mmcfd from Harper, Iowa to
Manhattan, Illinois (Chicago area); and (iv) 35 miles of 30-inch diameter pipe
capable of transporting 544 mmcfd from Manhattan, Illinois to a terminus near
North Hayden, Indiana. A summer design basis pipeline is capable of
transporting, at a minimum, the stated capacity at all times of the year. Along
the pipeline there are 16 compressor stations with total rated horsepower of
499,000 and measurement facilities to support the receipt and delivery of gas at
various points. Other facilities include four field offices and a microwave
communication system with 50 tower sites.

     The pipeline system has pipeline access to natural gas reserves in the
western Canadian sedimentary basin in the provinces of Alberta, British Columbia
and Saskatchewan in Canada, domestic natural gas produced within the Williston
Basin and the Powder River Basin, and synthetic gas produced at the Dakota
Gasification plant in North Dakota. In addition, the pipeline is capable of
physically receiving natural gas at two locations near Chicago. For the year
ended December 31, 2004, of the natural gas transported on the pipeline system,
approximately 88% was produced in Canada, approximately 4% was produced by the
Dakota Gasification plant, and approximately 8% was produced in the Williston
Basin.

     To access markets, the pipeline system interconnects with pipeline
facilities of various interstate and intrastate pipeline companies and local
distribution companies, as well as with end-users. The larger interconnections
are:

     -    Northern Natural Gas Company at Ventura, Iowa as well as multiple
          smaller interconnections in South Dakota, Minnesota and Iowa;

     -    Natural Gas Pipeline Company of America at Harper, Iowa;

     -    MidAmerican Energy Company at Iowa City and Davenport, Iowa and
          Cordova, Illinois;

     -    Alliant Power Company at Prophetstown, Illinois;

     -    Northern Illinois Gas Company at Troy Grove and Minooka, Illinois;

     -    Midwestern Gas Transmission near Channahon, Illinois;

     -    ANR Pipeline Company near Manhattan, Illinois;

     -    Vector Pipeline L.P. in Will County, Illinois;

     -    Guardian Pipeline in Will County, Illinois;

     -    The Peoples Gas Light and Coke Company near Manhattan, Illinois; and

     -    Northern Indiana Public Service Company near North Hayden, Indiana at
          the terminus of the pipeline system.


                                        5
<PAGE>
     Several market centers, where natural gas transported on the pipeline
system is sold, traded and received for transport to consuming markets in the
Midwest and to interconnecting pipeline facilities, have developed on the
pipeline system. The largest of these market centers is at Northern Border
Pipeline's Ventura, Iowa interconnection with Northern Natural Gas Company. Two
other market center locations are the Harper, Iowa connection with Natural Gas
Pipeline Company of America and the multiple interconnects in the Chicago area
that include connections with Northern Illinois Gas Company, The Peoples Gas
Light and Coke Company and Northern Indiana Public Service Company, as well as
four interstate pipelines.

     All of Northern Border Pipeline's summer design capacity was under contract
as of December 31, 2004 and, assuming no extensions of existing contracts or
execution of new contracts, approximately 61% and 51% of summer design capacity
is under contract as of December 31, 2005 and 2006, respectively. The pipeline
system serves approximately 40 firm transportation shippers with diverse
operating and financial profiles. Based upon shippers' contractual obligations,
as of December 31, 2004, 92% of firm capacity contracted is with producers and
marketers. The remaining firm capacity contracted primarily is with local
distribution companies (7%) and end-users (1%). As of December 31, 2004, the
termination dates of these contracts ranged from December 31, 2004 to December
21, 2013, and the weighted average contract life was approximately two and
three-quarters years based upon contractual obligations and summer design
capacity. See Item 7. "Management's Discussion and Analysis of Financial
Condition and Results of Operations - Overview - Interstate Natural Gas Pipeline
Segment - Northern Border Pipeline Recontracting" for information regarding
Northern Border Pipeline's recontracting.

     Northern Border Pipeline's shippers may change throughout the year as a
result of its shippers utilizing capacity release provisions that allow them to
release all or part of their capacity, either permanently for the full term of
their contract or temporarily. Under the terms of Northern Border Pipeline's
tariff, a temporary capacity release does not relieve the originally contracted
shipper from its payment obligations if the new shipper fails to pay.

     At December 31, 2004, Nexen Marketing U.S.A. Inc., BP Canada Energy
Marketing Corp. ("BP Canada"), EnCana Marketing U.S.A. Inc. and Cargill
Incorporated were obligated for approximately 18%, 14%, 13% and 12%,
respectively, of the summer design capacity. Contracts for approximately 63% of
the capacity contracted by these shippers are due to expire by November 1, 2005.
See Item 7. "Management's Discussion and Analysis of Financial Condition and
Results of Operations - Overview."

     One of Northern Border Pipeline's shippers, ONEOK Energy Services Company,
LP,("ONEOK Energy") a subsidiary of ONEOK, is affiliated with us. ONEOK Energy
holds firm contracts representing 3% of summer design capacity. ONEOK Energy has
also committed to be a shipper on the Chicago III Expansion project. See Item
13. "Certain Relationships and Related Transactions."

     MIDWESTERN GAS TRANSMISSION SYSTEM

     Midwestern Gas Transmission Company, our wholly-owned subsidiary
("Midwestern Gas Transmission"), owns a 350-mile pipeline system extending from
an interconnection with Tennessee Gas Transmission near Portland, Tennessee to a
point of interconnection with several interstate pipeline systems near Joliet,
Illinois. Midwestern Gas Transmission serves markets in Chicago, Illinois,
Kentucky, southern Illinois and Indiana.


                                        6
<PAGE>
     The Midwestern Gas Transmission system consists of 350 miles of 30-inch and
24-inch diameter pipe with a capacity of 650 mmcfd for volumes transported from
Portland, Tennessee to the north. There are seven compressor stations with total
rated horsepower of 65,570. The Midwestern Gas Transmission system is also
capable of moving approximately 387 mmcfd southbound depending upon receipt and
delivery point locations.

     The Midwestern Gas Transmission system connects with multiple pipeline
systems that provide its shippers access to various supply sources and markets.
Because of its position in the natural gas pipeline grid, Midwestern Gas
Transmission is designed to receive gas volumes at both ends of its system. On
the north end, Midwestern Gas Transmission can physically receive gas from ANR
Pipeline Company, Northern Border Pipeline, Natural Gas Pipeline Company of
America, Alliance Pipeline, The Peoples Gas Light and Coke Company and Trunkline
Gas Company. The significant receipt point on the southern end of the system is
the interconnection with Tennessee Gas Transmission at Portland. Additionally,
Midwestern Gas Transmission is capable of receiving gas at five other
interconnections along its pipeline system. With respect to market access,
Midwestern Gas Transmission is capable of delivering natural gas at points of
interconnection with the interstate pipeline systems of ANR Pipeline Company,
Guardian Pipeline, Natural Gas Pipeline Company of America, Northern Border
Pipeline, Texas Eastern Transmission Company and Texas Gas Transmission Company.
There are interconnections with local distribution companies such as Northern
Illinois Gas Company, The Peoples Gas Light and Coke Company, Illinois Power,
and Vectren Energy Delivery. In addition, a number of end-users and electric
power generation facilities can be served by connections off the pipeline
system.

     The Midwestern Gas Transmission system serves approximately 25 firm
transportation shippers. Based upon shipper firm contractual obligations as of
December 31, 2004, approximately 68% of the contracted capacity is with local
distribution companies, 30% with marketers and 2% with end-users.

     As of December 31, 2004, Midwestern Gas Transmission's three largest
shippers were Northern Illinois Gas Company, ProLiance Energy LLC and The
Peoples Gas Light and Coke Company who were obligated for approximately 32%, 16%
and 14%, respectively, of the system design capacity.

     As of December 31, 2004, the termination dates of Midwestern Gas
Transmission's firm transportation contracts ranged from December 31, 2004 to
October 31, 2019. On December 31, 2004, approximately 91% of the northbound
system design capacity and approximately 90% of southbound system design
capacity was contracted on a firm basis and assuming no extensions of existing
contracts or executions of new contracts approximately 75% and 20% of northbound
design capacity and 48% and 11% of southbound design capacity is under contract
as of December 31, 2005 and 2006, respectively. See Item 7. "Management's
Discussion and Analysis of Financial Condition and Results of Operations -
Overview."

     VIKING GAS TRANSMISSION SYSTEM

     Our wholly-owned subsidiary, Viking Gas Transmission Company ("Viking Gas
Transmission"), owns a pipeline system that extends from an interconnection with
TransCanada near Emerson, Manitoba to an interconnection with ANR Pipeline
Company near Marshfield, Wisconsin. Viking Gas Transmission's source of gas
supply is the western Canadian sedimentary basin. Viking Gas Transmission also
has interconnections with Northern Natural Gas Company and Great Lakes Gas
Transmission to serve markets in Minnesota, Wisconsin and North Dakota.


                                        7
<PAGE>
     The Viking Gas Transmission system consists of: (i) 499 miles of 24-inch
diameter mainline pipe with a summer design capacity of approximately 500 mmcfd
at the origin near Emerson, Manitoba and 300 mmcfd at the terminus near
Marshfield, Wisconsin, (ii) 95 miles of 24-inch mainline looping; and (iii) 79
miles of smaller diameter laterals. There are eight compressor stations with
total horsepower of 68,650.

     The Viking Gas Transmission system serves approximately 35 firm
transportation shippers. Based upon shipper contractual obligations as of
December 31, 2004, approximately 80% of the contracted firm capacity is with
local distribution companies, 15% with marketers and 5% with end-users. As of
December 31, 2004, Viking Gas Transmission's largest customers were Wisconsin
Gas, LLC, CenterPoint Energy Minnegasco, Northern States Power
Company-Minnesota, Michigan Consolidated Gas Company and Wisconsin Public
Service Corporation, who were obligated for approximately 19%, 15%, 15%, 10% and
10%, respectively, of the summer design capacity.

     As of December 31, 2004, the termination dates of Viking Gas Transmission's
firm transportation contracts ranged from March 31, 2005 to October 31, 2014. On
December 31, 2004, all of the summer design capacity at the origin of the
pipeline near Emerson was contracted on a firm basis and assuming no extensions
of existing contracts or execution of new contracts, approximately 85% and 83%
of summer design capacity is under contract as of December 31, 2005 and 2006,
respectively.

     GUARDIAN PIPELINE SYSTEM

     Viking Gas Transmission owns a 33-1/3% interest in Guardian Pipeline, which
is a 141-mile interstate natural gas pipeline that was placed into service in
December 2002. This system transports natural gas from Joliet, Illinois to a
point west of Milwaukee, Wisconsin. Subsidiaries of Wisconsin Public Service and
Wisconsin Energy Corporation hold the remaining interests in this system.
Wisconsin Gas Company, a subsidiary of Wisconsin Energy Corporation, has
contracted for 87% of the pipeline's 750 mmcfd capacity. Guardian Pipeline is
currently operated by Northern Plains under an operating agreement that was
effective July 1, 2004. Prior to that date, Trunkline Gas Company, which is part
of Southern Union Company, was the operator. See Item 13. "Certain Relationships
and Related Transactions."

     DEMAND FOR INTERSTATE PIPELINE TRANSPORTATION CAPACITY

     Recent developments have resulted in proposed expansions of our pipeline
systems. In September 2004, Northern Border Pipeline announced it had received
commitments from shippers sufficient to support a proposed expansion of the
pipeline system into the Chicago market area. The "Chicago III Expansion"
project, with an estimated 130 mmcfd of capacity, would involve construction of
a new compressor station and minor modifications to two other compressor
stations, and is estimated to cost approximately $21 million. The projected
in-service date is April 1, 2006. FERC approval of this project is required and
Northern Border Pipeline expects to file the required certificate application in
March 2005.

     Also, in August 2004, we announced that Midwestern Gas Transmission had
finalized the necessary contractual commitment to proceed with its Eastern
Extension Project. This project involves the construction of approximately 30
miles of 16-inch diameter pipeline, with a capacity of approximately 120 mmcfd,
from Portland, Tennessee to planned interconnections with Columbia Gulf
Transmission Company and East Tennessee Pipeline Company. The project is
supported by a


                                        8
<PAGE>
precedent agreement with Piedmont Natural Gas Company, a local distribution
company, for approximately 120 mmcfd for a term of 15 years. Pending the receipt
of regulatory and other required approvals, the proposed in-service date for the
project is November 2006 and project costs are estimated at approximately $22
million to $25 million.

     The long-term financial condition of our interstate natural gas pipeline
segment is dependent on the continued availability of economic natural gas
supplies, including western Canadian natural gas for import into the United
States. Natural gas reserves may require significant capital expenditures by
others for exploration and development drilling and the installation of
production, gathering, storage, transportation and other facilities that permit
natural gas to be produced and delivered to pipelines that interconnect with our
interstate pipelines' systems. Prices for natural gas, the currency exchange
rate between Canada and the United States, regulatory limitations or the lack of
available capital for these projects could adversely affect the development of
additional reserves and production, gathering, storage and pipeline transmission
of natural gas supplies. Increased Canadian consumption related to the
extraction process for oil sands projects as well as restrictions on gas
production to protect oil sand reserves could also impact supplies of natural
gas for export. Additional pipeline capacity from producing basins also could
accelerate depletion of these reserves. Excess pipeline capacity could also
affect the demand or value of the transport on our interstate pipelines.

     Each of our interstate pipelines' business also depends on the level of
demand for natural gas in the markets the pipeline system serves. The volumes of
natural gas delivered to these markets from other sources affect the demand for
both the natural gas supplies and the use of the pipeline systems. Demand for
natural gas to serve other markets also influences the ability and willingness
of shippers to use our pipeline systems to meet demand in the markets that our
interstate pipelines serve.

     A variety of factors could affect the demand for natural gas in the markets
that our pipeline systems serve. These factors include:

     -    economic conditions;

     -    fuel conservation measures;

     -    alternative energy sources' requirements and prices;

     -    gas storage inventory levels;

     -    climatic conditions;

     -    government regulation; and

     -    technological advances in fuel economy and energy generation devices.

     Our interstate pipelines' primary exposure to market risk occurs at the
time existing transportation contracts expire and are subject to renegotiation.
A key determinant of capacity value for shippers that have competitive pipeline
alternatives is the basis differential or market price spread between two points
on the pipeline. The difference in natural gas prices between the points along
the pipeline where gas enters and where gas is delivered represents the gross
margin that a shipper can expect to achieve from holding transportation capacity
at any


                                       9
<PAGE>
point in time. This margin and its variability become important factors in
determining the rate customers are willing to pay when they renegotiate their
transportation contracts. The basis differential between markets can be affected
by trends in production, available pipeline capacity, storage inventories,
weather and general market demand in the respective areas.

     Throughput on our interstate pipelines may experience seasonal fluctuations
depending upon the level of winter heating load demand, summer electric
generation usage in the markets served by the pipeline systems and/or storage
injection load. To the extent that capacity is contracted at maximum rates under
firm transportation agreements, 98% of the expected charges are from demand
charges that are not impacted materially by such seasonal throughput variations.
However, as contracts terminate, renewals and replacements may be affected by
seasonal fluctuations and historic usage patterns. See Item 7. "Management's
Discussion and Analysis of Financial Condition and Results of Operations -
Overview."

     We cannot predict whether these or other factors will have an adverse
affect on demand for use of our interstate pipelines' systems or how significant
that adverse affect could be.

     INTERSTATE PIPELINE COMPETITION

     Northern Border Pipeline and Viking Gas Transmission compete with other
pipeline companies that transport natural gas from the western Canadian
sedimentary basin or that transport natural gas to end-use markets in the
midwestern United States. Their competitive positions are affected by the
availability of Canadian natural gas for export, the availability of other
sources of natural gas and demand for natural gas in the United States. Demand
for transportation services on the systems is affected by natural gas prices,
the relationship between export capacity and production in the western Canadian
sedimentary basin, and natural gas shipped from producing areas in the United
States. Shippers of natural gas produced in the western Canadian sedimentary
basin also have other options to transport Canadian natural gas to the United
States, including transportation on the Alliance Pipeline to the Chicago market
area, on TransCanada's pipeline system through various interconnections with
U.S. interstate pipelines in the upper Midwest and northeast markets and on the
Westcoast Pipeline and TransCanada B.C. systems and through various
interconnections with U.S. interstate pipelines serving northwest and west coast
markets. In the near term, Northern Border Pipeline's short-term contracted
capacity competes primarily with available and short-term capacity on the
TransCanada and Westcoast pipelines. Alliance Pipeline is not a competitor in
the short-term for Northern Border Pipeline, since substantially all of its
capacity is contracted under long-term contracts.

     In addition, Northern Border Pipeline competes in its markets with other
interstate pipelines that provide access to other supply basins. Northern Border
Pipeline's major deliveries into Northern Natural Gas at Ventura, Iowa compete
with gas supplied from the Rockies and mid-continent regions. Northern Border
Pipeline also competes with these supply basins at its delivery interconnect
with Natural Gas Pipeline of America at Harper, Iowa. In the Chicago area,
Northern Border Pipeline competes with many interstate pipelines that transport
gas from the Gulf Coast, mid-continent, Rockies and western Canada. In December
2004, the Cheyenne Plains Pipeline system commenced service from the Cheyenne
Hub in the Rocky Mountain area to the mid-continent area. The pipeline will
provide additional supply and transportation competition in markets served by
Northern Border Pipeline. The supply balance in the mid-continent area can
impact the value of gas that is traded at Ventura, Iowa and Harper, Iowa
delivery points and gas traded in


                                       10
<PAGE>
the Chicago area. A change in trading value at these market centers will affect
the corresponding transportation value of that portion of Northern Border
Pipeline's system upstream and downstream of these trading centers.

     Midwestern Gas Transmission can receive and deliver gas at either end of
its system, which makes it a header pipeline system. Consequently, Midwestern
Gas Transmission faces competition from multiple supply sources and interstate
pipelines. In the Chicago market, Midwestern Gas Transmission's competition is
from pipelines transporting gas from the gulf coast and mid-continent regions
and gas sourced from Canada. In the Indiana and Western Kentucky markets,
Midwestern Gas Transmission's competition is from pipelines transporting gas
from the gulf coast and mid-continent regions.

     Viking Gas Transmission directly serves markets in North Dakota, Minnesota
and Wisconsin. Northern Natural Gas competes with Viking Gas Transmission in
these states. In addition, Viking Gas Transmission indirectly serves Wisconsin
and Michigan markets through deliveries into ANR Pipeline. The deliveries into
ANR Pipeline compete with other supply sources on ANR Pipeline, which includes
supply from the gulf coast and mid-continent regions and the Chicago market
center.

     In October 2004, FERC approved ANR Pipeline Company's application to expand
its capacity in the north leg of its pipeline system by approximately 107 mmcfd
per day to replace receipts from Viking Gas Transmission at the Marshfield,
Wisconsin interconnection by November 2005. See Item 7. "Management's Discussion
and Analysis of Financial Condition and Results of Operations - Overview."

     INTERSTATE PIPELINE REGULATION

     Our interstate pipelines are subject to extensive regulation by the FERC,
each as a "natural gas company" under the Natural Gas Act. Under the Natural Gas
Act and the Natural Gas Policy Act, the FERC has jurisdiction with respect to
virtually all aspects of this business segment, including:

     -    transportation of natural gas;

     -    rates and charges;

     -    terms of service including creditworthiness requirements;

     -    construction of new facilities;

     -    extension or abandonment of service and facilities;

     -    accounts and records;

     -    depreciation and amortization policies;

     -    the acquisition and disposition of facilities; and

     -    the initiation and discontinuation of services.

     Where required, our interstate pipelines hold certificates of public
convenience and necessity issued by the FERC covering the facilities, activities
and services. Under Section 8 of the Natural Gas Act, the FERC has the power to
prescribe the accounting treatment for items for regulatory purposes. Our
interstate pipelines' books and records may be periodically audited by the FERC
under Section 8.


                                       11
<PAGE>
     The FERC regulates the rates and charges for transportation in interstate
commerce. Natural gas companies may not charge rates that have been determined
not to be just and reasonable by the FERC. Generally, rates for interstate
pipelines are based on the cost of service including recovery of and a return on
the pipeline's actual prudent historical cost investment. In addition, the FERC
prohibits natural gas companies from unduly preferring or unreasonably
discriminating against any person with respect to pipeline rates or terms and
conditions of service. Some types of rates may be discounted without further
FERC authorization and rates may be negotiated subject to FERC approval. The
rates and terms and conditions for service are found in each pipeline's FERC
approved tariff.

     Under its tariff, an interstate pipeline is allowed to charge for its
services on the basis of stated transportation rates. Transportation rates are
established in FERC proceedings known as rate cases. The tariff also allows the
interstate pipeline to provide services under negotiated and discounted rates.
Generally, firm shippers are obligated to pay a monthly demand charge,
regardless of the amount of natural gas they actually transport, for the term of
their contracts. For our wholly-owned interstate pipelines, approximately 98% of
the revenue generated for a contract is attributed to demand charges. The
remaining 2% is attributed to commodity charges based on the volumes of gas
actually transported.

     Our interstate pipelines also provide interruptible transportation service.
Interruptible transportation service is transportation in circumstances when
capacity is available after satisfying firm service requests. The maximum rate
that may be charged to interruptible shippers is the sum of the firm
transportation maximum demand and commodity charges.

     Under the terms of settlement in Northern Border Pipeline's 1999 rate case,
neither Northern Border Pipeline nor its existing shippers can seek rate changes
to the settlement base rates until November 1, 2005, at which time Northern
Border Pipeline must file a new rate case. Midwestern Gas Transmission and
Viking Gas Transmission have no timing requirements or restriction in regard to
future rate case filings. Under the terms of Guardian Pipeline's certificate of
public convenience and necessity allowing for the construction of the Guardian
pipeline system, Guardian Pipeline must file a revenue and cost study by
December 7, 2005 to re-establish the recourse rates initially approved by the
FERC. Prior to a future rate case, the interstate pipelines will not be
permitted to increase rates if costs increase or if contract demand decreases,
nor will they be required to reduce rates based on cost savings. As a result,
the interstate pipelines' earnings and cash flow will depend on costs incurred,
contracted capacity, the volumes of gas transported and their ability to
recontract capacity at acceptable rates.

     Until new depreciation rates are approved by the FERC, the interstate
pipeline continues to depreciate its transmission plant at FERC approved
depreciation rates. For our pipelines, the annual depreciation rates on
transmission plant in service are 2.25% for Northern Border Pipeline, 1.9% for
Midwestern Gas Transmission, 2.0% for Viking Gas Transmission and 3.3% for
Guardian Pipeline. The effects of accumulated depreciation may be offset by
acquiring or constructing assets that replace or add to existing pipeline
facilities or transportation rates may be decreased.

     In Northern Border Pipeline's 1995 rate case, the FERC addressed the issue
of whether the federal income tax allowance included in Northern Border
Pipeline's proposed cost of service was reasonable in light of previous FERC
rulings. In those previous rulings, the FERC held that an interstate pipeline is
not entitled


                                       12
<PAGE>
to an income tax allowance for income attributable to limited partnership
interests held by individuals. The settlement of Northern Border Pipeline's 1995
rate case provided that Northern Border Pipeline could continue to calculate the
allowance for income taxes in the manner it had historically used for a period
which ends in December 2005. In addition, a settlement adjustment mechanism was
implemented, which effectively reduces the return on rate base. These provisions
of the 1995 rate case were maintained in the settlement of Northern Border
Pipeline's 1999 rate case.

     On July 20, 2004, the D.C. Circuit Court of Appeals issued an opinion in BP
West Coast Products, LLC v. FERC ("SFPP, L.P. Proceeding") that reversed the
FERC decision that provided for an income tax allowance in the rates for SFPP,
LP, a limited partnership. The D.C. Circuit Court remanded the case to the FERC
for its determination regarding the proper income tax allowance. On December 2,
2004, the FERC initiated an inquiry open to all interested parties on whether
the court's ruling applies only to the specific facts of the SFPP, L.P.
Proceeding or if it extends to other capital structures involving partnerships
and other forms of ownership. The inquiry did not propose a particular rule. The
FERC inquired how the decision in the SFPP, L.P. Proceeding may impact
investment in energy infrastructure and if there are other methods in providing
an opportunity to earn an adequate return that are not dependent on the tax
implications of a particular capital structure.

     Approximately 50 separate comments were filed by trade associations,
investor groups, producers, natural gas pipelines, electric utilities, oil
pipelines, and customers in January 2005. A number of comments, including
Northern Border Pipeline's, suggested that an income tax allowance is a proper
element of a pipeline's cost of service for all jurisdictional entities
regardless of legal structure. Some producers' and customers' comments argued
against the inclusion of an income tax allowance for partnerships and other
non-tax paying entities. It is not certain how, or when, the FERC may proceed
with respect to its Request for Comments or the affect on our interstate natural
gas pipelines, which are not corporations. In particular, Northern Border
Pipeline is a general partnership whose rates include an allowance for income
taxes. Northern Border Pipeline's specific circumstances regarding its tariff,
deferred income tax treatment, FERC orders, past history and underlying
agreements with shippers are different from those of SFPP, L.P. The issue of
whether the inclusion of an income tax allowance in Northern Border Pipeline's
rates is applicable, in light of the FERC and court rulings, may be addressed in
Northern Border Pipeline's 2005 rate case.

     Our interstate pipelines are subject to the requirements of FERC Order Nos.
497 and 566, which prohibit preferential treatment of transportation service
providers' marketing affiliates and govern how information may be provided to
those marketing affiliates. On November 25, 2003, the FERC issued a final rule,
Order No. 2004, adopting new standards of conduct for transmission providers
when dealing with their energy affiliates. Additional orders modifying Order No.
2004 were issued on April 16, August 2 and December 21, 2004. Transmission
providers were required to comply with the standards of conduct by September 22,
2004. The standards of conduct are designed to prevent transmission providers
from giving undue preferences to any of their energy affiliates. The final rule
generally requires that transmission function employees operate independently of
the marketing function employees and energy affiliates. As required of all
transmission providers, each of our interstate pipelines posted its standards of
conduct to its website on September 22, 2004. By definition, Bear Paw Energy,
LLC and ONEOK Energy Services Company, L.P, as well as other subsidiaries of
ONEOK, are energy affiliates. Prior to September 22, 2004, the operator of our
interstate pipelines, Northern Plains, provided after hours and weekend gas
control services


                                       13
<PAGE>
for Bear Paw Energy, LLC and Crestone Energy Ventures that resulted in some cost
savings to our interstate pipelines. Our interstate pipelines have requested a
waiver, which is still pending at the FERC, to permit Northern Plains to resume
after hours and weekend gas control services for Bear Paw Energy, LLC and
Crestone Energy Ventures.

     On July 17, 2002, the FERC issued a Notice of Inquiry Concerning Natural
Gas Pipeline Negotiated Rate Policies and Practices. Subsequently, the FERC
issued an order on July 25, 2003, modifying its prior policy on negotiated
rates. The FERC ruled that it would no longer permit the pricing of negotiated
rates based upon natural gas commodity price indices. Negotiated rates based
upon such indices may continue until the end of the contract period for which
such rates were negotiated, but such rates will not be prospectively approved by
the FERC. The FERC also imposed certain requirements on other types of
negotiated rate transactions to ensure that the agreements embodying such
transactions do not materially differ from the terms and conditions set forth in
the tariff of the pipeline entering into the transaction. This FERC ruling is
not expected to have a material effect on our businesses.

     Recent FERC orders in proceedings involving other natural gas pipelines
have addressed certain aspects of a pipeline's creditworthiness provisions set
forth in its tariff. In addition, industry groups, such as the North American
Energy Standards Board ("NAESB"), have issued creditworthiness standards. On
February 12, 2004, the FERC issued a Notice of Proposed Rulemaking to require
interstate pipelines to follow standardized procedures for determining the
creditworthiness of their shippers. The proposed rule would incorporate by
reference ten consensus standards passed within NAESB and would adopt additional
standards requiring, among other things, standardization of information shippers
provide to establish credit, collateral requirements for service, procedures for
suspension and termination for non-creditworthy shippers and procedures
governing capacity release transactions. The enactment of some of these
standards may have the effect of easing certain creditworthiness requirements
and parameters currently reflected in our tariffs on existing transportation
capacity. However, recent FERC orders, and this proposed rule, continue to allow
more stringent collateral requirements for the construction of new facilities by
a pipeline. However, we cannot predict the ultimate impact, if any, on our
interstate pipelines of any resulting final rule.

     In February 2004, the FERC adopted new quarterly financial reporting
requirements and accelerated the filing date for the interstate pipeline's
annual financial report. The quarterly reports include a basic set of financial
statements and other selected data and are submitted electronically. There is no
impact for complying with these requirements other than the time and additional
expense for preparation of these reports.

     In November 2004, the FERC issued a Notice of Proposed Accounting Release
("PAR") to provide guidance on the accounting for costs of pipeline assessment
programs required under the Pipeline Safety Improvement Act of 2002 and
regulations established thereunder. The PAR concluded that such costs should be
treated as maintenance costs. Comments have been filed by the Interstate Natural
Gas Association of America as well as individual pipelines setting forth the
arguments that these costs should be capitalized.

     In November 2004, the FERC issued a Notice of Inquiry on selective
discounting particularly as it relates to allowing discount adjustments for
contracts resulting from competition between interstate pipelines referred to as
gas-on-gas competition. The FERC noted that in several proceedings, parties have
objected to the FERC's current discounting policy, allowing selective
discounting


                                       14
<PAGE>
for gas-on-gas competition, on the grounds that it no longer benefits captive
customers by allowing fixed costs to be spread over more units of service. These
parties have argued that while benefits may still exist to the extent a discount
is given to a customer who would otherwise use an alternative fuel and not ship
gas at all, benefits do not exist in situations where discounts are given to
meet competition from other gas pipelines. Although the FERC has not disallowed
discount adjustments for gas-on-gas competition, the Notice of Inquiry seeks
comments and responses to a series of questions that will allow the FERC to
explore the potential impact of eliminating the discount adjustment for
gas-on-gas competition and how the FERC should implement and monitor such a
policy.

     In August 2003, Northern Border Pipeline filed revised tariff sheets to
clarify its procedures for the awarding of capacity. Several parties protested
the filing. One party requested a show cause proceeding to examine past tariff
practices alleging that Northern Border Pipeline violated its tariff by denying
a request for service that would have involved transportation for a distance
shorter than the available distance for less than a one-year term. Northern
Border Pipeline's position is that selling capacity for shorter distances or on
a shorter term basis may cause portions of its system to be "stranded" or not
subject to firm transportation contracts on a consistent basis or may
effectively constitute a discounted rate service. On September 10, 2003, the
FERC rejected Northern Border Pipeline's tariff sheets based on the conclusion
that certain aspects of the proposal were not in accordance with the FERC's
policy. The FERC affirmed that, up to ninety days prior to the effective date,
Northern Border Pipeline had the right not to sell capacity requested for
shorter distances or on a short-term basis to shippers offering the maximum
mileage-based transportation rate. Northern Border Pipeline filed a timely
request for rehearing of the FERC's Order in October 2003, which is still
pending. Northern Border Pipeline also filed responses to requests for further
information on the award of capacity in the summer of 2003. Northern Border
Pipeline filed its compliance tariff sheets in early December 2003 and is
awaiting the FERC's decision on these tariff sheets. An order was issued on
April 15, 2004, in which the FERC requested comments from interested parties on
whether the FERC's current policy on awarding available capacity to a short-haul
shipper appropriately balances the risks to the pipeline, prospective shippers
and current shippers on the pipeline. Comments from Northern Border Pipeline and
other interested parties were filed on June 15, 2004. The timing of the issuance
of the FERC's order in this proceeding is not known.

NATURAL GAS GATHERING AND PROCESSING SEGMENT

     Our gas gathering and processing segment provides services for the
measurement, gathering, treating, compression and processing of natural gas and
the fractionation of natural gas liquids (NGLs) for third parties and related
field services. We do not explore for, or produce, crude oil or natural gas, and
do not own crude oil or natural gas reserves.

     Bear Paw Energy, LLC ("Bear Paw Energy"), our wholly-owned subsidiary, has
extensive natural gas gathering, processing and fractionation operations in the
Williston Basin in Montana and North Dakota as well as gas gathering operations
in the Powder River Basin in Wyoming. In the Williston Basin, Bear Paw Energy
has over 3,000 miles of gathering pipelines and five processing plants with 93
mmcfd of capacity. In the Powder River Basin, Bear Paw Energy has approximately
600 miles of high and low pressure gathering pipelines, approximately 65
compressor stations with approximately 140,000 installed horsepower and
long-term volumetric contracts with producers covering approximately 390,000
acres of dedicated reserves in the


                                       15
<PAGE>
Powder River Basin. Bear Paw Energy's revenues are primarily derived under
fee-based gathering and percentage of proceeds agreements.

     In addition, through our wholly-owned subsidiary, Crestone Energy Ventures,
we own a 49% interest in Bighorn Gas Gathering, L.L.C. ("Bighorn"), a 33.33%
interest in Fort Union Gas Gathering, L.L.C. ("Fort Union") and a 35% interest
in Lost Creek Gathering, L.L.C. ("Lost Creek"), which collectively own over 300
miles of gas gathering facilities in the Powder River and Wind River Basins in
Wyoming.

     The Bighorn and Fort Union systems gather coalbed methane gas produced in
the Powder River Basin in northeastern Wyoming. Under various agreements, the
majority of which are long-term, producers have dedicated their gas reserves to
Bighorn, giving Bighorn the right to gather natural gas produced in areas of
Wyoming covering approximately 800,000 acres. Bighorn's system is capable of
gathering more than 250 mmcfd of natural gas for delivery to the Fort Union
gathering system. Fort Union has the capability of delivering more than 634
mmcfd of gas into the interstate pipeline grid. The Lost Creek system gathers
natural gas produced from conventional gas wells in the Wind River Basin in
central Wyoming and consists of 120 miles of gathering header. The system is
capable of delivering more than 275 mmcfd of gas into the interstate pipeline
grid.

     Cantera Natural Gas, LLC (formerly CMS Field Services, Inc.)("Cantera
Natural Gas") holds the remaining ownership interest in Bighorn and is the
project manager and operator. The Bighorn system is managed through a management
committee consisting of representatives of the owners. Cantera Natural Gas, CIG
Resources Company, Western Gas Resources and Bargath, Inc. hold the remaining
interests in Fort Union. Cantera Natural Gas is the managing member, Western Gas
Resources is the field operator and CIG Resources Company is the administrative
manager. Burlington Resources Trading, Inc. holds the remaining interest in Lost
Creek and is the managing member. A subsidiary of Crestone Energy Ventures is
the commercial and administrative manager. This system is operated by Elkhorn
Field Services Company, an unaffiliated third party.

     Bear Paw Energy's facilities in the Powder River Basin are interconnected
with the facilities of Bighorn, Fort Union, Thunder Creek Gas Gathering and
Maverick Pipeline, LLC, and all the gathering facilities interconnect to the
interstate gas pipeline grid serving gas markets in the Rocky Mountains, the
Midwest and California.

     Bear Paw Energy's Williston Basin gathering and processing facilities are
located in eastern Montana and western North Dakota, with a small extension into
Saskatchewan, Canada. The Williston Basin system consists of approximately 3,100
miles of polyethylene and steel pipeline and 31 compressor stations with a total
rated horsepower of 31,000, in addition to plant compression of approximately
20,000 horsepower. Most of the wells connected to the facilities produce
casinghead gas in association with crude oil. This gas is generally high in
NGLs. The NGLs are separated from the gas at our processing plants and then
fractionated into components and sold. The residue gas is sold into the
interstate market. A substantial portion of Bear Paw Energy's gathering and
processing contracts in the Williston Basin provide for the sale of the natural
gas stream to Bear Paw Energy. Upon sale of the NGLs and the residue gas
processed, Bear Paw Energy pays the producers based upon a percentage of the net
proceeds realized.

     For the year ended December 31, 2004, Bear Paw Energy's largest customers,
Lodgepole Energy Marketing ("Lodgepole"), BP Canada and Montana Dakota Utilities
("Montana Dakota") accounted for 44%, 14% and 12%, respectively, of Bear Paw
Energy's operating revenues. Lodgepole is the sole


                                       16
<PAGE>
purchaser of natural gas liquids from our processing plants in the
Williston Basin and the contract term extends until 2009. BP Canada and Montana
Dakota are purchasers of residue gas from our processing plants in the Williston
Basin under contracts whose terms are typically less than one year.

     We no longer own an interest in gathering facilities in Canada. Our
wholly-owned subsidiary, Border Midstream Services, Ltd. sold its undivided
minority interest in the Gregg Lake/Obed Pipeline located in Alberta, Canada in
December 2004 to KeySpan Energy Canada, Inc. for $14.0 million.

     FUTURE DEMAND AND COMPETITION

     Our gas gathering and processing segment competes with other natural gas
gathering, processing and pipeline companies in the production areas in the
Powder River, Wind River, and Williston Basins. Primary competitors in the
Powder River Basin of Wyoming include both independent gathering companies and
gathering companies affiliated with producers. Primary competitors affiliated
with producers include affiliates of Western Gas Resources, Thunder Creek Gas
Gathering, Bitter Creek Pipelines, LLC, Yates Petroleum and Anadarko Petroleum
Corp. Primary non-producer affiliated competitors include Bighorn, Optigas, Inc.
and Rimrock Pipeline, LLC. Competition for gathering and processing services in
the Williston Basin includes Amerada Hess, PetroHunt Corporation and Hiland
Resources in localized areas. Our competitive positions are affected by the pace
of oil and gas drilling, gas production rates, gas reserves, natural gas and
NGLs commodity prices, regulation and the demand for natural gas and NGLs in
North America.

     The pace of natural gas drilling may be impacted by, among other things,
the ability of producers to obtain and maintain the necessary drilling and
production permits in a timely and economic manner, reserve characteristics and
performance, surface access and infrastructure issues as well as commodity
prices. In addition, the regulation of discharge of the significant volumes of
water produced in association with coalbed methane production can be a deterrent
to producers in determining whether to drill or produce. The time period during
which coalbed methane wells dewater before significant gas production becomes
available may be unpredictable. Water quality may vary substantially, and
disposal alternatives and associated costs may also affect producers' decisions
to drill or produce. On January 17, 2003, the Bureau of Land Management ("BLM")
released two final environmental impact statements ("EIS") regarding oil and
natural gas development on Federal lands. One EIS pertains to oil and gas
development on BLM-administered public lands and federal mineral leases within
the Powder River Basin in northeastern Wyoming. The other EIS pertains to
statewide oil and natural gas development in Montana. Lawsuits have been filed
challenging the EIS in Wyoming and Montana. However, BLM's issuance of new
drilling permits under the regulatory preconditions has continued, albeit at a
slower rate than previous years. Approximately 65% of the Powder River Basin
acreage is on federal lands.

     In providing gas gathering, processing and other services, we may require
acreage dedication, long term commitment and/or minimum volume commitments or
demand charges from gas producers. Once a gathering and processing position is
established, the term of the dedication, the likely economic reserve life and
the cost of building duplicative facilities mitigate the level of competition in
the vicinity. Development of future gas gathering and processing facilities will
be staged to reflect the growth in number of wells and field production,
economics, permitting considerations and other factors impacting producers'
decisions to drill and produce. See Item 7. "Management's Discussion and
Analysis of Financial Condition and Results of Operations - Overview."


                                       17
<PAGE>
     We differentiate ourselves by the terms of services offered, our
flexibility and additional value-added services provided. Our relationships with
producers allow us to offer integrated services through all our gathering and
processing facilities, as well. We also provide a variety of delivery choices,
wide coverage area and operational efficiencies. We seek to improve operational
profitability by increasing natural gas throughput through new connections,
expansion, acquisitions, operational efficiencies and prudent deployment of
capital.

COAL SLURRY PIPELINE SEGMENT

     Black Mesa Pipeline, Inc., our wholly-owned subsidiary ("Black Mesa"), owns
a 273-mile, 18-inch diameter coal slurry pipeline which originates at a coal
mine in Kayenta, Arizona. The coal slurry pipeline transports crushed coal
suspended in water. It traverses westward through northern Arizona to the 1,500
megawatt Mohave Generating Station located in Laughlin, Nevada. The coal slurry
pipeline is the sole source of fuel for the Mohave Generating Station, which
consumes an average of 4.8 million tons of coal annually. The capacity of the
pipeline is fully contracted to Peabody Western Coal, the coal supplier for the
Mohave Generating Station, through the year ending December 31, 2005.

     The water used by the coal slurry pipeline is from an aquifer in The Navajo
Nation and Hopi Tribe joint use area. The Navajo Nation and Hopi Tribe have not
agreed to continued use of water from this aquifer after December 31, 2005.
Under a consent decree, the Mohave Generating Station has agreed to install
certain pollution control equipment by December 2005. With questions surrounding
the water supply and renegotiation of the coal supply contracts, Southern
California Edison ("SCE") a 56% owner of the Mohave Generating Station, filed a
petition before the California Public Utility Commission ("CPUC") requesting
that the CPUC either recognize the end of Mohave's coal-fired operations as of
the end of 2005 with appropriate ratemaking accounts or authorize expenditures
for pollution control activities required for future operation. On December 2,
2004, the CPUC issued its decision which authorizes SCE, among other things, to
make the necessary and appropriate expenditures for critical path investments,
including the new aquifer study and feasibility studies for alternatives to
replace or compliment the power from the coal-fired plant, and directs the
parties to continue working on resolution of the essential water and coal
issues. With successful resolution of the issues, it is expected that the Mohave
Generating Station, as well as the Black Mesa system, will be temporarily idled
for at least a three-year period while pollution control equipment is installed
at Mohave and the Black Mesa system is rebuilt. If efforts by the parties to
resolve these issues are not successful and the Mohave Generating Station is
permanently closed, it would be necessary to shut down Black Mesa in 2006,
resulting in shut down costs of approximately $5 million to $7 million and a
non-cash charge of approximately $12 million related to goodwill and the
remaining undepreciated cost of the pipeline. See Item 7. "Management's
Discussion and Analysis of Financial Condition and Results of Operations -
Overview."

     Approximately 57 people are employed in the operations of Black Mesa, of
which 28 are eligible to be represented by a labor union, the United Mine
Workers of America ("UMWA"). Black Mesa's collective bargaining agreement with
the UMWA was renewed in 2003 and is effective through December 31, 2005.

ENVIRONMENTAL AND SAFETY MATTERS

     Our interstate pipeline, coal slurry pipeline and U.S. gathering and
processing operations are subject to certain federal, state and local laws and


                                       18
<PAGE>
regulations relating to safety and the protection of the environment, which
include, as applicable, the Resource Conservation and Recovery Act, the
Comprehensive Environmental Response, the Compensation and Liability Act of
1980, as amended, the Clean Air Act, as amended, the Clean Water Act, as
amended, the Natural Gas Pipeline Safety Act of 1969, as amended, the Pipeline
Safety Act of 1992 and the Pipeline Safety Improvement Act of 2002.

     The Pipeline Safety Improvement Act of 2002 ("Act") was signed into law in
December 2002, providing guidelines for interstate pipelines in the areas of
risk analysis and integrity management, public education programs, verification
of operator qualification programs and filings with the National Pipeline
Mapping System. The Act requires pipeline companies to perform integrity
assessments on pipeline segments that exist in high population density areas or
near specifically identified sites that are designated as high consequence
areas. Pipeline companies are required to perform the integrity assessments
within ten years of the date of enactment and must perform subsequent integrity
assessments on a seven-year cycle. At least 50% of the highest risk segments
must be assessed within five years of the enactment date. In addition, within
one year of enactment, the pipeline's operator qualification programs, in force
since the mandatory compliance date of October 2002, must also conform to
standards provided by the Department of Transportation. Rules on integrity
management, direct assessment usage, and the operator qualification standards
have been issued. We have made the required filings with the National Pipeline
Mapping System and have reviewed and revised our public education program.
Compliance with the Act is expected to increase our operating costs particularly
related to integrity assessments for our interstate pipelines. As required, we
have developed an overall plan for pipeline integrity management. Detailed
analysis was performed to determine the priorities and costs for inspecting and
testing our pipelines. However, the plan will be modified as a result of the
findings noted and could result in additional assessment or remediation costs.
Presently we expect our annual costs for integrity assessments to be
approximately $1.0 million. We expect to include these costs in future rate case
filings. How these costs may be classified for all interstate pipelines is the
subject of the pending proceeding before the FERC. See "Interstate Natural Gas
Pipeline Segment-Interstate Pipeline Regulation" above.

     Black Mesa was subject to a judgment and Consent Decree entered in the
United States District Court of Arizona in July 2001 through December 31, 2004.
Under the Consent Decree, the United States Environmental Protection Agency
("EPA"), the Arizona Department of Environmental Quality ("ADEQ") and Black Mesa
agreed to the payment of penalties for alleged violations of federal and state
law due to unplanned discharges of coal slurry from Black Mesa's pipeline from
December 1997 through July 1999. The Consent Decree also set forth certain
preventative measures, reporting requirements and associated penalties for
failure to comply with the provisions of the Consent Decree. Since the Consent
Decree was entered, there have been several unplanned slurry discharges that
have been reported to the EPA and ADEQ. Future unplanned spills, if any, may be
subject to penalties for violations of federal and state laws.

     Although we believe that our operations and facilities are in general
compliance in all material respects with applicable environmental and safety
regulations, risks of substantial costs and liabilities are inherent in pipeline
and gas processing operations, and we cannot provide any assurances that we will
not incur such costs and liabilities. Moreover, it is possible that other
developments, such as enactment of increasingly strict environmental and safety
laws, regulations and enforcement policies thereunder by Congress, the FERC, the
Department of Transportation and other federal agencies, state regulatory bodies
and the courts, and claims for damages to property or persons resulting from our


                                       19
<PAGE>
operations, could result in substantial costs and liabilities to us. If we are
unable to recover such resulting costs, earnings and cash distributions could be
adversely affected.

ITEM 2. PROPERTIES.

     See Item 1. "Business-Interstate Natural Gas Pipeline Segment,"
"Business-Natural Gas Gathering and Processing Segment" and "Business-Coal
Slurry Pipeline Segment" for a brief description of the location and general
characteristics of our important physical properties by segment.

INTERSTATE NATURAL GAS PIPELINE SEGMENT

     Northern Border Pipeline, Midwestern Gas Transmission, Viking Gas
Transmission and Guardian Pipeline hold the right, title and interest in their
pipeline systems. With respect to real property, the pipeline systems fall into
two basic categories: (a) parcels which are owned in fee, such as sites for
compressor stations, meter stations, pipeline field offices, and microwave
towers; and (b) parcels where the interest derives from leases, easements,
rights-of-way, permits or licenses from landowners or governmental authorities
permitting the use of such land for the construction and operation of the
pipeline system. The right to construct and operate the pipeline systems across
certain property was obtained through exercise of the power of eminent domain.
The interstate pipeline systems continue to have the power of eminent domain in
each of the states in which they operate, although Northern Border Pipeline may
not have the power of eminent domain with respect to Native American tribal
lands.

     Approximately 90 miles of Northern Border Pipeline's system are located on
fee, allotted and tribal lands within the exterior boundaries of the Fort Peck
Indian Reservation in Montana. Tribal lands are lands owned in trust by the
United States for the Fort Peck Tribes and allotted lands are lands owned in
trust by the United States for an individual Indian or Indians. Northern Border
Pipeline does have the right of eminent domain with respect to allotted lands.

     In 1980, Northern Border Pipeline entered into a pipeline right-of-way
lease with the Fort Peck Tribal Executive Board, for and on behalf of the
Assiniboine and Sioux Tribes of the Fort Peck Indian Reservation ("Tribes").
This pipeline right-of-way lease, which was approved by the Department of the
Interior, Bureau of Indian Affairs ("BIA") in 1981, granted to Northern Border
Pipeline the right and privilege to construct and operate its pipeline on
certain tribal lands. This pipeline right-of-way lease was scheduled to expire
in 2011. Northern Border Pipeline has been granted options to renew the pipeline
right-of-way lease to 2061. See Item 3. "Legal Proceedings."

     In conjunction with obtaining a pipeline right-of-way lease across tribal
lands located within the exterior boundaries of the Fort Peck Indian
Reservation, Northern Border Pipeline also obtained a right-of-way across
allotted lands located within the reservation boundaries. Most of the allotted
lands are subject to a perpetual easement either granted by the BIA for and on
behalf of individual Indian owners or obtained through condemnation. Several
tracts are subject to a right-of-way grant that has a term of 15 years, expiring
in 2015.

NATURAL GAS GATHERING AND PROCESSING SEGMENT

     Bear Paw Energy, Bighorn, Lost Creek and Fort Union hold the right, title
and interest in their gathering and processing facilities, which consist of low
and high pressure gas gathering lines, compression and measurement installations
and


                                       20
<PAGE>
treating, processing and fractionation facilities. The real property rights for
these facilities are derived through fee ownership, leases, easements,
rights-of-way and permits.

COAL SLURRY PIPELINE SEGMENT

     Black Mesa holds title to its pipeline and pump stations. The real property
rights for Black Mesa facilities are derived through fee ownership, leases,
easements, rights-of-way and permits. Black Mesa holds rights-of-way grants from
private landowners as well as The Navajo Nation and the Hopi Tribe. These
rights-of-way grants extend for terms at least through December 31, 2005, the
date that Black Mesa's transportation contract with Peabody Western Coal is
presently scheduled to end.

ITEM 3. LEGAL PROCEEDINGS.

     On July 31, 2001, the Assiniboine and Sioux Tribes of the Fort Peck Indian
Reservation ("Tribes") filed a lawsuit in Tribal Court against Northern Border
Pipeline to collect more than $3 million in back taxes, together with interest
and penalties. The lawsuit related to a utilities tax on certain of Northern
Border Pipeline's properties within the Fort Peck Indian Reservation. The Tribes
and Northern Border Pipeline, through a mediation process, reached a settlement
with respect to pipeline right-of-way lease and taxation issues documented
through an Option Agreement and Expanded Facilities Lease ("Agreement") executed
in August 2004. Through the terms of the Agreement, the settlement grants to
Northern Border Pipeline, among other things: (i) an option to renew the
pipeline right-of-way lease upon agreed terms and conditions on or before April
1, 2011 for a term of 25 years with a renewal right for an additional 25 years;
(ii) a right to use additional tribal lands for expanded facilities; and (iii)
release and satisfaction of all tribal taxes against Northern Border Pipeline.
In consideration of this option and other benefits, Northern Border Pipeline
paid a lump sum amount of $7.4 million during August 2004 and will make
additional annual option payments of approximately $1.5 million thereafter
through March 31, 2011. Northern Border Pipeline intends to seek regulatory
recovery of the costs resulting from the settlement. See Item 7. "Management's
Discussion and Analysis of Financial Condition and Results of Operations - Risk
Factors and Information Regarding Forward-Looking Statements."

     See Item 1. "Business - Coal Slurry Pipeline Segment" for the discussion on
the proceeding before the CPUC related to Black Mesa's continuation of service
beyond 2005.

     See Item 1. "Business - Interstate Pipeline Regulation" for the discussion
on proceedings before the FERC.

     We are not currently parties to any other legal proceedings that,
individually or in the aggregate, would reasonably be expected to have a
material adverse impact on our financial condition.

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

     There were no matters submitted to a vote of security holders during the
fourth quarter of fiscal 2004.


                                       21
<PAGE>
                                     PART II

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

     Our common units are traded on the New York Stock Exchange. The following
table sets forth, for the periods indicated, the high and low sale prices per
common unit, as reported on the New York Stock Exchange Composite Tape, and the
amount of cash distributions per common unit declared for each quarter:

<TABLE>
<CAPTION>
                   Price Range
                 ---------------       Cash
2004              High      Low    Distribution
----             ------   ------   ------------
<S>              <C>      <C>      <C>
Fourth Quarter   $49.54   $44.60       $0.80
Third Quarter     45.81    38.61        0.80
Second Quarter    42.60    35.70        0.80
First Quarter     42.60    38.01        0.80
</TABLE>

<TABLE>
<CAPTION>
                   Price Range
                 ---------------       Cash
2003              High      Low    Distribution
----             ------   ------   ------------
<S>              <C>      <C>      <C>
Fourth Quarter   $43.70   $35.98       $0.80
Third Quarter     44.07    40.50        0.80
Second Quarter    42.33    38.10        0.80
First Quarter     39.00    36.57        0.80
</TABLE>

     As of March 8, 2005, there were approximately 1,200 record holders of
common units and approximately 64,800 beneficial owners of the common units,
including common units held in street name. On March 3, 2005, the last reported
sale price of our common units on the New York Stock Exchange was $51.70 per
common unit.

     We currently have 46,397,214 common units outstanding, representing a 98%
limited partner interest. The common units are the only outstanding limited
partner interests. Thus, our equity consists of general partner interests
representing in the aggregate a 2% interest and common units representing in the
aggregate a 98% limited partner interest.

     The general partners are entitled to 2% of all cash distributions, and the
holders of common units are entitled to the remaining 98% of all cash
distributions, except that the general partners are entitled to incentive
distributions if the amount distributed with respect to any quarter exceeds
$0.605 per common unit ($2.42 annualized). Under the incentive distribution
provisions, the general partners are entitled to 15% of amounts distributed in
excess of $0.605 per common unit ($2.42 annualized), 25% of amounts distributed
in excess of $0.715 per common unit ($2.86 annualized) and 50% of amounts
distributed in excess of $0.935 per common unit ($3.74 annualized). The amounts
that trigger incentive distributions at various levels are subject to adjustment
in certain events, as described in our partnership agreement.

EQUITY COMPENSATION PLAN INFORMATION

     Effective November 1, 2001, Northern Plains and NBP Services adopted the
Amended and Restated Northern Border Phantom Unit Plan as an incentive to
attract and retain employees who are essential to the services provided to us
and our


                                       22
<PAGE>
subsidiaries. By its terms, the Amended and Restated Northern Border Phantom
Unit Plan terminated on December 31, 2004. The Administrative Committee under
the Plan, which are appointees of Northern Plains and NBP Services, will
continue to administer the outstanding phantom units, which are based upon the
general partner distribution rate. The Administrative Committee has complete
authority to determine the time and provisions for settlement. During the
duration of a grant, the participant's account is credited with distributions
paid with respect to the underlying security. Upon settlement of the phantom
units, the participant will receive common units or cash or a combination
thereof, as determined by the Administrative Committee. The settlement value of
the phantom units is determined by using a value derived from the general
partner distribution rate and common unit distribution yield on the settlement
date.

<TABLE>
<CAPTION>
                            Number of securities
                              to be issued upon      Weighted average
                                 exercise of        Exercise price of      Number of units
                             outstanding phantom   outstanding phantom   remaining available
       Plan Category                units                 units          for future issuance
       -------------        --------------------   -------------------   -------------------
                                     (a)                   (b)                   (c)
                            --------------------   -------------------   -------------------
<S>                         <C>                    <C>                   <C>
Equity compensation plans
   approved by the
   unitholders (1)                   --                     --                    --

Equity compensation plans
   not approved by the
   unitholders (1)                 37,602 (2)             $48.18 (2)           189,500 (3)

Total                              37,602                                      189,500
</TABLE>

(1)  Under our partnership agreement, our partnership policy committee has the
     sole authority, without the approval of the unitholders, to adopt employee
     benefit or incentive plans or issue common units pursuant to any employee
     benefit or incentive plan maintained or sponsored by a general partner or
     its affiliates.

(2)  Based upon the closing price of the common units on December 31, 2004 and
     assumes that all outstanding phantom units were settled in common units as
     of December 31, 2004.

(3)  The Plan limits the number of grants of phantom units and phantom LP units
     to an aggregate of 200,000. This assumes all grants are phantom LP units.


                                       23
<PAGE>
ITEM 6. SELECTED FINANCIAL DATA.
(in thousands, except per unit, other financial data and operating data)

The following table sets forth, for the periods and at the dates indicated,
selected historical financial data for us. The selected consolidated financial
information should be read in conjunction with the Consolidated Financial
Statements and the Notes and Item 7. "Management's Discussion and Analysis of
Financial Condition and Results of Operations," which are included elsewhere in
this report.

<TABLE>
<CAPTION>
                                                 YEAR ENDED DECEMBER 31,
                             --------------------------------------------------------------
                                2004       2003 (1)       2002       2001 (2)     2000 (3)
                             ----------   ----------   ----------   ----------   ----------
<S>                          <C>          <C>          <C>          <C>          <C>
INCOME DATA:
Operating revenues, net      $  590,383   $  550,948   $  487,204   $  455,997   $  339,732
Product purchases               103,213       80,774       50,648       39,699           --
Operations and
   maintenance                  111,142      127,623      106,521       92,891       62,097
Depreciation and
   amortization (4)              86,431      299,791       74,672       75,424       60,699
Taxes other than income          36,212       35,443       32,194       27,863       28,634
                             ----------   ----------   ----------   ----------   ----------
   Operating income             253,385        7,317      223,169      220,120      188,302
Interest expense, net            76,943       78,980       82,898       89,908       81,495
Other income, net                19,648       23,679       15,170          258        8,410
Minority interests
   in net income                 50,033       44,460       42,816       42,138       38,119
Income taxes                      5,136        4,705        1,643          499          378
                             ----------   ----------   ----------   ----------   ----------
Income (loss) from
   continuing operations        140,921      (97,149)     110,982       87,833       76,720
Discontinued operations,
   net of tax (5)                 3,799        9,338        2,694          (47)          --
Cumulative effect of
   change in accounting
   principle, net of tax             --         (643)          --           --           --
                             ----------   ----------   ----------   ----------   ----------
Net income (loss) to
   partners                  $  144,720   $  (88,454)  $  113,676   $   87,786   $   76,720
                             ==========   ==========   ==========   ==========   ==========

Per unit income (loss)
   from continuing
   operations                $     2.81   $    (2.27)  $     2.38   $     2.12   $     2.50
                             ==========   ==========   ==========   ==========   ==========
Per unit net income (loss)   $     2.89   $    (2.08)  $     2.44   $     2.12   $     2.50
                             ==========   ==========   ==========   ==========   ==========
Number of units used
   in computation                46,397       45,370       42,709       38,538       29,665
                             ==========   ==========   ==========   ==========   ==========

CASH FLOW DATA:
Net cash provided by
   operating activities      $  244,658   $  224,660   $  244,006   $  233,948   $  169,615
Capital expenditures             43,477       30,282       50,738      126,414       19,721
Acquisition of businesses            --      123,194        1,561      345,074      229,505
Distribution per unit              3.20         3.20         3.20         2.99         2.65

BALANCE SHEET DATA
   (AT END OF YEAR):
Property, plant
   and equipment, net        $1,937,424   $1,992,104   $2,015,280   $2,040,099   $1,732,076
Total assets                  2,510,556    2,570,583    2,715,936    2,687,355    2,082,720
Long-term debt, including
   current maturities         1,330,358    1,415,986    1,403,743    1,423,227    1,171,962
Minority interests in
   partners' equity             290,142      240,731      242,931      250,078      248,098
Partners' equity                789,334      800,573      944,035      914,958      572,274
</TABLE>


                                       24
<PAGE>
<TABLE>
<CAPTION>
                                                YEAR ENDED DECEMBER 31,
                                 -----------------------------------------------------
                                    2004      2003 (1)     2002    2001 (2)   2000 (3)
                                 ---------   ---------   -------   --------   --------
<S>                              <C>         <C>         <C>       <C>        <C>
OTHER FINANCIAL DATA:
Ratio of earnings to
   fixed charges (6)                   3.4         0.4       2.8        2.5        2.4

OPERATING DATA:
Interstate Natural Gas
   Pipeline Segment:
      Million cubic feet of
         gas delivered           1,130,634   1,110,969   935,654    891,935    852,674
      Average receipts (mmcfd)       3,166       3,147     2,636      2,605      2,400
Natural Gas Gathering and
   Processing Segment:
      Gathering (mmcfd)              1,022       1,037     1,052        754        397
      Processing (mmcfd)                55          52        55         54         --
Coal Slurry
   Pipeline Segment:
      Thousands of tons
         of coal shipped             4,652       4,451     4,639      4,932      4,711
</TABLE>

----------
(1)  Includes results of operations for Viking Gas Transmission since date of
     acquisition in January 2003.

(2)  Includes results of operations for Bear Paw Energy (March 2001), Midwestern
     Gas Transmission (May 2001) and Border Midstream Services (April 2001)
     since dates of acquisition.

(3)  Includes results of operations for Crestone Energy Ventures and Crestone
     Gathering Services, L.L.C. since date of acquisition in September 2000.

(4)  Includes goodwill and asset impairment charge of $219,080 in 2003 related
     to our natural gas gathering and processing business segment.

(5)  In June 2003, Border Midstream Services sold its Gladys and Mazeppa
     processing plants and related gas gathering facilities. In December 2004,
     Border Midstream Services sold its undivided minority interest in the Gregg
     Lake/Obed Pipeline.

(6)  "Earnings" means the sum of pre-tax income from continuing operations
     (before adjustment for minority interests in consolidated subsidiaries or
     income from equity investees), fixed charges, amortization of capitalized
     interest and distributions from equity investees, less capitalized interest
     and the minority interests in pre-tax income of subsidiaries that have not
     incurred fixed charges. "Fixed charges" means the sum of (a) interest
     expensed and capitalized; (b) amortized premiums, discounts and capitalized
     expenses related to indebtedness; and (c) an estimate of interest within
     rental expenses. The ratio of earnings to fixed charges for 2003 was lower
     than prior years' ratios due primarily to the goodwill and asset impairment
     charges booked in 2003. Excluding the impact of the impairment, the ratio
     would have been 3.1 for 2003.


                                       25
<PAGE>
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS.

     Our discussion and analysis of our financial condition and operations are
based on our Consolidated Financial Statements, which were prepared in
accordance with U.S. generally accepted accounting principles. You should read
the following discussion and analysis in conjunction with our Consolidated
Financial Statements and the related notes included elsewhere in this report.

OVERVIEW

     The Partnership's businesses fall into three major business segments:

          -    the interstate natural gas pipeline segment, which comprises 76%
               of our assets;

          -    the natural gas gathering and processing segment, which comprises
               23% of our assets; and

          -    the coal slurry pipeline segment, which comprises 1% of our
               assets.

     INTERSTATE NATURAL GAS PIPELINE SEGMENT

     In the interstate natural gas pipeline segment, there are several major
business drivers. First, a healthy long-term supply outlook for each pipeline is
critical. Because the primary source of gas supply for two of our pipeline
systems is in the western Canadian sedimentary basin, western Canadian supply
trends are particularly important to this segment. With strong commodity prices,
the current outlook for western Canadian supply looks flat for the foreseeable
future, however, production has exceeded new reserve additions in recent years.
To maintain an adequate gas supply/demand balance in western Canada, production
will need to grow in the future to meet anticipated demand primarily driven by
gas consumption in the extraction and processing associated with Canadian oil
sands development. Canada holds substantial reserves of bitumen that is
extracted from sand and can be upgraded to synthesized crude oil through several
processes. The extraction and processing of bitumen require significant
quantities of natural gas. We do not know how many of the announced oil sands
development projects will be approved and constructed but the demand for
transportation on our pipeline systems could be affected adversely by the
additional competition for Canadian gas supply that would result. The supply
outlook may be enhanced over time by developments in the northern frontier with
new Mackenzie Delta supplies reaching the western Canadian pipeline grid
potentially beginning by the end of this decade and Alaskan gas thereafter,
although there is no assurance either project will be completed within that
timeframe. Moreover, prices of western Canadian supply must be competitive with
prices from other supply basins that serve our market areas. If prices are too
high, other sources of supply may satisfy demand that otherwise could be met by
us. Increased demand for western Canadian natural gas in markets other than
those served by us may also cause a reduction of demand for service on us.

     Natural gas markets are also critical to our long-term financial
performance. Our pipeline systems serve natural gas markets in the upper
midwestern area of the United States and access a major market hub in the
Chicago area. Market growth has been steady with both heating load growth and
direct end-user growth, such as power plants and ethanol plants for our
pipelines.


                                       26
<PAGE>
     We charge fees for transportation, which are primarily fixed and based on
the amount of capacity reserved for each shipper. Contracting with shippers to
reserve the available pipeline capacity as existing contracts expire is a
critical factor in our success. Based on contracts in place at December 31,
2004, the percentage of summer design capacity contracted as of December 31,
2005 was 61% for Northern Border Pipeline, 85% for Viking Gas Transmission and
75% and 48% for northbound and southbound transportation, respectively, on
Midwestern Gas Transmission.

     Northern Border Pipeline Recontracting

     During 2004, Northern Border Pipeline was successful in recontracting, at
maximum rates, essentially all of the summer design capacity under contracts
that expired on or before November 2004. However, most of those contracts were
for terms of five to six months so Northern Border Pipeline has a significant
amount of capacity, approximately 800 mmcfd or 28% of summer design capacity,
under contracts that expire by May 31, 2005. Most of this capacity will become
available on the pipeline system from Port of Morgan, Montana to the Ventura,
Iowa delivery point.

     Our objective for Northern Border Pipeline is to recontract the remaining
pipeline capacity at maximum transportation rates for the longest terms
possible. Because the forward natural gas basis differentials between Western
Canada and Northern Border Pipeline's market centers continue to be less than
the total transportation cost at maximum tariff rates, Northern Border Pipeline
may again sell a significant portion of this capacity on a short-term basis. So
long as we continue to provide economic value, gas likely will flow from western
Canada over our system and Northern Border Pipeline will maintain its relatively
high utilization levels. However, in any given month, current conditions of
weather and storage in supply and market areas may affect the demand for
capacity on Northern Border Pipeline. This could result in lower revenues in
some months. Although, we believe a reduction in expected 2005 net income and
cash flow of approximately $5 million to $10 million is possible, the impact on
net income and cash flow may vary outside this range depending on actual natural
gas basis differentials experienced during the year.

     The composition of natural gas can affect the amount of energy that is
transported through a pipeline system. Beginning in 2000, the energy content of
natural gas that Northern Border Pipeline receives at the Canadian border has
declined modestly from 1,023 British Thermal Units ("Btus") per cubic foot
("cf") to 1,005 Btus/cf. Northern Border Pipeline's transportation contracts in
conjunction with its tariff define both the volume and equivalent Btu value of
the gas to be transported. A reduction in the Btu level results in a higher
volume of natural gas to be transported to meet an overall equivalent Btu value
of the gas. This Btu decline that has been experienced was primarily the result
of greater processing capacity in Alberta. The change caused Northern Border
Pipeline to reduce its available capacity by almost 2 percent to maintain a high
standard of system reliability for its customers. During 2004, the Btu level
remained near the level of 1,005 Btus/cf and it is expected to remain at that
level during 2005. This Btu variance will be addressed in the November 1, 2005
rate case filing.

     Northern Border Pipeline Chicago III Expansion


                                       27
<PAGE>
     In September 2004, Northern Border Pipeline announced sufficient customer
support for a proposed expansion of the pipeline system into the Chicago market
area. The Chicago III Expansion Project, with 130 mmcfd of incremental capacity,
involves construction of a new 16,000 horsepower compressor station in Iowa and
minor modifications to existing compressor facilities, in Iowa and Illinois.
Capital costs are estimated to be approximately $21 million, and the target
in-service date is April 1, 2006, subject to timely receipt of regulatory
approval. We anticipate that approximately $15 million of the estimated $21
million capital budget will be expended in 2005, with the remaining $6 million
to be spent in 2006.

     Midwestern Gas Transmission Eastern Extension Project

     We announced on August 17, 2004 that Midwestern Gas Transmission had
finalized the necessary contractual commitment to proceed with the Eastern
Extension Project. The project involves the construction of approximately 30
miles of 16-inch diameter pipeline, with a capacity of approximately 120 mmcfd,
from Portland, Tennessee to planned interconnections with Columbia Gulf
Transmission Company and East Tennessee Pipeline Company. The project is
supported by a precedent agreement with Piedmont Natural Gas Company, a local
distribution company, for approximately 120 mmcf/d for a term of 15 years.
Midwestern Gas Transmission has pre-filed with the FERC under the National
Environmental Policy Act process. A scoping meeting was held by the FERC in
Tennessee on February 24, 2005. There is landowner opposition to the project,
which is not unusual for pipeline construction. Midwestern Gas Transmission is
working to keep the affected landowners, the FERC staff and other governmental
agencies informed. Pending the receipt of regulatory and other required
approvals, the proposed in-service date for the project is November 2006 and
project costs are estimated at approximately $22 million to $25 million with
approximately $8 million-$9 million to be expended in 2005.

     Viking Gas Transmission Recontracting

     During 2004, Viking Gas Transmission extended contracts of 49 mmcfd at
maximum rates with existing shippers for terms ranging from 3 to 5 years,
resulting in Viking Gas Transmission being fully contracted until November 2005.
Viking Gas Transmission has been successful in recontracting 89% of the 154
mmcfd of the expiring capacity at the Marshfield, Wisconsin delivery point for 2
to 5 year terms at maximum rates in spite of potential competition with ANR
Pipeline Company's North Leg Project scheduled to go into service in 2005. We
expect other projects may be proposed to further compete for these markets. WE
Energies, Wisconsin Power and Light Company and Wisconsin Public Service
Corporation are jointly exploring the acquisition of firm natural gas pipeline
capacity to accommodate growth and provide greater competition for deliveries to
various points along a route from the greater Milwaukee area to Green Bay,
Wisconsin.

     Rate Case Filings and FERC Inquiry

     Under the settlement agreement for Northern Border Pipeline's last rate
case, it was agreed that Northern Border Pipeline must file a proceeding under
section 4 of the Natural Gas Act to determine the just and reasonable rates to
be charged for its transportation services. During the rate case process, the
FERC staff and Northern Border Pipeline's customers will review the cost of
service elements, (including allowed return on capital, operations and
maintenance costs, depreciation and taxes) and contract


                                       28
<PAGE>
demand levels used to determine transportation rates. Also, as required under
the order granting a certificate of public convenience and necessity, Guardian
Pipeline must file a revenue and cost study by December 7, 2005.

     As described more fully in Item 1. "Business-Interstate Pipeline
Regulation", there is a FERC inquiry regarding the proper income tax allowance
in rates for regulated entities other than corporations. In response, a number
of comments, including ours, suggested that an income tax allowance is proper
for all jurisdictional entities regardless of legal structure. Some producers'
and customers' comments argued against the inclusion of an income tax allowance
for partnerships and other non-tax paying entities. It is not certain how, or
when, the FERC may proceed with respect to its Request for Comments or any
impact on the rate methodology for our interstate natural gas pipelines which
are not corporations. In particular, Northern Border Pipeline is a general
partnership and one of the elements used to determine its cost of service, upon
which its transportation rates are derived, is an allowance for income taxes.
While we cannot predict the outcome of the FERC's inquiry, we do believe that
Northern Border Pipeline's specific circumstances regarding its tariff, deferred
income tax treatment, FERC orders, past history and underlying agreements with
shippers are different from those of SFPP, L.P. The issue of whether Northern
Border Pipeline's rates should include an income tax allowance, and if so
the amount thereof, may be addressed in Northern Border Pipeline's 2005 rate
case.

     NATURAL GAS GATHERING AND PROCESSING SEGMENT

     The gas gathering and processing segment accepts delivery of raw gas from
natural gas wells at low pressure and gathers that wellhead production to
central points where it is processed as necessary and compressed to high
pressure for entry into the transmission pipeline grid. Key factors that have an
impact on this segment are the pace of reserve development, the decline rate of
existing wells, the composition of the raw gas stream being gathered, and the
value of natural gas and natural gas liquids.

     We charge a fee for this service in the Powder River Basin. In the
Williston Basin, we buy the natural gas we gather and then resell the extracted
natural gas liquids and residue, retaining a portion of the resale revenues in
return for our gathering and processing services. In some cases, we charge a fee
as well. The producers receive the balance of the proceeds from the resale.

     Williston Basin Expansions

     As a result of increased drilling and development by Bear Paw Energy's
customers in the Williston Basin, Bear Paw Energy has selectively expanded its
facilities and expects moderate growth in this area. The 5 mmcfd expansion of
the Marmarth plant has been in full operation since February 2004. The project
enables the plant to produce a higher grade of product by controlling the
maximum ethane-propane mixture. Also, Bear Paw Energy has expanded the northwest
portion of its system to accommodate additional volumes in the Bakken Oil Play.
It is anticipated that as a result of placing these facilities into service in
December 2004, an additional 3.8 mmcfd will be processed by Bear Paw Energy's
Grasslands processing plant in 2005. Further expansion in the Bakken Oil Play is
expected to bring additional volumes to our system.


                                       29
<PAGE>
     Powder River Basin Developments

     On our wholly-owned systems in the Powder River Basin, gathering volumes
have increased 9% since reaching a low point in the first quarter 2004. For the
full year 2004, average daily volumes gathered on our wholly-owned assets in the
Powder River Basin were down 3% compared to 2003, in spite of modest growth in
drilling activity and smaller than anticipated well production declines. Certain
gathering contracts were renegotiated to mitigate volumetric risk and to reduce
operation and maintenance expenses. In addition, certain non-strategic Powder
River assets were sold during 2004, which resulted in gains totaling $3.3
million during 2004. Late in 2004, we also purchased a gathering system that
gathers production from approximately 10,000 acres.

     We hold minority interests in Bighorn and Fort Union, which are trunk
gathering systems in the Powder River Basin. These businesses are also impacted
by the pace of drilling, regulatory issues and declines in upstream areas,
however, they are generally more stable in terms of throughput volumes and
revenues because they gather gas from larger areas. Also, our ownership in
Bighorn includes preferred A units, which effectively provide an incentive
mechanism to Cantera Natural Gas tied to the number of wells connected to the
system. Whether such targets have been met for 2004 is under discussion. We
believe that a distribution for the preferred A units is due us for 2004. Our
expected 2005 net income and cash flow includes approximately $2.6 million from
this distribution.

     Sale of Gregg Lake/Obed Pipeline Interest

     Our wholly-owned subsidiary, Border Midstream Services sold its undivided
minority interest in the Gregg Lake/Obed Pipeline located in Alberta, Canada in
December 2004 for approximately $14.0 million. The sale resulted in a $3.6
million after-tax gain.

     COAL SLURRY PIPELINE SEGMENT

     Black Mesa Pipeline Company is our coal slurry pipeline. This pipeline has
one major customer, the coal supplier to the Mohave Generating Station, in
Laughlin, Nevada. This contract on Black Mesa provides a steady, fee for
service, revenue stream through December 31, 2005. After that time, the future
is uncertain. The Mohave Generating Station must complete some significant
pollution control investments, and a new water supply for the coal slurry
mixture must be established. In addition, new contracts for the coal supply,
must be completed. We believe that we will be able to negotiate a new contract
for Black Mesa's services, however, we cannot predict the timing or ultimate
outcome. Should these issues be resolved, it appears likely that there would be
a temporary shutdown of the Mohave Generating Station and the Black Mesa
pipeline from 2006 to 2009. We anticipate that the capital expenditures for the
Black Mesa refurbishment project will be in the range of $175 million to $200
million, which will be supported by revenues from a new transportation contract.
Under certain circumstances upon the renewal of the transportation contract, we
have a contingent obligation to issue common units to prior owners of an
interest in Black Mesa Pipeline. If this obligation is triggered, approximately
70,000 to 75,000 common units would be issued. If efforts to resolve the issues
surrounding the Mohave Generating Station are not successful and it is
permanently closed, it would be necessary to shut down the Black Mesa


                                       30
<PAGE>
pipeline in 2006. In the event the Mohave Generating Station permanently closes,
estimated shut down costs for Black Mesa could be in the range of $5 million to
$7 million for such expenses as environmental reclamation, severance payments
and pension plan funding. We would also be required to take a non-cash charge of
approximately $12 million related to goodwill and the remaining undepreciated
cost of the assets.

     For all of our operations, we have continual focus on reliability for our
shippers, safety for the public and our customers, and compliance with
regulatory rules and regulations. In our businesses, these areas are essential.

STRATEGY

     We are focused on growing our businesses, our income and cash flow and our
distributions to unitholders. Our strategy involves three main components.

     INTERSTATE NATURAL GAS PIPELINE SEGMENT

     First, we will continue to focus on safe, efficient, and reliable
operations and the further development of our regulated pipelines. We intend to
maintain our position as a low cost transporter of Canadian gas to the
midwestern U.S. and provide highly valued services to our customers. Any growth
in our interstate pipelines would occur through incremental projects intended to
access new markets or supply areas and would be supported by long-term
contracts. For Northern Border Pipeline, the marketing of available capacity in
a short-term contracting environment, filing for and receiving regulatory
approvals for the Chicago III Expansion and filing the rate case will be
priorities for 2005. In addition, Midwestern Gas Transmission will focus on
receiving regulatory approvals for its Eastern Extension project and will
continue pursuit of expanding existing and developing new interconnections with
other interstate pipelines to access new markets.

     NATURAL GAS GATHERING AND PROCESSING SEGMENT

     Second, we also are developing our gas gathering and processing segment
where we are building on our established business relationships with producers
and marketers in the Rocky Mountain supply basins. We expect to see continued
build-out of our gathering systems within the areas of acreage dedications we
have secured, particularly in the Powder River Basin. Depending on the pace of
reserve and production development, time associated with regulatory compliance
including water-discharge permitting, and infrastructure development, we expect
growth from new well connections to offset the decline from existing gas wells,
resulting in approximately level aggregate gathered volumes on our Powder River
systems during 2005. We are also continuing to pursue different approaches to
conducting business in the Powder River Basin to reduce capital and operating
expenditures, improve revenue, and reduce volume and capital recovery risks. We
seek to build extensions to existing facilities on dedicated acreage using lower
risk rate structures, expand our gathering network by securing additional
acreage dedications, and encourage utilization of existing facilities.

     We expect modest growth in gas volumes for our pipelines in the Williston
Basin, reflecting prospects for drilling activity within the


                                       31
<PAGE>
Bakken Oil Play production area. In the Williston Basin, we seek to build
extensions and expansions around our existing facilities and also pursue
opportunities to reduce costs and streamline operations. In addition, we are
pursuing new acreage dedications in the basin. The build-out of our existing,
and the addition of new, acreage dedications should mitigate production declines
and allow further improvement in cost efficiencies. We will also continue to
seek opportunities to mitigate commodity price exposure on the Williston Basin
production.

     ACQUISITIONS

     Finally, our objective is to continue to acquire profitable and
complementary businesses. Our goal is approximately $200 to $250 million of
capital expenditures annually in growth through acquisitions and internal
development. We target businesses that leverage our core competencies of energy
transportation, are conservative in terms of commodity price risk, are located
in the U.S. and Canada, and provide immediate earnings and cash flow
contribution. Our strategy is to focus on acquisitions of natural gas assets
including interstate and intrastate natural gas pipelines, storage facilities
and gathering and processing assets and natural gas liquids pipelines and
storage facilities. We anticipate financing our capital expenditures and
acquisitions conservatively through an appropriate mix of additional borrowings
and equity issuances. Although we regularly evaluate various acquisition
opportunities, we cannot provide assurance that we will reach our goal each year
and would also expect that, depending on specific opportunities that develop,
acquisitions in some years could significantly exceed our goal stated above. Our
ability to maintain and grow our distributions to the unitholders is dependent
upon the growth of our existing businesses and/or our acquisitions.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

     Certain amounts included in or affecting our Consolidated Financial
Statements and related notes must be estimated, requiring us to make certain
assumptions with respect to values or conditions that cannot be known with
certainty at the time the financial statements are prepared. The preparation of
financial statements in conformity with accounting principles generally accepted
in the United States of America requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the financial
statements and the reported amounts of revenues and expenses during the
reporting period. Actual results could differ from those estimates. Key
estimates used by our management include the economic useful lives of our assets
used to determine depreciation and amortization, the fair values used to
determine possible asset impairment charges, the fair values used to record
derivative assets and liabilities, expense accruals, and the fair values of
assets acquired. Any effects on our business, financial position or results of
operations resulting from revisions to these estimates are recorded in the
period in which the facts that give rise to the revision become known.

     Our significant accounting policies are summarized in Note 2 - Notes to
Consolidated Financial Statements included elsewhere in this report. Certain of
our accounting policies are of more significance in our financial statement
preparation process than others.

     The interstate natural gas pipelines' accounting policies conform to


                                       32
<PAGE>
Statement of Financial Accounting Standards ("SFAS") No. 71, "Accounting for the
Effects of Certain Types of Regulation." Accordingly, certain assets that result
from the regulated ratemaking process are recorded that would not be recorded
under accounting principles generally accepted in the United States of America
for nonregulated entities. We continually assess whether the future recovery of
the regulatory assets is probable by considering such factors as regulatory
changes and the impact of competition. If future recovery ceases to be probable,
we would be required to write-off the regulatory assets at that time. At
December 31, 2004, we have recorded regulatory assets of $12.3 million, which
are being recovered, or expected to be recovered, from the pipelines' shippers
over varying time periods up to 44 years.

     Our long-lived assets are stated at original cost. We must use estimates in
determining the economic useful lives of those assets. Useful lives are based on
historical experience and are adjusted when changes in planned use,
technological advances or other factors show that a different life would be more
appropriate. The depreciation rate used for utility property is an integral part
of the interstate pipelines' FERC tariffs. Any revisions to the estimated
economic useful lives of our assets will change our depreciation and
amortization expense prospectively. For utility property, no retirement gain or
loss is included in income except in the case of retirements or sales of entire
operating units. The original cost of utility property retired is charged to
accumulated depreciation and amortization, net of salvage and cost of removal.

     We review long-lived assets for impairment in accordance with SFAS No. 144,
"Accounting for the Impairment or Disposal of Long-Lived Assets." Long-lived
assets are reviewed for impairment whenever events or changes in circumstances
indicate that the carrying amount of an asset may not be recoverable.
Recoverability of the carrying amount of assets is measured by a comparison of
the carrying amount of the asset to future net cash flows expected to be
generated by the asset. Estimates of future net cash flows include anticipated
future revenues, expected future operating costs and other estimates. If such
assets are considered to be impaired, the impairment to be recognized is
measured by the amount by which the carrying amount of the assets exceeds the
fair value of the assets.

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

     As discussed in Note 5, Notes to Consolidated Financial Statements,
effective January 1, 2003, we adopted SFAS No. 143, "Accounting for Asset
Retirement Obligations." SFAS No. 143 requires entities to record the fair value
of a liability for an asset retirement obligation in the period in which it is
incurred, if the liability can be reasonably estimated. We have, where possible,
developed our estimate of the retirement obligations. The implementation of SFAS
No. 143 resulted in an increase in net property, plant and equipment of $2.5
million, an increase in reserves and deferred credits of $3.1 million and a
reduction to net income of $0.6 million for the net-of-tax cumulative effect of
the change in accounting principle.

     Our accounting for financial instruments is in accordance with SFAS No.
133, "Accounting for Derivative Instruments and Hedging Activities," which
requires that every derivative instrument be recorded on the balance sheet as
either an asset or liability measured at its fair value. The statement requires
that changes in the derivative's fair value be recognized currently in earnings
unless specific hedge accounting criteria are met.


                                       33
<PAGE>
Special accounting for qualifying hedges allows a derivative's gains and losses
to offset related results on the hedged item in the income statement. At
December 31, 2004, the consolidated balance sheet included assets from
derivative financial instruments of $4.6 million.

     For our interstate natural gas pipelines, operating revenues are derived
from agreements for the receipt and delivery of gas at points along the pipeline
system as specified in each shipper's individual transportation contract.
Revenues are recognized based upon contracted capacity and actual volumes
transported under transportation service agreements. For our gas gathering and
processing businesses, operating revenue is recorded when gas is processed in or
transported through company facilities. For our coal slurry pipeline, operating
revenue is recognized based on a contracted demand payment, actual tons
transported and direct reimbursement of certain other expenses.

RESULTS OF OPERATIONS

The following table summarizes financial and other information by business
segment for the years ended December 31, 2004, 2003 and 2002 (in thousands):

<TABLE>
<CAPTION>
                                                Year Ended December 31,
                                            -------------------------------
                                              2004        2003        2002
                                            --------   ---------   --------
<S>                                         <C>        <C>         <C>
Operating revenues:
   Interstate Natural Gas Pipelines         $383,625   $ 375,256   $339,014
   Natural Gas Gathering and Processing      184,738     154,284    126,622
   Coal Slurry                                22,020      21,408     21,568
                                            --------   ---------   --------
      Total operating revenues               590,383     550,948    487,204
                                            --------   ---------   --------

Operating income (loss):
   Interstate Natural Gas Pipelines          231,027     212,841    200,584
   Natural Gas Gathering and Processing       28,278    (203,067)    23,278
   Coal Slurry                                 3,446       5,144      5,054
   Other                                      (9,366)     (7,601)    (5,747)
                                            --------   ---------   --------
      Total operating income (loss)          253,385       7,317    223,169
                                            --------   ---------   --------
Income (loss) from continuing operations:
   Interstate Natural Gas Pipelines          134,726     119,620    107,510
   Natural Gas Gathering and Processing       44,488    (183,016)    35,568
   Coal Slurry                                 3,088       4,092      4,136
   Other                                     (41,381)    (37,845)   (36,232)
                                            --------   ---------   --------
      Total income (loss) from continuing
         operations                          140,921     (97,149)   110,982
                                            --------   ---------   --------
Discontinued operations, net of tax            3,799       9,338      2,694
Cumulative effect of change in
   accounting principle, net of tax               --         643         --
                                            --------   ---------   --------
Net income (loss)                           $144,720   $ (88,454)  $113,676
                                            ========   =========   ========
</TABLE>

     Following is a detailed analysis of the results of operations for each of
our operating segments.

     Our operating results for 2004 reflect the settlement or expected
settlement of several outstanding issues related to our past relationship with
Enron Corp. ("Enron"). Our potential obligation for costs related to the
termination of Enron's cash balance plan was resolved late in 2004, which
allowed us to reduce our expenses. Settlement was also reached with


                                       34
<PAGE>
Enron for certain administrative expenses for 2002 and 2003 that had been
previously estimated, which also reduced our expenses. We also recorded income
in 2004 for estimated recovery of bankruptcy claims against the Enron estate
that we had previously fully reserved. In December 2004, Border Midstream sold
its undivided minority interest in the Gregg Lake/Obed Pipeline. The operating
results for Border Midstream are classified as discontinued operations. See
Notes 3 and 19 - Notes to Consolidated Financial Statements.

     Our operating results for 2003 reflected several significant events. Due to
lower throughput volumes experienced and anticipated in our wholly-owned
subsidiaries in our natural gas gathering and processing business segment, we
recorded impairment charges related to goodwill and tangible assets for that
segment. Effective January 17, 2003, we acquired all of the common stock of
Viking Gas Transmission, including a one-third interest in Guardian Pipeline. In
June 2003, we sold our Gladys and Mazeppa processing plants located in Alberta,
Canada. The operating results for these plants are classified as discontinued
operations. Finally, as a result of Enron's decision to terminate its cash
balance plan, we recorded expenses for our expected charges related to the
termination of that plan. See Notes 3, 4 and 18 - Notes to Consolidated
Financial Statements.

     Our income from continuing operations in 2004 was $140.9 million, $2.81 per
unit, as compared to a loss from continuing operations of ($97.1) million in
2003, ($2.27) per unit, and income from continuing operations of $111.0 million
in 2002, $2.38 per unit. Our loss in 2003 resulted from a $219.1 million
goodwill and asset impairment recorded for our natural gas gathering and
processing segment. Excluding the impairment charges, income from continuing
operations increased $18.9 million in 2004 as compared to 2003. We were advised
by Northern Plains and NBP Services, as a result of further evaluation and
negotiation of Enron's proposed allocation of the termination costs, that no
claim of reimbursement for the termination costs of Enron's cash balance plan
will be made, resulting in a reduction to expense in 2004 of $6.2 million ($4.8
million, net of tax and minority interest). When compared to the impact of the
charges recorded in 2003, this represents a $9.6 million change to income from
continuing operations between 2003 and 2004. Income from continuing operations
for 2004 also reflects an adjustment to our allowance for doubtful accounts for
estimated recoveries of claims against the Enron estate of $3.3 million ($3.0
million, net of minority interest) and a gain on sale of two of Bear Paw
Energy's gathering systems and other compressor equipment of $3.3 million.
Excluding the impairment charges, income from continuing operations increased
$11.0 million in 2003 as compared to 2002, which reflects income from Viking Gas
Transmission of $7.1 million, lower interest expense for Northern Border
Pipeline of $6.6 million ($4.6 million impact on continuing operations after
minority interest) due to a decrease in average interest rates as well as a
decrease in average debt outstanding, a $2.9 million special income allocation
related to a cash distribution from our preferred A interest in Bighorn Gas
Gathering and a $3.3 million payment received for a change in ownership of the
other partner in Bighorn Gas Gathering. These increases to income were partially
offset by charges associated with the termination of Enron's cash balance plan
of $6.2 million ($4.8 million, net of tax and minority interest). The
calculation of per unit income (loss) was also impacted by our issuance of
additional partnership interests in May and June 2003.

     Our consolidated income statement reflects income from discontinued


                                       35
<PAGE>
operations of $3.8 million in 2004, $9.3 million in 2003 and $2.7 million in
2002. Discontinued operations for 2004 include an after-tax gain of $3.6 million
on the sale of the undivided interest in the Gregg Lake/Obed Pipeline.
Discontinued operations for 2003 include an after-tax gain of $4.9 million on
the sale of the Gladys and Mazeppa processing plants. The consolidated income
statement also reflects a reduction to net income of $0.6 million due to a
net-of-tax cumulative effect of change in accounting principle, which resulted
from adopting SFAS No. 143, "Accounting for Asset Retirement Obligations."

INTERSTATE NATURAL GAS PIPELINE SEGMENT

     Our interstate natural gas pipeline segment reported income of $134.7
million in 2004, $119.6 million in 2003 and $107.5 million in 2002. The increase
in 2004 income from 2003 primarily relates to an increase in Northern Border
Pipeline's revenues by $4.9 million ($3.4 million net impact to income after
minority interests), a decrease in Northern Border Pipeline's operations and
maintenance expense by $10.0 million ($7.0 million net impact to income after
minority interests) and a decrease in Northern Border Pipeline's interest
expense by $3.5 million ($2.5 million net impact to income after minority
interests). The increase in 2003 income from 2002 primarily resulted from our
acquisition of Viking Gas Transmission on January 17, 2003, and lower interest
expense for Northern Border Pipeline. Viking Gas Transmission's income for 2003
totaled $7.1 million and Northern Border Pipeline's interest expense decreased
by $6.6 million ($4.6 million net impact to income after minority interests).

     Operating revenues for our interstate natural gas pipeline segment were
$383.6 million in 2004, $375.2 million in 2003 and $339.1 million in 2002. The
increase in operating revenues in 2004 over 2003 resulted from an increase in
Northern Border Pipeline's revenues of $4.9 million, an increase in Viking Gas
Transmission revenues of $2.1 million and an increase in Midwestern Gas
Transmission revenues of $1.4 million. Due to the expiration of conditions under
Northern Border Pipeline's previous rate case settlement, it was able to
generate and retain approximately $2.0 million from the sale of short-term firm
capacity and approximately $2.0 million due to no longer being required to share
new service revenue with its shippers. The remaining increase of $0.9 million
resulted from an additional day of transportation services due to leap year.
Viking Gas Transmission's revenue was higher in 2004 primarily because 2003 does
not reflect revenue prior to the January 17, 2003 acquisition date. Midwestern
Gas Transmission's revenue increased primarily due to operational sales of gas.
The increase in operating revenues in 2003 over 2002 resulted from Viking Gas
Transmission revenues of $29.0 million, an increase in Midwestern Gas
Transmission revenues of $4.0 million and an increase in Northern Border
Pipeline's revenues of $3.1 million. Midwestern Gas Transmission's revenues in
2003 reflect an increase in contracted capacity as compared to the same period
in 2002. Northern Border Pipeline's revenues for 2002 were affected by $1.8
million of uncollected revenues associated with the transportation capacity
formerly held by ENA, which filed for Chapter 11 bankruptcy protection in
December 2001 (see "The Impact Of Enron's Chapter 11 Filing On Our Business").

     Operations and maintenance expenses for our interstate natural gas pipeline
segment were $52.7 million in 2004, $63.6 million in 2003 and $48.3 million in
2002. The decrease in expenses from 2003 to 2004 primarily


                                       36
<PAGE>
resulted from a decrease in Northern Border Pipeline's and Midwestern Gas
Transmission's expense by $10.0 million and $1.1 million, respectively. In 2004,
Northern Border Pipeline and Midwestern Gas Transmission reduced expenses by
$4.2 million for adjustments to their accruals for estimated charges resulting
from the termination of Enron's cash balance plan. Additionally in 2004, the
interstate natural gas pipelines reduced their operations and maintenance
expense by approximately $1.9 million related to the settlement of previously
accrued charges for administrative services provided by Northern Plains, the
pipelines' operator, and its affiliates. Also contributing to the decrease were
adjustments made to our allowance for doubtful accounts of $1.1 million for
estimated recoveries of claims against Enron. Expense was increased by $1.0
million related to costs incurred as part of our comprehensive effort to ensure
compliance with Section 404 of the Sarbanes Oxley Act of 2002. The increase in
expenses in 2003 over 2002 resulted from Viking Gas Transmission's expense of
$10.8 million and an increase in Northern Border Pipeline's expense and
Midwestern Gas Transmission's expense by a combined $4.5 million. This increase
primarily related to the estimated charges for termination of Enron's cash
balance plan of $4.2 million. Northern Border Pipeline's expenses in 2002
reflected a $10.0 million accrual for costs related to the treatment of
previously collected quantities of natural gas used in utility operations to
cover electric power costs (see Footnote 6 - Notes to Consolidated Financial
Statements, included elsewhere in this report.) In February 2003, Northern
Border Pipeline filed to amend its FERC tariff to clarify the definition of
company use gas, which is gas supplied by its shippers for its operations.
Northern Border Pipeline had included in its retention of company use gas,
quantities that were equivalent to the cost of electric power at its
electric-driven compressor stations during the period of June 2001 through
January 2003. On March 27, 2003, the FERC issued an order rejecting Northern
Border Pipeline's proposed tariff sheet revision and requiring refunds with
interest within 90 days of the order. Northern Border Pipeline made refunds to
its shippers of $10.3 million in May 2003.

     Depreciation and amortization expenses for our interstate natural gas
pipeline segment were $67.1 million in 2004, $65.9 million in 2003 and $61.0
million in 2002. The increase between 2004 and 2003 is primarily a result of
assets that Viking Gas Transmission had placed in service in the fourth quarter
of 2003. The increase between 2002 and 2003 is primarily due to the acquisition
of Viking Gas Transmission in January 2003.

     Taxes other than income for our interstate natural gas pipeline segment
were $32.8 million in 2004, $32.9 million in 2003 and $29.2 million in 2002. The
increase in 2003 from 2002 is primarily due to Viking Gas Transmission expenses
of $2.5 million and a $1.2 million increase in Northern Border Pipeline's
expense. Northern Border Pipeline's 2002 expense reflected a refund of use taxes
previously paid on exempt purchases.

     Interest expense for our interstate natural gas pipeline segment was $43.9
million in 2004, $47.6 million in 2003 and $51.5 million in 2002. The decrease
in interest expense in 2004 from 2003 was primarily due to a decrease in average
debt outstanding for Northern Border Pipeline partially offset by an increase in
average interest rates. Northern Border Pipeline's interest expense decreased
$6.6 million in 2003 from 2002 due to a decrease in average interest rates as
well as a decrease in average debt outstanding. The 2003 expense included $2.7
million for Viking Gas Transmission.

     Other income, net for our interstate natural gas pipeline segment was


                                       37
<PAGE>
$0.8 million in 2004, $0.5 million in 2003 and $2.0 million in 2002. Significant
items included in the $0.3 million increase between 2003 and 2004 are additional
income of approximately $0.6 million for pipeline interconnections constructed
partially offset by $0.5 million of bad debt expense. The decrease from 2002 to
2003 relates to a $0.6 million expense for Northern Border Pipeline's repayment
of amounts received in 2002 for previously vacated microwave frequency bands.

     Equity earnings from unconsolidated affiliates for our interstate natural
gas pipeline segment were $1.6 million in 2004 and $2.0 million in 2003, which
represents earnings from our one-third interest in Guardian Pipeline. The
decrease in equity earnings was primarily due to higher depreciation expense as
well as higher administrative expenses for Guardian Pipeline.

     Minority interests in net income, which represent the 30% minority interest
in Northern Border Pipeline, were $50.0 million for 2004, $44.5 million for 2003
and $42.8 million for 2002. The increases in 2004 and 2003 from prior year
results were due to increased net income for Northern Border Pipeline.

     Income tax expense for our interstate natural gas pipeline segment was $4.8
million in 2004 and $3.6 million in 2003 as compared to an income tax benefit of
$0.7 million in 2002. The 2004 and 2003 amounts included Viking Gas Transmission
income taxes of $2.6 million. The remaining income tax amounts relate to
Midwestern Gas Transmission, which increased $1.2 million from 2003 to 2004 due
to an increase in income before income taxes.

NATURAL GAS GATHERING AND PROCESSING SEGMENT

     Our natural gas gathering and processing segment reported income from
continuing operations of $44.5 million in 2004, a loss from continuing
operations of ($183.0) million in 2003 and income from continuing operations of
$35.6 million in 2002. The segment recorded impairment charges of $219.1 million
in 2003 (see Note 4 - Notes to Consolidated Financial Statements, included
elsewhere in this report). Excluding the effect of the impairment charges, the
segment's income from continuing operations increased $8.4 million between 2003
and 2004 primarily due to a reduction to 2004 expense of $1.5 million for the
adjustment to an accrual made in 2003 for estimated charges resulting from the
termination of Enron's cash balance plan (resulting in a decrease between years
of $2.9 million), a gain on sale of two gathering systems and other compressor
equipment of $3.3 million and the adjustment to our allowance for doubtful
accounts for estimated recoveries of claims against Enron of $2.3 million.
Excluding the effect of the impairment charges, the segment's income from
continuing operations for 2003 and 2002 was relatively unchanged.

     Operating revenues for our natural gas gathering and processing segment
were $184.7 million in 2004, $154.3 million in 2003 and $126.6 million in 2002.
The increase in revenues in 2004 over 2003 reflects an increase in realized
prices for natural gas and natural gas liquids and increased gathering and
processing volumes in the Williston Basin, which accounted for $31.3 million of
the revenue increase, partially offset by lower gathering volumes in the Powder
River Basin, which decreased revenues by $3.3 million. The increase in 2003 over
2002 is due to an increase in natural gas and natural gas liquid prices, which
accounted for $31.6 million of the overall increase, partially offset by lower
volumes gathered in the


                                       38
<PAGE>
Powder River Basin, which decreased revenues $3.9 million.

     Product purchases for our natural gas gathering and processing segment were
$103.2 million in 2004, $80.8 million in 2003 and $50.6 million in 2002. Under
certain gathering and processing agreements in the Williston Basin, Bear Paw
Energy purchases raw natural gas from producers at a price tied to a percentage
of the price for which it sells extracted natural gas liquids and residue gas.
Total revenues from the sale of these products are included in operating
revenues. Amounts paid to the producers to purchase their raw natural gas are
reflected in product purchases. The increase in product purchases in 2004 over
2003 is due to an increase in natural gas and natural gas liquid prices and
increased gathering and processing volumes. The increase in 2003 over 2002 is
due to an increase in natural gas and natural gas liquid prices.

     Operations and maintenance expenses for our natural gas gathering and
processing segment were $35.9 million in 2004, $42.8 million in 2003 and $38.2
million in 2002. The reduction in 2004 from 2003 was due to several factors. The
2004 amount includes a $3.3 million gain on sale of two gathering systems and
other compressor equipment. In addition, the decrease in 2004 expense was due to
the segment recording a $2.3 million estimated recovery of previously recorded
bad debts. Expense for 2004 was also reduced by $1.5 million for the adjustment
to the accrual made in 2003 for estimated charges resulting from the termination
of Enron's cash balance plan. Partially offsetting these decreases to expense
were higher fuel costs of $0.8 million and expenses incurred as a result of the
Marmarth plant expansion, which went into service in 2004. Employee benefits
expenses for 2003 increased $3.6 million as compared to 2002, which included
$1.5 million of charges associated with the termination of Enron's cash balance
plan.

     For our natural gas gathering and processing segment, depreciation and
amortization expenses, excluding the impairment charge recorded in 2003, were
$14.8 million in 2004, $13.0 million in 2003 and $12.1 million in 2002. As a
result of the goodwill and asset impairment analysis, we decided to shorten the
useful life of our low-pressure gas gathering assets in the Powder River Basin
from 30 to 15 years, which increased our depreciation expense by $0.6 million
for this segment in 2003 and by $1.8 million in 2004.

     Other income, net from our natural gas gathering and processing segment was
$0.2 million in 2004, $3.9 million in 2003 and $0.1 million in 2002. The
increase in other income for 2003 is primarily due a $3.3 million payment
received for a change in ownership of the other partner in Bighorn Gas Gathering
and a $0.5 million refund from an electric cooperative.

     Equity earnings from our unconsolidated affiliates were $16.4 million in
2004, $16.8 million in 2003 and $13.0 million in 2002. The 2004 and 2003 equity
earnings include $2.8 million and $2.9 million from a special income allocation
related to a cash distribution from our preferred A interest in Bighorn Gas
Gathering. This distribution, determined in accordance with the joint venture
agreement, was based on the number of wells connected to the gathering system in
the preceding year. If certain targets are not met, we receive a
disproportionate share of cash distributions.

COAL SLURRY PIPELINE SEGMENT


                                       39
<PAGE>
     Our coal slurry pipeline segment reported income from continuing operations
of $3.1 million in 2004 on revenues of $22.0 million, income of $4.1 million in
2003 on revenues of $21.4 million and income of $4.1 million in 2002 on revenues
of $21.6 million. The $1.0 million decrease in income from continuing operations
between 2003 and 2004 was primarily due to higher depreciation expense of $2.6
million ($1.6 million impact after income taxes) partially offset by an increase
in revenue by $0.6 million ($0.4 million impact after income taxes).
Depreciation and amortization expense for the coal slurry pipeline was $4.5
million in 2004 as compared to $1.9 million in 2003 and $1.6 million in 2002.
The Partnership determined it was appropriate to shorten the useful life of
certain of its coal slurry assets to correspond with the expiration of the
existing coal slurry transportation agreement in 2005. The increase in revenues
in 2004 is primarily related to an increase in billing rates and an increase in
tons of coal shipped.

OTHER

     Items not attributable to any segment include certain of our general and
administrative expenses, interest expense on our debt and other income and
expense items. Our general and administrative expenses not allocated to any
segment were $9.4 million in 2004, $7.6 million in 2003 and $5.7 million in
2002. The increase in expense between 2003 and 2004 was primarily related to
increased insurance costs of $1.1 million, $1.0 million of costs incurred as
part of our comprehensive effort to ensure compliance with Section 404 of the
Sarbanes Oxley Act of 2002 and $0.8 million of additional business development
expenditures partially offset by a reduction to 2004 expense of $0.4 million for
the adjustment to an accrual made in 2003 for estimated charges resulting from
the termination of Enron's cash balance plan (resulting in a decrease between
years of $0.8 million) and a $0.7 million reduction related to the settlement of
previously accrued charges for administrative services provided by Northern
Plains and its affiliates. The 2003 expense included $0.4 million for the
termination of the Enron cash balance plan, an increase in insurance expense by
$0.5 million due to an increase in liability premiums and additional business
development expenditures of $0.4 million.

     Interest expense on our debt was $32.7 million in 2004, $30.8 million in
2003 and $30.6 million in 2002. The increase in expense for 2004 from 2003 was
primarily due to an increase in average debt outstanding partially offset by a
decrease in average interest rates.

LIQUIDITY AND CAPITAL RESOURCES

     The following table sets forth our contractual obligations as of December
31, 2004.

SUMMARY OF CERTAIN CONTRACTUAL OBLIGATIONS AND COMMERCIAL COMMITMENTS

<TABLE>
<CAPTION>
                                            Payments Due by Period
                                       --------------------------------------------
                                       Less Than                             After
                             Total       1 Year    1-3 Years   4-5 Years    5 Years
                          ----------   ---------   ---------   ---------   --------
                                                (In Thousands)
<S>                       <C>          <C>         <C>         <C>         <C>
2002 Pipeline Senior
   Notes due 2007         $  150,000    $    --     $150,000    $     --   $     --
1999 Pipeline Senior
   Notes due 2009            200,000         --           --     200,000         --
2000 Partnership Senior
   Notes due 2010            250,000         --           --          --    250,000
</TABLE>


                                       40
<PAGE>
<TABLE>
<S>                       <C>          <C>         <C>         <C>         <C>
2001 Partnership Senior
   Notes due 2011            225,000         --           --          --    225,000
2001 Pipeline Senior
   Notes due 2021            250,000         --           --          --    250,000
Viking Senior Notes
   due 2008 to 2014           31,120      2,133        4,266       1,779     22,942
2003 Partnership Credit
   Agreement due 2007        191,000         --      191,000          --         --
Capital Leases (a)             3,262      3,145          117          --         --
Operating Leases (b)          83,422      4,489        7,178       5,370     66,385
Other Long-Term
   Obligations (b)            61,260     11,624       23,247      22,710      3,679
                          ----------    -------     --------    --------   --------
Total                     $1,445,064    $21,391     $375,808    $229,859   $818,006
                          ==========    =======     ========    ========   ========
</TABLE>

(a)  See Note 8 - Notes to Consolidated Financial Statements.

(b)  See Note 13 - Notes to Consolidated Financial Statements.

     We have guaranteed the performance of certain of our unconsolidated
affiliates in connection with their credit agreements that expire in March 2009
and September 2009. Collectively at December 31, 2004, the amount of both
guarantees was $4.4 million.

     OVERVIEW

     We believe that we have adequate liquidity to fund future recurring
operating activities and investments. Short-term liquidity needs will be met by
our operating cash flows and our current or similar new credit facilities
discussed below. Other liquidity needs are expected to be funded through the
issuance of long-term debt as well as additional limited partner interests. Our
ability to complete future debt and equity offerings and the timing of any such
offerings will depend on various factors, including prevailing market
conditions, interest rates and our financial condition and credit ratings at the
time.

     CREDIT FACILITIES

     The Partnership and Northern Border Pipeline have entered into revolving
credit facilities, which are used for refinancing existing indebtedness, capital
expenditures, acquisitions and general business purposes. We entered into a $275
million four-year revolving credit agreement ("2003 Partnership Credit
Agreement") with certain financial institutions in November 2003. Northern
Border Pipeline entered into a $175 million three-year credit agreement ("2002
Pipeline Credit Agreement") with certain financial institutions in May 2002. At
December 31, 2004, $191 million was outstanding under the 2003 Partnership
Credit Agreement at an average interest rate of 3.20%. There were no amounts
outstanding under the 2002 Pipeline Credit Agreement at December 31, 2004. With
the 2002 Pipeline Credit Agreement due to expire in May 2005, Northern Border
Pipeline has commenced discussions with financial institutions and expects to
have a new credit agreement in place at terms and conditions similar to its
current agreement.

     Each of the 2003 Partnership Credit Agreement and the 2002 Pipeline Credit
Agreement requires the Partnership and Northern Border Pipeline to maintain
compliance with certain financial, operational and legal covenants. The 2003
Partnership Credit Agreement and 2002 Pipeline Credit Agreement


                                       41
<PAGE>
require the Partnership and Northern Border Pipeline to 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 credit 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 4.5 to 1. Under the 2003
Partnership Credit Agreement, if we consummate one or more acquisitions in which
the aggregate purchase price is $25 million or more, the allowable ratio of
indebtedness to adjusted EBITDA is temporarily increased to 5 to 1. At December
31, 2004, the Partnership and Northern Border Pipeline were in compliance with
the covenants of our credit agreements. The interest rate applied to amounts
outstanding under these agreements may, as selected by us and by Northern Border
Pipeline, be either the lender's base rate or LIBOR plus a spread that is based
upon the long-term unsecured debt ratings in effect for us and for Northern
Border Pipeline.

     DEBT SECURITIES

     In April 2002, Northern Border Pipeline completed a private offering of
$225 million of 6.25% Senior Notes due 2007 ("2002 Pipeline Senior Notes"). The
proceeds from the 2002 Pipeline Senior Notes were used to reduce indebtedness
outstanding. In December 2004, Northern Border Pipeline redeemed $75 million of
the 2002 Pipeline Senior Notes. The indentures under which the Pipeline Senior
Notes were issued do not limit the amount of unsecured debt Northern Border
Pipeline may incur, but they do contain material financial covenants, including
restrictions on incurrence of secured indebtedness.

     The indentures under which the Partnership Senior Notes were issued do
not limit the amount of unsecured debt we may incur, but they do contain
material financial covenants, including restrictions on incurrence, assumption
or guarantee of secured indebtedness. The indentures also contain provisions
that would require us to offer to repurchase the Partnership Senior Notes, if
either Standard & Poor's Rating Services or Moody's Investor Services, Inc. rate
the notes below investment grade and the investment grade rating is not
reinstated for a period of 40 days.

     At December 31, 2004, Viking Gas Transmission has four series of senior
notes outstanding. In November 2004, Viking Gas Transmission amended the
indenture on its senior notes. Prior to the amendment, Viking Gas Transmission
made monthly principal and interest payments on the four series of notes. As a
result of the amendment, three of the series of senior notes due between 2011
and 2014 require payment of interest quarterly and payment of principal at
maturity. The senior notes due in 2008 continue to require monthly principal and
interest payments. Under the previous indenture, Viking Gas Transmission's
transportation contracts were pledged as security for payment, which has been
replaced in the current indenture by a guarantee by the Partnership. In
addition, Viking Gas Transmission is no longer required to maintain debt service
funds on deposit. At December 31, 2003, the requirement for accumulation of debt
service funds was $3.7 million.

     HEDGING ACTIVITY

     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 to be placed in the first half of


                                       42
<PAGE>
2005. The interest rate swap agreements have been designated as cash flow hedges
as they hedge the fluctuations in Treasury rates and spreads between the
execution date of the swaps and the issuance of the fixed rate debt. We expect
to use the proceeds from the senior note issuance to repay amounts borrowed
under the 2003 Partnership Credit Agreement.

     We currently have outstanding interest rate swap agreements with notional
amounts totaling $150 million that expire in March 2011. Under the interest rate
swap 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. At December 31, 2004, the average effective interest rate on
our interest rate swap agreements was 4.60%.

     EQUITY ISSUANCES

     In May and June 2003, we sold 2,250,000 and 337,500 common units,
respectively. In July 2002, we sold 2,186,700 common units. In conjunction with
the issuance of additional common units, our general partners are required to
make capital contributions to maintain a 2% general partner interest in
accordance with the partnership agreements. The net proceeds from the sale of
common units and the general partners' capital contributions totaled
approximately $102.2 million and $75.4 million in 2003 and 2002, respectively,
and were primarily used to repay indebtedness outstanding.

     CASH FLOWS FROM OPERATING ACTIVITIES

     Cash flows provided by operating activities were $244.7 million in 2004,
$224.7 million in 2003 and $244.0 million in 2002. The increase in operating
revenues and lower interest expense in 2004 as compared to 2003 contributed to
the increase in operating cash flow. These increases were partially offset by
higher product purchases and a $2.3 million decrease in distributions received
from unconsolidated affiliates. Other cash flows from operating activities for
2004 reflect Northern Border Pipeline's initial payment of $7.4 million to the
Fort Peck Tribes, in accordance with the terms of the Agreement, and an inflow
of $3.7 million for funds that Viking Gas Transmission was previously required
to keep on deposit for debt service. The decrease from 2002 to 2003 is primarily
due to Northern Border Pipeline's refund to its shippers for $10.3 million (see
Note 6 - Notes to Consolidated Financial Statements, included elsewhere in this
report). Operating cash flows were also decreased due to payments made to NBP
Services and Northern Plains for administrative services provided prior to 2003
and due to a reduction in prepayments in 2003 that Northern Border Pipeline had
required certain shippers make in 2002 for transportation service. Distributions
received from unconsolidated affiliates increased $5.4 million to $16.3 million,
primarily due to distributions received from Bighorn Gas Gathering related to
our preferred A interest discussed previously.

     CASH FLOWS FROM INVESTING ACTIVITIES

     Cash used in investing activities was $20.9 million in 2004, $116.7 million
in 2003 and $55.3 million in 2002. In 2003, we spent higher amounts primarily
related to the acquisition of Viking Gas Transmission.

     Our capital expenditures were $43.5 million in 2004, which included


                                       43
<PAGE>
$25.6 million for natural gas gathering and processing facilities, $16.3 million
for interstate natural gas pipeline facilities and $1.6 million for coal slurry
pipeline facilities. Our capital expenditures were $30.3 million in 2003, which
included $19.5 million for interstate natural gas pipeline facilities, $9.0
million for natural gas gathering and processing facilities and $1.8 million for
coal slurry pipeline facilities. For 2002, our capital expenditures were $50.7
million, which included $33.7 million for natural gas gathering and processing
facilities, $16.5 million for interstate natural gas pipelines facilities and
$0.4 million for coal slurry pipeline facilities.

     Our cash used in acquisitions was $123.2 million in 2003, as compared to
$1.6 million in 2002. In January 2003, we acquired Viking Gas Transmission. We
did not make any acquisitions in 2004.

     Sale of assets were $22.7 million in 2004 due to the sale of our undivided
minority interest in the Gregg Lake/Obed Pipeline for $14.0 million and the sale
of two of Bear Paw Energy's gathering systems for $8.7 million. Sale of assets
was $40.3 million in 2003 due to the sale of the Gladys and Mazeppa processing
plants. No sale of assets occurred in 2002.

     Our investments in unconsolidated affiliates were $0.1 million in 2004,
$3.5 million in 2003 and $3.0 million in 2002. The 2003 amount primarily
represents capital contributions to Guardian Pipeline while the 2002 amounts
primarily reflect capital contributions to Bighorn Gas Gathering.

     Total capital expenditures for 2005 are estimated to be $87 million.
Capital expenditures for the interstate natural gas pipelines are estimated to
be $57 million, including approximately $40 million for Northern Border
Pipeline. Of the $57 million projected expenditures for the interstate natural
gas pipelines, approximately $15 million relates to Northern Border Pipeline's
Chicago III Expansion Project and $8 million to $9 million relates to Midwestern
Gas Transmission's Eastern Extension Project. Northern Border Pipeline currently
anticipates funding its 2005 capital expenditures primarily by borrowing on its
credit facility and using operating cash flows. Capital expenditures for natural
gas gathering and processing facilities are estimated to be $25 million for
2005. The remaining $5 million estimated to be spent in 2005 primarily relates
to information technology systems. Funds required to meet the capital
requirements for 2005 are anticipated to be provided from our credit facility
and operating cash flows.

CASH FLOWS FROM FINANCING ACTIVITIES

     Cash flows used in financing activities were $225.7 million for 2004,
$106.7 million for 2003 and $170.8 million for 2002. Our cash distributions to
our unitholders and our general partners in 2004, 2003 and 2002 were $159.6
million, $155.2 million and $147.0 million, respectively. The increase in
distributions paid between years is due to an increase in the number of common
units outstanding.

     In 2004, Northern Border Pipeline received equity contributions from its
general partners including $61.5 million from its minority interest holder.
Northern Border Pipeline's distributions to its minority interest holder
increased $15.5 million between 2003 and 2004. Effective January 1, 2004,
Northern Border Pipeline changed its cash distribution policy. Cash


                                       44
<PAGE>
distributions will be equal to 100% of distributable cash flow as determined
from Northern Border Pipeline's financial statements based upon earnings before
interest, taxes, depreciation and amortization less interest expense and less
maintenance capital expenditures.

     In 2003 and 2002, we issued additional partnership interests of $102.2
million (2.6 million common units) and $75.4 million (2.2 million common units),
respectively, which were primarily used to repay indebtedness outstanding.

     For 2004, our borrowings on long-term debt totaled $259.0 million, which
were primarily used to repay previously existing indebtedness. Issuances of
long-term debt included borrowings under our credit agreement of $152.0 million
and borrowings under Northern Border Pipeline's credit agreement of $107.0
million. Total repayments of debt were $327.5 million, which included the
redemption of $75 million of the 2002 Pipeline Senior Notes. In connection with
the redemption, Northern Border Pipeline was required to pay a premium of $4.8
million.

     For 2003, our borrowings on long-term debt totaled $342.0 million, which
were primarily used for our acquisition of Viking Gas Transmission and to repay
previously existing indebtedness. Issuances of long-term debt included
borrowings under our credit agreements of $200.0 million and borrowings under
Northern Border Pipeline's credit agreement of $142.0 million. Total repayments
of debt in 2003 were $361.1 million.

     For 2002, our borrowings on long-term debt totaled $499.9 million, which
were primarily used to repay previously existing indebtedness. Issuances of
long-term debt included net proceeds from the 2002 Pipeline Senior Notes of
approximately $223.5 million; borrowings under our prior credit agreement of
$68.0 million; and borrowings under Northern Border Pipeline's credit agreements
of $207.0 million. Total repayments of debt in 2002 were $567.5 million.

     In November 2004, Northern Border Pipeline received $7.6 million from the
termination of its interest rate swap agreements with a total notional amount of
$225 million. In March 2003, the Partnership received $12.3 million from the
termination of an interest rate swap agreement with a notional amount of $75
million. The proceeds were primarily used to repay existing indebtedness. In
2002, we agreed to an increase in the variable interest rate on two of our
interest rate swap agreements with a total notional amount of $150 million. As
consideration for the change to the variable interest rate, we received
approximately $18.2 million, which represented the fair value of the financial
instruments at the date of the adjustment. We used the proceeds to repay amounts
borrowed under our prior credit agreement. Also, in 2002, Northern Border
Pipeline received $2.4 million from the termination of forward starting interest
rate swap agreements (see Note 9 - Notes to Consolidated Financial Statements).

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

     On December 2, 2001, Enron filed a voluntary petition for bankruptcy
protection under Chapter 11 of the United States Bankruptcy Code. Certain
wholly-owned Enron subsidiaries also filed for Chapter 11 bankruptcy protection
on December 2, 2001 and thereafter. Until November 17, 2004, each of Northern
Plains and Pan Border, two of our general partners, were


                                       45
<PAGE>
subsidiaries of Enron. Northern Plains and Pan Border were not among the Enron
companies who filed for Chapter 11 protection.

     SALE OF ENRON ENTITIES

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

     On June 24, 2004, Enron announced that it had reached an agreement with a
joint venture of Southern Union Company and GE Commercial Finance Energy
Financial Services ("CCE Holdings") for the sale of CrossCountry. On September
1, 2004, Enron announced that it reached an amended agreement for the sale of
CrossCountry to CCE Holdings ("CCE Holdings Agreement"). On September 10, 2004,
the Bankruptcy Court issued an order (the "September 10 Order") approving the
CCE Holdings Agreement.

     On September 16, 2004, Southern Union Company and ONEOK, Inc. each
announced that ONEOK had entered into an agreement ("ONEOK Agreement") to
purchase Northern Plains, Pan Border and NBP Services (collectively the
"Transfer Group Companies") from CCE Holdings. This acquisition closed on
November 17, 2004. Under the CCE Holdings Agreement, Enron agreed to extend
certain of the terms of the transition services agreement and transition
services supplemental agreement between CrossCountry and Enron (together the
"TSA") for a period of six months from the closing date.

     As part of the closing, ONEOK and CCE Holdings entered a transition
services agreement referred to as the "Northern Border Transition Services
Agreement" covering certain transition services by and among ONEOK, CCE Holdings
and Enron for a period of six months. Certain of the services previously
provided by Enron are now being provided through ONEOK. As services are
transitioned to Northern Plains, NBP Services or ONEOK, it is possible that
additional costs for computer hardware, software and personnel may result. The
costs estimated to date do not appear to be materially greater than the costs
incurred in the past by Northern Plains and NBP Services from Enron and
CrossCountry.

     PENSION LIABILITY

     On December 31, 2003, Enron filed a motion seeking approval of the
Bankruptcy Court to provide additional funding to, and for authority to
terminate, the Enron Corp. Cash Balance Plan ("Cash Balance Plan") and certain
other defined benefit plans of Enron's affiliates (collectively the "Plans") in
"standard terminations" within the meaning of Section 4041 of the Employee
Retirement Income Security Act of 1974, as amended ("ERISA"). On January 30,
2004, the Bankruptcy Court entered an order authorizing the termination,
additional funding and other actions necessary to effect the relief requested.
Pursuant to the Bankruptcy Court order, any contributions to the Plans are
subject to the prior receipt of a favorable determination by the Internal
Revenue Service that the Plans are tax-qualified as of their respective dates of
termination.


                                       46
<PAGE>
     On July 19, 2004, Enron was served with a complaint filed by the Pension
Benefits Guaranty Corporation ("PBGC") in the District Court for the Southern
District of Texas against Enron as the sponsor and/or administrator of the Plans
(the "Action"). By filing the Action, the PBGC is seeking an order (i)
terminating the Plans; (ii) appointing the PBGC the statutory trustee of the
Plans; (iii) requiring transfer to the PBGC of all records, assets or other
property of the Plans required to determine the benefits payable to the Plans'
participants; and (iv) establishing June 2, 2004 as the termination date of the
Plans. In the Bankruptcy Court September 10 Order, Enron was authorized to enter
into an escrow agreement with CCE Holdings and PBGC. Upon closing, Enron
deposited the amount of $321.8 million to an escrow account, which is intended
to ensure that none of CCE Holdings or its affiliates are exposed to liability
to the PBGC under Title IV of the Employee Retirement Income Security Act of
1974, as amended, for which CCE Holdings may otherwise be indemnified pursuant
to the CCE Holdings Agreement. In addition, the form of escrow agreement
approved pursuant to the September 10 Order provides that, under certain
circumstances and upon approval by or notice to the parties to the escrow
agreement, some or all of the funds placed in escrow may be paid directly in
respect of the Cash Balance Plan to the PBGC. However, the September 10 Order
also provides that PBGC retains any rights or claims it may have against the
Transfer Group Companies.

     Enron management previously informed Northern Plains and NBP Services that
Enron would seek funding contributions from each member of its ERISA controlled
group of corporations that employs, or employed, individuals who are, or were,
covered under the Cash Balance Plan. Northern Plains and NBP Services are
considered members of Enron's ERISA controlled group of corporations. As of
December 31, 2003, the amount of approximately $6.2 million was estimated for
Northern Plains' and NBP Services' proportionate share of the up to $200 million
estimated termination costs for the Plans authorized by the Bankruptcy Court
order. Since under the operating agreement with Northern Plains and the
administrative agreement with NBP Services, these costs could be our
responsibility, we accrued $6.2 million to satisfy claims of reimbursement for
these termination costs.

     As a result of further evaluation and negotiation of Enron's proposed
allocation of the termination costs, Northern Plains and NBP Services advised us
that no claim of reimbursement for the termination costs will be made, resulting
in a reduction in reserves during 2004 of $6.2 million for the termination
costs. Under the ONEOK Agreement, neither Northern Plains nor NBP Services nor
the Partnership will be required to contribute to or otherwise be liable for any
contributions to Enron in connection with the Cash Balance Plan. The purchase
price under the agreements will be deemed to include all contributions which
otherwise would have been allocable to Northern Plains and NBP Services.

     CLAIMS FILED IN BANKRUPTCY

     At the time of the filing of the bankruptcy petition, we had a number of
contractual relationships with Enron and its subsidiaries.

     On July 15, 2004, the Bankruptcy Court approved the amended joint Chapter
11 plan and related disclosure statement ("Chapter 11 Plan"). Under the approved
Chapter 11 Plan, assuming the previously announced sale of


                                       47
<PAGE>
Portland General Electric is consummated, Enron creditors, which should include
subsidiaries of the Partnership as general unsecured creditors, will receive a
combination of cash and equity of Prisma Energy International, Enron's
international energy asset business. We have previously fully reserved our
claims against Enron.

     ENA, a wholly-owned subsidiary of Enron that is in bankruptcy, was a party
to transportation contracts, which obligated ENA to pay for 3.5% of Northern
Border Pipeline's capacity. Through the bankruptcy proceeding in 2002, ENA
rejected and terminated all of its firm transportation contracts on Northern
Border Pipeline. Since Enron guaranteed the obligations of ENA under those
contracts, Northern Border Pipeline filed claims against both ENA and Enron for
damages in the bankruptcy proceedings. As a result of a settlement agreement
between ENA, Enron and Northern Border Pipeline, each of ENA and Enron have
agreed to allow Northern Border Pipeline's claim of approximately $20.6 million.
The settlement agreement is expected to be presented to the Bankruptcy Court for
approval in March 2005. Based upon this settlement between the parties, at
December 31, 2004 Northern Border Pipeline adjusted its allowance for doubtful
accounts to reflect an estimated recovery of $1.1 million for this claim.

     ENA was also a party to a transportation contract for capacity on
Midwestern Gas Transmission. ENA rejected and terminated this contract in
November 2003. Midwestern Gas Transmission filed claims against ENA for breach
of contract and other claims. However, this claim of approximately $150 thousand
was denied.

     In addition, Bear Paw Energy filed claims against ENA relating to
terminated swap agreements. In accordance with SFAS No. 133 in 2001 Bear Paw
Energy ceased to account for these swap agreements as hedge transactions. Bear
Paw Energy had previously recorded approximately $6.7 million in accumulated
other comprehensive income related to these agreements, which is being recorded
into earnings in the same periods of the originally forecasted hedges. During
the third quarter 2004, the Bankruptcy Court approved a settlement between Bear
Paw Energy, Enron and certain of its wholly-owned subsidiaries of Bear Paw
Energy's claim for commodity hedges. As a result, we adjusted our allowance for
doubtful accounts to reflect an estimated $1.8 million recovery for this claim.

     Also, Crestone Energy Ventures filed claims against ENA for unpaid gas
gathering and administrative services fees in the amount of approximately $2.3
million. As a result of a settlement agreement between ENA and Crestone Energy
Ventures, ENA has agreed to allow Crestone Energy Ventures' claim of
approximately $2.3 million. The settlement agreement is expected to be presented
to the Bankruptcy Court for approval in March 2005. Based upon this settlement
between the parties, an adjustment of $0.5 million was made to our allowance for
doubtful accounts.

     We estimate that we could recognize, through future operating results,
additional recoveries of $4 million to $7 million for the claims in the Enron
bankruptcy proceedings. However, there can be no assurances on the amounts
actually recovered or timing of distributions under the Chapter 11 Plan.

     VEBA TRUST


                                       48
<PAGE>
     Enron is the grantor of the Enron Gas Pipeline Employee Benefit Trust (the
"Trust"), which when taken together with the Enron Corp. Medical Plan for
Inactive Participants (the "Medical Plan") constitutes a "voluntary employees'
beneficiary association" or "VEBA" under Section 501(c)(9) of the Internal
Revenue Code. In October 2002, Northern Plains was advised that Enron had
notified the committee that has administrative and fiduciary oversight related
to the Trust and the Medical Plan, that Enron had made the determination to
begin necessary steps to partition the assets of the Trust and the related
liabilities of the Medical Plan among all of the participating employers of the
Trust. The Trust was established as a regulatory requirement for inclusion of
certain costs for post-employment medical benefits in the rates established for
the affected pipelines, including Northern Border Pipeline. Enron requested the
enrolled actuary to prepare an analysis and recommendation for the allocation of
the Trust's assets and associated liabilities among all the participating
employers. On July 22, 2003, Enron sought approval of the Bankruptcy Court to
terminate the Trust and to distribute its assets among certain identified
pipeline companies, one being Northern Plains. If Enron's relief would have been
granted as requested, Northern Plains would have assumed retiree benefit
liabilities, estimated as of June 30, 2002, of $1.9 million with an asset
allocation of $0.8 million. An objection to the motion was filed. An additional
actuary has been engaged by Enron to review the analysis and recommendations for
allocations. The results of that review have not been provided to Northern
Plains. It is anticipated that a new motion will be filed and that the
allocation of liabilities and assets will change from those set forth in the
prior motion. We do not, however, believe that those changes will be material.

     PUBLIC UTILITY HOLDING COMPANY ACT ("PUHCA") REGULATION

     We were previously a subsidiary of a registered holding company. Upon
consummation of the sale of Northern Plains and Pan Border to CCE Holdings and
to ONEOK, we were no longer a subsidiary of a registered holding company.

RISK FACTORS AND INFORMATION REGARDING FORWARD-LOOKING STATEMENTS

     Statements in this Annual 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. These
forward-looking statements are identified as any statement that does not relate
strictly to historical or current facts. Forward-looking statements are not
guarantees of performance. They involve risks, uncertainties and assumptions.
The future results of our operations may differ materially from those expressed
in these forward-looking statements. Such forward-looking statements include:

     -    the discussions in "Management's Discussion and Analysis of Financial
          Condition and Results of Operations - The Impact Of Enron's Chapter 11
          Filing On Our Business";

     -    the discussions in "Management's Discussion and Analysis of Financial
          Condition and Results of Operations -- Overview"; and

     -    the discussions in "Management's Discussion and Analysis of Financial
          Condition and Results of Operations -- Liquidity and


                                       49
<PAGE>
          Capital Resources."

     Although we believe that our expectations regarding future events are based
on reasonable assumptions within the bounds of our knowledge of our business, we
cannot assure you that our goals will be achieved or that our expectations
regarding future developments will be realized.

     With this in mind, you should consider the following important factors that
could cause actual results to differ materially from those in the
forward-looking statements:

     -    Any customer's failure to perform its contractual obligations could
          adversely impact our cash flows and financial condition. Some of our
          shippers or their owners have experienced a deterioration of their
          financial condition. Should one or more file for bankruptcy
          protection, our ability to recover amounts owed or to resell the
          capacity would be impacted.

     -    Since Northern Plains, the interstate natural gas pipelines' operator,
          and NBP Services, administrator for us, are transitioning services
          from Enron and CrossCountry, Northern Plains and NBP Services may be
          unable to perform certain services under their agreements or may incur
          increases in costs to continue or replace the services.

     -    Contracts on our interstate pipelines will expire during the year 2005
          with significant expirations in April and October. On Northern Border
          Pipeline, those contracts represent approximately 40% of its summer
          design capacity. The interstate pipelines' ability to recontract
          capacity as existing contracts terminate for maximum transportation
          rates will be subject to a number of factors including availability of
          natural gas supplies from the western Canadian sedimentary basin, the
          demand for natural gas in our market areas and the basis differential
          between the receipt and delivery points on our system. Northern Border
          Pipeline may have to contract for shorter terms or at less than
          maximum rates. See "Overview" above and Item 1. "Business - Interstate
          Pipelines - Demand For Transportation Capacity."

     -    Our interstate pipelines are subject to extensive regulation by the
          FERC governing all aspects of our business, including our
          transportation rates. Under Northern Border Pipeline's 1999 rate case
          settlement, neither Northern Border Pipeline nor its existing
          customers can seek rate changes to its settlement base rates until
          November 2005, at which time Northern Border Pipeline is obligated to
          file a rate case. We cannot predict what challenges our interstate
          pipelines may have to their rates in the future. See Item 1. "Business
          - Interstate Pipelines - FERC Regulation."

     -    In the event that the FERC ultimately determines that interstate
          natural gas pipelines that are partnerships are not entitled to an
          allowance for income tax in their rates and Northern Border Pipeline
          is unsuccessful in its arguments regarding its facts and
          circumstances, the disallowance of this component of cost of service
          for rates in Northern Border Pipeline could be materially adverse to
          us. See Item 1. "Business - Interstate Pipelines - FERC Regulation."


                                       50
<PAGE>
     -    In a rate case proceeding setting the maximum rates that may be
          charged, our interstate pipeline systems are generally allowed the
          opportunity to collect from their customers a return on their assets
          or "rate base" as reflected in their financial records as well as
          recover that rate base through depreciation. The amount they may
          collect from customers, as a result of a subsequent rate case,
          decreases as the rate base declines as a result of, depreciation and
          amortization. In order to avoid a reduction in the level of cash
          available for distributions to its owners, in the event of a future
          rate case, each of these pipelines must maintain or increase its rate
          base through projects that maintain or add to existing pipeline
          facilities or increase its rate of return.

     -    Conflicts of interest may arise between our general partners and their
          affiliates on one hand, and us on the other hand. As a result of these
          conflicts, the general partners may favor their own interests and the
          interests of their affiliates over the interests of our limited
          partners.

     -    We face competition from third parties in our natural gas
          transportation, gathering and processing businesses. See Item 1.
          "Business - Interstate Pipeline Competition" and "Business -
          Interstate Pipelines-Future Demand and Competition."

     -    Our operations are subject to federal and state agencies for
          environmental protection and operational safety. We may incur
          substantial costs and liabilities in the future as a result of
          stricter environmental and safety laws, regulations and enforcement
          policies. See Item 1. "Business - Environmental and Safety Matters."

     -    Northern Border Pipeline expects to seek rate recovery of its costs
          associated with the settlement of pipeline right-of-way lease and
          taxation issues with the Fort Peck Tribes. If Northern Border Pipeline
          is unable to recover these settlement costs in rates, it will be
          required to expense costs previously deferred as regulatory assets.
          See Item 3. "Legal Proceedings."

     -    Black Mesa's contract to transport coal slurry terminates in December
          2005. If Black Mesa is unable to extend or enter into a new
          arrangement for transportation of coal slurry, Black Mesa could incur
          costs and expenses for employee related matters, a write-off of
          recorded goodwill and removal of certain facilities. See Item 1.
          "Business - Coal Slurry Pipeline" and "Overview" above.

     -    Part of our business strategy is to expand existing assets and acquire
          additional assets and businesses that will allow us to increase our
          cash flow and distributions to unitholders. Unexpected costs or
          challenges may arise whenever we acquire new assets or businesses.
          Successful acquisitions require management and other personnel to
          devote significant amounts of time to new businesses or integrating
          the acquired assets with existing businesses.


                                       51
<PAGE>
     -    Our ability to maintain and/or expand our midstream gas gathering
          business will depend in large part on the pace of drilling and
          production activity in the Powder River, Wind River and Williston
          Basins. Drilling and production activity will be impacted by a number
          of factors beyond our control, including demand for and prices of
          natural gas and refinery grade crude oil, producer response to the
          EIS, reserve performance, the ability of producers to obtain necessary
          permits and capacity constraints on natural gas transmission pipelines
          that transport gas from the producing areas. See Item 1. "Business -
          Natural Gas Gathering and Processing Segment - Future Demand and
          Competition."

     -    Our financial performance will depend on our ability to successfully
          manage business operations to further reduce operating expenditures
          and volume and capital recovery risks in the Powder River Basin
          operations.

     -    Initiatives by states to regulate the rates that we charge for our
          gathering and processing of natural gas and/or to assess taxes on
          certain aspects of our gas gathering and processing and interstate
          pipeline businesses may adversely impact us.

     -    The impact of changing quality of natural gas received into our
          gathering and processing facilities may adversely affect our revenues
          and operations. In particular, the energy content of our gathered
          Powder River Basin production during 2004 was approximately 940
          Btus/cf. Most natural gas quality standards of interstate pipelines
          require a minimum of 950 Btus/cf. If we are unable to blend customers'
          gas, additional treatment may be necessary to avoid curtailment of
          certain volumes.

     -    Although our business strategy is to pursue fee-based and fixed-rate
          contracts, some of our gas processing facilities are subject to
          certain contracts that give us quantities of natural gas liquids and
          residue gas as payment of our processing services. The income and cash
          flow from these contracts will be impacted directly by changes in
          these commodity prices. See Item 7A. "Quantitative and Qualitative
          Disclosures About Market Risk" below.

     -    We may need new capital to finance future acquisitions and expansions.
          If our access to capital is limited, this will impair our ability to
          execute our growth strategy. As we acquire new businesses and make
          additional investments in existing businesses, we may need to increase
          borrowings and issue additional equity in order to maintain an
          appropriate capital structure. This may be dilutive to our unitholders
          and impact the market value of our common units. See "Liquidity and
          Capital Resources - Debt and Credit Facilities and Issuance of Common
          Units" above.

     -    Our indentures contain provisions that would require us to offer to
          repurchase our Senior Notes if Moodys or Standard & Poor's rating
          services rate our notes below investment grade. See "Liquidity and
          Capital Resources-Debt and Credit Facilities and Issuance of Common
          Units" above.


                                       52
<PAGE>
     -    We may be adversely impacted by the potential enactment of legislation
          in various states to modify existing provisions for income tax
          withholding on partners' distributions.

     -    Under current law, we are treated as a partnership for federal income
          tax purposes and do not pay any income tax at the entity level. In
          order to qualify for this treatment, we must derive more than 90% of
          our annual gross income from specified investments and activities.
          While we believe that we currently do qualify and intend to meet this
          income requirement, if we should fail, we would be treated as if we
          were a newly formed corporation and the income we generate from the
          date of such failure would be subject to corporate income tax. Because
          the tax would be imposed on us, the cash available for distribution to
          our unitholders would be substantially reduced. In addition, the
          entire amount of cash received by each unitholder would generally be
          taxed as a corporate dividend when received.

     -    In addition, because of widespread state budget deficits, several
          states are evaluating ways to subject partnerships to entity-level
          taxation through the imposition of state income, use, franchise or
          other forms of taxation. If any state were to impose a tax upon us as
          an entity, the cash available to pay distributions would be reduced.
          The partnership agreement provides that, if a law is enacted or
          existing law is modified or interpreted in a manner that subjects us
          to taxation as a corporation or otherwise subjects us to entity-level
          taxation for federal, state or local income tax purposes, then the
          minimum quarterly distribution and the target distribution levels will
          be decreased to reflect that impact on us.

     Additional risks and uncertainties not currently known to us, or risks that
we currently deem immaterial may impair our business operations. Any of the risk
factors described above could significantly and adversely impair our operating
results.

NEW ACCOUNTING PRONOUNCEMENTS

     The FASB issued SFAS No. 153, "Exchanges of Nonmonetary Assets" in December
2004. See Note 15 - Notes to Consolidated Financial Statements for a discussion
of this new accounting pronouncement.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.

     We may be exposed to market risk through changes in commodity prices and
interest rates as discussed below. A control environment has been established
which includes policies and procedures for risk assessment and the approval,
reporting and monitoring of financial instrument activities.

     We have utilized and expect to continue to utilize financial instruments in
the management of interest rate risks and our natural gas and natural gas
liquids marketing activities to achieve a more predictable cash flow by reducing
our exposure to interest rate and price fluctuations. We do not use these
instruments for trading purposes.

     INTEREST RATE RISK


                                       53
<PAGE>
     Our interest rate exposure results from variable rate borrowings from
commercial banks. To mitigate potential fluctuations in interest rates, we
attempt to maintain a significant portion of our consolidated debt portfolio in
fixed rate debt. We also use interest rate swaps as a means to manage interest
expense by converting a portion of fixed rate debt to variable rate debt to take
advantage of declining interest rates. At December 31, 2004, we had $341.0
million of variable rate debt outstanding, $150.0 million of which was
previously fixed rate debt that had been converted to variable rate debt through
the use of interest rate swaps. As of December 31, 2004, approximately 74% of
our debt portfolio was in fixed rate debt. See Notes 8 and 9 - Notes to
Consolidated Financial Statements.

     If average interest rates change by one percent compared to rates in effect
as of December 31, 2004, consolidated annual interest expense would change by
approximately $3.4 million. This amount has been determined by considering the
impact of the hypothetical interest rates on our variable rate borrowings
outstanding as of December 31, 2004.

     COMMODITY PRICE RISK

     Bear Paw Energy is subject to certain contracts that give it quantities of
natural gas and natural gas liquids as partial consideration for processing
services. The income and cash flows from these contracts will be impacted by
changes in prices for these commodities. Considering the effects of any hedging,
for each $0.10 per million British thermal unit change in natural gas prices or
for each $0.01 per gallon change in natural gas liquid prices, our annual net
income would change by approximately $0.3 million. This amount has been
determined by considering the impact of the hypothetical commodity prices on our
projected gathering and processing volumes for 2005. The sensitivity could be
impacted by changes to our projected throughput volumes. We have hedged
approximately 42% of our commodity price risk in 2005.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.

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

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

     None.

ITEM 9A. CONTROLS AND PROCEDURES.

     CONCLUSION REGARDING THE EFFECTIVENESS OF DISCLOSURE CONTROLS AND
PROCEDURES

     The Partnership's principal executive officer and principal financial
officer have evaluated the effectiveness of the Partnership's "disclosure
controls and procedures," (as such term is defined in Exchange Act Rule
13a-15(e) or 15d-15(e)) as of the end of the period covered by this report.
Based upon their evaluation, the principal executive officer and principal
financial officer concluded that the Partnership's disclosure controls and
procedures are effective.


                                       54
<PAGE>
MANAGEMENT'S ANNUAL REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

     The Partnership's principal executive officer and principal financial
officer are responsible for establishing and maintaining adequate internal
control over financial reporting for the Partnership. The Partnership's internal
control system was designed to provide reasonable assurance to the Partnership's
management and members of the Partnership's Policy Committee and Audit Committee
regarding the fair presentation of published financial statements. All internal
control systems, no matter how well designed, have inherent limitations.
Therefore, even those systems determined to be effective can provide only
reasonable assurance with respect to financial statement preparation and
presentation.

     The Partnership's management assessed the effectiveness of the
Partnership's internal control over financial reporting as of December 31, 2004.
In making this assessment, it used the criteria set forth by the Committee of
Sponsoring Organizations of the Treadway Commission ("COSO") in Internal
Control-Integrated Framework. Based on the assessment, the Partnership's
management believes that, as of December 31, 2004, the Partnership's internal
control over financial reporting is effective based on those criteria.

     The Partnership's independent registered public accounting firm has issued
an attestation report on management's assessment of the Partnership's internal
control over financial reporting. This report appears in the Report of
Independent Registered Public Accounting Firm below.


/s/ WILLIAM R. CORDES
----------------------------------------
William R. Cordes
Chief Executive Officer


/s/ JERRY L. PETERS
----------------------------------------
Jerry L. Peters
Chief Financial and Accounting Officer


                                       55
<PAGE>
             Report of Independent Registered Public Accounting Firm

Northern Border Partners, L.P.:

We have audited management's assessment, included in the accompanying
Management's Report on Internal Control over Financial Reporting, that Northern
Border Partners, L.P. maintained effective internal control over financial
reporting as of December 31, 2004, based on criteria established in Internal
Control--Integrated Framework, issued by the Committee of Sponsoring
Organizations of the Treadway Commission (COSO). The Company's management is
responsible for maintaining effective internal control over financial reporting
and for its assessment of the effectiveness of internal control over financial
reporting. Our responsibility is to express an opinion on management's
assessment and an opinion on the effectiveness of the Company's internal control
over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company
Accounting Oversight Board (United States). Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether effective
internal control over financial reporting was maintained in all material
respects. Our audit included obtaining an understanding of internal control over
financial reporting, evaluating management's assessment, testing and evaluating
the design and operating effectiveness of internal control, and performing such
other procedures as we considered necessary in the circumstances. We believe
that our audit provides a reasonable basis for our opinion.

A company's internal control over financial reporting is a process designed to
provide reasonable assurance regarding the reliability of financial reporting
and the preparation of financial statements for external purposes in accordance
with generally accepted accounting principles. A company's internal control over
financial reporting includes those policies and procedures that (1) pertain to
the maintenance of records that, in reasonable detail, accurately and fairly
reflect the transactions and dispositions of the assets of the company; (2)
provide reasonable assurance that transactions are recorded as necessary to
permit preparation of financial statements in accordance with generally accepted
accounting principles and that receipts and expenditures of the company are
being made only in accordance with authorizations of management and directors of
the company; and (3) provide reasonable assurance regarding prevention or timely
detection of unauthorized acquisition, use, or disposition of the company's
assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting
may not prevent or detect misstatements. Also, projections of any evaluation of
effectiveness to future periods are subject to the risk that controls may become
inadequate because of changes in conditions, or that the degree of compliance
with the policies or procedures may deteriorate.


                                       56
<PAGE>
In our opinion, management's assessment that Northern Border Partners, L.P.
maintained effective internal control over financial reporting as of December
31, 2004, is fairly stated, in all material respects, based on COSO. Also, in
our opinion, Northern Border Partners, L.P. maintained, in all material
respects, effective internal control over financial reporting as of December 31,
2004, based on COSO.

We also have audited, in accordance with the standards of the Public Company
Accounting Oversight Board (United States), the consolidated balance sheets of
Northern Border Partners, L.P. and subsidiaries as of December 31, 2004 and
2003, and the related consolidated statements of income, comprehensive income,
cash flows, and changes in partners' equity, for each of the years in the
three-year period ended December 31, 2004, and our report dated March 2, 2005,
expressed an unqualified opinion on those consolidated financial statements.


/s/ KPMG LLP

Omaha, Nebraska
March 2, 2005

CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING.

     There were no changes in our internal control over financial reporting that
occurred during our last fiscal quarter that have materially affected, or are
reasonably likely to materially affect, our internal control over financial
reporting. However, in the quarter ending December 31, 2004, the payroll system
used for the employees of Northern Plains and NBP Services, was transitioned to
ONEOK's payroll system.

     The Partnership relied on certain systems owned or services provided by
Enron and CrossCountry that support our financial accounting and reporting.
Since the sale of Northern Plains and NBP Services on November 17, 2004, the
Partnership has begun the transition of these systems to systems owned by us or
provided by ONEOK.

     The Partnership's transition from the Enron and CrossCountry systems and
services should be completed in May 2005. This activity has and will cause
changes to the Partnership's internal control over financial reporting.

ITEM 9B. OTHER INFORMATION

     The following information is being provided in lieu of filing an Item 5.02
Form 8-K.

     On March 8, 2005, Gil J. Van Lunsen was appointed by the Partnership Policy
Committee as a member of the Audit Committee, effective upon Mr. Whitty's
retirement. Mr. Van Lunsen replaces Mr. Whitty who is retiring from the Audit
Committee effective March 15, 2005. See Item 10. "Partnership Management" for
biographical and other information regarding Mr. Van Lunsen and our Audit
Committee.


                                       57
<PAGE>
                                    PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.

     We are managed under the direction of the Partnership Policy Committee
consisting of three members, each of which has been appointed by one of our
general partners. The members appointed by Northern Plains, Pan Border and
Northwest Border have 50%, 32.5% and 17.5%, respectively, of the voting power.

     We also have an audit committee comprised of individuals who are neither
officers nor employees of any general partner nor any affiliate of a general
partner, to serve as a committee of the Partnership (the "Audit Committee"). The
Audit Committee members are not members of, and do not vote on matters,
submitted to the Partnership Policy Committee. The Partnership Policy Committee
has delegated to the Audit Committee oversight responsibility with respect to
the integrity of our financial statements, the performance of our internal audit
function, the independent auditor's qualification and independence and
compliance with legal and regulatory requirements. The Audit Committee directly
appoints, retains, evaluates and may terminate our independent auditors. The
Audit Committee reviews the annual financial statements and resolves, if
necessary, any significant disputes between management and the independent
auditor that arise in connection with the preparation of the financial
statements. The Audit Committee also has the authority to review, at the request
of a general partner, specific matters as to which a general partner believes
there may be a conflict of interest in order to determine if the resolution of
such conflict proposed by the Partnership Policy Committee is fair and
reasonable to us. The Audit Committee has all other responsibilities required by
the New York Listing Standards and SEC rules.

     Because we are a limited partnership, the listing standards of the New York
Stock Exchange do not require us to have a majority of independent directors or
a nominating/corporate governance or compensation committee. None of our Policy
Committee Members are independent.

     As is commonly the case with publicly-traded partnerships, we do not
directly employ any of the persons responsible for managing or operating the
Partnership or for providing it with services relating to its day-to-day
business affairs. We have entered into an Administrative Services Agreement with
NBP Services, a wholly-owned subsidiary of ONEOK, pursuant to which NBP Services
provides tax, accounting, legal, cash management, investor relations, operating
and other services for the Partnership. NBP Services has approximately 130
employees. It also uses employees of its affiliates who have duties and
responsibilities other than those relating to the Administrative Services
Agreement. Also, Northern Plains, one of our general partners and a wholly-owned
subsidiary of ONEOK, provides operating services to our interstate pipelines
pursuant to operating agreements. Northern Plains employs approximately 310
individuals located at our headquarters in Omaha, Nebraska, and at various
locations near the pipelines and also utilizes employees and information
technology systems of its affiliates to provide its services. In consideration
for their services under the Administrative Services Agreement and the operating
agreements, NBP Services and Northern Plains are reimbursed for their direct and
indirect costs and expenses, including an allocated portion of employee time and
overhead costs. See Item 13. "Certain Relationships and Related Transactions."


                                       58
<PAGE>
     Set forth below is certain information concerning the members of the
Partnership Policy Committee, our representatives on the Northern Border
Management Committee and the persons designated by the Partnership Policy
Committee as our executive officers and as Audit Committee members. All members
of the Partnership Policy Committee and our representatives on the Northern
Border Management Committee serve at the discretion of the general partner that
appointed them. The persons designated as executive officers serve in that
capacity at the discretion of the Partnership Policy Committee. The members of
the Partnership Policy Committee receive no management fee or other remuneration
for serving on this committee. The Audit Committee members are elected, and may
be removed, by the Partnership Policy Committee. Daniel P. Whitty, who has been
a member of the audit committee since 1993, has tendered his resignation to be
effective March 15, 2005. On March 8, 2005, the Partnership Policy Committee
appointed Gil J. Van Lunsen to be a member of the Audit Committee effective
March 15, 2005. The Chairman of the Audit Committee receives an annual fee of
$50,000 and other Audit Committee members receive an annual fee of $40,000 and
each is paid $1,500 for each meeting attended.

     As noted above, the members of our Partnership Policy Committee and Audit
Committee are not elected by unitholders. Accordingly, we do not have a
procedure by which security holders may recommend nominees to our Partnership
Policy Committee or Audit Committee.

     Effective with the purchase and sale of Northern Plains and Pan Border on
November 17, 2004, Stanley C. Horton resigned as a member of the Partnership
Policy Committee and as a member of the Management Committee of Northern Border
Pipeline Company. Effective November 17, 2004, David L. Kyle was appointed by
Northern Plains as its member and the Chairman of the Partnership Policy
Committee. Mr. Kyle has also been appointed by Pan Border as its member to the
Management Committee of Northern Border Pipeline Company. There are no family
relationships between any of our executive officers or members of the
Partnership Policy Committee and the Audit Committee.

<TABLE>
<CAPTION>
              NAME                AGE                  POSITIONS
              ----                ---                  ---------
<S>                               <C>   <C>
Executive Officers:
      William R. Cordes            56   Chief Executive Officer
      Jerry L. Peters              47   Chief Financial and Accounting Officer

Members of Partnership Policy
   Committee and Partnership's
   representatives on Northern
   Border Management Committee:

      David L. Kyle                52   Chairman
      William R. Cordes            56   Member
      Paul E. Miller               46   Member

Members of Audit Committee:
      Gerald B. Smith              54   Chairman
      Daniel P. Whitty             73   Member
      Gary N. Petersen             53   Member
      Gil J. Van Lunsen            62   Nominee
</TABLE>


                                       59
<PAGE>
     David L. Kyle was named Chairman of the Policy Committee in November 2004.
Mr. Kyle is Chairman and Chief Executive Officer of Northern Plains, Pan Border
and NBP Services. Besides Chairman of the Policy Committee of Northern Border
Partners, Mr. Kyle is the Chairman of the Board, President, and Chief Executive
Officer of ONEOK, Inc. He was employed by Oklahoma Natural Gas Company in 1974
as an engineer trainee. He served in a number of positions prior to being
elected Vice President of Gas Supply September 1, 1986, and Executive Vice
President May 17, 1990 of Oklahoma Natural Gas Company. He was elected President
of Oklahoma Natural Gas Company on September 1, 1994. He was elected President
of ONEOK, Inc. effective September 1, 1997, and was elected Chairman of the
Board and appointed the Chief Executive Officer of ONEOK, Inc. August 28, 2000.
Mr. Kyle is a member of the boards of directors of Bank of Oklahoma Financial
Corporation and Blue Cross and Blue Shield of Oklahoma.

     William R. Cordes was named Chief Executive Officer of the Partnership and
appointed to the Partnership Policy Committee in October 2000. He served as
Chairman of the Partnership Policy Committee from October 2000 until November
17, 2004. Mr. Cordes is the President of Northern Plains, Pan Border and NBP
Services, ONEOK subsidiaries, having been appointed to that position on October
1, 2000 for Northern Plains and Pan Border and November 17, 2004 for NBP
Services. Mr. Cordes was named Chairman of the Northern Border Management
Committee October 1, 2000. In 1970, he started his career with Northern Natural
Gas Company, an Enron subsidiary until February 2002, where he worked in several
management positions. From June of 1993 until September of 2000, he was
President of Northern Natural Gas Company and from May of 1996 until September
of 2000, he was also President of Transwestern Pipeline, a subsidiary of Enron.

     Paul E. Miller was designated by TransCanada as its member on the
Partnership Policy Committee in September 2003. Mr. Miller is also a
representative on the Northern Border Management Committee. Additionally, Mr.
Miller serves as Director Corporate Development of TransCanada, a position he
has held since February 2003. From July 1998 to January 2003, Mr. Miller was
Director Finance of TransCanada. Prior to July 1998, Mr. Miller was Manager,
Finance of TransCanada.

     Jerry L. Peters was named Chief Financial and Accounting Officer in July
1994. Mr. Peters has held several management positions with Northern Plains
since 1985 and was elected Vice President of Finance in July 1994, and Treasurer
in October 1998. Mr. Peters was also elected Vice President of Finance for NBP
Services in November 2004. Mr. Peters was also Vice President, Finance of the
following former affiliates of Northern Plains: Florida Gas Transmission Company
from February 2001 to May 2002; Transportation Trading Services Company from
September 2001 to July 2002; Citrus Corp. from October 2001 to July 2002; and
Transwestern Pipeline Company from November 2001 to May 2002. Prior to joining
Northern Plains in 1985, Mr. Peters was employed as a Certified Public
Accountant by KPMG LLP.

     Gerald B. Smith was appointed to the Audit Committee in April 1994. He is
Chairman and Chief Executive Officer and co-founder of Smith, Graham & Company
Investment Advisors, a global investment management firm, which was founded in
1990. He is a member of the Board of Trustees of Charles Schwab Family of Fund;
and a director and member of the audit committee of Cooper Industries. He is a
former director of the Fund Management Board of Robeco Group, Rorento N.V.
(Netherlands).


                                       60
<PAGE>
     Daniel P. Whitty was appointed to the Audit Committee in December 1993. Mr.
Whitty is an independent financial consultant. He has served as a member of the
Board of Directors of Methodist Retirement Communities Inc., and a Trustee of
the Methodist Retirement Trust. Mr. Whitty was a partner at Arthur Andersen LLP
("Andersen") until his retirement on January 31, 1988. At Andersen, he had firm
wide responsibility for the natural gas transmission industry for many years.
Until his resignation in December 2001, Mr. Whitty served as a director of EOTT
Energy Corp., a subsidiary of Enron and the general partner of EOTT Energy
Partners, L.P. EOTT Energy Corp. filed for bankruptcy protection on October 21,
2002.

     Gary N. Petersen was appointed to the Audit Committee on March 19, 2002.
Since 1998, he has provided consulting services related to strategic and
financial planning. Additionally, he is currently the President of Endres
Processing LLC. From 1977 to 1998, Mr. Petersen was employed by Reliant
Energy-Minnegasco. He served as Reliant Energy-Minnegasco's President and Chief
Operating Officer from 1991 to 1998. Prior to his employment at Minnegasco, he
was a senior auditor with Andersen. He currently serves on the boards of the
YMCA of Metropolitan Minneapolis and the Dunwoody Institute.

     Gil J. Van Lunsen was appointed to the Audit Committee on March 8, 2005.
Prior to his retirement in June 2000, Mr. Van Lunsen was a Managing Partner of
KPMG LLP and led the firm's Tulsa, Oklahoma office. He began his career with
KPMG in 1968. He is currently a director and audit committee chairman of Array
Biopharma in Boulder, Colorado and Sirenza Microdevices in Broomfield, Colorado.

     At the meeting of the Partnership Policy Committee on March 3, 2005, the
following persons were deemed to be officers of the Partnership for purposes of
Section 16 of the Securities Exchange Act of 1934. Some of these individuals are
officers at certain subsidiaries of the Partnership:

<TABLE>
<CAPTION>
        NAME          AGE                POSITIONS
        ----          ---                ---------
<S>                   <C>   <C>
Christopher R Skoog    41   Executive Vice President

Paul F. Miller         38   Vice President and General
                            Manager for Northern Border
                            Pipeline

Michel E. Nelson       57   Vice President, Operations,
                            Interstate Pipelines

Raymond D. Neppl       60   Vice President, Regulatory Affairs
                            and Market Services, Interstate
                            Pipelines

Pierce H. Norton       45   President, Bear Paw Energy

Janet K. Place         55   Vice President, General Counsel
                            and Secretary

Fred G. Rimington      54   Vice President, Administration and
                            President of Black Mesa Pipeline

Gaye Lynn Schaffart    45   Vice President and General
                            Manager, Interstates
</TABLE>


                                       61
<PAGE>
     Christopher R Skoog was appointed executive vice president of Northern
Plains and NBP Services effective February 1, 2005. Mr. Skoog is responsible for
all commercial, operational and regulatory functions of the Partnership's
natural gas businesses and will coordinate the Partnership's business
development initiatives. From 1999 to January 31, 2005, Mr. Skoog served as
President of ONEOK Energy Services Company, II. From 1995 to 1999, he was Vice
President, ONEOK Gas Marketing Company.

     Paul F. Miller is Vice President and General Manager for Northern Border
Pipeline of Northern Plains, having been elected in January 2005. From March
2002 until January 2005, Mr. Miller was Vice President of Marketing for Northern
Plains. Mr. Miller was previously Account Executive, Marketing from December
1998 until August 2000, when he was promoted to Director, Marketing. Mr. Miller
joined Northern Plains in 1990.

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

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

     Pierce H. Norton is President of Bear Paw Energy, a subsidiary of the
Partnership, having been appointed in February 2003. Mr. Norton is Vice
President and General Manager for midstream businesses for NBP Services, having
been appointed in 2003. Mr. Norton, from 2001 to 2003 served as Vice President,
Business Development for Bear Paw. Prior to the Partnership's purchase of Bear
Paw, Mr. Norton was Vice President--Business Development for Bear Paw Energy and
its predecessor from 1999 to 2001 where he was responsible for managing
contracts and asset acquisitions.

     Janet K. Place is Vice President, General Counsel and Secretary of Northern
Plains, having been elected in August 1994 as Vice President and November 2004
as Secretary. She was also elected Vice President, General Counsel and Secretary
of NBP Services in November 2004. In 1993, Ms. Place was named General Counsel.
Ms. Place joined Northern Plains in 1980 as an Attorney.

     Gaye Lynn Schaffart is Vice President and General Manager, Interstates of
Northern Plains, having been elected February 2005. Ms. Schaffart was previously
Director, Business Development and Planning from 1993 to 2004 when she was
promoted to Vice President, Business Development and Strategic Planning in March
2004. Ms. Schaffart joined Northern Plains in 1982.

     Fred G. Rimington is Vice President, Administration of Northern Plains and
NBP Services, having been elected in February 2005. He is also the President of
Black Mesa Pipeline, Inc., having been appointed in January


                                       62
<PAGE>
2000. Mr. Rimington was Director, Business Development from 1994 to 1999 for
Northern Plains. Mr. Rimington joined Northern Plains in 1980.

AUDIT COMMITTEE MATTERS

     INDEPENDENCE AND FINANCIAL EXPERT

     The Partnership has a separately-designated standing Audit Committee in
accordance with Section 3(a)(58)(A) of the Exchange Act. The members of our
Audit Committee are Mr. Gerald B. Smith, Daniel P. Whitty and Gary N. Petersen.
Additionally, Mr. Gil J. Van Lunsen was appointed to the Audit Committee on
March 8, 2005 and replaces Mr. Whitty who is retiring on March 15, 2005. The
Partnership's guidelines for determining independence are included in the
Partnership's Governance Guidelines, which, along with the Audit Committee
charter, is available on the "Governance" section of the Partnership's website
at www.northernborderpartners.com. Copies of the Governance Guidelines as well
as the Audit Committee charter are available in print to any security holder who
requests them by sending a written request to Investor Relations Department,
Northern Border Partners, L.P., P.O. Box 542500, Omaha, NE 68154-8500. Our
Governance Guidelines contain independence standards for our Audit Committee
members. The Governance Guidelines provide that the members of the Audit
Committee shall at all times qualify as independent members under the
independence standards of the New York Stock Exchange, including Section
10A(m)(3) of the Securities Exchange Act of 1934, the rules and regulations of
the Securities and Exchange Commission and other applicable laws. At least
annually the Partnership Policy Committee reviews the relationships that each
Audit Committee member has with the Partnership to affirmatively determine the
independence of each member. The Policy Committee has affirmatively determined
that Messrs. Petersen, Smith, Whitty, and Mr. Van Lunsen meet the standards for
independence set forth in the Governance Guidelines and are independent from
management.

     Annually, the Partnership Policy Committee determines the financial
expertise of the members of the audit committee. On March 3, 2005, the Policy
Committee determined that Messrs. Petersen, Smith and Whitty were "audit
committee financial experts" and each is independent, as noted above.

     SEPARATE SESSIONS OF NON-MANAGEMENT COMMITTEE MEMBERS

     The Partnership Policy Committee has documented its governance practices in
the Governance Guidelines, a copy of which is available on the "Governance"
section of the Partnership's website at www.northernborderpartners.com. The
Chairman of the Audit Committee, Mr. Gerald Smith, presides at these sessions of
non-management committee members, which include the members of the Audit
Committee and Messrs. Kyle and Miller of the Partnership Policy Committee. The
first meeting occurred at the November 2, 2004 meeting. In the future, meetings
of the non-management committee members are scheduled quarterly or as requested
by any non-management committee member.

     Interested parties desiring to communicate with the presiding member, the
non-management members of the Partnership Policy Committee as a group or the
Audit Committee members as a group regarding the Partnership may directly
contact such member(s) by utilizing the Partnership Ethics and Compliance
Hotline which is posted on the "Governance-Contact Information" section of our
website at www.northernborderpartners.com.

     SERVICE ON OTHER AUDIT COMMITTEES

     Mr. Smith, the Chairman of our Audit Committee, and Mr. Van Lunsen, our
newly appointed Audit Committee member, also serve on the audit committees of
two other public companies. The Partnership Policy Committee has determined


                                       63
<PAGE>
that Mr. Smith and Mr. Van Lunsen's service on these other audit committees does
not impair their ability to effectively serve on the Partnership's Audit
Committee.

SECTION 16(a) BENEFICIAL OWNERSHIP REPORTING COMPLIANCE

     Section 16(a) of the Securities Exchange Act of 1934 requires executive
officers, members of the Partnership Policy Committee and persons who own more
than ten percent of a registered class of the equity securities issued by us to
file reports of ownership and changes in ownership with the SEC and the New York
Stock Exchange and to furnish the Partnership with copies of all Section 16(a)
forms they file. Based solely on our review of the copies of such reports
received by us, or written representations from certain reporting persons that
no Form 5's were required for those persons, we believe that during 2004 our
reporting persons complied with all applicable filing requirements in a timely
manner.

CODE OF ETHICS AND CODE OF CONDUCT

     We have adopted an Accounting and Financial Reporting Code of Ethics
applicable to the Partnership's chief executive officer and chief financial and
accounting officer. A copy of the Accounting and Financial Reporting Code of
Ethics is posted on the "Governance" section of our website,
www.northernborderpartners.com, and we intend to post on our website any
amendments to, or waivers from, any provision of our Accounting and Financial
Reporting Code of Ethics that applies to our chief executive officer and chief
financial and accounting officer within four business days following such
amendment or waiver.

     We have also adopted a Code of Conduct applicable to the members of the
Partnership Policy Committee and Audit Committee, our officers and the deemed
executive officers and the employees of Northern Plains and NBP Services. The
Code of Conduct is intended to meet the requirements of a "code of business
conduct and ethics" under Section 303A.10 of the New York Stock Exchange Listed
Company Manual. A copy of the Code of Conduct is posted on the "Governance"
section of our website at www.northernborderpartners.com and is available in
print to any security holder who requests it by writing to Investor Relations
Department, Northern Border Partners, L.P., P.O. Box 542500, Omaha, NE
68154-8500. We intend to promptly post on our website any amendments to, or
waivers from (including any implicit waivers), any provision of our Code of
Conduct in accordance with the rules of the New York Stock Exchange ("NYSE").

CERTIFICATION

     Certifications

     As required by New York Stock Exchange ("NYSE") listing standards, William
R. Cordes, our Chief Executive Officer, certified on November 15, 2004 that he
was not aware of any violation by the Partnership of NYSE corporate governance
listing standards. The certifications required by Section 302 of the
Sarbanes-Oxley Act are attached as exhibits 31.1 and 31.2 to this Annual Report
on Form 10-K.


                                       64
<PAGE>
ITEM 11. EXECUTIVE COMPENSATION.

     We are managed by a three member policy committee, with one member
appointed by each general partner. The Partnership Policy Committee has
designated two executive officers who serve as officers of the Partnership at
the discretion of the Partnership Policy Committee. In addition, certain
officers of the general partners and certain officers of subsidiaries of the
partnership were deemed to be executive officers of the Partnership by the
Partnership Policy Committee.

     The following table sets forth a summary of compensation paid for the last
three years of the chief executive officer of the Partnership and the other four
most highly compensated executive officers of the Partnership during 2004, which
we collectively refer to as the "Named Officers." For the years 2002, 2003 and
through November 17, 2004, compensation plans were administered by Enron.
Beginning November 18, 2004, compensation plans are administered by ONEOK.

                           SUMMARY COMPENSATION TABLE

<TABLE>
<CAPTION>
                                                                               Long-Term Compensation
                                              Annual Compensation              ----------------------     All Other
                                  ------------------------------------------         Restricted         Compensation
    Name & Principal                                          Other Annual          Stock Awards        ------------
        Position           Year   Salary $   Bonus $ (1)    Compensation (2)         ($) (3) (4)           ($) (5)
    ----------------       ----   --------   ------------   ----------------        ------------           -------
<S>                        <C>    <C>        <C>            <C>                     <C>                 <C>
William R. Cordes          2004   $325,000     $175,000            --                 $     --             $ 4,908
Chief Executive Officer    2003   $324,583     $200,000            --                 $ 99,972             $ 3,000
                           2002   $319,333     $240,000            --                 $100,051             $ 1,031

Jerry L. Peters            2004   $171,380     $110,000            --                       --             $ 5,658
Chief Financial and        2003   $163,324     $107,500            --                       --             $76,386
Accounting Officer         2002   $159,285     $110,000            --                       --             $23,950

Janet K. Place             2004   $182,552     $115,000            --                       --             $ 8,675
Vice President & General   2003   $177,592     $110,000            --                       --             $ 6,233
Counsel and Secretary      2002   $171,500     $110,000            --                       --             $ 7,266
NPNG

Pierce H. Norton           2004   $183,834     $105,000            --                       --             $ 2,520
Vice President & General   2003   $178,842     $ 80,000            --                       --             $ 1,295
Manager - NBP Services     2002   $166,688     $ 57,250            --                       --             $ 1,580
Corp

Paul F. Miller             2004   $153,298     $118,000            --                       --             $ 5,335
Vice President & General   2003   $148,958     $111,000            --                       --             $90,325
Manager for Northern       2002   $139,850     $ 92,000            --                       --             $ 4,721
Border Pipeline
</TABLE>

(1)  For bonus amounts for 2004, there was an early payout of an amount equal to
     10/12ths in October 2004 and the remaining 2/12s was paid in March 2005.

(2)  No Named Officer received perquisites or other personal benefits,
     securities or property in an amount in excess of the lesser of either
     $50,000 or 10% of the total of salary and bonus reported for such officer
     in the two preceding columns.

(3)  The aggregate total of shares in unreleased Enron restricted stock holdings
     and their values as of December 31, 2003, for each of the Named Officers
     is: Mr. Cordes, 4,295 shares valued at $0, Mr. Peters, 1,701 shares valued
     at $0 and Ms. Place, 1,832 at $0. Dividend equivalents for all restricted
     stock awards accrue from date of grant and are paid upon vesting. Any
     dividends on Enron Corp. stock accrued and unreleased as of the date of
     Enron Corp.'s filing for bankruptcy protection will only be released in
     accordance with applicable bankruptcy law.

(4)  Mr. Cordes' employment agreement, as executed in September 2001, provided
     for a grant of 882 Northern Border Phantom Units. On June 1, 2002 and 2003,
     grants of 697 and 669 Northern Border Phantom Units valued at $143.5456 and
     $149.4346 per unit,


                                       65
<PAGE>
     respectively, were made in accordance with his employment agreement. The
     phantom units vest on the fifth anniversary of the date of each grant.

(5)  The amounts shown include the matching contributions to employees' Enron
     Corp. Savings Plan and to the Thrift Plan for employees of ONEOK, and
     imputed income on life insurance benefits. For Mr. Cordes and Mr. Peters,
     the amount shown for 2004 was for matching contributions. For Ms. Place,
     the amount shown for 2004 for matching contributions was $6,050 and for
     imputed income was $2,625. For Mr. Norton, the amount shown for 2004 for
     matching contributions was $2,520. For Mr. Miller, the amount shown for
     matching contributions was $5,080 for 2004 and the amount for imputed
     income was $255. Mr. Peters' employment agreement, as executed in April
     2002, provided for a "stay" bonus in which $23,950 of the amount was paid
     six months following the implementation of the agreement. The remaining
     amount of $71,853 was paid in March 2003 upon completion of the term of the
     agreement. Mr. Miller's employment agreement, as executed in October 2002,
     provided for a "stay" bonus in which 25% was to be paid six months
     following the implementation of the agreement and the remainder upon
     completion of the term of the agreement. The entire bonus of $85,470 was
     distributed in 2003.

     For 1999, 2000 and 2001, employees of Northern Plains were able to elect to
receive Northern Border phantom units, Enron Corp. phantom stock, and/or Enron
Corp. stock options in lieu of all or a portion of an annual bonus payment. Mr.
Cordes, Mr. Peters, Ms. Place and Mr. Miller elected to receive Northern Border
phantom units under the Northern Border Phantom Unit Plan in lieu of a portion
of the cash bonus payment. As a result of this deferral, Mr. Cordes received
1,914 units in 2001; Mr. Peters received 1,532 units in 1999, 1,450 units in
2000 and 842 units in 2001; Ms. Place received 901 units in 1999 and 240 units
in 2001; and Mr. Miller received 137 units in 1999, 123 units in 2000 and 230
units in 2001. In each case, units will be released based upon the holding
period selected by the participant. For the release in January 2004, Mr. Peters
received 4,727 common units. For the release in January 2003, Ms. Place received
1,091 common units and for the release in 2004, she elected a redemption payment
in cash of $83,232.28. For the release in January 2002, Mr. Miller received 333
common units; for the release in 2003, he received 329 common units and for the
release in 2004, he elected a redemption payment in cash of $25,283.42.

     On January 20, 2005, the Board of Directors of ONEOK granted restricted
stock incentive units and performance share units to the named executive
officers as follows: Mr. Cordes, 6,000 restricted stock incentive units and
10,500 performance share units; Mr. Peters, 3,000 restricted stock incentive
units and 4,500 performance share units; Ms. Place 2,000 restricted stock
incentive units and 3,500 performance share units; Mr. Norton 2,500 restricted
stock incentive units and 4,000 performance share units; and Mr. Miller 2,500
restricted stock incentive units and 4,000 performance share units. The
restricted stock incentive units vest three years from the date of grant at
which time the grantee is entitled to receive two-thirds of the grant in shares
of ONEOK common stock and one-third of the grant in cash. The performance share
units granted vest three years from the date of grant at which time the holder
is entitled to receive a percentage (0% to 200%) of the performance shares
granted based on ONEOK's total shareholder return over the period January 20,
2005, to January 20, 2008, compared to the total shareholder return of a peer
group of 20 other companies, payable two-thirds of the grant in shares of ONEOK
common stock and one-third of the grant in cash.

STOCK OPTION GRANTS IN 2004

     Due to the bankruptcy filing by Enron on December 2, 2001, there were no
grants of stock options pursuant to Enron's stock plans to the Named


                                       66
<PAGE>
Officers reflected in the Summary Compensation Table. No stock appreciation
rights were granted during 2004.

AGGREGATED OPTION/SAR EXERCISES IN 2004 AND 2004 YEAR-END OPTION/SAR VALUES

     The following table sets forth information with respect to the Named
Officers concerning the exercise of Enron SARs and options during the last
fiscal year and unexercised Enron options and SARs held as of December 31, 2005:

<TABLE>
<CAPTION>
                                                  Number of Securities
                                                 Underlying Unexercised         Value of Unexercised
                                                    Options/SARs at          In-the-Money Options/SARs
                       Shares                      December 31, 2004           December 31, 2004 (1)
                     Acquired on     Value    ---------------------------   ---------------------------
       Name         Exercise (#)   Realized   Exercisable   Unexercisable   Exercisable   Unexercisable
       ----         ------------   --------   -----------   -------------   -----------   -------------
<S>                 <C>            <C>        <C>           <C>             <C>           <C>
William R. Cordes        --           $--       182,270          650            $--            $--
Jerry L. Peters          --           $--        62,850          305            $--            $--
Janet K. Place           --           $--        37,383          332            $--            $--
Pierce H. Norton         --           $--            --          525            $--            $--
Paul F. Miller           --           $--        20,684          218            $--            $--
</TABLE>

(1) Due to Enron's bankruptcy filing there is no dollar value assignable to
    Enron Corp. stock options.

TERMINATION AGREEMENT

     Effective January 5, 2005, ONEOK, Inc. entered into termination agreements
with Messrs. Cordes, Peters, Norton and Miller and Ms. Place.

     Each termination agreement has an initial term from January 5, 2005 until
January 1, 2007 and is automatically extended in one-year increments after the
expiration of the initial term unless ONEOK provides notice to the officer or
the officer provides notice to ONEOK at least 90 days before January 1 preceding
the initial or any subsequent termination date of the agreement that the party
providing notice does not wish to extend the term. If a "change in control" of
ONEOK occurs, the term of each termination agreement will not expire for at
least three years after the change in control.

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

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

     -    an acquisition of voting securities of ONEOK by any person that
          results in the person having beneficial ownership of 20% or more of


                                       67
<PAGE>
          the combined voting power of ONEOK's outstanding voting securities,
          other than an acquisition directly from ONEOK;

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

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

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

RETIREMENT PLANS-ENRON

     Enron maintains the Enron Corp. Cash Balance Plan (the "Cash Balance
Plan"), which is a noncontributory defined benefit pension plan to provide
retirement income for employees of Enron and its subsidiaries. Through December
31, 1994, participants in the Cash Balance Plan with five years or more of
service were entitled to retirement benefits in the form of an annuity based on
a formula that uses a percentage of final average pay and years of service. In
1995, Enron's Board of Directors adopted an amendment to and restatement of the
Cash Balance Plan changing the plan's name from the Enron Corp. Retirement Plan
to the Enron Corp. Cash Balance Plan. In connection with a change to the
retirement benefit formula, all employees became fully vested in retirement
benefits earned through December 31, 1994. The formula in place prior to January
1, 1995 was suspended and replaced with a benefit accrual in the form of a cash
balance of 5% of eligible annual base pay beginning January 1, 1996. Effective
January 1, 2003 Enron suspended future 5% benefit accruals under the Cash
Balance Plan. Each employee's accrued benefit will continue to be credited with
interest based on ten-year Treasury Bond yields.

     Enron maintained a noncontributory employee stock ownership plan ("ESOP"),
which was merged into the Enron Corp. Savings Plan effective August 30, 2002 and
covered all eligible employees. Allocations to individual employees' retirement
accounts within the ESOP offset a portion of benefits earned under the Cash
Balance Plan prior to December 31, 1994. December 31, 1993 was the final date on
which ESOP allocations were made to employees' retirement accounts.

     The following table sets forth the estimated annual benefits payable under
the Cash Balance Plan at normal retirement at age 65, assuming only interest
credits based on ten-year Treasury Bond yields and no future 5%


                                       68
<PAGE>
benefit accruals after January 1, 2003, with to the Named Officers under the
provisions of the foregoing retirement plans.

<TABLE>
<CAPTION>
                        ESTIMATED
              CURRENT    CREDITED      CURRENT        ESTIMATED
             CREDITED    YEARS OF   COMPENSATION   ANNUAL BENEFIT
             YEARS OF    SERVICE       COVERED      PAYABLE UPON
              SERVICE   AT AGE 65     BY PLANS       RETIREMENT
             --------   ---------   ------------   --------------
<S>          <C>        <C>         <C>            <C>
Mr. Cordes     34.4        34.4          $0            $73,979
Mr. Peters     19.1        19.1          $0            $22,933
Ms. Place      24.1        24.1          $0            $30,096
Mr. Norton      3.9         3.9          $0            $ 3,132
Mr. Miller     14.7        14.7          $0            $13,028
</TABLE>

NOTE: The estimated annual benefits payable are based on the straight life
annuity form without adjustment for any offset applicable to a participant's
retirement subaccount in Enron's ESOP.

PENSION PLAN-ONEOK

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

                               PENSION PLAN TABLE

<TABLE>
<CAPTION>
                                 YEARS OF SERVICE
               ----------------------------------------------------
REMUNERATION   15 YEARS   20 YEARS   25 YEARS   30 YEARS   35 YEARS
------------   --------   --------   --------   --------   --------
<S>            <C>        <C>        <C>        <C>        <C>
125,000        $ 33,091   $ 44,122   $ 55,152   $ 66,182   $ 77,213
150,000        $ 40,404   $ 53,872   $ 67,340   $ 80,807   $ 94,275
175,000        $ 47,716   $ 63,622   $ 79,527   $ 95,432   $111,338
200,000        $ 55,029   $ 73,372   $ 91,715   $110,057   $128,400
225,000        $ 62,341   $ 83,122   $103,902   $124,682   $145,463
250,000        $ 69,654   $ 92,872   $116,090   $139,307   $162,525
300,000        $ 84,279   $112,372   $140,465   $168,557   $196,650
400,000        $113,529   $151,372   $189,215   $227,057   $264,900
450,000        $128,154   $170,872   $213,590   $256,307   $299,025
500,000        $142,779   $190,372   $237,965   $285,557   $333,150
</TABLE>

     Benefits under the ONEOK retirement plan become vested and non-forfeitable
after completion of five years of continuous employment. A vested participant
receives the monthly retirement benefit at normal retirement age under the
retirement plan, unless an early retirement benefit is elected under the plan,
in which case the retirement benefit is actuarially reduced for early
commencement. Benefits are calculated at retirement date based on a
participant's credited service, limited to a maximum of 35 years, and final
average earnings. Credited years of service under this plan for the named
executive officers as of December 31, 2004 is 1/12 years.

     For purposes of the table, the annual social security covered compensation
benefit $46,284 was used in the excess benefit calculation.


                                       69
<PAGE>
Benefits payable under ONEOK's retirement plan are not offset by social security
benefits.

     Under the Internal Revenue Code, the annual compensation of each employee
to be taken into account under ONEOK's retirement plan for 2004 cannot exceed
$205,000.

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

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

SUPPLEMENTAL EXECUTIVE RETIREMENT

     ONEOK maintains a Supplemental Executive Retirement Plan ("SERP" for
certain of its elected or appointed officers, and certain other employees in a
select group of management and highly compensated employees. Participants are
selected by ONEOK's Chief Executive Officer, or, in the case of ONEOK's Chief
Executive Officer, by the Board of Directors. Effective January 5, 2005, Messrs.
Cordes, Peters, Miller and Norton and Ms. Place were named participants.

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

ONEOK'S EMPLOYEE NON-QUALIFIED DEFERRED COMPENSATION PLAN

     The Named Officers are also eligible to participate in ONEOK's
Non-Qualified Deferred Compensation Plan. ONEOK's Non-Qualified Deferred
Compensation Plan provides select employees, as approved by the Board of
Directors, with the option to defer portions of their compensation and provides
non-qualified deferred compensation benefits which are not otherwise available
due to limitations on employer and employee contributions to qualified defined
contribution plans under the federal tax laws. Under the plan, participants have
the option to defer their salary and/or bonus


                                       70
<PAGE>
compensation to a short-term deferral account, which pays out a minimum of five
years from commencement, or to a long-term deferral account, which pays out at
retirement or termination of the employment of the participant. Participants are
immediately 100 percent vested. Short-term deferral accounts are credited with a
deemed investment return based on the five year Treasury Bond fund. Long-term
deferral accounts are credited with a deemed investment return based on various
investment options, which do not include an option to invest in ONEOK common
stock. At the distribution date, cash is distributed to participants based on
the fair market value of the deemed investment of the participant at that date.

SEVERANCE PLANS

     Northern Plains' and NBP Services' Severance Pay Plans provide for the
payment of benefits to employees who are terminated for failing to meet
performance objectives or standards or who are terminated due to reorganization
or similar business circumstances. The amount of benefits payable for
performance related terminations is based on length of service and may not
exceed eight weeks' pay. For those terminated as the result of reorganization or
similar business circumstances, the benefit is based on length of service and
amount of pay up to a maximum payment of 52 weeks of base pay. The employee must
sign a Waiver and Release of Claims Agreement in order to receive any severance
benefit. As part of the sale and purchase agreement between ONEOK and CCE
Holdings, for a period of twelve months, neither Northern Plains nor NBP
Services may take any action that would change the Severance Pay Plans that
would have an adverse impact on the employees of Northern Plains or NBP
Services.

See Item 10. "Directors and Executive Officers of the Registrant" for
information on compensation paid to the members of the Partnership Policy
Committee and our Audit Committee.


                                       71
<PAGE>
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND
RELATED STOCKHOLDER MATTERS.

     The following table sets forth the beneficial ownership of the voting
securities of the Partnership as of March 3, 2005 by our executive officers,
members of the Partnership Policy Committee and the Audit Committee who own
units and by certain beneficial owners. Other than as set forth below, no person
is known by the general partners to own beneficially more than 5% of the voting
securities.

<TABLE>
<CAPTION>
                                            Amount and Nature of Beneficial Ownership
                                            -----------------------------------------
                                                           Common Units
                                                       -------------------
                                                        Number     Percent
                                                       of Units   of Class
                                                       --------   --------
<S>                                                    <C>        <C>
William R. Cordes                                         1,000      *
   13710 FNB Parkway
   Omaha, NE 68154-5200

Jerry L. Peters (1/)                                      7,734      *
   13710 FNB Parkway
   Omaha, NE 68154-5200

Pierce H. Norton (2/)                                     6,778      *
   1400 16th Street, Suite 310
   Denver, CO 80202

Janet K. Place (3/)                                       1,691      *
   13710 FNB Parkway
   Omaha, NE 68154-5200

Gary N. Petersen                                          5,854      *
   3520 Wedgewood Ln. N
   Plymouth, MN 55441-2262

ONEOK, Inc. (4/)                                        501,603     1.06
   100 West Fifth Street
   Tulsa, OK74103-4298

All Policy Committee Members, Audit                      24,001      *
Committee Members, nominees and executive
officers as a group (16 persons)
</TABLE>

----------
*    Less than 1%.

(1/) Includes 1000 units held by immediate family members for which Mr. Peters
     has shared voting or investment power.

(2/) These units are held in trust for which Mr. Norton has sole voting or
     investment power.

(3/) Includes 500 units held by immediate family members for which Ms. Place has
     shared voting or investment power.

(4/) Indirect ownership through its subsidiaries. Northern Plains is the
     beneficial owner of 501,603 Common Units which includes 1,603 common units
     to satisfy obligations under the Amended and Restated Northern Border
     Phantom Unit Plan.

     For information on equity compensation plans of the Partnership, see Item
5. "Market for Registrant's Common Equity, Related Stockholder Matters


                                       72
<PAGE>
and Issuer Purchases of Equity Securities".

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.

     On December 2, 2001, Enron and certain of its subsidiaries filed voluntary
petitions for Chapter 11 reorganization under the Bankruptcy Code. During 2004,
we had a number of relationships with Enron and its subsidiaries. In November
2004, ONEOK purchased Northern Plains, Pan Border and NBP Services, LLC from CCE
Holdings, LLC. CCE Holdings, a joint venture between Southern Union Company and
GE Commercial Finance Energy Financial purchased Northern Plains, Pan Border and
NBP Services as part of its acquisition of CrossCountry. Through ONEOK's
ownership of two of our general partners, ONEOK is able to elect members with a
majority of the voting power on the Partnership Policy Committee and Northern
Border Pipeline Management Committee. Such other relationships include the
following:

     -    With the sale of Northern Plains and NBP Services from CCE Holdings to
          ONEOK, CCE Holdings and ONEOK entered into a transition services
          agreement. This transition services agreement provides for the
          continued use by Northern Plains and NBP Services of certain services,
          data applications, systems and infrastructure relied on by Northern
          Plains and NBP Services to perform under the Operating Agreements and
          Administrative Services Agreement with us or our subsidiaries, as more
          fully described below. The term of the transition services agreement
          is until May 16, 2005; the parties may agree to extend any transition
          service beyond the term. The cost of the transition services is
          estimated to be $3.9 million for the full term of the agreement.

     -    Northern Plains, a subsidiary of ONEOK, provides certain
          administrative, operating and management services to the Partnership
          through Operating Agreements with Northern Border Pipeline, Midwestern
          Gas Transmission and Viking Gas Transmission. NBP Services, a
          subsidiary of ONEOK, provides the Partnership services in connection
          with the operation and management of the Partnership and operating
          services for Crestone Energy Ventures and Bear Paw Energy pursuant to
          the terms of an Administrative Services Agreement between the
          Partnership and NBP Services. For the year ended December 31, 2004,
          the aggregate amount charged by Northern Plains and NBP Services for
          their services was approximately $45.8 million.

     -    ONEOK holds contracts for firm transportation on Northern Border
          Pipeline with expiration dates from December 31, 2004 to March 31,
          2009. Revenues from ONEOK for the period from the date of affiliation
          to December 31, 2004, were $1.1 million. Also, ONEOK has entered into
          a precedent agreement for capacity on Northern Border Pipeline's
          Chicago III Expansion Project.

     -    Commencing on July 1, 2004, Northern Plains, was selected on a fixed
          fee and cost reimbursement basis to provide certain administrative,
          operating and management services through an Operating Agreement with
          Guardian Pipeline, of which we own a one third interest. The annual
          amount of the fixed fee to be charged by Northern Plains for its
          services is $3.6 million. Guardian Pipeline has agreed to reimburse up
          to $800,000 of certain of Northern Plains' costs associated with the
          transition of the role of operator of Guardian Pipeline from Trunkline
          Gas Company to Northern Plains and has agreed to compensate Northern
          Plains for any services provided to Guardian Pipeline prior to July 1,
          2004.


                                       73
<PAGE>
     -    In conjunction with the selection of Northern Plains as operator of
          Guardian Pipeline, we agreed to contract with Northern Plains to
          assume the financial risks and benefits resulting from and arising out
          of Northern Plains' responsibilities and obligations as operator of
          Guardian Pipeline.

     The Partnership Policy Committee, whose members are designated by our three
general partners, establishes the business policies of the Partnership. We have
three representatives on the Northern Border Management Committee, each of whom
votes a portion of our 70% interest on the Northern Border Management Committee,
with the other 30% interest being voted by a representative of TC PipeLines,
which is an affiliate of one of our general partners.

     Our general partners (subsidiaries of ONEOK and a subsidiary of
TransCanada) and their respective affiliates, currently actively engage or may
engage in the businesses in which we engage or in which we may engage in the
future. As a result, conflicts of interest may arise between our general
partners and their affiliates on the one hand, and the Partnership on the other
hand. In such case the members of the Partnership Policy Committee will
generally have a fiduciary duty to resolve such conflicts in a manner that is in
our best interest.

     TC PipeLines (a 30% owner of Northern Border Pipeline whose general partner
is an affiliate of one of our general partners) and its affiliates are also
actively engaged in interstate pipeline transportation of natural gas in the
United States separate from their interests in Northern Border Pipeline. As a
result, conflicts also may arise between TransCanada and its affiliates or TC
PipeLines and its affiliates, on the one hand, and the Northern Border Pipeline
on the other hand. If such conflicts arise, the representatives on the Northern
Border Pipeline Management Committee will generally have a fiduciary duty to
resolve such conflicts in a manner that is in the best interest of Northern
Border Pipeline.

     Unless otherwise provided for in a partnership agreement, the laws of
Delaware and Texas generally require a general partner of a partnership to
adhere to fiduciary duty standards under which it owes its partners the highest
duties of good faith, fairness and loyalty. Similar rules apply to persons
serving on the Partnership Policy Committee or the Northern Border Management
Committee. Because of the competing interests identified above, our Partnership
Agreement and the partnership agreement for Northern Border Pipeline contain
provisions that modify certain of these fiduciary duties. For example:

          -    Our Partnership Agreement states that our general partners, their
               affiliates and their officers and directors will not be liable
               for damages to us, our limited partners or their assignees for
               errors of judgment or for any acts or omissions if the general
               partners and such other persons acted in good faith.

          -    Our Partnership Agreement allows our general partners and our
               Partnership Policy Committee to take into account the interests
               of parties in addition to our interest in resolving conflicts of
               interest.

          -    Our Partnership Agreement provides that the general partners will
               not be in breach of their obligations under


                                       74
<PAGE>
               our Partnership Agreement or their duties to us or our
               unitholders if the resolution of a conflict is fair and
               reasonable to us. The latitude given in our Partnership Agreement
               in connection with resolving conflicts of interest may
               significantly limit the ability of a unitholder to challenge what
               might otherwise be a breach of fiduciary duty.

          -    Our Partnership Agreement provides that a purchaser of Common
               Units is deemed to have consented to certain conflicts of
               interest and actions of the general partners and their affiliates
               that might otherwise be prohibited and to have agreed that such
               conflicts of interest and actions do not constitute a breach by
               the general partners of any duty stated or implied by law or
               equity.

          -    Our Audit Committee will, at the request of a general partner or
               a member of the Partnership Policy Committee, review conflicts of
               interest that may arise between a general partner and its
               affiliates (or the member of the Partnership Policy Committee
               designated by it), on the one hand, and the unitholders or us, on
               the other. Any resolution of a conflict approved by the Audit
               Committee is conclusively deemed fair and reasonable to us.

          -    The partnership agreement of Northern Border Pipeline that
               relieves us and TC PipeLines, their affiliates and their
               transferees from any duty to offer business opportunities to
               Northern Border Pipeline, subject to specified exceptions.

     We are required to indemnify the members of the Partnership Policy
Committee and general partners, their affiliates and their respective officers,
directors, employees, agents and trustees to the fullest extent permitted by law
against liabilities, costs and expenses incurred by any such person who acted in
good faith and in a manner reasonably believed to be in, or (in the case of a
person other than one of the general partners) not opposed to, our best
interests and with respect to any criminal proceedings, had no reasonable cause
to believe the conduct was unlawful.

ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

     The following sets forth fees billed for the audit and other services
provided by KPMG LLP, the Partnership's principal accountant, for the fiscal
years ended December 31, 2004 and December 31, 2003:

<TABLE>
<CAPTION>
                         Year Ended December 31,
                         -----------------------
                             2004       2003
                           --------   --------
<S>                        <C>        <C>
Audit fees (1)             $895,250   $431,045
Audit-related fees               --         --
Tax Fees (2)                     --        855
All Other Fees                   --         --
                           --------   --------
Total                      $895,250   $431,900
</TABLE>

     (1)  Includes fees for the audit of annual financial statements and
          internal control over financial reporting, reviews of the related
          quarterly financial statements and related consents and comfort
          letters for documents filed with the Securities and Exchange
          Commission.


                                       75
<PAGE>
     (2)  Includes fees related to professional services for tax compliance and
          consultation.


     The Audit Committee has considered whether the provision of the non-audit
services described above is compatible with maintaining the independence of KPMG
LLP and determined that the provision of such services was compatible with
maintaining such independence.

AUDIT COMMITTEE POLICIES AND PROCEDURES FOR PRE-APPROVAL OF AUDIT AND NON-AUDIT
SERVICES

     Consistent with SEC policies regarding auditor independence, the audit
committee is responsible for pre-approving all audit and non-audit services
performed by the independent auditor. In addition to its approval of the audit
engagement, the audit committee takes action at least annually to authorize the
performance by the independent auditor of several specific types of services
within the categories of audit services, audit-related services, tax services
and all other services. Audit services include assurance and related services
that are reasonably related to the performance of the audit or review of the
financial statements, attestations pursuant to Section 404 of the Sarbanes-Oxley
Act, quarterly reviews comfort letters, consents, review of registration
statements, accounting research from completed transactions and tax assistance
related to the audit services. Audit-related services include due diligence
related to potential business acquisitions/dispositions, accounting research and
other audit or attest services. Authorized tax services include
compliance-related services such as services involving tax filings, as well as
consulting services such as tax planning, transaction analysis and opinions. All
other services include special investigations to assist the Audit Committee or
its counsel and assistance with regulatory activities. Services are subject to
pre-approval of the specific engagement if they are outside the specific types
of services included in the periodic approvals covering service categories or if
they are in excess of specified fee limitations. The Audit Committee has
delegated pre-approval authority to the Audit Committee Chairman. The tax fees
for 2003 were pre-approved.


                                       76
<PAGE>
                                     PART IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES.

     (a)(1) and (2) Financial Statements and Financial Statement Schedules

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

     (A)(3) EXHIBITS

<TABLE>
<S>       <C>
    3.1   Northern Border Partners, L.P. Certificate of Limited Partnership,
          Certificate of Amendment dated February 16, 2001, and Certificate of
          Amendment dated May 20, 2003.

    3.2   Amended and Restated Agreement of Limited Partnership of Northern
          Border Partners, L.P. dated October 1, 1993.

    3.3   Northern Border Intermediate Limited Partnership Certificate of
          Limited Partnership, Certificate of Amendment dated February 16, 2001,
          and Certificate of Amendment dated May 20, 2003.

   *3.4   Form of Amended and Restated Agreement of Limited Partnership for
          Northern Border Intermediate Limited Partnership (incorporated by
          reference to Exhibit 10.1 to Form S-1 Registration Statement,
          Registration No. 33-66158 ("Form S-1")).

   *4.1   Indenture, dated as of June 2, 2000, between Northern Border Partners,
          L.P. and Northern Border Intermediate Limited Partnership and Bank One
          Trust Company, N.A. (incorporated by reference to Exhibit 4.1 to the
          Partnership's Quarterly Report on Form 10-Q for the quarterly period
          ended June 30, 2000 (File No. 1-12202) ("June 2000 10-Q")).

   *4.2   First Supplemental Indenture, dated as of September 14, 2000, between
          Northern Border Partners, L.P., Northern Border Intermediate Limited
          Partnership and Bank One Trust Company, N.A. (incorporated by
          reference to Exhibit 4.2 to the Partnership's Form S-4 Registration
          Statement, Registration No. 333-46212 ("NBP Form S-4")).

   *4.3   Indenture, dated as of March 21, 2001, between Northern Border
          Partners, L.P. and Northern Border Intermediate Limited Partnership
          and Bank One Trust Company, N.A., Trustee (incorporated by reference
          to Exhibit 4.3 to the Partnership's Form 10-K for the year ended
          December 31, 2001 (File No. 1-12202)).

   *4.4   Indenture, dated as of August 17, 1999, between Northern Border
          Pipeline Company and Bank One Trust Company, NA, successor to The
          First National Bank of Chicago, as trustee. (incorporated by reference
          to Exhibit No. 4.1 to Northern Border Pipeline Company's Form S-4
          Registration Statement filed on October 7, 1999, Registration No.
          333-88577 ("NB Form S-4")).

   *4.5   Indenture, dated as of September 17, 2001, between Northern Border
          Pipeline Company and Bank Trust Company, N.A. (incorporated by
          reference to Exhibit 4.2 to Northern Border Pipeline Company's
          Registration Statement on Form S-4 filed on November 13, 2001,
          Registration No. 333-73282 ("2001 NB Form S-4")).
</TABLE>


                                       77
<PAGE>
<TABLE>
<S>       <C>
   *4.6   Indenture, dated as of April 29, 2002, between Northern Border
          Pipeline Company and Bank One Trust Company, N.A. (incorporated by
          reference to Exhibit 4.1 to Northern Border Pipeline Company's Form
          10-Q for the quarter ended March 31, 2002 (File No. 333-88577)).

  *10.1   Northern Border Pipeline Company General Partnership Agreement between
          Northern Plains Natural Gas Company, Northwest Border Pipeline
          Company, Pan Border Gas Company, TransCanada Border Pipeline Ltd. and
          TransCan Northern Ltd., effective March 9, 1978, as amended
          (incorporated by reference to Exhibit 10.2 to Form S-1).

  *10.2   Form of Seventh Supplement Amending Northern Border Pipeline Company
          General Partnership Agreement (incorporated by reference to Exhibit
          10.15 to Form S-1).

  *10.3   Eighth Supplement Amending Northern Border Pipeline Company General
          Partnership Agreement (incorporated by reference to Exhibit 10.15 to
          NB Form S-4).

  *10.4   Ninth Supplement Amending Northern Border Pipeline Company General
          Partnership Agreement (incorporated by reference to Exhibit 10.37 to
          2001 NB Form S-4).

  *10.5   Tenth Supplement Amending Northern Border Pipeline Company General
          Partnership Agreement dated March 2, 2005 (incorporated by reference
          to Exhibit 3.5 to Northern Border Pipeline's Form 10-K filed on March
          11, 2005 (File No. 333-88577)).

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

  *10.7   Administrative Services Agreement between NBP Services Corporation,
          Northern Border Partners, L.P. and Northern Border Intermediate
          Limited Partnership (incorporated by reference to Exhibit 10.4 to Form
          S-1).

  *10.8   Revolving Credit Agreement, dated as of November 24, 2003, among
          Northern Border Partners, L.P., SunTrust Bank, Harris Nesbitt Corp.,
          Wachovia Bank, National Association, Citigroup, N.A., SunTrust Capital
          Markets, Inc., and the Lenders (as named therein) (incorporated by
          reference to Exhibit 10.7 to the Partnership's Form 10-K for the year
          ended December 31, 2003 (File No. 1-12202)).

  *10.9   First Amendment to the Revolving Credit Agreement dated as of April 9,
          2004 between Northern Border Partners, L.P., SUNTRUST BANK and the
          lenders named therein (incorporated by reference to Exhibit 10.1 to
          the Partnership's Form 10-Q for the quarter ended March 31, 2004 (File
          No. 1-12202)).

 *10.10   Second Amendment entered into as of October 25, 2004 to Northern
          Border Partners' Revolving Credit Agreement dated as of November 24,
          2003 (incorporated by reference to Exhibit 99.1 to the Partnership's
          Form 8-K filed on November 5, 2004 (File No. 1-12202)).

 *10.11   Revolving Credit Agreement, dated as of May 16, 2002, among Northern
          Border Pipeline Company, Bank One, NA, Citibank, N.A., Bank of
          Montreal, SunTrust Bank, Wachovia Bank, National Association, Banc One
          Capital Markets, Inc, and Lenders (as defined therein) (incorporated
          by reference to Exhibit 10.1 to the Partnership's Current Report on
          Form 8-K dated June 26, 2002 (File No. 1-12202)).

 *10.12   First Amendment to the Revolving Credit Agreement dated as of April 9,
          2004 between Northern Border Pipeline Company, Bank One, NA and the
          lenders named therein. (incorporated by reference to Exhibit No. 10.1
          to Northern Border Pipeline
</TABLE>


                                       78
<PAGE>
<TABLE>
<S>       <C>
          Company's Quarterly Report on Form 10-Q for the quarterly period ended
          March 31, 2004 (File No. 333-88577)).

 *10.13   Agreement between Northern Plains and Northern Border Intermediate
          Limited Partnership regarding the costs, expenses and expenditures
          arising under the operating agreement between Northern Plains and
          Guardian Pipeline, LLC (incorporated by reference to Exhibit 10.3 to
          the Partnership's Form 10-Q for the quarter ended March 31, 2004 (File
          No. 1-12202)).

+*10.14   Form of Termination Agreement with ONEOK dated as of January 5, 2005
          (incorporated by reference to Exhibit 99.1 to the Partnership's Form
          8-K filed on January 11, 2005 (File No. 1-12202)).

+*10.15   ONEOK, Inc. 2005 Supplemental Executive Retirement Plan. (incorporated
          by reference to Exhibit 99.1 to the Partnership's Form 8-K filed on
          January 11, 2005(File No. 1-12202)).

+*10.16   ONEOK, Inc. Long-Term Incentive Plan (incorporated by reference from
          Exhibit 10(a) to ONEOK's Form 10-K for the year ended December 31,
          2001 (File No. 1-13643)).

+*10.17   ONEOK, Inc. Form of Restricted Stock Incentive Award (incorporated by
          reference from Exhibit 10.4 to ONEOK's Form 10-Q for the quarterly
          period ended September 30, 2004 (File No. 1-13643)).

+*10.18   ONEOK, Inc. Form of Performance Shares Award (incorporated by
          reference from Exhibit 10.5 to ONEOK's Form 10-Q for the quarterly
          period ended September 30, 2004 (File No. 1-13643)).

+*10.19   ONEOK, Inc. Employee Non-Qualified Deferred Compensation Plan, as
          amended, dated February 2001 (incorporated by reference to Exhibit
          10(g) to ONEOK's Form 10-K for the year ended December 31, 2001(File
          No. 1-13643)).

+*10.20   ONEOK, Inc. Annual Officer Incentive Plan (incorporated by reference
          to Exhibit 10(f) to ONEOK's Form 10-K for the year ended December 31,
          2001 (File No. 1-13643)).

 *10.21   Operating Agreement between Midwestern Gas Transmission Company and
          Northern Plains Natural Gas Company dated as of April 1, 2001
          (incorporated by reference to Exhibit 10.38 to the Partnership's Form
          10-K for the year ended December 31, 2001 (File No. 1-12202)).

 *10.22   Operating Agreement between Viking Gas Transmission Company and
          Northern Plains Natural Gas Company dated as of January 17, 2003
          (incorporated by reference to Exhibit 10.18 to the Partnership's Form
          10-K for the year ended December 31, 2002 (File No. 1-12202)).

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


                                       79
<PAGE>
<TABLE>
<S>       <C>
  10.24   Northern Border Transition Services Agreement dated November 17, 2004,
          by and between ONEOK, Inc. and CCE Holdings, LLC.

   12.1   Statement re computation of ratios.

     21   List of subsidiaries.

   23.1   Consent of KPMG LLP.

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

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

   32.1   Section 1350 certification of principal executive officer.

   32.2   Section 1350 certification of principal financial officer.

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

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

+    Management contract, compensatory plan or arrangement.

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


                                       80
<PAGE>
                                   SIGNATURES

     Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized on this 11th day of
March, 2005.

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


                                        By: WILLIAM R. CORDES
                                        ----------------------------------------
                                        William R. Cordes
                                        Chief Executive Officer

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

<TABLE>
<CAPTION>
           Signature                          Title                    Date
           ---------                          -----                    ----
<S>                               <C>                             <C>


/s/ WILLIAM R. CORDES             Chief Executive Officer and     March 11, 2005
-------------------------------   Member of Partnership Policy
    William R. Cordes             Committee
                                  (Principal Executive Officer)


/s/ DAVID L. KYLE                 Chairman of the Partnership
-------------------------------   Policy Committee                March 11, 2005
    David L. Kyle


/s/ PAUL E. MILLER                Member of Partnership Policy    March 11, 2005
-------------------------------   Committee
    Paul E. Miller


/s/ JERRY L. PETERS               Chief Financial and             March 11, 2005
-------------------------------   Accounting Officer
    Jerry L. Peters               (Principal Financial
                                  and Accounting Officer)
</TABLE>


                                       81


<PAGE>
                 NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES
                          INDEX TO FINANCIAL STATEMENTS

<TABLE>
<CAPTION>
                                                                      PAGE NO.
                                                                     -----------
<S>                                                                  <C>
Consolidated Financial Statements

   Report of Independent Registered Public Accounting Firm           F-2
   Consolidated Balance Sheet - December 31, 2004 and 2003           F-3
   Consolidated Statement of Income - Years Ended                    F-4
      December 31, 2004, 2003 and 2002
   Consolidated Statement of Comprehensive Income - Years Ended      F-5
      December 31, 2004, 2003 and 2002
   Consolidated Statement of Cash Flows - Years Ended                F-6
      December 31, 2004, 2003 and 2002
   Consolidated Statement of Changes in Partners' Equity -           F-7
      Years Ended December 31, 2004, 2003 and 2002
   Notes to Consolidated Financial Statements                        F-8 through
                                                                     F-35

Financial Statements Schedule

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


                                       F-1
<PAGE>
             REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Northern Border Partners, L.P.:

We have audited the accompanying consolidated balance sheets of Northern Border
Partners, L.P. and subsidiaries as of December 31, 2004 and 2003, and the
related consolidated statements of income, comprehensive income, cash flows, and
changes in partners' equity for each of the years in the three-year period ended
December 31, 2004. These consolidated financial statements are the
responsibility of the Company's management. Our responsibility is to express an
opinion on these consolidated financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company
Accounting Oversight Board (United States). Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present
fairly, in all material respects, the financial position of Northern Border
Partners, L.P. and subsidiaries as of December 31, 2004 and 2003, and the
results of their operations and their cash flows for each of the years in the
three-year period ended December 31, 2004, in conformity with U.S. generally
accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company
Accounting Oversight Board (United States), the effectiveness of Northern Border
Partners, L.P.'s internal control over financial reporting as of December 31,
2004, based on criteria established in Internal Control--Integrated Framework,
issued by the Committee of Sponsoring Organizations of the Treadway Commission,
and our report dated March 2, 2005 expressed an unqualified opinion on
management's assessment of, and the effective operation of, internal control
over financial reporting.


/s/ KPMG LLP

Omaha, Nebraska
March 2, 2005


                                       F-2
<PAGE>
                 NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES

                           CONSOLIDATED BALANCE SHEET

                                 (IN THOUSANDS)

<TABLE>
<CAPTION>
                                                               DECEMBER 31,
                                                         -----------------------
                                                            2004         2003
                                                         ----------   ----------
<S>                                                      <C>          <C>
ASSETS

CURRENT ASSETS
   Cash and cash equivalents                             $   33,980   $   35,895
   Accounts receivable (net of allowance for doubtful
      accounts of $9,175 in 2004)                            68,930       61,503
   Related party receivables (net of allowance
      for doubtful accounts of $11,988 in 2003)               1,077           --
   Materials and supplies, at cost                            5,654        7,826
   Prepaid expenses                                           4,642        6,726
   Derivative financial instruments                           1,996           --
   Other                                                      1,008        2,245
                                                         ----------   ----------
      Total current assets                                  117,287      114,195
                                                         ----------   ----------

PROPERTY, PLANT AND EQUIPMENT
   Interstate Natural Gas Pipelines                       2,626,579    2,612,241
   Gas Gathering and Processing                             265,484      253,903
   Coal Slurry                                               47,402       45,911
                                                         ----------   ----------

Total property, plant and equipment                       2,939,465    2,912,055
   Less: Accumulated provision for depreciation
      and amortization                                    1,002,041      919,951
                                                         ----------   ----------
      Property, plant and equipment, net                  1,937,424    1,992,104
                                                         ----------   ----------

INVESTMENTS AND OTHER ASSETS
   Investment in unconsolidated affiliates                  273,202      268,166
   Goodwill                                                 152,782      152,782
   Derivative financial instruments                           2,555       19,553
   Other                                                     27,306       23,783
                                                         ----------   ----------
      Total investments and other assets                    455,845      464,284
                                                         ----------   ----------
      Total assets                                       $2,510,556   $2,570,583
                                                         ==========   ==========

LIABILITIES AND PARTNERS' EQUITY

CURRENT LIABILITIES
   Current maturities of long-term debt                  $    5,126   $    7,740
   Accounts payable                                          28,802       20,834
   Related party payables                                     6,293       25,698
   Accrued taxes other than income                           32,563       33,708
   Accrued interest                                          16,530       13,206
   Derivative financial instruments                              --        5,736
                                                         ----------   ----------
      Total current liabilities                              89,314      106,922
                                                         ----------   ----------
LONG-TERM DEBT, net of current maturities                 1,325,232    1,408,246
                                                         ----------   ----------
MINORITY INTERESTS IN PARTNERS' EQUITY                      290,142      240,731
                                                         ----------   ----------

RESERVES AND DEFERRED CREDITS
   Deferred income taxes                                      7,186        2,898
   Other                                                      9,348       11,213
                                                         ----------   ----------
      Total reserves and deferred credits                    16,534       14,111
                                                         ----------   ----------

COMMITMENTS AND CONTINGENCIES (NOTE 13)

PARTNERS' EQUITY
   General partners                                          15,603       15,902
   Common units (46,397,214 units issued and
      outstanding at December 31, 2004 and 2003)            764,550      779,195
   Accumulated other comprehensive income                     9,181        5,476
                                                         ----------   ----------
      Total partners' equity                                789,334      800,573
                                                         ----------   ----------
      Total liabilities and partners' equity             $2,510,556   $2,570,583
                                                         ==========   ==========
</TABLE>

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

                                       F-3
<PAGE>
                 NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES

                        CONSOLIDATED STATEMENT OF INCOME

                     (IN THOUSANDS, EXCEPT PER UNIT AMOUNTS)

<TABLE>
<CAPTION>
                                                     YEAR ENDED DECEMBER 31,
                                                 ------------------------------
                                                   2004       2003       2002
                                                 --------   --------   --------
<S>                                              <C>        <C>        <C>
OPERATING REVENUES                               $590,383   $550,948   $487,204
                                                 --------   --------   --------
OPERATING EXPENSES
   Product purchases                              103,213     80,774     50,648
   Operations and maintenance                     111,142    127,623    106,521
   Depreciation and amortization, including
      impairment charges of $219,080 in 2003       86,431    299,791     74,672
   Taxes other than income                         36,212     35,443     32,194
                                                 --------   --------   --------
      Operating expenses                          336,998    543,631    264,035
                                                 --------   --------   --------
OPERATING INCOME                                  253,385      7,317    223,169
                                                 --------   --------   --------
INTEREST EXPENSE
   Interest expense                                77,346     79,159     83,227
   Interest expense capitalized                      (403)      (179)      (329)
                                                 --------   --------   --------
      Interest expense, net                        76,943     78,980     82,898
                                                 --------   --------   --------
OTHER INCOME (EXPENSE)
   Allowance for equity funds used during
      construction                                    117        331        248
   Equity earnings of unconsolidated
      affiliates                                   18,015     18,815     12,983
   Other income                                     3,654      5,992      2,740
   Other expense                                   (2,138)    (1,459)      (801)
                                                 --------   --------   --------
        Other income, net                          19,648     23,679     15,170
                                                 --------   --------   --------
MINORITY INTERESTS IN NET INCOME                   50,033     44,460     42,816
                                                 --------   --------   --------
INCOME (LOSS) FROM CONTINUING OPERATIONS
   BEFORE INCOME TAXES                            146,057    (92,444)   112,625

INCOME TAXES                                        5,136      4,705      1,643
                                                 --------   --------   --------
INCOME (LOSS) FROM CONTINUING OPERATIONS          140,921    (97,149)   110,982

DISCONTINUED OPERATIONS, NET OF TAX                 3,799      9,338      2,694

CUMULATIVE EFFECT OF CHANGE IN
   ACCOUNTING PRINCIPLE, NET OF TAX                    --       (643)        --
                                                 --------   --------   --------
NET INCOME (LOSS) TO PARTNERS                    $144,720   $(88,454)  $113,676
                                                 ========   ========   ========

CALCULATION OF LIMITED PARTNERS' INTEREST
   IN NET INCOME (LOSS):
Net income (loss) to partners                    $144,720   $(88,454)  $113,676
Less: general partners' interest in
   net income (loss)                               10,854      5,969      9,602
                                                 --------   --------   --------
Limited partners' interest in
   net income (loss)                             $133,866   $(94,423)  $104,074
                                                 ========   ========   ========

LIMITED PARTNERS' PER UNIT NET INCOME (LOSS):
   Income (loss) from continuing operations      $   2.81   $  (2.27)  $   2.38
   Discontinued operations, net of tax               0.08       0.20       0.06
   Cumulative effect of change in
      accounting principle, net of tax                 --      (0.01)        --
                                                 --------   --------   --------
   Net income (loss)                             $   2.89   $  (2.08)  $   2.44
                                                 ========   ========   ========
NUMBER OF UNITS USED IN COMPUTATION                46,397     45,370     42,709
                                                 ========   ========   ========
</TABLE>

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


                                       F-4
<PAGE>
                 NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES

                 CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME

                                 (IN THOUSANDS)

<TABLE>
<CAPTION>
                                                     YEAR ENDED DECEMBER 31,
                                                 ------------------------------
                                                   2004       2003       2002
                                                 --------   --------   --------
<S>                                              <C>        <C>        <C>
Net income (loss) to partners                    $144,720   $(88,454)  $113,676
Other comprehensive income:
   Change associated with current period
      hedging transactions                          5,263     (4,383)   (13,490)
   Change associated with current
      period foreign currency translation          (1,558)     2,345        475
                                                 --------   --------   --------
Total comprehensive income (loss)                $148,425   $(90,492)  $100,661
                                                 ========   ========   ========
</TABLE>

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


                                       F-5
<PAGE>
                 NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES

                      CONSOLIDATED STATEMENT OF CASH FLOWS

                                 (IN THOUSANDS)

<TABLE>
<CAPTION>
                                                                   YEAR ENDED DECEMBER 31,
                                                              ---------------------------------
                                                                 2004        2003        2002
                                                              ---------   ---------   ---------
<S>                                                           <C>         <C>         <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
   Net income (loss) to partners                              $ 144,720   $ (88,454)  $ 113,676
                                                              ---------   ---------   ---------
   Adjustments to reconcile net income (loss) to
   partners to net cash provided by operating activities:
      Depreciation and amortization, including
         impairment charges of $219,080 in 2003                  87,203     301,977      76,239
      Minority interests in net income                           50,033      44,460      42,816
      Non-cash gains from risk management activities               (460)       (209)     (4,509)
      Provision for regulatory refunds                               --         261      10,000
      Regulatory refunds paid                                        --     (10,261)         --
      Cumulative effect of change in accounting principle            --         643          --
      Gain on sale of gathering and processing assets            (6,621)     (4,872)         --
      Equity earnings in unconsolidated affiliates              (18,015)    (18,928)    (14,570)
      Distributions received from unconsolidated affiliates      13,946      16,262      10,820
      Allowance for equity funds used during construction          (117)       (331)       (248)
      Reserves and deferred credits                              (2,747)      4,472         (24)
      Changes in components of working capital                  (19,243)    (18,592)      9,670
      Other                                                      (4,041)     (1,768)        136
                                                              ---------   ---------   ---------
         Total adjustments                                       99,938     313,114     130,330
                                                              ---------   ---------   ---------
      Net cash provided by operating activities                 244,658     224,660     244,006
                                                              ---------   ---------   ---------

CASH FLOWS FROM INVESTING ACTIVITIES:
   Capital expenditures for property, plant
      and equipment, net                                        (43,477)    (30,282)    (50,738)
   Acquisition of businesses                                         --    (123,194)     (1,561)
   Sale of gathering and processing assets                       22,685      40,250          --
   Investments in unconsolidated affiliates and other               (84)     (3,514)     (2,972)
                                                              ---------   ---------   ---------
      Net cash used in investing activities                     (20,876)   (116,740)    (55,271)
                                                              ---------   ---------   ---------

CASH FLOWS FROM FINANCING ACTIVITIES:
   Cash distributions
      General and limited partners                             (159,624)   (155,173)   (146,960)
      Minority Interests                                        (61,690)    (46,194)    (49,238)
   Equity contributions from Minority Interests                  61,500          --          --
   Issuance of partnership interests, net                           (40)    102,203      75,376
   Issuance of long-term debt, net                              259,000     342,000     499,894
   Retirement of long-term debt                                (327,521)   (361,129)   (567,540)
   Proceeds upon termination of derivatives                       7,575      12,250      20,551
   Debt reacquisition costs                                      (4,897)         --          --
   Long-term debt financing costs                                    --        (671)     (2,884)
                                                              ---------   ---------   ---------
      Net cash used in financing activities                    (225,697)   (106,714)   (170,801)
                                                              ---------   ---------   ---------

NET CHANGE IN CASH AND CASH EQUIVALENTS                          (1,915)      1,206      17,934
Cash and cash equivalents-beginning of year                      35,895      34,689      16,755
                                                              ---------   ---------   ---------
Cash and cash equivalents-end of year                         $  33,980   $  35,895   $  34,689
                                                              =========   =========   =========
Changes in components of working capital:
   Accounts receivable                                        $ (12,992)  $  (3,135)  $   4,303
   Materials and supplies, prepaid expenses and other             3,355      (3,833)     (2,573)
   Accounts payable                                             (10,065)     (8,525)      9,370
   Accrued taxes other than income                               (1,145)        437       2,378
   Accrued interest                                               1,604      (3,536)     (3,808)
                                                              ---------   ---------   ---------
   Total                                                      $ (19,243)  $ (18,592)  $   9,670
                                                              =========   =========   =========
</TABLE>

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


                                       F-6
<PAGE>
                 NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES

              CONSOLIDATED STATEMENT OF CHANGES IN PARTNERS' EQUITY

                                 (IN THOUSANDS)

<TABLE>
<CAPTION>
                                                                 ACCUMULATED
                                                                    OTHER         TOTAL
                                          GENERAL    COMMON     COMPREHENSIVE   PARTNERS'
                                         PARTNERS     UNITS        INCOME        EQUITY
                                         --------   ---------   -------------   ---------
<S>                                      <C>        <C>         <C>             <C>
Partners' Equity at December 31, 2001    $ 17,889   $ 876,540     $ 20,529      $ 914,958
Net income to partners                      9,602     104,074           --        113,676
Change associated with current
   period hedging transactions                 --          --      (13,490)       (13,490)
Change associated with current
   period foreign currency translation         --          --          475            475
Issuance of partnership interests, net
   (2,186,700 common units)                 1,507      73,869           --         75,376
Distributions paid                        (10,268)   (136,692)          --       (146,960)
                                         --------   ---------      -------      ---------
Partners' Equity at December 31, 2002      18,730     917,791        7,514        944,035
Net income (loss) to partners               5,969     (94,423)          --        (88,454)
Change associated with current
   period hedging transactions                 --          --       (4,383)        (4,383)
Change associated with current
   period foreign currency translation         --          --        2,345          2,345
Issuance of partnership interests, net
   (2,587,500 common units)                 2,044     100,159           --        102,203
Distributions paid                        (10,841)   (144,332)          --       (155,173)
                                         --------   ---------      -------      ---------
Partners' Equity at December 31, 2003      15,902     779,195        5,476        800,573
Net income to partners                     10,854     133,866           --        144,720
Change associated with current
   period hedging transactions                 --          --        5,263          5,263
Change associated with current
   period foreign currency translation         --          --       (1,558)        (1,558)
Issuance of partnership interests, net         (1)        (39)          --            (40)
Distributions paid                        (11,152)   (148,472)          --       (159,624)
                                         --------   ---------     --------      ---------
Partners' Equity at December 31, 2004    $ 15,603   $ 764,550     $  9,181      $ 789,334
                                         ========   =========     ========      =========
</TABLE>

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


                                       F-7
<PAGE>
                 NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES

                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1.   ORGANIZATION AND MANAGEMENT

     Northern Border Partners, L.P., through a subsidiary limited partnership,
     Northern Border Intermediate Limited Partnership, both Delaware limited
     partnerships, collectively referred to herein as the Partnership, owns a
     70% general partner interest in Northern Border Pipeline Company (Northern
     Border Pipeline). The remaining 30% general partner interest in Northern
     Border Pipeline is owned by TC PipeLines Intermediate Limited Partnership
     (TC PipeLines). Crestone Energy Ventures, L.L.C. (Crestone Energy
     Ventures); Bear Paw Energy, L.L.C. (Bear Paw Energy); Border Midstream
     Services, Ltd. (Border Midstream); Midwestern Gas Transmission Company
     (Midwestern Gas Transmission); Viking Gas Transmission Company (Viking Gas
     Transmission) and Black Mesa Pipeline, Inc. (Black Mesa) are wholly-owned
     subsidiaries of the Partnership. As discussed in Note 3, the Partnership
     acquired all of the common stock of Viking Gas Transmission on January 17,
     2003.

     Northern Plains Natural Gas Company, LLC (Northern Plains), a wholly-owned
     subsidiary of ONEOK, Inc. (ONEOK), Pan Border Gas Company, LLC (Pan
     Border), a wholly-owned subsidiary of Northern Plains, and Northwest Border
     Pipeline Company (Northwest Border), a wholly-owned subsidiary of
     TransCanada PipeLines Limited, which is a subsidiary of TransCanada
     Corporation, and affiliate of TC PipeLines, serve as the General Partners
     of the Partnership and collectively own a 2% general partner interest in
     the Partnership. Northern Plains and Pan Border hold an aggregate 1.65%
     general partner interest and Northwest Border holds a 0.35% general partner
     interest. Northern Plains also owns common units representing a 1.1%
     limited partner interest.

     The Partnership is managed under the direction of the Partnership Policy
     Committee consisting of one person appointed by each General Partner. The
     members appointed by Northern Plains, Pan Border and Northwest Border have
     50%, 32.5% and 17.5%, respectively, of the voting interest on the
     Partnership Policy Committee.

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

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


                                       F-8
<PAGE>
                 NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES

                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1.   ORGANIZATION AND MANAGEMENT (continued)

     As part of the closing, ONEOK and CCE Holdings entered into a transition
     services agreement referred to as the "Northern Border Transition Services
     Agreement" covering certain transition services by and among ONEOK, CCE
     Holdings and Enron for a period of six months. Certain of the services
     previously provided by Enron are now being provided through ONEOK.

     The Partnership has entered into an administrative services agreement with
     NBP Services, a wholly-owned subsidiary of ONEOK. NBP Services provides
     certain administrative, operating and management services for the
     Partnership and its gas gathering and processing and coal slurry businesses
     and is reimbursed for its direct and indirect costs and expenses. The
     day-to-day management of Northern Border Pipeline's, Midwestern Gas
     Transmission's and Viking Gas Transmission's affairs is the responsibility
     of Northern Plains, as defined by their respective operating agreements
     with Northern Plains. Northern Border Pipeline, Midwestern Gas Transmission
     and Viking Gas Transmission are charged for the salaries, benefits and
     expenses of Northern Plains. Northern Plains and NBP Services also utilize
     their current and former affiliates for management services including those
     provided through the Northern Border Transition Services Agreement. For the
     years ended December 31, 2004, 2003 and 2002, charges from NBP Services,
     Northern Plains and their current and former affiliates totaled
     approximately $45.8 million, $57.6 million and $45.3 million, respectively.
     See Note 18 for a discussion of the Partnership's previous relationships
     with Enron and developments involving Enron.

     Northern Border Pipeline is a Texas general partnership formed in 1978.
     Northern Border Pipeline owns a 1,249-mile natural gas transmission
     pipeline system extending from the United States-Canadian border near Port
     of Morgan, Montana, to a terminus near North Hayden, Indiana.

     Northern Border Pipeline is managed by a Management Committee that includes
     three representatives from the Partnership (one representative appointed by
     each of the General Partners of the Partnership) and one representative
     from TC PipeLines. The Partnership's representatives selected by Northern
     Plains, Pan Border and Northwest Border have 35%, 22.75% and 12.25%,
     respectively, of the voting interest on the Northern Border Pipeline
     Management Committee. The representative designated by TC PipeLines votes
     the remaining 30% interest.

     Midwestern Gas Transmission system consists of a 350-mile interstate
     natural gas pipeline extending from Portland, Tennessee to Joliet,
     Illinois. Midwestern Gas Transmission's pipeline system connects with
     multiple pipeline systems, including Northern Border Pipeline.

     On January 17, 2003, the Partnership acquired Viking Gas Transmission (see
     Note 3). The Viking Gas Transmission system is a 578-mile interstate
     natural gas pipeline extending from the United States-Canadian border near
     Emerson, Manitoba to Marshfield, Wisconsin. Viking Gas Transmission
     connects with multiple pipeline systems.

     Bear Paw Energy has extensive natural gas gathering, processing and
     fractionation operations in the Williston Basin in Montana, North Dakota
     and Saskatchewan as well as gas gathering operations in the Powder River
     Basin


                                       F-9
<PAGE>
                 NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES

                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1.   ORGANIZATION AND MANAGEMENT (continued)

     in Wyoming. In the Williston Basin, Bear Paw Energy has over 3,000 miles of
     gathering pipelines and five processing plants with 93 million cubic feet
     per day of capacity. Bear Paw Energy has approximately 600 miles of high
     and low pressure gathering pipelines and approximately 390,000 acres of
     dedicated reserves in the Powder River Basin.

     Border Midstream previously owned the Mazeppa and Gladys gas processing
     plants, gas gathering systems and an undivided minority interest in the
     Gregg Lake/Obed Pipeline. In June 2003, the Partnership sold its Gladys and
     Mazeppa processing plants and related gas gathering facilities. Effective
     December 1, 2004, the Partnership sold its undivided minority interest in
     the Gregg Lake/Obed Pipeline (see Note 3).

     The Partnership owns a 49% common membership interest and a 100% preferred
     A share interest in Bighorn Gas Gathering, L.L.C. (Bighorn); a 33% interest
     in Fort Union Gas Gathering, L.L.C. (Fort Union); a 35% interest in Lost
     Creek Gathering, L.L.C. (Lost Creek); and a 33% interest in Guardian
     Pipeline, L.L.C. (Guardian Pipeline). The Partnership acquired its interest
     in Guardian Pipeline in January 2003 (see Note 3).

     Collectively, Bighorn, Fort Union and Lost Creek own over 300 miles of gas
     gathering facilities in Wyoming. The gathering facilities interconnect to
     the interstate gas pipeline grid serving gas markets in the Rocky
     Mountains, the Midwest and California. Guardian Pipeline is a 141-mile
     interstate natural gas pipeline system that went into service on December
     7, 2002. This system transports natural gas from Joliet, Illinois to a
     point west of Milwaukee, Wisconsin.

     Black Mesa owns a 273-mile, 18-inch diameter coal slurry pipeline that
     originates at a coal mine in Kayenta, Arizona and ends at the 1,500
     megawatt Mohave Generating Station located in Laughlin, Nevada.

2.   SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

     (A)  Principles of Consolidation and Use of Estimates

          The consolidated financial statements include the assets, liabilities
          and results of operations of the Partnership and its majority-owned
          subsidiaries. The Partnership operates through a subsidiary limited
          partnership of which the Partnership is the sole limited partner and
          the General Partners are the sole general partners. The 30% ownership
          of Northern Border Pipeline by TC PipeLines is accounted for as a
          minority interest. All significant intercompany balances and
          transactions have been eliminated in consolidation.

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


                                      F-10
<PAGE>
                 NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES

                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

2.   SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)

     (B)  Government Regulation

          Northern Border Pipeline, Midwestern Gas Transmission, Viking Gas
          Transmission and Guardian Pipeline are subject to regulation by the
          Federal Energy Regulatory Commission (FERC). Northern Border
          Pipeline's and Viking Gas Transmission's accounting policies conform
          to Statement of Financial Accounting Standards (SFAS) No. 71,
          "Accounting for the Effects of Certain Types of Regulation."
          Accordingly, certain assets that result from the regulated ratemaking
          process are recorded that would not be recorded under accounting
          principles generally accepted in the United States of America for
          nonregulated entities. Northern Border Pipeline and Viking Gas
          Transmission continually assess whether the recovery of the regulatory
          assets are probable by such factors as regulatory changes and the
          impact of competition. Northern Border Pipeline and Viking Gas
          Transmission believe the recovery of the existing regulatory assets is
          probable. If future recovery ceases to be probable, Northern Border
          Pipeline and Viking Gas Transmission would be required to write off
          the regulatory assets at that time. At December 31, 2004 and 2003,
          Northern Border Pipeline and Viking Gas Transmission have reflected
          regulatory assets, which are currently being recovered or are expected
          to be recovered from their shippers, of approximately $12.3 million
          and $8.9 million, respectively, on the consolidated balance sheet.
          Northern Border Pipeline is recovering the regulatory assets from its
          shippers over varying time periods, which range from five to 44 years.
          Viking Gas Transmission is recovering the regulatory assets from its
          shippers over five years.

          Although Northern Border Pipeline is a general partnership, Northern
          Border Pipeline's tariff establishes the method of accounting for and
          calculating income taxes and requires Northern Border Pipeline to
          reflect in its financial records the income taxes, which would have
          been paid or accrued if Northern Border Pipeline were organized during
          the period as a corporation. As a result, for purposes of determining
          transportation rates in calculating the return allowed by the FERC,
          partners' capital and rate base are reduced by the amount equivalent
          to the net accumulated deferred income taxes. Such amounts were
          approximately $355 million and $350 million at December 31, 2004 and
          2003, respectively, and are primarily related to accelerated
          depreciation and other plant-related differences.

     (C)  Cash and Cash Equivalents

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

     (D)  Revenue Recognition

          Northern Border Pipeline, Midwestern Gas Transmission and Viking Gas
          Transmission transport gas for shippers under tariffs regulated by the
          FERC. The tariffs specify the calculation of amounts to be paid by
          shippers and the general terms and conditions of transportation
          service


                                      F-11
<PAGE>
                 NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES

                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

2.   SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)

     (D)  Revenue Recognition (continued)

          on the respective pipeline systems. Operating revenues are derived
          from agreements for the receipt and delivery of gas at points along
          the pipeline system as specified in each shipper's individual
          transportation contract. Revenues for the natural gas pipelines are
          recognized based upon contracted capacity and actual volumes
          transported under transportation service agreements. Northern Border
          Pipeline, Midwestern Gas Transmission and Viking Gas Transmission do
          not own the gas that they transport, and therefore do not assume the
          related natural gas commodity risk.

          For the gas gathering and processing businesses, operating revenue is
          recorded when gas is processed in or transported through company
          facilities. The gas gathering and processing businesses also receive
          certain cash payments from customers in advance for gathering services
          to be provided in the future. These cash payments are deferred and
          recognized into operating revenues by using a percentage based on the
          depletion of natural gas reserves associated with the gathering
          system.

          Black Mesa's operating revenue is derived from a pipeline
          transportation agreement. Black Mesa's revenue is recognized based on
          a monthly demand payment, actual tons transported and direct
          reimbursement of certain other expenses.

          Accounts receivable from customers are reviewed regularly for
          collectibility. An allowance for doubtful accounts is recorded in
          situations where collectibility is not reasonably assured.

     (E)  Income Taxes

          The Partnership is not a taxable entity for federal income tax
          purposes. As such, the Partnership does not directly pay federal
          income tax. The Partnership's taxable income or loss, which may vary
          substantially from the net income or loss reported in the consolidated
          statement of income, is includable in the federal income tax returns
          of each partner. The aggregate difference in the basis of the
          Partnership's net assets for financial and income tax purposes cannot
          be readily determined as the Partnership does not have access to
          information about each partner's tax attributes related to the
          Partnership.

          The Partnership's corporate subsidiaries are required to pay federal
          and state income taxes. Income taxes are accounted for under the asset
          and liability method. Deferred income tax assets and liabilities are
          recognized by these entities for the future tax consequences
          attributable to differences between the financial statement carrying
          amount of existing assets and liabilities and their respective tax
          bases and operating loss carryforwards. Deferred tax assets and
          liabilities are measured using enacted tax rates expected to apply to
          taxable income in the years in which those temporary differences are
          expected to be recovered or settled. The effect on deferred tax assets
          and liabilities of a change in tax rates is recognized in income in
          the period that includes the enactment date.


                                      F-12
<PAGE>
                 NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES

                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

2.   SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)

     (F)  Property, Plant and Equipment and Related Depreciation and
          Amortization

          Property, plant and equipment is stated at original cost. During
          periods of construction, utilities are permitted to capitalize an
          allowance for funds used during construction, which represents the
          estimated costs of funds used for construction purposes. Property,
          plant and equipment on the consolidated balance sheet includes
          construction work in progress of $13.8 million and $17.5 million at
          December 31, 2004 and 2003, respectively.

          The original cost of utility property retired is charged to
          accumulated depreciation and amortization, net of salvage and cost of
          removal. For utility property, no retirement gain or loss is included
          in income except in the case of retirements or sales of entire
          operating units. Maintenance and repairs are charged to operations in
          the period incurred.

          For utility property, the provision for depreciation and amortization
          is an integral part of the interstate pipelines' FERC tariffs. The
          effective depreciation rate applied to Northern Border Pipeline's,
          Midwestern Gas Transmission's and Viking Gas Transmission's
          transmission plant was 2.25%, 1.9% and 2.0%, respectively. Composite
          rates are applied to all other functional groups of utility property
          having similar economic characteristics. The effective depreciation
          rate applied to natural gas gathering and processing assets ranges
          from 5% to 20%. The effective depreciation rate applied to coal slurry
          assets ranges from 4% to 20%.

          The Partnership evaluates impairment of long-lived assets in
          accordance with SFAS No. 144, "Accounting for the Impairment or
          Disposal of Long-Lived Assets." Long-lived assets are reviewed for
          impairment whenever events or changes in circumstances indicate that
          the carrying amount of an asset may not be recoverable. Recoverability
          of the carrying amount of assets is measured by a comparison of the
          carrying amount of the asset to future net cash flows expected to be
          generated by the asset. If such assets are considered to be impaired,
          the impairment to be recognized is measured by the amount by which the
          carrying amount of the assets exceeds the fair value of the assets.

     (G)  Foreign Currency Translation

          For the Partnership's Canadian subsidiary, Border Midstream, asset and
          liability accounts are translated from its functional currency (the
          Canadian dollar) at year-end rates of exchange and revenue and
          expenses are translated at average exchange rates prevailing during
          the year. Translation adjustments are included as a separate component
          of other comprehensive income and partners' equity. Currency
          transaction gains and losses, which result when Border Midstream pays
          Canadian dollars to the Partnership, are recorded in other income
          (expense) and discontinued operations on the consolidated statement of
          income. During the years ended December 31, 2004 and 2003, the
          Partnership recorded currency transaction gains of $2.2 million and
          $6.0 million, respectively. Currency transaction gains were
          insignificant in 2002.


                                      F-13
<PAGE>
                 NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES

                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

2.   SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)

     (H)  Goodwill

          The excess of cost over fair value of the net assets acquired in
          business acquisitions is accounted for as goodwill. The Partnership's
          accounting for goodwill is in accordance with SFAS No. 142, "Goodwill
          and Other Intangible Assets." Among other things, SFAS No. 142
          requires entities to perform annual impairment tests by applying a
          fair-value-based analysis on the goodwill in each reporting segment.

     (I)  Equity Method of Accounting

          The Partnership accounts for its investments, which it does not
          control, by the equity method of accounting. Under this method, an
          investment is carried at its acquisition cost, plus the equity in
          undistributed earnings or losses since acquisition.

     (J)  Risk Management

          The Partnership uses financial instruments in the management of its
          interest rate and commodity price exposure. A control environment has
          been established which includes policies and procedures for risk
          assessment and the approval, reporting and monitoring of financial
          instrument activities. The Partnership does not use these instruments
          for trading purposes. SFAS No. 133, "Accounting for Derivative
          Instruments and Hedging Activities," as amended by SFAS No. 137 and
          SFAS No. 138, requires that every derivative instrument (including
          certain derivative instruments embedded in other contracts) be
          recorded on the balance sheet as either an asset or liability measured
          at its fair value. The statement requires that changes in the
          derivative's fair value be recognized currently in earnings unless
          specific hedge accounting criteria are met. Special accounting for
          qualifying hedges allows a derivative's gains and losses to offset
          related results on the hedged item in the income statement, and
          requires that a company formally document, designate and assess the
          effectiveness of transactions that receive hedge accounting. See Note
          9 for a discussion of the Partnership's derivative instruments and
          hedging activities.

     (K)  Reclassifications

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

3.   BUSINESS ACQUISITIONS AND DISPOSITIONS

     On January 17, 2003, the Partnership acquired all of the common stock of
     Viking Gas Transmission including a one-third interest in Guardian Pipeline
     for approximately $162 million, which included the assumption of $40
     million of debt.

     The Partnership has accounted for the acquisition using the purchase method
     of accounting and accordingly, operations of Viking Gas Transmission have
     been included since the date of acquisition. The purchase price has been


                                      F-14
<PAGE>
                 NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES

                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

3.   BUSINESS ACQUISITIONS AND DISPOSITIONS (continued)

     allocated based upon the estimated fair value of the assets and liabilities
     acquired as of the acquisition date. The investment in Guardian Pipeline is
     reflected in investments in unconsolidated affiliates on the consolidated
     balance sheet.

     The following is a summary of the effects of the acquisition on the
     Partnership's consolidated financial position as of December 31, 2003
     (amounts in thousands):

<TABLE>
<S>                                                 <C>
     Current assets                                 $  8,804
     Property, plant and equipment                   127,619
     Investments in unconsolidated affiliates         27,600
     Goodwill and other assets                         5,035
     Current liabilities                              (5,559)
     Long-term debt, including current maturities    (40,025)
     Other liabilities                                  (280)
                                                    --------
                                                    $123,194
                                                    ========
</TABLE>

     Border Midstream sold its undivided minority interest in the Gregg
     Lake/Obed Pipeline (Gregg Lake/Obed) for $14.0 million, effective December
     1, 2004. In June 2003, the Partnership sold its Gladys and Mazeppa
     processing plants and related gas gathering facilities located in Alberta,
     Canada for approximately $40.3 million. Operating revenues, operating
     expenses and other income and expense for 2003 and 2002 have been
     reclassified for amounts related to the discontinued operations. Operating
     revenues for discontinued operations for the years ended December 31, 2004,
     2003 and 2002, were $3.0 million, $9.9 million and $8.1 million,
     respectively. Discontinued operations on the accompanying consolidated
     statement of income consists of the following:

<TABLE>
<CAPTION>
                                                             December 31,
                                                      -------------------------
     (in thousands)                                     2004     2003      2002
     -------------                                    -------   ------   ------
<S>                                                    <C>      <C>      <C>
     Operating income                                 $ 2,248   $3,259   $1,650
     Other income (expense)                              (540)   1,747    1,587
     Gain on sale of assets                             5,026    4,056       --
     Income tax (expense) benefit                      (2,935)     276     (543)
                                                      -------   ------   ------
     Income from discontinued operations              $ 3,799   $9,338   $2,694
                                                      =======   ======   ======
</TABLE>

4.   GOODWILL AND ASSET IMPAIRMENT

     At December 31, 2004 and 2003, the Partnership's balance sheet included
     goodwill of approximately $334 million. Of the total goodwill,
     approximately $182 million was recorded in the Partnership's investment in
     unconsolidated affiliates at December 31, 2004 and 2003. The Partnership
     has selected the fourth quarter to perform its annual impairment testing.
     If testing indicates an impairment of goodwill exists in a reporting
     segment, the carrying value of tangible assets in that segment are also
     tested for impairment under SFAS No. 144.

     During 2003, due to lower throughput volumes experienced and anticipated in
     its wholly owned subsidiaries in its natural gas gathering and processing
     business segment, the Partnership accelerated its annual impairment test


                                      F-15
<PAGE>
                 NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES

                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

4.   GOODWILL AND ASSET IMPAIRMENT (continued)

     under SFAS No. 142 from the fourth quarter to the third quarter for this
     segment. For the Partnership's remaining reporting segments, the annual
     impairment testing was performed in the fourth quarter. In future years,
     unless conditions indicate earlier testing is needed, the annual impairment
     testing for all business segments will occur in the fourth quarter.

     The Partnership engaged the services of an outside independent consultant
     to assist in the determination of fair value, as defined by SFAS No. 142,
     for purposes of computing the amount of the goodwill impairment. Upon the
     determination of the existence of a goodwill impairment, the Partnership
     further analyzed, under SFAS No. 144, the carrying value of the tangible
     assets in its wholly owned subsidiaries in its natural gas gathering and
     processing business segment to determine the impairment attributed to the
     tangible assets. The Partnership recorded total impairment charges of
     $219.1 million in the third quarter of 2003. This was comprised of $76.0
     million related to the tangible assets in the Powder River Basin and $143.1
     million for the goodwill related to the natural gas gathering and
     processing business segment. Beginning October 1, 2003, the estimated
     depreciable life of the Partnership's assets in the Powder River Basin was
     reduced from 30 years to 15 years to reflect the results of the analysis
     performed.

     Changes in the carrying amount of goodwill for the years ended December 31,
     2004 and 2003, are summarized as follows:

<TABLE>
<CAPTION>
                                    Interstate    Gas Gathering
                                    Natural Gas        and         Coal
     (In thousands)                  Pipelines     Processing     Slurry     Total
     --------------                 -----------   -------------   ------   ---------
<S>                                 <C>           <C>             <C>      <C>
     Balance at December 31, 2002     $68,872       $ 398,633     $8,378   $ 475,883
     Goodwill acquired                  1,527              --                  1,527
     Impairment losses                     --        (143,066)        --    (143,066)
                                      -------       ---------     ------   ---------
     Balance at December 31, 2003      70,399         255,567      8,378     334,344
     Impairment losses                     --              --         --          --
                                      -------       ---------     ------   ---------
     Balance at December 31, 2004     $70,399       $ 255,567     $8,378   $ 334,344
                                      =======       =========     ======   =========
</TABLE>

5.   ASSET RETIREMENT OBLIGATIONS

     In 2001, the Financial Accounting Standards Board (FASB) issued SFAS No.
     143, "Accounting for Asset Retirement Obligations." SFAS No. 143 requires
     entities to record the fair value of a liability for an asset retirement
     obligation in the period in which it is incurred, if the liability can be
     reasonably estimated. When the liability is initially recorded, the
     carrying amount of the related asset is increased by the same amount. Over
     time, the liability is accreted to its future value and the accretion is
     recorded to expense. The initial adjustment to the asset is depreciated
     over its useful life. Upon settlement of the liability, an entity either
     settles the obligation for its recorded amount or incurs a gain or loss. In
     some instances, the Partnership's subsidiaries are obligated by contractual
     terms or regulatory requirements to remove facilities or perform other
     remediation upon retirement. The Partnership has, where possible, developed
     its estimate of the retirement obligations.


                                      F-16
<PAGE>
                 NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES

                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

5.   ASSET RETIREMENT OBLIGATIONS (continued)

     Effective January 1, 2003, the Partnership adopted SFAS No. 143. The
     implementation of SFAS No. 143 resulted in an increase in net property,
     plant and equipment of $2.5 million, an increase in reserves and deferred
     credits of $3.1 million and a reduction to net income of $0.6 million for
     the net-of-tax cumulative effect of change in accounting principle. The
     impact of SFAS No. 143 on prior periods' results of operations is
     immaterial. A reconciliation of the beginning and ending aggregate carrying
     amount of the Partnership's asset retirement obligations for the years
     ended December 31, 2004 and 2003, is as follows (in thousands):

<TABLE>
<S>                                               <C>
     Balance at December 31, 2002                 $    --
     Cumulative effect of transition adjustment     3,496
     Accretion expense                                159
     Liabilities transferred with asset sales      (2,016)
                                                  -------
     Balance at December 31, 2003                   1,639
     Accretion expense                                102
                                                  -------
     Balance at December 31, 2004                 $ 1,741
                                                  =======
</TABLE>

6.   RATES AND REGULATORY ISSUES

     The FERC regulates the rates and charges for transportation on the
     Partnership's interstate natural gas pipelines. Interstate natural gas
     pipeline companies may not charge rates that have been determined not to be
     just and reasonable by the FERC. Generally, rates for interstate pipelines
     are based on the cost of service including recovery of and a return on the
     pipeline's actual prudent historical cost investment. The rates and terms
     and conditions for service are found in each pipeline's FERC approved
     tariff. Under its tariff, an interstate pipeline is allowed to charge for
     its services on the basis of stated transportation rates. Transportation
     rates are established periodically in FERC proceedings known as rate cases.
     The tariff also allows the interstate pipeline to provide services under
     negotiated and discounted rates. Under the terms of settlement in Northern
     Border Pipeline's 1999 rate case, neither Northern Border Pipeline nor its
     existing shippers can seek rate changes to the settlement base rates until
     November 1, 2005, at which time Northern Border Pipeline must file a new
     rate case. Midwestern Gas Transmission and Viking Gas Transmission have no
     timing requirements or restriction in regard to future rate case filings.

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

7.   TRANSPORTATION, GATHERING AND PROCESSING AGREEMENTS

     Northern Border Pipeline's, Midwestern Gas Transmission's and Viking Gas
     Transmission's operating revenues are collected pursuant to their FERC
     tariffs through transportation service agreements. Northern Border
     Pipeline's firm service agreements extend for various terms with


                                      F-17
<PAGE>
                 NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES

                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

7.   TRANSPORTATION, GATHERING AND PROCESSING AGREEMENTS

     termination dates that range from December 2004 to December 2013. The
     termination dates for Midwestern Gas Transmission's firm service agreements
     range from December 2004 to October 2019. The termination dates for Viking
     Gas Transmission's firm service agreements range from March 2005 to October
     2014. Northern Border Pipeline, Midwestern Gas Transmission and Viking Gas
     Transmission also have interruptible transportation service agreements and
     other transportation service agreements with numerous shippers.

     Under the capacity release provisions of Northern Border Pipeline's,
     Midwestern Gas Transmission's and Viking Gas Transmission's FERC tariffs,
     shippers are allowed to release all or part of their capacity either
     permanently for the full term of the contract or temporarily. A temporary
     capacity release does not relieve the original contract shipper from its
     payment obligations if the replacement shipper fails to pay for the
     capacity temporarily released to it.

     For the interstate natural gas pipeline segment, Northern Border Pipeline's
     revenues represented approximately 86%, 86% and 95% of the segment's
     revenues in 2004, 2003 and 2002, respectively. At December 31, 2004,
     Northern Border Pipeline's largest shippers, Nexen Marketing, U.S.A. Inc
     (Nexen), BP Canada Energy Marketing Corp. (BP Canada), EnCana Marketing
     U.S.A. Inc. (EnCana) and Cargill Incorporated (Cargill), were obligated for
     approximately 18%, 14%, 13% and 12% of the summer design capacity,
     respectively. The Nexen, BP Canada, Encana and Cargill firm service
     agreements extend for various terms with termination dates from March 2005
     to December 2013, December 2004 to February 2012, October 2005 to June 2009
     and March 2005 to December 2008, respectively. For the year ending December
     31, 2004, shippers providing significant operating revenues were BP Canada
     and Encana with revenues of $65.6 million and $56.3 million, respectively.
     For the year ended December 31, 2003, Northern Border Pipeline's
     significant shippers were BP Canada, EnCana, and Pan-Alberta Gas (U.S) Inc.
     (Pan Alberta) with operating revenues of $54.7 million, $32.9 million and
     $45.5 million, respectively. For the year ended December 31, 2002, Northern
     Border Pipeline's largest shippers were Pan-Alberta and Mirant Americas
     Energy Marketing, LP with combined operating revenues of $105.5 million.

     At December 31, 2004, Northern Border Pipeline had contracted firm capacity
     held by one shipper affiliated with its general partners. ONEOK Energy
     Services Company L.P. (ONEOK Energy Services), a subsidiary of ONEOK, holds
     firm service agreements representing 3% of summer design capacity. The firm
     service agreements with ONEOK Energy Services extend for various terms with
     termination dates that range from March 2005 to March 2009. ONEOK Energy
     Services became affiliated with Northern Border Pipeline on November 17,
     2004 in connection with ONEOK's purchase of Northern Plains. Revenues from
     ONEOK Energy Services for the period from the date of affiliation to
     December 31, 2004 were $1.1 million. At December 31, 2004, Northern Border
     Pipeline had an outstanding receivable from ONEOK Energy Services of $0.8
     million. In 2003, there were no operating revenues from affiliates. In
     2002, one of Northern Border Pipeline's shippers was affiliated with its
     general partners. Operating revenues from affiliates were $1.4 million for
     the year ended December 31, 2002.


                                      F-18
<PAGE>
                 NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES

                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

7.   TRANSPORTATION, GATHERING AND PROCESSING AGREEMENTS (continued)

     The gas gathering and processing businesses provide services for gathering,
     treating, processing and compression of natural gas and the fractionation
     of natural gas liquids. For the year ended December 31, 2004, Bear Paw
     Energy's largest customers, Lodgepole Energy Marketing (Lodgepole), BP
     Canada Energy Marketing Corp. (BP Canada) and Montana Dakota Utilities
     accounted for $82.0 million (44%), $26.7 million (14%) and $21.7 million
     (12%), respectively of Bear Paw Energy's operating revenues. For the year
     ended December 31, 2003, Bear Paw Energy's largest customers, Lodgepole,
     Tenaska Marketing Ventures (Tenaska) and BP Canada accounted for $62.4
     million (40%), $27.3 million (18%) and $16.6 million (11%), respectively,
     of Bear Paw Energy's operating revenue. For the year ended December 31,
     2002, Bear Paw Energy's largest customers, Lodgepole and Tenaska accounted
     for $44.2 million (35%) and $20.2 million (16%), respectively, of Bear Paw
     Energy's operating revenue. Crestone Energy Venture's revenues from
     affiliates totaled $0.2 million, $0.1 million and $0.2 million in 2004,
     2003 and 2002, respectively.

     Black Mesa's operating revenue is derived from a transportation agreement
     with Peabody Western Coal, the coal supplier for the Mohave Generating
     Station that expires in December 2005. The coal slurry pipeline is the sole
     source of fuel for the Mohave plant. Operating revenues under the agreement
     totaled $22.0 million, $21.4 million and $21.5 million for the years ended
     December 31, 2004, 2003, and 2002, respectively.

8.   CREDIT FACILITIES, LONG-TERM DEBT AND CAPITAL LEASES

     Detailed information on long-term debt is as follows:

<TABLE>
<CAPTION>
                                                                    December 31,
                                                              -----------------------
     (In thousands)                                              2004         2003
     --------------                                           ----------   ----------
<S>                                                           <C>          <C>
     Northern Border Pipeline
        2002 Pipeline Credit Agreement - average
           1.95% at December 31, 2003, due 2005               $       --   $  131,000
        1999 Pipeline Senior Notes - 7.75%, due 2009             200,000      200,000
        2001 Pipeline Senior Notes - 7.50%, due 2021             250,000      250,000
        2002 Pipeline Senior Notes - 6.25%, due 2007             150,000      225,000
     Viking Gas Transmission
        Senior Notes (Series A) - 6.65%, due 2008                  8,178       10,311
        Senior Notes (Series B) - 7.10%, due 2011                  2,520        2,850
        Senior Notes (Series C) - 7.31%, due 2012                  7,311        8,167
        Senior Notes (Series D) - 8.04%, due 2014                 13,111       14,333
     Northern Border Partners, L.P.
        2003 Partnership Credit Agreement -
           average 3.20% and 2.67% at December 31, 2004
           and 2003, respectively, due 2007                      191,000       46,000
        2000 Partnership Senior Notes - 8 7/8%, due 2010         250,000      250,000
        2001 Partnership Senior Notes - 7.10%, due 2011          225,000      225,000
     Bear Paw Energy Capital Leases                                3,110        6,090
     Fair value adjustment for interest rate swaps (Note 9)        2,555       19,553
     Unamortized debt premium                                     27,573       27,682
                                                              ----------   ----------
     Total                                                     1,330,358    1,415,986
     Less: Current maturities of long-term debt                    5,126        7,740
                                                              ----------   ----------
     Long-term debt                                           $1,325,232   $1,408,246
                                                              ==========   ==========
</TABLE>


                                      F-19
<PAGE>
                 NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES

                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

8.   CREDIT FACILITIES, LONG-TERM DEBT AND CAPITAL LEASES (continued)

     The Partnership and Northern Border Pipeline have entered into revolving
     credit facilities, which are used for capital expenditures, acquisitions
     and general business purposes and for refinancing existing indebtedness.
     Northern Border Pipeline entered into a $175 million three-year credit
     agreement (2002 Pipeline Credit Agreement) with certain financial
     institutions in May 2002. The Partnership entered into a $275 million
     four-year credit agreement (2003 Partnership Credit Agreement) with certain
     financial institutions in November 2003. Both of the revolving credit
     facilities permit the Partnership and Northern Border Pipeline to choose
     among various interest rate options, to 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.

     In April 2002, Northern Border Pipeline completed a private offering of
     $225 million of 6.25% Senior Notes due 2007 (2002 Pipeline Senior Notes).
     The 2002 Pipeline Senior Notes were subsequently exchanged in registered
     offerings for notes with substantially identical terms. The proceeds from
     the senior notes were used to reduce indebtedness outstanding.

     On December 1, 2004, Northern Border Pipeline redeemed $75 million of the
     2002 Pipeline Senior Notes. In connection with the redemption, Northern
     Border Pipeline was required to pay a premium of $4.8 million and received
     $2.5 million from the termination of interest rate swaps associated with
     the debt (see Note 9). The net loss from the redemption, including
     unamortized debt costs and discounts associated with the debt, is recorded
     as a loss on reacquired debt and amortized to interest expense over the
     remaining life of the 2002 Pipeline Senior Notes. At December 31, 2004, the
     unamortized loss on reacquired debt was $2.6 million and is included in
     other assets on the consolidated balance sheet.

     Interest paid, net of amounts capitalized, during the years ended December
     31, 2004, 2003 and 2002 was $77.7 million, $86.7 million and $88.2 million,
     respectively.

     Aggregate repayments of long-term debt required for the next five years,
     excluding payments required under Bear Paw Energy's capital leases, are as
     follows: $2 million, $2 million, $343 million, $2 million and $200 million
     for 2005, 2006, 2007, 2008 and 2009, respectively.

     The indentures under which the 1999, 2001 and 2002 Pipeline Senior Notes
     were issued do not limit the amount of indebtedness or other obligations
     that Northern Border Pipeline may incur, but do contain material financial
     covenants, including restrictions on the incurrence of secured
     indebtedness. The 2002 Pipeline Credit Agreement requires the maintenance
     of a ratio of EBITDA (net income plus interest expense, income taxes and
     depreciation and amortization) to interest expense to be greater than 3 to
     1. The 2002 Pipeline Credit Agreement also requires the maintenance of the
     ratio of indebtedness to EBITDA of no more than 4.5 to 1. At December 31,
     2004, Northern Border Pipeline was in compliance with its financial
     covenants.

     At December 31, 2004, Viking Gas Transmission has four series of senior
     notes outstanding. In November 2004, Viking Gas Transmission amended the
     indenture on its senior notes. Prior to the amendment, Viking Gas
     Transmission made monthly principal and interest payments on the four
     series


                                      F-20
<PAGE>
                 NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES

                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

8.   CREDIT FACILITIES, LONG-TERM DEBT AND CAPITAL LEASES (continued)

     of notes. As a result of the amendment, three of the series of senior notes
     due between 2011 and 2014 require payment of interest quarterly and payment
     of principal at maturity. The senior notes due in 2008 continue to require
     monthly principal and interest payments. Under the previous indenture,
     Viking Gas Transmission's transportation contracts were pledged as security
     for payment, which has been replaced in the current indenture by a
     guarantee by the Partnership. In addition, Viking Gas Transmission is no
     longer required to maintain debt service funds on deposit in an amount
     equal to all scheduled payments of principal and interest for the 180-day
     period following the current month end. At December 31, 2003, the
     requirement for accumulation of debt service funds was $3.7 million. The
     senior notes contain certain financial covenants and at December 31, 2004,
     Viking Gas Transmission was in compliance with its financial covenants.

     The indentures under which the 2001 and 2000 Partnership Senior Notes were
     issued do not limit the amount of indebtedness or other obligations that
     the Partnership may incur, but do contain material financial covenants,
     including restrictions on the incurrence of secured indebtedness. The
     indentures also contain a provision that would require the Partnership to
     offer to repurchase the 2001 and 2000 Partnership Senior Notes if either
     Standard & Poor's Rating Services or Moody's Investor Service, Inc. rate
     the notes below investment grade and the investment grade rating is not
     reinstated for a period of 40 days. The 2003 Partnership Credit Agreement
     requires the maintenance of a ratio of consolidated EBITDA (consolidated
     net income plus minority interests in net income, consolidated interest
     expense, income taxes, depreciation and amortization and all other non-cash
     charges) to consolidated interest expense of greater than 3 to 1. The 2003
     Partnership Credit Agreement also requires the maintenance of the ratio of
     consolidated total debt to adjusted consolidated EBITDA (EBITDA adjusted
     for pro forma operating results of acquisitions made during the year) of no
     more than 4.5 to 1. If the Partnership consummates one or more acquisitions
     in which the aggregate purchase price is $25 million or more, the allowable
     ratio of consolidated total debt to adjusted consolidated EBITDA
     temporarily increases to 5 to 1. At December 31, 2004, the Partnership was
     in compliance with these covenants.

     Bear Paw Energy has entered into non-cancelable capital leases on
     compressors. The capital leases incorporate annual interest rates ranging
     from 7.10% to 8.85% and are for a term of five years, after which Bear Paw
     Energy receives ownership of the equipment. Future minimum payments under
     Bear Paw Energy's capital leases are as follows (in thousands):

<TABLE>
<S>                                      <C>
        Years ending December 31,
                2005                     $3,145
                2006                        117
                                         ------
                                         $3,262
     Less amount representing interest      152
                                         ------
     Present value of lease payments      3,110
     Less: current portion                2,993
                                         ------
     Long-term portion                   $  117
                                         ======
</TABLE>

     The following estimated fair values of financial instruments represent the
     amount at which each instrument could be exchanged in a current transaction
     between willing parties. Based on quoted market prices for similar issues


                                      F-21
<PAGE>
                 NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES

                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

8.   CREDIT FACILITIES, LONG-TERM DEBT AND CAPITAL LEASES (continued)

     with similar terms and remaining maturities, the estimated fair value of
     the aggregate of the 1999 Pipeline Senior Notes, 2000 Partnership Senior
     Notes, 2001 Partnership Senior Notes, 2001 Pipeline Senior Notes, 2002
     Pipeline Senior Notes and Viking Gas Transmission Senior Notes was
     approximately $1,205 million and $1,306 million at December 31, 2004 and
     2003, respectively. The Partnership presently intends to maintain the
     current schedule of maturities for the 1999 Pipeline Senior Notes, 2000
     Partnership Senior Notes, 2001 Partnership Senior Notes, 2001 Pipeline
     Senior Notes, 2002 Pipeline Senior Notes and Viking Gas Transmission Senior
     Notes, which will result in no gains or losses on their respective
     repayment. The fair value of the 2003 Partnership Credit Agreement and the
     2002 Pipeline Credit Agreement approximates the carrying value since the
     interest rates are periodically adjusted to reflect current market
     conditions.

9.   DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

     The Partnership reflects in consolidated accumulated other comprehensive
     income its 70% share of Northern Border Pipeline's accumulated other
     comprehensive income. The remaining 30% is reflected as an adjustment to
     minority interests in partners' equity. The Partnership also reflects in
     consolidated accumulated other comprehensive income its ownership share of
     accumulated other comprehensive income of its unconsolidated affiliates
     (see Note 10).

     Prior to the anticipated issuance of fixed rate debt, both the Partnership
     and Northern Border Pipeline have entered into forward starting interest
     rate swap agreements. The interest rate swap agreements have been
     designated as cash flow hedges as they hedge the fluctuations in Treasury
     rates and spreads between the execution date of the swap agreements and the
     issuance of the fixed rate debt. The notional amount of the interest rate
     swap agreements does not exceed the expected principal amount of fixed rate
     debt to be issued. Upon issuance of the fixed rate debt, the swap
     agreements were terminated and the proceeds received or amounts paid to
     terminate the swap agreements were recorded in accumulated other
     comprehensive income and amortized to interest expense over the term of the
     hedged debt. The Partnership also recorded an adjustment to minority
     interests in partners' equity for Northern Border Pipeline's terminated
     swap agreements.

     On December 9, 2004, the Partnership 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 note issuance to be placed in
     the first half of 2005. At December 31, 2004, the Partnership has recorded
     a derivative instrument liability of $0.8 million, the fair value of the
     interest rate swap agreements, with a corresponding offset to accumulated
     other comprehensive income.

     For the year ended December 31, 2002, Northern Border Pipeline received
     $2.4 million from terminated interest rate swap agreements that had been
     designated as cash flow hedges, of which $1.6 million was recorded in
     accumulated other comprehensive income and $0.8 million was recorded as an
     adjustment to minority interests in partners' equity.


                                      F-22
<PAGE>
                 NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES

                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

9.   DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES (continued)

     During the years ended December 31, 2004, 2003 and 2002, the Partnership
     and Northern Border Pipeline amortized approximately $2.1 million, $2.2
     million and $2.1 million, respectively, related to the terminated interest
     rate swap agreements, as a reduction to interest expense from accumulated
     other comprehensive income. A comparable amount is expected to be amortized
     in 2005.

     At December 31, 2004 and 2003, the Partnership had outstanding interest
     rate swaps with notional amounts totaling $150 million. Under the interest
     rate swap agreements, the Partnership makes payments to counterparties at
     variable rates based on the London Interbank Offered Rate and in return
     receives payments based on a 7.10% fixed rate. At December 31, 2004 and
     2003, the average effective interest rate on the Partnership's interest
     rate swap agreements was 4.60% and 3.72%, respectively.

     Northern Border Pipeline entered into interest rate swap agreements with
     notional amounts totaling $225 million in May 2002. Under the interest rate
     swap agreements, Northern Border Pipeline makes payments to counterparties
     at variable rates based on the London Interbank Offered Rate and in return
     receives payments based on a 6.25% fixed rate. At December 31, 2003 the
     average effective interest rate on Northern Border Pipeline's interest rate
     swap agreements was 2.31%.

     In November 2004, Northern Border Pipeline terminated its interest rate
     swap agreements with notional amounts totaling $225 million and received
     $7.5 million. Of the total proceeds, $2.5 million related to the redemption
     of $75 million of the 2002 Pipeline Senior Notes (see note 8). In October
     2002, the Partnership agreed to an increase in the variable interest rate
     on two of its interest rate swap agreements with notional amounts totaling
     $150 million. As consideration for the change to the variable interest
     rate, the Partnership received approximately $18.2 million, which
     represented the fair value of the financial instruments at the date of the
     adjustment. In March 2003, the Partnership terminated one of its interest
     rate swap agreements with a notional amount of $75 million and received
     $12.3 million. The Partnership used the proceeds to repay amounts borrowed
     under its credit facility.

     The Partnership and Northern Border Pipeline records 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. During the years ended December 31, 2004, 2003 and 2002, the
     Partnership and Northern Border Pipeline amortized approximately $3.3
     million, $3.4 million and $0.5 million, respectively, as a reduction to
     interest expense. The Partnership and Northern Border Pipeline expect to
     amortize approximately $5.2 million as a reduction to interest expense in
     2005 for these agreements.

     Both the Partnership's and Northern Border Pipeline's 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 the
     Partnership in 2001 and by Northern Border Pipeline in 2002.


                                      F-23
<PAGE>
                 NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES

                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

9.   DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES (continued)

     The accompanying consolidated balance sheet at December 31, 2004 and 2003,
     reflects an unrealized gain of approximately $2.6 million and $19.6
     million, respectively, in derivative financial instruments with a
     corresponding increase in long-term debt.

     Bear Paw Energy periodically enters into commodity derivatives 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 gas and natural gas liquid price volatility. During
     the years ended December 31, 2004, 2003 and 2002, respectively, Bear Paw
     Energy recognized losses of $9.4 million, $8.5 million and $2.8 million
     from the settlement of derivative contracts. At December 31, 2004, the
     consolidated balance sheet reflected an unrealized gain of approximately
     $2.0 million in derivative financial instruments with a corresponding
     increase of $2.0 million in accumulated other comprehensive income. At
     December 31, 2003, the consolidated balance sheet reflected an unrealized
     loss of approximately $5.7 million in derivative financial instruments with
     a corresponding reduction of $5.5 million in accumulated other
     comprehensive income. For 2005, if prices remain at current levels, Bear
     Paw Energy expects to reclassify approximately $2.0 million from
     accumulated other comprehensive income as an increase to operating
     revenues. However, this increase would be offset with decreased operating
     revenues due to the lower prices assumed.

     At September 30, 2001, Bear Paw Energy had outstanding commodity price swap
     arrangements with ENA, which had been accounted for as cash flow hedges,
     and resulted in Bear Paw Energy recording a non-cash gain of approximately
     $6.7 million in accumulated other comprehensive income. During the fourth
     quarter of 2001, the Partnership determined that ENA was no longer likely
     to honor the obligations it had to Bear Paw Energy for these derivatives
     and terminated the swap arrangements (see Note 18). In accordance with SFAS
     No. 133, Bear Paw Energy ceased to account for these derivatives as hedges.
     The gain previously recorded in accumulated other comprehensive income is
     reflected in earnings in the same periods during which the hedged
     forecasted transactions will affect earnings. During the years ended
     December 31, 2004, 2003 and 2002, the Partnership recorded approximately
     $0.2 million, $0.3 million and $4.6 million, respectively, in earnings and
     expects to record approximately $0.1 million in earnings in 2005.

10.  UNCONSOLIDATED AFFILIATES

     The Partnership's investments in unconsolidated affiliates which are
     accounted for by the equity method is as follows:

<TABLE>
<CAPTION>
                                                  Net          December 31,
                                               Ownership   ---------------------
     (In thousands)                            Interest      2004         2003
     --------------                            ---------   --------     --------
<S>                                            <C>         <C>          <C>
     Bighorn                                      (a)      $ 92,350     $ 94,153
     Fort Union                                   33%        71,710       70,278
     Lost Creek                                   35%        74,935       71,177
     Guardian Pipeline                            33%        34,207       32,558
                                                           --------     --------
                                                           $273,202(b)  $268,166
                                                           ========     ========
</TABLE>


                                      F-24
<PAGE>
                 NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES

                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

10.  UNCONSOLIDATED AFFILIATES (continued)

     (a)  The Partnership held a 49% common membership interest in Bighorn and
          100% of the non-voting preferred A shares of Bighorn at December 31,
          2004 and 2003. Bighorn's ownership structure consists of common
          membership interests and non-voting preferred A and B shares. Both of
          the non-voting classes of shares are subject to certain distribution
          preferences and limitations based on the cumulative number of wells
          connected to the Bighorn system at the end of each calendar year.
          These shares will receive an income allocation equal to the cash
          distributions received and are not entitled to any other allocations
          of income or distributions of cash. Ownership of these shares does not
          affect the amount of capital contributions that may be required to be
          made to the operations of Bighorn by the owners of the common
          membership interests.

     (b)  The unamortized excess of the Partnership's investments in
          unconsolidated affiliates over the underlying fair value of the net
          assets accounted for under the equity method was $181.6 million at
          December 31, 2004 and 2003.

     The Partnership's equity earnings of unconsolidated affiliates is as
     follows:

<TABLE>
<CAPTION>
     (In thousands)                                    2004      2003      2002
     --------------                                  -------   -------   -------
<S>                                                  <C>       <C>       <C>
     Bighorn                                         $ 5,832   $ 6,467   $ 3,764
     Fort Union                                        5,357     5,953     5,540
     Lost Creek                                        5,176     4,403     3,679
     Guardian Pipeline                                 1,650     1,992        --
                                                     -------   -------   -------
                                                     $18,015   $18,815   $12,983
                                                     =======   =======   =======
</TABLE>

     Summarized combined financial information of the Partnership's
     unconsolidated affiliates is presented below:

<TABLE>
<CAPTION>
                                                                December 31,
                                                            --------------------
     (In thousands)                                           2004       2003
     --------------                                         --------   --------
<S>                                                         <C>        <C>
     Balance sheet
        Current assets                                      $ 37,651   $ 34,101
        Property, plant and equipment, net                   466,775    470,840
        Other noncurrent assets                                3,224      3,260
        Current liabilities                                   39,936     44,013
        Long-term debt                                       224,965    243,620
        Other noncurrent liabilities                           2,605      4,958
        Accumulated other comprehensive income                (2,605)    (4,958)
        Owners' equity                                       242,749    220,568
</TABLE>

<TABLE>
<CAPTION>
     (In thousands)                                    2004      2003      2002
     --------------                                  -------   -------   -------
<S>                                                  <C>       <C>       <C>
     Income statement
        Operating revenues                           $92,402   $94,318   $57,364
        Operating expenses                            34,160    31,927    17,976
        Net income                                    39,736    42,583    33,065
     Distributions paid to the Partnership           $13,946   $16,262   $10,820
</TABLE>


                                      F-25
<PAGE>
                 NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES

                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

11.  PARTNERS' EQUITY

     At December 31, 2004 and 2003, partners' equity consisted of 46,397,214
     common units representing an effective 98% limited partner interest in the
     Partnership and a 2% general partner interest. At December 31, 2004 and
     2003, approximately 1.1% of the limited partner interest was held by
     Northern Plains. Sundance Assets, L.P. (Sundance), an indirect subsidiary
     of Enron) held approximately 5.8% of the limited partnership interest at
     December 31, 2003. Sundance sold its limited partner interest during 2004.
     The Partnership did not receive any proceeds from the sale.

     In conjunction with the issuance of additional common units, the
     Partnership's general partners are required to make equity contributions to
     the Partnership to maintain a 2% general partner interest in accordance
     with the partnership agreements.

     In May and June 2003, the Partnership sold 2,250,000 and 337,500 common
     units, respectively. In July 2002, the Partnership sold 2,186,700 common
     units. The net proceeds from the sale of common units and the general
     partners' contributions totaled approximately $102.2 million in 2003 and
     $75.4 million in 2002 and were primarily used to repay indebtedness
     outstanding.

     Under the partnership agreement, the Partnership will make distributions to
     its partners with respect to each calendar quarter in an amount equal to
     100% of its Available Cash. "Available Cash" generally consists of all of
     the cash receipts of the Partnership adjusted for its cash disbursements
     and net changes to cash reserves. Available Cash will generally be
     distributed 98% to the Unitholders and 2% to the General Partners. As an
     incentive, the General Partners' percentage interest in quarterly
     distributions is increased after certain specified target levels are met.
     Under the incentive distribution provisions, the General Partners receive
     15% of amounts distributed in excess of $0.605 per common unit, 25% of
     amounts distributed in excess of $0.715 per unit and 50% of amounts
     distributed in excess of $0.935 per unit. Partnership income is allocated
     to the General Partners and the limited partners in accordance with their
     respective partnership percentages, after giving effect to any priority
     income allocations for incentive distributions that are allocated to the
     General Partners. For the years ended December 31, 2004, 2003 and 2002,
     incentive distributions to the General Partners totaled $8.0 million, $7.7
     million and $7.3 million, respectively.

12.  NORTHERN BORDER PIPELINE CASH DISTRIBUTION POLICY

     The Northern Border Pipeline partnership agreement provides that
     distributions to Northern Border Pipeline's partners are to be made on a
     pro rata basis according to each partner's capital account balance. The
     Northern Border Pipeline Management Committee determines the amount and
     timing of such distributions. Any changes to, or suspension of, the cash
     distribution policy of Northern Border Pipeline requires the unanimous
     approval of the Northern Border Pipeline Management Committee. In December
     2003, Northern Border Pipeline's Management Committee voted to (i) issue
     equity cash calls to its partners in the total amount of $130 million in
     early 2004 and $90 million in 2007; (ii) fund future growth capital


                                      F-26
<PAGE>
                 NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES

                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

12.  NORTHERN BORDER PIPELINE CASH DISTRIBUTION POLICY (continued)

     expenditures with 50% equity capital contributions from its partners; and
     (iii) change the cash distribution policy of Northern Border Pipeline.
     Effective January 1, 2004, cash distributions are equal to 100% of
     distributable cash flow as determined from Northern Border Pipeline's
     financial statements based upon earnings before interest, taxes,
     depreciation and amortization less interest expense and maintenance capital
     expenditures. Effective January 1, 2008, the cash distribution policy will
     be adjusted to maintain a consistent capital structure. On November 30,
     2004, Northern Border Pipeline issued an equity cash call to its partners
     in the total amount of $75 million, which was utilized to repay existing
     bank debt. This equity contribution will reduce the previously approved
     2007 equity cash call from $90 million to $15 million.

13.  COMMITMENTS AND CONTINGENCIES

     Firm Transportation Obligations and Other Commitments

     Crestone Energy Ventures has firm transportation agreements with Fort Union
     and Lost Creek. Under these agreements, Crestone Energy Ventures must make
     specified minimum payments each month. Crestone Energy Ventures recorded
     expenses of $11.8 million, $11.7 million and $ 11.4 million for the years
     ended December 31, 2004, 2003 and 2002, respectively, related to these
     agreements. At December 31, 2004, the estimated aggregate amounts of such
     required future payments were $11.6 million annually for 2005 through 2008,
     $11.1 million for 2009 and $3.7 million for later years.

     At December 31, 2004, the Partnership has guaranteed the performance of
     certain of its unconsolidated affiliates in connection with credit
     agreements that expire in March 2009 and September 2009. Collectively, at
     December 31, 2004, the amount of both guarantees was $4.4 million.

     Operating Leases

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

<TABLE>
<S>                             <C>
     Year ending December 31,
               2005             $ 4,489
               2006               4,024
               2007               3,154
               2008               2,978
               2009               2,392
               Thereafter        66,385
                                -------
                                $83,422
                                =======
</TABLE>

     Expenses incurred related to these lease obligations for the years ended
     December 31, 2004, 2003 and 2002, were $3.8 million, $3.7 million and $2.0
     million, respectively.


                                      F-27
<PAGE>
                 NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES

                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

13.  COMMITMENTS AND CONTINGENCIES (continued)

     Cash Balance Plan

     As further discussed in Note 18, on December 31, 2003, Enron filed a motion
     seeking approval of the Bankruptcy Court to provide additional funding to,
     and for authority to, terminate the Enron Corp. Cash Balance Plan and
     certain other defined benefit plans. The Partnership recorded charges
     associated with the termination of the cash balance plan of $6.2 million in
     2003. In 2004, the Partnership reduced its expense by $6.2 million, since
     it determined it is no longer liable for terminations costs of the Cash
     Balance Plan.

     Capital Expenditures

     Total capital expenditures for 2005 are estimated to be $87 million. This
     includes approximately $57 million for interstate natural gas pipeline
     facilities, $25 million for natural gas gathering and processing facilities
     and $5 million for information technology systems. Funds required to meet
     the capital requirements for 2005 are anticipated to be provided from
     credit facilities and operating cash flows.

     Environmental Matters

     The Partnership is not aware of any material contingent liabilities with
     respect to compliance with applicable environmental laws and regulations.

     Other

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

     Various legal actions that have arisen in the ordinary course of business
     are pending. The Partnership believes that the resolution of these issues
     will not have a material adverse impact on the Partnership's results of
     operations or financial position.


                                      F-28
<PAGE>
                 NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES

                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

14.  INCOME TAXES

     Components of the income tax provision applicable to continuing operations
     and income taxes paid by the Partnership's corporate subsidiaries are as
     follows (in thousands):

<TABLE>
<CAPTION>
                                                         Year Ended December 31,
                                                        ------------------------
                                                         2004     2003     2002
                                                        ------   ------   ------
<S>                                                     <C>      <C>      <C>
     Taxes currently payable:
        Federal                                         $1,346   $  900   $  453
        State                                              289      311       87
                                                        ------   ------   ------
           Total                                         1,635    1,211      540
                                                        ------   ------   ------
     Taxes deferred:
        Federal                                          2,789    2,842      934
        State                                              712      652      169
                                                        ------   ------   ------
           Total                                         3,501    3,494    1,103
                                                        ------   ------   ------
     Total tax provision                                $5,136   $4,705   $1,643
                                                        ======   ======   ======
     Income taxes paid                                  $5,346   $1,544   $   32
                                                        ======   ======   ======
</TABLE>

     The difference between the statutory federal income tax rate and the
     Partnership's effective income tax rate is summarized as follows:

<TABLE>
<CAPTION>
                                                         Year Ended December 31,
                                                         -----------------------
                                                          2004    2003     2002
                                                         -----   -----    -----
<S>                                                      <C>     <C>      <C>
     Federal income tax rate                              35.0%   35.0%    35.0%
     Increase (decrease) as a result of:
        Partnership earnings not subject to tax          (35.0)  (35.0)   (35.0)
        Corporate subsidiary earnings subject to tax       2.8    (4.1)     1.3
        State taxes                                        0.7    (1.0)     0.2
                                                         -----   -----    -----
     Effective tax rate                                    3.5%   (5.1)%    1.5%
                                                         =====   =====    =====
</TABLE>

     Deferred tax assets and liabilities result from the following (in
     thousands):

<TABLE>
<CAPTION>
                                                                  December 31,
                                                               -----------------
                                                                 2004      2003
                                                               -------   -------
<S>                                                            <C>       <C>
     Deferred tax assets:
        Net operating loss                                     $ 6,606   $ 6,379
        Plant related differences                                2,333       670
        Joint venture income                                        --       675
        Other                                                      410       816
                                                               -------   -------
     Total deferred tax assets                                 $ 9,349   $ 8,540
                                                               -------   -------
     Deferred tax liabilities:
        Goodwill                                               $ 5,458   $ 4,383
        Accelerated depreciation and other plant
           related differences                                   3,514     3,829
        Partnership income                                       7,563     3,226
                                                               -------   -------
     Total deferred tax liabilities                            $16,535   $11,438
                                                               -------   -------
     Net deferred tax liabilities                              $ 7,186   $ 2,898
                                                               =======   =======
</TABLE>


                                      F-29
<PAGE>
                 NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES

                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

14.  INCOME TAXES (continued)

     The Partnership had available, at December 31, 2004, approximately $6.6
     million of tax benefits related to net operating loss carryforwards, which
     will expire between the years 2008 and 2024. The Partnership believes that
     it is more likely than not that the tax benefits of the net operating loss
     carryforwards will be utilized prior to their expiration; therefore, no
     valuation allowance is necessary.

15.  ACCOUNTING PRONOUNCEMENTS

     In December 2003, the FASB issued Interpretation No. (FIN) 46 (revised
     December 2003), "Consolidation of Variable Interest Entities," which
     addresses how a business enterprise should evaluate whether it has a
     controlling financial interest in an entity through means other than voting
     rights and accordingly should consolidate the entity; such entities are
     known as variable interest entities. The Partnership adopted FIN 46 as of
     January 1, 2004. In connection with the adoption of FIN 46, the Partnership
     evaluated its investments in Bighorn, Fort Union, Lost Creek and Guardian
     Pipeline and determined that these entities are appropriately accounted for
     as equity method investments. The adoption of FIN 46 did not have an effect
     on the Partnership's financial position, results of operations or cash
     flows.

     In December 2004, the FASB issued SFAS No. 153, "Exchanges of Nonmonetary
     Assets." This Statement amends the guidance in APB Opinion No. 29,
     "Accounting for Nonmonetary Transactions." APB 29 provided an exception to
     the basic measurement principle (fair value) for exchanges of similar
     assets, requiring that some nonmonetary exchanges be recorded on a
     carryover basis. SFAS 153 eliminates the exception to fair value for
     exchanges of similar productive assets and replaces it with a general
     exception for exchange transactions that do not have commercial substance,
     that is, transactions that are not expected to result in significant
     changes in the cash flows of the reporting entity. The provisions of SFAS
     153 are effective for exchanges of nonmonetary assets occurring in fiscal
     periods beginning after June 15, 2005. The Partnership believes that SFAS
     153 will not have a significant effect on the financial position, results
     of operations, and cash flows of the Partnership.

16.  BUSINESS SEGMENT INFORMATION

     The Partnership's business is divided into three reportable segments,
     defined as components of the enterprise about which financial information
     is available and evaluated regularly by the Partnership's executive
     management and the Partnership Policy Committee in deciding how to allocate
     resources to an individual segment and in assessing performance of the
     segment.

     The Partnership's reportable segments are strategic business units that
     offer different services. Each are managed separately because each business
     requires different marketing strategies. These segments are as follows: the
     Interstate Natural Gas Pipeline segment provides natural gas transmission
     services; the Natural Gas Gathering and Processing segment 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 transports crushed coal suspended in water. The accounting
     policies of the segments are the same as those described in the summary of
     significant accounting policies in Note 2.


                                      F-30
<PAGE>
                 NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES

                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

16.  BUSINESS SEGMENT INFORMATION (continued)

The Partnership evaluates 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 its segments and to internally manage those business segments and
believes that EBITDA is a good indicator of each segment's performance. EBITDA
should not be considered an alternative to, or more meaningful than, net income
or cash flow as determined in accordance with GAAP. EBITDA calculations may vary
from company to company, so the Partnership's computation of EBITDA may not be
comparable to a similarly titled measure of another company. The following table
shows how EBITDA is calculated:

RECONCILIATION OF NET INCOME (LOSS) TO EBITDA

<TABLE>
<CAPTION>
                                                                   Natural
                                                    Interstate       Gas
                                                      Natural     Gathering
                                                        Gas          and        Coal
     (In thousands)                                  Pipelines   Processing    Slurry    Other(a)     Total
     --------------                                 ----------   ----------   --------   --------   ---------
<S>                                                 <C>          <C>          <C>        <C>        <C>
     2004
     Net income (loss)                              $ 134,726     $  44,488    $ 3,088   ($37,582)  $ 144,720
     Minority interest                                 50,033            --         --         --      50,033
     Interest expense, net                             43,882           369         11     32,681      76,943
     Depreciation and amortization                     67,487        14,851      4,465        400      87,203
     Income tax                                         4,783            26        327      2,935       8,071
     AFUDC                                               (117)           --         --         --        (117)
                                                    ---------     ---------    -------   --------   ---------
     EBITDA                                         $ 300,794     $  59,734    $ 7,891   ($ 1,566)  $ 366,853
                                                    =========     =========    =======   ========   =========

     2003
     Net income (loss)                              $ 119,620     ($183,016)   $ 3,658   ($28,716)  ($ 88,454)
     Cumulative effect of change in accounting
      principle, net of tax                                --            --        434        209         643
     Minority interest                                 44,460            --         --         --      44,460
     Interest expense, net                             47,577           591         33     30,779      78,980
     Depreciation and amortization                     66,245       232,777      1,848      1,107     301,977
     Income tax                                         3,629            --      1,076       (276)      4,429
     AFUDC                                               (331)           --         --         --        (331)
                                                    ---------     ---------    -------   --------   ---------
     EBITDA                                         $ 281,200     $  50,352    $ 7,049   $  3,103   $ 341,704
                                                    =========     =========    =======   ========   =========

     2002
     Net income (loss)                              $ 107,510     $  35,568    $ 4,136   ($33,538)  $ 113,676
     Minority interest                                 42,816            --         --         --      42,816
     Interest expense, net                             51,525           794         33     30,546      82,898
     Depreciation and amortization                     61,002        12,102      1,568      1,202      75,874
     Income tax                                           730            --        913        543       2,186
     AFUDC                                               (248)           --         --         --        (248)
                                                    ---------     ---------    -------   --------   ---------
     EBITDA                                         $ 263,335     $  48,464    $ 6,650   ($ 1,247)  $ 317,202
                                                    =========     =========    =======   ========   =========
</TABLE>

     BUSINESS SEGMENT DATA

<TABLE>
<CAPTION>
                                                                   Natural
                                                    Interstate       Gas
                                                      Natural     Gathering     Coal
                                                        Gas          and       Slurry
     (In thousands)                                  Pipelines   Processing   Pipeline   Other(a)      Total
     --------------                                 ----------   ----------   --------   --------   ----------
<S>                                                 <C>          <C>          <C>        <C>        <C>
     2004
     Revenues from external customers               $  383,625   $ 184,738    $22,020    $    --    $  590,383
     Depreciation and amortization                      67,115      14,851      4,465         --        86,431
     Operating income (loss)                           231,027      28,278      3,446     (9,366)      253,385
     Interest expense, net                              43,882         369         11     32,681        76,943
     Equity earnings of unconsolidated affiliates        1,649      16,366         --         --        18,015
     Other income (expense), net                           748         239        (20)       666         1,633
     Income tax expense                                  4,783          26        327         --         5,136
     Capital expenditures                               16,258      25,646      1,573         --        43,477
     Identifiable assets                             1,866,348     337,502     18,268     15,236     2,237,354
     Investments in unconsolidated affiliates           34,207     238,995         --         --       273,202
     Total assets                                   $1,900,555   $ 576,497    $18,268    $15,236    $2,510,556

     2003
     Revenues from external customers               $  375,256   $ 154,284    $21,408    $    --    $  550,948
     Depreciation and amortization (b)                  65,881     232,063      1,847         --       299,791
     Operating income (loss)                           212,841    (203,067)     5,144     (7,601)        7,317
     Interest expense, net                              47,577         591         33     30,779        78,980
     Equity earnings unconsolidated affiliates           1,992      16,823         --         --        18,815
     Other income (expense), net                           453       3,819         57        535         4,864
     Income tax expense                                  3,629          --      1,076         --         4,705
     Capital expenditures                               19,497       8,981      1,804         --        30,282
     Identifiable assets                             1,938,249     317,182     21,319     25,667     2,302,417
     Investments in unconsolidated affiliates           32,558     235,608         --         --       268,166
     Total assets                                   $1,970,807   $ 552,790    $21,319    $25,667    $2,570,583
</TABLE>


                                      F-31
<PAGE>
                 NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES

                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

16.  BUSINESS SEGMENT INFORMATION (continued)

<TABLE>
<CAPTION>
                                                   Natural
                                                 Interstate       Gas
                                                   Natural     Gathering     Coal
                                                     Gas          and       Slurry
     (In thousands)                               Pipelines   Processing   Pipeline   Other(a)      Total
     --------------                              ----------   ----------   --------   --------   ----------
<S>                                              <C>          <C>          <C>        <C>        <C>
     2002
     Revenues from external customers            $  339,014    $126,622     $21,568   $    --    $  487,204
     Depreciation and amortization                   61,002      12,102       1,568        --        74,672
     Operating income (loss)                        200,584      23,278       5,054    (5,747)      223,169
     Interest expense, net                           51,525         794          33    30,546        82,898
     Equity earnings unconsolidated affiliates           --      12,983          --        --        12,983
     Other income (expense), net                      1,997         101          28        61         2,187
     Income tax expense                                 730          --         913        --         1,643
     Capital expenditures                            16,579      33,718         441        --        50,738
     Identifiable assets                          1,848,960     536,937      20,206    75,448     2,481,551
     Investments in unconsolidated affiliates            --     234,385          --        --       234,385
     Total assets                                $1,848,960    $771,322     $20,206   $75,448    $2,715,936
</TABLE>

     (a)  Includes other items not allocable to segments.

     (b)  Natural gas gathering and processing results includes goodwill and
          asset impairment charges of $219,080 (see Note 4).

17.  OTHER INCOME (EXPENSE)

     Other income (expense) on the consolidated statement of income includes
     such items as investment income, nonoperating revenues and expenses,
     foreign currency gains and losses, and nonrecurring other income and
     expense items. For the year ended December 31, 2003, other income also
     included a $3.3 million payment received for a change in ownership of the
     other partner in Bighorn.


                                      F-32
<PAGE>
                 NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES

                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

18.  QUARTERLY FINANCIAL DATA (Unaudited)

<TABLE>
<CAPTION>
                                                       Income       Per Unit
                                                       (Loss)     Income (Loss)
                                         Operating      From           From
     (In thousands, except   Operating     Income    Continuing     Continuing
       per unit amounts)      Revenues     (Loss)    Operations     Operations
     ---------------------   ---------   ---------   ----------   -------------
<S>                          <C>         <C>         <C>          <C>
     2004
        First Quarter         $143,773   $  61,761   $  35,852       $ 0.71
        Second Quarter         142,476      60,595      32,872         0.65
        Third Quarter          147,355      62,093      34,400         0.68
        Fourth Quarter         156,779      68,936      37,797         0.76

     2003
        First Quarter         $138,175   $  58,731   $  32,520       $ 0.68
        Second Quarter         134,362      56,767      27,170         0.55
        Third Quarter          138,008    (160,795)   (183,976)       (3.93)
        Fourth Quarter         140,403      52,614      27,137         0.53
</TABLE>

19.  RELATIONSHIPS WITH ENRON

     In December 2001, Enron and certain of its subsidiaries filed a voluntary
     petition for bankruptcy protection under Chapter 11 of the United States
     Bankruptcy Code. Until November 17, 2004, each of Northern Plains, Pan
     Border and NBP Services were subsidiaries of Enron. Northern Plains, Pan
     Border and NBP Services were not among the Enron companies filing for
     Chapter 11 protection.

     Enron North America (ENA), a wholly owned subsidiary of Enron that is in
     bankruptcy, was a party to transportation contracts which obligated ENA to
     pay for 3.5% of Northern Border Pipeline's capacity. Through the bankruptcy
     proceeding in 2002, ENA rejected and terminated all of its firm
     transportation contracts on Northern Border Pipeline. Northern Border
     Pipeline had previously fully reserved for amounts invoiced to ENA. Since
     Enron guaranteed the obligations of ENA under those contracts, Northern
     Border Pipeline filed claims against both ENA and Enron for damages in the
     bankruptcy proceedings. As a result of a settlement agreement between ENA,
     Enron and Northern Border Pipeline, each of ENA and Enron have agreed to
     allow Northern Border Pipeline's claim of approximately $20.6 million. The
     settlement agreement is expected to be presented to the Bankruptcy Court
     for approval in March 2005. Based upon this settlement between the parties,
     at December 31, 2004, Northern Border Pipeline adjusted its allowance for
     doubtful accounts to reflect an estimated recovery of $1.1 million for
     these claims.

     ENA was also a party to a transportation contract for capacity on
     Midwestern Gas Transmission. ENA rejected and terminated this contract in
     November 2003. Midwestern Gas Transmission filed claims against ENA for
     breach of contract and other claims. However, this claim of approximately
     $150,000 was denied.

     In addition, Bear Paw Energy filed claims against ENA relating to
     terminated swap agreements. In accordance with SFAS No. 133, Bear Paw
     Energy ceased to account for these swap agreements as hedge transactions.
     Bear Paw Energy had previously recorded approximately $6.7 million in
     accumulated other comprehensive income related to these agreements, which
     is being recorded into earnings in the same periods of the originally
     forecasted


                                      F-33
<PAGE>
                 NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES

                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

19.  RELATIONSHIPS WITH ENRON (continued)

     hedges. During the third quarter 2004, the Bankruptcy Court approved a
     settlement between Bear Paw Energy, Enron and certain of its wholly-owned
     subsidiaries of Bear Paw Energy's claim for commodity hedges. As a result,
     the Partnership adjusted its allowance for doubtful accounts to reflect an
     estimated $1.8 million recovery for its claim.

     Also, Crestone Energy Ventures filed claims against ENA for unpaid gas
     gathering and administrative services fees in the amount of $2.3 million.
     As a result of a settlement agreement between ENA and Crestone Energy
     Ventures, ENA has agreed to allow Crestone Energy Ventures' claim of
     approximately $2.3 million. The settlement agreement is expected to be
     presented to the Bankruptcy Court for approval in March 2005. Based upon
     this settlement between the parties, the Partnership adjusted its allowance
     for doubtful accounts to reflect an estimated $0.5 million recovery for its
     claim.

     The Partnership estimates that it could recognize, through future operating
     results, additional recoveries of $4 million to $7 million for the claims
     in the Enron bankruptcy proceedings. However, there can be no assurances on
     the amounts actually recovered or timing of distributions under the Chapter
     11 Plan.

     On December 31, 2003, Enron filed a motion seeking approval of the
     Bankruptcy Court to provide additional funding to, and for authority to
     terminate the Enron Corp. Cash Balance Plan (Plan) and certain other
     defined benefit plans of Enron's affiliates in 'standard terminations'
     within the meaning of Section 4041 of the Employee Retirement Income
     Security Act of 1974, as amended (ERISA). Such standard terminations would
     satisfy all of the obligations of Enron and its affiliates with respect to
     funding liabilities under the Plan. In addition, a standard termination
     would eliminate the contingent claims of Pension Benefit Guaranty
     Corporation (PBGC) against Enron and its affiliates with respect to funding
     liabilities under the Plan. On January 30, 2004, the Bankruptcy Court
     entered an order authorizing termination, additional funding and other
     actions necessary to effect the relief requested. Pursuant to the
     Bankruptcy Court order, any contributions to the Plan are subject to the
     prior receipt of a favorable determination by the Internal Revenue Service
     that the Plan is tax-qualified as of the date of termination.

     On July 19, 2004, Enron was served with a complaint filed by the PBGC in
     the District Court for the Southern District of Texas against Enron as the
     sponsor and/or administrator of the Plans (the Action). By filing the
     Action, the PBGC is seeking an order (i) terminating the Plans; (ii)
     appointing the PBGC the statutory trustee of the Plans; (iii) requiring
     transfer to the PBGC of all records, assets or other property of the Plans
     required to determine the benefits payable to the Plans' participants; and
     (iv) establishing June 2, 2004 as the termination date of the Plans. In the
     Bankruptcy Court September 10 Order, Enron was authorized to enter into an
     escrow agreement with CCE Holdings and PBGC. Upon closing, Enron deposited
     the amount of $321.8 million to an escrow account, which is intended to
     ensure that none of CCE Holdings or its affiliates are exposed


                                      F-34
<PAGE>
                 NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES

                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

19.  RELATIONSHIPS WITH ENRON (continued)

     to liability to the PBGC under Title IV of the Employee Retirement Income
     Security Act of 1974, as amended, for which CCE Holdings may otherwise be
     indemnified pursuant to the CCE Holdings Agreement. In addition, the form
     of escrow agreement approved pursuant to the September 10 Order provides
     that, under certain circumstances and upon approval by or notice to the
     parties to the escrow agreement, some or all of the funds placed in escrow
     may be paid directly in respect of the Cash Balance Plan or to the PBGC.
     However, the September 10 Order also provides that PBGC retains any rights
     or claims it may have against the Transfer Group Companies.

     Enron management previously informed Northern Plains and NBP Services that
     Enron would seek funding contributions from each member of its ERISA
     controlled group of corporations that employs, or employed, individuals who
     are, or were, covered under the Cash Balance Plan. Northern Plains and NBP
     Services are considered members of Enron's ERISA controlled group of
     corporations. As of December 31, 2003, the amount of approximately $6.2
     million was estimated for Northern Plains' and NBP Services' proportionate
     share of the up to $200 million estimated termination costs for the Plans
     authorized by the Bankruptcy Court order. Since under the operating
     agreement with Northern Plains and the administrative agreement with NBP
     Services, these costs could be the Partnership's responsibility, the
     Partnership accrued $6.2 million to satisfy claims of reimbursement for
     these termination costs. As a result of further evaluation and negotiation
     of Enron's proposed allocation of the termination costs, Northern Plains
     and NBP Services advised the Partnership that no claim of reimbursement for
     the termination costs will be made, resulting in a reduction in reserves
     during 2004 of $6.2 million for the termination costs. Under the ONEOK
     Agreement, neither Northern Plains nor NBP Services nor the Partnership
     will be required to contribute to or otherwise be liable for any
     contributions to Enron in connection with the Cash Balance Plan. The
     purchase price under the agreements will be deemed to include all
     contributions which otherwise would have been allocable to Northern Plains
     and NBP Services.

     Management continues to monitor developments at Enron, to assess the impact
     on the Partnership of its existing agreements and relationships with Enron
     and to take appropriate action to protect the interests of the Partnership.

20.  SUBSEQUENT EVENTS

     On January 21, 2005, the Partnership declared a cash distribution of $0.80
     per unit ($3.20 per unit on an annualized basis) for the quarter ended
     December 31, 2004. The distribution was paid February 14, 2005, to
     unitholders of record at January 31, 2005.


                                      F-35
<PAGE>
       REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM ON SCHEDULE

Northern Border Partners, L.P.:

We have audited in accordance with the standards of the Public Company
Accounting Oversight Board (United States), the consolidated financial
statements of Northern Border Partners, L.P. and Subsidiaries as of December 31,
2004 and 2003 and for each of the years in the three-year period ended December
31, 2004 included in this Form 10-K, and have issued our report thereon dated
March 2, 2005.

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


/s/ KPMG LLP

Omaha, Nebraska
March 2, 2005


                                       S-1
<PAGE>
                                                                     SCHEDULE II

                 NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES
                 SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
              FOR THE YEARS ENDED DECEMBER 31, 2004, 2003 AND 2002
                                 (IN THOUSANDS)

<TABLE>
<CAPTION>
Column A                           Column B           Column C             Column D        Column E
-----------                       ----------   ---------------------   ---------------   -----------
                                                     Additions
                                               ---------------------     Deductions
                                  Balance at   Charged to    Charged   For Purpose For
                                   Beginning    Costs and   to Other   Which Reserves    Balance at
Description                         of Year     Expenses    Accounts    Were Created     End of Year
-----------                       ----------   ----------   --------   ---------------   -----------
<S>                               <C>          <C>          <C>        <C>               <C>
Reserve for regulatory issues
   2004                             $ 7,644      $  640        $--         $ 6,329         $ 1,955
   2003                             $12,294      $5,611        $--         $10,261         $ 7,644
   2002                             $ 2,531      $9,763        $--         $    --         $12,294

Allowance for doubtful accounts
   2004                             $11,988      $  569        $--         $ 3,382         $ 9,175
   2003                             $11,936      $   52        $--         $    --         $11,988
   2002                             $10,287      $3,463        $52         $ 1,866         $11,936
</TABLE>


                                       S-2
<PAGE>
                                Index to Exhibits


<TABLE>
<CAPTION>
EXHIBITS          DESCRIPTION
---------------   -----------
<S>               <C>
            3.1   Northern Border Partners, L.P. Certificate of Limited
                  Partnership, Certificate of Amendment dated February 16, 2001,
                  and Certificate of Amendment dated May 20, 2003.

            3.2   Amended and Restated Agreement of Limited Partnership of
                  Northern Border Partners, L.P. dated October 1, 1993.

            3.3   Northern Border Intermediate Limited Partnership Certificate
                  of Limited Partnership, Certificate of Amendment dated
                  February 16, 2001, and Certificate of Amendment dated May 20,
                  2003.

           *3.4   Form of Amended and Restated Agreement of Limited Partnership
                  for Northern Border Intermediate Limited Partnership
                  (incorporated by reference to Exhibit 10.1 to Form S-1
                  Registration Statement, Registration No. 33-66158 ("Form
                  S-1")).

           *4.1   Indenture, dated as of June 2, 2000, between Northern Border
                  Partners, L.P. and Northern Border Intermediate Limited
                  Partnership and Bank One Trust Company, N.A. (incorporated by
                  reference to Exhibit 4.1 to the Partnership's Quarterly Report
                  on Form 10-Q for the quarterly period ended June 30, 2000
                  (File No. 1-12202) ("June 2000 10-Q")).

           *4.2   First Supplemental Indenture, dated as of September 14, 2000,
                  between Northern Border Partners, L.P., Northern Border
                  Intermediate Limited Partnership and Bank One Trust Company,
                  N.A. (incorporated by reference to Exhibit 4.2 to the
                  Partnership's Form S-4 Registration Statement, Registration
                  No. 333-46212 ("NBP Form S-4")).

           *4.3   Indenture, dated as of March 21, 2001, between Northern Border
                  Partners, L.P. and Northern Border Intermediate Limited
                  Partnership and Bank One Trust Company, N.A., Trustee
                  (incorporated by reference to Exhibit 4.3 to the Partnership's
                  Form 10-K for the year ended December 31, 2001 (File No.
                  1-12202)).

           *4.4   Indenture, dated as of August 17, 1999, between Northern
                  Border Pipeline Company and Bank One Trust Company, NA,
                  successor to The First National Bank of Chicago, as trustee.
                  (incorporated by reference to Exhibit No. 4.1 to Northern
                  Border Pipeline Company's Form S-4 Registration Statement
                  filed on October 7, 1999, Registration No. 333-88577 ("NB Form
                  S-4")).

           *4.5   Indenture, dated as of September 17, 2001, between Northern
                  Border Pipeline Company and Bank Trust Company, N.A.
                  (incorporated by reference to Exhibit 4.2 to Northern Border
                  Pipeline Company's Registration Statement on Form S-4 filed on
                  November 13, 2001, Registration No. 333-73282 ("2001 NB Form
                  S-4")).
</TABLE>
<PAGE>
<TABLE>
<S>               <C>
           *4.6   Indenture, dated as of April 29, 2002, between Northern Border
                  Pipeline Company and Bank One Trust Company, N.A.
                  (incorporated by reference to Exhibit 4.1 to Northern Border
                  Pipeline Company's Form 10-Q for the quarter ended March 31,
                  2002 (File No. 333-88577)).

          *10.1   Northern Border Pipeline Company General Partnership Agreement
                  between Northern Plains Natural Gas Company, Northwest Border
                  Pipeline Company, Pan Border Gas Company, TransCanada Border
                  Pipeline Ltd. and TransCan Northern Ltd., effective March 9,
                  1978, as amended (incorporated by reference to Exhibit 10.2 to
                  Form S-1).

          *10.2   Form of Seventh Supplement Amending Northern Border Pipeline
                  Company General Partnership Agreement (incorporated by
                  reference to Exhibit 10.15 to Form S-1).

          *10.3   Eighth Supplement Amending Northern Border Pipeline Company
                  General Partnership Agreement (incorporated by reference to
                  Exhibit 10.15 to NB Form S-4).

          *10.4   Ninth Supplement Amending Northern Border Pipeline Company
                  General Partnership Agreement (incorporated by reference to
                  Exhibit 10.37 to 2001 NB Form S-4).

          *10.5   Tenth Supplement Amending Northern Border Pipeline Company
                  General Partnership Agreement dated March 2, 2005
                  (incorporated by reference to Exhibit 3.5 to Northern Border
                  Pipeline's Form 10-K filed on March 11, 2005 (File No.
                  333-88577)).

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

          *10.7   Administrative Services Agreement between NBP Services
                  Corporation, Northern Border Partners, L.P. and Northern
                  Border Intermediate Limited Partnership (incorporated by
                  reference to Exhibit 10.4 to Form S-1).

          *10.8   Revolving Credit Agreement, dated as of November 24, 2003,
                  among Northern Border Partners, L.P., SunTrust Bank, Harris
                  Nesbitt Corp., Wachovia Bank, National Association, Citigroup,
                  N.A., SunTrust Capital Markets, Inc., and the Lenders (as
                  named therein) (incorporated by reference to Exhibit 10.7 to
                  the Partnership's Form 10-K for the year ended December 31,
                  2003 (File No. 1-12202)).

          *10.9   First Amendment to the Revolving Credit Agreement dated as of
                  April 9, 2004 between Northern Border Partners, L.P., SUNTRUST
                  BANK and the lenders named therein (incorporated by reference
                  to Exhibit 10.1 to the Partnership's Form 10-Q for the quarter
                  ended March 31, 2004 (File No. 1-12202)).

         *10.10   Second Amendment entered into as of October 25, 2004 to
                  Northern Border Partners' Revolving Credit Agreement dated as
                  of November 24, 2003 (incorporated by reference to Exhibit
                  99.1 to the Partnership's Form 8-K filed on November 5, 2004
                  (File No. 1-12202)).

         *10.11   Revolving Credit Agreement, dated as of May 16, 2002, among
                  Northern Border Pipeline Company, Bank One, NA, Citibank,
                  N.A., Bank of Montreal, SunTrust Bank, Wachovia Bank, National
                  Association, Banc One Capital Markets, Inc, and Lenders (as
                  defined therein) (incorporated by reference to Exhibit 10.1 to
                  the Partnership's Current Report on Form 8-K dated June 26,
                  2002 (File No. 1-12202)).

         *10.12   First Amendment to the Revolving Credit Agreement dated as of
                  April 9, 2004 between Northern Border Pipeline Company, Bank
                  One, NA and the lenders named therein. (incorporated by
                  reference to Exhibit No. 10.1 to Northern Border Pipeline
</TABLE>
<PAGE>
<TABLE>
<S>               <C>
                  Company's Quarterly Report on Form 10-Q for the quarterly
                  period ended March 31, 2004 (File No. 333-88577).

         *10.13   Agreement between Northern Plains and Northern Border
                  Intermediate Limited Partnership regarding the costs, expenses
                  and expenditures arising under the operating agreement between
                  Northern Plains and Guardian Pipeline, LLC (incorporated by
                  reference to Exhibit 10.3 to the Partnership's Form 10-Q for
                  the quarter ended March 31, 2004 (File No. 1-12202)).

        +*10.14   Form of Termination Agreement with ONEOK dated as of January
                  5, 2005 (incorporated by reference to Exhibit 99.1 to the
                  Partnership's Form 8-K filed on January 11, 2005 (File No.
                  1-12202)).

        +*10.15   ONEOK, Inc. 2005 Supplemental Executive Retirement Plan.
                  (incorporated by reference to Exhibit 99.1 to the
                  Partnership's Form 8-K filed on January 11, 2005(File No.
                  1-12202)).

        +*10.16   ONEOK, Inc. Long-Term Incentive Plan (incorporated by
                  reference from Exhibit 10(a) to ONEOK's Form 10-K for the year
                  ended December 31, 2001 (File No. 1-13643)).

        +*10.17   ONEOK, Inc. Form of Restricted Stock Incentive Award
                  (incorporated by reference from Exhibit 10.4 to ONEOK's Form
                  10-Q for the quarterly period ended September 30, 2004 (File
                  No. 1-13643)).

        +*10.18   ONEOK, Inc. Form of Performance Shares Award (incorporated by
                  reference from Exhibit 10.5 to ONEOK's Form 10-Q for the
                  quarterly period ended September 30, 2004 (File No. 1-13643)).

        +*10.19   ONEOK, Inc. Employee Non-Qualified Deferred Compensation Plan,
                  as amended, dated February 2001 (incorporated by reference to
                  Exhibit 10(g) to ONEOK's Form 10-K for the year ended December
                  31, 2001 (File No. 1-13643)).

        +*10.20   ONEOK, Inc. Annual Officer Incentive Plan (incorporated by
                  reference to Exhibit 10(f) to ONEOK's Form 10-K for the year
                  ended December 31, 2001 (File No. 1-13643)).

         *10.21   Operating Agreement between Midwestern Gas Transmission
                  Company and Northern Plains Natural Gas Company dated as of
                  April 1, 2001 (incorporated by reference to Exhibit 10.38 to
                  the Partnership's Form 10-K for the year ended December 31,
                  2001 (File No. 1-12202)).

         *10.22   Operating Agreement between Viking Gas Transmission Company
                  and Northern Plains Natural Gas Company dated as of January
                  17, 2003 (incorporated by reference to Exhibit 10.18 to the
                  Partnership's Form 10-K for the year ended December 31, 2002
                  (File No. 1-12202)).

         *10.23   Northern Border Pipeline Company Agreement among Northern
                  Plains Natural Gas Company, Pan Border Gas Company, Northwest
                  Border Pipeline Company, TransCanada Border PipeLine Ltd.,
                  TransCan Northern Ltd., Northern Border Intermediate Limited
                  Partnership, Northern Border Partners, L.P., and the
                  Management Committee of Northern Border Pipeline, dated as of
                  March 17, 1999 (incorporated by reference to Exhibit 10.21 to
                  the Partnership's Form 10-K/A for the year ended December 31,
                  1998 (File No. 1-12202) ("1998 10-K")).
</TABLE>
<PAGE>
<TABLE>
<S>               <C>
          10.24   Northern Border Transition Services Agreement dated November
                  17, 2004, by and between ONEOK, Inc. and CCE Holdings, LLC.

           12.1   Statement re computation of ratios.

             21   List of subsidiaries.

           23.1   Consent of KPMG LLP.

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

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

           32.1   Section 1350 certification of principal executive officer.

           32.2   Section 1350 certification of principal financial officer.

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

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

+    Management contract, compensatory plan or arrangement.

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