10-K 1 h03425e10vk.txt NORTHERN BORDER PARTNERS, L.P. - DATED 12/31/2002 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, 2002 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 28, 2002, was approximately $1,373,496,413. ii NORTHERN BORDER PARTNERS, L.P. TABLE OF CONTENTS

PAGE NO. -------- PART I Item 1. Business 1 Item 2. Properties 18 Item 3. Legal Proceedings 19 Item 4. Submission of Matters to a Vote of Security Holders 19 PART II Item 5. Market for Registrant's Common Units and Related Security Holder Matters 20 Item 6. Selected Financial Data 22 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations 24 Item 7a. Quantitative and Qualitative Disclosures About Market Risk 45 Item 8. Financial Statements and Supplementary Data 46 Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure 46 PART III Item 10. Partnership Management 47 Item 11. Executive Compensation 51 Item 12. Security Ownership of Certain Beneficial Owners and Management 54 Item 13. Certain Relationships and Related Transactions 54 Item 14. Controls and Procedures 57 PART IV Item 15. Exhibits, Financial Statement Schedules and Reports on Form 8-K. 58

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: o Interstate Natural Gas Pipelines o Natural Gas Gathering and Processing o 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, and the western Canadian sedimentary basin, in Alberta, Canada. Our coal slurry pipeline segment is comprised of our ownership of Black Mesa Pipeline, Inc., a 273-mile pipeline, 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 and Pan Border Gas Company, both subsidiaries of Enron Corp. ("Enron"), and Northwest Border Pipeline Company, a subsidiary of TransCanada PipeLines Limited ("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." Our general partners hold an aggregate 2% general partner interest in the Partnership. Northern Plains also owns common units representing a 1.14% limited partner interest and Sundance Assets, L.P., 1 an affiliate of Enron, holds a 6.19% 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 8.83% 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 utilizes employees and information technology systems of its affiliates to provide these services. Northern Plains provides operating services to our interstate pipelines and the coal slurry pipeline segment pursuant to operating agreements. Northern Plains employs approximately 223 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 March 19, 2003, Enron announced its intention to create a new pipeline operating entity, which will include Enron's interests in Northern Plains, Pan Border and NBP Services. See Item 7. "Management's Discussion and Analysis of Financial Condition and Results of Operations - Update On The Impact Of Enron's Chapter 11 Filing On Our Business," Item 13. "Certain Relationships and Related Transactions" and Item 10. "Partnership Management." We make available 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 and geographic areas, 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 calculation of amounts to be paid by shippers 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 price risk for quantities transported. 2 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, 2002, we estimate that Northern Border Pipeline transported approximately 20% of the total amount of natural gas imported from Canada to the United States. Over the same period, approximately 89% 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 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 51 tower sites. 3 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 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 and Duke Energy, 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 EnCana Corporation. 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. 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, 2002, of the natural gas transported on the pipeline system, approximately 89% was produced in Canada, approximately 5% was produced by the Dakota Gasification plant and approximately 6% was produced in the Williston Basin. To access markets, the pipeline system interconnects with pipeline facilities of various interstate and intrastate pipeline companies and local distribution companies, of which the larger interconnections are: o Northern Natural Gas Company at Ventura, Iowa as well as multiple smaller interconnections in South Dakota, Minnesota and Iowa; o Natural Gas Pipeline Company of America at Harper, Iowa; o MidAmerican Energy Company at Iowa City and Davenport, Iowa and Cordova, Illinois; o Alliant Power Company at Prophetstown, Illinois; o Northern Illinois Gas Company at Troy Grove and Minooka, Illinois; o Midwestern Gas Transmission Company near Channahon, Illinois; o ANR Pipeline Company near Manhattan, Illinois; o Vector Pipeline L.P. in Will County, Illinois; o Guardian Pipeline, L.L.C. in Will County, Illinois; o The Peoples Gas Light and Coke Company near Manhattan, Illinois; and 4 o 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 50 firm transportation shippers with diverse operating and financial profiles. Based upon shippers' contractual obligations, as of December 31, 2002, 91% of the firm capacity is contracted by producers and marketers. The remaining firm capacity is contracted to local distribution companies (6%), interstate pipelines (2%) and end-users (1%). As of December 31, 2002, the termination dates of these contracts ranged from March 31, 2003 to December 21, 2013, and the weighted average contract life, based upon annual contractual obligations, was approximately four and one-half years. Contracts for approximately 42% of the capacity will expire during 2003. See Item 7. "Management's Discussion and Analysis of Financial Condition and Results of Operations - Outlook." Northern Border Pipeline's mix and number of 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. Shippers on the pipeline system temporarily released capacity during 2002 for varying periods of time. There were also permanent releases of capacity to other shippers for the full term of the contracts. As of December 31, 2002, the largest shipper, Pan-Alberta Gas (U.S.) ("Pan-Alberta") is obligated for approximately 20% of the contracted firm capacity, of which approximately 3% of the total contracted capacity has been temporarily released by Pan-Alberta to other shippers through October 31, 2003. Pan-Alberta's firm contracts expire October 31, 2003. Mirant Americas Energy Marketing, LP, who manages the assets of Pan-Alberta Gas, Ltd., including Pan-Alberta's contracts with Northern Border Pipeline, is also obligated for approximately 10% of the contracted firm capacity. Mirant's firm contracts expire in October 2006 and December 2008. Mirant and Pan-Alberta have agreed to maintain credit support in accordance with our tariff, including letters of credit, that mitigate a portion of our credit exposure. The only other shipper that held over 10% of the contracted firm capacity at December 31, 2002 is BP Canada Energy Marketing Corp., with approximately 12% of the contracted firm capacity, of which approximately 8% of the total contracted capacity 5 expires on October 31, 2003. See Item 7. "Management's Discussion and Analysis of Financial Condition and Results of Operations - Outlook." 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 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 69,070. 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 CMS 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, 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 South. 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, 2002, approximately 54% of the firm transportation capacity is contracted by local distribution companies, 43% by marketers and 3% by end-users. For the year end December 31, 2002, Midwestern Gas Transmission's two major customers, Northern Illinois Gas Company and Northern Indiana Public Service Company accounted for $5.2 million (28%) and $2.9 million (16%), respectively, of its revenues. As of December 31, 2002, the termination dates of Midwestern Gas Transmission's firm transportation contracts ranged from March 31, 2003 to October 31, 2019. The weighted average contract life, based upon annual contract obligations, was approximately two and one-half years. 6 See Item 7. "Management's Discussion and Analysis of Financial Condition and Results of Operations - Outlook." One shipper, Enron North America Corp. ("ENA"), which has filed for bankruptcy protection, is affiliated with two of our general partners, Northern Plains and Pan Border. ENA's contract, which has not been terminated or rejected by ENA, covers 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 - Update On 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. from Xcel Energy Inc. 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 a total horsepower of 68,650. Based upon shipper contractual obligations as of December 31, 2002, approximately 72% of the firm transportation capacity is contracted by local distribution companies, 24% by marketers and 4% by end-users. 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 CMS Energy Corporation and Wisconsin Energy Corporation hold the remaining interests in this system. Wisconsin Gas Company, a subsidiary of Wisconsin Energy Corporation, has contracted for 80% of the pipeline's 750 mmcfd capacity. Guardian Pipeline is operated by CMS Trunkline Gas Company, which is part of the CMS Panhandle Companies. CMS Energy announced that an agreement has been reached to sell the CMS Panhandle Companies to a new entity owned by Southern Union Company and AIG Highstar Capital, L.P. and also announced that it intends to sell its one-third interest in Guardian. 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 7 and other facilities that permit natural gas to be produced and delivered to pipelines that interconnect with our interstate pipelines' systems. Low prices for natural gas, 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. Additional pipeline export capacity also could accelerate depletion of these reserves. Excess export capacity could also affect the demand or value of the transport on our interstate pipelines. Each of our interstate pipelines' business also depends on the level of demand for natural gas in the markets the pipeline system serves. The volumes of natural gas delivered to these markets from other sources affect the demand for both the natural gas supplies and the use of the pipeline systems. Demand for natural gas to serve other markets also influences the ability and willingness of shippers to use our pipeline systems to meet demand in the markets that our interstate pipelines serve. A variety of factors could affect the demand for natural gas in the markets that our pipeline systems serve. These factors include: o economic conditions; o fuel conservation measures; o alternative energy requirements and prices; o gas storage inventory levels; o climatic conditions; o government regulation; and o 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. 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. 8 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 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 has no interconnections with other pipelines upstream of the liquids extraction facilities, which are located near Chicago. This contrasts with Northern Border Pipeline, which serves various markets through interconnections with other pipelines along its route. The competitive impact of the Alliance Pipeline has been mitigated by the continuing development of additional capacity to ship natural gas from the Chicago area to other markets in the United States. Vector Pipeline L.P. interconnects with the Alliance Pipeline and transports gas eastward to a terminus in eastern Canada. Guardian Pipeline was placed into service in December 2002 and interconnects with both Northern Border Pipeline and Midwestern Gas Transmission. Guardian Pipeline delivers into markets in Wisconsin and could provide access to additional markets for Northern Border Pipeline and Midwestern Gas Transmission shippers. 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 51% of Midwestern Gas Transmission natural gas receipts during 2002. 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. 9 Viking Gas Transmission directly serves markets in North Dakota, Minnesota and Wisconsin. Northern Natural Gas Company 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. Natural gas is also produced in the United States and transported by competing pipeline systems to the same markets as those served by our pipeline systems. 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: o transportation of natural gas; o rates and charges; o construction of new facilities; o extension or abandonment of service and facilities; o accounts and records; o depreciation and amortization policies; o the acquisition and disposition of facilities; and o 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 of 2002 that Northern Border Pipeline and Midwestern Gas Transmission are two of the companies selected by the FERC to undergo an industry-wide audit of FERC-assessed annual charges. The overall audit objective is 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 covers the period of January 1, 2001 to December 31, 2001. The FERC issued its final 10 report on Midwestern Gas Transmission finding it was compliant. We are awaiting the final report on Northern Border Pipeline, but do not believe the results of the audit will have a material adverse impact on our results of operation or financial position. 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 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 agreed upon cost of service 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 transportation 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 11 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 to interruptible shippers is calculated as the sum of the firm transportation maximum reservation charge and commodity rate. Under its tariff, Northern Border Pipeline shares net interruptible transportation service revenue and any new services revenue on an equal basis with its firm shippers through October 31, 2003. However, Northern Border Pipeline is permitted to retain revenue from interruptible transportation service to offset any decontracted firm capacity. Neither Midwestern Gas Transmission nor Viking Gas Transmission share revenue from interruptible transportation service with firm shippers. 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. In September 2001, the FERC issued a Notice of Proposed Rulemaking proposing new standards of conduct that would apply uniformly to natural gas pipelines and transmitting public utilities. FERC is proposing one set of standards to govern relationships between regulated transmission providers and all energy affiliates. Should a final rule be issued in this proceeding, we may be subject to standards that could result in additional costs and separation of functions and staffing with our affiliates. On August 1, 2002, FERC issued a Notice of Proposed Rulemaking regarding the Regulation of Cash Management and is proposing to establish limits on the amount of funds that can be transferred from the regulated subsidiary to its non-regulated parent. We do not expect that the FERC's proposed policy will have a material adverse impact on our cash management practices. On July 17, 2002, FERC issued a Notice of Inquiry Concerning Natural Gas Pipeline Negotiated Rate Policies and Practices. In this proceeding, the FERC is evaluating its negotiated rate program and has invited all segments of the industry to provide comments. The outcome of this inquiry may change the existing FERC policy concerning the types of negotiated rates that it allows and may have an undetermined impact on the pricing practices for a pipeline's transportation services. 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 are studying creditworthiness standards and may recommend that the FERC 12 promulgate changes in such standards on an industry-wide basis. The enactment of some of these recommendations may have the effect of easing certain creditworthiness standards and parameters currently reflected in our tariff. At this stage of the proceedings, however, we cannot predict the ultimate impact, if any, such changes would have on us. From time to time, we file to make changes to our 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 clarify the language by adding detail to the broad categories that comprise company use gas. Relying upon the currently effective version of the tariff, Northern Border Pipeline 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. Several parties have filed protests of this change and have requested that the FERC order refunds. At its meeting on March 26, 2003, the FERC voted to reject Northern Border Pipeline's filing and require refunds. In its draft 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. Other parties and Northern Border Pipeline will have thirty days from the date of the order to request rehearing. Northern Border Pipeline has established a reserve in the amount of $10 million, which we believe is sufficient to cover the potential refunds. 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 (NGLs) for third parties and related field services. We do not explore for, or produce, crude oil or natural gas, and do not own crude oil or natural gas reserves. Bear Paw Energy, LLC, our wholly-owned subsidiary, has extensive natural gas gathering, processing and fractionation operations in the Williston Basin in Montana and North Dakota as well as gas gathering operations in the Powder River Basin in Wyoming. In the Williston Basin, Bear Paw Energy as over 3,000 miles of gathering pipelines and five processing plants with 90 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 agreements. In addition, through our wholly-owned subsidiary, Crestone Energy Ventures, L.L.C., 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 13 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. CMS Field Services, Inc. holds the remaining ownership interest in Bighorn and is the project manager and operator. CMS Energy Corporation, the parent of CMS Field Services, Inc. has announced it intends to sell CMS Field Services. The Bighorn system is managed through a management committee consisting of representatives of the owners. CMS Field Services, CIG Resources Company, Western Gas Resources and Bargath, Inc. hold the remaining interests in Fort Union. CMS Field Services 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 are interconnected with the facilities of Bighorn and Fort Union, and all the gathering facilities interconnect to the interstate gas pipeline grid serving gas markets in the Rocky Mountains, the Midwest and California. Bear Paw Energy's Williston Basin gathering and processing facilities are located in eastern Montana and western North Dakota, with a small extension into Saskatchewan, Canada. The Williston Basin system consists of approximately 3,000 miles of polyethylene and steel pipeline and 28 compressor stations with a total rated horsepower of 28,000, 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 the Mazeppa and Gladys gas processing plants, and a minority interest in the Gregg Lake/Obed Pipeline, all of which are located in Alberta, Canada. The Mazeppa Plant is a sour gas processing plant with 80 mmcfd of capacity and 115 miles of associated gathering pipelines. Sour gas processing involves the removal of high quantities of sulphur from the gas stream. The Gladys Plant is a sour gas processing plant with 10 mmcfd of capacity. The Gregg Lake/Obed Pipeline is comprised of 85 14 miles of gathering lines with a capacity of 150 mmcfd. The operations of these facilities have been outsourced to Thermal Gas Group International Corp. and TGG Operating Corp., both of which are third parties. The Mazeppa and Gladys plants are staffed with 27 employees of TGG Operating Corp., of which 21 are represented by a labor union. 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. The pipelines are operated by a third party, Central Alberta Midstream. Border Midstream contracts with its customers to process gas at the Mazeppa and Gladys plants under volumetric contracts with life of reserves dedication from producers. The largest dedication is from Compton Petroleum involving over one million acres. The major customers of Border Midstream are Compton Petroleum, ConocoPhillips, and ExxonMobil. They account for approximately 70%, 11% and 9% of revenues, respectively. 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 and Wind River Basins of Wyoming are affiliates of Western Gas Resources and Thunder Creek Gas Gathering. Competition for gathering and processing services in the Williston Basin is less significant, and includes Amerada Hess and PetroHunt Corporation in localized areas. In the western Canadian sedimentary basin, there are several gas plants owned by AltaGas, Esso and Canadian 88 in the general vicinity of Border Midstream's plants. 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, 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 affect producers' decisions to drill or produce. On January 17, 2003, the Bureau of Land Management ("BLM") released two final environmental impact statements ("EIS") regarding oil and natural gas development on Federal lands. One EIS pertains to oil and gas development on BLM-administered public lands and federal mineral leases within the Powder River Basin in northeastern Wyoming. The other EIS pertains to statewide oil and natural gas development in Montana. The protest period for these EIS's 15 closed on February 18, 2003. The result of any protests, as well as recommended mitigation measures, may affect drilling and production activity on BLM-administered public lands and on federal mineral leases in the Powder River Basin. 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 volume commitments 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 mitigates the competitive effect 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. 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 after December 31, 2005. If efforts by the parties to obtain sources of water are not successful and the Mohave Plant is closed, it would be necessary to shut down Black Mesa in 2006. Southern California Edison, as one of the owners of the Mohave Plant, has filed a petition before the California Public Utility Commission ("CPUC") requesting that the CPUC either recognize the end of Mohave's coal-fired operations as of the end of 2005 with appropriate ratemaking accounts or authorize expenditures for pollution control activities required for future operation. This proceeding is pending. Approximately 59 people are employed in the operations of Black Mesa, of which 26 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 for an additional year in February 2002. The UMWA has indicated its intent to begin discussion of a new contract for 2003. 16 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, and the Pipeline Safety Act of 1992. The Pipeline Safety Improvement Act ("Act") was signed into law in December 2002. The Act contains numerous provisions that increase federal inspection and safety requirements for our interstate pipelines. As a result, the Secretary of Transportation and various government agencies are required to develop and implement regulations under the Act in order for our interstate pipelines to carry out the prescribed evaluations and implementation of programs to ensure the safety of our facilities. The Act and subsequent regulations have prescribed timelines and the implementation may have an impact on the costs that pipelines incur. In Canada, our processing plants and 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 December 2002, the EPA and ADEQ demanded payment of stipulated penalties determined pursuant to the Consent Decree in the amount of $176,000. Black Mesa has paid $47,000 of this amount and after informal discussions with the EPA and ADEQ, Black Mesa agreed to pay $127,250. 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 increasingly strict environmental and safety laws, regulations and enforcement policies thereunder, and claims for damages to property or persons resulting from our operations, could result in substantial 17 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 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. This pipeline right-of-way lease, which was approved by the Department of the Interior 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. 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 Bureau of Indian Affairs 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, Border Midstream, 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. 18 Black Mesa holds title to its pipeline and pump stations. The real property rights for Black Mesa facilities are derived through fee ownership, leases, easements, rights-of-way and permits. Black Mesa holds rights-of-way grants from private landowners as well as The Navajo Nation and the Hopi Tribe. These rights-of-way grants extend for terms at least through December 31, 2005, the date that Black Mesa's transportation contract with Peabody Western Coal is presently scheduled to end. ITEM 3. LEGAL PROCEEDINGS On July 31, 2001, the Assiniboine and Sioux Tribes of the Fort Peck Indian Reservation 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 principle on pipeline right-of-way lease and taxation issues, subject to final documentation and necessary governmental approvals. We believe that Northern Border Pipeline will obtain regulatory recovery of the costs resulting from the settlement, which will result in no material adverse impact to our results of operations or financial position. 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 California Public Utility Commission related to Black Mesa's continuation of service beyond 2005. See Item 1. "Business - Interstate Pipeline Regulation" for the discussion on the proceedings before 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 2002. 19 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 ------------ ------------ ------------- 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 2001 Fourth Quarter .................... $ 41.05 $ 33.60 $ 0.80 Third Quarter ..................... 39.99 32.50 0.7625 Second Quarter .................... 41.20 35.20 0.7625 First Quarter ..................... 37.60 30.25 0.7625

As of March 19, 2003, there were approximately 1,500 record holders of common units and approximately 58,700 beneficial owners of the common units, including common units held in street name. On March 20, 2003, the last reported sale price of our common units on the New York Stock Exchange was $37.73 per common unit. We currently have 43,809,714 common units outstanding, representing a 98% limited partner interest. The common units are the only outstanding limited partner interests. Thus, our equity consists of general partner interests representing in the aggregate a 2% interest and common units representing in the aggregate a 98% limited partner interest. The general partners are entitled to 2% of all cash distributions, and the holders of common units are entitled to the remaining 98% of all cash distributions, except that the general partners are entitled to incentive distributions if the amount distributed with respect to any quarter exceeds $0.605 per common unit ($2.42 annualized). Under the incentive distribution provisions, the general partners are entitled to 15% of amounts distributed in excess of $0.605 per common unit, 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 the Partnership Agreement. On January 22, 2003, we declared a distribution of $0.80 per unit ($3.20 per unit on an annualized basis), payable February 14, 2003 to the general partners and unitholders of record at January 31, 2003. 20 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 exercise Weighted average Number of units of outstanding phantom exercise price of remaining available for Plan Category units outstanding phantom units future issuance ------------------------------ -------------------------- -------------------------- -------------------------- (a) (b) (c) Equity compensation plans approved by the unitholders(1) -- -- -- Equity compensation plans 41,934 (2) $37.87 (2) 194,542(3) not approved by the unitholders (1) Total

(1) Under our partnership agreement, the 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, 2002 and assumes that all outstanding phantom units were settled in common units as of December 31, 2002. (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. 21 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, ------------------------------------------------------------------------------- 2002 2001 (2) 2000 (3) 1999 1998 ------------ ------------ ------------ ------------ ------------ INCOME DATA: Operating revenues, net $ 495,617 $ 461,469 $ 339,732 $ 318,963 $ 217,592 Product purchases 50,648 39,699 -- -- -- Operations and maintenance 111,668 96,449 62,097 53,451 44,770 Depreciation and amortization 75,874 76,310 60,699 54,842 43,885 Taxes other than income 32,446 28,052 28,634 30,952 22,012 Regulatory credit -- -- -- -- (8,878) ------------ ------------ ------------ ------------ ------------ Operating income 224,981 220,959 188,302 179,718 115,803 Interest expense, net 82,898 89,908 81,495 67,709 30,922 Other income 14,409 86 8,032 4,562 13,208 Minority interests in net income 42,816 42,138 38,119 35,568 30,069 ------------ ------------ ------------ ------------ ------------ Net income before extraordinary items 113,676 88,999 76,720 81,003 68,020 Extraordinary loss from debt restructuring -- (1,213) -- -- -- ------------ ------------ ------------ ------------ ------------ Net income to partners $ 113,676 $ 87,786 $ 76,720 $ 81,003 $ 68,020 ============ ============ ============ ============ ============ Net income per unit $ 2.44 $ 2.12 $ 2.50 $ 2.70 $ 2.27 ============ ============ ============ ============ ============ Number of units used in computation 42,709 38,538 29,665 29,347 29,345 ============ ============ ============ ============ ============ CASH FLOW DATA: Net cash provided by operating activities $ 243,142 $ 233,948 $ 169,615 $ 173,368 $ 103,849 Capital expenditures 49,874 126,414 19,721 102,270 652,194 Acquisition of businesses 1,561 345,074 229,505 31,895 -- Distribution per unit 3.20 2.99 2.65 2.44 2.30 BALANCE SHEET DATA (AT END OF YEAR): Property, plant and equipment, net $ 2,015,280 $ 2,040,099 $ 1,732,076 $ 1,745,356 $ 1,730,476 Total assets 2,725,495 2,687,355 2,082,720 1,863,437 1,825,766 Long-term debt, including current maturities 1,403,743 1,423,227 1,171,962 1,031,986 976,832 Minority interests in partners' equity 242,931 250,078 248,098 250,450 253,031 Partners' equity 944,035 914,958 572,274 515,269 507,426 OTHER FINANCIAL DATA: Ratio of earnings to fixed charges (1) 2.8 2.5 2.4 2.7 3.0 OPERATING DATA: Interstate Natural Gas Pipeline Segment: Million cubic feet of gas delivered 935,654 891,935 852,674 834,833 608,187 Average daily throughput (mmcfd) 2,636 2,605 2,400 2,353 1,706 Natural Gas Gathering and Processing Segment: Gathering (mmcfd) 1,089 793 397 -- -- Processing (mmcfd) 127 118 -- -- -- Coal Slurry Pipeline Segment: Thousands of tons of coal shipped 4,639 4,932 4,711 4,494 4,489

22 (1) "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. (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. 23 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. 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 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. 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. Northern Border Pipeline'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 continually assesses 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, Northern Border Pipeline would be required to write off the regulatory assets at that time. At December 31, 2002, Northern Border Pipeline has reflected regulatory assets of $10.5 million, which are being recovered from its 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. 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. Our accounting for financial instruments follows SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities," which we adopted on January 1, 2001. SFAS No. 133 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 24 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, 2002, our balance sheet included assets from derivative financial instruments of $36.7 million and liabilities from derivative financial instruments of $4.1 million. Our accounting for goodwill changed effective January 1, 2002, when 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. RESULTS OF OPERATIONS Our operating results for 2002 and 2001 were significantly influenced by the acquisitions we made in the first half of 2001 and in September 2000. 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. In September 2000, we purchased interests in gas gathering businesses in the Powder and Wind River basins in Wyoming. Our 2002 operating results also benefited from the change in accounting for goodwill. Our net income was $113.7 million in 2002 ($2.44 per unit), compared to net income of $87.8 million in 2001 ($2.12 per unit) and $76.7 million in 2000 ($2.50 per unit). The increase in net income in 2002 over 2001 resulted from the acquisitions made in 2001, Northern Border Pipeline's completion of Project 2000, which was a pipeline expansion and extension placed in service in October 2001, a decline in interest rates and the effect of the change in accounting for goodwill. The increase in net income in 2001 over 2000 resulted from the acquisitions made in 2001 and 2000 and improved performance by Northern Border Pipeline. Northern Border Pipeline's operating results benefited from lower interest rates that reduced its interest expense, lower operations and maintenance expenses and higher revenues. Although our net income increased between 2000 and 2001, our net income per unit decreased due to an increase in our average number of common units outstanding. Additional common units were issued during 2001 to partially finance our acquisitions and to repay amounts borrowed on our debt facilities. 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. Our 2000 operating results included $2.7 million of goodwill amortization or $0.09 per unit. Goodwill amortization for 2000 by business segment was as follows: natural gas gathering and processing - $2.3 million; and coal slurry - $0.4 million. INTERSTATE NATURAL GAS PIPELINES Our interstate natural gas pipeline segment reported earnings of $107.5 million in 2002. In 2001, excluding the impact of goodwill 25 amortization, the segment reported earnings of $103.2 million. In 2000, the segment reported earnings of $89.0 million. The increase in 2002 and 2001 earnings from the prior year resulted from our acquisition of Midwestern Gas Transmission in 2001 and Northern Border Pipeline's completion of Project 2000. The 2001 results included eight months and three months of revenues and expenses for Midwestern Gas Transmission and Project 2000, respectively. Operating revenues for our interstate natural gas pipeline segment were $339.4 million in 2002, $322.6 million in 2001 and $311.0 million in 2000. The increase in operating revenues in 2002 over 2001 resulted from an $8.8 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. The impact of the additional revenues associated with Project 2000 was partially offset by uncollected revenues associated with the transportation capacity formerly held by ENA, which filed for Chapter 11 bankruptcy protection in December 2001 (see "Update On The Impact Of Enron's Chapter 11 Filing On Our Business"). For 2002, the revenues lost on this capacity totaled approximately $1.8 million. The increase in operating revenues in 2001 over 2000 was primarily due to $9.5 million of revenues from Midwestern Gas Transmission acquired effective May 2001 and an increase in revenues for Northern Border Pipeline of $2.1 million. Northern Border Pipeline reflected additional revenues associated with the completion of Project 2000 in October 2001. Operations and maintenance expenses for our interstate natural gas pipeline segment were $48.6 million in 2002, $36.9 million in 2001 and $41.5 million in 2000. 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 $3.9 million. Northern Border Pipeline's expenses in 2002 reflected a $10.0 million reserve for costs that may arise from the treatment of previously collected quantities of natural gas used in utility operations to cover electric power costs (see Item 1. "Business - Interstate Natural Gas Pipelines - Interstate Pipeline Regulation"). From 2001 to 2002, Northern Border Pipeline also had an increase in regulatory commission expense and decreases in employee benefits expenses, administrative expenses and bad debt expense. The 2001 expense included $1.3 million of bad debt expense related to ENA. Midwestern Gas Transmission's expense increase for 2002 over 2001 was due to increases in employee benefit expenses and administrative expenses and 2001 results had included only eight months of activity. The decrease in operations and maintenance expense in 2001 from 2000 reflects a decrease in Northern Border Pipeline's expense by $7.8 million partially offset by $3.2 million of expense from Midwestern Gas Transmission. Northern Border Pipeline's operations and maintenance expense decreased due primarily to a reduction in regulatory commission expense, decreased employee payroll, employee benefits expenses and administrative expenses and decreased costs to operate two of its 26 electric-powered compressor units as a result of collected quantities of natural gas used in utility operations to cover electric power costs. Depreciation and amortization expenses, excluding goodwill amortization, for our interstate natural gas pipeline segment were $61.0 million in 2002, $58.9 million in 2001 and $57.3 million in 2000. 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. The increase in depreciation and amortization expenses between 2000 and 2001 is due primarily to Midwestern Gas Transmission. Taxes other than income for our interstate natural gas pipeline segment were $29.2 million in 2002, $26.1 million in 2001 and $28.0 million in 2000. The increase in 2002 from 2001 is primarily due to a $2.8 million increase in Northern Border Pipeline's expense and a $0.3 million increase in expense for Midwestern Gas Transmission. 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. The decrease in taxes other than income in 2001 from 2000 was also due to a decrease in use taxes. As a result of a ruling by the Minnesota Supreme Court, Northern Border Pipeline filed for a refund of use taxes previously paid on exempt purchases. Northern Border Pipeline received the refund in March 2002. Interest expense for our interstate natural gas pipeline segment, which relates to Northern Border Pipeline's financing activities, was $51.5 million in 2002, $55.4 million in 2001 and $65.2 million in 2000. Both 2002 and 2001 interest expense decreased from prior year levels due to a decrease in average interest rates as well as a decrease in average debt outstanding. The segment also recorded $0.9 million of interest expense capitalized in 2001 primarily related to construction of Project 2000 facilities. Other income for our interstate natural gas pipeline segment was $1.2 million in 2002, $0.0 million in 2001 and $8.1 million in 2000. The 2002 amount includes income of approximately $0.6 million for previously vacated microwave frequency bands and income of $0.2 million due to a reduction in reserves previously established for Minnesota use taxes. The amount for 2001 includes a charge of approximately $1.5 million for an uncollectible receivable from a telecommunications company that had purchased excess capacity on Northern Border Pipeline's communication system and a $0.7 million charge for reserves established. Income tax expense for Midwestern Gas Transmission, which is netted in other income, increased $1.1 million in 2002 over 2001. Northern Border Pipeline recorded an allowance for equity funds used during construction of $0.9 million in 2001 primarily due to Project 2000. In 2000, Northern Border Pipeline had recorded approximately $1.7 million of income from the sale of excess capacity on its communication system. Other income for 2000 also included $5.6 million of income due to a reduction in reserves previously established for regulatory issues by Northern Border Pipeline as the result of the settlement of its rate case. 27 Minority interests in net income, which represent the 30% minority interest in Northern Border Pipeline, were $42.8 million for 2002, $42.1 million for 2001 and $38.1 million for 2000. The increases in 2002 and 2001 from prior year results were due to increased net income for Northern Border Pipeline. NATURAL GAS GATHERING AND PROCESSING Our natural gas gathering and processing segment reported earnings of $38.3 million in 2002. Excluding the impact of goodwill amortization, the segment reported earnings of $32.3 million and $3.7 million in 2001 and 2000, respectively. The increase in 2002 and 2001 earnings over the prior year resulted from our acquisitions made in 2001 and 2000. The 2001 results included nine months of activity for Bear Paw Energy and Border Midstream Services. The 2000 results included three months of activity for the assets acquired in September 2000. Operating revenues for our natural gas gathering and processing segment were $134.7 million in 2002, $116.8 million in 2001 and $7.5 million in 2000. The increase in operating revenues in 2002 over 2001 was primarily due to the acquisitions we made in 2001. The 2001 revenues for the segment included only nine months of activity for Bear Paw Energy and Border Midstream Services. 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. The increase in operating revenues in 2001 over 2000 was primarily due to the acquisitions made beginning in March 2001 and September 2000. Product purchases for our natural gas gathering and processing segment were $50.6 million in 2002 and $39.7 million in 2001. In conjunction with its gathering and processing activities, Bear Paw Energy purchases the natural gas stream from producers. The price Bear Paw Energy pays the producers is based upon a percentage of the revenues it receives upon sale of the natural gas liquids and residue that it processes in its facilities. 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 $43.2 million in 2002, $43.2 million in 2001 and $5.1 million in 2000. The nine months of activity for Bear Paw Energy in the 2001 expense included bad debt expense of $7.5 million related to ENA's bankruptcy. See "Update On The Impact of Enron's Chapter 11 Filing On Our Business" and Item 13. "Certain Relationships and Related Transactions." The increase in expense between 2000 and 2001 was primarily due to the acquisitions made in 2001 and 2000 and the bad debt expense for ENA. Depreciation and amortization expenses, excluding goodwill amortization, for our natural gas gathering and processing segment were $13.3 million in 2002, $8.6 million in 2001 and $0.2 million in 2000. The increase in 2002 and 2001 expense over prior year levels was due primarily to the acquisitions made in 2001 and 2000. Other income (expenses) from our natural gas gathering and processing segment were ($0.4 million) in 2002, $1.2 million in 2001 and $0.0 million in 2000. The decrease in 2002 from 2001 was primarily 28 due to additional income tax expense for Border Midstream Services of $0.8 million. Other income for 2001 included $0.7 million from a gain on sale of gas processing assets and income from well connects. Equity earnings from our unconsolidated affiliates, excluding the impact of goodwill amortization, were $14.6 million in 2002, $8.0 million in 2001 and $1.6 million in 2000. The increase in equity earnings in 2002 over 2001 was primarily due to an increase in gathering volumes and the acquisitions made in 2001. The 2001 results included nine months of activity for Gregg Lake/Obed Pipeline. The increase in equity earnings in 2001 over 2000 was primarily due to the acquisitions made in late September 2000. The 2000 results included three months of activity. COAL SLURRY Our coal slurry pipeline segment reported earnings of $4.1 million in 2002 on revenues of $21.5 million. In 2001, excluding the impact of goodwill amortization, the segment reported earnings of $4.9 million on revenues of $22.1 million. In 2000, excluding the impact of goodwill amortization, the segment reported earnings of $3.1 million on revenues of $21.2 million. The 2002 results were impacted by unplanned coal slurry discharges, which increased the segments operations and maintenance expense by $1.1 million over 2001. The 2001 results were impacted by an increase in tons of coal shipped and the repayment of Black Mesa Pipeline's debt in June 2001. Interest expense was $0.7 million in 2001 and $1.7 million in 2000. 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 an extraordinary loss on reacquired debt. Our general and administrative expenses not allocated to any segment were $5.5 million in 2002, $3.1 million in 2001 and $2.3 million in 2000. The amount of general and administrative expenses recorded in each year has increased due to the acquisitions made in 2001 and 2000. Interest expense on our debt was $30.6 million in 2002, $33.1 million in 2001 and $14.6 million in 2000. The decrease in expense for 2002 from 2001 was primarily due to a decrease in interest rates partially offset by an increase in average debt outstanding related to the acquisitions made in 2001. The increase in expense for 2001 from 2000 was primarily due an increase in average debt outstanding related to the acquisitions made in 2001 and 2000. In 2000, we issued $250 million of 8 -7/8% Senior Notes and in 2001, we issued $225 million of 7.10% Senior Notes. Other income (expenses) not allocated to any segment were ($0.1 million) in 2002, ($2.0 million) in 2001 and $0.5 million in 2000. The amount for 2001 included a non-recurring charge of $2.4 million, primarily related to a loss on a forward purchase of Canadian dollars to fund our acquisition of Border Midstream Service's gathering and processing assets. Income from temporary cash investments decreased $0.4 million in 2002 from 2001. 29 The extraordinary loss from debt restructuring of $1.2 million recorded in 2001, 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) 1992 Series D Senior Notes $ 65,000 $ 65,000 $ -- $ -- $ -- 2002 Pipeline Senior Notes due 2007 225,000 -- -- 225,000 -- 1999 Pipeline Senior 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 2002 Pipeline Credit Agreement due 2005 89,000 -- 89,000 -- -- 2001 Partnership Credit Agreement due 2004 35,000 -- 35,000 -- -- Capital Leases (a) 9,953 3,355 6,429 169 -- Operating Leases (b) 15,416 3,112 5,983 4,036 2,285 Other Long-Term Obligations (b) 84,539 11,624 23,279 23,247 26,389 ------------ ------------ ------------ ------------ ------------ Total $ 1,448,908 $ 83,091 $ 159,691 $ 252,452 $ 953,674 ============ ============ ============ ============ ============

(a) See Note 7 - Notes to Consolidated Financial Statements. (b) See Note 11 - Notes to Consolidated Financial Statements. We have guaranteed the performance of our unconsolidated affiliates in connection with their credit agreements that expire in March 2009 and September 2009. Collectively at December 31, 2002, the amount of both guarantees was $4.4 million. Upon closing of the acquisition of Viking Gas Transmission, we agreed to guarantee our ownership share (33%) of Guardian Pipeline's indebtedness. The amount of our guarantee is $60 million. Pursuant to the terms of Guardian Pipeline's debt agreements, the guarantee is removed upon Guardian Pipeline meeting certain conditions, which we expect to occur in the second quarter of 2003. 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 $200 million 30 three-year revolving credit agreement with certain financial institutions ("2001 Partnership Credit Agreement") in March 2001. Both credit agreements replaced prior credit agreements. At December 31, 2002, $89 million was outstanding under the 2002 Pipeline Credit Agreement at an average interest rate of 2.05% and $35 million was outstanding under the 2001 Partnership Credit Agreement at an average interest rate of 2.27%. The 2002 Pipeline Credit Agreement and 2001 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 adjusted for pro forma operating results of acquisitions made during the year) of no more than 4.5 to 1. At December 31, 2002, we were in compliance with these covenants. At December 31, 2002, Northern Border Pipeline had outstanding $65 million of Series D Senior Notes issued in a $250 million private placement under a July 1992 note purchase agreement. The Series D Senior Notes mature in August 2003. Northern Border Pipeline anticipates borrowing under the 2002 Pipeline Credit Agreement to repay the Series D Senior Notes. 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, 2002, the average effective interest rate on Northern Border Pipeline's interest rate swap agreements was 2.70%. 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 31 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. In the third quarter of 2001, we entered into interest rate swap agreements with notional amounts totaling $225 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 swaps were entered into to hedge the fluctuations in the market value of the 2001 Partnership Senior Notes. At December 31, 2002, the average effective interest rate on our interest rate swap agreements was 3.97%. 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. 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 November 2000, we sold 2,156,250 common units. The net proceeds from the sale of common units and the general partners' capital contributions totaled approximately $75.4 million, $172.2 million and $60.7 million in 2002, 2001 and 2000, respectively, and were primarily used to repay indebtedness outstanding. On January 17, 2003, we 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. We financed the acquisition under the 2001 Partnership Credit Agreement. Effective with the closing of the Viking Gas Transmission acquisition, we amended the 2001 Partnership Credit Agreement to increase the ratio of consolidated funded debt to adjusted consolidated EBITDA from no more than 4.50 to 1 to no more than 4.75 to 1 through June 2003 at which time the ratio will revert to 4.50. Short-term liquidity needs will be met by our operating cash flows and through the 2001 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 $243.1 million in 2002, $233.9 million in 2001 and $169.6 million in 2000. The $9.2 million increase from 2001 to 2002 reflects a $3.7 million increase in distributions received from our unconsolidated affiliates. During 32 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. The $64.3 million increase in operating cash flows from 2000 to 2001 was primarily due to our gas gathering and processing businesses acquired in 2001 and in September of 2000. Other cash flows from operating activities for 2001 also included $7.1 million of distributions received from our unconsolidated affiliates as compared to distributions received in 2000 of $0.9 million. Related party payables increased $17.1 million between 2000 and 2001 primarily related to amounts due to Northern Plains and NBP Services Corporation. As discussed in Item 13. "Certain Relationships and Related Transactions," Northern Plains and NBP Services Corporation provide us with administrative and operating services. CASH FLOWS FROM INVESTING ACTIVITIES Cash used in investing activities was $54.4 million in 2002 compared to $482.7 million in 2001 and $258.0 million in 2000. In 2001 and 2000, 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 $49.9 million in 2002, which included $33.7 million for the natural gas gathering and processing segment and $15.7 million for the interstate natural gas pipelines segment. 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. For 2000, our capital expenditures were $19.7 million, which included $15.5 million for interstate natural gas pipeline facilities and $3.8 million for gas gathering and processing facilities. The 2001 and 2000 expenditures for interstate natural gas pipeline facilities included $49.0 million and $7.4 million, respectively, for Northern Border Pipeline's Project 2000. Our cash used in acquisitions was $1.6 million in 2002, as compared to $345.1 million in 2001 and $229.5 million in 2000. 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. In 2000, we acquired gas gathering businesses in the Powder River and Wind River basins in Wyoming. Our investments in unconsolidated affiliates of $3.0 million in 2002 and $11.2 million in 2001 primarily reflect capital contributions to Bighorn. Our investment in 2000 of $8.8 million reflects capital contributions of $11.8 million to Bighorn, net of a $3.5 million payment received from ENA. As part of the terms of the purchase agreement when we acquired gas gathering businesses in 2000, ENA agreed to fund an equity investment in Lost Creek. As discussed previously, we acquired Viking Gas Transmission in January 2003 for approximately $162 million, which 33 included the assumption of $40 million of debt. Total capital expenditures for 2003 are estimated to be $51 million. Capital expenditures for the interstate pipelines are estimated to be $17 million, including approximately $11 million for Northern Border Pipeline. Northern Border Pipeline currently anticipates funding its 2003 capital expenditures primarily by borrowing on debt facilities and using operating cash flows. Capital expenditures for gas gathering and processing facilities are estimated to be $32 million for 2003. Funds required to meet the capital requirements for 2003 are anticipated to be provided from our debt borrowings, issuance of additional limited partnership interests and operating cash flows. CASH FLOWS FROM FINANCING ACTIVITIES Cash flows used in financing activities were $170.8 million for 2002, as compared to cash provided by financing activities of $230.1 for 2001 and $100.8 million for 2000. Our cash distributions to our unitholders and our general partners in 2002, 2001 and 2000 were $147.0 million, $120.9 million and $80.4 million, respectively. The increase in 2002 and 2001 over prior year results is due to both an increase in the number of common units outstanding and an increase in the distribution rate. The distribution paid in each quarter of 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. For 2000, the distribution paid was $0.65 per unit in the first, second and third quarter and $0.70 per unit in the fourth quarter. In 2002, 2001 and 2000, we issued additional partnership interests of $75.4 million, $172.2 million and $60.7 million, respectively, which were primarily used to repay indebtedness outstanding. 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 the 2001 Partnership 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 the 2001 Partnership 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 the 2001 Partnership 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. 34 For 2000, our borrowings on long-term debt were $431.1 million, which were used for both repayments of previously existing indebtedness and to finance a portion of our acquisitions. Issuances of long-term debt included net proceeds from the private offering of the 2000 Partnership Senior Notes of approximately $252.0 million; borrowings under the Partnership's credit agreements of $102.5 million; and borrowings under Northern Border Pipeline's credit agreements of $75.0 million. Total repayments of debt were $304.8 million in 2000. 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 April 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 2000, we received $15.0 million from the termination of interest rate swap agreements entered into in June 2000. Also 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 financial instruments at the date of the adjustment. We used the proceeds to repay amounts borrowed under the 2001 Partnership Credit Agreement. NEW ACCOUNTING PRONOUNCEMENTS In the third quarter of 2001, the Financial Accounting Standards Board SFAS No. 143, "Accounting for Asset Retirement Obligations" and in 2002, the FASB issued SFAS No. 145, "Rescission of FASB Statements No. 4, No. 44 and No. 64, Amendments to FASB Statements No. 13 and Technical Corrections" and SFAS No. 146, "Accounting for Costs Associated with Exit or Disposal Activities." See Note 13 - Notes to Consolidated Financial Statements. UPDATE ON 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. 35 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 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. Factors taken into account by Enron in making its business decisions while in Chapter 11, may include decisions with respect to its investment in Northern Plains and Pan Border, which decisions may affect us. CURRENT EFFECTS 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 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 obligating ENA to pay for 3.5% of Northern Border Pipeline's capacity. Through the proceeding, ENA rejected and terminated all of its contracts on Northern Border Pipeline. Northern Border Pipeline contracted a portion of that capacity with others for varying terms. For 2002, Northern Border Pipeline experienced lost revenues of approximately $1.8 million for ENA's capacity. Northern Border Pipeline has claims against ENA for damages for breach of contract and other claims. In addition, Bear Paw Energy has claims against ENA relating to terminated hedge transactions. In accordance with SFAS No. 133, Bear Paw Energy ceased to account for these swap agreements as hedges. 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 2002, Bear Paw Energy recorded approximately $4.6 million in earnings related to the terminated hedges. Also, Crestone Energy Ventures has claims against ENA for unpaid gas gathering and administrative services fees. We have filed claims against ENA's bankruptcy estate related to these agreements. These claims will likely be deemed to be unsecured claims against certain of the Enron related Chapter 11 companies. 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 36 such delay in collecting or failure to collect will not have a material adverse effect on our financial condition, and any amounts collected will not be material to us. Northern Plains and NBP Services have advised us that under the Operating Agreements with Northern Plains and the Administrative Services Agreement with NBP Services, increased costs may be incurred for health care expenses and pension benefits. Such costs are projected to increase as a result of actual medical claims experience, pension investment returns and effects of the Enron bankruptcy filing. While the determination of reimbursement of such costs by us under the appropriate agreement will be made at the time of occurrence, we estimate an increase of $6 million over 2002 levels. 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 "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 Plan, that Enron had made the determination to begin necessary steps to partition the assets of the Trust and the related liabilities of the 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. Enron management has advised that it intends to seek bankruptcy court approval for the termination of the Trust and for the participating employers to establish a separate trust adequate to receive the assets. On May 2, 2002, Enron presented to the creditors' committee a proposal under which specified core energy assets of Enron would be separated from Enron's bankruptcy estate and operated prospectively as a new integrated power and pipeline company. On August 27, 2002, Enron announced that it had commenced a formal sales process for its interests in certain major assets, including Northern Plains, Pan Border and NBP Services. However, on March 19, 2003, Enron announced that its Board of Directors had voted to move forward with the creation of a new pipeline operating entity rather than sell its interests in its North American pipelines. This new company, temporarily referred to as "PipeCo", will include Northern Plains, Pan Border and NBP Services. Enron's announcement also stated that Enron expects PipeCo to be governed by an independent board of directors and afforded protection from joint and several Enron group liabilities and that upon resolution of Enron's Chapter 11 bankruptcy case, it anticipates that shares of PipeCo will be distributed to creditors in connection with the Plan of Reorganization. Enron also stated that it is evaluating the potential sale of a minority interest in PipeCo. The formation of PipeCo will require various Enron Board, bankruptcy court and other regulatory approvals, as well as the consent of the Enron's Official Unsecured Creditors' Committee. 37 Enron's filing for bankruptcy protection and related developments have had other impacts on our business and management. Arthur Andersen LLP resigned in early 2002 as our auditors, and we retained KPMG LLP as our new auditors. Enron has received several requests for information from different agencies and committees of the United States House of Representatives and Senate. Some of the information requested from Enron may include information about us. In addition, we are aware that the Senate Committee on Governmental Affairs has issued a subpoena to Enron requesting documents disclosing Enron's communications with the SEC and the FERC, as well as information on compensation matters. As a result of Enron's indirect ownership interest in us, we have been asked to comply with the mandate of the subpoena in such a manner that may be determined by the Committee on Governmental Affairs of the Senate of the United States. POSSIBLE EFFECTS 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 Northern Border Partners. 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. If Northern Plains and Pan Border were to file for bankruptcy relief, our Partnership Agreement provides that they would automatically be deemed to have withdrawn as general partners of the Partnership. It is possible that the enforceability of the automatic withdrawal provisions in this partnership agreement may be challenged. The success and impact of a challenge are unknown. Upon the occurrence of such an event of withdrawal, the remaining general partner has the right to purchase the withdrawing partners' general partnership interests. If the remaining general partner does not purchase such general partnership interests, the limited partners have the right to elect new general partners. In the event that the remaining general partner does not elect to purchase the general partner interests or a successor is not so elected by the limited partners, then the partnership shall be dissolved. The 2001 Partnership Credit Agreement provides that it will be a change of control (and consequently an event of default) thereunder if subsidiaries of Enron and The Williams Companies do not control, free of any liens, greater than 50% of general partner percentages. The Williams Companies sold the stock of Northwest Border Pipeline Company to TransCanada. Consequently, if Enron sells the stock of Northern Plains and Pan Border or causes such companies to file for bankruptcy relief, the Partnership will be in default under the 2001 Partnership Credit Agreement. In addition, the agreements evidencing the Partnership's other material outstanding debt 38 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 is 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 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. OUTLOOK 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 would be supported by long-term contracts. We are currently working 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. In addition, Midwestern Gas Transmission's recently completed Joliet Compression Project provides the opportunity 39 to deliver gas directly into Northern Border Pipeline, increasing natural gas market liquidity between the pipeline systems and enhancing transportation demand for both pipelines. Furthermore, Midwestern Gas Transmission will pursue serving additional power plants under development in southwest Indiana and new delivery interconnects with other interstate pipelines to grow transportation revenues. We also intend to continue to expand the marketing of new services to meet our customers' needs. Northern Border Pipeline and Midwestern Gas Transmission have begun contract extension discussions with customers for contracts that will expire prior to November 1, 2003. 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, the relationship between gas prices in Canada and prices in the midwestern U.S. markets will determine the underlying value of transportation. This relationship, and natural gas markets overall, has been volatile, which is also an important factor in contracting for firm transportation capacity. Under Northern Border Pipeline's FERC tariff, it may concurrently solicit bids for available capacity from other parties subject to the existing customer's rights to match the best offer. During 2002, after completion of this process, Northern Border Pipeline received only bids to extend service from mid-September 2003 to October 31, 2003 and all other existing customers' rights to match an offer were terminated. Northern Border Pipeline is now in a position to contract with interested parties on a first come, first served basis. Based on current conditions, contracts for service on Northern Border Pipeline may require discounts from maximum transportation rates established in its tariff and shorter duration than its existing contract portfolio. Additionally, Northern Border Pipeline may enter into negotiated rate contracts involving charges established on the basis of Canadian-midwestern U.S. gas price differentials or other factors. Regarding Midwestern Gas Transmission, an agreement has been reached with its largest shipper, Northern Illinois Gas Company, to extend its negotiated rate contract for a three year term subject to regulatory approval and upstream capacity arrangements. In February 2003, Northern Border Pipeline filed to amend the definition of company use gas, which is gas supplied by our shippers for our operations, to clarify the language by adding detail to the broad categories that comprise company use gas (See Item 1. "Business - FERC Regulation"). Relying upon the currently effective version of the tariff, Northern Border Pipeline included in its collection of company use gas, quantities that were equivalent to the cost of electric power at its electric-driven compressor stations, resulting in cost savings of approximately $8 million annually. Pending the final outcome of this FERC proceeding, we may not realize electric power cost savings to the same extent for 2003. 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 40 basins. During 2002, the pricing of gas produced from the Powder River Basin was depressed due to capacity constraints on pipelines to market hubs. We expect to see continued build-out of our gathering systems within the areas of acreage dedications we have secured, particularly in the Powder River Basin. Depending on the pace of production development, producer response to the basin-wide EIS and water-discharge permitting, we expect 10 to 15 percent growth in aggregate gathered volumes on our Powder River systems (Bear Paw Energy, Bighorn and Fort Union) during 2003. We expect growth in gas volumes for our pipelines and plants in the Wind River, Williston and western Canadian sedimentary basins to be more modest, reflecting prospects for drilling activity within these production areas. 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 some further improvement in cost efficiencies. Also, our ownership in Bighorn includes preferred A units, which effectively provide an incentive mechanism tied to the number of wells connected to the system. Whether such targets have been met is under discussion. Resolution of this matter, as expected, would result in income between $4 and $7 million for 2003. 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. 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. 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: o the discussions in "Management's Discussion and Analysis of Financial Condition and Results of Operations - Update On The Impact Of Enron's Chapter 11 Filing On Our Business"; 41 o the discussions in "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Outlook"; and o 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: o The war with Iraq, increasing military tension with regard to North Korea, as well as the terrorist attacks of September 11, 2001 and subsequent unrest, have caused instability in the world's financial and commercial markets and have contributed to volatility in prices for natural gas. In addition, since the September 11, 2001 attacks, the United States government has issued warnings that energy assets, including our nation's pipeline infrastructure, may be a target of future terrorist attacks. o 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. o 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. Most recently, Enron announced its intention to create a new pipeline operating entity, which will include Northern Plains, Pan Border and NBP Services. See "Update on The Impact Of Enron's Chapter 11 Filing On Our Business - Possible Effects" above. o Contracts on Northern Border Pipeline and Midwestern Gas Transmission will expire prior to November 1, 2003. On Northern Border Pipeline, those contracts represent approximately 42% 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 "Outlook" 42 above and Item 1. "Business - Interstate Pipelines - Demand For Transportation Capacity." o 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 challenges our interstate pipelines may have to their rates in the future. See Item 1. "Business - Interstate Pipelines - FERC Regulation." o 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. o 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." o 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." o 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, have held settlement discussions and have reached a settlement in principle on the pipeline right-of-way lease and taxation issues, subject to final documentation and necessary governmental approvals. 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. o 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 significant costs and expenses for employee related matters, write off of recorded goodwill and removal of certain facilities. o 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. 43 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. o Our ability to 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, producer response to the recently issued EIS, 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." o 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. o 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 impact the market value of our common units. See "Debt and Credit Facilities and Issuance of Common Units" above. o 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. o 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 44 substantially reduced. In addition, the entire amount of cash received by each unitholder would generally be taxed as a corporate dividend when received. o On January 7, 2003, the Bush Administration released a proposal that would exclude certain corporate dividends from an individual's federal taxable income. Enactment of legislation reducing or eliminating the federal income tax on corporate dividends may cause certain investments to be more attractive to individual investors than an investment in our units. We cannot predict whether the proposal will ultimately be enacted into law or if enacted, the potential impact on the market for our units. 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 operational results. ITEM 7a. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK 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, 2002, we had $574.0 million of variable rate debt outstanding, $450.0 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, 2002, approximately 57% 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, 2002, consolidated annual interest expense would change by approximately $5.7 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, 2002. 45 COMMODITY PRICE RISK Our gas gathering and processing businesses are subject to certain contracts that give them 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 2003. We have hedged 70% to 75% of our commodity price risk in 2003. ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA The information required hereunder is included in this report as set forth in the "Index to Financial Statements" on page F-1. ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE None. 46 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 has authority and responsibility for selecting our independent auditors, reviewing our annual audit and resolving accounting policy questions. 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 Corporation, 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. The Chairman of the Audit Committee receives an annual fee of $50,000 and other Audit Committee members receive an annual fee of $40,000 and each is paid $1,500 for each meeting attended. As a result of the purchase by TransCanada of the general partner interest held by Williams, effective August 2002, Paul MacGregor was designated by TransCanada as its member on the Partnership Policy Committee and one of our representatives on the Northern Border Management Committee, replacing James C. Moore. There are no family relationships between any of our executive officers or members of the Partnership Policy and Audit Committees. 47

NAME AGE POSITIONS ---- --- --------- Executive Officers: William R. Cordes 54 Chief Executive Officer Jerry L. Peters 45 Chief Financial and Accounting Officer Members of Partnership Policy Committee and Partnership's representatives on Northern Border Management Committee: William R. Cordes 54 Chairman Stanley C. Horton 53 Member Paul F. MacGregor 45 Member Members of Audit Committee: Daniel P. Whitty 71 Chairman Gerald B. Smith 52 Member Gary N. Petersen 51 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 Chairman and Chief Executive Officer of Enron Global Services, and has held that position since August 2001. 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. On May 1, 2001, Mr. Horton became a member of the Board of Directors of Portland General Electric. Mr. Horton also holds the elected position of officer and/or director of the following Enron companies that have filed for Chapter 11 bankruptcy protection: Calypso Pipeline, L.L.C. (Director, President and Chief Executive Officer) Enron Transportation Services Company (Chairman, President and Chief Executive Officer and Director) Enron Wind Corp.(n/k/a Enron Wind LLC) (Chairman and Director until April 19, 2002) Enron Wind Systems, Inc.(n/k/a Enron Wind Systems, LLC) (Director until April 19, 2002) 48 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) Zond Pacific, LLC (Chairman until September 25, 2002) In August 2002, TransCanada designated Paul MacGregor as its member on the Partnership Policy Committee. Mr. MacGregor is also TC PipeLines' alternate representative on the Northern Border Management Committee. Additionally, Mr. MacGregor serves as the Vice President, Eastern Business Development, TransCanada, a position he has held since September 1999 and as Vice President, Business Development, of the general partner of TC PipeLines, a position he has also held since April 1999. From July 1998 to September 1999, Mr. MacGregor was Vice-President, North American Pipeline Investments for TransCanada's Transmission division. From 1997 until July 1998, he was Vice-President, Alberta Natural Gas Company Ltd. (energy services), a former subsidiary of TransCanada that has since amalgamated into TransCanada. Mr. MacGregor started his career with TransCanada in 1981 and has held various other positions in the Facilities Planning and Evaluations, Finance and Operations Group. 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. 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. 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 has served as a director of Pennzoil-Quaker States since December 1998 and is a member of the Audit Committee and Executive Committee of its board. He is a director of: Charles Schwab Family of Funds, Cooper Industries, and Rorento N.V. (Netherlands). From 1988 to 1990, he served as Senior Vice President and Director of Fixed Income and Chairman of the Executive Committee of Underwood Neuhaus & Co. 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 49 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. 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 2002 our reporting persons complied with all applicable filing requirements in a timely manner. 50 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 LTIP Other Annual Stock Awards Options/ Payouts Name & Position Year Salary(1) Bonus(2) Compensation(3) ($)(4)(5) SARs(#) ($)(6) ($)(7) ------------------- ---- ------------ ------------ --------------- ------------ ------------ ------------ ------------ William R. Cordes 2002 $ 319,333 $ 250,000 $ -- $ 100,051 -- $ -- $ 1,031 Chief Executive 2001 $ 312,000 $ 250,000 $ 8,550 $ 227,150 6,475 $ 300,000 $ 255 Officer 2000 $ 311,000 $ 250,000 $ 15,000 $ 137,529 17,405 $ 131,250 $ 13,110 Jerry L. Peters 2002 $ 159,285 $ 156,250 $ -- $ -- -- $ -- $ 23,950 Chief Financial and 2001 $ 154,292 $ 125,000 $ 3,399 $ 75,063 7,085 $ -- $ 198 Accounting Officer 2000 $ 145,293 $ 110,000 $ 3,708 $ 75,036 15,040 $ -- $ 10,091

(1) Mr. Cordes was appointed President of Northern Plains and Chief Executive Officer of the Partnership on October 1, 2000. (2) 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 1,450 units in 2000 and 842 units in 2001. In each case, units will be released to both five years following the grant date. (3) 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 2000 and 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 2000 and 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 2000 and 2001. (4) The aggregate total of shares in unreleased Enron restricted stock holdings and their values as of December 31, 2002, for each of the Named Officers is: Mr. Cordes, 4,295 shares valued at $258, and Mr. Peters, 1,701 shares valued at $102. 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. (5) 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, an additional grant of 697 Northern Border Phantom Units valued at $143.5456 per unit was made in accordance with his employment agreement. The phantom units vest 100% on the fifth anniversary of the date of the grant. (6) Reflects cash payments under the Enron Corp. Performance Unit Plan in 2000 for the 1996-1999 period and 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 1996-1999 performance period rendered a value of $1.50 based on a ranking of second as compared to 11 industry peers. Its performance over the 1997-2000 performance period rendered a value of $2.00 based on a ranking of first. 51 (7) The amounts shown include the value of Enron Common Stock allocated to employees' special subaccounts under Enron's Employee Stock Ownership Plan, matching contributions to employees' Enron Corp. Savings Plan, and imputed income on life insurance benefits. Mr. Peters' employment agreement, as executed in April, 2002, provided for a "stay" bonus in which $23,950 of the amount was paid six months following the implementation of the agreement. The remaining amount of $71,853 will be paid upon completion of the term of the agreement. STOCK OPTION GRANTS DURING 2002 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 2002. AGGREGATED STOCK OPTION/SAR EXERCISES DURING 2002 AND STOCK OPTION/SAR VALUES AS OF DECEMBER 31, 2002 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 Options/SARs at In-the-Money Options/SARs Shares December 31, 2002 December 31, 2002 (1) Acquired on Value --------------------------- --------------------------- Name Exercise(#) Realized Exercisable Unexercisable Exercisable Unexercisable ----------------- ------------ ------------ ------------ ------------- ------------ ------------- William R. Cordes -- $ -- 232,936 11,664 $ -- $ -- Jerry L. Peters -- $ -- 63,429 4,156 $ -- $ --

(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, 2002 ($0.06) 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 also maintains 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. 52 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 payable under normal retirement at age 65, assuming current remuneration levels without any salary or bonus projections and participation until normal retirement at age 65, with respect 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 32.4 44.1 $200,000 $74,023 Mr. Peters 17.9 38.8 $159,671 $22,780

-------- 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. 53 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, 2003 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/ 15,000 * 1400 Smith Street Houston, TX 77002-7369 Gary N. Petersen 5,679 * 3520 Wedgewood Ln. N Plymouth, MN 55441-2262 Enron Corp. 2/ 3,210,042 7.3 1400 Smith Street Houston, TX 77002

-------------- * 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 500,042 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 54 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: o Northern Plains, a subsidiary of Enron, which has not filed for bankruptcy protection, provides certain administrative, operating and management services to the Partnership. For the year ended December 31, 2002, the aggregate amount charged by Northern Plains for its services was approximately $29.1 million. o NBP Services, a subsidiary of Enron that is not in bankruptcy, 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, 2002, the aggregate amount charged by NBP Services for its services was approximately $16.2 million. o ENA holds a contract for firm transportation on Midwestern Gas Transmission. At present, ENA has not assumed or rejected the contracts on Midwestern Gas Transmission. ENA's ability to utilize its capacity has been suspended until ENA provides adequate assurances of credit support and payment. Midwestern Gas Transmission's ability to terminate ENA's contract is stayed as a result of the bankruptcy court proceedings. See Item 7. "Management's Discussion and Analysis of Financial Condition and Results of Operations - Update on The Impact Of Enron's Chapter 11 Filing On Our Business." 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 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 Company whose general partner is an affiliate of one of our general partners) and its affiliates also actively engage in interstate pipeline transportation of 55 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 Company 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: o 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. o 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. o 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. o 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. o Our Audit Committee will, at the request of a general partner or a member of the Partnership Policy Committee, review conflicts of interest that may arise between a general partner and its affiliates (or the member of the Partnership Policy Committee designated by it), on the one hand, and the unitholders or us, on the other. Any resolution of a conflict approved by the Audit Committee is conclusively deemed fair and reasonable to us. o 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 56 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. 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)-14(c) 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. 57 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). 58 *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 Note Purchase Agreement between Northern Border Pipeline Company and the parties listed therein, dated July 15, 1992 (Exhibit 10.6 to Form S-1). *10.8 Supplemental Agreement to the Note Purchase Agreement dated as of June 1, 1995 (Exhibit 10.6.1 to the Partnership's Annual Report on Form 10-K for the year ended December 31, 1995 ("1995 10-K")). *10.9 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 Borders Partners, L.P.'s Current Report on Form 8-K dated June 26, 2002). *10.10 Revolving Credit Agreement, dated as of March 21, 2001, between Northern Border Partners, L.P., SunTrust Bank, Administrative Agent, Bank of Montreal and Bank of America, N.A., Co-Syndication Agents and Bank One, NA, Documentation Agent and Lenders (as defined therein)(Exhibit 10.20 to Northern Border Partners, L.P. Form 10-K for the year ended December 31, 2000 ("2000 10-K")). *10.11 Northern Border Pipeline Company U.S. Shippers Service Agreement between Northern Border Pipeline Company and Pan-Alberta Gas (US) Inc., dated October 1, 1993, with Amended Exhibit A effective June 22, 1998 (Exhibit 10.36 to Northern Border Pipeline Company Annual Report on Form 10-K for the year ended December 31, 1999 ("NB Pipeline 1999 10-K")). *10.12 Northern Border Pipeline Company U.S. Shippers Service Agreement between Northern Border Pipeline Company and Pan-Alberta Gas (US) Inc.,(successor to Natgas U.S. Inc.) dated October 6, 1989, with Amended Exhibit A effective April 2, 1999 (Exhibit 10.37 to NB Pipeline 1999 10-K). *10.13 Northern Border Pipeline Company U.S. Shippers Service Agreement between Northern Border Pipeline Company and Pan-Alberta Gas (U.S.) Inc., dated October l, 1992, with Amended Exhibit A effective June 22, 1998 (Exhibit 10.38 to NB Pipeline 1999 10-K). *10.14 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). *10.15 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). *10.16 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). 59 *10.17 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 Partner, L.P.'s Form 10-K for year ended December 31, 2001). 10.18 Operating Agreement between Viking Gas Transmission Company and Northern Plains Natural Gas Company dated as of January 17, 2003. *10.19 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")). *16.1 Letter of Arthur Andersen LLP, former auditors of Northern Border Partners, L.P. dated February 11, 2002 (Exhibit 99.3 to Northern Border Partners, L.P's Form 8-K filed on February 13, 2002). 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. *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). 99.2 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. 99.3 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. *Indicates exhibits incorporated by reference as indicated; all other exhibits are filed herewith. (b)REPORTS The Partnership filed a Current Report on Form 8-K, dated October 2, 2002 reporting the re-audit of 1999 and 2000 financial statements by KPMG LLP and an amendment to update Items 10 and 13 of the Form 10-K for the year ended 2001 as a result of the purchase by TransCanada PipeLines Limited of the general partner interest formerly owned by The Williams Companies. The Partnership filed a Current Report on Form 8-K, dated November 8, 2002 reporting a press release dated November 8, 2002 announcing the execution of a definitive agreement to purchase Viking Gas Transmission Company, including a one-third interest in Guardian Pipeline. The Partnership filed a Current Report on Form 8-K, dated December 9, 2002, pursuant to Item 9 of that form, including a press release announcing a presentation to be made by the Chairman and Chief Executive Officer at the Wachovia Pipeline Conference on December 10, 2002. The Partnership filed a Current Report on Form 8-K, dated December 11, 2002, reporting receipt of a letter from the United States Environmental Protection Agency demanding payment of $176,000 in stipulated penalties. 60 SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized on this 28th day of March, 2003. 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 28, 2003 ------------------------------------ Chairman of the Partnership William R. Cordes Policy Committee (Principal Executive Officer) /s/ STANLEY C. HORTON Member of Partnership Policy March 28, 2003 ------------------------------------ Committee Stanley C. Horton /s/ PAUL F. MACGREGOR Member of Partnership Policy March 28, 2003 ------------------------------------ Committee Paul F. MacGregor /s/ JERRY L. PETERS Chief Financial and March 28, 2003 ------------------------------------ Accounting Officer Jerry L. Peters

61 CERTIFICATION PURSUANT TO RULE 13-A OR 15d-14 OF THE SECURITIES EXCHANGE ACT OF 1934, AS ADOPTED PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002 I, William R. Cordes, certify that: 1. I have reviewed this annual report on Form 10-K of Northern Border Partners, L.P.; 2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report; 3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report; 4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have: a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared; b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the "Evaluation Date"); and c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date; 5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation, to the registrant's auditors and audit committee of registrant's board of directors (or persons performing the equivalent function): a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and 6. The registrant's other certifying officer and I have indicated in this annual report whether or not there are significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses. Date: March 28, 2003 /s/ William R. Cores --------------------------------- William R. Cordes Chief Executive Officer 62 CERTIFICATION PURSUANT TO RULE 13-A OR 15d-14 OF THE SECURITIES EXCHANGE ACT OF 1934, AS ADOPTED PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002 I, Jerry L. Peters, certify that: 1. I have reviewed this annual report on Form 10-K of Northern Border Partners, L.P.; 2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report; 3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report; 4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have: a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared; b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the "Evaluation Date"); and c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date; 5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation, to the registrant's auditors and audit committee of registrant's board of directors (or persons performing the equivalent function): a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and 6. The registrant's other certifying officer and I have indicated in this annual report whether or not there are significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses. Date: March 28, 2003 /s/ Jerry L. Peters -------------------------------- Jerry L. Peters Chief Financial and Accounting Officer 63 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, 2002 and 2001 F-3 Consolidated Statement of Income - Years Ended F-4 December 31, 2002, 2001 and 2000 Consolidated Statement of Comprehensive Income - Years Ended F-4 December 31, 2002, 2001 and 2000 Consolidated Statement of Cash Flows - Years Ended F-5 December 31, 2002, 2001 and 2000 Consolidated Statement of Changes in Partners' Equity - F-6 Years Ended December 31, 2002, 2001 and 2000 Notes to Consolidated Financial Statements F-7 through F-32 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, 2002 and 2001, 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, 2002. 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, 2002 and 2001, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2002, in conformity with accounting principles generally accepted in the United States of America. As discussed in note 4 to the consolidated financial statements, Northern Border Partners, L.P. and Subsidiaries adopted the provisions of Statement of Financial Accounting Standards (SFAS) No. 142, Goodwill and Other Intangibles. KPMG LLP January 23, 2003 Omaha, Nebraska F-2 NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEET (IN THOUSANDS)

DECEMBER 31, ------------------------------- 2002 2001 ------------ ------------ ASSETS CURRENT ASSETS Cash and cash equivalents $ 34,689 $ 16,755 Accounts receivable (net of allowance for doubtful accounts of $1,964 in 2001) 55,358 49,285 Related party receivables (net of allowance for doubtful accounts of $12,392 and $8,779 in 2002 and 2001, respectively) 70 455 Materials and supplies, at cost 5,252 5,584 Other 9,477 6,572 ------------ ------------ Total current assets 104,846 78,651 ------------ ------------ PROPERTY, PLANT AND EQUIPMENT Interstate Natural Gas Pipelines 2,471,627 2,466,427 Gas Gathering and Processing 354,652 320,603 Coal Slurry 43,092 42,661 ------------ ------------ Total property, plant and equipment 2,869,371 2,829,691 Less: Accumulated provision for depreciation and amortization 854,091 789,592 ------------ ------------ Property, plant and equipment, net 2,015,280 2,040,099 ------------ ------------ INVESTMENTS AND OTHER ASSETS Investment in unconsolidated affiliates 244,515 239,729 Goodwill 295,848 295,402 Derivative financial instruments 36,885 9,635 Other 28,121 23,839 ------------ ------------ Total investments and other assets 605,369 568,605 ------------ ------------ Total assets $ 2,725,495 $ 2,687,355 ============ ============ LIABILITIES AND PARTNERS' EQUITY CURRENT LIABILITIES Current maturities of long-term debt $ 67,765 $ 352,395 Accounts payable 30,584 20,434 Related party payables 25,927 18,812 Accrued taxes other than income 31,108 28,730 Accrued interest 16,742 20,550 Derivative financial instruments 4,095 -- ------------ ------------ Total current liabilities 176,221 440,921 ------------ ------------ LONG-TERM DEBT, net of current maturities 1,335,978 1,070,832 ------------ ------------ MINORITY INTERESTS IN PARTNERS' EQUITY 242,931 250,078 ------------ ------------ RESERVES AND DEFERRED CREDITS 26,330 10,566 ------------ ------------ COMMITMENTS AND CONTINGENCIES (NOTE 11) PARTNERS' EQUITY Partners' capital 936,521 894,429 Accumulated other comprehensive income 7,514 20,529 ------------ ------------ Total partners' equity 944,035 914,958 ------------ ------------ Total liabilities and partners' equity $ 2,725,495 $ 2,687,355 ============ ============

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, ---------------------------------------------------- 2002 2001 2000 ------------ ------------ ------------ OPERATING REVENUES Operating revenues $ 495,617 $ 463,526 $ 363,688 Provision for rate refunds -- (2,057) (23,956) ------------ ------------ ------------ Operating revenues, net 495,617 461,469 339,732 ------------ ------------ ------------ OPERATING EXPENSES Product purchases 50,648 39,699 -- Operations and maintenance 111,668 96,449 62,097 Depreciation and amortization 75,874 76,310 60,699 Taxes other than income 32,446 28,052 28,634 ------------ ------------ ------------ Operating expenses 270,636 240,510 151,430 ------------ ------------ ------------ OPERATING INCOME 224,981 220,959 188,302 ------------ ------------ ------------ INTEREST EXPENSE Interest expense 83,227 91,653 81,881 Interest expense capitalized (329) (1,745) (386) ------------ ------------ ------------ Interest expense, net 82,898 89,908 81,495 ------------ ------------ ------------ OTHER INCOME Allowance for equity funds used during construction 248 947 305 Equity earnings (losses) of unconsolidated affiliates 14,570 1,697 (647) Other income (expense), net (409) (2,558) 8,374 ------------ ------------ ------------ Other income 14,409 86 8,032 ------------ ------------ ------------ MINORITY INTERESTS IN NET INCOME 42,816 42,138 38,119 ------------ ------------ ------------ NET INCOME BEFORE EXTRAORDINARY ITEMS 113,676 88,999 76,720 EXTRAORDINARY LOSS FROM DEBT RESTRUCTURING -- (1,213) -- ------------ ------------ ------------ NET INCOME TO PARTNERS $ 113,676 $ 87,786 $ 76,720 ============ ============ ============ NET INCOME PER UNIT (NOTE 12) $ 2.44 $ 2.12 $ 2.50 ============ ============ ============ NUMBER OF UNITS USED IN COMPUTATION 42,709 38,538 29,665 ============ ============ ============

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

YEAR ENDED DECEMBER 31, ---------------------------------------------------- 2002 2001 2000 ------------ ------------ ------------ Net income to partners $ 113,676 $ 87,786 $ 76,720 Other comprehensive income: Transition adjustment from adoption of SFAS No. 133 -- 22,183 -- Change associated with current period hedging transactions (13,490) (1,100) -- Change associated with current period foreign currency translation 475 (554) -- ------------ ------------ ------------ Total comprehensive income $ 100,661 $ 108,315 $ 76,720 ============ ============ ============

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

YEAR ENDED DECEMBER 31, ---------------------------------------------------- 2002 2001 2000 ------------ ------------ ------------ CASH FLOWS FROM OPERATING ACTIVITIES: Net income to partners $ 113,676 $ 87,786 $ 76,720 ------------ ------------ ------------ Adjustments to reconcile net income to partners to net cash provided by operating activities: Depreciation and amortization 76,239 76,675 61,054 Minority interests in net income 42,816 42,138 38,119 Non-cash (gains) losses from risk management activities (4,509) 5,304 -- Provision for rate refunds -- 2,036 25,082 Rate refunds paid -- (6,762) (22,673) Equity earnings in unconsolidated affiliates (14,570) (1,697) 647 Distributions received from unconsolidated affiliates 10,820 7,083 933 Allowance for equity funds used during construction (248) (947) (305) Reserves and deferred credits 9,976 119 (4,801) Changes in components of working capital 8,806 20,677 (2,279) Other 136 1,536 (2,882) ------------ ------------ ------------ Total adjustments 129,466 146,162 92,895 ------------ ------------ ------------ Net cash provided by operating activities 243,142 233,948 169,615 ------------ ------------ ------------ CASH FLOWS FROM INVESTING ACTIVITIES: Capital expenditures for property, plant and equipment, net (49,874) (126,414) (19,721) Acquisition of businesses (1,561) (345,074) (229,505) Investments in unconsolidated affiliates and other (2,972) (11,197) (8,766) ------------ ------------ ------------ Net cash used in investing activities (54,407) (482,685) (257,992) ------------ ------------ ------------ CASH FLOWS FROM FINANCING ACTIVITIES: Cash distributions General and limited partners (146,960) (120,884) (80,411) Minority Interests (49,238) (42,910) (40,471) Issuance of partnership interests, net 75,376 172,222 60,696 Issuance of long-term debt, net 499,894 863,103 431,148 Retirement of long-term debt (567,540) (604,929) (304,817) Increase (decrease) in bank overdrafts -- (22,437) 22,437 Proceeds (payments) upon termination of derivatives 20,551 (8,417) 15,005 Long-term debt financing costs (2,884) (5,619) (2,774) ------------ ------------ ------------ Net cash provided by (used in) financing activities (170,801) 230,129 100,813 ------------ ------------ ------------ NET CHANGE IN CASH AND CASH EQUIVALENTS 17,934 (18,608) 12,436 Cash and cash equivalents-beginning of year 16,755 35,363 22,927 ------------ ------------ ------------ Cash and cash equivalents-end of year $ 34,689 $ 16,755 $ 35,363 ============ ============ ============ Changes in components of working capital: Accounts receivable $ (5,688) $ 6,493 $ (8,502) Materials and supplies and other (2,573) (4,937) (1,313) Accounts payable 18,497 14,321 4,755 Accrued taxes other than income 2,378 (115) 1,686 Accrued interest (3,808) 4,915 (1,973) Over/under recovered cost of service -- -- 3,068 ------------ ------------ ------------ Total $ 8,806 $ 20,677 $ (2,279) ============ ============ ============

The accompanying notes are an integral part of these consolidated financial statements. F-5 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, 1999 $ 10,305 $ 504,964 $ -- $ 515,269 Net income to partners 2,566 74,154 -- 76,720 Issuance of partnership interests, net 1,214 59,482 -- 60,696 Distributions paid (2,640) (77,771) -- (80,411) ------------ ------------ ------------ ------------ 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 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 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 ============ ============ ============ ============

The accompanying notes are an integral part of these consolidated financial statements. F-6 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) and Black Mesa Pipeline, Inc. (Black Mesa) are wholly-owned subsidiaries of the Partnership. As discussed in Note 17, the Partnership acquired all of the common stock of Viking Gas Transmission Company (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 (TransCanada) 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 6.2% limited partner interest in the Partnership at December 31, 2002 (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, 2002, 2001 and 2000, charges from NBP Services and its affiliates totaled approximately $16.2 million, $15.3 million and $3.5 million, respectively. See Note 16 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%, respectively, of the voting interest on the Northern Border Pipeline Management Committee. The representative designated by TC PipeLines votes the remaining 30% interest. F-7 NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 1. ORGANIZATION AND MANAGEMENT (continued) 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. The day-to-day management of Northern Border Pipeline's and Midwestern Gas Transmission's affairs is the responsibility of Northern Plains, as defined by their respective operating agreements with Northern Plains. Northern Border Pipeline and Midwestern 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 and Midwestern Gas Transmission. For the years ended December 31, 2002, 2001 and 2000, Northern Plains' and its affiliates' charges to Northern Border Pipeline and Midwestern Gas Transmission totaled approximately $29.1 million, $31.5 million and $31.7 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 90 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 a minority interest in the Gregg Lake/Obed Pipeline (see Note 3). The Mazeppa and Gladys plants, which are located near Calgary, Alberta, have a combined capacity of 87 million cubic feet per day. The Gregg Lake/Obed Pipeline system, which is located near Edmonton, Alberta, is comprised of 85 miles of gathering lines. 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); and a 35% interest in Lost Creek Gathering, L.L.C. (Lost Creek). The Partnership acquired its interests in Fort Union, Lost Creek and a portion of Bighorn in September 2000 (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. F-8 NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 1. ORGANIZATION AND MANAGEMENT (continued) 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 items have been eliminated in consolidation. The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. (B) Government Regulation Northern Border Pipeline and Midwestern Gas Transmission are subject to regulation by the Federal Energy Regulatory Commission (FERC). Northern Border Pipeline'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 continually assesses whether the recovery of the regulatory assets is probable by considering such factors as regulatory changes and the impact of competition. Northern Border Pipeline believes the recovery of the existing regulatory assets is probable. If future recovery ceases to be probable, Northern Border Pipeline would be required to write off the regulatory assets at that time. At December 31, 2002 and 2001, Northern Border Pipeline has reflected regulatory assets of approximately $10.5 million and $11.5 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. 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 F-9 NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued) (B) Government Regulation (continued) 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 $343 million and $336 million at December 31, 2002 and 2001, 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 and Midwestern 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. Northern Border Pipeline and Midwestern Gas Transmission do not own the gas that they transport, and therefore do not assume the related natural gas commodity risk. For the gas gathering and processing businesses, operating revenue is recorded when gas is processed in or transported through company facilities. 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. F-10 NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued) (E) Income Taxes (continued) The Partnership's corporate subsidiaries are required to pay federal and state income taxes. Deferred income tax assets and liabilities are recognized by these entities for temporary differences between the assets and liabilities for financial reporting and tax purposes. The amount of income taxes recorded for these entities is presently not material to the Partnership's financial position or results of operations. (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. 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 transmission plant was 2.25%. Midwestern Gas Transmission applied a 1.9% depreciation rate to its transmission plant. Composite rates are applied to all other functional groups of utility property having similar economic characteristics. The effective depreciation rate applied to gas gathering and processing assets ranges from 3.33% to 20%. The effective depreciation rate applied to coal slurry assets ranges from 3.1% to 14.3%. (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 are recorded in income. (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 F-11 NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued) (H) Goodwill (continued) straight-line method over 30 years. During 2001 and 2000, respectively, the Partnership recorded amortization expense of $6.3 million and $2.2 million related to its investments in unconsolidated affiliates, which is reflected as a component of equity earnings (losses) 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 (losses). For the Partnership's consolidated affiliates, during 2001 and 2000, the Partnership recorded amortization expense of $7.0 million and $0.5 million, respectively. This amortization expense is reflected as a component of depreciation and amortization in the consolidated statement of income. (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. F-12 NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 3. BUSINESS ACQUISITIONS Pursuant to a 1999 purchase agreement, in June 2000, the Partnership purchased 80% of the preferred A shares outstanding of Bighorn for approximately $20.8 million. In September 2000, the Partnership purchased interests in gas gathering businesses in the Powder River and Wind River basins in Wyoming from Enron North America Corp. (ENA), a subsidiary of Enron, for approximately $208.7 million. The acquisition included the purchase of Crestone Gathering Services, L.L.C., a 33% interest in Fort Union and a 35% interest in Lost Creek. The purchase of Crestone Gathering Services increased the Partnership's ownership in Bighorn to a 49% common membership interest and a 100% interest in the preferred A shares. 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 a 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. The purchase price has 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, Midwestern Gas Transmission and Crestone Gathering Services net assets acquired is reflected as goodwill on the consolidated balance sheet. The investments in Bighorn, Fort Union, Lost Creek and Gregg Lake/Obed are being reflected in investments in unconsolidated affiliates on the consolidated balance sheet. See Note 9 for additional discussion of the Partnership's investments in unconsolidated affiliates. The following is a summary of the effects of the acquisitions made in 2001 and 2000 on the Partnership's consolidated financial position (amounts in thousands):

2002 2001 2000 ------------ ------------ ------------ Current assets $ -- $ 17,257 $ 1,949 Property, plant and equipment -- 249,762 29,789 Investments in unconsolidated affiliates -- 11,463 179,079 Goodwill and other 361 275,443 18,887 Current liabilities 1,200 (14,908) (199) Long-term debt, including current maturities -- (13,113) -- Other liabilities -- (498) -- Accumulated other comprehensive income -- 2,699 -- Common units issued by the Partnership -- (183,031) -- ------------ ------------ ------------ $ 1,561 $ 345,074 $ 229,505 ============ ============ ============

F-13 NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 3. BUSINESS ACQUISITIONS (continued) 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 net income per unit 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. 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. During 2001, the non-voting preferred A shares received a $0.1 million income allocation and cash distribution. No income allocation or cash distribution was made to the non-voting shares in 2002 or 2000. 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. 4. GOODWILL 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, 2002 and 2001, the Partnership's balance sheet included goodwill of approximately $476 million and $475 million, respectively, with approximately $180 million recorded in the Partnership's investment in unconsolidated affiliates. 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. Changes in the carrying amount of goodwill for the year ended December 31, 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 Impairment losses -- -- -- -- ------------ ------------ ------------ ------------ Balance at December 31, 2002 $ 68,872 $ 398,633 $ 8,378 $ 475,883 ============ ============ ============ ============

F-14 NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 4. GOODWILL (continued) The following information discloses the effect of goodwill amortization on the Partnership's net income to partners and net income per unit.

December 31, (Amounts in thousands, ---------------------------------------------- except per unit amounts) 2002 2001 2000 ------------ ------------ ------------ Reported net income to partners $ 113,676 $ 87,786 $ 76,720 Add back: goodwill amortization -- 13,286 2,747 ------------ ------------ ------------ Adjusted net income to partners $ 113,676 $ 101,072 $ 79,467 ============ ============ ============ Reported net income per unit $ 2.44 $ 2.12 $ 2.50 Add back: goodwill amortization -- .34 .09 ------------ ------------ ------------ Adjusted net income per unit $ 2.44 $ 2.46 $ 2.59 ============ ============ ============

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. In 2003, Northern Border Pipeline filed to amend its tariff for the definition of company use gas, which is gas supplied by its shippers for its operations, to clarify the language by adding detail to the broad categories that comprise company use gas. Relying upon the currently effective version of the tariff, Northern Border Pipeline 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. The proposed language provides F-15 NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 5. RATES AND REGULATORY ISSUES (continued) additional detail concerning the practice of recognizing electric costs at electric powered compressor stations in the determination of company use gas. Northern Border Pipeline requested that the tariff change be effective April 1, 2003. Several parties have filed protests of this change and have requested that the FERC order refunds. While the Partnership cannot predict the outcome of this proceeding at this time, the accompanying consolidated financial statements reflect a reserve of $10 million. 6. TRANSPORTATION AGREEMENTS Northern Border Pipeline's and Midwestern Gas Transmission's operating revenues are collected pursuant to their FERC tariffs through firm transportation service agreements. Northern Border Pipeline's firm service agreements extend for various terms with termination dates that range from March 2003 to December 2013. The termination dates for Midwestern Gas Transmission's firm service agreements range from March 2003 to October 2019. Northern Border Pipeline and Midwestern 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 and Midwestern 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. At December 31, 2002, Northern Border Pipeline's largest shipper is Pan-Alberta Gas (U.S.) Inc. (Pan-Alberta) with approximately 20% of the contracted firm capacity, of which approximately 3% has been temporarily released to other shippers through October 31, 2003. Mirant Americas Energy Marketing, LP (Mirant), who manages the assets of Pan-Alberta Gas, Ltd., including the Pan-Alberta contracts with Northern Border Pipeline, also is obligated for approximately 10% of the contracted firm capacity. The Pan-Alberta firm service agreements expire in October 2003. The Mirant firm service agreements expire in October 2006 and December 2008. The obligations of Pan-Alberta and Mirant are supported by various credit support arrangements, including among others, letters of credit and escrow accounts and an upstream capacity transfer agreement. Operating revenues from Mirant and Pan-Alberta for the years ended December 31, 2002, 2001 and 2000 were $105.5 million, $80.7 million and $78.2 million, respectively. At December 31, 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, $52.1 million and $58.5 million for the years ended December 31, 2002, 2001, and 2000, respectively. F-16 NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 6. TRANSPORTATION AGREEMENTS (continued) For the year ended December 31, 2002, Midwestern Gas Transmission's two largest shippers were Northern Illinois Gas Company (Northern Illinois) and Northern Indiana Public Service Company (NIPSCO). The transportation agreements with Northern Illinois expire in October 2003 and the agreements with NIPSCO expire in October 2004 and December 2006. For 2002, Northern Illinois and NIPSCO accounted for $5.2 million (28%) and $2.9 million (16%), respectively, of Midwestern Gas Transmission's operating revenues. For the period from May 2001 to December 2001, Midwestern Gas Transmission's two largest customers, Northern Illinois and PSI Energy LLC had total operating revenues of $4.7 million. 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, 2002, Bear Paw Energy's two largest customers, Lodgepole Energy Marketing (Lodgepole) and Tenaska Marketing Ventures (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 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 and 2000, 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 and $7.2 million for the years ended December 31, 2001 and 2000, respectively (see Note 16). Crestone's revenues from other affiliates totaled $0.2 million, $0.3 million and $0.1 million in 2002, 2001 and 2000, respectively. For the year ended December 31, 2002, Border Midstream's two largest customers, Compton Petroleum (Compton) and ConocoPhillips (Conoco), accounted for $5.6 million (70%) and $0.9 million (11%) of Border Midstream's operating revenues. Compton and Conoco, accounted for $3.1 million (65%) and $0.6 million (13%) of Border Midstream's revenues for the period from April 2001 to December 2001. Black Mesa's operating revenue is derived from a transportation agreement with 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 $21.5 million, $22.0 million and $21.1 million for the years ended December 31, 2002, 2001 and 2000, respectively. F-17 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) 2002 2001 ------------ ------------ Northern Border Pipeline 1992 Pipeline Senior Notes - average 8.57% and 8.53% at December 31, 2002 and 2001, respectively, due from 2002 to 2003 $ 65,000 $ 143,000 Pipeline Credit Agreement - Term loan - average 2.46% at December 31, 2001, due 2002 -- 272,000 2002 Pipeline Credit Agreement - average 2.05% at December 31, 2002, due 2005 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 -- 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% and 3.49% at December 31, 2002 and 2001, respectively, due 2004 35,000 64,000 Bear Paw Energy Capital leases 8,854 11,395 Fair value adjustment for interest rate swaps (Note 8) 36,885 6,269 Unamortized debt premium 19,004 1,563 ------------ ------------ Total 1,403,743 1,423,227 Less: Current maturities of long-term debt 67,765 352,395 ------------ ------------ Long-term debt $ 1,335,978 $ 1,070,832 ============ ============

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 $200 million three-year revolving credit agreement with certain financial institutions (2001 Partnership Credit Agreement) in March 2001. 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. F-18 NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 7. CREDIT FACILITIES, LONG-TERM DEBT AND CAPITAL LEASES (continued) 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). 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). In June 2000, the Partnership completed a private offering of $150 million of 8 -7/8% Senior Notes due 2010 (2000 Partnership Senior Notes) and in September 2000, the Partnership completed an additional private offering of $100 million of 2000 Partnership Senior Notes. The 2001 Partnership Senior Notes and 2000 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 and 2000. 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 as an extraordinary loss on the consolidated statement of income. Interest paid, net of amounts capitalized, during the years ended December 31, 2002, 2001 and 2000 was $88.2 million, $86.5 million and $84.2 million, respectively. Aggregate repayments of long-term debt required for the next five years, excluding payments required under Bear Paw Energy's capital leases, are as follows: $65 million, $35 million, $89 million and $225 million for 2003, 2004, 2005 and 2007, respectively. There are no scheduled debt maturities for 2006. 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, 2003 $ 3,355 2004 3,355 2005 3,074 2006 169 ------- $ 9,953 Less amount representing interest 1,099 ------- Present value of lease payments 8,854 Less: current portion 2,765 ------- Long-term portion $ 6,089 ======= F-19 NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 7. CREDIT FACILITIES, LONG-TERM DEBT AND CAPITAL LEASES (continued) Certain of Northern Border Pipeline's long-term debt and credit arrangements contain requirements as to the maintenance of minimum partners' capital, debt to capitalization ratios, leverage ratios and interest coverage ratios that restrict the incurrence of other indebtedness by Northern Border Pipeline and also place certain restrictions on distributions to the partners of Northern Border Pipeline. Under the most restrictive of the covenants, as of December 31, 2002 and 2001, respectively, $99 million and $110 million of partners' capital of Northern Border Pipeline could be distributed. 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, 2002, Northern Border Pipeline was in compliance with its financial covenants. The indentures under which the 2001 and 2000 Partnership Senior Notes were issued do not limit the amount of indebtedness or other obligations that the Partnership may incur, but do contain material financial covenants, including restrictions on the incurrence of secured indebtedness. The indentures also contain a provision that would require the Partnership to offer to repurchase the 2001 and 2000 Partnership Senior Notes if either Standard & Poor's Rating Services or Moody's Investor Service, Inc. rate the notes below investment grade and the investment grade rating is not reinstated for a period of 40 days. The 2001 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 and depreciation and amortization) to consolidated interest expense of greater than 3 to 1. The 2001 Partnership Credit Agreement also requires the maintenance of the ratio of consolidated funded 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. At December 31, 2002, the Partnership was in compliance with these covenants. 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 and 2002 Pipeline Senior Notes was approximately $1,367 million and $1,125 million at December 31, 2002 and 2001, respectively. The Partnership presently intends to maintain the current schedule of maturities for the 1992 Pipeline Senior Notes, 1999 Pipeline Senior Notes, 2000 Partnership Senior Notes, 2001 Partnership Senior Notes, 2001 Pipeline Senior Notes and 2002 Pipeline Senior Notes, which will result in no gains or losses on their respective repayment. The fair value of the 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-20 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 each of the years ended December 31, 2002 and 2001, the Partnership and Northern Border Pipeline amortized approximately $2.1 million 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 2003. During the third quarter of 2001, the Partnership entered into interest rate swaps with notional amounts totaling $225 million. Under the interest rate swap agreements, the Partnership makes payments to counterparties at variable rates based on the London Interbank Offered Rate and in return F-21 NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 8. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES (continued) 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. The Partnership used the proceeds to repay amounts borrowed under its credit facility. The proceeds are recorded in long-term debt and will be recognized as a reduction in interest expense over the remaining life of the interest rate swap agreements. The Partnership amortized approximately $0.5 million in the fourth quarter of 2002 and expects to amortize approximately $2.2 million in 2003 for these agreements. At December 31, 2002 and 2001, the average effective interest rate on the Partnership's interest rate swap agreements was 3.97% and 4.21%, 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, 2002, the average effective interest rate on Northern Border Pipeline's interest rate swap agreements was 2.70%. 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, 2002, reflects a non-cash gain of approximately $36.9 million 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 year ended December 31, 2002, Bear Paw Energy recognized losses of $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 for 2002, which is included in operating revenues. At December 31, 2002, Bear Paw Energy reflected a non-cash loss of approximately $4.1 million in derivative financial instruments with a corresponding reduction of $4.0 million in accumulated other comprehensive income. In 2003, Bear Paw Energy expects to reclassify approximately $3.4 million from accumulated other comprehensive income as a reduction to operating revenues. 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 F-22 NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 8. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES (continued) and terminated the swap arrangements (see Note 16). 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. In 2002 and 2001, the Partnership recorded approximately $4.6 million and $1.4 million, respectively, in earnings and expects to record approximately $0.3 million in earnings in 2003. 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 2002 2001 --------- -------- -------- Bighorn (a) $ 96,151 $ 93,207 Fort Union 33% 68,937 68,653 Lost Creek 35% 69,297 66,280 Gregg Lake/Obed 36% 7,765 9,495 Other 50%-60% 2,365 2,094 -------- -------- $244,515 (b) $239,729 ======== ========

(a) As discussed in Note 3, the Partnership held a 49% common membership interest in Bighorn and 100% of the non-voting preferred A shares of Bighorn at December 31, 2002 and 2001. (b) At December 31, 2002 and 2001, the unamortized excess of the Partnership's investments in unconsolidated affiliates was $180.1 million. The Partnership's equity earnings (losses) of unconsolidated affiliates is as follows:

(In thousands) 2002 (a) 2001 2000 ------- ------- ------- Bighorn $ 3,764 $ (875) $(1,394) Fort Union 5,540 1,514 285 Lost Creek 3,678 188 462 Gregg Lake/Obed (b) 1,536 870 -- Other 52 -- -- ------- ------- ------- $14,570 $ 1,697 $ (647) ======= ======= =======

(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 and $2.2 million in 2001 and 2000, respectively. (b) Investments in Gregg Lake/Obed began in April 2001 (See Note 3). F-23 NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 9. UNCONSOLIDATED AFFILIATES (continued) Summarized combined financial information of the Partnership's unconsolidated affiliates is presented below:

December 31, ------------------------------ (In thousands) 2002 2001 ------------ ------------ Balance sheet Current assets $ 27,275 $ 17,436 Property, plant and equipment, net 204,018 204,154 Other noncurrent assets 3,322 4,072 Current liabilities 12,716 10,382 Long-term debt 89,697 100,659 Other noncurrent liabilities 7,114 1,861 Accumulated other comprehensive income (7,114) -- Owners' equity 132,202 112,760

(In thousands) 2002 2001 2000(a) ------------ ------------ ------------ Income statement Operating revenues $ 57,419 $ 41,206 $ 8,598 Operating expenses 17,763 15,458 3,871 Net income 33,351 19,312 4,116 Distributions paid to the Partnership $ 10,820 $ 7,083 $ 933

(a) Includes results for Fort Union and Lost Creek after they were acquired in September 2000. 10. PARTNERS' CAPITAL At December 31, 2002, partners' capital 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. At December 31, 2001, partners' capital consisted of 41,623,014 common units representing an effective 98% limited partner interest in the Partnership (including 1.2% held by Northern Plains and 6.5% held by Sundance Assets) and a 2% general partner interest. 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 capital contributions to the Partnership to maintain a 2% general partner interest in accordance with the partnership agreements. 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. In November 2000, the Partnership sold 2,156,250 common units. The net proceeds from the sale of common units and the general partners' capital contributions totaled approximately $75.4 million in 2002, $172.2 million in 2001 and $60.7 million in 2000 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 F-24 NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 10. PARTNERS' CAPITAL (continued) 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 (see Note 12). 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 100% to the General Partners. 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 $11.4 million, $8.6 million and $2.2 million for the years ended December 31, 2002, 2001 and 2000, respectively, related to these agreements. At December 31, 2002, the estimated aggregate amounts of such required future payments were $11.6 million annually for 2003 through 2007 and $26.4 million for later years. At December 31, 2002, 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, 2002, the amount of both guarantees was $4.4 million. Operating Leases Future minimum lease payments under non-cancelable operating leases on office space, pipeline equipment and vehicles are as follows (in thousands): Year ending December 31, 2003 $ 3,112 2004 3,082 2005 2,901 2006 2,439 2007 1,597 Thereafter 2,285 ------- $15,416 ======= Expenses incurred related to these lease obligations for the years ended December 31, 2002 and 2001, were $2.0 million and $1.1 million, respectively. Capital expenditures Total capital expenditures for 2003 are estimated to be $51 million. This includes approximately $32 million for gas gathering and processing facilities and $17 million for interstate natural gas pipeline facilities. F-25 NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 11. COMMITMENTS AND CONTINGENCIES (continued) Capital expenditures (continued) Funds required to meet the capital requirements for 2003 are anticipated to be provided from debt borrowings, 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 principle on pipeline right-of-way lease and taxation issues, subject to final documentation and necessary government approvals. The Partnership believes that the resolution of this lawsuit will not have a material adverse impact on the Partnership's results of operations or financial position. 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. NET INCOME PER UNIT Net income per unit is computed by dividing net income, after deduction of the General Partners' allocation, by the weighted average number of units outstanding. The General Partners' allocation is equal to an amount based upon their combined 2% general partner interest, adjusted to reflect an amount equal to incentive distributions. Net income per unit was determined as follows:

(In thousands, except Year ended December 31, per unit amounts) ------------------------------------------------ 2002 2001 2000 ------------ ------------ ------------ Net income to partners $ 113,676 $ 87,786 $ 76,720 ------------ ------------ ------------ Net income allocated to General Partners (2,274) (1,756) (1,534) Adjustment to reflect incentive distributions (7,328) (4,252) (1,032) ------------ ------------ ------------ (9,602) (6,008) (2,566) ------------ ------------ ------------ Net income allocable to units $ 104,074 $ 81,778 $ 74,154 ============ ============ ============ Weighted average units outstanding 42,709 38,538 29,665 ============ ============ ============ Net income per unit $ 2.44 $ 2.12 $ 2.50 ============ ============ ============

F-26 NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 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 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. SFAS No. 143 is effective for fiscal years beginning after June 15, 2002, with earlier application encouraged. 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 and the effect of adopting SFAS No. 143 is not expected to be material to the consolidated financial statements. In April 2002, the FASB issued SFAS No. 145, "Rescission of FASB Statements No. 4, No. 44 and No. 64, Amendments to FASB Statements No. 13 and Technical Corrections." SFAS No. 146, "Accounting for Costs Associated with Exit or Disposal Activities" was issued in June 2002. SFAS No. 145 streamlines the reporting of debt extinguishments and requires that only gains and losses from extinguishments meeting the criteria in Accounting Principles Board Opinion 30 would be classified as extraordinary. SFAS No. 146 requires that a liability for a cost associated with an exit or disposal activity be recognized when the liability is incurred. SFAS No. 145 is effective for fiscal years beginning after May 15, 2002. SFAS No. 146 is effective for exit or disposal activities that are initiated after December 31, 2002. The Partnership does not expect the adoption of SFAS No. 145 and SFAS No. 146 to have a material impact on its financial position, results of operations or cash flows. 14. GEOGRAPHIC AND 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 and operating income. Interest expense on the Partnership's debt is not allocated to the segments. Therefore, management believes that EBITDA is the dominant measurement of segment performance. F-27 NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 14. GEOGRAPHIC AND BUSINESS SEGMENT INFORMATION (continued) Geographic Segments

Year Ended December 31, (In thousands) 2002 2001 2000 ------------ ------------ ------------ Revenues from external customers United States $ 487,553 $ 455,997 $ 339,732 Foreign 8,064 5,472 -- ------------ ------------ ------------ $ 495,617 $ 461,469 $ 339,732 ============ ============ ============ EBITDA United States $ 312,763 $ 300,346 $ 259,347 Foreign 4,439 2,636 -- ------------ ------------ ------------ $ 317,202 $ 302,982 $ 259,347 ============ ============ ============ Long-lived assets United States $ 1,981,280 $ 2,006,136 $ 1,732,076 Foreign 34,000 33,963 -- ------------ ------------ ------------ $ 2,015,280 $ 2,040,099 $ 1,732,076 ============ ============ ============

Business Segments

Gas Interstate Gathering Natural and Gas Processing Coal (In thousands) Pipelines (b) Slurry Other(d) Total ------------------------ ------------ ------------ ------------ ------------ ------------ 2002 Revenues from external customers $ 339,363 $ 134,686 $ 21,568 $ -- $ 495,617 Depreciation and amortization 61,002 13,304 1,568 -- 75,874 Operating income (loss) 200,584 24,900 5,054 (5,557) 224,981 Interest expense, net 51,525 794 33 30,546 82,898 Equity earnings (losses) of unconsolidated affiliates -- 14,570 -- -- 14,570 Other income (expense), net 1,267 (414) (885) (129) (161) EBITDA 263,335 52,903 6,650 (5,686) 317,202 Capital expenditures 15,715 33,718 441 -- 49,874 Identifiable assets 1,853,796 579,402 20,423 27,359 2,480,980 Investments in unconsolidated affiliates -- 244,515 -- -- 244,515 Total assets $ 1,853,796 $ 823,917 $ 20,423 $ 27,359 $ 2,725,495

F-28 NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 14. GEOGRAPHIC AND BUSINESS SEGMENT INFORMATION (continued) Business Segments (continued)

Interstate Gas Natural Gathering Gas and Pipelines Processing Coal (In thousands) (a) (b) Slurry Other(d) Total ------------------------ ------------ ------------ ------------ ------------ ------------ 2001 Revenues from external customers $ 322,584 $ 116,844 $ 22,041 $ -- $ 461,469 Depreciation and amortization 59,854 14,312 2,144 -- 76,310 Operating income (loss) 199,822 18,239 5,953 (3,055) 220,959 Interest expense, net 55,351 706 717 33,134 89,908 Equity earnings (losses) of unconsolidated affiliates -- 1,697 -- -- 1,697 Other income (expense), net (8) 682 (746) (1,539) (1,611) EBITDA 258,310 41,388 8,261 (4,977) 302,982 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

Gas Interstate Gathering Natural and Gas Processing Coal (In thousands) Pipelines (c) Slurry Other(d) Total ------------------------ ------------ ------------ ------------ ------------ ------------ 2000 Revenues from external customers $ 311,022 $ 7,540 $ 21,170 $ -- $ 339,732 Depreciation and amortization 57,328 394 2,977 -- 60,699 Operating income (loss) 184,167 2,019 4,355 (2,239) 188,302 Interest expense, net 65,161 -- 1,677 14,657 81,495 Equity earnings (losses) of unconsolidated affiliates -- (647) -- -- (647)

F-29 NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 14. GEOGRAPHIC AND BUSINESS SEGMENT INFORMATION (continued) Business Segments (continued)

Gas Interstate Gathering Natural and Gas Processing Coal (In thousands) Pipelines (c) Slurry Other(d) Total ---------------------- ------------ ------------ ------------ ------------ ------------ 2000 (CONTINUED) Other income, net 8,058 -- 32 589 8,679 EBITDA 249,248 4,007 7,742 (1,650) 259,347 Capital expenditures 15,523 3,812 386 -- 19,721 Identifiable assets 1,768,505 58,230 29,605 4,755 1,861,095 Investments in unconsolidated affiliates -- 221,625 -- -- 221,625 Total assets $ 1,768,505 $ 279,855 $ 29,605 $ 4,755 $ 2,082,720

(a) Includes interstate natural gas pipeline results of Midwestern Gas Transmission commencing from the effective date of acquisition in May 2001 (see Note 3). (b) Includes 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). (c) Gas gathering and processing operating results commence from the date of acquisition in September 2000 (see Note 3) except for equity earnings (losses) of Bighorn, which commenced in January 2000. (d) Includes other items not allocable to segments. 15. QUARTERLY FINANCIAL DATA (Unaudited)

(In thousands, except Operating Operating Net Income Net Income per unit amounts) Revenues, net Income to Partners per Unit --------------------- ---------------- ------------ ------------ ------------ 2002 First Quarter $ 118,007 $ 56,485 $ 27,969 $ 0.62 Second Quarter 123,303 60,890 30,106 0.67 Third Quarter 126,237 60,431 31,650 0.67 Fourth Quarter 128,070 47,175 23,951 0.49 2001 First Quarter $ 87,960 $ 52,156 $ 17,973 $ 0.54 Second Quarter 125,474 55,609 20,469 0.48 Third Quarter 124,646 59,843 29,087 0.65 Fourth Quarter 123,389 53,351 20,257 0.45

F-30 NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 16. 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. 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. The Partnership believes, however, that any amounts collected will not be material. 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. 17. SUBSEQUENT EVENTS On January 17, 2003, the Partnership acquired all of the common stock of Viking Gas Transmission including a one-third interest in Guardian Pipeline L.L.C. (Guardian Pipeline) for approximately $162 million, which included the assumption of $40 million of debt. The Partnership financed the acquisition initially the 2001 Partnership Credit Agreement. Effective with the closing of the Viking Gas Transmission acquisition, the Partnership amended the 2001 Partnership Credit Agreement to increase the ratio of F-31 NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 17. SUBSEQUENT EVENTS (continued) consolidated funded debt to adjusted consolidated EBITDA to no more than 4.75 to 1 through June 30, 2003, at which time the ratio reverts back to 4.5 to 1. As part of the acquisition, the Partnership agreed to guarantee its ownership share of Guardian Pipeline's indebtedness. The amount of the guarantee is $60 million. Pursuant to the terms of Guardian Pipeline's debt agreements, the guarantee is removed upon Guardian Pipeline meeting certain conditions, which the Partnership expects to occur in the second quarter of 2003. The Viking Gas Transmission system is a 578-mile interstate natural gas pipeline extending from the U.S.-Canadian border near Emerson, Manitoba to Marshfield, Wisconsin. Viking Gas Transmission connects to other major pipeline systems including TransCanada, Northern Natural Gas Company, Great Lakes Gas Transmission and ANR Pipeline Company to provide service to markets in Minnesota, Wisconsin and North Dakota. 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. On January 22, 2003, 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, 2002. The distribution was payable February 14, 2003, to unitholders of record at January 31, 2003. F-32 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, 2002 and 2001 and for each of the years in the three-year period ended December 31, 2002 included in this Form 10-K, and have issued our report thereon dated January 23, 2003. 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 January 23, 2003 Omaha, Nebraska S-1 SCHEDULE II NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS FOR THE YEARS ENDED DECEMBER 31, 2002, 2001 AND 2000 (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 2002 $ 2,531 $ 9,763 $ -- $ -- $ 12,294 2001 $ 1,800 $ 731 $ -- $ -- $ 2,531 2000 $ 7,376 $ 1,800 $ -- $ 7,376 $ 1,800 Allowance for doubtful accounts 2002 $ 10,743 $ 3,463 $ 52 $ 1,866 $ 12,392 2001 $ -- $ 10,743 $ -- $ -- $ 10,743 2000 $ -- $ -- $ -- $ -- $ --

S-2 EXHIBIT INDEX *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 Note Purchase Agreement between Northern Border Pipeline Company and the parties listed therein, dated July 15, 1992 (Exhibit 10.6 to Form S-1). *10.8 Supplemental Agreement to the Note Purchase Agreement dated as of June 1, 1995 (Exhibit 10.6.1 to the Partnership's Annual Report on Form 10-K for the year ended December 31, 1995 ("1995 10-K")). *10.9 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 Borders Partners, L.P.'s Current Report on Form 8-K dated June 26, 2002). *10.10 Revolving Credit Agreement, dated as of March 21, 2001, between Northern Border Partners, L.P., SunTrust Bank, Administrative Agent, Bank of Montreal and Bank of America, N.A., Co-Syndication Agents and Bank One, NA, Documentation Agent and Lenders (as defined therein)(Exhibit 10.20 to Northern Border Partners, L.P. Form 10-K for the year ended December 31, 2000 ("2000 10-K")). *10.11 Northern Border Pipeline Company U.S. Shippers Service Agreement between Northern Border Pipeline Company and Pan-Alberta Gas (US) Inc., dated October 1, 1993, with Amended Exhibit A effective June 22, 1998 (Exhibit 10.36 to Northern Border Pipeline Company Annual Report on Form 10-K for the year ended December 31, 1999 ("NB Pipeline 1999 10-K")). *10.12 Northern Border Pipeline Company U.S. Shippers Service Agreement between Northern Border Pipeline Company and Pan-Alberta Gas (US) Inc.,(successor to Natgas U.S. Inc.) dated October 6, 1989, with Amended Exhibit A effective April 2, 1999 (Exhibit 10.37 to NB Pipeline 1999 10-K). *10.13 Northern Border Pipeline Company U.S. Shippers Service Agreement between Northern Border Pipeline Company and Pan-Alberta Gas (U.S.) Inc., dated October l, 1992, with Amended Exhibit A effective June 22, 1998 (Exhibit 10.38 to NB Pipeline 1999 10-K). *10.14 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). *10.15 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). *10.16 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). *10.17 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 Partner, L.P.'s Form 10-K for year ended December 31, 2001). 10.18 Operating Agreement between Viking Gas Transmission Company and Northern Plains Natural Gas Company dated as of January 17, 2003. *16.1 Letter of Arthur Andersen LLP, former auditors of Northern Border Partners, L.P. dated February 11, 2002 (Exhibit 99.3 to Northern Border Partners, L.P's Form 8-K filed on February 13, 2002). 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. *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). 99.2 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. 99.3 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. *Indicates exhibits incorporated by reference as indicated; all other exhibits are filed herewith.