10-K 1 h13182e10vk.txt NORTHERN BORDER PARTNERS, L.P.- DECEMBER 31, 2003 UNITED STATES SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 ----------------------- FORM 10-K ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended December 31, 2003 Commission file number: 1-12202 NORTHERN BORDER PARTNERS, L.P. (Exact name of registrant as specified in its charter) DELAWARE 93-1120873 (State or other jurisdiction (I.R.S. Employer of incorporation or organization) Identification No.) 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: Title of each class Name of each exchange on which registered ------------------- ----------------------------------------- Common Units New York Stock Exchange 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] Indicate by check mark whether the registrant is an accelerated filer (as defined by Rule 12b-2 of the Securities Exchange Act of 1934). 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, 2003, was approximately $1,802,117,583. NORTHERN BORDER PARTNERS, L.P. TABLE OF CONTENTS

PAGE NO. -------- 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 22 PART II Item 5. Market for Registrant's Common Units and Related Security Holder Matters 23 Item 6. Selected Financial Data 26 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations 28 Item 7a. Quantitative and Qualitative Disclosures About Market Risk 56 Item 8. Financial Statements and Supplementary Data 57 Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure 58 Item 9a. Controls and Procedures 58 PART III Item 10. Partnership Management 59 Item 11. Executive Compensation 66 Item 12. Security Ownership of Certain Beneficial Owners and Management 69 Item 13. Certain Relationships and Related Transactions 69 Item 14. Principal Accounting Fees and Services 72 PART IV Item 15. Exhibits, Financial Statement Schedules and Reports on Form 8-K 73

i 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 Pipelines - 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. In mid January 2003, we expanded this segment with our acquisition of Viking Gas Transmission Company, including a one-third interest in Guardian Pipeline, L.L.C. 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 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. We have extensive gas gathering operations in the Powder River Basin in Wyoming. We also have natural gas gathering, processing and fractionation operations in the Williston Basin in Montana and North Dakota. In June 2003, we sold our processing plants and related facilities in Alberta, Canada but we still hold an interest in gathering pipelines in the region. 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. 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 ("Northern Plains") and Pan Border Gas Company, both subsidiaries of Enron Corp. ("Enron"), and Northwest Border Pipeline Company, a subsidiary of TransCanada PipeLines Limited which is a subsidiary of TransCanada Corporation, collectively referred to as "TransCanada". In this report, references to "we", "us", "our" or the "Partnership" collectively refer to Northern Border Partners and our subsidiary, Northern Border Intermediate Limited Partnership. See Item 10. "Partnership Management." 1 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 and Sundance Assets, L.P., an affiliate of Enron, holds a 5.72% 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 Enron and TransCanada are 8.43% and 0.35%, respectively. NBP Services Corporation, an Enron subsidiary, provides administrative services for us and operating services for our natural gas gathering and processing segment. NBP Services has approximately 135 employees 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 and to the coal slurry pipeline segment. Northern Plains employs approximately 285 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. NBP Services' and Northern Plains' employees are not represented by any labor union and are not covered by any collective bargaining agreements. On December 2, 2001, Enron filed a voluntary petition for Chapter 11 protection in bankruptcy court. On September 25, 2003, a motion by Enron to transfer Enron's interests in, among other entities, Northern Plains, Pan Border and NBP Services to CrossCountry Energy, a new pipeline operating entity, was approved. 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," Item 13. "Certain Relationships and Related Transactions" and Item 10. "Partnership Management." We make available free of charge, through our website, www.northernborderpartners.com, 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. For additional information about our business segments, see Note 14 - Notes to Consolidated Financial Statements included in this report. INTERSTATE NATURAL GAS PIPELINES Our interstate pipelines 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. 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. The interstate pipelines do not own the gas that they transport and therefore do not assume natural gas commodity 2 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. The interstate pipelines do 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 2003, 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. NORTHERN BORDER PIPELINE SYSTEM We own a 70% general partnership interest in Northern Border Pipeline Company, a Texas general partnership. 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. In the year ended December 31, 2003, 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 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, Enron 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." The pipeline system consists of 822 miles of 42-inch diameter pipe from the Canadian border to Ventura, Iowa, capable of transporting 3 a total of 2,374 million cubic feet per day ("mmcfd"); 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; 226 miles of 36-inch diameter pipe and 19 miles of 30-inch diameter pipe capable of transporting 844 mmcfd from Harper, Iowa to Manhattan, Illinois (Chicago area); and 35 miles of 30-inch diameter pipe capable of transporting 545 mmcfd from Manhattan, Illinois to a terminus near North Hayden, Indiana. 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. At its northern end, the pipeline system's gas supplies are received through an interconnection with Foothills Pipe Lines (Sask.) Ltd. system in Canada. The Foothills system, owned by TransCanada, is connected to TransCanada's Alberta system and the pipeline system owned by Transgas Limited in Saskatchewan. Also at the north end, the pipeline system connects to a domestic natural gas gathering system owned by Omimex Ltd. In North Dakota, the pipeline system connects with facilities of Northern Natural Gas Company at Buford, which facilities in turn are connected to Williston Basin Interstate and the gathering system owned by us through Bear Paw Energy. In December 2003, an interconnection with a newly constructed pipeline owned by Williston Basin Interstate Pipeline Company near Manning, North Dakota was placed in service. The initial design capacity of the interconnect facilities is 200 mmcfd. The pipeline, with an initial design capacity of 80 mmcfd, was constructed to transport natural gas from coalbed and conventional natural gas supplies in the Powder River Basin of northeastern Wyoming and southeastern Montana as well as conventional supplies in the Rocky Mountain area. Other locations in North Dakota where the pipeline can receive gas are interconnections with Williston Basin Interstate Pipeline at Glen Ullin, Amerada Hess Corporation at Watford City, and Dakota Gasification Company at Hebron. Near its terminus, the pipeline system is capable of physically receiving natural gas from Northern Illinois Gas Company at Troy Grove, Illinois and from Midwestern Gas Transmission Company at Channahon, Illinois. For the year ended December 31, 2003, of the natural gas transported on the pipeline system, approximately 88% was produced in Canada, approximately 5% was produced by the Dakota Gasification plant, approximately 6% was produced in the Williston Basin and 1% from other sources. 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 4 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 Company near Channahon, Illinois; - ANR Pipeline Company near Manhattan, Illinois; - Vector Pipeline L.P. in Will County, Illinois; - Guardian Pipeline, L.L.C. 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. 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. The pipeline system serves more than 40 firm transportation shippers with diverse operating and financial profiles. Based upon shippers' contractual obligations, as of December 31, 2003, 94% of the firm capacity is contracted by producers and marketers. The remaining firm capacity is contracted primarily by local distribution companies (5%), and interstate pipelines (1%). As of December 31, 2003, the termination dates of these contracts ranged from March 31, 2004 to December 21, 2013, and the weighted average contract life, based upon contractual obligations, was approximately three and one-third years. All of Northern Border Pipeline's capacity was under contract through December 31, 2003 and, assuming no extensions of existing contracts or execution of new contracts, approximately 70% and 59% is under contract through December 31, 2004 and 2005, respectively. See Item 7. "Management's Discussion and Analysis of Financial Condition and Results of Operations - Overview." 5 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 original contract shipper from its payment obligations if the new shipper fails to pay. For the year ended December 31, 2003, BP Canada Energy Marketing Corp. ("BP Canada"), EnCana Marketing U.S.A. Inc. ("EnCana") and Pan Alberta Gas (U.S.) Inc. ("Pan-Alberta") collectively accounted for approximately 41% of Northern Border Pipeline's revenues. As of December 31, 2003, Northern Border Pipeline's three largest shippers were BP Canada, EnCana and Cargill Incorporated who are obligated for approximately 21%, 19% and 9%, respectively, of the contracted firm capacity. In July 2003, Cargill Incorporated completed the assignment of all the firm capacity formerly held by Mirant Americas Energy Marketing, LP, which extends for terms into 2006 and 2008. Approximately half of the capacity contracted to BP Canada and EnCana is due to expire by November 1, 2004. During 2003, all of the contracted capacity due to expire by November 1, 2003, of which Pan-Alberta held approximately 20%, was recontracted with 10 shippers. See Item 7. "Management's Discussion and Analysis of Financial Condition and Results of Operations - Overview." MIDWESTERN GAS TRANSMISSION SYSTEM Midwestern Gas Transmission Company, our wholly-owned subsidiary, 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, Kentucky, southern Illinois and Indiana. 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. Midwestern Gas Transmission system is also capable of moving approximately 350 mmcfd south-bound 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, 6 L.L.C., Natural Gas Pipeline Company of America, Northern Border Pipeline, and Texas Gas Transmission Company as well as 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 30 firm transportation shippers. Based upon shipper contractual obligations as of December 31, 2003, approximately 49% of the firm transportation capacity is contracted by local distribution companies, 48% by marketers and 3% by end-users. For the year ended December 31, 2003, Midwestern Gas Transmission's three major customers, Northern Illinois Gas Company, Northern Indiana Public Service Company and ProLiance Energy LLC accounted for $5.2 million (24%), $2.9 million (13%) and $2.9 million (13%), respectively, of its revenues. As of December 31, 2003, the termination dates of Midwestern Gas Transmission's firm transportation contracts ranged from March 31, 2004 to October 31, 2019. The weighted average contract life, based upon annual contract obligations, was approximately two and one-third years. See Item 7. "Management's Discussion and Analysis of Financial Condition and Results of Operations - Overview." One shipper, Enron North America Corp. ("ENA"), which filed for bankruptcy protection, is affiliated with two of our general partners, Northern Plains and Pan Border. ENA's contract was rejected in November 2003 by ENA, and covered less than 1 percent of Midwestern Gas Transmission's firm capacity. 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" and Item 13. "Certain Relationships and Related Transactions." VIKING GAS TRANSMISSION SYSTEM Effective January 17, 2003, we acquired Viking Gas Transmission Company, including a one-third interest in Guardian Pipeline, L.L.C. The Viking Gas Transmission system 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. The Viking Gas Transmission system consists of 499 miles of 24-inch diameter mainline pipe with a design capacity of approximately 500 mmcfd at the origin near Emerson, Manitoba and 300 mmcfd at the terminus near Marshfield, Wisconsin, 95 miles of 24-inch mainline looping and 79 miles of smaller diameter laterals. There are eight compressor stations with total horsepower of 68,650. The Viking Gas Transmission system serves over 40 firm transportation shippers. Based upon shipper contractual obligations as 7 of December 31, 2003, approximately 81% of the firm transportation capacity is contracted by local distribution companies, 12% by marketers and 7% by end-users. As of December 31, 2003, Viking Gas Transmission's largest customers were Northern States Power Company-Minnesota, CenterPoint Energy Minnegasco, Michigan Consolidated Gas Company, Wisconsin Gas Company and Wisconsin Public Service Corporation, who were obligated for approximately 16%, 12%, 10%, 10% and 9%, respectively, of the contracted firm capacity. As of December 31, 2003, the termination dates of Viking Gas Transmission's firm transportation contracts ranged from May 31, 2004 to October 31, 2014. The weighted average contract life, based upon contract obligations, was approximately four years. GUARDIAN PIPELINE SYSTEM 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. 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 Trunkline Gas Company, which is part of the Panhandle Companies. Northern Plains has been selected to be the operator of Guardian Pipeline effective July 1, 2004. See Item 13. "Certain Relationships and Related Transactions." DEMAND FOR INTERSTATE PIPELINE TRANSPORTATION CAPACITY The long-term financial condition of our interstate natural gas pipelines 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 8 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 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 the value that customers can realize from firm transportation on a pipeline 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 customer can expect to achieve from holding transportation capacity at any 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 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 or summer electric generation usage in the markets served by the pipeline systems. However, since approximately 98% of the expected revenue for these pipelines is attributable to demand charges, our revenues and cash flow are not impacted materially by such seasonal throughput variations. We cannot predict whether these or other factors will have an adverse effect on demand for use of our interstate pipeline systems or how significant that adverse effect 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 midwest. 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 9 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, on TransCanada's pipeline system through various interconnects with U.S. interstate pipelines or to markets on the West Coast. The Alliance Pipeline competes directly with Northern Border Pipeline in the transportation of natural gas from the western Canadian sedimentary basin to the Chicago area. Because it transports liquids-rich natural gas, the Alliance Pipeline currently has no major interconnections with other pipelines upstream of liquids extraction facilities located near Chicago. This contrasts with Northern Border Pipeline, which serves various markets through interconnections with other pipelines along its route. The Chicago market hub has absorbed the new supply from Alliance Pipeline as incremental pipeline capacity has been developed to transport natural gas from the Chicago area to other market regions. The Alliance Pipeline has also brought increased supply access for Midwestern Gas Transmission's customers. The Alliance Pipeline receipt point into the Midwestern Gas Transmission system near Joliet, Illinois provided 46% of Midwestern Gas Transmission natural gas receipts during 2003. 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 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. 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 the mid-continent 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 into these markets. 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, mid-continent and Chicago market center. In October 2003, ANR Pipeline filed a certificate application with the FERC to expand its capacity in the north leg of 10 its pipeline system by approximately 107,000 dekatherms per day to replace receipts from Viking Gas Transmission at the Marshfield, Wisconsin interconnection by November 2005. Viking Gas Transmission intervened in ANR's proceeding and the FERC staff is currently evaluating ANR's proposal. We cannot predict at this time how this project, if approved, may impact the amount of capacity contracted after 2005. 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; - 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. We were notified in November 2002 that Northern Border Pipeline and Midwestern Gas Transmission were two of the companies selected by the FERC to undergo an industry-wide audit of FERC-assessed annual charges. The overall audit objective was to determine compliance with FERC accounting requirements and regulations as they relate to the calculation and assessment of annual charges by validating the accuracy of the data filed annually with the FERC. The audit covered the period of January 1, 2001 to December 31, 2001. During 2003, the FERC issued its final reports that found both to be in compliance. The FERC regulates the rates and charges for transportation in interstate commerce. Natural gas companies may not charge rates exceeding rates judged 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 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 11 authorization and rates may be negotiated subject to FERC approval. The rates and terms and conditions for service are found in the FERC approved tariffs. 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. Firm shippers that contract for the stated transportation rate 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 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. 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 until November 1, 2005, at which time Northern Border Pipeline must file a new rate case. Midwestern Gas Transmission and Viking Gas Transmission are under no obligation to file new rate cases. Prior to a future rate case, the interstate pipelines will not be permitted to increase rates if costs increase, 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 future costs, 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 and 2.0% for Viking Gas Transmission. In order to avoid a decline in the transportation rates established in future rate cases as a result of accumulated depreciation, the interstate pipeline must maintain or increase its rate base by acquiring or constructing assets that replace or add to existing pipeline facilities or by adding new facilities. 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 rulings, the FERC held that an interstate pipeline is not entitled to a tax allowance for income attributable to limited partnership interests held by individuals. The settlement of Northern Border Pipeline's 1995 rate case provided that until at least December 2005, Northern Border Pipeline could continue to calculate the allowance for income taxes in the manner it had historically used. 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. 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 12 to interruptible shippers is the sum of the firm transportation maximum demand and commodity charges. From December 1, 1999 through October 31, 2003, Northern Border Pipeline shared net interruptible transportation service revenue and any new services revenue on an equal basis with its firm shippers. Beginning November 1, 2003, Northern Border Pipeline retained all revenues from these services. Our interstate pipelines are subject to the requirements of FERC Order Nos. 497 and 566, which prohibit preferential treatment of their 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. All transmission providers must comply with the standards of conduct by June 1, 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 a compliance plan to its website on February 9, 2004. By definition, Bear Paw Energy, LLC and Crestone Energy Ventures, L.L.C. are energy affiliates. The operator of our interstate pipelines, Northern Plains, provides after hours and weekend gas control services for Bear Paw Energy and Crestone Energy Ventures that results in some cost savings to our interstate pipelines. Our interstate pipelines have requested a waiver to permit Northern Plains to continue to provide after hours and weekend gas control services for Bear Paw Energy and Crestone Energy Ventures. If the waiver is not granted, the cost to maintain gas control for these affiliates and our interstate pipelines will increase slightly. Several parties have filed for rehearing on a number of issues, including whether gathering companies should be included in the definition of energy affiliate. On August 1, 2002, the FERC issued a Notice of Proposed Rulemaking regarding the regulation of cash management practices of the natural gas and other companies that it regulates. On June 26, 2003, the FERC issued an interim rule in that proceeding that amended its regulations to provide for documentation requirements for cash management programs and to implement new reporting requirements. Specifically, under the interim rule, all cash management agreements between regulated entities and their affiliates must be in writing, must specify the duties and responsibilities of cash management participants and administrators, must specify the methods for calculating interest and for allocating interest income and expense, and must specify any restrictions on deposits or borrowings by participants. A FERC-regulated entity must file with the FERC any cash management agreements to which it is a party, as well as any subsequent changes to such agreements. In addition, a FERC-regulated entity must notify the FERC when its equity component of proprietary capital ratio falls below 30%. The cash management agreements between Midwestern Gas Transmission, Viking Gas Transmission and us have been filed with FERC. Northern Border Pipeline does not have a cash management agreement nor is it required to and FERC was so notified. We do not expect that the FERC's policy will have a material impact on our cash management practices. 13 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. Since our businesses do not derive a significant amount of their revenues from negotiated rate transactions, 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 the pipelines' creditworthiness provisions set forth in their tariffs. In addition, industry groups, such as the North American Energy Standards Board ("NAESB"), are studying 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. Comments are due on the proposed rule by March 26, 2004. The enactment of some of these standards may have the effect of easing certain creditworthiness requirements and parameters currently reflected in our tariffs. Recent FERC orders, and this proposed rule, support greater collateral requirements for credit on shippers 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 will include a basic set of financial statements and other selected data and will be submitted electronically. For 2004, each quarterly report will be due approximately 70 days following the end of the quarter except for the first quarter report which is due on or before July 9, 2004. Subsequent reports will be due 60 days after the end of each quarter. The annual report, previously required to be filed each year on or before April 30, will be required on or before April 25, 2005 for 2004 and on April 18 thereafter. No impact is anticipated for complying with these requirements other than the time and additional expenses for preparation of these reports. From time to time, our interstate pipelines file to make changes to their tariffs to clarify provisions, to reflect current industry practices and to reflect recent FERC rulings. In February 2003, Northern Border Pipeline filed to amend the definition of company use gas, which is gas supplied by its shippers for its operations, to 14 clarify the language by adding detail to the broad categories that comprise company use gas. However, in its March 2003 order, the FERC directed Northern Border Pipeline to cease collecting electric costs through its company use gas provisions and to refund with interest, within 90 days, all electric costs that had been collected through its company use gas provisions. Refunds of approximately $10 million were made in May 2003. 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 a short distance for less than one year. 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 Commission policy. The FERC did affirm that, up to ninety days prior to the effective date, Northern Border Pipeline had the right not to sell capacity requested for short distances or on a short-term basis. Northern Border Pipeline filed a timely request for rehearing of the Commission'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 a Commission decision on these tariff sheets. Northern Border Pipeline's tariff sheets and the final orders to be entered in this proceeding will impact how it awards available capacity. With contracts expiring before November 1, 2004, if timely bids for one year of service or longer on the entire transportation path available are not received, Northern Border Pipeline may potentially be required to accept bids for shorter distances or shorter time periods that may result in creating segments of capacity of minimal value. In March 2004, Northern Border Pipeline filed tariff sheets to implement two balancing services to assist deliveries at variable load points, such as electrical generation plants. Northern Border Pipeline also filed with the FERC certain agreements related to third party balancing which it believed are administrative in nature and which will be terminated upon approval of the new balancing services. Under current orders and rulings in other proceedings before the FERC, it is unclear whether these agreements would be deemed non-conforming. However, we do not expect that orders on these tariff sheets and agreements filed in March 2004 will have a material adverse impact on our business. NATURAL GAS GATHERING AND PROCESSING SEGMENT 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 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, our wholly-owned subsidiary, has extensive natural gas gathering, processing and fractionation operations in the 15 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 95 mmcfd of capacity. In the Powder River Basin, Bear Paw Energy has approximately 1,100 miles of high and low pressure gathering pipelines, approximately 92 compressor stations with approximately 130,000 installed horsepower and long-term volumetric contracts with producers covering approximately 430,000 acres of dedicated reserves in the 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., a 33.33% interest in Fort Union Gas Gathering, L.L.C. and a 35% interest in Lost Creek Gathering, L.L.C., 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.) holds the remaining ownership interest in Bighorn and is the project manager and operator. In July 2003, CMS Field Services, Inc. was sold by CMS Energy to Cantera Natural Gas, LLC. 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 and Thunder Creek Gas Gathering, 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 16 consists of approximately 3,000 miles of polyethylene and steel pipeline and 29 compressor stations with a total rated horsepower of 29,000, in addition to plant compression of approximately 19,000 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. Our wholly-owned subsidiary, Border Midstream Services, Ltd. owns an undivided minority interest in the Gregg Lake/Obed Pipeline located in Alberta, Canada. Until June 2003, it also owned the Mazeppa and Gladys gas processing plants, and associated gathering pipelines. The Gregg Lake/Obed Pipeline is located in west central Alberta and consists of 85 miles of pipeline with a design capacity of 150 mmcfd. Border Midstream receives 63% of the cash distributions until such time when it has been reimbursed its share of the original construction costs of the Gregg Lake portion of the pipeline, which is expected to occur in 2006. Subsequently, Border Midstream will receive 36% of the distributions, which is equal to its ownership interest in the entire Gregg Lake/Obed Pipeline. Central Alberta Midstream holds the remaining undivided interest in Gregg Lake/Obed Pipeline and is its operator. 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, Williston and western Canadian sedimentary 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, Devon Energy Corporation, Fidelity Exploration & Production, Yates Petroleum and Anadarko Petroleum Corp. Primary non-producer affiliated competitors include Bighorn and Optigas. Competition for gathering and processing services in the Williston Basin includes Amerada Hess and PetroHunt Corporation in localized areas. Our competitive positions are affected by the pace of 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 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 17 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." 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 Black Mesa Pipeline, Inc., our wholly - owned subsidiary, 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 Power Station located in Laughlin, Nevada. The coal slurry pipeline is the sole source of fuel for the Mohave Power 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 Power Station, through the year 2005. The source of water used 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 Plant 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, as one of the owners of the Mohave Plant, 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 18 expenditures for pollution control activities required for future operation. Evidentiary hearings are expected this year. If efforts by the parties to resolve these issues are not successful and the Mohave Plant is permanently closed, it would be necessary to shut down Black Mesa in 2006. Even with successful resolution of the issues, it may require that the plant, as well as the Black Mesa system, be temporarily idled for a two to three year period while pollution control equipment is installed at the plant and the Black Mesa system is rebuilt. See Item 7. "Management's Discussion and Analysis of Financial Condition and Results of Operations - Overview." Approximately 53 people are employed in the operations of Black Mesa, of which 25 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 and U.S. gathering and processing operations are subject to federal, state and local laws and 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. The regulations implementing the Act are not yet final. 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 is being 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 19 additional assessment or remediation costs. Although we expect to include these costs in future rate case filings, total recovery is not assured. Presently we expect our costs for integrity assessments for 2004 to be approximately $1.0 million. In Canada, our gathering facilities are subject to Canadian, provincial and local laws and regulations relating to safety and the protection of the environment, which include the following Alberta laws: the Energy Resources Conservation Act, the Oil and Gas Conservation Act, the Pipeline Act, and the Environmental Protection and Enhancement Act. Black Mesa is subject to a judgment and Consent Decree entered in the United States District Court of Arizona in July 2001. 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 sets forth certain preventative measures, reporting requirements and associated penalties for failure to comply in the future. Since the Consent Decree was entered, there have been several unplanned slurry discharges that have been reported to the EPA and ADEQ. In 2003, Black Mesa paid to the EPA and ADEQ total stipulated penalties pursuant to the Consent Decree of $229,250. 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 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 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 20 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 expires in 2011. 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. 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 treating, processing and fractionation facilities. The real property rights for these facilities are derived through fee ownership, leases, easements, rights-of-way and permits. 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 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 relates 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 in 21 principle on pipeline right-of-way lease and taxation issues, subject to final documentation and necessary governmental approvals. Final documentation has been completed and is subject to the approval of the BIA, which the parties believe will be obtained shortly. This 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 present 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 will pay a lump sum amount of $5.9 million and an annual amount of approximately $1.5 million beginning April 2004. 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 - Environmental and Safety Matters" for the discussion on the Consent Decree entered against Black Mesa and "Business - Coal Slurry Pipeline" 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 2003. 22 PART II ITEM 5. MARKET FOR THE REGISTRANT'S COMMON UNITS AND RELATED SECURITY HOLDER MATTERS 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:

Price Range Cash High Low Distributions ---- --- ------------- 2003 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 2002 Fourth Quarter................. $38.00 $33.46 $0.80 Third Quarter.................. 37.50 29.30 0.80 Second Quarter................. 41.90 35.43 0.80 First Quarter.................. 42.50 34.25 0.80

As a result of pending proceedings by Enron before the Securities and Exchange Commission on regulation under the Public Utility Holding Company Act of 1935, we delayed the declaration of distribution for the fourth quarter 2003. On February 9, 2004, we declared a distribution of $0.80 per unit ($3.20 per unit on an annualized basis), payable February 20, 2004 to the general partners and unitholders of record at February 17, 2004. Based upon the order issued by the Securities and Exchange Commission on March 9, 2004, we have received the necessary approvals under the Public Utility Holding Company Act of 1935 to declare and pay future distributions. See Item 7. "Management's Discussion and Analysis of Financial Condition and Results of Operations - Public Utility Holding Company Act ("PUHCA") Regulation." As of February 17, 2004, there were approximately 1,400 record holders of common units and approximately 60,900 beneficial owners of the common units, including common units held in street name. On March 3, 2004, the last reported sale price of our common units on the New York Stock Exchange was $40.09 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 23 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 subsidiaries. The Administrative Committee under the Plan, which are appointees of Northern Plains and NBP Services, may grant either phantom units which are based upon the general partner distribution rate or phantom LP units which are based on the price of our common units. The Administrative Committee has complete authority to determine the terms and conditions of a grant, including the identity of the participants, the time of grant, time and provisions for settlement and duration of a grant. 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 and phantom LP 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. The settlement payment for the phantom LP units is determined by the closing price of the common units on the settlement date.

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) ------------------------------------------------------------------------------------------------------ Equity compensation plans approved by the unitholders (1) -- -- -- Equity compensation plans not approved by the unitholders (1) 43,989 (2) $ 39.27 (2) 194,500 (3) ------------------------------------------------------------------------------------------------------ Total 43,989 194,500

(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, 2003 and assumes that all outstanding phantom units were settled in common units as of December 31, 2003. 24 (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. On December 23, 2003, the Partnership announced a repurchase program by Northern Plains to purchase in the open market up to 5,000 common units to satisfy obligations in January 2004 under the Amended and Restated Northern Border Phantom Unit Plan. Those units were purchased by December 30, 2003. 25 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.

YEAR ENDED DECEMBER 31, ---------------------------------------------------------------------- 2003 (1) 2002 2001 (2) 2000 (3) 1999 ----------- ---------- ----------- ---------- ---------- INCOME DATA: Operating revenues, net $ 555,927 $ 487,204 $ 455,997 $ 339,732 $ 318,963 Product purchases 80,774 50,648 39,699 -- -- Operations and maintenance 127,574 106,331 92,891 62,097 53,451 Depreciation and amortization (4) 300,199 74,672 75,424 60,699 54,842 Taxes other than income 35,443 32,194 27,863 28,634 30,952 ----------- ---------- ----------- ---------- ---------- Operating income 11,937 223,359 220,120 188,302 179,718 Interest expense, net 78,980 82,898 89,908 81,495 67,709 Other income, net 24,861 16,567 719 8,410 4,915 Minority interests in net income 44,460 42,816 42,138 38,119 35,568 Income taxes 5,365 1,643 499 378 353 ----------- ---------- ----------- ---------- ---------- Income (loss) from continuing operations (92,007) 112,569 88,294 76,720 81,003 Discontinued operations, net of tax (5) 4,196 1,107 (508) -- -- Cumulative effect of change in accounting principle, net of tax (643) -- -- -- -- ----------- ---------- ----------- ---------- ---------- Net income (loss) to partners $ (88,454) $ 113,676 $ 87,786 $ 76,720 $ 81,003 =========== ========== =========== ========== ========== Per unit income (loss) from continuing operations $ (2.16) $ 2.41 $ 2.13 $ 2.50 $ 2.70 =========== ========== =========== ========== ========== Per unit net income (loss) $ (2.08) $ 2.44 $ 2.12 $ 2.50 $ 2.70 =========== ========== =========== ========== ========== Number of units used in computation 45,370 42,709 38,538 29,665 29,347 =========== ========== =========== ========== ========== CASH FLOW DATA: Net cash provided by operating activities $ 224,660 $ 244,006 $ 233,948 $ 169,615 $ 173,368 Capital expenditures 30,282 50,738 126,414 19,721 102,270 Acquisition of businesses 123,194 1,561 345,074 229,505 31,895 Distribution per unit 3.20 3.20 2.99 2.65 2.44 BALANCE SHEET DATA (AT END OF YEAR): Property, plant and equipment, net $ 1,992,104 $2,015,280 $ 2,040,099 $1,732,076 $1,745,356 Total assets 2,570,583 2,715,936 2,687,355 2,082,720 1,863,437 Long-term debt, including current maturities 1,415,986 1,403,743 1,423,227 1,171,962 1,031,986 Minority interests in partners' equity 240,731 242,931 250,078 248,098 250,450 Partners' equity 800,573 944,035 914,958 572,274 515,269

26

YEAR ENDED DECEMBER 31, ----------------------------------------------------- 2003 (1) 2002 2001 (2) 2000 (3) 1999 --------- ------- ------- ------- ------- OTHER FINANCIAL DATA: Ratio of earnings to fixed charges (6) 0.4 2.8 2.5 2.4 2.7 OPERATING DATA: Interstate Natural Gas Pipeline Segment: Million cubic feet of gas delivered 1,110,969 935,654 891,935 852,674 834,833 Average daily throughput (mmcfd) 3,147 2,636 2,605 2,400 2,353 Natural Gas Gathering and Processing Segment: Gathering (mmcfd) 1,094 1,089 793 397 -- Processing (mmcfd) 52 55 54 -- -- Coal Slurry Pipeline Segment: Thousands of tons of coal shipped 4,451 4,639 4,932 4,711 4,494

(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. The gathering activities of Crestone Gathering have been integrated with those of Bear Paw Energy. (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. (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 be 3.2 for 2003. 27 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 accounting principles generally accepted in the United States of America. You should read the following discussion and analysis in conjunction with our Consolidated Financial Statements included elsewhere in this report. OVERVIEW The Partnership's businesses fall into three major business segments: - the interstate natural gas pipeline segment, which comprises 77% of our assets; - the natural gas gathering and processing segment, which comprises 22% of our assets; and - the coal slurry pipeline, which comprises 1% of our assets. INTERSTATE NATURAL GAS PIPELINES 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. The current outlook for western Canadian supply looks stable for the foreseeable future, however production has exceeded new reserve addition in recent years. 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. The supply outlook may be significantly enhanced over time by new Alaskan and Mackenzie Delta supplies reaching the western Canadian pipeline grid potentially beginning by the end of this decade. 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. 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. The weighted average life of contracts for Northern Border Pipeline, Midwestern Gas Transmission and Viking Gas Transmission are three and one third years, two and one third years and four years, respectively. During 2003, Northern Border Pipeline was successful in recontracting, at maximum rates, all the capacity under contracts that expired on or before November 2003. 28 The composition of the 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 is being experienced is primarily the result of greater processing capacity in Alberta, Canada. The change has caused Northern Border Pipeline to reduce its capacity by almost 2 percent to maintain a high standard of system reliability for its customers. Although Btu levels could go lower, we believe the Btu level will stabilize near the current level of 1,005 Btus/cf. Midwestern Gas Transmission's strategy is to maximize the benefits of its central location and its connections to multiple pipeline systems. During the fourth quarter of 2003, it conducted a non-binding open season for transportation service through new delivery interconnects with interstate pipelines serving eastern markets. Results were encouraging and we are in final negotiations for new contracts to support the development of one to two new interconnects. In addition, competitive pipeline projects may have a negative impact on our profitability such as the proposed ANR Pipeline Company project to expand its access to the Chicago hub and reduce its reliance on Viking Gas Transmission's deliveries at Marshfield, Wisconsin for its Wisconsin customers. This project would increase the price competition between Canadian supply entering ANR Pipeline in Wisconsin versus Chicago sourced natural gas in Illinois and could affect Viking Gas Transmission's future revenues for Wisconsin markets served through ANR Pipeline. NATURAL GAS GATHERING AND PROCESSING 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. The Williston Basin has exhibited steady to slow growth in overall volume levels. The Powder River area has seen net declines in gathering volumes throughout 2003 where production from existing wells declined and was not replaced by new wells at the same rate. Growth 29 was limited by the slower than expected issuance of drilling permits on federal lands, reserve performance and regulatory issues. In the Powder River Basin, earnings and cash flows have been below initial expectations as a result of a slower pace of drilling and higher than expected well production declines. We recorded impairment charges of $219 million and shortened the depreciable life to reflect the current value of these assets. In addition, we are in the process of renegotiating our gathering contracts with the purpose of stabilizing the revenue levels by charging a fee for the use of our facilities instead of fees based upon volumes gathered. We will also reconfigure systems where possible to reduce costs. We hold minority interests in Bighorn, Fort Union, and Lost Creek which are trunk gathering systems in the Powder River and Wind River Basins. 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. COAL SLURRY PIPELINE 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 2005. After that time, the future is uncertain. The Mohave Plant 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. In the event the Mohave Plant permanently closes, estimated shut down costs 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 $15 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 PIPELINES 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 30 would be supported by long-term contracts. We continue to work with producers and marketers to develop the contractual support for a new 300-mile pipeline project, the Bison Pipeline, to connect the coal bed methane reserves in the Powder River Basin to markets served by Northern Border Pipeline. Northern Border Pipeline intends to hold a new open season for the Bison pipeline when production increases to levels that it believes will support the project. If sufficient commitments are received, Northern Border Pipeline will pursue regulatory approvals. In addition, Midwestern Gas Transmission will pursue expanding existing interconnects and serving new delivery interconnects with other interstate pipelines to grow transportation revenues. On Viking Gas Transmission, we will work to minimize any impact on our recontracting efforts that ANR Pipeline Company's proposal to expand its capacity in the north leg of its pipeline system may have. We also intend to continue to expand the marketing of new services to meet our customers' needs on our interstate pipelines. As was the case last year, each of our interstate pipelines have some firm transportation contracts expiring in 2004. Similar to other industries, the value of capacity on interstate pipelines is driven by supply and demand conditions. In particular, with respect to Northern Border Pipeline and Viking Gas Transmission, the relationship between gas prices in Canada and prices in the midwestern U.S. markets will determine the underlying value of transportation capacity. The current gas balance in western Canada is such that our transportation has been commercially attractive for available supply that is not consumed within western Canada or committed to transportation capacity on pipelines reaching downstream markets. With expectations of a continued favorable commodity pricing environment and successful drilling programs that will trend toward more non-conventional production, supply may remain stable in the near-term. To maintain an adequate gas balance in western Canada, production will need to grow moderately 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 an estimated 1.6 trillion barrels of bitumen reserves. Bitumen, after it is extracted from sand, 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. NATURAL GAS GATHERING AND PROCESSING 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 Canadian and Rocky Mountain supply basins. During 2003, the pricing of gas produced from the Powder River Basin improved as there was some relief of capacity constraints on pipelines to market hubs. However, the pace of drilling has been slower than expected due primarily to regulatory issues (including the basin-wide environmental impact statement ("EIS"), associated litigation and response, and water disposal issues) and reserve performance. We expect to see continued build-out of our gathering systems within the areas of 31 acreage dedications we have secured, particularly in the Powder River Basin, but more slowly than previously expected. Depending on the pace of production development, response to the basin-wide EIS and resultant litigation and water-discharge permitting, we expect growth from new well connection to offset the decline from existing gas wells to result in level to slightly lower in aggregate gathered volumes on our Powder River systems (Bear Paw Energy, Bighorn and Fort Union) during 2004. We are also pursuing 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 securing additional acreage dedications, and encourage utilization of existing facilities. We expect modest growth in gas volumes for our pipelines in the Wind River, Williston and western Canadian sedimentary basins, reflecting prospects for drilling activity within these production areas. 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 each of these areas. The build-out of our existing, and the addition of new, acreage dedications should mitigate production declines and allow further improvement in cost efficiencies. With regard to our investment in the Gregg Lake/Obed pipeline in Alberta, Canada, opportunities exist for a potential expansion of the pipeline and discussions are underway with prospective customers. ACQUISITIONS Finally, our objective is to continue to acquire 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. 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 disclosures 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 32 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 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, 2003, we have recorded regulatory assets of $8.9 million, which are being recovered from the pipelines' shippers over varying periods of time. 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 33 fair value of the assets. Effective January 1, 2002, we adopted SFAS No. 142, "Goodwill and Other Intangible Assets." The comparative impact of no longer amortizing goodwill is shown in Note 4, Notes to Consolidated Financial Statements included elsewhere in this report. We have selected the fourth quarter for the performance of our annual impairment testing. As discussed below, in 2003, we decided to accelerate the impairment testing for our natural gas gathering and processing business segment to the third quarter. Our remaining business segments were tested in the fourth quarter. As discussed in Note 13, 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. 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, 2003, the consolidated balance sheet included assets from derivative financial instruments of $19.6 million and liabilities from derivative financial instruments of $5.7 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 derived from a pipeline transportation agreement. Under the terms of the agreement, we receive a monthly demand payment, a per ton commodity payment and a reimbursement for certain other expenses. RESULTS OF OPERATIONS 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. See Note 4 - Notes to 34 Consolidated Financial Statements, included elsewhere in this report. Effective January 17, 2003, we acquired all of the common stock of Viking Gas Transmission, including a one-third interest in Guardian Pipeline. See Note 3 - Notes to Consolidated Financial Statements, included elsewhere in this report. 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. See Note 3 - Notes to Consolidated Financial Statements. 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. Our operating results for 2002 reflected a full year of operating results for acquisitions we made in the first half of 2001. During 2001, we made the following acquisitions: Bear Paw Energy on March 30; the Mazeppa and Gladys gas processing plants, gas gathering systems and a minority interest in the Gregg Lake/Obed Pipeline on April 4, which are included in the operating results of Border Midstream Services; and Midwestern Gas Transmission on May 1. Our 2002 operating results also benefited from the adoption of SFAS No. 142. Our loss from continuing operations in 2003 was ($92.0 million), ($2.16) per unit, as compared to income from continuing operations of $112.6 million in 2002, $2.41 per unit, and $88.3 million in 2001, $2.13 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 $14.5 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 the Partnership's issuance of additional partnership interests in May and June 2003. The $24.3 million increase in income from continuing operations in 2002 over 2001 resulted from the acquisitions made in 2001, a decline in interest expense and the effect of the change in accounting for goodwill. As a result of adopting SFAS No. 142, we are no longer amortizing goodwill (see Note 4 - Notes to Consolidated Financial Statements). Our 2001 operating results included $13.3 million of goodwill amortization or $0.34 per unit. Goodwill amortization for 2001 by business segment was as follows: interstate natural gas pipelines - $0.9 million; natural gas gathering and processing - $12.0 million; and coal slurry - $0.4 million. Interest expense decreased $7.0 million ($6.0 million impact on continuing operations after tax and minority interest) between 2001 and 2002 primarily due to a decline in interest rates. Our average debt outstanding increased between 2001 and 2002 due to our acquisitions in 2001. 35 The Partnership's consolidated income statement reflects income (loss) from discontinued operations of $4.2 million in 2003 as compared to $1.1 million in 2002 and ($0.5 million) in 2001. Discontinued operations for 2003 include an after-tax gain of $4.9 million on the sale of the Gladys and Mazeppa processing plants. In 2001, discontinued operations included a $1.6 million loss on a forward purchase of Canadian dollars to fund our acquisition of Border Midstream Service's gathering and processing assets. 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 PIPELINES Our interstate natural gas pipeline segment reported income of $119.6 million in 2003 and $107.5 million in 2002. In 2001, excluding the impact of goodwill amortization, the segment reported income of $103.2 million. 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). The increase in 2002 income from 2001 resulted from our acquisition of Midwestern Gas Transmission in April 2001. Midwestern Gas Transmission's income, excluding the impact of goodwill amortization, increased $2.7 million from 2001 to 2002 as the 2001 results included only eight months of revenues and expenses. Operating revenues for our interstate natural gas pipeline segment were $375.2 million in 2003, $339.1 million in 2002 and $322.6 million in 2001. 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"). The increase in operating revenues in 2002 over 2001 resulted from an $8.5 million increase in Midwestern Gas Transmission's revenues and an $8.0 million increase in Northern Border Pipeline's revenues. Midwestern Gas Transmission's revenues in 2002 reflect an increase in contracted capacity as compared to the same period in 2001. Midwestern Gas Transmission's revenues in 2001 reflected only eight months of operations. For 2002, Northern Border Pipeline reflected additional revenues of approximately $10.3 million related to Project 2000, which was a pipeline expansion and extension placed in service in October 2001. The impact of the additional revenues associated with Project 2000 was partially offset by $1.8 million of uncollected revenues associated with the transportation capacity formerly held by ENA. Operations and maintenance expenses for our interstate natural 36 gas pipeline segment were $63.6 million in 2003, $48.3 million in 2002, and $36.9 million in 2001. 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. The increase in expenses in 2002 over 2001 resulted from an increase in Northern Border Pipeline's expense by $7.8 million and an increase in Midwestern Gas Transmission's expense by $3.6 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 5 - 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, by adding detailed language to the broad categories that comprise company use gas. Northern Border Pipeline had included in its collection 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. Partially offsetting this increase in expense was a reduction in bad debt expense by $1.3 million. Northern Border Pipeline's expenses in 2001 included bad debt expense related to ENA's bankruptcy. Midwestern Gas Transmission's increase for 2002 over 2001 was primarily due to 2001 results had included only eight months of activity and due to a $1.3 million increase in employee benefit expenses and administrative expenses. Depreciation and amortization expenses, excluding goodwill amortization, for our interstate natural gas pipeline segment were $65.9 million in 2003, $61.0 million in 2002 and $58.9 million in 2001. The increase between 2002 and 2003 is primarily due to Viking Gas Transmission. The increase between 2001 and 2002 reflects a $1.2 million increase in Northern Border Pipeline's expense due to Project 2000 and a $0.9 million increase from Midwestern Gas Transmission. Midwestern Gas Transmission's 2001 results had included only eight months of activity. Taxes other than income for our interstate natural gas pipeline segment were $32.9 million, $29.2 million in 2002 and $26.1 million in 2001. 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. The increase in 2002 from 2001 is primarily due to a $2.8 million increase in Northern Border Pipeline's expense. Northern Border Pipeline periodically reviews and adjusts its estimates of ad valorem taxes. Reductions to previous estimates in 2001 exceeded reductions to previous estimates in 2002 by approximately $2.1 million. Northern Border Pipeline's ad valorem taxes also increased for 2002 due to the completion of Project 2000. 37 Interest expense for our interstate natural gas pipeline segment was $47.6 million in 2003, $51.5 million in 2002 and $55.4 million in 2001. The 2003 expense included $2.7 million for Viking Gas Transmission. Northern Border Pipeline's interest expense decreased in both 2003 and 2002 from prior year levels due to a decrease in average interest rates as well as a decrease in average debt outstanding. Other income, net for our interstate natural gas pipeline segment was $0.5 million in 2003 and $2.0 million in 2002 as compared to other expense of $0.4 million in 2001. 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. The 2001 amount included bad debt expense of $1.5 million related to the bankruptcy of a telecommunications company and an allowance for equity funds used during construction of $0.9 million related primarily to Northern Border Pipeline's Project 2000. Equity earnings from unconsolidated affiliates for our interstate natural gas pipeline segment were $2.0 million in 2003, which represents earnings from our one-third interest in Guardian Pipeline. Minority interests in net income, which represent the 30% minority interest in Northern Border Pipeline, were $44.5 million for 2003, $42.8 million for 2002 and $42.1 million for 2001. The increases in 2003 and 2002 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 $3.6 million in 2003 and $0.7 million in 2002 as compared to an income tax benefit of $0.4 million in 2001. The 2003 amount included Viking Gas Transmission income taxes of $2.6 million. The remaining income tax amounts relate to Midwestern Gas Transmission. NATURAL GAS GATHERING AND PROCESSING Our natural gas gathering and processing segment reported a loss from continuing operations of ($177.9) million in 2003 and income from continuing operations of $37.2 million in 2002. Excluding the impact of goodwill amortization, the segment reported income from continuing operations of $31.2 million in 2001. 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 $4.0 million to $41.2 million between 2002 and 2003 primarily due to a $3.5 million increase in Border Midstream Services's income from its Gregg Lake/Obed investment. The increase in 2002 earnings over the prior year resulted from our acquisitions made in 2001. The 2001 results included nine months of activity for Bear Paw Energy and Border Midstream Services. Operating revenues for our natural gas gathering and processing segment were $159.3 million in 2003, $126.6 million in 2002 and $111.3 million in 2001. 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 Powder River Basin, which decreased revenues $3.9 million. The increase in operating revenues in 2002 over 2001 was 38 primarily due to the acquisitions made in 2001. The 2001 revenues for the segment included only nine months of activity for Bear Paw Energy. Revenues for 2001 included $8.3 million recorded from gas gathering and administrative services under a master services agreement with ENA that was terminated in 2001. Product purchases for our natural gas gathering and processing segment were $80.8 million in 2003, $50.6 million in 2002 and $39.7 million in 2001. Under certain gathering and processing agreements, 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 2003 over 2002 is due to an increase in natural gas and natural gas liquid prices. The increase in 2002 over 2001 was due to the 2001 results only including nine months of activity for Bear Paw Energy. Operations and maintenance expenses for our natural gas gathering and processing segment were $43.3 million in 2003, $38.2 million in 2002 and $39.6 million in 2001. 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. In 2001, the nine months of activity for Bear Paw Energy included bad debt expense of $7.5 million related to ENA's bankruptcy. See "The Impact of Enron's Chapter 11 Filing On Our Business" and Item 13. "Certain Relationships and Related Transactions." For our natural gas gathering and processing segment, depreciation and amortization expenses, excluding the impairment charge recorded in 2003 and goodwill amortization recorded in 2001, were $13.4 million in 2003, $12.1 million in 2002 and $7.7 million in 2001. 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 Basis from 30 to 15 years, which increased our depreciation expense by $0.6 million for this segment in 2003. We expect our 2004 depreciation and amortization expense for this segment to increase $1.8 million, as compared to 2003, due to the shorter useful lives. The increase in 2002 expense over 2001 was due primarily to the 2001 results only including nine months of activity for Bear Paw Energy. Other income, net from our natural gas gathering and processing segment was $5.6 million in 2003, $0.1 million in 2002 and $0.8 million in 2001. 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. Other income for 2001 included $0.7 million from a gain on sale of gas processing assets and fees collected for gas well connections. Equity earnings from our unconsolidated affiliates, excluding the impact of goodwill amortization, were $16.8 million in 2003, $14.6 million in 2002 and $8.0 million in 2001. The 2003 equity earnings include $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 a joint venture 39 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. The increase in equity earnings in 2002 over 2001 was primarily due to an increase in gathering volumes and the acquisitions made in 2001. COAL SLURRY Our coal slurry pipeline segment reported income of $3.7 million in 2003 on revenues of $21.4 million and $4.1 million in 2002 on revenues of $21.5 million. In 2001, excluding the impact of goodwill amortization, the segment reported income of $4.9 million on revenues of $22.1 million. The coal slurry segment income for 2003 was reduced by $0.4 million for a cumulative effect of change in accounting principle, which resulted from adopting SFAS No. 143. The 2002 results were impacted by unplanned coal slurry discharges, which increased operations and maintenance expense by $1.1 million over 2001. The 2001 results included interest expense of $0.7 million associated with debt that was repaid in June 2001. OTHER Items not attributable to any segment include certain of our general and administrative expenses, interest expense on our debt, other income and expense items and a loss on reacquired debt. Our general and administrative expenses not allocated to any segment were $7.0 million in 2003, $5.5 million in 2002 and $3.1 million in 2001. The 2003 expense included $0.4 million for the termination of the Enron cash balance plan and an increase in insurance expense by $0.5 million due to an increase in liability premiums. The amount of general and administrative expenses recorded in each year has increased due to our acquisitions and due to additional common units issued, which increased our unitholder tax return processing expenses. Interest expense on our debt was $30.8 million in 2003, $30.6 million in 2002 and $33.1 million in 2001. The decrease in expense for 2002 from 2001 was primarily due to a decrease in average interest rates partially offset by an increase in average debt outstanding related to the acquisitions made in 2001. Other expenses, net not allocated to any segment were $0.1 million in 2002 and $1.5 million in 2001. The amount for 2001 included a loss from debt restructuring of $1.2 million related to the repayment of Black Mesa's 10.7% Secured Senior Notes. The total repayment of approximately $13.6 million consisted of remaining principal and interest of $12.4 million and an early payment premium of $1.2 million. LIQUIDITY AND CAPITAL RESOURCES SUMMARY OF CERTAIN CONTRACTUAL OBLIGATIONS AND COMMERCIAL COMMITMENTS

Payments Due by Period -------------------------------------------- Less Than After Total 1 Year 1-3 Years 4-5 Years 5 Years ---------- ------- --------- --------- ------- (In Thousands) 2002 Pipeline Senior Notes due 2007 $ 225,000 $ -- $ -- $225,000 $ -- 1999 Pipeline Senior

40 Notes due 2009 200,000 -- -- -- 200,000 2000 Partnership Senior Notes due 2010 250,000 -- -- -- 250,000 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 35,661 4,760 9,520 9,164 12,217 2002 Pipeline Credit Agreement due 2005 131,000 -- 131,000 -- -- 2003 Partnership Credit Agreement due 2007 46,000 -- -- 46,000 -- Capital Leases (a) 6,610 3,348 3,262 -- -- Operating Leases (b) 26,608 8,035 8,513 6,132 3,928 Other Long-Term Obligations (b) 72,915 11,656 23,247 23,279 14,733 ---------- ------- -------- -------- -------- Total $1,468,794 $27,799 $175,542 $309,575 $955,878 ========== ======= ======== ======== ======== (a) See Note 7 - Notes to Consolidated Financial Statements. (b) See Note 11 - 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, 2003, the amount of both guarantees was $4.4 million. DEBT AND CREDIT FACILITIES AND ISSUANCE OF COMMON UNITS Northern Border Pipeline and we have entered into revolving credit facilities, which are used for refinancing existing indebtedness, capital expenditures, acquisitions and general business purposes. Northern Border Pipeline entered into a $175 million three-year credit agreement ("2002 Pipeline Credit Agreement") with certain financial institutions in May 2002. We entered into a $275 million four-year revolving credit agreement ("2003 Partnership Credit Agreement") with certain financial institutions in November 2003. Both credit agreements replaced prior credit agreements. At December 31, 2003, $131 million was outstanding under the 2002 Pipeline Credit Agreement at an average interest rate of 1.95% and $46 million was outstanding under the 2003 Partnership Credit Agreement at an average interest rate of 2.67%. In January 2004, TC PipeLines and the Partnership contributed $19.5 million and $45.5 million, respectively, to Northern Border Pipeline to be used by Northern Border Pipeline to repay a portion of its existing indebtedness under the 2002 Pipeline Credit Agreement. In May 2004 and May 2007, Northern Border Pipeline intends to issue additional equity cash calls to its partners for $65 million and $90 million, respectively. We will be responsible for our ownership share of each equity cash call (currently 70%). The 2002 Pipeline Credit Agreement and 2003 Partnership Credit Agreement require Northern Border Pipeline and us 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 41 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, 2003, we were in compliance with these covenants. In April 2002, Northern Border Pipeline completed a private offering of $225 million of 6.25% Senior Notes due 2007 ("2002 Pipeline Senior Notes"). In September 2001, Northern Border Pipeline completed a private offering of $250 million of 7.50% Senior Notes due 2021 ("2001 Pipeline Senior Notes"). In August 1999, Northern Border Pipeline completed a private offering of $200 million of 7.75% Senior Notes due 2009 ("1999 Pipeline Senior Notes"). The 2002 Pipeline Senior Notes, 2001 Pipeline Senior Notes and 1999 Pipeline Senior Notes (collectively "Pipeline Senior Notes") were subsequently exchanged in registered offerings for notes with substantially identical terms. 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 proceeds from the Pipeline Senior Notes were used to reduce indebtedness outstanding. 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. The swaps were entered into to hedge the fluctuations in the market value of the 2002 Pipeline Senior Notes. At December 31, 2003, the average effective interest rate on Northern Border Pipeline's interest rate swap agreements was 2.31%. In March 2001, we completed a private offering of $225 million of 7.10% Senior Notes due 2011 ("2001 Partnership Senior Notes"). In June 2000, we completed a private offering of $150 million of 8 7/8% Senior Notes due 2010 ("2000 Partnership Senior Notes") and in September 2000, we completed an additional private offering of $100 million of 2000 Partnership Senior Notes. The 2001 and 2000 Partnership Senior Notes were subsequently exchanged in registered offerings for notes with substantially identical terms. The indentures under which the 2001 and 2000 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 2001 and 2000 Partnership Senior Notes, if either Standard & Poor's Rating Services or Moodys' Investor Services, Inc. rate the notes below investment grade and the investment grade rating is not reinstated for a period of 40 days. We used the proceeds from the 2001 and 2000 Partnership Senior Notes to fund our acquisitions in 2001 and 2000. 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 receives payments based on a 7.10% fixed rate. The 42 swaps were entered into to hedge the fluctuations in the market value of the 2001 Partnership Senior Notes. At December 31, 2003, the average effective interest rate on our interest rate swap agreements was 3.72%. At December 31, 2003, Viking Gas Transmission has four series of senior notes outstanding. Transportation service agreements have been pledged as security for these senior notes. Viking Gas Transmission's senior notes indenture provides for certain restrictions on the payment of cash dividends on common stock. The most restrictive of these is that the payment of cash dividends on common stock is prohibited unless debt service funds in an amount equal to all scheduled payments of principal and interest for the 180-day period following the current month end would remain on deposit following the dividend payment. At December 31, 2003, the requirement for accumulation of debt service funds prior to payment of dividends was $3.7 million. 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 April and May of 2001, we sold 407,550 and 4,000,000 common units, respectively. 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, $75.4 million and $172.2 million in 2003, 2002 and 2001, respectively, and were primarily used to repay indebtedness outstanding. Short-term liquidity needs will be met by our operating cash flows and through the 2003 Partnership Credit Agreement and the 2002 Pipeline Credit Agreement. Long-term capital needs may be met through our ability to issue long-term indebtedness as well as additional limited partner interests. CASH FLOWS FROM OPERATING ACTIVITIES Cash flows provided by operating activities were $224.7 million in 2003, $244.0 million in 2002 and $233.9 million in 2001. The decrease from 2002 to 2003 is primarily due to Northern Border Pipeline's refund to its shippers for $10.3 million (see Note 5 - 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. The increase from 2001 to 2002 reflects a $3.7 million increase in distributions received from our unconsolidated affiliates and the prepayments received by Northern Border Pipeline from certain shippers for transportation service. During 2001, we realized net cash outflows of $4.7 million related to Northern Border Pipeline's rate case, which included $2.1 million of amounts collected subject to refund less refunds issued in early 2001 totaling $6.8 million. 43 CASH FLOWS FROM INVESTING ACTIVITIES Cash used in investing activities was $116.7 million in 2003, $55.3 million in 2002 and $482.7 million in 2001. In 2003 and 2001, we spent higher amounts primarily related to the acquisitions we made in both years and for Northern Border Pipeline's Project 2000 facilities. Our capital expenditures were $30.3 million in 2003, which included $19.5 million for interstate natural gas pipeline facilities and $9.0 million for natural gas gathering and processing facilities. For 2002, our capital expenditures were $50.7 million, which included $33.7 million for natural gas gathering and processing facilities and $16.5 million for interstate natural gas pipelines facilities. For 2001, our capital expenditures were $126.4 million, which included $69.1 million for gas gathering and processing facilities and $57.0 million for interstate natural gas pipeline facilities. The 2001 expenditures for interstate natural gas pipeline facilities included $49.0 million for Northern Border Pipeline's Project 2000. Our cash used in acquisitions was $123.2 million in 2003, as compared to $1.6 million in 2002 and $345.1 million in 2001. In January 2003, we acquired Viking Gas Transmission. In 2001, we acquired Midwestern Gas Transmission and the assets of Border Midstream Services in April 2001 and Bear Paw Energy in March 2001. The purchase of Bear Paw Energy also required us to issue 5.7 million common units valued at $183.0 million, for a total purchase price of $381.7 million. Sale of assets were $40.3 million in 2003 due to the sale of the Gladys and Mazeppa processing plants discussed previously. Our investments in unconsolidated affiliates were $3.5 million in 2003, $3.0 million in 2002 and $11.2 million in 2001. The 2003 amount primarily represents capital contributions to Guardian Pipeline while the 2002 and 2001 amounts primarily reflect capital contributions to Bighorn Gas Gathering. Total capital expenditures for 2004 are estimated to be $29 million. Capital expenditures for the interstate pipelines are estimated to be $19 million, including approximately $14 million for Northern Border Pipeline. Northern Border Pipeline currently anticipates funding its 2004 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 $9 million for 2004. Funds required to meet the capital requirements for 2004 are anticipated to be provided from our credit facility, issuance of additional limited partnership interests and operating cash flows. CASH FLOWS FROM FINANCING ACTIVITIES Cash flows used in financing activities were $106.7 million for 2003 and $170.8 million for 2002, as compared to cash provided by financing activities of $230.1 for 2001. Our cash distributions to our unitholders and our general partners in 2003, 2002 and 2001 were $155.2 million, $147.0 million and $120.9 million, respectively. The increase in 2003 over 2002 is due to an increase in the number of common units outstanding. The increase in 2002 over 2001 results is due to both an increase in the number of common units 44 outstanding and an increase in the distribution rate. The distribution paid in each quarter of 2003 and 2002 was $0.80 per unit as compared to $0.70 per unit paid in the first quarter of 2001 and $0.7625 per unit paid in the second quarter, third quarter and fourth quarter of 2001. In 2003, 2002 and 2001, we issued additional partnership interests of $102.2 million (2.6 million common units), $75.4 million (2.2 million common units) and $172.2 million (4.4 million common units), respectively, which were primarily used to repay indebtedness outstanding. 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 private offering of 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. For 2001, our borrowings on long-term debt totaled $863.1 million, which were used for both repayments of previously existing indebtedness and to finance a portion of our acquisitions in March and April of 2001. Issuances of long-term debt included net proceeds from the private offering of the 2001 Partnership Senior Notes of approximately $223.2 million; borrowings under our prior credit agreement of $232.0 million; net proceeds from the issuance of the 2001 Pipeline Senior Notes of approximately $247.2 million; and borrowings under Northern Border Pipeline's prior credit agreement of $136.0 million. The proceeds from the 2001 Partnership Senior Notes and our prior credit agreement were primarily used to fund the acquisitions of Bear Paw Energy, Canadian midstream assets and Midwestern Gas Transmission discussed previously and to repay indebtedness outstanding. Total repayments of debt were $604.9 million in 2001. For the year ended December 31, 2001, Northern Border Pipeline recognized a decrease in bank overdraft of $22.4 million. At December 31, 2000, Northern Border Pipeline reflected the bank overdraft primarily due to rate refund checks outstanding. 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. As consideration for the change to the variable interest rate, we received approximately $18.2 million, which represented the fair value of the 45 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. In March 2001, we paid approximately $4.3 million to terminate forward starting interest rate swap agreements and in September 2001, Northern Border Pipeline paid approximately $4.1 million to terminate interest rate swap agreements. The interest rate swaps had been entered into to hedge the fluctuations in Treasury rates and spreads between the execution date of the swaps and the issuance of fixed rate debt by Northern Border Pipeline and us (see Note 8 - Notes to Consolidated Financial Statements). 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 expenditures with 50% equity capital contributions from its partners; and (iii) change the cash distribution policy of the Company effective January 1, 2004. At that time, cash distributions will be equal to 100% of distributable cash flow as determined from the Company's financial statements based upon earnings before interest, taxes, depreciation and amortization less interest expense and less maintenance capital expenditures. Effective January 1, 2008, the cash distribution policy will be adjusted to maintain a consistent capital structure. NEW ACCOUNTING PRONOUNCEMENTS In the third quarter of 2001, the Financial Accounting Standards Board ("FASB") issued SFAS No. 143, "Accounting for Asset Retirement Obligations." In November 2002, the FASB issued Interpretation No. 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others." In 2003, the FASB issued SFAS No. 149, "Amendment of Statement 133 on Derivative Instruments and Hedging Activities," SFAS No. 150, "Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity," EITF No. 00-21 "Revenue Arrangements with Multiple Deliverables," and Interpretation No. 46, "Consolidation of Variable Interest Entities." See Note 13 - 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. We have not filed for bankruptcy protection. Northern Plains, Pan Border and Northwest Border are our general partners. Each of Northern Plains and Pan Border are wholly owned subsidiaries of Enron, and Northwest Border is a wholly owned subsidiary of TransCanada. Northern Plains and Pan Border were not among the Enron companies filing for Chapter 11 protection. The business of Enron and its subsidiaries that have filed for bankruptcy protection are currently being administered under the direction and control of the bankruptcy court. An unsecured creditors committee has been appointed in the Chapter 11 cases. The creditors 46 committee is responsible for general oversight of the bankruptcy case, and has the power, among other things, to: investigate the acts, conduct, assets, liabilities, and financial condition of the debtor, the operation of the debtor's business and the desirability of the continuance of such business; participate in the formulation of a plan of reorganization; and file acceptances or rejections to such a plan. On June 25, 2003, Enron announced the organization of CrossCountry Energy Corp., a newly formed holding company, to hold, among other assets, Enron's ownership interest in Northern Plains, Pan Border and NBP Services. The motion filed in Bankruptcy Court to approve the proposed transfer of those ownership interests was approved on September 25, 2003. An amended order on December 18, 2003 made the approval applicable to CrossCountry Energy, LLC ("CrossCountry"). In connection with the closing, CrossCountry and Enron will enter into a transition services agreement pursuant to which Enron will 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 (iii) contract management and purchasing support services (iv) corporate secretary services, and (v) payroll, employee benefits and administrative services. In turn, these services are provided to us through Northern Plains and NBP Services. When the transfer of interests in Northern Plains, Pan Border and NBP Services to CrossCountry as contemplated above takes place, the articles of incorporation of Northern Plains, Pan Border and NBP Services will be amended to reflect certain shareholder protections that will be retained by Enron until distribution of any common stock of CrossCountry pursuant to the Chapter 11 Plan. Northern Plains and Pan Border, subject to applicable fiduciary duties and/or contractual obligations, will need the affirmative vote of Enron to vote its interest at the Partnership Policy Committee to, among other things, (a) enter into any business other than owning and operating natural gas pipeline, coal slurry pipelines, natural gas gathering facilities, midstream gas processing facilities, gas and hydrocarbon liquids storage facilities and related businesses; and (b) enter into any compromise or settlement of any action, suit, litigation, arbitration proceeding or any governmental investigation or audit relating to the assets, liabilities or business of the entities or the Partnership in excess of $2 million. On January 9, 2004, the Bankruptcy Court approved as complete the amended joint Chapter 11 plan and related disclosure statement ("Chapter 11 Plan"). The Chapter 11 Plan has been submitted to the creditors for approval. Several creditors have filed objections to the Chapter 11 Plan, including Pension Benefit Guaranty Corporation ("PBGC"). The Bankruptcy Court has scheduled a hearing for April 20, 2004 on the approval. Under the Chapter 11 Plan, it is anticipated that if CrossCountry is not sold to a third party, as permitted by the Chapter 11 Plan, its shares would be distributed directly or indirectly to creditors of the debtors. Enron's filing for bankruptcy protection has impacted us. At the time of the filing of the bankruptcy petition, we had a number of contractual relationships with Enron and its subsidiaries. NBP Services Corporation, a wholly owned subsidiary of Enron that is not in 47 bankruptcy, and Northern Plains provided and continue to provide operating and administrative services for us and our subsidiaries. Northern Plains and NBP Services have continued to meet their operational and administrative service obligations under the existing agreements, and we believe they will continue to do so. 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 proceeding in 2002, ENA rejected and terminated all of its contracts on Northern Border Pipeline. Northern Border Pipeline filed claims against ENA for damages for breach of contract and other 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. 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 hedges. In 2003, Bear Paw Energy recorded approximately $0.3 million in earnings related to the terminated hedges. Also, Crestone Energy Ventures filed claims against ENA for unpaid gas gathering and administrative services fees. The claims against Enron and ENA referenced above are unsecured claims. We are uncertain regarding the ultimate amount of damages for breach of contract or other claims that we will be able to establish in the bankruptcy proceeding, and we cannot predict the amounts that we will collect or the timing of collection. We believe, however, that any such delay in collecting or failure to collect will not have a material adverse effect on our financial condition. 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 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. In addition, the Bankruptcy Court order provides that the rights of PBGC and others to assert that their filed claims have not been released or adjudicated as a result of the Bankruptcy Court order and 48 Enron and all other interested parties retained the right to assert that such claims had been adjudicated or released. Enron management has informed Northern Plains and NBP Services that it will 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 Plan. Northern Plains and NBP Services have advised us that each is a member of the ERISA controlled group of corporations of Enron that employs, or employed, individuals who are, or were, covered under the Plan and that an amount of approximately $6.2 million has been estimated for our share of Northern Plains' and NBP Services' proportionate share of the up to $200 million estimated termination costs authorized by the Bankruptcy Court order. Under the operating agreements with Northern Plains and the administrative services agreement with NBP Services, these increased costs may be our responsibility. We have accrued the amount of $6.2 million to satisfy claims of reimbursement for these termination costs. While the final amounts have not been determined, we believe this accrual is adequate to cover the allocation of these costs to us. 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 us. 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 as requested is granted, Northern Plains would assume 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 has been filed and no hearing date has been set. An additional actuary has been engaged by Enron to review the analysis and recommendations for allocations. There can be no assurances that the allocation of liabilities and assets will not change from those set forth in the motion. Enron's filing for bankruptcy protection and related developments have had other impacts on our business and management. Numerous shareholder and employee class action lawsuit have been initiated against Enron, its former independent accountants, legal advisors, executives, and board members. Enron has received several requests for information from different federal and state agencies, including FERC, and committees of the United States House of Representatives and Senate. Some of the information requested from Enron may include information about us. While the Partnership has not been subject to 49 these investigations or lawsuits, it is possible that in the documentation production by Enron and others, confidential proprietary or commercially sensitive information concerning the Partnership may have been produced. It is also possible that some of this information may be made available to the public. While Northern Plains, Pan Border and NBP Services have not filed for Chapter 11 bankruptcy protection, their stock is owned by Enron, which is in bankruptcy. As noted above, Enron could sell its interest in Northern Plains and/or Pan Border, or take other action with respect to their investment in us. Enron could also cause Northern Plains and Pan Border to file for bankruptcy protection. We have had no indication from Enron that it intends to cause such companies to file for bankruptcy protection. We are managed by a three member policy committee, with one member appointed by each general partner. The vote of each member of the policy committee is weighted by the general partner percentage of the general partner appointing such member. The general partner percentages for Northern Plains, Pan Border and Northwest Border are 50%, 32.5% and 17.5%, respectively. If Enron were to sell the stock of Northern Plains and Pan Border, the purchaser would have the right to appoint a majority of our policy committee and control the activities of the Partnership. The 2003 Partnership Credit Agreement provides that it would be a change of control (and consequently an event of default) thereunder if subsidiaries of Enron, CrossCountry and/or TransCanada PipeLines Limited do not control, free of any liens, greater than 50% of the general partner percentages. Consequently, if Enron sells the stock of Northern Plains and Pan Border or CrossCountry to a third party, a waiver under the 2003 Partnership Credit Agreement would need to be obtained. In addition, the agreements evidencing the Partnership's other material outstanding debt obligations provide that an uncured default under one material debt agreement will result in a default under other debt agreements. Northern Plains also serves as operator of Northern Border Pipeline. If Northern Plains were to file for bankruptcy relief, it could potentially be removed as operator. Certain of Northern Border Pipeline's credit agreements provide that it would be an event of default thereunder if Northern Plains were replaced as operator without the consent of the lenders thereunder. The Administrative Services Agreement between NBP Services and us provides that it will terminate at such time as Northern Plains is no longer a general partner of the Partnership. Consequently, since our Partnership Agreement provides that a general partner is automatically withdrawn as general partner upon filing of bankruptcy, if Northern Plains were to file for bankruptcy relief, the Administrative Services Agreement would be terminated. Our Partnership Agreement requires that each general partner make additional capital contributions to us when we sell common units. Enron may determine that it is not in the best interest of its creditors and other constituencies in bankruptcy to make these capital contributions to Northern Plains and Pan Border. Enron could therefore decide not to allow us to pursue acquisitions financed with the issuance of additional common units. Even if Enron were to permit the 50 general partners to make a capital contribution to us, if the general partners were to subsequently file for bankruptcy relief, the capital contribution might be subject to challenge as voidable under applicable law. Other than the items set forth above, we are not are not aware of any claims made against us that arise out of the Enron bankruptcy cases. We continue to monitor developments at Enron, to assess the impact on us of our existing agreements and relationships with Enron and its subsidiaries, and to take appropriate action to protect our interests. PUBLIC UTILITY HOLDING COMPANY ACT ("PUHCA") REGULATION Besides its ownership in two of our general partners, all of the common stock of Portland General Electric Company ("PGE") is owned by Enron. As the owner of PGE's common stock, Enron is a holding company for purposes of the Public Utility Holding Company Act of 1935 ("PUHCA"). Following Enron's acquisition of PGE in 1997, Enron annually filed a statement claiming an exemption from all provisions of PUHCA (except the provision which addresses the acquisition of public utility company affiliates) under Section 3(a)(1). Due to Enron's bankruptcy filing in December 2001, Enron was no longer able to provide necessary financial information needed to file the exemption statement. As a result, in February 2002, Enron applied to the Securities and Exchange Commission ("SEC") for an order of exemption under Sections 3(a)(1), 3(a)(3) and 3(a)(5). On December 29, 2003, the SEC issued an order denying the two applications filed by Enron seeking exemption as a public utility holding company under Sections 3(a)(1), 3(a)(3) and 3(a)(5) of PUHCA. The SEC order found, relative to the application under Section 3(a)(1), that Enron's subsidiary, PGE, is not predominantly and substantially intrastate in character and does not carry on business substantially in a single state. Relative to the application under Sections 3(a)(3) and 3(a)(5), the SEC found that Enron was unable to establish that it is only incidentally a holding company and that it derives no material part of its income from an electric utility subsidiary. On December 31, 2003, Enron and other related entities filed an application under Section 3(a)(4) of PUHCA (the "3(a)(4) Application"). This application claims, for each of the applicants, an exemption as a public utility holding company based on the temporary nature of the applicants' current or proposed interest in PGE under the chapter 11 plan filed by Enron and certain of its subsidiaries. By SEC order entered January 30, 2004, the hearing date on Enron's pending application for exemption under PUHCA was postponed until February 9, 2004 and by SEC order entered February 6, 2004, the hearing date was postponed until further notice. On March 9, 2004, pursuant to an offer of settlement that had been previously made to the SEC, Enron, withdrew the 3(a)(4) Application and registered as a holding company under PUHCA. Immediately after Enron registered, the SEC issued two orders, one granting Enron and its subsidiaries authority to undertake certain transactions without further authorization from the SEC under PUHCA (referred to as the "Omnibus Order") and the other approving 51 Enron's Fifth Amended Bankruptcy Plan (referred to as the "Plan Order"). The Omnibus Order authorizes, among other items, certain transactions specific to Northern Border Partners, L.P. and its subsidiaries, including authority for Northern Border Partners to declare and pay distributions out of capital. Further, the Omnibus Order authorizes Northern Border Partners to invest as much as an additional $1 billion in natural gas gathering, processing, storage and transportation assets and to issue and sell debt and equity securities as may be required to fund such investments or acquisitions. The authorizations are effective until the earlier of the deregistration of Enron under PUHCA or July 31, 2005. We believe that the authority relating to Northern Border Partners and its affiliates in the Omnibus Order minimizes the likelihood that our business will be adversely impacted by Enron's registration under PUHCA. However, PUHCA imposes a number of restrictions on the operations of a registered holding company and its subsidiaries within the registered holding company system that can become materially more expensive and cumbersome than operations by companies that are not subject to, or exempt, from PUHCA. As a subsidiary of a registered holding company, we are subject to regulation by the SEC with respect to the acquisition of the securities of public utilities; the acquisition of assets and interests in any other business, declaration and payment of certain cash distributions; intra-system borrowings or indemnifications; sales, services or construction transactions with other holding company system companies; and the issuance of debt or equity securities, among other matters. To the extent those regulated activities are not approved under the Omnibus Order or otherwise exempt under various rules and the regulations promulgated under PUHCA, we would need to seek additional approvals from the SEC. At this time, we do not believe that there is a need to seek any additional authorizations from the SEC in order to conduct our operations. Nevertheless, there can be no assurance that PUHCA will not have an adverse impact on our operations as a result of Enron's registration as a 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 52 - the discussions in "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Liquidity and 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, Northern Border Pipeline's operator, and NBP Services, administrator for us, are wholly-owned subsidiaries of Enron and depend on Enron and certain of its affiliates for some services they provide to us, potential further developments in the Enron Chapter 11 proceeding may cause either or both Northern Plains and NBP Services to be unable to perform under their agreements or to incur increases in costs to continue or replace the services provided by Enron and its affiliates. Higher costs may result from the termination of Enron's pension plan and partition of the Voluntary Employee Benefit Trust. Also, Enron announced its intention to create a new pipeline operating entity, which will include Northern Plains, Pan Border and NBP Services. See "The Impact Of Enron's Chapter 11 Filing On Our Business" above. - Contracts on our interstate pipelines will expire prior to November 1, 2004. On Northern Border Pipeline, those contracts represent approximately 30% of its system 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. 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 until November 2005, at which time Northern Border Pipeline is obligated to file a rate case. We cannot predict what 53 challenges our interstate pipelines may have to their rates in the future. See Item 1. "Business - Interstate Pipelines - FERC Regulation." - 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, each of these pipelines must maintain or increase its rate base through projects that maintain or add to existing pipeline facilities and/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's ability to operate its pipeline on certain tribal lands will depend on Northern Border Pipeline's success in renegotiating before 2011 its right-of-way rights on tribal lands within the Fort Peck Reservation. See Item 2. "Properties." Northern Border Pipeline and the Tribes, through a mediation process, reached a settlement in principle on the pipeline right-of-way lease and taxation issues. See Item 3. "Legal Proceedings." If the settlement is not finalized or if Northern Border Pipeline is unable to recover the costs of the proposed settlement in its future rates, it could have a material adverse impact on our results of operation. - 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. 54 - 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. - 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 western Canadian sedimentary, 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 recently issued 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 restructure certain gathering contracts to improve revenues, reduce operating expenditures and reduce 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 exhibited a decline of approximately 2% during 2003 to approximately 940 Btu/cubic foot. Most natural gas quality standards of interstate pipelines require a minimum of 950 Btu/cubic foot. 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 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. 55 - 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. Enron's circumstances have caused the credit rating agencies to review the capital structure and earnings power of energy companies, including us. 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 "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 "Debt and Credit Facilities and Issuance of Common Units" above. - 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, 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. ITEM 7a. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK 56 We may be exposed to market risk through changes in commodity prices, exchange rates 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. Other than entering into a forward purchase of Canadian dollars in 2001 to fund our acquisition of the Canadian midstream assets, we have not used financial instruments in the management of exchange rates. INTEREST RATE RISK 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, 2003, we had $552.0 million of variable rate debt outstanding, $375.0 million of which was previously fixed rate debt that had been converted to variable rate debt through the use of interest rate swaps. For additional information on our debt obligations and derivative instruments, see Note 7 and Note 8 to our Consolidated Financial Statements, included elsewhere in this report. As of December 31, 2003, approximately 59% of our debt portfolio was in fixed rate debt. If average interest rates change by one percent compared to rates in effect as of December 31, 2003, consolidated annual interest expense would change by approximately $5.5 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, 2003. 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. Prior to 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 2004. We have hedged 45% to 50% of our commodity price risk in 2004. ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA The information required hereunder is included in this report as 57 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 Our principal executive officer and principal financial officer have evaluated the effectiveness of our "disclosure controls and procedures" as such term is defined in Rule 13(a)-15(e) or Rule 15(d)-15(e) of the Securities Exchange Act of 1934, as amended, within 90 days of the filing of this report. Based upon their evaluation, the principal executive officer and principal financial officer concluded that our disclosure controls and procedures are effective. There were no significant changes in our internal controls or in other factors that could significantly affect these controls, since the date the controls were evaluated. 58 PART III ITEM 10. PARTNERSHIP MANAGEMENT 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 or 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. 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 Enron that has not filed for bankruptcy protection, pursuant to which NBP Services provides tax, accounting, legal, cash management, investor relations, operating and other services for the Partnership. NBP Services has approximately 135 employees. It also uses employees of Enron or its affiliates who have duties and responsibilities other than those relating to the Administrative Services Agreement. In consideration for its services under the Administrative Services Agreement, NBP Services is reimbursed for its direct and indirect costs and expenses, including an allocated portion of employee time and Enron's overhead costs. See Item 13. "Certain Relationships and Related Transactions." 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. On March 4, 2004, the Policy Committee appointed Gerald 59 B. Smith as the Chairman of the Audit Committee. Also, the Policy Committee determined that all of the Audit Committee members are financial experts and that they are independent. 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. Effective September 2003, Paul E. Miller was designated by TransCanada as its member on the Partnership Policy Committee and one of our representatives on the Northern Border Management Committee, replacing Paul MacGregor. There are no family relationships between any of our executive officers or members of the Partnership Policy and Audit Committees. 60

NAME AGE POSITIONS ---- --- --------- Executive Officers: William R. Cordes 55 Chief Executive Officer Jerry L. Peters 46 Chief Financial and Accounting Officer Members of Partnership Policy Committee and Partnership's representatives on Northern Border Management Committee: William R. Cordes 55 Chairman Stanley C. Horton 54 Member Paul E. Miller 45 Member Members of Audit Committee: Gerald B. Smith 53 Chairman Daniel P. Whitty 72 Member Gary N. Petersen 52 Member

William R. Cordes was named Chief Executive Officer of the Partnership and Chairman of the Partnership Policy Committee in October 2000. Mr. Cordes is the President of Northern Plains, an Enron subsidiary, having been appointed to that position on October 1, 2000, and is a director of Northern Plains. 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 and from May of 1996 until September of 2000, he was also President of Transwestern Pipeline, a subsidiary of Enron. Stanley C. Horton was appointed to the Partnership Policy Committee and to the Northern Border Management Committee in December 1998. Mr. Horton is the President and Chief Executive Officer of CrossCountry Energy, L.L.C. and has held that position since November 21, 2003. He is Chairman of the Boards of Northern Plains and Pan Border and was appointed to those positions in October 1993 and December 1998, respectively. He is the Chairman, President and Chief Executive Officer of NBP Services and was appointed to those positions in August 1993. He is Chairman, President and Chief Executive Officer of CrossCountry Energy Services, L.L.C. (formerly CGNN, Inc.) and has held those positions since November 2001. From August 2001 until November 2003, he was Chairman and Chief Executive Officer of Enron Global Services. From January 1997 to August 2001, he was Chairman and Chief Executive Officer of Enron Transportation Services Company, formerly known as the Enron Gas Pipeline Group. From February 1996 to January 1997, he was Co-Chairman and Chief Executive Officer of Enron Operations Corp. From June 1993 to February 1996, he was President and Chief Operating Officer of Enron Operations Corp. He was a Director and Chairman of the Board of EOTT Energy Corp., the general partner of EOTT Energy Partners, L.P. until his resignation from the office of Chairman on April 10, 2002 and then his resignation as Director on May 31, 2002. EOTT Energy Corp. filed for bankruptcy protection on October 21, 2002. From May 2001 to November 2001, Mr. Horton was a member of the Board of Directors of Portland General Electric. Mr. Horton also holds or held the elected position of officer and/or director of the following Enron companies that have filed for Chapter 11 bankruptcy protection: 61 Calypso Pipeline, L.L.C. (Director, President and Chief Executive Officer) Enron Transportation Services Company (Chairman, President and Chief Executive Officer and Director) Enron Asset Management Resources, Inc. (Chairman, President and Chief Executive Officer) Enron Liquid Services Corp. (Chairman, President and Chief Executive Officer) Enron Machine and Mechanical Services, Inc. (Chairman, President and Chief Executive Officer) Enron Operations Services Corp.(n/k/a Enron Operations, LLC) (President) Enron Pipeline Construction Services Company (Chairman, President and Chief Executive Officer) Enron Processing Properties, Inc. (Director, Chairman and President) Enron Trailblazer Pipeline Company (Chairman and President) Enron Alligator Alley Pipeline Company (Director and President until February 14, 2003) Enron Renewable Energy Corp. (Chairman until November 14, 2002) Enron Pipeline Services Company (Chairman and Chief Executive Officer until September 19, 2002) Enron Wind Corp.(n/k/a Enron Wind LLC) (Chairman and Director until April 19, 2002) Enron Wind Development Corp. (N/K/A Enron Development LLC) (Director and Chairman until April 19, 2002) Enron Wind Systems, Inc.(n/k/a Enron Wind Systems, LLC) (Director until April 19, 2002) Enron Wind Energy Systems Corp.(n/k/a Enron Wind Energy Systems, LLC) (Chairman, Director until April 19, 2002) Enron Wind Maintenance Corp.(n/k/a Enron Wind Maintenance, LLC) (Chairman, Director until April 19, 2002) Enron Wind Constructors Corp.(n/k/a Enron Wind Constructors, LLC) (Chairman, Director until April 19, 2002) Portland General Holdings, Inc. (Chairman and Director until October 31, 2002) Zond Pacific, LLC (Chairman until September 25, 2002) In September 2003, TransCanada designated Paul E. Miller as its member on the Partnership Policy Committee. 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, director in August 1994 and Treasurer in October 1998. Mr. Peters was also Vice President, Finance of: 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. 62 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; a director and member of the audit committee of Cooper Industries; and a director of the Fund Management Board of Robeco Group,Rorento N.V. (Netherlands). He served as a director of Pennzoil-Quaker States and was a member of the Audit Committee and Executive Committee of its board until October 2002. 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. Also at the meeting of the Partnership Policy Committee on March 4, 2004, the following persons were deemed to be officers for purposes of Section 16 of the Securities Exchange Act of 1934. Some of these individuals are officers at certain subsidiaries of the Partnership:

NAME AGE POSITIONS ---- --- --------- Vice President of Marketing, Interstate Paul F. Miller 37 Pipelines Vice President, Regulatory Affairs and Market Raymond D. Neppl 59 Services, Interstate Pipelines Vice President, General Counsel and Assistant Janet K. Place 55 Secretary Randy K. Rice 46 Vice President, Operations, Interstate Pipelines Vice President, Business Development and Strategic Gaye Lynn Schaffart 44 Planning Pierce H. Norton 44 President, Bear Paw Energy, LLC Fred G. Rimington 53 President, Black Mesa Pipeline, Inc.

63 Paul F. Miller is Vice President of Marketing, Interstate Pipelines of Northern Plains, having been elected in March 2002. 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. 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 1991-1994. Mr Neppl joined Northern Natural Gas Company, formerly affiliated with Northern Plains, in 1975 and transferred to Northern Plains in 1981. Janet K. Place is Vice President, General Counsel and Assistant Secretary of Northern Plains, having been elected in August 1994. In 1993, Ms. Place was named General Counsel. Ms. Place joined Northern Plains in 1980 as an Attorney. Randy K. Rice is Vice President, Operations for Northern Plains, having been elected in March 2002. Mr. Rice was previously Vice President of North Operations for a division of Enron from 2001 to 2002, and from 1999 to 2001, held various management positions within the operations division supporting various pipeline assets owned by Enron. Mr. Rice joined Northern Natural Gas Company, formerly affiliated with Northern Plains, in 1980. Gaye Lynn Schaffart is Vice President, Business Development and Strategic Planning, having been elected in March 2004. Ms. Schaffart was previously Director, Business Development and Planning from 1993 to 2004. Ms. Schaffart joined Northern Plains in 1982. Pierce H. Norton is President of Bear Paw Energy, LLC, a subsidiary of Northern Border, having been appointed in February 2003. Mr. Norton, from 2001 to 2003 served as Vice President, Business Development for Bear Paw. Prior to the Company's purchase of Bear Paw, Mr. Norton was Vice President -- Business Development for Bear Paw Energy, LLC and its predecessor from 1999 to 2001 where he was responsible for managing contracts and asset acquisitions. Fred G. Rimington is President of Black Mesa Pipeline, Inc., having been appointed in January 2000. Mr. Rimington was Director, Business Development from 1994 to 1999 for Northern Plains. Mr. Rimington joined Northern Plains in 1980. 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 2003 our reporting persons complied with all applicable filing requirements in a timely manner. 64 CODE OF ETHICS 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 our website, www.northernborderpartners.com, and we intend to post on our website any amendments to, or waivers from, our Accounting and Financial Reporting Code of Ethics within five business days following such amendment or waiver. 65 ITEM 11. EXECUTIVE COMPENSATION The following table summarizes certain information regarding compensation paid or accrued during each of Northern Plains' last three fiscal years to the executive officers of the Partnership (the "Named Officers") for services performed in their capacities as executive officers of Northern Plains: SUMMARY COMPENSATION TABLE

All Other Annual Compensation Long-Term Compensation Compensation Securities Restricted Underlying Other Annual Stock Awards Options / SARs LTIP Payouts Name & Position Year Salary Bonus (1) Compensation ($)(3)(4) (#) ($) (5) ($) (6) --------------- ---- -------- -------- ------------ -------- ----- -------- -------- (2) William R. Cordes 2003 $324,583 $200,000 $ -- $ 99,972 -- $ -- $ 3,000 Chief Executive Officer 2002 $319,333 $240,000 $ -- $100,051 -- $ -- $ 1,031 2001 $312,000 $250,000 $ 8,550 $227,150 6,475 $300,000 $ 255 Jerry L. Peters 2003 $163,324 $107,500 $ -- $ -- -- $ -- $ 76,386 Chief Financial and 2002 $159,285 $110,000 $ -- $ -- -- $ -- $ 23,950 Accounting Officer 2001 $154,292 $125,000 $ 3,399 $ 75,063 7,085 $ -- $ 198

(1) For 2001, employees 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 and Mr. Peters elected to receive Northern Border phantom units in lieu of a portion of the cash bonus payment under the Northern Border Phantom Unit Plan. Mr. Cordes received 1,914 units in 2001. Mr. Peters received 842 units in 2001. In each case, units will be released to both five years following the grant date. (2) Other Annual Compensation includes cash perquisite allowances, service awards and vacation payouts. Also, Enron maintained three deferral plans for key employees under which payment of base salary, annual bonus and long-term incentive awards could be deferred to a later specified date. Under the 1985 Deferral Plan, interest is credited on amounts deferred based on 150% of Moody's seasoned corporate bond yield index with a minimum rate of 12%, which for 2001 was the minimum rate of 12%. No interest has been reported as Other Annual Compensation under the 1985 Deferral Plan for participating Named Officers because the crediting rates during 2001 did not exceed 120% of the long-term Applicable Federal Rate of 14.38% in effect at the time the 1985 Deferral Plan was implemented. Beginning January 1, 1996, the 1994 Deferral Plan credits interest based on fund elections chosen by participants. Since earnings on deferred compensation invested in third-party investment vehicles, comparable to mutual funds, need not be reported, no interest has been reported as Other Annual Compensation under the 1994 Deferral Plan during 2001. (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 $120, and Mr. Peters, 1,701 shares valued at $48. 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 valued as of July 30, 2001 at $115.6978 per unit and granted on October 1, 2001. On June 1, 2002 and 2003, additional grants of 697 and 669 Northern Border Phantom Units valued at $143.5456 and $149.4346 per unit, respectively, were made in accordance with his employment agreement. The phantom units vest on the fifth anniversary of the date of the grant. (5) Reflects cash payments under the Enron Corp. Performance Unit Plan in 2001 for the 1997-2000 period. Payments made under the Performance Unit Plan are based on Enron's total shareholder return relative to its peers. Enron's performance over the 1997-2000 performance period rendered a value of $2.00 based on a ranking of first as compared to 11 industry peers. (6) The amounts shown includes matching contributions to employees' Enron Corp. Savings Plan. 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 66 agreement. The remaining amount of $71,853 was paid in March 2003 upon completion of the term of the agreement. STOCK OPTION GRANTS DURING 2003 Due to the bankruptcy filing by Enron Corp on December 2, 2001, there were no grants of stock options pursuant to Enron's stock plans to the Named Officers reflected in the Summary Compensation Table. No stock appreciation rights were granted during 2003. AGGREGATED STOCK OPTION/SAR EXERCISES DURING 2003 AND STOCK OPTION/SAR VALUES AS OF DECEMBER 31, 2003 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 the end of the fiscal year:

Number of Securities Underlying Unexercised Value of Unexercised Shares Options/SARs at In-the-Money Options/SARs Acquired on Value December 31, 2003 December 31, 2003 (1) Name Exercise (#) Realized Exercisable Unexercisable Exercisable Unexercisable ---- ------------ -------- ----------- ------------- ----------- ------------- William R. Cordes -- $-- 242,755 1,845 $-- $-- Jerry L. Peters -- $-- 66,650 935 $-- $--

(1) The dollar value in this column for Enron Corp. stock options was calculated by determining the difference between the fair market value underlying the options as of December 31, 2003 ( $0.028) and the grant price. RETIREMENT AND SUPPLEMENTAL BENEFIT PLANS 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. Effective December 2, 2001, Enron no longer maintains a Supplemental Retirement Plan. The following table sets forth the estimated annual benefits 67 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% benefit accruals after January 1, 2003, with to the Named Officers under the provisions of the foregoing retirement plans.

ESTIMATED CURRENT CREDITED CURRENT ESTIMATED CREDITED YEARS OF COMPENSATION ANNUAL BENEFIT YEARS OF SERVICE COVERED PAYABLE UPON SERVICE AT AGE 65 BY PLANS RETIREMENT ------- --------- -------- ---------- Mr. Cordes 33.4 43.1 $0 $74,211 Mr. Peters 18.9 37.8 $0 $23,212

---------------- 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. 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. 68 ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT The following table sets forth the beneficial ownership of the voting securities of the Partnership as of March 3, 2004 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.

Amount and Nature of Beneficial Ownership Common Units ------------ Number Percent of Units/ of Class -------- -------- William R. Cordes 1/ 1,000 * 13710 FNB Parkway Omaha, NE 68154-5200 Jerry L. Peters 1/ 1,000 * 13710 FNB Parkway Omaha, NE 68154-5200 Stanley C. Horton 1/ 20,000 * 1331 Lamar Street Houston, TX 77010 Gary N. Petersen 5,854 * 3520 Wedgewood Ln. N Plymouth, MN 55441-2262 Enron Corp.2/ 3,210,000 6.9 1331 Lamar Street Houston, TX 77010

--------------------- * Less than 1%. 1/ All units involve sole voting and investment power. 2/Indirect ownership through its subsidiaries. Northern Plains is the beneficial owner of 500,000 Common Units. Sundance Assets, L.P. is the beneficial owner of 2,710,000. In a Schedule 13D/A filing in January 2002, it was disclosed that dispositive power of Sundance Assets, L.P. is shared by Enron and Citibank, N.A. For information on equity compensation plans of the Partnership, see Item 5. "Market for Registrant's Common Units and Related Securities Holder Matters." 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. We have a number of relationships with Enron and its subsidiaries. Through 69 Enron's ownership of two of our general partners, Enron 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: - Northern Plains, a subsidiary of Enron, provides certain administrative, operating and management services to the Partnership through Operating Agreements with Northern Border Pipeline, Midwestern Gas Transmission and Viking Gas Transmission. For the year ended December 31, 2003, the aggregate amount charged by Northern Plains for its services was approximately $38.5 million. - NBP Services, a subsidiary of Enron, 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, 2003, the aggregate amount charged by NBP Services for its services was approximately $16.2 million. - ENA held a contract for firm transportation on Midwestern Gas Transmission until it was rejected and terminated on November 12, 2003. - Northern Plains, has been selected on a fixed fee and cost reimbursement basis to provide, commencing on July 1, 2004, certain administrative, operating and management services through an Operating Agreement with Guardian Pipeline, L.L.C., 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, L.L.C. 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. - In conjunction with the selection of Northern Plains, as operator of Guardian Pipeline, L.L.C., 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. - 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." 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 Enron 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 70 will generally have a fiduciary duty to resolve such conflicts in a manner that is in our best interest. Enron (the parent of two of our general partners) and its affiliates and TC PipeLines (a 30% owner of Northern Border Pipeline whose general partner is an affiliate of one of our general partners) and its affiliates also actively engage 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 Enron and its affiliates, 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 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 71 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. - We entered into an amendment to 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 for the fiscal years ended December 31, 2003 and December 31, 2002:

Year Ended December 31, --------------------------------- 2003 2002 ----------- ----------- Audit fees (1) $ 323,050 $ 644,850 Audit-related fees(2) $ 107,995 $ 800 Tax Fees(3) $ 855 $ 10,425 Other $ 0 $ 0 Total $ 431,900 $ 656,075

(1) Includes fees for the audit of annual financial statements, reviews of the related quarterly financial statements and reviews and related consents for documents filed with the Securities and Exchange Commission. The fees for 2002 also include professional services for the re-audit of the years 1999, 2000 and 2001. (2) Includes fees related to professional services consultation for internal controls review and agreed upon procedures review. (3) Includes fees related to professional services for tax review and consultation. Our Audit Committee is responsible for reviewing and approving, in advance, any audit and permissible non-audit engagement or relationship between us and our independent auditors. KPMG's engagement to conduct our audit was approved by the Audit Committee on November 7, 2002. Additionally, all permissible non-audit engagements with KPMG have been reviewed and approved by the Audit Committee pursuant to procedures established by the Audit Committee. 72 PART IV ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K (a)(1) and (2) Financial Statements and Financial Statement Schedules See "Index to Financial Statements" set forth on page F-1. (a)(3) EXHIBITS *3.1 Form of Amended and Restated Agreement of Limited Partnership of Northern Border Partners, L.P. (Exhibit 3.1 No. 2 to the Partnership's Form S-1 Registration Statement, Registration No. 33-66158 ("Form S-1")). *3.2 Form of Amended and Restated Agreement of Limited Partnership For Northern Border Intermediate Limited Partnership (Exhibit 10.1 to Form S-1). *4.1 Indenture, dated as of June 2, 2000, between the registrants and Bank One Trust Company, N.A. (Exhibit 4.1 to the Partnership's Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2000 ("June 2000 10-Q")). *4.2 First Supplemental Indenture, dated as of September 14, 2000, between the registrants and Bank One Trust Company, N.A. (Exhibit 4.2 to 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 (Exhibit 4.3 to Northern Border Partners, L.P. Form 10-K for the year ended December 31, 2001). *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. (Exhibit No. 4.1 to Northern Border Pipeline Company's Form S-4 Registration Statement, 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. (Exhibit 4.2 to Northern Border Pipeline Company's Registration Statement on Form S-4, Registration No. 333-73282 ("2001 NB Form S-4")). *4.6 Indenture, dated as of April 29, 2002, between Northern Border Pipeline Company and Bank One Trust Company, N.A. (Exhibit 4.1 to Northern Border Pipeline Company's Form 10-Q for the quarter ended March 31, 2002). *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 (Exhibit 10.2 to Form S-1). *10.2 Form of Seventh Supplement Amending Northern Border Pipeline Company General Partnership Agreement (Exhibit 10.15 to Form S-1). *10.3 Eighth Supplement Amending Northern Border Pipeline Company General Partnership Agreement (Exhibit 10.15 to NB Form S-4). 73 *10.4 Ninth Supplement Amending Northern Border Pipeline Company General Partnership Agreement (Exhibit 10.37 to 2001 Form S-4). *10.5 Operating Agreement between Northern Border Pipeline Company and Northern Plains Natural Gas Company, dated February 28, 1980 (Exhibit 10.3 to Form S-1). *10.6 Administrative Services Agreement between NBP Services Corporation, Northern Border Partners, L.P. and Northern Border Intermediate Limited Partnership (Exhibit 10.4 to Form S-1). 10.7 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). *10.8 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) (Exhibit 10.1 to Northern Border Partners, L.P.'s Current Report on Form 8-K dated June 26, 2002). *10.9 Employment Agreement between Northern Plains Natural Gas Company and William R. Cordes effective June 1, 2001 (Exhibit 10.27 to Northern Border Partners, L.P.'s Quarterly Report on Form 10-Q for the quarter ended June 30, 2001). *10.10 Amendment to Employment Agreement between Northern Plains Natural Gas Company and William R. Cordes, effective September 25, 2001 (Exhibit 10.36 to 2001 Form S-4). *10.11 Employment Agreement between Northern Plains Natural Gas Company and Jerry L. Peters effective April 1, 2002 (Exhibit 10.1 to Northern Border Pipeline Company's Form 10-Q for the quarter ended March 31, 2002). *10.12 Operating Agreement between Midwestern Gas Transmission Company and Northern Plains Natural Gas Company dated as of April 1, 2001. (Exhibit 10.38 to Northern Border Partners, L.P.'s Form 10-K for the year ended December 31, 2001). *10.13 Operating Agreement between Viking Gas Transmission Company and Northern Plains Natural Gas Company dated as of January 17, 2003. Exhibit 10.18 to Northern Border Partners, L.P.'s Form 10-K for the year ended December 31, 2002) *10.14 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 (Exhibit 10.21 to Northern Border Partners, L.P.'s Form 10-K/A for the year ended December 31, 1998, SEC File No. 1-12202 ("1998 10-K")). 12.1 Statement re computation of ratios 21 The subsidiaries of Northern Border Partners, L.P. are Northern Border Intermediate Limited Partnership; Northern Border Pipeline Company; Crestone Energy Ventures, L.L.C.; Bear Paw Investments, LLC; Bear Paw Energy, LLC; Border Midwestern Company; Midwestern Gas Transmission Company; Border Viking Company; and Viking Gas Transmission Company. 74 23.01 Consent of KPMG LLP. 31.1 Certification of principal executive office pursuant to rule 13-A or 15d of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. 31.2 Certification of principal financial officer pursuant to rule 13-A or 15d of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 32.1 Certification of principal executive officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. 32.2 Certification of principal financial officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. *99.1 Northern Border Phantom Unit Plan (Exhibit 99.1 to Amendment No. 1 to Form S-8, Registration No. 333-66949 and Exhibit 99.1 to Northern Border Partners, L.P.'s Registration No. 333-72696). *Indicates exhibits incorporated by reference as indicated; all other exhibits are filed herewith. 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. (b)REPORTS The Partnership filed a Current Report on Form 8-K, dated October 1, 2003, including an announcement and a copy of a press release regarding a non-cash charge to be recorded by Northern Border Partners, L.P. of approximately $219 million to reflect asset and goodwill impairments for its natural gas and processing business. The information was furnished under Items 9 and 12 of the Form. The Partnership filed a Current Report on Form 8-K, dated October 24, 2003, including a copy of a press release announcing earnings for the third quarter of 2003. The information was furnished under Item 9 of the Form. The Partnership filed a Current Report on Form 8-K, dated December 19, 2003, discussing the changes to the cash distribution policy and issuance of equity cash calls. The Partnership filed a Current Report on Form 8-K, dated December 31, 2003, discussing developments in Enron Corp.'s pending exemption application under the Public Utility Holding Company Act of 1935. 75 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 12th day of March, 2004. 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.

Signature Title Date --------- ----- ---- /s/WILLIAM R. CORDES Chief Executive Officer and March 12, 2004 --------------------------- Chairman of the Partnership William R. Cordes Policy Committee (Principal Executive Officer) /s/STANLEY C. HORTON Member of Partnership Policy March 12, 2004 --------------------------- Committee Stanley C. Horton /s/PAUL E. MILLER Member of Partnership Policy March 12, 2004 --------------------------- Committee Paul E. Miller /s/JERRY L. PETERS Chief Financial and March 12, 2004 --------------------------- Accounting Officer Jerry L. Peters

76 NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES INDEX TO FINANCIAL STATEMENTS

PAGE NO. -------- Consolidated Financial Statements Independent Auditors' Report F-2 Consolidated Balance Sheet - December 31, 2003 and 2002 F-3 Consolidated Statement of Income - Years Ended F-4 December 31, 2003, 2002 and 2001 Consolidated Statement of Comprehensive Income - Years Ended F-5 December 31, 2003, 2002 and 2001 Consolidated Statement of Cash Flows - Years Ended F-6 December 31, 2003, 2002 and 2001 Consolidated Statement of Changes in Partners' Equity - F-7 Years Ended December 31, 2003, 2002 and 2001 Notes to Consolidated Financial Statements F-8 through F-37 Financial Statements Schedule Independent Auditors' Report on Schedule S-1 Schedule II - Valuation and Qualifying Accounts S-2

F-1 INDEPENDENT AUDITORS' REPORT Northern Border Partners, L.P.: We have audited the accompanying consolidated balance sheets of Northern Border Partners, L.P. (a Delaware limited partnership) and Subsidiaries as of December 31, 2003 and 2002, 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, 2003. 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 auditing standards generally accepted in the United States of America. 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, 2003 and 2002, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2003, in conformity with accounting principles generally accepted in the United States of America. As discussed in note 13 to the consolidated financial statements, Northern Border Partners, L.P. and Subsidiaries adopted the provisions of Statement of Financial Accounting Standards (SFAS) No. 143, Accounting for Asset Retirement Obligations in 2003. As discussed in note 4 to the consolidated financial statements, Northern Border Partners, L.P. and Subsidiaries adopted SFAS No. 142, Accounting for Goodwill and Other Intangible Assets in 2002. KPMG LLP Omaha, Nebraska January 27, 2004 F-2 NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEET (IN THOUSANDS, EXCEPT UNIT AMOUNTS)

DECEMBER 31, ----------------------- 2003 2002 ---------- ---------- ASSETS CURRENT ASSETS Cash and cash equivalents $ 35,895 $ 34,689 Accounts receivable 61,503 55,358 Related party receivables (net of allowance for doubtful accounts of $12,444 and $12,392 in 2003 and 2002, respectively) -- 70 Materials and supplies, at cost 7,826 5,252 Prepaid expenses 6,726 4,456 Other 2,245 332 ---------- ---------- Total current assets 114,195 100,157 ---------- ---------- PROPERTY, PLANT AND EQUIPMENT Interstate Natural Gas Pipelines 2,612,241 2,471,627 Gas Gathering and Processing 253,903 354,652 Coal Slurry 45,911 43,092 ---------- ---------- Total property, plant and equipment 2,912,055 2,869,371 Less: Accumulated provision for depreciation and amortization 919,951 854,091 ---------- ---------- Property, plant and equipment, net 1,992,104 2,015,280 ---------- ---------- INVESTMENTS AND OTHER ASSETS Investment in unconsolidated affiliates 268,166 244,515 Goodwill 152,782 295,848 Derivative financial instruments 19,553 36,885 Other 23,783 23,251 ---------- ---------- Total investments and other assets 464,284 600,499 ---------- ---------- Total assets $2,570,583 $2,715,936 ========== ========== LIABILITIES AND PARTNERS' EQUITY CURRENT LIABILITIES Current maturities of long-term debt $ 7,740 $ 67,765 Accounts payable 20,834 30,584 Related party payables 25,698 25,927 Accrued taxes other than income 33,708 31,108 Accrued interest 13,206 16,742 Derivative financial instruments 5,736 4,095 ---------- ---------- Total current liabilities 106,922 176,221 ---------- ---------- LONG-TERM DEBT, net of current maturities 1,408,246 1,335,978 ---------- ---------- MINORITY INTERESTS IN PARTNERS' EQUITY 240,731 242,931 ---------- ---------- RESERVES AND DEFERRED CREDITS Deferred income taxes 2,898 450 Other 11,213 16,321 ---------- ---------- Total reserves and deferred credits 14,111 16,771 ---------- ---------- COMMITMENTS AND CONTINGENCIES (NOTE 11) PARTNERS' EQUITY General partners 15,902 18,730 Common units (46,397,214 and 43,809,714 units issued and outstanding at December 31, 2003 and 2002, respectively) 779,195 917,791 Accumulated other comprehensive income 5,476 7,514 ---------- ---------- Total partners' equity 800,573 944,035 ---------- ---------- Total liabilities and partners' equity $2,570,583 $2,715,936 ========== ==========

The accompanying notes are an integral part of these consolidated financial statements. F-3 NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES CONSOLIDATED STATEMENT OF INCOME (IN THOUSANDS, EXCEPT PER UNIT AMOUNTS)

YEAR ENDED DECEMBER 31, ----------------------------------- 2003 2002 2001 --------- --------- --------- OPERATING REVENUES Operating revenues $ 555,927 $ 487,204 $ 458,054 Provision for rate refunds -- -- (2,057) --------- --------- --------- Operating revenues, net 555,927 487,204 455,997 --------- --------- --------- OPERATING EXPENSES Product purchases 80,774 50,648 39,699 Operations and maintenance 127,574 106,331 92,891 Depreciation and amortization, including impairment charges of $219,080 in 2003 300,199 74,672 75,424 Taxes other than income 35,443 32,194 27,863 --------- --------- --------- Operating expenses 543,990 263,845 235,877 --------- --------- --------- OPERATING INCOME 11,937 223,359 220,120 --------- --------- --------- INTEREST EXPENSE Interest expense 79,159 83,227 91,653 Interest expense capitalized (179) (329) (1,745) --------- --------- --------- Interest expense, net 78,980 82,898 89,908 --------- --------- --------- OTHER INCOME (EXPENSE) Allowance for equity funds used during construction 331 248 947 Equity earnings of unconsolidated affiliates 18,815 14,570 1,697 Other income 7,739 2,740 2,997 Other expense (2,024) (991) (4,922) --------- --------- --------- Other income, net 24,861 16,567 719 --------- --------- --------- MINORITY INTERESTS IN NET INCOME 44,460 42,816 42,138 --------- --------- --------- INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES (86,642) 114,212 88,793 INCOME TAXES 5,365 1,643 499 --------- --------- --------- INCOME (LOSS) FROM CONTINUING OPERATIONS (92,007) 112,569 88,294 DISCONTINUED OPERATIONS, NET OF TAX 4,196 1,107 (508) CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE, NET OF TAX (643) -- -- --------- --------- --------- NET INCOME (LOSS) TO PARTNERS $ (88,454) $ 113,676 $ 87,786 ========= ========= ========= CALCULATION OF LIMITED PARTNERS' INTEREST IN NET INCOME (LOSS): Net income (loss) to partners $ (88,454) $ 113,676 $ 87,786 Less: general partners' interest in net income (loss) 5,969 9,602 6,008 --------- --------- --------- Limited partners' interest in net income (loss) $ (94,423) $ 104,074 $ 81,778 ========= ========= ========= LIMITED PARTNERS' PER UNIT NET INCOME (LOSS): Income (loss) from continuing operations $ (2.16) $ 2.41 $ 2.13 Discontinued operations, net of tax 0.09 0.03 (0.01) Cumulative effect of change in accounting principle, net of tax (0.01) -- -- --------- --------- --------- Net income (loss) $ (2.08) $ 2.44 $ 2.12 ========= ========= ========= NUMBER OF UNITS USED IN COMPUTATION 45,370 42,709 38,538 ========= ========= =========

The accompanying notes are an integral part of these consolidated financial statements. F-4 NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME (IN THOUSANDS)

YEAR ENDED DECEMBER 31, ----------------------------------- 2003 2002 2001 --------- --------- --------- Net income (loss) to partners $ (88,454) $ 113,676 $ 87,786 Other comprehensive income: Transition adjustment from adoption of SFAS No. 133 -- -- 22,183 Change associated with current period hedging transactions (4,383) (13,490) (1,100) Change associated with current period foreign currency translation 2,345 475 (554) --------- --------- --------- Total comprehensive income (loss) $ (90,492) $ 100,661 $ 108,315 ========= ========= =========

The accompanying notes are an integral part of these consolidated financial statements. F-5 NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES CONSOLIDATED STATEMENT OF CASH FLOWS (IN THOUSANDS)

YEAR ENDED DECEMBER 31, ----------------------------------- 2003 2002 2001 --------- --------- --------- CASH FLOWS FROM OPERATING ACTIVITIES: Net income (loss) to partners $ (88,454) $ 113,676 $ 87,786 --------- --------- --------- 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 301,977 76,239 76,675 Minority interests in net income 44,460 42,816 42,138 Non-cash (gains) losses from risk management activities (209) (4,509) 5,304 Provision for regulatory refunds 261 10,000 2,036 Regulatory refunds paid (10,261) -- (6,762) Cumulative effect of change in accounting principle 643 -- -- Gain on sale of gathering and processing assets (4,872) -- -- Equity earnings in unconsolidated affiliates (18,928) (14,570) (1,697) Distributions received from unconsolidated affiliates 16,262 10,820 7,083 Allowance for equity funds used during construction (331) (248) (947) Reserves and deferred credits 4,472 (24) 119 Changes in components of working capital (18,592) 9,670 20,677 Other (1,768) 136 1,536 --------- --------- --------- Total adjustments 313,114 130,330 146,162 --------- --------- --------- Net cash provided by operating activities 224,660 244,006 233,948 --------- --------- --------- CASH FLOWS FROM INVESTING ACTIVITIES: Capital expenditures for property, plant and equipment, net (30,282) (50,738) (126,414) Acquisition of businesses (123,194) (1,561) (345,074) Sale of gathering and processing assets 40,250 -- -- Investments in unconsolidated affiliates and other (3,514) (2,972) (11,197) --------- --------- --------- Net cash used in investing activities (116,740) (55,271) (482,685) --------- --------- --------- CASH FLOWS FROM FINANCING ACTIVITIES: Cash distributions General and limited partners (155,173) (146,960) (120,884) Minority Interests (46,194) (49,238) (42,910) Issuance of partnership interests, net 102,203 75,376 172,222 Issuance of long-term debt, net 342,000 499,894 863,103 Retirement of long-term debt (361,129) (567,540) (604,929) Decrease in bank overdrafts -- -- (22,437) Proceeds (payments) upon termination of derivatives 12,250 20,551 (8,417) Long-term debt financing costs (671) (2,884) (5,619) --------- --------- --------- Net cash provided by (used in) financing activities (106,714) (170,801) 230,129 --------- --------- --------- NET CHANGE IN CASH AND CASH EQUIVALENTS 1,206 17,934 (18,608) Cash and cash equivalents-beginning of year 34,689 16,755 35,363 --------- --------- --------- Cash and cash equivalents-end of year $ 35,895 $ 34,689 $ 16,755 ========= ========= ========= Changes in components of working capital: Accounts receivable $ (3,135) $ 4,303 $ 6,493 Materials and supplies, prepaid expenses and other (3,833) (2,573) (4,937) Accounts payable (8,525) 9,370 14,321 Accrued taxes other than income 437 2,378 (115) Accrued interest (3,536) (3,808) 4,915 --------- --------- --------- Total $ (18,592) $ 9,670 $ 20,677 ========= ========= =========

The accompanying notes are an integral part of these consolidated financial statements. F-6 NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES CONSOLIDATED STATEMENT OF CHANGES IN PARTNERS' EQUITY (IN THOUSANDS)

ACCUMULATED OTHER TOTAL GENERAL COMMON COMPREHENSIVE PARTNERS' PARTNERS UNITS INCOME EQUITY --------- --------- ------------- --------- Partners' Equity at December 31, 2000 $ 11,445 $ 560,829 $ -- $ 572,274 Net income to partners 6,008 81,778 -- 87,786 Transition adjustment from adoption of SFAS No. 133 -- -- 22,183 22,183 Change associated with current period hedging transactions -- -- (1,100) (1,100) Change associated with current period foreign currency translation -- -- (554) (554) Issuance of partnership interests, net (10,119,451 common units, including 5,711,901 common units issued as consideration for an acquisition) 7,105 348,148 -- 355,253 Distributions paid (6,669) (114,215) -- (120,884) --------- --------- --------- --------- 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 ========= ========= ========= =========

The accompanying notes are an integral part of these consolidated financial statements. F-7 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 (Northern Plains), a wholly-owned subsidiary of Enron Corp. (Enron), Pan Border Gas Company (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 also owns common units representing a 1.1% limited partner interest and Enron, through an indirect subsidiary, owns common units representing a 5.8% limited partner interest in the Partnership at December 31, 2003 (see Note 10). 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. The Partnership has entered into an administrative services agreement with NBP Services Corporation (NBP Services), a wholly owned subsidiary of Enron. 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. NBP Services also utilizes Enron affiliates to provide these services. For the years ended December 31, 2003, 2002 and 2001, charges from NBP Services and its affiliates totaled approximately $19.1 million, $16.2 million and $15.3 million, respectively. See Note 17 for a discussion of the Partnership's 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%, F-8 NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 1. ORGANIZATION AND MANAGEMENT (continued) respectively, of the voting interest on the Northern Border Pipeline Management Committee. The representative designated by TC PipeLines votes the remaining 30% interest. 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. The Partnership acquired Midwestern Gas Transmission effective May 1, 2001 (see Note 3). The Midwestern Gas Transmission system is 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. 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 also utilizes Enron affiliates for management services related to Northern Border Pipeline, Midwestern Gas Transmission and Viking Gas Transmission. For the years ended December 31, 2003, 2002 and 2001, Northern Plains' and its affiliates' charges to Northern Border Pipeline, Midwestern Gas Transmission and Viking Gas Transmission totaled approximately $38.5 million, $29.1 million and $31.5 million, respectively. On March 30, 2001, the Partnership acquired Bear Paw Energy (see Note 3). 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 in Wyoming. In the Williston Basin, Bear Paw Energy has over 3,000 miles of gathering pipelines and five processing plants with 95 million cubic feet per day of capacity. Bear Paw Energy has approximately 1,100 miles of high and low pressure gathering pipelines and approximately 430,000 acres of dedicated reserves in the Powder River Basin. On April 4, 2001, Border Midstream completed the acquisition of the Mazeppa and Gladys gas processing plants, gas gathering systems and an undivided minority interest in the Gregg Lake/Obed Pipeline (see Note 3). The Gregg Lake/Obed Pipeline system, which is located near Edmonton, Alberta, is comprised of 85 miles of gathering lines. In June 2003, the Partnership sold its Gladys and Mazeppa processing plants and related gas gathering facilities (see Note 3). F-9 NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 1. ORGANIZATION AND MANAGEMENT (continued) 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); a 36% interest in the Gregg Lake/Obed Pipeline; 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 Power 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 accounting principles generally accepted (GAAP) 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. (B) Government Regulation Northern Border Pipeline, Midwestern Gas Transmission and Viking Gas Transmission 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 F-10 NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued) (B) Government Regulation (continued) the regulatory assets are probable by considering 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, 2003 and 2002, Northern Border Pipeline and Viking Gas Transmission have reflected regulatory assets of approximately $8.9 million and $10.5 million, respectively, in other assets 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 $350 million and $343 million at December 31, 2003 and 2002, 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 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. An allowance for doubtful accounts is recorded in situations where collectibility is not reasonably assured. 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. F-11 NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued) (D) Revenue Recognition (continued) 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 were 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. Under the terms of the agreement, Black Mesa receives a monthly demand payment, a per ton commodity payment and a reimbursement for certain other expenses. (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) 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. 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. F-12 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 (continued) 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% (see Note 4). 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 2003, the Partnership recorded currency transactions gains of $6.0 million. Currency transaction gains were insignificant in 2002 and 2001. (H) Goodwill Beginning January 1, 2002, the excess of cost over fair value of the net assets acquired in business acquisitions or goodwill is no longer being amortized and instead is tested for impairment (see Note 4). Prior to January 1, 2002, the excess was being amortized using a straight-line method over 30 years. During 2001, the Partnership recorded amortization expense of $6.3 million related to its investments in unconsolidated affiliates, which is reflected as a component of equity earnings of unconsolidated affiliates in the consolidated statement of income. See Note 9 for details on the Partnership's investments in unconsolidated affiliates and related equity earnings. For the Partnership's consolidated affiliates, during 2001, the Partnership recorded amortization expense of $7.0 million. This amortization expense is reflected as a component of depreciation and amortization in the consolidated statement of income. F-13 NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued) (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. The Partnership adopted SFAS No. 133 beginning January 1, 2001. See Note 8 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 completed three acquisitions during 2001. On March 30, 2001, the Partnership acquired Bear Paw Energy for $381.7 million. The purchase price consisted of $198.7 million in cash and the issuance of 5.7 million common units valued at $183.0 million. Border Midstream acquired the Mazeppa and Gladys gas processing plants, gas gathering systems and an undivided minority interest in the Gregg Lake/Obed Pipeline (Gregg Lake/Obed) for $70 million (Canadian) or $45 million (U.S.) on April 4, 2001. Effective May 1, 2001, the Partnership acquired Midwestern Gas Transmission for $102 million. The Partnership has accounted for these acquisitions using the purchase method of accounting and accordingly, operations of the acquired entities have been included since the dates of acquisition. The purchase price has F-14 NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 3. BUSINESS ACQUISITIONS AND DISPOSITIONS (continued) been allocated based upon the estimated fair value of the assets and liabilities acquired as of the acquisition date. The excess of the purchase price over the fair value of the Bear Paw Energy and Midwestern Gas Transmission net assets acquired is reflected as goodwill on the consolidated balance sheet. 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 acquisitions on the Partnership's consolidated financial position (amounts in thousands):

2003 2002 2001 -------- -------- --------- Current assets $ 8,804 $ -- $ 17,257 Property, plant and equipment 127,619 -- 261,225 Investments in unconsolidated affiliates 27,600 -- -- Goodwill and other assets 5,035 361 275,443 Current liabilities (5,559) 1,200 (14,908) Long-term debt, including current maturities (40,025) -- (13,113) Other liabilities (280) -- (498) Accumulated other comprehensive income -- -- 2,699 Common units issued by the Partnership -- -- (183,031) -------- -------- --------- $123,194 $ 1,561 $ 345,074 ======== ======== =========

If the Viking Gas Transmission acquisition made in 2003 had occurred at the beginning of 2002, the Partnership's 2002 consolidated operating revenues, net income to partners and per unit net income would have been $517 million, $119 million and $2.55 per unit, respectively. If the acquisitions made in 2001 had occurred at the beginning of 2001, the Partnership's 2001 consolidated operating revenues, net income to partners and per unit net income would have been $506 million, $88 million and $2.12 per unit, respectively. These unaudited pro forma results are for illustrative purposes only and are not necessarily indicative of the operating results that would have occurred had the business acquisitions been consummated at that date, nor are they necessarily indicative of future operating results. 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 2002 and 2001 have been reclassified for amounts related to the discontinued operations. Operating revenues for the years ended December 31, 2003, 2002 and 2001, were $4.9 million, $8.1 million and $5.5 million, respectively. Discontinued operations on the accompanying consolidated statement of income consists of the following:

December 31, ------------------------ (in thousands) 2003 2002 2001 ------------------------------------------ ------ ------ ------ Operating income (loss) $ (796) $1,650 $ (721) Gain on sale of assets 4,056 -- -- Income tax (expense) benefit 936 (543) 213 ------ ------ ------ Income (loss) from discontinued operations $4,196 $1,107 $ (508) ====== ====== ======

F-15 NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 4. GOODWILL AND ASSET IMPAIRMENT In the third quarter of 2001, the Financial Accounting Standards Board (FASB) issued SFAS No. 142, "Goodwill and Other Intangible Assets." SFAS No. 142 modifies the accounting and reporting of goodwill and intangible assets. It requires entities to discontinue the amortization of goodwill, reallocate goodwill among its reporting segments and perform impairment tests by applying a fair-value-based analysis on the goodwill in each reporting segment. The Partnership adopted SFAS No. 142 effective January 1, 2002. At December 31, 2003 and 2002, the Partnership's balance sheet included goodwill of approximately $334 million and $476 million, respectively. Of the total goodwill, approximately $182 million and $180 million was recorded in the Partnership's investment in unconsolidated affiliates at December 31, 2003 and 2002, respectively. 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 entity must analyze the carrying value of the tangible assets in that segment under SFAS No. 144. During 2002, the Partnership completed its initial and annual evaluations of approximately $296 million recorded goodwill. The Partnership determined that it did not have an impairment loss for 2002. For 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 under SFAS No. 142 from the fourth quarter to the third quarter for this segment. For the Partnership's remaining business 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 in the Powder River Basin. 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 on the tangible assets in the Powder River Basin. F-16 NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 4. GOODWILL AND ASSET IMPAIRMENT (continued) Changes in the carrying amount of goodwill for the years ended December 31, 2003 and 2002, are summarized as follows:

Interstate Gas Gathering Natural Gas and Coal (In thousands) Pipelines Processing Slurry Total -------------- ----------- ------------- ------ -------- Balance at December 31, 2001 $68,408 $ 398,651 $8,378 $ 475,437 Goodwill acquired 464 (18) -- 446 ------- ---------- ------ --------- 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 ======= ========== ====== =========

The following information discloses the effect of goodwill amortization on the Partnership's net income (loss) to partners and per unit net income (loss).

December 31, (Amounts in thousands, ---------------------------------------- except per unit amounts) 2003 2002 2001 -------------------------------------- ----------- ----------- ----------- Reported net income (loss) to partners $ (88,454) $ 113,676 $ 87,786 Add back: goodwill amortization -- -- 13,286 ----------- ----------- ----------- Adjusted net income (loss) to partners $ (88,454) $ 113,676 $ 101,072 =========== =========== =========== Reported per unit net income (loss) $ (2.08) $ 2.44 $ 2.12 Add back: goodwill amortization -- -- .34 ----------- ----------- ----------- Adjusted per unit net income (loss) $ (2.08) $ 2.44 $ 2.46 =========== =========== ===========

5. RATES AND REGULATORY ISSUES Northern Border Pipeline filed a rate proceeding with the FERC in May 1999 for, among other things, a redetermination of its allowed equity rate of return. In September 2000, Northern Border Pipeline filed a stipulation and agreement with the FERC that documented the proposed settlement of its 1999 rate case. The settlement was approved by the FERC in December 2000. Under the settlement, both Northern Border Pipeline and its existing shippers will not be able to seek rate changes until November 1, 2005, at which time Northern Border Pipeline must file a new rate case. After the FERC approved the rate case settlement and prior to the end of 2000, Northern Border Pipeline made estimated refund payments to its shippers totaling approximately $22.7 million, primarily related to the period from December 1999 to November 2000. During the first quarter of 2001, Northern Border Pipeline paid the remaining refund obligation to its shippers totaling approximately $6.8 million, which related to periods through January 2001. On March 16, 2000, the FERC issued an order granting Northern Border Pipeline's application for a certificate to construct and operate an expansion and extension of its pipeline system into Indiana (Project 2000). The facilities for Project 2000 were placed into service on October 1, 2001. F-17 NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 5. RATES AND REGULATORY ISSUES (continued) 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, by adding detailed language to the broad categories that comprise company use gas. Northern Border Pipeline had included in its collection 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. 6. 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 transportation service agreements extend for various terms with termination dates that range from March 2004 to December 2013. The termination dates for Midwestern Gas Transmission's firm service agreements range from March 2004 to October 2019. The termination dates for Viking Gas Transmission's firm service agreements range from May 2004 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%, 95% and 97% of the segment's revenues in 2003, 2002 and 2001, respectively. For the year ended December 31, 2003, Northern Border Pipeline's largest shippers were BP Canada Energy Marketing Corp. (BP Canada), Pan-Alberta Gas (U.S.) Inc. (Pan-Alberta) and EnCana Marketing U.S.A. Inc. (EnCana). At December 31, 2003, BP Canada had approximately 21% of the contracted firm capacity and EnCana had approximately 19% of the contracted firm capacity. Pan-Alberta's firm service agreements, which had been managed by Mirant Americas Energy Marketing, LP, terminated October 31, 2003. The BP Canada firm service agreements extend for various terms with termination dates from October 2004 to February 2012. The EnCana firm service agreements extend for various terms with termination dates from March 2004 to June 2009. Operating revenues from BP Canada, EnCana and Pan-Alberta for the year ended December 31, 2003, were $54.7 million, $32.9 million and $45.5 million, respectively. For the years ended December 31, 2002 and 2001, Northern Border Pipeline's largest shippers were Pan-Alberta and Mirant with combined operating revenues of $105.5 million and $80.7 million, respectively. F-18 NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 6. TRANSPORTATION, GATHERING AND PROCESSING AGREEMENTS (continued) At December 31, 2003 and 2002, there is no contracted firm capacity held by shippers affiliated with Northern Border Pipeline. Previously, some of Northern Border Pipeline's shippers have been affiliated with its general partners. Operating revenues from affiliates were $1.4 million and $52.1 million for the years ended December 31, 2002 and 2001, respectively. 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, 2003, Bear Paw Energy's largest customers, Lodgepole Energy Marketing (Lodgepole), Tenaska Marketing Ventures (Tenaska) and BP Canada Energy Marketing Corp. 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. Lodgepole and Tenaska accounted for $34.8 million (40%) and $8.7 million (10%), respectively, of Bear Paw Energy's operating revenue for the period from March 31, 2001 to December 2001. Bear Paw Energy's operating revenue for 2001 also included $1.7 million from Enron North America (ENA) related to swap arrangements to hedge risks of changes in commodity prices (see Note 8) and $0.5 million from TransCanada Energy. In 2001, Crestone Energy Ventures and Crestone Gathering Services (collectively Crestone) provided gas gathering and administrative services to ENA under a master services agreement. Crestone's revenues from ENA totaled $20.6 million for the year ended December 31, 2001 (see Note 17). Crestone's revenues from other affiliates totaled $0.1 million, $0.2 million and $0.3 million in 2003, 2002 and 2001, respectively. Black Mesa's operating revenue is derived from a transportation agreement with Peabody Western Coal, the coal supplier for the Mohave Power 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 $21.4 million, $21.5 million and $22.0 million for the years ended December 31, 2003, 2002, and 2001, respectively. F-19 NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 7. CREDIT FACILITIES, LONG-TERM DEBT AND CAPITAL LEASES Detailed information on long-term debt is as follows:

December 31, ----------------------- (In thousands) 2003 2002 ---------------------------------------------- ---------- ---------- Northern Border Pipeline 1992 Pipeline Senior Notes - average 8.57% at December 31, 2002, paid in 2003 $ -- $ 65,000 2002 Pipeline Credit Agreement - average 1.95% and 2.05% at December 31, 2003 and 2002, respectively, due 2005 131,000 89,000 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 225,000 225,000 Viking Gas Transmission Senior Notes (Series A) - 6.65%, due 2008 10,311 -- Senior Notes (Series B) - 7.10%, due 2011 2,850 -- Senior Notes (Series C) - 7.31%, due 2012 8,167 -- Senior Notes (Series D) - 8.04%, due 2014 14,333 -- Northern Border Partners, L.P. 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 2001 Partnership Credit Agreement - average 2.27% at December 31, 2002, paid in 2003 -- 35,000 2003 Partnership Credit Agreement - average 2.67% at December 31, 2003, due 2007 46,000 -- Bear Paw Energy Capital Leases 6,090 8,854 Fair value adjustment for interest rate swaps (Note 8) 19,553 36,885 Unamortized debt premium 27,682 19,004 ---------- ---------- Total 1,415,986 1,403,743 Less: Current maturities of long-term debt 7,740 67,765 ---------- ---------- Long-term debt $1,408,246 $1,335,978 ========== ==========

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. The 2003 Partnership Credit Agreement replaced the 2001 Partnership Credit Agreement. 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) and in September 2001, Northern Border Pipeline completed a private offering of $250 million of 7.50% Senior Notes due 2021 (2001 Pipeline Senior Notes). F-20 NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 7. CREDIT FACILITIES, LONG-TERM DEBT AND CAPITAL LEASES (continued) The 2002 Pipeline Senior Notes and 2001 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. In March 2001, the Partnership completed a private offering of $225 million of 7.10% Senior Notes due 2011 (2001 Partnership Senior Notes). The 2001 Partnership Senior Notes were subsequently exchanged in registered offerings for notes with substantially identical terms. The proceeds from the Partnership's senior notes were used to fund its acquisitions in 2001. In June 2001, the Partnership repaid Black Mesa's 10.7% Secured Senior Notes due May 2004. The total repayment of approximately $13.6 million consisted of remaining principal and interest of $12.4 million and an early payment premium of $1.2 million. The early payment premium is reflected in other expense on the consolidated statement of income. Interest paid, net of amounts capitalized, during the years ended December 31, 2003, 2002 and 2001 was $86.7 million, $88.2 million and $86.5 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: $5 million, $136 million, $5 million, $276 million and $4 million for 2004, 2005, 2006, 2007 and 2008, 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, 2003, Northern Border Pipeline was in compliance with its financial covenants. At December 31, 2003, Viking Gas Transmission has four series of senior notes outstanding. Transportation service agreements have been pledged as security for these senior notes. Viking Gas Transmission's senior notes indenture provides for certain restrictions on the payment of cash dividends on common stock. The most restrictive of these is that the payment of cash dividends on common stock is prohibited unless debt service funds in an amount equal to all scheduled payments of principal and interest for the 180-day period following the current month-end would remain on deposit following the dividend payment. At December 31, 2003, the requirement for accumulation of debt service funds prior to payment of dividends to the Partnership was $3.7 million, which is included in other assets on the consolidated balance sheet. The senior notes contain certain financial covenants and at December 31, 2003, Viking Gas Transmission was in compliance with its financial covenants. F-21 NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 7. CREDIT FACILITIES, LONG-TERM DEBT AND CAPITAL LEASES (continued) 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, 2003, 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): Years ending December 31, 2004 3,348 2005 3,145 2006 117 ------- $ 6,610 Less amount representing interest 520 ------- Present value of lease payments 6,090 Less: current portion 2,980 ------- Long-term portion $ 3,110 ======= The following estimated fair values of financial instruments represent the amount at which each instrument could be exchanged in a current transaction between willing parties. Based on quoted market prices for similar issues with similar terms and remaining maturities, the estimated fair value of the 1992 Pipeline Senior Notes, 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 $1,306 million and $1,367 million at December 31, 2003 and 2002, 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, 2002 Pipeline Credit Agreement and 2001 Partnership Credit Agreement approximates the carrying value since the interest rates are periodically adjusted to reflect current market conditions. F-22 NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 8. 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 9). As a result of the adoption of SFAS No. 133, the Partnership reclassified $22.7 million from long-term debt to accumulated other comprehensive income and $3.3 million from long-term debt to minority interests in partners' equity related to unamortized proceeds from interest rate swap agreements terminated prior to 2001. Also upon adoption of SFAS No. 133, Northern Border Pipeline designated an outstanding interest rate swap agreement with a notional amount of $40 million as a cash flow hedge. As a result, the Partnership recorded a non-cash loss of $0.5 million in accumulated other comprehensive income and $0.3 million as an adjustment to minority interests in partners' equity. The $40 million interest rate swap agreement terminated in November 2001. 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 swaps have been designated as cash flow hedges as they were entered into to hedge the fluctuations in Treasury rates and spreads between the execution date of the swaps and the issuance of the fixed rate debt. The notional amount of the interest rate swaps does not exceed the expected principal amount of fixed rate debt to be issued. Upon issuance of the fixed rate debt, the swaps were terminated and the proceeds received or amounts paid to terminate the swaps 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 swaps. For the year ended December 31, 2002, Northern Border Pipeline received $2.4 million from terminated interest rate swaps, 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. For the year ended December 31, 2001, the Partnership and Northern Border Pipeline paid $4.3 million and $4.1 million, respectively, to terminate interest rate swaps, of which $7.2 million was recorded in accumulated other comprehensive income and $1.2 million was recorded as an adjustment to minority interests in partners' equity. During the years ended December 31, 2003, 2002 and 2001, the Partnership and Northern Border Pipeline amortized approximately $2.2 million, $2.1 million and $2.1 million, respectively, related to the terminated derivatives, as a reduction to interest expense from accumulated other comprehensive income. A comparable amount is expected to be amortized in 2004. At December 31, 2003 and 2002, the Partnership had outstanding interest rate swaps with notional amounts totaling $150 million and $225 million, respectively. Under the interest rate swap agreements, the Partnership F-23 NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 8. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES (continued) 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. 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 swaps 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 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 year ended December 31, 2003 and 2002, the Partnership amortized approximately $3.4 million and $0.5 million, respectively, as a reduction to interest expense. The Partnership expects to amortize approximately $3.7 million in 2004 for these agreements. At December 31, 2003 and 2002, the average effective interest rate on the Partnership's interest rate swap agreements was 3.72% and 3.97%, 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 and 2002, the average effective interest rate on Northern Border Pipeline's interest rate swap agreements was 2.31% and 2.70%, respectively. Both the Partnership's and Northern Border Pipeline's interest rate swap agreements have been designated as fair value hedges as they were entered into to hedge the fluctuations in the market value of the senior notes issued by the Partnership in 2001 and by Northern Border Pipeline in 2002. The accompanying consolidated balance sheet at December 31, 2003 and 2002, reflects a non-cash gain of approximately $19.6 million and $36.9 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, 2003 and 2002, respectively, Bear Paw Energy recognized losses of $8.5 million and $2.8 million from the settlement of derivative contracts. During the period from late March 2001 to December 2001, Bear Paw Energy recognized gains of $4.7 million from the settlement of derivative contracts. Bear Paw Energy recognized a loss of $0.1 million for ineffective hedges in both 2003 and 2002, which is included in operating revenues. At December 31, 2003 and 2002, the consolidated balance sheet reflected non-cash losses of approximately $5.7 million and $4.1 million, respectively, in derivative financial instruments with F-24 NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 8. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES (continued) corresponding reductions of $5.5 million and $4.0 million, respectively, in accumulated other comprehensive income. For 2004, if prices remain at current levels, Bear Paw Energy expects to reclassify approximately $5.5 million from accumulated other comprehensive income as a reduction to operating revenues. However, this reduction would be offset with increased operating revenues due to the higher 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 17). 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, 2003, 2002 and 2001, the Partnership recorded approximately $0.3 million, $4.6 million and $1.4 million, respectively, in earnings and expects to record approximately $0.2 million in earnings in 2004. 9. UNCONSOLIDATED AFFILIATES The Partnership's investments in unconsolidated affiliates which are accounted for by the equity method is as follows:

Net December 31, Ownership -------------------- (In thousands) Interest 2003 2002 ----------------- --------- -------- -------- Bighorn (a) $ 94,153 $ 96,151 Fort Union 33% 70,278 68,937 Lost Creek 35% 71,177 69,297 Guardian Pipeline 33% 32,558 -- Other Various -- 10,130 -------- -------- $268,166(b) $244,515 ======== ========

(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, 2003 and 2002. 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 are required to be made to the operations of Bighorn by the owners of the common membership interests. (b) At December 31, 2003 and 2002, 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 and $180.1 million, respectively. F-25 NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 9. UNCONSOLIDATED AFFILIATES (continued) The Partnership's equity earnings (losses) of unconsolidated affiliates is as follows:

(In thousands) 2003 2002 2001(a) ----------------- ------- ------- ------- Bighorn $ 6,467 $ 3,764 $ (875) Fort Union 5,953 5,540 1,514 Lost Creek 4,403 3,678 188 Guardian Pipeline 1,992 -- -- Other -- 1,588 870 ------- ------- ------- $18,815 $14,570 $ 1,697 ======= ======= =======

(a) As discussed in Note 4, the Partnership has adopted SFAS No. 142 and beginning January 1, 2002, the Partnership is no longer recording amortization expense related to goodwill. The equity earnings (losses) of unconsolidated affiliates included goodwill amortization of $6.3 million in 2001. Summarized combined financial information of the Partnership's unconsolidated affiliates is presented below:

December 31, ---------------------- (In thousands) 2003 (a) 2002 ---------------------------------------- -------- --------- Balance sheet Current assets $ 34,136 $ 30,127 Property, plant and equipment, net 469,837 204,019 Other noncurrent assets 3,487 3,337 Current liabilities 24,552 14,549 Long-term debt 253,620 89,697 Other noncurrent liabilities 5,574 7,114 Accumulated other comprehensive income (4,958) (7,114) Owners' equity 228,672 133,237

(In thousands) 2003(a) 2002 2001 --------------------- ------- ------- ------- Income statement Operating revenues $94,318 $57,364 $41,206 Operating expenses 31,922 17,976 15,458 Net income 42,588 33,065 19,312 Distributions paid to the Partnership $16,262 $10,820 $ 7,083

(a) Includes results for Guardian Pipeline after it was acquired in January 2003. 10. PARTNERS' EQUITY At December 31, 2003, partners' equity consisted of 46,397,214 common units representing an effective 98% limited partner interest in the Partnership (including 1.1% held by Northern Plains and 5.8% held by Sundance Assets, L.P., an indirect subsidiary of Enron) and a 2% general partner interest. At December 31, 2002, partners' equity consisted of 43,809,714 common units representing an effective 98% limited partner interest in the Partnership (including 1.1% held by Northern Plains and 6.2% held by Sundance Assets, L.P., an indirect subsidiary of Enron) and a 2% general partner interest. F-26 NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 10. PARTNERS' EQUITY (continued) The dispositive power of Sundance Assets is shared by Enron and Citibank, N.A. 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. In April and May of 2001, the Partnership sold 407,550 and 4,000,000 common units, respectively. The net proceeds from the sale of common units and the general partners' contributions totaled approximately $102.2 million in 2003, $75.4 million in 2002 and $172.2 million in 2001 and were primarily used to repay indebtedness outstanding. 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, 2003, 2002 and 2001, incentive distributions to the General Partners totaled $7.7 million, $7.3 million and $4.3 million, respectively. 11. 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 $11.7 million, $11.4 million and $8.6 million for the years ended December 31, 2003, 2002 and 2001, respectively, related to these agreements. At December 31, 2003, the estimated aggregate amounts of such required future payments were $11.6 million annually for 2004 through 2008 and $14.7 million for later years. At December 31, 2003, 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, 2003, the amount of both guarantees was $4.4 million. F-27 NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 11. COMMITMENTS AND CONTINGENCIES (continued) 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): Year ending December 31, 2004 8,035 2005 4,489 2006 4,024 2007 3,154 2008 2,978 Thereafter 3,928 ------- $26,608 ======= Expenses incurred related to these lease obligations for the years ended December 31, 2003, 2002 and 2001, were $3.7 million, $2.0 million and $1.1 million, respectively. Cash Balance Plan As further discussed in Note 17, 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. The Partnership believes this accrual is adequate to cover the likely allocation of these costs to the Partnership. Capital Expenditures Total capital expenditures for 2004 are estimated to be $29 million. This includes approximately $19 million for interstate natural gas pipeline facilities and $9 million for natural gas gathering and processing facilities. Funds required to meet the capital requirements for 2004 are anticipated to be provided from credit facilities, issuance of additional limited partnership interests in the Partnership 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 relates 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, have held settlement discussions and have reached a settlement in F-28 NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 11. COMMITMENTS AND CONTINGENCIES (continued) principle on pipeline right-of-way lease and taxation issues, subject to final documentation and necessary government approvals. Final documentation has been completed and is subject to the approval of the Bureau of Indian Affairs, which the parties believe will be obtained in the very near term. This 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 present 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 will pay a lump sum amount of $5.9 million and an annual amount of approximately $1.5 million beginning April 2004. Northern Border Pipeline intends to seek regulatory recovery of the costs resulting from the settlement. 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. 12. 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):

Year Ended December 31, --------------------------- 2003 2002 2001 ------- ------- ------- Taxes currently payable: Federal $ 900 $ 453 $ 430 State 311 87 116 Foreign 188 -- -- ------- ------- ------- Total 1,399 540 546 ------- ------- ------- Taxes deferred: Federal 2,841 934 (60) State 652 169 13 Foreign 473 -- -- ------- ------- ------- Total 3,966 1,103 (47) ------- ------- ------- Total tax provision $ 5,365 $ 1,643 $ 499 ======= ======= ======= Income taxes paid $ 1,544 $ 32 $ 1,122 ======= ======= =======

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

Year Ended December 31, ---------------------------------- 2003 2002 2001 -------- -------- -------- 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 (4.3) 1.2 0.4 State taxes (1.1) 0.2 0.2 Foreign taxes (0.8) -- -- -------- -------- -------- Effective tax rate (6.2%) 1.4% 0.6% ======== ======== ========

F-29 NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 12. INCOME TAXES (continued) Deferred tax assets and liabilities result from the following (in thousands):

December 31, ----------------- 2003 2002 ------- ------- Deferred tax assets: Net operating loss $ 6,379 $ 8,824 Plant related differences 670 -- Joint venture income 675 -- Other 816 735 ------- ------- Total deferred tax assets $ 8,540 $ 9,559 ------- ------- Deferred tax liabilities: Goodwill $ 4,383 $ 3,659 Accelerated depreciation and other plant related differences 3,829 6,350 Partnership income 3,226 -- ------- ------- Total deferred tax liabilities $11,438 $10,009 ------- ------- Net deferred tax liabilities $ 2,898 $ 450 ======= =======

The Partnership had available, at December 31, 2003, approximately $6.4 million of tax benefits related to net operating loss carryforwards, which will expire between the years 2008 and 2023. 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. 13. ACCOUNTING PRONOUNCEMENTS In 2001, the 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. 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 F-30 NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 13. ACCOUNTING PRONOUNCEMENTS (continued) amount of the Partnership's asset retirement obligations for the year ended December 31, 2003, is as follows (in thousands): 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 ======= In November 2002, the FASB issued Interpretation No. (FIN) 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others." This interpretation elaborates on the disclosures to be made by a guarantor in its interim and annual financial statements about its obligations under certain guarantees that it has issued. It also clarifies that a guarantor is required to recognize, at the inception of a guarantee, a liability for the fair value of the obligation undertaken in issuing the guarantee. The initial recognition and initial measurement provisions of this interpretation are applicable on a prospective basis to guarantees issued or modified after December 31, 2002. FIN 45 did not have a material impact on the Partnership's financial position or results of operations. In April 2003, the FASB issued SFAS No. 149, "Amendment of Statement 133 on Derivative Instruments and Hedging Activities." SFAS No. 149 amends and clarifies accounting for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities under SFAS No. 133. SFAS No. 149 did not have a material impact on the Partnership's financial position or results of operations. In May 2003, the FASB issued SFAS No. 150, "Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity." This statement establishes standards for how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity. SFAS No. 150 is effective for financial instruments entered into or modified after May 31, 2003. SFAS No. 150 did not have a material impact on the Partnership's financial position or results of operations. In May 2003, the Emerging Issues Task Force of the FASB issued EITF 00-21, "Revenue Arrangements with Multiple Deliverables." EITF 00-21 requires companies to separate components of a complex contract into separate units of accounting. EITF 00-21 was effective for contracts signed after June 30, 2003, although retroactive application to existing contracts was permitted. EITF 00-21 did not have a material impact on the Partnership's financial position or results of operations. In December 2003, the FASB issued 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 will be required to apply FIN 46 for periods ending after March 15, 2004. The Partnership does not expect FIN 46 to have a material impact on its financial position or results of operations. F-31 NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 14. 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. The accounting policies of the segments are the same as those described in the summary of significant accounting policies in Note 2. 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

Natural Interstate Gas Natural Gathering Gas and Coal (In thousands) Pipelines Processing Slurry Other(e) Total ---------------------- ------------- ------------- --------- --------- --------- 2003 Net income (loss) $ 119,620 ($ 177,874) $ 3,658 ($ 33,858) ($ 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 66,245 233,185 1,848 699 301,977 Income tax 3,629 660 1,076 (936) 4,429 AFUDC (331) -- -- -- (331) ------------- ------------- --------- --------- --------- EBITDA $ 281,200 $ 56,562 $ 7,049 ($ 3,107) $ 341,704 ============= ============= ========= ========= ========= 2002 Net income (loss) $ 107,510 $ 37,155 $ 4,136 ($ 35,125) $ 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 $ 50,051 $ 6,650 ($ 2,834) $ 317,202 ============= ============= ========= ========= =========

F-32 NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 14. BUSINESS SEGMENT INFORMATION (continued) RECONCILIATION OF NET INCOME (LOSS) TO EBITDA

Natural Interstate Gas Natural Gathering Gas and Coal (In thousands) Pipelines Processing Slurry Other(e) Total ----------------------- ------------- ------------- --------- --------- --------- 2001 Net income (loss) $ 102,325 $ 19,202 $ 4,490 ($ 38,231) $ 87,786 Minority interest 42,138 -- -- -- 42,138 Interest expense, net 55,351 706 717 33,134 89,908 Debt restructuring loss -- -- -- 1,213 1,213 Depreciation and amortization 59,854 19,714 2,144 886 82,598 Income tax (411) -- 910 (213) 286 AFUDC (947) -- -- -- (947) ------------- ------------- --------- --------- --------- EBITDA $ 258,310 $ 39,622 $ 8,261 ($ 3,211) $ 302,982 ============= ============= ========= ========= =========

BUSINESS SEGMENT DATA

Natural Interstate Gas Natural Gathering Gas and Coal (In thousands) Pipelines Processing Slurry Other(e) Total ----------------------- ------------- ------------- ---------- ---------- ---------- 2003 (a) Revenues from external customers $ 375,256 $ 159,263 $ 21,408 $ -- $ 555,927 Depreciation and Amortization (b) 65,881 232,471 1,847 -- 300,199 Operating income (loss) 212,841 (199,012) 5,144 (7,036) 11,937 Interest expense, net 47,577 591 33 30,779 78,980 Equity earnings of unconsolidated affiliates 1,992 16,823 -- -- 18,815 Other income (expense), net 453 5,566 57 (30) 6,046 Income tax expense 3,629 660 1,076 -- 5,365 Capital expenditures 19,497 8,981 1,804 -- 30,282 Identifiable assets 1,938,249 329,857 21,319 12,992 2,302,417 Investments in unconsolidated affiliates 32,558 235,608 -- -- 268,166 Total assets $ 1,970,807 $ 565,465 $ 21,319 $ 12,992 $2,570,583

F-33 NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 14. BUSINESS SEGMENT INFORMATION (continued)

Natural Interstate Gas Natural Gathering Gas and Coal (In thousands) Pipelines Processing Slurry Other(e) Total ----------------------- ------------- ------------- ----------- ----------- ----------- 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 (5,557) 223,359 Interest expense, net 51,525 794 33 30,546 82,898 Equity earnings unconsolidated affiliates -- 14,570 -- -- 14,570 Other income (expense), net 1,997 101 28 (129) 1,997 Income tax expense 730 -- 913 -- 1,643 Capital expenditures 16,579 33,718 441 -- 50,738 Identifiable assets 1,848,960 574,896 20,206 27,359 2,471,421 Investments in unconsolidated affiliates -- 244,515 -- -- 244,515 Total assets $ 1,848,960 $ 819,411 $ 20,206 $ 27,359 $ 2,715,936 2001 (c)(d) Revenues from external customers $ 322,584 $ 111,372 $ 22,041 $ -- $ 455,997 Depreciation and amortization 59,854 13,426 2,144 -- 75,424 Operating income (loss) 199,822 17,400 5,953 (3,055) 220,120 Interest expense, net 55,351 706 717 33,134 89,908 Equity earnings unconsolidated affiliates -- 1,697 -- -- 1,697 Other income (expense), net (419) 811 164 (1,534) (978) Income tax expense (benefit) (411) -- 910 -- 499 Capital expenditures 57,021 69,143 250 -- 126,414 Identifiable assets 1,858,902 552,520 22,009 14,195 2,447,626 Investments in unconsolidated affiliates -- 239,729 -- -- 239,729 Total assets $ 1,858,902 $ 792,249 $ 22,009 $ 14,195 $ 2,687,355

F-34 NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 14. BUSINESS SEGMENT INFORMATION (continued) (a) Includes interstate natural gas pipeline results of Viking Gas Transmission commencing from the effective date of acquisition in January 2003 (see Note 3). (b) Natural gas gathering and processing results includes goodwill and asset impairment charges of $219,080 (see Note 4). (c) Includes interstate natural gas pipeline results of Midwestern Gas Transmission commencing from the effective date of acquisition in May 2001 (see Note 3). (d) Includes natural gas gathering and processing results of Bear Paw Energy and Border Midstream commencing from the date of acquisition in March and April of 2001, respectively (see Note 3). (e) Includes other items not allocable to segments. 15. 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 Gas Gathering. For the year ended December 31, 2001, other expense also included bad debt expense of $1.5 million related to the bankruptcy of a telecommunications company that had purchased excess capacity on Northern Border Pipeline's communication system and $1.2 million for a loss on restructuring of Black Mesa Pipeline's debt. 16. QUARTERLY FINANCIAL DATA (Unaudited)

Income Per Unit (Loss) Income(Loss) Operating From From (In thousands, except Operating Income Continuing Continuing per unit amounts) Revenues (Loss) Operations Operations --------------------- --------- --------- ---------- ---------- 2003 First Quarter $ 138,175 $ 59,037 $ 33,302 $ 0.70 Second Quarter 134,362 56,904 27,719 0.56 Third Quarter 138,008 (160,764) (183,570) (3.92) Fourth Quarter 145,382 56,760 30,542 0.60 2002 First Quarter $ 115,956 $ 55,968 $ 27,452 $ 0.60 Second Quarter 121,327 60,566 30,147 0.67 Third Quarter 123,878 59,915 31,236 0.66 Fourth Quarter 126,043 46,910 23,734 0.49

17. RELATIONSHIPS WITH ENRON In December 2001, Enron and certain of its subsidiaries filed voluntary petitions for Chapter 11 reorganization with the U.S. Bankruptcy Court. Northern Plains and NBP Services were not included in the bankruptcy filing and management believes that Northern Plains and NBP Services will continue to be able to meet their operational and administrative service obligations under the existing operating agreements. ENA, a subsidiary of Enron, was included in the bankruptcy filing. F-35 NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 17. RELATIONSHIPS WITH ENRON (continued) At the time of the bankruptcy filing, ENA had firm service agreements with Northern Border Pipeline representing approximately 3.5% of contracted capacity, a portion of which (1.1%) had been temporarily released to a third party until October 31, 2002. Northern Border Pipeline recorded a bad debt expense of approximately $1.3 million representing ENA's unpaid November and December 2001 transportation, which is included in operations and maintenance expense on the consolidated statement of income. On June 13, 2002, the Bankruptcy Court approved a Stipulation and Order entered into on May 15, 2002, by ENA and Northern Border Pipeline pursuant to which ENA agreed that all but one of the shipper contracts, representing 1.7% of pipeline capacity, will be deemed rejected and terminated. The remaining contract was terminated in the third quarter of 2002. For the year ended December 31, 2002, Northern Border Pipeline has experienced lost revenues of approximately $1.8 million related to ENA's capacity. Crestone had provided gas gathering and administrative services to ENA under a master services agreement. This agreement was terminated for ENA's failure to pay approximately $2.1 million, which was recorded as bad debt expense in 2001. Subsequent to the termination of the agreement, the services are being provided through contracts directly with the producers. Bear Paw Energy had also periodically entered into certain swap arrangements with ENA to hedge risks of changes in commodity prices (see Note 8). Bear Paw Energy terminated the swap arrangements with ENA prior to December 31, 2001, and recorded bad debt expense of approximately $5.4 million. The Partnership and its subsidiaries have filed proofs of claims regarding the amount of damages for breach of contract and other claims in the bankruptcy proceeding. However, the Partnership cannot predict the amounts, if any, that it will collect or the timing of collection. 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. In addition, the Bankruptcy Court order provides that the rights of PBGC and others to assert that their filed claims have not been released or adjudicated as a result of the Bankruptcy Court order and Enron and all other interested parties retained the right to assert that such claims had been adjudicated or released. F-36 NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 17. RELATIONSHIPS WITH ENRON (continued) Enron management has informed Northern Plains and NBP Services that it will 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 Plan. Northern Plains and NBP Services have advised us that each is a member of the ERISA controlled group of corporations of Enron that employs, or employed, individuals who are, or were, covered under the Plan and that an amount of approximately 6.2 million has been estimated for the Partnership's share of Northern Plains and NBP Services proportionate share of the up to $200 million estimated termination costs authorized by the Bankruptcy Court order. Under the operating agreements with Northern Plains and the administrative services agreement with NBP Services, these increased costs may be the Partnership's responsibility. The Partnership has accrued this amount to satisfy claims of reimbursement for these termination costs. While the final amounts have not been determined, the Partnership believes this accrual is adequate to cover the allocation of these costs to the Partnership. 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. 18. SUBSEQUENT EVENTS 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 expenditures with 50% equity capital contributions from its partners; and (iii) change the cash distribution policy of Northern Border Pipeline effective January 1, 2004. At that time, cash 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. Effective January 1, 2008, the cash distribution policy will be adjusted to maintain a consistent capital structure. The Partnership will be responsible for its ownership share of each equity cash call (currently 70%). In January 2004, the Partnership and TC PipeLines contributed $45.5 million and $19.5 million, respectively, to Northern Border Pipeline to be used by Northern Border Pipeline to repay a portion of its existing indebtedness under the 2002 Pipeline Credit Agreement. On February 9, 2004, 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, 2003. The distribution is payable February 20, 2004, to unitholders of record at February 17, 2004. F-37 INDEPENDENT AUDITORS' REPORT ON SCHEDULE Northern Border Partners, L.P.: We have audited in accordance with auditing standards generally accepted in the United States of America, the consolidated financial statements of Northern Border Partners, L.P. and Subsidiaries as of December 31, 2003 and 2002 and for each of the years in the three-year period ended December 31, 2003 included in this Form 10-K, and have issued our report thereon dated January 27, 2004. 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 14 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. KPMG LLP Omaha, Nebraska January 27, 2004 S-1 SCHEDULE II NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS FOR THE YEARS ENDED DECEMBER 31, 2003, 2002 AND 2001 (IN THOUSANDS)

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 ------------------- ---------- ---------- -------- --------------- ----------- Reserve for regulatory issues 2003 $ 12,294 $ 5,611 $ -- $ 10,261 $ 7,644 2002 $ 2,531 $ 9,763 $ -- $ -- $ 12,294 2001 $ 1,800 $ 731 $ -- $ -- $ 2,531 Allowance for doubtful accounts 2003 $ 12,392 $ 52 $ -- $ -- $ 12,444 2002 $ 10,743 $ 3,463 $ 52 $ 1,866 $ 12,392 2001 $ -- $ 10,743 $ -- $ -- $ 10,743

S-2 INDEX TO EXHIBITS *3.1 Form of Amended and Restated Agreement of Limited Partnership of Northern Border Partners, L.P. (Exhibit 3.1 No. 2 to the Partnership's Form S-1 Registration Statement, Registration No. 33-66158 ("Form S-1")). *3.2 Form of Amended and Restated Agreement of Limited Partnership For Northern Border Intermediate Limited Partnership (Exhibit 10.1 to Form S-1). *4.1 Indenture, dated as of June 2, 2000, between the registrants and Bank One Trust Company, N.A. (Exhibit 4.1 to the Partnership's Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2000 ("June 2000 10-Q")). *4.2 First Supplemental Indenture, dated as of September 14, 2000, between the registrants and Bank One Trust Company, N.A. (Exhibit 4.2 to 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 (Exhibit 4.3 to Northern Border Partners, L.P. Form 10-K for the year ended December 31, 2001). *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. (Exhibit No. 4.1 to Northern Border Pipeline Company's Form S-4 Registration Statement, 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. (Exhibit 4.2 to Northern Border Pipeline Company's Registration Statement on Form S-4, Registration No. 333-73282 ("2001 NB Form S-4")). *4.6 Indenture, dated as of April 29, 2002, between Northern Border Pipeline Company and Bank One Trust Company, N.A. (Exhibit 4.1 to Northern Border Pipeline Company's Form 10-Q for the quarter ended March 31, 2002). *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 (Exhibit 10.2 to Form S-1). *10.2 Form of Seventh Supplement Amending Northern Border Pipeline Company General Partnership Agreement (Exhibit 10.15 to Form S-1). *10.3 Eighth Supplement Amending Northern Border Pipeline Company General Partnership Agreement (Exhibit 10.15 to NB Form S-4). *10.4 Ninth Supplement Amending Northern Border Pipeline Company General Partnership Agreement (Exhibit 10.37 to 2001 Form S-4). *10.5 Operating Agreement between Northern Border Pipeline Company and Northern Plains Natural Gas Company, dated February 28, 1980 (Exhibit 10.3 to Form S-1). *10.6 Administrative Services Agreement between NBP Services Corporation, Northern Border Partners, L.P. and Northern Border Intermediate Limited Partnership (Exhibit 10.4 to Form S-1). 10.7 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). *10.8 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) (Exhibit 10.1 to Northern Border Partners, L.P.'s Current Report on Form 8-K dated June 26, 2002). *10.9 Employment Agreement between Northern Plains Natural Gas Company and William R. Cordes effective June 1, 2001 (Exhibit 10.27 to Northern Border Partners, L.P.'s Quarterly Report on Form 10-Q for the quarter ended June 30, 2001). *10.10 Amendment to Employment Agreement between Northern Plains Natural Gas Company and William R. Cordes, effective September 25, 2001 (Exhibit 10.36 to 2001 Form S-4). *10.11 Employment Agreement between Northern Plains Natural Gas Company and Jerry L. Peters effective April 1, 2002 (Exhibit 10.1 to Northern Border Pipeline Company's Form 10-Q for the quarter ended March 31, 2002). *10.12 Operating Agreement between Midwestern Gas Transmission Company and Northern Plains Natural Gas Company dated as of April 1, 2001. (Exhibit 10.38 to Northern Border Partners, L.P.'s Form 10-K for the year ended December 31, 2001). *10.13 Operating Agreement between Viking Gas Transmission Company and Northern Plains Natural Gas Company dated as of January 17, 2003.Exhibit 10.18 to Northern Border Partners, L.P.'s Form 10-K for the year ended December 31, 2002) *10.14 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 (Exhibit 10.21 to Northern Border Partners, L.P.'s Form 10-K/A for the year ended December 31, 1998, SEC File No. 1-12202 ("1998 10-K")). 12.1 Statement re computation of ratios 21 The subsidiaries of Northern Border Partners, L.P. are Northern Border Intermediate Limited Partnership; Northern Border Pipeline Company; Crestone Energy Ventures, L.L.C.; Bear Paw Investments, LLC; Bear Paw Energy, LLC; Border Midwestern Company; Midwestern Gas Transmission Company; Border Viking Company; and Viking Gas Transmission Company. 23.01 Consent of KPMG LLP. 31.1 Certification of principal executive office pursuant to rule 13-A or 15d of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. 31.2 Certification of principal financial officer pursuant to rule 13-A or 15d of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 32.1 Certification of principal executive officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. 32.2 Certification of principal financial officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. *99.1 Northern Border Phantom Unit Plan (Exhibit 99.1 to Amendment No. 1 to Form S-8, Registration No. 333-66949 and Exhibit 99.1 to Northern Border Partners, L.P.'s Registration No. 333-72696). *Indicates exhibits incorporated by reference as indicated; all other exhibits are filed herewith.