10-K 1 nbp10-ka.txt FORM 10-K UNITED STATES SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 _______________________ F O R M 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, 2000 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.) 1400 Smith Street, Houston, Texas 77002-7369 (Address of principal executive offices)(zip code) Registrant's telephone number, including area code: 713-853-6161 ___________________ Securities registered pursuant to Section 12(b) of the Act: Title of each class Name of each exchange on which registered Common Units New York Stock Exchange Securities registered pursuant to Section 12(g) of the Act: None Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes X No _ Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. X 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 2, 2001, was approximately $995,168,848. NORTHERN BORDER PARTNERS, L.P. TABLE OF CONTENTS Page No. Part I Item 1. Business 1 Item 2. Properties 13 Item 3. Legal Proceedings 14 Item 4. Submission of Matters to a Vote of Security Holders 14 Part II Item 5. Market for Registrant's Common Units and Related Security Holder Matters 15 Item 6. Selected Financial Data 16 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations 17 Item 7a. Quantitative and Qualitative Disclosures About Market Risk 24 Item 8. Financial Statements and Supplementary Data 24 Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure 24 Part III Item 10. Partnership Management 25 Item 11. Executive Compensation 28 Item 12. Security Ownership of Certain Beneficial Owners and Management 33 Item 13. Certain Relationships and Related Transactions 33 Part IV Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K. 36 PART I Item 1. Business General We are a publicly traded limited partnership 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. In addition, Crestone Energy Ventures, L.L.C. and Black Mesa Pipeline Company are wholly-owned subsidiaries of the Partnership. 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., and Northwest Border Pipeline Company, a subsidiary of The Williams Companies, Inc. Our general partners hold an aggregate 2% general partner interest in the Partnership. The general partners or their affiliates also own common units representing an aggregate 13.5% limited partner interest. The combined general and limited partner interests in the Partnership held by Enron and Williams are 11.7% and 3.8%, respectively (See Item 13. "Certain Relationships and Related Transactions"). The Partnership is managed by or under the direction of the Partnership Policy Committee consisting of three members, each of whom has been appointed by one of the general partners (See Item 10. "Partnership Management"). Northern Border Pipeline owns an interstate pipeline system that transports natural gas from the Montana- Saskatchewan border to natural gas markets in the midwestern United States. This pipeline system connects with multiple pipelines that provide shippers with access to the various natural gas markets served by those pipelines. In the year ended December 31, 2000, we estimate that Northern Border Pipeline transported approximately 22% of the total amount of natural gas imported from Canada to the United States. Over the same period, approximately 90% of the natural gas transported was produced in the western Canadian sedimentary basin located in the provinces of Alberta, British Columbia and Saskatchewan. Northern Border Pipeline transports gas for shippers under a tariff regulated by the Federal Energy Regulatory Commission ("FERC"). The tariff specifies the calculation of amounts to be paid by shippers and the general terms and conditions of transportation service on the pipeline system. Northern Border Pipeline's 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 does not own the gas that it transports, and therefore it does not assume the related natural gas commodity risk. 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. The general partner of TC PipeLines and its subsidiary limited partnership is TC PipeLines GP, Inc., which is a subsidiary of TransCanada PipeLines Limited. 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 general partner) and one representative from TC PipeLines. Voting power on the management committee is presently 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 the members of the management committee. For a discussion of specific relationships with affiliates, refer to Item 13. "Certain Relationships and Related Transactions." The pipeline system is operated by Northern Plains pursuant to an operating agreement. Northern Plains employs approximately 200 individuals located at the operating headquarters in Omaha, Nebraska, and at various locations along the pipeline route. Northern Plains' employees are not represented by any labor union and are not covered by any collective bargaining agreements. In September 2000, we purchased interests in gas gathering businesses in the Powder River and Wind River Basins in Wyoming for approximately $209 million from Enron North America. The transaction included the purchase of Enron Midstream Services, L.L.C., now known as Crestone Gathering Services, L.L.C., and ownership interests in Bighorn Gas Gathering, L.L.C. ("Bighorn"), Fort Union Gas Gathering, L.L.C. ("Fort Union") and Lost Creek Gathering, L.L.C. ("Lost Creek"). The transaction added to our previous ownership in Bighorn. Through our wholly owned subsidiary, Crestone Energy Ventures, we own 100% of Crestone Gathering Services, a 49% interest in Bighorn, a 33% interest in Fort Union and a 35% interest in Lost Creek, which collectively own over 300 miles of gas gathering facilities in Wyoming. Crestone Gathering Services provides gas gathering services to third parties. The gathering facilities interconnect to the interstate gas pipeline grid serving gas markets in the Rocky Mountains, the Midwest and California. The Bighorn and Fort Union systems gather coal seam 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 reserves to Bighorn, giving Bighorn the right to gather coal seam methane gas produced in areas of Wyoming covering 800,000 acres. Bighorn's system is capable of gathering more that 250 million cubic feet per day of coal bed methane gas for delivery to the Fort Union gathering system. The Fort Union gathering system is capable of delivering more than 450 million cubic feet per day of coal seam methane gas into the interstate pipeline grid. Fort Union has announced a planned expansion to increase capacity to 634 million cubic feet per day that is expected to be in service in October 2001. 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 million cubic feet per day 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 Barrett Resources hold the remaining interest in Fort Union. CMS Field Services is the managing member, Western Gas Resources is the field operator and CIG 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. The system is operated by Elkhorn Field Services Company. NBP Services Corporation, an Enron subsidiary, provides administrative services for us and operating services for Crestone Energy Ventures. NBP Services Corporation has 22 employees and utilizes employees of its affiliates to provide these services. We also own Black Mesa Pipeline Company. Black Mesa owns a 273-mile, 18-inch diameter coal slurry pipeline which originates at a coal mine in Kayenta, Arizona. The coal slurry pipeline transports crushed coal suspended in water. It traverses westward through northern Arizona to the 1,500 megawatt Mohave Power Station located in Laughlin, Nevada. The coal slurry pipeline is the sole source of fuel for the Mohave Power Station, which consumes an average of 4.8 million tons of coal annually. The capacity of the pipeline is fully contracted to the coal supplier for the Mohave Power Station through the year 2005. The pipeline is operated by Black Mesa Pipeline Operations, LLC, a wholly-owned subsidiary of the Partnership. Approximately 58 people are employed in the operations of Black Mesa, of which 26 are represented by a labor union, the United Mine Workers. Pending Acquisitions In March 2001, we signed a definitive agreement for the acquisition of Midwestern Gas Transmission from El Paso Corporation for approximately $100 million. The Midwestern system is a 350-mile interstate natural gas pipeline extending from Portland, Tennessee to Joliet, Illinois. Midwestern connects to Northern Border Pipeline and other major interstate pipeline systems including Alliance Pipeline, Tennessee Gas Pipeline, Trunkline and Texas Gas Transmission to provide bi-directional service to markets in Kentucky, Indiana, southern Illinois and the Joliet/Chicago market hub. The acquisition is expected to close in the second quarter of this year, subject to the receipt of all necessary approvals. In March 2001, we signed a definitive agreement to purchase Bear Paw Energy, L.L.C. The purchase price is approximately $366 million to be paid with 5.7 million of our common units and $183 million in cash, of which $98.2 million will be used to retire debt of Bear Paw Energy with the remainder payable to the sellers. An additional $6 million will be payable in February 2002, if certain performance criteria are met. The purchase is targeted for completion by the end of the first quarter of this year. Bear Paw Energy has extensive gathering and processing operations in the Powder River Basin in Wyoming and the Williston Basin in Montana, North Dakota and Saskatchewan. Bear Paw Energy has approximately 226,000 leasehold production acres under dedication and 600 miles of high and low pressure gathering pipelines in the Powder River Basin. In the Williston Basin, Bear Paw Energy has over 2,800 miles of gathering pipelines and four processing plants with 90 million cubic feet per day of capacity. In February 2001, we signed a purchase and sale agreement to purchase the Mazeppa Plant, Gladys Plant and a minority interest in the Gregg Lake/Obed Pipeline, all of which are located in Alberta, Canada, from Dynegy Canada, Inc. The purchase price, which is subject to adjustment, is approximately $46 million. The Mazeppa Plant is a sour gas processing plant with 87 million cubic feet per day of combined capacity and associated gathering pipelines. The Gladys Plant is a sour gas processing plant with 7 million cubic feet per day of capacity. The Gregg Lake/Obed Pipeline is comprised of 85 miles of gathering lines with a capacity of 150 million cubic feet per day. We are targeting to close on this transaction by the end of March 2001. The Northern Border Pipeline System Northern Border Pipeline owns a 1,214-mile United States interstate pipeline system that transports natural gas from the Montana-Saskatchewan border near Port of Morgan, Montana, to interconnecting pipelines in the upper Midwest of the United States. Construction of the pipeline was initially completed in 1982. The pipeline system was expanded and/or extended in 1991, 1992 and 1998. 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. For the year ended December 31, 2000, of the natural gas transported on the 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. The pipeline system consists of 822 miles of 42-inch diameter pipe designed to transport 2,373 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 1,300 mmcfd in total from Ventura, Iowa to Harper, Iowa; and 226 miles of 36-inch diameter pipe and 19 miles of 30-inch diameter pipe designed to transport 645 mmcfd from Harper, Iowa to a terminus near Manhattan, Illinois (Chicago area). Along the pipeline there are 15 compressor stations with total rated horsepower of 476,500 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. At its northern end, the pipeline system is connected to 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 Alberta system gathers and transports approximately 18% of the total North American natural gas production and approximately 74% of the natural gas produced in the western Canadian sedimentary basin. 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. Interconnects The pipeline system connects with multiple pipelines that provide its shippers with access to the various natural gas markets served by those pipelines. The pipeline system interconnects with pipeline facilities of: * Northern Natural Gas Company, an Enron subsidiary, at Ventura, Iowa as well as multiple smaller interconnections in South Dakota, Minnesota and Iowa; * Natural Gas Pipeline Company of America at Harper, Iowa; * MidAmerican Energy Company at Iowa City and Davenport, Iowa and Cordova, Illinois; * Alliant Power Company at Prophetstown, Illinois; * Northern Illinois Gas Company at Troy Grove and Minooka, Illinois; * Midwestern Gas Transmission Company near Channahon, Illinois; * ANR Pipeline Company near Manhattan, Illinois; and * The Peoples Gas Light and Coke Company near Manhattan, Illinois 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. Shippers 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, 2000, 92% of the firm capacity is contracted by producers and marketers. The remaining firm capacity is contracted to local distribution companies (5%), interstate pipelines (2%) and end-users (1%). As of December 31, 2000, the termination dates of these contracts ranged from October 31, 2001 to December 21, 2013 and the weighted average contract life, based upon annual contractual obligations, was approximately six years with just under 99% of capacity contracted through mid-September 2003. Based on their proportionate shares of capacity, as of December 31, 2000, the five largest shippers are: Pan- Alberta Gas (U.S.) Inc. (25.5%), TransCanada Energy Marketing USA, Inc. (11.4%), PanCanadian Energy Services Inc (7.3%), Enron North America Corp. (6.3%) and Engage Energy US, LP. (5.4%). The 20 largest shippers, in total, are responsible for approximately 93% of total revenues. As of December 31, 2000, the largest shipper, Pan- Alberta, holds firm capacity of 690 mmcfd under three contracts with terms to October 31, 2003. An affiliate of Enron provides guaranties for 300 mmcfd of Pan-Alberta's contractual obligations through October 31, 2001. In addition, Pan-Alberta's remaining capacity is supported by various credit support arrangements, including, among others, a letter of credit, a guaranty from an interstate pipeline company through October 31, 2001 for 132 mmcfd, an escrow account and an upstream capacity transfer agreement. Mirant Americas Energy Marketing, LP, formerly Southern Company Energy Marketing L.P., 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. TransCanada Energy Marketing USA, Inc., a subsidiary of TransCanada, holds firm contracts representing 11.4% of capacity. Enron North America Corp., a subsidiary of Enron, holds firm contracts representing 6.3% of capacity. Transcontinental Gas Pipe Line Corporation, a subsidiary of Williams, holds a contract representing 0.8% of capacity. See Item 13. "Certain Relationships and Related Transactions." Demand For Transportation Capacity Northern Border Pipeline's long-term financial condition is dependent on the continued availability of economic 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 pipeline system. 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 western Canadian natural gas supplies. Additional pipeline export capacity also could accelerate depletion of these reserves. Northern Border Pipeline's business depends in part on the level of demand for western Canadian natural gas in the markets the pipeline system serves. The volumes of natural gas delivered to these markets from other sources affect the demand for both western Canadian natural gas and use of the pipeline system. Demand for western Canadian natural gas to serve other markets also influences the ability and willingness of shippers to use the pipeline system to meet demand in the markets that the pipeline serves. A variety of factors could affect the demand for natural gas in the markets that the pipeline system serves. These factors include: * economic conditions; * fuel conservation measures; * alternative energy requirements and prices; * climatic conditions; * government regulation; and * technological advances in fuel economy and energy generation devices. We cannot predict whether these or other factors will have an adverse effect on demand for use of the pipeline system or how significant that adverse effect could be. Future Demand and Competition On March 16, 2000, the FERC issued an order granting Northern Border Pipeline's application for a certificate to construct and operate its proposed Project 2000 facilities. Project 2000 will expand and extend the pipeline system into Indiana. Project 2000 will afford shippers on the extended pipeline system access to industrial 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. The capital expenditures for Project 2000 are estimated to be approximately $94 million with a planned in-service of November 2001. Proposed facilities include approximately 34.4 miles of 30-inch pipeline, new equipment and modifications at three compressor stations resulting in a net increase of 22,500 compressor horsepower and one meter station. As a result of the Project 2000 expansion, the pipeline system will have the ability to transport 1,484 mmcfd from Ventura to Harper, Iowa, 844 mmcfd from Harper to Manhattan, Illinois, and 544 mmcfd on the new extension from Manhattan to North Hayden, Indiana. Five shippers have contracted for all the additional capacity under long-term transportation agreements. The Project 2000 shippers are: Bethlehem Steel Corporation, El Paso Energy Marketing Company, Northern Indiana Public Service Company, Peoples Energy Services Corporation and The Peoples Gas Light and Coke Company. Northern Border Pipeline competes with other pipeline companies that transport natural gas from the western Canadian sedimentary basin or that transport natural gas to markets in the midwestern United States. The competitors for the supply of natural gas include six pipelines and the Canadian domestic users in the western Canadian sedimentary basin region. Northern Border Pipeline's competitive position is affected by the availability of Canadian natural gas for export, the prices of natural gas in alternative markets, the cost of producing natural gas in Canada, and demand for natural gas in the United States. Alliance Pipeline, which commenced transporting natural gas from the western Canadian sedimentary basin to the midwestern United States in December 2000, delivers its volumes into the Chicago market and other interstate pipelines. Alliance Pipeline transports gas containing high-energy liquid hydrocarbons. Additional facilities to extract the natural gas liquids were constructed near Alliance Pipeline's terminus in Chicago to permit Alliance to transport natural gas with the liquids-rich element. As a consequence of Alliance Pipeline, there has been an increase in natural gas moving from the western Canadian sedimentary basin to Chicago. Vector Pipeline L.P. interconnects with Alliance and transports gas eastward to a terminus in eastern Canada. There are several additional projects proposed to transport natural gas from the Chicago area that would provide access to additional markets for the shippers. The proposed projects currently being pursued by third parties are targeting markets in northern Illinois, Wisconsin and the northeast United States. These proposed projects are in various stages of regulatory approval. Williams has a minority interest (14.6%) in Alliance Pipeline. TransCanada 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 customers. Natural gas is also produced in the United States and transported by competing pipeline systems to the same markets as those served by the pipeline system. Crestone Energy Ventures competes with other natural gas gathering and pipelines companies to carry natural gas from the production area of the Powder River and Wind River Basins of Wyoming to the major interstate transmission pipelines in the Rocky Mountain Region. Crestone Energy Ventures' competitive position is affected by the pace of gas drilling, gas production rates, gas reserves, and the demand for natural gas in the Rocky Mountains, Midwest, and California markets served by the interstate pipeline gas grid. The pace of drilling may be impacted by the ability of gas producers to obtain the necessary drilling and production permits in an economic manner. In providing gas gathering services, Crestone Energy Ventures may require acreage dedication and/or volume commitments from gas producers. Development of future gas gathering systems will be staged to reflect the growth in number of wells and field production. FERC Regulation General Northern Border Pipeline is subject to extensive regulation by the FERC 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 the business, including: * transportation of natural gas; * rates and charges; * construction of new facilities; * extension or abandonment of service and facilities; * accounts and records; * depreciation and amortization policies; * the acquisition and disposition of facilities; and * the initiation and discontinuation of services. Where required, Northern Border Pipeline holds 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. Northern Border Pipeline's books and records are 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. 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. Northern Border Rate Case Proceeding In May 1999, Northern Border Pipeline filed a rate case wherein it proposed, among other things, to increase the allowed equity rate of return to 15.25%. The total annual cost of service increase due to the proposed changes was approximately $30 million. A number of the shippers and competing pipelines filed interventions and protests. In June 1999, the FERC issued an order in which the proposed changes were suspended until December 1, 1999, after which they were implemented with subsequent billings subject to refund. The order set for hearing not only the proposed changes but also several issues raised by intervenors including the appropriateness of the cost of service form of tariff and the depreciation schedule. Upon a request for clarification, the FERC issued an order in August 1999 that provided that the manner in which the costs of the recently completed expansion and extension project ("The Chicago Project") could be recovered from shippers may be examined in this proceeding and that, while Northern Border Pipeline had not proposed to change the depreciation rates approved in the last rate case, it had the burden of proving that the depreciation rates are just and reasonable. On September 26, 2000, Northern Border Pipeline filed a stipulation and agreement in its 1999 rate case proceeding that documented a settlement. On December 13, 2000, the FERC issued its order approving the terms of the settlement. One of the important elements of the settlement is the conversion of Northern Border Pipeline's form of tariff from cost of service to stated rates based on a straight-fixed variable rate design. Under the former cost of service tariff, the firm transportation shippers contracted to pay for a proportionate share of the pipeline system's cost of service. During any given month, each of these shippers paid a uniform mileage-based charge for the amount of capacity contracted, and calculated under a cost of service tariff. The shippers were obligated to pay their proportionate share of the cost of service regardless of the amount of natural gas they actually transported. Under the cost of service form of tariff, Northern Border Pipeline could not charge or collect more than the cost of service. Under Northern Border Pipeline's new form of tariff, shippers pay Northern Border Pipeline on the basis of stated transportation rates. Under the terms of the settlement, and in accordance with straight-fixed variable rate design principles, approximately 98% of the agreed upon revenue level is attributed to demand charges. The firm shippers are obligated to pay a monthly demand charge, regardless of the amount of natural gas they actually transport, for the term of their contracts. The remaining 2% of the agreed upon revenue level is attributed to the commodity charge based on the volumes of gas actually transported. From December 1, 1999, through and including December 31, 2000, the rates were based upon an annual revenue level of $307 million. For periods after December 31, 2000, the rates are based upon an annual revenue level of $305 million. On a per unit of transportation basis, the rates under the new tariff are approximately equal to the cost of service on a per unit basis charged prior to December 1, 1999. The settlement also provides that 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. Prior to the new rate case, Northern Border Pipeline will not be permitted to increase rates if its costs increase, nor will it be required to reduce rates based on cost savings. Northern Border Pipeline's earnings and cash flow will depend on its future costs, contracted capacity, the volumes of gas transported and its ability to recontract capacity at acceptable rates. Under Northern Border Pipeline's previous cost of service form of tariff, the amount of revenue that it collected from customers generally declined as the rate base was recovered. Under its new tariff, Northern Border Pipeline is entitled to collect revenue based on stated rates established in its 1999 rate case until its next rate case, which will be filed November 1, 2005. It will, however, continue to depreciate its rate base at an annual depreciation rate on transmission plant in service of 2.25% and its rate base in 2005 will be a factor in determining what it can charge when it files a new rate case at that time. In order to avoid a decline in revenue it can collect from its customers, Northern Border Pipeline must maintain or increase its rate base by acquiring or constructing assets that replace or add to existing pipeline facilities or by adding new facilities and maintain its level of contracted capacity at the stated rates. It was agreed in the settlement of the 1999 rate case, that there would be no project cost containment mechanism adjustment for The Chicago Project and that all costs as of November 30, 1999 incurred in the construction and commissioning of the Chicago Project were included in rate base. The project cost containment mechanism was created in the settlement of the 1995 rate case. The purpose of the project cost containment mechanism was to limit Northern Border Pipeline's ability to include cost overruns for The Chicago Project in rate base and to provide incentives for cost underruns. The settlement of Northern Border Pipeline's 1995 rate case provided that for at least seven years from the date The Chicago Project was completed, 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's 1999 rate case. Northern Border Pipeline also provides interruptible transportation service. Interruptible transportation service is transportation in circumstances when surplus 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 Rate Schedule T-1 maximum reservation charge and commodity rate. Under the previous cost of service form of tariff, all interruptible transportation service revenue generated was credited to the benefit of the firm shippers. Under the new 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. After October 31, 2003, all revenues from interruptible transportation service and other new services will no longer be subject to sharing and thus will be retained by Northern Border Pipeline. In addition, the settlement of the 1999 rate case also provided for an equal sharing with its firm shippers of revenue generated from a certain telecommunications contract for the term of that contract. Northern Border Pipeline intends to develop new services and seek the FERC's authorization to implement such services. While the receipt of those approvals and the future impact of the revenue sharing provisions of the settlement on Northern Border Pipeline's earnings cannot be determined at this time, revenues from these sources are expected to be minimal through at least October 31, 2003. Open access regulation Beginning on April 8, 1992, the FERC issued a series of orders, known as Order 636, which required pipeline companies to unbundle their services and offer sales, transportation, storage, gathering and other services separately, to provide all transportation services on a basis that is equal in quality for all shippers and to implement a program to allow firm holders of pipeline capacity to resell or release their capacity to other shippers. Capacity release provisions were adopted that allowed shippers to release all or part of their capacity either permanently or temporarily. Shippers on the pipeline system have temporarily released capacity as well as permanently released capacity to other shippers who have agreed to comply with the underlying contractual and regulatory obligations associated with that capacity. Beginning in 1996, the FERC issued a series of orders, referred to together as Order 587, amending its open access regulations to standardize business practices and procedures governing transactions between interstate natural gas pipelines, their customers, and others doing business with the pipelines. The intent of Order 587 was to assist shippers that deal with more than one pipeline by establishing standardized business practices and procedures. These business standards, developed by the Gas Industry Standards Board, govern important business practices including shipper supplied service nominations, allocation of available capacity, accounting and invoicing of transportation service, standardized internet business transactions and capacity release. Northern Border Pipeline has implemented the necessary changes to its tariff and internal systems. In 1998, the FERC initiated a number of proceedings to further amend its open access regulations. In the resulting order, Order 637 issued February 9, 2000, the FERC revised the short-term transportation regulations by 1) waiving the maximum rate ceiling in its capacity release regulations until September 30, 2002 for short-term releases of capacity of less than one year; 2) permitting value-oriented peak/off- peak rates to better allocate revenue responsibility between short-term and long-term markets; 3) permitting term- differentiated rates to better allocate risks between shippers and the pipelines; 4) revising the regulations related to scheduling procedures, capacity segmentation, imbalance management and penalties; 5) retaining the right of first refusal and the five-year matching cap but limiting the right to customers with maximum rate contracts for 12 or more consecutive months of service; and 6) adopting new reporting requirements to take effect September 1, 2000 that include reporting daily transactional data on all firm and interruptible contracts, daily reporting of scheduled quantities at points or segments, and the posting of corporate and pipeline organizational charts, names and functions. As required by Order No. 637, Northern Border Pipeline filed pro forma tariff sheets in compliance to address the issues identified in 4) above. This filing is pending at the FERC. All other related compliance filings and reporting requirements have been completed and implemented. We do not believe that these regulatory initiatives will have a material adverse impact to Northern Border Pipeline's operations. Environmental and Safety Matters Our operations are subject to federal, state and local laws and regulations relating to safety and the protection of the environment which include the Resource Conservation and Recovery Act, the Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended, 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. Black Mesa Pipeline Company, our subsidiary, has received a Findings of Violation by the United States Environmental Protection Agency ("EPA"), citing violations of the Clean Water Act and Notice of Violation from the Arizona Department of Environmental Quality citing violations of state laws due to discharges of coal slurry on Black Mesa's pipeline from December 1997 through July 1999. Black Mesa Pipeline has paid an amount of $128,000 in penalties for all alleged violations into an escrow account and has executed a Consent Decree which sets forth this payment as well as certain preventative measures, reporting requirements and associated penalties for failure to comply. Upon execution by the EPA and the Arizona Department of Environmental Quality, this Consent Decree will be filed in the United States District Court, District of Arizona for public notice, comment and final approval. 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 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 the Partnership's operations, could result in substantial costs and liabilities to the Partnership. If we are unable to recover such resulting costs, earnings and cash distributions could be adversely affected. Item 2. Properties Northern Border Pipeline holds the right, title and interest in its pipeline system. With respect to real property, the pipeline system falls into two basic categories: (a) parcels which Northern Border Pipeline owns 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 of Northern Border Pipeline 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 across certain property was obtained by Northern Border Pipeline through exercise of the power of eminent domain. Northern Border Pipeline continues to have the power of eminent domain in each of the states in which it operates the pipeline system, although it may not have the power of eminent domain with respect to Native American tribal lands. Approximately 90 miles of the pipeline is 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 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. This right- of-way on allotted lands is either a perpetual easement or for a term of years. Most of the allotted lands are subject to a perpetual easement either granted, by the Bureau of Indian Affairs ("BIA") for and on behalf of individual Indian owners or obtained through condemnation. Several tracts are subject to a right-of-way grant that has a term of 15 years. Crestone Gathering Services holds the right, title and interest in its gathering system which consists of low pressure gas gathering lines and compression and measurement facilities. Crestone Gathering Services' system is utilized for the gathering and compression of coal bed methane gas from low pressure at the wellhead to high pressure gathering lines of which 30 miles is steel pipe and 99 miles is polyethylene pipe. Along these gathering lines, Crestone Gathering Services has installed 42 gas compression facilities with a total rated horsepower of 36,000 and measurement facilities to support the receipt and delivery of gas at various points. The real property rights for Crestone Gathering Service's system are derived through leases, easements, rights-of-way and permits. Item 3. Legal Proceedings We are not currently parties to any legal proceedings that, individually or in the aggregate, would reasonably be expected to have a material adverse impact on our results of operations or financial position. Also, see Item 1. "Business - Environmental and Safety Matters." Item 4. Submission of Matters to a Vote of Security Holders There were no matters submitted to a vote of security holders during 2000. PART II Item 5. Market for the Registrant's Common Units and Related Security Holder Matters 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 2000 First Quarter.................. $29.25 $23.00 $0.65 Second Quarter................. 28.125 23.75 $0.65 Third Quarter.................. 31.875 27.25 $0.70 Fourth Quarter................. 33.625 27.75 $0.70 1999 First Quarter.................. $35.50 $30.375 $0.61 Second Quarter................. 33.5625 30.1875 0.61 Third Quarter.................. 31.875 28.00 0.61 Fourth Quarter................. 29.50 21.625 0.65

As of March 1, 2001, there were approximately 1,480 record holders of common units and approximately 39,700 beneficial owners of the common units, including common units held in street name. We currently have 31,503,563 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 18, 2001, we declared a distribution of $0.70 per unit ($2.80 per unit on an annualized basis), payable February 14, 2001 to the general partners and unitholders of record at January 31, 2001. Item 6. Selected Financial Data (in thousands, except per unit, other financial data and operating data)

Year Ended December 31, 2000 1999 1998 1997 1996 INCOME DATA: Operating revenues, net $ 339,732 $ 318,963 $ 217,592 $ 198,574 $ 201,943 Operations and maintenance 62,097 53,451 44,770 37,418 28,366 Depreciation and amortization 60,699 54,842 43,885 40,332 46,979 Taxes other than income 28,634 30,952 22,012 22,836 24,390 Regulatory credit -- -- (8,878) -- -- Operating income 188,302 179,718 115,803 97,988 102,208 Interest expense, net 81,495 67,709 30,922 30,860 32,670 Other income 8,032 4,562 13,208 8,149 2,900 Minority interests in net income 38,119 35,568 30,069 22,253 22,153 Net income to partners $ 76,720 $ 81,003 $ 68,020 $ 53,024 $ 50,285 Net income per unit $ 2.50 $ 2.70 $ 2.27 $ 1.97 $ 1.88 Number of units used in computation 29,665 29,347 29,345 26,392 26,200 CASH FLOW DATA: Net cash provided by operating activities $ 169,615 $ 173,368 $ 103,849 $ 119,621 $ 137,534 Capital expenditures 19,721 102,270 652,194 152,658 18,597 Distribution per unit 2.65 2.44 2.30 2.20 2.20 BALANCE SHEET DATA (AT END OF PERIOD): Property, plant and equipment, net $1,732,076 $1,745,356 $1,730,476 $1,118,364 $ 937,859 Total assets 2,082,720 1,863,437 1,825,766 1,266,917 1,016,484 Long-term debt, including current maturities 1,171,962 1,031,986 976,832 481,355 377,500 Minority interests in partners' capital 248,098 250,450 253,031 174,424 158,089 Partners' capital 572,274 515,269 507,426 500,728 410,586 OTHER FINANCIAL DATA: Ratio of earnings to fixed charges (1) 2.4 2.7 3.0 3.2 3.2 OPERATING DATA: Northern Border Pipeline: Million cubic feet of gas delivered 852,674 834,833 608,187 621,262 630,148 Average daily throughput (MMcfd) 2,400 2,353 1,706 1,735 1,755 Transportation units (million dekatherm miles per day): Firm service 2,276 2,289 1,417 1,393 1,392 Interruptible 19 6 28 47 56 (1) "Earnings" means the sum of pre-tax 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.

Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations Results of Operations 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 - Northern Border Rate Case Proceeding". Operating revenues for 1999 were determined under Northern Border Pipeline's 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 the acquisition of gas gathering businesses in late September 2000 (see Item 1. "Business - General"). 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. 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. Year Ended December 31, 1999 Compared With the Year Ended December 31, 1998 Operating revenues, net increased $101.4 million (47%) for the year ended December 31, 1999, as compared to the same period in 1998, due primarily to additional revenue from Northern Border Pipeline's operation of The Chicago Project facilities. Additional receipt capacity of 700 mmcfd, a 42% increase, and new firm transportation agreements with 27 shippers resulted from The Chicago Project. Northern Border Pipeline's cost of service tariff provided an opportunity to recover 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 an opportunity to collect from its shippers a return on unrecovered rate base as well as recover that rate base through depreciation and amortization. The Chicago Project increased Northern Border Pipeline's rate base, which increased return for the year ended December 31, 1999. Also reflected in the increase in 1999 revenues are recoveries of increased pipeline operating expenses due to the new facilities. Operations and maintenance expense increased $8.7 million (19%) for the year ended December 31, 1999, from the same period in 1998, due primarily to operations and maintenance expenses for The Chicago Project facilities and increased employee payroll and benefit expenses. Depreciation and amortization expense increased $11.0 million (25%) for the year ended December 31, 1999, as compared to the same period in 1998, due primarily to The Chicago Project facilities placed into service. The impact of the additional facilities on depreciation and amortization expense was partially offset by a decrease in the depreciation rate applied to transmission plant from 2.5% to 2.0%. Northern Border Pipeline agreed to reduce the depreciation rate at the time The Chicago Project was placed into service as part of a previous rate case settlement. Taxes other than income increased $8.9 million (41%) for the year ended December 31, 1999, as compared to the same period in 1998, due primarily to ad valorem taxes attributable to the facilities placed into service for The Chicago Project. For the year ended December 31, 1998, Northern Border Pipeline recorded a regulatory credit of $8.9 million. During the construction of The Chicago Project, Northern Border Pipeline placed new facilities into service in advance of the December 1998 project in-service date to maintain gas flow at firm contracted capacity while existing facilities were being modified. The regulatory credit deferred the cost of service of these new facilities, which Northern Border Pipeline began to recover from its shippers commencing with the in-service date of The Chicago Project. Interest expense, net increased $36.8 million (119%) for the year ended December 31, 1999, as compared to the same period in 1998, due to an increase in interest expense of $17.9 million and a decrease in interest expense capitalized of $18.9 million. Interest expense increased due primarily to an increase in average debt outstanding, reflecting amounts borrowed to finance a portion of the capital expenditures for The Chicago Project. The impact of the increased borrowings on interest expense was partially offset by a decrease in average interest rates between 1998 and 1999. The decrease in interest expense capitalized is due to the completion of construction of The Chicago Project in December 1998. Other income decreased $8.6 million (65%) for the year ended December 31, 1999, as compared to the same period in 1998, primarily due to a decrease in the allowance for equity funds used during construction. The decrease in the allowance for equity funds used during construction is due to the completion of construction of The Chicago Project in December 1998. Minority interests in net income increased $5.5 million (18%) for the year ended December 31, 1999, as compared to the same period in 1998, due to increased net income for Northern Border Pipeline. Liquidity and Capital Resources General 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 ("Pipeline Senior Notes"). The indenture under which the Pipeline Senior Notes were issued does not limit the amount of unsecured debt Northern Border Pipeline may incur, but does contain material financial covenants, including restrictions on incurrence of secured indebtedness. The proceeds from the Pipeline Senior Notes were used to reduce indebtedness under a June 1997 credit agreement. In June 1997, Northern Border Pipeline entered into a credit agreement ("Pipeline Credit Agreement") with certain financial institutions to borrow up to an aggregate principal amount of $750 million. The Pipeline Credit Agreement is comprised of a $200 million five-year revolving credit facility to be used for the retirement of Northern Border Pipeline's prior credit facilities and for general business purposes, and a $550 million three-year revolving credit facility to be used for the construction of The Chicago Project. Effective March 1999, in accordance with the provisions of the Pipeline Credit Agreement, Northern Border Pipeline converted the three-year revolving credit facility to a term loan maturing in 2002. At December 31, 2000, $424 million was outstanding under the term loan and $45 million was outstanding under the five-year revolving credit facility. At December 31, 2000, Northern Border Pipeline also had outstanding $184 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 were repaid in August 2000. The Series B Notes with a principal amount of $41 million mature in August 2001. Northern Border Pipeline anticipates borrowing on the Pipeline Credit Agreement to repay the Series B Notes. In June 2000, the Partnership completed a private offering of $150 million of 8 7/8% Senior Notes due 2010 ("Partnership Senior Notes"). In September 2000, the Partnership completed an additional private offering of $100 million of Partnership Senior Notes. The Partnership Senior Notes were subsequently exchanged in a registered offering for notes with substantially identical terms. The indenture under which the Partnership Senior Notes were issued does not limit the amount of unsecured debt the Partnership may incur, but does contain material financial covenants, including restrictions on incurrence of secured indebtedness. The proceeds from the Partnership Senior Notes were used in acquisitions made by the Partnership in June 2000 and September 2000 (see Cash Flows from Investing Activities). In June 2000, the Partnership 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"). At December 31, 2000, $26.3 million was outstanding under the 2000 Partnership Credit Agreements. In November 2000, the Partnership sold, through an underwritten public offering, 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 the 2000 Partnership Credit Agreements. In March 2001, the Partnership completed a private offering of $225 million of 7.10% Senior Notes due 2011 ("2001 Partnership Senior Notes"). The Partnership will register an exchange offer with the Securities and Exchange Commission to exchange the 2001 Partnership Senior Notes for notes with substantially identical terms. The indenture under which the 2001 Partnership Senior Notes were issued does not limit the amount of unsecured debt the Partnership may incur, but does contain material financial covenants, including restrictions on incurrence of secured indebtedness. The proceeds from the 2001 Partnership Senior Notes are to be used to fund a portion of the acquisition of Bear Paw Energy (see Item 1. Business - Pending Acquisitions) and for capital investments and general corporate purposes. In March 2001, the Partnership entered into a $200 million three-year revolving credit agreement with certain financial institutions ("2001 Partnership Credit Agreement"). The 2001 Partnership Credit Agreement is to be used for capital expenditures, working capital and general business purposes. The 2001 Partnership Credit Agreement replaced the 2000 Partnership Credit Agreements discussed previously. Short-term liquidity needs will be met by internal sources and through the lines of credit discussed above. 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 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 provided by operating activities increased $69.5 million to $173.4 million for the year ended December 31, 1999, as compared to the same period in 1998, primarily attributed to The Chicago Project facilities placed into service in late December 1998. Cash Flows From Investing Activities Business acquisitions for the year ended December 31, 2000 include gas gathering businesses in the Powder River and Wind River basins in Wyoming for approximately $229.5 million. For the comparable period in 1999, the Partnership acquired a 39% common member interest in Bighorn for $31.9 million. See Item 1. "Business - General" for a discussion of the acquisitions. 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 Enron North America. As part of the terms of the purchase agreement, Enron North America agreed to fund approximately $3.5 million of an equity investment in Lost Creek. Crestone Energy Ventures expects to make the investment in Lost Creek during 2001. Capital expenditures of $19.7 million for the year ended December 31, 2000 included $7.4 million for Northern Border Pipeline's Project 2000 (see Item 1. "Business - Future Demand and Competition") and $3.8 million for gas gathering facilities for Crestone Energy Ventures. For the same period in 1999, capital expenditures were $102.3 million and included $85.5 million for The Chicago Project and $2.5 million for Project 2000. The remaining capital expenditures for 2000 and 1999 are primarily related to renewals and replacements of existing facilities. Total capital expenditures and investments in unconsolidated affiliates for 2001 are estimated to be $198 million. Capital expenditures for Northern Border Pipeline are estimated to be $97 million, including approximately $81 million for Project 2000 and approximately $16 million primarily for renewals and replacements of existing facilities. Northern Border Pipeline currently anticipates funding its 2001 capital expenditures primarily by using internal sources and borrowing on the Pipeline Credit Agreement. Capital expenditures for Crestone Energy Ventures are estimated to be $79 million and investments in unconsolidated affiliates are estimated to be $22 million for 2001. The Partnership anticipates financing Crestone Energy Venture's capital requirements primarily by borrowing on the Partnership Credit Agreements or other debt facilities. If the acquisitions discussed in Item 1. "Business - Pending Acquisitions" are completed, capital expenditures of $30 to $35 million, in addition to those discussed above, are expected in 2001. Cash Flows From Financing Activities 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 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 the 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 a cash overdraft of approximately $22.4 million primarily due to Northern Border Pipeline's refund checks outstanding. The goal of our cash management program is to maximize the amount of our cash and cash equivalents balance in highly liquid, interest- bearing investments. Those investments are converted to cash when needed to replenish our bank accounts for check clearing requirements. Cash flows used in financing activities were $57.3 million for the year ended December 31, 1999, as compared to cash flows provided by financing activities of $482.6 million for the year ended December 31, 1998. Cash distributions to the unitholders and the general partners increased $4.3 million reflecting an increase in the quarterly distribution from $2.30 per unit for 1998 to $2.44 per unit for 1999. Distributions paid to minority interest holders were $38.1 million for the year ended December 31, 1999, as compared to net cash contributions received from minority interest holders of $48.5 million for the year ended December 31, 1998, which included amounts needed to finance a portion of the capital expenditures for The Chicago Project. Financing activities for the year ended December 31, 1998 reflect $7.6 million in net proceeds from the issuance of 225,000 common units and related capital contributions by the Partnership's general partners in January 1998. Advances under the Pipeline Credit Agreement, which were primarily used to finance a portion of the capital expenditures for The Chicago Project, were $90.0 million for the year ended December 31, 1999. Advances under a Partnership credit agreement, which were used for the acquisition of Bighorn, were $24.5 million for the year ended December 31, 1999. For the same period in 1998, advances under the Pipeline Credit Agreement and a Partnership credit agreement totaled $498.0 million. During the year ended December 31, 1999, $263.0 million was repaid on the Pipeline Credit Agreement. New Accounting Pronouncements In June 1998, the Financial Accounting Standards Board ("FASB") issued Statement of Financial Accounting Standards ("SFAS") No. 133, "Accounting for Derivative Instruments and Hedging Activities." In June 1999, the FASB issued SFAS No. 137, which deferred the effective date of SFAS No. 133 to fiscal years beginning after June 15, 2000. In June 2000, the FASB issued SFAS No. 138, which amended certain guidance within SFAS No. 133. See Note 11 to the Consolidated Financial Statements. Information Regarding Forward Looking Statements Statements in this Annual Report that are not historical information are forward looking statements. Such forward looking statements include: * the discussions under "Business - Future Demand and Competition" and elsewhere regarding Northern Border Pipeline's efforts to pursue opportunities to further increase the capacity of its pipeline system; * the discussion under "Business - Northern Border Rate Case Proceeding" regarding Northern Border Pipeline's rate case settlement; * the discussions under "Business - Pending Acquisitions"; and * the discussion 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 can give no assurance that our goals will be achieved or that our expectations regarding future developments will be realized. Important factors that could cause actual results to differ materially from those in the forward looking statements include: * future demand for natural gas; * availability of economic western Canadian natural gas; * industry conditions; * natural gas, political and regulatory developments that impact FERC proceedings; * Northern Border Pipeline's success in sustaining its positions in such proceedings, or the success of intervenors in opposing Northern Border Pipeline's positions; * Northern Border Pipeline's ability to replace its rate base as it is depreciated and amortized; * competitive developments by Canadian and U.S. natural gas transmission companies; * political and regulatory developments in the U.S. and Canada; * our ability to successfully negotiate final definitive purchase agreements and to receive necessary approvals; and * conditions of the capital markets and equity markets. Item 7a. Quantitative and Qualitative Disclosures About Market Risk Our interest rate exposure results from variable rate borrowings from commercial banks. To mitigate potential fluctuations in interest rates, we attempt to maintain a significant portion of our consolidated debt portfolio in fixed rate debt. We also use interest rate swap agreements to increase the portion of fixed rate debt. As of December 31, 2000, approximately 60% of our debt portfolio, after considering the effect of interest rate swap agreements, is in fixed rate debt. If average interest rates change by one percentage compared to rates in effect as of December 31, 2000, consolidated annual interest expense would change by approximately $4.6 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, 2000. Item 8. Financial Statements and Supplementary Data The information required hereunder is included in this report as set forth in the "Index to Financial Statements" on page F-1. Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure None. Item 10. Partnership Management We are managed by or under the direction of the Partnership Policy Committee consisting of three members, each of which has been appointed by one of the 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. The Partnership Policy Committee has appointed three 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") with 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, pursuant to which NBP Services provides tax, accounting, legal, cash management, investor relations, operating and other services for the Partnership. NBP Services has 22 employees and uses the employees of Enron or its affiliates who have duties and responsibilities other than those relating to the Administrative Services Agreement. Upon completion of the acquisition of the interests in Bear Paw, NBP Services will increase its employees by approximately 100. 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. 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. Effective October 1, 2000, William R. Cordes replaced Larry L. DeRoin as our Chief Executive Officer and Chairman of the Partnership Policy Committee and of the Northern Border Management 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. Each Audit Committee member receives an annual fee of $20,000 and is paid $1,500 for each meeting attended. Effective February 2001, a third Audit Committee member was elected. Name Age Positions Executive Officers: William R. Cordes 52 Chief Executive Officer Jerry L. Peters 43 Chief Financial and Accounting Officer Members of Partnership Policy Committee and Partnership's representatives on Northern Border Management Committee: William R. Cordes 52 Chairman Stanley C. Horton 51 Member Cuba Wadlington, Jr. 57 Member Members of Audit Committee: Daniel P. Whitty 69 Chairman Daniel Dienstbier 60 Member Gerald B. Smith 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. In June of 1993, he was named President of Northern Natural and added the position of President of Transwestern Pipeline in May of 1996. 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 Transportation Services Company, formerly the Enron Gas Pipeline Group, and has held that position since January 1997. 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, Chairman of the Board and Chief Executive Officer of EOTT Energy Corp., the general partner of EOTT Energy Partners, L.P. Cuba Wadlington, Jr. was named to the Partnership Policy Committee and to the Northern Border Management Committee on December 1, 1999. On January 4, 2000, Mr. Wadlington was named President and Chief Executive Officer of Williams Gas Pipeline. Previously, he had served as Executive Vice President and Chief Operating Officer of Williams Gas Pipeline since July 1999. Mr. Wadlington joined Transco in 1995 when Williams acquired Transco Energy Company. From 1995 to 1999, he served as senior vice president and general manager of Williams Gas Pipeline-Transco. From 1988 to 1995, he served as senior vice president and general manager of Williams Western Pipeline Company, executive vice president of Kern River Gas Transmission Company, and director of Northwest Pipeline Corporation and Williams Western Pipeline, all affiliates or subsidiaries of Williams. Mr. Wadlington serves on the Board of Directors of Williams Communication Group Inc., and Sterling Bancshares Inc. 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 Treasurer for Northern Plains in October 1998, Vice President of Finance for Northern Plains in July 1994, and director of Northern Plains in August 1994. Mr. Peters was also named Vice President, Finance of Enron Transportation Services Company in February 2001. Prior to joining Northern Plains in 1985, Mr. Peters was employed as a Certified Public Accountant by KPMG Peat Marwick, LLP. Daniel P. Whitty was appointed to the Audit Committee in December 1993. Mr. Whitty is an independent financial consultant. He is a director of Enron Funding Corp., Enron Equity Corp. and of EOTT Energy Corp., all subsidiaries of Enron, and the latter of which is the general partner of EOTT Energy Partners, L.P. 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 & Co. until his retirement on January 31, 1988. 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 that company since December 1998 and is a member of the Audit Committee and Executive Committee of the board. He is also a director of Pennzoil-Quaker States, 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. Daniel Dienstbier was appointed to the Audit Committee effective February 1, 2001. Mr. Dienstbier is currently a member of the Board of Directors of Dynegy Corporation and has served on that board since 1995. At the time of his retirement in 1994, he was the President and Chief Operating Officer of American Oil & Gas Company. He serves on arbitration panels involving energy contract disputes. From 1965 through mid-1988, Mr. Dienstbier held various positions with Northern Natural Gas Company. From 1985 to 1988, he was the President of Enron's Gas Pipeline Group, which included Enron's interest in Northern Border Pipeline. 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) Larry L. DeRoin 2000 $209,167 $ -- $16,844 $164,754 11,335 $403,125 $513,534 Chief Executive 1999 $266,367 $225,000 $ 7,773 $ -- -- $ -- $ 10,413 Officer 1998 $256,067 $250,000 $ 7,200 $125,024 19,020 $ -- $ 6,380 William R. Cordes 2000 $311,000 $250,000 $15,000 $205,984 17,405 $131,250 $ 13,110 Chief Executive Officer Jerry L. Peters 2000 $145,293 $110,000 $ 3,708 $112,385 15,040 $ -- $ 10,091 Chief Financial and 1999 $132,933 $100,000 $ 3,983 $ -- 9,070 $ -- $ 5,260 Accounting Officer 1998 $123,225 $110,000 $ 1,214 $ 60,030 20,000 $ -- $ 1,956 (1) Mr. DeRoin retired effective September 30, 2000. Mr. Cordes was appointed President of Northern Plains and Chief Executive Officer of the Partnership on October 1, 2000. (2) Employees may 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. 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. He received 1,532 units in 1999 and 1,450 units in 2000. In each case, units will be released to him five years following the grant date. (3) Other Annual Compensation includes cash perquisite allowances, service awards, and vacation payouts. Also, Enron maintains three deferral plans for key employees under which payment of base salary, annual bonus, and long-term incentive awards may 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 1998, 1999 and 2000 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 1998, 1999, and 2000, 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 1998, 1999 and 2000. (4) The aggregate total of shares in unreleased Enron restricted stock holdings and their values as of December 31, 2000, for each of the Named Officers is: Mr. Cordes, 7,737 shares valued at $643,138, and Mr. Peters, 2,755 shares valued at $229,009. Dividend equivalents for all restricted stock awards accrue from date of grant and are paid upon vesting. (5) Reflects cash payments under the Enron Corp. Performance Unit Plan for the 1996-1999 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. Mr. DeRoin's payment includes amounts relating to 1997-2000 and 1998-2001 performance periods ($187,250 and $103,125 respectively) which were paid early due to his retirement. (6) The amounts shown include the value of Enron Common Stock allocated to employees' special subaccounts under Enron's Employee Stock Ownership Plan, matching contributions to employees' Enron Corp. Savings Plan, and imputed income on life insurance benefits. Mr. DeRoin received a $500,000 payment following his retirement. Such payment was in lieu of any severance pay or severance benefits that otherwise would be payable under Enron's Severance Pay Plan. In addition, Mr. DeRoin has entered into an agreement under which he has agreed to provide consulting services to Northern Plains and its businesses until September 30, 2002 for which he receives a payment of $20,833 per month.

Stock Option Grants During 2000 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 2000.

Potential Realizable Value at Individual Grants Assumed Annual Rates of Stock Number of % of Total Price Appreciation for Option Term (1) Securities Options/SARs Underlying Granted to Exercise or Options/SARs Employees in Base Price Expiration Name Granted(#) Fiscal Year ($/Sh) Date 0%(2) 5% 10% Larry L. DeRoin 11,285 (3) 0.03% $55.5000 01/18/2007 $ -- $254,974 $594,198 50 (4) 0.00% $55.5000 01/18/2007 $ -- $ 1,130 $ 2,633 William R. Cordes 14,105 (3) 0.04% $55.5000 01/18/2007 $ -- $318,689 $742,682 50 (4) 0.00% $55.5000 01/18/2007 $ -- $ 1,130 $ 2,633 3,250 (6) 0.01% $83.1250 12/29/2007 $ -- $ 73,431 $171,125 Jerry L. Peters 7,695 (3) 0.02% $55.5000 01/18/2007 $ -- $173,861 $405,171 50 (4) 0.00% $55.5000 01/18/2007 $ -- $ 1,130 $ 2,633 5,770 (5) 0.01% $65.0000 01/24/2007 $ -- $152,683 $355,816 1,525 (6) 0.00% $83.1250 12/29/2007 $ -- $ 34,456 $ 80,297 (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. (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 25% on the grant date and 25% on each anniversary thereafter. (4) A grant of 50 stock options was provided to each eligible Enron employee in recognition of Enron stock reaching a fair market value of $50 after the August, 1999, 2-for-1 stock split. (5) Mr. Peters elected to receive stock options in lieu of a portion of his 1999 annual cash bonus payment in the form of stock options which were granted in January, 2000 and were 100% vested on date of grant. (6) All eligible employees received an option grant under the EnronOptions Program. The EnronOptions Program provides a grant of options equal to 5% of base annual salary for each year of participation in the program, not to exceed five years of participation. Stock options vest 20% each year beginning June 30, 2001.

Aggregated Stock Option/SAR Exercises During 2000 and Stock Option/SAR Values as of December 31, 2000 The following table sets forth information with respect to the Named Officers concerning the exercise of Enron SARs and options during the last fiscal year and unexercised Enron options and SARs held as of the end of the fiscal year:

Number of Securities Underlying Unexercised Value of Unexercised Shares Options/SARs at In-the-Money Options/SARs Acquired on Value December 31, 2000 December 31, 2000 (1) Name Exercise (#) Realized Exercisable Unexercisable Exercisable Unexercisable Larry L. DeRoin 102,990 $5,458,031 50,875 -- $ 2,630,794 $ -- William R. Cordes 47,130 $2,922,001 213,788 41,327 $13,454,935 $1,945,463 Jerry L. Peters 9,090 $ 432,676 54,084 9,891 $ 2,915,839 $ 393,525 (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, 2000 ($83.1250) 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. 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 30.4 43.1 $311,000 $142,234 Mr. Peters 15.9 37.8 $145,293 $ 78,957 ________ 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.

Mr. DeRoin participates in the Executive Supplemental Survivor Benefit Plan. In the event of death after retirement, the Plan provides an annual benefit to the participant's beneficiary equal to 50 percent of the participant's annual base salary at retirement, paid for 10 years. The Plan also provides that in the event of death before retirement, the participant's beneficiary receives an annual benefit equal to 30% of the participant's annual base salary at death, paid for the life of the participant's spouse (but for no more than 20 years in some cases). Severance Plans Enron's Severance Pay Plan, as amended, 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 economic factors. The amount of benefits payable for performance related terminations is based on length of service and may not exceed six weeks' pay. For those terminated as the result of reorganization or economic circumstances, the benefit is based on length of service and amount of pay up to a maximum payment of 26 weeks of base pay. If the employee signs a Waiver and Release of Claims Agreement, the severance pay benefits are doubled. Under no circumstances will the total severance pay benefit exceed 52 weeks of pay. Under the Enron Corp. Change of Control Severance Plan, in the event of an unapproved change of control of Enron, any employee who is involuntarily terminated within two years following the change of control will be eligible for severance benefits equal to two weeks of base pay multiplied by the number of full or partial years of service, plus one month of base pay for each $10,000 (or portion of $10,000) included in the employee's annual base pay, plus one month of base pay for each five percent of annual incentive award opportunity under any approved plan. The maximum an employee can receive is 2.99 times the employee's average W-2 earnings over the past five years. 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 February 15, 2001 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 Units1/ of Class Jerry L. Peters 1,000 * 1111 South 103rd Street Omaha, NE 68124-1000 Stanley C. Horton 1400 Smith Street Houston, TX 77002-7369 10,000 * The Williams Companies, Inc.2/ 1,123,500 3.6 One Williams Center Tulsa, OK 74101-3288 Enron Corp.2/ 1400 Smith Street Houston, TX 77002 3,215,452 10.2 Duke Energy Corp.2/ 422 So. Church St. Charlotte, NC 88242-0001 2,086,500 6.6 ______________ * Less than 1%. 1/ All units involve sole voting and investment power. 2/ Indirect ownership through their subsidiaries. Item 13. Certain Relationships and Related Transactions We have extensive ongoing relationships with the general partners. Such relationships include the following: (i) Northern Plains provides, in its capacity as the operator of the Northern Border pipeline system, certain tax, accounting and other information to the Partnership, (ii) NBP Services, an affiliate of Enron, assists the Partnership in connection with the operation and management of the Partnership and operating services for Crestone Energy Ventures pursuant to the terms of an Administrative Services Agreement between the Partnership and NBP Services, (iii) NBP Energy Pipelines, L.L.C. (now known as Crestone Energy Ventures, L.L.C) purchased from Enron North America Corp., an affiliate of Enron, interests in gas gathering businesses in the Powder River and Wind River Basins in Wyoming for approximately $209 million, and (iv) Crestone Energy Ventures provides to Enron North America Corp., under a Master Services Agreement effective September 21, 2000, gas and administrative services for fixed and variable fees. The amount of fixed fees for 2000 was $45,000 per day and for 2001 is $21,600 per day. In addition, Northern Border Pipeline has extensive ongoing relationships with the general partners and certain of their affiliates and with affiliates of TC PipeLines. For example, Northern Plains has acted (since 1980), and will continue to act, as the operator of the pipeline system pursuant to the terms of an operating agreement between Northern Plains and Northern Border Pipeline. In addition, as of February 1, 2001: * Enron North America Corp., an affiliate of Enron, is one of Northern Border Pipeline's firm shippers, and is obligated to pay for 6.3% of the capacity. It also has contracted with Crestone Energy Venture and Crestone Gas Services for certain gas and administrative services for which it pays both a fixed and variable fee. * TransCanada Energy Marketing USA, Inc., an affiliate of TransCanada PipeLines Limited, is one of Northern Border Pipeline's firm shippers and is currently obligated to pay for 11.4% of the capacity; * 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 0.8% of the capacity; and * Northern Natural Gas Company, an affiliate of Enron, provides a financial guaranty for a portion of the transportation capacity held by Pan-Alberta Gas, which currently represents 10.5% 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 the Partnership's 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 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 the our interest or the interest of TC PipeLines and their 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 restrict the Partnership from taking actions that might be in our best interest but in conflict with the fiduciary duty that our representatives or we owe to 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: * The Partnership Agreement states that the general partners, their affiliates and their officers and directors will not be liable for damages to the Partnership, its 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. * The Partnership Agreement allows the general partners and the Partnership Policy Committee to take into account the interests of parties in addition to our interest in resolving conflicts of interest. * The Partnership Agreement provides that the general partners will not be in breach of their obligations under the 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 the 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. * The Partnership Agreement provides that a purchaser of Common Units is deemed to have consented to certain conflicts of interest and actions of the general partners and their affiliates that might otherwise be prohibited and to have agreed that such conflicts of interest and actions do not constitute a breach by the general partners of any duty stated or implied by law or equity. * Our Audit Committee will, at the request of a general partner or a member of the Partnership Policy Committee, review conflicts of interest that may arise between a general partner and its affiliates (or the member of the Partnership Policy Committee designated by it), on the one hand, and the unitholders or us, on the other. Any resolution of a conflict approved by the Audit Committee is conclusively deemed fair and reasonable to us. * We entered into an amendment to the partnership agreement for 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. 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, the Partnership's best interests and with respect to any criminal proceedings, had no reasonable cause to believe the conduct was unlawful. 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 Registration Rights Agreement dated March 21, 2001 by and among Northern Border Partners, L.P., Northern Border Intermediate Limited Partnership, Banc of America Securities LLC, SunTrust Equitable Securities Corporation, Banc One Capital Markets, Inc. and BMO Nesbitt Burns Corp. * 4.5 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"). *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). *10.4.1 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")). *10.5 Guaranty made by Panhandle Eastern Pipeline Company, dated October 31, 1992 (Exhibit 10.9 to Form S-1). *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). *10.6.1 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")). *10.6.2 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). *10.6.3 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). *10.6.4 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")). *10.7 Guaranty made by Northern Natural Gas Company, dated October 7, 1993 (Exhibit 10.11.1 to 1993 10-K). *10.8 Guaranty made by Northern Natural Gas Company, dated October 7, 1993 (Exhibit 10.11.2 to 1993 10-K). *10.9 Northern Border Pipeline Company U.S. Shippers Service Agreement between Northern Border Pipeline Company and Western Gas Marketing Limited, as agent for TransCanada PipeLines Limited, dated December 15, 1980 (Exhibit 10.13 to Form S-1). *10.9.1 Amendment to Northern Border Pipeline Company Service Agreement extending the term effective November 1, 1995 (Exhibit 10.13.1 to 1995 10-K). *10.10 Form of Seventh Supplement Amending Northern Border Pipeline Company General Partnership Agreement (Exhibit 10.15 to Form S-1). *10.11 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). *10.12 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")). *10.13 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). *10.14 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). *10.15 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). *10.16 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). *10.17 Northern Border Pipeline Company U.S. Shippers Service Agreement between Northern Border Pipeline Company and TransCanada Gas Services Inc., as agent for TransCanada PipeLines Limited dated August 5, 1997 (Exhibit 10.27 to 1997 10-K). *10.18 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). *10.19 Eighth Supplement Amending Northern Border Pipeline Company General Partnership Agreement (Exhibit 10.15 to NB Form S-4). 10.20 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). *10.21 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")). *10.22 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). *10.23 Northern Border Pipeline Company U.S. Shippers Service Agreement between Northern Border Pipeline Company and Pan- Alberta Gas (U.S.) Inc., dated October l, 1992, with Amended Exhibit A effective June 22, 1998 (Exhibit 10.38 to NB Pipeline 1999 10-K). 10.24 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.). 10.25 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. 10.26 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). 21 The subsidiaries of Northern Border Partners, L.P. are Northern Border Intermediate Limited Partnership; Northern Border Pipeline Company; and Crestone Energy Ventures, L.L.C. 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). *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 2, 2000, reporting the public offering of up to 2,156,250 common units representing limited partner interests and including exhibits. 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, 2001. NORTHERN BORDER PARTNERS, L.P. (A Delaware Limited Partnership) By: WILLIAM R. CORDES William R. Cordes Chief Executive Officer Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons in the capacities and on the dates indicated. Signature Title Date WILLIAM R. CORDES Chief Executive Officer and March 29, 2001 William R. Cordes Chairman of the Partnership Policy Committee (Principal Executive Officer) STANLEY C. HORTON Member of Partnership Policy March 29, 2001 Stanley C. Horton Committee CUBA WADLINGTON, JR. Member of Partnership Policy March 29, 2001 Cuba Wadlington, Jr. Committee JERRY L. PETERS Chief Financial and March 29, 2001 Jerry L. Peters Accounting Officer NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES INDEX TO FINANCIAL STATEMENTS Page No. Consolidated Financial Statements Report of Independent Public Accountants F-2 Consolidated Balance Sheet - December 31, 2000 and 1999 F-3 Consolidated Statement of Income - Years Ended F-4 December 31, 2000, 1999 and 1998 Consolidated Statement of Cash Flows - Years Ended F-5 December 31, 2000, 1999 and 1998 Consolidated Statement of Changes in Partners' Capital - Years Ended December 31, 2000, 1999 and 1998 F-6 Notes to Consolidated Financial Statements F-7 through F-26 Financial Statements Schedule Report of Independent Public Accountants on Schedule S-1 Schedule II - Valuation and Qualifying Accounts S-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 1999, and the related consolidated statements of income, cash flows and changes in partners' capital for each of the three 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 1999, and the results of their operations and their cash flows for each of the three 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 NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEET (In Thousands)

December 31, ASSETS 2000 1999 CURRENT ASSETS Cash and cash equivalents $ 35,363 $ 22,927 Accounts receivable 31,538 24,946 Related party receivables 9,079 5,292 Materials and supplies, at cost 5,736 4,410 Under recovered cost of service -- 3,068 Total current assets 81,716 60,643 TRANSMISSION PLANT Property, plant and equipment 2,454,918 2,410,133 Less: Accumulated provision for depreciation and amortization 722,842 664,777 Property, plant and equipment, net 1,732,076 1,745,356 INVESTMENTS AND OTHER ASSETS Investments in unconsolidated affiliates 221,625 31,895 Goodwill 28,405 9,076 Other 18,898 16,467 Total investments and other assets 268,928 57,438 Total assets $2,082,720 $1,863,437 LIABILITIES AND PARTNERS' CAPITAL CURRENT LIABILITIES Current maturities of long-term debt $ 44,464 $ 183,617 Accounts payable 35,413 8,279 Accrued taxes other than income 28,493 26,608 Accrued interest 15,635 17,608 Accumulated provision for rate refunds 4,726 2,317 Total current liabilities 128,731 238,429 LONG-TERM DEBT, net of current maturities 1,127,498 848,369 MINORITY INTERESTS IN PARTNERS' CAPITAL 248,098 250,450 RESERVES AND DEFERRED CREDITS 6,119 10,920 COMMITMENTS AND CONTINGENCIES (NOTE 9) PARTNERS' CAPITAL General Partners 11,445 10,305 Common Units 560,829 504,964 Total partners' capital 572,274 515,269 Total liabilities and partners' capital $2,082,720 $1,863,437 The accompanying notes are an integral part of these consolidated financial statements.

NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES CONSOLIDATED STATEMENT OF INCOME (In Thousands, Except Per Unit Amounts)

Year Ended December 31, 2000 1999 1998 OPERATING REVENUES Operating revenues $363,688 $321,280 $217,592 Provision for rate refunds (23,956) (2,317) -- Operating revenues, net 339,732 318,963 217,592 OPERATING EXPENSES Operations and maintenance 62,097 53,451 44,770 Depreciation and amortization 60,699 54,842 43,885 Taxes other than income 28,634 30,952 22,012 Regulatory credit -- -- (8,878) Operating expenses 151,430 139,245 101,789 OPERATING INCOME 188,302 179,718 115,803 INTEREST EXPENSE Interest expense 81,881 67,807 49,923 Interest expense capitalized (386) (98) (19,001) Interest expense, net 81,495 67,709 30,922 OTHER INCOME Allowance for equity funds used during construction 305 101 10,237 Equity earnings (losses) of unconsolidated affiliates (647) -- -- Other income, net 8,374 4,461 2,971 Other income 8,032 4,562 13,208 MINORITY INTERESTS IN NET INCOME 38,119 35,568 30,069 NET INCOME TO PARTNERS $ 76,720 $ 81,003 $ 68,020 NET INCOME PER UNIT $ 2.50 $ 2.70 $ 2.27 NUMBER OF UNITS USED IN COMPUTATION 29,665 29,347 29,345 The accompanying notes are an integral part of these consolidated financial statements.

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

Year Ended December 31, 2000 1999 1998 CASH FLOWS FROM OPERATING ACTIVITIES: Net income to partners $ 76,720 $ 81,003 $ 68,020 Adjustments to reconcile net income to partners to net cash provided by operating activities: Depreciation and amortization 61,054 54,895 43,899 Minority interests in net income 38,119 35,568 30,069 Provision for rate refunds 25,082 2,317 -- Rate refunds paid (22,673) -- -- Allowance for equity funds used during construction (305) (101) (10,237) Reserves and deferred credits (4,801) 1,077 (24) Regulatory credit -- -- (9,105) Changes in components of working capital (2,279) (1,482) (19,243) Other (1,302) 91 470 Total adjustments 92,895 92,365 35,829 Net cash provided by operating activities 169,615 173,368 103,849 CASH FLOWS FROM INVESTING ACTIVITIES: Capital expenditures for property, plant and equipment, net (19,721) (102,270) (652,194) Acquisition of businesses (229,505) (31,895) -- Investments in unconsolidated affiliates (8,766) -- -- Net cash used in investing activities (257,992) (134,165) (652,194) CASH FLOWS FROM FINANCING ACTIVITIES: Cash distributions General and limited partners (80,411) (73,160) (68,876) Minority Interests (40,471) (38,149) (18,362) Contributions received from Minority Interests -- -- 66,900 Issuance of partnership interests, net 60,696 -- 7,554 Issuance of long-term debt, net 431,148 313,526 498,000 Retirement of long-term debt (304,817) (270,805) (2,523) Increase in cash overdraft 22,437 -- -- Proceeds received upon termination of derivatives 15,005 12,896 -- Long-term debt financing costs (2,774) (1,626) (63) Net cash provided by (used in) financing activities 100,813 (57,318) 482,630 NET CHANGE IN CASH AND CASH EQUIVALENTS 12,436 (18,115) (65,715) Cash and cash equivalents-beginning of year 22,927 41,042 106,757 Cash and cash equivalents-end of year $ 35,363 $ 22,927 $ 41,042 Changes in components of working capital: Accounts receivable $ (8,502) $ (8,691) $ (1,628) Materials and supplies (1,313) (221) 269 Accounts payable 4,755 (3,897) (11,830) Accrued taxes other than income 1,686 6,468 (368) Accrued interest (1,973) 5,146 1,696 Over/under recovered cost of service 3,068 (287) (7,382) Total $ (2,279) $ (1,482) $ (19,243) The accompanying notes are an integral part of these consolidated financial statements.

NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES CONSOLIDATED STATEMENT OF CHANGES IN PARTNERS' CAPITAL (In Thousands)

Total General Common Subordinated Partners' Partners Units Units Capital Partners' Capital at December 31, 1997 $10,015 $394,587 $ 96,126 $500,728 Net income to partners 1,359 52,077 14,584 68,020 Issuance of partnership interests, net 151 7,457 (54) 7,554 Distributions paid (1,377) (52,733) (14,766) (68,876) Partners' Capital 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' Capital 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' Capital at December 31, 2000 $11,445 $560,829 $ -- $572,274 The accompanying notes are an integral part of these consolidated financial statements.

NORTHERN BORDER PARTNERS, L. P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 1. ORGANIZATION AND MANAGEMENT Northern Border Partners, L.P., a Delaware limited partnership, through a subsidiary limited partnership, Northern Border Intermediate Limited Partnership, a Delaware limited partnership, 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). Black Mesa Holdings, Inc. (Black Mesa) and Crestone Energy Ventures, L.L.C. (Crestone Energy Ventures)(formerly NBP Energy Pipelines, L.L.C.) 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. serve as the General Partners of the Partnership and collectively own a 2% general partner interest in the Partnership. In December 1998, Northern Plains acquired Pan Border from a subsidiary of Duke Energy Corporation. At the closing of the acquisition, Pan Border's sole asset consisted of its general partner interest in the Partnership. The General Partners or their affiliates also own common units representing, in the aggregate, an effective 13.5% limited partner interest in the Partnership at December 31, 2000 (see Note 8). The Partnership is managed by or is under the direction of a committee (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 is reimbursed for its direct and indirect costs and expenses. Northern Border Pipeline is a general partnership, formed in 1978, pursuant to the Texas Uniform Partnership Act. Northern Border Pipeline owns a 1,214-mile natural gas transmission pipeline system extending from the United States-Canadian border near Port of Morgan, Montana, to a terminus near Manhattan, Illinois. 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), 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, 2000, 1999 and 1998, Northern Border Pipeline reimbursed the Operator approximately $31.7 million, $29.7 million and $30.0 million, respectively. Additionally, Northern Border Pipeline utilizes 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. Crestone Energy Ventures owns a 49% common membership interest and a 100% class A share interest in Bighorn Gas Gathering, L.L.C. (Bighorn); a 33% interest in Fort Union Gas Gathering, L.L.C. (Fort Union); and a 35% interest in Lost Creek Gathering, L.L.C. (Lost Creek). Crestone Gathering Services, L.L.C. (Crestone Gathering Services) is a wholly-owned subsidiary of Crestone Energy Ventures. Crestone Energy Ventures acquired its interests in Fort Union, Lost Creek, Crestone Gathering Services and a portion of Bighorn in September 2000 (see Note 3). Collectively, Crestone Gathering Services, 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. NBP Services provides certain administrative and management services for Crestone Energy Ventures. Black Mesa, through a wholly-owned subsidiary, 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 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 is 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 generally accepted accounting principles for nonregulated entities. At December 31, 2000 and 1999, Northern Border Pipeline has reflected regulatory assets of approximately $12.4 million and $12.1 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 four to 43 years. (C) Revenue Recognition Northern Border Pipeline transports gas for shippers under a tariff regulated by the FERC. The tariff specifies the calculation of amounts to be paid by shippers and the general terms and conditions of transportation service on the pipeline system. Northern Border Pipeline's 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 does not own the gas that it transports, and therefore it does not assume the related natural gas commodity risk. See Notes 4 and 5 for a further discussion of Northern Border Pipeline's tariff and transportation agreements. (D) 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. (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 $326 million and $316 million at December 31, 2000 and 1999, 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. The original cost of utility property retired is charged to accumulated depreciation and amortization, net of salvage and cost of removal. No retirement gain or loss is included in income except in the case of extraordinary retirements or sales. Maintenance and repairs are charged to operations in the period incurred. The provision for depreciation and amortization of the transmission line is an integral part of Northern Border Pipeline's FERC tariff. The effective depreciation rates applied to Northern Border Pipeline's transmission plant in 2000, 1999 and 1998 were 2.25%, 2.0% and 2.5%, respectively. Based upon the rate case settlement discussed in Note 4, Northern Border Pipeline will continue to use a 2.25% depreciation rate. The effective depreciation rate applied to Crestone Energy Venture's gathering facilities was 3.33%. Composite rates are applied to all other functional groups of property having similar economic characteristics. (G) Allowance for Funds Used During Construction The allowance for funds used during construction (AFUDC) represents the estimated costs, during the period of construction, of funds used for construction purposes. For regulated activities, Northern Border Pipeline is permitted to earn a return on and recover AFUDC through its inclusion in rate base and the provision for depreciation. (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 2000, the Partnership recorded amortization expense of $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 Partnership's consolidated statement of income. See Note 7 for details on the Partnership's investments in unconsolidated affiliates and related equity earnings (losses). (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 2000, 1999 and 1998, the Partnership recorded amortization expense of $0.5 million, $0.3 million and $0.3 million, respectively. This amortization expense is reflected as a component of depreciation and amortization in the Partnership's consolidated statement of income. (J) Risk Management Financial instruments are used in the management of the Partnership's interest rate 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. As a result, Northern Border Pipeline has entered into various interest rate swap agreements with major financial institutions which hedge interest rate risk by effectively converting certain of its floating rate debt to fixed rate debt. Northern Border Pipeline does not use these instruments for trading purposes. The cost or benefit of the interest rate swap agreements is recognized currently as a component of interest expense. (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, Crestone Energy Ventures purchased a 39% common membership interest in Bighorn for approximately $31.9 million and in June 2000, Crestone Energy Ventures purchased 80% of class A shares in Bighorn for approximately $20.8 million. In September 2000, Crestone Energy Ventures 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 Crestone Energy Venture's ownership in Bighorn to a 49% common membership interest and a 100% interest in the class A shares. The Partnership has accounted for these acquisitions using the purchase method of accounting. The purchase price has been allocated based upon the estimated fair value of the assets and liabilities acquired as of the acquisition date. The excess of the purchase price over the fair value of the Crestone Gathering Services net assets acquired is reflected as goodwill on the consolidated balance sheet. The investments in Bighorn, Fort Union and Lost Creek are being reflected in investments in unconsolidated affiliates on the consolidated balance sheet. See Note 7 for additional discussion of the Partnership's investments in unconsolidated affiliates. The following is a summary of the effects of the acquisitions made in 2000 and 1999 on the Partnership's consolidated financial position (amounts in thousands):

2000 1999 Current assets $ 1,949 $ -- Property, plant and equipment 29,789 -- Investments in unconsolidated affiliates 179,079 31,895 Goodwill 18,887 -- Current liabilities (199) -- $229,505 $31,895

If the acquisitions made in 2000 had occurred at the beginning of 2000, the Partnership's 2000 consolidated operating revenues would have been $343 million, net income to partners would have been $65 million and net income per unit would have been $2.00. 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, which represents approximately 93.8% of its capitalization, and non-voting class A and class B shares, each of which represents approximately 3.1% of the total capitalization. Both of the non-voting classes of shares are subject to certain distribution preferences as well as 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 1999 and 2000, no income allocation or cash distribution was made to the non-voting shares. Ownership of these shares does not affect the amount of capital contributions that are required to be made to the operations of Bighorn by the owners of the common membership interests. 4. RATES AND REGULATORY ISSUES 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 current 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. Under the cost of service tariff, Northern Border Pipeline billed on an estimated basis for a six-month cycle. Any net excess or deficiency resulting from the comparison of the actual cost of service determined for the period in accordance with the FERC tariff to the estimated billing was accumulated, including carrying charges thereon, and was either billed to or credited back to the shippers. Revenues reflected actual cost of service. An amount equal to differences between billing estimates and the actual cost of service, including carrying charges, was reflected in current assets or current liabilities. 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 pending rate case. The settlement was approved by the FERC in December 2000. Under the approved settlement, effective December 1, 1999, shippers will pay 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. From December 1, 1999, through and including December 31, 2000, the rates were based upon an annual revenue level of $307 million. For periods after December 31, 2000, the rates are based upon an annual revenue level of $305 million. The settlement further provides for the incorporation into Northern Border Pipeline's rate base all of the construction costs of The Chicago Project, which was Northern Border Pipeline's expansion and extension of its pipeline from near Harper, Iowa to a point near Manhattan, Illinois. Northern Border Pipeline had placed into service the facilities for The Chicago Project in December 1998. 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. At December 31, 2000, Northern Border Pipeline had estimated its remaining refund obligation through the end of 2000 to be approximately $4.7 million, which is expected to be paid in the first quarter of 2001. Northern Border Pipeline's operating revenues for 2000 reflect the significant terms of the approved settlement. Certificate application In October 1998, Northern Border Pipeline filed a certificate application with the FERC to seek approval to expand and extend its pipeline system into Indiana (Project 2000). When completed, Project 2000 will afford shippers on the expanded and extended pipeline system access to industrial gas consumers in northern Indiana. The certificate application was subsequently amended by Northern Border Pipeline in March and December 1999. On March 16, 2000, the FERC issued an order granting Northern Border Pipeline's application for a certificate to construct and operate the proposed facilities. The FERC approved Northern Border Pipeline's request for rolled-in rate treatment based upon the proposed project costs. The project has a targeted in-service date of November 2001. The capital expenditures for the project are estimated to be approximately $94 million, of which $10.8 million had been incurred through December 31, 2000. 5. TRANSPORTATION AGREEMENTS Northern Border Pipeline's operating revenues are collected pursuant to the FERC tariff through firm transportation service agreements (firm service agreements). The firm service agreements extend for various terms with termination dates that range from October 2001 to December 2013. Northern Border Pipeline also has interruptible service agreements with numerous other shippers as a result of its self-implementing blanket transportation authority. Under the approved settlement of Northern Border Pipeline's rate case discussed in Note 4, in certain situations, 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. After October 31, 2003, all revenues from interruptible transportation service will be retained by Northern Border Pipeline. Northern Border Pipeline's largest shipper, Pan-Alberta Gas (U.S.) Inc. (PAGUS), is presently obligated for approximately 25.5% of the contracted firm capacity through three firm service agreements which expire in October 2003. Financial guarantees exist through October 2001 for approximately 16.3% of the contracted firm capacity of PAGUS, including 10.5% guaranteed by Northern Natural Gas Company, a wholly-owned subsidiary of Enron. The remaining obligation of PAGUS is supported by various credit support arrangements, including among others, a letter of credit, an escrow account and an upstream capacity transfer agreement. Operating revenues from the PAGUS firm service agreements and interruptible service agreements for the years ended December 31, 2000, 1999 and 1998 were $65.0 million, $76.6 million and $87.3 million, respectively. TransCanada Energy Marketing USA, Inc. (TransCanada Energy), an affiliate of TC PipeLines, has firm service agreements representing approximately 11.4% of contracted capacity. The firm service agreements for TransCanada Energy extend for various terms with termination dates that range from October 2003 to December 2008. Other shippers affiliated with the partners of Northern Border Pipeline have firm service agreements representing approximately 7.1% of contracted capacity. These firm service agreements extend for various terms with termination dates that range from January 2002 to May 2009. Operating revenues from the affiliated firm service agreements and interruptible service agreements for the years ended December 31, 2000, 1999, and 1998 were $58.5 million, $52.5 million and $22.4 million, respectively. Crestone Energy Ventures and Crestone Gathering Services (collectively Crestone) provide gas gathering and administrative services to third parties, ENA, and the Partnership's unconsolidated affiliates. Crestone's total revenues from affiliates for the year ended December 31, 2000, were $7.3 million. Black Mesa's operating revenue is derived from a pipeline transportation agreement (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. 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. 6. CREDIT FACILITIES AND LONG-TERM DEBT Detailed information on long-term debt is as follows:

December 31, (In thousands) 2000 1999 Northern Border Pipeline 1992 Pipeline Senior Notes - average 8.49% and 8.43% at December 31, 2000 and 1999, respectively, due from 2000 to 2003 $ 184,000 $ 250,000 Pipeline Credit Agreement Term loan, due 2002 424,000 439,000 Five-year revolving credit facility 45,000 -- 1999 Pipeline Senior Notes - 7.75%, due 2009 200,000 200,000 Northern Border Partners, L.P. Partnership Senior Notes - 8 7/8%, due 2010 250,000 -- Partnership Credit Agreements - Three-year revolving credit facility 26,300 -- Credit agreements - average 6.78%, due 2000 -- 114,500 Black Mesa 10.7% Note agreement, due quarterly to 2004 13,910 17,027 Unamortized proceeds from termination of derivatives 26,046 12,397 Unamortized debt premium (discount) 2,706 (938) Total 1,171,962 1,031,986 Less: Current maturities of long-term debt 44,464 183,617 Long-term debt $1,127,498 $ 848,369

In June 2000, the Partnership completed a private offering of $150 million of 8 7/8% Senior Notes due 2010 (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 Partnership Senior Notes. The proceeds from this offering, along with the proceeds from the credit agreements described below, were used for the acquisition of the interests in gas gathering businesses from ENA (see Note 3). The 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 June 2000, the Partnership 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, Partnership Credit Agreements). The Partnership Credit Agreements are to be used for capital expenditures, working capital and general business purposes. The Partnership Credit Agreements permit 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 $150 million. At December 31, 2000, the average effective interest rate on the Partnership Credit Agreements was 8.92% 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 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 a June 1997 credit agreement. In June 1997, Northern Border Pipeline entered into a credit agreement (Pipeline Credit Agreement) with certain financial institutions to borrow up to an aggregate principal amount of $750 million. The Pipeline Credit Agreement is comprised of a $200 million five-year revolving credit facility to be used for the retirement of a previously existing bank loan agreement and for general business purposes, and a $550 million three-year revolving credit facility to be used for the construction of The Chicago Project. Effective March 1999, in accordance with the provisions of the Pipeline Credit Agreement, Northern Border Pipeline converted the three-year revolving credit facility to a term loan 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 remaining aggregate principal commitment amount of $624 million. At December 31, 2000 and 1999, Northern Border Pipeline had an outstanding interest rate swap agreement with a notional amount of $40 million, which will terminate in November 2001. Under the agreement, Northern Border Pipeline makes payments to counterparties at fixed rates and in return receives payments at variable rates based on the London Interbank Offered Rate. At December 31, 2000 and 1999, Northern Border Pipeline was in a payable position relative to its counterparties. The average effective interest rate of Northern Border Pipeline's variable rate debt, taking into consideration the interest rate swap agreement, was 7.06% and 6.73% at December 31, 2000 and 1999, respectively. Interest paid, net of amounts capitalized, during the years ended December 31, 2000, 1999 and 1998 was $84.2 million, $62.5 million and $28.7 million, respectively. Aggregate repayments of long-term debt required for the next five years are as follows: $44 million, $551 million, $96 million, and $2 million for 2001, 2002, 2003, and 2004, respectively. There are no scheduled debt maturities for 2005. 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 most restrictive of the covenants, as of December 31, 2000 and 1999, respectively, $136 million and $132 million of partners' capital of Northern Border Pipeline could be distributed. The indenture under which the Partnership Senior Notes were issued does not limit the amount of indebtedness or other obligations that the Partnership may incur, but does contain material financial covenants, including restrictions on the incurrence of secured indebtedness. The Partnership Credit Agreements, as amended, require the maintenance of a ratio of debt to total capital, excluding the nonrecourse debt of subsidiaries, of no more than 45% currently and gradually decreasing to 35% by September 30, 2001. 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 was approximately $191 million and $273 million at December 31, 2000 and 1999, respectively. The estimated fair value of the 1999 Pipeline Senior Notes was approximately $213 million and $201 million at December 31, 2000 and 1999, respectively. The estimated fair value of the Partnership Senior Notes was approximately $271 million at December 31, 2000. The estimated fair value of the Black Mesa note agreement was approximately $15 million and $18 million at December 31, 2000 and 1999, respectively. At December 31, 2000 and 1999, the estimated fair value which would be payable to terminate the interest rate swap agreement, taking into account current interest rates, was approximately $1 million. The Partnership presently intends to maintain the current schedule of maturities for the 1992 Pipeline Senior Notes, 1999 Pipeline Senior Notes, Partnership Senior Notes, the Black Mesa note agreement and the interest rate swap agreement that will result in no gains or losses on their respective repayment. The fair value of the Pipeline Credit Agreement and Partnership Credit Agreements approximates the carrying value since the interest rates are periodically adjusted to reflect current market conditions. 7. UNCONSOLIDATED AFFILIATES The Partnership's investments in unconsolidated affiliates which are accounted for by the equity method is as follows:

Net Ownership December 31, (In thousands) Interest 2000 1999 Bighorn (a) $ 83,562 $31,895 Fort Union 33% 69,872 -- Lost Creek 35% 68,191 -- $221,625(b) $31,895 (a) As discussed in Note 3, the Partnership's common membership interest in Bighorn increased from 39% at December 31, 1999 to 49% at December 31, 2000. The Partnership also held 100% of the non-voting class A shares of Bighorn at December 31, 2000. (b) At December 31, 2000 and 1999, the unamortized excess of the Partnership's investments in unconsolidated affiliates was $189.5 million and $20.0 million, respectively.

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

(In thousands) 2000(a) Bighorn $(1,394) Fort Union 285 Lost Creek 462 $ (647) (a) Initial investments in unconsolidated affiliates began in late December 1999.

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

December 31, (In thousands) 2000 1999(b) Balance sheet Current assets (a) $ 15,202 $ 1,770 Property, plant and equipment, net 160,558 32,619 Other noncurrent assets 1,329 -- Current liabilities 4,509 1,912 Long-term debt 99,364 -- Other noncurrent liabilities 4,008 -- Owners' equity 69,208 32,477 (a) Includes $434 thousand receivable from the Partnership at December 31, 2000. (b) Includes only balances from Bighorn.

(In thousands) 2000 (a) Income statement Operating revenues $8,598 Operating expenses 3,871 Net income 4,116 Distributions paid to the Partnership $ 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.

8. PARTNERS' CAPITAL At December 31, 2000, partners' capital consisted of 31,503,563 common units representing an effective 98% limited partner interest in the Partnership (including 13.5% held collectively by the General Partners or their affiliates) and a 2% general partner interest. At December 31, 1999, partners' capital consisted of 29,347,313 common units representing an effective 98% limited partner interest in the Partnership (including 14.5% held collectively by the General Partners or their affiliates) and a 2% general partner interest. Effective January 19, 1999, the Partnership converted its 6,420,000 outstanding subordinated units into an equal number of common units since the Partnership Policy Committee determined the subordination period ended as a result of satisfying the criteria set forth in the partnership agreement. In November 2000, the Partnership sold, through an underwritten public offering, 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 the Partnership Credit Agreements. In January 1998, the Partnership sold, through an underwritten public offering, 225,000 common units. The units sold in 1998 resulted from the underwriters exercise of an over-allotment option to purchase a limited number of additional common units after an offering of common units in December 1997. The net proceeds, of the public offering and the associated general partners' capital contributions, was approximately $7.6 million. 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. 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. As an incentive, the General Partners' percentage interest in quarterly distributions is increased after certain specified target levels are met (see Note 10). At the time the quarterly distributions exceed $0.605 per unit, the General Partners receive 15% of the excess. As the quarterly distributions are increased above $0.715 per unit, the General Partners receive increasing percentages in excess of the targets reaching a maximum of 50% of the excess of the highest target level. 9. 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. At December 31, 2000, the estimated aggregate amounts of such required future payments were $8.2 million annually for 2001 through 2005 and $35.7 million for later years. At December 31, 2000, the Partnership is a guarantor on a construction loan outstanding of an unconsolidated affiliate of approximately $23.1 million. The Partnership has also guaranteed the performance of an unconsolidated affiliate in connection with a credit agreement that expires in September 2009. At December 31, 2000, the guarantee was $2.9 million. Capital expenditure and investment program Total capital expenditures for 2001 are estimated to be $176 million. This includes approximately $81 million for Northern Border Pipeline's Project 2000 (see Note 4), $79 million for Crestone Energy Ventures gathering facilities and approximately $16 million for renewals and replacements of the existing facilities. Crestone Energy Ventures also estimates that it will be required to make additional investments in its unconsolidated affiliates of approximately $22 million in 2001 to support their capital expenditure projects. Funds required to meet the capital requirements for 2001 are anticipated to be provided primarily from debt borrowings and internal sources. Environmental Matters The Partnership is not aware of any material contingent liabilities with respect to compliance with applicable environmental laws and regulations. Other 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. 10. NET INCOME PER UNIT Net income per unit is computed by dividing net income, after deduction of the General Partners' allocation, by the weighted average number of units outstanding. The General Partners' allocation is equal to an amount based upon their combined 2% general partner interest, adjusted to reflect an amount equal to incentive distributions. Net income per unit was determined as follows:

(In thousands, except Year ended December 31, per unit amounts) 2000 1999 1998 Net income to partners $76,720 $81,003 $68,020 Net income allocated to General Partners (1,534) (1,620) (1,359) Adjustment to reflect incentive distributions (1,032) (90) -- (2,566) (1,710) (1,359) Net income allocable to units $74,154 $79,293 $66,661 Weighted average units outstanding 29,665 29,347 29,345 Net income per unit $ 2.50 $ 2.70 $ 2.27

11. ACCOUNTING PRONOUNCEMENTS In 1998, the Financial Accounting Standards Board (FASB) issued SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities." SFAS No. 133 establishes accounting and reporting standards requiring that every derivative instrument (including certain derivative instruments embedded in other contracts) be recorded on the balance sheet as either an asset or liability measured at its fair value. The statement requires that changes in the derivative's fair value be recognized currently in earnings unless specific hedge accounting criteria are met. Special accounting for qualifying hedges allows a derivative's gains and losses to offset related results on the hedged item in the income statement, and requires that a company formally document, designate and assess the effectiveness of transactions that receive hedge accounting. In June 1999, the FASB issued SFAS No. 137, which deferred the effective date of SFAS No. 133 to fiscal years beginning after June 15, 2000. In June 2000, the FASB issued SFAS No. 138, which amended certain guidance within SFAS No. 133. The Partnership and its subsidiaries will adopt SFAS No. 133 beginning January 1, 2001. The adoption of SFAS No. 133, as amended, will not have a material impact on the Partnership's financial position or results of operations. 12. 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; and depreciation and amortization, including goodwill amortization, which is netted against equity earnings 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.

Gas Interstate Coal Gathering (In thousands) Pipeline Slurry (a) Other(b) 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 249,553 7,364 4,007 (1,650) 259,274 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 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, net 1,363 (39) -- 3,238 4,562 EBITDA 230,682 6,565 -- 1,875 239,122 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 1998 Revenues from external customers $ 196,600 $ 20,992 $ -- $ -- $ 217,592 Depreciation and amortization 40,989 2,896 -- -- 43,885 Operating income (loss) 113,661 3,631 -- (1,489) 115,803 Interest expense, net 25,541 2,281 -- 3,100 30,922 Other income, net 12,111 640 -- 457 13,208 EBITDA 166,761 7,167 -- (1,032) 172,896 Capital expenditures 651,169 1,025 -- -- 652,194 Identifiable assets 1,790,889 34,421 -- 456 1,825,766 Total assets $1,790,889 $ 34,421 $ -- $ 456 $1,825,766 (a) Gas gathering operating results commence from the date of acquisition in September 2000 (see Note 4) except for equity earnings of Bighorn, which commenced in January 2000. (b) Includes other items not allocable to segments.

13. QUARTERLY FINANCIAL DATA (Unaudited)

(In thousands, except Operating Operating Net Income Net Income per unit amounts) Revenues, net Income to Partners per Unit 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 1999 First Quarter $78,895 $44,961 $21,631 $0.72 Second Quarter 78,012 44,255 20,561 0.69 Third Quarter 79,046 44,728 19,357 0.65 Fourth Quarter 83,010 45,774 19,454 0.65

14. SUBSEQUENT EVENTS On January 18, 2001, the Partnership declared a cash distribution of $0.70 per unit ($2.80 per unit on an annualized basis) for the quarter ended December 31, 2000. The distribution is payable February 14, 2001, to unitholders of record at January 31, 2001. 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 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 SCHEDULE II NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS FOR THE YEARS ENDED DECEMBER 31, 2000, 1999 AND 1998 (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 2000 $7,376 $1,800 $-- $7,376 $1,800 1999 $6,726 $ 650 $-- $ -- $7,376 1998 $6,726 $ -- $-- $ -- $6,726

UNITED STATES SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 _______________________ EXHIBITS TO F O R M 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, 2000 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 Identification No.) or organization) 1400 Smith Street, Houston, Texas 77002-7369 (Address of principal executive offices)(zip code) Registrant's telephone number, including area code: 713-853-6161 ___________________ EXHIBIT INDEX * 3.1 Form of Amended and Restated Agreement of Limited Partnership of Northern Border Partners, L.P. (Exhibit 3.1 No. 2 to the Partnership's Form S-1 Registration Statement, Registration No. 33-66158 ("Form S-1")). * 3.2 Form of Amended and Restated Agreement of Limited Partnership For Northern Border Intermediate Limited Partnership (Exhibit 10.1 to Form S-1). * 4.1 Indenture, dated as of June 2, 2000, between the registrants and Bank One Trust Company, N.A. (Exhibit 4.1 to the Partnership's Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2000 ("June 2000 10-Q")). * 4.2 First Supplemental Indenture, dated as of September 14, 2000, between the registrants and Bank One Trust Company, N.A.(Exhibit 4.2 to Form S-4 Registration Statement, Registration No. 333-46212 ("NBP Form S-4")). 4.3 Indenture, dated as of March 21, 2001, between Northern Border Partners, L.P. and Northern Border Intermediate Limited Partnership and Bank One Trust Company, N.A., Trustee. 4.4 Registration Rights Agreement dated March 21, 2001 by and among Northern Border Partners, L.P., Northern Border Intermediate Limited Partnership, Banc of America Securities LLC, SunTrust Equitable Securities Corporation, Banc One Capital Markets, Inc. and BMO Nesbitt Burns Corp. * 4.5 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"). *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). *10.4.1 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")). *10.5 Guaranty made by Panhandle Eastern Pipeline Company, dated October 31, 1992 (Exhibit 10.9 to Form S-1). *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). *10.6.1 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")). *10.6.2 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). *10.6.3 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). *10.6.4 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")). *10.7 Guaranty made by Northern Natural Gas Company, dated October 7, 1993 (Exhibit 10.11.1 to 1993 10-K). *10.8 Guaranty made by Northern Natural Gas Company, dated October 7, 1993 (Exhibit 10.11.2 to 1993 10-K). *10.9 Northern Border Pipeline Company U.S. Shippers Service Agreement between Northern Border Pipeline Company and Western Gas Marketing Limited, as agent for TransCanada PipeLines Limited, dated December 15, 1980 (Exhibit 10.13 to Form S-1). *10.9.1 Amendment to Northern Border Pipeline Company Service Agreement extending the term effective November 1, 1995 (Exhibit 10.13.1 to 1995 10-K). *10.10 Form of Seventh Supplement Amending Northern Border Pipeline Company General Partnership Agreement (Exhibit 10.15 to Form S-1). *10.11 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). *10.12 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")). *10.13 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). *10.14 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). *10.15 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). *10.16 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). *10.17 Northern Border Pipeline Company U.S. Shippers Service Agreement between Northern Border Pipeline Company and TransCanada Gas Services Inc., as agent for TransCanada PipeLines Limited dated August 5, 1997 (Exhibit 10.27 to 1997 10-K). *10.18 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). *10.19 Eighth Supplement Amending Northern Border Pipeline Company General Partnership Agreement (Exhibit 10.15 to NB Form S-4). 10.20 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). *10.21 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")). *10.22 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). *10.23 Northern Border Pipeline Company U.S. Shippers Service Agreement between Northern Border Pipeline Company and Pan-Alberta Gas (U.S.) Inc., dated October l, 1992, with Amended Exhibit A effective June 22, 1998 (Exhibit 10.38 to NB Pipeline 1999 10-K). 10.24 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.). 10.25 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. 10.26 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). 21 The subsidiaries of Northern Border Partners, L.P. are Northern Border Intermediate Limited Partnership; Northern Border Pipeline Company; and Crestone Energy Ventures, L.L.C. 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). *Indicates exhibits incorporated by reference as indicated; all other exhibits are filed herewith.