10-K 1 h23122e10vk.txt NORTHERN BORDER PIPELINE COMPANY DATED 12/31/2004 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: 333-88577 NORTHERN BORDER PIPELINE COMPANY (Exact name of registrant as specified in its charter) TEXAS 74-2684967 (State or other jurisdiction (I.R.S. Employer of incorporation or organization) Identification No.) 13710 FNB PARKWAY, OMAHA, NEBRASKA 68154-5200 (Address of principal executive offices)(Zip Code) Registrant's telephone number, including area code: 402-492-7300 --------------------- SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT: Title of each class registered Name of each exchange on which ------------------------------ ------------------------------ None 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 [ ] No [X] Aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant on June 30, 2004, was $0. DOCUMENTS INCORPORATED BY REFERENCE None. NORTHERN BORDER PIPELINE COMPANY TABLE OF CONTENTS

~~Year~~PAGE ~~Ended~~NO. December 31, 2000 1999 1998 1997 1996 INCOME DATA: Operating revenues, net $ 311,022 $ 298,347 $ 196,600 $ 186,050 $ 201,943 Operations and maintenance 41,548 38,708 29,447 28,522 26,974 Depreciation and amortization 57,328 51,908 40,989 38,708 46,979 Taxes other than income 27,979 30,320 21,381 22,393 24,390 Regulatory credit -- -- ~~(8,878)~~ -- -- ~~Operating~~PART ~~income~~I ~~184,167~~Item ~~177,411~~1. ~~113,661~~Business ~~96,427~~1 ~~103,600~~Item ~~Interest~~2. ~~expense,~~Properties ~~net~~12 ~~65,161~~Item ~~60,214~~3. ~~25,541~~Legal ~~29,360~~Proceedings ~~32,670~~13 ~~Other~~Item ~~income~~4. ~~8,058~~Submission ~~1,363~~of ~~12,111~~Matters ~~5,705 2,913 Net income~~ to ~~partners~~a $Vote ~~127,064~~of $Security ~~118,560~~Holders $14 ~~100,231~~PART $II ~~72,772~~Item $5. ~~73,843~~Market ~~CASH~~for ~~FLOW~~Registrant's ~~DATA:~~Common ~~Net cash provided by operating activities $ 175~~Equity,~~967~~ $Related ~~171,466~~Stockholder $Matters ~~103,777~~and $Issuer ~~115,328~~Purchases $of ~~136,808~~Equity ~~Capital~~Securities ~~expenditures~~ 15~~,523~~ ~~101,678~~Item ~~651,169~~6. ~~152,070~~Selected ~~18,597~~Financial ~~Distributions~~Data to16 ~~partners~~Item ~~134,904~~7. ~~127,163~~Management's ~~61,205~~Discussion ~~99,322~~and ~~102,845~~Analysis ~~BALANCE~~of ~~SHEET~~Financial ~~DATA~~Condition ~~(AT END OF PERIOD): Property, plant~~ and ~~equipment,~~Results ~~net~~of ~~$1,686,992~~Operations ~~$1,731,394~~17 ~~$1,714,523~~Item ~~$1,100,890~~7A. $Quantitative ~~937,859~~and ~~Total~~Qualitative ~~assets~~Disclosures ~~1,768,505~~About ~~1,796,691~~Market ~~1,790,889~~Risk ~~1,147,120~~30 ~~974,137~~Item ~~Long-term~~8. ~~debt,~~Financial ~~including~~Statements ~~current~~and ~~maturities~~Supplementary ~~863,267~~Data ~~900,459~~30 ~~862,000~~Item ~~459,000~~9. ~~377,500~~Changes ~~Partners'~~in ~~capital~~and ~~826,995~~Disagreements ~~834,835~~With ~~843,438~~Accountants ~~581,412~~on ~~526,962~~Accounting ~~OTHER~~and ~~FINANCIAL~~Financial ~~DATA:~~Disclosure ~~Ratio~~30 ofItem ~~earnings~~9A. toControls ~~fixed~~and ~~charges~~Procedures ~~(1)~~31 ~~2.9~~Item 39B.0 ~~3.2~~Other ~~3.2~~Information ~~3.2~~31 ~~OPERATING~~PART ~~DATA:~~III ~~Natural~~Item ~~gas~~10. ~~delivered~~Directors ~~(millions~~and ofExecutive ~~cubic~~Officers ~~feet) 852,674 834,833 608,187 621,262 630,148 Average throughput (millions~~ of ~~cubic~~Registrant ~~feet~~32 ~~per~~Item ~~day)~~11. ~~2,400~~Executive ~~2,353~~Compensation ~~1,706~~35 ~~1,735~~Item ~~1,755~~12. ~~Transportation~~Security ~~units~~Ownership ~~(million~~of ~~dekatherm~~Certain ~~miles~~Beneficial ~~per~~Owners ~~day):~~and ~~Firm~~Management ~~service~~and ~~2,276~~Related ~~2,289~~Stockholder ~~1,417~~Matters ~~1,393~~42 ~~1,392~~Item ~~Interruptible~~13. 19Certain 6Relationships 28and 47Related 56Transactions ~~(1)~~42 ~~"Earnings"~~Item ~~means the sum of pre-tax income from continuing operations and fixed charges~~14. ~~"Fixed~~Principal ~~charges"~~Accounting ~~means~~Fees ~~the sum of (a) interest expensed~~ and ~~capitalized;~~Services ~~(b)~~43 ~~amortized~~PART ~~premiums,~~IV ~~discounts~~Item ~~and~~15. ~~capitalized~~Exhibits ~~expenses related to indebtedness;~~ and ~~(c)~~Financial anStatement ~~estimate~~Schedules ~~of interest within rental expenses.~~45

i PART I ITEM 1. BUSINESS. GENERAL Northern Border Pipeline Company is a general partnership formed in 1978. Our general partners are Northern Border Partners, L.P. ("Northern Border Partners") and TC PipeLines, LP ("TC PipeLines"), both of which are publicly traded partnerships. Each of Northern Border Partners and TC PipeLines holds its interest in us, 70% and 30% of voting power, respectively, through a subsidiary limited partnership. The general partners of Northern Border Partners and its subsidiary limited partnership are Northern Plains Natural Gas Company ("Northern Plains") and Pan Border Gas Company, both subsidiaries of ONEOK, Inc. ("ONEOK"), and Northwest Border Pipeline Company, a subsidiary of TransCanada PipeLines Limited, which is a subsidiary of TransCanada Corporation. The general partner of TC PipeLines and its subsidiary limited partnership, TC PipeLines GP, Inc., is also a subsidiary of TransCanada. We own an interstate pipeline system that transports natural gas from the Montana-Saskatchewan border to natural gas markets in the midwestern United States. This pipeline system connects with multiple pipelines that provide shippers with access to the various natural gas markets served by those pipelines. For the year ended December 31, 2004, we estimate that we transported approximately 22% of the total amount of natural gas imported from Canada to the United States. Over the same period, approximately 88% of the natural gas transported was produced in the western Canadian sedimentary basin located in the provinces of Alberta, British Columbia and Saskatchewan. We transport gas for shippers under a tariff regulated by the Federal Energy Regulatory Commission ("FERC"). The tariff specifies the maximum and minimum transportation rates and the general terms and conditions of transportation service on the pipeline system. Our 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. We do not own the gas that we transport, and therefore we do not assume natural gas commodity price risk for quantities transported. Any exposure to commodity risk for imbalances on our system that may result from under or over deliveries to customers or interconnecting pipelines is either recovered through provisions in our tariff or is immaterial. We own the line pack, which is the amount of gas necessary to maintain efficient operations of the pipeline. Our shippers are responsible to provide fuel gas necessary for the operation of gas compressor stations. Our management is overseen by a four-member management committee. Three representatives are designated by Northern Border Partners, with each of its general partners selecting one representative; and one representative is designated by 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 1 Northern Border Partners' 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. Northern Plains and Pan Border are subsidiaries of ONEOK. Therefore, ONEOK controls 57.75% of the voting power of the management committee and has the right to select two of the members. In November 2004, ONEOK purchased Northern Plains and Pan Border 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." Our pipeline system is operated by Northern Plains pursuant to an operating agreement. As of December 31, 2004, Northern Plains employed approximately 230 individuals located at its headquarters in Omaha, Nebraska and at various locations along the pipeline route and also used employees and information technology systems of its affiliates to provide its services. Northern Plains' employees are not represented by any labor union and are not covered by any collective bargaining agreements. THE PIPELINE SYSTEM We own 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. Our pipeline system was expanded and/or extended in 1991, 1992, 1998 and 2001. Our pipeline system connects directly and through multiple pipelines to various natural gas markets in the United States. Our 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. Our 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 2 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. INTERCONNECTS To access markets, our 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 Company, a wholly owned subsidiary of Northern Border Partners, near Channahon, Illinois; - ANR Pipeline Company near Manhattan, Illinois; - Vector Pipeline L.P. in Will County, Illinois; - Guardian Pipeline, L.L.C., an affiliate of Northern Border Partners, in Will County, Illinois; - The Peoples Gas Light and Coke Company near Manhattan, Illinois; and - Northern Indiana Public Service Company near North Hayden, Indiana at the terminus of the pipeline system. Several market centers, where natural gas transported on the pipeline system is sold, traded and received for transport to consuming markets in the Midwest and to interconnecting pipeline facilities, have developed on the pipeline system. The largest of these market centers is at our 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 our 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. 3 SHIPPERS All of our 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. Our 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." Our shippers may change throughout the year as a result of our 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., EnCana Marketing U.S.A. Inc. and Cargill Incorporated were obligated for approximately 18%, 14%, 13% and 12%, respectively, of our 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 our 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." DEMAND FOR TRANSPORTATION CAPACITY Recent developments have resulted in proposed expansion of our pipeline. In September 2004, we announced we 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 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 we expect to file the required certificate application in March 2005. 4 Our long-term financial condition is dependent on the continued availability of economic western Canadian natural gas supplies for import into the United States. Natural gas reserves may require significant capital expenditures by others for exploration and development drilling and the installation of production, gathering, storage, transportation and other facilities that permit natural gas to be produced and delivered to pipelines that interconnect with the interstate pipelines' systems. 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 western Canadian natural gas supplies. Increased Canadian consumption of natural gas 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 export capacity also could accelerate depletion of these reserves. Furthermore, the availability of export capacity could also affect the demand or value of the transport on our pipeline system. Our 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 our pipeline system. Demand for natural gas to serve other markets also influences the ability and willingness of shippers to use our pipeline system to meet demand in the markets that we serve. A variety of factors could affect the demand for natural gas in the markets that we 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. Interstate pipelines' primary exposure to market risk occurs at the time existing transportation contracts expire and are subject to renegotiation. A key determinant of the 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 point in time. This margin and its variability become 5 important factors in determining the transportation rate customers are willing to pay when they renegotiate their transportation contracts. The basis differential between markets can be affected by trends in production, available capacity, storage inventories, weather and general market demand in the respective areas. Throughput on our pipeline may experience seasonal fluctuations depending upon the level of winter heating load demand or summer electric generation usage in the markets we serve. 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 pipeline system or how significant that adverse affect could be. INTERSTATE PIPELINE COMPETITION We 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. Our competitive position is affected by the availability of Canadian natural gas for export, the availability of other sources of natural gas and demand for natural gas in the United States. Demand for transportation services on our system 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, including Viking Gas Transmission Company which is owned by Northern Border Partners, 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, our 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 us since substantially all of its capacity is contracted under long-term contracts. In addition, we compete in our markets with other interstate pipelines that provide access to other supply basins. Our major deliveries into Northern Natural Gas at Ventura, Iowa compete with gas supplied from the Rockies and mid-continent regions. We also compete with these supply basins at our delivery interconnect with Natural Gas Pipeline of America at Harper, Iowa. In the Chicago area, we compete 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 6 in the Rocky Mountain area to the mid-continent area. The pipeline will provide additional supply and transportation competition in markets served by us. 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 the Chicago area. A change in trading value at these market centers will affect the corresponding transportation value of that portion of our system upstream and downstream of these trading centers. FERC REGULATION We are subject to extensive regulation by the FERC as a "natural gas company" under the Natural Gas Act. Under the Natural Gas Act and the Natural Gas Policy Act, the FERC has jurisdiction with respect to virtually all aspects of our business, including: - transportation of natural gas; - rates and charges; - construction of new facilities; - extension or abandonment of service and facilities; - accounts and records; - depreciation and amortization policies; - the acquisition and disposition of facilities; and - the initiation and discontinuation of services. Where required, we hold certificates of public convenience and necessity issued by the FERC covering our 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 books and records may be periodically audited by the FERC under Section 8. 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 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 our service are found in our FERC approved tariff. Transportation rates are established in FERC proceedings known as rate cases. Under our tariff, we are allowed to charge for our services on the basis of stated transportation rates established in our 1999 rate case. We may also provide services under negotiated and discounted rates. Generally, firm shippers are obligated to pay a 7 monthly demand charge, regardless of the amount of natural gas they actually transport, for the term of their contracts. Approximately 98% of the revenue generated is attributed to demand charges. The remaining 2% of the agreed upon revenue level is attributed to commodity charges based on the volumes of gas actually transported. Under the terms of settlement in our 1999 rate case, neither our existing shippers nor we can seek rate changes until November 1, 2005, at which time we must file a rate case. Prior to this rate case, we will not be permitted to increase rates if costs increase or if our contracted demand decreases, nor will we be required to reduce rates based on cost savings. As a result, our earnings and cash flow will depend on costs incurred, contracted capacity, the volumes of gas transported and our ability to recontract capacity at acceptable rates. Until new depreciation rates are approved by the FERC, we continue to depreciate our transmission plant at the FERC approved annual depreciation rate. Our annual depreciation rate on transmission plant in service is 2.25%. The effects of accumulated depreciation may be offset by acquiring or constructing assets that replace or add to existing pipeline facilities or by adding new facilities or our transportation rates may be decreased. In our 1995 rate case, the FERC addressed the issue of whether the federal income tax allowance included in our 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 to a tax allowance for income attributable to limited partnership interests held by individuals. The settlement of our 1995 rate case provided that until at least December 2005, we could continue to calculate the allowance for income taxes in the manner we had historically used. In addition, a settlement adjustment mechanism was implemented, which effectively reduced the return on rate base. These provisions of the 1995 rate case were maintained in the settlement of our 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 ours, suggested that an income tax 8 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 us. In particular, we are a general partnership whose rates include an allowance for income taxes. Our specific circumstances regarding our 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 our rates is applicable, in light of the FERC and court rulings, may be addressed in our 2005 rate case. We 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, we posted our standards of conduct to our website on September 22, 2004. By definition, Bear Paw Energy, LLC, a subsidiary of Northern Border Partners and ONEOK Energy Services Company, L.P, as well as other subsidiaries of ONEOK, are energy affiliates. Prior to September 22, 2004, our operator, Northern Plains, provided after hours and weekend gas control services for Bear Paw Energy, LLC and Crestone Energy Ventures, also a subsidiary of Northern Border Partners that resulted in some cost savings to us. We 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 FERC. 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 business. Recent FERC orders in proceedings involving other natural gas pipelines have addressed certain aspects of a pipeline's 9 creditworthiness provisions set forth in their tariffs. In addition, industry groups, such as the North American Energy Standards Board ("NAESB"), are studying creditworthiness standards. On February 12, 2004, the FERC issued a Notice of Proposed Rulemaking to require interstate pipelines to follow standardized procedures for determining the creditworthiness of their shippers. The proposed rule would incorporate by reference ten consensus standards passed within NAESB and would adopt additional standards requiring, among other things, standardization of information shippers provide to establish credit, collateral requirements for service, procedures for suspension and termination for non-creditworthy shippers and procedures governing capacity release transactions. 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 us, of any resulting final rule. In February 2004, the FERC adopted new quarterly financial reporting requirements and accelerated the filing date for 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 expenses 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 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. 10 In August 2003, we 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 we violated our 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. Our position is that selling capacity for shorter distances or on a shorter term basis may cause portions of our 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 our 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, we 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. We filed a timely request for rehearing of the FERC's Order in October 2003, which is still pending. We also filed responses to requests for further information on the award of capacity in the summer of 2003. We filed our compliance tariff sheets in early December 2003 and are awaiting the FERC 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 us 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. ENVIRONMENTAL AND SAFETY MATTERS Our operations are subject to federal, state and local laws and regulations relating to safety and the protection of the environment, which include the Resource Conservation and Recovery Act, the Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended, Clean Air Act, as amended, the Clean Water Act, as amended, the Natural Gas Pipeline Safety Act of 1969, as amended, the Pipeline Safety Act of 1992 and the Pipeline Safety Improvement Act of 2002. The Pipeline Safety Improvement Act ("Act") of 2002 was signed into law in December 2002, providing guidelines for interstate pipelines in the areas of risk analysis and integrity management, public education programs, verification of operator qualification programs and filings with the National Pipeline Mapping System. The Act requires pipeline companies to perform integrity assessments on pipeline segments that exist in high population density areas or near specifically identified sites that are designated as high consequence areas. Pipeline companies are required to perform the integrity assessments within ten years of the date of enactment and must perform subsequent integrity assessments on a seven-year cycle. At least 50% of the highest risk segments must be assessed within five years of the enactment date. In addition, within one year of enactment, the pipeline's operator qualification programs, in force since the mandatory compliance date of October 2002, must also conform to standards provided by the Department of Transportation. The regulations implementing the Act are final. Rules on integrity 11 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 pipeline. As required, we have developed an overall plan for pipeline integrity management. Detailed analysis is being performed to determine the priorities and costs for inspecting and testing our pipeline. 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 $0.5 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 "FERC Regulation" above. Although we believe that our operations and facilities are in general compliance in all material respects with applicable environmental and safety regulations, risks of substantial costs and liabilities are inherent in pipeline operations, and we cannot provide any assurances that we will not incur such costs and liabilities. Moreover, it is possible that other developments, such as the enactment of increasingly strict environmental and safety laws, regulations and enforcement policies by Congress, the FERC, the Department of Transportation and other federal agencies, state regulatory bodies and the courts, and claims for damages to property or persons resulting from our operations, could result in substantial costs and liabilities to us. If we are unable to recover such resulting costs, earnings and cash distributions could be adversely affected. ITEM 2. PROPERTIES. See Item 1. "Business - The Pipeline System" and "Business - Interconnects" for a brief description of the location and general characteristics of our important physical properties. We hold the right, title and interest in our pipeline system. With respect to real property, the pipeline system falls 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 system across certain property was obtained through exercise of the power of eminent domain. We continue to have the power of eminent domain in each of the states in which we operate, although we may not have the power of eminent domain with respect to Native American tribal lands. Approximately 90 miles of our pipeline 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 12 or Indians. We do have the right of eminent domain with respect to allotted lands. In 1980, we 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 in 1981, granted to us the right and privilege to construct and operate our pipeline on certain tribal lands. This pipeline right-of-way lease expires in 2011. We have 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, we also obtained a right-of-way across allotted lands located within the reservation boundaries. Most of the allotted lands are subject to a perpetual easement either granted by the Bureau of Indian Affairs ("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. 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 us to collect more than $3 million in back taxes, together with interest and penalties. The lawsuit related to a utilities tax on certain of our properties within the Fort Peck Indian Reservation. The Tribes and we, 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 us, 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 us. In consideration of this option and other benefits, we 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. We intend 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 - FERC Regulation" for a discussion on the proceeding 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 results of operations or financial position. 13 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. 14 PART II ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES. The general partnership interests of Northern Border Pipeline Company are not traded in an established public trading market. In December 2003, our management committee voted to (i) issue equity cash calls to our general partners in the total amount of $130 million in early 2004 and $90 million in 2007; (ii) fund future growth capital expenditures with 50% equity capital contributions from our general partners; and (iii) change our cash distribution policy to be effective January 1, 2004, when cash distributions will be based upon 100% of distributable cash flow as determined from the Company's financial statements as earnings before interest, taxes, depreciation and amortization less interest expense and less maintenance capital expenditures, until January 1, 2008 when the cash distribution policy will be adjusted to maintain a consistent capital structure. Under the previous cash distribution policy, approximately $28 to $30 million was retained annually by us to periodically repay outstanding bank debt. The additional equity contributions in 2004 were utilized to fully repay our existing bank debt and thereby reducing our debt leverage in light of existing business conditions. Upon repayment of the existing bank debt, our next scheduled debt maturity is May 2007. On November 30, 2004, we issued an equity cash call to our partners in the total amount of $75 million, which was paid on December 22, 2004. This additional equity contribution was utilized to repay our existing bank debt and thereby reduce our debt leverage in light of existing business conditions. This equity contribution will reduce the previously approved 2007 equity cash call from $90 million to $15 million. 15 ITEM 6. SELECTED FINANCIAL DATA. (in thousands, except other financial and operating data) The following table sets forth, for the periods and at the dates indicated, selected historical financial data for us. The selected financial information should be read in conjunction with the 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.

~~Annual~~YEAR ~~Compensation~~ENDED ~~Long-Term~~DECEMBER ~~Compensation~~31, ~~Compensation~~----------------------------------------------------------------------------- ~~Securities~~2004 ~~Restricted~~2003 ~~Underlying~~2002 ~~Other~~2001 ~~Annual Stock Awards Options/SARs LTIP Payouts Name & Position Year Salary(1) Bonus(2) Compensation(3) ($)(4) (#) ($)(5) ($)(6) Larry L. DeRoin~~ 2000 ~~$209,167~~---------- $ ---------- ~~$16,844 $164,754 11,335 $403,125 $513,534 Chief Executive 1999 $266,367 $225,000 $ 7,773 $~~ ---------- ---------- $ ---------- $INCOME ~~10,413~~DATA: ~~Officer~~Operating ~~1998 $256~~revenues,~~067~~ net $~~250~~ 329,~~000~~115 $ 7324,~~200~~185 $~~125,024~~ 19321,~~020~~050 $ --313,088 $ 6311,~~380~~022 ~~William~~Operations R.and ~~Cordes~~maintenance ~~2000 $311~~33,~~000~~763 ~~$250~~43,~~000~~791 ~~$15~~41,~~000~~442 ~~$205~~33,~~984~~695 1741,~~405~~548 ~~$131,250~~Depreciation $and ~~13,110~~amortization ~~Chief Executive Officer Jerry L. Peters 2000 $145~~58,~~293~~375 ~~$110~~57,~~000~~779 ~~$ 3~~58,~~708~~714 ~~$112~~57,~~385~~516 1557,~~040~~328 $Taxes --other $than 10income 29,~~091~~368 ~~Chief~~29,634 ~~Financial and 1999 $132~~28,~~933~~436 ~~$100~~25,~~000~~636 ~~$ 3~~27,~~983~~979 $---------- ---------- ~~9,070~~---------- $---------- ---------- $Operating 5income 207,~~260~~609 ~~Accounting~~192,981 ~~Officer~~192,458 ~~1998 $123~~196,~~225~~241 ~~$110~~184,~~000~~167 $Interest 1expense,~~214~~ $net 6041,~~030~~356 2044,~~000~~857 $51,525 ~~-- $ 1~~55,~~956~~351 ~~(1) Mr. DeRoin retired effective September 30~~65,161 ~~2000.~~Other ~~Mr.~~income ~~Cordes~~(expense) ~~was~~524 ~~appointed~~76 ~~President of Northern Plains on October~~ 1,786 ~~2000.~~ (2432) ~~Employees may elect to receive Northern Border phantom units~~8,058 ~~Enron~~---------- ~~Corp.~~---------- ~~phantom~~---------- ~~stock,~~---------- ~~and/or~~---------- ~~Enron~~Net ~~Corp.~~income ~~stock options in lieu of all or a portion of an annual bonus payment. Mr. Peters elected~~ to ~~receive~~partners ~~Northern~~$ ~~Border~~166,777 ~~phantom~~$ ~~units~~148,200 in$ ~~lieu of a portion of the cash bonus payment under the Northern Border Phantom Unit Plan. He received 1~~142,~~532~~719 ~~units~~$ ~~in 1999 and 1~~140,~~450~~458 ~~units~~$ ~~in 2000. In each case~~127,064 ~~units~~========== ~~will~~========== be========== ~~released~~========== to========== ~~him~~CASH ~~five~~FLOW ~~years~~DATA: ~~following~~Net ~~the~~cash ~~grant~~provided ~~date.~~by ~~(3)~~operating ~~Other~~activities ~~Annual~~$ ~~Compensation includes cash perquisite allowances~~206,149 ~~service~~$ ~~awards~~193,270 ~~and~~$ ~~vacation payouts. Also~~224,356 ~~Enron~~$ ~~maintains three deferral plans for key employees under which payment of base salary~~197,322 ~~annual~~$ ~~bonus~~175,967 ~~and~~Capital ~~long-term~~expenditures ~~incentive awards may be deferred to a later specified date. Under the 1985 Deferral Plan~~10,569 ~~interest is credited on amounts deferred based on 150% of Moody's seasoned corporate bond yield index with a minimum rate of~~ 12%,918 ~~which~~9,243 ~~for~~54,659 ~~1998~~15,523 ~~1999~~Distributions ~~and~~to ~~2000~~partners ~~was~~205,635 ~~the~~153,978 ~~minimum rate of 12%. No interest has been reported as Other Annual Compensation under the 1985 Deferral Plan for participating Named Officers because the crediting rates during 1998~~164,126 ~~1999~~143,032 ~~and 2000~~134,904 ~~did~~Equity ~~not~~contributions ~~exceed~~from ~~120%~~partners of205,000 ~~the~~-- ~~long~~-~~term~~- ~~Applicable~~-- ~~Federal~~-- ~~Rate~~BALANCE ofSHEET ~~14.38%~~DATA in(AT ~~effect~~END atOF ~~the~~YEAR): ~~time~~Property, ~~the~~plant ~~1985~~and ~~Deferral~~equipment, ~~Plan~~net ~~was~~$1,543,833 ~~implemented.~~$1,591,755 ~~Beginning~~$1,635,961 ~~January~~ $1,685,665 ~~1996~~$1,686,992 ~~the~~Total ~~1994~~assets ~~Deferral~~1,623,348 ~~Plan~~1,691,309 ~~credits~~1,740,037 ~~interest~~1,751,869 ~~based~~1,768,505 ~~on fund elections chosen by participants. Since earnings on deferred compensation invested in third~~Long-~~party~~term ~~investment vehicles~~debt, ~~comparable~~including tocurrent ~~mutual~~maturities ~~funds~~603,860 ~~need not be reported~~821,498 ~~no interest has been reported as Other Annual Compensation under the 1994 Deferral Plan during 1998~~848,906 ~~1999 and 2000. (4) The aggregate total of shares in unreleased Enron restricted stock holdings and their values as of December 31~~863,666 ~~2000~~863,267 ~~for~~Partners' ~~each~~equity ~~of the Named Officers is: Mr. Cordes~~967,140 7802,~~737~~438 ~~shares valued at $643~~809,~~138,~~772 ~~and Mr. Peters~~833,594 2826,~~755~~995 ~~shares~~OTHER ~~valued~~FINANCIAL atDATA: ~~$229,009.~~Ratio ~~Dividend equivalents for all restricted stock awards accrue from date~~ of ~~grant~~earnings ~~and~~to ~~are~~fixed ~~paid~~charges ~~upon vesting.~~ (51) ~~Reflects cash payments under the Enron Corp~~5.0 ~~Performance Unit Plan for the 1996-1999 period~~4.3 ~~Payments made under the Performance Unit Plan are based on Enron's total shareholder return relative to its peers~~3.8 ~~Enron's performance over the 1996- 1999 performance period rendered a value of $1~~3.505 ~~based on a ranking of second as compared to 11 industry peers~~2.9 ~~Mr.~~OPERATING ~~DeRoin's~~DATA: ~~payment~~Natural ~~includes~~gas ~~amounts~~delivered ~~relating~~(millions toof ~~1997-2000~~cubic ~~and~~feet) ~~1998-2001 performance periods ($187~~844,~~250~~963 ~~and $103~~849,~~125~~920 respectively) which were paid early due to his retirement. (6) The amounts shown include the value of Enron Common Stock allocated to employees' special subaccounts under Enron's Employee Stock Ownership Plan838,736 ~~matching contributions to employees' Enron Corp. Savings Plan~~820,851 ~~and imputed income on life insurance benefits. Mr. DeRoin received a $500~~852,~~000~~674 ~~payment~~Average ~~following~~receipts ~~his~~(millions ~~retirement. Such payment was in lieu~~ of ~~any~~cubic ~~severance~~feet ~~pay~~per orday) ~~severance benefits that otherwise would be payable under Enron's Severance Pay Plan. In addition~~2,377 ~~Mr. DeRoin has entered into an agreement under which he has agreed to provide consulting services to Northern Plains and its businesses until September 30~~2,396 ~~2002~~2,369 ~~for which he receives a payment of $20~~2,~~833~~312 ~~per month.~~2,400

------------------------------------------------------------------------------- (1) "Earnings" means the sum of pre-tax income from continuing operations and fixed charges. "Fixed charges" means the sum of (a) interest expensed and capitalized; (b) amortized premiums, discounts and capitalized expenses related to indebtedness; and (c) an estimate of interest within rental expenses. 16 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 Financial Statements, which were prepared in accordance with accounting principles generally accepted in the United States of America. You should read the following discussion and analysis in conjunction with our Financial Statements and the related notes included elsewhere in this report. OVERVIEW For Northern Border Pipeline, there are several major business drivers. First, a healthy long-term supply outlook is critical. Because the primary source of gas supply that is transported on our pipeline system is in the western Canadian sedimentary basin, western Canadian supply trends are particularly important to us. 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 new proposed Alaskan and Mackenzie Delta supplies reaching the western Canadian pipeline grid potentially beginning by the end of this decade, 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 financial performance. Our pipeline system serves natural gas markets in the upper midwestern area of the United States and accesses a major trading 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. However, competitive pipeline projects may have a negative impact on our profitability. We charge fees for transportation, which are primarily fixed and are based on the amount of capacity reserved by each shipper. Contracting with shippers to reserve the available pipeline capacity as existing contracts expire is a critical factor in our success. Based on our contracts in place at December 31, 2004, the percentage of summer design capacity contracted as of December 31, 2005 was 61%. During 2004, we were successful in recontracting, at maximum 17 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 we have 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 is to recontract as much of the remaining pipeline capacity at maximum transportation rates for the longest terms possible. Because the forward natural gas basis differentials between Western Canada and our market centers continue to be less than the total transportation cost at maximum tariff rates, we may again sell a significant portion of this capacity on a short-term basis. So long as we continue to provide economic value, gas will likely flow from western Canada over our system and we will maintain our 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 us. This could result in lower revenues in some months. Although, we believe a reduction in expected 2005 net income and cash flow of approximately $7 million to $14 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 we receive at the Canadian border has declined modestly from 1,023 British Thermal Units ("Btus") per cubic foot ("cf") to 1,005 Btus/cf. Our transportation contracts in conjunction with our 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 us to reduce our available capacity by almost 2 percent to maintain a high standard of system reliability for our 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 our November 1, 2005 rate case filing. We will continue to focus on safe, efficient, and reliable operations and the further development of our pipeline. We are working to maintain our position as a low cost transporter of Canadian gas to the midwestern U.S. and provide highly valued services to our customers. Growth may occur through incremental projects intended to access new markets or supply areas and supported by long-term contracts. In September 2004, we announced sufficient customer support for a proposed expansion from various receipts point along the pipeline system for deliveries into the Chicago 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. An April 1, 2006 in-service date is the target and subject to timely receipt of regulatory approval, we anticipate that approximately $15 million of the estimated $21 million 18 capital budget will be expended in 2005, with the remaining $6 million to be spent in 2006. We will focus on several regulatory matters. Under our settlement agreement from the last rate case, it was agreed that we must file a proceeding under section 4 of the Natural Gas Act to determine the just and reasonable rates to be charged for our transportation services. During the rate case process, the FERC staff and our customers will review the cost of service elements, (including allowed return on capital, operations and maintenance costs, depreciation and taxes) and contracted capacity levels used to determine transportation rates. As described more fully in Item 1. "Business - FERC 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 interstate natural gas pipelines, including us. In particular, we are a general partnership and one of the elements used to determine our cost of service upon which our 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 our specific circumstances regarding our 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 our rates should include an income tax allowance, and if so, the amount thereof, may be addressed in our 2005 rate case. CRITICAL ACCOUNTING POLICIES AND ESTIMATES Certain amounts included in or affecting our 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. 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 gave rise to the revision become known. Our significant accounting policies are summarized in Note 2 - Notes to Financial Statements included elsewhere in this report. Certain of our accounting policies are of more significance in our financial statement preparation process than others. Our 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 19 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 regulatory assets are probable of future recovery 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 reflected regulatory assets of $11.8 million, which are being recovered, or are expected to be recovered from our 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. For utility property, no retirement gain or loss is included in income except in the case of retirements or sales of entire regulated operating units. The original cost of utility property retired is charged to accumulated depreciation and amortization, net of salvage and cost of removal. Our accounting for financial instruments is in accordance with SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities." SFAS No. 133 requires that every derivative instrument be recorded on the balance sheet as either an asset or liability measured at its fair value. The statement requires that changes in the derivative's fair value be recognized currently in earnings unless specific hedge accounting criteria are met. Special accounting for qualifying hedges allows a derivative's gains and losses to offset related results on the hedged item in the income statement. At December 31, 2004, we had no derivative financial instruments outstanding. RESULTS OF OPERATIONS Our net income to partners was $166.8 million in 2004, $148.2 million in 2003 and $142.7 million in 2002. Our increase in net income in 2004 resulted from increased operating revenues as a result of our ability to generate and retain revenue from the sale of short-term capacity following the expiration of a condition under the previous rate case settlement that restricted our sale of short-term firm capacity and that had required us to share new service revenue with our shippers, a reduction in operations and maintenance expense due to adjustments to expenses previously recorded for termination costs of Enron Corp.'s Cash Balance Plan ("Cash Balance Plan") and the settlement of previously accrued charges for administrative services provided by Northern Plains and its affiliates and a reduction in interest expense due to a decrease in average debt outstanding. Our 2003 operating results benefited from increased operating revenues as a result of our ability to generate and retain revenue from the sale of short-term capacity following the expiration of a condition under the previous rate case settlement that restricted our sale of short-term firm capacity and that had required us to share interruptible transmission and new service revenue with our shippers, the re-contracting of capacity previously held by Enron North America Corp. ("ENA"), and a reduction in interest expense due to lower interest rates. Partially offsetting these increases to our operating results were higher operations and maintenance expenses for 2003 as compared to 2002. 20 Operating revenues were $329.1 million in 2004, $324.2 million in 2003 and $321.1 million in 2002. The $4.9 million increase in operating revenues in 2004 over 2003 was primarily due to the expiration of conditions under Northern Border Pipeline's previous rate case settlement, which enabled us 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. In addition, we had an additional day of transportation services due to leap year, which approximated an additional $0.9 million in revenue. The $3.1 million increase in operating revenues in 2003 over 2002 resulted primarily from additional revenues of approximately $1.8 million related to the re-contracted capacity of ENA contracts. ENA filed for Chapter 11 bankruptcy protection in December 2001 (see "The Impact Of Enron's Chapter 11 Filing On Our Business"). In addition, we recognized revenues from our ability to offer short-term firm contracts and also being able to retain revenue for transportation service beyond a shipper's contracted transportation path. Operations and maintenance expenses were $33.8 million in 2004, $43.8 million in 2003 and $41.4 million in 2002. The $10.0 million decrease in expense from 2003 to 2004 included a reduction of expenses of $3.1 million, as we determined we were no longer liable for termination costs of the Cash Balance Plan. When compared to the impact of the charges recorded in 2003, this represents a $6.2 million decrease in expense between 2003 and 2004. Additionally in 2004, we reduced our operations and maintenance expense by approximately $1.7 million and $0.6 million related to the settlement of previously accrued charges for administrative services provided by Northern Plains and its affiliates and a true-up for corporate compensation plans, respectively. Also contributing to the decrease were adjustments to allowance for doubtful accounts of $1.1 million for estimated recoveries of claims against Enron. Operations and maintenance 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 2003 expense included a $3.1 million charge for our allocation from Northern Plains related to the Cash Balance Plan (see "The Impact of Enron's Chapter 11 Filing On Our Business"). In 2003, we also had increases in salaries and benefits, rights-of-way damages, and telecommunication expenses offset by decreases in electric power costs, as compared to 2002. The 2002 expense included a $10.0 million reserve for costs associated with the treatment of previously collected quantities of natural gas used in utility operations to cover electric power costs. The FERC ordered refunds for these costs in 2003. Depreciation and amortization expense was $58.4 million in 2004, $57.8 million in 2003 and $58.7 million in 2002. The increase in 2004 over 2003 is primarily related to asset additions. The decrease from 2002 to 2003 primarily reflects asset retirements. Taxes other than income were $29.4 million in 2004, $29.6 million in 2003 and $28.4 million in 2002. The increase in 2003 from 2002 is due primarily to a refund received in 2002 from Minnesota for previously paid use taxes resulting from a ruling by the Minnesota Supreme Court. 21 Interest expense was $41.4 million in 2004, $44.9 million in 2003 and $51.5 million in 2002. The $3.5 million decrease from 2003 to 2004 resulted from a decrease in average debt outstanding partially offset by an increase in average interest rates. Interest expense for 2003 decreased from 2002 due to a decrease in our average interest rate as well as a decrease in our average debt outstanding. Other income (expense) was $0.5 million in 2004, $0.1 million in 2003 and $1.8 million in 2002. Significant items included in the $0.4 million increase between 2003 and 2004 are additional income of approximately $0.6 million for interconnections constructed and the reimbursement for the use of previously vacated microwave frequencies of $0.2 million partially offset by approximately $0.5 million of bad debt expense and a $0.4 million inventory write off. In 2003, we recorded expense of approximately $0.6 million for a repayment of amounts previously received for vacated microwave frequency bands, interest expense of $0.3 million due to the FERC ordered refunds of electric power costs and $0.2 million of interest income received related to a sales tax refund on exempt purchases. The amount for 2002 includes approximately $0.6 million for amounts received for previously vacated microwave frequency bands and income of $0.2 million due to a reduction in reserves previously established. LIQUIDITY AND CAPITAL RESOURCES SUMMARY OF CERTAIN CONTRACTUAL OBLIGATIONS The following table sets forth our contractual obligations as of December 31, 2004.

~~Potential~~Payments ~~Realizable~~Due ~~Value~~by atPeriod ~~Individual~~---------------------------------------------- ~~Grants~~Less ~~Assumed~~Than ~~Annual~~After ~~Rates of Stock Number of % of~~ Total ~~Price~~1 ~~Appreciation~~Year ~~for Option Term (~~1)-3 ~~Securities~~Years ~~Options/SARs~~4-5 ~~Underlying~~Years ~~Granted~~5 toYears ~~Exercise~~-------- or--------- ~~Options/SARs~~--------- ~~Employees~~--------- in-------- ~~Base Price Expiration Name Granted~~(#)In ~~Fiscal Year ($/Sh~~Thousands) ~~Date~~Senior ~~0%(2)~~Notes 5%due ~~10%~~2007 ~~Larry L. DeRoin 11~~$150,~~285~~000 ~~(3) 0.03%~~ $~~55.5000~~ ~~01/18/2007 $~~ -- $~~254~~150,~~974~~000 $~~594,198~~ 50-- ~~(4) 0.00%~~ $~~55.5000~~ ~~01/18/2007 $~~ -- $Senior ~~1,130~~Notes $due ~~2,633~~2009 ~~William R. Cordes 14~~200,~~105~~000 ~~(3)~~-- ~~0.04% $55.5000 01/18/2007 $~~ -- ~~$318~~200,~~689~~000 ~~$742,682 50 (4) 0.00% $55.5000 01/18/2007 $~~ -- $Senior ~~1,130~~Notes $due ~~2,633~~2021 3,250,000 ~~(6)~~-- ~~0.01%~~-- ~~$83.1250 12/29/2007 $~~ -- ~~$ 73~~250,~~431~~000 ~~$171,125~~Credit ~~Jerry~~Agreement L.due ~~Peters~~2005 ~~7,695~~-- ~~(3) 0.02% $55.5000 01/18/2007 $~~ -- ~~$173,861 $405,171 50 (4) 0.00% $55.5000 01/18/2007 $~~ -- ~~$ 1,130 $ 2,633 5,770 (5) 0.01% $65.0000 01/24/2007 $~~ -- ~~$152,683 $355,816 1,525 (6) 0.00% $83.1250 12/29/2007 $~~ -- $Operating ~~34,456~~Leases ~~$ 80,297~~ (1a) The dollar amounts under these columns represent the potential realizable value of each grant of options assuming that the market price on Enron Common Stock appreciates in value from the date of grant at the 5% and 10% annual rates prescribed by the SEC and therefore are not intended to forecast possible future appreciation78,345 ~~if any, of the price of Enron Common Stock. (~~2~~) An appreciation in stock price~~,392 ~~which will benefit all shareholders~~4,784 is required for optionees to receive any gain. A stock price appreciation of 0% would render the option without value to the optionees. (3) Represents stock options awarded under the Enron Corp. Long-Term Incentive Program. Awards vest 25% on the grant date and 25% on each anniversary thereafter. (4~~) A grant of 50 stock options was provided to each eligible Enron employee in recognition of Enron stock reaching a fair market value of $50 after the August~~,784 ~~1999~~66,385 2-~~for~~-1------ ~~stock~~------ ~~split.~~-------- ~~(5)~~-------- ~~Mr.~~-------- ~~Peters~~Total ~~elected~~$678,345 to$2,392 ~~receive~~$154,784 ~~stock options in lieu of a portion of his 1999 annual cash bonus payment in the form of stock options which were granted in January~~$204,784 2000 and were 100% vested on date of grant. (6) All eligible employees received an option grant under the EnronOptions Program. The EnronOptions Program provides a grant of options equal to 5% of base annual salary for each year of participation in the program$316,385 ~~not~~======== to====== ~~exceed~~======== ~~five~~======== ~~years of participation. Stock options vest 20% each year beginning June 30, 2001.~~========

(a) See Note 7 - Notes to Financial Statements. OVERVIEW We believe that we have adequate liquidity to fund future recurring operating activities and capital expenditures. Short-term liquidity needs will be met by our operating cash flows and the 2002 Pipeline Credit Agreement (defined below) or similar new credit facilities. Other liquidity needs are expected to be funded through the issuance of long-term debt and capital contributions made by our general partners. Our ability to complete future debt 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. 22 DEBT AND CREDIT FACILITIES We entered into a $175 million three-year credit agreement ("2002 Pipeline Credit Agreement") with certain financial institutions in May 2002. The 2002 Pipeline Credit Agreement replaced a previous credit agreement. The 2002 Pipeline Credit Agreement is to be used to refinance existing indebtedness and for general business purposes. At December 31, 2004, there were no amounts outstanding under the 2002 Pipeline Credit Agreement. 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 of 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, we were in compliance with these covenants. With the 2002 Pipeline Credit Agreement due to expire in May 2005, we have commenced discussions with financial institutions and expect to have a facility in place at terms and conditions similar to the current facility. In April 2002, we completed a private offering of $225 million of 6.25% Senior Notes due 2007 ("2002 Pipeline Senior Notes"). The indentures under which the Pipeline 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 of secured indebtedness. The proceeds from the Pipeline Senior Notes were used to reduce indebtedness outstanding. In December 2004, we redeemed $75 million of the 2002 Pipeline Senior Notes. CASH FLOWS FROM OPERATING ACTIVITIES Cash flows provided by operating activities were $206.1 million in 2004, $193.3 million in 2003 and $224.4 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. An additional $10.3 million of the increase in 2004 over 2003 operating cash flows was due to FERC ordered refunds paid in 2003. Other cash flows from operating activities for 2004 reflect our initial payment of $7.4 million to the Fort Peck Tribes, in accordance with the terms of the Agreement. The $31.1 million decrease in 2003 from 2002 was primarily due to the payment of the FERC ordered refunds related to the electric power costs and the discontinuance of certain shipper transportation prepayments. CASH FLOWS FROM INVESTING ACTIVITIES Cash used in investing activities was $10.6 million for 2004 as compared to $12.9 million for 2003 and $9.2 million for 2002. The capital expenditures for 2004, 2003 and 2002 were primarily related to renewals and replacements of existing facilities. Total capital expenditures for 2005 are estimated to be approximately $40 million, which includes approximately $15 million for the Chicago III Expansion Project. The remaining capital expenditures for 2005 are primarily related to renewals and replacements of existing facilities. We currently anticipate funding our 2005 capital expenditures primarily by borrowing on our credit facility and using 23 operating cash flows. CASH FLOWS FROM FINANCING ACTIVITIES Cash flows used in financing activities were $204.0 million for the year ended December 31, 2004 as compared to $177.0 million in 2003 and $200.8 million in 2002. Distributions to our partners were $205.6 million, $154.0 million and $164.1 million for 2004, 2003 and 2002, respectively. In 2004, contributions of $205.0 million were received from our partners to pay existing bank debt. The increase in distributions from 2003 to 2004 was primarily due to the change to our cash distribution policy in 2004 (see Note 8 - Notes to Financial Statements). The decrease from 2002 to 2003 in distributions was primarily due to the impact of the refunds ordered by FERC on March 27, 2003. For 2004, 2003 and 2002, our borrowings on long-term debt totaled $107.0 million, $142.0 million and $431.9 million, respectively. In 2004 and 2003, the borrowings were made under our credit agreements. For 2002, we received net proceeds from the 2002 Pipeline Senior Notes of approximately $223.5 million and borrowed $207.0 million under our credit agreements. Total payments on debt were $313.0 million, $165.0 million and $468.0 million in 2004, 2003 and 2002, respectively. In 2004, we redeemed $75 million of the 2002 Senior Notes. In connection with the redemption, we were required to pay a premium of $4.8 million. In November 2004, we received $7.6 million from the termination of our interest rate swap agreements with a total notional amount of $225 million. In April 2002, we received $2.4 million from the termination of forward starting interest rate swaps upon issuance of the 2002 Pipeline Senior Notes (see Note 6 - Notes to 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, our operator, and Pan Border, two of the general partners of Northern Border Partners, were 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, and Pan Border 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 through Northern Plains. On June 24, 2004, Enron announced that it had reached an agreement with a joint venture of Southern Union Company and GE 24 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 and Pan Border (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 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 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. 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 25 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 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' 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, these costs could be our responsibility, we accrued $3.1 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 advised us that no claim of reimbursement for the termination costs will be made, resulting in a reduction in reserves during 2004 of $3.1 million for the termination costs. Under the ONEOK Agreement, neither we nor Northern Plains 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. 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 Portland General Electric is consummated, Enron creditors, which should include us as a general unsecured creditor, 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 our capacity. Through the bankruptcy proceeding in 2002, ENA rejected and terminated all of its firm transportation contracts on us. Since Enron guaranteed the obligations of ENA under those contracts, we filed claims against both ENA and Enron for damages in the bankruptcy 26 proceedings. As a result of a settlement agreement between ENA, Enron and us, each of ENA and Enron have agreed to allow our 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 we adjusted our allowance for doubtful accounts to reflect an estimated recovery of $1.1 million for these claims. We estimate that we could recognize, through future operating results, additional recoveries of $6 million to $9 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 Enron is the grantor of the Enron Gas Pipeline Employee Benefit Trust (the "Trust"), which when taken together with the Enron Corp. Medical Plan for Inactive Participants (the "Medical Plan") constitutes a "voluntary employees' beneficiary association" or "VEBA" under Section 501(c) (9) of the Internal Revenue Code. In October 2002, Northern Plains was advised that Enron had notified the committee that has administrative and fiduciary oversight related to the Trust and the Medical Plan, that Enron had made the determination to begin necessary steps to partition the assets of the Trust and the related liabilities of the Medical Plan among all of the participating employers of the Trust. The Trust was established as a regulatory requirement for inclusion of certain costs for post-employment medical benefits in the rates established for the affected pipelines, including us. Enron requested the enrolled actuary to prepare an analysis and recommendation for the allocation of the Trust's assets and associated liabilities among all the participating employers. On July 22, 2003, Enron sought approval of the Bankruptcy Court to terminate the Trust and to distribute its assets among certain identified pipeline companies, one being Northern Plains. If Enron's relief 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 on Form 10-K 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 27 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 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 shipper'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, our operator, is transitioning services from Enron and CrossCountry, Northern Plains may be unable to perform certain services under it operation agreement or may incur increases in costs to continue or replace the services. - Our 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. We may have to contract for shorter periods or at less than maximum rates. See "Overview" above and Item 1. "Business - Demand For Transportation Capacity." - We are subject to extensive regulation by the FERC governing all aspects of our business, including our transportation rates. Under our 1999 rate case settlement, 28 neither our existing customers nor we can seek rate changes until November 2005, at which time we are obligated to file a rate case. We cannot predict what challenges we may have to our rates in the future. See Item 1. "Business - 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 we are unsuccessful in our arguments regarding our facts and circumstances, the disallowance of this component of cost of service for rates could be materially adverse to us. See Item 1. "Business - FERC Regulation." - In a rate case proceeding setting the maximum rates that may be charged, 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 an interstate pipeline must maintain or increase its rate base through projects that maintain or add to existing pipeline facilities or increase its rate of return in a future rate case. - 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." - Due to widespread state budget deficits, several states are evaluating ways to increase revenues through taxation. Such taxation may adversely impact us. - We expect to seek rate recovery of our costs associated with the settlement of pipeline right-of-way lease and taxation issues with the Fort Peck Tribes and the costs associated with the early redemption of $75 million of our senior notes. If we are unable to recover these costs in rates, we will be required to expense costs previously deferred as regulatory assets. See Item 3. "Legal Proceedings." Additional risks and uncertainties not currently known to us, or risks that we currently deem immaterial may impair our business operations. Any of the risk factors described above could significantly and adversely impair our operating results. ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK. We may be exposed to market risk through changes in interest 29 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 to achieve a more predictable cash flow by reducing our exposure to interest rate fluctuations. We do not use these instruments for trading purposes. 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 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 into variable rate debt to take advantage of declining interest rates. At December 31, 2004, we had no variable rate debt outstanding. For additional information on our debt obligations and derivative instruments, see Note 5 and Note 6 to our Financial Statements, included elsewhere in this report. 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 equivalent of our 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 equivalent of our principal executive officer and principal financial officer concluded that our disclosure controls and procedures are effective. 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 was transitioned to ONEOK's payroll system. The Partnership relied on certain systems owned or services provided by Enron and/or CrossCountry that support our financial accounting and reporting. Since the sale of Northern Plains on November 17, 2004, the Partnership has begun the transition of these systems to systems owned by us or provided by ONEOK. 30 The Partnership's transition from the Enron and/or 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. None. 31 PART III ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT. Northern Border Pipeline Company is overseen by the management committee, which is composed of the following individuals: William R. Cordes, Chairman(1) David L. Kyle (1) Max Feldman(2) Paul E. Miller(1) ---------- (1) Designated by Northern Border Partners. (2) Designated by TC PipeLines. William R. Cordes (56) has been a member and Chairman of our management committee since October 1, 2000. Mr. Cordes was named Chief Executive Officer of Northern Border Partners in October 2000. 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. In 1970, he started his career at 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 the President of Transwestern Pipeline, an Enron subsidiary. David L. Kyle (52) was designated as a member of our Management Committee and named Chairman of the Partnership Policy Committee of Northern Border Partners 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. In September 2003, TC PipeLines, LP designated Max Feldman (56) as its member on our Management Committee. Mr. Feldman is Vice-President, Gas Transmission-West, of TransCanada PipeLines Limited, a position he has held since April 2003. From 1999 to 2003, he was Senior Vice-President, Customer Sales and Service, and from 1995 to 1999, Mr. Feldman held several Vice-President positions in the operations, customer service and marketing areas of TransCanada PipeLines Limited. 32 In September 2003, TransCanada designated Paul E. Miller (45) as its member on the Northern Border Partners, L.P. Policy Committee and designated Mr. Miller as Northwest Border's representative on our 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. Day-to-day management and operations are the responsibility of the operator, Northern Plains, as set forth in the operating agreement. We have no employees or executive officers. Officers and employees of Northern Plains, as well as employees of its affiliates, provide services to our operations and we reimburse Northern Plains for such costs. We do not compensate members of the management committee for their services. The following individuals, as well as Mr. Cordes whose information is provided above, are officers of the Operator who are deemed to be executive officers of the partnership: Jerry L. Peters was named Chief Financial and Accounting Officer of Northern Border Partners, L.P. 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 for Northern Plains. 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. 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 33 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. 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. 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 2000. Mr. Rimington was Director, Business Development from 1994 to 1999 for Northern Plains. Mr. Rimington joined Northern Plains in 1980. There is also an audit committee composed of members appointed by the management committee. The audit committee, consisting of Mr. Lee Hobbs, Vice President and Controller, TransCanada, and Mr. Max Feldman, Vice President, TransCanada, oversees the annual audit process and confers with KPMG LLP, our independent auditors. There are only two members on the audit committee since no member can be appointed by Northern Plains or any of its affiliates. The Management Committee has determined that Mr. Lee Hobbs is our "audit committee financial expert". Our audit committee financial expert is not independent and is not required to be independent because we do not have securities that are listed on a national exchange or national securities association. Code of Ethics The management committee has adopted an Accounting and Financial Reporting Code of Ethics for those officers of Northern Plains that are the equivalent of our principal executive officer and principal financial and accounting officer. The code of ethics is posted on the "Other Postings" section of our website, www.nbpl.nborder.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 those officers of Northern Plains that are the equivalent of our principal executive officer and principal financial and accounting officer within four business days following such amendment or waiver. 34 ITEM 11. EXECUTIVE COMPENSATION. The following table sets forth a summary of compensation paid for the last three years, if applicable, of the equivalent of the chief executive officer of the partnership and the other four most highly compensated executive officers of the Operator 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

~~Number~~Annual ofCompensation ~~Securities~~Other ~~Underlying~~Annual ~~Unexercised~~Long-Term ~~Value~~Compensation ofAll ~~Unexercised~~Other ~~Shares~~Compensation ~~Options/SARs~~Restricted atStock InCompensation Name & Position Year Salary$ Bonus $(1) (2) Awards ($) (3)(4) ($) (5) -~~the~~-~~Money~~------------- ~~Options/SARs~~---- ~~Acquired~~-------- on--------- ~~Value~~------------- ~~December~~---------------------- 31------- William R. Cordes 2004 $325,000 ~~2000~~$ ~~December~~175,000 31-- $ -- $ 4,908 ~~2000~~Chief ~~(1)~~Executive ~~Name~~Officer ~~Exercise~~2003 ~~(#)~~$324,583 ~~Realized~~$ ~~Exercisable~~200,000 ~~Unexercisable~~-- ~~Exercisable~~$ ~~Unexercisable~~99,972 ~~Larry~~$ 3,000 2002 $319,333 $ 240,000 -- $100,051 $ 1,031 Jerry L. ~~DeRoin~~Peters ~~102~~2004 $171,~~990~~380 $ 110,000 -- -- $ 5,~~458~~658 Chief Financial and 2003 $163,~~031~~324 50$ 107,~~875~~500 -- -- $ 276,~~630~~386 Accounting Officer 2002 $159,~~794~~285 $ 110,000 -- ~~William~~-- R$ 23,950 Janet K. ~~Cordes~~Place 472004 $182,~~130~~552 $2 115,~~922~~000 -- -- $ 8,~~001~~675 ~~213~~Vice President & General 2003 $177,~~788~~592 41$ 110,~~327~~000 -- -- $13 6,~~454~~233 Counsel and Secretary 2002 $171,~~935~~500 $1 110,~~945~~000 -- -- $ 7,~~463~~266 ~~Jerry~~NPNG LPaul F. ~~Peters~~Miller 92004 $153,~~090~~298 $ ~~432~~118,~~676~~000 54-- -- $ 5,~~084~~335 9Vice President & General 2003 $148,~~891~~958 $ 2111,~~915,839~~000 -- -- $ ~~393~~90,~~525~~325 ~~(1)~~Manager ~~The~~for ~~dollar~~Northern ~~value~~2002 in$139,850 ~~this~~$ ~~column~~92,000 ~~for~~-- ~~Enron~~-- ~~Corp~~$ 4,721 Border Pipeline Raymond D. ~~stock~~Neppl ~~options~~2004 ~~was~~$165,393 ~~calculated~~$ by82,500 ~~determining~~-- ~~the~~-- ~~difference~~$ ~~between~~5,489 ~~the~~Vice ~~fair~~President, ~~market~~Regulator ~~value~~2003 ~~underlying~~$160,905 ~~the~~$ ~~options~~74,000 as-- of-- ~~December~~$ 314,965 ~~2000~~Affairs (& Market Services 2002 $~~83.1250)~~155,433 ~~and~~$ ~~the~~70,000 ~~grant~~-- ~~price.~~-- $ 5,112

(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, respectively, were made in accordance with his employment agreement. The phantom units vest on the fifth anniversary of the date of the grant. (5) The amounts shown for 2004 include the matching contributions to employees' Enron Corp. Savings Plan and the Thrift Plan for employees of ONEOK, and imputed income on life insurance benefits. For each of 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. Miller, the amount shown for 2004 for matching contributions was $5,080 and for imputed income was $255. For Mr. Neppl, the amount shown for 2004 for matching contributions was $5,481 and for imputed income was $8. 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 35 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. Messrs. Cordes, Peters, Neppl and Miller and Ms. Place 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; Mr. Miller received 137 units in 1999, 123 units in 2000 and 230 units in 2001 and Mr. Neppl received 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. Neppl 1,500 restricted stock incentive units and 2,500 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. OPTION/SAR GRANTS IN 2004 Due to the bankruptcy filing by Enron Corp on December 2, 2001, there were no grants of stock options pursuant to Enron's stock plans to the Named Officers reflected in the Summary Compensation Table. No stock appreciation rights were granted during 2004. AGGREGATED OPTION/SAR EXERCISES IN 2004 AND YEAR-END 2004 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, 2004: 36

~~Estimated~~Number ~~Current~~of ~~Credited~~Securities ~~Current~~Underlying ~~Estimated~~Unexercised ~~Credited~~Value ~~Years~~ of ~~Compensation~~Unexercised ~~Annual~~Options/SARs ~~Benefit~~at ~~Years~~In-the-Money ofOptions/SARs ~~Service~~Shares ~~Covered~~December ~~Payable~~31, ~~Upon~~2004 ~~Service~~December at31, ~~Age~~2004 65(1) ByName ~~Plans~~Acquired ~~Retirement~~on ~~Mr.~~Value ~~Cordes~~-------------------------- ~~30.4~~-------------------------- 43Exercisable Exercise (#) Realized($) Exercisable Unexercisable Exercisable Unexercisable ------------- ------------ ----------- ----------- ------------- ----------- ------------- William R.1 Cordes -- $~~311~~-- 182,~~000~~270 650 $~~142,234~~-- ~~Mr.~~$-- ~~Peters~~Jerry 15L.9 ~~37.8~~Peters ~~$145,293~~-- $-- 7862,~~957~~850 ~~________~~305 ~~NOTE:~~$-- ~~The~~$-- ~~estimated~~Janet ~~annual~~K. ~~benefits~~Place ~~payable~~-- ~~are~~$-- ~~based~~37,383 on332 ~~the~~$-- ~~straight~~$-- ~~life~~Raymond ~~annuity~~D. ~~form~~Neppl ~~without~~-- ~~adjustment~~$-- ~~for~~30,661 ~~any~~304 ~~offset~~$-- ~~applicable~~$-- toPaul aF. ~~participant's~~Miller ~~retirement~~-- ~~subaccount~~$-- in20,684 ~~Enron's~~218 ~~ESOP.~~$-- $--

(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, Neppl 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 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 37 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% benefit accruals after January 1, 2003, with to the Named Officers under the provisions of the foregoing retirement plans. 38

~~General~~ESTIMATED ~~Partnership~~CURRENT ~~Name~~CREDITED ofCURRENT ~~Beneficial~~ESTIMATED ~~Owner~~CREDITED ~~Interest~~YEARS ~~Northern~~OF ~~Border~~COMPENSATION ~~Partners,~~ANNUAL ~~L.P.(1)~~BENEFIT ~~70%~~YEARS TCOF ~~PipeLines,~~SERVICE ~~LP(2)~~COVERED ~~30%~~PAYABLE ~~__________~~UPON ~~(1)~~SERVICE ~~The~~AT ~~address~~AGE of65 ~~Northern~~BY ~~Border~~PLANS ~~Partners,~~RETIREMENT ~~L.P.~~-------- is---------- ~~1400~~------------ ~~Smith~~-------------- ~~Street,~~Mr. ~~Houston,~~Cordes ~~Texas~~34.4 ~~77002~~34.4 ~~Northern~~$ ~~Border~~0 ~~Partners holds its 70% general partnership interest through Northern Border Intermediate Limited Partnership~~$73,979 ~~a subsidiary limited partnership~~Mr. ~~Northern~~Peters ~~Border Partners has three general partners: Northern Plains Natural Gas Company, Pan Border Gas Company and Northwest Border Pipeline Company~~19.1 ~~Northern Plains and Pan Border are wholly-owned subsidiaries of Enron Corp~~19.1 ~~and~~$ ~~Northwest~~0 ~~Border is a wholly-owned subsidiary of The Williams Companies~~$22,933 ~~Inc~~Ms. ~~(2)~~Place ~~The~~24.1 ~~address of TC PipeLines, LP is 110 Turnpike Road, Suite 203, Westborough, Massachusetts 01581~~24.1 TC$ ~~PipeLines~~0 ~~holds its~~ $30~~% general partnership interest through TC PipeLines Intermediate Limited Partnership~~,096 aMr. ~~subsidiary~~Neppl ~~limited~~29.9 ~~partnership~~29.9 TC$ ~~PipeLines~~0 ~~has one general partner~~$41,033 TCMr. ~~PipeLines~~Miller ~~GP,~~14.9 ~~Inc~~14.,7 a$ ~~wholly-owned~~0 ~~subsidiary of TransCanada PipeLines Limited.~~$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.

~~December~~PENSION ~~31,~~PLAN ~~ASSETS~~TABLE ~~2000~~YEARS ~~1999~~OF ~~CURRENT~~SERVICE ~~ASSETS~~Remuneration ~~Cash~~15 ~~and~~YEARS ~~cash~~20 ~~equivalents~~YEARS $25 ~~29,046~~YEARS $30 ~~17,310~~YEARS ~~Accounts~~35 ~~receivable~~YEARS ~~27,128~~------------ ~~21,929~~--------- ~~Related~~--------- ~~party~~--------- ~~receivables~~--------- ~~6,008~~--------- 5125,~~120~~000 ~~Materials~~$ ~~and supplies~~33,091 at$ ~~cost 4~~44,~~957~~122 3$ 55,~~645~~152 ~~Under~~$ ~~recovered~~66,182 ~~cost~~$ of77,213 ~~service~~150,000 --$ 340,~~068~~404 ~~Total~~$ ~~current~~53,872 ~~assets~~$ 67,~~139~~340 51$ 80,~~072~~807 ~~NATURAL~~$ ~~GAS TRANSMISSION PLANT In service 2~~94,~~364,487~~275 2175,~~363,291~~000 ~~Construction~~$ ~~work~~47,716 in$ ~~progress 14~~63,~~405~~622 4$ 79,~~730~~527 ~~Total~~$ ~~property~~95,432 ~~plant~~$ ~~and equipment 2~~111,~~378,892~~338 2200,~~368,021~~000 ~~Less:~~$ ~~Accumulated~~55,029 ~~provision~~$ ~~for depreciation and amortization 691~~73,~~900~~372 ~~636,627~~$ ~~Property~~91,715 ~~plant~~$ ~~and equipment~~110,057 ~~net~~$ 1128,~~686,992~~400 1225,~~731,394~~000 ~~OTHER~~$ ~~ASSETS 14~~62,~~374~~341 14$ 83,~~225~~122 ~~Total~~$ ~~assets~~103,902 $1 124,~~768,505~~682 $1 145,~~796~~463 250,~~691~~000 ~~LIABILITIES~~$ ~~AND~~69,654 ~~PARTNERS'~~$ ~~CAPITAL~~92,872 ~~CURRENT LIABILITIES Current maturities of long-term debt~~ $ 41116,~~000~~090 $ 66139,~~000~~307 ~~Accounts~~$ ~~payable 26~~162,~~087~~525 5300,~~588~~000 ~~Accrued~~$ ~~taxes~~84,279 ~~other~~$ ~~than~~112,372 ~~income~~$ 28140,~~137~~465 26$ 168,~~290~~557 ~~Accrued~~$ ~~interest 14~~196,~~401~~650 16400,~~504~~000 ~~Accumulated~~$ ~~provision~~113,529 ~~for~~$ ~~rate~~151,372 ~~refunds~~$ 4189,~~726~~215 2$ 227,~~317~~057 ~~Total~~$ ~~current liabilities 114~~264,~~351~~900 ~~116~~450,~~699~~000 ~~LONG-TERM~~$ ~~DEBT~~128,154 ~~NET~~$ OF170,872 ~~CURRENT~~$ ~~MATURITIES 22~~213,~~267~~590 ~~834~~$ 256,~~459~~307 ~~RESERVES~~$ ~~AND DEFERRED CREDITS 4~~299,~~892~~025 10500,~~698~~000 ~~COMMITMENTS~~$ ~~AND~~142,779 ~~CONTINGENCIES~~$ ~~(Note~~190,372 6)$ ~~PARTNERS' CAPITAL 826~~237,~~995~~965 ~~834,835 Total liabilities and partners' capital~~ $1 285,~~768,505~~557 $~~1,796,691~~ ~~The accompanying notes are an integral part of these financial statements.~~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 Officers as of December 31, 2004 is 1/12 years. For purposes of the table, the annual social security covered compensation benefit of $46,284 was used in the excess benefit calculation. 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. 39 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 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 Neppl 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 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 ONEOK's 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 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. 40 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 12 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. 41 ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDERS MATTERS. The following table sets forth the beneficial ownership of our general partnership interests. There are no limited partnership interests.

~~Year~~GENERAL ~~Ended~~NAME ~~December~~OF ~~31,~~BENEFICIAL ~~2000~~PARTNERSHIP ~~1999~~OWNER ~~1998~~INTEREST ~~OPERATING~~Northern ~~REVENUES~~Border ~~Operating~~70% ~~revenues $334~~Partners,~~978~~ ~~$300,664~~L.P. ~~$196,600 Provision for rate refunds~~ (~~23,956~~1) ~~(2,317)~~TC ~~-- Operating revenues~~PipeLines, ~~net~~LP 311,022 298,347 196,600 OPERATING EXPENSES Operations and maintenance 41,548 38,708 29,447 Depreciation and amortization 57,328 51,908 40,989 Taxes other than income 27,979 30,320 21,381 Regulatory credit -- -- (~~8,878~~2) Operating expenses 126,855 120,936 82,939 OPERATING INCOME 184,167 177,411 113,661 INTEREST EXPENSE Interest expense 65,489 60,312 44,542 Interest expense capitalized (328) (98) (19,001) Interest expense, net 65,161 60,214 25,541 OTHER INCOME Allowance for equity funds used during construction 305 101 10,237 Other income, net 7,753 1,262 1,874 Other income 8,058 1,363 12,111 NET INCOME TO PARTNERS $127,064 $118,560 $100,231 The accompanying notes are an integral part of these financial statements.30%

---------- (1) The address of Northern Border Partners is 13710 FNB Parkway, Omaha, NE 68154-5200. Northern Border Partners holds its 70% general partnership interest through Northern Border Intermediate Limited Partnership, a subsidiary limited partnership. Northern Border Partners has three general partners: Northern Plains, Pan Border and Northwest Border. Northern Plains and Pan Border are wholly-owned subsidiaries of ONEOK, Inc. and Northwest Border is a wholly-owned subsidiary of TransCanada. (2) The address of TC PipeLines is 110 Turnpike Road, Suite 203, Westborough, Massachusetts 01581. TC PipeLines holds its 30% general partnership interest through TC PipeLines Intermediate Limited Partnership, a subsidiary limited partnership. TC PipeLines has one general partner, TC PipeLines GP, Inc., a wholly-owned subsidiary of TransCanada. ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS. We have extensive ongoing relationships with our general partners and ONEOK. Northern Plains has acted and will continue to act as the operator of our pipeline system pursuant to the terms of the operating agreement. The initial term of the operating agreement expires in 2007. The operating agreement will continue in effect thereafter on a year-to-year basis unless terminated by us or Northern Plains upon six months written notice by either party. The operator is entitled to reimbursement for all reasonable costs, including overhead and administrative expenses, incurred by it and its affiliates in connection with the performance of its responsibilities as operator. In addition, we have agreed to indemnify the operator against any claims and liabilities arising out of the good faith performance by the operator of its responsibilities under our partnership agreement, to the extent the operator is acting within the scope of its authority and in the course of our business. For the year ended December 31, 2004, the aggregate amount charged by Northern Plains and its current and former affiliates, for its services as operator, was approximately $18.3 million. While Northern Plains continues to perform its obligations, certain of the services are provided through CrossCountry and Enron through the Northern Border Transition Agreement and through ONEOK. This transition services agreement provides for the continued use by Northern Plains of certain services, data applications, systems and infrastructure relied on by Northern Plains and to perform under the Operating Agreement with us. 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 approximately $2 million for the full term of the agreement. 42 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 our Chicago III Expansion Project. 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." Our interests could conflict with the interests of our general partners or their affiliates, and in such case the members of our management committee will generally have a fiduciary duty to resolve such conflicts in a manner that is in our best interest. Unless otherwise provided for in a partnership agreement, the laws of 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. These rules apply to our management committee. Because of the competing interests identified above, the Northern Border Pipeline Company Partnership Agreement contains provisions that modify certain of these fiduciary duties. For example: - Our partnership agreement provides that we indemnify the members of our management committee and Northern Plains, as the operator, against all actions if such actions were in good faith and within the scope of their authority in the course of our business. It also provides that such persons will not be liable for any liabilities incurred by us as a result of such acts. - Our partnership agreement states that our general partners will not be liable to third persons for our losses, deficits, liabilities or obligations (unless our assets have been exhausted). - Our partnership agreement requires that any contract entered into on our behalf must contain a provision limiting the claims of persons to our assets and expressly waiving any rights of such persons to proceed against our general partners individually. - Our partnership agreement relieves Northern Border Partners and TC PipeLines, their affiliates and their transferees from any duty to offer business opportunities to us, except that neither our general partners or their affiliates may pursue any opportunity relating to expansion or improvements of our pipeline system as it existed on January 15, 1999. ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES. The following sets forth fees billed for the audit and other services provided by KPMG LLP, our principal accountant, for the fiscal years ended December 31, 2004 and December 31, 2003:

Year Ended December 31, ~~2000~~2004 ~~1999~~2003 ~~1998~~Audit ~~CASH~~fees FLOWS FROM OPERATING ACTIVITIES: Net income to partners $ 127,064 $ 118,560 $ 100,231 Adjustments to reconcile net income to partners to net cash provided by operating activities: Depreciation and amortization 57,682 51,962 41,005 Provision for rate refunds 25,082 2,317 -- Rate refunds paid (~~22,673~~1) ~~-- -- Allowance for equity funds used during construction (305) (101) (10~~$412,~~237)~~790 Reserves and deferred credits (5,806) 880 (10) Regulatory credit -- -- (9,105) Changes in components of working capital (3,002) (2,112) (18,471) Other (2,075) (40) 364 Total adjustments 48,903 52,906 3,546 Net cash provided by operating activities 175,967 171,466 103,777 CASH FLOWS FROM INVESTING ACTIVITIES: Capital expenditures for property, plant and equipment, net (15,523) (101,678) (651,169) CASH FLOWS FROM FINANCING ACTIVITIES: Contributions from partners -- -- 223,000 Distributions to partners (134,904) (127,163) (61,205) Issuance of long-term debt, net 75,000 289,026 403,000 Retirement of long-term debt ($111,~~000)~~810 ~~(263,000)~~ Audit--related ~~Increase~~fees in$ ~~bank overdraft 22,437~~ -- --$ ~~Proceeds received upon termination of interest rate forward agreements~~ -- ~~12,896~~Tax --fees ~~Long-term~~$ ~~debt financing costs (241) (1,626)~~ -- ~~Net~~$ ~~cash provided by (used in) financing activities (148,708) (89,867) 564,795 NET CHANGE IN CASH AND CASH EQUIVALENTS 11,736 (20,079) 17,403 Cash and cash equivalents~~-~~beginning of year 17,310 37,389 19,986 Cash and cash equivalents~~-end of year $ 29,046 $ 17,310 $ 37,389 Changes in components of working capital: Accounts receivable $ (6,087) $ (8,145) $ (1,567) Materials and supplies (1,312) (285) 317 Accounts payable 1,585 (4,598) (10,769) Accrued taxes other than income 1,847 6,462 (466) Accrued interest (2,103) 4,741 1,396 Over/under recovered cost of service 3,068 (287) (7,382) Total $ (3,002) $ (2,112) $ (18,471) The accompanying notes are an integral part of these financial statements.

43 ~~All other fees $ -- $ -- -------- -------- Total $412,790 $111,810~~

(1) Includes fees for the audit of annual financial statements and audit of internal control over financial reporting related to Northern Border Partners' audit, reviews of the related quarterly financial statements and reviews and related consents and comfort letters for documents filed with the Securities and Exchange Commission. The fees related to the audit of internal control were pre-approved by the audit committee of Northern Border Partners. The remaining fees were approved as discussed below. Before our independent principal accountant is engaged each year for the annual audit and other audit and any non-audit services, these services and fees are reviewed and approved by our audit committee and recommended to our Management Committee for approval. 44 PART IV ITEM 15. EXHIBITS, 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 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 Northern Border Partners, L.P.'s Form S-1, SEC File No. 33-66158 ("Form S-1")). * 3.2 Seventh Supplement Amending Northern Border Pipeline Company General Partnership Agreement (incorporated by reference to Exhibit 10.15 to Form S-1). * 3.3 Eighth Supplement Amending Northern Border Pipeline Company General Partnership Agreement (incorporated by reference to Exhibit 10.15 to Northern Border Pipeline Company's Form S-4 Registration Statement, filed on October 7, 1999, Registration No. 333-88577 ("Form S-4"). * 3.4 Ninth Supplement Amending Northern Border Pipeline Company General Partnership Agreement (incorporated by reference to Exhibit 10.37 to Northern Border Pipeline Company's Registration Statement on Form S-4, filed on November 13, 2001, Registration No. 333-73282 ("2001 Form S-4"). 3.5 Tenth Supplement Amending Northern Border Pipeline Company General Partnership Agreement dated March 3, 2005. * 4.1 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 4.1 to Form S-4). * 4.2 Indenture, dated as of September 17, 2001, between Northern Border Pipeline Company and Bank One Trust Company, N.A. (incorporated by reference to Exhibit 4.2 to 2001 Form S-4). * 4.3 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) (Filed No. 333-88577). * 10.1 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). * 10.2 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 Northern Border Partners, L.P.'s Current Report on Form 8-K dated June 26, 2002 (File No. 1-12202)). * 10.3 First Amendment to the Revolving Credit Agreement dated as of April 9, 2004 between Northern Border Pipeline Company, Bank

45 One, NA and the lenders named therein. (incorporated by reference to Exhibit No. 10.1 to Northern Border Pipeline Company Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2004 (File No. 333-88577)). * 10.4 Form of Conveyance, Contribution and Assumption Agreement among Northern Plains Natural Gas Company, Northwest Border Pipeline Company, Pan Border Gas Company, Northern Border Partners, L.P., and Northern Border Intermediate Limited Partnership (incorporated by reference to Exhibit 10.16 to Form S-1). * 10.5 Form of Contribution, Conveyance and Assumption Agreement among TC PipeLines, LP and certain other parties. (incorporated by reference to Exhibit 10.2 to TC PipeLines, LP's Form S-1, SEC File No. 333-69947 ("TC Form S-1")). +*10.6 Form of Termination Agreement with ONEOK dated as of January 5, 2005. (incorporated by reference to Exhibit 99.1 to Northern Border Partners, L.P. Form 8-K filed on January 11, 2005 (File No. 1-12201)). +*10.7 ONEOK, Inc. 2005 Supplemental Executive Retirement Plan. (incorporated by reference to Exhibit 99.1 to Northern Border Partners, L.P. Form 8-K filed on January 11, 2005 (File No. 1-12201)). +*10.8 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)). +*10.9 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)). +*10.10 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)). +*10.11 ONEOK, Inc. Employee Non-Qualified Deferred Compensation Plan, as amended, dated February 2001 (incorporated by reference from Exhibit 10(g) to ONEOK's Form 10-K for the year ended December 31, 2001 (File No. 1-13643)). +*10.12 ONEOK, Inc. Annual Officer Incentive Plan (incorporated by reference from Exhibit 10(f) to Form 10-K for the year ended December 31, 2001 (File No. 1-13643)). *10.13 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 Northern Border Partners, L.P.'s Form 10-K/A for the year ended December 31, 1998 File No. 1-12202 ("1998 10-K")). *10.14 Northern Border Transition Services Agreement dated November 17, 2004, by and between ONEOK, Inc. and CCE Holdings, LLC. (incorporated by reference to Exhibit 10.24 to Northern Border Partners, L.P.'s Form 10-K for the year ended December 31, 2004 (File No. 1-122022)). 12.1 Statement re computation of ratios.

46 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 Northern Border Partners, L.P.'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. 47 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 11 day of March, 2005. NORTHERN BORDER PIPELINE COMPANY (A Texas General partnership) BY: Northern Plains Natural Gas Company, As Operator By:/s/ Jerry L. Peters --------------------- Jerry L. Peters Vice President, Finance and Treasurer 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.

TCSignature ~~Northern~~Title ~~TransCanada~~Date ~~PipeLines~~--------- ~~Border~~----- ~~Border~~---- ~~TransCan~~/s/ ~~Intermediate~~William ~~Intermediate~~R. ~~Total~~Cordes ~~PipeLine~~President, Northern ~~Limited~~Plains ~~Limited~~Natural ~~Partners'~~March ~~Ltd.~~11, ~~Ltd.~~2005 ~~Partnership~~--------------------- ~~Partnership~~Gas ~~Capital~~Company ~~Partners'~~William ~~Capital~~R. atCordes ~~December~~(functional ~~31,~~equivalent ~~1997~~to $the ~~34,885~~registrant's $principal ~~139,539~~executive $officer) --and ~~$406,988~~Management $Committee ~~581,412~~Member ~~Net~~/s/ ~~income~~Jerry toL. ~~partners~~Peters ~~6,014~~Vice 24President,~~055~~ --Finance ~~70,162~~and ~~100,231~~March ~~Contributions received 13~~11,~~380~~ ~~53,520~~2005 -- ~~156,100 223,000 Distributions paid (3,673) (14,689)~~ ------------------- ~~(42~~Treasurer,~~843)~~ ~~(61,205)~~Jerry ~~Partners'~~L. ~~Capital~~Peters atNorthern ~~December~~Plains ~~31,~~Natural ~~1998~~Gas ~~50,606~~Company ~~202,425~~(functional --equivalent ~~590,407 843,438 Net income~~ to ~~partners~~the ~~2,930~~registrant's ~~11,715~~principal ~~20,923~~financial ~~82,992~~and ~~118,560~~accounting ~~Distributions paid (5,206~~officer) ~~(20,819)~~/s/ ~~(12,124)~~David ~~(89,014)~~L. ~~(127,163)~~Kyle ~~Ownership~~Management ~~transfer~~Committee ~~(48,330)~~Member ~~(193,321)~~March ~~241~~11,~~651~~ 2005 -- -- ~~Partners' Capital at December 31, 1999~~ -- -- ~~250,450 584,385 834,835 Net income to partners~~ -- -- ~~38,119 88,945 127,064 Distributions paid~~ -- ------- ~~(40,471)~~David ~~(94,433)~~L. ~~(134,904)~~Kyle ~~Partners'~~/s/ ~~Capital~~Max atFeldman ~~December~~Management ~~31,~~Committee ~~2000~~Member $March --11, $2005 --------------------- ~~$248,098~~Max ~~$578,897~~Feldman $/s/ ~~826,995~~Paul ~~The~~E. ~~accompanying~~Miller ~~notes~~Management ~~are~~Committee anMember ~~integral~~March ~~part~~11, of2005 ~~these~~--------------------- ~~financial~~Paul ~~statements~~E. Miller

48 SUPPLEMENTAL INFORMATION TO BE FURNISHED WITH REPORTS FILED PURSUANT TO SECTION 15(d) OF THE ACT BY REGISTRANTS WHICH HAVE NOT REGISTERED SECURITIES PURSUANT TO SECTION 12 OF THE ACT No annual report to security holders covering our last fiscal year has been sent to our security holders and no proxy statement, form of proxy or other proxy soliciting material has been sent to more than ten of our security holder's with respect to any annual or other meeting of security holders. No such report or proxy material is expected to be furnished to security holders subsequent to the filing of this Annual Report on Form 10-K. 49 NORTHERN BORDER PIPELINE COMPANY INDEX TO FINANCIAL STATEMENTS

~~December~~PAGE ~~31,~~NO. ~~(Thousands~~----------- ofFinancial ~~dollars)~~Statements ~~2000~~Report ~~1999~~of ~~1992~~Independent ~~Senior~~Registered ~~Notes~~Public -Accounting ~~average~~Firm ~~8.49%~~F-2 ~~and~~Balance ~~8.43%~~Sheet at- December 31, ~~2000~~2004 and ~~1999,~~2003 ~~respectively,~~F-3 ~~due~~Statement ~~from~~of ~~2000~~Income to- ~~2003~~Years ~~$184~~Ended F-4 December 31,~~000~~ ~~$250~~2004,~~000~~ ~~Pipeline~~2003 ~~Credit~~and ~~Agreement~~2002 ~~Term~~Statement ~~loan,~~of ~~due~~Comprehensive ~~2002~~Income ~~424,000~~- ~~439,000~~Years ~~Five~~Ended F-~~year~~4 ~~revolving~~December ~~credit~~31, ~~facility 45~~2004,~~000~~ --2003 ~~1999~~and ~~Senior~~2002 ~~Notes~~Statement of Cash Flows - ~~7.75%,~~Years ~~due~~Ended ~~2009~~F-5 ~~200~~December 31,~~000~~ ~~200~~2004,~~000~~ ~~Unamortized~~2003 ~~proceeds~~and ~~from~~2002 ~~termination~~Statement of ~~interest~~Changes ~~rate~~in ~~forward~~Partners' ~~agreements~~Equity 11- F-6 Years Ended December 31,~~107~~ 122004,~~397~~ ~~Unamortized~~2003 ~~debt~~and ~~discount~~2002 ~~(840)~~Notes ~~(938)~~to ~~Total~~Financial ~~863,267~~Statements ~~900,459~~F-7 ~~Less:~~through ~~Current~~F-18 ~~maturities~~Financial Statements Schedule Report of ~~long-term~~Independent ~~debt~~Registered ~~41,000~~Public ~~66,000~~Accounting ~~Long~~Firm on Schedule S-~~term~~1 ~~debt~~Schedule ~~$822,267~~II ~~$834,459~~- Valuation and Qualifying Accounts S-2

F-1 REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM Northern Border Pipeline Company: We have audited the accompanying balance sheets of Northern Border Pipeline Company as of December 31, 2004 and 2003, and the related 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 financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with 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 financial statements referred to above present fairly, in all material respects, the financial position of Northern Border Pipeline Company as of December 31, 2004 and 2003, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2004, in conformity with accounting principles generally accepted in the United States of America. /s/ KPMG LLP Omaha, Nebraska March 2, 2005 F-2 NORTHERN BORDER PIPELINE COMPANY BALANCE SHEET (IN THOUSANDS)

~~Operating~~DECEMBER ~~Operating~~31, ~~Net~~--------------------------- ~~Income~~2004 2003 ----------- ----------- ASSETS CURRENT ASSETS Cash and cash equivalents $ 20,355 $ 28,732 Accounts receivable (Innet ~~thousands~~of allowance for doubtful accounts of $4,208 in 2004) ~~Revenues~~32,559 33,292 Related party receivables (net ~~Income~~of toallowance ~~Partners~~for ~~2000~~doubtful ~~First~~accounts ~~Quarter~~of $764,~~241~~815 ~~$44~~in 2003) 1,~~628~~311 ~~$28~~395 Materials and supplies,~~744~~ ~~Second~~at ~~Quarter~~cost 773,~~346~~409 444,~~305~~818 29Prepaid expenses and other 1,~~413~~688 ~~Third~~2,267 ~~Quarter~~----------- 78----------- Total current assets 59,~~241~~322 4769,~~584~~504 34----------- ----------- NATURAL GAS TRANSMISSION PLANT In service 2,~~293~~444,729 ~~Fourth~~2,434,369 ~~Quarter~~Construction 79work in progress 2,~~194~~768 474,~~650~~447 34----------- ----------- Total property,~~614~~ ~~1999~~plant ~~First~~and ~~Quarter~~equipment 2,447,497 2,438,816 Less: Accumulated provision for depreciation and amortization 903,664 847,061 ----------- ----------- Property, plant and equipment, net 1,543,833 1,591,755 ----------- ----------- OTHER ASSETS Derivative financial instruments -- 16,648 Unamortized debt expense 3,837 5,206 Regulatory asset 11,807 8,196 Other 4,549 -- ----------- ----------- Total other assets 20,193 30,050 ----------- ----------- Total assets $73 1,~~635~~623,348 $44 1,~~271~~691,309 =========== =========== LIABILITIES AND PARTNERS' EQUITY CURRENT LIABILITIES Accounts payable $30 4,~~315~~058 ~~Second~~$ ~~Quarter~~7,055 73Related party payables 5,~~022~~286 4315,~~788~~582 Accrued taxes other than income 27,113 28,~~933~~947 ~~Third~~Accrued ~~Quarter~~interest 7311,~~925~~365 4410,~~017~~717 29----------- ----------- Total current liabilities 47,~~127~~822 ~~Fourth~~62,301 ~~Quarter~~----------- 77----------- LONG-TERM DEBT 603,~~765~~860 45821,~~335~~498 30----------- ----------- RESERVES AND DEFERRED CREDITS 4,~~185~~526 5,072 ----------- ----------- COMMITMENTS AND CONTINGENCIES (Note 7) PARTNERS' EQUITY Partners' capital 963,378 797,236 Accumulated other comprehensive income 3,762 5,202 ----------- ----------- Total partners' equity 967,140 802,438 ----------- ----------- Total liabilities and partners' equity $ 1,623,348 $ 1,691,309 =========== ===========

The accompanying notes are an integral part of these financial statements. F-3 NORTHERN BORDER PIPELINE COMPANY STATEMENT OF INCOME (IN THOUSANDS)

~~Column~~YEAR AENDED ~~Column~~DECEMBER B31, ~~Column~~------------------------------------------ C2004 ~~Column~~2003 D2002 ~~Column~~---------- E---------- ~~Additions~~---------- ~~Deductions~~OPERATING ~~Balance~~REVENUES at$ ~~Charged~~329,115 to$ ~~Charged~~324,185 ~~For~~$ ~~Purpose~~321,050 ~~For~~---------- ~~Beginning~~---------- ~~Costs~~---------- OPERATING EXPENSES Operations and tomaintenance ~~Other~~33,763 ~~Which~~43,791 ~~Reserves~~41,442 ~~Balance~~Depreciation atand ~~Description~~amortization of58,375 ~~Year~~57,779 ~~Expenses~~58,714 ~~Accounts~~Taxes ~~Were~~other ~~Created~~than ~~End~~income of29,368 ~~Year~~29,634 ~~Reserve~~28,436 ~~for~~---------- ~~regulatory~~---------- ~~issues~~---------- ~~2000~~Operating $7expenses 121,~~376~~506 $1131,~~800~~204 $128,592 ---------- $7---------- ---------- OPERATING INCOME 207,~~376~~609 $1192,~~800~~981 ~~1999~~192,458 $6---------- ---------- ---------- INTEREST EXPENSE Interest expense 41,~~726~~374 $44,903 ~~650~~51,550 $Interest expense capitalized (18) (46) (25) ---------- $---------- ---------- $7Interest expense,~~376~~ ~~1998~~net $641,~~726~~356 $44,857 51,525 ---------- $---------- $---------- OTHER INCOME (EXPENSE) Allowance for equity funds used during construction 31 53 26 Other income 2,552 1,373 2,476 Other expense (2,059) (1,350) (716) ---------- ---------- ---------- Other income (expense), net 524 76 1,786 ---------- ---------- ---------- NET INCOME TO PARTNERS $6 166,~~726~~777 $ 148,200 $ 142,719 ========== ========== ==========

NORTHERN BORDER PIPELINE COMPANY STATEMENT OF COMPREHENSIVE INCOME (IN THOUSANDS)

The accompanying notes are an integral part of these financial statements. F-4 NORTHERN BORDER PIPELINE COMPANY STATEMENT OF CASH FLOWS (IN THOUSANDS)

Changes in components of working capital: Accounts receivable $ (2,969) $ (4,908) $ 5,369 Materials and supplies 697 (97) 152 Prepaid expenses and other 578 (422) (113) Accounts payable (9,731) 3,758 10,006 Accrued taxes other than income (1,834) 573 1,207 Accrued interest 648 (2,455) (3,353) ---------- ---------- ---------- Total $ (12,611) $ (3,551) $ 13,268 ========== ========== ==========

The accompanying notes are an integral part of these financial statements. F-5 NORTHERN BORDER PIPELINE COMPANY STATEMENT OF CHANGES IN PARTNERS' EQUITY (IN THOUSANDS)

The accompanying notes are an integral part of these financial statements. F-6 NORTHERN BORDER PIPELINE COMPANY NOTES TO FINANCIAL STATEMENTS 1. ORGANIZATION AND MANAGEMENT Northern Border Pipeline Company (Northern Border Pipeline) is a Texas general partnership formed in 1978. The ownership percentages of the partners in Northern Border Pipeline (Partners) at December 31, 2004 and 2003 are as follows:

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 Northern Border Intermediate Limited Partnership (Partnership) and one representative from TC PipeLines Intermediate Limited Partnership (TC PipeLines). The Partnership's representatives selected by its general partners, 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, a wholly-owned subsidiary of TransCanada PipeLines Limited, which is a subsidiary of TransCanada Corporation, and affiliate of TC PipeLines, have 35%, 22.75% and 12.25%, respectively, of the voting interest on the Management Committee. The representative designated by TC PipeLines votes the remaining 30% interest. In November 2004, ONEOK purchased Northern Plains and Pan Border from CCE Holdings, LLC (CCE Holdings). CCE Holdings, a joint venture between Southern Union Company and GE Commercial Finance Energy Financial purchased Northern Plains and Pan Border as part of its acquisition of CrossCountry Energy, LLC (CrossCountry). On March 31, 2004, Enron Corp. (Enron) transferred its ownership interest in Northern Plains and Pan Border 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 Northern Border Pipeline through Northern Plains. The day-to-day management of Northern Border Pipeline's affairs is the responsibility of Northern Plains, as defined by an operating agreement between Northern Border Pipeline and Northern Plains. Northern Border Pipeline is charged for the salaries, benefits and expenses of Northern Plains. 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 by ONEOK. For the years ended December 31, 2004, 2003, and 2002, Northern Border Pipeline's charges from Northern Plains and its current and former affiliates totaled approximately $18.3 million, $25.6 million and F-7 NORTHERN BORDER PIPELINE COMPANY NOTES TO FINANCIAL STATEMENTS 1. ORGANIZATION AND MANAGEMENT (continued) $22.8 million, respectively. See Note 11 for a discussion of Northern Border Pipeline's previous relationships with Enron and developments involving Enron. 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (A) Use of Estimates The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. (B) Government Regulation Northern Border Pipeline is subject to regulation by the Federal Energy Regulatory Commission (FERC). Northern Border Pipeline's accounting policies conform to Statement of Financial Accounting Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation." Accordingly, certain assets that result from the regulated ratemaking process are recorded that would not be recorded under accounting principles generally accepted in the United States of America for nonregulated entities. At December 31, 2004 and 2003, Northern Border Pipeline has reflected regulatory assets, which are currently being recovered or are expected to be recovered from its shippers, of approximately $11.8 million and $8.2 million, respectively, on the balance sheet. Northern Border Pipeline is recovering these regulatory assets from its shippers over varying time periods, which range from 5 to 44 years. Northern Border Pipeline continually assesses whether the recovery of the regulatory assets is probable by considering such factors as regulatory changes and the impact of competition. Northern Border Pipeline believes the recovery of the existing regulatory assets is probable. If future recovery ceases to be probable, Northern Border Pipeline would be required to write off the regulatory assets at that time. (C) Revenue Recognition Northern Border Pipeline transports gas for shippers under a tariff regulated by the FERC. The tariff specifies the calculation of amounts to be paid by shippers and the general terms and conditions of transportation service on the pipeline system. Northern Border Pipeline's revenues are derived from agreements for the receipt and delivery of gas at points along the pipeline system as specified in each shipper's individual transportation contract. Revenues for Northern Border Pipeline are recognized based upon contracted capacity and actual volumes transported under transportation service agreements. An allowance for doubtful accounts is recorded in situations where collectibility is not reasonably assured. F-8 NORTHERN BORDER PIPELINE COMPANY NOTES TO FINANCIAL STATEMENTS 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued) (C) Revenue Recognition (continued) Northern Border Pipeline does not own the gas that it transports, and therefore it does not assume the related natural gas commodity risk. (D) Income Taxes Income taxes are the responsibility of the Partners and are not reflected in these financial statements. However, the Northern Border Pipeline FERC tariff establishes the method of accounting for and calculating income taxes and requires Northern Border Pipeline to reflect in its rates 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. (E) 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. (F) Property, Plant and Equipment and Related Depreciation and Amortization Property, plant and equipment is stated at original cost. During periods of construction, Northern Border Pipeline is permitted to capitalize an allowance for funds used during construction, which represents the estimated costs of funds used for construction purposes. The original cost of property retired is charged to accumulated depreciation and amortization, net of salvage and cost of removal. No retirement gain or loss is included in income except in the case of retirements or sales of entire regulated operating units. Maintenance and repairs are charged to operations in the period incurred. The provision for depreciation and amortization of the transmission line is an integral part of Northern Border Pipeline's FERC tariff. The effective depreciation rate applied to Northern Border Pipeline's transmission plant is 2.25%. Composite rates are applied to all other functional groups of property having similar economic characteristics. (G) Risk Management Financial instruments are used by Northern Border Pipeline in the management of its interest rate exposure. A control environment has been established which includes policies and procedures for risk assessment and the approval, reporting and monitoring of financial instrument activities. Northern Border Pipeline does not use these instruments for trading purposes. SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities," as amended by SFAS F-9 NORTHERN BORDER PIPELINE COMPANY NOTES TO FINANCIAL STATEMENTS 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued) (G) Risk Management (continued) 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 6 for a discussion of Northern Border Pipeline's derivative instruments and hedging activities. (H) Reclassifications Certain reclassifications have been made to the financial statements for prior years to conform with the current year presentation. 3. RATES AND REGULATORY ISSUES 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. 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. 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. 4. TRANSPORTATION SERVICE AGREEMENTS Operating revenues are collected pursuant to the FERC tariff through firm transportation service agreements. The firm service agreements extend for various terms with termination dates that range from December 2004 to December 2013. Northern Border Pipeline also has interruptible transportation service agreements and other transportation service agreements with numerous shippers. F-10 NORTHERN BORDER PIPELINE COMPANY NOTES TO FINANCIAL STATEMENTS 4. TRANSPORTATION SERVICE AGREEMENTS (continued) Under the capacity release provisions of Northern Border Pipeline's FERC tariff, shippers are allowed to release all or part of their capacity either permanently for the full term of the contract or temporarily. A temporary capacity release does not relieve the original contract shipper from its payment obligations if the replacement shipper fails to pay for the capacity temporarily released to it. At December 31, 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 December 2004 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-11 NORTHERN BORDER PIPELINE COMPANY NOTES TO FINANCIAL STATEMENTS 5. CREDIT FACILITIES AND LONG-TERM DEBT Detailed information on long-term debt is as follows:

Northern Border Pipeline has 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 2002 Pipeline Credit Agreement permits Northern Border Pipeline to choose among various interest rate options, to specify the portion of the borrowings to be covered by specific interest rate options and to specify the interest rate period. Northern Border Pipeline is required to pay a fee on the principal commitment amount of $175 million. The 2002 Pipeline Credit Agreement will mature in 2005, and is expected to be replaced with a similar credit facility. 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, incurred a $0.4 million loss related to the unamortized debt costs and discount associated with the debt and received $2.5 million from the termination of interest rate swaps associated with the debt (see Note 6). The net loss from the redemption 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 net unamortized loss on reacquired debt was $2.6 million, which is recorded in regulatory assets on the balance sheet. Interest paid, net of amounts capitalized, during the years ended December 31, 2004, 2003 and 2002 was $41.1 million, $47.8 million and $55.3 million, respectively. Aggregate required repayments of long-term debt for the next five years are $150 million in 2007 and $200 million in 2009. Aggregate required repayments of long-term debt thereafter total $250 million. There are no required repayment obligations for 2005, 2006 or 2008. F-12 NORTHERN BORDER PIPELINE COMPANY NOTES TO FINANCIAL STATEMENTS 5. CREDIT FACILITIES AND LONG-TERM DEBT (continued) Certain of Northern Border Pipeline's long-term debt and credit arrangements contain requirements as to the maintenance of minimum partners' capital and debt to capitalization ratios, leverage ratios and interest coverage ratios that restrict the incurrence of other indebtedness by Northern Border Pipeline and also place certain restrictions on distributions to the partners of Northern Border Pipeline. 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 of 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. The following estimated fair values of financial instruments represent the amount at which each instrument could be exchanged in a current transaction between willing parties. Based on quoted market prices for similar issues with similar terms and remaining maturities, the estimated fair value of the aggregate of the 1999 Pipeline Senior Notes, 2001 Pipeline Senior Notes and 2002 Pipeline Senior Notes was approximately $652 million and $739 million at December 31, 2004 and 2003, respectively. Northern Border Pipeline presently intends to maintain the current schedule of maturities for the 1999 Pipeline Senior Notes, the 2001 Pipeline Senior Notes and the 2002 Pipeline Senior Notes, which will result in no gains or losses on their respective repayments. The fair value of Northern Border Pipeline's variable rate debt approximates the carrying value since the interest rates are periodically adjusted to reflect current market conditions. 6. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES Prior to the anticipated issuance of fixed rate debt, Northern Border Pipeline entered into forward starting interest rate swap agreements. The interest rate swap agreements were 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 did 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 debt. For the year ended December 31, 2002, Northern Border Pipeline received $2.4 million from terminated interest rate swap agreements. During the years ended December 31, 2004, 2003, and 2002, respectively, Northern Border Pipeline amortized approximately $1.4 million, $1.6 million, and $1.4 million related to the terminated interest rate swap agreements as a reduction to interest expense from accumulated other comprehensive income. Northern Border Pipeline expects to amortize approximately $1.5 million as a reduction to interest expense in 2005. 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. F-13 NORTHERN BORDER PIPELINE COMPANY NOTES TO FINANCIAL STATEMENTS 6. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES (continued) In November 2004, Northern Border Pipeline terminated its interest rate swap agreements with notional amounts of $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 5). The remaining $5.0 million is recorded in long-term debt with such amount amortized to interest expense over the remaining life of the interest rate swap agreements. During the year ended December 31, 2004, Northern Border Pipeline amortized approximately $0.2 million as a reduction to interest expense. Northern Border Pipeline expects to amortize approximately $2.2 million as a reduction of interest expense in 2005 for these agreements. At December 31, 2003, the average effective interest rate on Northern Border Pipeline's interest rate swap agreements was 2.31%. Northern Border Pipeline's interest rate swap agreements were designated as fair value hedges as they were entered into to hedge the fluctuations in the market value of the 2002 Pipeline Senior Notes. The accompanying balance sheet at December 31, 2003, reflects an unrealized gain of approximately $16.6 million in derivative financial assets with a corresponding increase in long-term debt. 7. COMMITMENTS AND CONTINGENCIES Operating Leases Future minimum lease payments under non-cancelable operating leases on office space and rights-of-way are as follows (in thousands):

Expenses incurred related to these lease obligations for the years ended December 31, 2004, 2003 and 2002, were $0.6 million, $0.7 million, and $0.1 million, respectively. Cash Balance Plan As further discussed in Note 11, 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. Northern Border Pipeline recorded estimated charges associated with the termination of the cash balance plan of $3.1 million in 2003. In 2004, Northern Border Pipeline reduced its expense by $3.1 million, since it determined it is no longer liable for termination costs of the Cash Balance Plan (see Note 11). F-14 NORTHERN BORDER PIPELINE COMPANY NOTES TO FINANCIAL STATEMENTS 7. COMMITMENTS AND CONTINGENCIES (continued) Capital Expenditures Total capital expenditures for 2005 are estimated to be $40 million. Funds required to meet the capital expenditures for 2005 are anticipated to be provided primarily by borrowings under the 2002 Pipeline Credit Agreement or similar facilities and operating cash flows. Environmental Matters Northern Border Pipeline 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. Northern Border Pipeline believes that the resolution of these issues will not have a material adverse impact on Northern Border Pipeline's results of operations or financial position. 8. 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 expenditures with 50% equity capital contributions from its F-15 NORTHERN BORDER PIPELINE COMPANY NOTES TO FINANCIAL STATEMENT 8. CASH DISTRIBUTION POLICY (Continued) 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 fron $90 million to $15 million. 9. QUARTERLY FINANCIAL DATA (Unaudited)

10. OTHER INCOME (EXPENSE) Other income (expense) on the statement of income includes such items as investment income, nonoperating revenues and expenses, and nonrecurring other income and expense items. For the years ended December 31, 2004, 2003 and 2002, other income included income from interconnections constructed of $0.7 million, $0.1 million and $0.1 million, respectively. Other income for 2004 also included an adjustment to reserves previously established of $0.4 million. Other expense for the year ended December 31, 2004, included approximately $0.6 million due to reserves established for costs associated with a potential future project and $0.5 million of bad debt expense. For the year ended December 31, 2003, other expense included $0.6 million for a repayment of amounts previously received for vacated microwave frequency bands. For the year ended December 31, 2002, other income included $0.6 million for amounts received for previously vacated microwave frequency bands. 11. RELATIONSHIPS WITH ENRON In December 2001, Enron and certain of its subsidiaries filed voluntary petitions for Chapter 11 reorganization with the U.S. Bankruptcy Court. Until November 17, 2004, Northern Plains and Pan Border were subsidiaries of Enron. Northern Plains and Pan Border 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 F-16 NORTHERN BORDER PIPELINE COMPANY NOTES TO FINANCIAL STATEMENT 11. RELATIONSHIPS WITH ENRON (continued) 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. Northern Border Pipeline estimates that it could recognize, through future operating results, additional recoveries of $6 million to $9 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 3, 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 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. F-17 NORTHERN BORDER PIPELINE COMPANY NOTES TO FINANCIAL STATEMENT 11. RELATIONSHIPS WITH ENRON (continued) Enron management previously informed Northern Plains 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 is considered a member of Enron's ERISA controlled group of corporations. As of December 31, 2003, approximately $3.1 million was estimated for Northern Border Pipeline's proportionate allocation of Northern Plains' 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, these costs could be the Northern Border Pipeline's responsibility, $3.1 million was accrued 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 advised Northern Border Pipeline that no claim of reimbursement of the termination costs will be made, resulting in an adjustment in reserves during 2004 of $3.1 million for the termination costs. Under the ONEOK Agreement, neither Northern Plains nor Northern Border Pipeline 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. Northern Border Pipeline continues to monitor developments at Enron, to assess the impact on Northern Border Pipeline of its existing agreements and relationships with Enron, and to take appropriate action to protect Northern Border Pipeline's interests. 12. SUBSEQUENT EVENTS Northern Border Pipeline makes distributions to it general partners approximately one month following the end of the quarter. The distribution for the fourth quarter of 2004 of approximately $54.1 million was declared in January 2005 was paid in February 2005. F-18 REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM ON SCHEDULE Northern Border Pipeline Company: We have audited in accordance with the standards of the Public Company Accounting Oversight Board (United States), the financial statements of Northern Border Pipeline Company 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 Pipeline Company 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 PIPELINE COMPANY SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS FOR THE YEARS ENDED DECEMBER 31, 2004, 2003 AND 2002 (IN THOUSANDS)

S-2 INDEX TO EXHIBITS

One, NA and the lenders named therein. (incorporated by reference to Exhibit No. 10.1 to Northern Border Pipeline Company Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2004 (File No. 333-88577)). * 10.4 Form of Conveyance, Contribution and Assumption Agreement among Northern Plains Natural Gas Company, Northwest Border Pipeline Company, Pan Border Gas Company, Northern Border Partners, L.P., and Northern Border Intermediate Limited Partnership (incorporated by reference to Exhibit 10.16 to Form S-1). * 10.5 Form of Contribution, Conveyance and Assumption Agreement among TC PipeLines, LP and certain other parties. (incorporated by reference to Exhibit 10.2 to TC PipeLines, LP's Form S-1, SEC File No. 333-69947 ("TC Form S-1")). +*10.6 Form of Termination Agreement with ONEOK dated as of January 5, 2005. (incorporated by reference to Exhibit 99.1 to Northern Border Partners, L.P. Form 8-K filed on January 11, 2005 (File No. 1-12201)). +*10.7 ONEOK, Inc. 2005 Supplemental Executive Retirement Plan. (incorporated by reference to Exhibit 99.1 to Northern Border Partners, L.P. Form 8-K filed on January 11, 2005 (File No. 1-12201)). +*10.8 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)). +*10.9 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)). +*10.10 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)). +*10.11 ONEOK, Inc. Employee Non-Qualified Deferred Compensation Plan, as amended, dated February 2001 (incorporated by reference from Exhibit 10(g) to ONEOK's Form 10-K for the year ended December 31, 2001 (File No. 1-13643)). +*10.12 ONEOK, Inc. Annual Officer Incentive Plan (incorporated by reference from Exhibit 10(f) to Form 10-K for the year ended December 31, 2001 (File No. 1-13643)). *10.13 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 Northern Border Partners, L.P.'s Form 10-K/A for the year ended December 31, 1998 File No. 1-12202 ("1998 10-K")). *10.14 Northern Border Transition Services Agreement dated November 17, 2004, by and between ONEOK, Inc. and CCE Holdings, LLC. (incorporated by reference to Exhibit 10.24 to Northern Border Partners, L.P.'s Form 10-K for the year ended December 31, 2004 (File No. 1-122022)). 12. Statement re computation of ratios.

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 Northern Border Partners, L.P.'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.

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