10-K 1 h95054e10-k.txt NORTHERN BORDER PARTNERS L P - YEAR END 12/31/2001 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, 2001 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.) 1111 SOUTH 103RD STREET, OMAHA, NEBRASKA 68124-1000 (Address of principal executive offices) (zip code) Registrant's telephone number, including area code: 402-398-7700 ---------- 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. --- 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 March 1, 2002, was approximately $1,438,920,000. NORTHERN BORDER PARTNERS, L.P. TABLE OF CONTENTS

PAGE NO. -------- PART I Item 1. Business 1 Item 2. Properties 15 Item 3. Legal Proceedings 16 Item 4. Submission of Matters to a Vote of Security Holders 16 PART II Item 5. Market for Registrant's Common Units and Related Security Holder Matters 17 Item 6. Selected Financial Data 18 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations 19 Item 7a. Quantitative and Qualitative Disclosures About Market Risk 36 Item 8. Financial Statements and Supplementary Data 37 Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure 37 PART III Item 10. Partnership Management 39 Item 11. Executive Compensation 43 Item 12. Security Ownership of Certain Beneficial Owners and Management 48 Item 13. Certain Relationships and Related Transactions 48 PART IV Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K. 52

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. We, through our subsidiary limited partnership, Northern Border Intermediate Limited Partnership, collectively referred to herein as "Partnership", own a 70% general partner interest in Northern Border Pipeline Company, a Texas general partnership ("Northern Border Pipeline"). In 2001, we completed several acquisitions. We acquired Midwestern Gas Transmission Company ("Midwestern Gas Transmission"), a 350-mile interstate natural gas pipeline system. We purchased Bear Paw Energy, LLC ("Bear Paw Energy"), which owns extensive gathering and processing operations in the Powder River Basin in Wyoming and in the Williston Basin in Montana and North Dakota. We also acquired an interest in processing and gathering operations in Alberta, Canada. We are managed under the direction of a partnership policy committee (similar to a board of directors) appointed by our general partners. Our general partners and the general partners of the 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 The Williams Companies, Inc. ("Williams"). Our general partners hold an aggregate 2% general partner interest in the Partnership. Northern Plains also owns common units representing a 1.2% limited partner interest and Enron, through an indirect subsidiary, holds a 6.5% 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 Williams are 9.4% and 0.3%, respectively. On December 2, 2001, Enron filed a voluntary petition for Chapter 11 protection in bankruptcy court. See Item 7. "Management's Discussion and Analysis of Financial Condition and Results of Operations - Impact of Enron's Chapter 11 Filing on Our Business" and Item 13. "Certain Relationships and Related Transactions." The Partnership policy committee consists of three members, each of whom has been appointed by one of our general partners. See Item 10. "Partnership Management." Our operations are comprised of the following segments: o Interstate Natural Gas Pipelines o Natural Gas Gathering and Processing o Coal Slurry Pipeline For information about our operating segments and geographic areas, see Note 13 to the Consolidated Financial Statements. INTERSTATE NATURAL GAS PIPELINES Our interstate pipelines segment provides natural gas transmission services in the midwestern United States. 1 Northern Border Pipeline and Midwestern Gas Transmission transport gas for shippers under tariffs regulated by the Federal Energy Regulatory Commission ("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 the related natural gas commodity risk. The pipeline systems are operated by Northern Plains pursuant to operating agreements. Northern Plains employs approximately 230 individuals located at our headquarters in Omaha, Nebraska, and at various locations near the pipelines. Northern Plains' employees are not represented by any labor union and are not covered by any collective bargaining agreements. NORTHERN BORDER PIPELINE SYSTEM 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 with various natural gas markets. In the year ended December 31, 2001, 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 90% 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 PipeLines Limited ("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 2 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 designed to transport 2,374 million cubic feet per day ("mmcfd") from the Canadian border to Ventura, Iowa; 30-inch diameter pipe and 36-inch diameter pipe, each approximately 147 miles in length, designed to transport 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 designed to transport 844 mmcfd from Harper, Iowa to Manhattan, Illinois (Chicago area); and 35 miles of 30-inch diameter pipe designed to transport 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. On October 1, 2001, Northern Border Pipeline completed construction and began operation of its Project 2000 facilities. Project 2000 gives shippers access to industrial natural gas consumers in northern Indiana through an interconnect with Northern Indiana Public Service Company, a major midwest local distribution company, at the terminus near North Hayden, Indiana and provides 545 mmcfd of transportation capacity. Project 2000 also expands Northern Border Pipeline's delivery capability into the Chicago area by approximately 30%. Capital expenditures for Project 2000 are approximately $63 million. Project 2000 facilities include approximately 35 miles of 30-inch pipeline, one 13,000 horsepower compressor station in Illinois, additional horsepower at two Iowa compressor stations and one meter station. 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, as well as the Williston Basin in the United States. The pipeline system also has access to synthetic gas produced at the Dakota Gasification plant in North Dakota. At its northern end, the pipeline system's gas supplies are received through an interconnection with TransCanada's majority-owned Foothills Pipe Lines (Sask.) Ltd. system in Canada, which is connected to TransCanada's Alberta system and the pipeline system owned by Transgas Limited in Saskatchewan. The pipeline system also connects with facilities of Williston Basin Interstate Pipeline at Glen Ullin and Buford, North Dakota, facilities of Amerada Hess Corporation at Watford City, North Dakota and facilities of Dakota Gasification Company at Hebron, North Dakota in the northern portion of the pipeline system. For the year ended December 31, 2001, of the natural gas transported on the pipeline system, approximately 90% was produced in Canada, approximately 5% was produced by the Dakota Gasification plant and approximately 5% was produced in the Williston Basin. To access markets, the pipeline system interconnects with pipeline facilities of: o Northern Natural Gas Company, an Enron subsidiary until February 1, 2002, and now a subsidiary of Dynegy, Inc., at Ventura, Iowa as well as multiple smaller interconnections in South Dakota, Minnesota and Iowa; 3 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 The Peoples Gas Light and Coke Company near Manhattan, Illinois; and o Northern Indiana Public Service Company near North Hayden, Indiana at the terminus of the pipeline system. The Ventura, Iowa interconnect with Northern Natural Gas Company functions as a large market center, where natural gas transported on the pipeline system is sold, traded and received for transport to significant consuming markets in the Midwest and to interconnecting pipeline facilities destined for other markets. 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, 2001, 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, 2001, the termination dates of these contracts ranged from March 31, 2002 to December 21, 2013, and the weighted average contract life, based upon annual contractual obligations, was approximately five and one-half years with just under 99% of capacity contracted through mid-September 2003. Contracts for approximately 42% of the capacity will expire prior to November 1, 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 its capacity release provisions that allow them to release all or part of their capacity, either permanently for the full term of their contract or temporarily. Under the terms of Northern Border Pipeline's tariff, a temporary capacity release does not relieve the original contract shipper from its payment obligations if the new shipper fails to pay for the capacity temporarily released to it. Shippers on the pipeline system temporarily released capacity during 2001 for varying periods of time. There were also permanent releases of capacity to other shippers for the full term of the contracts. 4 As of December 31, 2001, the largest shipper, Mirant Americas Energy Marketing, LP, is obligated for approximately 33.7% of the contracted firm capacity. Of this amount, 24.4% of Northern Border Pipeline's contracted firm capacity was obtained under temporary releases from Pan-Alberta Gas (U.S.) ("Pan-Alberta") for a term through October 2002. Pan-Alberta's firm contracts expire October 31, 2003. Mirant Americas Energy Marketing, LP, manages the assets of Pan-Alberta Gas, Ltd., which include Pan-Alberta's contracts with Northern Border Pipeline. Some of the shippers are affiliated with the general partners of Northern Border Pipeline. Enron North America Corp. ("ENA"), a subsidiary of Enron, which also has filed for bankruptcy protection, holds firm contracts representing 3.5% of capacity, a portion of which (1.1%) has been temporarily released to a third party until October 31, 2002. The third party that holds the 1.1% of capacity has filed a complaint with the FERC requesting, in effect, that its contract be deemed terminated as a consequence of ENA's filing for bankruptcy protection. We believe this shipper's contract will remain in effect until October 31, 2002. ENA's contractual obligations were supported by a guaranty from Enron. Transcontinental Gas Pipe Line Corporation, a subsidiary of Williams, holds a contract representing 0.7% of capacity. See Item 7. "Management's Discussion and Analysis of Financial Condition and Results of Operations - Impact of Enron's Chapter 11 Filing On Our Business" and Item 13. "Certain Relationships and Related Transactions." MIDWESTERN GAS TRANSMISSION SYSTEM Effective May 1, 2001, we acquired Midwestern Gas Transmission from El Paso Corporation for approximately $102 million. The Midwestern Gas Transmission system extends 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 Tennessee to the north. There are six compressor stations capable of generating 70,170 horsepower. The Midwestern Gas Transmission system connects with multiple pipeline systems that provide its shippers access to various markets served by those pipelines. Because of its position in the U.S. grid, Midwestern Gas Transmission is configured to receive gas volumes at both ends of its system. In the north end, Midwestern Gas Transmission can receive gas from ANR Pipeline Company, Northern Border Pipeline, Natural Gas Pipeline Company of America and Alliance Pipeline. The southern end of the system has an interconnection with Tennessee Gas Transmission at Portland. Additionally, Midwestern Gas Transmission has interconnections with four interstate pipelines in Kentucky, Indiana and Illinois. The Midwestern Gas Transmission system serves 30 firm transportation shippers. Based upon shipper contractual obligations as 5 of December 31, 2001, approximately 49% of the firm transportation capacity is contracted by local distribution companies, 49% by marketers and two percent by end users. Based upon the proportionate share of capacity, two shippers account for approximately 60% of the capacity. They are Northern Illinois Gas Company (38.4%) and PSI Energy Inc. (20.9%). As of December 31, 2001, the termination dates of Midwestern Gas Transmission's firm transportation contracts ranged from March 31, 2002 to October 31, 2019. The weighted average contract life, based upon annual contract obligations, was approximately three and one-half years. One shipper, ENA, which has filed for bankruptcy protection, is affiliated with our general partners. ENA holds 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 - Impact of Enron Bankruptcy On Our Business" and Item 13. "Certain Relationships and Related Transactions." DEMAND FOR INTERSTATE PIPELINE TRANSPORTATION CAPACITY The interstate pipelines' long-term financial condition is dependent on the continued availability of economic natural gas supplies including western Canadian natural gas for import into the United States. Natural gas reserves may require significant capital expenditures by others for exploration and development drilling and the installation of production, gathering, storage, transportation and other facilities that permit natural gas to be produced and delivered to pipelines that interconnect with the 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 Northern Border Pipeline. The interstate pipelines' business also depends on the level of demand for natural gas in the markets the pipeline systems serve. 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 the pipeline systems to meet demand in the markets that the 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; 6 o climatic conditions; o government regulation; and o technological advances in fuel economy and energy generation devices. 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 the pipelines 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 level of demand charges customers are willing to commit to 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 the interstate pipeline systems or how significant that adverse effect could be. INTERSTATE PIPELINE COMPETITION Northern Border Pipeline competes 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. Its competitive position is 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 Northern Border Pipeline's system is affected by natural gas prices, the relationship between export capacity from 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 pipelines eastward in Canada or to markets on the West Coast. The Alliance Pipeline, which was placed in service in December 2000, competes directly with Northern Border Pipeline in the transportation of natural gas from the western Canadian sedimentary basin to the Chicago area. Williams has a minority interest (14.6%) in Alliance Pipeline. 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 7 States. Vector Pipeline L.P., which interconnects with the Alliance Pipeline and transports gas eastward to a terminus in eastern Canada, commenced operations in December 2000. Guardian Pipeline proposes to be in service in November 2002 and to interconnect with Northern Border Pipeline. Guardian Pipeline is targeting markets in northern Illinois and Wisconsin and could provide access to additional markets for Northern Border Pipeline's shippers. The Alliance Pipeline has also brought about increased supply access for Midwestern Gas Transmission customers. The Alliance Pipeline receipt point into the Midwestern Gas Transmission system near Joliet, Illinois provided anywhere from ten to thirty percent of the daily needs of Midwestern Gas Transmission customers during 2001. TransCanada PipeLines Limited and other unaffiliated companies own and operate pipeline systems that transport natural gas from the same natural gas reserves in western Canada that supply Northern Border Pipeline's shippers. Natural gas is produced in the United States and is also transported by competing pipeline systems to the same markets as those served by the 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 under Section 8. 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, 8 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 gas tariffs. Under the tariffs, interstate pipelines are allowed to charge for their services on the basis of stated transportation rates established in their rate cases. The tariffs also allow the interstate pipelines to provide services under negotiated and discounted rates. For our interstate pipelines, approximately 98% of the agreed upon cost of service or revenue level is attributed to demand charges. 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. The remaining 2% of the agreed upon revenue level 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 is under no obligation to file a new rate case. Prior to any new 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. 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 FERC, the interstate pipelines continue to depreciate their transmission plant at FERC approved depreciation rates. For Northern Border Pipeline, the annual depreciation rate on transmission plant in service is 2.25% and for Midwestern Gas Transmission, the annual depreciation rate on transmission plant in service is 1.9%. In order to avoid a decline in transportation rates set in future rate cases as a result of accumulated depreciation, the interstate pipelines must maintain or increase their 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 recent FERC rulings. In those rulings, the FERC held that an interstate pipeline is not entitled to a tax allowance for income attributable to limited partnership interests held by individuals. The settlement of Northern Border Pipeline's 1995 rate case provided that until at least December 2005, Northern Border Pipeline could continue to calculate the allowance for income taxes in the manner it had historically used. In addition, a settlement adjustment mechanism of $31 million 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. 9 The 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. In addition, Northern Border Pipeline is permitted to retain revenue from interruptible transportation service to offset any decontracted firm capacity. Midwestern Gas Transmission does not share revenue from its interruptible transportation service with its firm shippers. After October 31, 2003, all revenues from interruptible and other new transportation service for Northern Border Pipeline will no longer be subject to sharing and thus will be retained by Northern Border Pipeline. During 2001, Northern Border Pipeline and Midwestern Gas Transmission filed and received approval to implement several new services. The interstate pipelines intend to continue to develop other new services to meet customer needs and seek the FERC's authorization to implement such services. Revenues from these sources are expected to be minimal for the near term. The 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 Regulation 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. NATURAL GAS GATHERING AND PROCESSING SEGMENT Our gas gathering and processing segment provides services for the gathering, treating, processing and compression of natural gas and the fractionation of natural gas liquids ("NGLs") for third parties and related field services. We do not explore for, or produce, crude oil or natural gas, and do not own crude oil or natural gas reserves. On March 30, 2001, we completed our purchase of Bear Paw Energy for approximately $381.7 million, paid with 5.7 million of our common units valued at $183 million and $198.7 million in cash. 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 four processing plants with 90 mmcfd of capacity. 10 Following the acquisition, Bear Paw Energy's Powder River Basin gathering activities in northeastern Wyoming were integrated with those of our wholly-owned subsidiary, Crestone Gathering Services, L.L.C. ("Crestone Gathering"). Bear Paw Energy and Crestone Gathering have approximately 1,100 miles of high and low pressure gathering pipelines, approximately 71 compressor stations with approximately 114,000 installed horsepower and long-term volumetric contracts with producers covering approximately 300,000 acres of dedicated reserves in the Powder River Basin. 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. ("Bighorn"), a 33.33% interest in Fort Union Gas Gathering, L.L.C. ("Fort Union") and a 35% interest in Lost Creek Gathering, L.L.C. ("Lost Creek"), which collectively own over 300 miles of gas gathering facilities in the Powder River and Wind River Basins in Wyoming. The Bighorn and Fort Union systems gather coalbed methane gas produced in the Powder River Basin in northeastern Wyoming. Under various agreements, the majority of which are long-term, producers have dedicated their gas reserves to Bighorn, giving Bighorn the right to gather natural gas produced in areas of Wyoming covering approximately 800,000 acres. Bighorn's system is capable of gathering more than 250 mmcfd of natural gas for delivery to the Fort Union gathering system. During the fourth quarter of 2001, Fort Union completed an expansion, increasing its capacity such that it now 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 106 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. 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 interest 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 and Crestone Gathering'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 11 pipeline and 28 compressor stations with a total rated horsepower of 28,378, in addition to plant compression of 19,163 horsepower. Most of the wells connected to the facilities produce casinghead gas in association with crude oil, which Bear Paw Energy does not purchase. This gas is generally high in natural gas liquids ("NGLs") content. The NGLs are separated from the gas at our processing plants and this mix may then be sold or fractionated into components and then sold, depending on market conditions. 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 delivery 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 gross proceeds realized. NBP Services Corporation, an Enron subsidiary, provides administrative services for us and operating services for Bear Paw Energy and Crestone Energy Ventures. NBP Services Corporation has approximately 170 employees and utilizes employees of its affiliates to provide these services. In April of 2001, we acquired interests in the midstream business in Canada. Our subsidiary, Border Midstream Services, Ltd. ("Border Midstream") 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 associated gathering pipelines. Sour gas processing involves the removal of high quantities of sulphur from the gas stream. These associated pipelines consist of 115 miles of gathering systems. The Gladys Plant is a sour gas processing plant with 10 mmcfd of capacity. The Gregg Lake/Obed Pipeline is comprised of 85 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., 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. 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. The major customers of Border Midstream are Compton, Conoco, and Mobil. They account for approximately 65%, 12% and 8% of the Mazeppa revenue stream, 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 12 and Wind River Basins of Wyoming are affiliates of Western Gas Resources, Thunder Creek Gas Gathering, El Paso Field Services and Bighorn. 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 currently two gas plants in the general vicinity of Border Midstream's plants. The Crestar Vulcan plant is approximately 30 miles from Mazeppa/Gladys and has processing capabilities of approximately 56 mmcfd. The Esso Quirk Creek plant is approximately 30 miles from Mazeppa/Gladys. 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 drilling may be impacted by the ability of gas producers to obtain and maintain the necessary drilling and production permits in a timely and economic manner, as well as commodity prices. In the Powder River Basin, 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. 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 Company ("Black Mesa"), 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 13 pipeline is fully contracted to 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 been willing to agree to continued use of water after December 31, 2005. If efforts by the Mohave Plant 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. Approximately 58 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. Black Mesa's collective bargaining agreement with the United Mineworkers of America was renewed for an additional year in February 2002. 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, 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. 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: Energy Resources Conservation Act, Oil and Gas Conservation Act, Pipeline Act, and 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 payment of penalties in the amount of $128,000 for alleged violations of federal and state law due to discharges of coal slurry on 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. We believe that three of those incidents give rise to the stipulated penalties agreed to in the Consent Decree. The estimated amount of the penalties is $30,000. Black Mesa also has received and responded to a request for information from the EPA. 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 costs and liabilities to us. If we are unable to recover such resulting costs, earnings and cash distributions could be adversely affected. 14 ITEM 2. PROPERTIES Northern Border Pipeline and Midwestern Gas Transmission 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 certain of the compressor stations, meter stations, pipeline field office sites, and microwave tower sites; 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, Crestone Gathering, 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. Border Midstream's systems are used for gathering, compressing and processing of natural gas in the Province of Alberta, Canada. 15 Border Midstream holds the right, title and interest in their gathering and processing facilities, which consist of gas gathering lines, compression and measurement installations and treating, processing and fractionation facilities. The real property rights for these facilities are derived through fee ownership, leases, easements, rights-of-way and permits. Black Mesa holds grant of right of way from private landowners as well as The Navajo Nation and the Hopi Tribe. These right-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. 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. 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 Reservation. Based on recent decisions by the federal courts and other defenses, we believe that the Tribes do not have authority to impose the tax and that the lawsuit will not have a material adverse impact on the Partnership. See Item 1. "Business - Environmental and Safety Matters" for the discussion on the Consent Decree entered against Black Mesa. 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 2001. 16 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 ------------- ------------- ------------- 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 2000 Fourth Quarter .............................. $ 33.625 $ 27.75 $ 0.70 Third Quarter ............................... 31.875 27.25 0.70 Second Quarter .............................. 28.125 23.75 0.65 First Quarter ............................... 29.25 23.00 0.65

As of March 1, 2002, there were approximately 1,600 record holders of common units and approximately 68,200 beneficial owners of the common units, including common units held in street name. On March 21, 2002, the last reported sale price of our common units on the New York Stock Exchange was $39.09 per common unit. We currently have 41,623,014 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 16, 2002, we declared a distribution of $0.80 per unit ($3.20 per unit on an annualized basis), payable February 14, 2002 to the general partners and unitholders of record at January 31, 2002. 17 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, --------------------------------------------------------------------- 2001(2) 2000(3) 1999 1998 1997 ----------- ----------- ----------- ----------- ----------- INCOME DATA: Operating revenues, net $ 461,469 $ 339,732 $ 318,963 $ 217,592 $ 198,574 Product purchases 39,699 -- -- -- -- Operations and maintenance 96,449 62,097 53,451 44,770 37,418 Depreciation and amortization 76,310 60,699 54,842 43,885 40,332 Taxes other than income 28,052 28,634 30,952 22,012 22,836 Regulatory credit -- -- -- (8,878) -- ----------- ----------- ----------- ----------- ----------- Operating income 220,959 188,302 179,718 115,803 97,988 Interest expense, net 89,908 81,495 67,709 30,922 30,860 Other income 86 8,032 4,562 13,208 8,149 Minority interests in net income 42,138 38,119 35,568 30,069 22,253 ----------- ----------- ----------- ----------- ----------- Net income before extraordinary items 88,999 76,720 81,003 68,020 53,024 Extraordinary loss from debt restructuring (1,213) -- -- -- -- ----------- ----------- ----------- ----------- ----------- Net income to partners $ 87,786 $ 76,720 $ 81,003 $ 68,020 $ 53,024 =========== =========== =========== =========== =========== Net income per unit $ 2.12 $ 2.50 $ 2.70 $ 2.27 $ 1.97 =========== =========== =========== =========== =========== Number of units used in computation 38,538 29,665 29,347 29,345 26,392 =========== =========== =========== =========== =========== CASH FLOW DATA: Net cash provided by operating activities $ 233,948 $ 169,615 $ 173,368 $ 103,849 $ 119,621 Capital expenditures 126,414 19,721 102,270 652,194 152,658 Acquisition of businesses 345,074 229,505 31,895 -- -- Distribution per unit 2.99 2.65 2.44 2.30 2.20 BALANCE SHEET DATA (AT END OF PERIOD): Property, plant and equipment, net $ 2,040,099 $ 1,732,076 $ 1,745,356 $ 1,730,476 $ 1,118,364 Total assets 2,687,355 2,082,720 1,863,437 1,825,766 1,266,917 Long-term debt, including current maturities 1,423,227 1,171,962 1,031,986 976,832 481,355 Minority interests in partners' equity 250,078 248,098 250,450 253,031 174,424 Partners' equity 914,958 572,274 515,269 507,426 500,728 OTHER FINANCIAL DATA: Ratio of earnings to fixed charges (1) 2.4 2.4 2.7 3.0 3.2 OPERATING DATA: Interstate Natural Gas Pipeline Segment: Million cubic feet of gas delivered 891,935 852,674 834,833 608,187 621,262 Average daily throughput (MMcfd) 2,605 2,400 2,353 1,706 1,735 Natural Gas Gathering and Processing Segment: Gathering (MMcfd) 793 397 -- -- -- Processing (MMcfd) 118 -- -- -- -- Coal Slurry Pipeline Segment: Thousands of tons of coal shipped 4,932 4,711 4,494 4,489 4,394

---------- (1) "Earnings" means the sum of net income from continuing operations and 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 Canadian midstream assets (April 2001) since dates of acquisition. (3) Includes results of operations for Crestone Energy Ventures and Crestone Gathering since date of acquisition in September 2000. 18 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 generally accepted accounting principles for nonregulated entities. 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 extraordinary retirements or sales. The original cost of utility property retired is charged to accumulated depreciation and amortization, net of salvage and cost of removal. With respect to our acquisitions made in 2000 and 2001, the excess of our purchase price over the fair value of the net assets acquired or goodwill is being amortized over 30 years. The accounting for goodwill will change for us in 2002 due to our adoption of SFAS No. 141, "Business Combinations," and SFAS No. 142, "Goodwill and Other Intangible Assets." Finally, our accounting for financial instruments follows SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities," which we adopted on January 1, 2001. 19 RESULTS OF OPERATIONS YEAR ENDED DECEMBER 31, 2001 COMPARED WITH THE YEAR ENDED DECEMBER 31, 2000 Our operating results for 2001 were significantly influenced by the acquisitions we made in the first half of 2001 and improved performance by Northern Border Pipeline. Our net income before extraordinary items increased $12.3 million (16%) for the year ended December 31, 2001, as compared to the same period in 2000. Net income from our new acquisitions totaled $22.3 million in 2001. Primarily as a result of borrowings made to fund our acquisitions, the Partnership's interest expense increased approximately $18.5 million in 2001 as compared to 2000. Our share of Northern Border Pipeline's net income increased $9.4 million in 2001 as compared to 2000. Northern Border Pipeline's operating results benefited from reductions in interest rates, which reduced its interest expense for 2001 as compared to 2000. Northern Border Pipeline was also able to control its operating costs resulting in reductions to operations and maintenance expenses. Although our net income increased between years, our net income per unit decreased from $2.50 per unit in 2000 to $2.12 per unit for 2001 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. Operating revenues, net increased $121.7 million (36%) for the year ended December 31, 2001, as compared to the same period in 2000. Operating revenues from the gas gathering and processing businesses increased $109.3 million primarily due to the businesses acquired in 2001. Operating revenues from the interstate pipelines increased $11.6 million due primarily to $9.5 million of revenues from Midwestern Gas Transmission acquired effective May 2001. Operating revenues for Northern Border Pipeline increased $2.1 million for the year ended December 31, 2001, as compared to the same period in 2000, primarily due to additional revenues associated with the completion of Project 2000 in October 2001. See Item 1. "Business - Interstate Natural Gas Pipelines - Northern Border Pipeline System." Product purchases of $39.7 million recorded in 2001 represent amounts incurred by Bear Paw Energy. In conjunction with its gathering and processing activities, Bear Paw Energy receives the natural gas stream from producers. Upon sale of the natural gas liquids and residue that it processes in its facilities, Bear Paw Energy pays the producers based upon a percentage of the gross proceeds. Operations and maintenance expense increased $34.4 million (55%) for the year ended December 31, 2001, as compared to the same period in 2000. Operations and maintenance expense for the gas gathering and processing segment increased $38.1 million, primarily due to the businesses acquired in 2001. Operations and maintenance expense from the interstate pipelines decreased $4.7 million due primarily to a decrease in Northern Border Pipeline's expense by $7.9 million (19%) 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 Northern Border Pipeline's regulatory commission expense, decreased costs to operate two of its electric-powered compressor units and decreased employee payroll, benefit and administrative expenses for the pipeline. Operations and maintenance expense for 2001 includes approximately $8.8 million of bad debt expense related to ENA. See "Impact of Enron's Chapter 11 Filing On Our Business" and Item 13. "Certain Relationships and Related Transactions." 20 Depreciation and amortization expense increased $15.6 million (26%) for the year ended December 31, 2001, as compared to the same period in 2000. Depreciation and amortization expense from the gas gathering and processing segment increased $13.9 million, primarily due to businesses acquired in 2001. Depreciation and amortization expense from the interstate pipelines increased $2.5 million due primarily to $2.3 million of expense from Midwestern Gas Transmission. Depreciation and amortization expense in 2001 and 2000 includes goodwill amortization of $7.0 million and $0.5 million, respectively. See "New Accounting Pronouncements" below for discussion of a recently issued accounting pronouncement that will impact goodwill amortization in 2002. Taxes other than income decreased $0.6 million (2%) for the year ended December 31, 2001, as compared to the same period in 2000, due primarily to a decrease in Northern Border Pipeline's expense by $2.3 million (8%) offset by $1.4 million of expense from the gas gathering and processing segment. The decrease in Northern Border Pipeline's taxes other than income is due primarily to a decrease in use taxes paid to the state of Minnesota. Northern Border Pipeline had been paying Minnesota a use tax based on the fuel used at its compressor stations located in the state. A recent ruling by the Minnesota Supreme Court directed that the compressor fuel used was exempt from this particular tax. Northern Border Pipeline filed for a refund of amounts previously paid and received the refund in March 2002. Consolidated interest expense increased $8.4 million (10%) for the year ended December 31, 2001, as compared to the same period in 2000. Interest expense for the Partnership increased approximately $18.5 million (126%) for the year ended December 31, 2001, as compared to the same period in 2000, due to additional borrowings. In June 2000 and September 2000, the Partnership issued $250 million of 8 7/8% Senior Notes, and in March 2001, the Partnership issued $225 million of 7.10% Senior Notes. The additional borrowings were made primarily for the acquisition of gas gathering and processing businesses during 2000 and the acquisitions made in March 2001 and April 2001 (see Item 1. "Business"). Interest expense attributable to Northern Border Pipeline decreased $9.8 million (15%) for the year ended December 31, 2001, as compared to the same period in 2000, due primarily to a decrease in Northern Border Pipeline's average interest rate between 2000 and 2001 as well as a decrease in average debt outstanding. Other income decreased $7.9 million for the year ended December 31, 2001, as compared to the same period in 2000. Other income for 2001 includes a net 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. 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. Also included for 2001 are non-recurring charges of $2.4 million, primarily related to a loss on a forward purchase of Canadian dollars to fund the acquisition of gathering and processing assets in Alberta, Canada. Equity earnings (losses) in 21 unconsolidated affiliates increased $2.3 million to $1.7 million for 2001 as compared to 2000. Goodwill amortization netted against equity earnings (losses) in unconsolidated affiliates totaled $6.3 million and $2.2 million in 2001 and 2000, respectively. See "New Accounting Pronouncements" below for discussion of a recently issued accounting pronouncement that will impact goodwill amortization in 2002. The extraordinary loss from debt restructuring of $1.2 million recorded in the year ended December 31, 2001, relates to Black Mesa's 10.7% Secured Senior Notes. In June 2001, the Partnership repaid Black Mesa's 10.7% Secured Senior Notes due in 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. Minority interests in net income increased $4.0 million (11%) for the year ended December 31, 2001, as compared to the same period in 2000, due to increased net income for Northern Border Pipeline. YEAR ENDED DECEMBER 31, 2000 COMPARED WITH THE YEAR ENDED DECEMBER 31, 1999 Operating revenues, net increased $20.8 million (7%) for the year ended December 31, 2000, as compared to the same period in 1999. Operating revenues attributable to Northern Border Pipeline were $311.0 million for the year ended December 31, 2000, as compared to $298.3 million for the same period in 1999, an increase of $12.7 million (4%). Northern Border Pipeline's operating revenues for 2000 reflect the significant terms of the rate case settlement discussed in Item 1. "Business - Interstate Natural Gas Pipelines - Interstate Pipeline Regulation." Operating revenues for 1999 were determined under Northern Border Pipeline's former cost of service tariff. Operating revenues from Crestone Energy Ventures were $7.5 million for 2000, which represented three months of activity. Crestone Energy Venture's operating results occurred in the fourth quarter of 2000 after its acquisition by the Partnership in late September 2000. Operations and maintenance expense increased $8.6 million (16%) for the year ended December 31, 2000, from the same period in 1999, due primarily to $5.1 million of expense from Crestone Energy Ventures. Operations and maintenance expense attributable to Northern Border Pipeline increased $2.8 million (7%) for the year ended December 31, 2000, from the same period in 1999, due primarily to increased employee payroll and benefit expenses and costs to operate two electric-powered compressor units. Depreciation and amortization expense increased $5.9 million (11%) for the year ended December 31, 2000, as compared to the same period in 1999. Depreciation and amortization expense attributable to Northern Border Pipeline increased $5.4 million (10%) for the year ended December 31, 2000, as compared to the same period in 1999, due primarily to an increase in the depreciation rate applied to transmission plant. As a result of the rate case settlement, Northern Border Pipeline used a depreciation rate for transmission plant of 2.25% for 2000. Northern Border Pipeline had used a depreciation rate of 2.0% for 1999. 22 Taxes other than income decreased $2.3 million (7%) for the year ended December 31, 2000, as compared to the same period in 1999, due primarily to adjustments to Northern Border Pipeline's previous estimates of ad valorem taxes. Interest expense, net increased $13.8 million (20%) for the year ended December 31, 2000, as compared to the same period in 1999. Interest expense for the Partnership increased approximately $9.2 million (167%) for the year ended December 31, 2000, as compared to the same period in 1999, due to additional borrowings and an increase in interest rates. The additional borrowings were made primarily for the acquisition of gas gathering businesses in the Powder River and Wind River basins in Wyoming in December 1999, June 2000 and September 2000. Interest expense attributable to Northern Border Pipeline increased $4.9 million (8%) for the year ended December 31, 2000, as compared to the same period in 1999, due primarily to an increase in average interest rates between 1999 and 2000. The impact of the increase in interest rates was partially offset by a decrease in average debt outstanding. Other income increased $3.5 million (76%) for the year ended December 31, 2000, as compared to the same period in 1999. Other income attributable to Northern Border Pipeline increased $6.7 million (491%) for the year ended December 31, 2000, as compared to the same period in 1999, due primarily to a reduction in reserves previously established for regulatory issues as a result of the settlement of Northern Border Pipeline's rate case. The 1999 results included $3.0 million of other non-recurring income for the Partnership. Minority interests in net income increased $2.6 million (7%) for the year ended December 31, 2000, as compared to the same period in 1999, due to increased net income for Northern Border Pipeline. 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 C and D Senior Notes $ 143,000 $ 78,000 $ 65,000 $ -- $ -- Senior Notes due 2009 200,000 -- -- -- 200,000 Senior Notes due 2010 250,000 -- -- -- 250,000 Senior Notes due 2011 225,000 -- -- -- 225,000 Senior Notes due 2021 250,000 -- -- -- 250,000 Pipeline Credit Agreement 272,000 272,000 -- -- -- Partnership Credit Agreement 64,000 -- 64,000 -- -- Capital Leases 13,279 3,355 6,710 3,214 -- Operating Leases 7,622 1,327 2,787 2,322 1,186 Other Long-Term Obligations 69,135 8,176 16,374 16,352 28,233 ---------- ---------- ---------- ---------- ---------- Total $1,494,036 $ 362,858 $ 154,871 $ 21,888 $ 954,419 ========== ========== ========== ========== ==========

We have guaranteed the performance of our unconsolidated affiliates in connection with their credit agreements that expire in 23 March 2009 and September 2009. At December 31, 2001, the combined guarantee was $4.4 million. DEBT AND CREDIT FACILITIES AND ISSUANCE OF COMMON UNITS Northern Border Pipeline had previously entered into a 1997 credit agreement ("Pipeline Credit Agreement") with certain financial institutions, which is comprised of a $100 million five-year revolving credit facility and a $272 million term loan, both maturing in June 2002. At December 31, 2001, no amounts were outstanding under the five-year revolving credit facility. Northern Border Pipeline anticipates refinancing the Pipeline Credit Agreement in the second quarter of 2002. Northern Border Pipeline's refinancing plans are to issue $225 million of senior notes and to enter into a $175 million revolving credit facility. At December 31, 2001, Northern Border Pipeline also had outstanding $143 million of senior notes issued in a $250 million private placement under a July 1992 note purchase agreement. The note purchase agreement provides for four series of notes, Series A through D, maturing between August 2000 and August 2003. The Series A Notes with a principal amount of $66 million and Series B Notes with a principal amount of $41 million were repaid in August 2000 and August 2001, respectively. The Series C Notes with a principal amount of $78 million mature in August 2002. Northern Border Pipeline anticipates borrowing on the refinanced Pipeline Credit Agreement to repay the Series C 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") and in August 1999, Northern Border Pipeline completed a private offering of $200 million of 7.75% Senior Notes due 2009 ("1999 Pipeline Senior Notes"). Both the 2001 Pipeline Senior Notes and the 1999 Pipeline Senior Notes were subsequently exchanged in a registered offering for notes with substantially identical terms. The indentures under which the 2001 Pipeline Senior Notes and 1999 Pipeline Senior Notes were issued does 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 2001 Pipeline Senior Notes and 1999 Pipeline Senior Notes were used to reduce indebtedness outstanding under the Pipeline Credit Agreement. In November 2001, Northern Border Pipeline entered into forward starting interest rate swaps with notional amounts totaling $150 million related to the planned issuance of senior notes discussed previously. The swaps were entered into to hedge the fluctuations in Treasury rates and spreads between the execution date of the swaps and the issuance date of the senior notes. 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 24 subsequently exchanged in registered offerings for notes with substantially identical terms. The indentures under which the 2001 Partnership Senior Notes and 2000 Partnership Senior Notes were issued do not limit the amount of unsecured debt the Partnership may incur, but they do contain material financial covenants, including restrictions on incurrence of secured indebtedness. The indentures also contain provisions that would require the Partnership to offer to repurchase the 2001 and 2000 Partnership Senior Notes, if either Standard & Poor's Rating Services or Moodys' Investor Services, Inc. ("Moodys") rate the notes as below investment grade. In February 2002, Moodys placed Northern Border Pipeline and us on credit review for a possible downgrade in credit rating. At this time, no action has been taken by Moodys. If Moodys was to issue the downgrade, we expect our credit rating to remain above investment grade. The proceeds from the 2001 Partnership Senior Notes were used to fund a portion of the acquisition of Bear Paw Energy. The proceeds from the 2000 Partnership Senior Notes were used to fund acquisitions made by the Partnership in June 2000 and September 2000. The Partnership entered into a $200 million three-year revolving credit agreement with certain financial institutions ("2001 Partnership Credit Agreement") in March 2001. The 2001 Partnership Credit Agreement is to be used for capital expenditures, acquisitions and general business purposes. The 2001 Partnership Credit Agreement replaced revolving credit agreements entered into in June 2000. At December 31, 2001, $64.0 million was outstanding under the 2001 Partnership Credit Agreement. In the third quarter of 2001, the Partnership entered into interest rate swap agreements with notional amounts totaling $225 million that expire in March 2011. Under the interest rate swap agreements, the Partnership makes payments to counterparties at variable rates based on the London Interbank Offered Rate and in return receives payments based on a 7.10% fixed rate. The swaps were entered into to hedge the fluctuations in the market value of the 2001 Partnership Senior Notes. In April and May of 2001, the Partnership sold 407,550 and 4,000,000 common units, respectively. In conjunction with the issuance of the additional common units, including the units issued for Bear Paw Energy in March 2001, the Partnership's general partners made capital contributions to the Partnership to maintain a 2% general partner interest in accordance with the partnership agreements. The net proceeds of the sale of common units and the general partners' capital contributions totaled approximately $172.2 million and were primarily used to repay amounts borrowed under the 2001 Partnership Credit Agreement. In November 2000, the Partnership sold 2,156,250 common units. In conjunction with the issuance of the additional common units, the Partnership's general partners made capital contributions to the Partnership to maintain a 2% general partner interest in accordance with the partnership agreements. The net proceeds of the public offering and the general partners' capital contribution totaled approximately $60.7 million and were primarily used to repay amounts borrowed under revolving credit agreements. 25 Short-term liquidity needs will be met by operating cash flows and through the 2001 Partnership Credit Agreement and the Pipeline Credit Agreement, which is being refinanced in 2002. Long-term capital needs may be met through the ability to issue long-term indebtedness as well as additional limited partner interests of the Partnership. CASH FLOWS FROM OPERATING ACTIVITIES Cash flows provided by operating activities increased $64.3 million to $233.9 million for the year ended December 31, 2001, as compared to the same period in 2000. Net income to partners before depreciation and amortization increased $26.7 million primarily due to our gas gathering and processing businesses acquired in 2001 and the fourth quarter of 2000. Other cash flows from operating activities for 2001 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 provided by operating activities decreased $3.8 million to $169.6 million for the year ended December 31, 2000, as compared to the same period in 1999, primarily due to reduced earnings from higher interest costs. During 2000, we realized net cash inflows of approximately $2.4 million related to Northern Border Pipeline's rate case, which included $25.1 million of amounts collected subject to refund less estimated refunds issued in late December 2000 totaling approximately $22.7 million. CASH FLOWS FROM INVESTING ACTIVITIES Capital expenditures of $126.4 million for the year ended December 31, 2001 include $69.1 million for gas gathering and processing facilities and $57.0 million for interstate pipeline facilities. The expenditures for interstate pipeline facilities include $49.0 million for Northern Border Pipeline's Project 2000 (see Item 1. "Business - Interstate Natural Gas Pipelines - Northern Border Pipeline System"). For the same period in 2000, total capital expenditures were $19.7 million, which included $7.4 million for Project 2000 and $3.8 million for gas gathering facilities for Crestone Energy Ventures. Acquisitions of businesses of $345.1 million for the year ended December 31, 2001, represents acquisitions of Midwestern Gas Transmission and midstream assets in Alberta, Canada in April 2001 and the cash portion of the purchase price of Bear Paw Energy in March 2001. The purchase of Bear Paw Energy also involved the issuance of 5.7 million common units valued at $183.0 million. The acquisitions of businesses for the year ended December 31, 2000, included the acquisition of gas gathering businesses in the Powder River and Wind River basins in Wyoming for $229.5 million. The investments in unconsolidated affiliates of $11.2 million for the year ended December 31, 2001, primarily reflects capital 26 contributions to Bighorn. The investments in unconsolidated affiliates of $8.8 million for the year ended December 31, 2000 primarily 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, ENA agreed to fund approximately $3.5 million of an equity investment in Lost Creek. Total capital expenditures and investments in unconsolidated affiliates for 2002 are estimated to be $86 million. Capital expenditures for the interstate pipelines are estimated to be $25 million, including approximately $12 million for Northern Border Pipeline. Northern Border Pipeline currently anticipates funding its 2002 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 $49 million and additional investments in unconsolidated affiliates are estimated to be $12 million for 2002. Funds required to meet the capital requirements for 2002 are anticipated to be provided from debt borrowings, issuance of additional limited partners interests in the Partnership and operating cash flows. The estimated capital expenditures and investments do not include any amount for acquisitions of assets that might become available for purchase during the year. If any such acquisitions are made, our estimated capital requirements would be increased, which we would anticipate funding from debt borrowings and the issuance of additional limited partner interests in the Partnership. CASH FLOWS FROM FINANCING ACTIVITIES Cash flows provided by financing activities increased $129.3 million to $230.1 million for the year ended December 31, 2001, as compared to the same period in 2000. Cash distributions to the unitholders and the general partners increased $40.5 million to $120.9 million. The increase is due to both an increase in the number of common units outstanding and an increase in the distribution rate. The distributions paid in 2001 were $2.99 per unit ($0.70 per unit in the first quarter and $0.7625 per unit in the second, third and fourth quarter) as compared to distributions paid in 2000 of $2.65 per unit ($0.65 per unit in the first, second and third quarter and $0.70 per unit in the fourth quarter). In January 2002, we increased our quarterly distribution rate to $0.80 per unit. During the year ended December 31, 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 the Pipeline 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 $47.3 million of indebtedness outstanding. Repayments of amounts borrowed under the Pipeline Credit Agreement totaled $333.0 million during the year ended December 31, 2001, as compared to repayments of $45.0 million for the comparable period in 2000. A significant portion of the 2001 payments on the Pipeline Credit Agreements was made using proceeds from the 2001 Pipeline Senior Notes. In August 2001 and 27 August 2000, Northern Border Pipeline repaid its Series B and A Notes of $41 million and $66 million, respectively, primarily by borrowing under the Pipeline Credit Agreement. For the year ended December 31, 2001, we recognized a decrease in bank overdrafts of $22.4 million. At December 31, 2000, Northern Border Pipeline reflected the bank overdrafts primarily due to rate case refund checks outstanding. In March 2001, the Partnership paid approximately $4.3 million to terminate 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 the 2001 Partnership Senior Notes and 2001 Pipeline Senior Notes (see Note 7 - Notes to Consolidated Financial Statements). Financing activities for 2001 reflect the issuance of partnership interests of $172.2 million, which was primarily used to repay amounts borrowed on the 2001 Partnership Credit Agreement of $168.0 million. Cash flows provided by financing activities were $100.8 million for the year ended December 31, 2000 compared to cash flows used of $57.3 million for the same period in 1999. Cash distributions to the unitholders and the general partners increased $7.3 million to $80.4 million reflecting an increase in the distribution from $2.44 per unit for 1999 to $2.65 per unit for 2000. The proceeds from the private offering of the 2000 Partnership Senior Notes, including premiums but net of associated debt discounts and issuance costs, totaled approximately $252.0 million. The proceeds were used to repay the Partnership's existing indebtedness of $119.5 million and to partially fund the acquisition of gas gathering businesses discussed previously. The funding for the remainder of the acquisition of gas gathering businesses came from borrowings under Partnership credit agreements of $97.5 million. Financing activities for 2000 reflect $60.7 million in net proceeds from the issuance of 2,156,250 common units and a related capital contribution by the Partnership's general partners in November 2000. In December 2000, the Partnership received approximately $15.0 million from the termination of interest rate swap agreements. Repayments on the 2000 Partnership credit agreements of approximately $71.2 million were primarily made using the proceeds from the issuance of common units and the termination of the interest rate swap agreements. For the year ended December 31, 2000, advances under the Pipeline Credit Agreement, which were primarily used to repay $66 million of Series A Notes, were $75 million as compared to advances of $90 million for the same period in 1999, which were primarily used to finance a portion of the capital expenditures for The Chicago Project. Financing activities for the year ended December 31, 1999 included $197.4 million from the issuance of the Pipeline Senior Notes, net of associated debt discounts and issuance costs, and $12.9 million from the termination of Northern Border Pipeline's interest rate forward agreements. Payments on the Pipeline Credit Agreement were $45 million for the year ended December 31, 2000, as compared to $263 million for the same period 1999. At December 31, 2000, we reflected bank overdrafts of approximately $22.4 million primarily due to Northern Border Pipeline's refund checks outstanding. 28 NEW ACCOUNTING PRONOUNCEMENTS In the third quarter of 2001, the Financial Accounting Standards Board issued SFAS No. 141, "Business Combinations," SFAS No. 142, "Goodwill and Other Intangible Assets," SFAS No. 143, "Accounting for Asset Retirement Obligations" and SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets." See Note 12 - Notes to Consolidated Financial Statements. 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 Williams. Northern Plains and Pan Border were not among the Enron companies filing for Chapter 11 protection. The business of Enron and its subsidiaries that have filed for bankruptcy protection are currently being administered under the direction and control of the bankruptcy court. An unsecured creditors committee has been appointed in the Chapter 11 cases. The creditors 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, is a party to shipper contracts obligating ENA to pay for 3.5% of Northern Border Pipeline's capacity. Through October 31, 2002, ENA has temporarily released 1.1% of this capacity to a third party. Although this third party has filed a complaint with the FERC requesting, in effect, that its contract be deemed terminated as a consequence of ENA's filing for bankruptcy protection, we believe this shipper's contract will remain in effect until October 31, 2002. ENA has not assumed or rejected these contracts, but its ability to use the capacity has been suspended until it provides adequate assurance of credit support. We estimate that Northern Border Pipeline has aggregate financial exposure over the next 12 months of approximately $9 million of revenues under its firm transportation contracts with ENA. We believe that failure by ENA to perform its obligations under the firm transportation contracts will not have a material adverse impact on our financial condition. 29 In addition, Bear Paw Energy entered into certain swap arrangements with ENA to hedge risks of changes in commodity prices. These swaps were terminated prior to December 31, 2001, and Bear Paw Energy recorded bad debt expense of approximately $5.4 million. 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 2001, Bear Paw Energy recorded approximately $1.4 million into earnings and expects to record approximately $4.6 million into earnings in 2002. Also, Crestone Energy Ventures provided gas and administrative services to ENA under a Master Services Agreement. This agreement was terminated in November 2001 for ENA's failure to pay approximately $2.1 million in fees. We have retained outside counsel and intend to assert and file 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 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. Enron's filing for bankruptcy protection and related developments have had other impacts on our business and management. Arthur Andersen LLP resigned 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. Because of Enron's indirect ownership interest in us, we are willing 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 and Pan Border have not filed for Chapter 11 bankruptcy protection, their stock is owned by Enron, which is in bankruptcy. It is possible that in the course of Enron's bankruptcy proceedings, Enron could attempt to 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 current indication from Enron that they intend to sell the stock in Northern Plains or Pan Border or cause such companies to file for bankruptcy protection. 30 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. 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 Williams do not control, free of any liens, greater than 50% of general partner percentages. 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 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. We believe these administrative services could be readily obtained through other sources. 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. 31 Other than the complaint against Northern Border Pipeline filed with the FERC by the shipper with temporarily released capacity, we are not are not aware of any claims made against us that arise out of the Enron bankruptcy cases. We plan to continue to monitor developments at Enron, to continue 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. Growth in our interstate pipelines is expected to occur primarily in market areas we serve through incremental projects supported by long-term contracts. Project 2000, our recently completed extension into Indiana, is a good example. This project, completed on time and well under budget, connects Northern Border Pipeline directly to a large Chicago-area gas distribution company (Northern Indiana Public Service Company) and to industrial gas consumers in northern Indiana. We also intend to continue to expand the marketing of new services to meet our customers' needs. Depending on natural gas prices and gas development activities, selected opportunities to connect new sources of supply to our interstate pipelines may arise. We are currently working with producers and marketers to develop the contractual support for a new 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 Joliet Compression Project will provide the opportunity 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. In 2002, Northern Border Pipeline will begin contract extension discussions with customers for contracts that will expire prior to November 1, 2003, which represents approximately 42% of its system capacity. 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 of late, 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. We can begin this process during a period that extends from 6 to 18 months before the termination date of the contract. The 32 commencement of any bidding negotiations and the market conditions affecting the value of transportation on the pipeline. 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 negotiated rate contracts involving charges established on the basis of Canadian-midwestern U.S. gas price differentials or other factors. NATURAL GAS GATHERING AND PROCESSING We also are aggressively developing our gas gathering and processing segment where we are building on our established business relationships with producers and marketers in the Canadian and Rocky Mountain supply basins. 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 and water-discharge permitting, we expect 50 to 70 percent growth in aggregate gathered volumes on our Powder River systems (Bear Paw Energy, Bighorn and Fort Union) during 2002. 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 the nature of and 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 decline and provide solid growth in revenues and further improve cost efficiencies due to the increased scale and scope of our gathering and processing operations. ACQUISITIONS Finally, our objective is to continue to acquire complementary businesses. Our goal is approximately $200 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 33 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 - Impact of Enron's Chapter 11 Filing On Our Business"; 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 Any customer's failure to perform its contractual obligations could adversely impact our cash flows and financial condition. ENA has 3.5% of Northern Border Pipeline's firm capacity and less than 1% of Midwestern Gas Transmission's firm capacity and has failed to pay its demand and any applicable commodity charges due for November 2001 transport and thereafter. ENA has neither assumed nor rejected its contracts and its ability to use the capacity has been suspended. Until ENA assumes or rejects its contracts, Northern Border Pipeline and Midwestern Gas Transmission are unable to recontract all or a portion of this capacity on a longer-term basis. See "Impact of Enron's Chapter 11 Filing On Our Business" above. 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 it provides 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. See "Impact of Enron's Chapter 11 Filing On Our Business" above. o Contracts representing approximately 42% of Northern Border Pipeline's system capacity will expire prior to November 1, 2003. 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 34 gas in our market areas and the basis differential between the receipt and delivery points on our system. See "Outlook" 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 We face competition from third parties in our natural gas transportation, gathering and processing businesses. See Item 1. "Business - Interstate Pipeline Competition" and "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." 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. 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, 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." 35 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 Risks" 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. 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 substantially reduced. In addition, the entire amount of cash received by each unitholder would generally be taxed as a corporate dividend when received. 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 to fund our acquisition of Canadian midstream assets, we have not used financial instruments in the management of exchange rates. 36 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. As of December 31, 2001, approximately 60% of our debt portfolio is in fixed rate debt. If average interest rates change by one percent compared to rates in effect as of December 31, 2001, consolidated annual interest expense would change by approximately $5.6 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, 2001. COMMODITY PRICE RISK Our gas gathering and processing businesses are subject to certain contracts that give it quantities of natural gas and natural gas liquids as partial consideration for processing services. The income and cash flows from these contracts will be impacted by changes in prices for these commodities. For each $0.10 per mcf 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 $0.4 million. This amount has been determined by considering the impact of the hypothetical commodity prices on our projected gathering and processing volumes for 2002. We have hedged a portion of our commodity price risk in 2002. 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 (a) Effective February 5, 2002, Arthur Andersen LLP ("Andersen") resigned as auditors of the Partnership. (b) The reports of Andersen on the Partnership's financial statements for the past two fiscal years did not contain an adverse opinion or disclaimer of opinion and were not qualified or modified as to audit scope, uncertainty or accounting principles. Andersen has advised us that it has not withdrawn any of its opinions expressed in their auditor's report for any periods for which they conducted audits of the Partnership. (c) The resignation by Andersen was not approved by the Partnership Policy Committee or the Audit Committee of the Partnership. (d) During the preceding two years and in the subsequent interim periods, there were no disagreements with Andersen 37 on any matters of accounting principles or practices, financial statement disclosures, or auditing scope or procedures, which if not resolved to the satisfaction of Andersen would have caused Andersen to make reference to the matter in their report. (e) During the preceding two years and in the subsequent interim periods, there were no "reportable events" within the meaning of Item 304(a)(1)(v) of Regulation S-K. (f) The Partnership has retained the services of KPMG LLP as its independent auditor. 38 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 public accountants, 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 170 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. Effective March 18, 2002, Gary N. Petersen was appointed to the Audit Committee, replacing Daniel Dienstbier who resigned on January 12, 2002. There are no family relationships between any of our executive officers or members of the Partnership Policy and Audit Committees. 39

NAME AGE POSITIONS ---- --- --------- Executive Officers: William R. Cordes 53 Chief Executive Officer Jerry L. Peters 44 Chief Financial and Accounting Officer Members of Partnership Policy Committee and Partnership's representatives on Northern Border Management Committee: William R. Cordes 53 Chairman Stanley C. Horton 52 Member James C. Moore 46 Member Members of Audit Committee: Daniel P. Whitty 70 Chairman Gerald B. Smith 51 Member Gary N. Petersen 50 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. He started his career with another Enron company, Northern Natural, in 1970 and has worked in several management positions at Northern Natural. 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 President of Transwestern Pipeline. 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 is a Director and Chairman of the Board of EOTT Energy Corp., the general partner of EOTT Energy Partners, L.P. Mr. Horton also holds the elected position of officer and/or director of the following companies that have filed for Chapter 11 bankruptcy protection: Calypso Pipeline, L.L.C. (Director) Enron Transportation Services Company (Chairman, President and Chief Executive Officer and Director) Enron Wind Corp. (Chairman, Director) Enron Wind Systems, Inc. (Director) Enron Wind Energy Systems Corp. (Chairman, Director) Enron Wind Maintenance Corp. (Chairman, Director) Enron Wind Constructors Corp. (Chairman, Director) James C. Moore was named to the Partnership Policy Committee and to the Northern Border Management Committee on December 21, 2001. Mr. Moore has served as Senior Vice President of Group Planning and Development for 40 Williams Gas Pipeline since August 2001. He joined Williams in 1990 as Director of MIS and in 1992 he became Director of Business Development for Williams Natural Gas. In August 2000, he was named Vice President of Group Planning and Development for Williams Gas Pipeline. Mr. Moore serves as one of Williams' representatives on the Canadian and U.S. boards of Alliance Pipeline. 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 named Vice President, Finance of: Florida Gas Transmission Company in February 2001; Transportation Trading Services Company in September 2001; Citrus Corp. in October 2001; and Transwestern Pipeline Company in November 2001. 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 fixed income 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 provides consulting services related to strategic and financial planning. Additionally, he is currently the President of Endres Processing LLC. From 1977 to 1998, Mr. Petersen was employed by Reliant Energy-Minnegasco. He served as Reliant Energy-Minnegasco's President and Chief Operating Officer from 1991 to 1998. Prior to his employment at Minnegasco, he was a senior auditor with Andersen. He currently serves on the board 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 2001 our reporting persons complied with all applicable filing requirements in a timely manner except Cub Investment, LLC, 41 Haddington/Chase Energy Partners (Bear Paw) LP, and James C. Moore did not timely file one report each on Form 3. Mr. Moore's filed report on Form 3 disclosed no ownership in our common units. 42 ITEM 11. EXECUTIVE COMPENSATION The following table summarizes certain information regarding compensation paid or accrued during each of Northern Plains' last three fiscal years to the executive officers of the Partnership (the "Named Officers") for services performed in their capacities as executive officers of Northern Plains: SUMMARY COMPENSATION TABLE

All Other Annual Compensation Long-Term Compensation Compensation ------------ Securities Restricted Underlying Other Annual Stock Awards Options/SARs LTIP Payouts Name & Position Year Salary(1) Bonus(2) Compensation(3) ($)(4)(5) (#) ($)(6) ($)(7) --------------- ---- --------- --------- -------------- ------------ ------------ ------------ ------- William R. Cordes 2001 $312,000 $250,000 $ 8,550 $227,150 6,475 $300,000 $ 255 Chief Executive Officer 2000 $311,000 $250,000 $ 15,000 $137,529 17,405 $131,250 $ 13,110 Jerry L. Peters 2001 $154,292 $125,000 $ 3,399 $ 75,063 7,085 $ -- $ 198 Chief Financial and 2000 $145,293 $110,000 $ 3,708 $ 75,036 15,040 $ -- $ 10,091 Accounting Officer 1999 $132,933 $100,000 $ 3,983 $ -- 9,070 $ -- $ 5,260

(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 1,532 units in 1999; 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 1999, 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 1999, 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 1999, 2000 and 2001. (4) The aggregate total of shares in unreleased Enron restricted stock holdings and their values as of December 31, 2001, for each of the Named Officers is: Mr. Cordes, 4,295 shares valued at $2,577, and Mr. Peters, 1,701 shares valued at $1,021. Dividend equivalents for all restricted stock awards accrue from date of grant and are paid upon vesting. Any dividends on Enron Corp. stock accrued an unreleased as of the date of Enron Corp's filing for bankruptcy protection will only be released in accordance with applicable bankruptcy law. 43 (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. 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. It's performance over the 1997-2000 performance period rendered a value of $2.00 based on a ranking of first. (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. 44 STOCK OPTION GRANTS DURING 2001 The following table sets forth information with respect to 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 2001.

POTENTIAL REALIZABLE VALUE AT ASSUMED ANNUAL RATES INDIVIDUAL GRANTS OF STOCK PRICE APPRECIATION FOR OPTION TERM(1) ------------------------------------------------------------ -------------------------------------------------- Number of % of Total Securities Options/SARs Exercise Underlying Granted to or Base Options/SARs Employees in Price Expiration Name Granted (#) Fiscal Year ($/Sh) Date 0%(2) 5% 10% ---- ------------ ------------- ---------- ----------- ------ -- --- William R. Cordes 5,435 (3) 0.03% $75.0625 1/22/2006 $ -0 $ -0 $-0 1,040 (4) 0.01% $36.8800 8/21/2006 $ -0 $ -0 $-0 Jerry L. Peters 3,265 (3) 0.02% $75.0625 1/22/2006 $ -0 $ -0 $-0 3,300 (5) 0.02% $75.0625 1/22/2006 $ -0 $ -0 $-0 520 (4) 0.00% $36.8800 8/21/2006 $ -0 $ -0 $-0

(1) The dollar amounts under these columns represent the potential realizable value of each grant of options assuming that the market price on Enron Common Stock appreciates in value from the date of grant at the 5% and 10% annual rates prescribed by the SEC and therefore are not intended to forecast possible future appreciation, if any, of the price of Enron Common Stock. This section is not applicable under the current circumstances. (2) An appreciation in stock price, which will benefit all shareholders, is required for optionees to receive any gain. A stock price appreciation of 0% would render the option without value to the optionees. (3) Represents stock options awarded under the Enron Corp. Long-Term Incentive Program. Awards vest 15% on the grant date and 15% every 6 months thereafter with the final vesting of 10% on January 31, 2004. (4) All eligible Enron employees received an option grant under the 2001 Special Stock Option Grant. A grant of options equal to 5% of base annual salary as of August 13, 2001 was awarded on August 21, 2001. Options granted through the 2001 Special Stock Option Grant were 100% vested on the date of grant. (5) Mr. Peters elected to receive stock options in lieu of a portion of his 2000 annual cash bonus payment in the form of stock options, which were granted in January, 2001 and were 100% vested on date of grant. 45 AGGREGATED STOCK OPTION/SAR EXERCISES DURING 2001 AND STOCK OPTION/SAR VALUES AS OF DECEMBER 31, 2001 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, 2001 December 31, 2001 (1) Acquired on Value ----------------------------- ----------------------------- Name Exercise (#) Realized Exercisable Unexercisable Exercisable Unexercisable ---- ------------ ------------ ------------ ------------- ------------ ------------- William R. Cordes 20,240 $ 651,850 223,118 21,482 $ -- $ -- Jerry L. Peters 5,000 $ 146,233 59,808 7,777 $ -- $ --

(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, 2001 ($0.60) 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 annual base pay beginning January 1, 1996. Under the Cash Balance Plan, each employee's accrued benefit will be credited with interest based on ten-year Treasury Bond yields. Enron also maintains a noncontributory employee stock ownership plan ("ESOP"), which covers all eligible employees. Allocations to individual employees' retirement accounts within the ESOP offset a portion of benefits earned under the Cash Balance Plan prior to December 31, 1994. December 31, 1993 was the final date on which ESOP allocations were made to employees' retirement accounts. In addition, Enron has a Supplemental Retirement Plan that is designed to assure payments to certain employees of that retirement income that would be provided under the Cash Balance Plan except for the dollar limitation on accrued benefits imposed by the Internal Revenue Code of 1986, as amended, and a Pension Program for Deferral Plan Participants that provides supplemental retirement benefits equal to any reduction in benefits due to deferral of salary into Enron's Deferral Plan. 46 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 31.4 43.1 $312,000 $115,593 Mr. Peters 16.9 37.8 $155,024 $ 59,481

---------- 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' Severance Pay Plan provides 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. 47 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 21, 2002 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 * 1111 South 103rd Street Omaha, NE 68124-10000 Jerry L. Peters(1) 1,000 * 1111 South 103rd Street Omaha, NE 68124-1000 Stanley C. Horton(1) 15,000 * 1400 Smith Street Houston, TX 77002-7369 Gary N. Petersen 5,500 * 3520 Wedgewood Ln. N Plymouth, MN 55441-2262 Enron Corp.(2) 3,214,338 7.7 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 504,338 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 shown as shared by Enron and Citibank, N.A. 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 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: 48 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, 2001, the aggregate amount charged by Northern Plains for it services was approximately $31.5 million. o NBP Services, a subsidiary of Enron which 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, 2001, the aggregate amount charged by NBP Services for its services was approximately $15.3 million. o Crestone Energy Ventures provided gas gathering and administrative services for fixed and variable fees to Enron North America Corp. ("ENA"), an Enron subsidiary that has filed for bankruptcy protection, under a Master Services Agreement effective September 21, 2000. The amount of fixed fees for 2001 was $21,600 per day. The Master Services Agreement was terminated for ENA's failure to pay and was replaced by individual gathering and various service agreements with individual producers. The approximate amount of the unpaid fees is $2,150,000. o Bear Paw Energy entered into certain swap arrangements with ENA to hedge risks of changes in commodity prices. ENA's obligations were supported by a guaranty by Enron. These arrangements were terminated by Bear Paw Energy on November 28, 2001, at which time the market value of the swaps was approximately $5 million in our favor. o ENA is one of Northern Border Pipeline's firm shippers, and is obligated to pay for 3.5% of the capacity. A guaranty from Enron supported ENA's obligations. ENA is also a shipper on Midwestern Gas Transmission. At present, ENA has not assumed or rejected the contracts on Northern Border Pipeline or Midwestern Gas Transmission. ENA's ability to utilize their capacity has been suspended until ENA provides adequate assurances of credit support and payment. Northern Border Pipeline and Midwestern Gas Transmission's ability to terminate ENA's contracts are stayed as a result of the bankruptcy court proceedings. See Item 7. "Management's Discussion and Analysis of Financial Condition and Results of Operations - Impact of Enron's Chapter 11 Filing on Our Business." In addition, Northern Border Pipeline has other ongoing relationships with the general partners and certain of their affiliates. Transcontinental Gas Pipe Line Corporation, an affiliate of Williams, is one of Northern Border Pipeline's firm shippers and is currently obligated to pay for 0.7% of the capacity. 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. These representatives are also designated by our general partners. Our interests could conflict with the interests of our general partners or their affiliates, and in such case the members of the Partnership Policy 49 Committee will generally have a fiduciary duty to resolve such conflicts in a manner that is in our best interest. Northern Border Pipeline's interests could conflict with our interest or the interest of TC PipeLines and its affiliates, and in such case our representatives on the Northern Border 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. Our fiduciary duty as a general partner of Northern Border Pipeline may prevent us from taking actions that might be in our best interest but in conflict with the fiduciary duty that our representatives or we owe to Northern Border Pipeline or TC PipeLines. 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 duty to offer business opportunities to Northern Border Pipeline, with certain exceptions. 50 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. 51 PART IV ITEM 14. 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. * 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"). *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 Operating Agreement between Northern Border Pipeline Company and Northern Plains Natural Gas Company, dated February 28, 1980 (Exhibit 10.3 to Form S-1). *10.3 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). *10.4 Note Purchase Agreement between Northern Border Pipeline Company and the parties listed therein, dated July 15, 1992 (Exhibit 10.6 to Form S-1). 52 *10.5 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")). *10.6 Northern Border Pipeline Company U.S. Shippers Service Agreement between Northern Border Pipeline Company and Enron Gas Marketing, Inc., dated June 22, 1990 (Exhibit 10.10 to Form S-1). *10.7 Amended Exhibit A to Northern Border Pipeline Company U.S. Shippers Service Agreement between Northern Border Pipeline Company and Enron Gas Marketing, Inc. (Exhibit 10.10.1 to the Partnership's Annual Report on Form 10-K for the year ended December 31, 1993 ("1993 10-K")). *10.8 Amended Exhibit A to Northern Border Pipeline U.S. Shippers Service Agreement between Northern Border Pipeline Company and Enron Gas Marketing, Inc., effective November 1, 1994 (Exhibit 10.10.2 to the Partnership's Annual Report on Form 10-K for the year ended December 31, 1994). *10.9 Amended Exhibit A's to Northern Border Pipeline Company U.S. Shipper Service Agreement effective, August 1, 1995 and November 1, 1995 (Exhibit 10.10.3 to 1995 10-K). *10.10 Amended Exhibit A to Northern Border Pipeline Company U.S. Shipper Service Agreement effective April l, 1998 (Exhibit 10.10.4 to the Partnership's Annual Report on Form 10-K for the year ended December 31, 1997 ("1997 10-K")). *10.11 Guaranty made by Enron Corp. dated August 8, 1989 (Exhibit 10.9 to Northern Border Pipeline Company's Form 10-K for the year ended December 31, 2001("NB Pipeline 2001 10-K")). *10.12 Form of Seventh Supplement Amending Northern Border Pipeline Company General Partnership Agreement (Exhibit 10.15 to Form S-1). *10.13 Northern Border Pipeline Company U.S. Shippers Service Agreement between Northern Border Pipeline Company and Transcontinental Gas Pipe Line Corporation, dated July 14, 1983, with Amended Exhibit A effective February 11, 1994 (Exhibit 10.17 to 1995 10-K). *10.14 Form of Credit Agreement among Northern Border Pipeline Company, The First National Bank of Chicago, as Administrative Agent, The First National Bank of Chicago, Royal Bank of Canada, and Bank of America National Trust and Savings Association, as Syndication Agents, First Chicago Capital Markets, Inc., Royal Bank of Canada, and BancAmerica Securities, Inc, as Joint Arrangers and Lenders (as defined therein) dated as of June 16, 1997 (Exhibit 10(c) to Amendment No. 1 to Form S-3, Registration Statement No. 333-40601 ("Form S-3")). *10.15 Northern Border Pipeline Company U.S. Shippers Service Agreement between Northern Border Pipeline Company and Enron Capital & Trade Resources Corp. dated October 15, 1997 (Exhibit 10.21 to 1997 10-K). *10.16 Guaranty made by Enron Corp., dated October 20, 1997 (Exhibit 10.16 to NB Pipeline 2001 10-K). *10.17 Northern Border Pipeline Company U.S. Shippers Service Agreement between Northern Border Pipeline Company and Enron Capital & Trade Resources Corp. dated October 15, 1997 (Exhibit 10.22 to 1997 10-K). 53 *10.18 Guaranty made by Enron Corp., dated October 20, 1997 (Exhibit 10.18 to NB Pipeline 2001 10-K). *10.19 Northern Border Pipeline Company U.S. Shippers Service Agreement between Northern Border Pipeline Company and Enron Capital & Trade Resources Corp. dated August 5, 1997 with Amendment dated September 25, 1997 (Exhibit 10.25 to 1997 10-K). *10.20 Guaranty made by Enron Corp., dated April 29, 1997 (Exhibit 10.20 to NB Pipeline 2001 10-K). *10.21 Northern Border Pipeline Company U.S. Shippers Service Agreement between Northern Border Pipeline Company and Enron Capital & Trade Resources Corp. dated August 5, 1997 (Exhibit 10.26 to 1997 10-K). *10.22 Guaranty made by Enron Corp., dated April 29, 1997 (Exhibit 10.22 to NB Pipeline 2001 10-K). *10.23 Project Management Agreement by and between Northern Plains Natural Gas Company and Enron Engineering & Construction Company, dated March 1, 1996 (Exhibit No. 10.39 to NB Form S-4). *10.24 Eighth Supplement Amending Northern Border Pipeline Company General Partnership Agreement (Exhibit 10.15 to NB Form S-4). *10.25 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")). *10.26 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")). *10.27 Northern 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). *10.28 Northern Border Pipeline Company U.S. Shippers Service Agreement between Northern Border Pipeline Company and Pan-Alberta Gas (U.S.) Inc., dated October 1, 1992, with Amended Exhibit A effective June 22, 1998 (Exhibit 10.38 to NB Pipeline 1999 10-K). *10.29 Purchase and Sale Agreement, dated as of September 21, 2000 by and between Enron North America Corp. and NBP Energy Pipeline, L.L.C. (now known as Crestone Energy Ventures, L.L.C.) (Exhibit 10.24 to 2000 10-K). *10.30 Master Services Agreement, dated as of September 21, 2000 between NBP Energy Pipelines, L.L.C., (now known as Crestone Energy Ventures, L.L.C.) and Enron North America Corp. (Exhibit 10.25 to 2000 10-K). *10.31 Acquisition Agreement, dated as of March 14, 2001, among Northern Border Partners, L.P., Northern Border Intermediate Limited Partnership, Bear Paw Investments, LLC, Bear Paw Energy, LLC and Sellers (defined therein) (Exhibit 10.26 to 2000 10-K). 54 *10.32 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). *10.33 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). *10.34 Ninth Supplement Amending Northern Border Pipeline Company General Partnership Agreement (Exhibit 10.37 to 2001 Form S-4). *10.35 Northern Border Pipeline Company U.S. Shipper Service Agreement between Northern Border Pipeline Company and Enron North America Corp., dated October 29, 2001 (Exhibit 10.38 to 2001 Form S-4). *10.36 Northern Border Pipeline Company U.S. Shipper Service Agreement between Northern Border Pipeline Company and Enron North America Corp., dated October 29, 2001 (Exhibit 10.35 to NB Pipeline 2001 10-K). *10.37 Guaranty made by Enron Corp., dated October 31, 2001 (Exhibit 10.36 to NB Pipeline 2001 10-K). 10.38 Operating Agreement between Midwestern Gas Transmission Company and Northern Plains Natural Gas Company dated as of April 1, 2001. 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; and Midwestern Gas Transmission Company. 23.01 Consent of Arthur Andersen 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). *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 November 29, 2001, which included a press release issued by Northern Border Partners to reassure investors regarding its exposure to Enron. 55 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 29th day of March, 2002. NORTHERN BORDER PARTNERS, L.P. (A Delaware Limited Partnership) By: /s/ 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 --------- ----- ---- WILLIAM R. CORDES Chief Executive Officer and March 29, 2002 ------------------------------------ Chairman of the Partnership William R. Cordes Policy Committee (Principal Executive Officer) STANLEY C. HORTON Member of Partnership Policy March 29, 2002 ------------------------------------ Committee Stanley C. Horton James C. Moore Member of Partnership Policy March 29, 2002 ------------------------------------ Committee James C. Moore. JERRY L. PETERS Chief Financial and March 29, 2002 ------------------------------------ Accounting Officer Jerry L. Peters

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

PAGE NO. -------- Consolidated Financial Statements Independent Auditors' Report F-2 Report of Independent Public Accountants F-3 Consolidated Balance Sheet - December 31, 2001 and 2000 F-4 Consolidated Statement of Income - Years Ended F-5 December 31, 2001, 2000 and 1999 Consolidated Statement of Comprehensive Income - Years Ended F-5 December 31, 2001, 2000 and 1999 Consolidated Statement of Cash Flows - Years Ended F-6 December 31, 2001, 2000 and 1999 Consolidated Statement of Changes in Partners' Equity - F-7 Years Ended December 31, 2001, 2000 and 1999 Notes to Consolidated Financial Statements F-8 through F-32 Financial Statements Schedule Independent Auditors' Report on Schedule S-1 Report of Independent Public Accountants on Schedule S-2 Schedule II - Valuation and Qualifying Accounts S-3

F-1 INDEPENDENT AUDITORS' REPORT To Northern Border Partners, L.P.: We have audited the accompanying consolidated balance sheet of Northern Border Partners, L.P. (a Delaware limited partnership) and Subsidiaries as of December 31, 2001, and the related consolidated statements of income, comprehensive income, cash flows and changes in partners' equity for the year then ended. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audit. The accompanying consolidated financial statements of Northern Border Partners, L.P. as of December 31, 2000 and for the years ended December 31, 2000 and 1999 were audited by other auditors whose report thereon dated January 22, 2001 expressed an unqualified opinion on those statements. We conducted our audit 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 audit provides a reasonable basis for our opinion. In our opinion, the 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, 2001, and the results of their operations and their cash flows for the year then ended, in conformity with accounting principles generally accepted in the United States of America. As discussed in note 7 to the consolidated financial statements, Northern Border Partners, L.P. and Subsidiaries adopted the provisions of Statement of Financial Accounting Standards (SFAS) No. 133, "Accounting for Derivative Instruments and Hedging Activities," which was subsequently amended by SFAS No. 137 and SFAS No. 138. KPMG LLP Omaha, Nebraska, March 8, 2002 F-2 REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS To Northern Border Partners, L.P.: We have audited the accompanying consolidated balance sheet of Northern Border Partners, L.P. (a Delaware limited partnership) and Subsidiaries as of December 31, 2000, and the related consolidated statements of income, comprehensive income, cash flows and changes in partners' equity for each of the two years in the period ended December 31, 2000. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the 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, 2000, and the results of their operations and their cash flows for each of the two years in the period ended December 31, 2000, in conformity with accounting principles generally accepted in the United States. ARTHUR ANDERSEN LLP Omaha, Nebraska, January 22, 2001 F-3 NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEET (IN THOUSANDS)

DECEMBER 31, ----------------------- ASSETS 2001 2000 ---------- ---------- CURRENT ASSETS Cash and cash equivalents $ 16,755 $ 35,363 Accounts receivable (net of allowance for doubtful accounts of $1,964 and $0 in 2001 and 2000, respectively) 49,285 31,538 Related party receivables (net of allowance for doubtful accounts of $8,779 and $0 in 2001 and 2000, respectively) 455 9,079 Materials and supplies, at cost 5,584 4,896 Other 6,572 840 ---------- ---------- Total current assets 78,651 81,716 ---------- ---------- PROPERTY, PLANT AND EQUIPMENT Interstate Natural Gas Pipelines 2,466,427 2,378,892 Gas Gathering and Processing 320,603 33,602 Coal Slurry 42,661 42,424 ---------- ---------- Total property, plant and equipment 2,829,691 2,454,918 Less: Accumulated provision for depreciation and amortization 789,592 722,842 ---------- ---------- Property, plant and equipment, net 2,040,099 1,732,076 ---------- ---------- INVESTMENTS AND OTHER ASSETS Investment in unconsolidated affiliates 239,729 221,625 Goodwill 295,402 28,405 Assets from price risk management activities 9,635 -- Other 23,839 18,898 ---------- ---------- Total investments and other assets 568,605 268,928 ---------- ---------- Total assets $2,687,355 $2,082,720 ========== ========== LIABILITIES AND PARTNERS' EQUITY CURRENT LIABILITIES Current maturities of long-term debt $ 352,395 $ 44,464 Accounts payable 20,434 33,669 Related party payables 18,812 1,744 Accrued taxes other than income 28,730 28,493 Accrued interest 20,550 15,635 Accumulated provision for rate refunds -- 4,726 ---------- ---------- Total current liabilities 440,921 128,731 ---------- ---------- LONG-TERM DEBT, net of current maturities 1,070,832 1,127,498 ---------- ---------- MINORITY INTERESTS IN PARTNERS' EQUITY 250,078 248,098 ---------- ---------- RESERVES AND DEFERRED CREDITS 10,566 6,119 ---------- ---------- COMMITMENTS AND CONTINGENCIES (NOTE 10) PARTNERS' EQUITY Partners' capital 894,429 572,274 Accumulated other comprehensive income 20,529 -- ---------- ---------- Total partners' equity 914,958 572,274 ---------- ---------- Total liabilities and partners' equity $2,687,355 $2,082,720 ========== ==========

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

YEAR ENDED DECEMBER 31, -------------------------------------------- 2001 2000 1999 ------------ ------------ ------------ OPERATING REVENUES Operating revenues $ 463,526 $ 363,688 $ 321,280 Provision for rate refunds (2,057) (23,956) (2,317) ------------ ------------ ------------ Operating revenues, net 461,469 339,732 318,963 ------------ ------------ ------------ OPERATING EXPENSES Product purchases 39,699 -- -- Operations and maintenance 96,449 62,097 53,451 Depreciation and amortization 76,310 60,699 54,842 Taxes other than income 28,052 28,634 30,952 ------------ ------------ ------------ Operating expenses 240,510 151,430 139,245 ------------ ------------ ------------ OPERATING INCOME 220,959 188,302 179,718 ------------ ------------ ------------ INTEREST EXPENSE Interest expense 91,653 81,881 67,807 Interest expense capitalized (1,745) (386) (98) ------------ ------------ ------------ Interest expense, net 89,908 81,495 67,709 ------------ ------------ ------------ OTHER INCOME Allowance for equity funds used during construction 947 305 101 Equity earnings (losses) of unconsolidated affiliates 1,697 (647) -- Other income (expense), net (2,558) 8,374 4,461 ------------ ------------ ------------ Other income 86 8,032 4,562 ------------ ------------ ------------ MINORITY INTERESTS IN NET INCOME 42,138 38,119 35,568 ------------ ------------ ------------ NET INCOME BEFORE EXTRAORDINARY ITEMS 88,999 76,720 81,003 EXTRAORDINARY LOSS FROM DEBT RESTRUCTURING (1,213) -- -- ------------ ------------ ------------ NET INCOME TO PARTNERS $ 87,786 $ 76,720 $ 81,003 ============ ============ ============ NET INCOME PER UNIT (NOTE 11) $ 2.12 $ 2.50 $ 2.70 ============ ============ ============ NUMBER OF UNITS USED IN COMPUTATION 38,538 29,665 29,347 ============ ============ ============

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

YEAR ENDED DECEMBER 31, -------------------------------------------- 2001 2000 1999 ------------ ------------ ------------ Net income to partners $ 87,786 $ 76,720 $ 81,003 Other comprehensive income: Transition adjustment from adoption of SFAS No. 133 22,183 -- -- Change associated with current period hedging transactions (1,100) -- -- Change associated with current period foreign currency translation (554) -- -- ------------ ------------ ------------ Total comprehensive income $ 108,315 $ 76,720 $ 81,003 ============ ============ ============

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

YEAR ENDED DECEMBER 31, -------------------------------------------- 2001 2000 1999 ------------ ------------ ------------ CASH FLOWS FROM OPERATING ACTIVITIES: Net income to partners $ 87,786 $ 76,720 $ 81,003 ------------ ------------ ------------ Adjustments to reconcile net income to partners to net cash provided by operating activities: Depreciation and amortization 76,675 61,054 54,895 Minority interests in net income 42,138 38,119 35,568 Writedown of financial instruments 5,304 -- -- Provision for rate refunds 2,036 25,082 2,317 Rate refunds paid (6,762) (22,673) -- Allowance for equity funds used during construction (947) (305) (101) Reserves and deferred credits 119 (4,801) 1,077 Changes in components of working capital 20,677 (2,279) (1,482) Other 6,922 (1,302) 91 ------------ ------------ ------------ Total adjustments 146,162 92,895 92,365 ------------ ------------ ------------ Net cash provided by operating activities 233,948 169,615 173,368 ------------ ------------ ------------ CASH FLOWS FROM INVESTING ACTIVITIES: Capital expenditures for property, plant and equipment, net (126,414) (19,721) (102,270) Acquisition of businesses (345,074) (229,505) (31,895) Investments in unconsolidated affiliates and other (11,197) (8,766) -- ------------ ------------ ------------ Net cash used in investing activities (482,685) (257,992) (134,165) ------------ ------------ ------------ CASH FLOWS FROM FINANCING ACTIVITIES: Cash distributions General and limited partners (120,884) (80,411) (73,160) Minority Interests (42,910) (40,471) (38,149) Issuance of partnership interests, net 172,222 60,696 -- Issuance of long-term debt, net 863,103 431,148 313,526 Retirement of long-term debt (604,929) (304,817) (270,805) Increase (decrease) in bank overdrafts (22,437) 22,437 -- Proceeds (payments) upon termination of derivatives (8,417) 15,005 12,896 Long-term debt financing costs (5,619) (2,774) (1,626) ------------ ------------ ------------ Net cash provided by (used in) financing activities 230,129 100,813 (57,318) ------------ ------------ ------------ NET CHANGE IN CASH AND CASH EQUIVALENTS (18,608) 12,436 (18,115) Cash and cash equivalents-beginning of year 35,363 22,927 41,042 ------------ ------------ ------------ Cash and cash equivalents-end of year $ 16,755 $ 35,363 $ 22,927 ============ ============ ============ Changes in components of working capital: Accounts receivable $ 6,493 $ (8,502) $ (8,691) Materials and supplies and other (4,937) (1,313) (221) Accounts payable 14,321 4,755 (3,897) Accrued taxes other than income (115) 1,686 6,468 Accrued interest 4,915 (1,973) 5,146 Over/under recovered cost of service -- 3,068 (287) ------------ ------------ ------------ Total $ 20,677 $ (2,279) $ (1,482) ============ ============ ============

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

ACCUMULATED OTHER TOTAL GENERAL COMMON SUBORDINATED COMPREHENSIVE PARTNERS' PARTNERS UNITS UNITS INCOME EQUITY ------------ ------------ ------------ ------------- ------------ Partners' Equity at December 31, 1998 $ 10,148 $ 401,388 $ 95,890 $ -- $ 507,426 Subordinated Units converted to Common Units -- 95,890 (95,890) -- -- Net income to partners 1,710 79,293 -- -- 81,003 Distributions paid (1,553) (71,607) -- -- (73,160) ------------ ------------ ------------ ------------ ------------ 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 ============ ============ ============ ============ ============

The accompanying notes are an integral part of these consolidated financial statements. F-7 NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 1. ORGANIZATION AND MANAGEMENT Northern Border Partners, L.P., through a subsidiary limited partnership, Northern Border Intermediate Limited Partnership, both Delaware limited partnerships, collectively referred to herein as the Partnership, owns a 70% general partner interest in Northern Border Pipeline Company (Northern Border Pipeline). The remaining 30% general partner interest in Northern Border Pipeline is owned by TC PipeLines Intermediate Limited Partnership (TC PipeLines). Crestone Energy Ventures, L.L.C. (Crestone Energy Ventures); Crestone Gathering Services, L.L.C. (Crestone Gathering Services); 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. 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 The Williams Companies, Inc. (Williams) 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 1.2% limited partner interest and Enron, through an indirect subsidiary, owns common units representing a 6.5% limited partner interest in the Partnership at December 31, 2001 (see Note 9). 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, pursuant to which NBP Services provides certain administrative, operating and management services for the Partnership and its subsidiaries and is reimbursed for its direct and indirect costs and expenses. For the years ended December 31, 2001, 2000 and 1999, the Partnership's charges from NBP Services and its affiliates totaled approximately $15.3 million, $3.5 million and $1.4 million, respectively. See Note 15 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. The day-to-day management of Northern Border Pipeline's affairs is the responsibility of Northern Plains (the Operator), F-8 NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 1. ORGANIZATION AND MANAGEMENT (continued) as defined by the operating agreement between Northern Border Pipeline and Northern Plains. Northern Border Pipeline is charged for the salaries, benefits and expenses of the Operator. For the years ended December 31, 2001, 2000 and 1999, Northern Border Pipeline's charges from the Operator totaled approximately $29.5 million, $31.7 million and $29.7 million, respectively. Additionally, Northern Border Pipeline has utilized Enron affiliates for management on pipeline expansion and extension projects. 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 with a capacity of 650 million cubic feet per day. Midwestern Gas Transmission's pipeline system connects with multiple pipeline systems, including Northern Border Pipeline. The day-to-day management of Midwestern Gas Transmission is the responsibility of Northern Plains, as defined by the operating agreement between Midwestern Gas Transmission and Northern Plains. Midwestern Gas Transmission is charged for the salaries, benefits and expenses of Northern Plains. For the year ended December 31, 2001, Midwestern Gas Transmission's charges from Northern Plains totaled approximately $2.0 million. 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 four processing plants with 90 million cubic feet per day of capacity. Following the acquisition, Bear Paw Energy's Powder River Basin gathering activities in northeastern Wyoming were integrated with those of Crestone Gathering Services. Bear Paw Energy and Crestone Gathering Services have approximately 1,100 miles of high and low pressure gathering pipelines and approximately 300,000 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 with a capacity of approximately 150 million cubic feet per day. The Partnership owns a 49% common membership interest and a 100% class A share interest in Bighorn Gas Gathering, L.L.C. (Bighorn); a 33% interest F-9 NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 1. ORGANIZATION AND MANAGEMENT (continued) 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, Crestone Gathering Services 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. 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. At December 31, 2001 and 2000, Northern Border Pipeline has reflected regulatory assets of approximately $11.5 million and $12.4 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. F-10 NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued) (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 (Pipeline Agreement). Under the terms of the Pipeline Agreement, Black Mesa receives a monthly demand payment, a per ton commodity payment and a reimbursement for certain other expenses. (E) Income Taxes Income taxes are the responsibility of the partners and are not reflected in these financial statements. However, the Northern Border Pipeline tariff establishes the method of accounting for and calculating income taxes and requires Northern Border Pipeline to reflect in its financial records the income taxes, which would have been paid or accrued if Northern Border Pipeline were organized during the period as a corporation. As a result, for purposes of determining transportation rates in calculating the return allowed by the FERC, partners' capital and rate base are reduced by the amount equivalent to the net accumulated deferred income taxes. Such amounts were approximately $336 million and $326 million at December 31, 2001 and 2000, respectively, and are primarily related to accelerated depreciation and other plant-related differences. (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 F-11 NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued) (F) Property, Plant and Equipment and Related Depreciation and Amortization (continued) the case of extraordinary retirements or sales. 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 rates applied to Northern Border Pipeline's transmission plant in 2001, 2000 and 1999 were 2.25%, 2.25% and 2.0%, respectively. Midwestern Gas Transmission applied a 1.9% depreciation rate to its transmission plant in 2001. 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 3.2% 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) Investments in Unconsolidated Affiliates The investments in unconsolidated affiliates are accounted for by the equity method. The excess of the Partnership's investments in unconsolidated affiliates over the underlying equity in the fair value of the net assets acquired is being amortized on a straight-line basis 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 8 for details on the Partnership's investments in unconsolidated affiliates and related equity earnings (losses). See Note 12 for discussion of an accounting pronouncement that will impact goodwill amortization in 2002. (I) Goodwill Goodwill consists of the excess of cost over fair value of the net assets acquired in business acquisitions and is being amortized using a straight-line method over 30 years. During 2001, 2000 and 1999, the Partnership recorded amortization expense of $7.0 million, $0.5 million and $0.3 million, respectively. This amortization expense is reflected as a component of depreciation and amortization in the consolidated statement of income. See Note 12 for discussion of an accounting pronouncement that will impact goodwill amortization in 2002. F-12 NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued) (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. See Note 7 for a discussion of the Partnership's accounting for derivatives and hedging activities. (K) Reclassifications Certain reclassifications have been made to the consolidated financial statements for prior years to conform with the current year presentation. 3. BUSINESS ACQUISITIONS In December 1999, the Partnership purchased a 39% common membership interest in Bighorn for approximately $31.9 million and in June 2000, the Partnership purchased 80% of class A shares in 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 a 100% interest in Enron Midstream Services, L.L.C., now known as Crestone Gathering Services, 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 class A shares. The Partnership completed three acquisitions during 2001. On March 30, 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. Effective May 1, 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 F-13 NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 3. BUSINESS ACQUISITIONS (continued) 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 8 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, 2000 and 1999 on the Partnership's consolidated financial position (amounts in thousands):

2001 2000 1999 -------------- -------------- -------------- Current assets $ 17,257 $ 1,949 $ -- Property, plant and equipment 249,762 29,789 -- Investments in unconsolidated affiliates 11,463 179,079 31,895 Goodwill 275,443 18,887 -- Current liabilities (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) -- -- -------------- -------------- -------------- $ 345,074 $ 229,505 $ 31,895 ============== ============== ==============

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 class A and class 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 class 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 2000 or 1999. 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. F-14 NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 4. RATES AND REGULATORY ISSUES Northern Border Pipeline Rate Case Northern Border Pipeline's revenue is derived from agreements with various shippers for the transportation of natural gas. It transports gas under a FERC regulated tariff. Northern Border Pipeline had used a cost of service form of tariff since its inception but agreed to convert to a stated rate form of tariff as part of the settlement of its 1999 rate case discussed below. Under the cost of service tariff, Northern Border Pipeline was provided an opportunity to recover all of the operations and maintenance costs of the pipeline, taxes other than income taxes, interest, depreciation and amortization, an allowance for income taxes and a regulated return on equity. Northern Border Pipeline was generally allowed to collect from its shippers a return on regulated rate base as well as recover that rate base through depreciation and amortization. Billings for the firm transportation agreements were based on contracted volumes to determine the allocable share of the cost of service and were not dependent upon the percentage of available capacity actually used. 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. The total annual cost of service increase due to Northern Border Pipeline's proposed changes was approximately $30 million. In June 1999, the FERC issued an order in which the proposed changes were suspended until December 1, 1999, after which the proposed changes were implemented with subsequent billings subject to refund. 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 approved settlement, effective December 1, 1999, shippers began paying stated transportation rates based on a straight fixed variable rate design. Under the straight fixed variable rate design, approximately 98% of the agreed upon revenue level is attributed to demand charges, based upon contracted firm capacity, and the remaining 2% is attributed to commodity charges, based on the volumes of gas actually transported on the system. 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. F-15 NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 4. RATES AND REGULATORY ISSUES (continued) Northern Border Pipeline Certificate application 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. The capital expenditures for the project are expected to be approximately $63 million, of which $60.5 million had been incurred through December 31, 2001. 5. 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 2002 to December 2013. The termination dates for Midwestern Gas Transmission's firm service agreements range from March 2002 to October 2019. Northern Border Pipeline also has interruptible service agreements with numerous other shippers. Under the approved settlement of Northern Border Pipeline's rate case discussed in Note 4, Northern Border Pipeline will reduce the billings for the firm service agreements by one half of the revenues received from the interruptible service agreements through October 31, 2003. Northern Border Pipeline is permitted to retain revenue from interruptible transportation service to offset any decontracted capacity. After October 31, 2003, all revenues from interruptible transportation service will be retained by Northern Border Pipeline. Under the capacity release provisions of Northern Border Pipeline's FERC tariff, 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, 2001, Northern Border Pipeline's largest shipper, Mirant Americas Energy Marketing, LP (Mirant) is obligated for approximately 33.7% of the contracted firm capacity, which consists of the following: 24.4% from temporary releases of firm capacity from Pan-Alberta Gas (U.S.) Inc. (PAGUS) and 9.3% from permanent releases of firm capacity from TransCanada Energy Marketing USA, Inc. (TransCanada Energy), an affiliate of TC PipeLines. The PAGUS firm service agreements expire in October 2003. The permanent release to Mirant commenced in December 2001 and the firm service agreements expire in October 2006 and December 2008. The obligations of Mirant and PAGUS 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 the Mirant and PAGUS firm service agreements and interruptible service agreements for the years ended December 31, 2001, 2000 and 1999 were $80.7 million, $78.2 million and $76.6 million, respectively. F-16 NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 5. TRANSPORTATION AGREEMENTS (continued) Some of Northern Border Pipeline's shippers are affiliated with its general partners. ENA has firm service agreements representing 3.5% of capacity, a portion of which (1.1%) has been temporarily released to a third party until October 31, 2002 (see Note 15). Transcontinental Gas Pipe Line Corporation, a subsidiary of Williams, holds a firm service agreement representing 0.7% of capacity. The firm service agreements with affiliates extend for various terms with termination dates that range from October 2002 to May 2009. Operating revenues from the affiliated firm service agreements and interruptible service agreements, including revenues from TransCanada Energy when it held capacity on Northern Border Pipeline, were $52.1 million, $58.5 million and $52.5 million for the years ended December 31, 2001, 2000, and 1999, respectively. Based upon the proportionate share of capacity, two of Midwestern Gas Transmission's shippers account for approximately 60% of its capacity. Northern Illinois Gas Company (Northern Illinois) and PSI Energy Inc. (PSI) have capacity on Midwestern Gas Transmission of 38.4% and 20.9%, respectively. Operating revenues from Northern Illinois and PSI for the period from May 2001 to December 2001 totaled $3.8 million and $0.9 million, respectively. The gas gathering and processing businesses provide services for gathering, treating, processing and compression of natural gas and the fractionation of natural gas liquids. Bear Paw Energy's two largest customers, Lodgepole Energy Marketing and Tenaska Marketing Venture, 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 7) 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 15). Crestone's revenues from other affiliates totaled $0.3 million and $0.1 million in 2001 and 2000, respectively. Border Midstream's two largest customers, 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 Pipeline Agreement with the coal supplier for the Mohave Power Station that expires in December 2005. The pipeline is the sole source of fuel for the Mohave plant. Operating revenues under the Pipeline Agreement totaled $22.0 million, $21.1 million and $20.6 million for the years ended December 31, 2001, 2000 and 1999, respectively. F-17 NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 6. CREDIT FACILITIES, LONG-TERM DEBT AND CAPITAL LEASES Detailed information on long-term debt is as follows:

December 31, (In thousands) 2001 2000 -------------------------------------------------------------------------------- Northern Border Pipeline 1992 Pipeline Senior Notes - average 8.53% and 8.49% at December 31, 2001 and 2000, respectively, due from 2000 to 2003 $ 143,000 $ 184,000 Pipeline Credit Agreement Term loan - average 2.46% and 6.95% at December 31, 2001 and 2000, respectively, due 2002 272,000 424,000 Five-year revolving credit facility - average 6.87% at December 31, 2000 -- 45,000 1999 Pipeline Senior Notes - 7.75%, due 2009 200,000 200,000 2001 Pipeline Senior Notes - 7.50%, due 2021 250,000 -- 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 -- 2000 Partnership Credit Agreements - average 8.92% at December 31, 2000 -- 26,300 2001 Partnership Credit Agreement - average 3.49% at December 31, 2001, due 2004 64,000 -- Bear Paw Energy Capital leases 11,395 -- Black Mesa 10.7% Note agreement, due quarterly to 2004 -- 13,910 Fair value adjustment (Note 7) 6,269 -- Unamortized proceeds from termination of derivatives -- 26,046 Unamortized debt premium 1,563 2,706 ------------ ------------ Total 1,423,227 1,171,962 Less: Current maturities of long-term debt 352,395 44,464 ------------ ------------ Long-term debt $ 1,070,832 $ 1,127,498 ============ ============

In September 2001, Northern Border Pipeline completed a private offering of $250 million of 7.50% Senior Notes due 2021, which notes were subsequently exchanged in a registered offering for notes with substantially identical terms (2001 Pipeline Senior Notes). The proceeds from the 2001 Pipeline Senior Notes were used to reduce indebtedness outstanding under the Pipeline Credit Agreement. In March 2001, the Partnership completed a private offering of $225 million of 7.10% Senior Notes due 2011 (2001 Partnership Senior Notes). The 2001 Partnership Senior Notes were subsequently exchanged in a registered offering for notes with substantially identical terms. The proceeds from the 2001 Partnership Senior Notes were used to fund a portion of the acquisition of Bear Paw Energy (see Note 3). F-18 NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 6. CREDIT FACILITIES, LONG-TERM DEBT AND CAPITAL LEASES (continued) The Partnership entered into a $200 million three-year revolving credit agreement with certain financial institutions (2001 Partnership Credit Agreement) in March 2001. The 2001 Partnership Credit Agreement is to be used for capital expenditures, acquisitions and general business purposes. The 2001 Partnership Credit Agreement permits the Partnership 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. The Partnership is required to pay a fee on the principal commitment amount of $200 million. The 2001 Partnership Credit Agreement replaced revolving credit agreements entered into in June 2000. In June 2000, the Partnership had entered into two credit agreements with certain financial institutions, a $75 million 364-day credit agreement and a $75 million three-year revolving credit agreement (collectively, 2000 Partnership Credit Agreements). The 2000 Partnership Credit Agreements were to be used for capital expenditures, working capital and general business purposes. 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. In June 2000, the Partnership completed a private offering of $150 million of 8 7/8% Senior Notes due 2010 (2000 Partnership Senior Notes). The proceeds from the private offering, net of debt discounts and issuance costs, were primarily used to reduce existing indebtedness under a November 1997 credit agreement and to acquire the class A shares in Bighorn (see Note 3). In September 2000, the Partnership completed a private offering of an additional $100 million of 2000 Partnership Senior Notes. The proceeds from this offering, along with the proceeds from the credit agreements described above, were used for the acquisition of the interests in gas gathering businesses from ENA (see Note 3). The 2000 Partnership Senior Notes were subsequently exchanged in a registered offering for notes with substantially identical terms. The Partnership entered into 10-year interest rate swap agreements with an aggregate notional principal amount of $150 million in June 2000. The interest rate swap agreements were terminated in December 2000 and resulted in proceeds to the Partnership of approximately $15.0 million. The proceeds are being amortized against interest expense over the 10-year life of the terminated interest rate swap agreements. In August 1999, Northern Border Pipeline completed a private offering of $200 million of 7.75% Senior Notes due 2009, which notes were subsequently exchanged in a registered offering for notes with substantially identical terms (1999 Pipeline Senior Notes). Also in August 1999, Northern Border Pipeline received approximately $12.9 million from the termination of interest rate forward agreements, which is being amortized against interest expense over the life of the 1999 Pipeline Senior Notes. The interest rate forward agreements, which had an aggregate notional amount of $150 million, had been executed in September 1998 to hedge the interest rate on a planned F-19 NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 6. CREDIT FACILITIES, LONG-TERM DEBT AND CAPITAL LEASES (continued) issuance of fixed rate debt in 1999. The proceeds from the private offering, net of debt discounts and issuance costs, and the termination of the interest rate forward agreements were used to reduce existing indebtedness under the Pipeline Credit Agreement. In June 1997, Northern Border Pipeline entered into a credit agreement (Pipeline Credit Agreement) with certain financial institutions, which is comprised of a $100 million five-year revolving credit facility and a $272 million term loan, both maturing in June 2002. The Pipeline Credit Agreement permits 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, subject to certain parameters. Northern Border Pipeline is required to pay a facility fee on the aggregate principal commitment amount of $372 million. Interest paid, net of amounts capitalized, during the years ended December 31, 2001, 2000 and 1999 was $86.5 million, $84.2 million and $62.5 million, respectively. Aggregate repayments of long-term debt required for the next five years, excluding payments required under Bear Paw Energy's capital leases, are as follows: $350 million, $65 million and $64 million for 2002, 2003, and 2004, respectively. There are no scheduled debt maturities for 2005 or 2006. Future minimum payments under Bear Paw Energy's non-cancelable capital leases on compressors are as follows (in thousands):

Years ending December 31, 2002 $ 3,355 2003 3,355 2004 3,355 2005 3,045 2006 169 Thereafter -- ------- $13,279 Less amount representing interest 1,884 ------- Present value of lease payments 11,395 Less: current portion 2,395 ------- Long-term portion $ 9,000 =======

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. Certain of Northern Border Pipeline's long-term debt and credit arrangements contain requirements as to the maintenance of minimum partners' capital and debt to capitalization ratios which 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 F-20 NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 6. CREDIT FACILITIES, LONG-TERM DEBT AND CAPITAL LEASES (continued) most restrictive of the covenants, as of December 31, 2001 and 2000, respectively, $110 million and $136 million of partners' capital of Northern Border Pipeline could be distributed. 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. (Moodys) rate the notes as below investment grade. In February 2002, Moodys placed Northern Border Pipeline and the Partnership on credit review for a possible downgrade in credit rating. At this time, no action has been taken by Moodys. If Moodys was to issue the downgrade, the Partnership expects Northern Border Pipeline and its credit ratings to remain above investment grade. 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 to be 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, 2001, 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 and 2001 Pipeline Senior Notes was approximately $1,125 million and $675 million at December 31, 2001 and 2000, 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 and 2001 Pipeline Senior Notes, which will result in no gains or losses on their respective repayment. The fair value of the Pipeline Credit Agreement and 2001 Partnership Credit Agreement approximates the carrying value since the interest rates are periodically adjusted to reflect current market conditions. The estimated fair value of the Black Mesa note agreement was approximately $15 million at December 31, 2000. 7. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES 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. In 1998, the Financial Accounting Standards Board issued SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities," which was subsequently amended by SFAS No. 137 and SFAS No. 138. SFAS No. 133 requires that every derivative instrument (including certain derivative instruments embedded in other contracts) be recorded on the balance sheet F-21 NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 7. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES (continued) 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. At December 31, 2000, the Partnership had classified in long-term debt $26.0 million of unamortized proceeds from the termination of derivatives. This included unamortized proceeds of $14.9 million from the termination of interest rate swap agreements by the Partnership in December 2000 and $11.1 million from the termination of interest rate forward agreements by Northern Border Pipeline in August 1999. 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. The Partnership is reflecting 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. 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. In February 2001, the Partnership entered into forward starting interest rate swaps with notional amounts totaling $150 million related to the anticipated issuance of fixed rate debt. Upon issuance of the 2001 Partnership Senior Notes in March 2001, the Partnership paid approximately $4.3 million to terminate the swaps, which was recorded in accumulated other comprehensive income. The swaps were 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 2001 Partnership Senior Notes. In March 2001, Northern Border Pipeline entered into forward starting interest rate swaps with notional amounts totaling $200 million related to the planned issuance of 10-year and 30-year fixed rate debt. Upon issuance of the 2001 Pipeline Senior Notes in September 2001, Northern Border Pipeline paid approximately $4.1 million to terminate the swaps, of which $2.9 million was recorded in accumulated other comprehensive income and $1.2 million was recorded as an adjustment to minority interests in partners' equity. The swaps were 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 2001 Pipeline Senior Notes. F-22 NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 7. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES (continued) During the year ended December 31, 2001, the Partnership amortized approximately $2.1 million related to the terminated derivatives, as a reduction to interest expense from accumulated other comprehensive income. The Partnership expects to amortize a comparable amount in 2002. 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 receives payments based on a 7.10% fixed rate. At December 31, 2001, the average effective interest rate on the interest rate swaps was 4.21%. The swaps have been designated as fair value hedges as they were entered into to hedge the fluctuations in the market value of the 2001 Partnership Senior Notes. A non-cash gain of approximately $6.3 million is reflected in assets from price risk management activities and long-term debt on the accompanying consolidated balance sheet. In November 2001, Northern Border Pipeline entered into forward starting interest rate swaps with notional amounts totaling $150 million related to the planned issuance of senior notes. The 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 date of the senior notes, which is expected to occur in the second quarter of 2002. At December 31, 2001, the Partnership reflected approximately $3.4 million in assets from price risk management activities on the accompanying consolidated balance sheet with corresponding offsets of $2.4 million in accumulated other comprehensive income and $1.0 million in minority interests in partners' equity. Bear Paw Energy, which was acquired by the Partnership in March 2001 (see Note 3), 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 Bear Paw Energy's exposure to gas and natural gas liquid price volatility. The price swaps and collars that Bear Paw Energy had in place when it was acquired by the Partnership were redesignated as hedges upon acquisition. 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. At December 31, 2001, Bear Paw Energy did not have any outstanding derivative contracts. At September 30, 2001, Bear Paw Energy had outstanding commodity price swap arrangements with ENA, which had been accounted for as cash flow hedges, and resulted in Bear Paw Energy recording a non-cash gain of approximately $6.7 million in accumulated other comprehensive income. During the fourth quarter of 2001, the Partnership determined that ENA was no longer likely to honor the obligations it had to Bear Paw Energy for these derivatives and terminated the swap arrangements (see Note 15). 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 being recorded into earnings in the same periods during which the hedged forecasted transactions will affect earnings. In 2001, the Partnership recorded approximately $1.4 million into earnings and expects to record approximately $4.6 million into earnings in 2002. F-23 NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 8. 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 2001 2000 --------------------------------------------------------------------------------------------------------- Bighorn (a) $ 93,207 $83,562 Fort Union 33% 68,653 69,872 Lost Creek 35% 66,280 68,191 Gregg Lake 36% 9,495 -- Gladys/Mazeppa joint venture project 50% 2,094 -- -------- -------- $239,729(b) $221,625 ======== ========

(a) As discussed in Note 3, the Partnership held a 49% common membership interest in Bighorn at December 31, 2001 and 2000. The Partnership also held 100% of the non-voting class A shares of Bighorn at December 31, 2001 and 2000. (b) At December 31, 2001 and 2000, the unamortized excess of the Partnership's investments in unconsolidated affiliates was $180.1 million and $189.5 million, respectively. The Partnership's equity earnings (losses) of unconsolidated affiliates is as follows:

(In thousands) 2001 2000 (a) ------------------------------------------------------------------------------------------------- Bighorn $ (875) $ (1,394) Fort Union 1,514 285 Lost Creek 188 462 Gregg Lake (b) 870 -- -------------- -------------- $ 1,697 $ (647) ============== ==============

(a) Initial investments in unconsolidated affiliates began in late December 1999. (b) Investments in Gregg Lake began in April 2001 (See Note 3). Summarized combined financial information of the Partnership's unconsolidated affiliates is presented below:

December 31, -------------------------------- (In thousands) 2001 2000 ----------------------------------------------------------------------------------------------- Balance sheet Current assets (a) $ 17,436 $ 15,202 Property, plant and equipment, net 204,154 160,558 Other noncurrent assets 4,072 1,329 Current liabilities 10,382 4,509 Long-term debt 100,659 99,364 Other noncurrent liabilities 1,861 4,008 Owners' equity 112,760 69,208

(a) Includes $434 thousand receivable from the Partnership at December 31, 2000. F-24 NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 8. UNCONSOLIDATED AFFILIATES (continued)

(In thousands) 2001 (b) 2000 (a) ---------------------------------------------------------------------------------------------------------- Income statement Operating revenues $41,206 $8,598 Operating expenses 15,458 3,871 Net income 19,312 4,116 Distributions paid to the Partnership $ 7,083 $ 933

(a) Includes entire year results for Bighorn, which was acquired in late December 1999, and results for Fort Union and Lost Creek after they were acquired in September 2000. (b) Includes results for Gregg Lake after it was acquired in April 2001. 9. PARTNERS' CAPITAL At December 31, 2001, partners' capital consisted of 41,623,014 common units representing an effective 98% limited partner interest in the Partnership (including 7.7% held by Northern Plains and Enron, through an indirect subsidiary) and a 2% general partner interest. At December 31, 2000, partners' capital consisted of 31,503,563 common units representing an effective 98% limited partner interest in the Partnership (including 13.8% held collectively by the General Partners or their affiliates) and a 2% general partner interest. 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 April and May of 2001, the Partnership sold 407,550 and 4,000,000 common units, respectively. The net proceeds from the sale of common units and the general partners' capital contributions totaled approximately $172.2 million and were primarily used to repay amounts borrowed under the 2001 Partnership Credit Agreement. In connection with the Partnership's sale of common units in May 2001, Northwest Border sold its 1,123,500 common units. These common units had previously been outstanding and did not affect the number of the Partnership's total common units outstanding. The Partnership did not receive any of the proceeds from the common units sold by Northwest Border. In November 2000, the Partnership sold 2,156,250 common units. The net proceeds of the public offering and the general partners' capital contribution totaled approximately $60.7 million and were primarily used to repay amounts borrowed under the 2000 Partnership Credit Agreements. The Partnership will make distributions to its partners with respect to each calendar quarter in an amount equal to 100% of its Available Cash. "Available Cash" generally consists of all of the cash receipts of the Partnership adjusted for its cash disbursements and net changes to cash reserves. Available Cash will generally be distributed 98% to the Unitholders and 2% to the General Partners. As an incentive, the General Partners' percentage interest in quarterly distributions is increased after certain specified target levels are met (see Note 11). Under the incentive distribution provisions, the General Partners receive 15% of amounts F-25 NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 9. PARTNERS' CAPITAL (continued) 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. 10. 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 $8.6 million and $2.2 million for the years ended December 31, 2001 and 2000, respectively, related to these agreements. At December 31, 2001, the estimated aggregate amounts of such required future payments were $8.2 million annually for 2002 through 2006 and $28.2 million for later years. At December 31, 2001, the Partnership has guaranteed the performance of its unconsolidated affiliates in connection with credit agreements that expire in March 2009 and September 2009. At December 31, 2001, the combined guarantee was $4.4 million. Operating Leases Future minimum lease payments under non-cancelable operating leases on office space and vehicles of Bear Paw Energy are as follows (in thousands):

Year ending December 31, 2002 $1,327 2003 1,385 2004 1,402 2005 1,262 2006 1,060 Thereafter 1,186 ------ $7,622 ======

Expenses incurred related to these lease obligations for the period from April to December 2001, which were the months the Partnership's operating results included those of Bear Paw Energy, were $1.1 million. Capital expenditure and investment program Total capital expenditures and investments in unconsolidated affiliates for 2002 are estimated to be $86 million. This includes approximately $49 million for gas gathering and processing facilities and $25 million for interstate pipeline facilities. The Partnership also estimates that it will F-26 NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 10. COMMITMENTS AND CONTINGENCIES (continued) Capital expenditure and investment program (continued) be required to make additional investments in its unconsolidated affiliates of approximately $12 million in 2002 to support their capital expenditure projects. Funds required to meet the capital requirements for 2002 are anticipated to be provided from debt borrowings, issuance of additional limited partners 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 Reservation. Based on recent decisions by the federal courts and other defenses, Northern Border Pipeline believes that the Tribes do not have the authority to impose the tax and that the lawsuit will not have a material adverse impact on the Partnership. 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. 11. 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:

Year ended December 31, (In thousands, except -------------------------------------- per unit amounts) 2001 2000 1999 --------------------- ---------- ---------- ---------- Net income to partners $ 87,786 $ 76,720 $ 81,003 ---------- ---------- ---------- Net income allocated to General Partners (1,756) (1,534) (1,620) Adjustment to reflect incentive distributions (4,252) (1,032) (90) ---------- ---------- ---------- (6,008) (2,566) (1,710) ---------- ---------- ---------- Net income allocable to units $ 81,778 $ 74,154 $ 79,293 ========== ========== ========== Weighted average units outstanding 38,538 29,665 29,347 ========== ========== ========== Net income per unit $ 2.12 $ 2.50 $ 2.70 ========== ========== ==========

F-27 NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 12. ACCOUNTING PRONOUNCEMENTS In the third quarter of 2001, the Financial Accounting Standards Board issued SFAS No. 141, "Business Combinations," SFAS No. 142, "Goodwill and Other Intangible Assets," SFAS No. 143, "Accounting for Asset Retirement Obligations" and SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets." SFAS No. 141 requires all business combinations initiated after June 30, 2001, to be accounted for using the purchase method. 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 initial impairment tests by applying a fair-value-based analysis on the goodwill in each reporting segment. Subsequent to the initial adoption, goodwill shall be tested for impairment annually or more frequently if circumstances indicate a possible impairment. For goodwill and intangible assets on the balance sheet at June 30, 2001, the provisions of SFAS No. 142 must be applied to fiscal years beginning after December 15, 2001. At December 31, 2001, the Partnership's balance sheet included goodwill of approximately $475 million. The Partnership adopted SFAS No. 142 effective January 1, 2002. At the date of this report, the Partnership is evaluating the impact of adopting SFAS No. 142, including whether any transitional impairment losses will be required to be recognized as the cumulative effect of a change in accounting principle. Beginning January 1, 2002, effective with the adoption of SFAS No. 142, the Partnership will no longer record amortization expense related to goodwill. 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. When the liability is initially recorded, the entity capitalizes a cost by increasing the carrying amount of the related long-lived asset. Over time, the liability is accreted to its present value and the capitalized cost is depreciated over the useful life of the related asset. 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. The Partnership is in the process of evaluating the application of this pronouncement. SFAS No. 144 establishes one accounting model to be used for long-lived assets to be disposed of by sale and broadens the presentation of discontinued operations to include more disposal transactions. SFAS No. 144 supersedes both SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed of," and the accounting and reporting provisions of APB Opinion No. 30. This standard is effective for fiscal years beginning after December 15, 2001. The Partnership adopted SFAS No. 144 effective January 1, 2002. The Partnership doe not expect the adoption of SFAS No. 144 will have a material impact on the Partnership's financial position or results of operations. F-28 NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 13. GEOGRAPHIC AND BUSINESS SEGMENT INFORMATION The Partnership's business is divided into operating 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. They 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 (net income before minority interests; interest expense; income taxes; and depreciation and amortization, including goodwill amortization, which is netted against equity earnings (losses) of unconsolidated affiliates) 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.

Geographic Segments ------------------- Year Ended December 31, (In thousands) 2001 2000 1999 -------------- ------------ ------------ ------------ Revenues from external customers United States $ 455,997 $ 339,732 $ 318,963 Foreign 5,472 -- -- ------------ ------------ ------------ $ 461,469 $ 339,732 $ 318,963 ============ ============ ============ EBITDA United States $ 300,346 $ 259,347 $ 239,374 Foreign 2,636 -- -- ------------ ------------ ------------ $ 302,982 $ 259,347 $ 239,374 ============ ============ ============ Long-lived assets United States $ 2,006,136 $ 1,732,076 $ 1,745,356 Foreign 33,963 -- -- ------------ ------------ ------------ $ 2,040,099 $ 1,732,076 $ 1,745,356 ============ ============ ============

Business Segments Interstate Gas Natural Gathering Gas and Pipelines Coal Processing (In thousands) (a) Slurry (b) Other(d) Total -------------------------------------------------------------------------------------------------------- 2001 Revenues from external customers $ 322,584 $ 22,041 $ 116,844 $ -- $ 461,469 Depreciation and amortization 59,854 2,144 14,312 -- 76,310 Operating income (loss) 199,822 5,953 18,239 (3,055) 220,959 Interest expense, net 55,351 717 706 33,134 89,908 F-29 NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 13. GEOGRAPHIC AND BUSINESS SEGMENT INFORMATION (continued) Business Segments (continued)

Interstate Gas Natural Gathering Gas and Pipelines Coal Processing (In thousands) (a) Slurry (b) Other(d) Total ----------------- ------------- ------------- ------------- ------------- ------------- 2001 (CONTINUED) Equity earnings (losses) of unconsolidated affiliates -- -- 1,697 -- 1,697 Other income (expense), net (8) (746) 682 (1,539) (1,611) EBITDA 258,310 8,261 41,388 (4,977) 302,982 Capital expenditures 57,021 250 69,143 -- 126,414 Identifiable assets 1,858,902 22,009 552,520 14,195 2,447,626 Investments in unconsolidated affiliates -- -- 239,729 -- 239,729 Total assets $ 1,858,902 $ 22,009 $ 792,249 $ 14,195 $ 2,687,355

Interstate Gas Natural Gathering Gas and Pipelines Coal Processing (In thousands) (a) Slurry (b) Other(d) Total ----------------- ------------- ------------- ------------- ------------- ------------- 2000 Revenues from external customers $ 311,022 $ 21,170 $ 7,540 $ -- $ 339,732 Depreciation and amortization 57,328 2,977 394 -- 60,699 Operating income (loss) 184,167 4,355 2,019 (2,239) 188,302 Interest expense, net 65,161 1,677 -- 14,657 81,495 Equity earnings (losses) of unconsolidated affiliates -- -- (647) -- (647) Other income, net 8,058 32 -- 589 8,679 EBITDA 249,248 7,742 4,007 (1,650) 259,347 Capital expenditures 15,523 386 3,812 -- 19,721 Identifiable assets 1,768,505 29,605 58,230 4,755 1,861,095 Investments in unconsolidated affiliates -- -- 221,625 -- 221,625 Total assets $ 1,768,505 $ 29,605 $ 279,855 $ 4,755 $ 2,082,720

F-30 NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 13. GEOGRAPHIC AND BUSINESS SEGMENT INFORMATION (continued) Business Segments (continued)

Gas Interstate Gathering Natural and Gas Coal Processing (In thousands) Pipelines Slurry (c) Other(d) Total -------------- ------------ ------------ ------------ ------------ ------------ 1999 Revenues from external customers $ 298,347 $ 20,616 $ -- $ -- $ 318,963 Depreciation and amortization 51,908 2,934 -- -- 54,842 Operating income (loss) 177,411 3,670 -- (1,363) 179,718 Interest expense, net 60,214 1,997 -- 5,498 67,709 Other income (expense), net 1,363 (39) -- 3,238 4,562 EBITDA 230,581 6,918 -- 1,875 239,374 Capital expenditures 101,678 592 -- -- 102,270 Identifiable assets 1,796,691 32,075 -- 2,776 1,831,542 Investments in unconsolidated affiliates -- -- 31,895 -- 31,895 Total assets $ 1,796,691 $ 32,075 $ 31,895 $ 2,776 $ 1,863,437

(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. 14. QUARTERLY FINANCIAL DATA (Unaudited)

(In thousands, except Operating Operating Net Income Net Income per unit amounts) Revenues, net Income to Partners per Unit ------------------------ ------------- --------- ----------- ---------- 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 2000 First Quarter $ 81,517 $45,171 $17,966 $0.59 Second Quarter 82,536 44,747 18,042 0.60 Third Quarter 83,550 48,216 20,338 0.66 Fourth Quarter 92,129 50,168 20,374 0.65

F-31 NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 15. 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. As indicated in Note 5, ENA has firm service agreements with Northern Border Pipeline representing approximately 3.5% of contracted capacity, a portion of which (1.1%) has 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. ENA has not assumed or rejected these contracts, but its ability to use the capacity has been suspended until ENA provides adequate assurance of credit support and payment. The third party that holds the 1.1% of capacity through October 31, 2002, has filed a complaint with the FERC requesting, in effect, that its contract be deemed terminated as a consequence of ENA's filing for bankruptcy protection. Management believes this shipper's contract will remain in effect until October 31, 2002. For 2002, Northern Border Pipeline's estimated financial exposure for ENA's firm service agreements is approximately $9 million. Management believes that even if ENA continues to fail to perform its obligations under Northern Border Pipeline's firm service agreements, it will not have a material adverse impact on the Partnership's financial condition and results of operations. 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 7). Bear Paw Energy terminated the swap arrangements with ENA prior to December 31, 2001, and recorded bad debt expense of approximately $5.4 million. Management plans to continue to monitor developments at Enron, to continue 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. 16. SUBSEQUENT EVENTS On January 16, 2002, 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, 2001. The distribution was paid February 14, 2002, to unitholders of record at January 31, 2002. F-32 INDEPENDENT AUDITORS' REPORT ON SCHEDULE To 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 included in this Form 10-K and have issued our report thereon dated March 8, 2002. Our audit was made for the purpose of forming an opinion on the basic financial statements taken as a whole. The schedule of Northern Border Partners, L.P. and Subsidiaries listed in Item 14 of Part IV of this Form 10-K is the responsibility of the Company's management and is presented for purposes of complying with the Securities and Exchange Commission's rules and is not part of the basic financial statements. This schedule has been subjected to the auditing procedures applied in the audits of the basic financial statements and, in our opinion, fairly states in all material respects the financial data required to be set forth therein in relation to the basic financial statements taken as a whole. KPMG LLP Omaha, Nebraska, March 8, 2002 S-1 REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS ON SCHEDULE To Northern Border Partners, L.P.: We have audited in accordance with auditing standards generally accepted in the United States, the consolidated financial statements as of December 31, 2000, and for each of the two years in the period ended December 31, 2000, of Northern Border Partners, L.P. and Subsidiaries included in this Form 10-K and have issued our report thereon dated January 22, 2001. 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. ARTHUR ANDERSEN LLP Omaha, Nebraska, January 22, 2001 S-2 SCHEDULE II NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS FOR THE YEARS ENDED DECEMBER 31, 2001, 2000 AND 1999 (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 2001 $1,800 $ 731 $ -- $ -- $ 2,531 2000 $7,376 $ 1,800 $ -- $7,376 $ 1,800 1999 $6,726 $ 650 $ -- $ -- $ 7,376 Allowance for doubtful accounts $ -- $10,743 $ -- $ -- $10,743

S-3 INDEX TO EXHIBITS

EXHIBIT NUMBER DESCRIPTION ------- ----------- * 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. * 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"). *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 Operating Agreement between Northern Border Pipeline Company and Northern Plains Natural Gas Company, dated February 28, 1980 (Exhibit 10.3 to Form S-1). *10.3 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). *10.4 Note Purchase Agreement between Northern Border Pipeline Company and the parties listed therein, dated July 15, 1992 (Exhibit 10.6 to Form S-1).

*10.5 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")). *10.6 Northern Border Pipeline Company U.S. Shippers Service Agreement between Northern Border Pipeline Company and Enron Gas Marketing, Inc., dated June 22, 1990 (Exhibit 10.10 to Form S-1). *10.7 Amended Exhibit A to Northern Border Pipeline Company U.S. Shippers Service Agreement between Northern Border Pipeline Company and Enron Gas Marketing, Inc. (Exhibit 10.10.1 to the Partnership's Annual Report on Form 10-K for the year ended December 31, 1993 ("1993 10-K")). *10.8 Amended Exhibit A to Northern Border Pipeline U.S. Shippers Service Agreement between Northern Border Pipeline Company and Enron Gas Marketing, Inc., effective November 1, 1994 (Exhibit 10.10.2 to the Partnership's Annual Report on Form 10-K for the year ended December 31, 1994). *10.9 Amended Exhibit A's to Northern Border Pipeline Company U.S. Shipper Service Agreement effective, August 1, 1995 and November 1, 1995 (Exhibit 10.10.3 to 1995 10-K). *10.10 Amended Exhibit A to Northern Border Pipeline Company U.S. Shipper Service Agreement effective April l, 1998 (Exhibit 10.10.4 to the Partnership's Annual Report on Form 10-K for the year ended December 31, 1997 ("1997 10-K")). *10.11 Guaranty made by Enron Corp. dated August 8, 1989 (Exhibit 10.9 to Northern Border Pipeline Company's Form 10-K for the year ended December 31, 2001("NB Pipeline 2001 10-K")). *10.12 Form of Seventh Supplement Amending Northern Border Pipeline Company General Partnership Agreement (Exhibit 10.15 to Form S-1). *10.13 Northern Border Pipeline Company U.S. Shippers Service Agreement between Northern Border Pipeline Company and Transcontinental Gas Pipe Line Corporation, dated July 14, 1983, with Amended Exhibit A effective February 11, 1994 (Exhibit 10.17 to 1995 10-K). *10.14 Form of Credit Agreement among Northern Border Pipeline Company, The First National Bank of Chicago, as Administrative Agent, The First National Bank of Chicago, Royal Bank of Canada, and Bank of America National Trust and Savings Association, as Syndication Agents, First Chicago Capital Markets, Inc., Royal Bank of Canada, and BancAmerica Securities, Inc, as Joint Arrangers and Lenders (as defined therein) dated as of June 16, 1997 (Exhibit 10(c) to Amendment No. 1 to Form S-3, Registration Statement No. 333-40601 ("Form S-3")). *10.15 Northern Border Pipeline Company U.S. Shippers Service Agreement between Northern Border Pipeline Company and Enron Capital & Trade Resources Corp. dated October 15, 1997 (Exhibit 10.21 to 1997 10-K). *10.16 Guaranty made by Enron Corp., dated October 20, 1997 (Exhibit 10.16 to NB Pipeline 2001 10-K). *10.17 Northern Border Pipeline Company U.S. Shippers Service Agreement between Northern Border Pipeline Company and Enron Capital & Trade Resources Corp. dated October 15, 1997 (Exhibit 10.22 to 1997 10-K). *10.18 Guaranty made by Enron Corp., dated October 20, 1997 (Exhibit 10.18 to NB Pipeline 2001 10-K). *10.19 Northern Border Pipeline Company U.S. Shippers Service Agreement between Northern Border Pipeline Company and Enron Capital & Trade Resources Corp. dated August 5, 1997 with Amendment dated September 25, 1997 (Exhibit 10.25 to 1997 10-K). *10.20 Guaranty made by Enron Corp., dated April 29, 1997 (Exhibit 10.20 to NB Pipeline 2001 10-K). *10.21 Northern Border Pipeline Company U.S. Shippers Service Agreement between Northern Border Pipeline Company and Enron Capital & Trade Resources Corp. dated August 5, 1997 (Exhibit 10.26 to 1997 10-K). *10.22 Guaranty made by Enron Corp., dated April 29, 1997 (Exhibit 10.22 to NB Pipeline 2001 10-K). *10.23 Project Management Agreement by and between Northern Plains Natural Gas Company and Enron Engineering & Construction Company, dated March 1, 1996 (Exhibit No. 10.39 to NB Form S-4). *10.24 Eighth Supplement Amending Northern Border Pipeline Company General Partnership Agreement (Exhibit 10.15 to NB Form S-4). *10.25 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")). *10.26 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")). *10.27 Northern 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). *10.28 Northern Border Pipeline Company U.S. Shippers Service Agreement between Northern Border Pipeline Company and Pan-Alberta Gas (U.S.) Inc., dated October 1, 1992, with Amended Exhibit A effective June 22, 1998 (Exhibit 10.38 to NB Pipeline 1999 10-K). *10.29 Purchase and Sale Agreement, dated as of September 21, 2000 by and between Enron North America Corp. and NBP Energy Pipeline, L.L.C. (now known as Crestone Energy Ventures, L.L.C.) (Exhibit 10.24 to 2000 10-K). *10.30 Master Services Agreement, dated as of September 21, 2000 between NBP Energy Pipelines, L.L.C., (now known as Crestone Energy Ventures, L.L.C.) and Enron North America Corp. (Exhibit 10.25 to 2000 10-K). *10.31 Acquisition Agreement, dated as of March 14, 2001, among Northern Border Partners, L.P., Northern Border Intermediate Limited Partnership, Bear Paw Investments, LLC, Bear Paw Energy, LLC and Sellers (defined therein) (Exhibit 10.26 to 2000 10-K). *10.32 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). *10.33 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). *10.34 Ninth Supplement Amending Northern Border Pipeline Company General Partnership Agreement (Exhibit 10.37 to 2001 Form S-4). *10.35 Northern Border Pipeline Company U.S. Shipper Service Agreement between Northern Border Pipeline Company and Enron North America Corp., dated October 29, 2001 (Exhibit 10.38 to 2001 Form S-4). *10.36 Northern Border Pipeline Company U.S. Shipper Service Agreement between Northern Border Pipeline Company and Enron North America Corp., dated October 29, 2001 (Exhibit 10.35 to NB Pipeline 2001 10-K). *10.37 Guaranty made by Enron Corp., dated October 31, 2001 (Exhibit 10.36 to NB Pipeline 2001 10-K). 10.38 Operating Agreement between Midwestern Gas Transmission Company and Northern Plains Natural Gas Company dated as of April 1, 2001. 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; and Midwestern Gas Transmission Company. 23.01 Consent of Arthur Andersen 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). *Indicates exhibits incorporated by reference as indicated; all other exhibits are filed herewith.