10-K 1 h23121e10vk.txt NORTHERN BORDER PARTNERS, L.P. UNITED STATES SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 ---------- FORM 10-K [X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended December 31, 2004 [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from _________ to _________ Commission file number: 1-12202 NORTHERN BORDER PARTNERS, L.P. (Exact name of registrant as specified in its charter) DELAWARE 93-1120873 (State or other jurisdiction of (I.R.S. Employer incorporation or organization) Identification No.) 13710 FNB PARKWAY, OMAHA, NEBRASKA 68154-5200 (Address of principal executive offices) (Zip Code) Registrant's telephone number, including area code: 402-492-7300 ---------- SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:

Title of each class Name of each exchange on which registered ------------------- ----------------------------------------- Common Units New York Stock Exchange

SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT: None Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes [X] No [ ] Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [X] Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Act). Yes [X] No [ ] Aggregate market value of the Common Units held by non-affiliates of the registrant, based on closing prices in the daily composite list for transactions on the New York Stock Exchange on June 30, 2004, was approximately $1,832,811,558. As of March 3, 2005, 46,397,214 Common Units were outstanding. DOCUMENTS INCORPORATED BY REFERENCE None. ii NORTHERN BORDER PARTNERS, L.P. TABLE OF CONTENTS

PAGE NO. -------- PART I Item 1. Business 1 Item 2. Properties 20 Item 3. Legal Proceedings 21 Item 4. Submission of Matters to a Vote of Security Holders 21 PART II Item 5. Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities 22 Item 6. Selected Financial Data 24 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations 26 Item 7A. Quantitative and Qualitative Disclosures About Market Risk 53 Item 8. Financial Statements and Supplementary Data 54 Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure 54 Item 9A. Controls and Procedures 57 Item 9B. Other Information PART III Item 10. Directors and Executive Officers of the Registrant 58 Item 11. Executive Compensation 66 Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters 73 Item 13. Certain Relationships and Related Transactions 74 Item 14. Principal Accounting Fees and Services 76 PART IV Item 15. Exhibits and Financial Statement Schedules 78

i PART I ITEM 1. BUSINESS. GENERAL We are a publicly-traded limited partnership formed in 1993 and a leading transporter of natural gas imported from Canada to the United States. Our business operations are comprised of the following segments: - Interstate Natural Gas Pipeline - Natural Gas Gathering and Processing - Coal Slurry Pipeline Our interstate natural gas pipelines segment includes companies that provide natural gas transmission services in the midwestern United States. The companies in this segment transport gas for shippers under tariffs regulated by the Federal Energy Regulatory Commission ("FERC"). The interstate pipelines' revenues are derived from agreements for the receipt and delivery of gas at points along the pipeline systems as specified in each shipper's individual transportation contract. Our gas gathering and processing segment provides services for the gathering, treating, processing and compression of natural gas and the fractionation of natural gas liquids ("NGLs") for third parties. We do not explore for, or produce, crude oil or natural gas, and do not own crude oil or natural gas reserves. We have extensive natural gas gathering, processing and fractionation operations in the Williston Basin in Montana and North Dakota as well as gas gathering operations in the Powder River Basin and Wind River Basin in Wyoming. In December 2004, we sold our interest in the Gregg/Lake Obed Pipeline in Alberta, Canada. Our coal slurry pipeline segment is comprised of our ownership of Black Mesa Pipeline, Inc. The 273-mile pipeline is the only coal slurry pipeline in operation in the United States. The coal slurry pipeline transports crushed coal suspended in water from a coal mine in Kayenta, Arizona to the Mohave Generating Station in Laughlin, Nevada. We are managed under the direction of a partnership policy committee (similar to a board of directors). The partnership policy committee consists of three members, each of whom has been appointed by one of our general partners. Our general partners and the general partners of our subsidiary limited partnership, Northern Border Intermediate Limited Partnership, are Northern Plains Natural Gas Company, LLC ("Northern Plains") and Pan Border Gas Company, LLC, ("Pan Border") both subsidiaries of ONEOK, Inc. ("ONEOK"), and Northwest Border Pipeline Company, a subsidiary of TransCanada PipeLines Limited which is a subsidiary of TransCanada Corporation, collectively referred to as "TransCanada". In November 2004, ONEOK purchased Northern Plains, Pan Border and NBP Services, LLC from CCE Holdings, LLC ("CCE Holdings"). CCE Holdings, a joint venture between Southern Union Company and GE Commercial Finance Energy Financial purchased Northern Plains, Pan Border and NBP Services, LLC as part of its acquisition of CrossCountry Energy, LLC ("CrossCountry"). See Item 7. "Management's Discussion and Analysis of Financial Condition and Results of Operations - The Impact Of Enron's Chapter 11 Filing On Our Business." 2 In this report, references to "we", "us", "our" or the "Partnership" collectively refer to Northern Border Partners, L.P. and our subsidiary, Northern Border Intermediate Limited Partnership. Our general partners hold an aggregate 2% general partner interest in the Partnership. Northern Plains also owns common units representing a 1.06% limited partner interest. See Item 12. "Security Ownership of Certain Beneficial Owners and Management." The combined general and limited partner interests in the Partnership held by ONEOK and TransCanada are 2.71% and 0.35%, respectively. NBP Services, LLC, a ONEOK subsidiary ("NBP Services"), provides administrative services for us and our subsidiaries and operating services for our natural gas gathering and processing segment. NBP Services has approximately 130 employees located in Denver, Colorado and at various locations at or near our gathering and processing facilities and also utilizes employees and information technology systems of its affiliates to provide these services. Northern Plains provides operating services to our interstate pipelines pursuant to operating agreements. Northern Plains employs approximately 310 individuals located at our headquarters in Omaha, Nebraska, and at various locations near the pipelines and also utilizes employees and information technology systems of its affiliates to provide these services. NBP Services' and Northern Plains' employees are not represented by any labor union and are not covered by any collective bargaining agreements. For financial information about each of our business segments, see Note 16 to Consolidated Financial Statements included elsewhere in this report. AVAILABLE INFORMATION We make available free of charge, through our website, www.northernborderpartners.com, (a) our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act as soon as reasonably practicable after we electronically file such material with, or furnish it to, the Securities and Exchange Commission ("SEC"), (b) our Governance Guidelines, (c) our Code of Conduct, (d) our Accounting and Financial Reporting Code of Ethics, (e) our Partnership Agreement and (f) the written charter of the Audit Committee. The Partnership's documents filed with, or furnished to, the SEC are also available at the SEC's website at www.sec.gov. Additionally, you can request a copy of these documents, excluding exhibits, at no cost, by contacting Investor Relations Department, Northern Border Partners, L.P., P.O. Box 542500, Omaha, NE 68154-8500. INTERSTATE NATURAL GAS PIPELINE SEGMENT Our interstate natural gas pipeline segment provides natural gas transmission services in the midwestern United States. Our interstate pipelines transport gas for shippers under tariffs regulated by the FERC. The tariffs specify the maximum and minimum transportation rates and the general terms and conditions of transportation service on the pipeline systems. Our interstate pipelines' revenues are derived from agreements for the receipt and delivery of gas at points along the pipeline systems as specified in each shipper's individual transportation contract. Generally, firm shippers are obligated to pay a monthly demand charge, regardless of the amount of natural gas they actually transport, for the term of their contracts. For our wholly-owned interstate pipelines, approximately 98% of the revenue generated is attributed to demand charges. The remaining 2% is attributed to commodity charges based on the volumes of gas actually transported. Our 3 interstate pipelines do not own the gas that they transport for others and therefore do not assume natural gas commodity price risk for quantities transported. Any exposure to commodity risk for imbalances on the pipeline systems that may result from under or over deliveries to customers or interconnecting pipelines is either recovered through provisions in the tariffs or is immaterial. Our interstate pipelines own the line pack, which is the amount of gas necessary to maintain efficient operations of the pipeline. Shippers on each system are responsible to provide fuel gas necessary for the operation of the gas compressor stations on the pipelines. For Northern Border Pipeline Company and Viking Gas Transmission Company, the fuel gas collected from shippers is adjusted periodically to track the gas consumed. On Midwestern Gas Transmission Company, a fixed amount of fuel gas is collected. As a result, if the amount provided by shippers does not equal the amount consumed in its operations, Midwestern Gas Transmission is required to buy or sell natural gas. For 2004, Northern Border Pipeline Company, Midwestern Gas Transmission Company and Viking Gas Transmission Company accounted for 86%, 6% and 8%, respectively of the revenues in the interstate pipeline segment. Also reported in this segment is Guardian Pipeline, L.L.C. ("Guardian Pipeline") for which we own a one-third interest. NORTHERN BORDER PIPELINE SYSTEM We own a 70% general partnership interest in Northern Border Pipeline Company, a Texas general partnership ("Northern Border Pipeline"). Northern Border Pipeline owns a 1,249-mile interstate pipeline system that transports natural gas from the Montana-Saskatchewan border near Port of Morgan, Montana to natural gas markets in the midwestern United States. Construction of the pipeline was initially completed in 1982. The pipeline system was expanded and/or extended in 1991, 1992, 1998 and 2001. This pipeline system connects directly and through multiple pipelines to various natural gas markets in the United States. For the year ended December 31, 2004, we estimate that Northern Border Pipeline transported approximately 22% of the total amount of natural gas imported from Canada to the United States. Over the same period, approximately 88% of the natural gas transported by Northern Border Pipeline was produced in the western Canadian sedimentary basin located in the provinces of Alberta, British Columbia and Saskatchewan. Our interest in Northern Border Pipeline represents the largest proportion of our assets, earnings and cash flows. The remaining 30% general partner interest in Northern Border Pipeline is owned by TC PipeLines Intermediate Limited Partnership, a subsidiary limited partnership of TC PipeLines, LP, a publicly-traded partnership ("TC PipeLines"). The general partner of TC PipeLines and its subsidiary limited partnership is TC PipeLines GP, Inc., which is a subsidiary of TransCanada. Management of Northern Border Pipeline is overseen by the Northern Border Management Committee, which is comprised of three representatives from the Partnership (one designated by each of our general partners) and one representative from TC PipeLines. Voting power on the management committee is allocated among Northern Border Partners' three representatives in proportion to their general partner interests in Northern Border Partners. As a result, the 70% voting power of our three representatives on the management committee is allocated as follows: 35% to the representative designated by Northern Plains, 22.75% to the representative designated by Pan Border and 12.25% to the representative designated by Northwest Border. Therefore, ONEOK controls 57.75% of the voting power of the management committee and has the right to select two of its members. For a discussion of specific relationships with affiliates, refer to Item 13. "Certain Relationships and Related Transactions." 4 The Northern Border Pipeline system consists of: (i) 822 miles of 42-inch diameter pipe from the Canadian border to Ventura, Iowa, capable of transporting on a summer design basis a total of 2,374 million cubic feet per day ("mmcfd"); (ii) 30-inch diameter pipe and 36-inch diameter pipe, each approximately 147 miles in length, capable of transporting 1,484 mmcfd in total from Ventura, Iowa to Harper, Iowa; (iii) 224 miles of 36-inch diameter pipe and 21 miles of 30-inch diameter pipe capable of transporting 844 mmcfd from Harper, Iowa to Manhattan, Illinois (Chicago area); and (iv) 35 miles of 30-inch diameter pipe capable of transporting 544 mmcfd from Manhattan, Illinois to a terminus near North Hayden, Indiana. A summer design basis pipeline is capable of transporting, at a minimum, the stated capacity at all times of the year. Along the pipeline there are 16 compressor stations with total rated horsepower of 499,000 and measurement facilities to support the receipt and delivery of gas at various points. Other facilities include four field offices and a microwave communication system with 50 tower sites. The pipeline system has pipeline access to natural gas reserves in the western Canadian sedimentary basin in the provinces of Alberta, British Columbia and Saskatchewan in Canada, domestic natural gas produced within the Williston Basin and the Powder River Basin, and synthetic gas produced at the Dakota Gasification plant in North Dakota. In addition, the pipeline is capable of physically receiving natural gas at two locations near Chicago. For the year ended December 31, 2004, of the natural gas transported on the pipeline system, approximately 88% was produced in Canada, approximately 4% was produced by the Dakota Gasification plant, and approximately 8% was produced in the Williston Basin. To access markets, the pipeline system interconnects with pipeline facilities of various interstate and intrastate pipeline companies and local distribution companies, as well as with end-users. The larger interconnections are: - Northern Natural Gas Company at Ventura, Iowa as well as multiple smaller interconnections in South Dakota, Minnesota and Iowa; - Natural Gas Pipeline Company of America at Harper, Iowa; - MidAmerican Energy Company at Iowa City and Davenport, Iowa and Cordova, Illinois; - Alliant Power Company at Prophetstown, Illinois; - Northern Illinois Gas Company at Troy Grove and Minooka, Illinois; - Midwestern Gas Transmission near Channahon, Illinois; - ANR Pipeline Company near Manhattan, Illinois; - Vector Pipeline L.P. in Will County, Illinois; - Guardian Pipeline in Will County, Illinois; - The Peoples Gas Light and Coke Company near Manhattan, Illinois; and - Northern Indiana Public Service Company near North Hayden, Indiana at the terminus of the pipeline system. 5 Several market centers, where natural gas transported on the pipeline system is sold, traded and received for transport to consuming markets in the Midwest and to interconnecting pipeline facilities, have developed on the pipeline system. The largest of these market centers is at Northern Border Pipeline's Ventura, Iowa interconnection with Northern Natural Gas Company. Two other market center locations are the Harper, Iowa connection with Natural Gas Pipeline Company of America and the multiple interconnects in the Chicago area that include connections with Northern Illinois Gas Company, The Peoples Gas Light and Coke Company and Northern Indiana Public Service Company, as well as four interstate pipelines. All of Northern Border Pipeline's summer design capacity was under contract as of December 31, 2004 and, assuming no extensions of existing contracts or execution of new contracts, approximately 61% and 51% of summer design capacity is under contract as of December 31, 2005 and 2006, respectively. The pipeline system serves approximately 40 firm transportation shippers with diverse operating and financial profiles. Based upon shippers' contractual obligations, as of December 31, 2004, 92% of firm capacity contracted is with producers and marketers. The remaining firm capacity contracted primarily is with local distribution companies (7%) and end-users (1%). As of December 31, 2004, the termination dates of these contracts ranged from December 31, 2004 to December 21, 2013, and the weighted average contract life was approximately two and three-quarters years based upon contractual obligations and summer design capacity. See Item 7. "Management's Discussion and Analysis of Financial Condition and Results of Operations - Overview - Interstate Natural Gas Pipeline Segment - Northern Border Pipeline Recontracting" for information regarding Northern Border Pipeline's recontracting. Northern Border Pipeline's shippers may change throughout the year as a result of its shippers utilizing capacity release provisions that allow them to release all or part of their capacity, either permanently for the full term of their contract or temporarily. Under the terms of Northern Border Pipeline's tariff, a temporary capacity release does not relieve the originally contracted shipper from its payment obligations if the new shipper fails to pay. At December 31, 2004, Nexen Marketing U.S.A. Inc., BP Canada Energy Marketing Corp. ("BP Canada"), EnCana Marketing U.S.A. Inc. and Cargill Incorporated were obligated for approximately 18%, 14%, 13% and 12%, respectively, of the summer design capacity. Contracts for approximately 63% of the capacity contracted by these shippers are due to expire by November 1, 2005. See Item 7. "Management's Discussion and Analysis of Financial Condition and Results of Operations - Overview." One of Northern Border Pipeline's shippers, ONEOK Energy Services Company, LP,("ONEOK Energy") a subsidiary of ONEOK, is affiliated with us. ONEOK Energy holds firm contracts representing 3% of summer design capacity. ONEOK Energy has also committed to be a shipper on the Chicago III Expansion project. See Item 13. "Certain Relationships and Related Transactions." MIDWESTERN GAS TRANSMISSION SYSTEM Midwestern Gas Transmission Company, our wholly-owned subsidiary ("Midwestern Gas Transmission"), owns a 350-mile pipeline system extending from an interconnection with Tennessee Gas Transmission near Portland, Tennessee to a point of interconnection with several interstate pipeline systems near Joliet, Illinois. Midwestern Gas Transmission serves markets in Chicago, Illinois, Kentucky, southern Illinois and Indiana. 6 The Midwestern Gas Transmission system consists of 350 miles of 30-inch and 24-inch diameter pipe with a capacity of 650 mmcfd for volumes transported from Portland, Tennessee to the north. There are seven compressor stations with total rated horsepower of 65,570. The Midwestern Gas Transmission system is also capable of moving approximately 387 mmcfd southbound depending upon receipt and delivery point locations. The Midwestern Gas Transmission system connects with multiple pipeline systems that provide its shippers access to various supply sources and markets. Because of its position in the natural gas pipeline grid, Midwestern Gas Transmission is designed to receive gas volumes at both ends of its system. On the north end, Midwestern Gas Transmission can physically receive gas from ANR Pipeline Company, Northern Border Pipeline, Natural Gas Pipeline Company of America, Alliance Pipeline, The Peoples Gas Light and Coke Company and Trunkline Gas Company. The significant receipt point on the southern end of the system is the interconnection with Tennessee Gas Transmission at Portland. Additionally, Midwestern Gas Transmission is capable of receiving gas at five other interconnections along its pipeline system. With respect to market access, Midwestern Gas Transmission is capable of delivering natural gas at points of interconnection with the interstate pipeline systems of ANR Pipeline Company, Guardian Pipeline, Natural Gas Pipeline Company of America, Northern Border Pipeline, Texas Eastern Transmission Company and Texas Gas Transmission Company. There are interconnections with local distribution companies such as Northern Illinois Gas Company, The Peoples Gas Light and Coke Company, Illinois Power, and Vectren Energy Delivery. In addition, a number of end-users and electric power generation facilities can be served by connections off the pipeline system. The Midwestern Gas Transmission system serves approximately 25 firm transportation shippers. Based upon shipper firm contractual obligations as of December 31, 2004, approximately 68% of the contracted capacity is with local distribution companies, 30% with marketers and 2% with end-users. As of December 31, 2004, Midwestern Gas Transmission's three largest shippers were Northern Illinois Gas Company, ProLiance Energy LLC and The Peoples Gas Light and Coke Company who were obligated for approximately 32%, 16% and 14%, respectively, of the system design capacity. As of December 31, 2004, the termination dates of Midwestern Gas Transmission's firm transportation contracts ranged from December 31, 2004 to October 31, 2019. On December 31, 2004, approximately 91% of the northbound system design capacity and approximately 90% of southbound system design capacity was contracted on a firm basis and assuming no extensions of existing contracts or executions of new contracts approximately 75% and 20% of northbound design capacity and 48% and 11% of southbound design capacity is under contract as of December 31, 2005 and 2006, respectively. See Item 7. "Management's Discussion and Analysis of Financial Condition and Results of Operations - Overview." VIKING GAS TRANSMISSION SYSTEM Our wholly-owned subsidiary, Viking Gas Transmission Company ("Viking Gas Transmission"), owns a pipeline system that extends from an interconnection with TransCanada near Emerson, Manitoba to an interconnection with ANR Pipeline Company near Marshfield, Wisconsin. Viking Gas Transmission's source of gas supply is the western Canadian sedimentary basin. Viking Gas Transmission also has interconnections with Northern Natural Gas Company and Great Lakes Gas Transmission to serve markets in Minnesota, Wisconsin and North Dakota. 7 The Viking Gas Transmission system consists of: (i) 499 miles of 24-inch diameter mainline pipe with a summer design capacity of approximately 500 mmcfd at the origin near Emerson, Manitoba and 300 mmcfd at the terminus near Marshfield, Wisconsin, (ii) 95 miles of 24-inch mainline looping; and (iii) 79 miles of smaller diameter laterals. There are eight compressor stations with total horsepower of 68,650. The Viking Gas Transmission system serves approximately 35 firm transportation shippers. Based upon shipper contractual obligations as of December 31, 2004, approximately 80% of the contracted firm capacity is with local distribution companies, 15% with marketers and 5% with end-users. As of December 31, 2004, Viking Gas Transmission's largest customers were Wisconsin Gas, LLC, CenterPoint Energy Minnegasco, Northern States Power Company-Minnesota, Michigan Consolidated Gas Company and Wisconsin Public Service Corporation, who were obligated for approximately 19%, 15%, 15%, 10% and 10%, respectively, of the summer design capacity. As of December 31, 2004, the termination dates of Viking Gas Transmission's firm transportation contracts ranged from March 31, 2005 to October 31, 2014. On December 31, 2004, all of the summer design capacity at the origin of the pipeline near Emerson was contracted on a firm basis and assuming no extensions of existing contracts or execution of new contracts, approximately 85% and 83% of summer design capacity is under contract as of December 31, 2005 and 2006, respectively. GUARDIAN PIPELINE SYSTEM Viking Gas Transmission owns a 33-1/3% interest in Guardian Pipeline, which is a 141-mile interstate natural gas pipeline that was placed into service in December 2002. This system transports natural gas from Joliet, Illinois to a point west of Milwaukee, Wisconsin. Subsidiaries of Wisconsin Public Service and Wisconsin Energy Corporation hold the remaining interests in this system. Wisconsin Gas Company, a subsidiary of Wisconsin Energy Corporation, has contracted for 87% of the pipeline's 750 mmcfd capacity. Guardian Pipeline is currently operated by Northern Plains under an operating agreement that was effective July 1, 2004. Prior to that date, Trunkline Gas Company, which is part of Southern Union Company, was the operator. See Item 13. "Certain Relationships and Related Transactions." DEMAND FOR INTERSTATE PIPELINE TRANSPORTATION CAPACITY Recent developments have resulted in proposed expansions of our pipeline systems. In September 2004, Northern Border Pipeline announced it had received commitments from shippers sufficient to support a proposed expansion of the pipeline system into the Chicago market area. The "Chicago III Expansion" project, with an estimated 130 mmcfd of capacity, would involve construction of a new compressor station and minor modifications to two other compressor stations, and is estimated to cost approximately $21 million. The projected in-service date is April 1, 2006. FERC approval of this project is required and Northern Border Pipeline expects to file the required certificate application in March 2005. Also, in August 2004, we announced that Midwestern Gas Transmission had finalized the necessary contractual commitment to proceed with its Eastern Extension Project. This project involves the construction of approximately 30 miles of 16-inch diameter pipeline, with a capacity of approximately 120 mmcfd, from Portland, Tennessee to planned interconnections with Columbia Gulf Transmission Company and East Tennessee Pipeline Company. The project is supported by a 8 precedent agreement with Piedmont Natural Gas Company, a local distribution company, for approximately 120 mmcfd for a term of 15 years. Pending the receipt of regulatory and other required approvals, the proposed in-service date for the project is November 2006 and project costs are estimated at approximately $22 million to $25 million. The long-term financial condition of our interstate natural gas pipeline segment is dependent on the continued availability of economic natural gas supplies, including western Canadian natural gas for import into the United States. Natural gas reserves may require significant capital expenditures by others for exploration and development drilling and the installation of production, gathering, storage, transportation and other facilities that permit natural gas to be produced and delivered to pipelines that interconnect with our interstate pipelines' systems. Prices for natural gas, the currency exchange rate between Canada and the United States, regulatory limitations or the lack of available capital for these projects could adversely affect the development of additional reserves and production, gathering, storage and pipeline transmission of natural gas supplies. Increased Canadian consumption related to the extraction process for oil sands projects as well as restrictions on gas production to protect oil sand reserves could also impact supplies of natural gas for export. Additional pipeline capacity from producing basins also could accelerate depletion of these reserves. Excess pipeline capacity could also affect the demand or value of the transport on our interstate pipelines. Each of our interstate pipelines' business also depends on the level of demand for natural gas in the markets the pipeline system serves. The volumes of natural gas delivered to these markets from other sources affect the demand for both the natural gas supplies and the use of the pipeline systems. Demand for natural gas to serve other markets also influences the ability and willingness of shippers to use our pipeline systems to meet demand in the markets that our interstate pipelines serve. A variety of factors could affect the demand for natural gas in the markets that our pipeline systems serve. These factors include: - economic conditions; - fuel conservation measures; - alternative energy sources' requirements and prices; - gas storage inventory levels; - climatic conditions; - government regulation; and - technological advances in fuel economy and energy generation devices. Our interstate pipelines' primary exposure to market risk occurs at the time existing transportation contracts expire and are subject to renegotiation. A key determinant of capacity value for shippers that have competitive pipeline alternatives is the basis differential or market price spread between two points on the pipeline. The difference in natural gas prices between the points along the pipeline where gas enters and where gas is delivered represents the gross margin that a shipper can expect to achieve from holding transportation capacity at any 9 point in time. This margin and its variability become important factors in determining the rate customers are willing to pay when they renegotiate their transportation contracts. The basis differential between markets can be affected by trends in production, available pipeline capacity, storage inventories, weather and general market demand in the respective areas. Throughput on our interstate pipelines may experience seasonal fluctuations depending upon the level of winter heating load demand, summer electric generation usage in the markets served by the pipeline systems and/or storage injection load. To the extent that capacity is contracted at maximum rates under firm transportation agreements, 98% of the expected charges are from demand charges that are not impacted materially by such seasonal throughput variations. However, as contracts terminate, renewals and replacements may be affected by seasonal fluctuations and historic usage patterns. See Item 7. "Management's Discussion and Analysis of Financial Condition and Results of Operations - Overview." We cannot predict whether these or other factors will have an adverse affect on demand for use of our interstate pipelines' systems or how significant that adverse affect could be. INTERSTATE PIPELINE COMPETITION Northern Border Pipeline and Viking Gas Transmission compete with other pipeline companies that transport natural gas from the western Canadian sedimentary basin or that transport natural gas to end-use markets in the midwestern United States. Their competitive positions are affected by the availability of Canadian natural gas for export, the availability of other sources of natural gas and demand for natural gas in the United States. Demand for transportation services on the systems is affected by natural gas prices, the relationship between export capacity and production in the western Canadian sedimentary basin, and natural gas shipped from producing areas in the United States. Shippers of natural gas produced in the western Canadian sedimentary basin also have other options to transport Canadian natural gas to the United States, including transportation on the Alliance Pipeline to the Chicago market area, on TransCanada's pipeline system through various interconnections with U.S. interstate pipelines in the upper Midwest and northeast markets and on the Westcoast Pipeline and TransCanada B.C. systems and through various interconnections with U.S. interstate pipelines serving northwest and west coast markets. In the near term, Northern Border Pipeline's short-term contracted capacity competes primarily with available and short-term capacity on the TransCanada and Westcoast pipelines. Alliance Pipeline is not a competitor in the short-term for Northern Border Pipeline, since substantially all of its capacity is contracted under long-term contracts. In addition, Northern Border Pipeline competes in its markets with other interstate pipelines that provide access to other supply basins. Northern Border Pipeline's major deliveries into Northern Natural Gas at Ventura, Iowa compete with gas supplied from the Rockies and mid-continent regions. Northern Border Pipeline also competes with these supply basins at its delivery interconnect with Natural Gas Pipeline of America at Harper, Iowa. In the Chicago area, Northern Border Pipeline competes with many interstate pipelines that transport gas from the Gulf Coast, mid-continent, Rockies and western Canada. In December 2004, the Cheyenne Plains Pipeline system commenced service from the Cheyenne Hub in the Rocky Mountain area to the mid-continent area. The pipeline will provide additional supply and transportation competition in markets served by Northern Border Pipeline. The supply balance in the mid-continent area can impact the value of gas that is traded at Ventura, Iowa and Harper, Iowa delivery points and gas traded in 10 the Chicago area. A change in trading value at these market centers will affect the corresponding transportation value of that portion of Northern Border Pipeline's system upstream and downstream of these trading centers. Midwestern Gas Transmission can receive and deliver gas at either end of its system, which makes it a header pipeline system. Consequently, Midwestern Gas Transmission faces competition from multiple supply sources and interstate pipelines. In the Chicago market, Midwestern Gas Transmission's competition is from pipelines transporting gas from the gulf coast and mid-continent regions and gas sourced from Canada. In the Indiana and Western Kentucky markets, Midwestern Gas Transmission's competition is from pipelines transporting gas from the gulf coast and mid-continent regions. Viking Gas Transmission directly serves markets in North Dakota, Minnesota and Wisconsin. Northern Natural Gas competes with Viking Gas Transmission in these states. In addition, Viking Gas Transmission indirectly serves Wisconsin and Michigan markets through deliveries into ANR Pipeline. The deliveries into ANR Pipeline compete with other supply sources on ANR Pipeline, which includes supply from the gulf coast and mid-continent regions and the Chicago market center. In October 2004, FERC approved ANR Pipeline Company's application to expand its capacity in the north leg of its pipeline system by approximately 107 mmcfd per day to replace receipts from Viking Gas Transmission at the Marshfield, Wisconsin interconnection by November 2005. See Item 7. "Management's Discussion and Analysis of Financial Condition and Results of Operations - Overview." INTERSTATE PIPELINE REGULATION Our interstate pipelines are subject to extensive regulation by the FERC, each as a "natural gas company" under the Natural Gas Act. Under the Natural Gas Act and the Natural Gas Policy Act, the FERC has jurisdiction with respect to virtually all aspects of this business segment, including: - transportation of natural gas; - rates and charges; - terms of service including creditworthiness requirements; - construction of new facilities; - extension or abandonment of service and facilities; - accounts and records; - depreciation and amortization policies; - the acquisition and disposition of facilities; and - the initiation and discontinuation of services. Where required, our interstate pipelines hold certificates of public convenience and necessity issued by the FERC covering the facilities, activities and services. Under Section 8 of the Natural Gas Act, the FERC has the power to prescribe the accounting treatment for items for regulatory purposes. Our interstate pipelines' books and records may be periodically audited by the FERC under Section 8. 11 The FERC regulates the rates and charges for transportation in interstate commerce. Natural gas companies may not charge rates that have been determined not to be just and reasonable by the FERC. Generally, rates for interstate pipelines are based on the cost of service including recovery of and a return on the pipeline's actual prudent historical cost investment. In addition, the FERC prohibits natural gas companies from unduly preferring or unreasonably discriminating against any person with respect to pipeline rates or terms and conditions of service. Some types of rates may be discounted without further FERC authorization and rates may be negotiated subject to FERC approval. The rates and terms and conditions for service are found in each pipeline's FERC approved tariff. Under its tariff, an interstate pipeline is allowed to charge for its services on the basis of stated transportation rates. Transportation rates are established in FERC proceedings known as rate cases. The tariff also allows the interstate pipeline to provide services under negotiated and discounted rates. Generally, firm shippers are obligated to pay a monthly demand charge, regardless of the amount of natural gas they actually transport, for the term of their contracts. For our wholly-owned interstate pipelines, approximately 98% of the revenue generated for a contract is attributed to demand charges. The remaining 2% is attributed to commodity charges based on the volumes of gas actually transported. Our interstate pipelines also provide interruptible transportation service. Interruptible transportation service is transportation in circumstances when capacity is available after satisfying firm service requests. The maximum rate that may be charged to interruptible shippers is the sum of the firm transportation maximum demand and commodity charges. Under the terms of settlement in Northern Border Pipeline's 1999 rate case, neither Northern Border Pipeline nor its existing shippers can seek rate changes to the settlement base rates until November 1, 2005, at which time Northern Border Pipeline must file a new rate case. Midwestern Gas Transmission and Viking Gas Transmission have no timing requirements or restriction in regard to future rate case filings. Under the terms of Guardian Pipeline's certificate of public convenience and necessity allowing for the construction of the Guardian pipeline system, Guardian Pipeline must file a revenue and cost study by December 7, 2005 to re-establish the recourse rates initially approved by the FERC. Prior to a future rate case, the interstate pipelines will not be permitted to increase rates if costs increase or if contract demand decreases, nor will they be required to reduce rates based on cost savings. As a result, the interstate pipelines' earnings and cash flow will depend on costs incurred, contracted capacity, the volumes of gas transported and their ability to recontract capacity at acceptable rates. Until new depreciation rates are approved by the FERC, the interstate pipeline continues to depreciate its transmission plant at FERC approved depreciation rates. For our pipelines, the annual depreciation rates on transmission plant in service are 2.25% for Northern Border Pipeline, 1.9% for Midwestern Gas Transmission, 2.0% for Viking Gas Transmission and 3.3% for Guardian Pipeline. The effects of accumulated depreciation may be offset by acquiring or constructing assets that replace or add to existing pipeline facilities or transportation rates may be decreased. In Northern Border Pipeline's 1995 rate case, the FERC addressed the issue of whether the federal income tax allowance included in Northern Border Pipeline's proposed cost of service was reasonable in light of previous FERC rulings. In those previous rulings, the FERC held that an interstate pipeline is not entitled 12 to an income tax allowance for income attributable to limited partnership interests held by individuals. The settlement of Northern Border Pipeline's 1995 rate case provided that Northern Border Pipeline could continue to calculate the allowance for income taxes in the manner it had historically used for a period which ends in December 2005. In addition, a settlement adjustment mechanism was implemented, which effectively reduces the return on rate base. These provisions of the 1995 rate case were maintained in the settlement of Northern Border Pipeline's 1999 rate case. On July 20, 2004, the D.C. Circuit Court of Appeals issued an opinion in BP West Coast Products, LLC v. FERC ("SFPP, L.P. Proceeding") that reversed the FERC decision that provided for an income tax allowance in the rates for SFPP, LP, a limited partnership. The D.C. Circuit Court remanded the case to the FERC for its determination regarding the proper income tax allowance. On December 2, 2004, the FERC initiated an inquiry open to all interested parties on whether the court's ruling applies only to the specific facts of the SFPP, L.P. Proceeding or if it extends to other capital structures involving partnerships and other forms of ownership. The inquiry did not propose a particular rule. The FERC inquired how the decision in the SFPP, L.P. Proceeding may impact investment in energy infrastructure and if there are other methods in providing an opportunity to earn an adequate return that are not dependent on the tax implications of a particular capital structure. Approximately 50 separate comments were filed by trade associations, investor groups, producers, natural gas pipelines, electric utilities, oil pipelines, and customers in January 2005. A number of comments, including Northern Border Pipeline's, suggested that an income tax allowance is a proper element of a pipeline's cost of service for all jurisdictional entities regardless of legal structure. Some producers' and customers' comments argued against the inclusion of an income tax allowance for partnerships and other non-tax paying entities. It is not certain how, or when, the FERC may proceed with respect to its Request for Comments or the affect on our interstate natural gas pipelines, which are not corporations. In particular, Northern Border Pipeline is a general partnership whose rates include an allowance for income taxes. Northern Border Pipeline's specific circumstances regarding its tariff, deferred income tax treatment, FERC orders, past history and underlying agreements with shippers are different from those of SFPP, L.P. The issue of whether the inclusion of an income tax allowance in Northern Border Pipeline's rates is applicable, in light of the FERC and court rulings, may be addressed in Northern Border Pipeline's 2005 rate case. Our interstate pipelines are subject to the requirements of FERC Order Nos. 497 and 566, which prohibit preferential treatment of transportation service providers' marketing affiliates and govern how information may be provided to those marketing affiliates. On November 25, 2003, the FERC issued a final rule, Order No. 2004, adopting new standards of conduct for transmission providers when dealing with their energy affiliates. Additional orders modifying Order No. 2004 were issued on April 16, August 2 and December 21, 2004. Transmission providers were required to comply with the standards of conduct by September 22, 2004. The standards of conduct are designed to prevent transmission providers from giving undue preferences to any of their energy affiliates. The final rule generally requires that transmission function employees operate independently of the marketing function employees and energy affiliates. As required of all transmission providers, each of our interstate pipelines posted its standards of conduct to its website on September 22, 2004. By definition, Bear Paw Energy, LLC and ONEOK Energy Services Company, L.P, as well as other subsidiaries of ONEOK, are energy affiliates. Prior to September 22, 2004, the operator of our interstate pipelines, Northern Plains, provided after hours and weekend gas control services 13 for Bear Paw Energy, LLC and Crestone Energy Ventures that resulted in some cost savings to our interstate pipelines. Our interstate pipelines have requested a waiver, which is still pending at the FERC, to permit Northern Plains to resume after hours and weekend gas control services for Bear Paw Energy, LLC and Crestone Energy Ventures. On July 17, 2002, the FERC issued a Notice of Inquiry Concerning Natural Gas Pipeline Negotiated Rate Policies and Practices. Subsequently, the FERC issued an order on July 25, 2003, modifying its prior policy on negotiated rates. The FERC ruled that it would no longer permit the pricing of negotiated rates based upon natural gas commodity price indices. Negotiated rates based upon such indices may continue until the end of the contract period for which such rates were negotiated, but such rates will not be prospectively approved by the FERC. The FERC also imposed certain requirements on other types of negotiated rate transactions to ensure that the agreements embodying such transactions do not materially differ from the terms and conditions set forth in the tariff of the pipeline entering into the transaction. This FERC ruling is not expected to have a material effect on our businesses. Recent FERC orders in proceedings involving other natural gas pipelines have addressed certain aspects of a pipeline's creditworthiness provisions set forth in its tariff. In addition, industry groups, such as the North American Energy Standards Board ("NAESB"), have issued creditworthiness standards. On February 12, 2004, the FERC issued a Notice of Proposed Rulemaking to require interstate pipelines to follow standardized procedures for determining the creditworthiness of their shippers. The proposed rule would incorporate by reference ten consensus standards passed within NAESB and would adopt additional standards requiring, among other things, standardization of information shippers provide to establish credit, collateral requirements for service, procedures for suspension and termination for non-creditworthy shippers and procedures governing capacity release transactions. The enactment of some of these standards may have the effect of easing certain creditworthiness requirements and parameters currently reflected in our tariffs on existing transportation capacity. However, recent FERC orders, and this proposed rule, continue to allow more stringent collateral requirements for the construction of new facilities by a pipeline. However, we cannot predict the ultimate impact, if any, on our interstate pipelines of any resulting final rule. In February 2004, the FERC adopted new quarterly financial reporting requirements and accelerated the filing date for the interstate pipeline's annual financial report. The quarterly reports include a basic set of financial statements and other selected data and are submitted electronically. There is no impact for complying with these requirements other than the time and additional expense for preparation of these reports. In November 2004, the FERC issued a Notice of Proposed Accounting Release ("PAR") to provide guidance on the accounting for costs of pipeline assessment programs required under the Pipeline Safety Improvement Act of 2002 and regulations established thereunder. The PAR concluded that such costs should be treated as maintenance costs. Comments have been filed by the Interstate Natural Gas Association of America as well as individual pipelines setting forth the arguments that these costs should be capitalized. In November 2004, the FERC issued a Notice of Inquiry on selective discounting particularly as it relates to allowing discount adjustments for contracts resulting from competition between interstate pipelines referred to as gas-on-gas competition. The FERC noted that in several proceedings, parties have objected to the FERC's current discounting policy, allowing selective discounting 14 for gas-on-gas competition, on the grounds that it no longer benefits captive customers by allowing fixed costs to be spread over more units of service. These parties have argued that while benefits may still exist to the extent a discount is given to a customer who would otherwise use an alternative fuel and not ship gas at all, benefits do not exist in situations where discounts are given to meet competition from other gas pipelines. Although the FERC has not disallowed discount adjustments for gas-on-gas competition, the Notice of Inquiry seeks comments and responses to a series of questions that will allow the FERC to explore the potential impact of eliminating the discount adjustment for gas-on-gas competition and how the FERC should implement and monitor such a policy. In August 2003, Northern Border Pipeline filed revised tariff sheets to clarify its procedures for the awarding of capacity. Several parties protested the filing. One party requested a show cause proceeding to examine past tariff practices alleging that Northern Border Pipeline violated its tariff by denying a request for service that would have involved transportation for a distance shorter than the available distance for less than a one-year term. Northern Border Pipeline's position is that selling capacity for shorter distances or on a shorter term basis may cause portions of its system to be "stranded" or not subject to firm transportation contracts on a consistent basis or may effectively constitute a discounted rate service. On September 10, 2003, the FERC rejected Northern Border Pipeline's tariff sheets based on the conclusion that certain aspects of the proposal were not in accordance with the FERC's policy. The FERC affirmed that, up to ninety days prior to the effective date, Northern Border Pipeline had the right not to sell capacity requested for shorter distances or on a short-term basis to shippers offering the maximum mileage-based transportation rate. Northern Border Pipeline filed a timely request for rehearing of the FERC's Order in October 2003, which is still pending. Northern Border Pipeline also filed responses to requests for further information on the award of capacity in the summer of 2003. Northern Border Pipeline filed its compliance tariff sheets in early December 2003 and is awaiting the FERC's decision on these tariff sheets. An order was issued on April 15, 2004, in which the FERC requested comments from interested parties on whether the FERC's current policy on awarding available capacity to a short-haul shipper appropriately balances the risks to the pipeline, prospective shippers and current shippers on the pipeline. Comments from Northern Border Pipeline and other interested parties were filed on June 15, 2004. The timing of the issuance of the FERC's order in this proceeding is not known. NATURAL GAS GATHERING AND PROCESSING SEGMENT Our gas gathering and processing segment provides services for the measurement, gathering, treating, compression and processing of natural gas and the fractionation of natural gas liquids (NGLs) for third parties and related field services. We do not explore for, or produce, crude oil or natural gas, and do not own crude oil or natural gas reserves. Bear Paw Energy, LLC ("Bear Paw Energy"), our wholly-owned subsidiary, has extensive natural gas gathering, processing and fractionation operations in the Williston Basin in Montana and North Dakota as well as gas gathering operations in the Powder River Basin in Wyoming. In the Williston Basin, Bear Paw Energy has over 3,000 miles of gathering pipelines and five processing plants with 93 mmcfd of capacity. In the Powder River Basin, Bear Paw Energy has approximately 600 miles of high and low pressure gathering pipelines, approximately 65 compressor stations with approximately 140,000 installed horsepower and long-term volumetric contracts with producers covering approximately 390,000 acres of dedicated reserves in the 15 Powder River Basin. Bear Paw Energy's revenues are primarily derived under fee-based gathering and percentage of proceeds agreements. In addition, through our wholly-owned subsidiary, Crestone Energy Ventures, we own a 49% interest in Bighorn Gas Gathering, L.L.C. ("Bighorn"), a 33.33% interest in Fort Union Gas Gathering, L.L.C. ("Fort Union") and a 35% interest in Lost Creek Gathering, L.L.C. ("Lost Creek"), which collectively own over 300 miles of gas gathering facilities in the Powder River and Wind River Basins in Wyoming. The Bighorn and Fort Union systems gather coalbed methane gas produced in the Powder River Basin in northeastern Wyoming. Under various agreements, the majority of which are long-term, producers have dedicated their gas reserves to Bighorn, giving Bighorn the right to gather natural gas produced in areas of Wyoming covering approximately 800,000 acres. Bighorn's system is capable of gathering more than 250 mmcfd of natural gas for delivery to the Fort Union gathering system. Fort Union has the capability of delivering more than 634 mmcfd of gas into the interstate pipeline grid. The Lost Creek system gathers natural gas produced from conventional gas wells in the Wind River Basin in central Wyoming and consists of 120 miles of gathering header. The system is capable of delivering more than 275 mmcfd of gas into the interstate pipeline grid. Cantera Natural Gas, LLC (formerly CMS Field Services, Inc.)("Cantera Natural Gas") holds the remaining ownership interest in Bighorn and is the project manager and operator. The Bighorn system is managed through a management committee consisting of representatives of the owners. Cantera Natural Gas, CIG Resources Company, Western Gas Resources and Bargath, Inc. hold the remaining interests in Fort Union. Cantera Natural Gas is the managing member, Western Gas Resources is the field operator and CIG Resources Company is the administrative manager. Burlington Resources Trading, Inc. holds the remaining interest in Lost Creek and is the managing member. A subsidiary of Crestone Energy Ventures is the commercial and administrative manager. This system is operated by Elkhorn Field Services Company, an unaffiliated third party. Bear Paw Energy's facilities in the Powder River Basin are interconnected with the facilities of Bighorn, Fort Union, Thunder Creek Gas Gathering and Maverick Pipeline, LLC, and all the gathering facilities interconnect to the interstate gas pipeline grid serving gas markets in the Rocky Mountains, the Midwest and California. Bear Paw Energy's Williston Basin gathering and processing facilities are located in eastern Montana and western North Dakota, with a small extension into Saskatchewan, Canada. The Williston Basin system consists of approximately 3,100 miles of polyethylene and steel pipeline and 31 compressor stations with a total rated horsepower of 31,000, in addition to plant compression of approximately 20,000 horsepower. Most of the wells connected to the facilities produce casinghead gas in association with crude oil. This gas is generally high in NGLs. The NGLs are separated from the gas at our processing plants and then fractionated into components and sold. The residue gas is sold into the interstate market. A substantial portion of Bear Paw Energy's gathering and processing contracts in the Williston Basin provide for the sale of the natural gas stream to Bear Paw Energy. Upon sale of the NGLs and the residue gas processed, Bear Paw Energy pays the producers based upon a percentage of the net proceeds realized. For the year ended December 31, 2004, Bear Paw Energy's largest customers, Lodgepole Energy Marketing ("Lodgepole"), BP Canada and Montana Dakota Utilities ("Montana Dakota") accounted for 44%, 14% and 12%, respectively, of Bear Paw Energy's operating revenues. Lodgepole is the sole 16 purchaser of natural gas liquids from our processing plants in the Williston Basin and the contract term extends until 2009. BP Canada and Montana Dakota are purchasers of residue gas from our processing plants in the Williston Basin under contracts whose terms are typically less than one year. We no longer own an interest in gathering facilities in Canada. Our wholly-owned subsidiary, Border Midstream Services, Ltd. sold its undivided minority interest in the Gregg Lake/Obed Pipeline located in Alberta, Canada in December 2004 to KeySpan Energy Canada, Inc. for $14.0 million. FUTURE DEMAND AND COMPETITION Our gas gathering and processing segment competes with other natural gas gathering, processing and pipeline companies in the production areas in the Powder River, Wind River, and Williston Basins. Primary competitors in the Powder River Basin of Wyoming include both independent gathering companies and gathering companies affiliated with producers. Primary competitors affiliated with producers include affiliates of Western Gas Resources, Thunder Creek Gas Gathering, Bitter Creek Pipelines, LLC, Yates Petroleum and Anadarko Petroleum Corp. Primary non-producer affiliated competitors include Bighorn, Optigas, Inc. and Rimrock Pipeline, LLC. Competition for gathering and processing services in the Williston Basin includes Amerada Hess, PetroHunt Corporation and Hiland Resources in localized areas. Our competitive positions are affected by the pace of oil and gas drilling, gas production rates, gas reserves, natural gas and NGLs commodity prices, regulation and the demand for natural gas and NGLs in North America. The pace of natural gas drilling may be impacted by, among other things, the ability of producers to obtain and maintain the necessary drilling and production permits in a timely and economic manner, reserve characteristics and performance, surface access and infrastructure issues as well as commodity prices. In addition, the regulation of discharge of the significant volumes of water produced in association with coalbed methane production can be a deterrent to producers in determining whether to drill or produce. The time period during which coalbed methane wells dewater before significant gas production becomes available may be unpredictable. Water quality may vary substantially, and disposal alternatives and associated costs may also affect producers' decisions to drill or produce. On January 17, 2003, the Bureau of Land Management ("BLM") released two final environmental impact statements ("EIS") regarding oil and natural gas development on Federal lands. One EIS pertains to oil and gas development on BLM-administered public lands and federal mineral leases within the Powder River Basin in northeastern Wyoming. The other EIS pertains to statewide oil and natural gas development in Montana. Lawsuits have been filed challenging the EIS in Wyoming and Montana. However, BLM's issuance of new drilling permits under the regulatory preconditions has continued, albeit at a slower rate than previous years. Approximately 65% of the Powder River Basin acreage is on federal lands. In providing gas gathering, processing and other services, we may require acreage dedication, long term commitment and/or minimum volume commitments or demand charges from gas producers. Once a gathering and processing position is established, the term of the dedication, the likely economic reserve life and the cost of building duplicative facilities mitigate the level of competition in the vicinity. Development of future gas gathering and processing facilities will be staged to reflect the growth in number of wells and field production, economics, permitting considerations and other factors impacting producers' decisions to drill and produce. See Item 7. "Management's Discussion and Analysis of Financial Condition and Results of Operations - Overview." 17 We differentiate ourselves by the terms of services offered, our flexibility and additional value-added services provided. Our relationships with producers allow us to offer integrated services through all our gathering and processing facilities, as well. We also provide a variety of delivery choices, wide coverage area and operational efficiencies. We seek to improve operational profitability by increasing natural gas throughput through new connections, expansion, acquisitions, operational efficiencies and prudent deployment of capital. COAL SLURRY PIPELINE SEGMENT Black Mesa Pipeline, Inc., our wholly-owned subsidiary ("Black Mesa"), owns a 273-mile, 18-inch diameter coal slurry pipeline which originates at a coal mine in Kayenta, Arizona. The coal slurry pipeline transports crushed coal suspended in water. It traverses westward through northern Arizona to the 1,500 megawatt Mohave Generating Station located in Laughlin, Nevada. The coal slurry pipeline is the sole source of fuel for the Mohave Generating Station, which consumes an average of 4.8 million tons of coal annually. The capacity of the pipeline is fully contracted to Peabody Western Coal, the coal supplier for the Mohave Generating Station, through the year ending December 31, 2005. The water used by the coal slurry pipeline is from an aquifer in The Navajo Nation and Hopi Tribe joint use area. The Navajo Nation and Hopi Tribe have not agreed to continued use of water from this aquifer after December 31, 2005. Under a consent decree, the Mohave Generating Station has agreed to install certain pollution control equipment by December 2005. With questions surrounding the water supply and renegotiation of the coal supply contracts, Southern California Edison ("SCE") a 56% owner of the Mohave Generating Station, filed a petition before the California Public Utility Commission ("CPUC") requesting that the CPUC either recognize the end of Mohave's coal-fired operations as of the end of 2005 with appropriate ratemaking accounts or authorize expenditures for pollution control activities required for future operation. On December 2, 2004, the CPUC issued its decision which authorizes SCE, among other things, to make the necessary and appropriate expenditures for critical path investments, including the new aquifer study and feasibility studies for alternatives to replace or compliment the power from the coal-fired plant, and directs the parties to continue working on resolution of the essential water and coal issues. With successful resolution of the issues, it is expected that the Mohave Generating Station, as well as the Black Mesa system, will be temporarily idled for at least a three-year period while pollution control equipment is installed at Mohave and the Black Mesa system is rebuilt. If efforts by the parties to resolve these issues are not successful and the Mohave Generating Station is permanently closed, it would be necessary to shut down Black Mesa in 2006, resulting in shut down costs of approximately $5 million to $7 million and a non-cash charge of approximately $12 million related to goodwill and the remaining undepreciated cost of the pipeline. See Item 7. "Management's Discussion and Analysis of Financial Condition and Results of Operations - Overview." Approximately 57 people are employed in the operations of Black Mesa, of which 28 are eligible to be represented by a labor union, the United Mine Workers of America ("UMWA"). Black Mesa's collective bargaining agreement with the UMWA was renewed in 2003 and is effective through December 31, 2005. ENVIRONMENTAL AND SAFETY MATTERS Our interstate pipeline, coal slurry pipeline and U.S. gathering and processing operations are subject to certain federal, state and local laws and 18 regulations relating to safety and the protection of the environment, which include, as applicable, the Resource Conservation and Recovery Act, the Comprehensive Environmental Response, the Compensation and Liability Act of 1980, as amended, the Clean Air Act, as amended, the Clean Water Act, as amended, the Natural Gas Pipeline Safety Act of 1969, as amended, the Pipeline Safety Act of 1992 and the Pipeline Safety Improvement Act of 2002. The Pipeline Safety Improvement Act of 2002 ("Act") was signed into law in December 2002, providing guidelines for interstate pipelines in the areas of risk analysis and integrity management, public education programs, verification of operator qualification programs and filings with the National Pipeline Mapping System. The Act requires pipeline companies to perform integrity assessments on pipeline segments that exist in high population density areas or near specifically identified sites that are designated as high consequence areas. Pipeline companies are required to perform the integrity assessments within ten years of the date of enactment and must perform subsequent integrity assessments on a seven-year cycle. At least 50% of the highest risk segments must be assessed within five years of the enactment date. In addition, within one year of enactment, the pipeline's operator qualification programs, in force since the mandatory compliance date of October 2002, must also conform to standards provided by the Department of Transportation. Rules on integrity management, direct assessment usage, and the operator qualification standards have been issued. We have made the required filings with the National Pipeline Mapping System and have reviewed and revised our public education program. Compliance with the Act is expected to increase our operating costs particularly related to integrity assessments for our interstate pipelines. As required, we have developed an overall plan for pipeline integrity management. Detailed analysis was performed to determine the priorities and costs for inspecting and testing our pipelines. However, the plan will be modified as a result of the findings noted and could result in additional assessment or remediation costs. Presently we expect our annual costs for integrity assessments to be approximately $1.0 million. We expect to include these costs in future rate case filings. How these costs may be classified for all interstate pipelines is the subject of the pending proceeding before the FERC. See "Interstate Natural Gas Pipeline Segment-Interstate Pipeline Regulation" above. Black Mesa was subject to a judgment and Consent Decree entered in the United States District Court of Arizona in July 2001 through December 31, 2004. Under the Consent Decree, the United States Environmental Protection Agency ("EPA"), the Arizona Department of Environmental Quality ("ADEQ") and Black Mesa agreed to the payment of penalties for alleged violations of federal and state law due to unplanned discharges of coal slurry from Black Mesa's pipeline from December 1997 through July 1999. The Consent Decree also set forth certain preventative measures, reporting requirements and associated penalties for failure to comply with the provisions of the Consent Decree. Since the Consent Decree was entered, there have been several unplanned slurry discharges that have been reported to the EPA and ADEQ. Future unplanned spills, if any, may be subject to penalties for violations of federal and state laws. Although we believe that our operations and facilities are in general compliance in all material respects with applicable environmental and safety regulations, risks of substantial costs and liabilities are inherent in pipeline and gas processing operations, and we cannot provide any assurances that we will not incur such costs and liabilities. Moreover, it is possible that other developments, such as enactment of increasingly strict environmental and safety laws, regulations and enforcement policies thereunder by Congress, the FERC, the Department of Transportation and other federal agencies, state regulatory bodies and the courts, and claims for damages to property or persons resulting from our 19 operations, could result in substantial costs and liabilities to us. If we are unable to recover such resulting costs, earnings and cash distributions could be adversely affected. ITEM 2. PROPERTIES. See Item 1. "Business-Interstate Natural Gas Pipeline Segment," "Business-Natural Gas Gathering and Processing Segment" and "Business-Coal Slurry Pipeline Segment" for a brief description of the location and general characteristics of our important physical properties by segment. INTERSTATE NATURAL GAS PIPELINE SEGMENT Northern Border Pipeline, Midwestern Gas Transmission, Viking Gas Transmission and Guardian Pipeline hold the right, title and interest in their pipeline systems. With respect to real property, the pipeline systems fall into two basic categories: (a) parcels which are owned in fee, such as sites for compressor stations, meter stations, pipeline field offices, and microwave towers; and (b) parcels where the interest derives from leases, easements, rights-of-way, permits or licenses from landowners or governmental authorities permitting the use of such land for the construction and operation of the pipeline system. The right to construct and operate the pipeline systems across certain property was obtained through exercise of the power of eminent domain. The interstate pipeline systems continue to have the power of eminent domain in each of the states in which they operate, although Northern Border Pipeline may not have the power of eminent domain with respect to Native American tribal lands. Approximately 90 miles of Northern Border Pipeline's system are located on fee, allotted and tribal lands within the exterior boundaries of the Fort Peck Indian Reservation in Montana. Tribal lands are lands owned in trust by the United States for the Fort Peck Tribes and allotted lands are lands owned in trust by the United States for an individual Indian or Indians. Northern Border Pipeline does have the right of eminent domain with respect to allotted lands. In 1980, Northern Border Pipeline entered into a pipeline right-of-way lease with the Fort Peck Tribal Executive Board, for and on behalf of the Assiniboine and Sioux Tribes of the Fort Peck Indian Reservation ("Tribes"). This pipeline right-of-way lease, which was approved by the Department of the Interior, Bureau of Indian Affairs ("BIA") in 1981, granted to Northern Border Pipeline the right and privilege to construct and operate its pipeline on certain tribal lands. This pipeline right-of-way lease was scheduled to expire in 2011. Northern Border Pipeline has been granted options to renew the pipeline right-of-way lease to 2061. See Item 3. "Legal Proceedings." In conjunction with obtaining a pipeline right-of-way lease across tribal lands located within the exterior boundaries of the Fort Peck Indian Reservation, Northern Border Pipeline also obtained a right-of-way across allotted lands located within the reservation boundaries. Most of the allotted lands are subject to a perpetual easement either granted by the BIA for and on behalf of individual Indian owners or obtained through condemnation. Several tracts are subject to a right-of-way grant that has a term of 15 years, expiring in 2015. NATURAL GAS GATHERING AND PROCESSING SEGMENT Bear Paw Energy, Bighorn, Lost Creek and Fort Union hold the right, title and interest in their gathering and processing facilities, which consist of low and high pressure gas gathering lines, compression and measurement installations and 20 treating, processing and fractionation facilities. The real property rights for these facilities are derived through fee ownership, leases, easements, rights-of-way and permits. COAL SLURRY PIPELINE SEGMENT Black Mesa holds title to its pipeline and pump stations. The real property rights for Black Mesa facilities are derived through fee ownership, leases, easements, rights-of-way and permits. Black Mesa holds rights-of-way grants from private landowners as well as The Navajo Nation and the Hopi Tribe. These rights-of-way grants extend for terms at least through December 31, 2005, the date that Black Mesa's transportation contract with Peabody Western Coal is presently scheduled to end. ITEM 3. LEGAL PROCEEDINGS. On July 31, 2001, the Assiniboine and Sioux Tribes of the Fort Peck Indian Reservation ("Tribes") filed a lawsuit in Tribal Court against Northern Border Pipeline to collect more than $3 million in back taxes, together with interest and penalties. The lawsuit related to a utilities tax on certain of Northern Border Pipeline's properties within the Fort Peck Indian Reservation. The Tribes and Northern Border Pipeline, through a mediation process, reached a settlement with respect to pipeline right-of-way lease and taxation issues documented through an Option Agreement and Expanded Facilities Lease ("Agreement") executed in August 2004. Through the terms of the Agreement, the settlement grants to Northern Border Pipeline, among other things: (i) an option to renew the pipeline right-of-way lease upon agreed terms and conditions on or before April 1, 2011 for a term of 25 years with a renewal right for an additional 25 years; (ii) a right to use additional tribal lands for expanded facilities; and (iii) release and satisfaction of all tribal taxes against Northern Border Pipeline. In consideration of this option and other benefits, Northern Border Pipeline paid a lump sum amount of $7.4 million during August 2004 and will make additional annual option payments of approximately $1.5 million thereafter through March 31, 2011. Northern Border Pipeline intends to seek regulatory recovery of the costs resulting from the settlement. See Item 7. "Management's Discussion and Analysis of Financial Condition and Results of Operations - Risk Factors and Information Regarding Forward-Looking Statements." See Item 1. "Business - Coal Slurry Pipeline Segment" for the discussion on the proceeding before the CPUC related to Black Mesa's continuation of service beyond 2005. See Item 1. "Business - Interstate Pipeline Regulation" for the discussion on proceedings before the FERC. We are not currently parties to any other legal proceedings that, individually or in the aggregate, would reasonably be expected to have a material adverse impact on our financial condition. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS. There were no matters submitted to a vote of security holders during the fourth quarter of fiscal 2004. 21 PART II ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES. Our common units are traded on the New York Stock Exchange. The following table sets forth, for the periods indicated, the high and low sale prices per common unit, as reported on the New York Stock Exchange Composite Tape, and the amount of cash distributions per common unit declared for each quarter:

Price Range --------------- Cash 2004 High Low Distribution ---- ------ ------ ------------ Fourth Quarter $49.54 $44.60 $0.80 Third Quarter 45.81 38.61 0.80 Second Quarter 42.60 35.70 0.80 First Quarter 42.60 38.01 0.80

Price Range --------------- Cash 2003 High Low Distribution ---- ------ ------ ------------ Fourth Quarter $43.70 $35.98 $0.80 Third Quarter 44.07 40.50 0.80 Second Quarter 42.33 38.10 0.80 First Quarter 39.00 36.57 0.80

As of March 8, 2005, there were approximately 1,200 record holders of common units and approximately 64,800 beneficial owners of the common units, including common units held in street name. On March 3, 2005, the last reported sale price of our common units on the New York Stock Exchange was $51.70 per common unit. We currently have 46,397,214 common units outstanding, representing a 98% limited partner interest. The common units are the only outstanding limited partner interests. Thus, our equity consists of general partner interests representing in the aggregate a 2% interest and common units representing in the aggregate a 98% limited partner interest. The general partners are entitled to 2% of all cash distributions, and the holders of common units are entitled to the remaining 98% of all cash distributions, except that the general partners are entitled to incentive distributions if the amount distributed with respect to any quarter exceeds $0.605 per common unit ($2.42 annualized). Under the incentive distribution provisions, the general partners are entitled to 15% of amounts distributed in excess of $0.605 per common unit ($2.42 annualized), 25% of amounts distributed in excess of $0.715 per common unit ($2.86 annualized) and 50% of amounts distributed in excess of $0.935 per common unit ($3.74 annualized). The amounts that trigger incentive distributions at various levels are subject to adjustment in certain events, as described in our partnership agreement. EQUITY COMPENSATION PLAN INFORMATION Effective November 1, 2001, Northern Plains and NBP Services adopted the Amended and Restated Northern Border Phantom Unit Plan as an incentive to attract and retain employees who are essential to the services provided to us and our 22 subsidiaries. By its terms, the Amended and Restated Northern Border Phantom Unit Plan terminated on December 31, 2004. The Administrative Committee under the Plan, which are appointees of Northern Plains and NBP Services, will continue to administer the outstanding phantom units, which are based upon the general partner distribution rate. The Administrative Committee has complete authority to determine the time and provisions for settlement. During the duration of a grant, the participant's account is credited with distributions paid with respect to the underlying security. Upon settlement of the phantom units, the participant will receive common units or cash or a combination thereof, as determined by the Administrative Committee. The settlement value of the phantom units is determined by using a value derived from the general partner distribution rate and common unit distribution yield on the settlement date.

Number of securities to be issued upon Weighted average exercise of Exercise price of Number of units outstanding phantom outstanding phantom remaining available Plan Category units units for future issuance ------------- -------------------- ------------------- ------------------- (a) (b) (c) -------------------- ------------------- ------------------- Equity compensation plans approved by the unitholders (1) -- -- -- Equity compensation plans not approved by the unitholders (1) 37,602 (2) $48.18 (2) 189,500 (3) Total 37,602 189,500

(1) Under our partnership agreement, our partnership policy committee has the sole authority, without the approval of the unitholders, to adopt employee benefit or incentive plans or issue common units pursuant to any employee benefit or incentive plan maintained or sponsored by a general partner or its affiliates. (2) Based upon the closing price of the common units on December 31, 2004 and assumes that all outstanding phantom units were settled in common units as of December 31, 2004. (3) The Plan limits the number of grants of phantom units and phantom LP units to an aggregate of 200,000. This assumes all grants are phantom LP units. 23 ITEM 6. SELECTED FINANCIAL DATA. (in thousands, except per unit, other financial data and operating data) The following table sets forth, for the periods and at the dates indicated, selected historical financial data for us. The selected consolidated financial information should be read in conjunction with the Consolidated Financial Statements and the Notes and Item 7. "Management's Discussion and Analysis of Financial Condition and Results of Operations," which are included elsewhere in this report.

YEAR ENDED DECEMBER 31, -------------------------------------------------------------- 2004 2003 (1) 2002 2001 (2) 2000 (3) ---------- ---------- ---------- ---------- ---------- INCOME DATA: Operating revenues, net $ 590,383 $ 550,948 $ 487,204 $ 455,997 $ 339,732 Product purchases 103,213 80,774 50,648 39,699 -- Operations and maintenance 111,142 127,623 106,521 92,891 62,097 Depreciation and amortization (4) 86,431 299,791 74,672 75,424 60,699 Taxes other than income 36,212 35,443 32,194 27,863 28,634 ---------- ---------- ---------- ---------- ---------- Operating income 253,385 7,317 223,169 220,120 188,302 Interest expense, net 76,943 78,980 82,898 89,908 81,495 Other income, net 19,648 23,679 15,170 258 8,410 Minority interests in net income 50,033 44,460 42,816 42,138 38,119 Income taxes 5,136 4,705 1,643 499 378 ---------- ---------- ---------- ---------- ---------- Income (loss) from continuing operations 140,921 (97,149) 110,982 87,833 76,720 Discontinued operations, net of tax (5) 3,799 9,338 2,694 (47) -- Cumulative effect of change in accounting principle, net of tax -- (643) -- -- -- ---------- ---------- ---------- ---------- ---------- Net income (loss) to partners $ 144,720 $ (88,454) $ 113,676 $ 87,786 $ 76,720 ========== ========== ========== ========== ========== Per unit income (loss) from continuing operations $ 2.81 $ (2.27) $ 2.38 $ 2.12 $ 2.50 ========== ========== ========== ========== ========== Per unit net income (loss) $ 2.89 $ (2.08) $ 2.44 $ 2.12 $ 2.50 ========== ========== ========== ========== ========== Number of units used in computation 46,397 45,370 42,709 38,538 29,665 ========== ========== ========== ========== ========== CASH FLOW DATA: Net cash provided by operating activities $ 244,658 $ 224,660 $ 244,006 $ 233,948 $ 169,615 Capital expenditures 43,477 30,282 50,738 126,414 19,721 Acquisition of businesses -- 123,194 1,561 345,074 229,505 Distribution per unit 3.20 3.20 3.20 2.99 2.65 BALANCE SHEET DATA (AT END OF YEAR): Property, plant and equipment, net $1,937,424 $1,992,104 $2,015,280 $2,040,099 $1,732,076 Total assets 2,510,556 2,570,583 2,715,936 2,687,355 2,082,720 Long-term debt, including current maturities 1,330,358 1,415,986 1,403,743 1,423,227 1,171,962 Minority interests in partners' equity 290,142 240,731 242,931 250,078 248,098 Partners' equity 789,334 800,573 944,035 914,958 572,274

24

YEAR ENDED DECEMBER 31, ----------------------------------------------------- 2004 2003 (1) 2002 2001 (2) 2000 (3) --------- --------- ------- -------- -------- OTHER FINANCIAL DATA: Ratio of earnings to fixed charges (6) 3.4 0.4 2.8 2.5 2.4 OPERATING DATA: Interstate Natural Gas Pipeline Segment: Million cubic feet of gas delivered 1,130,634 1,110,969 935,654 891,935 852,674 Average receipts (mmcfd) 3,166 3,147 2,636 2,605 2,400 Natural Gas Gathering and Processing Segment: Gathering (mmcfd) 1,022 1,037 1,052 754 397 Processing (mmcfd) 55 52 55 54 -- Coal Slurry Pipeline Segment: Thousands of tons of coal shipped 4,652 4,451 4,639 4,932 4,711

---------- (1) Includes results of operations for Viking Gas Transmission since date of acquisition in January 2003. (2) Includes results of operations for Bear Paw Energy (March 2001), Midwestern Gas Transmission (May 2001) and Border Midstream Services (April 2001) since dates of acquisition. (3) Includes results of operations for Crestone Energy Ventures and Crestone Gathering Services, L.L.C. since date of acquisition in September 2000. (4) Includes goodwill and asset impairment charge of $219,080 in 2003 related to our natural gas gathering and processing business segment. (5) In June 2003, Border Midstream Services sold its Gladys and Mazeppa processing plants and related gas gathering facilities. In December 2004, Border Midstream Services sold its undivided minority interest in the Gregg Lake/Obed Pipeline. (6) "Earnings" means the sum of pre-tax income from continuing operations (before adjustment for minority interests in consolidated subsidiaries or income from equity investees), fixed charges, amortization of capitalized interest and distributions from equity investees, less capitalized interest and the minority interests in pre-tax income of subsidiaries that have not incurred fixed charges. "Fixed charges" means the sum of (a) interest expensed and capitalized; (b) amortized premiums, discounts and capitalized expenses related to indebtedness; and (c) an estimate of interest within rental expenses. The ratio of earnings to fixed charges for 2003 was lower than prior years' ratios due primarily to the goodwill and asset impairment charges booked in 2003. Excluding the impact of the impairment, the ratio would have been 3.1 for 2003. 25 ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS. Our discussion and analysis of our financial condition and operations are based on our Consolidated Financial Statements, which were prepared in accordance with U.S. generally accepted accounting principles. You should read the following discussion and analysis in conjunction with our Consolidated Financial Statements and the related notes included elsewhere in this report. OVERVIEW The Partnership's businesses fall into three major business segments: - the interstate natural gas pipeline segment, which comprises 76% of our assets; - the natural gas gathering and processing segment, which comprises 23% of our assets; and - the coal slurry pipeline segment, which comprises 1% of our assets. INTERSTATE NATURAL GAS PIPELINE SEGMENT In the interstate natural gas pipeline segment, there are several major business drivers. First, a healthy long-term supply outlook for each pipeline is critical. Because the primary source of gas supply for two of our pipeline systems is in the western Canadian sedimentary basin, western Canadian supply trends are particularly important to this segment. With strong commodity prices, the current outlook for western Canadian supply looks flat for the foreseeable future, however, production has exceeded new reserve additions in recent years. To maintain an adequate gas supply/demand balance in western Canada, production will need to grow in the future to meet anticipated demand primarily driven by gas consumption in the extraction and processing associated with Canadian oil sands development. Canada holds substantial reserves of bitumen that is extracted from sand and can be upgraded to synthesized crude oil through several processes. The extraction and processing of bitumen require significant quantities of natural gas. We do not know how many of the announced oil sands development projects will be approved and constructed but the demand for transportation on our pipeline systems could be affected adversely by the additional competition for Canadian gas supply that would result. The supply outlook may be enhanced over time by developments in the northern frontier with new Mackenzie Delta supplies reaching the western Canadian pipeline grid potentially beginning by the end of this decade and Alaskan gas thereafter, although there is no assurance either project will be completed within that timeframe. Moreover, prices of western Canadian supply must be competitive with prices from other supply basins that serve our market areas. If prices are too high, other sources of supply may satisfy demand that otherwise could be met by us. Increased demand for western Canadian natural gas in markets other than those served by us may also cause a reduction of demand for service on us. Natural gas markets are also critical to our long-term financial performance. Our pipeline systems serve natural gas markets in the upper midwestern area of the United States and access a major market hub in the Chicago area. Market growth has been steady with both heating load growth and direct end-user growth, such as power plants and ethanol plants for our pipelines. 26 We charge fees for transportation, which are primarily fixed and based on the amount of capacity reserved for each shipper. Contracting with shippers to reserve the available pipeline capacity as existing contracts expire is a critical factor in our success. Based on contracts in place at December 31, 2004, the percentage of summer design capacity contracted as of December 31, 2005 was 61% for Northern Border Pipeline, 85% for Viking Gas Transmission and 75% and 48% for northbound and southbound transportation, respectively, on Midwestern Gas Transmission. Northern Border Pipeline Recontracting During 2004, Northern Border Pipeline was successful in recontracting, at maximum rates, essentially all of the summer design capacity under contracts that expired on or before November 2004. However, most of those contracts were for terms of five to six months so Northern Border Pipeline has a significant amount of capacity, approximately 800 mmcfd or 28% of summer design capacity, under contracts that expire by May 31, 2005. Most of this capacity will become available on the pipeline system from Port of Morgan, Montana to the Ventura, Iowa delivery point. Our objective for Northern Border Pipeline is to recontract the remaining pipeline capacity at maximum transportation rates for the longest terms possible. Because the forward natural gas basis differentials between Western Canada and Northern Border Pipeline's market centers continue to be less than the total transportation cost at maximum tariff rates, Northern Border Pipeline may again sell a significant portion of this capacity on a short-term basis. So long as we continue to provide economic value, gas likely will flow from western Canada over our system and Northern Border Pipeline will maintain its relatively high utilization levels. However, in any given month, current conditions of weather and storage in supply and market areas may affect the demand for capacity on Northern Border Pipeline. This could result in lower revenues in some months. Although, we believe a reduction in expected 2005 net income and cash flow of approximately $5 million to $10 million is possible, the impact on net income and cash flow may vary outside this range depending on actual natural gas basis differentials experienced during the year. The composition of natural gas can affect the amount of energy that is transported through a pipeline system. Beginning in 2000, the energy content of natural gas that Northern Border Pipeline receives at the Canadian border has declined modestly from 1,023 British Thermal Units ("Btus") per cubic foot ("cf") to 1,005 Btus/cf. Northern Border Pipeline's transportation contracts in conjunction with its tariff define both the volume and equivalent Btu value of the gas to be transported. A reduction in the Btu level results in a higher volume of natural gas to be transported to meet an overall equivalent Btu value of the gas. This Btu decline that has been experienced was primarily the result of greater processing capacity in Alberta. The change caused Northern Border Pipeline to reduce its available capacity by almost 2 percent to maintain a high standard of system reliability for its customers. During 2004, the Btu level remained near the level of 1,005 Btus/cf and it is expected to remain at that level during 2005. This Btu variance will be addressed in the November 1, 2005 rate case filing. Northern Border Pipeline Chicago III Expansion 27 In September 2004, Northern Border Pipeline announced sufficient customer support for a proposed expansion of the pipeline system into the Chicago market area. The Chicago III Expansion Project, with 130 mmcfd of incremental capacity, involves construction of a new 16,000 horsepower compressor station in Iowa and minor modifications to existing compressor facilities, in Iowa and Illinois. Capital costs are estimated to be approximately $21 million, and the target in-service date is April 1, 2006, subject to timely receipt of regulatory approval. We anticipate that approximately $15 million of the estimated $21 million capital budget will be expended in 2005, with the remaining $6 million to be spent in 2006. Midwestern Gas Transmission Eastern Extension Project We announced on August 17, 2004 that Midwestern Gas Transmission had finalized the necessary contractual commitment to proceed with the Eastern Extension Project. The project involves the construction of approximately 30 miles of 16-inch diameter pipeline, with a capacity of approximately 120 mmcfd, from Portland, Tennessee to planned interconnections with Columbia Gulf Transmission Company and East Tennessee Pipeline Company. The project is supported by a precedent agreement with Piedmont Natural Gas Company, a local distribution company, for approximately 120 mmcf/d for a term of 15 years. Midwestern Gas Transmission has pre-filed with the FERC under the National Environmental Policy Act process. A scoping meeting was held by the FERC in Tennessee on February 24, 2005. There is landowner opposition to the project, which is not unusual for pipeline construction. Midwestern Gas Transmission is working to keep the affected landowners, the FERC staff and other governmental agencies informed. Pending the receipt of regulatory and other required approvals, the proposed in-service date for the project is November 2006 and project costs are estimated at approximately $22 million to $25 million with approximately $8 million-$9 million to be expended in 2005. Viking Gas Transmission Recontracting During 2004, Viking Gas Transmission extended contracts of 49 mmcfd at maximum rates with existing shippers for terms ranging from 3 to 5 years, resulting in Viking Gas Transmission being fully contracted until November 2005. Viking Gas Transmission has been successful in recontracting 89% of the 154 mmcfd of the expiring capacity at the Marshfield, Wisconsin delivery point for 2 to 5 year terms at maximum rates in spite of potential competition with ANR Pipeline Company's North Leg Project scheduled to go into service in 2005. We expect other projects may be proposed to further compete for these markets. WE Energies, Wisconsin Power and Light Company and Wisconsin Public Service Corporation are jointly exploring the acquisition of firm natural gas pipeline capacity to accommodate growth and provide greater competition for deliveries to various points along a route from the greater Milwaukee area to Green Bay, Wisconsin. Rate Case Filings and FERC Inquiry Under the settlement agreement for Northern Border Pipeline's last rate case, it was agreed that Northern Border Pipeline must file a proceeding under section 4 of the Natural Gas Act to determine the just and reasonable rates to be charged for its transportation services. During the rate case process, the FERC staff and Northern Border Pipeline's customers will review the cost of service elements, (including allowed return on capital, operations and maintenance costs, depreciation and taxes) and contract 28 demand levels used to determine transportation rates. Also, as required under the order granting a certificate of public convenience and necessity, Guardian Pipeline must file a revenue and cost study by December 7, 2005. As described more fully in Item 1. "Business-Interstate Pipeline Regulation", there is a FERC inquiry regarding the proper income tax allowance in rates for regulated entities other than corporations. In response, a number of comments, including ours, suggested that an income tax allowance is proper for all jurisdictional entities regardless of legal structure. Some producers' and customers' comments argued against the inclusion of an income tax allowance for partnerships and other non-tax paying entities. It is not certain how, or when, the FERC may proceed with respect to its Request for Comments or any impact on the rate methodology for our interstate natural gas pipelines which are not corporations. In particular, Northern Border Pipeline is a general partnership and one of the elements used to determine its cost of service, upon which its transportation rates are derived, is an allowance for income taxes. While we cannot predict the outcome of the FERC's inquiry, we do believe that Northern Border Pipeline's specific circumstances regarding its tariff, deferred income tax treatment, FERC orders, past history and underlying agreements with shippers are different from those of SFPP, L.P. The issue of whether Northern Border Pipeline's rates should include an income tax allowance, and if so the amount thereof, may be addressed in Northern Border Pipeline's 2005 rate case. NATURAL GAS GATHERING AND PROCESSING SEGMENT The gas gathering and processing segment accepts delivery of raw gas from natural gas wells at low pressure and gathers that wellhead production to central points where it is processed as necessary and compressed to high pressure for entry into the transmission pipeline grid. Key factors that have an impact on this segment are the pace of reserve development, the decline rate of existing wells, the composition of the raw gas stream being gathered, and the value of natural gas and natural gas liquids. We charge a fee for this service in the Powder River Basin. In the Williston Basin, we buy the natural gas we gather and then resell the extracted natural gas liquids and residue, retaining a portion of the resale revenues in return for our gathering and processing services. In some cases, we charge a fee as well. The producers receive the balance of the proceeds from the resale. Williston Basin Expansions As a result of increased drilling and development by Bear Paw Energy's customers in the Williston Basin, Bear Paw Energy has selectively expanded its facilities and expects moderate growth in this area. The 5 mmcfd expansion of the Marmarth plant has been in full operation since February 2004. The project enables the plant to produce a higher grade of product by controlling the maximum ethane-propane mixture. Also, Bear Paw Energy has expanded the northwest portion of its system to accommodate additional volumes in the Bakken Oil Play. It is anticipated that as a result of placing these facilities into service in December 2004, an additional 3.8 mmcfd will be processed by Bear Paw Energy's Grasslands processing plant in 2005. Further expansion in the Bakken Oil Play is expected to bring additional volumes to our system. 29 Powder River Basin Developments On our wholly-owned systems in the Powder River Basin, gathering volumes have increased 9% since reaching a low point in the first quarter 2004. For the full year 2004, average daily volumes gathered on our wholly-owned assets in the Powder River Basin were down 3% compared to 2003, in spite of modest growth in drilling activity and smaller than anticipated well production declines. Certain gathering contracts were renegotiated to mitigate volumetric risk and to reduce operation and maintenance expenses. In addition, certain non-strategic Powder River assets were sold during 2004, which resulted in gains totaling $3.3 million during 2004. Late in 2004, we also purchased a gathering system that gathers production from approximately 10,000 acres. We hold minority interests in Bighorn and Fort Union, which are trunk gathering systems in the Powder River Basin. These businesses are also impacted by the pace of drilling, regulatory issues and declines in upstream areas, however, they are generally more stable in terms of throughput volumes and revenues because they gather gas from larger areas. Also, our ownership in Bighorn includes preferred A units, which effectively provide an incentive mechanism to Cantera Natural Gas tied to the number of wells connected to the system. Whether such targets have been met for 2004 is under discussion. We believe that a distribution for the preferred A units is due us for 2004. Our expected 2005 net income and cash flow includes approximately $2.6 million from this distribution. Sale of Gregg Lake/Obed Pipeline Interest Our wholly-owned subsidiary, Border Midstream Services sold its undivided minority interest in the Gregg Lake/Obed Pipeline located in Alberta, Canada in December 2004 for approximately $14.0 million. The sale resulted in a $3.6 million after-tax gain. COAL SLURRY PIPELINE SEGMENT Black Mesa Pipeline Company is our coal slurry pipeline. This pipeline has one major customer, the coal supplier to the Mohave Generating Station, in Laughlin, Nevada. This contract on Black Mesa provides a steady, fee for service, revenue stream through December 31, 2005. After that time, the future is uncertain. The Mohave Generating Station must complete some significant pollution control investments, and a new water supply for the coal slurry mixture must be established. In addition, new contracts for the coal supply, must be completed. We believe that we will be able to negotiate a new contract for Black Mesa's services, however, we cannot predict the timing or ultimate outcome. Should these issues be resolved, it appears likely that there would be a temporary shutdown of the Mohave Generating Station and the Black Mesa pipeline from 2006 to 2009. We anticipate that the capital expenditures for the Black Mesa refurbishment project will be in the range of $175 million to $200 million, which will be supported by revenues from a new transportation contract. Under certain circumstances upon the renewal of the transportation contract, we have a contingent obligation to issue common units to prior owners of an interest in Black Mesa Pipeline. If this obligation is triggered, approximately 70,000 to 75,000 common units would be issued. If efforts to resolve the issues surrounding the Mohave Generating Station are not successful and it is permanently closed, it would be necessary to shut down the Black Mesa 30 pipeline in 2006. In the event the Mohave Generating Station permanently closes, estimated shut down costs for Black Mesa could be in the range of $5 million to $7 million for such expenses as environmental reclamation, severance payments and pension plan funding. We would also be required to take a non-cash charge of approximately $12 million related to goodwill and the remaining undepreciated cost of the assets. For all of our operations, we have continual focus on reliability for our shippers, safety for the public and our customers, and compliance with regulatory rules and regulations. In our businesses, these areas are essential. STRATEGY We are focused on growing our businesses, our income and cash flow and our distributions to unitholders. Our strategy involves three main components. INTERSTATE NATURAL GAS PIPELINE SEGMENT First, we will continue to focus on safe, efficient, and reliable operations and the further development of our regulated pipelines. We intend to maintain our position as a low cost transporter of Canadian gas to the midwestern U.S. and provide highly valued services to our customers. Any growth in our interstate pipelines would occur through incremental projects intended to access new markets or supply areas and would be supported by long-term contracts. For Northern Border Pipeline, the marketing of available capacity in a short-term contracting environment, filing for and receiving regulatory approvals for the Chicago III Expansion and filing the rate case will be priorities for 2005. In addition, Midwestern Gas Transmission will focus on receiving regulatory approvals for its Eastern Extension project and will continue pursuit of expanding existing and developing new interconnections with other interstate pipelines to access new markets. NATURAL GAS GATHERING AND PROCESSING SEGMENT Second, we also are developing our gas gathering and processing segment where we are building on our established business relationships with producers and marketers in the Rocky Mountain supply basins. We expect to see continued build-out of our gathering systems within the areas of acreage dedications we have secured, particularly in the Powder River Basin. Depending on the pace of reserve and production development, time associated with regulatory compliance including water-discharge permitting, and infrastructure development, we expect growth from new well connections to offset the decline from existing gas wells, resulting in approximately level aggregate gathered volumes on our Powder River systems during 2005. We are also continuing to pursue different approaches to conducting business in the Powder River Basin to reduce capital and operating expenditures, improve revenue, and reduce volume and capital recovery risks. We seek to build extensions to existing facilities on dedicated acreage using lower risk rate structures, expand our gathering network by securing additional acreage dedications, and encourage utilization of existing facilities. We expect modest growth in gas volumes for our pipelines in the Williston Basin, reflecting prospects for drilling activity within the 31 Bakken Oil Play production area. In the Williston Basin, we seek to build extensions and expansions around our existing facilities and also pursue opportunities to reduce costs and streamline operations. In addition, we are pursuing new acreage dedications in the basin. The build-out of our existing, and the addition of new, acreage dedications should mitigate production declines and allow further improvement in cost efficiencies. We will also continue to seek opportunities to mitigate commodity price exposure on the Williston Basin production. ACQUISITIONS Finally, our objective is to continue to acquire profitable and complementary businesses. Our goal is approximately $200 to $250 million of capital expenditures annually in growth through acquisitions and internal development. We target businesses that leverage our core competencies of energy transportation, are conservative in terms of commodity price risk, are located in the U.S. and Canada, and provide immediate earnings and cash flow contribution. Our strategy is to focus on acquisitions of natural gas assets including interstate and intrastate natural gas pipelines, storage facilities and gathering and processing assets and natural gas liquids pipelines and storage facilities. We anticipate financing our capital expenditures and acquisitions conservatively through an appropriate mix of additional borrowings and equity issuances. Although we regularly evaluate various acquisition opportunities, we cannot provide assurance that we will reach our goal each year and would also expect that, depending on specific opportunities that develop, acquisitions in some years could significantly exceed our goal stated above. Our ability to maintain and grow our distributions to the unitholders is dependent upon the growth of our existing businesses and/or our acquisitions. CRITICAL ACCOUNTING POLICIES AND ESTIMATES Certain amounts included in or affecting our Consolidated Financial Statements and related notes must be estimated, requiring us to make certain assumptions with respect to values or conditions that cannot be known with certainty at the time the financial statements are prepared. The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Key estimates used by our management include the economic useful lives of our assets used to determine depreciation and amortization, the fair values used to determine possible asset impairment charges, the fair values used to record derivative assets and liabilities, expense accruals, and the fair values of assets acquired. Any effects on our business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the facts that give rise to the revision become known. Our significant accounting policies are summarized in Note 2 - Notes to Consolidated Financial Statements included elsewhere in this report. Certain of our accounting policies are of more significance in our financial statement preparation process than others. The interstate natural gas pipelines' accounting policies conform to 32 Statement of Financial Accounting Standards ("SFAS") No. 71, "Accounting for the Effects of Certain Types of Regulation." Accordingly, certain assets that result from the regulated ratemaking process are recorded that would not be recorded under accounting principles generally accepted in the United States of America for nonregulated entities. We continually assess whether the future recovery of the regulatory assets is probable by considering such factors as regulatory changes and the impact of competition. If future recovery ceases to be probable, we would be required to write-off the regulatory assets at that time. At December 31, 2004, we have recorded regulatory assets of $12.3 million, which are being recovered, or expected to be recovered, from the pipelines' shippers over varying time periods up to 44 years. Our long-lived assets are stated at original cost. We must use estimates in determining the economic useful lives of those assets. Useful lives are based on historical experience and are adjusted when changes in planned use, technological advances or other factors show that a different life would be more appropriate. The depreciation rate used for utility property is an integral part of the interstate pipelines' FERC tariffs. Any revisions to the estimated economic useful lives of our assets will change our depreciation and amortization expense prospectively. For utility property, no retirement gain or loss is included in income except in the case of retirements or sales of entire operating units. The original cost of utility property retired is charged to accumulated depreciation and amortization, net of salvage and cost of removal. We review long-lived assets for impairment in accordance with SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets." Long-lived assets are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of the carrying amount of assets is measured by a comparison of the carrying amount of the asset to future net cash flows expected to be generated by the asset. Estimates of future net cash flows include anticipated future revenues, expected future operating costs and other estimates. If such assets are considered to be impaired, the impairment to be recognized is measured by the amount by which the carrying amount of the assets exceeds the fair value of the assets. Our accounting for goodwill is in accordance with SFAS No. 142, "Goodwill and Other Intangible Assets." We have selected the fourth quarter for the performance of our annual impairment testing. As discussed in Note 5, Notes to Consolidated Financial Statements, effective January 1, 2003, we adopted SFAS No. 143, "Accounting for Asset Retirement Obligations." SFAS No. 143 requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred, if the liability can be reasonably estimated. We have, where possible, developed our estimate of the retirement obligations. The implementation of SFAS No. 143 resulted in an increase in net property, plant and equipment of $2.5 million, an increase in reserves and deferred credits of $3.1 million and a reduction to net income of $0.6 million for the net-of-tax cumulative effect of the change in accounting principle. Our accounting for financial instruments is in accordance with SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities," which requires that every derivative instrument be recorded on the balance sheet as either an asset or liability measured at its fair value. The statement requires that changes in the derivative's fair value be recognized currently in earnings unless specific hedge accounting criteria are met. 33 Special accounting for qualifying hedges allows a derivative's gains and losses to offset related results on the hedged item in the income statement. At December 31, 2004, the consolidated balance sheet included assets from derivative financial instruments of $4.6 million. For our interstate natural gas pipelines, operating revenues are derived from agreements for the receipt and delivery of gas at points along the pipeline system as specified in each shipper's individual transportation contract. Revenues are recognized based upon contracted capacity and actual volumes transported under transportation service agreements. For our gas gathering and processing businesses, operating revenue is recorded when gas is processed in or transported through company facilities. For our coal slurry pipeline, operating revenue is recognized based on a contracted demand payment, actual tons transported and direct reimbursement of certain other expenses. RESULTS OF OPERATIONS The following table summarizes financial and other information by business segment for the years ended December 31, 2004, 2003 and 2002 (in thousands):

Year Ended December 31, ------------------------------- 2004 2003 2002 -------- --------- -------- Operating revenues: Interstate Natural Gas Pipelines $383,625 $ 375,256 $339,014 Natural Gas Gathering and Processing 184,738 154,284 126,622 Coal Slurry 22,020 21,408 21,568 -------- --------- -------- Total operating revenues 590,383 550,948 487,204 -------- --------- -------- Operating income (loss): Interstate Natural Gas Pipelines 231,027 212,841 200,584 Natural Gas Gathering and Processing 28,278 (203,067) 23,278 Coal Slurry 3,446 5,144 5,054 Other (9,366) (7,601) (5,747) -------- --------- -------- Total operating income (loss) 253,385 7,317 223,169 -------- --------- -------- Income (loss) from continuing operations: Interstate Natural Gas Pipelines 134,726 119,620 107,510 Natural Gas Gathering and Processing 44,488 (183,016) 35,568 Coal Slurry 3,088 4,092 4,136 Other (41,381) (37,845) (36,232) -------- --------- -------- Total income (loss) from continuing operations 140,921 (97,149) 110,982 -------- --------- -------- Discontinued operations, net of tax 3,799 9,338 2,694 Cumulative effect of change in accounting principle, net of tax -- 643 -- -------- --------- -------- Net income (loss) $144,720 $ (88,454) $113,676 ======== ========= ========

Following is a detailed analysis of the results of operations for each of our operating segments. Our operating results for 2004 reflect the settlement or expected settlement of several outstanding issues related to our past relationship with Enron Corp. ("Enron"). Our potential obligation for costs related to the termination of Enron's cash balance plan was resolved late in 2004, which allowed us to reduce our expenses. Settlement was also reached with 34 Enron for certain administrative expenses for 2002 and 2003 that had been previously estimated, which also reduced our expenses. We also recorded income in 2004 for estimated recovery of bankruptcy claims against the Enron estate that we had previously fully reserved. In December 2004, Border Midstream sold its undivided minority interest in the Gregg Lake/Obed Pipeline. The operating results for Border Midstream are classified as discontinued operations. See Notes 3 and 19 - Notes to Consolidated Financial Statements. Our operating results for 2003 reflected several significant events. Due to lower throughput volumes experienced and anticipated in our wholly-owned subsidiaries in our natural gas gathering and processing business segment, we recorded impairment charges related to goodwill and tangible assets for that segment. Effective January 17, 2003, we acquired all of the common stock of Viking Gas Transmission, including a one-third interest in Guardian Pipeline. In June 2003, we sold our Gladys and Mazeppa processing plants located in Alberta, Canada. The operating results for these plants are classified as discontinued operations. Finally, as a result of Enron's decision to terminate its cash balance plan, we recorded expenses for our expected charges related to the termination of that plan. See Notes 3, 4 and 18 - Notes to Consolidated Financial Statements. Our income from continuing operations in 2004 was $140.9 million, $2.81 per unit, as compared to a loss from continuing operations of ($97.1) million in 2003, ($2.27) per unit, and income from continuing operations of $111.0 million in 2002, $2.38 per unit. Our loss in 2003 resulted from a $219.1 million goodwill and asset impairment recorded for our natural gas gathering and processing segment. Excluding the impairment charges, income from continuing operations increased $18.9 million in 2004 as compared to 2003. We were advised by Northern Plains and NBP Services, as a result of further evaluation and negotiation of Enron's proposed allocation of the termination costs, that no claim of reimbursement for the termination costs of Enron's cash balance plan will be made, resulting in a reduction to expense in 2004 of $6.2 million ($4.8 million, net of tax and minority interest). When compared to the impact of the charges recorded in 2003, this represents a $9.6 million change to income from continuing operations between 2003 and 2004. Income from continuing operations for 2004 also reflects an adjustment to our allowance for doubtful accounts for estimated recoveries of claims against the Enron estate of $3.3 million ($3.0 million, net of minority interest) and a gain on sale of two of Bear Paw Energy's gathering systems and other compressor equipment of $3.3 million. Excluding the impairment charges, income from continuing operations increased $11.0 million in 2003 as compared to 2002, which reflects income from Viking Gas Transmission of $7.1 million, lower interest expense for Northern Border Pipeline of $6.6 million ($4.6 million impact on continuing operations after minority interest) due to a decrease in average interest rates as well as a decrease in average debt outstanding, a $2.9 million special income allocation related to a cash distribution from our preferred A interest in Bighorn Gas Gathering and a $3.3 million payment received for a change in ownership of the other partner in Bighorn Gas Gathering. These increases to income were partially offset by charges associated with the termination of Enron's cash balance plan of $6.2 million ($4.8 million, net of tax and minority interest). The calculation of per unit income (loss) was also impacted by our issuance of additional partnership interests in May and June 2003. Our consolidated income statement reflects income from discontinued 35 operations of $3.8 million in 2004, $9.3 million in 2003 and $2.7 million in 2002. Discontinued operations for 2004 include an after-tax gain of $3.6 million on the sale of the undivided interest in the Gregg Lake/Obed Pipeline. Discontinued operations for 2003 include an after-tax gain of $4.9 million on the sale of the Gladys and Mazeppa processing plants. The consolidated income statement also reflects a reduction to net income of $0.6 million due to a net-of-tax cumulative effect of change in accounting principle, which resulted from adopting SFAS No. 143, "Accounting for Asset Retirement Obligations." INTERSTATE NATURAL GAS PIPELINE SEGMENT Our interstate natural gas pipeline segment reported income of $134.7 million in 2004, $119.6 million in 2003 and $107.5 million in 2002. The increase in 2004 income from 2003 primarily relates to an increase in Northern Border Pipeline's revenues by $4.9 million ($3.4 million net impact to income after minority interests), a decrease in Northern Border Pipeline's operations and maintenance expense by $10.0 million ($7.0 million net impact to income after minority interests) and a decrease in Northern Border Pipeline's interest expense by $3.5 million ($2.5 million net impact to income after minority interests). The increase in 2003 income from 2002 primarily resulted from our acquisition of Viking Gas Transmission on January 17, 2003, and lower interest expense for Northern Border Pipeline. Viking Gas Transmission's income for 2003 totaled $7.1 million and Northern Border Pipeline's interest expense decreased by $6.6 million ($4.6 million net impact to income after minority interests). Operating revenues for our interstate natural gas pipeline segment were $383.6 million in 2004, $375.2 million in 2003 and $339.1 million in 2002. The increase in operating revenues in 2004 over 2003 resulted from an increase in Northern Border Pipeline's revenues of $4.9 million, an increase in Viking Gas Transmission revenues of $2.1 million and an increase in Midwestern Gas Transmission revenues of $1.4 million. Due to the expiration of conditions under Northern Border Pipeline's previous rate case settlement, it was able to generate and retain approximately $2.0 million from the sale of short-term firm capacity and approximately $2.0 million due to no longer being required to share new service revenue with its shippers. The remaining increase of $0.9 million resulted from an additional day of transportation services due to leap year. Viking Gas Transmission's revenue was higher in 2004 primarily because 2003 does not reflect revenue prior to the January 17, 2003 acquisition date. Midwestern Gas Transmission's revenue increased primarily due to operational sales of gas. The increase in operating revenues in 2003 over 2002 resulted from Viking Gas Transmission revenues of $29.0 million, an increase in Midwestern Gas Transmission revenues of $4.0 million and an increase in Northern Border Pipeline's revenues of $3.1 million. Midwestern Gas Transmission's revenues in 2003 reflect an increase in contracted capacity as compared to the same period in 2002. Northern Border Pipeline's revenues for 2002 were affected by $1.8 million of uncollected revenues associated with the transportation capacity formerly held by ENA, which filed for Chapter 11 bankruptcy protection in December 2001 (see "The Impact Of Enron's Chapter 11 Filing On Our Business"). Operations and maintenance expenses for our interstate natural gas pipeline segment were $52.7 million in 2004, $63.6 million in 2003 and $48.3 million in 2002. The decrease in expenses from 2003 to 2004 primarily 36 resulted from a decrease in Northern Border Pipeline's and Midwestern Gas Transmission's expense by $10.0 million and $1.1 million, respectively. In 2004, Northern Border Pipeline and Midwestern Gas Transmission reduced expenses by $4.2 million for adjustments to their accruals for estimated charges resulting from the termination of Enron's cash balance plan. Additionally in 2004, the interstate natural gas pipelines reduced their operations and maintenance expense by approximately $1.9 million related to the settlement of previously accrued charges for administrative services provided by Northern Plains, the pipelines' operator, and its affiliates. Also contributing to the decrease were adjustments made to our allowance for doubtful accounts of $1.1 million for estimated recoveries of claims against Enron. Expense was increased by $1.0 million related to costs incurred as part of our comprehensive effort to ensure compliance with Section 404 of the Sarbanes Oxley Act of 2002. The increase in expenses in 2003 over 2002 resulted from Viking Gas Transmission's expense of $10.8 million and an increase in Northern Border Pipeline's expense and Midwestern Gas Transmission's expense by a combined $4.5 million. This increase primarily related to the estimated charges for termination of Enron's cash balance plan of $4.2 million. Northern Border Pipeline's expenses in 2002 reflected a $10.0 million accrual for costs related to the treatment of previously collected quantities of natural gas used in utility operations to cover electric power costs (see Footnote 6 - Notes to Consolidated Financial Statements, included elsewhere in this report.) In February 2003, Northern Border Pipeline filed to amend its FERC tariff to clarify the definition of company use gas, which is gas supplied by its shippers for its operations. Northern Border Pipeline had included in its retention of company use gas, quantities that were equivalent to the cost of electric power at its electric-driven compressor stations during the period of June 2001 through January 2003. On March 27, 2003, the FERC issued an order rejecting Northern Border Pipeline's proposed tariff sheet revision and requiring refunds with interest within 90 days of the order. Northern Border Pipeline made refunds to its shippers of $10.3 million in May 2003. Depreciation and amortization expenses for our interstate natural gas pipeline segment were $67.1 million in 2004, $65.9 million in 2003 and $61.0 million in 2002. The increase between 2004 and 2003 is primarily a result of assets that Viking Gas Transmission had placed in service in the fourth quarter of 2003. The increase between 2002 and 2003 is primarily due to the acquisition of Viking Gas Transmission in January 2003. Taxes other than income for our interstate natural gas pipeline segment were $32.8 million in 2004, $32.9 million in 2003 and $29.2 million in 2002. The increase in 2003 from 2002 is primarily due to Viking Gas Transmission expenses of $2.5 million and a $1.2 million increase in Northern Border Pipeline's expense. Northern Border Pipeline's 2002 expense reflected a refund of use taxes previously paid on exempt purchases. Interest expense for our interstate natural gas pipeline segment was $43.9 million in 2004, $47.6 million in 2003 and $51.5 million in 2002. The decrease in interest expense in 2004 from 2003 was primarily due to a decrease in average debt outstanding for Northern Border Pipeline partially offset by an increase in average interest rates. Northern Border Pipeline's interest expense decreased $6.6 million in 2003 from 2002 due to a decrease in average interest rates as well as a decrease in average debt outstanding. The 2003 expense included $2.7 million for Viking Gas Transmission. Other income, net for our interstate natural gas pipeline segment was 37 $0.8 million in 2004, $0.5 million in 2003 and $2.0 million in 2002. Significant items included in the $0.3 million increase between 2003 and 2004 are additional income of approximately $0.6 million for pipeline interconnections constructed partially offset by $0.5 million of bad debt expense. The decrease from 2002 to 2003 relates to a $0.6 million expense for Northern Border Pipeline's repayment of amounts received in 2002 for previously vacated microwave frequency bands. Equity earnings from unconsolidated affiliates for our interstate natural gas pipeline segment were $1.6 million in 2004 and $2.0 million in 2003, which represents earnings from our one-third interest in Guardian Pipeline. The decrease in equity earnings was primarily due to higher depreciation expense as well as higher administrative expenses for Guardian Pipeline. Minority interests in net income, which represent the 30% minority interest in Northern Border Pipeline, were $50.0 million for 2004, $44.5 million for 2003 and $42.8 million for 2002. The increases in 2004 and 2003 from prior year results were due to increased net income for Northern Border Pipeline. Income tax expense for our interstate natural gas pipeline segment was $4.8 million in 2004 and $3.6 million in 2003 as compared to an income tax benefit of $0.7 million in 2002. The 2004 and 2003 amounts included Viking Gas Transmission income taxes of $2.6 million. The remaining income tax amounts relate to Midwestern Gas Transmission, which increased $1.2 million from 2003 to 2004 due to an increase in income before income taxes. NATURAL GAS GATHERING AND PROCESSING SEGMENT Our natural gas gathering and processing segment reported income from continuing operations of $44.5 million in 2004, a loss from continuing operations of ($183.0) million in 2003 and income from continuing operations of $35.6 million in 2002. The segment recorded impairment charges of $219.1 million in 2003 (see Note 4 - Notes to Consolidated Financial Statements, included elsewhere in this report). Excluding the effect of the impairment charges, the segment's income from continuing operations increased $8.4 million between 2003 and 2004 primarily due to a reduction to 2004 expense of $1.5 million for the adjustment to an accrual made in 2003 for estimated charges resulting from the termination of Enron's cash balance plan (resulting in a decrease between years of $2.9 million), a gain on sale of two gathering systems and other compressor equipment of $3.3 million and the adjustment to our allowance for doubtful accounts for estimated recoveries of claims against Enron of $2.3 million. Excluding the effect of the impairment charges, the segment's income from continuing operations for 2003 and 2002 was relatively unchanged. Operating revenues for our natural gas gathering and processing segment were $184.7 million in 2004, $154.3 million in 2003 and $126.6 million in 2002. The increase in revenues in 2004 over 2003 reflects an increase in realized prices for natural gas and natural gas liquids and increased gathering and processing volumes in the Williston Basin, which accounted for $31.3 million of the revenue increase, partially offset by lower gathering volumes in the Powder River Basin, which decreased revenues by $3.3 million. The increase in 2003 over 2002 is due to an increase in natural gas and natural gas liquid prices, which accounted for $31.6 million of the overall increase, partially offset by lower volumes gathered in the 38 Powder River Basin, which decreased revenues $3.9 million. Product purchases for our natural gas gathering and processing segment were $103.2 million in 2004, $80.8 million in 2003 and $50.6 million in 2002. Under certain gathering and processing agreements in the Williston Basin, Bear Paw Energy purchases raw natural gas from producers at a price tied to a percentage of the price for which it sells extracted natural gas liquids and residue gas. Total revenues from the sale of these products are included in operating revenues. Amounts paid to the producers to purchase their raw natural gas are reflected in product purchases. The increase in product purchases in 2004 over 2003 is due to an increase in natural gas and natural gas liquid prices and increased gathering and processing volumes. The increase in 2003 over 2002 is due to an increase in natural gas and natural gas liquid prices. Operations and maintenance expenses for our natural gas gathering and processing segment were $35.9 million in 2004, $42.8 million in 2003 and $38.2 million in 2002. The reduction in 2004 from 2003 was due to several factors. The 2004 amount includes a $3.3 million gain on sale of two gathering systems and other compressor equipment. In addition, the decrease in 2004 expense was due to the segment recording a $2.3 million estimated recovery of previously recorded bad debts. Expense for 2004 was also reduced by $1.5 million for the adjustment to the accrual made in 2003 for estimated charges resulting from the termination of Enron's cash balance plan. Partially offsetting these decreases to expense were higher fuel costs of $0.8 million and expenses incurred as a result of the Marmarth plant expansion, which went into service in 2004. Employee benefits expenses for 2003 increased $3.6 million as compared to 2002, which included $1.5 million of charges associated with the termination of Enron's cash balance plan. For our natural gas gathering and processing segment, depreciation and amortization expenses, excluding the impairment charge recorded in 2003, were $14.8 million in 2004, $13.0 million in 2003 and $12.1 million in 2002. As a result of the goodwill and asset impairment analysis, we decided to shorten the useful life of our low-pressure gas gathering assets in the Powder River Basin from 30 to 15 years, which increased our depreciation expense by $0.6 million for this segment in 2003 and by $1.8 million in 2004. Other income, net from our natural gas gathering and processing segment was $0.2 million in 2004, $3.9 million in 2003 and $0.1 million in 2002. The increase in other income for 2003 is primarily due a $3.3 million payment received for a change in ownership of the other partner in Bighorn Gas Gathering and a $0.5 million refund from an electric cooperative. Equity earnings from our unconsolidated affiliates were $16.4 million in 2004, $16.8 million in 2003 and $13.0 million in 2002. The 2004 and 2003 equity earnings include $2.8 million and $2.9 million from a special income allocation related to a cash distribution from our preferred A interest in Bighorn Gas Gathering. This distribution, determined in accordance with the joint venture agreement, was based on the number of wells connected to the gathering system in the preceding year. If certain targets are not met, we receive a disproportionate share of cash distributions. COAL SLURRY PIPELINE SEGMENT 39 Our coal slurry pipeline segment reported income from continuing operations of $3.1 million in 2004 on revenues of $22.0 million, income of $4.1 million in 2003 on revenues of $21.4 million and income of $4.1 million in 2002 on revenues of $21.6 million. The $1.0 million decrease in income from continuing operations between 2003 and 2004 was primarily due to higher depreciation expense of $2.6 million ($1.6 million impact after income taxes) partially offset by an increase in revenue by $0.6 million ($0.4 million impact after income taxes). Depreciation and amortization expense for the coal slurry pipeline was $4.5 million in 2004 as compared to $1.9 million in 2003 and $1.6 million in 2002. The Partnership determined it was appropriate to shorten the useful life of certain of its coal slurry assets to correspond with the expiration of the existing coal slurry transportation agreement in 2005. The increase in revenues in 2004 is primarily related to an increase in billing rates and an increase in tons of coal shipped. OTHER Items not attributable to any segment include certain of our general and administrative expenses, interest expense on our debt and other income and expense items. Our general and administrative expenses not allocated to any segment were $9.4 million in 2004, $7.6 million in 2003 and $5.7 million in 2002. The increase in expense between 2003 and 2004 was primarily related to increased insurance costs of $1.1 million, $1.0 million of costs incurred as part of our comprehensive effort to ensure compliance with Section 404 of the Sarbanes Oxley Act of 2002 and $0.8 million of additional business development expenditures partially offset by a reduction to 2004 expense of $0.4 million for the adjustment to an accrual made in 2003 for estimated charges resulting from the termination of Enron's cash balance plan (resulting in a decrease between years of $0.8 million) and a $0.7 million reduction related to the settlement of previously accrued charges for administrative services provided by Northern Plains and its affiliates. The 2003 expense included $0.4 million for the termination of the Enron cash balance plan, an increase in insurance expense by $0.5 million due to an increase in liability premiums and additional business development expenditures of $0.4 million. Interest expense on our debt was $32.7 million in 2004, $30.8 million in 2003 and $30.6 million in 2002. The increase in expense for 2004 from 2003 was primarily due to an increase in average debt outstanding partially offset by a decrease in average interest rates. LIQUIDITY AND CAPITAL RESOURCES The following table sets forth our contractual obligations as of December 31, 2004. SUMMARY OF CERTAIN CONTRACTUAL OBLIGATIONS AND COMMERCIAL COMMITMENTS

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

40 2001 Partnership Senior Notes due 2011 225,000 -- -- -- 225,000 2001 Pipeline Senior Notes due 2021 250,000 -- -- -- 250,000 Viking Senior Notes due 2008 to 2014 31,120 2,133 4,266 1,779 22,942 2003 Partnership Credit Agreement due 2007 191,000 -- 191,000 -- -- Capital Leases (a) 3,262 3,145 117 -- -- Operating Leases (b) 83,422 4,489 7,178 5,370 66,385 Other Long-Term Obligations (b) 61,260 11,624 23,247 22,710 3,679 ---------- ------- -------- -------- -------- Total $1,445,064 $21,391 $375,808 $229,859 $818,006 ========== ======= ======== ======== ======== (a) See Note 8 - Notes to Consolidated Financial Statements. (b) See Note 13 - Notes to Consolidated Financial Statements. We have guaranteed the performance of certain of our unconsolidated affiliates in connection with their credit agreements that expire in March 2009 and September 2009. Collectively at December 31, 2004, the amount of both guarantees was $4.4 million. OVERVIEW We believe that we have adequate liquidity to fund future recurring operating activities and investments. Short-term liquidity needs will be met by our operating cash flows and our current or similar new credit facilities discussed below. Other liquidity needs are expected to be funded through the issuance of long-term debt as well as additional limited partner interests. Our ability to complete future debt and equity offerings and the timing of any such offerings will depend on various factors, including prevailing market conditions, interest rates and our financial condition and credit ratings at the time. CREDIT FACILITIES The Partnership and Northern Border Pipeline have entered into revolving credit facilities, which are used for refinancing existing indebtedness, capital expenditures, acquisitions and general business purposes. We entered into a $275 million four-year revolving credit agreement ("2003 Partnership Credit Agreement") with certain financial institutions in November 2003. Northern Border Pipeline entered into a $175 million three-year credit agreement ("2002 Pipeline Credit Agreement") with certain financial institutions in May 2002. At December 31, 2004, $191 million was outstanding under the 2003 Partnership Credit Agreement at an average interest rate of 3.20%. There were no amounts outstanding under the 2002 Pipeline Credit Agreement at December 31, 2004. With the 2002 Pipeline Credit Agreement due to expire in May 2005, Northern Border Pipeline has commenced discussions with financial institutions and expects to have a new credit agreement in place at terms and conditions similar to its current agreement. Each of the 2003 Partnership Credit Agreement and the 2002 Pipeline Credit Agreement requires the Partnership and Northern Border Pipeline to maintain compliance with certain financial, operational and legal covenants. The 2003 Partnership Credit Agreement and 2002 Pipeline Credit Agreement 41 require the Partnership and Northern Border Pipeline to maintain ratios of EBITDA (net income plus minority interests in net income, interest expense, income taxes and depreciation and amortization) to interest expense of greater than 3 to 1. The credit agreements also require the maintenance of the ratio of indebtedness to adjusted EBITDA (EBITDA adjusted for pro forma operating results of acquisitions made during the year) of no more than 4.5 to 1. Under the 2003 Partnership Credit Agreement, if we consummate one or more acquisitions in which the aggregate purchase price is $25 million or more, the allowable ratio of indebtedness to adjusted EBITDA is temporarily increased to 5 to 1. At December 31, 2004, the Partnership and Northern Border Pipeline were in compliance with the covenants of our credit agreements. The interest rate applied to amounts outstanding under these agreements may, as selected by us and by Northern Border Pipeline, be either the lender's base rate or LIBOR plus a spread that is based upon the long-term unsecured debt ratings in effect for us and for Northern Border Pipeline. DEBT SECURITIES In April 2002, Northern Border Pipeline completed a private offering of $225 million of 6.25% Senior Notes due 2007 ("2002 Pipeline Senior Notes"). The proceeds from the 2002 Pipeline Senior Notes were used to reduce indebtedness outstanding. In December 2004, Northern Border Pipeline redeemed $75 million of the 2002 Pipeline Senior Notes. The indentures under which the Pipeline Senior Notes were issued do not limit the amount of unsecured debt Northern Border Pipeline may incur, but they do contain material financial covenants, including restrictions on incurrence of secured indebtedness. The indentures under which the Partnership Senior Notes were issued do not limit the amount of unsecured debt we may incur, but they do contain material financial covenants, including restrictions on incurrence, assumption or guarantee of secured indebtedness. The indentures also contain provisions that would require us to offer to repurchase the Partnership Senior Notes, if either Standard & Poor's Rating Services or Moody's Investor Services, Inc. rate the notes below investment grade and the investment grade rating is not reinstated for a period of 40 days. At December 31, 2004, Viking Gas Transmission has four series of senior notes outstanding. In November 2004, Viking Gas Transmission amended the indenture on its senior notes. Prior to the amendment, Viking Gas Transmission made monthly principal and interest payments on the four series of notes. As a result of the amendment, three of the series of senior notes due between 2011 and 2014 require payment of interest quarterly and payment of principal at maturity. The senior notes due in 2008 continue to require monthly principal and interest payments. Under the previous indenture, Viking Gas Transmission's transportation contracts were pledged as security for payment, which has been replaced in the current indenture by a guarantee by the Partnership. In addition, Viking Gas Transmission is no longer required to maintain debt service funds on deposit. At December 31, 2003, the requirement for accumulation of debt service funds was $3.7 million. HEDGING ACTIVITY In 2004, we entered into forward starting interest rate swap agreements with a total notional amount of $100 million in anticipation of a ten-year fixed rate senior notes issuance to be placed in the first half of 42 2005. The interest rate swap agreements have been designated as cash flow hedges as they hedge the fluctuations in Treasury rates and spreads between the execution date of the swaps and the issuance of the fixed rate debt. We expect to use the proceeds from the senior note issuance to repay amounts borrowed under the 2003 Partnership Credit Agreement. We currently have outstanding interest rate swap agreements with notional amounts totaling $150 million that expire in March 2011. Under the interest rate swap agreements, we make payments to counterparties at variable rates based on the London Interbank Offered Rate and in return receive payments based on a 7.10% fixed rate. At December 31, 2004, the average effective interest rate on our interest rate swap agreements was 4.60%. EQUITY ISSUANCES In May and June 2003, we sold 2,250,000 and 337,500 common units, respectively. In July 2002, we sold 2,186,700 common units. In conjunction with the issuance of additional common units, our general partners are required to make capital contributions to maintain a 2% general partner interest in accordance with the partnership agreements. The net proceeds from the sale of common units and the general partners' capital contributions totaled approximately $102.2 million and $75.4 million in 2003 and 2002, respectively, and were primarily used to repay indebtedness outstanding. CASH FLOWS FROM OPERATING ACTIVITIES Cash flows provided by operating activities were $244.7 million in 2004, $224.7 million in 2003 and $244.0 million in 2002. The increase in operating revenues and lower interest expense in 2004 as compared to 2003 contributed to the increase in operating cash flow. These increases were partially offset by higher product purchases and a $2.3 million decrease in distributions received from unconsolidated affiliates. Other cash flows from operating activities for 2004 reflect Northern Border Pipeline's initial payment of $7.4 million to the Fort Peck Tribes, in accordance with the terms of the Agreement, and an inflow of $3.7 million for funds that Viking Gas Transmission was previously required to keep on deposit for debt service. The decrease from 2002 to 2003 is primarily due to Northern Border Pipeline's refund to its shippers for $10.3 million (see Note 6 - Notes to Consolidated Financial Statements, included elsewhere in this report). Operating cash flows were also decreased due to payments made to NBP Services and Northern Plains for administrative services provided prior to 2003 and due to a reduction in prepayments in 2003 that Northern Border Pipeline had required certain shippers make in 2002 for transportation service. Distributions received from unconsolidated affiliates increased $5.4 million to $16.3 million, primarily due to distributions received from Bighorn Gas Gathering related to our preferred A interest discussed previously. CASH FLOWS FROM INVESTING ACTIVITIES Cash used in investing activities was $20.9 million in 2004, $116.7 million in 2003 and $55.3 million in 2002. In 2003, we spent higher amounts primarily related to the acquisition of Viking Gas Transmission. Our capital expenditures were $43.5 million in 2004, which included 43 $25.6 million for natural gas gathering and processing facilities, $16.3 million for interstate natural gas pipeline facilities and $1.6 million for coal slurry pipeline facilities. Our capital expenditures were $30.3 million in 2003, which included $19.5 million for interstate natural gas pipeline facilities, $9.0 million for natural gas gathering and processing facilities and $1.8 million for coal slurry pipeline facilities. For 2002, our capital expenditures were $50.7 million, which included $33.7 million for natural gas gathering and processing facilities, $16.5 million for interstate natural gas pipelines facilities and $0.4 million for coal slurry pipeline facilities. Our cash used in acquisitions was $123.2 million in 2003, as compared to $1.6 million in 2002. In January 2003, we acquired Viking Gas Transmission. We did not make any acquisitions in 2004. Sale of assets were $22.7 million in 2004 due to the sale of our undivided minority interest in the Gregg Lake/Obed Pipeline for $14.0 million and the sale of two of Bear Paw Energy's gathering systems for $8.7 million. Sale of assets was $40.3 million in 2003 due to the sale of the Gladys and Mazeppa processing plants. No sale of assets occurred in 2002. Our investments in unconsolidated affiliates were $0.1 million in 2004, $3.5 million in 2003 and $3.0 million in 2002. The 2003 amount primarily represents capital contributions to Guardian Pipeline while the 2002 amounts primarily reflect capital contributions to Bighorn Gas Gathering. Total capital expenditures for 2005 are estimated to be $87 million. Capital expenditures for the interstate natural gas pipelines are estimated to be $57 million, including approximately $40 million for Northern Border Pipeline. Of the $57 million projected expenditures for the interstate natural gas pipelines, approximately $15 million relates to Northern Border Pipeline's Chicago III Expansion Project and $8 million to $9 million relates to Midwestern Gas Transmission's Eastern Extension Project. Northern Border Pipeline currently anticipates funding its 2005 capital expenditures primarily by borrowing on its credit facility and using operating cash flows. Capital expenditures for natural gas gathering and processing facilities are estimated to be $25 million for 2005. The remaining $5 million estimated to be spent in 2005 primarily relates to information technology systems. Funds required to meet the capital requirements for 2005 are anticipated to be provided from our credit facility and operating cash flows. CASH FLOWS FROM FINANCING ACTIVITIES Cash flows used in financing activities were $225.7 million for 2004, $106.7 million for 2003 and $170.8 million for 2002. Our cash distributions to our unitholders and our general partners in 2004, 2003 and 2002 were $159.6 million, $155.2 million and $147.0 million, respectively. The increase in distributions paid between years is due to an increase in the number of common units outstanding. In 2004, Northern Border Pipeline received equity contributions from its general partners including $61.5 million from its minority interest holder. Northern Border Pipeline's distributions to its minority interest holder increased $15.5 million between 2003 and 2004. Effective January 1, 2004, Northern Border Pipeline changed its cash distribution policy. Cash 44 distributions will be equal to 100% of distributable cash flow as determined from Northern Border Pipeline's financial statements based upon earnings before interest, taxes, depreciation and amortization less interest expense and less maintenance capital expenditures. In 2003 and 2002, we issued additional partnership interests of $102.2 million (2.6 million common units) and $75.4 million (2.2 million common units), respectively, which were primarily used to repay indebtedness outstanding. For 2004, our borrowings on long-term debt totaled $259.0 million, which were primarily used to repay previously existing indebtedness. Issuances of long-term debt included borrowings under our credit agreement of $152.0 million and borrowings under Northern Border Pipeline's credit agreement of $107.0 million. Total repayments of debt were $327.5 million, which included the redemption of $75 million of the 2002 Pipeline Senior Notes. In connection with the redemption, Northern Border Pipeline was required to pay a premium of $4.8 million. For 2003, our borrowings on long-term debt totaled $342.0 million, which were primarily used for our acquisition of Viking Gas Transmission and to repay previously existing indebtedness. Issuances of long-term debt included borrowings under our credit agreements of $200.0 million and borrowings under Northern Border Pipeline's credit agreement of $142.0 million. Total repayments of debt in 2003 were $361.1 million. For 2002, our borrowings on long-term debt totaled $499.9 million, which were primarily used to repay previously existing indebtedness. Issuances of long-term debt included net proceeds from the 2002 Pipeline Senior Notes of approximately $223.5 million; borrowings under our prior credit agreement of $68.0 million; and borrowings under Northern Border Pipeline's credit agreements of $207.0 million. Total repayments of debt in 2002 were $567.5 million. In November 2004, Northern Border Pipeline received $7.6 million from the termination of its interest rate swap agreements with a total notional amount of $225 million. In March 2003, the Partnership received $12.3 million from the termination of an interest rate swap agreement with a notional amount of $75 million. The proceeds were primarily used to repay existing indebtedness. In 2002, we agreed to an increase in the variable interest rate on two of our interest rate swap agreements with a total notional amount of $150 million. As consideration for the change to the variable interest rate, we received approximately $18.2 million, which represented the fair value of the financial instruments at the date of the adjustment. We used the proceeds to repay amounts borrowed under our prior credit agreement. Also, in 2002, Northern Border Pipeline received $2.4 million from the termination of forward starting interest rate swap agreements (see Note 9 - Notes to Consolidated Financial Statements). THE IMPACT OF ENRON'S CHAPTER 11 FILING ON OUR BUSINESS On December 2, 2001, Enron filed a voluntary petition for bankruptcy protection under Chapter 11 of the United States Bankruptcy Code. Certain wholly-owned Enron subsidiaries also filed for Chapter 11 bankruptcy protection on December 2, 2001 and thereafter. Until November 17, 2004, each of Northern Plains and Pan Border, two of our general partners, were 45 subsidiaries of Enron. Northern Plains and Pan Border were not among the Enron companies who filed for Chapter 11 protection. SALE OF ENRON ENTITIES On March 31, 2004, Enron transferred its ownership interest in Northern Plains, Pan Border and NBP Services to CrossCountry Energy, LLC ("CrossCountry"). In addition, CrossCountry and Enron entered into a transition services agreement pursuant to which Enron would provide to CrossCountry, on an interim, transitional basis, various services, including but not limited to (i) information technology services, (ii) accounting system usage rights and administrative support and (iii) payroll, employee benefits and administrative services. In turn, these services are provided to us and our subsidiaries through Northern Plains and NBP Services. On June 24, 2004, Enron announced that it had reached an agreement with a joint venture of Southern Union Company and GE Commercial Finance Energy Financial Services ("CCE Holdings") for the sale of CrossCountry. On September 1, 2004, Enron announced that it reached an amended agreement for the sale of CrossCountry to CCE Holdings ("CCE Holdings Agreement"). On September 10, 2004, the Bankruptcy Court issued an order (the "September 10 Order") approving the CCE Holdings Agreement. On September 16, 2004, Southern Union Company and ONEOK, Inc. each announced that ONEOK had entered into an agreement ("ONEOK Agreement") to purchase Northern Plains, Pan Border and NBP Services (collectively the "Transfer Group Companies") from CCE Holdings. This acquisition closed on November 17, 2004. Under the CCE Holdings Agreement, Enron agreed to extend certain of the terms of the transition services agreement and transition services supplemental agreement between CrossCountry and Enron (together the "TSA") for a period of six months from the closing date. As part of the closing, ONEOK and CCE Holdings entered a transition services agreement referred to as the "Northern Border Transition Services Agreement" covering certain transition services by and among ONEOK, CCE Holdings and Enron for a period of six months. Certain of the services previously provided by Enron are now being provided through ONEOK. As services are transitioned to Northern Plains, NBP Services or ONEOK, it is possible that additional costs for computer hardware, software and personnel may result. The costs estimated to date do not appear to be materially greater than the costs incurred in the past by Northern Plains and NBP Services from Enron and CrossCountry. PENSION LIABILITY On December 31, 2003, Enron filed a motion seeking approval of the Bankruptcy Court to provide additional funding to, and for authority to terminate, the Enron Corp. Cash Balance Plan ("Cash Balance Plan") and certain other defined benefit plans of Enron's affiliates (collectively the "Plans") in "standard terminations" within the meaning of Section 4041 of the Employee Retirement Income Security Act of 1974, as amended ("ERISA"). On January 30, 2004, the Bankruptcy Court entered an order authorizing the termination, additional funding and other actions necessary to effect the relief requested. Pursuant to the Bankruptcy Court order, any contributions to the Plans are subject to the prior receipt of a favorable determination by the Internal Revenue Service that the Plans are tax-qualified as of their respective dates of termination. 46 On July 19, 2004, Enron was served with a complaint filed by the Pension Benefits Guaranty Corporation ("PBGC") in the District Court for the Southern District of Texas against Enron as the sponsor and/or administrator of the Plans (the "Action"). By filing the Action, the PBGC is seeking an order (i) terminating the Plans; (ii) appointing the PBGC the statutory trustee of the Plans; (iii) requiring transfer to the PBGC of all records, assets or other property of the Plans required to determine the benefits payable to the Plans' participants; and (iv) establishing June 2, 2004 as the termination date of the Plans. In the Bankruptcy Court September 10 Order, Enron was authorized to enter into an escrow agreement with CCE Holdings and PBGC. Upon closing, Enron deposited the amount of $321.8 million to an escrow account, which is intended to ensure that none of CCE Holdings or its affiliates are exposed to liability to the PBGC under Title IV of the Employee Retirement Income Security Act of 1974, as amended, for which CCE Holdings may otherwise be indemnified pursuant to the CCE Holdings Agreement. In addition, the form of escrow agreement approved pursuant to the September 10 Order provides that, under certain circumstances and upon approval by or notice to the parties to the escrow agreement, some or all of the funds placed in escrow may be paid directly in respect of the Cash Balance Plan to the PBGC. However, the September 10 Order also provides that PBGC retains any rights or claims it may have against the Transfer Group Companies. Enron management previously informed Northern Plains and NBP Services that Enron would seek funding contributions from each member of its ERISA controlled group of corporations that employs, or employed, individuals who are, or were, covered under the Cash Balance Plan. Northern Plains and NBP Services are considered members of Enron's ERISA controlled group of corporations. As of December 31, 2003, the amount of approximately $6.2 million was estimated for Northern Plains' and NBP Services' proportionate share of the up to $200 million estimated termination costs for the Plans authorized by the Bankruptcy Court order. Since under the operating agreement with Northern Plains and the administrative agreement with NBP Services, these costs could be our responsibility, we accrued $6.2 million to satisfy claims of reimbursement for these termination costs. As a result of further evaluation and negotiation of Enron's proposed allocation of the termination costs, Northern Plains and NBP Services advised us that no claim of reimbursement for the termination costs will be made, resulting in a reduction in reserves during 2004 of $6.2 million for the termination costs. Under the ONEOK Agreement, neither Northern Plains nor NBP Services nor the Partnership will be required to contribute to or otherwise be liable for any contributions to Enron in connection with the Cash Balance Plan. The purchase price under the agreements will be deemed to include all contributions which otherwise would have been allocable to Northern Plains and NBP Services. CLAIMS FILED IN BANKRUPTCY At the time of the filing of the bankruptcy petition, we had a number of contractual relationships with Enron and its subsidiaries. On July 15, 2004, the Bankruptcy Court approved the amended joint Chapter 11 plan and related disclosure statement ("Chapter 11 Plan"). Under the approved Chapter 11 Plan, assuming the previously announced sale of 47 Portland General Electric is consummated, Enron creditors, which should include subsidiaries of the Partnership as general unsecured creditors, will receive a combination of cash and equity of Prisma Energy International, Enron's international energy asset business. We have previously fully reserved our claims against Enron. ENA, a wholly-owned subsidiary of Enron that is in bankruptcy, was a party to transportation contracts, which obligated ENA to pay for 3.5% of Northern Border Pipeline's capacity. Through the bankruptcy proceeding in 2002, ENA rejected and terminated all of its firm transportation contracts on Northern Border Pipeline. Since Enron guaranteed the obligations of ENA under those contracts, Northern Border Pipeline filed claims against both ENA and Enron for damages in the bankruptcy proceedings. As a result of a settlement agreement between ENA, Enron and Northern Border Pipeline, each of ENA and Enron have agreed to allow Northern Border Pipeline's claim of approximately $20.6 million. The settlement agreement is expected to be presented to the Bankruptcy Court for approval in March 2005. Based upon this settlement between the parties, at December 31, 2004 Northern Border Pipeline adjusted its allowance for doubtful accounts to reflect an estimated recovery of $1.1 million for this claim. ENA was also a party to a transportation contract for capacity on Midwestern Gas Transmission. ENA rejected and terminated this contract in November 2003. Midwestern Gas Transmission filed claims against ENA for breach of contract and other claims. However, this claim of approximately $150 thousand was denied. In addition, Bear Paw Energy filed claims against ENA relating to terminated swap agreements. In accordance with SFAS No. 133 in 2001 Bear Paw Energy ceased to account for these swap agreements as hedge transactions. Bear Paw Energy had previously recorded approximately $6.7 million in accumulated other comprehensive income related to these agreements, which is being recorded into earnings in the same periods of the originally forecasted hedges. During the third quarter 2004, the Bankruptcy Court approved a settlement between Bear Paw Energy, Enron and certain of its wholly-owned subsidiaries of Bear Paw Energy's claim for commodity hedges. As a result, we adjusted our allowance for doubtful accounts to reflect an estimated $1.8 million recovery for this claim. Also, Crestone Energy Ventures filed claims against ENA for unpaid gas gathering and administrative services fees in the amount of approximately $2.3 million. As a result of a settlement agreement between ENA and Crestone Energy Ventures, ENA has agreed to allow Crestone Energy Ventures' claim of approximately $2.3 million. The settlement agreement is expected to be presented to the Bankruptcy Court for approval in March 2005. Based upon this settlement between the parties, an adjustment of $0.5 million was made to our allowance for doubtful accounts. We estimate that we could recognize, through future operating results, additional recoveries of $4 million to $7 million for the claims in the Enron bankruptcy proceedings. However, there can be no assurances on the amounts actually recovered or timing of distributions under the Chapter 11 Plan. VEBA TRUST 48 Enron is the grantor of the Enron Gas Pipeline Employee Benefit Trust (the "Trust"), which when taken together with the Enron Corp. Medical Plan for Inactive Participants (the "Medical Plan") constitutes a "voluntary employees' beneficiary association" or "VEBA" under Section 501(c)(9) of the Internal Revenue Code. In October 2002, Northern Plains was advised that Enron had notified the committee that has administrative and fiduciary oversight related to the Trust and the Medical Plan, that Enron had made the determination to begin necessary steps to partition the assets of the Trust and the related liabilities of the Medical Plan among all of the participating employers of the Trust. The Trust was established as a regulatory requirement for inclusion of certain costs for post-employment medical benefits in the rates established for the affected pipelines, including Northern Border Pipeline. Enron requested the enrolled actuary to prepare an analysis and recommendation for the allocation of the Trust's assets and associated liabilities among all the participating employers. On July 22, 2003, Enron sought approval of the Bankruptcy Court to terminate the Trust and to distribute its assets among certain identified pipeline companies, one being Northern Plains. If Enron's relief would have been granted as requested, Northern Plains would have assumed retiree benefit liabilities, estimated as of June 30, 2002, of $1.9 million with an asset allocation of $0.8 million. An objection to the motion was filed. An additional actuary has been engaged by Enron to review the analysis and recommendations for allocations. The results of that review have not been provided to Northern Plains. It is anticipated that a new motion will be filed and that the allocation of liabilities and assets will change from those set forth in the prior motion. We do not, however, believe that those changes will be material. PUBLIC UTILITY HOLDING COMPANY ACT ("PUHCA") REGULATION We were previously a subsidiary of a registered holding company. Upon consummation of the sale of Northern Plains and Pan Border to CCE Holdings and to ONEOK, we were no longer a subsidiary of a registered holding company. RISK FACTORS AND INFORMATION REGARDING FORWARD-LOOKING STATEMENTS Statements in this Annual Report that are not historical information are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. These forward-looking statements are identified as any statement that does not relate strictly to historical or current facts. Forward-looking statements are not guarantees of performance. They involve risks, uncertainties and assumptions. The future results of our operations may differ materially from those expressed in these forward-looking statements. Such forward-looking statements include: - the discussions in "Management's Discussion and Analysis of Financial Condition and Results of Operations - The Impact Of Enron's Chapter 11 Filing On Our Business"; - the discussions in "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Overview"; and - the discussions in "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Liquidity and 49 Capital Resources." Although we believe that our expectations regarding future events are based on reasonable assumptions within the bounds of our knowledge of our business, we cannot assure you that our goals will be achieved or that our expectations regarding future developments will be realized. With this in mind, you should consider the following important factors that could cause actual results to differ materially from those in the forward-looking statements: - Any customer's failure to perform its contractual obligations could adversely impact our cash flows and financial condition. Some of our shippers or their owners have experienced a deterioration of their financial condition. Should one or more file for bankruptcy protection, our ability to recover amounts owed or to resell the capacity would be impacted. - Since Northern Plains, the interstate natural gas pipelines' operator, and NBP Services, administrator for us, are transitioning services from Enron and CrossCountry, Northern Plains and NBP Services may be unable to perform certain services under their agreements or may incur increases in costs to continue or replace the services. - Contracts on our interstate pipelines will expire during the year 2005 with significant expirations in April and October. On Northern Border Pipeline, those contracts represent approximately 40% of its summer design capacity. The interstate pipelines' ability to recontract capacity as existing contracts terminate for maximum transportation rates will be subject to a number of factors including availability of natural gas supplies from the western Canadian sedimentary basin, the demand for natural gas in our market areas and the basis differential between the receipt and delivery points on our system. Northern Border Pipeline may have to contract for shorter terms or at less than maximum rates. See "Overview" above and Item 1. "Business - Interstate Pipelines - Demand For Transportation Capacity." - Our interstate pipelines are subject to extensive regulation by the FERC governing all aspects of our business, including our transportation rates. Under Northern Border Pipeline's 1999 rate case settlement, neither Northern Border Pipeline nor its existing customers can seek rate changes to its settlement base rates until November 2005, at which time Northern Border Pipeline is obligated to file a rate case. We cannot predict what challenges our interstate pipelines may have to their rates in the future. See Item 1. "Business - Interstate Pipelines - FERC Regulation." - In the event that the FERC ultimately determines that interstate natural gas pipelines that are partnerships are not entitled to an allowance for income tax in their rates and Northern Border Pipeline is unsuccessful in its arguments regarding its facts and circumstances, the disallowance of this component of cost of service for rates in Northern Border Pipeline could be materially adverse to us. See Item 1. "Business - Interstate Pipelines - FERC Regulation." 50 - In a rate case proceeding setting the maximum rates that may be charged, our interstate pipeline systems are generally allowed the opportunity to collect from their customers a return on their assets or "rate base" as reflected in their financial records as well as recover that rate base through depreciation. The amount they may collect from customers, as a result of a subsequent rate case, decreases as the rate base declines as a result of, depreciation and amortization. In order to avoid a reduction in the level of cash available for distributions to its owners, in the event of a future rate case, each of these pipelines must maintain or increase its rate base through projects that maintain or add to existing pipeline facilities or increase its rate of return. - Conflicts of interest may arise between our general partners and their affiliates on one hand, and us on the other hand. As a result of these conflicts, the general partners may favor their own interests and the interests of their affiliates over the interests of our limited partners. - We face competition from third parties in our natural gas transportation, gathering and processing businesses. See Item 1. "Business - Interstate Pipeline Competition" and "Business - Interstate Pipelines-Future Demand and Competition." - Our operations are subject to federal and state agencies for environmental protection and operational safety. We may incur substantial costs and liabilities in the future as a result of stricter environmental and safety laws, regulations and enforcement policies. See Item 1. "Business - Environmental and Safety Matters." - Northern Border Pipeline expects to seek rate recovery of its costs associated with the settlement of pipeline right-of-way lease and taxation issues with the Fort Peck Tribes. If Northern Border Pipeline is unable to recover these settlement costs in rates, it will be required to expense costs previously deferred as regulatory assets. See Item 3. "Legal Proceedings." - Black Mesa's contract to transport coal slurry terminates in December 2005. If Black Mesa is unable to extend or enter into a new arrangement for transportation of coal slurry, Black Mesa could incur costs and expenses for employee related matters, a write-off of recorded goodwill and removal of certain facilities. See Item 1. "Business - Coal Slurry Pipeline" and "Overview" above. - Part of our business strategy is to expand existing assets and acquire additional assets and businesses that will allow us to increase our cash flow and distributions to unitholders. Unexpected costs or challenges may arise whenever we acquire new assets or businesses. Successful acquisitions require management and other personnel to devote significant amounts of time to new businesses or integrating the acquired assets with existing businesses. 51 - Our ability to maintain and/or expand our midstream gas gathering business will depend in large part on the pace of drilling and production activity in the Powder River, Wind River and Williston Basins. Drilling and production activity will be impacted by a number of factors beyond our control, including demand for and prices of natural gas and refinery grade crude oil, producer response to the EIS, reserve performance, the ability of producers to obtain necessary permits and capacity constraints on natural gas transmission pipelines that transport gas from the producing areas. See Item 1. "Business - Natural Gas Gathering and Processing Segment - Future Demand and Competition." - Our financial performance will depend on our ability to successfully manage business operations to further reduce operating expenditures and volume and capital recovery risks in the Powder River Basin operations. - Initiatives by states to regulate the rates that we charge for our gathering and processing of natural gas and/or to assess taxes on certain aspects of our gas gathering and processing and interstate pipeline businesses may adversely impact us. - The impact of changing quality of natural gas received into our gathering and processing facilities may adversely affect our revenues and operations. In particular, the energy content of our gathered Powder River Basin production during 2004 was approximately 940 Btus/cf. Most natural gas quality standards of interstate pipelines require a minimum of 950 Btus/cf. If we are unable to blend customers' gas, additional treatment may be necessary to avoid curtailment of certain volumes. - Although our business strategy is to pursue fee-based and fixed-rate contracts, some of our gas processing facilities are subject to certain contracts that give us quantities of natural gas liquids and residue gas as payment of our processing services. The income and cash flow from these contracts will be impacted directly by changes in these commodity prices. See Item 7A. "Quantitative and Qualitative Disclosures About Market Risk" below. - We may need new capital to finance future acquisitions and expansions. If our access to capital is limited, this will impair our ability to execute our growth strategy. As we acquire new businesses and make additional investments in existing businesses, we may need to increase borrowings and issue additional equity in order to maintain an appropriate capital structure. This may be dilutive to our unitholders and impact the market value of our common units. See "Liquidity and Capital Resources - Debt and Credit Facilities and Issuance of Common Units" above. - Our indentures contain provisions that would require us to offer to repurchase our Senior Notes if Moodys or Standard & Poor's rating services rate our notes below investment grade. See "Liquidity and Capital Resources-Debt and Credit Facilities and Issuance of Common Units" above. 52 - We may be adversely impacted by the potential enactment of legislation in various states to modify existing provisions for income tax withholding on partners' distributions. - Under current law, we are treated as a partnership for federal income tax purposes and do not pay any income tax at the entity level. In order to qualify for this treatment, we must derive more than 90% of our annual gross income from specified investments and activities. While we believe that we currently do qualify and intend to meet this income requirement, if we should fail, we would be treated as if we were a newly formed corporation and the income we generate from the date of such failure would be subject to corporate income tax. Because the tax would be imposed on us, the cash available for distribution to our unitholders would be substantially reduced. In addition, the entire amount of cash received by each unitholder would generally be taxed as a corporate dividend when received. - In addition, because of widespread state budget deficits, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, use, franchise or other forms of taxation. If any state were to impose a tax upon us as an entity, the cash available to pay distributions would be reduced. The partnership agreement provides that, if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for federal, state or local income tax purposes, then the minimum quarterly distribution and the target distribution levels will be decreased to reflect that impact on us. Additional risks and uncertainties not currently known to us, or risks that we currently deem immaterial may impair our business operations. Any of the risk factors described above could significantly and adversely impair our operating results. NEW ACCOUNTING PRONOUNCEMENTS The FASB issued SFAS No. 153, "Exchanges of Nonmonetary Assets" in December 2004. See Note 15 - Notes to Consolidated Financial Statements for a discussion of this new accounting pronouncement. ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK. We may be exposed to market risk through changes in commodity prices and interest rates as discussed below. A control environment has been established which includes policies and procedures for risk assessment and the approval, reporting and monitoring of financial instrument activities. We have utilized and expect to continue to utilize financial instruments in the management of interest rate risks and our natural gas and natural gas liquids marketing activities to achieve a more predictable cash flow by reducing our exposure to interest rate and price fluctuations. We do not use these instruments for trading purposes. INTEREST RATE RISK 53 Our interest rate exposure results from variable rate borrowings from commercial banks. To mitigate potential fluctuations in interest rates, we attempt to maintain a significant portion of our consolidated debt portfolio in fixed rate debt. We also use interest rate swaps as a means to manage interest expense by converting a portion of fixed rate debt to variable rate debt to take advantage of declining interest rates. At December 31, 2004, we had $341.0 million of variable rate debt outstanding, $150.0 million of which was previously fixed rate debt that had been converted to variable rate debt through the use of interest rate swaps. As of December 31, 2004, approximately 74% of our debt portfolio was in fixed rate debt. See Notes 8 and 9 - Notes to Consolidated Financial Statements. If average interest rates change by one percent compared to rates in effect as of December 31, 2004, consolidated annual interest expense would change by approximately $3.4 million. This amount has been determined by considering the impact of the hypothetical interest rates on our variable rate borrowings outstanding as of December 31, 2004. COMMODITY PRICE RISK Bear Paw Energy is subject to certain contracts that give it quantities of natural gas and natural gas liquids as partial consideration for processing services. The income and cash flows from these contracts will be impacted by changes in prices for these commodities. Considering the effects of any hedging, for each $0.10 per million British thermal unit change in natural gas prices or for each $0.01 per gallon change in natural gas liquid prices, our annual net income would change by approximately $0.3 million. This amount has been determined by considering the impact of the hypothetical commodity prices on our projected gathering and processing volumes for 2005. The sensitivity could be impacted by changes to our projected throughput volumes. We have hedged approximately 42% of our commodity price risk in 2005. ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA. The information required hereunder is included in this report as set forth in the "Index to Financial Statements" on page F-1. ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE. None. ITEM 9A. CONTROLS AND PROCEDURES. CONCLUSION REGARDING THE EFFECTIVENESS OF DISCLOSURE CONTROLS AND PROCEDURES The Partnership's principal executive officer and principal financial officer have evaluated the effectiveness of the Partnership's "disclosure controls and procedures," (as such term is defined in Exchange Act Rule 13a-15(e) or 15d-15(e)) as of the end of the period covered by this report. Based upon their evaluation, the principal executive officer and principal financial officer concluded that the Partnership's disclosure controls and procedures are effective. 54 MANAGEMENT'S ANNUAL REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING The Partnership's principal executive officer and principal financial officer are responsible for establishing and maintaining adequate internal control over financial reporting for the Partnership. The Partnership's internal control system was designed to provide reasonable assurance to the Partnership's management and members of the Partnership's Policy Committee and Audit Committee regarding the fair presentation of published financial statements. All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. The Partnership's management assessed the effectiveness of the Partnership's internal control over financial reporting as of December 31, 2004. In making this assessment, it used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission ("COSO") in Internal Control-Integrated Framework. Based on the assessment, the Partnership's management believes that, as of December 31, 2004, the Partnership's internal control over financial reporting is effective based on those criteria. The Partnership's independent registered public accounting firm has issued an attestation report on management's assessment of the Partnership's internal control over financial reporting. This report appears in the Report of Independent Registered Public Accounting Firm below. /s/ WILLIAM R. CORDES ---------------------------------------- William R. Cordes Chief Executive Officer /s/ JERRY L. PETERS ---------------------------------------- Jerry L. Peters Chief Financial and Accounting Officer 55 Report of Independent Registered Public Accounting Firm Northern Border Partners, L.P.: We have audited management's assessment, included in the accompanying Management's Report on Internal Control over Financial Reporting, that Northern Border Partners, L.P. maintained effective internal control over financial reporting as of December 31, 2004, based on criteria established in Internal Control--Integrated Framework, issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management's assessment and an opinion on the effectiveness of the Company's internal control over financial reporting based on our audit. We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating management's assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion. A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. 56 In our opinion, management's assessment that Northern Border Partners, L.P. maintained effective internal control over financial reporting as of December 31, 2004, is fairly stated, in all material respects, based on COSO. Also, in our opinion, Northern Border Partners, L.P. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2004, based on COSO. We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Northern Border Partners, L.P. and subsidiaries as of December 31, 2004 and 2003, and the related consolidated statements of income, comprehensive income, cash flows, and changes in partners' equity, for each of the years in the three-year period ended December 31, 2004, and our report dated March 2, 2005, expressed an unqualified opinion on those consolidated financial statements. /s/ KPMG LLP Omaha, Nebraska March 2, 2005 CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING. There were no changes in our internal control over financial reporting that occurred during our last fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. However, in the quarter ending December 31, 2004, the payroll system used for the employees of Northern Plains and NBP Services, was transitioned to ONEOK's payroll system. The Partnership relied on certain systems owned or services provided by Enron and CrossCountry that support our financial accounting and reporting. Since the sale of Northern Plains and NBP Services on November 17, 2004, the Partnership has begun the transition of these systems to systems owned by us or provided by ONEOK. The Partnership's transition from the Enron and CrossCountry systems and services should be completed in May 2005. This activity has and will cause changes to the Partnership's internal control over financial reporting. ITEM 9B. OTHER INFORMATION The following information is being provided in lieu of filing an Item 5.02 Form 8-K. On March 8, 2005, Gil J. Van Lunsen was appointed by the Partnership Policy Committee as a member of the Audit Committee, effective upon Mr. Whitty's retirement. Mr. Van Lunsen replaces Mr. Whitty who is retiring from the Audit Committee effective March 15, 2005. See Item 10. "Partnership Management" for biographical and other information regarding Mr. Van Lunsen and our Audit Committee. 57 PART III ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT. We are managed under the direction of the Partnership Policy Committee consisting of three members, each of which has been appointed by one of our general partners. The members appointed by Northern Plains, Pan Border and Northwest Border have 50%, 32.5% and 17.5%, respectively, of the voting power. We also have an audit committee comprised of individuals who are neither officers nor employees of any general partner nor any affiliate of a general partner, to serve as a committee of the Partnership (the "Audit Committee"). The Audit Committee members are not members of, and do not vote on matters, submitted to the Partnership Policy Committee. The Partnership Policy Committee has delegated to the Audit Committee oversight responsibility with respect to the integrity of our financial statements, the performance of our internal audit function, the independent auditor's qualification and independence and compliance with legal and regulatory requirements. The Audit Committee directly appoints, retains, evaluates and may terminate our independent auditors. The Audit Committee reviews the annual financial statements and resolves, if necessary, any significant disputes between management and the independent auditor that arise in connection with the preparation of the financial statements. The Audit Committee also has the authority to review, at the request of a general partner, specific matters as to which a general partner believes there may be a conflict of interest in order to determine if the resolution of such conflict proposed by the Partnership Policy Committee is fair and reasonable to us. The Audit Committee has all other responsibilities required by the New York Listing Standards and SEC rules. Because we are a limited partnership, the listing standards of the New York Stock Exchange do not require us to have a majority of independent directors or a nominating/corporate governance or compensation committee. None of our Policy Committee Members are independent. As is commonly the case with publicly-traded partnerships, we do not directly employ any of the persons responsible for managing or operating the Partnership or for providing it with services relating to its day-to-day business affairs. We have entered into an Administrative Services Agreement with NBP Services, a wholly-owned subsidiary of ONEOK, pursuant to which NBP Services provides tax, accounting, legal, cash management, investor relations, operating and other services for the Partnership. NBP Services has approximately 130 employees. It also uses employees of its affiliates who have duties and responsibilities other than those relating to the Administrative Services Agreement. Also, Northern Plains, one of our general partners and a wholly-owned subsidiary of ONEOK, provides operating services to our interstate pipelines pursuant to operating agreements. Northern Plains employs approximately 310 individuals located at our headquarters in Omaha, Nebraska, and at various locations near the pipelines and also utilizes employees and information technology systems of its affiliates to provide its services. In consideration for their services under the Administrative Services Agreement and the operating agreements, NBP Services and Northern Plains are reimbursed for their direct and indirect costs and expenses, including an allocated portion of employee time and overhead costs. See Item 13. "Certain Relationships and Related Transactions." 58 Set forth below is certain information concerning the members of the Partnership Policy Committee, our representatives on the Northern Border Management Committee and the persons designated by the Partnership Policy Committee as our executive officers and as Audit Committee members. All members of the Partnership Policy Committee and our representatives on the Northern Border Management Committee serve at the discretion of the general partner that appointed them. The persons designated as executive officers serve in that capacity at the discretion of the Partnership Policy Committee. The members of the Partnership Policy Committee receive no management fee or other remuneration for serving on this committee. The Audit Committee members are elected, and may be removed, by the Partnership Policy Committee. Daniel P. Whitty, who has been a member of the audit committee since 1993, has tendered his resignation to be effective March 15, 2005. On March 8, 2005, the Partnership Policy Committee appointed Gil J. Van Lunsen to be a member of the Audit Committee effective March 15, 2005. The Chairman of the Audit Committee receives an annual fee of $50,000 and other Audit Committee members receive an annual fee of $40,000 and each is paid $1,500 for each meeting attended. As noted above, the members of our Partnership Policy Committee and Audit Committee are not elected by unitholders. Accordingly, we do not have a procedure by which security holders may recommend nominees to our Partnership Policy Committee or Audit Committee. Effective with the purchase and sale of Northern Plains and Pan Border on November 17, 2004, Stanley C. Horton resigned as a member of the Partnership Policy Committee and as a member of the Management Committee of Northern Border Pipeline Company. Effective November 17, 2004, David L. Kyle was appointed by Northern Plains as its member and the Chairman of the Partnership Policy Committee. Mr. Kyle has also been appointed by Pan Border as its member to the Management Committee of Northern Border Pipeline Company. There are no family relationships between any of our executive officers or members of the Partnership Policy Committee and the Audit Committee.

NAME AGE POSITIONS ---- --- --------- Executive Officers: William R. Cordes 56 Chief Executive Officer Jerry L. Peters 47 Chief Financial and Accounting Officer Members of Partnership Policy Committee and Partnership's representatives on Northern Border Management Committee: David L. Kyle 52 Chairman William R. Cordes 56 Member Paul E. Miller 46 Member Members of Audit Committee: Gerald B. Smith 54 Chairman Daniel P. Whitty 73 Member Gary N. Petersen 53 Member Gil J. Van Lunsen 62 Nominee

59 David L. Kyle was named Chairman of the Policy Committee in November 2004. Mr. Kyle is Chairman and Chief Executive Officer of Northern Plains, Pan Border and NBP Services. Besides Chairman of the Policy Committee of Northern Border Partners, Mr. Kyle is the Chairman of the Board, President, and Chief Executive Officer of ONEOK, Inc. He was employed by Oklahoma Natural Gas Company in 1974 as an engineer trainee. He served in a number of positions prior to being elected Vice President of Gas Supply September 1, 1986, and Executive Vice President May 17, 1990 of Oklahoma Natural Gas Company. He was elected President of Oklahoma Natural Gas Company on September 1, 1994. He was elected President of ONEOK, Inc. effective September 1, 1997, and was elected Chairman of the Board and appointed the Chief Executive Officer of ONEOK, Inc. August 28, 2000. Mr. Kyle is a member of the boards of directors of Bank of Oklahoma Financial Corporation and Blue Cross and Blue Shield of Oklahoma. William R. Cordes was named Chief Executive Officer of the Partnership and appointed to the Partnership Policy Committee in October 2000. He served as Chairman of the Partnership Policy Committee from October 2000 until November 17, 2004. Mr. Cordes is the President of Northern Plains, Pan Border and NBP Services, ONEOK subsidiaries, having been appointed to that position on October 1, 2000 for Northern Plains and Pan Border and November 17, 2004 for NBP Services. Mr. Cordes was named Chairman of the Northern Border Management Committee October 1, 2000. In 1970, he started his career with Northern Natural Gas Company, an Enron subsidiary until February 2002, where he worked in several management positions. From June of 1993 until September of 2000, he was President of Northern Natural Gas Company and from May of 1996 until September of 2000, he was also President of Transwestern Pipeline, a subsidiary of Enron. Paul E. Miller was designated by TransCanada as its member on the Partnership Policy Committee in September 2003. Mr. Miller is also a representative on the Northern Border Management Committee. Additionally, Mr. Miller serves as Director Corporate Development of TransCanada, a position he has held since February 2003. From July 1998 to January 2003, Mr. Miller was Director Finance of TransCanada. Prior to July 1998, Mr. Miller was Manager, Finance of TransCanada. Jerry L. Peters was named Chief Financial and Accounting Officer in July 1994. Mr. Peters has held several management positions with Northern Plains since 1985 and was elected Vice President of Finance in July 1994, and Treasurer in October 1998. Mr. Peters was also elected Vice President of Finance for NBP Services in November 2004. Mr. Peters was also Vice President, Finance of the following former affiliates of Northern Plains: Florida Gas Transmission Company from February 2001 to May 2002; Transportation Trading Services Company from September 2001 to July 2002; Citrus Corp. from October 2001 to July 2002; and Transwestern Pipeline Company from November 2001 to May 2002. Prior to joining Northern Plains in 1985, Mr. Peters was employed as a Certified Public Accountant by KPMG LLP. Gerald B. Smith was appointed to the Audit Committee in April 1994. He is Chairman and Chief Executive Officer and co-founder of Smith, Graham & Company Investment Advisors, a global investment management firm, which was founded in 1990. He is a member of the Board of Trustees of Charles Schwab Family of Fund; and a director and member of the audit committee of Cooper Industries. He is a former director of the Fund Management Board of Robeco Group, Rorento N.V. (Netherlands). 60 Daniel P. Whitty was appointed to the Audit Committee in December 1993. Mr. Whitty is an independent financial consultant. He has served as a member of the Board of Directors of Methodist Retirement Communities Inc., and a Trustee of the Methodist Retirement Trust. Mr. Whitty was a partner at Arthur Andersen LLP ("Andersen") until his retirement on January 31, 1988. At Andersen, he had firm wide responsibility for the natural gas transmission industry for many years. Until his resignation in December 2001, Mr. Whitty served as a director of EOTT Energy Corp., a subsidiary of Enron and the general partner of EOTT Energy Partners, L.P. EOTT Energy Corp. filed for bankruptcy protection on October 21, 2002. Gary N. Petersen was appointed to the Audit Committee on March 19, 2002. Since 1998, he has provided consulting services related to strategic and financial planning. Additionally, he is currently the President of Endres Processing LLC. From 1977 to 1998, Mr. Petersen was employed by Reliant Energy-Minnegasco. He served as Reliant Energy-Minnegasco's President and Chief Operating Officer from 1991 to 1998. Prior to his employment at Minnegasco, he was a senior auditor with Andersen. He currently serves on the boards of the YMCA of Metropolitan Minneapolis and the Dunwoody Institute. Gil J. Van Lunsen was appointed to the Audit Committee on March 8, 2005. Prior to his retirement in June 2000, Mr. Van Lunsen was a Managing Partner of KPMG LLP and led the firm's Tulsa, Oklahoma office. He began his career with KPMG in 1968. He is currently a director and audit committee chairman of Array Biopharma in Boulder, Colorado and Sirenza Microdevices in Broomfield, Colorado. At the meeting of the Partnership Policy Committee on March 3, 2005, the following persons were deemed to be officers of the Partnership for purposes of Section 16 of the Securities Exchange Act of 1934. Some of these individuals are officers at certain subsidiaries of the Partnership:

NAME AGE POSITIONS ---- --- --------- Christopher R Skoog 41 Executive Vice President Paul F. Miller 38 Vice President and General Manager for Northern Border Pipeline Michel E. Nelson 57 Vice President, Operations, Interstate Pipelines Raymond D. Neppl 60 Vice President, Regulatory Affairs and Market Services, Interstate Pipelines Pierce H. Norton 45 President, Bear Paw Energy Janet K. Place 55 Vice President, General Counsel and Secretary Fred G. Rimington 54 Vice President, Administration and President of Black Mesa Pipeline Gaye Lynn Schaffart 45 Vice President and General Manager, Interstates

61 Christopher R Skoog was appointed executive vice president of Northern Plains and NBP Services effective February 1, 2005. Mr. Skoog is responsible for all commercial, operational and regulatory functions of the Partnership's natural gas businesses and will coordinate the Partnership's business development initiatives. From 1999 to January 31, 2005, Mr. Skoog served as President of ONEOK Energy Services Company, II. From 1995 to 1999, he was Vice President, ONEOK Gas Marketing Company. Paul F. Miller is Vice President and General Manager for Northern Border Pipeline of Northern Plains, having been elected in January 2005. From March 2002 until January 2005, Mr. Miller was Vice President of Marketing for Northern Plains. Mr. Miller was previously Account Executive, Marketing from December 1998 until August 2000, when he was promoted to Director, Marketing. Mr. Miller joined Northern Plains in 1990. Michel E. Nelson is Vice President, Operations for Northern Plains, having been elected in November 2004. Mr. Nelson was previously Vice President of Operations and Support Services for CrossCountry Energy, LLC, an Enron subsidiary, from 2002 to November 2004. From 1997 to 2002, Mr. Nelson held various positions for Enron Transportation Services with responsibility for pipeline operations. Mr. Nelson started his pipeline operations career with Northern Natural Gas Company in 1968. CrossCountry Energy, Enron Transportation Services and Northern Natural Gas Company were formerly affiliated with Northern Plains. Raymond D. Neppl is Vice President, Regulatory Affairs and Market Services, a position he has held since July 1994. Mr. Neppl was previously Vice President of Regulatory Affairs from 1991 to 1994. Mr. Neppl joined Northern Natural Gas Company, formerly affiliated with Northern Plains, in 1975 and transferred to Northern Plains in 1980. Pierce H. Norton is President of Bear Paw Energy, a subsidiary of the Partnership, having been appointed in February 2003. Mr. Norton is Vice President and General Manager for midstream businesses for NBP Services, having been appointed in 2003. Mr. Norton, from 2001 to 2003 served as Vice President, Business Development for Bear Paw. Prior to the Partnership's purchase of Bear Paw, Mr. Norton was Vice President--Business Development for Bear Paw Energy and its predecessor from 1999 to 2001 where he was responsible for managing contracts and asset acquisitions. Janet K. Place is Vice President, General Counsel and Secretary of Northern Plains, having been elected in August 1994 as Vice President and November 2004 as Secretary. She was also elected Vice President, General Counsel and Secretary of NBP Services in November 2004. In 1993, Ms. Place was named General Counsel. Ms. Place joined Northern Plains in 1980 as an Attorney. Gaye Lynn Schaffart is Vice President and General Manager, Interstates of Northern Plains, having been elected February 2005. Ms. Schaffart was previously Director, Business Development and Planning from 1993 to 2004 when she was promoted to Vice President, Business Development and Strategic Planning in March 2004. Ms. Schaffart joined Northern Plains in 1982. Fred G. Rimington is Vice President, Administration of Northern Plains and NBP Services, having been elected in February 2005. He is also the President of Black Mesa Pipeline, Inc., having been appointed in January 62 2000. Mr. Rimington was Director, Business Development from 1994 to 1999 for Northern Plains. Mr. Rimington joined Northern Plains in 1980. AUDIT COMMITTEE MATTERS INDEPENDENCE AND FINANCIAL EXPERT The Partnership has a separately-designated standing Audit Committee in accordance with Section 3(a)(58)(A) of the Exchange Act. The members of our Audit Committee are Mr. Gerald B. Smith, Daniel P. Whitty and Gary N. Petersen. Additionally, Mr. Gil J. Van Lunsen was appointed to the Audit Committee on March 8, 2005 and replaces Mr. Whitty who is retiring on March 15, 2005. The Partnership's guidelines for determining independence are included in the Partnership's Governance Guidelines, which, along with the Audit Committee charter, is available on the "Governance" section of the Partnership's website at www.northernborderpartners.com. Copies of the Governance Guidelines as well as the Audit Committee charter are available in print to any security holder who requests them by sending a written request to Investor Relations Department, Northern Border Partners, L.P., P.O. Box 542500, Omaha, NE 68154-8500. Our Governance Guidelines contain independence standards for our Audit Committee members. The Governance Guidelines provide that the members of the Audit Committee shall at all times qualify as independent members under the independence standards of the New York Stock Exchange, including Section 10A(m)(3) of the Securities Exchange Act of 1934, the rules and regulations of the Securities and Exchange Commission and other applicable laws. At least annually the Partnership Policy Committee reviews the relationships that each Audit Committee member has with the Partnership to affirmatively determine the independence of each member. The Policy Committee has affirmatively determined that Messrs. Petersen, Smith, Whitty, and Mr. Van Lunsen meet the standards for independence set forth in the Governance Guidelines and are independent from management. Annually, the Partnership Policy Committee determines the financial expertise of the members of the audit committee. On March 3, 2005, the Policy Committee determined that Messrs. Petersen, Smith and Whitty were "audit committee financial experts" and each is independent, as noted above. SEPARATE SESSIONS OF NON-MANAGEMENT COMMITTEE MEMBERS The Partnership Policy Committee has documented its governance practices in the Governance Guidelines, a copy of which is available on the "Governance" section of the Partnership's website at www.northernborderpartners.com. The Chairman of the Audit Committee, Mr. Gerald Smith, presides at these sessions of non-management committee members, which include the members of the Audit Committee and Messrs. Kyle and Miller of the Partnership Policy Committee. The first meeting occurred at the November 2, 2004 meeting. In the future, meetings of the non-management committee members are scheduled quarterly or as requested by any non-management committee member. Interested parties desiring to communicate with the presiding member, the non-management members of the Partnership Policy Committee as a group or the Audit Committee members as a group regarding the Partnership may directly contact such member(s) by utilizing the Partnership Ethics and Compliance Hotline which is posted on the "Governance-Contact Information" section of our website at www.northernborderpartners.com. SERVICE ON OTHER AUDIT COMMITTEES Mr. Smith, the Chairman of our Audit Committee, and Mr. Van Lunsen, our newly appointed Audit Committee member, also serve on the audit committees of two other public companies. The Partnership Policy Committee has determined 63 that Mr. Smith and Mr. Van Lunsen's service on these other audit committees does not impair their ability to effectively serve on the Partnership's Audit Committee. SECTION 16(a) BENEFICIAL OWNERSHIP REPORTING COMPLIANCE Section 16(a) of the Securities Exchange Act of 1934 requires executive officers, members of the Partnership Policy Committee and persons who own more than ten percent of a registered class of the equity securities issued by us to file reports of ownership and changes in ownership with the SEC and the New York Stock Exchange and to furnish the Partnership with copies of all Section 16(a) forms they file. Based solely on our review of the copies of such reports received by us, or written representations from certain reporting persons that no Form 5's were required for those persons, we believe that during 2004 our reporting persons complied with all applicable filing requirements in a timely manner. CODE OF ETHICS AND CODE OF CONDUCT We have adopted an Accounting and Financial Reporting Code of Ethics applicable to the Partnership's chief executive officer and chief financial and accounting officer. A copy of the Accounting and Financial Reporting Code of Ethics is posted on the "Governance" section of our website, www.northernborderpartners.com, and we intend to post on our website any amendments to, or waivers from, any provision of our Accounting and Financial Reporting Code of Ethics that applies to our chief executive officer and chief financial and accounting officer within four business days following such amendment or waiver. We have also adopted a Code of Conduct applicable to the members of the Partnership Policy Committee and Audit Committee, our officers and the deemed executive officers and the employees of Northern Plains and NBP Services. The Code of Conduct is intended to meet the requirements of a "code of business conduct and ethics" under Section 303A.10 of the New York Stock Exchange Listed Company Manual. A copy of the Code of Conduct is posted on the "Governance" section of our website at www.northernborderpartners.com and is available in print to any security holder who requests it by writing to Investor Relations Department, Northern Border Partners, L.P., P.O. Box 542500, Omaha, NE 68154-8500. We intend to promptly post on our website any amendments to, or waivers from (including any implicit waivers), any provision of our Code of Conduct in accordance with the rules of the New York Stock Exchange ("NYSE"). CERTIFICATION Certifications As required by New York Stock Exchange ("NYSE") listing standards, William R. Cordes, our Chief Executive Officer, certified on November 15, 2004 that he was not aware of any violation by the Partnership of NYSE corporate governance listing standards. The certifications required by Section 302 of the Sarbanes-Oxley Act are attached as exhibits 31.1 and 31.2 to this Annual Report on Form 10-K. 64 ITEM 11. EXECUTIVE COMPENSATION. We are managed by a three member policy committee, with one member appointed by each general partner. The Partnership Policy Committee has designated two executive officers who serve as officers of the Partnership at the discretion of the Partnership Policy Committee. In addition, certain officers of the general partners and certain officers of subsidiaries of the partnership were deemed to be executive officers of the Partnership by the Partnership Policy Committee. The following table sets forth a summary of compensation paid for the last three years of the chief executive officer of the Partnership and the other four most highly compensated executive officers of the Partnership during 2004, which we collectively refer to as the "Named Officers." For the years 2002, 2003 and through November 17, 2004, compensation plans were administered by Enron. Beginning November 18, 2004, compensation plans are administered by ONEOK. SUMMARY COMPENSATION TABLE

Long-Term Compensation Annual Compensation ---------------------- All Other ------------------------------------------ Restricted Compensation Name & Principal Other Annual Stock Awards ------------ Position Year Salary $ Bonus $ (1) Compensation (2) ($) (3) (4) ($) (5) ---------------- ---- -------- ------------ ---------------- ------------ ------- William R. Cordes 2004 $325,000 $175,000 -- $ -- $ 4,908 Chief Executive Officer 2003 $324,583 $200,000 -- $ 99,972 $ 3,000 2002 $319,333 $240,000 -- $100,051 $ 1,031 Jerry L. Peters 2004 $171,380 $110,000 -- -- $ 5,658 Chief Financial and 2003 $163,324 $107,500 -- -- $76,386 Accounting Officer 2002 $159,285 $110,000 -- -- $23,950 Janet K. Place 2004 $182,552 $115,000 -- -- $ 8,675 Vice President & General 2003 $177,592 $110,000 -- -- $ 6,233 Counsel and Secretary 2002 $171,500 $110,000 -- -- $ 7,266 NPNG Pierce H. Norton 2004 $183,834 $105,000 -- -- $ 2,520 Vice President & General 2003 $178,842 $ 80,000 -- -- $ 1,295 Manager - NBP Services 2002 $166,688 $ 57,250 -- -- $ 1,580 Corp Paul F. Miller 2004 $153,298 $118,000 -- -- $ 5,335 Vice President & General 2003 $148,958 $111,000 -- -- $90,325 Manager for Northern 2002 $139,850 $ 92,000 -- -- $ 4,721 Border Pipeline

(1) For bonus amounts for 2004, there was an early payout of an amount equal to 10/12ths in October 2004 and the remaining 2/12s was paid in March 2005. (2) No Named Officer received perquisites or other personal benefits, securities or property in an amount in excess of the lesser of either $50,000 or 10% of the total of salary and bonus reported for such officer in the two preceding columns. (3) The aggregate total of shares in unreleased Enron restricted stock holdings and their values as of December 31, 2003, for each of the Named Officers is: Mr. Cordes, 4,295 shares valued at $0, Mr. Peters, 1,701 shares valued at $0 and Ms. Place, 1,832 at $0. Dividend equivalents for all restricted stock awards accrue from date of grant and are paid upon vesting. Any dividends on Enron Corp. stock accrued and unreleased as of the date of Enron Corp.'s filing for bankruptcy protection will only be released in accordance with applicable bankruptcy law. (4) Mr. Cordes' employment agreement, as executed in September 2001, provided for a grant of 882 Northern Border Phantom Units. On June 1, 2002 and 2003, grants of 697 and 669 Northern Border Phantom Units valued at $143.5456 and $149.4346 per unit, 65 respectively, were made in accordance with his employment agreement. The phantom units vest on the fifth anniversary of the date of each grant. (5) The amounts shown include the matching contributions to employees' Enron Corp. Savings Plan and to the Thrift Plan for employees of ONEOK, and imputed income on life insurance benefits. For Mr. Cordes and Mr. Peters, the amount shown for 2004 was for matching contributions. For Ms. Place, the amount shown for 2004 for matching contributions was $6,050 and for imputed income was $2,625. For Mr. Norton, the amount shown for 2004 for matching contributions was $2,520. For Mr. Miller, the amount shown for matching contributions was $5,080 for 2004 and the amount for imputed income was $255. Mr. Peters' employment agreement, as executed in April 2002, provided for a "stay" bonus in which $23,950 of the amount was paid six months following the implementation of the agreement. The remaining amount of $71,853 was paid in March 2003 upon completion of the term of the agreement. Mr. Miller's employment agreement, as executed in October 2002, provided for a "stay" bonus in which 25% was to be paid six months following the implementation of the agreement and the remainder upon completion of the term of the agreement. The entire bonus of $85,470 was distributed in 2003. For 1999, 2000 and 2001, employees of Northern Plains were able to elect to receive Northern Border phantom units, Enron Corp. phantom stock, and/or Enron Corp. stock options in lieu of all or a portion of an annual bonus payment. Mr. Cordes, Mr. Peters, Ms. Place and Mr. Miller elected to receive Northern Border phantom units under the Northern Border Phantom Unit Plan in lieu of a portion of the cash bonus payment. As a result of this deferral, Mr. Cordes received 1,914 units in 2001; Mr. Peters received 1,532 units in 1999, 1,450 units in 2000 and 842 units in 2001; Ms. Place received 901 units in 1999 and 240 units in 2001; and Mr. Miller received 137 units in 1999, 123 units in 2000 and 230 units in 2001. In each case, units will be released based upon the holding period selected by the participant. For the release in January 2004, Mr. Peters received 4,727 common units. For the release in January 2003, Ms. Place received 1,091 common units and for the release in 2004, she elected a redemption payment in cash of $83,232.28. For the release in January 2002, Mr. Miller received 333 common units; for the release in 2003, he received 329 common units and for the release in 2004, he elected a redemption payment in cash of $25,283.42. On January 20, 2005, the Board of Directors of ONEOK granted restricted stock incentive units and performance share units to the named executive officers as follows: Mr. Cordes, 6,000 restricted stock incentive units and 10,500 performance share units; Mr. Peters, 3,000 restricted stock incentive units and 4,500 performance share units; Ms. Place 2,000 restricted stock incentive units and 3,500 performance share units; Mr. Norton 2,500 restricted stock incentive units and 4,000 performance share units; and Mr. Miller 2,500 restricted stock incentive units and 4,000 performance share units. The restricted stock incentive units vest three years from the date of grant at which time the grantee is entitled to receive two-thirds of the grant in shares of ONEOK common stock and one-third of the grant in cash. The performance share units granted vest three years from the date of grant at which time the holder is entitled to receive a percentage (0% to 200%) of the performance shares granted based on ONEOK's total shareholder return over the period January 20, 2005, to January 20, 2008, compared to the total shareholder return of a peer group of 20 other companies, payable two-thirds of the grant in shares of ONEOK common stock and one-third of the grant in cash. STOCK OPTION GRANTS IN 2004 Due to the bankruptcy filing by Enron on December 2, 2001, there were no grants of stock options pursuant to Enron's stock plans to the Named 66 Officers reflected in the Summary Compensation Table. No stock appreciation rights were granted during 2004. AGGREGATED OPTION/SAR EXERCISES IN 2004 AND 2004 YEAR-END OPTION/SAR VALUES The following table sets forth information with respect to the Named Officers concerning the exercise of Enron SARs and options during the last fiscal year and unexercised Enron options and SARs held as of December 31, 2005:

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

(1) Due to Enron's bankruptcy filing there is no dollar value assignable to Enron Corp. stock options. TERMINATION AGREEMENT Effective January 5, 2005, ONEOK, Inc. entered into termination agreements with Messrs. Cordes, Peters, Norton and Miller and Ms. Place. Each termination agreement has an initial term from January 5, 2005 until January 1, 2007 and is automatically extended in one-year increments after the expiration of the initial term unless ONEOK provides notice to the officer or the officer provides notice to ONEOK at least 90 days before January 1 preceding the initial or any subsequent termination date of the agreement that the party providing notice does not wish to extend the term. If a "change in control" of ONEOK occurs, the term of each termination agreement will not expire for at least three years after the change in control. Under the termination agreements, severance payments and benefits are payable if the officer's employment is terminated by ONEOK without "just cause" or by the officer for "good reason" at any time during the three years after a change in control. In general, severance payments and benefits include a lump sum payment in an amount equal to (1) two times (three times, in the case of William Cordes) the officer's annual compensation and (2) a prorated portion of the officer's targeted short-term incentive compensation. The officer would also be entitled to accelerated vesting of retirement and other benefits under the Supplemental Executive Retirement Plan (discussed below) and continuation of welfare benefits for 24 months (36 months in case of Mr. Cordes). Severance payments will be reduced if the net after-tax benefit to such officer exceeds the net after-tax benefit if such reduction were not made. Gross up payments will be made to such officers only if the severance payments, as reduced, are subsequently deemed to constitute excess parachute payments. For purposes of these agreements, a "change in control" generally means any of the following events: - an acquisition of voting securities of ONEOK by any person that results in the person having beneficial ownership of 20% or more of 67 the combined voting power of ONEOK's outstanding voting securities, other than an acquisition directly from ONEOK; - the current members of ONEOK's Board of Directors, and any new director approved by a vote of at least two-thirds of ONEOK's Board of Directors, cease for any reason to constitute at least a majority of ONEOK's Board of Directors, other than in connection with an actual or threatened proxy contest (collectively, the "Incumbent Board"); - a merger, consolidation or reorganization with ONEOK or in which ONEOK issues securities, unless (a) ONEOK's shareholders immediately before the transaction do not, as a result of the transaction, own, directly or indirectly, at least 50% of the combined voting power of the voting securities of the company resulting from the transaction, (b) members of ONEOK's Incumbent Board after the execution of the transaction agreement do not constitute at least a majority of the members of the Board of the company resulting from the transaction, or (c) no person other than persons who, immediately before the transaction owned 30% or more of ONEOK's outstanding voting securities, has beneficial ownership of 30% or more of the outstanding voting securities of the company resulting from the transaction; or - ONEOK's complete liquidation or dissolution or the sale or other disposition of all or substantially all of our assets. RETIREMENT PLANS-ENRON Enron maintains the Enron Corp. Cash Balance Plan (the "Cash Balance Plan"), which is a noncontributory defined benefit pension plan to provide retirement income for employees of Enron and its subsidiaries. Through December 31, 1994, participants in the Cash Balance Plan with five years or more of service were entitled to retirement benefits in the form of an annuity based on a formula that uses a percentage of final average pay and years of service. In 1995, Enron's Board of Directors adopted an amendment to and restatement of the Cash Balance Plan changing the plan's name from the Enron Corp. Retirement Plan to the Enron Corp. Cash Balance Plan. In connection with a change to the retirement benefit formula, all employees became fully vested in retirement benefits earned through December 31, 1994. The formula in place prior to January 1, 1995 was suspended and replaced with a benefit accrual in the form of a cash balance of 5% of eligible annual base pay beginning January 1, 1996. Effective January 1, 2003 Enron suspended future 5% benefit accruals under the Cash Balance Plan. Each employee's accrued benefit will continue to be credited with interest based on ten-year Treasury Bond yields. Enron maintained a noncontributory employee stock ownership plan ("ESOP"), which was merged into the Enron Corp. Savings Plan effective August 30, 2002 and covered all eligible employees. Allocations to individual employees' retirement accounts within the ESOP offset a portion of benefits earned under the Cash Balance Plan prior to December 31, 1994. December 31, 1993 was the final date on which ESOP allocations were made to employees' retirement accounts. The following table sets forth the estimated annual benefits payable under the Cash Balance Plan at normal retirement at age 65, assuming only interest credits based on ten-year Treasury Bond yields and no future 5% 68 benefit accruals after January 1, 2003, with to the Named Officers under the provisions of the foregoing retirement plans.

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

NOTE: The estimated annual benefits payable are based on the straight life annuity form without adjustment for any offset applicable to a participant's retirement subaccount in Enron's ESOP. PENSION PLAN-ONEOK ONEOK's retirement plan is a tax-qualified, defined-benefit pension plan under both the Internal Revenue Code of 1986, as amended, and the Employee Retirement Income Security Act of 1974, as amended. The following table sets forth the estimated annual retirement benefits payable to a non-bargaining unit plan participant based upon the final average pay formulas under ONEOK's retirement plan for employees in the compensation and years-of-service classifications specified. The estimates assume that benefits are received in the form of a single life annuity. PENSION PLAN TABLE

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

Benefits under the ONEOK retirement plan become vested and non-forfeitable after completion of five years of continuous employment. A vested participant receives the monthly retirement benefit at normal retirement age under the retirement plan, unless an early retirement benefit is elected under the plan, in which case the retirement benefit is actuarially reduced for early commencement. Benefits are calculated at retirement date based on a participant's credited service, limited to a maximum of 35 years, and final average earnings. Credited years of service under this plan for the named executive officers as of December 31, 2004 is 1/12 years. For purposes of the table, the annual social security covered compensation benefit $46,284 was used in the excess benefit calculation. 69 Benefits payable under ONEOK's retirement plan are not offset by social security benefits. Under the Internal Revenue Code, the annual compensation of each employee to be taken into account under ONEOK's retirement plan for 2004 cannot exceed $205,000. Amounts shown in the table are estimates only and are subject to adjustment based on rules and regulations applicable to the method of distribution and survivor benefit options selected by the retiree. The compensation covered by the retirement plan benefit formula for non-bargaining unit employees is the base salary and bonus paid to an employee within the employee's final average earnings. Final average earnings means the employee's highest earnings during any 60 consecutive months during the last 120 months of employment. For any named executive officer who retires with vested benefits under the plan, the compensation shown as "Salary" and "Bonus" in the Summary Compensation Table could be considered covered compensation in determining benefits, except that the plan benefit formula takes into account only a fixed percentage of final average earnings which is uniformly applied to all employees. The amount of covered compensation that may be considered in calculating retirement benefits is also subject to limitations in the Internal Revenue Code of 1986, as amended, applicable to the plan. SUPPLEMENTAL EXECUTIVE RETIREMENT ONEOK maintains a Supplemental Executive Retirement Plan ("SERP" for certain of its elected or appointed officers, and certain other employees in a select group of management and highly compensated employees. Participants are selected by ONEOK's Chief Executive Officer, or, in the case of ONEOK's Chief Executive Officer, by the Board of Directors. Effective January 5, 2005, Messrs. Cordes, Peters, Miller and Norton and Ms. Place were named participants. Benefits payable under the SERP are based upon a specified percentage (reduced for early retirement) of the highest 36 consecutive months' compensation of the employee's last 60 months of service. The SERP will, in any case, pay a benefit at least equal to the benefit which would be payable to the participant under ONEOK's retirement plan if limitations imposed by the Internal Revenue Code were not applicable, less the benefit payable under ONEOK's retirement plan with such limitations. Benefits under the SERP are paid concurrently with the payment of benefits under ONEOK's retirement plan or as ONEOK's administrative committee may determine. SERP benefits are offset by benefits payable under our retirement plan, but are not offset by social security benefits ONEOK'S EMPLOYEE NON-QUALIFIED DEFERRED COMPENSATION PLAN The Named Officers are also eligible to participate in ONEOK's Non-Qualified Deferred Compensation Plan. ONEOK's Non-Qualified Deferred Compensation Plan provides select employees, as approved by the Board of Directors, with the option to defer portions of their compensation and provides non-qualified deferred compensation benefits which are not otherwise available due to limitations on employer and employee contributions to qualified defined contribution plans under the federal tax laws. Under the plan, participants have the option to defer their salary and/or bonus 70 compensation to a short-term deferral account, which pays out a minimum of five years from commencement, or to a long-term deferral account, which pays out at retirement or termination of the employment of the participant. Participants are immediately 100 percent vested. Short-term deferral accounts are credited with a deemed investment return based on the five year Treasury Bond fund. Long-term deferral accounts are credited with a deemed investment return based on various investment options, which do not include an option to invest in ONEOK common stock. At the distribution date, cash is distributed to participants based on the fair market value of the deemed investment of the participant at that date. SEVERANCE PLANS Northern Plains' and NBP Services' Severance Pay Plans provide for the payment of benefits to employees who are terminated for failing to meet performance objectives or standards or who are terminated due to reorganization or similar business circumstances. The amount of benefits payable for performance related terminations is based on length of service and may not exceed eight weeks' pay. For those terminated as the result of reorganization or similar business circumstances, the benefit is based on length of service and amount of pay up to a maximum payment of 52 weeks of base pay. The employee must sign a Waiver and Release of Claims Agreement in order to receive any severance benefit. As part of the sale and purchase agreement between ONEOK and CCE Holdings, for a period of twelve months, neither Northern Plains nor NBP Services may take any action that would change the Severance Pay Plans that would have an adverse impact on the employees of Northern Plains or NBP Services. See Item 10. "Directors and Executive Officers of the Registrant" for information on compensation paid to the members of the Partnership Policy Committee and our Audit Committee. 71 ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS. The following table sets forth the beneficial ownership of the voting securities of the Partnership as of March 3, 2005 by our executive officers, members of the Partnership Policy Committee and the Audit Committee who own units and by certain beneficial owners. Other than as set forth below, no person is known by the general partners to own beneficially more than 5% of the voting securities.

Amount and Nature of Beneficial Ownership ----------------------------------------- Common Units ------------------- Number Percent of Units of Class -------- -------- William R. Cordes 1,000 * 13710 FNB Parkway Omaha, NE 68154-5200 Jerry L. Peters (1/) 7,734 * 13710 FNB Parkway Omaha, NE 68154-5200 Pierce H. Norton (2/) 6,778 * 1400 16th Street, Suite 310 Denver, CO 80202 Janet K. Place (3/) 1,691 * 13710 FNB Parkway Omaha, NE 68154-5200 Gary N. Petersen 5,854 * 3520 Wedgewood Ln. N Plymouth, MN 55441-2262 ONEOK, Inc. (4/) 501,603 1.06 100 West Fifth Street Tulsa, OK74103-4298 All Policy Committee Members, Audit 24,001 * Committee Members, nominees and executive officers as a group (16 persons)

---------- * Less than 1%. (1/) Includes 1000 units held by immediate family members for which Mr. Peters has shared voting or investment power. (2/) These units are held in trust for which Mr. Norton has sole voting or investment power. (3/) Includes 500 units held by immediate family members for which Ms. Place has shared voting or investment power. (4/) Indirect ownership through its subsidiaries. Northern Plains is the beneficial owner of 501,603 Common Units which includes 1,603 common units to satisfy obligations under the Amended and Restated Northern Border Phantom Unit Plan. For information on equity compensation plans of the Partnership, see Item 5. "Market for Registrant's Common Equity, Related Stockholder Matters 72 and Issuer Purchases of Equity Securities". ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS. On December 2, 2001, Enron and certain of its subsidiaries filed voluntary petitions for Chapter 11 reorganization under the Bankruptcy Code. During 2004, we had a number of relationships with Enron and its subsidiaries. In November 2004, ONEOK purchased Northern Plains, Pan Border and NBP Services, LLC from CCE Holdings, LLC. CCE Holdings, a joint venture between Southern Union Company and GE Commercial Finance Energy Financial purchased Northern Plains, Pan Border and NBP Services as part of its acquisition of CrossCountry. Through ONEOK's ownership of two of our general partners, ONEOK is able to elect members with a majority of the voting power on the Partnership Policy Committee and Northern Border Pipeline Management Committee. Such other relationships include the following: - With the sale of Northern Plains and NBP Services from CCE Holdings to ONEOK, CCE Holdings and ONEOK entered into a transition services agreement. This transition services agreement provides for the continued use by Northern Plains and NBP Services of certain services, data applications, systems and infrastructure relied on by Northern Plains and NBP Services to perform under the Operating Agreements and Administrative Services Agreement with us or our subsidiaries, as more fully described below. The term of the transition services agreement is until May 16, 2005; the parties may agree to extend any transition service beyond the term. The cost of the transition services is estimated to be $3.9 million for the full term of the agreement. - Northern Plains, a subsidiary of ONEOK, provides certain administrative, operating and management services to the Partnership through Operating Agreements with Northern Border Pipeline, Midwestern Gas Transmission and Viking Gas Transmission. NBP Services, a subsidiary of ONEOK, provides the Partnership services in connection with the operation and management of the Partnership and operating services for Crestone Energy Ventures and Bear Paw Energy pursuant to the terms of an Administrative Services Agreement between the Partnership and NBP Services. For the year ended December 31, 2004, the aggregate amount charged by Northern Plains and NBP Services for their services was approximately $45.8 million. - ONEOK holds contracts for firm transportation on Northern Border Pipeline with expiration dates from December 31, 2004 to March 31, 2009. Revenues from ONEOK for the period from the date of affiliation to December 31, 2004, were $1.1 million. Also, ONEOK has entered into a precedent agreement for capacity on Northern Border Pipeline's Chicago III Expansion Project. - Commencing on July 1, 2004, Northern Plains, was selected on a fixed fee and cost reimbursement basis to provide certain administrative, operating and management services through an Operating Agreement with Guardian Pipeline, of which we own a one third interest. The annual amount of the fixed fee to be charged by Northern Plains for its services is $3.6 million. Guardian Pipeline has agreed to reimburse up to $800,000 of certain of Northern Plains' costs associated with the transition of the role of operator of Guardian Pipeline from Trunkline Gas Company to Northern Plains and has agreed to compensate Northern Plains for any services provided to Guardian Pipeline prior to July 1, 2004. 73 - In conjunction with the selection of Northern Plains as operator of Guardian Pipeline, we agreed to contract with Northern Plains to assume the financial risks and benefits resulting from and arising out of Northern Plains' responsibilities and obligations as operator of Guardian Pipeline. The Partnership Policy Committee, whose members are designated by our three general partners, establishes the business policies of the Partnership. We have three representatives on the Northern Border Management Committee, each of whom votes a portion of our 70% interest on the Northern Border Management Committee, with the other 30% interest being voted by a representative of TC PipeLines, which is an affiliate of one of our general partners. Our general partners (subsidiaries of ONEOK and a subsidiary of TransCanada) and their respective affiliates, currently actively engage or may engage in the businesses in which we engage or in which we may engage in the future. As a result, conflicts of interest may arise between our general partners and their affiliates on the one hand, and the Partnership on the other hand. In such case the members of the Partnership Policy Committee will generally have a fiduciary duty to resolve such conflicts in a manner that is in our best interest. TC PipeLines (a 30% owner of Northern Border Pipeline whose general partner is an affiliate of one of our general partners) and its affiliates are also actively engaged in interstate pipeline transportation of natural gas in the United States separate from their interests in Northern Border Pipeline. As a result, conflicts also may arise between TransCanada and its affiliates or TC PipeLines and its affiliates, on the one hand, and the Northern Border Pipeline on the other hand. If such conflicts arise, the representatives on the Northern Border Pipeline Management Committee will generally have a fiduciary duty to resolve such conflicts in a manner that is in the best interest of Northern Border Pipeline. Unless otherwise provided for in a partnership agreement, the laws of Delaware and Texas generally require a general partner of a partnership to adhere to fiduciary duty standards under which it owes its partners the highest duties of good faith, fairness and loyalty. Similar rules apply to persons serving on the Partnership Policy Committee or the Northern Border Management Committee. Because of the competing interests identified above, our Partnership Agreement and the partnership agreement for Northern Border Pipeline contain provisions that modify certain of these fiduciary duties. For example: - Our Partnership Agreement states that our general partners, their affiliates and their officers and directors will not be liable for damages to us, our limited partners or their assignees for errors of judgment or for any acts or omissions if the general partners and such other persons acted in good faith. - Our Partnership Agreement allows our general partners and our Partnership Policy Committee to take into account the interests of parties in addition to our interest in resolving conflicts of interest. - Our Partnership Agreement provides that the general partners will not be in breach of their obligations under 74 our Partnership Agreement or their duties to us or our unitholders if the resolution of a conflict is fair and reasonable to us. The latitude given in our Partnership Agreement in connection with resolving conflicts of interest may significantly limit the ability of a unitholder to challenge what might otherwise be a breach of fiduciary duty. - Our Partnership Agreement provides that a purchaser of Common Units is deemed to have consented to certain conflicts of interest and actions of the general partners and their affiliates that might otherwise be prohibited and to have agreed that such conflicts of interest and actions do not constitute a breach by the general partners of any duty stated or implied by law or equity. - Our Audit Committee will, at the request of a general partner or a member of the Partnership Policy Committee, review conflicts of interest that may arise between a general partner and its affiliates (or the member of the Partnership Policy Committee designated by it), on the one hand, and the unitholders or us, on the other. Any resolution of a conflict approved by the Audit Committee is conclusively deemed fair and reasonable to us. - The partnership agreement of Northern Border Pipeline that relieves us and TC PipeLines, their affiliates and their transferees from any duty to offer business opportunities to Northern Border Pipeline, subject to specified exceptions. We are required to indemnify the members of the Partnership Policy Committee and general partners, their affiliates and their respective officers, directors, employees, agents and trustees to the fullest extent permitted by law against liabilities, costs and expenses incurred by any such person who acted in good faith and in a manner reasonably believed to be in, or (in the case of a person other than one of the general partners) not opposed to, our best interests and with respect to any criminal proceedings, had no reasonable cause to believe the conduct was unlawful. ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES The following sets forth fees billed for the audit and other services provided by KPMG LLP, the Partnership's principal accountant, for the fiscal years ended December 31, 2004 and December 31, 2003:

Year Ended December 31, ----------------------- 2004 2003 -------- -------- Audit fees (1) $895,250 $431,045 Audit-related fees -- -- Tax Fees (2) -- 855 All Other Fees -- -- -------- -------- Total $895,250 $431,900

(1) Includes fees for the audit of annual financial statements and internal control over financial reporting, reviews of the related quarterly financial statements and related consents and comfort letters for documents filed with the Securities and Exchange Commission. 75 (2) Includes fees related to professional services for tax compliance and consultation. The Audit Committee has considered whether the provision of the non-audit services described above is compatible with maintaining the independence of KPMG LLP and determined that the provision of such services was compatible with maintaining such independence. AUDIT COMMITTEE POLICIES AND PROCEDURES FOR PRE-APPROVAL OF AUDIT AND NON-AUDIT SERVICES Consistent with SEC policies regarding auditor independence, the audit committee is responsible for pre-approving all audit and non-audit services performed by the independent auditor. In addition to its approval of the audit engagement, the audit committee takes action at least annually to authorize the performance by the independent auditor of several specific types of services within the categories of audit services, audit-related services, tax services and all other services. Audit services include assurance and related services that are reasonably related to the performance of the audit or review of the financial statements, attestations pursuant to Section 404 of the Sarbanes-Oxley Act, quarterly reviews comfort letters, consents, review of registration statements, accounting research from completed transactions and tax assistance related to the audit services. Audit-related services include due diligence related to potential business acquisitions/dispositions, accounting research and other audit or attest services. Authorized tax services include compliance-related services such as services involving tax filings, as well as consulting services such as tax planning, transaction analysis and opinions. All other services include special investigations to assist the Audit Committee or its counsel and assistance with regulatory activities. Services are subject to pre-approval of the specific engagement if they are outside the specific types of services included in the periodic approvals covering service categories or if they are in excess of specified fee limitations. The Audit Committee has delegated pre-approval authority to the Audit Committee Chairman. The tax fees for 2003 were pre-approved. 76 PART IV ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES. (a)(1) and (2) Financial Statements and Financial Statement Schedules See "Index to Financial Statements" set forth on page F-1. (A)(3) EXHIBITS 3.1 Northern Border Partners, L.P. Certificate of Limited Partnership, Certificate of Amendment dated February 16, 2001, and Certificate of Amendment dated May 20, 2003. 3.2 Amended and Restated Agreement of Limited Partnership of Northern Border Partners, L.P. dated October 1, 1993. 3.3 Northern Border Intermediate Limited Partnership Certificate of Limited Partnership, Certificate of Amendment dated February 16, 2001, and Certificate of Amendment dated May 20, 2003. *3.4 Form of Amended and Restated Agreement of Limited Partnership for Northern Border Intermediate Limited Partnership (incorporated by reference to Exhibit 10.1 to Form S-1 Registration Statement, Registration No. 33-66158 ("Form S-1")). *4.1 Indenture, dated as of June 2, 2000, between Northern Border Partners, L.P. and Northern Border Intermediate Limited Partnership and Bank One Trust Company, N.A. (incorporated by reference to Exhibit 4.1 to the Partnership's Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2000 (File No. 1-12202) ("June 2000 10-Q")). *4.2 First Supplemental Indenture, dated as of September 14, 2000, between Northern Border Partners, L.P., Northern Border Intermediate Limited Partnership and Bank One Trust Company, N.A. (incorporated by reference to Exhibit 4.2 to the Partnership's Form S-4 Registration Statement, Registration No. 333-46212 ("NBP Form S-4")). *4.3 Indenture, dated as of March 21, 2001, between Northern Border Partners, L.P. and Northern Border Intermediate Limited Partnership and Bank One Trust Company, N.A., Trustee (incorporated by reference to Exhibit 4.3 to the Partnership's Form 10-K for the year ended December 31, 2001 (File No. 1-12202)). *4.4 Indenture, dated as of August 17, 1999, between Northern Border Pipeline Company and Bank One Trust Company, NA, successor to The First National Bank of Chicago, as trustee. (incorporated by reference to Exhibit No. 4.1 to Northern Border Pipeline Company's Form S-4 Registration Statement filed on October 7, 1999, Registration No. 333-88577 ("NB Form S-4")). *4.5 Indenture, dated as of September 17, 2001, between Northern Border Pipeline Company and Bank Trust Company, N.A. (incorporated by reference to Exhibit 4.2 to Northern Border Pipeline Company's Registration Statement on Form S-4 filed on November 13, 2001, Registration No. 333-73282 ("2001 NB Form S-4")). 77 *4.6 Indenture, dated as of April 29, 2002, between Northern Border Pipeline Company and Bank One Trust Company, N.A. (incorporated by reference to Exhibit 4.1 to Northern Border Pipeline Company's Form 10-Q for the quarter ended March 31, 2002 (File No. 333-88577)). *10.1 Northern Border Pipeline Company General Partnership Agreement between Northern Plains Natural Gas Company, Northwest Border Pipeline Company, Pan Border Gas Company, TransCanada Border Pipeline Ltd. and TransCan Northern Ltd., effective March 9, 1978, as amended (incorporated by reference to Exhibit 10.2 to Form S-1). *10.2 Form of Seventh Supplement Amending Northern Border Pipeline Company General Partnership Agreement (incorporated by reference to Exhibit 10.15 to Form S-1). *10.3 Eighth Supplement Amending Northern Border Pipeline Company General Partnership Agreement (incorporated by reference to Exhibit 10.15 to NB Form S-4). *10.4 Ninth Supplement Amending Northern Border Pipeline Company General Partnership Agreement (incorporated by reference to Exhibit 10.37 to 2001 NB Form S-4). *10.5 Tenth Supplement Amending Northern Border Pipeline Company General Partnership Agreement dated March 2, 2005 (incorporated by reference to Exhibit 3.5 to Northern Border Pipeline's Form 10-K filed on March 11, 2005 (File No. 333-88577)). *10.6 Operating Agreement between Northern Border Pipeline Company and Northern Plains Natural Gas Company, dated February 28, 1980 (incorporated by reference to Exhibit 10.3 to Form S-1). *10.7 Administrative Services Agreement between NBP Services Corporation, Northern Border Partners, L.P. and Northern Border Intermediate Limited Partnership (incorporated by reference to Exhibit 10.4 to Form S-1). *10.8 Revolving Credit Agreement, dated as of November 24, 2003, among Northern Border Partners, L.P., SunTrust Bank, Harris Nesbitt Corp., Wachovia Bank, National Association, Citigroup, N.A., SunTrust Capital Markets, Inc., and the Lenders (as named therein) (incorporated by reference to Exhibit 10.7 to the Partnership's Form 10-K for the year ended December 31, 2003 (File No. 1-12202)). *10.9 First Amendment to the Revolving Credit Agreement dated as of April 9, 2004 between Northern Border Partners, L.P., SUNTRUST BANK and the lenders named therein (incorporated by reference to Exhibit 10.1 to the Partnership's Form 10-Q for the quarter ended March 31, 2004 (File No. 1-12202)). *10.10 Second Amendment entered into as of October 25, 2004 to Northern Border Partners' Revolving Credit Agreement dated as of November 24, 2003 (incorporated by reference to Exhibit 99.1 to the Partnership's Form 8-K filed on November 5, 2004 (File No. 1-12202)). *10.11 Revolving Credit Agreement, dated as of May 16, 2002, among Northern Border Pipeline Company, Bank One, NA, Citibank, N.A., Bank of Montreal, SunTrust Bank, Wachovia Bank, National Association, Banc One Capital Markets, Inc, and Lenders (as defined therein) (incorporated by reference to Exhibit 10.1 to the Partnership's Current Report on Form 8-K dated June 26, 2002 (File No. 1-12202)). *10.12 First Amendment to the Revolving Credit Agreement dated as of April 9, 2004 between Northern Border Pipeline Company, Bank One, NA and the lenders named therein. (incorporated by reference to Exhibit No. 10.1 to Northern Border Pipeline 78 Company's Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2004 (File No. 333-88577)). *10.13 Agreement between Northern Plains and Northern Border Intermediate Limited Partnership regarding the costs, expenses and expenditures arising under the operating agreement between Northern Plains and Guardian Pipeline, LLC (incorporated by reference to Exhibit 10.3 to the Partnership's Form 10-Q for the quarter ended March 31, 2004 (File No. 1-12202)). +*10.14 Form of Termination Agreement with ONEOK dated as of January 5, 2005 (incorporated by reference to Exhibit 99.1 to the Partnership's Form 8-K filed on January 11, 2005 (File No. 1-12202)). +*10.15 ONEOK, Inc. 2005 Supplemental Executive Retirement Plan. (incorporated by reference to Exhibit 99.1 to the Partnership's Form 8-K filed on January 11, 2005(File No. 1-12202)). +*10.16 ONEOK, Inc. Long-Term Incentive Plan (incorporated by reference from Exhibit 10(a) to ONEOK's Form 10-K for the year ended December 31, 2001 (File No. 1-13643)). +*10.17 ONEOK, Inc. Form of Restricted Stock Incentive Award (incorporated by reference from Exhibit 10.4 to ONEOK's Form 10-Q for the quarterly period ended September 30, 2004 (File No. 1-13643)). +*10.18 ONEOK, Inc. Form of Performance Shares Award (incorporated by reference from Exhibit 10.5 to ONEOK's Form 10-Q for the quarterly period ended September 30, 2004 (File No. 1-13643)). +*10.19 ONEOK, Inc. Employee Non-Qualified Deferred Compensation Plan, as amended, dated February 2001 (incorporated by reference to Exhibit 10(g) to ONEOK's Form 10-K for the year ended December 31, 2001(File No. 1-13643)). +*10.20 ONEOK, Inc. Annual Officer Incentive Plan (incorporated by reference to Exhibit 10(f) to ONEOK's Form 10-K for the year ended December 31, 2001 (File No. 1-13643)). *10.21 Operating Agreement between Midwestern Gas Transmission Company and Northern Plains Natural Gas Company dated as of April 1, 2001 (incorporated by reference to Exhibit 10.38 to the Partnership's Form 10-K for the year ended December 31, 2001 (File No. 1-12202)). *10.22 Operating Agreement between Viking Gas Transmission Company and Northern Plains Natural Gas Company dated as of January 17, 2003 (incorporated by reference to Exhibit 10.18 to the Partnership's Form 10-K for the year ended December 31, 2002 (File No. 1-12202)). *10.23 Northern Border Pipeline Company Agreement among Northern Plains Natural Gas Company, Pan Border Gas Company, Northwest Border Pipeline Company, TransCanada Border PipeLine Ltd., TransCan Northern Ltd., Northern Border Intermediate Limited Partnership, Northern Border Partners, L.P., and the Management Committee of Northern Border Pipeline, dated as of March 17, 1999 (incorporated by reference to Exhibit 10.21 to the Partnership's Form 10-K/A for the year ended December 31, 1998 (File No. 1-12202) ("1998 10-K")). 79 10.24 Northern Border Transition Services Agreement dated November 17, 2004, by and between ONEOK, Inc. and CCE Holdings, LLC. 12.1 Statement re computation of ratios. 21 List of subsidiaries. 23.1 Consent of KPMG LLP. 31.1 Rule 13a-14(a)/15d-14(a) certification of principal executive officer. 31.2 Rule 13a-14(a)/15d-14(a) Certification of principal financial officer. 32.1 Section 1350 certification of principal executive officer. 32.2 Section 1350 certification of principal financial officer. +*99.1 Northern Border Phantom Unit Plan (incorporated by reference to Exhibit 99.1 to Amendment No. 1 to the Partnership's Form S-8, Registration No. 333-66949 and Exhibit 99.1 to Northern Border Partners, L.P.'s Registration No. 333-72696). * Indicates exhibits incorporated by reference as indicated; all other exhibits are filed herewith. + Management contract, compensatory plan or arrangement. The total amount of securities of the Partnership authorized under any instrument with respect to long-term debt not filed as an exhibit does not exceed 10% of the total assets of the Partnership and its subsidiaries on a consolidated basis. The Partnership agrees, upon request of the Securities and Exchange Commission, to furnish copies of any or all of such instruments to the Securities and Exchange Commission. 80 SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized on this 11th day of March, 2005. NORTHERN BORDER PARTNERS, L.P. (A Delaware Limited Partnership) By: WILLIAM R. CORDES ---------------------------------------- William R. Cordes Chief Executive Officer Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons in the capacities and on the dates indicated.

Signature Title Date --------- ----- ---- /s/ WILLIAM R. CORDES Chief Executive Officer and March 11, 2005 ------------------------------- Member of Partnership Policy William R. Cordes Committee (Principal Executive Officer) /s/ DAVID L. KYLE Chairman of the Partnership ------------------------------- Policy Committee March 11, 2005 David L. Kyle /s/ PAUL E. MILLER Member of Partnership Policy March 11, 2005 ------------------------------- Committee Paul E. Miller /s/ JERRY L. PETERS Chief Financial and March 11, 2005 ------------------------------- Accounting Officer Jerry L. Peters (Principal Financial and Accounting Officer)

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

PAGE NO. ----------- Consolidated Financial Statements Report of Independent Registered Public Accounting Firm F-2 Consolidated Balance Sheet - December 31, 2004 and 2003 F-3 Consolidated Statement of Income - Years Ended F-4 December 31, 2004, 2003 and 2002 Consolidated Statement of Comprehensive Income - Years Ended F-5 December 31, 2004, 2003 and 2002 Consolidated Statement of Cash Flows - Years Ended F-6 December 31, 2004, 2003 and 2002 Consolidated Statement of Changes in Partners' Equity - F-7 Years Ended December 31, 2004, 2003 and 2002 Notes to Consolidated Financial Statements F-8 through F-35 Financial Statements Schedule Report of Independent Registered Public Accounting Firm on Schedule S-1 Schedule II - Valuation and Qualifying Accounts S-2

F-1 REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM Northern Border Partners, L.P.: We have audited the accompanying consolidated balance sheets of Northern Border Partners, L.P. and subsidiaries as of December 31, 2004 and 2003, and the related consolidated statements of income, comprehensive income, cash flows, and changes in partners' equity for each of the years in the three-year period ended December 31, 2004. These consolidated financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Northern Border Partners, L.P. and subsidiaries as of December 31, 2004 and 2003, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2004, in conformity with U.S. generally accepted accounting principles. We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of Northern Border Partners, L.P.'s internal control over financial reporting as of December 31, 2004, based on criteria established in Internal Control--Integrated Framework, issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated March 2, 2005 expressed an unqualified opinion on management's assessment of, and the effective operation of, internal control over financial reporting. /s/ KPMG LLP Omaha, Nebraska March 2, 2005 F-2 NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEET (IN THOUSANDS)

DECEMBER 31, ----------------------- 2004 2003 ---------- ---------- ASSETS CURRENT ASSETS Cash and cash equivalents $ 33,980 $ 35,895 Accounts receivable (net of allowance for doubtful accounts of $9,175 in 2004) 68,930 61,503 Related party receivables (net of allowance for doubtful accounts of $11,988 in 2003) 1,077 -- Materials and supplies, at cost 5,654 7,826 Prepaid expenses 4,642 6,726 Derivative financial instruments 1,996 -- Other 1,008 2,245 ---------- ---------- Total current assets 117,287 114,195 ---------- ---------- PROPERTY, PLANT AND EQUIPMENT Interstate Natural Gas Pipelines 2,626,579 2,612,241 Gas Gathering and Processing 265,484 253,903 Coal Slurry 47,402 45,911 ---------- ---------- Total property, plant and equipment 2,939,465 2,912,055 Less: Accumulated provision for depreciation and amortization 1,002,041 919,951 ---------- ---------- Property, plant and equipment, net 1,937,424 1,992,104 ---------- ---------- INVESTMENTS AND OTHER ASSETS Investment in unconsolidated affiliates 273,202 268,166 Goodwill 152,782 152,782 Derivative financial instruments 2,555 19,553 Other 27,306 23,783 ---------- ---------- Total investments and other assets 455,845 464,284 ---------- ---------- Total assets $2,510,556 $2,570,583 ========== ========== LIABILITIES AND PARTNERS' EQUITY CURRENT LIABILITIES Current maturities of long-term debt $ 5,126 $ 7,740 Accounts payable 28,802 20,834 Related party payables 6,293 25,698 Accrued taxes other than income 32,563 33,708 Accrued interest 16,530 13,206 Derivative financial instruments -- 5,736 ---------- ---------- Total current liabilities 89,314 106,922 ---------- ---------- LONG-TERM DEBT, net of current maturities 1,325,232 1,408,246 ---------- ---------- MINORITY INTERESTS IN PARTNERS' EQUITY 290,142 240,731 ---------- ---------- RESERVES AND DEFERRED CREDITS Deferred income taxes 7,186 2,898 Other 9,348 11,213 ---------- ---------- Total reserves and deferred credits 16,534 14,111 ---------- ---------- COMMITMENTS AND CONTINGENCIES (NOTE 13) PARTNERS' EQUITY General partners 15,603 15,902 Common units (46,397,214 units issued and outstanding at December 31, 2004 and 2003) 764,550 779,195 Accumulated other comprehensive income 9,181 5,476 ---------- ---------- Total partners' equity 789,334 800,573 ---------- ---------- Total liabilities and partners' equity $2,510,556 $2,570,583 ========== ==========

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

YEAR ENDED DECEMBER 31, ------------------------------ 2004 2003 2002 -------- -------- -------- OPERATING REVENUES $590,383 $550,948 $487,204 -------- -------- -------- OPERATING EXPENSES Product purchases 103,213 80,774 50,648 Operations and maintenance 111,142 127,623 106,521 Depreciation and amortization, including impairment charges of $219,080 in 2003 86,431 299,791 74,672 Taxes other than income 36,212 35,443 32,194 -------- -------- -------- Operating expenses 336,998 543,631 264,035 -------- -------- -------- OPERATING INCOME 253,385 7,317 223,169 -------- -------- -------- INTEREST EXPENSE Interest expense 77,346 79,159 83,227 Interest expense capitalized (403) (179) (329) -------- -------- -------- Interest expense, net 76,943 78,980 82,898 -------- -------- -------- OTHER INCOME (EXPENSE) Allowance for equity funds used during construction 117 331 248 Equity earnings of unconsolidated affiliates 18,015 18,815 12,983 Other income 3,654 5,992 2,740 Other expense (2,138) (1,459) (801) -------- -------- -------- Other income, net 19,648 23,679 15,170 -------- -------- -------- MINORITY INTERESTS IN NET INCOME 50,033 44,460 42,816 -------- -------- -------- INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES 146,057 (92,444) 112,625 INCOME TAXES 5,136 4,705 1,643 -------- -------- -------- INCOME (LOSS) FROM CONTINUING OPERATIONS 140,921 (97,149) 110,982 DISCONTINUED OPERATIONS, NET OF TAX 3,799 9,338 2,694 CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE, NET OF TAX -- (643) -- -------- -------- -------- NET INCOME (LOSS) TO PARTNERS $144,720 $(88,454) $113,676 ======== ======== ======== CALCULATION OF LIMITED PARTNERS' INTEREST IN NET INCOME (LOSS): Net income (loss) to partners $144,720 $(88,454) $113,676 Less: general partners' interest in net income (loss) 10,854 5,969 9,602 -------- -------- -------- Limited partners' interest in net income (loss) $133,866 $(94,423) $104,074 ======== ======== ======== LIMITED PARTNERS' PER UNIT NET INCOME (LOSS): Income (loss) from continuing operations $ 2.81 $ (2.27) $ 2.38 Discontinued operations, net of tax 0.08 0.20 0.06 Cumulative effect of change in accounting principle, net of tax -- (0.01) -- -------- -------- -------- Net income (loss) $ 2.89 $ (2.08) $ 2.44 ======== ======== ======== NUMBER OF UNITS USED IN COMPUTATION 46,397 45,370 42,709 ======== ======== ========

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

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

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

YEAR ENDED DECEMBER 31, --------------------------------- 2004 2003 2002 --------- --------- --------- CASH FLOWS FROM OPERATING ACTIVITIES: Net income (loss) to partners $ 144,720 $ (88,454) $ 113,676 --------- --------- --------- Adjustments to reconcile net income (loss) to partners to net cash provided by operating activities: Depreciation and amortization, including impairment charges of $219,080 in 2003 87,203 301,977 76,239 Minority interests in net income 50,033 44,460 42,816 Non-cash gains from risk management activities (460) (209) (4,509) Provision for regulatory refunds -- 261 10,000 Regulatory refunds paid -- (10,261) -- Cumulative effect of change in accounting principle -- 643 -- Gain on sale of gathering and processing assets (6,621) (4,872) -- Equity earnings in unconsolidated affiliates (18,015) (18,928) (14,570) Distributions received from unconsolidated affiliates 13,946 16,262 10,820 Allowance for equity funds used during construction (117) (331) (248) Reserves and deferred credits (2,747) 4,472 (24) Changes in components of working capital (19,243) (18,592) 9,670 Other (4,041) (1,768) 136 --------- --------- --------- Total adjustments 99,938 313,114 130,330 --------- --------- --------- Net cash provided by operating activities 244,658 224,660 244,006 --------- --------- --------- CASH FLOWS FROM INVESTING ACTIVITIES: Capital expenditures for property, plant and equipment, net (43,477) (30,282) (50,738) Acquisition of businesses -- (123,194) (1,561) Sale of gathering and processing assets 22,685 40,250 -- Investments in unconsolidated affiliates and other (84) (3,514) (2,972) --------- --------- --------- Net cash used in investing activities (20,876) (116,740) (55,271) --------- --------- --------- CASH FLOWS FROM FINANCING ACTIVITIES: Cash distributions General and limited partners (159,624) (155,173) (146,960) Minority Interests (61,690) (46,194) (49,238) Equity contributions from Minority Interests 61,500 -- -- Issuance of partnership interests, net (40) 102,203 75,376 Issuance of long-term debt, net 259,000 342,000 499,894 Retirement of long-term debt (327,521) (361,129) (567,540) Proceeds upon termination of derivatives 7,575 12,250 20,551 Debt reacquisition costs (4,897) -- -- Long-term debt financing costs -- (671) (2,884) --------- --------- --------- Net cash used in financing activities (225,697) (106,714) (170,801) --------- --------- --------- NET CHANGE IN CASH AND CASH EQUIVALENTS (1,915) 1,206 17,934 Cash and cash equivalents-beginning of year 35,895 34,689 16,755 --------- --------- --------- Cash and cash equivalents-end of year $ 33,980 $ 35,895 $ 34,689 ========= ========= ========= Changes in components of working capital: Accounts receivable $ (12,992) $ (3,135) $ 4,303 Materials and supplies, prepaid expenses and other 3,355 (3,833) (2,573) Accounts payable (10,065) (8,525) 9,370 Accrued taxes other than income (1,145) 437 2,378 Accrued interest 1,604 (3,536) (3,808) --------- --------- --------- Total $ (19,243) $ (18,592) $ 9,670 ========= ========= =========

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

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

The accompanying notes are an integral part of these consolidated financial statements. F-7 NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 1. ORGANIZATION AND MANAGEMENT Northern Border Partners, L.P., through a subsidiary limited partnership, Northern Border Intermediate Limited Partnership, both Delaware limited partnerships, collectively referred to herein as the Partnership, owns a 70% general partner interest in Northern Border Pipeline Company (Northern Border Pipeline). The remaining 30% general partner interest in Northern Border Pipeline is owned by TC PipeLines Intermediate Limited Partnership (TC PipeLines). Crestone Energy Ventures, L.L.C. (Crestone Energy Ventures); Bear Paw Energy, L.L.C. (Bear Paw Energy); Border Midstream Services, Ltd. (Border Midstream); Midwestern Gas Transmission Company (Midwestern Gas Transmission); Viking Gas Transmission Company (Viking Gas Transmission) and Black Mesa Pipeline, Inc. (Black Mesa) are wholly-owned subsidiaries of the Partnership. As discussed in Note 3, the Partnership acquired all of the common stock of Viking Gas Transmission on January 17, 2003. Northern Plains Natural Gas Company, LLC (Northern Plains), a wholly-owned subsidiary of ONEOK, Inc. (ONEOK), Pan Border Gas Company, LLC (Pan Border), a wholly-owned subsidiary of Northern Plains, and Northwest Border Pipeline Company (Northwest Border), a wholly-owned subsidiary of TransCanada PipeLines Limited, which is a subsidiary of TransCanada Corporation, and affiliate of TC PipeLines, serve as the General Partners of the Partnership and collectively own a 2% general partner interest in the Partnership. Northern Plains and Pan Border hold an aggregate 1.65% general partner interest and Northwest Border holds a 0.35% general partner interest. Northern Plains also owns common units representing a 1.1% limited partner interest. The Partnership is managed under the direction of the Partnership Policy Committee consisting of one person appointed by each General Partner. The members appointed by Northern Plains, Pan Border and Northwest Border have 50%, 32.5% and 17.5%, respectively, of the voting interest on the Partnership Policy Committee. In November 2004, ONEOK purchased Northern Plains, Pan Border and NBP Services LLC (NBP Services) from CCE Holdings, LLC (CCE Holdings). CCE Holdings, a joint venture between Southern Union Company and GE Commercial Finance Energy Financial purchased Northern Plains, Pan Border and NBP Services as part of its acquisition of CrossCountry Energy, LLC (CrossCountry). On March 31, 2004, Enron Corp. (Enron) transferred its ownership interest in Northern Plains, Pan Border, and NBP Services to CrossCountry. In addition, CrossCountry and Enron entered into a transition services agreement pursuant to which Enron would provide to CrossCountry, on an interim, transitional basis, various services, including but not limited to (i) information technology services, (ii) accounting system usage rights and administrative support and (iii) payroll, employee benefits and administrative services. In turn, these services are provided to the Partnership through Northern Plains and NBP Services. F-8 NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 1. ORGANIZATION AND MANAGEMENT (continued) As part of the closing, ONEOK and CCE Holdings entered into a transition services agreement referred to as the "Northern Border Transition Services Agreement" covering certain transition services by and among ONEOK, CCE Holdings and Enron for a period of six months. Certain of the services previously provided by Enron are now being provided through ONEOK. The Partnership has entered into an administrative services agreement with NBP Services, a wholly-owned subsidiary of ONEOK. NBP Services provides certain administrative, operating and management services for the Partnership and its gas gathering and processing and coal slurry businesses and is reimbursed for its direct and indirect costs and expenses. The day-to-day management of Northern Border Pipeline's, Midwestern Gas Transmission's and Viking Gas Transmission's affairs is the responsibility of Northern Plains, as defined by their respective operating agreements with Northern Plains. Northern Border Pipeline, Midwestern Gas Transmission and Viking Gas Transmission are charged for the salaries, benefits and expenses of Northern Plains. Northern Plains and NBP Services also utilize their current and former affiliates for management services including those provided through the Northern Border Transition Services Agreement. For the years ended December 31, 2004, 2003 and 2002, charges from NBP Services, Northern Plains and their current and former affiliates totaled approximately $45.8 million, $57.6 million and $45.3 million, respectively. See Note 18 for a discussion of the Partnership's previous relationships with Enron and developments involving Enron. Northern Border Pipeline is a Texas general partnership formed in 1978. Northern Border Pipeline owns a 1,249-mile natural gas transmission pipeline system extending from the United States-Canadian border near Port of Morgan, Montana, to a terminus near North Hayden, Indiana. Northern Border Pipeline is managed by a Management Committee that includes three representatives from the Partnership (one representative appointed by each of the General Partners of the Partnership) and one representative from TC PipeLines. The Partnership's representatives selected by Northern Plains, Pan Border and Northwest Border have 35%, 22.75% and 12.25%, respectively, of the voting interest on the Northern Border Pipeline Management Committee. The representative designated by TC PipeLines votes the remaining 30% interest. Midwestern Gas Transmission system consists of a 350-mile interstate natural gas pipeline extending from Portland, Tennessee to Joliet, Illinois. Midwestern Gas Transmission's pipeline system connects with multiple pipeline systems, including Northern Border Pipeline. On January 17, 2003, the Partnership acquired Viking Gas Transmission (see Note 3). The Viking Gas Transmission system is a 578-mile interstate natural gas pipeline extending from the United States-Canadian border near Emerson, Manitoba to Marshfield, Wisconsin. Viking Gas Transmission connects with multiple pipeline systems. Bear Paw Energy has extensive natural gas gathering, processing and fractionation operations in the Williston Basin in Montana, North Dakota and Saskatchewan as well as gas gathering operations in the Powder River Basin F-9 NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 1. ORGANIZATION AND MANAGEMENT (continued) in Wyoming. In the Williston Basin, Bear Paw Energy has over 3,000 miles of gathering pipelines and five processing plants with 93 million cubic feet per day of capacity. Bear Paw Energy has approximately 600 miles of high and low pressure gathering pipelines and approximately 390,000 acres of dedicated reserves in the Powder River Basin. Border Midstream previously owned the Mazeppa and Gladys gas processing plants, gas gathering systems and an undivided minority interest in the Gregg Lake/Obed Pipeline. In June 2003, the Partnership sold its Gladys and Mazeppa processing plants and related gas gathering facilities. Effective December 1, 2004, the Partnership sold its undivided minority interest in the Gregg Lake/Obed Pipeline (see Note 3). The Partnership owns a 49% common membership interest and a 100% preferred A share interest in Bighorn Gas Gathering, L.L.C. (Bighorn); a 33% interest in Fort Union Gas Gathering, L.L.C. (Fort Union); a 35% interest in Lost Creek Gathering, L.L.C. (Lost Creek); and a 33% interest in Guardian Pipeline, L.L.C. (Guardian Pipeline). The Partnership acquired its interest in Guardian Pipeline in January 2003 (see Note 3). Collectively, Bighorn, Fort Union and Lost Creek own over 300 miles of gas gathering facilities in Wyoming. The gathering facilities interconnect to the interstate gas pipeline grid serving gas markets in the Rocky Mountains, the Midwest and California. Guardian Pipeline is a 141-mile interstate natural gas pipeline system that went into service on December 7, 2002. This system transports natural gas from Joliet, Illinois to a point west of Milwaukee, Wisconsin. Black Mesa owns a 273-mile, 18-inch diameter coal slurry pipeline that originates at a coal mine in Kayenta, Arizona and ends at the 1,500 megawatt Mohave Generating Station located in Laughlin, Nevada. 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (A) Principles of Consolidation and Use of Estimates The consolidated financial statements include the assets, liabilities and results of operations of the Partnership and its majority-owned subsidiaries. The Partnership operates through a subsidiary limited partnership of which the Partnership is the sole limited partner and the General Partners are the sole general partners. The 30% ownership of Northern Border Pipeline by TC PipeLines is accounted for as a minority interest. All significant intercompany balances and transactions have been eliminated in consolidation. The preparation of financial statements in conformity with U.S. generally accepted accounting principles (GAAP) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. F-10 NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued) (B) Government Regulation Northern Border Pipeline, Midwestern Gas Transmission, Viking Gas Transmission and Guardian Pipeline are subject to regulation by the Federal Energy Regulatory Commission (FERC). Northern Border Pipeline's and Viking Gas Transmission's accounting policies conform to Statement of Financial Accounting Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation." Accordingly, certain assets that result from the regulated ratemaking process are recorded that would not be recorded under accounting principles generally accepted in the United States of America for nonregulated entities. Northern Border Pipeline and Viking Gas Transmission continually assess whether the recovery of the regulatory assets are probable by such factors as regulatory changes and the impact of competition. Northern Border Pipeline and Viking Gas Transmission believe the recovery of the existing regulatory assets is probable. If future recovery ceases to be probable, Northern Border Pipeline and Viking Gas Transmission would be required to write off the regulatory assets at that time. At December 31, 2004 and 2003, Northern Border Pipeline and Viking Gas Transmission have reflected regulatory assets, which are currently being recovered or are expected to be recovered from their shippers, of approximately $12.3 million and $8.9 million, respectively, on the consolidated balance sheet. Northern Border Pipeline is recovering the regulatory assets from its shippers over varying time periods, which range from five to 44 years. Viking Gas Transmission is recovering the regulatory assets from its shippers over five years. Although Northern Border Pipeline is a general partnership, Northern Border Pipeline's tariff establishes the method of accounting for and calculating income taxes and requires Northern Border Pipeline to reflect in its financial records the income taxes, which would have been paid or accrued if Northern Border Pipeline were organized during the period as a corporation. As a result, for purposes of determining transportation rates in calculating the return allowed by the FERC, partners' capital and rate base are reduced by the amount equivalent to the net accumulated deferred income taxes. Such amounts were approximately $355 million and $350 million at December 31, 2004 and 2003, respectively, and are primarily related to accelerated depreciation and other plant-related differences. (C) Cash and Cash Equivalents Cash equivalents consist of highly liquid investments with original maturities of three months or less. The carrying amount of cash and cash equivalents approximates fair value because of the short maturity of these investments. (D) Revenue Recognition Northern Border Pipeline, Midwestern Gas Transmission and Viking Gas Transmission transport gas for shippers under tariffs regulated by the FERC. The tariffs specify the calculation of amounts to be paid by shippers and the general terms and conditions of transportation service F-11 NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued) (D) Revenue Recognition (continued) on the respective pipeline systems. Operating revenues are derived from agreements for the receipt and delivery of gas at points along the pipeline system as specified in each shipper's individual transportation contract. Revenues for the natural gas pipelines are recognized based upon contracted capacity and actual volumes transported under transportation service agreements. Northern Border Pipeline, Midwestern Gas Transmission and Viking Gas Transmission do not own the gas that they transport, and therefore do not assume the related natural gas commodity risk. For the gas gathering and processing businesses, operating revenue is recorded when gas is processed in or transported through company facilities. The gas gathering and processing businesses also receive certain cash payments from customers in advance for gathering services to be provided in the future. These cash payments are deferred and recognized into operating revenues by using a percentage based on the depletion of natural gas reserves associated with the gathering system. Black Mesa's operating revenue is derived from a pipeline transportation agreement. Black Mesa's revenue is recognized based on a monthly demand payment, actual tons transported and direct reimbursement of certain other expenses. Accounts receivable from customers are reviewed regularly for collectibility. An allowance for doubtful accounts is recorded in situations where collectibility is not reasonably assured. (E) Income Taxes The Partnership is not a taxable entity for federal income tax purposes. As such, the Partnership does not directly pay federal income tax. The Partnership's taxable income or loss, which may vary substantially from the net income or loss reported in the consolidated statement of income, is includable in the federal income tax returns of each partner. The aggregate difference in the basis of the Partnership's net assets for financial and income tax purposes cannot be readily determined as the Partnership does not have access to information about each partner's tax attributes related to the Partnership. The Partnership's corporate subsidiaries are required to pay federal and state income taxes. Income taxes are accounted for under the asset and liability method. Deferred income tax assets and liabilities are recognized by these entities for the future tax consequences attributable to differences between the financial statement carrying amount of existing assets and liabilities and their respective tax bases and operating loss carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. F-12 NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued) (F) Property, Plant and Equipment and Related Depreciation and Amortization Property, plant and equipment is stated at original cost. During periods of construction, utilities are permitted to capitalize an allowance for funds used during construction, which represents the estimated costs of funds used for construction purposes. Property, plant and equipment on the consolidated balance sheet includes construction work in progress of $13.8 million and $17.5 million at December 31, 2004 and 2003, respectively. The original cost of utility property retired is charged to accumulated depreciation and amortization, net of salvage and cost of removal. For utility property, no retirement gain or loss is included in income except in the case of retirements or sales of entire operating units. Maintenance and repairs are charged to operations in the period incurred. For utility property, the provision for depreciation and amortization is an integral part of the interstate pipelines' FERC tariffs. The effective depreciation rate applied to Northern Border Pipeline's, Midwestern Gas Transmission's and Viking Gas Transmission's transmission plant was 2.25%, 1.9% and 2.0%, respectively. Composite rates are applied to all other functional groups of utility property having similar economic characteristics. The effective depreciation rate applied to natural gas gathering and processing assets ranges from 5% to 20%. The effective depreciation rate applied to coal slurry assets ranges from 4% to 20%. The Partnership evaluates impairment of long-lived assets in accordance with SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets." Long-lived assets are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of the carrying amount of assets is measured by a comparison of the carrying amount of the asset to future net cash flows expected to be generated by the asset. If such assets are considered to be impaired, the impairment to be recognized is measured by the amount by which the carrying amount of the assets exceeds the fair value of the assets. (G) Foreign Currency Translation For the Partnership's Canadian subsidiary, Border Midstream, asset and liability accounts are translated from its functional currency (the Canadian dollar) at year-end rates of exchange and revenue and expenses are translated at average exchange rates prevailing during the year. Translation adjustments are included as a separate component of other comprehensive income and partners' equity. Currency transaction gains and losses, which result when Border Midstream pays Canadian dollars to the Partnership, are recorded in other income (expense) and discontinued operations on the consolidated statement of income. During the years ended December 31, 2004 and 2003, the Partnership recorded currency transaction gains of $2.2 million and $6.0 million, respectively. Currency transaction gains were insignificant in 2002. F-13 NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued) (H) Goodwill The excess of cost over fair value of the net assets acquired in business acquisitions is accounted for as goodwill. The Partnership's accounting for goodwill is in accordance with SFAS No. 142, "Goodwill and Other Intangible Assets." Among other things, SFAS No. 142 requires entities to perform annual impairment tests by applying a fair-value-based analysis on the goodwill in each reporting segment. (I) Equity Method of Accounting The Partnership accounts for its investments, which it does not control, by the equity method of accounting. Under this method, an investment is carried at its acquisition cost, plus the equity in undistributed earnings or losses since acquisition. (J) Risk Management The Partnership uses financial instruments in the management of its interest rate and commodity price exposure. A control environment has been established which includes policies and procedures for risk assessment and the approval, reporting and monitoring of financial instrument activities. The Partnership does not use these instruments for trading purposes. SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities," as amended by SFAS No. 137 and SFAS No. 138, requires that every derivative instrument (including certain derivative instruments embedded in other contracts) be recorded on the balance sheet as either an asset or liability measured at its fair value. The statement requires that changes in the derivative's fair value be recognized currently in earnings unless specific hedge accounting criteria are met. Special accounting for qualifying hedges allows a derivative's gains and losses to offset related results on the hedged item in the income statement, and requires that a company formally document, designate and assess the effectiveness of transactions that receive hedge accounting. See Note 9 for a discussion of the Partnership's derivative instruments and hedging activities. (K) Reclassifications Certain reclassifications have been made to the consolidated financial statements for prior years to conform with the current year presentation. 3. BUSINESS ACQUISITIONS AND DISPOSITIONS On January 17, 2003, the Partnership acquired all of the common stock of Viking Gas Transmission including a one-third interest in Guardian Pipeline for approximately $162 million, which included the assumption of $40 million of debt. The Partnership has accounted for the acquisition using the purchase method of accounting and accordingly, operations of Viking Gas Transmission have been included since the date of acquisition. The purchase price has been F-14 NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 3. BUSINESS ACQUISITIONS AND DISPOSITIONS (continued) allocated based upon the estimated fair value of the assets and liabilities acquired as of the acquisition date. The investment in Guardian Pipeline is reflected in investments in unconsolidated affiliates on the consolidated balance sheet. The following is a summary of the effects of the acquisition on the Partnership's consolidated financial position as of December 31, 2003 (amounts in thousands): Current assets $ 8,804 Property, plant and equipment 127,619 Investments in unconsolidated affiliates 27,600 Goodwill and other assets 5,035 Current liabilities (5,559) Long-term debt, including current maturities (40,025) Other liabilities (280) -------- $123,194 ======== Border Midstream sold its undivided minority interest in the Gregg Lake/Obed Pipeline (Gregg Lake/Obed) for $14.0 million, effective December 1, 2004. In June 2003, the Partnership sold its Gladys and Mazeppa processing plants and related gas gathering facilities located in Alberta, Canada for approximately $40.3 million. Operating revenues, operating expenses and other income and expense for 2003 and 2002 have been reclassified for amounts related to the discontinued operations. Operating revenues for discontinued operations for the years ended December 31, 2004, 2003 and 2002, were $3.0 million, $9.9 million and $8.1 million, respectively. Discontinued operations on the accompanying consolidated statement of income consists of the following:

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

4. GOODWILL AND ASSET IMPAIRMENT At December 31, 2004 and 2003, the Partnership's balance sheet included goodwill of approximately $334 million. Of the total goodwill, approximately $182 million was recorded in the Partnership's investment in unconsolidated affiliates at December 31, 2004 and 2003. The Partnership has selected the fourth quarter to perform its annual impairment testing. If testing indicates an impairment of goodwill exists in a reporting segment, the carrying value of tangible assets in that segment are also tested for impairment under SFAS No. 144. During 2003, due to lower throughput volumes experienced and anticipated in its wholly owned subsidiaries in its natural gas gathering and processing business segment, the Partnership accelerated its annual impairment test F-15 NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 4. GOODWILL AND ASSET IMPAIRMENT (continued) under SFAS No. 142 from the fourth quarter to the third quarter for this segment. For the Partnership's remaining reporting segments, the annual impairment testing was performed in the fourth quarter. In future years, unless conditions indicate earlier testing is needed, the annual impairment testing for all business segments will occur in the fourth quarter. The Partnership engaged the services of an outside independent consultant to assist in the determination of fair value, as defined by SFAS No. 142, for purposes of computing the amount of the goodwill impairment. Upon the determination of the existence of a goodwill impairment, the Partnership further analyzed, under SFAS No. 144, the carrying value of the tangible assets in its wholly owned subsidiaries in its natural gas gathering and processing business segment to determine the impairment attributed to the tangible assets. The Partnership recorded total impairment charges of $219.1 million in the third quarter of 2003. This was comprised of $76.0 million related to the tangible assets in the Powder River Basin and $143.1 million for the goodwill related to the natural gas gathering and processing business segment. Beginning October 1, 2003, the estimated depreciable life of the Partnership's assets in the Powder River Basin was reduced from 30 years to 15 years to reflect the results of the analysis performed. Changes in the carrying amount of goodwill for the years ended December 31, 2004 and 2003, are summarized as follows:

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

5. ASSET RETIREMENT OBLIGATIONS In 2001, the Financial Accounting Standards Board (FASB) issued SFAS No. 143, "Accounting for Asset Retirement Obligations." SFAS No. 143 requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred, if the liability can be reasonably estimated. When the liability is initially recorded, the carrying amount of the related asset is increased by the same amount. Over time, the liability is accreted to its future value and the accretion is recorded to expense. The initial adjustment to the asset is depreciated over its useful life. Upon settlement of the liability, an entity either settles the obligation for its recorded amount or incurs a gain or loss. In some instances, the Partnership's subsidiaries are obligated by contractual terms or regulatory requirements to remove facilities or perform other remediation upon retirement. The Partnership has, where possible, developed its estimate of the retirement obligations. F-16 NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 5. ASSET RETIREMENT OBLIGATIONS (continued) Effective January 1, 2003, the Partnership adopted SFAS No. 143. The implementation of SFAS No. 143 resulted in an increase in net property, plant and equipment of $2.5 million, an increase in reserves and deferred credits of $3.1 million and a reduction to net income of $0.6 million for the net-of-tax cumulative effect of change in accounting principle. The impact of SFAS No. 143 on prior periods' results of operations is immaterial. A reconciliation of the beginning and ending aggregate carrying amount of the Partnership's asset retirement obligations for the years ended December 31, 2004 and 2003, is as follows (in thousands): Balance at December 31, 2002 $ -- Cumulative effect of transition adjustment 3,496 Accretion expense 159 Liabilities transferred with asset sales (2,016) ------- Balance at December 31, 2003 1,639 Accretion expense 102 ------- Balance at December 31, 2004 $ 1,741 ======= 6. RATES AND REGULATORY ISSUES The FERC regulates the rates and charges for transportation on the Partnership's interstate natural gas pipelines. Interstate natural gas pipeline companies may not charge rates that have been determined not to be just and reasonable by the FERC. Generally, rates for interstate pipelines are based on the cost of service including recovery of and a return on the pipeline's actual prudent historical cost investment. The rates and terms and conditions for service are found in each pipeline's FERC approved tariff. Under its tariff, an interstate pipeline is allowed to charge for its services on the basis of stated transportation rates. Transportation rates are established periodically in FERC proceedings known as rate cases. The tariff also allows the interstate pipeline to provide services under negotiated and discounted rates. Under the terms of settlement in Northern Border Pipeline's 1999 rate case, neither Northern Border Pipeline nor its existing shippers can seek rate changes to the settlement base rates until November 1, 2005, at which time Northern Border Pipeline must file a new rate case. Midwestern Gas Transmission and Viking Gas Transmission have no timing requirements or restriction in regard to future rate case filings. In February 2003, Northern Border Pipeline filed to amend its FERC tariff to clarify the definition of company use gas, which is gas supplied by its shippers for its operations. Northern Border Pipeline had included in its retention of company use gas, quantities that were equivalent to the cost of electric power at its electric-driven compressor stations during the period of June 2001 through January 2003. On March 27, 2003, the FERC issued an order rejecting Northern Border Pipeline's proposed tariff sheet revision and requiring refunds with interest within 90 days of the order. Northern Border Pipeline made refunds to its shippers of $10.3 million in May 2003. 7. TRANSPORTATION, GATHERING AND PROCESSING AGREEMENTS Northern Border Pipeline's, Midwestern Gas Transmission's and Viking Gas Transmission's operating revenues are collected pursuant to their FERC tariffs through transportation service agreements. Northern Border Pipeline's firm service agreements extend for various terms with F-17 NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 7. TRANSPORTATION, GATHERING AND PROCESSING AGREEMENTS termination dates that range from December 2004 to December 2013. The termination dates for Midwestern Gas Transmission's firm service agreements range from December 2004 to October 2019. The termination dates for Viking Gas Transmission's firm service agreements range from March 2005 to October 2014. Northern Border Pipeline, Midwestern Gas Transmission and Viking Gas Transmission also have interruptible transportation service agreements and other transportation service agreements with numerous shippers. Under the capacity release provisions of Northern Border Pipeline's, Midwestern Gas Transmission's and Viking Gas Transmission's FERC tariffs, shippers are allowed to release all or part of their capacity either permanently for the full term of the contract or temporarily. A temporary capacity release does not relieve the original contract shipper from its payment obligations if the replacement shipper fails to pay for the capacity temporarily released to it. For the interstate natural gas pipeline segment, Northern Border Pipeline's revenues represented approximately 86%, 86% and 95% of the segment's revenues in 2004, 2003 and 2002, respectively. At December 31, 2004, Northern Border Pipeline's largest shippers, Nexen Marketing, U.S.A. Inc (Nexen), BP Canada Energy Marketing Corp. (BP Canada), EnCana Marketing U.S.A. Inc. (EnCana) and Cargill Incorporated (Cargill), were obligated for approximately 18%, 14%, 13% and 12% of the summer design capacity, respectively. The Nexen, BP Canada, Encana and Cargill firm service agreements extend for various terms with termination dates from March 2005 to December 2013, December 2004 to February 2012, October 2005 to June 2009 and March 2005 to December 2008, respectively. For the year ending December 31, 2004, shippers providing significant operating revenues were BP Canada and Encana with revenues of $65.6 million and $56.3 million, respectively. For the year ended December 31, 2003, Northern Border Pipeline's significant shippers were BP Canada, EnCana, and Pan-Alberta Gas (U.S) Inc. (Pan Alberta) with operating revenues of $54.7 million, $32.9 million and $45.5 million, respectively. For the year ended December 31, 2002, Northern Border Pipeline's largest shippers were Pan-Alberta and Mirant Americas Energy Marketing, LP with combined operating revenues of $105.5 million. At December 31, 2004, Northern Border Pipeline had contracted firm capacity held by one shipper affiliated with its general partners. ONEOK Energy Services Company L.P. (ONEOK Energy Services), a subsidiary of ONEOK, holds firm service agreements representing 3% of summer design capacity. The firm service agreements with ONEOK Energy Services extend for various terms with termination dates that range from March 2005 to March 2009. ONEOK Energy Services became affiliated with Northern Border Pipeline on November 17, 2004 in connection with ONEOK's purchase of Northern Plains. Revenues from ONEOK Energy Services for the period from the date of affiliation to December 31, 2004 were $1.1 million. At December 31, 2004, Northern Border Pipeline had an outstanding receivable from ONEOK Energy Services of $0.8 million. In 2003, there were no operating revenues from affiliates. In 2002, one of Northern Border Pipeline's shippers was affiliated with its general partners. Operating revenues from affiliates were $1.4 million for the year ended December 31, 2002. F-18 NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 7. TRANSPORTATION, GATHERING AND PROCESSING AGREEMENTS (continued) The gas gathering and processing businesses provide services for gathering, treating, processing and compression of natural gas and the fractionation of natural gas liquids. For the year ended December 31, 2004, Bear Paw Energy's largest customers, Lodgepole Energy Marketing (Lodgepole), BP Canada Energy Marketing Corp. (BP Canada) and Montana Dakota Utilities accounted for $82.0 million (44%), $26.7 million (14%) and $21.7 million (12%), respectively of Bear Paw Energy's operating revenues. For the year ended December 31, 2003, Bear Paw Energy's largest customers, Lodgepole, Tenaska Marketing Ventures (Tenaska) and BP Canada accounted for $62.4 million (40%), $27.3 million (18%) and $16.6 million (11%), respectively, of Bear Paw Energy's operating revenue. For the year ended December 31, 2002, Bear Paw Energy's largest customers, Lodgepole and Tenaska accounted for $44.2 million (35%) and $20.2 million (16%), respectively, of Bear Paw Energy's operating revenue. Crestone Energy Venture's revenues from affiliates totaled $0.2 million, $0.1 million and $0.2 million in 2004, 2003 and 2002, respectively. Black Mesa's operating revenue is derived from a transportation agreement with Peabody Western Coal, the coal supplier for the Mohave Generating Station that expires in December 2005. The coal slurry pipeline is the sole source of fuel for the Mohave plant. Operating revenues under the agreement totaled $22.0 million, $21.4 million and $21.5 million for the years ended December 31, 2004, 2003, and 2002, respectively. 8. CREDIT FACILITIES, LONG-TERM DEBT AND CAPITAL LEASES Detailed information on long-term debt is as follows:

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

F-19 NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 8. CREDIT FACILITIES, LONG-TERM DEBT AND CAPITAL LEASES (continued) The Partnership and Northern Border Pipeline have entered into revolving credit facilities, which are used for capital expenditures, acquisitions and general business purposes and for refinancing existing indebtedness. Northern Border Pipeline entered into a $175 million three-year credit agreement (2002 Pipeline Credit Agreement) with certain financial institutions in May 2002. The Partnership entered into a $275 million four-year credit agreement (2003 Partnership Credit Agreement) with certain financial institutions in November 2003. Both of the revolving credit facilities permit the Partnership and Northern Border Pipeline to choose among various interest rate options, to specify the portion of the borrowings to be covered by specific interest rate options and to specify the interest rate period. Both the Partnership and Northern Border Pipeline are required to pay a fee on the principal commitment amounts. In April 2002, Northern Border Pipeline completed a private offering of $225 million of 6.25% Senior Notes due 2007 (2002 Pipeline Senior Notes). The 2002 Pipeline Senior Notes were subsequently exchanged in registered offerings for notes with substantially identical terms. The proceeds from the senior notes were used to reduce indebtedness outstanding. On December 1, 2004, Northern Border Pipeline redeemed $75 million of the 2002 Pipeline Senior Notes. In connection with the redemption, Northern Border Pipeline was required to pay a premium of $4.8 million and received $2.5 million from the termination of interest rate swaps associated with the debt (see Note 9). The net loss from the redemption, including unamortized debt costs and discounts associated with the debt, is recorded as a loss on reacquired debt and amortized to interest expense over the remaining life of the 2002 Pipeline Senior Notes. At December 31, 2004, the unamortized loss on reacquired debt was $2.6 million and is included in other assets on the consolidated balance sheet. Interest paid, net of amounts capitalized, during the years ended December 31, 2004, 2003 and 2002 was $77.7 million, $86.7 million and $88.2 million, respectively. Aggregate repayments of long-term debt required for the next five years, excluding payments required under Bear Paw Energy's capital leases, are as follows: $2 million, $2 million, $343 million, $2 million and $200 million for 2005, 2006, 2007, 2008 and 2009, respectively. The indentures under which the 1999, 2001 and 2002 Pipeline Senior Notes were issued do not limit the amount of indebtedness or other obligations that Northern Border Pipeline may incur, but do contain material financial covenants, including restrictions on the incurrence of secured indebtedness. The 2002 Pipeline Credit Agreement requires the maintenance of a ratio of EBITDA (net income plus interest expense, income taxes and depreciation and amortization) to interest expense to be greater than 3 to 1. The 2002 Pipeline Credit Agreement also requires the maintenance of the ratio of indebtedness to EBITDA of no more than 4.5 to 1. At December 31, 2004, Northern Border Pipeline was in compliance with its financial covenants. At December 31, 2004, Viking Gas Transmission has four series of senior notes outstanding. In November 2004, Viking Gas Transmission amended the indenture on its senior notes. Prior to the amendment, Viking Gas Transmission made monthly principal and interest payments on the four series F-20 NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 8. CREDIT FACILITIES, LONG-TERM DEBT AND CAPITAL LEASES (continued) of notes. As a result of the amendment, three of the series of senior notes due between 2011 and 2014 require payment of interest quarterly and payment of principal at maturity. The senior notes due in 2008 continue to require monthly principal and interest payments. Under the previous indenture, Viking Gas Transmission's transportation contracts were pledged as security for payment, which has been replaced in the current indenture by a guarantee by the Partnership. In addition, Viking Gas Transmission is no longer required to maintain debt service funds on deposit in an amount equal to all scheduled payments of principal and interest for the 180-day period following the current month end. At December 31, 2003, the requirement for accumulation of debt service funds was $3.7 million. The senior notes contain certain financial covenants and at December 31, 2004, Viking Gas Transmission was in compliance with its financial covenants. The indentures under which the 2001 and 2000 Partnership Senior Notes were issued do not limit the amount of indebtedness or other obligations that the Partnership may incur, but do contain material financial covenants, including restrictions on the incurrence of secured indebtedness. The indentures also contain a provision that would require the Partnership to offer to repurchase the 2001 and 2000 Partnership Senior Notes if either Standard & Poor's Rating Services or Moody's Investor Service, Inc. rate the notes below investment grade and the investment grade rating is not reinstated for a period of 40 days. The 2003 Partnership Credit Agreement requires the maintenance of a ratio of consolidated EBITDA (consolidated net income plus minority interests in net income, consolidated interest expense, income taxes, depreciation and amortization and all other non-cash charges) to consolidated interest expense of greater than 3 to 1. The 2003 Partnership Credit Agreement also requires the maintenance of the ratio of consolidated total debt to adjusted consolidated EBITDA (EBITDA adjusted for pro forma operating results of acquisitions made during the year) of no more than 4.5 to 1. If the Partnership consummates one or more acquisitions in which the aggregate purchase price is $25 million or more, the allowable ratio of consolidated total debt to adjusted consolidated EBITDA temporarily increases to 5 to 1. At December 31, 2004, the Partnership was in compliance with these covenants. Bear Paw Energy has entered into non-cancelable capital leases on compressors. The capital leases incorporate annual interest rates ranging from 7.10% to 8.85% and are for a term of five years, after which Bear Paw Energy receives ownership of the equipment. Future minimum payments under Bear Paw Energy's capital leases are as follows (in thousands): Years ending December 31, 2005 $3,145 2006 117 ------ $3,262 Less amount representing interest 152 ------ Present value of lease payments 3,110 Less: current portion 2,993 ------ Long-term portion $ 117 ====== The following estimated fair values of financial instruments represent the amount at which each instrument could be exchanged in a current transaction between willing parties. Based on quoted market prices for similar issues F-21 NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 8. CREDIT FACILITIES, LONG-TERM DEBT AND CAPITAL LEASES (continued) with similar terms and remaining maturities, the estimated fair value of the aggregate of the 1999 Pipeline Senior Notes, 2000 Partnership Senior Notes, 2001 Partnership Senior Notes, 2001 Pipeline Senior Notes, 2002 Pipeline Senior Notes and Viking Gas Transmission Senior Notes was approximately $1,205 million and $1,306 million at December 31, 2004 and 2003, respectively. The Partnership presently intends to maintain the current schedule of maturities for the 1999 Pipeline Senior Notes, 2000 Partnership Senior Notes, 2001 Partnership Senior Notes, 2001 Pipeline Senior Notes, 2002 Pipeline Senior Notes and Viking Gas Transmission Senior Notes, which will result in no gains or losses on their respective repayment. The fair value of the 2003 Partnership Credit Agreement and the 2002 Pipeline Credit Agreement approximates the carrying value since the interest rates are periodically adjusted to reflect current market conditions. 9. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES The Partnership reflects in consolidated accumulated other comprehensive income its 70% share of Northern Border Pipeline's accumulated other comprehensive income. The remaining 30% is reflected as an adjustment to minority interests in partners' equity. The Partnership also reflects in consolidated accumulated other comprehensive income its ownership share of accumulated other comprehensive income of its unconsolidated affiliates (see Note 10). Prior to the anticipated issuance of fixed rate debt, both the Partnership and Northern Border Pipeline have entered into forward starting interest rate swap agreements. The interest rate swap agreements have been designated as cash flow hedges as they hedge the fluctuations in Treasury rates and spreads between the execution date of the swap agreements and the issuance of the fixed rate debt. The notional amount of the interest rate swap agreements does not exceed the expected principal amount of fixed rate debt to be issued. Upon issuance of the fixed rate debt, the swap agreements were terminated and the proceeds received or amounts paid to terminate the swap agreements were recorded in accumulated other comprehensive income and amortized to interest expense over the term of the hedged debt. The Partnership also recorded an adjustment to minority interests in partners' equity for Northern Border Pipeline's terminated swap agreements. On December 9, 2004, the Partnership entered into forward starting interest rate swap agreements with a total notional amount of $100 million in anticipation of a ten-year fixed rate senior note issuance to be placed in the first half of 2005. At December 31, 2004, the Partnership has recorded a derivative instrument liability of $0.8 million, the fair value of the interest rate swap agreements, with a corresponding offset to accumulated other comprehensive income. For the year ended December 31, 2002, Northern Border Pipeline received $2.4 million from terminated interest rate swap agreements that had been designated as cash flow hedges, of which $1.6 million was recorded in accumulated other comprehensive income and $0.8 million was recorded as an adjustment to minority interests in partners' equity. F-22 NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 9. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES (continued) During the years ended December 31, 2004, 2003 and 2002, the Partnership and Northern Border Pipeline amortized approximately $2.1 million, $2.2 million and $2.1 million, respectively, related to the terminated interest rate swap agreements, as a reduction to interest expense from accumulated other comprehensive income. A comparable amount is expected to be amortized in 2005. At December 31, 2004 and 2003, the Partnership had outstanding interest rate swaps with notional amounts totaling $150 million. Under the interest rate swap agreements, the Partnership makes payments to counterparties at variable rates based on the London Interbank Offered Rate and in return receives payments based on a 7.10% fixed rate. At December 31, 2004 and 2003, the average effective interest rate on the Partnership's interest rate swap agreements was 4.60% and 3.72%, respectively. Northern Border Pipeline entered into interest rate swap agreements with notional amounts totaling $225 million in May 2002. Under the interest rate swap agreements, Northern Border Pipeline makes payments to counterparties at variable rates based on the London Interbank Offered Rate and in return receives payments based on a 6.25% fixed rate. At December 31, 2003 the average effective interest rate on Northern Border Pipeline's interest rate swap agreements was 2.31%. In November 2004, Northern Border Pipeline terminated its interest rate swap agreements with notional amounts totaling $225 million and received $7.5 million. Of the total proceeds, $2.5 million related to the redemption of $75 million of the 2002 Pipeline Senior Notes (see note 8). In October 2002, the Partnership agreed to an increase in the variable interest rate on two of its interest rate swap agreements with notional amounts totaling $150 million. As consideration for the change to the variable interest rate, the Partnership received approximately $18.2 million, which represented the fair value of the financial instruments at the date of the adjustment. In March 2003, the Partnership terminated one of its interest rate swap agreements with a notional amount of $75 million and received $12.3 million. The Partnership used the proceeds to repay amounts borrowed under its credit facility. The Partnership and Northern Border Pipeline records in long-term debt amounts received or paid related to terminated or amended interest rate swap agreements for fair value hedges with such amounts amortized to interest expense over the remaining life of the interest rate swap agreement. During the years ended December 31, 2004, 2003 and 2002, the Partnership and Northern Border Pipeline amortized approximately $3.3 million, $3.4 million and $0.5 million, respectively, as a reduction to interest expense. The Partnership and Northern Border Pipeline expect to amortize approximately $5.2 million as a reduction to interest expense in 2005 for these agreements. Both the Partnership's and Northern Border Pipeline's interest rate swap agreements have been designated as fair value hedges as they hedge the fluctuations in the market value of the senior notes issued by the Partnership in 2001 and by Northern Border Pipeline in 2002. F-23 NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 9. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES (continued) The accompanying consolidated balance sheet at December 31, 2004 and 2003, reflects an unrealized gain of approximately $2.6 million and $19.6 million, respectively, in derivative financial instruments with a corresponding increase in long-term debt. Bear Paw Energy periodically enters into commodity derivatives contracts and fixed-price physical contracts. Bear Paw Energy primarily utilizes price swaps and collars, which have been designated as cash flow hedges, to hedge its exposure to gas and natural gas liquid price volatility. During the years ended December 31, 2004, 2003 and 2002, respectively, Bear Paw Energy recognized losses of $9.4 million, $8.5 million and $2.8 million from the settlement of derivative contracts. At December 31, 2004, the consolidated balance sheet reflected an unrealized gain of approximately $2.0 million in derivative financial instruments with a corresponding increase of $2.0 million in accumulated other comprehensive income. At December 31, 2003, the consolidated balance sheet reflected an unrealized loss of approximately $5.7 million in derivative financial instruments with a corresponding reduction of $5.5 million in accumulated other comprehensive income. For 2005, if prices remain at current levels, Bear Paw Energy expects to reclassify approximately $2.0 million from accumulated other comprehensive income as an increase to operating revenues. However, this increase would be offset with decreased operating revenues due to the lower prices assumed. At September 30, 2001, Bear Paw Energy had outstanding commodity price swap arrangements with ENA, which had been accounted for as cash flow hedges, and resulted in Bear Paw Energy recording a non-cash gain of approximately $6.7 million in accumulated other comprehensive income. During the fourth quarter of 2001, the Partnership determined that ENA was no longer likely to honor the obligations it had to Bear Paw Energy for these derivatives and terminated the swap arrangements (see Note 18). In accordance with SFAS No. 133, Bear Paw Energy ceased to account for these derivatives as hedges. The gain previously recorded in accumulated other comprehensive income is reflected in earnings in the same periods during which the hedged forecasted transactions will affect earnings. During the years ended December 31, 2004, 2003 and 2002, the Partnership recorded approximately $0.2 million, $0.3 million and $4.6 million, respectively, in earnings and expects to record approximately $0.1 million in earnings in 2005. 10. UNCONSOLIDATED AFFILIATES The Partnership's investments in unconsolidated affiliates which are accounted for by the equity method is as follows:

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

F-24 NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 10. UNCONSOLIDATED AFFILIATES (continued) (a) The Partnership held a 49% common membership interest in Bighorn and 100% of the non-voting preferred A shares of Bighorn at December 31, 2004 and 2003. Bighorn's ownership structure consists of common membership interests and non-voting preferred A and B shares. Both of the non-voting classes of shares are subject to certain distribution preferences and limitations based on the cumulative number of wells connected to the Bighorn system at the end of each calendar year. These shares will receive an income allocation equal to the cash distributions received and are not entitled to any other allocations of income or distributions of cash. Ownership of these shares does not affect the amount of capital contributions that may be required to be made to the operations of Bighorn by the owners of the common membership interests. (b) The unamortized excess of the Partnership's investments in unconsolidated affiliates over the underlying fair value of the net assets accounted for under the equity method was $181.6 million at December 31, 2004 and 2003. The Partnership's equity earnings of unconsolidated affiliates is as follows:

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

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

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

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

F-25 NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 11. PARTNERS' EQUITY At December 31, 2004 and 2003, partners' equity consisted of 46,397,214 common units representing an effective 98% limited partner interest in the Partnership and a 2% general partner interest. At December 31, 2004 and 2003, approximately 1.1% of the limited partner interest was held by Northern Plains. Sundance Assets, L.P. (Sundance), an indirect subsidiary of Enron) held approximately 5.8% of the limited partnership interest at December 31, 2003. Sundance sold its limited partner interest during 2004. The Partnership did not receive any proceeds from the sale. In conjunction with the issuance of additional common units, the Partnership's general partners are required to make equity contributions to the Partnership to maintain a 2% general partner interest in accordance with the partnership agreements. In May and June 2003, the Partnership sold 2,250,000 and 337,500 common units, respectively. In July 2002, the Partnership sold 2,186,700 common units. The net proceeds from the sale of common units and the general partners' contributions totaled approximately $102.2 million in 2003 and $75.4 million in 2002 and were primarily used to repay indebtedness outstanding. Under the partnership agreement, the Partnership will make distributions to its partners with respect to each calendar quarter in an amount equal to 100% of its Available Cash. "Available Cash" generally consists of all of the cash receipts of the Partnership adjusted for its cash disbursements and net changes to cash reserves. Available Cash will generally be distributed 98% to the Unitholders and 2% to the General Partners. As an incentive, the General Partners' percentage interest in quarterly distributions is increased after certain specified target levels are met. Under the incentive distribution provisions, the General Partners receive 15% of amounts distributed in excess of $0.605 per common unit, 25% of amounts distributed in excess of $0.715 per unit and 50% of amounts distributed in excess of $0.935 per unit. Partnership income is allocated to the General Partners and the limited partners in accordance with their respective partnership percentages, after giving effect to any priority income allocations for incentive distributions that are allocated to the General Partners. For the years ended December 31, 2004, 2003 and 2002, incentive distributions to the General Partners totaled $8.0 million, $7.7 million and $7.3 million, respectively. 12. NORTHERN BORDER PIPELINE CASH DISTRIBUTION POLICY The Northern Border Pipeline partnership agreement provides that distributions to Northern Border Pipeline's partners are to be made on a pro rata basis according to each partner's capital account balance. The Northern Border Pipeline Management Committee determines the amount and timing of such distributions. Any changes to, or suspension of, the cash distribution policy of Northern Border Pipeline requires the unanimous approval of the Northern Border Pipeline Management Committee. In December 2003, Northern Border Pipeline's Management Committee voted to (i) issue equity cash calls to its partners in the total amount of $130 million in early 2004 and $90 million in 2007; (ii) fund future growth capital F-26 NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 12. NORTHERN BORDER PIPELINE CASH DISTRIBUTION POLICY (continued) expenditures with 50% equity capital contributions from its partners; and (iii) change the cash distribution policy of Northern Border Pipeline. Effective January 1, 2004, cash distributions are equal to 100% of distributable cash flow as determined from Northern Border Pipeline's financial statements based upon earnings before interest, taxes, depreciation and amortization less interest expense and maintenance capital expenditures. Effective January 1, 2008, the cash distribution policy will be adjusted to maintain a consistent capital structure. On November 30, 2004, Northern Border Pipeline issued an equity cash call to its partners in the total amount of $75 million, which was utilized to repay existing bank debt. This equity contribution will reduce the previously approved 2007 equity cash call from $90 million to $15 million. 13. COMMITMENTS AND CONTINGENCIES Firm Transportation Obligations and Other Commitments Crestone Energy Ventures has firm transportation agreements with Fort Union and Lost Creek. Under these agreements, Crestone Energy Ventures must make specified minimum payments each month. Crestone Energy Ventures recorded expenses of $11.8 million, $11.7 million and $ 11.4 million for the years ended December 31, 2004, 2003 and 2002, respectively, related to these agreements. At December 31, 2004, the estimated aggregate amounts of such required future payments were $11.6 million annually for 2005 through 2008, $11.1 million for 2009 and $3.7 million for later years. At December 31, 2004, the Partnership has guaranteed the performance of certain of its unconsolidated affiliates in connection with credit agreements that expire in March 2009 and September 2009. Collectively, at December 31, 2004, the amount of both guarantees was $4.4 million. Operating Leases Future minimum lease payments under non-cancelable operating leases on office space, pipeline equipment, rights-of-way and vehicles are as follows (in thousands): Year ending December 31, 2005 $ 4,489 2006 4,024 2007 3,154 2008 2,978 2009 2,392 Thereafter 66,385 ------- $83,422 ======= Expenses incurred related to these lease obligations for the years ended December 31, 2004, 2003 and 2002, were $3.8 million, $3.7 million and $2.0 million, respectively. F-27 NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 13. COMMITMENTS AND CONTINGENCIES (continued) Cash Balance Plan As further discussed in Note 18, on December 31, 2003, Enron filed a motion seeking approval of the Bankruptcy Court to provide additional funding to, and for authority to, terminate the Enron Corp. Cash Balance Plan and certain other defined benefit plans. The Partnership recorded charges associated with the termination of the cash balance plan of $6.2 million in 2003. In 2004, the Partnership reduced its expense by $6.2 million, since it determined it is no longer liable for terminations costs of the Cash Balance Plan. Capital Expenditures Total capital expenditures for 2005 are estimated to be $87 million. This includes approximately $57 million for interstate natural gas pipeline facilities, $25 million for natural gas gathering and processing facilities and $5 million for information technology systems. Funds required to meet the capital requirements for 2005 are anticipated to be provided from credit facilities and operating cash flows. Environmental Matters The Partnership is not aware of any material contingent liabilities with respect to compliance with applicable environmental laws and regulations. Other On July 31, 2001, the Assiniboine and Sioux Tribes of the Fort Peck Indian Reservation (Tribes) filed a lawsuit in Tribal Court against Northern Border Pipeline to collect more than $3 million in back taxes, together with interest and penalties. The lawsuit related to a utilities tax on certain of Northern Border Pipeline's properties within the Fort Peck Indian Reservation. The Tribes and Northern Border Pipeline, through a mediation process, reached a settlement with respect to pipeline right-of-way lease and taxation issues documented through an Option Agreement and Expanded Facilities Lease (Agreement) executed in August 2004. Through the terms of the Agreement, the settlement grants to Northern Border Pipeline, among other things: (i) an option to renew the pipeline right-of-way lease upon agreed terms and conditions on or before April 1, 2011 for a term of 25 years with a renewal right for an additional 25 years; (ii) a right to use additional tribal lands for expanded facilities; and (iii) release and satisfaction of all tribal taxes against Northern Border Pipeline. In consideration of this option and other benefits, Northern Border Pipeline paid a lump sum amount of $7.4 million and will make additional annual option payments of approximately $1.5 million thereafter through March 31, 2011. Of the amount paid in 2004, $1.0 million was determined to be a settlement of previously accrued property taxes. The remainder has been recorded in other assets on the balance sheet. Northern Border Pipeline intends to seek regulatory recovery from the settlement in its upcoming rate case. Various legal actions that have arisen in the ordinary course of business are pending. The Partnership believes that the resolution of these issues will not have a material adverse impact on the Partnership's results of operations or financial position. F-28 NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 14. INCOME TAXES Components of the income tax provision applicable to continuing operations and income taxes paid by the Partnership's corporate subsidiaries are as follows (in thousands):

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

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

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

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

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

F-29 NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 14. INCOME TAXES (continued) The Partnership had available, at December 31, 2004, approximately $6.6 million of tax benefits related to net operating loss carryforwards, which will expire between the years 2008 and 2024. The Partnership believes that it is more likely than not that the tax benefits of the net operating loss carryforwards will be utilized prior to their expiration; therefore, no valuation allowance is necessary. 15. ACCOUNTING PRONOUNCEMENTS In December 2003, the FASB issued Interpretation No. (FIN) 46 (revised December 2003), "Consolidation of Variable Interest Entities," which addresses how a business enterprise should evaluate whether it has a controlling financial interest in an entity through means other than voting rights and accordingly should consolidate the entity; such entities are known as variable interest entities. The Partnership adopted FIN 46 as of January 1, 2004. In connection with the adoption of FIN 46, the Partnership evaluated its investments in Bighorn, Fort Union, Lost Creek and Guardian Pipeline and determined that these entities are appropriately accounted for as equity method investments. The adoption of FIN 46 did not have an effect on the Partnership's financial position, results of operations or cash flows. In December 2004, the FASB issued SFAS No. 153, "Exchanges of Nonmonetary Assets." This Statement amends the guidance in APB Opinion No. 29, "Accounting for Nonmonetary Transactions." APB 29 provided an exception to the basic measurement principle (fair value) for exchanges of similar assets, requiring that some nonmonetary exchanges be recorded on a carryover basis. SFAS 153 eliminates the exception to fair value for exchanges of similar productive assets and replaces it with a general exception for exchange transactions that do not have commercial substance, that is, transactions that are not expected to result in significant changes in the cash flows of the reporting entity. The provisions of SFAS 153 are effective for exchanges of nonmonetary assets occurring in fiscal periods beginning after June 15, 2005. The Partnership believes that SFAS 153 will not have a significant effect on the financial position, results of operations, and cash flows of the Partnership. 16. BUSINESS SEGMENT INFORMATION The Partnership's business is divided into three reportable segments, defined as components of the enterprise about which financial information is available and evaluated regularly by the Partnership's executive management and the Partnership Policy Committee in deciding how to allocate resources to an individual segment and in assessing performance of the segment. The Partnership's reportable segments are strategic business units that offer different services. Each are managed separately because each business requires different marketing strategies. These segments are as follows: the Interstate Natural Gas Pipeline segment provides natural gas transmission services; the Natural Gas Gathering and Processing segment provides services for the gathering, treating, processing and compression of natural gas and the fractionation of natural gas liquids; and the Coal Slurry Pipeline segment transports crushed coal suspended in water. The accounting policies of the segments are the same as those described in the summary of significant accounting policies in Note 2. F-30 NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 16. BUSINESS SEGMENT INFORMATION (continued) The Partnership evaluates performance based on EBITDA, earnings before interest, taxes, depreciation and amortization less the allowance for equity funds used during construction (AFUDC). Management uses EBITDA to compare the financial performance of its segments and to internally manage those business segments and believes that EBITDA is a good indicator of each segment's performance. EBITDA should not be considered an alternative to, or more meaningful than, net income or cash flow as determined in accordance with GAAP. EBITDA calculations may vary from company to company, so the Partnership's computation of EBITDA may not be comparable to a similarly titled measure of another company. The following table shows how EBITDA is calculated: RECONCILIATION OF NET INCOME (LOSS) TO EBITDA

Natural Interstate Gas Natural Gathering Gas and Coal (In thousands) Pipelines Processing Slurry Other(a) Total -------------- ---------- ---------- -------- -------- --------- 2004 Net income (loss) $ 134,726 $ 44,488 $ 3,088 ($37,582) $ 144,720 Minority interest 50,033 -- -- -- 50,033 Interest expense, net 43,882 369 11 32,681 76,943 Depreciation and amortization 67,487 14,851 4,465 400 87,203 Income tax 4,783 26 327 2,935 8,071 AFUDC (117) -- -- -- (117) --------- --------- ------- -------- --------- EBITDA $ 300,794 $ 59,734 $ 7,891 ($ 1,566) $ 366,853 ========= ========= ======= ======== ========= 2003 Net income (loss) $ 119,620 ($183,016) $ 3,658 ($28,716) ($ 88,454) Cumulative effect of change in accounting principle, net of tax -- -- 434 209 643 Minority interest 44,460 -- -- -- 44,460 Interest expense, net 47,577 591 33 30,779 78,980 Depreciation and amortization 66,245 232,777 1,848 1,107 301,977 Income tax 3,629 -- 1,076 (276) 4,429 AFUDC (331) -- -- -- (331) --------- --------- ------- -------- --------- EBITDA $ 281,200 $ 50,352 $ 7,049 $ 3,103 $ 341,704 ========= ========= ======= ======== ========= 2002 Net income (loss) $ 107,510 $ 35,568 $ 4,136 ($33,538) $ 113,676 Minority interest 42,816 -- -- -- 42,816 Interest expense, net 51,525 794 33 30,546 82,898 Depreciation and amortization 61,002 12,102 1,568 1,202 75,874 Income tax 730 -- 913 543 2,186 AFUDC (248) -- -- -- (248) --------- --------- ------- -------- --------- EBITDA $ 263,335 $ 48,464 $ 6,650 ($ 1,247) $ 317,202 ========= ========= ======= ======== =========

BUSINESS SEGMENT DATA

Natural Interstate Gas Natural Gathering Coal Gas and Slurry (In thousands) Pipelines Processing Pipeline Other(a) Total -------------- ---------- ---------- -------- -------- ---------- 2004 Revenues from external customers $ 383,625 $ 184,738 $22,020 $ -- $ 590,383 Depreciation and amortization 67,115 14,851 4,465 -- 86,431 Operating income (loss) 231,027 28,278 3,446 (9,366) 253,385 Interest expense, net 43,882 369 11 32,681 76,943 Equity earnings of unconsolidated affiliates 1,649 16,366 -- -- 18,015 Other income (expense), net 748 239 (20) 666 1,633 Income tax expense 4,783 26 327 -- 5,136 Capital expenditures 16,258 25,646 1,573 -- 43,477 Identifiable assets 1,866,348 337,502 18,268 15,236 2,237,354 Investments in unconsolidated affiliates 34,207 238,995 -- -- 273,202 Total assets $1,900,555 $ 576,497 $18,268 $15,236 $2,510,556 2003 Revenues from external customers $ 375,256 $ 154,284 $21,408 $ -- $ 550,948 Depreciation and amortization (b) 65,881 232,063 1,847 -- 299,791 Operating income (loss) 212,841 (203,067) 5,144 (7,601) 7,317 Interest expense, net 47,577 591 33 30,779 78,980 Equity earnings unconsolidated affiliates 1,992 16,823 -- -- 18,815 Other income (expense), net 453 3,819 57 535 4,864 Income tax expense 3,629 -- 1,076 -- 4,705 Capital expenditures 19,497 8,981 1,804 -- 30,282 Identifiable assets 1,938,249 317,182 21,319 25,667 2,302,417 Investments in unconsolidated affiliates 32,558 235,608 -- -- 268,166 Total assets $1,970,807 $ 552,790 $21,319 $25,667 $2,570,583

F-31 NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 16. BUSINESS SEGMENT INFORMATION (continued)

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

(a) Includes other items not allocable to segments. (b) Natural gas gathering and processing results includes goodwill and asset impairment charges of $219,080 (see Note 4). 17. OTHER INCOME (EXPENSE) Other income (expense) on the consolidated statement of income includes such items as investment income, nonoperating revenues and expenses, foreign currency gains and losses, and nonrecurring other income and expense items. For the year ended December 31, 2003, other income also included a $3.3 million payment received for a change in ownership of the other partner in Bighorn. F-32 NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 18. QUARTERLY FINANCIAL DATA (Unaudited)

Income Per Unit (Loss) Income (Loss) Operating From From (In thousands, except Operating Income Continuing Continuing per unit amounts) Revenues (Loss) Operations Operations --------------------- --------- --------- ---------- ------------- 2004 First Quarter $143,773 $ 61,761 $ 35,852 $ 0.71 Second Quarter 142,476 60,595 32,872 0.65 Third Quarter 147,355 62,093 34,400 0.68 Fourth Quarter 156,779 68,936 37,797 0.76 2003 First Quarter $138,175 $ 58,731 $ 32,520 $ 0.68 Second Quarter 134,362 56,767 27,170 0.55 Third Quarter 138,008 (160,795) (183,976) (3.93) Fourth Quarter 140,403 52,614 27,137 0.53

19. RELATIONSHIPS WITH ENRON In December 2001, Enron and certain of its subsidiaries filed a voluntary petition for bankruptcy protection under Chapter 11 of the United States Bankruptcy Code. Until November 17, 2004, each of Northern Plains, Pan Border and NBP Services were subsidiaries of Enron. Northern Plains, Pan Border and NBP Services were not among the Enron companies filing for Chapter 11 protection. Enron North America (ENA), a wholly owned subsidiary of Enron that is in bankruptcy, was a party to transportation contracts which obligated ENA to pay for 3.5% of Northern Border Pipeline's capacity. Through the bankruptcy proceeding in 2002, ENA rejected and terminated all of its firm transportation contracts on Northern Border Pipeline. Northern Border Pipeline had previously fully reserved for amounts invoiced to ENA. Since Enron guaranteed the obligations of ENA under those contracts, Northern Border Pipeline filed claims against both ENA and Enron for damages in the bankruptcy proceedings. As a result of a settlement agreement between ENA, Enron and Northern Border Pipeline, each of ENA and Enron have agreed to allow Northern Border Pipeline's claim of approximately $20.6 million. The settlement agreement is expected to be presented to the Bankruptcy Court for approval in March 2005. Based upon this settlement between the parties, at December 31, 2004, Northern Border Pipeline adjusted its allowance for doubtful accounts to reflect an estimated recovery of $1.1 million for these claims. ENA was also a party to a transportation contract for capacity on Midwestern Gas Transmission. ENA rejected and terminated this contract in November 2003. Midwestern Gas Transmission filed claims against ENA for breach of contract and other claims. However, this claim of approximately $150,000 was denied. In addition, Bear Paw Energy filed claims against ENA relating to terminated swap agreements. In accordance with SFAS No. 133, Bear Paw Energy ceased to account for these swap agreements as hedge transactions. Bear Paw Energy had previously recorded approximately $6.7 million in accumulated other comprehensive income related to these agreements, which is being recorded into earnings in the same periods of the originally forecasted F-33 NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 19. RELATIONSHIPS WITH ENRON (continued) hedges. During the third quarter 2004, the Bankruptcy Court approved a settlement between Bear Paw Energy, Enron and certain of its wholly-owned subsidiaries of Bear Paw Energy's claim for commodity hedges. As a result, the Partnership adjusted its allowance for doubtful accounts to reflect an estimated $1.8 million recovery for its claim. Also, Crestone Energy Ventures filed claims against ENA for unpaid gas gathering and administrative services fees in the amount of $2.3 million. As a result of a settlement agreement between ENA and Crestone Energy Ventures, ENA has agreed to allow Crestone Energy Ventures' claim of approximately $2.3 million. The settlement agreement is expected to be presented to the Bankruptcy Court for approval in March 2005. Based upon this settlement between the parties, the Partnership adjusted its allowance for doubtful accounts to reflect an estimated $0.5 million recovery for its claim. The Partnership estimates that it could recognize, through future operating results, additional recoveries of $4 million to $7 million for the claims in the Enron bankruptcy proceedings. However, there can be no assurances on the amounts actually recovered or timing of distributions under the Chapter 11 Plan. On December 31, 2003, Enron filed a motion seeking approval of the Bankruptcy Court to provide additional funding to, and for authority to terminate the Enron Corp. Cash Balance Plan (Plan) and certain other defined benefit plans of Enron's affiliates in 'standard terminations' within the meaning of Section 4041 of the Employee Retirement Income Security Act of 1974, as amended (ERISA). Such standard terminations would satisfy all of the obligations of Enron and its affiliates with respect to funding liabilities under the Plan. In addition, a standard termination would eliminate the contingent claims of Pension Benefit Guaranty Corporation (PBGC) against Enron and its affiliates with respect to funding liabilities under the Plan. On January 30, 2004, the Bankruptcy Court entered an order authorizing termination, additional funding and other actions necessary to effect the relief requested. Pursuant to the Bankruptcy Court order, any contributions to the Plan are subject to the prior receipt of a favorable determination by the Internal Revenue Service that the Plan is tax-qualified as of the date of termination. On July 19, 2004, Enron was served with a complaint filed by the PBGC in the District Court for the Southern District of Texas against Enron as the sponsor and/or administrator of the Plans (the Action). By filing the Action, the PBGC is seeking an order (i) terminating the Plans; (ii) appointing the PBGC the statutory trustee of the Plans; (iii) requiring transfer to the PBGC of all records, assets or other property of the Plans required to determine the benefits payable to the Plans' participants; and (iv) establishing June 2, 2004 as the termination date of the Plans. In the Bankruptcy Court September 10 Order, Enron was authorized to enter into an escrow agreement with CCE Holdings and PBGC. Upon closing, Enron deposited the amount of $321.8 million to an escrow account, which is intended to ensure that none of CCE Holdings or its affiliates are exposed F-34 NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 19. RELATIONSHIPS WITH ENRON (continued) to liability to the PBGC under Title IV of the Employee Retirement Income Security Act of 1974, as amended, for which CCE Holdings may otherwise be indemnified pursuant to the CCE Holdings Agreement. In addition, the form of escrow agreement approved pursuant to the September 10 Order provides that, under certain circumstances and upon approval by or notice to the parties to the escrow agreement, some or all of the funds placed in escrow may be paid directly in respect of the Cash Balance Plan or to the PBGC. However, the September 10 Order also provides that PBGC retains any rights or claims it may have against the Transfer Group Companies. Enron management previously informed Northern Plains and NBP Services that Enron would seek funding contributions from each member of its ERISA controlled group of corporations that employs, or employed, individuals who are, or were, covered under the Cash Balance Plan. Northern Plains and NBP Services are considered members of Enron's ERISA controlled group of corporations. As of December 31, 2003, the amount of approximately $6.2 million was estimated for Northern Plains' and NBP Services' proportionate share of the up to $200 million estimated termination costs for the Plans authorized by the Bankruptcy Court order. Since under the operating agreement with Northern Plains and the administrative agreement with NBP Services, these costs could be the Partnership's responsibility, the Partnership accrued $6.2 million to satisfy claims of reimbursement for these termination costs. As a result of further evaluation and negotiation of Enron's proposed allocation of the termination costs, Northern Plains and NBP Services advised the Partnership that no claim of reimbursement for the termination costs will be made, resulting in a reduction in reserves during 2004 of $6.2 million for the termination costs. Under the ONEOK Agreement, neither Northern Plains nor NBP Services nor the Partnership will be required to contribute to or otherwise be liable for any contributions to Enron in connection with the Cash Balance Plan. The purchase price under the agreements will be deemed to include all contributions which otherwise would have been allocable to Northern Plains and NBP Services. Management continues to monitor developments at Enron, to assess the impact on the Partnership of its existing agreements and relationships with Enron and to take appropriate action to protect the interests of the Partnership. 20. SUBSEQUENT EVENTS On January 21, 2005, the Partnership declared a cash distribution of $0.80 per unit ($3.20 per unit on an annualized basis) for the quarter ended December 31, 2004. The distribution was paid February 14, 2005, to unitholders of record at January 31, 2005. F-35 REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM ON SCHEDULE Northern Border Partners, L.P.: We have audited in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements of Northern Border Partners, L.P. and Subsidiaries as of December 31, 2004 and 2003 and for each of the years in the three-year period ended December 31, 2004 included in this Form 10-K, and have issued our report thereon dated March 2, 2005. Our audits were made for the purpose of forming an opinion on the basic financial statements taken as a whole. The schedule of Northern Border Partners, L.P. and Subsidiaries listed in Item 15 of Part IV of this Form 10-K is the responsibility of the Company's management and is presented for purposes of complying with the Securities and Exchange Commission's rules and is not part of the basic financial statements. This schedule has been subjected to the auditing procedures applied in the audits of the basic financial statements and, in our opinion, fairly states in all material respects, the financial data required to be set forth therein in relation to the basic financial statements taken as a whole. /s/ KPMG LLP Omaha, Nebraska March 2, 2005 S-1 SCHEDULE II NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS FOR THE YEARS ENDED DECEMBER 31, 2004, 2003 AND 2002 (IN THOUSANDS)

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 2004 $ 7,644 $ 640 $-- $ 6,329 $ 1,955 2003 $12,294 $5,611 $-- $10,261 $ 7,644 2002 $ 2,531 $9,763 $-- $ -- $12,294 Allowance for doubtful accounts 2004 $11,988 $ 569 $-- $ 3,382 $ 9,175 2003 $11,936 $ 52 $-- $ -- $11,988 2002 $10,287 $3,463 $52 $ 1,866 $11,936

S-2 Index to Exhibits

EXHIBITS DESCRIPTION --------------- ----------- 3.1 Northern Border Partners, L.P. Certificate of Limited Partnership, Certificate of Amendment dated February 16, 2001, and Certificate of Amendment dated May 20, 2003. 3.2 Amended and Restated Agreement of Limited Partnership of Northern Border Partners, L.P. dated October 1, 1993. 3.3 Northern Border Intermediate Limited Partnership Certificate of Limited Partnership, Certificate of Amendment dated February 16, 2001, and Certificate of Amendment dated May 20, 2003. *3.4 Form of Amended and Restated Agreement of Limited Partnership for Northern Border Intermediate Limited Partnership (incorporated by reference to Exhibit 10.1 to Form S-1 Registration Statement, Registration No. 33-66158 ("Form S-1")). *4.1 Indenture, dated as of June 2, 2000, between Northern Border Partners, L.P. and Northern Border Intermediate Limited Partnership and Bank One Trust Company, N.A. (incorporated by reference to Exhibit 4.1 to the Partnership's Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2000 (File No. 1-12202) ("June 2000 10-Q")). *4.2 First Supplemental Indenture, dated as of September 14, 2000, between Northern Border Partners, L.P., Northern Border Intermediate Limited Partnership and Bank One Trust Company, N.A. (incorporated by reference to Exhibit 4.2 to the Partnership's Form S-4 Registration Statement, Registration No. 333-46212 ("NBP Form S-4")). *4.3 Indenture, dated as of March 21, 2001, between Northern Border Partners, L.P. and Northern Border Intermediate Limited Partnership and Bank One Trust Company, N.A., Trustee (incorporated by reference to Exhibit 4.3 to the Partnership's Form 10-K for the year ended December 31, 2001 (File No. 1-12202)). *4.4 Indenture, dated as of August 17, 1999, between Northern Border Pipeline Company and Bank One Trust Company, NA, successor to The First National Bank of Chicago, as trustee. (incorporated by reference to Exhibit No. 4.1 to Northern Border Pipeline Company's Form S-4 Registration Statement filed on October 7, 1999, Registration No. 333-88577 ("NB Form S-4")). *4.5 Indenture, dated as of September 17, 2001, between Northern Border Pipeline Company and Bank Trust Company, N.A. (incorporated by reference to Exhibit 4.2 to Northern Border Pipeline Company's Registration Statement on Form S-4 filed on November 13, 2001, Registration No. 333-73282 ("2001 NB Form S-4")).

*4.6 Indenture, dated as of April 29, 2002, between Northern Border Pipeline Company and Bank One Trust Company, N.A. (incorporated by reference to Exhibit 4.1 to Northern Border Pipeline Company's Form 10-Q for the quarter ended March 31, 2002 (File No. 333-88577)). *10.1 Northern Border Pipeline Company General Partnership Agreement between Northern Plains Natural Gas Company, Northwest Border Pipeline Company, Pan Border Gas Company, TransCanada Border Pipeline Ltd. and TransCan Northern Ltd., effective March 9, 1978, as amended (incorporated by reference to Exhibit 10.2 to Form S-1). *10.2 Form of Seventh Supplement Amending Northern Border Pipeline Company General Partnership Agreement (incorporated by reference to Exhibit 10.15 to Form S-1). *10.3 Eighth Supplement Amending Northern Border Pipeline Company General Partnership Agreement (incorporated by reference to Exhibit 10.15 to NB Form S-4). *10.4 Ninth Supplement Amending Northern Border Pipeline Company General Partnership Agreement (incorporated by reference to Exhibit 10.37 to 2001 NB Form S-4). *10.5 Tenth Supplement Amending Northern Border Pipeline Company General Partnership Agreement dated March 2, 2005 (incorporated by reference to Exhibit 3.5 to Northern Border Pipeline's Form 10-K filed on March 11, 2005 (File No. 333-88577)). *10.6 Operating Agreement between Northern Border Pipeline Company and Northern Plains Natural Gas Company, dated February 28, 1980 (incorporated by reference to Exhibit 10.3 to Form S-1). *10.7 Administrative Services Agreement between NBP Services Corporation, Northern Border Partners, L.P. and Northern Border Intermediate Limited Partnership (incorporated by reference to Exhibit 10.4 to Form S-1). *10.8 Revolving Credit Agreement, dated as of November 24, 2003, among Northern Border Partners, L.P., SunTrust Bank, Harris Nesbitt Corp., Wachovia Bank, National Association, Citigroup, N.A., SunTrust Capital Markets, Inc., and the Lenders (as named therein) (incorporated by reference to Exhibit 10.7 to the Partnership's Form 10-K for the year ended December 31, 2003 (File No. 1-12202)). *10.9 First Amendment to the Revolving Credit Agreement dated as of April 9, 2004 between Northern Border Partners, L.P., SUNTRUST BANK and the lenders named therein (incorporated by reference to Exhibit 10.1 to the Partnership's Form 10-Q for the quarter ended March 31, 2004 (File No. 1-12202)). *10.10 Second Amendment entered into as of October 25, 2004 to Northern Border Partners' Revolving Credit Agreement dated as of November 24, 2003 (incorporated by reference to Exhibit 99.1 to the Partnership's Form 8-K filed on November 5, 2004 (File No. 1-12202)). *10.11 Revolving Credit Agreement, dated as of May 16, 2002, among Northern Border Pipeline Company, Bank One, NA, Citibank, N.A., Bank of Montreal, SunTrust Bank, Wachovia Bank, National Association, Banc One Capital Markets, Inc, and Lenders (as defined therein) (incorporated by reference to Exhibit 10.1 to the Partnership's Current Report on Form 8-K dated June 26, 2002 (File No. 1-12202)). *10.12 First Amendment to the Revolving Credit Agreement dated as of April 9, 2004 between Northern Border Pipeline Company, Bank One, NA and the lenders named therein. (incorporated by reference to Exhibit No. 10.1 to Northern Border Pipeline Company's Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2004 (File No. 333-88577). *10.13 Agreement between Northern Plains and Northern Border Intermediate Limited Partnership regarding the costs, expenses and expenditures arising under the operating agreement between Northern Plains and Guardian Pipeline, LLC (incorporated by reference to Exhibit 10.3 to the Partnership's Form 10-Q for the quarter ended March 31, 2004 (File No. 1-12202)). +*10.14 Form of Termination Agreement with ONEOK dated as of January 5, 2005 (incorporated by reference to Exhibit 99.1 to the Partnership's Form 8-K filed on January 11, 2005 (File No. 1-12202)). +*10.15 ONEOK, Inc. 2005 Supplemental Executive Retirement Plan. (incorporated by reference to Exhibit 99.1 to the Partnership's Form 8-K filed on January 11, 2005(File No. 1-12202)). +*10.16 ONEOK, Inc. Long-Term Incentive Plan (incorporated by reference from Exhibit 10(a) to ONEOK's Form 10-K for the year ended December 31, 2001 (File No. 1-13643)). +*10.17 ONEOK, Inc. Form of Restricted Stock Incentive Award (incorporated by reference from Exhibit 10.4 to ONEOK's Form 10-Q for the quarterly period ended September 30, 2004 (File No. 1-13643)). +*10.18 ONEOK, Inc. Form of Performance Shares Award (incorporated by reference from Exhibit 10.5 to ONEOK's Form 10-Q for the quarterly period ended September 30, 2004 (File No. 1-13643)). +*10.19 ONEOK, Inc. Employee Non-Qualified Deferred Compensation Plan, as amended, dated February 2001 (incorporated by reference to Exhibit 10(g) to ONEOK's Form 10-K for the year ended December 31, 2001 (File No. 1-13643)). +*10.20 ONEOK, Inc. Annual Officer Incentive Plan (incorporated by reference to Exhibit 10(f) to ONEOK's Form 10-K for the year ended December 31, 2001 (File No. 1-13643)). *10.21 Operating Agreement between Midwestern Gas Transmission Company and Northern Plains Natural Gas Company dated as of April 1, 2001 (incorporated by reference to Exhibit 10.38 to the Partnership's Form 10-K for the year ended December 31, 2001 (File No. 1-12202)). *10.22 Operating Agreement between Viking Gas Transmission Company and Northern Plains Natural Gas Company dated as of January 17, 2003 (incorporated by reference to Exhibit 10.18 to the Partnership's Form 10-K for the year ended December 31, 2002 (File No. 1-12202)). *10.23 Northern Border Pipeline Company Agreement among Northern Plains Natural Gas Company, Pan Border Gas Company, Northwest Border Pipeline Company, TransCanada Border PipeLine Ltd., TransCan Northern Ltd., Northern Border Intermediate Limited Partnership, Northern Border Partners, L.P., and the Management Committee of Northern Border Pipeline, dated as of March 17, 1999 (incorporated by reference to Exhibit 10.21 to the Partnership's Form 10-K/A for the year ended December 31, 1998 (File No. 1-12202) ("1998 10-K")). 10.24 Northern Border Transition Services Agreement dated November 17, 2004, by and between ONEOK, Inc. and CCE Holdings, LLC. 12.1 Statement re computation of ratios. 21 List of subsidiaries. 23.1 Consent of KPMG LLP. 31.1 Rule 13a-14(a)/15d-14(a) certification of principal executive officer. 31.2 Rule 13a-14(a)/15d-14(a) Certification of principal financial officer. 32.1 Section 1350 certification of principal executive officer. 32.2 Section 1350 certification of principal financial officer. +*99.1 Northern Border Phantom Unit Plan (incorporated by reference to Exhibit 99.1 to Amendment No. 1 to the Partnership's Form S-8, Registration No. 333-66949 and Exhibit 99.1 to Northern Border Partners, L.P.'s Registration No. 333-72696). * Indicates exhibits incorporated by reference as indicated; all other exhibits are filed herewith. + Management contract, compensatory plan or arrangement. The total amount of securities of the Partnership authorized under any instrument with respect to long-term debt not filed as an exhibit does not exceed 10% of the total assets of the Partnership and its subsidiaries on a consolidated basis. The Partnership agrees, upon request of the Securities and Exchange Commission, to furnish copies of any or all of such instruments to the Securities and Exchange Commission.