10-K 1 h33256e10vk.txt NORTHERN BORDER PARTNERS, L.P. - 12/31/2005 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, 2005 or [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from _______ to ________. Commission File Number: 1-12202 NORTHERN BORDER PARTNERS, L.P. (Exact name of registrant as specified in its charter) DELAWARE 93-1120873 (State or other jurisdiction of (I.R.S. Employer incorporation or organization) Identification Number) 13710 FNB PARKWAY OMAHA, NEBRASKA 68154-5200 (Address of principal executive offices) (Zip code) (402) 492-7300 (Registrant's telephone number, including area code) Securities registered pursuant to Section 12(b) of the Act: COMMON UNITS NEW YORK STOCK EXCHANGE (Title of each class) (Name of each exchange on which registered) Securities registered pursuant to Section 12(g) of the Act: None Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes [X] No [ ] Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes [ ] No [X] 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. [ ] Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Act). Yes [X] No [ ] Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes [ ] No [X] The aggregate market value of the common units held by non-affiliates of the registrant, based on closing prices in the daily composite list for transactions on the New York Stock Exchange as of June 30, 2005, was $2,256,424,496. The number of common units outstanding as of January 31, 2006, was 46,397,214. DOCUMENTS INCORPORATED BY REFERENCE None NORTHERN BORDER PARTNERS, L.P. ANNUAL REPORT ON FORM 10-K TABLE OF CONTENTS

Page No. -------- PART I Item 1. Business General Development of Business............................ 4 Financial Information About Segments....................... 7 Narrative Description of Business.......................... 7 Environmental and Safety Matters........................... 17 Major Customers............................................ 18 Employees.................................................. 18 Available Information...................................... 19 Item 1A. Risk Factors.................................................. 19 Item 1B. Unresolved Staff Comments..................................... 29 Item 2. Properties.................................................... 29 Item 3. Legal Proceedings............................................. 29 Item 4. Submission of Matters to a Vote of Security Holders........... 30 PART II Item 5. Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.......... 30 Item 6. Selected Financial Data....................................... 32 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations Executive Summary.......................................... 34 Critical Accounting Estimates.............................. 37 Results of Operations...................................... 39 Liquidity and Capital Resources............................ 43 Recent Accounting Pronouncements........................... 49 Forward-Looking Statements................................. 49 Item 7A. Quantitative and Qualitative Disclosures about Market Risk.... 50 Item 8. Financial Statements and Supplementary Data................... 52 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure................................... 52 Item 9A. Controls and Procedures....................................... 52 Item 9B. Other Information............................................. 54 PART III Item 10. Directors and Executive Officers of the Registrant............ 54 Item 11. Executive Compensation........................................ 59 Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters................. 65 Item 13. Certain Relationships and Related Transactions................ 66 Item 14. Principal Accounting Fees and Services........................ 69 PART IV Item 15. Exhibits and Financial Statement Schedules.................... 69

2 GLOSSARY The abbreviations, acronyms, and industry terminology used in this annual report are defined as follows: Bcf/d......................... Billion cubic feet per day Bear Paw Energy............... Bear Paw Energy, LLC Bighorn Gas Gathering......... Bighorn Gas Gathering, L.L.C. Black Mesa.................... Black Mesa Pipeline, Inc. Border Midstream.............. Border Midstream Services, Ltd. Btu/cf........................ British thermal units per cubic feet Cantera....................... Cantera Natural Gas, LLC (formerly CMS Field Services, Inc) CCE Holdings.................. CCE Holdings, LLC, a Southern Union Company and GE Commercial Finance Energy Financial joint venture Crestone Energy............... Crestone Energy Ventures, L.L.C. Crestone Gathering............ Crestone Gathering Services, L.L.C., a wholly-owned subsidiary of Crestone Energy Design capacity............... Pipeline capacity available to transport natural gas based on system facilities and design conditions Enron......................... Enron Corp. Enron North America........... Enron North America Corp. EPA........................... Environmental Protection Agency Exchange Act.................. Securities Exchange Act of 1934 FASB.......................... Financial Accounting Standards Board FERC.......................... Federal Energy Regulatory Commission Fort Union Gas Gathering...... Fort Union Gas Gathering, L.L.C. GAAP.......................... Generally accepted accounting principles Guardian Pipeline............. Guardian Pipeline, L.L.C. IRS........................... Internal Revenue Service Lost Creek Gathering.......... Lost Creek Gathering, L.L.C. MDth/d........................ Thousand dekatherms per day Midwestern Gas Transmission... Midwestern Gas Transmission Company MMBtu......................... Million British thermal units MMcf/d........................ Million cubic feet per day NBP Services.................. NBP Services, LLC, a ONEOK subsidiary NOAA.......................... National Oceanic and Atmospheric Administration Northern Border Pipeline...... Northern Border Pipeline Company Northern Plains............... Northern Plains Natural Gas Company, LLC, a ONEOK subsidiary Northwest Border.............. Northwest Border Pipeline Company, a subsidiary of TransCanada NYSE.......................... New York Stock Exchange ONEOK......................... ONEOK, Inc. ONEOK Energy.................. ONEOK Energy Services Company, LP, a ONEOK subsidiary Pan Border.................... Pan Border Gas Company, LLC, a ONEOK subsidiary Partnership................... Northern Border Partners, L.P., Northern Border Intermediate Limited Partnership and its subsidiaries SEC........................... Securities and Exchange Commission SFAS.......................... Statement of Financial Accounting Standards TC PipeLines.................. TC PipeLines Intermediate Limited Partnership, a subsidiary of TC PipeLines, LP TransCanada................... TransCanada Corporation Trunk gathering system........ Large diameter pipeline running through a production area to which smaller individual gathering systems are connected U.S........................... United States Viking Gas Transmission....... Viking Gas Transmission Company 3 The statements in this annual report that are not historical information, including statements concerning plans and objectives of management for future operations, economic performance or related assumptions, are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Forward-looking statements may include words such as "anticipate," "estimate," "expect," "project," "intend," "plan," "believe," "should" and other words and terms of similar meaning. Although we believe that our expectations regarding future events are based on reasonable assumptions, we can give no assurance that our goals will be achieved. Important factors that could cause actual results to differ materially from those in the forward-looking statements are described under Item 1A, "Risk Factors." PART I ITEM 1. BUSINESS GENERAL DEVELOPMENT OF BUSINESS In this report, references to "we," "us," "our" or the "Partnership" collectively refer to Northern Border Partners, L.P., our subsidiary, Northern Border Intermediate Limited Partnership, and its subsidiaries. OVERVIEW Northern Border Partners is a publicly-traded Delaware limited partnership formed in 1993. Our common units are listed on the NYSE under the trading symbol "NBP." Our purpose is to acquire, own and manage pipeline and other midstream energy assets. We are a leading transporter of natural gas imported from Canada into the U.S. Our operations are conducted through the following three business segments: - Interstate Natural Gas Pipeline, which provides natural gas transportation services; - Natural Gas Gathering and Processing, which gathers, processes and compresses natural gas, and fractionates natural gas liquids; and - Coal Slurry Pipeline, which transports crushed coal suspended in water. PARTNERSHIP STRUCTURE We are managed under the direction of a partnership policy committee (similar to a corporation's board of directors). The Partnership Policy Committee consists of three members, one of whom is appointed by each of our general partners. Our general partners and the general partners of our subsidiary limited partnership, Northern Border Intermediate Limited Partnership, are Northern Plains, Pan Border and Northwest Border. Our general partners hold an aggregate 2% general partner interest. Northern Plains and Pan Border, both subsidiaries of ONEOK, hold a combined 1.65% general partner interest. In addition, Northern Plains owns 501,603 of our common units, which represents a 1.06% limited partner interest. The combined general and limited partner interests held by ONEOK are 2.71%. Northwest Border, a subsidiary of TransCanada, holds a 0.35% general partner interest. At December 31, 2005, the voting interests of the Partnership Policy Committee were as follows:

MEMBER DESIGNATED BY VOTING INTEREST -------------------- --------------- Northern Plains 50% Pan Border 32.5% Northwest Border 17.5%

OUR HISTORY 1993 Northern Border Partners is formed by Enron, Panhandle Eastern Corporation and The Williams Companies, Inc., whose general partner interests are held by Northern Plains, Pan Border and Northwest Border, respectively. We hold a 70% general partner interest in Northern Border Pipeline. 1996 - 1997 We acquire Black Mesa. 4 1998 Enron acquires Pan Border. 1999 - 2000 We acquire joint venture interests in Bighorn Gas Gathering, Fort Union Gas Gathering and Lost Creek Gathering. 2001 We acquire Midwestern Gas Transmission and Bear Paw Energy. Our subsidiary, Border Midstream, acquires assets in Canada. 2002 TransCanada acquires Northwest Border. 2003 We acquire Viking Gas Transmission, including a 33-1/3% interest in Guardian Pipeline. 2004 ONEOK acquires Northern Plains and Pan Border. Border Midstream sells its remaining Canadian assets. BUSINESS STRATEGY Our primary business objectives are to generate stable cash flow sufficient to pay quarterly cash distributions to our unitholders and to increase our quarterly cash distribution over time. Our ability to maintain and grow our distributions to unitholders depends on acquisitions and the growth of our existing businesses. Our acquisition strategy and business strategy by major segment are as follows: Acquisitions - We seek opportunities to expand our existing businesses and strategically acquire related businesses. We focus on U.S. and Canadian assets related to energy transportation that will leverage our core competencies, minimize commodity price risk and provide immediate cash flow. We target interstate and intrastate natural gas pipelines, natural gas gathering and processing assets, natural gas liquids pipelines and storage facilities. We finance our acquisitions and capital expenditures conservatively with a mix of debt and equity. Interstate Natural Gas Pipeline - We focus on safe, efficient and reliable operations and further development of our regulated pipelines. We intend to continue to provide cost-effective transportation for Canadian natural gas to the Midwestern U.S. We seek growth of our interstate natural gas pipelines through incremental projects that access new market areas and are supported by long-term transportation contracts. Our priorities for Northern Border Pipeline in 2006 include: marketing its available transportation capacity, actively processing its current rate case before the FERC and placing the Chicago III Expansion Project into service. Midwestern Gas Transmission is focused on receiving regulatory approval for its Eastern Extension project and pursuing the expansion of existing and the development of new interconnections with other interstate pipelines to access new markets. Natural Gas Gathering and Processing - We seek to reduce costs, streamline operations and increase facility utilization of our wholly-owned natural gas gathering and processing operations. We pursue growth of our gathering network through additional well connections, consolidation and acreage dedications, and facility expansions in new production areas. We also seek to restructure contracts when they come to term to mitigate commodity price exposure and offset increased operating costs. RECENT DEVELOPMENTS The following is a summary of our significant developments during 2005. Additional information regarding most of these items may be found elsewhere in this annual report and in previous reports filed with the SEC. Northern Border Pipeline Contracting - During 2005, short-term firm service transportation contracts partially replaced expired contracts and continued to expose Northern Border Pipeline to seasonal demand. As a result, Northern Border Pipeline did not sell all of its available capacity and firm transportation revenue decreased 5% compared with 2004 when the pipeline's transportation capacity was sold out at maximum rates. To maximize overall revenue, Northern Border Pipeline discounted transportation rates during certain periods of the year. Transition from CCE Holdings to ONEOK - In May 2005, the transition, from CCE Holdings to ONEOK or us, of various services, including: information technology services; accounting system usage rights and administrative support; and payroll, employee benefits and administrative services, was completed. 5 Credit Agreements - In May 2005, we entered into a five-year, $500 million revolving credit agreement. Northern Border Pipeline entered into a five-year, $175 million revolving credit agreement. We terminated our previously existing $275 million credit facility and Northern Border Pipeline terminated its previously existing $175 million credit facility in conjunction with the execution of the new agreements. Bankruptcy Claims - In June 2005, Northern Border Pipeline, Crestone Gathering and Bear Paw Energy executed term sheets with a third party for the sale of their bankruptcy claims against Enron and Enron North America. Proceeds from the sale of the claims were $14.6 million ($11.2 million, net to the Partnership). Bighorn Gas Gathering Preferred A Settlement - In August 2005, as a result of the settlement agreement with our partner in Bighorn Gas Gathering related to cash flow incentives based on well connections to the gathering system, we recognized $5.4 million of equity earnings that were due to us for 2004 and 2005 through our ownership of preferred A shares. Interest in Fort Union Gas Gathering - In August 2005, Crestone Energy acquired, for $5.1 million, an additional 3.7% interest in Fort Union Gas Gathering, bringing our total interest to 37%. Northern Border Pipeline Chicago III Expansion Project - In September 2005, Northern Border Pipeline accepted the FERC's certificate of public convenience and necessity for the Chicago III Expansion Project. This project will add 130 MMcf/d of transportation capacity on the eastern portion of the pipeline into the Chicago area. It is estimated that the project will cost approximately $21 million and the target in-service date is April 2006. Midwestern Gas Transmission Eastern Extension Project - In October 2005, the FERC issued its Environmental Assessment concluding that the Eastern Extension Project would not constitute a major federal action significantly affecting the quality of the environment. The Eastern Extension Project will add 31 miles of pipeline with 120 MDth/d (approximately 120 MMcf/d) of transportation capacity. It is estimated that the project will cost approximately $28 million. As a result of the pending FERC certificate of public convenience and necessity, the Eastern Extension Project's proposed in-service date of November 2006 will likely be delayed. Guardian Pipeline Revenue and Cost Study - In October 2005, Guardian Pipeline filed a revenue and cost study with the FERC. In conjunction with the filing, Guardian requested approval of a settlement agreement to re-establish the rates initially approved by the FERC and to reduce the depreciation rate. In February 2006, the FERC issued an order accepting Guardian's revenue and cost study, including the settlement agreement reducing its depreciation rate from 3.33% to 2.0%, effective January 1, 2005. Northern Border Pipeline Rate Case - On November 1, 2005, Northern Border Pipeline filed a rate case with the FERC as required by the provisions of the settlement of its last rate case. The rate case filing proposes, among other things, a 7.8% increase to Northern Border Pipeline's revenue requirement; a change to its rate design approach with a supply zone and market area utilizing a fixed rate per dekatherm and a dekatherm-mile rate, respectively; an increase in the depreciation rate for transmission plant; the implementation of a short-term rate structure on a prospective basis; and the continued inclusion of income taxes in the rate calculation. In December 2005, the FERC issued an order that identified issues that were raised in the proceeding, accepted the proposed rates but suspended their effectiveness until May 1, 2006, at which time the new rates will be collected subject to refund until final resolution of the rate case. The FERC also issued a procedural schedule which set a hearing commencement date of October 4, 2006, with an initial decision scheduled for February 2007, unless a settlement of the issues is reached with the FERC and a majority of Northern Border Pipeline's customers. Midwestern Gas Transmission Southbound Expansion Project - In November 2005, Midwestern Gas Transmission completed the Southbound Expansion Project which increased the pipeline's southbound capacity by 86 MDth/d (approximately 86 MMcf/d). Shut Down of Black Mesa - On December 31, 2005, Black Mesa's transportation contract with the coal supplier of the Mohave Generating Station expired and our coal slurry pipeline operation was shut down as expected. Proposed Transactions - On February 15, 2006, we announced a series of transactions that are expected to increase unitholder value and facilitate additional growth opportunities. In separate transactions, we will sell a 20% partnership interest in Northern Border Pipeline to TC PipeLines for approximately $300 million. The price of the 6 20% interest, along with the related share of Northern Border Pipeline's outstanding debt, totals $420 million. Following completion of the sale, we will own a 50% interest in Northern Border Pipeline and TC PipeLines will own the remaining 50% interest. In 2006, Northern Border Pipeline's cash distributions are expected to be split equally between us and TC PipeLines. In April 2007, an affiliate of TransCanada will become the operator of Northern Border Pipeline. Northern Plains will purchase TransCanada's 0.35% general partner interest in us, increasing ONEOK's general partner interest to 2.0%. We will acquire ONEOK's entire gathering and processing, natural gas liquids, and pipelines and storage segments in a transaction valued at approximately $3 billion. We will pay ONEOK approximately $1.35 billion in cash and 36.5 million Class B units. Upon completion of these transactions, ONEOK will own approximately 37.0 million of our limited partner units, which, when combined with the general partner interest acquired from TransCanada, will increase its total interest in us to 45.7%. The limited partner units and the related general partner interest contribution are valued at approximately $1.65 billion. Closings of the transactions are subject to regulatory approvals and other conditions, including antitrust clearance from the Federal Trade Commission under the Hart-Scott-Rodino Act. The transactions are expected to be completed by April 1, 2006. Additional information about the proposed transactions is included under Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations-Executive Summary." FINANCIAL INFORMATION ABOUT SEGMENTS Financial information about each of our business segments is included in Note 16 of the Consolidated Financial Statements. NARRATIVE DESCRIPTION OF BUSINESS INTERSTATE NATURAL GAS PIPELINE SEGMENT OVERVIEW The interstate natural gas pipeline segment transports natural gas along 2,320 miles of pipelines with a design capacity of approximately 4.7 Bcf/d. Our transportation network provides pipeline access to the Midwestern U.S. primarily from natural gas reserves in the Western Canada Sedimentary Basin, which is located in the Canadian provinces of Alberta, British Columbia and Saskatchewan. Our interstate natural gas pipeline segment included the following assets at December 31, 2005:

2005 AVERAGE CONTRACTED SEGMENT SUBSIDIARY OWNERSHIP LENGTH DESIGN CAPACITY CAPACITY ------------------ --------- ----------- ----------------------- ---------- Northern Border Pipeline 70% 1,249 miles 2,374 MMcf/d 97% Midwestern Gas Transmission 100% 350 miles Northbound - 650 MMcf/d 87% Southbound - 475 MMcf/d(1) 100% Viking Gas Transmission 100% 578 miles 496 MMcf/d 100% Guardian Pipeline 33-1/3% 143 miles 750 MMcf/d 98%

(1) Capacity increased by 86 MMcf/d on November 1, 2005. Operating revenue is derived from transportation contracts at rates that are stated in our tariffs. Transportation rates are established in a FERC proceeding known as a rate case. Tariffs specify the maximum rates we can charge our customers and the general terms and conditions for natural gas transportation service on our pipelines. During a rate case, a determination is reached by the FERC, either through a hearing or a settlement, on maximum rates permissible for interstate natural gas transportation service that include the recovery of our prudent cost-based investment, operating expenses and a reasonable return for our investors. Our pipelines' tariffs also allow for services to be provided under negotiated and discounted rates. Once rates are set in a rate case, interstate natural gas pipelines are not permitted to increase rates if costs increase or contract demand decreases, nor are they required to reduce rates based on cost savings until a new rate case is filed and completed. As a result, the interstate natural gas pipeline segment's earnings and cash flow depend on costs incurred, contracted capacity, the volume of gas transported and our ability to recontract capacity at acceptable rates. 7 Our transportation contracts include specifications regarding the receipt and delivery of natural gas at points along the pipeline systems. The type of transportation contract, either firm or interruptible service, determines the basis by which each customer is charged. Customers with firm service transportation agreements pay a fee known as a demand charge to reserve pipeline capacity, regardless of use, for the term of their contracts. Firm service transportation customers also pay a fee known as a commodity charge that is based on the volume of natural gas they transport. Customers with interruptible service transportation agreements may utilize available capacity on our pipelines after firm service transportation requests are satisfied. Interruptible service customers are assessed commodity charges only. For the year ended December 31, 2005, approximately 97% of the interstate natural gas pipeline segment's revenue was derived from demand charges and the remaining 3% was attributable to commodity charges. Operating revenue from the interstate natural gas pipeline segment accounted for 56%, 65% and 68% of our consolidated operating revenue in 2005, 2004 and 2003, respectively. Our interest in Northern Border Pipeline represents the largest portion of our interstate natural gas pipeline assets, earnings and cash flow. For the year ended December 31, 2005, Northern Border Pipeline accounted for 85% of our interstate natural gas pipeline segment revenue. Midwestern Gas Transmission and Viking Gas Transmission accounted for 7% and 8% of the segment's revenue, respectively. Earnings related to our interest in Guardian Pipeline are reported in this segment as equity earnings of unconsolidated affiliates. INTERSTATE PIPELINE SYSTEMS Northern Border Pipeline - Northern Border Pipeline is a Texas general partnership that was formed in 1978. We own a 70% general partner interest and TC PipeLines owns the remaining 30%. Northern Border Pipeline is managed by a management committee that consists of four members: one representative designated by each of our three general partners and one representative designated by TC PipeLines. TC PipeLines is a subsidiary of TC PipeLines, LP, a publicly-traded partnership. The general partner of TC PipeLines, LP is TC PipeLines GP, Inc., which is a subsidiary of TransCanada. On February 15, 2006, we announced a series of transactions that will impact our relationship with Northern Border Pipeline. Information about the proposed transactions is included under Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations-Executive Summary." At December 31, 2005, the voting interests of the Northern Border Management Committee were as follows:

MEMBER DESIGNATED BY VOTING INTEREST -------------------- --------------- Northern Plains 35% Pan Border 22.75% Northwest Border 12.25% TC PipeLines 30%

Northern Border Pipeline transports natural gas from the Montana-Saskatchewan border near Port of Morgan, Montana to a terminus near North Hayden, Indiana. The system consists of 1,249 miles of pipeline with diameters ranging from 30 inches to 42 inches and a design capacity of 2,374 MMcf/d. Along the pipeline are 16 compressor stations with a total of 499,000 horsepower, measurement facilities to support the receipt and delivery of gas at various points, four field offices and a microwave communication system with 50 tower sites. Construction of Northern Border Pipeline was initially completed in 1982 followed by expansions or extensions in 1991, 1992, 1998 and 2001. Northern Border Pipeline filed an application for a certificate of public convenience and necessity with the FERC for the Chicago III Expansion Project in March 2005, which the FERC issued in September 2005. The Chicago III Expansion Project will add 130 MMcf/d of transportation capacity from Harper, Iowa to the Chicago market area with the construction of a new 16,000-horsepower compressor station in Iowa and minor modifications to two other compressor stations in Iowa and Illinois. We estimate that the project will cost approximately $21 million and the target in-service date is April 2006. This expansion is fully subscribed by four shippers under long-term firm service transportation agreements with terms ranging from five and one-half years to ten years. 8 Midwestern Gas Transmission - Midwestern Gas Transmission is a bi-directional system that interconnects with Tennessee Gas Transmission near Portland, Tennessee and several interstate pipelines near Joliet, Illinois. The system consists of 350 miles of pipeline with diameters ranging from 24 inches to 30 inches, a northbound capacity of 650 MMcf/d and a southbound capacity of 475 MMcf/d. Along the pipeline are 7 compressor stations with a total of approximately 68,000 horsepower. We acquired Midwestern Gas Transmission in May 2001. In June 2005, Midwestern Gas Transmission filed an application requesting a certificate of public convenience and necessity with the FERC for the Eastern Extension Project, which is pending approval. The Eastern Extension Project will add 31 miles of pipeline with 120 MDth/d of transportation capacity from Portland, Tennessee to planned interconnections with Columbia Gulf Transmission Company and East Tennessee Pipeline Company. In October 2005, the FERC issued its Environmental Assessment concluding that the approval of the Eastern Extension Project, with appropriate mitigating measures, would not constitute a major federal action significantly affecting the quality of the environment. It is estimated that the project will cost approximately $28 million. The additional transportation capacity is fully subscribed by a local distribution company under a 15-year firm service transportation agreement. As a result of the pending FERC certificate of public convenience and necessity, the Eastern Extension Project's proposed in-service date of November 2006 will likely be delayed. On November 1, 2005, Midwestern Gas Transmission completed its Southbound Expansion Project and began service. The fully-subscribed project increased the pipeline's southbound capacity by 86 MDth/d. Viking Gas Transmission - Viking Gas Transmission transports natural gas from an interconnection with TransCanada near Emerson, Manitoba to an interconnection with ANR Pipeline Company near Marshfield, Wisconsin. The system consists of 578 miles of pipeline with diameters ranging from 3 inches to 24 inches. The pipeline's design capacity is 496 MMcf/d. Along the pipeline are 8 compressor stations with a total of approximately 69,000 horsepower. We acquired Viking Gas Transmission in January 2003. Guardian Pipeline - Viking Gas Transmission owns a 33-1/3% interest in Guardian Pipeline. Subsidiaries of Wisconsin Public Service and Wisconsin Energy Corporation hold the remaining interests. Guardian Pipeline transports natural gas from Joliet, Illinois to a point west of Milwaukee, Wisconsin. The system consists of 143 miles of pipeline with a design capacity of 750 MMcf/d. Northern Plains is the operator of Guardian Pipeline. On February 7, 2006, Guardian Pipeline announced that it signed precedent agreements with two major Wisconsin utility companies to expand the existing pipeline system in eastern Wisconsin. The proposed project will extend the pipeline approximately 106 miles from its current terminus near Ixonia, Wisconsin to the Green Bay area, adding 537 MDth/d (approximately 537 MMcf/d) of capacity. Guardian Pipeline's capital costs for the project are estimated to range between $200 million and $250 million. Pending all necessary approvals, Guardian Pipeline anticipates that construction could begin in early 2008. TITLE TO PROPERTIES Northern Border Pipeline, Midwestern Gas Transmission, Viking Gas Transmission and Guardian Pipeline hold the right, title and interest in their pipeline systems. With respect to real property, they own sites for compressor stations, meter stations, pipeline field offices and microwave towers, and derive interests from leases, easements, rights-of-way, permits and licenses from landowners or governmental authorities permitting land use for construction and operation of our pipelines. Approximately 90 miles of Northern Border Pipeline's system are located within the boundaries of the Fort Peck Indian Reservation in Montana. In 1980, Northern Border Pipeline entered into a pipeline right-of-way lease with the Fort Peck Tribal Executive Board on behalf of the Assiniboine and Sioux Tribes of the Fort Peck Indian Reservation. This pipeline right-of-way lease granted Northern Border Pipeline the right and privilege to construct and operate its pipeline on certain tribal lands. The pipeline right-of-way lease expires in 2011, although Northern Border Pipeline has an option to renew the pipeline right-of-way lease through 2061. In conjunction with obtaining right-of-way across tribal lands located within the exterior boundaries of the Fort Peck Indian Reservation, Northern Border Pipeline also obtained right-of-way across allotted lands located within the reservation boundaries. Most of the allotted lands are subject to a perpetual easement granted by the Bureau of Indian Affairs for and on behalf of the individual Indian owners or obtained through condemnation. Several tracts are subject to a right-of-way grant that expires in 2015. 9 SUPPLY The primary source of natural gas for Northern Border Pipeline is the Western Canada Sedimentary Basin. In 2005, approximately 85% of the natural gas transported by Northern Border Pipeline was produced in Canada. In addition, Viking Gas Transmission's natural gas receipts were primarily from Canada. For these reasons, the continuous supply of Canadian natural gas is crucial to our long-term financial condition. Significant factors that can impact the supply of Canadian natural gas transported by our pipelines include: - Canadian natural gas available for export; - transportation capacity and related market pricing options on other pipelines; - storage capacity for Canadian natural gas and demand for storage injection; - natural gas from other supply sources that can be transported to the Midwestern U.S.; - demand for Canadian natural gas in other U.S. consumer markets; and - natural gas market price spread between Alberta, Canada and the Midwestern U.S., which reflects the relative supply and demand for Canadian natural gas in Canada and in the U.S. The composition of natural gas can impact transportation capacity of our pipelines. If the energy content of natural gas declines, more natural gas must be transported to meet the energy equivalent specified in our transportation contracts. This in turn reduces the available transportation capacity of our pipelines and negatively impacts revenue. Since 2004, Canadian natural gas transported by our pipelines has maintained an average of 1,005 Btu/cf. Natural gas produced in the Williston Basin of Montana, North Dakota and the Canadian province of Saskatchewan and the Powder River Basin of Wyoming accounted for 9% of the natural gas transported by Northern Border Pipeline in 2005. The remaining 6% of the natural gas transported by Northern Border Pipeline was synthetic gas produced at the Dakota Gasification plant in North Dakota. Midwestern Gas Transmission transports natural gas from various supply sources through its multiple interconnections with other natural gas pipelines. In 2005, 50% and 7% of Midwestern Gas Transmission's direct receipts of natural gas originated from Canada and the Gulf Coast, respectively. The remaining 43% of receipts were supplied through interconnections with other pipelines, including Northern Border Pipeline. In August and September 2005, Hurricanes Katrina and Rita adversely impacted natural gas production and transportation in the Gulf Coast region. As a result, some Chicago market supply was redirected to the East Coast, utilizing Midwestern Gas Transmission, to replace supply from the Gulf Coast region. DEMAND Demand for natural gas transportation service on our pipelines is directly related to demand for natural gas in the markets that our customers serve. Factors that may impact demand for natural gas include: - weather conditions; - economic conditions; - government regulation; - availability and price of alternative energy sources; - fuel conservation measures; and - technological advances in fuel economy and energy generation devices. Furthermore, factors that may impact demand for natural gas transportation service on our pipelines include: - the ability and willingness of natural gas shippers to utilize our pipelines over alternative pipelines; - transportation rates; and - volume of natural gas delivered to Midwestern U.S. markets from other supply sources and storage facilities. The interstate natural gas pipeline segment's primary exposure to market risk occurs when existing transportation contracts expire and are subject to renegotiation. Customers with competitive alternatives analyze the market price spread or basis differential between receipt and delivery points along the pipeline to determine their expected gross margin. The anticipated margin and its variability are important determinants of the transportation rate customers are willing to pay. In addition to general demand for natural gas, regional economic conditions, climate, trends in 10 production, available pipeline capacity and natural gas storage inventories in each market area can also impact the basis differential and affect demand for transportation service on our pipelines. SEASONALITY Demand for natural gas is seasonal. In the natural gas industry, winter season is considered to be during the months of November to March. Summer season is considered to be the remaining months. Peak summer season for electric power generation includes July, August and September. Weather conditions throughout the U.S. can significantly impact regional natural gas supply and demand. The Western U.S. market is sensitive to precipitation levels which impact hydroelectric power generation. During the summer, high temperatures combined with low hydroelectric power generation levels can increase demand for Canadian natural gas in the Western U.S. markets and shift supply away from our pipelines. In the Midwestern U.S., the current pipeline infrastructure is designed to meet the region's winter heating demand loads. Moderate winter temperatures can lead to the decline in the value of our services due to reduced demand for our transportation services. To the extent that our pipeline capacity is contracted under firm service transportation agreements, a significant portion of our revenue, which is generated from demand charges, is not impacted by seasonal throughput variations. However, when transportation agreements expire, seasonal demand can impact our ability to recontract firm service transportation capacity. Accordingly, throughput on our interstate natural gas pipelines may experience seasonal fluctuations and discounting of rates may be required to maximize revenue. Natural gas storage is necessary to balance the relatively steady natural gas supply with the seasonal demand of residential, commercial and electric power generation users. In 2004, residential, commercial and electric power generation users consumed 65% of the total natural gas volume delivered that year according to the Energy Information Administration. Industrial users, who consumed the remaining 35% of the total natural gas volume delivered, demand a steady load of natural gas to operate their facilities but will turn to alternative energy sources when it is not economical to use natural gas. CUSTOMERS The interstate natural gas pipeline segment serves customers in North and South Dakota, Minnesota, Iowa, Wisconsin, Illinois, Indiana and Kentucky. Our customers include natural gas producers, marketers, industrial facilities, local distribution companies and electric power generating plants. The interstate natural gas pipeline segment's four largest customers contributed approximately 16%, 10%, 10% and 9% of the segment's revenue in 2005. COMPETITION Competition among natural gas pipelines is based primarily on transportation charges and proximity to natural gas supply areas and markets. Our interstate natural gas pipelines compete primarily with other pipelines that transport Western Canadian natural gas to markets in the West, Midwest and East in North America, including TransCanada Pipeline and Alliance Pipeline. We also compete with other pipelines that provide access to natural gas storage facilities, alternate supply basins, such as the Rockies, Mid-Continent, the Permian Basin and the Gulf Coast, and liquefied natural gas. CONTRACTING Northern Border Pipeline contracted 97% of its design capacity on a firm basis in 2005, some of which was sold at a discount to maximize overall revenue on the Port of Morgan, Montana to Ventura, Iowa portion of the pipeline. As of January 31, 2006, 73% of the pipeline's design capacity was contracted on a firm basis through December 31, 2006. The weighted average life of these contracts is approximately two years. Midwestern Gas Transmission contracted 87% and 100% of its northbound and southbound design capacity, respectively, on a firm basis in 2005. As of January 31, 2006, the pipeline had contracted 80% and approximately 100% of its northbound and southbound design capacity, respectively, on a firm basis through December 31, 2006. 11 Viking Gas Transmission contracted 100% of its design capacity on a firm basis in 2005. As of January 31, 2006, 98% of the pipeline's design capacity was contracted on a firm basis through December 31, 2006. GOVERNMENT REGULATION Our interstate natural gas pipelines are regulated under the Natural Gas Act and Natural Gas Policy Act, which give the FERC jurisdiction to regulate virtually all aspects of this business segment, including: - transportation of natural gas; - rates and charges; - terms of service, including creditworthiness requirements; - construction of new facilities; - extension or abandonment of service and facilities; - accounts and records; - depreciation and amortization policies; - acquisition and disposition of facilities; and - initiation and discontinuation of services. Northern Border Pipeline Rate Case - On November 1, 2005, Northern Border Pipeline filed a rate case with the FERC as required by the provisions of the settlement of Northern Border Pipeline's 1999 rate case. The rate case filing proposes a 7.8% increase to Northern Border Pipeline's revenue requirement; a change to its rate design approach with a supply zone and market area utilizing a fixed rate per dekatherm and a dekatherm-mile rate, respectively; a compressor usage surcharge primarily to recover costs related to powering electric compressors; and the implementation of a short-term rate structure on a prospective basis. The filing also incorporates an overall cost of capital of 10.56% based on a rate of return on equity of 14.20%, an increase in the depreciation rate for transmission plant from 2.25% to 2.84%, the institution of a negative salvage rate of 0.59% and a decrease in billing determinants. Also included in the filing is the continued inclusion of income taxes in the rate calculation. In December 2005, the FERC issued an order that identified issues that were raised in the proceeding, accepted the proposed rates but suspended their effectiveness until May 1, 2006, at which time the new rates will be collected subject to refund until final resolution of the rate case. The FERC also issued a procedural schedule which set a hearing commencement date of October 4, 2006, with an initial decision scheduled for February 2007, unless a settlement of the issues is reached with the FERC and a majority of Northern Border Pipeline's customers. Other Interstate Natural Gas Pipeline Rate Cases - Midwestern Gas Transmission and Viking Gas Transmission have no timing requirements or restrictions regarding future rate case filings. Guardian Pipeline Revenue and Cost Study - In October 2005, as required under the terms of its certificate of public convenience and necessity which allowed for the construction of the interstate natural gas pipeline, Guardian Pipeline filed a revenue and cost study with the FERC. In conjunction with the filing, Guardian requested approval of a settlement agreement to re-establish the rates initially approved by the FERC and reduce the depreciation rate from 3.3% to 2% retroactive to January 1, 2005. In February 2006, the FERC issued an order accepting Guardian's revenue and cost study, including the settlement agreement to reduce its depreciation rate. Income Tax Allowance - In Northern Border Pipeline's 1995 and 1999 rate cases, the FERC addressed the federal income tax allowance included in Northern Border Pipeline's proposed cost of service. In previous FERC rulings involving other companies, interstate pipelines were not entitled to an income tax allowance for income attributable to limited partnership interests held by individuals. The settlements of Northern Border Pipeline's 1995 and 1999 rate cases provided that Northern Border Pipeline could continue to calculate the allowance for income taxes in the manner used historically until December 2005. In May 2005, the FERC issued a policy statement permitting the inclusion of an income tax allowance in the rates for partnership interests held by partners with an actual or potential income tax liability. On December 16, 2005, the FERC issued an order (December 16 Order) in its first case-specific review of the income tax allowance issue, reaffirming its new tax allowance policy and directing the pipeline to provide certain evidence necessary to determine the income tax allowance. The FERC's new policy and the December 16 Order have been appealed to the D.C. Circuit and rehearing requests have been filed with respect to the December 16 Order. The ultimate outcome of these proceedings could impact how the policy statement is applied to us. Northern Border Pipeline's present rates and recent rate case filing reflect an allowance for income taxes in accordance with the provisions of its tariff. 12 Energy Affiliates - In November 2003, the FERC adopted revised standards of conduct which govern the relationships between regulated interstate natural gas pipelines and their energy affiliates. The new standards of conduct were designed to prevent interstate natural gas pipelines from giving any undue preference to their energy affiliates and ensure that transmission service is provided on a nondiscriminatory basis. Bear Paw Energy, subsidiaries of ONEOK, including ONEOK Energy, and subsidiaries of TransCanada are energy affiliates of our interstate pipeline subsidiaries. Selective Discounting - In May 2005, the FERC issued an order reaffirming existing discount regulations that permit pipelines to discount transportation rates to meet gas-on-gas competition. The FERC found that its current policy on selective discounting is an integral and essential part of its policies to further develop a competitive natural gas transportation market. Creditworthiness Standards - In June 2005, the FERC adopted a new policy detailing credit standards for interstate pipelines. The FERC's policy states that pipelines must use objective criteria to determine a shipper's creditworthiness utilizing a standard set of documents that shippers are required to provide. For current shippers on existing facilities, the FERC reiterated its traditional policy of permitting no more than the equivalent of three months of reservation charges as security. For new mainline construction, the FERC will continue its policy of permitting larger security requirements that reasonably reflect the risk of the project. The issue of whether a pipeline may justify security in an amount greater than three months of reservation charges has recently been voluntarily remanded to the FERC for further consideration. Energy Policy Act of 2005 - In August 2005, the Energy Policy Act of 2005 was signed into law addressing a wide range of energy issues, including many that impact the oil and gas industries. The Energy Policy Act of 2005 directs federal agencies to implement certain provisions. Significant provisions affecting the interstate natural gas industry: (1) provides for the FERC to be the lead agency and creates a common record for review of federal permitting decisions associated with interstate natural gas pipeline projects authorized under the Natural Gas Act, (2) makes it unlawful to engage in market manipulation under the Natural Gas Act; (3) authorizes the FERC to issue market transparency rules that will provide greater information about natural gas prices, and (4) increases criminal penalties that may be assessed under the Natural Gas Act and the Natural Gas Policy Act up to $1 million per violation, increases civil penalties under the Natural Gas Policy Act up to $1 million per day per violation, and creates new civil penalties under the Natural Gas Act up to $1 million per day for violations as long as they continue. Market Manipulation - In January 2006, the FERC issued a final rule making it unlawful for any entity subject to its jurisdiction that directly or indirectly purchases or sells natural gas, transportation services or electric energy to defraud, using any device, scheme or artifice; make untrue statements of a material fact or omit a material fact; or engage in any act, practice or course of business that operates as a fraud. The maximum civil penalty under these statutes is $1 million per day, per violation. Negotiated Rate Policy - In January 2006, the FERC issued an order revising its negotiated rate policy to allow the use of basis differentials without a revenue cap in determining negotiated rates. The use of basis differentials for negotiated rates was previously banned because the FERC believed that such mechanism could give pipelines an incentive to withhold capacity and manipulate the natural gas markets by widening the basis between indexes. The FERC found such policy to be overly restrictive, given the benefits that such a pricing mechanism yields. Since negotiated rate transactions must be filed and approved by the FERC and such filings give all parties an opportunity to comment, any allegations of attempted manipulation would be investigated. Comments were filed seeking clarification or conditions to the implementation of this policy. NATURAL GAS GATHERING AND PROCESSING SEGMENT OVERVIEW The natural gas gathering and processing segment gathers natural gas from producers' wells and central delivery points in three producing basins: the Williston Basin, which spans portions of Montana, North Dakota and the Canadian province of Saskatchewan, and the Powder River and Wind River Basins of Wyoming. Our Williston Basin facilities gather raw natural gas, primarily associated with oil production, at the wellhead. We compress and transport the natural gas through pipelines to our processing facilities where water and other contaminants are removed and valuable natural gas liquids are extracted. We separate the natural gas liquids into marketable components, including propane, isobutane, normal butane and natural gasoline, utilizing a distillation process known as fractionation, and sell the components to refineries or local markets. We compress the remaining residue gas, consisting primarily of methane, sell it to various parties and deliver it to interstate natural gas pipelines. 13 Our Powder River Basin facilities gather coalbed methane gas generally from producer-owned central delivery points. We compress and transport the coalbed methane gas through various pipeline systems. We remove water, further compress and deliver the natural gas primarily to the Bighorn Gas Gathering and Fort Union Gas Gathering trunk gathering systems for transport and delivery to interstate natural gas pipelines. Our Wind River Basin facilities consist of a partnership interest in a trunk gathering system that receives natural gas from pipeline interconnections with producer-owned gathering systems and processing plants. The natural gas is processed as necessary and delivered to interstate natural gas pipelines. The natural gas gathering and processing segment included the following assets at December 31, 2005:

2005 AVERAGE SEGMENT SUBSIDIARY OWNERSHIP GATHERING LINES RECEIPT CAPACITY THROUGHPUT ------------------ --------- --------------- ---------------- ------------ Bear Paw Energy 100% 3,964 miles 370 MMcf/d 251 MMcf/d Bighorn Gas Gathering 49% 210 miles 250 MMcf/d 163 MMcf/d Fort Union Gas Gathering 37% 106 miles 634 MMcf/d 429 MMcf/d Lost Creek Gathering 35% 120 miles 275 MMcf/d 200 MMcf/d

Our interests in Bighorn Gas Gathering, Fort Union Gas Gathering and Lost Creek Gathering are held through our wholly-owned subsidiary, Crestone Energy. Operating revenue is derived primarily from percentage-of-proceeds and fee-based contracts. A significant portion of this segment's revenue is derived from percentage-of-proceeds contracts, under which we retain a percentage of the commodities that we gather and process. We are exposed to commodity price risk when we then sell the natural gas and natural gas liquids we retain in the open market. We use derivative instruments to mitigate our sensitivity to fluctuations in the price of natural gas and natural gas liquids. Our volumetric fee-based contracts are impacted by the volume of gas gathered and the level of gathering service provided for high- and low-pressure gas. Our gathering margins are generally higher for low-pressure gas gathered due to the additional services and compression we provide that are necessary for the gas to be gathered through our gathering system and delivered to the interstate pipeline grid. As a result of these different service levels, a change in our gathered volumes will not impact revenue proportionately. Operating revenue from the natural gas gathering and processing segment accounted for 41%, 31% and 28% of our consolidated operating revenue in 2005, 2004 and 2003, respectively. NATURAL GAS GATHERING AND PROCESSING SYSTEMS Bear Paw Energy - Bear Paw Energy's natural gas gathering operations are located in the Williston and Powder River Basins. Bear Paw Energy's natural gas processing and fractionation operations are located in the Williston Basin. The Powder River Basin system consists of approximately 420 miles of gathering lines with diameters ranging from 4 inches to 16 inches and approximately 65 compressor stations with a total of approximately 140,000 horsepower. The Williston Basin system consists of approximately 3,540 miles of gathering lines with diameters ranging from 2 inches to 16 inches, 31 compressor stations with a total of approximately 31,000 horsepower and the Grasslands, Lignite, Marmarth and Baker/Little Beaver processing facilities, which can process 94 MMcf/d of raw natural gas. In 2005, Bear Paw Energy's average daily throughput was 251 MMcf/d and its processing capacity and utilization in the Williston Basin by facility were as follows:

2005 WILLISTON BASIN PROCESSING FACILITY PROCESSING CAPACITY UTILIZATION ----------------------------------- ------------------- ----------- Grasslands 60 MMcf/d 83% Lignite 20 MMcf/d 24% Marmarth 8 MMcf/d 63% Baker/Little Beaver 6 MMcf/d 98%

Due to additional land dedication in the Bakken formation that extends across the Williston Basin, a second phase of expansion was initiated and completed during the second quarter of 2005. During the third quarter of 2005, we completed an expansion of our gathering system in the Beaver Creek area, which increased our processing volumes 14 at the Grasslands facility. In the fourth quarter of 2005, we completed optimization projects at the Grasslands and Baker facilities, which improved our natural gas liquids recoveries. Bighorn Gas Gathering - Crestone Energy owns a 49% interest in Bighorn Gas Gathering, which is a trunk gathering system with operations in the Powder River Basin. The remaining interest is held by Cantera, which is the project manager and operator. The Management Committee consists of representatives of the two owners. The Bighorn Gas Gathering system consists of 210 miles of gathering lines with diameters ranging from 8 inches to 24 inches and receipt capacity of 250 MMcf/d. Bighorn Gas Gathering's average daily throughput in 2005 was 163 MMcf/d. Fort Union Gas Gathering - In August 2005, Crestone Energy acquired, for $5.1 million, an additional 3.7% interest in Fort Union Gas Gathering with operations in the Powder River Basin, bringing our total interest to 37%. The remaining interests are held by Cantera, Western Gas Resources and Bargath, Inc. Cantera is the managing member, Western Gas Resources is the field operator and CIG Resources Company, pursuant to contractual arrangement, is the administrative manager. The Fort Union Gas Gathering system is a trunk gathering system which consists of 106 miles of 24-inch diameter gathering lines with a receipt capacity of 634 MMcf/d. Fort Union Gas Gathering's average daily throughput in 2005 was 429 MMcf/d. Lost Creek Gathering - Crestone Energy owns a 35% interest in Lost Creek Gathering with operations in the Wind River Basin. The remaining interest is held by Burlington Resources Trading, Inc., which is the managing member. A subsidiary of Crestone Energy is the commercial and administrative manager, and an unaffiliated third party, Elkhorn Field Services Company, is the operator. The Lost Creek Gathering system consists of 120 miles of 24-inch diameter gathering lines with a receipt capacity of 275 MMcf/d. Lost Creek Gathering's average daily throughput in 2005 was 200 MMcf/d. TITLE TO PROPERTIES Bear Paw Energy, Bighorn Gas Gathering, Fort Union Gas Gathering and Lost Creek Gathering hold the right, title and interest in their respective gathering and processing assets which consist of low- and high-pressure gathering lines, compression and measurement installations, and treating, processing and fractionation facilities. With respect to real property, we either own the properties on which our facilities are located or derive interests from leases, easements, rights-of-way and permits. SUPPLY We do not explore for or produce crude oil or natural gas, nor do we own crude oil or natural gas reserves. Supply for our natural gas gathering and processing segment depends on the pace of natural gas drilling by producers. Significant factors that can impact the supply of natural gas gathered and processed include: - producers' ability to obtain and maintain the necessary drilling and production permits in a timely and economic manner; - reserve characteristics and performance; - surface access and infrastructure issues; - environmental regulations governing water discharge associated with coalbed methane gas production; - oil and natural gas commodity prices; and - natural gas and crude oil take-away capacity from the various basins that we service. We mitigate supply risk by requiring acreage dedication, long-term or minimum volume commitments and/or demand charges from gas producers. Williston Basin - Most of the wells connected to our Williston Basin facilities produce casinghead gas, which is associated gas that occurs in crude oil reservoirs. Casinghead gas is generally high in natural gas liquids and is significantly higher in energy content than coalbed methane gas. Natural gas liquids, which are separated from raw natural gas and fractionated into components, and residue gas are sold in the open market. Powder River Basin - Coalbed methane gas, which is natural gas extracted from coal seams in the earth's crust, is produced in the Powder River Basin. Approximately 396,000 and 832,000 acres are dedicated by producers to Bear Paw Energy and Bighorn Gas Gathering, respectively, primarily under long-term agreements. Bighorn Gas 15 Gathering and Fort Union Gas Gathering are generally stable in terms of throughput volume because they are trunk gathering systems and the natural gas is gathered from large areas. Coalbed methane wells can produce large amounts of water, which can impact producers' willingness and ability to drill. The time required for coalbed methane wells to dewater prior to significant gas production can be difficult to predict and environmentally acceptable disposal alternatives for the water can be costly. In addition, production on federal lands, which accounts for 65% of the Powder River Basin acreage, requires producers to obtain drilling and production permits from the Bureau of Land Management. Wind River Basin - The Lost Creek Gathering system gathers natural gas produced from conventional gas wells in the Wind River Basin in central Wyoming. DEMAND Demand for natural gas gathering and processing services is directly related to the proximity of our systems to natural gas supply areas. Other factors that may impact demand for gathering and processing services provided by our systems include: - gathering and processing services offered; - our rate structure and contractual terms for services; - competition; - system operating conditions, including pressure, volumes and capacity; - speed of connectivity of new receipt points; - quality of natural gas produced; - natural gas reserve characteristics; - location and capacity availability of receipt and delivery points along the gathering lines; - regulatory requirements; and - commodity prices. SEASONALITY While certain components of demand for natural gas are seasonal, demand for gathering and processing services are aligned with supply, which flows at a relatively steady pace over the life of the reserves. CUSTOMERS The natural gas gathering and processing segment's customers are primarily natural gas producers. Three of Bear Paw Energy's largest customers contributed approximately 45%, 20% and 7% of its operating revenue in 2005. COMPETITION The natural gas gathering and processing segment competes with companies that provide gathering and processing services in the Powder River, Wind River and Williston Basin production areas. We compete with independent gathering companies and gathering companies who are affiliated with producers for gathering and processing contracts based on terms, integrated service offerings, delivery options and coverage area. Once a relationship with a producer is established, the term of the acreage dedication and cost of building duplicative facilities mitigate competition in the vicinity. Strong natural gas and natural gas liquids prices continue to attract natural gas gathering and processing competition, particularly in the Western U.S. where our gathering and processing facilities are located. Increased competition continues to put pressure on our gathering and processing margins. GOVERNMENT REGULATION FERC Regulation of Gathering Affiliates - In September 2005, the FERC issued a notice of inquiry to evaluate possible changes in the criteria used by the FERC in evaluating whether and under what circumstances the FERC may invoke its "in connection with" jurisdiction to guard against abusive practices by natural gas companies and their gathering affiliates. The notice asks for comments on the relevant factors in determining whether a gathering company is separate from its pipeline affiliate and what kind of conduct should trigger the FERC's reassertion of jurisdiction over the gathering affiliate. The notice also asks whether states have incentives to ensure that gathering 16 service providers do not engage in anticompetitive behavior and for assessments of the nature of any gap between state and FERC regulation of natural gas companies. COAL SLURRY PIPELINE SEGMENT OVERVIEW The coal slurry pipeline segment consists of Black Mesa. Black Mesa is designed to transport crushed coal suspended in water along 273 miles of pipeline that originates at a coal mine in Kayenta, Arizona and terminates at the Mohave Generating Station in Laughlin, Nevada. The coal slurry pipeline is the sole source of fuel for the Mohave Generating Station and was fully contracted to Peabody Western Coal until December 31, 2005. The water used by the coal slurry pipeline was supplied from an aquifer in the Navajo Nation and Hopi Tribe joint use area until December 31, 2005. Under a consent decree, the Mohave Generating Station agreed to install pollution control equipment by December 2005. However, due to the uncertainty surrounding the ongoing source of water supply and coal supply negotiations, Southern California Edison, a 56% owner of the Mohave Generating Station, filed a petition before the California Public Utility Commission requesting that they either recognize the end of Mohave Generating Station's coal-fired operations on December 31, 2005, or authorize expenditures for pollution control activities required for future operation. In December 2004, the California Public Utility Commission authorized Southern California Edison to make the necessary expenditures for critical path investments and directed interested parties to continue working toward resolution of essential water and coal supply issues. On December 31, 2005, we shut down our coal slurry pipeline operation. The Mohave Generating Station co-owners, Navajo Nation, Hopi Tribe, Peabody Western Coal Company and other interested parties continue to negotiate water source and coal supply issues and Black Mesa is working to resolve coal slurry transportation issues so that operations may resume in the future. If there are successful resolutions of these issues and the project receives a favorable Environmental Impact Statement, Black Mesa will reconstruct the coal slurry pipeline in late 2008 and 2009. Portions of the pipeline must be modified or reconstructed to repair normal wear related use before coal slurry transportation service can resume. If the Mohave Generating Station permanently closes, we will also permanently shut down our coal slurry operation. TITLE TO PROPERTIES Black Mesa holds the titles to its pipeline and pump stations. Black Mesa either owns the properties on which its facilities are located or derives interests from leases, easements, rights-of-way and permits, including the rights-of-way grants from the Navajo Nation and Hopi Tribe. ENVIRONMENTAL AND SAFETY MATTERS Our operations are subject to extensive federal, state and local laws and regulations governing the discharge of materials into the environment or otherwise relating to the protection of the environment. Failure to comply with these laws and regulations can result in substantial penalties, enforcement actions and remedial liabilities. Although we believe our operations and facilities are in compliance in all material respects with applicable environmental laws and safety regulations, we cannot provide any assurances that compliance with current and future laws and regulations will not have a material adverse affect on our financial position or results of operations. PIPELINE SAFETY We are subject to U.S. Department of Transportation integrity management regulations. The Pipeline Safety Improvement Act requires pipeline companies to perform integrity assessments on pipeline segments that exist in densely populated 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 perform subsequent integrity assessments on a seven-year cycle. We are on schedule to meet the required assessment of 50% of the highest priority high consequence areas by 2007. AIR AND WATER EMISSIONS The Clean Air Act and the Clean Water Act impose restrictions and controls regarding the discharge of pollutants into the air and water in the U.S. Under the Clean Air Act, a federal operating permit is required for sources of 17 significant air emissions. We may be required to incur certain capital expenditures for air pollution control equipment in connection with obtaining or maintaining permits and approvals for sources of air emissions. The Clean Water Act imposes substantial potential liability for the removal and remediation of pollutants discharged in U.S. water. Although we cannot provide any assurances, we believe that we are in compliance with state and federal requirements related to these regulations. SUPERFUND The Comprehensive Environmental Response, Compensation and Liability Act, also known as Superfund, imposes liability, without regard to fault or the legality of the original act, on certain classes of persons who contributed to the release of a hazardous substance into the environment. These persons include the owner or operator of a facility where the release occurred and companies that disposed or arranged for the disposal of the hazardous substances found at the facility. Under the Comprehensive Environmental Response, Compensation and Liability Act, these persons may be liable for the costs of cleaning up the hazardous substances released into the environment, damages to natural resources and the costs of certain health studies. In July 2005, the EPA notified Midwestern Gas Transmission and several other non-affiliated parties, of possible liability pursuant to the Comprehensive Environmental Response, Compensation and Liability Act and requested information related to the Dunavan Oil Site located in Oakwood, Illinois. The EPA identified Midwestern Gas Transmission as possibly transporting and disposing of used oil at the contaminated site and classified Midwestern Gas Transmission as a de minimis party. While it is difficult to determine the liability related to this site because of the number of responsible parties involved, cost sharing arrangements with other potentially responsible parties and the uncertainty surrounding remediation costs, we believe the costs to resolve this matter will not be material to our financial position or results of operations. NITROGEN OXIDES STATE IMPLEMENTATION PLAN In September 2005, the Illinois EPA distributed a draft of a rule to control nitrogen oxide emissions from reciprocating engines and turbines state-wide by January 1, 2009. Under this rule, the state would require the installation of necessary controls to comply with EPA rules regarding the Nitrogen Oxides State Implementation Plan Call, ozone non-attainment and fine particulate standards. Midwestern Gas Transmission participated in several stakeholder meetings to provide comments concerning the draft rule. Another draft of the rule is expected to be distributed before it is submitted to the Illinois Pollution Control Board. As currently drafted, the rule affects five Midwestern Gas Transmission engines in Illinois and the preliminary cost estimates for the required emission controls are less than $5 million. MAJOR CUSTOMERS For the year ended December 31, 2005, two customers each accounted for more than 10% of our consolidated revenue. Total transactions with Lodgepole Energy Marketing and BP Canada Energy Marketing Corp. contributed 18% and 17% of consolidated revenue, respectively. Lodgepole Energy Marketing is Bear Paw Energy's largest customer. BP Canada Energy Marketing Corp. conducts business with both the interstate natural gas pipeline segment and the natural gas gathering and processing segment. EMPLOYEES We do not directly employ any of the persons responsible for managing or operating the Partnership or for providing us with services related to our day-to-day business affairs. Northern Plains provides administrative, operating and 18 management services to us and our interstate natural gas pipeline segment under operating agreements. NBP Services provides administrative, operating and management services to us and our natural gas gathering and processing segment. As of January 31, 2006, Northern Plains and NBP Services had 336 and 125 employees, respectively. Eighteen employees, 4 of whom were eligible to be represented by the United Mine Workers of America or a collective bargaining agreement, support Black Mesa's coal slurry pipeline operations. AVAILABLE INFORMATION Our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act are available, free of charge, on our website at www.northernborderpartners.com as soon as reasonably practicable after we electronically file the material with, or furnish it to, the SEC. Our documents filed with or furnished to the SEC are also available on the SEC's website at www.sec.gov. Our Governance Guidelines, Code of Conduct, Accounting and Financial Reporting Code of Ethics, Partnership Agreement and written charter of the Audit Committee are also available on our website. You may receive a copy of these documents, excluding exhibits, free of charge by contacting Investor Relations at 877-208-7318 or writing to Northern Border Partners, L.P., P.O. Box 542500, Omaha, Nebraska 68154-8500. ITEM 1A. RISK FACTORS Limited partner interests are inherently different from the capital stock of a corporation, although many of the business risks to which we are subject are similar to those faced by corporations engaged in a similar business. The following risk factors should be carefully considered together with all of the other information included in this annual report when evaluating our business. If any of the following risks were to actually occur, our business, results of operations and financial condition could be materially adversely affected. In that case, we may not be able to pay distributions to our common unitholders and the trading price of our common units could decline. RISKS INHERENT IN OUR BUSINESS IF PRODUCTION FROM THE WESTERN CANADA SEDIMENTARY BASIN REMAINS FLAT OR DECLINES AND DEMAND FOR NATURAL GAS FROM THE WESTERN CANADA SEDIMENTARY BASIN IS GREATER IN MARKET AREAS OTHER THAN THE MIDWESTERN U.S., DEMAND FOR OUR TRANSPORTATION SERVICES COULD SIGNIFICANTLY DECREASE. We depend on natural gas supply from the Western Canada Sedimentary Basin because our interstate natural gas pipeline segment transports primarily Canadian natural gas from the Western Canada Sedimentary Basin to the Midwestern U.S. market area. If demand for natural gas increases in Canada or other markets not served by our pipelines and production remains flat or declines, demand for transportation service on our interstate natural gas pipelines could decrease significantly, which could adversely impact our results of operations. THE VOLATILITY OF NATURAL GAS AND NATURAL GAS LIQUIDS PRICES COULD ADVERSELY AFFECT OUR CASH FLOW. A significant portion of our natural gas gathering and processing revenue is derived from the sale of commodities we retain for our gathering and processing services. As a result, we are sensitive to natural gas and natural gas liquids price fluctuations. Natural gas and natural gas liquids prices have been and are likely to continue to be volatile in the future. The recent record high natural gas and natural gas liquids prices may not continue and could drop precipitously in a short period of time. The prices of natural gas and natural gas liquids are subject to wide fluctuations in response to a variety of factors beyond our control, including the following: - relatively minor changes in the supply of, and demand for, domestic and foreign natural gas and natural gas liquids; - market uncertainty; - availability and cost of transportation capacity; - the level of consumer product demand; - political conditions in international natural gas-producing regions; - weather conditions; - domestic and foreign governmental regulations and taxes; 19 - the price and availability of alternative fuels; - speculation in the commodity futures markets; - overall domestic and global economic conditions; - the price of natural gas and natural gas liquids imports; and - the effect of worldwide energy conservation measures. These external factors and the volatile nature of the energy markets make it difficult to reliably estimate future prices of natural gas and natural gas liquids. As natural gas and natural gas liquids prices decline, we are paid less for our commodities, thereby reducing our cash flow. In addition, production and related volumes could also decline. OUR INTERSTATE NATURAL GAS PIPELINES' TRANSPORTATION RATES ARE SUBJECT TO REVIEW AND POSSIBLE ADJUSTMENT BY FEDERAL REGULATORS. Our interstate natural gas pipelines are subject to extensive regulation by the FERC, which regulates most aspects of our pipeline business, including our transportation rates. Under the Natural Gas Act, interstate transportation rates must be just and reasonable and not unduly discriminatory. In November 2005, Northern Border Pipeline filed a rate case with the FERC as required by the provisions of the settlement of its last rate case. If the increased rates that Northern Border Pipeline is seeking to collect are ultimately lowered by the FERC, on its own initiative, or as a result of challenges raised by Northern Border Pipeline's customers or third parties, the FERC could require refunds of amounts collected under rates that it finds unlawful. In addition, an adverse decision by the FERC in Northern Border Pipeline's rate case could result in reductions to Northern Border Pipeline's regulated rates on a prospective basis, which could adversely affect our cash flow. IF WE ARE UNABLE TO COMPETE FOR CUSTOMERS, WE MAY HAVE SIGNIFICANT LEVELS OF UNCONTRACTED OR DISCOUNTED TRANSPORTATION CAPACITY ON OUR INTERSTATE NATURAL GAS PIPELINES. Our interstate natural gas pipeline segment competes with other pipelines for Canadian natural gas supplies delivered to U.S. markets. If we do not successfully compete with the other natural gas pipelines, we may have significant levels of uncontracted or discounted capacity on our pipelines, which could adversely impact our results of operations. OUR INTERSTATE NATURAL GAS PIPELINES HAVE RECORDED CERTAIN ASSETS THAT MAY NOT BE RECOVERABLE FROM OUR CUSTOMERS. Accounting policies for FERC-regulated companies permit certain assets to be recorded that result from the regulated ratemaking process that would not be recorded under GAAP for nonregulated entities. We consider factors such as regulatory changes and the impact of competition to determine the probability of future recovery of these assets. If we determine future recovery is no longer probable, we would be required to write off the regulatory assets at that time. IF THE LEVEL OF DRILLING AND PRODUCTION IN THE WILLISTON, POWDER RIVER AND WIND RIVER BASINS SUBSTANTIALLY DECLINES, OUR GATHERING AND PROCESSING VOLUMES AND REVENUE COULD DECLINE. Our ability to maintain or expand our natural gas gathering and processing business depends largely on the level of drilling and production in the Williston, Powder River and Wind River Basins. Drilling and production in the Williston and Wind River Basins are impacted by factors beyond our control, including: - demand for natural gas and refinery-grade crude oil; - producers' desire and ability to obtain necessary permits in a timely and economic manner; - natural gas field characteristics and production performance; - surface access and infrastructure issues; and - capacity constraints on natural gas, crude oil and natural gas liquids pipelines that transport gas from the producing areas and our facilities. In addition, drilling and production in the Powder River Basin are impacted by environmental regulations governing water discharge associated with coalbed methane production. If the level of drilling and production in these 20 areas substantially declines, our gathering and processing volumes and revenue could be reduced. THE COMPOSITION OF NATURAL GAS RECEIVED BY OUR PIPELINES OR GATHERED BY OUR GATHERING AND PROCESSING OPERATIONS COULD REDUCE OUR AVAILABLE TRANSPORTATION CAPACITY AND INCREASE OUR OPERATING EXPENSES. If the energy content of the natural gas received by our pipelines is below the energy equivalent specified under our transportation contracts, we must transport additional natural gas to meet our contractual commitments. The transportation of this additional natural gas reduces the available transportation capacity on our pipelines and would negatively impact our operating revenue. In addition, if the energy content of the natural gas gathered by our natural gas gathering and processing operations is below pipeline quality standards and we are unable to blend the gas, we would incur higher operating expenses related to the additional processing required to avoid curtailment. OUR OPERATIONS ARE SUBJECT TO FEDERAL AND STATE LAWS AND REGULATIONS RELATING TO THE PROTECTION OF THE ENVIRONMENT, WHICH MAY EXPOSE US TO SIGNIFICANT COSTS AND LIABILITIES. The risk of incurring substantial environmental costs and liabilities is inherent in the performance of our operations. Our operations are subject to extensive federal, state and local laws and regulations governing the discharge of materials into the environment or otherwise relating to the protection of the environment. These laws include, for example: - the federal Clean Air Act and analogous state laws, which impose obligations related to air emissions; - the federal Water Pollution Control Act of 1972, as renamed and amended as the Clean Water Act and analogous state laws, which regulate discharge of wastewaters from our facilities to state and federal waters; - the federal Comprehensive Environmental Response, Compensation and Liability Act and analogous state laws that regulate the cleanup of hazardous substances that may have been released at properties currently or previously owned or operated by us or locations to which we have sent wastes for disposal; and - the federal Resource Conservation and Recovery Act and analogous state laws that impose requirements for the handling and discharge of solid and hazardous waste from our facilities. Various governmental authorities, including the U.S. EPA, have the power to enforce compliance with these laws and regulations and the permits issued under them. Violators are subject to administrative, civil and criminal penalties, including civil fines, injunctions or both. Joint and several, strict liability may be incurred without regard to fault under the Comprehensive Environmental Response, Compensation and Liability Act, Resource Conservation and Recovery Act and analogous state laws for the remediation of contaminated areas. There is inherent risk of the incurrence of environmental costs and liabilities in our business due to our handling of the products we gather, transport and process, air emissions related to our operations, historical industry operations and waste disposal practices, some of which may be material. Private parties, including the owners of properties through which our pipeline systems pass, may have the right to pursue legal actions to enforce compliance as well as to seek damages for non-compliance with environmental laws and regulations or for personal injury or property damage arising from our operations. Some sites we operate are located near current or former third-party hydrocarbon storage and processing operations and there is a risk that contamination has migrated from those sites to ours. In addition, increasingly strict laws, regulations and enforcement policies could significantly increase our compliance costs and the cost of any remediation that may become necessary, some of which may be material. Additional information is included under Item 1, "Business-Environmental and Safety Matters." Our insurance may not cover all environmental risks and costs or may not provide sufficient coverage in the event an environmental claim is made against us. Our business may be adversely affected by increased costs due to stricter pollution control requirements or liabilities resulting from non-compliance with required operating or other regulatory permits. New environmental regulations might also adversely affect our products and activities and federal and state agencies could impose additional safety requirements, all of which could materially affect our profitability. 21 PIPELINE INTEGRITY PROGRAMS AND REPAIRS MAY IMPOSE SIGNIFICANT COSTS AND LIABILITIES. In December 2003, the U.S. Department of Transportation issued a final rule requiring pipeline operators to develop integrity management programs for pipelines located near "high consequence areas," where a leak or rupture could do the most harm. The final rule requires operators to perform ongoing assessments of pipeline integrity; identify and characterize applicable threats to pipeline segments that could impact a high consequence area; improve data collection, integration and analysis; repair and remediate the pipeline as necessary; and implement preventive and mitigating actions. The final rule incorporates the requirements of the Pipeline Safety Improvement Act of 2002 and became effective in January 2004. The results of these testing programs could cause us to incur significant capital and operating expenditures in response to repair, remediation, preventative or mitigating actions that are determined to be necessary. WE ARE EXPOSED TO THE CREDIT RISK OF OUR CUSTOMERS AND OUR CREDIT RISK MANAGEMENT MAY NOT BE ADEQUATE TO PROTECT AGAINST SUCH RISK. We are subject to the risk of loss resulting from nonpayment and/or nonperformance by our customers. Our customers are predominantly natural gas producers and marketers that may experience deterioration of their financial condition as a result of changing market conditions or financial difficulties that could impact their creditworthiness or ability to pay us for our services. We have obtained the maximum security allowed under the FERC creditworthiness policy. If we fail to adequately assess the creditworthiness of existing or future customers, unanticipated deterioration in their creditworthiness and any resulting nonpayment and/or nonperformance could adversely impact our results of operations. In addition, if any of our customers filed for bankruptcy protection, we may not be able to recover amounts owed or resell the capacity held by such customer, which would negatively impact our results of operations. PERMANENT SHUT DOWN OF OUR COAL SLURRY OPERATION COULD ADVERSELY IMPACT OUR RESULTS OF OPERATIONS. Our coal slurry pipeline is the sole source of fuel for the Mohave Generating Station and was fully contracted to Peabody Western Coal until December 31, 2005. The water used by our coal slurry pipeline was supplied from an aquifer in the Navajo Nation and Hopi Tribe joint use area until December 31, 2005. The Mohave Generating Station co-owners, the Navajo Nation, Hopi Tribe, Peabody Western Coal Company and other interested parties continue to negotiate water source and coal supply issues and we are working to resolve coal slurry transportation issues so that operations may resume in the future. If the Mohave Generating Station is permanently closed, we expect to incur pipeline removal and remediation costs and a non-cash impairment charge related to the remaining undepreciated cost of the pipeline assets and goodwill. We may be required to take an impairment charge in accordance with GAAP prior to final resolution of the issues concerning the Mohave Generating Station even though the project may ultimately proceed. Each quarter, we will take into consideration our assumptions and estimates about economic conditions and the probability of Black Mesa's future profitability. If an event or change in circumstance occurs that potentially impacts our assumptions and estimates, we will be required to test the assets for impairment. If our testing indicates that the carrying amount of Black Mesa's assets exceeds their fair value, we would recognize an impairment charge. OUR USE OF FINANCIAL INSTRUMENTS TO HEDGE MARKET RISK MAY RESULT IN REDUCED INCOME. We utilize financial instruments to mitigate our exposure to interest rate and commodity price fluctuations. Hedging instruments that are used to reduce our exposure to interest rate fluctuations could expose us to risk of financial loss where we have contracted for variable-rate swap instruments to hedge fixed-rate instruments and the variable rate exceeds the fixed rate. In addition, these hedging arrangements may limit the benefit we would otherwise receive if we have contracted for fixed-rate swap agreements to hedge variable-rate instruments and the variable rate falls below the fixed rate. Hedging arrangements that are used to reduce our exposure to commodity price fluctuations may limit the benefit we would otherwise receive if market prices for natural gas and natural gas liquids exceed the stated price in the hedge instrument for these commodities. A DOWNGRADE OF OUR CREDIT RATING MAY REQUIRE US TO OFFER TO REPURCHASE OUR SENIOR NOTES OR IMPAIR OUR ABILITY TO ACCESS CAPITAL. 22 We could be required to offer to repurchase certain of our senior notes at par value, plus any associated penalties and premiums, if Moody's Investor Services or Standard & Poor's Rating Services rate our senior notes below investment grade. We may not have sufficient cash on hand to repurchase the senior notes at par value, which may cause us to borrow money under our credit facilities or seek alternative financing sources to finance the repurchase. We could also face difficulties accessing capital or our borrowing costs could increase, impacting our ability to obtain financing for acquisitions or capital expenditures and to refinance indebtedness. OUR INABILITY TO EXECUTE GROWTH AND DEVELOPMENT PROJECTS AND ACQUIRE NEW ASSETS COULD REDUCE CASH DISTRIBUTIONS TO UNITHOLDERS. Our interstate natural gas pipelines are generally allowed to collect a return on their assets' recorded book value, generally referred to as rate base, in their transportation rates. Our interstate pipelines must maintain or increase the book value of their assets through growth projects in order to maintain or increase the return collected on our rate base. Accordingly, if we are unable to implement business development opportunities and finance such activities on economically acceptable terms, our future growth will be limited, which could adversely impact our results of operations. RISKS RELATED TO PROPOSED TRANSACTIONS WE MAY NOT BE ABLE TO CONSUMMATE THE ACQUISITION OF THE ONEOK SUBSIDIARIES. The agreements with ONEOK to acquire certain subsidiaries of ONEOK contain customary and other closing conditions that, if not satisfied or waived, would result in the acquisition not occurring. These conditions include, among others: - expiration or early termination of the waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976; - continued accuracy of the representations and warranties contained in the agreements; - performance by each party of its obligations under the agreements; - consummation of ONEOK's purchase of Northwest Border; - consummation of our sale of a 20% interest in Northern Border Pipeline to TC PipeLines; - amendments to certain debt agreements of ONEOK, us and Northern Border Pipeline; - lender approvals; and - absence of any decree, order, injunction or law that prohibits, restricts or substantially delays the transaction or makes the transaction unlawful. If we are unable to consummate the acquisition, we would be subject to a number of risks, including the following: - we would not realize the anticipated benefits of the proposed acquisition; - we will incur and will remain liable for significant transaction costs, including legal, accounting, financial advisory and other costs relating to the acquisition whether or not it is consummated; and - our business and operations may be harmed to the extent that customers, suppliers and others believe that we cannot effectively compete in the marketplace without the acquisition or there is customer or employee uncertainty surrounding the future direction of our service offerings and strategy. The occurrence of any of these events individually or in combination could have an adverse effect on our results of operations. WE MAY NOT BE ABLE TO SUCCESSFULLY INTEGRATE THE OPERATIONS OF ONEOK WITH OUR CURRENT OPERATIONS. If we consummate the acquisition of certain ONEOK subsidiaries, the integration of their operations with our current operations will be a complex, time-consuming and costly process. Failure to timely and successfully integrate the operations of the ONEOK subsidiaries may have a material adverse effect on our business, financial condition and results of operations. The difficulties of integrating the ONEOK operations will present challenges to our management including: - operating a significantly larger combined company with operations in geographic areas in which we have not previously operated; 23 - managing relationships with new customers for whom we have not previously provided services; - integrating personnel with diverse backgrounds and organizational cultures; - experiencing operational interruptions or the loss of key employees, customers or suppliers; - inefficiencies and complexities that may arise due to the unfamiliarity with the new operations and the businesses associated with them, including with their markets; - assimilating the operations, technologies, services and products of the acquired operations; - assessing the internal controls and procedures for the combined entity that we are required to maintain under the Sarbanes-Oxley Act of 2002; and - consolidating other corporate and administrative functions. We will also be exposed to risks that are commonly associated with transactions similar to this acquisition, such as unanticipated liabilities and costs, some of which may be material, and diversion of management's attention. As a result, the anticipated benefits of the acquisition may not be fully realized, if at all. THE ISSUANCE OF UNITS TO ONEOK IN CONNECTION WITH THE ACQUISITION WILL DILUTE OUR CURRENT UNITHOLDERS' OWNERSHIP INTERESTS UPON THEIR CONVERSION TO COMMON UNITS. In connection with the acquisition of the ONEOK subsidiaries, we will issue approximately 36.5 million Class B units representing limited partner interests in us to ONEOK. The Class B units will convert to common units on a one-for-one basis at the holder's option upon the requisite approval of such conversion by our unitholders at a special meeting of unitholders or automatically, upon the requisite approval of both the conversion and certain amendments to our partnership agreement by our unitholders at a special meeting of unitholders. The conversion of the Class B units will have the following effects: - our unitholders' proportionate ownership interest in us will decrease; - the amount of cash available to pay distributions on each common unit may decrease; - the relative voting strength of each previously outstanding common unit may be diminished; and - the market price of the common units may decline. In addition, ONEOK may, from time to time, sell all or a portion of its common units. Sales of substantial amounts of their common units, or the anticipation of such sales, could lower the market price of our common units and may make it more difficult for us to sell our equity securities in the future at a time and at a price that we deem appropriate. RISKS INHERENT IN AN INVESTMENT IN US WE DO NOT OPERATE ALL OF OUR ASSETS NOR DO WE DIRECTLY EMPLOY ANY OF THE PERSONS RESPONSIBLE FOR PROVIDING US WITH ADMINISTRATIVE, OPERATING AND MANAGEMENT SERVICES. THIS RELIANCE ON OTHERS TO OPERATE OUR ASSETS AND TO PROVIDE OTHER SERVICES COULD ADVERSELY AFFECT OUR BUSINESS AND OPERATING RESULTS. We rely on Northern Plains and NBP Services to provide us with administrative, operating and management services. We have a limited ability to control our operations or the associated costs of such operations. The success of these operations depends on a number of factors that are outside our control, including the competence and financial resources of the operator. Northern Plains and NBP Services may outsource some or all of these services to third parties, and a failure to perform by these third-party providers could lead to delays in or interruptions of these services. Should Northern Plains or NBP Services not perform their respective contractual obligations, we may have to contract elsewhere for these services, which may cost more than we are currently paying. In addition, we may not be able to obtain the same level or kind of service or retain or receive the services in a timely manner, which may impact our ability to perform under our transportation contracts and negatively affect our business and operating results. Our reliance on Northern Plains, NBP Services and the third-party providers with which they contract, together with our limited ability to control certain costs, could harm our business and results of operations. THE PARTNERSHIP POLICY COMMITTEE, OUR GENERAL PARTNERS AND THEIR AFFILIATES HAVE CONFLICTS OF INTEREST AND LIMITED FIDUCIARY DUTIES, WHICH MAY PERMIT THEM TO FAVOR THEIR OWN INTERESTS. 24 Our general partners collectively own a 2% general partner interest and a 1.06% limited partner interest in us. Although our general partners, through the Partnership Policy Committee, have a fiduciary duty to manage us in a manner beneficial to us and our unitholders, the boards of directors of the general partners have a fiduciary duty to manage our general partners in a manner beneficial to their respective owners. Some members of our Partnership Policy Committee are also members of their respective general partner's board of directors. Conflicts of interest may arise between our general partners and their affiliates and us and our unitholders. In resolving these conflicts, our general partners may favor their own interests and the interests of their respective affiliates over the interests of our unitholders. These conflicts include, among others, the following situations: - the Partnership Policy Committee and our general partners are allowed to take into account the interests of parties other than us, such as ONEOK and TransCanada, in resolving conflicts of interest, which has the effect of limiting its fiduciary duty to our unitholders; - the respective affiliates of our general partners may engage in competition with us; - the Partnership Policy Committee and our general partners have limited their liability and reduced their fiduciary duties, and have also restricted the remedies available to our unitholders for actions that, without the limitations, might constitute breaches of fiduciary duty; - the Partnership Policy Committee determines the amount and timing of our cash reserves, asset purchases and sales, capital expenditures, borrowings and issuances of additional partnership securities, each of which can affect the amount of cash that is distributed to our unitholders; - the Partnership Policy Committee approves the amount and timing of any capital expenditures. The nature of the capital expenditure, whether it is a maintenance capital expenditure or a growth capital expenditure, can affect the amount of cash that is distributed to our unitholders; - the Partnership Policy Committee may cause us to borrow funds in order to permit the payment of cash distributions, even if the purpose or effect of the borrowing is to make incentive distributions; - the Partnership Policy Committee determines which costs incurred by them, our general partners and their respective affiliates are reimbursable by us; - our partnership agreement does not restrict the Partnership Policy Committee from causing us to pay them, our general partners or their respective affiliates for any services rendered to us or entering into additional contractual arrangements with any of these entities on our behalf; - our general partners may exercise their limited right to call and purchase common units if they and their respective affiliates own more than 80% of the units; and - the Partnership Policy Committee decides whether to retain separate counsel, accountants or others to perform services for us. OUR PARTNERSHIP AGREEMENT LIMITS OUR GENERAL PARTNERS' FIDUCIARY DUTIES TO OUR UNITHOLDERS AND RESTRICTS THE REMEDIES AVAILABLE TO UNITHOLDERS FOR ACTIONS TAKEN BY OUR GENERAL PARTNERS THAT MIGHT OTHERWISE CONSTITUTE BREACHES OF FIDUCIARY DUTY. Our partnership agreement contains provisions that reduce the standards to which our general partners would otherwise be held by state fiduciary duty law. For example, our partnership agreement: - permits our general partners to make a number of decisions in their individual capacities, as opposed to in their capacity as our general partners. This entitles our general partners to consider only the interests and factors that they desire, and they have no duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or any limited partner. Examples include the exercise of their limited call right, their voting rights with respect to the units they own, their registration rights and their determination (through the Partnership Policy Committee) whether or not to consent to any merger or consolidation of the partnership; - provides that our general partners will not have any liability to us or our unitholders for decisions made in their capacity as a general partner so long as they acted in good faith, meaning they believed the decision was in the best interests of our partnership; - provides that our general partners are entitled to make other decisions in "good faith" if they reasonably believe that the decision is in our best interests; - provides generally that affiliated transactions and resolutions of conflicts of interest not approved by the Audit Committee and not involving a vote of unitholders must be on terms no less favorable to us than those generally being provided to or available from unrelated third parties or be "fair and reasonable" to us, as determined by our general partners in good faith, and that, in determining whether a transaction or 25 resolution is "fair and reasonable," our general partners may consider the totality of the relationships between the parties involved, including other transactions that may be particularly advantageous or beneficial to us; and - provides that our general partners, their respective affiliates and their officers and directors will not be liable for monetary damages to us or our limited partners for any acts or omissions so long as such person acted in good faith and in a manner believed to be in, or not opposed to, the best interest of the partnership and, with respect to any criminal proceeding, had no reasonable cause to believe its conduct was unlawful. By purchasing a common unit, a common unitholder will be bound by the provisions in the partnership agreement, including the provisions discussed above. THE CONTROL OF OUR GENERAL PARTNERS MAY BE TRANSFERRED TO A THIRD PARTY WITHOUT UNITHOLDER CONSENT. Our general partners may transfer their respective general partner interests to a third party without the consent of the unitholders. Furthermore, our partnership agreement does not restrict the ability of the members of our general partners from transferring their interests in our general partners to a third party. The new members or stockholders, as the case may be, of our general partners would then be in a position to replace the members of the Partnership Policy Committee with their own choices and to control the decisions taken by the Partnership Policy Committee. INCREASES IN INTEREST RATES MAY CAUSE THE MARKET PRICE OF OUR COMMON UNITS TO DECLINE. An increase in interest rates may cause a corresponding decline in demand for equity investments in general, and in particular for yield-based equity investments such as our common units. Any such increase in interest rates or reduction in demand for our common units resulting from other more attractive investment opportunities may cause the trading price of our common units to decline. WE MAY ISSUE ADDITIONAL COMMON UNITS WITHOUT UNITHOLDER APPROVAL, WHICH WOULD DILUTE UNITHOLDERS' OWNERSHIP INTERESTS. Our general partners, without the approval of our unitholders, may cause us to issue an unlimited number of additional units, subject to the limitations imposed by the NYSE. The issuance by us of additional common units or other equity securities of equal or senior rank will have the following effects: - our unitholders' proportionate ownership interest in us will decrease; - the amount of cash available to pay distributions on each unit may decrease; - the relative voting strength of each previously outstanding unit may be diminished; and - the market price of the common units may decline. OUR GENERAL PARTNERS AND THEIR AFFILIATES MAY COMPETE DIRECTLY WITH US AND HAVE NO OBLIGATION TO PRESENT BUSINESS OPPORTUNITIES TO US. Our general partners and their affiliates are not prohibited from owning assets or engaging in businesses that compete directly or indirectly with us. ONEOK may acquire, construct or dispose of additional midstream or other assets in the future without any obligation to offer us the opportunity to purchase or construct any of those assets. In addition, under our partnership agreement, the doctrine of corporate opportunity, or any analogous doctrine, will not apply to ONEOK and its affiliates. As a result, neither ONEOK nor any of its affiliates has any obligation to present business opportunities to us. OUR GENERAL PARTNERS HAVE A LIMITED CALL RIGHT THAT MAY REQUIRE UNITHOLDERS TO SELL THEIR COMMON UNITS AT AN UNDESIRABLE TIME OR PRICE. If at any time our general partners and their respective affiliates own more than 80% of the common units, our general partners will have the right, but not the obligation, which they may assign to any of their respective affiliates or to us, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price not less than their then-current market price. As a result, unitholders may be required to sell their common units at an undesirable time or price and may not receive any return on their investment. Unitholders may also incur a tax liability upon the sale of their units. Our general partners are not obligated to obtain a fairness opinion regarding the value of the 26 common units to be repurchased by them upon exercise of the limited call right. There is no restriction in our partnership agreement that prevents our general partners from issuing additional common units and exercising their call right. If our general partners exercised their limited call right, the effect would be to take us private and, if the units were subsequently deregistered, we would not longer be subject to the reporting requirements of the Exchange Act. OUR PARTNERSHIP AGREEMENT RESTRICTS THE VOTING RIGHTS OF UNITHOLDERS OWNING 20% OR MORE OF OUR COMMON UNITS. Our partnership agreement restricts unitholders' voting rights by providing that any units held by a person that owns 20% or more of any class of units then outstanding, other than our general partners and their respective affiliates, cannot vote on any matter. The partnership agreement also contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting the unitholders ability to influence the manner or direction of management. COST REIMBURSEMENTS DUE TO OUR GENERAL PARTNERS AND THEIR RESPECTIVE AFFILIATES WILL REDUCE CASH AVAILABLE TO PAY DISTRIBUTIONS TO UNITHOLDERS. Prior to making any distribution on the common units, we will reimburse our general partners and their respective affiliates for all expenses they incur on our behalf, which will be determined by our general partners. These expenses will include all costs incurred by the general partners and their respective affiliates in managing and operating us, including costs for rendering corporate staff and support services to us. The reimbursement of expenses and payment of fees, if any, to our general partners and their respective affiliates, could adversely affect our ability to pay cash distributions to our unitholders. UNITHOLDERS MAY NOT HAVE LIMITED LIABILITY IF A COURT FINDS THAT UNITHOLDER ACTION CONSTITUTES CONTROL OF OUR BUSINESS. UNITHOLDERS MAY ALSO HAVE LIABILITY TO REPAY DISTRIBUTIONS. As a limited partner in a partnership organized under Delaware law, unitholders could be held liable for our obligations to the same extent as a general partner if they participate in the "control" of our business. Our general partners generally have unlimited liability for the obligations of the partnership, such as its debts and environmental liabilities, except for those contractual obligations of the partnership that are expressly made without recourse to our general partners. In addition, the Delaware Revised Uniform Limited Partnership Act provides that, under some circumstances, a unitholder may be liable to us for the amount of a distribution for a period of three years from the date of the distribution. The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some of the other states in which we do business. TAX RISKS OUR TAX TREATMENT DEPENDS ON OUR STATUS AS A PARTNERSHIP FOR FEDERAL INCOME TAX PURPOSES, AS WELL AS OUR NOT BEING SUBJECT TO ENTITY-LEVEL TAXATION BY STATES. IF THE IRS WERE TO TREAT US AS A CORPORATION OR IF WE WERE TO BECOME SUBJECT TO ENTITY-LEVEL TAXATION FOR STATE TAX PURPOSES, THEN OUR CASH AVAILABLE TO PAY DISTRIBUTIONS TO UNITHOLDERS WOULD BE SUBSTANTIALLY REDUCED. The anticipated after-tax benefit of an investment in common units depends largely on our being treated as a partnership for federal income tax purposes. We have not requested a ruling from the IRS with respect our classification as a partnership for federal income tax purposes. Under current law, we are treated as a partnership for federal income tax purposes and do not pay any income tax at the entity level. In order to qualify for this treatment, we must derive more than 90% of our annual gross income from specified investments and activities. While we believe that we currently do qualify and intend to meet this income requirement, if we should fail, we would be treated as if we were a newly formed corporation. If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our income at the corporate tax rate, which is currently a maximum of 35%. In addition, the entire amount of cash received by each unitholder would generally be taxed again as a corporate distribution when received, and no income, gains, losses, deductions or credits would flow through to our unitholders. Because a tax would be imposed upon us as a corporation, the cash available for distribution to our unitholders would be substantially reduced. Thus, treatment of us as a corporation would result in a material 27 reduction in the anticipated cash flow and after-tax return to unitholders, likely causing a substantial reduction in the value of the common units. Current law may change, causing us to be treated as a corporation for federal income tax purposes or otherwise subjecting us to entity-level taxation. For example, because of widespread state budget deficits, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, use, franchise or other forms of taxation. If any state were to impose a tax upon us as an entity, the cash available to pay distributions would be reduced. Our partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for federal, state or local income tax purposes, then the minimum quarterly distribution amount and the target distribution levels will be decreased to reflect that impact on us. A SUCCESSFUL IRS CONTEST OF THE FEDERAL INCOME TAX POSITIONS WE TAKE MAY ADVERSELY IMPACT THE MARKET FOR OUR COMMON UNITS, AND THE COSTS OF ANY CONTEST WILL BE BORNE BY OUR UNITHOLDERS AND GENERAL PARTNERS. We have not requested any ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes. The IRS may adopt positions that differ from the federal income tax positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take. A court may not agree with some or all of the positions we take. Any contest with the IRS may materially and adversely impact the market for our common units and the price at which they trade. In addition, the costs of any contest with the IRS will result in a reduction in cash available to pay distributions to our unitholders and our general partners and thus will be borne indirectly by our unitholders and our general partners. A UNITHOLDER MAY BE REQUIRED TO PAY TAXES ON A SHARE OF OUR INCOME EVEN IF THE UNITHOLDER DOES NOT RECEIVE ANY CASH DISTRIBUTIONS FROM US. A unitholder will be required to pay federal income taxes and, in some cases, state and local income taxes on the unitholder's share of our taxable income, whether or not the unitholder receives cash distributions from us. A unitholder may not receive cash distributions from us equal to the unitholder's share of our taxable income or even equal to the actual tax liability that results from that share of our taxable income. THE TAXABLE GAIN OR LOSS ON THE DISPOSITION OF OUR COMMON UNITS COULD BE DIFFERENT THAN EXPECTED. A unitholder will recognize gain or loss on the sale of common units equal to the difference between the amount realized and the unitholder's tax basis in those common units. A unitholder's amount realized will be measured by the sum of the cash or the fair market value of other property received plus the unitholder's share of our nonrecourse liabilities. Because the amount realized includes a unitholder's share of our nonrecourse liabilities, the gain recognized on the sale of common units could result in a tax liability in excess of any cash received from the sale. Prior distributions to a unitholder in excess of the total net taxable income allocated to a unitholder for a common unit, which decreased the tax basis in that common unit, will, in effect, become taxable income to a unitholder if the common unit is sold at a price greater than the tax basis in that common unit, even if the price received is less than the original cost. A substantial portion of the amount realized, whether or not representing gain, may be ordinary income to a unitholder. TAX-EXEMPT ENTITIES AND FOREIGN PERSONS FACE UNIQUE TAX ISSUES FROM OWNING COMMON UNITS THAT MAY RESULT IN ADVERSE TAX CONSEQUENCES TO THEM. Investment in common units by tax-exempt entities, such as individual retirement accounts, regulated investment companies known as mutual funds, and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to organizations exempt from federal income tax, including individual retirement accounts and other retirement plans, will be unrelated business taxable income and will be taxable to them. Distributions to non-U.S. persons will be reduced by withholding taxes at the highest applicable effective tax rate, and non-U.S. persons will be required to file U.S. federal income tax returns and pay tax on their share of our taxable income. WE WILL TREAT EACH PURCHASER OF UNITS AS HAVING THE SAME TAX BENEFITS WITHOUT REGARD TO THE UNITS PURCHASED. THE IRS MAY CHALLENGE THIS TREATMENT, WHICH COULD ADVERSELY AFFECT THE VALUE OF THE COMMON UNITS. 28 Because we cannot match transferors and transferees of common units, we have adopted depreciation and amortization positions that may not conform to all aspects of existing Treasury regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to unitholders. It also could affect the timing of these tax benefits or the amount of gain from a unitholder's sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to a unitholder's tax returns. UNITHOLDERS WILL BE SUBJECT TO STATE AND LOCAL TAXES AND RETURN FILING REQUIREMENTS AS A RESULT OF INVESTING IN OUR COMMON UNITS. In addition to federal income taxes, unitholders will be subject to other taxes, such as state and local income taxes, unincorporated business taxes and estate, inheritance, or intangible taxes that are imposed by the various jurisdictions in which we do business or own property. Unitholders will be required to file state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions and may be subject to penalties for failure to comply with those requirements. We may own property or conduct business in other states or foreign countries in the future. It is each unitholder's responsibility to file all federal, state and local tax returns. Some of the states in which we do business or own property may require us, or we may elect to withhold a percentage of income from amounts to be distributed to a unitholder who is not a resident of the state. Withholding, the amount of which may be greater or less than a particular unitholder's income tax liability to the state, generally does not relieve the non-resident unitholder from the obligation to file an income tax return. Amounts withheld may be treated as if distributed to unitholders for purposes of determining the amounts distributed by us. Our counsel has not rendered an opinion on the state and local tax consequences of an investment in our units. THE SALE OR EXCHANGE OF 50% OR MORE OF OUR CAPITAL AND PROFITS INTERESTS WILL RESULT IN THE TERMINATION OF OUR PARTNERSHIP FOR FEDERAL INCOME TAX PURPOSES. We will be considered to have terminated for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a 12-month period. Our termination would, among other things, result in the closing of our taxable year for all unitholders and could result in a deferral of depreciation deductions allowable in computing our taxable income. ITEM 1B. UNRESOLVED STAFF COMMENTS None. ITEM 2. PROPERTIES See Item 1, "Business-Narrative Description of Business," for a description of our properties, their utilization, and how each property is held. ITEM 3. LEGAL PROCEEDINGS NORTHERN BORDER PIPELINE RATE CASE On November 1, 2005, as required by the provisions of the settlement of Northern Border Pipeline's 1999 rate case, Northern Border Pipeline filed a rate case with the FERC. The rate case filing proposes a 7.8% increase to Northern Border Pipeline's revenue requirement; a change to its rate design approach with a supply zone and market area utilizing a fixed rate per dekatherm and a dekatherm-mile rate, respectively; a compressor usage surcharge primarily to recover costs related to powering electric compressors; and the implementation of a short-term rate structure on a prospective basis. The filing also incorporates an overall cost of capital of 10.56% based on a rate of return on equity of 14.20%, an increase in the depreciation rate for transmission plant from 2.25% to 2.84%, the institution of a negative salvage rate of 0.59% and a decrease in billing determinants. Also included in the filing is the continued inclusion of income taxes in the rate calculation. In December 2005, the FERC issued an order that identified issues raised in the proceeding, accepted the proposed rates but suspended their effectiveness until May 1, 2006, at which time the new rates will be collected subject to refund until final resolution of the rate case. The FERC also issued a procedural schedule which set a hearing 29 commencement date of October 4, 2006, with an initial decision scheduled for February 2007, unless a settlement of the issues is reached with the FERC and a majority of Northern Border Pipeline's customers. F. RICHARD MANSON V. NORTHERN PLAINS NATURAL GAS COMPANY, LLC, ET AL., CIVIL ACTION NO. 1973-N, IN THE NEW CASTLE COUNTY CHANCERY COURT, DELAWARE. On February 15, 2006, Northern Border Partners, L.P. and ONEOK, Inc. issued a joint press release announcing certain transactions relating to (1) the sale of certain assets by ONEOK to Northern Border Partners, (2) the increase of ONEOK's general partnership interest in Northern Border Partners to 100% and (3) the sale by Northern Border Partners of 20% of its interest in Northern Border Pipeline Company to TC PipeLines, LP. (collectively, the "Transactions"). On March 2, 2006, a holder of limited partnership units of Northern Border Partners, L.P. filed a class action and derivative complaint, Civil Action No. 1973-N, in the New Castle County Chancery Court in the State of Delaware, on behalf of a putative class of all holders of limited partnership units against Northern Border Partners, ONEOK, Northern Plains Natural Gas Company, LLC, and related entities involved in the Transactions. The plaintiff claims the Transactions will constitute a breach of our partnership agreement and a breach of defendants' fiduciary duties. The plaintiff seeks to enjoin the Transactions or to rescind the Transactions if the Transactions are completed prior to entry of a final judgment in the case. The Plaintiff also seeks to recover on behalf of the class damages for the profits and any special benefits obtained by the defendants, as well as interest, costs, and attorney and expert fees. We have not yet been served with the complaint. Various other legal actions that have arisen in the ordinary course of business are pending. We believe that the resolution of these issues will not have a material adverse impact on our results of operations or financial position. ITEM 4. SUBMISSIONS OF MATTERS TO A VOTE OF SECURITY HOLDERS Not applicable. PART II ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES Our equity consists of a 2% general partner interest and a 98% limited partner interest. Our limited partner interests are represented by our common units, which are listed on the NYSE under the trading symbol "NBP." At January 31, 2006, there were approximately 67,400 beneficial owners (held in street name) and 1,100 holders of record of our 46,397,214 outstanding common units. The high and low trading prices and cash distributions per common unit declared for each quarter of fiscal 2005 and 2004 were as follows:

PRICE RANGE ------------------- CASH HIGH LOW DISTRIBUTION ------ ------ ------------ 2004 First quarter $42.60 $38.01 $0.80 Second quarter $42.60 $35.70 $0.80 Third quarter $45.81 $38.61 $0.80 Fourth quarter $49.54 $44.60 $0.80 2005 First quarter $52.99 $45.60 $0.80 Second quarter $51.13 $45.21 $0.80 Third quarter $52.35 $45.75 $0.80 Fourth quarter $48.00 $40.60 $0.80

CASH DISTRIBUTION POLICY We are required to distribute 100% of our available cash as defined in our partnership agreement to our general and limited partners within 45 days following the end of each quarter. Available cash generally consists of all cash receipts less adjustments for cash disbursements and net changes to reserves. Our income is allocated to the general partners and limited partners according to their respective partnership percentages of 2% and 98%, respectively, after the effect of any incremental income allocations for incentive distributions to the general partners. The general partners receive incentive distributions if the quarterly cash distribution exceeds $0.605 per common unit as follows:

QUARTERLY INCENTIVE QUALIFIER INCENTIVE DISTRIBUTION ----------------------------- ---------------------- Cash distribution in excess of $0.605 per common unit 15% of the amount in excess of $0.605 Cash distribution in excess of $0.715 per common unit 25% of the amount in excess of $0.715 Cash distribution in excess of $0.935 per common unit 50% of the amount in excess of $0.935

30 In 2005 and 2004, we paid cash distributions of $159.6 million to our general and limited partners, which included an incentive distribution of $8.0 million to our general partners, each year. Additional information about our cash distributions is included under Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations-Liquidity and Capital Resources," and Item 13, "Certain Relationships and Related Transactions." On February 15, 2006, the Partnership Policy Committee announced that after we close a series of proposed transactions, including the sale of a 20% partnership interest in Northern Border Pipeline, Northern Plain's acquisition of TransCanada's 0.35% general partner interest and our purchase of ONEOK's entire gathering and processing, natural gas liquids, and pipelines and storage segments, they intend to consider an increase in the quarterly distributions to unitholders, which could also exceed the maximum general partner incentive distribution target. Depending on the timing of the closing, an increase could be included in the first quarter distribution payable in May 2006. Additional information about the proposed transactions is included under Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations-Executive Summary." 31 ITEM 6. SELECTED FINANCIAL DATA The following table sets forth our selected financial data for each of the periods indicated.

YEARS ENDED DECEMBER 31, -------------------------------------------------------------- 2005 2004 2003 (1) 2002 2001 (2) ---------- ---------- ---------- ---------- ---------- (In thousands, except per unit, other financial and operating data) Income data: Operating revenue, net $ 678,560 $ 590,383 $ 550,948 $ 487,204 $ 455,997 Product purchases 167,257 103,213 80,774 50,648 39,699 Operations and maintenance 129,950 111,142 127,623 106,521 92,891 Depreciation and amortization (3) 86,010 86,431 299,791 74,672 75,424 Taxes other than income 38,575 36,212 35,443 32,194 27,863 ---------- ---------- ---------- ---------- ---------- Operating income 256,768 253,385 7,317 223,169 220,120 Interest expense, net 86,903 76,943 78,980 82,898 89,908 Other income, net 28,108 19,648 23,679 15,170 258 Minority interests in net income 45,674 50,033 44,460 42,816 42,138 Income taxes 5,792 5,136 4,705 1,643 499 ---------- ---------- ---------- ---------- ---------- Income (loss) from continuing operations 146,507 140,921 (97,149) 110,982 87,833 Discontinued operations, net of tax (4) 506 3,799 9,338 2,694 (47) Cumulative effect of change in accounting principle, net of tax -- -- (643) -- -- ---------- ---------- ---------- ---------- ---------- Net income (loss) to partners $ 147,013 $ 144,720 $ (88,454) $ 113,676 $ 87,786 ========== ========== ========== ========== ========== Per unit income (loss) from continuing operations $ 2.92 $ 2.81 $ (2.27) $ 2.38 $ 2.12 ========== ========== ========== ========== ========== Per unit net income (loss) $ 2.93 $ 2.89 $ (2.08) $ 2.44 $ 2.12 ========== ========== ========== ========== ========== Number of units used in computation 46,397 46,397 45,370 42,709 38,538 ========== ========== ========== ========== ========== Cash flow data: Net cash provided by operating activities $ 267,372 $ 244,658 $ 224,660 $ 244,006 $ 233,948 Capital expenditures 59,882 43,477 30,282 50,738 126,414 Acquisition of businesses -- -- 123,194 1,561 345,074 Distribution per unit 3.20 3.20 3.20 3.20 2.99 Balance sheet data: Property, plant and equipment, net $1,918,510 $1,941,558 $1,992,104 $2,015,280 $2,040,099 Total assets 2,527,766 2,514,690 2,570,583 2,715,936 2,687,355 Long-term debt, including current maturities 1,354,971 1,330,358 1,415,986 1,403,743 1,423,227 Minority interests in partners' equity 274,510 290,142 240,731 242,931 250,078 Partners' equity 765,589 789,334 800,573 944,035 914,958 Other financial data: Ratio of earnings to fixed charges (5) 3.1 3.4 0.4 2.8 2.5

32 Operating data by segment: Interstate natural gas pipeline: MMcf delivered 1,141,902 1,130,634 1,110,969 935,654 891,935 MMcf/d average throughput 3,204 3,166 3,147 2,636 2,605 Natural gas gathering and processing: MMcf/d gathered 1,044 1,022 1,037 1,052 754 MMcf/d processed 64 55 52 55 54 Coal slurry pipeline: Thousands of tons shipped 4,561 4,652 4,451 4,639 4,932 (1) Includes results of operations for Viking Gas Transmission since date of acquisition in January 2003. (2) Includes results of operations for Bear Paw Energy (March 2001), Midwestern Gas Transmission (May 2001) and Border Midstream (April 2001) since dates of acquisition. (3) Includes goodwill and asset impairment charge of $219,080 in 2003 related to our natural gas gathering and processing business segment. (4) In June 2003, Border Midstream sold its Gladys and Mazeppa processing plants and related gas gathering facilities. In December 2004, Border Midstream sold its undivided minority interest in the Gregg Lake/Obed Pipeline. (5) Earnings are the sum of pre-tax income from continuing operations (before adjustment for minority interests in consolidated subsidiaries or income from equity investees), fixed charges, amortization of capitalized interest and distributions from equity investees, less capitalized interest and the minority interests in pre-tax income of subsidiaries that have not incurred fixed charges. Fixed charges are the sum of interest expensed and capitalized; amortized premiums, discounts and capitalized expenses related to indebtedness; and an estimate of interest within rental expenses. The ratio of earnings to fixed charges for 2003 was lower than prior years' ratios due primarily to the goodwill and asset impairment charges booked in 2003. Excluding the impact of the impairment, the ratio would have been 3.1 for 2003. 33 ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS The following discussion and analysis should be read in conjunction with our consolidated financial statements and accompanying notes included under Item 15. EXECUTIVE SUMMARY OVERVIEW Northern Border Partners is a publicly-traded Delaware limited partnership formed in 1993. Our common units are listed on the NYSE under the trading symbol "NBP." Our purpose is to acquire, own and manage pipeline and other midstream energy assets. Our equity consists of a 2% general partner interest and a 98% limited partner interest. ONEOK is our majority general partner and holds a combined general and limited partner interest in us of 2.71%. We provide natural gas transportation services and are a leading transporter of natural gas imported from Canada to the U.S. In addition, we gather, process and compress natural gas, fractionate natural gas liquids, and transport coal slurry. Our operations are conducted through the following three business segments: - Interstate Natural Gas Pipeline; - Natural Gas Gathering and Processing; and - Coal Slurry Pipeline. In 2005, the interstate natural gas pipeline segment accounted for 81% of our consolidated operating income. Operating revenue of this segment is derived from transportation contracts under FERC-regulated tariffs. Customers with firm service transportation agreements pay a fee known as a demand charge to reserve pipeline capacity, regardless of use, for the term of their contracts. Firm service transportation customers also pay a fee known as a commodity charge that is based on the volume of natural gas they transport. Customers with interruptible service transportation agreements may utilize available capacity on our pipelines after firm service transportation requests are satisfied. Interruptible service customers are assessed commodity charges only. In 2005, 97% of the interstate natural gas pipeline segment's revenue was derived from demand charges. The natural gas gathering and processing segment accounted for 17% of our consolidated operating income in 2005. Operating revenue of this segment is derived primarily from percentage-of-proceeds and fee-based contracts. Under percentage-of-proceeds contracts, we retain a percentage of the commodities that we gather and process in exchange for our services. We are exposed to commodity price risk when we sell the natural gas and natural gas liquids we retain in the open market. We use derivative instruments to mitigate our sensitivity to fluctuations in the price of natural gas and natural gas liquids. Information about our business, properties and strategy can be found under Item 1, "Business," and a description of our risk factors can be found under Item 1A, "Risk Factors." OUR BUSINESS ENVIRONMENT A healthy long-term natural gas supply outlook is critical for our operations. Western Canada supply trends are particularly important to us because the majority of the natural gas we transport is produced in the Western Canada Sedimentary Basin. We estimate that Northern Border Pipeline transported approximately 20% of Canada's natural gas export volume in 2005. In 2005, Canadian natural gas supplies available for export were relatively flat compared with prior years. Canadian natural gas supplies available for export could be impacted by the development of oil sand reserves due to increased natural gas consumption associated with production. Increased production of crude oil from oil sand reserves in Canada could reduce natural gas available for export to the U.S. if production and the related demand for natural gas are significantly greater than supply growth. Despite this possibility, we anticipate that Canadian natural gas supplies available for export in 2006 will be similar to 2005. Once new pipeline projects associated with the Mackenzie Delta in Northern Canada and Alaska are constructed, we could have access to new supply sources. 34 We gather and process unconventional natural gas produced in the Powder River Basin and conventional natural gas in the Williston and Wind River Basins. Unconventional natural gas differs from conventional natural gas only by its reservoirs, which have characteristics that make production more difficult compared with conventional natural gas reservoirs. We expect coalbed methane gas production in the Powder River Basin to remain flat or increase moderately in 2006. We expect casinghead gas production in the Williston Basin to increase at least through 2006 but at a slower rate of growth compared with 2005 because of curtailment of crude oil production due to refinery outages and constraints in crude oil pipeline shipments. This situation in the Williston Basin, which began in late 2005, is expected to continue moderately affecting natural gas production at least through 2006. We serve natural gas markets in the Midwestern U.S. and provide our customers with access to the Chicago market area, which is the third largest market area hub in North America. Although domestic demand for natural gas is expected to remain near 2005 levels in 2006, relatively high prices may significantly impact natural gas supply and demand. Strong natural gas prices may lead to increased production, supply source and market competition, and demand destruction and volatility. Supply competition from other sources of natural gas can adversely impact demand for transportation on our pipelines. New supply from the Rocky Mountain region transported by a competitor impacted demand for service on Northern Border Pipeline at certain times during 2005 and will continue to put pressure on us when market demand is light. In August 2005, Kinder Morgan Energy Partners, L.P. (Kinder Morgan) and Sempra Pipelines & Storage proposed to construct a natural gas pipeline that would transport natural gas from the Rocky Mountain region to the upper Midwestern and Eastern U.S. In February 2006, Kinder Morgan announced that the 1.8 Bcf/d, 1,323-mile Rockies Express Pipeline was fully subscribed. The proposed project's interim service to the Mid-Continent region, anticipated to begin in late 2008, may adversely impact the value of transportation service on our pipelines which currently serve the Midwestern U.S. markets. Production in the Wind River Basin, where we own an equity interest in a gathering system, however, may increase as a result of the greater pipeline access the project is expected to provide. Temperatures in the U.S. were above normal averages from December 2004 through November 2005, according to the NOAA National Climate Data Center. During the first half of 2005, the market responded by increasing natural gas storage injection activity, which resulted in natural gas in storage at levels greater than the five-year average. With ample natural gas already in storage and the U.S. experiencing higher than normal summer temperatures during the third quarter of 2005, demand for Canadian natural gas increased to meet demand for electricity. In addition, demand for natural gas from the Chicago market area increased as a result of decreased production in the Gulf Coast region due to infrastructure disruptions following Hurricanes Katrina and Rita. December 2005 began with unusually cold conditions across the U.S. that retreated in the last two weeks of the year and above normal temperatures resumed in January 2006. Natural gas storage is essential to balance natural gas supply with temperature-driven seasonal demand. As the market gains the ability to better align its demand with supply by utilizing natural gas storage, we anticipate demand for transportation services will become increasingly volatile. With new Canadian storage projects expected to go in service during 2006, we anticipate that increased storage may reduce demand for Northern Border Pipeline's transportation capacity during the spring and early summer months and increase demand during the winter months. YEAR IN REVIEW In 2005, income from continuing operations of $146.5 million exceeded 2004 income from continuing operations by 4% due to improved results from the gathering and processing segment and the benefit of non-recurring items which offset decreased demand for transportation capacity on Northern Border Pipeline. During the second quarter of 2005, increased storage injection activity of Canadian natural gas negatively impacted demand for Northern Border Pipeline's firm service transportation when several contracts expired. In order to maximize revenue, Northern Border Pipeline discounted transportation rates primarily on a short-term basis. As Western Canadian working gas in storage rose to high levels and summer temperatures were higher than normal, demand for Northern Border Pipeline's transportation capacity also increased. While we anticipate that demand for Northern Border Pipeline's transportation capacity in 2006 will be similar to 2005 demand based on our expectations of Canadian natural gas supply and demand for natural gas in the Midwestern U.S., the level of discounting in the future may vary from 2005 depending upon transient market conditions, which are difficult to predict. 35 In 2005, Northern Border Pipeline accounted for 47% of our consolidated operating revenue. The outcome of Northern Border Pipeline's rate case filed in November 2005 could have a significant impact on our financial results because the resulting tariff will specify the maximum rates the pipeline can charge its customers for natural gas transportation service. In December 2005, the FERC identified the issues raised in the proceeding and accepted the proposed rates but suspended their effectiveness until May 1, 2006. At that time, Northern Border Pipeline will collect the new rates, which will be subject to refund until final resolution of the rate case following hearings conducted by the FERC or by settlement. A change in Northern Border Pipeline's rates will not affect earnings until final resolution with the FERC staff and a majority of our customers is reached and subsequently approved by the FERC, which may not occur until 2007. We continue to seek internal growth opportunities to expand our business. We commenced construction on several interstate natural gas pipeline projects in 2005. In September, the FERC issued a certificate of public convenience and necessity for Northern Border Pipeline's Chicago III Expansion Project, which will increase the pipeline's transportation capacity from Harper, Iowa to the Chicago market area by 130 MMcf/d to 974 MMcf/d. The additional capacity is fully subscribed for five and one-half years to ten years. The Chicago III Expansion Project is expected to be in service in April 2006. In October, Midwestern Gas Transmission received a positive Environmental Assessment from the FERC for its Eastern Extension Project. The Eastern Extension Project will extend Midwestern Gas Transmission's transportation service 31 miles into Tennessee. The Eastern Extension Project's proposed in-service date of November 2006 will likely be delayed since the FERC's certificate of public convenience and necessity for the project is still pending. In November, Midwestern Gas Transmission completed its Southbound Expansion Project, which increased the pipeline's southbound capacity by 86 MDth/d. Our overall business strategy encompasses a focus on growth opportunities that will balance our supply source and market risk exposures. Since 2000, our business mix has evolved from primarily interstate pipeline transportation service operations to our present mix, which includes 23% natural gas gathering and processing operations based on EBITDA. Strong natural gas and natural gas liquids prices in 2005 resulted in improved consolidated results due to our natural gas gathering and processing segment. In August 2005, we acquired an additional 3.7% interest in Fort Union Gas Gathering to bring our total interest to 37%. During 2005, several events marked the end of our relationship with Enron. In May, our transition from CCE Holdings, through which Enron provided certain services to ONEOK was completed. In June, Northern Border Pipeline, Crestone Gathering and Bear Paw Energy sold their unsecured claims against Enron and Enron North America to a third party, which sale is reflected in our operating results. In addition, Enron was the grantor of the Enron Gas Pipeline Employee Benefit Trust (Trust), which when taken together with the Enron Corp. Medical Plan for Inactive Participants (Medical Plan) constituted a "voluntary employees' beneficiary association" or VEBA under the Internal Revenue Code. The Trust was established as a result of a regulatory requirement for the inclusion of certain costs for post-employment medical benefits in the rates established for the affected pipelines, including Northern Border Pipeline. In 2002, Enron began the 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, including Northern Plains, and requested the enrolled actuary to prepare an analysis and recommendation for the allocation of the Trust's assets and associated liabilities. In June 2005, Enron filed an amended motion in bankruptcy court seeking approval to terminate the Trust and to distribute its assets among certain identified companies. If Enron's relief is granted as requested, Northern Plains would assume retiree benefit liabilities, estimated as of 36 November 17, 2004, of approximately $2.3 million and Trust assets of approximately $1.7 million. Northern Natural Gas Company, a participating employer of the Trust through June 30, 2002, along with other parties filed a motion alleging that the allocation of assets and liabilities of the Trust should be decided in a pending lawsuit filed in the U.S. District Court for the District of Nebraska and not in bankruptcy court. The lawsuit filed in Nebraska was dismissed. On February 15, 2006, we announced a series of proposed transactions expected to increase unitholder value and facilitate additional growth opportunities, including the sale of a 20% partnership interest in Northern Border Pipeline to TC PipeLines, Northern Plain's acquisition of TransCanada's 0.35% general partner interest and our purchase of ONEOK's entire gathering and processing, natural gas liquids, and pipelines and storage segments. Upon completion of these transactions, ONEOK will own approximately 37.0 million of our limited partner units, which, when combined with the general partnership interest acquired from TransCanada, will increase their total interest in us to 45.7%. We expect the acquisition of ONEOK's assets and the sale of a portion of our interest in Northern Border Pipeline will be immediately accretive to our distributable cash flow. In addition, we anticipate increasing our cash distribution to unitholders by the end 2006 as a result of greater cash flow associated with the additional assets. The acquisition will result in a more diversified master limited partnership and an improved ability to fund future growth. Additional information about the proposed transactions is included under "Liquidity and Capital Resources," of this section, Item 1, "Business-General Development of Business," Item 1A, "Risk Factors," Item 3, "Legal Proceedings," Item 5, "Market for Registrant's Common Equity Related Stockholder Matters and Issuer Purchases of Equity Securities," and Item 13, "Certain Relationships and Related Transactions." We believe we are well-positioned for growth in 2006. The natural gas industry continues to be a critical component of the energy infrastructure in the U.S. We expect strong natural gas prices and continually improving technology will encourage producers to replace depleted reserves with new supply sources providing the natural gas transportation and gathering and processing sectors with growth opportunities. Our commitment to fee-based businesses and disciplined hedging policies will continue to be the foundation upon which we will strive to grow our businesses and provide consistent distributions to unitholders. BLACK MESA On December 31, 2005, Black Mesa's transportation contract with the coal supplier of the Mohave Generating Station expired and our coal slurry pipeline operations were shut down as expected. We expect the impact associated with the shutdown will be a reduction of net income of approximately $7 million in 2006, which includes approximately $4 million to $6 million of operations and maintenance expense we expect to incur related to stand by costs. Under a consent decree, the Mohave Generating Station must complete significant pollution control investments to operate in the future. In addition, issues surrounding the use of an alternative water source for the coal slurry pipeline must be resolved. The original water source was an aquifer in the Navajo Nation and Hopi Tribe joint use area. Black Mesa is working to resolve coal slurry transportation issues and interested parties continue to negotiate water and coal supply issues so that operations may resume in the future. If these issued are resolved and the project receives a favorable Environmental Impact Statement, portions of the pipeline would be modified or reconstructed to repair normal wear related to use. If the pipeline is reconstructed, we anticipate Black Mesa's capital expenditures for the project will be approximately $175 million to $200 million beginning in late 2008 and 2009, supported by revenue from a new transportation contract, for an anticipated in-service date during 2010. If the Mohave Generating Station is permanently closed, we expect to incur pipeline removal and remediation costs of approximately $1 million to $2 million, net of salvage, and a non-cash impairment charge of approximately $10 million related to the remaining undepreciated cost of the pipeline assets and goodwill. We may be required to take an impairment charge in accordance with GAAP prior to final resolution of the issues concerning Mohave Generating Station even though the project may ultimately proceed. Each quarter, we will take into consideration our assumptions and estimates about economic conditions and the probability of Black Mesa's future profitability. If an event or change in circumstance occurs that potentially impacts our assumptions and estimates, we will be required to test the assets for impairment. If our testing indicates that the carrying amount of Black Mesa's assets exceed their fair value, we would recognize an impairment charge. Additional information about our critical accounting policies and estimates related to asset impairment is included under the following sections, "Critical Accounting Estimates," and in Note 2 of the Consolidated Financial Statements. CRITICAL ACCOUNTING ESTIMATES The preparation of financial statements in accordance with U.S. GAAP requires us to make estimates and assumptions, with respect to values or conditions which cannot be known with certainty, that affect the reported amount of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the financial 37 statements. Such estimates and assumptions also affect the reported amounts of revenue and expenses during the reporting period. Although we believe these estimates are reasonable, actual results could differ from our estimates. The following summarizes our critical accounting estimates, which should be read in conjunction with Note 2 of the Consolidated Financial Statements. IMPAIRMENT OF GOODWILL Goodwill represents the excess of the purchase price over the fair value of identifiable net assets acquired. We review goodwill for possible impairment annually and when events or changes in circumstances indicate the carrying value of the goodwill might exceed its current fair value. An assessment is made for each of our business segments by comparing the fair value of the business, as determined in accordance with SFAS No. 142, "Goodwill and Other Intangible Assets," to the book value, including goodwill, of each reporting unit. In addition, we obtained a business valuation from an independent valuation firm of our coal slurry pipeline segment in 2005. If the fair value of the business is less than the book value including the goodwill, goodwill is deemed to be impaired and we are required to perform a second test to measure the amount of the impairment. In the second test, we calculate the fair value of the goodwill by deducting the fair value of all tangible and intangible net assets of the operations from the fair value determined in step one of the assessment. If the carrying value of the goodwill exceeds this calculated fair value of the goodwill, we will record a goodwill impairment charge. We determine fair value using the discounted cash flow method for each of our business segments. This type of analysis requires us to make assumptions and estimates regarding industry economic factors and the profitability of future business strategies. Our assumptions and estimates are based on our current business strategy taking into consideration present industry and economic conditions, as well as our analysis of future expectations. Our evaluation of our coal slurry pipeline segment incorporated an assessment of the probabilities of permanent closure of the Mohave Generating Station. See "Executive Summary" of this section for further discussion of Black Mesa's shutdown. In the fourth quarter of 2005, we completed our annual impairment testing of goodwill for each of our business segments using the methodology described above. We determined there is no goodwill impairment. The business valuation of the coal slurry pipeline segment we received from the independent valuation firm concluded there was no impairment to goodwill. If actual results differ from our assumptions and estimates, we may be exposed to a goodwill impairment charge. At December 31, 2005, we had $339 million of goodwill recorded on our consolidated balance sheet. At December 31, 2005, goodwill per business segment was $71 million, $260 million and $8 million for our interstate natural gas pipeline, natural gas gathering and processing and coal slurry pipeline segments, respectively. IMPAIRMENT OF LONG-LIVED ASSETS Long-lived assets, such as property and equipment, are reviewed for impairment when events or changes in circumstances indicate that their carrying amount may exceed their fair value. We assess our long-lived assets for impairment based on SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets." Fair values are based on the sum of the undiscounted future cash flow expected to result from the use and eventual disposition of the assets. If the undiscounted future cash flow is less than the carrying value of the asset, we calculate an impairment loss. The impairment loss calculation compares the carrying value of the asset to the asset's estimated fair value, which is based on future discounted cash flow. If we recognize an impairment loss, the adjusted carrying amount of the asset will be its new cost basis. For a depreciable long-lived asset, the new cost basis will be depreciated over the remaining useful life of that asset. Restoration of a previously recognized impairment loss is prohibited. We will prepare a fair value analysis when events or changes in circumstances indicate that the carrying amount of our long-lived assets may exceed the fair value. Management reviews our assets at the end of each reporting period to determine if any events that would trigger asset impairment have occurred. This type of analysis requires us to make assumptions and estimates regarding industry economic factors and the profitability of future business strategies. Our assumptions and estimates are based on our current business strategy, taking into consideration 38 present industry and economic conditions as well as our analysis of future expectations. Using the impairment review methodology described herein, we determined there was no asset impairment in 2005. If actual results differ from our assumptions and judgments used in estimating future cash flow and asset fair values, we may be exposed to impairment losses that could be material to our results of operations. REGULATORY ASSETS The interstate natural gas pipeline segment's accounting policies conform to SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation." We consider several factors to evaluate our continued application of the provisions of SFAS No. 71 such as potential deregulation of our pipelines; anticipated changes from cost-based ratemaking to another form of regulation; increasing competition that limits our ability to recover costs; and regulatory actions that limit rate relief to a level insufficient to recover costs. Certain assets that result from the ratemaking process are reflected on the balance sheet as regulatory assets. If we determine future recovery of these assets is no longer probable as a result of discontinuing application of SFAS No. 71 or other regulatory actions, we would be required to write off the regulatory asset at that time. As of December 31, 2005, the interstate natural gas pipeline segment reflected regulatory assets of $14.2 million that we expect to recover from our customers over varying time periods up to 44 years. CONTINGENCIES Our accounting for contingencies covers a variety of business activities, including contingencies for legal and environmental liabilities. We accrue these contingencies when our assessments indicate that it is probable that a liability has been incurred or an asset will not be recovered and an amount can be reasonably estimated in accordance with SFAS No. 5, "Accounting for Contingencies." We base our estimates on currently available facts and our estimates of the ultimate outcome or resolution. Actual results may differ from our estimates resulting in an impact, positive or negative, on earnings. RESULTS OF OPERATIONS SELECTED FINANCIAL RESULTS BY SEGMENT The following table summarizes financial results by segment for the years ended December 31, 2005, 2004 and 2003:

YEARS ENDED DECEMBER 31, ------------------------------------------------------------- % % % 2005 SEGMENT 2004 SEGMENT 2003 SEGMENT -------- ------- -------- ------- --------- ------- (In thousands) Operating revenue: Interstate natural gas pipeline $378,701 55.8% $383,625 65.0% $ 375,256 68.1% Natural gas gathering and processing 275,287 40.6 184,738 31.3 154,284 28.0 Coal slurry pipeline 24,572 3.6 22,020 3.7 21,408 3.9 -------- ----- -------- ----- --------- ----- Total operating revenue 678,560 100.0 590,383 100.0 550,948 100.0 -------- ----- -------- ----- --------- ----- Operating income (loss): Interstate natural gas pipeline 214,168 81.1 231,027 87.9 212,841 91.0 Natural gas gathering and processing 44,714 16.9 28,278 10.8 (203,067) 6.8 Coal slurry pipeline 5,186 2.0 3,446 1.3 5,144 2.2 Other (7,300) -- (9,366) -- (7,601) -- -------- ----- -------- ----- --------- ----- Total operating income (loss) 256,768 100.0 253,385 100.0 7,317 100.0 -------- ----- -------- ----- --------- ----- Income (loss) from continuing operations: Interstate natural gas pipeline 123,604 63.4 134,726 73.9 119,620 74.9 Natural gas gathering and processing 67,552 34.6 44,488 24.4 (183,016) 22.6 Coal slurry pipeline 3,902 2.0 3,088 1.7 4,092 2.6 Other (48,551) -- (41,381) -- (37,845) -- -------- ----- -------- ----- --------- ----- Total income (loss) from continuing operations 146,507 100.0% 140,921 100.0% (97,149) 100.0% -------- ----- -------- ----- --------- ----- Discontinued operations, net of tax 506 3,799 9,338 Cumulative effect of change in accounting principle, net of tax -- -- (643) -------- -------- --------- Net income (loss) $147,013 $144,720 $ (88,454) ======== ======== =========

39 COMPARISON OF THE YEAR ENDED DECEMBER 31, 2005, WITH YEAR ENDED DECEMBER 31, 2004 CONSOLIDATED RESULTS Operating revenue increased $88.2 million, or 15%, in 2005 compared with 2004 due to strong natural gas gathering and processing segment results which more than offset the interstate natural gas pipeline segment's modest revenue decline. Operating income was relatively flat as a result of the significantly greater contribution by the natural gas gathering and processing segment offset by decreased operating income from the interstate natural gas pipeline segment. Both the interstate natural gas pipeline and the natural gas gathering and processing segments benefited from the sale of their bankruptcy claims related to Enron and Enron North America in 2005. Income from continuing operations increased $5.6 million, or 4%, despite higher interest expense of $10.0 million as a result of interest rates. Equity earnings of unconsolidated affiliates increased $6.7 million, or 37%, due to the settlement of our preferred A shares with Bighorn Gas Gathering and improved results from our gathering and processing joint ventures interests. Discontinued operations included an after-tax gain of $3.6 million related to the sale of Border Midstream's undivided interest in the Gregg Lake/Obed Pipeline in 2004. INTERSTATE NATURAL GAS PIPELINE SEGMENT Income from continuing operations decreased $11.1 million, or 8%, in 2005 compared with 2004 primarily as a result of the following: - unsold transportation capacity on Northern Border Pipeline; - discounted transportation rates on Northern Border Pipeline; and - increased operations and maintenance expense; partially offset by - the sale of Northern Border Pipeline's bankruptcy claims against Enron and Enron North America. Operating revenue decreased $4.9 million in 2005 compared with 2004 due to Northern Border Pipeline's decreased demand for transportation capacity. During the second quarter of 2005, contracts for 800 MMcf/d of capacity on the Port of Morgan, Montana to Ventura, Iowa portion of the pipeline expired. Some of this firm transportation capacity was not sold. To maximize revenue, Northern Border Pipeline discounted transportation rates primarily on a short-term basis and sold most of its remaining capacity in 2005. Revenue from firm service transportation decreased $16.2 million as a result of uncontracted and discounted capacity. Partially offsetting this decrease, Northern Border Pipeline recognized revenue of $9.4 million from the sale of its bankruptcy claims for transportation contracts and associated guarantees against Enron and Enron North America. In 2004, Northern Border Pipeline recognized revenue of $0.9 million due to an additional day of transportation service because of the leap year. Operations and maintenance expense increased $9.3 million, or 18%, in 2005 compared with 2004 primarily due to the settlement or anticipated settlement of several outstanding issues related to Enron which reduced expenses in 2004. The resolution of our potential obligation for costs related to the termination of Enron's cash balance plan, the settlement for certain administrative expenses for 2002 and 2003, and an adjustment to our allowance for doubtful accounts related to bankruptcy claims held by Northern Border Pipeline reduced expenses by $7.2 million in 2004. In 2005, operational gas volume imbalances on Viking Gas Transmission resulted in a $2.2 million net increase of operations and maintenance expense. Interest expense increased $1.1 million in 2005 compared with 2004 due to higher average interest rates partially offset by decreased average debt outstanding. Equity earnings of unconsolidated affiliates represent earnings from our one-third interest in Guardian Pipeline. Minority interests in net income represent the 30% minority interest in Northern Border Pipeline. NATURAL GAS GATHERING AND PROCESSING SEGMENT Income from continuing operations increased $23.1 million, or 52%, in 2005 compared with 2004 primarily as a 40 result of the following: - increased gathering and processing volumes in the Williston Basin; - higher commodity prices realized on equity natural gas and natural gas liquids derived from percentage-of-proceeds contracts; - the sale of Bear Paw Energy and Crestone Gathering's bankruptcy claims against Enron and Enron North America; - the settlement of preferred A shares in Bighorn Gas Gathering; and - increased equity earnings from our joint venture interests. Operating revenue increased $90.6 million, or nearly 50%, in 2005 compared with 2004 due to our Williston Basin results. Williston Basin operating revenue is derived primarily from the sale of natural gas and natural gas liquids gathered and processed under percentage-of-proceeds contracts. Williston Basin gathering and processing volumes increased 9 MMcf/d, or 16%, as a result of accelerated production and drilling activity across the entire basin driven by strong natural gas and natural gas liquids prices. The Charlie Creek Expansion Project and Beaver Creek Expansion Project also helped to increase volume and improve utilization at our Grasslands facility. Optimization projects at the Grasslands and Baker facilities increased natural gas liquids recoveries. The increased Williston Basin volumes more than offset the 9% decreased Powder River Basin volumes related to production declines and the diversion of a producer's volume to its own gathering lines during the year. Better prices were also realized on our sales of natural gas and natural gas liquids retained through percentage-of-proceeds contracts, which also contributed to the segment's increased operating revenue. The weighted average price of natural gas realized, net of the effects of hedging, was $6.87 per MMBtu in 2005 compared with $4.76 per MMBtu in 2004. The weighted average price of natural gas liquids realized, net of the effects of hedging, was $0.92 per gallon in 2005 compared with $0.53 per gallon in 2004. Commodity sales more than offset the impact of modestly lower gathering rates in the Powder River Basin. Product purchases increased $64.1 million in 2005 compared with 2004. Product purchases as a percent of operating revenue increased to 61% of operating revenue in 2005 compared with 56% of operating revenue in 2004 due to declining percentage-of-proceeds contract margins. Product purchases reflect the amounts we paid to producers for raw natural gas. Operations and maintenance expense increased $9.0 million, or 25%, in 2005 compared with 2004. Operations and maintenance expense included additional expenses related to expansions, pipeline repairs and employee costs of $3.5 million offset by the recovery of Bear Paw Energy and Crestone Gathering's allowance for doubtful accounts related to Enron and Enron North America of $1.2 million in 2005. In 2004, resolution of our potential obligation for costs related to the termination of Enron's cash balance plan and an adjustment to our allowance for doubtful accounts related to bankruptcy claims reduced expenses by $3.7 million. We also sold two non-strategic gathering systems and compressor equipment in the Powder River Basin and recognized a $3.4 million gain in operations and maintenance expense in 2004. Equity earnings of unconsolidated affiliates increased $6.1 million, or 37%, in 2005 compared with 2004. Increased volumes and transportation rates are reflected in our equity earnings from our investments in Bighorn Gas Gathering, Fort Union Gas Gathering and Lost Creek Gathering. Crestone Energy's acquisition of an additional 3.7% interest in Fort Union Gas Gathering also contributed to our equity earnings growth. We also recognized $5.4 million of equity earnings related to our preferred A shares held in Bighorn Gas Gathering that were due to us for 2004 and 2005 resulting from a settlement agreement with our partner in Bighorn Gas Gathering. Provisions of the joint venture agreement provided for cash flow incentives based on well connections to the gathering system. The settlement agreement cancelled and effectively redeemed Bighorn Gas Gathering's outstanding preferred A shares held by us and preferred B shares held by our partner in Bighorn Gas Gathering and eliminated future incentives. In 2004, we recorded $2.7 million of equity earnings related to our preferred A shares that were due to us for 2003. COAL SLURRY PIPELINE SEGMENT On December 31, 2005, our coal slurry pipeline operations were shut down. We incurred one-time termination costs of $0.7 million in the fourth quarter which were reflected in the segment's operations and maintenance expense. 41 COMPARISON OF THE YEAR ENDED DECEMBER 31, 2004, WITH YEAR ENDED DECEMBER 31, 2003 CONSOLIDATED RESULTS Operating revenue increased $39.4 million, or 7%, in 2004 compared with 2003 as a result of higher interstate natural gas pipeline segment revenue due to expired regulatory conditions and improved natural gas gathering and processing segment results. In 2003, we recorded an impairment charge of $219.1 million related to our natural gas gathering and processing segment's tangible assets and goodwill. Excluding the impairment charge, operating income increased $27.0 million, or 12%, in 2004 compared with 2003 due to several Enron-related settlements and the sale of non-strategic gathering and processing assets which reduced expenses in 2004. Income from continuing operations, excluding the 2003 impairment charge, increased $19.0 million, or 16%, which included lower interest expense of $2.0 million as a result of decreased average debt outstanding. Discontinued operations included an after-tax gain of $4.9 million related to the sale of the Gladys and Mazeppa processing plants located in Alberta, Canada in 2003. INTERSTATE NATURAL GAS PIPELINE SEGMENT Income from continuing operations increased $15.1 million, or 13%, in 2004 compared with 2003 primarily as a result of the following: - increased revenue; - decreased Northern Border Pipeline operations and maintenance expense; and - decreased Northern Border Pipeline interest expense. Operating revenue increased $8.4 million in 2004 compared with 2003 due to improved results from all three interstate natural gas pipelines. Northern Border Pipeline's operating revenue increased $4.9 million primarily as a result of expired regulatory conditions under its previous rate case settlement, which enabled the pipeline to generate and retain $2.0 million from the sale of short-term firm capacity and $2.0 million from new service revenue. Northern Border Pipeline also recognized revenue of $0.9 million due to an additional day of transportation service because of the leap year. In 2004, Viking Gas Transmission's operating revenue was $2.1 million higher primarily because 2003 results did not include the pipeline's revenue prior to the pipeline's January 17, 2003 acquisition date. Midwestern Gas Transmission's revenue included operational gas sales which increased its revenue $1.4 million in 2004. Operations and maintenance expense decreased $10.9 million in 2004 compared with 2003 primarily due to the settlement or anticipated settlement of several outstanding issues related to Enron which reduced expenses in 2004, including the resolution of costs related to the termination of Enron's cash balance plan of $4.2 million, the settlement for certain administrative expenses for 2002 and 2003 of $1.9 million and an adjustment to our allowance for doubtful accounts related to bankruptcy claims held by Northern Border Pipeline of $1.1 million. Interest expense decreased $3.7 million in 2004 compared with 2003 due to Northern Border Pipeline's lower average debt outstanding as a result of equity contributions from its general partners that were used to repay outstanding indebtedness. NATURAL GAS GATHERING AND PROCESSING SEGMENT Income from continuing operations increased $8.4 million, or 23%, in 2004 compared with 2003 excluding the effect of impairment charges that were recorded in 2003, primarily as a result of the following: - the sale of non-strategic assets in the Powder River Basin; and - estimated recoveries of bankruptcy claims against Enron and Enron North America. In 2003, we accelerated our annual impairment testing due to lower throughput volumes for the segment. We determined that impairment existed related to our tangible assets and goodwill. We recorded an impairment charge of $219.1 million as a result, which consisted of $76.0 million related to tangible assets in the Powder River Basin and $143.1 million for goodwill related to the segment. Operating revenue increased $30.5 million, nearly 20%, in 2004 compared with 2003 due to our Williston Basin 42 results. Gathering and processing volumes for our Williston Basin operations increased 4 MMcf/d, or 7%, as a result of increased drilling activity due to strong commodity prices, which partially offset lower gathering volumes in the Powder River Basin. We also benefited from higher prices on our natural gas and natural gas liquids. The weighted average price of natural gas realized, net of the effects of hedging, was $4.76 per MMBtu in 2004 compared with $3.64 per MMBtu in 2003. The weighted average price of natural gas liquids realized, net of the effects of hedging, was $0.53 per gallon in 2004 compared with $0.43 per gallon in 2003. Product purchases increased $22.4 million, or 28%, in 2004 compared with 2003. Product purchases as a percent of operating revenue increased to 56% of operating revenue in 2004 compared with 52% of operating revenue in 2003. Product purchases reflect the amounts we paid to producers for raw natural gas. Operations and maintenance expense decreased $6.9 million, or 16%, in 2004 compared with 2003. In 2004, the average daily volume gathered in the Powder River Basin was down 3% compared with 2003 due to well production declining more than anticipated despite modest growth in drilling activity. We sold two non-strategic gathering systems and compressor equipment in the Powder River Basin, resulting in a $3.3 million gain which reduced operations and maintenance expense in 2004. In addition, we renegotiated certain gathering contracts to mitigate volumetric risk and reduce operations and maintenance expense. Operations and maintenance expense was also reduced due to the settlement or anticipated settlement of several outstanding issues related to Enron, including a reduction to our allowance for doubtful accounts of $2.3 million and the resolution of costs related to the termination of Enron's cash balance plan of $1.5 million. LIQUIDITY AND CAPITAL RESOURCES OVERVIEW Our principal sources of liquidity include cash generated from operating activities and bank credit facilities. We fund our operating expenses, debt service and cash distributions to limited and general partners primarily with operating cash flow. Capital resources for acquisitions and maintenance and growth expenditures are funded by a variety of sources, including cash generated from operating activities, borrowings under bank credit facilities, issuance of senior unsecured notes or sale of additional limited partner interests. Our ability to access capital markets for debt and equity financing under reasonable terms depends on our financial condition, credit ratings and market conditions. We believe that our ability to obtain financing at reasonable rates and our history of consistent cash flow from operating activities provide a solid foundation to meet our future liquidity and capital resource requirements. SHORT-TERM LIQUIDITY We use cash from operating activities and bank credit facilities as our primary sources of short-term liquidity. In May 2005, we entered into a $500 million five-year revolving credit agreement with certain financial institutions. Under this agreement, we borrowed $186 million to pay the outstanding balance of our existing $275 million revolving credit agreement and terminated that agreement. At our option, the interest rate on the outstanding borrowings may be the lender's base rate or the London Interbank Offered Rate (LIBOR) plus a spread that is based on our long-term unsecured debt ratings. We are required to comply with certain financial, operational and legal covenants, including the maintenance of an EBITDA (net income plus minority interests in net income, interest expense, income taxes and depreciation and amortization) to interest expense ratio of greater than 3 to 1 and a debt to adjusted EBITDA (EBITDA adjusted for pro forma operating results of acquisitions made during the year) ratio of no more than 4.75 to 1. If we consummate one or more acquisitions that exceed $25 million in total purchase price, the allowable ratio of debt to adjusted EBITDA is increased to 5.25 to 1 for two calendar quarters following the acquisition. If we breach any of these covenants, amounts outstanding may become due and payable immediately. Also in May 2005, Northern Border Pipeline entered into a $175 million five-year revolving credit agreement with certain financial institutions. Under this agreement, Northern Border Pipeline borrowed $29 million to pay the outstanding balance on its existing $175 million revolving credit agreement and terminated that agreement. Similar to our revolving credit agreement, Northern Border Pipeline may select the lender's base rate or the LIBOR plus a 43 spread that is based on Northern Border Pipeline's long-term unsecured debt ratings as the interest rate on the loan. Northern Border Pipeline is required to comply with certain financial, operational and legal covenants, including the maintenance of an EBITDA to interest expense ratio of greater than 3 to 1 and a debt to adjusted EBITDA ratio of no more than 4.5 to 1. If Northern Border Pipeline consummates one or more acquisitions that exceed $25 million in total purchase price, the allowable ratio of debt to adjusted EBITDA is increased to 5 to 1 for two calendar quarters following the acquisition. If Northern Border Pipeline breaches any of these covenants, amounts outstanding may become due and payable immediately. The fair value of our variable rate debt is approximately the carrying value since the interest rates are periodically adjusted to reflect current market conditions. At December 31, 2005, our outstanding borrowings under our credit agreement were $204 million and we were in compliance with the covenants of our agreement. The average interest rate on our debt at December 31, 2005, was 5.18%. At December 31, 2005, Northern Border Pipeline's outstanding borrowings under its credit agreement were $27 million and they were in compliance with the covenants of their agreement. The average interest rate on Northern Border Pipeline's debt at December 31, 2005, was 5.11%. LONG-TERM FINANCING On February 15, 2006, we announced a series of transactions that will involve long-term financing. Information about the proposed transactions is included under "Executive Summary" of this section. DEBT SECURITIES We periodically issue long-term debt securities to meet our capital resource requirements. All of our outstanding debt securities are senior unsecured notes with similar terms except for interest rates, maturity dates and prepayment premiums. As of December 31, 2005, the total liability on our outstanding senior notes was $1,104 million. Our senior note issuances of $250 million due in 2010 and $225 million due in 2011 are borrowed at fixed interest rates of 8.875% and 7.10%, respectively. The indentures of the notes do not limit the amount of unsecured debt we may incur, but they do contain material financial covenants, including restrictions on incurrence, assumption or guarantee of secured indebtedness. The indentures also contain provisions that require us to offer to repurchase the notes at par value if either Standard & Poor's Rating Services or Moody's Investor Services rate the notes below investment grade and the investment grade rating is not reinstated for a period of 40 days. At December 31, 2005, the aggregate fair value of the notes was approximately $499 million. In 2005, the interest expense related to our outstanding senior notes was $38.2 million. Northern Border Pipeline's senior notes issuances of $150 million due in 2007, $200 million due in 2009 and $250 million due in 2021 are borrowed at fixed interest rates of 6.25%, 7.75% and 7.50%, respectively. The indentures of the notes do not limit the amount of unsecured debt we may incur but contain material financial covenants, including the restriction of secured indebtedness. At December 31, 2005, the aggregate fair value of the notes was approximately $637 million. In 2005, interest expense related to Northern Border Pipeline's senior notes was $43.6 million. In 2004, Northern Border Pipeline redeemed $75 million of the $225 million principal amount outstanding of its senior notes due in 2007. Viking Gas Transmission has four series of senior note issuances outstanding. Interest payments for the senior notes due between 2011 and 2014 are paid quarterly and the principal payment is due at maturity. We pay interest and principal payments monthly for the senior notes due in 2008. Under the indentures of the notes, we are the guarantor as security for payment. At December 31, 2005, the aggregate fair value of the notes was approximately $32 million. In 2005, the interest expense related to Viking Gas Transmission's senior notes was $2.2 million. EQUITY ISSUANCES In May and June 2003, we sold 2,587,500 common units. According to our partnership agreement, the general partners are required to make capital contributions in conjunction with the issuance of additional common units to maintain a 2% general partner interest. The net proceeds from the sale of common units and the general partners' capital contributions of $102.2 million were used primarily to repay outstanding debt. 44 CASH FLOW FROM OPERATING, INVESTING AND FINANCING ACTIVITIES OPERATING ACTIVITIES Cash provided by operating activities increased $22.7 million, or 9%, in 2005 compared with 2004 primarily as a result of the following: - increased earnings from the natural gas gathering and processing segment; - the sale of bankruptcy claims against Enron and Enron North America; - receipt of cash flow incentives due to us for 2005 through our ownership of preferred A shares in Bighorn Gas Gathering; and - decreased payment in 2005 compared with 2004 related to Northern Border Pipeline's settlement with respect to right-of-way lease and taxation issues with the Fort Peck Tribes. Northern Border Pipeline paid the Fort Peck Tribes $7.4 million as part of the settlement in 2004 and an option payment of approximately $1.5 million in 2005. The increased inflow of cash in 2005 was partially offset by the following: - decreased earnings from the interstate natural gas pipeline segment as a result of unsold and discounted capacity on Northern Border Pipeline; and - increased interest expense. Cash provided by operating activities increased $20.0 million, or 9%, in 2004 compared with 2003 due to higher operating revenue and lower interest expense. Northern Border Pipeline's initial payment related to the settlement with respect to right-of-way lease and taxation issues with the Fort Peck Tribes was partially offset by the release of restricted funds previously required on deposit for Viking Gas Transmission's debt service. INVESTING ACTIVITIES Cash used for investing activities was $68.4 million in 2005 compared with $20.9 million in 2004 primarily due to increased interstate natural gas pipeline segment capital expenditures in 2005 and the sale of gathering and processing assets in 2004. We fund our investing activities primarily with operating cash and borrowings under our credit facilities. In 2005 and 2004, maintenance and growth capital expenditures, and investments in unconsolidated affiliates for the interstate natural gas pipeline and natural gas gathering and processing segments were as follows:

INTERSTATE NATURAL GAS PIPELINE SEGMENT ($ MILLIONS) 2005 2004 ---------------------------------------------------- ----- ----- Maintenance Capital Expenditures $23.4 $15.9 Growth Capital Expenditures 16.3 0.3 ----- ----- Total $39.7 $16.2 ===== =====

NATURAL GAS GATHERING AND PROCESSING SEGMENT ($ MILLIONS) 2005 2004 --------------------------------------------------------- ----- ----- Maintenance Capital Expenditures $ 2.3 $ 3.4 Growth Capital Expenditures 22.8 22.1 ----- ----- Total $25.1 $25.5 ===== =====

Consolidated maintenance capital expenditures increased $8.4 million in 2005 compared with 2004 primarily due to pipeline replacements and compressor station overhauls by Northern Border Pipeline. Growth capital expenditures increased $16.7 million in 2005 compared with 2004 primarily due to the following interstate natural gas pipeline segment projects:

2005 INTERSTATE NATURAL EXPENDITURES GAS PIPELINE SYSTEM EXPANSION PROJECT ($ MILLIONS) ------------------- --------------------- ------------ Northern Border Pipeline Chicago III Expansion $10.4 Midwestern Gas Transmission Southbound Expansion $ 2.4 Midwestern Gas Transmission Eastern Extension $ 2.9

Growth capital expenditures for the natural gas gathering and processing segment included investments in unconsolidated affiliates of $8.5 million in 2005. Crestone Energy increased its investment in Fort Union Gas 45 Gathering and acquired an additional 3.7% interest for $5.1 million. Contributions to Bighorn Gas Gathering were $3.4 million. In 2004, we sold our undivided minority interest in the Gregg Lake/Obed Pipeline for $14.0 million and two gathering systems in the Powder River Basin for $8.7 million. In 2003, we acquired Viking Gas Transmission for $123.2 million and sold the Gladys and Mazeppa processing plants for $40.3 million. Capital contributions of $3.5 million in 2003 primarily represented amounts made to Guardian Pipeline to fund additional expenditures related to the construction of the pipeline that was completed in December 2002. FINANCING ACTIVITIES Cash provided by financing activities was $189.8 million in 2005 compared with $225.7 million in 2004. In 2005, borrowings under our and Northern Border Pipeline's revolving credit agreements were primarily used to repay amounts borrowed under our and Northern Border Pipeline's previously existing credit agreements. Total borrowings in 2005 were $165.0 million and debt repayments were $130.2 million. We also paid $2.8 million to terminate forward-starting interest rate swaps and distributions of $159.6 million to our general partners and unitholders in 2005. In 2004, we borrowed $152.0 million under our credit agreement. Northern Border Pipeline borrowed $107.0 million under its credit agreement and received an equity contribution of $61.5 million from its minority interest holder. Northern Border Pipeline also terminated interest rate swap agreements with a total notional amount of $225 million and received $7.6 million. We and Northern Border Pipeline used the cash to repay $327.5 million of debt, which included the $75 million redemption of Northern Border Pipeline's senior notes due in 2007, and the related $4.8 million premium. In 2004, the Northern Border Management Committee approved a change to its cash distribution policy to equal 100% of its distributable cash flow based on earnings before interest, taxes, depreciation and amortization less interest expense and maintenance capital expenditures which increased distributions to its minority interest holder by $15.5 million compared with 2003. In 2003, we borrowed $200.0 million under our credit agreement and Northern Border Pipeline borrowed $142.0 million under its credit agreement. We issued 2.6 million additional common units which raised $102.2 million. We also terminated interest rate swap agreements with a total notional amount of $75 million and received $12.3 million. We used the cash to fund the $123.2 million Viking Gas Transmission acquisition and repay $361.1 million of debt. CAPITAL EXPENDITURES We will continue to make capital expenditures for acquisitions, new development projects, and maintenance and growth activities. We intend to finance our capital expenditures, either separately or in combination, with cash generated from operating activities, borrowings under our bank credit facilities, issuance of senior notes or the sale of additional limited partner interests. In 2006, we expect to invest in our currently existing businesses approximately $94 million for capital expenditures and investments in unconsolidated affiliates by segment as follows:

2006 PROJECTED SEGMENT ($ MILLIONS) MAINTENANCE GROWTH EXPENDITURES -------------------- ----------- ------ ------------- Interstate Natural Gas Pipeline $21 $38 $59 Natural Gas Gathering and Processing 4 28 32 Other 3 -- 3

We expect to invest approximately $50 million in 2006 for the following significant growth projects:

2006 ESTIMATED EXPENDITURES SUBSIDIARY EXPANSION PROJECT ($ MILLIONS) ---------- ----------------- ------------- Midwestern Gas Transmission Eastern Extension $25 Bear Paw Energy Williston Basin Expansions 15 Northern Border Pipeline Chicago III Expansion 10

46 PROPOSED TRANSACTIONS On February 15, 2006, we announced a series of proposed transactions, including the sale of a 20% partnership interest in Northern Border Pipeline to TC PipeLines, Northern Plain's acquisition of TransCanada's 0.35% general partner interest and our purchase of ONEOK's entire gathering and processing, natural gas liquids, and pipelines and storage segments. We expect to initially fund the $1.35 billion cash portion of the ONEOK asset acquisition with proceeds from the sale of a 20% interest in Northern Border Pipeline of $300 million and bridge financing. The bridge financing is expected to consist of borrowings under a 364-day bank credit facility, which is under negotiation with certain banks. We expect to repay these borrowings with proceeds from the issuance of long-term debt securities in 2006. The remainder of the ONEOK asset acquisition will be funded with the issuance of 36.5 million Class B units. The newly created units will carry the same distribution rights as our outstanding common units but will be subordinated related to cash distributions to the common units and will have limited voting rights. The Class B units' cash distribution will be prorated from the date of issuance. We will hold a special election for holders of common units as soon as practical, but within 12 months of issuing the Class B units, to approve the conversion of the Class B units into common units and certain amendments to our partnership agreement. If the common unitholders do not approve the conversion and amendments, the Class B unit distribution rights will increase to 115% of the distributions paid on the common units. Additional information about the proposed transactions is included under "Executive Summary" of this section. COMMITMENTS CONTRACTUAL OBLIGATIONS Our contractual obligations related to debt, capital and operating leases and other long-term obligations as of December 31, 2005, included the following:

PAYMENTS DUE BY PERIOD -------------------------------------------------------------- LESS THAN 1 MORE THAN 5 TOTAL YEAR 1-3 YEARS 4-5 YEARS YEARS ---------- ----------- --------- --------- ----------- (In thousands) Northern Border Pipeline: 6.25% senior notes due 2007 $ 150,000 $ -- $150,000 $ -- $ -- 7.75% senior notes due 2009 200,000 -- -- 200,000 -- 7.50% senior notes due 2021 250,000 -- -- -- 250,000 $175 million credit agreement due 2010, average 5.11% 27,000 -- -- 27,000 -- Viking Gas Transmission: Series A, B, C and D senior notes due 2008 to 2014, average 7.48% 28,987 2,133 3,912 -- 22,942 Northern Border Partners: 8.875% senior notes due 2010 250,000 -- -- 250,000 -- 7.10% senior notes due 2011 225,000 -- -- -- 225,000 $500 million credit agreement due 2010, average 5.18% 204,000 -- -- 204,000 -- Interest payments on debt 563,768 84,647 153,247 116,713 209,161 Capital leases 61 61 -- -- -- Operating leases 80,176 3,788 6,842 4,697 64,849 Other long-term obligations 49,776 11,659 23,351 14,766 -- ---------- -------- -------- -------- -------- Total contractual obligations $2,028,768 $102,288 $337,352 $817,176 $771,952 ========== ======== ======== ======== ========

Operating Leases - We are required to make future minimum payments for office space, pipeline equipment, rights-of-way and vehicles under non-cancelable operating leases. 47 Other Long-Term Obligations - Crestone Energy's firm transportation agreements with Fort Union Gas Gathering and Lost Creek Gathering require minimum monthly payments. We guarantee the performance of certain of our unconsolidated affiliates in connection with credit agreements that expire in March 2009 and September 2009. The collective amount of the guarantees was $4.4 million at December 31, 2005. CASH DISTRIBUTIONS We distribute 100% of our available cash, which generally consists of all cash receipts less adjustments for cash disbursements and net change to reserves, to our general and limited partners. Our income is allocated to the general partners and limited partners according to their respective partnership percentages of 2% and 98%, respectively, after the effect of any incremental income allocations for incentive distributions to the general partners. In each of 2005 and 2004, we paid $148.5 million to our common unitholders and $11.2 million to our general partners for their general partner and incentive distribution interests. In 2003, we paid $144.3 million to our common unitholders and $10.8 million to our general partners for their general partner and incentive distribution interests. On February 14, 2006, we paid quarterly cash distributions of $0.80 per unit on all outstanding units. We paid $37.1 million to our common unitholders and approximately $2.8 million to our general partners for their general partner and incentive distribution interests. Additional information about our cash distributions is included under Item 5, "Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities," and Item 13, "Certain Relationships and Related Transactions." CONTINGENCIES LEGAL On November 1, 2005, as required by the provisions of the settlement of Northern Border Pipeline's 1999 rate case, Northern Border Pipeline filed a rate case with the FERC. Information about the rate case is included under Item 3, "Legal Proceedings." ENVIRONMENTAL Our operations are subject to extensive federal, state and local laws and regulations governing the discharge of materials into the environment or otherwise relating to the protection of the environment. Failure to comply with these laws and regulations can result in substantial penalties, enforcement actions and remedial liabilities. Dunavan Superfund Site - In July 2005, the U.S. EPA notified Midwestern Gas Transmission and several other non-affiliated parties of possible liability pursuant to the Comprehensive Environmental Response, Compensation and Liability Act and requested information related to the Dunavan Oil Site located in Oakwood, Illinois. The EPA identified Midwestern Gas Transmission as possibly transporting and disposing of used oil at the contaminated site and classified Midwestern Gas Transmission as a de minimis party. We believe costs related to resolving this matter will not materially impact our results of operations or financial position. Nitrogen Oxides State Implementation Plan - In September 2005, the Illinois EPA distributed a draft of a rule to control nitrogen oxide emissions from reciprocating engines and turbines state-wide by January 1, 2009, to mitigate ground level ozone. Under this rule, the state would require the installation of necessary controls to comply with EPA rules regarding the Nitrogen Oxides State Implementation Plan Call, ozone non-attainment and fine particulate standards. Midwestern Gas Transmission participated in several stakeholder meetings to provide comments concerning the draft rule. Another draft of the rule is expected to be distributed before it is submitted to the Illinois Pollution Control Board. As currently drafted, the rule affects five Midwestern Gas Transmission engines in Illinois and preliminary cost estimates for the required emission controls are less than $5 million. 48 RECENT ACCOUNTING PRONOUNCEMENTS The FASB recently issued SFAS No. 123R, "Share-Based Payment" and Interpretation 47, "Accounting for Conditional Asset Retirement Obligations-an interpretation of FASB Statement No. 143." In addition, the FERC issued guidance related to accounting for pipeline integrity costs. Additional information about these accounting pronouncements is included in Note 15 of the Consolidated Financial Statements. FORWARD-LOOKING STATEMENTS The statements in this annual report that are not historical information, including statements concerning plans and objectives of management for future operations, economic performance or related assumptions, are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Exchange Act. Forward-looking statements may include words such as "anticipate," "estimate," "expect," "project," "intend," "plan," "believe," "should" and other words and terms of similar meaning. Although we believe that our expectations regarding future events are based on reasonable assumptions, we can give no assurance that our goals will be achieved. Important factors that could cause actual results to differ materially from those in the forward-looking statements include: - the impact of unsold capacity on Northern Border Pipeline being greater or less than expected; - the ability to market pipeline capacity on favorable terms, which is affected by: - future demand for and prices of natural gas; - competitive conditions in the overall natural gas and electricity markets; - availability of supplies of Canadian and U.S. natural gas; - availability of additional storage capacity; - weather conditions; and - competitive developments by Canadian and U.S. natural gas transmission peers; - final orders by the FERC which adversely impact changes requested in Northern Border Pipeline's November 2005 rate case; - performance of contractual obligations by our customers; - the ability to recover operating costs, costs of property, plant and equipment and regulatory assets in our FERC-regulated rates; - timely receipt of approval by the FERC for construction and operation of Midwestern Gas Transmission's Eastern Extension Project and required regulatory clearances; our ability to acquire all necessary rights-of-way and obtain agreements for interconnects in a timely manner; and our ability to promptly obtain all necessary materials and supplies required for construction; - rate of development, well performance and competitive conditions near our natural gas gathering systems in the Powder River and Williston Basins and our investments in the Powder River and Wind River Basins; - prices of natural gas and natural gas liquids; - composition and quality of the natural gas we gather and process in our plants; - impact on drilling and production by factors beyond our control, including the demand for natural gas and refinery-grade crude oil; producers' desire and ability to obtain necessary permits; reserve performance; and capacity constraints on the pipelines that transport natural gas, crude oil and natural gas liquids from producing areas and our facilities; - efficiency of our plants in processing natural gas and extracting natural gas liquids; - renewal of the coal slurry pipeline transportation contract under reasonable terms and our success in completing the necessary reconstruction of the coal slurry pipeline; - impact of potential impairment charges; - developments in the December 2, 2001, filing by Enron of a voluntary petition for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy Code affecting our settled claims; - ability to control operating costs; - conditions in the capital markets and our ability to access the capital markets; - risks inherent in the use of information systems in our respective businesses, implementation of new software and hardware, and the impact on the timeliness of information for financial reporting; 49 - our ability to consummate the acquisition of the ONEOK subsidiaries, which could adversely affect our business, financial condition and results of operations; our ability to successfully integrate the operations of ONEOK with our current operations; the dilution of our current unitholders' ownership interests upon issuance of units to ONEOK in connection with the acquisition; and - acts of nature, sabotage, terrorism or other similar acts causing damage to our facilities or our suppliers' or shippers' facilities. These factors are not necessarily all of the important factors that could cause actual results to differ materially from those expressed in any of our forward-looking statements. Other factors could also have material adverse effects on our future results. These and other risks are described in greater detail under Item 1A, "Risk Factors." All forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by these factors. Other than as required under securities laws, we undertake no obligation to update publicly any forward-looking statement whether as a result of new information, subsequent events or change in circumstances, expectations or otherwise. ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK OVERVIEW Our exposure to market risk discussed below includes forward-looking statements and represents an estimate of possible changes in future earnings that would occur assuming hypothetical future movements in interest rates or commodity prices. Our views on market risk are not necessarily indicative of actual results that may occur and do not represent the maximum possible gains and losses that may occur, since actual gains and losses will differ from those estimated, based on actual fluctuations in interest rates or commodity prices and the timing of transactions. We are exposed to market risk due to interest rate and commodity price volatility. Market risk is the risk of loss arising from adverse changes in market rates and prices. We utilize financial instruments, including forwards, swaps, collars and futures to manage the risks of certain identifiable or anticipated transactions and achieve a more predictable cash flow. Our risk management function follows established policies and procedures to monitor interest rates and natural gas and natural gas liquids marketing activities to ensure our hedging activities mitigate market risks. We do not use financial instruments for trading purposes. In accordance with SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities," we record financial instruments on the balance sheet as assets and liabilities based on fair value. We estimate the fair value of financial instruments using available market information and appropriate valuation techniques. Changes in financial instruments' fair value are recognized in earnings unless the instrument qualifies as a hedge under SFAS No. 133 and meets specific hedge accounting criteria. Qualifying financial instruments' gains and losses may offset the hedged items' related results in earnings for a fair value hedge or be deferred in accumulated other comprehensive income for a cash flow hedge. INTEREST RATE RISK We utilize both fixed- and variable-rate debt and are exposed to market risk due to the floating interest rates on our credit facilities. We regularly assess the impact of interest rate fluctuations on future cash flows and evaluate hedging opportunities to mitigate our interest rate risk. FAIR VALUE HEDGES - INTEREST RATE SWAPS We maintain a significant portion of our debt at fixed rates to reduce our sensitivity to interest rate fluctuations and utilize interest rate swap agreements to convert fixed-rate debt to variable-rate debt to manage interest expense. Our interest rate swap agreements are designated as fair value hedges under SFAS No. 133 because they mitigate fluctuations in the market value of the underlying fixed-rate debt. Under these agreements, we pay counterparties variable interest rates based on LIBOR and receive interest payments based on the senior notes' fixed rate. 50

EFFECTIVE NOTIONAL HEDGED FIXED-RATE DEBT PERIOD COVERED BY SWAP INTEREST RATE AMOUNT ---------------------- -------------------------- ------------- ----------- Senior Notes, 7.10% fixed rate, January 2005 to March 2011 6.32% $75 million due March 2011 Senior Notes, 7.10% fixed rate, January 2005 to March 2011 6.80% $75 million due March 2011

As of December 31, 2005, the fair value of our hedges in effect was a liability of $2.4 million. Consolidated interest expense for 2005 reflected a $1.0 million benefit from these swap agreements. If interest rates hypothetically increased 1% compared with rates in effect as of December 31, 2005, our annual consolidated interest expense would increase and our consolidated income before income taxes would decrease by approximately $3.8 million. CASH FLOW HEDGES - FORWARD-STARTING INTEREST RATE SWAPS In December 2004, we entered into forward-starting interest rate swap agreements with a total notional amount of $100 million in anticipation of a ten-year senior note issuance. We paid $2.7 million to counterparties when the swap agreements expired in late May and early June of 2005. In June 2005, we entered into a Treasury lock interest rate agreement with a total notional amount of $200 million, which expired in July 2005 at which time we paid $0.1 million to the counterparty. As of December 31, 2005, there were no forward-starting interest rate swap agreements outstanding. COMMODITY PRICE RISK Our interstate natural gas pipelines generally are not exposed to commodity price risk because they do not own the natural gas they transport. Northern Border Pipeline and Viking Gas Transmission own the natural gas necessary to maintain efficient pipeline operations and shippers provide the natural gas necessary to operate the compressor stations. Midwestern Gas Transmission collects a fixed amount of natural gas for its operations. When the amount of natural gas utilized by Midwestern Gas Transmission differs from the amount provided by its shippers, the pipeline must buy or sell natural gas and is exposed to commodity price risk. Bear Paw Energy receives a significant portion of its revenue from the sale of commodities in exchange for gathering and processing services and is exposed to market risk due to its sensitivity to natural gas and natural gas liquids prices. To reduce our exposure to natural gas and natural gas liquids price volatility, we enter into commodity financial instruments, including price swaps and collars, which are designated as cash flow hedges. In 2005, we entered into a limited number of commodity financial instruments to manage our earnings on equity natural gas and natural gas liquids. Our equity volumes for 2005 were hedged as follows:

2005 WEIGHTED AVERAGE AVERAGE HEDGE HEDGED COMMODITY HEDGED VOLUME PRICE PER UNIT ---------------- ------------- -------------- Natural Gas (in MMBtu/d) 5,500 $7.15 Natural Gas Liquids (in gallons/d) 65,600 $0.92

As of January 31, 2006, our projected natural gas and natural gas liquids volumes were hedged for 2006 as follows:

2006 2006 WEIGHTED PROJECTED EQUITY AVERAGE AVERAGE HEDGE HEDGED COMMODITY VOLUME RANGE HEDGED VOLUME PRICE PER UNIT ---------------- ----------------- ------------- ---------------- Natural Gas (in MMBtu/d) 11,000 - 12,400 7,300 $8.08 Natural Gas Liquids (in gallons/d) 101,400 - 122,500 49,500 $1.01

Our natural gas is hedged based on pricing indexes at Colorado Interstate Gas (CIG) and Northern Natural Gas (NNG) Ventura. Our natural gas liquids are hedged based on pricing indexes at Conway and Koch West Texas Intermediate (WTI). 51 If the weighted average price of natural gas hypothetically decreased $1.00 per MMBtu compared with the price at December 31, 2005, annual net income would decrease approximately $4.4 million based on our projected 2006 volumes as of January 31, 2006. If the weighted average price of natural gas liquids hypothetically decreased $0.10 per gallon compared with the price in effect as of December 31, 2005, annual net income would decrease approximately $4.3 million based on our projected 2006 volumes as of January 31, 2006. Additional information about our financial instruments is included in Note 9 of the Consolidated Financial Statements. ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA The information required hereunder is included in this report as set forth in the "Index to Financial Statements" on page F-1. ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE None. ITEM 9A. CONTROLS AND PROCEDURES CONCLUSION REGARDING THE EFFECTIVENESS OF DISCLOSURE CONTROLS AND PROCEDURES The Partnership's principal executive officer and principal financial officer have evaluated the effectiveness of the Partnership's "disclosure controls and procedures," (as such term is defined in Exchange Act Rule 13a-15(e) or 15d-15(e)) as of the end of the period covered by this annual report. Based upon their evaluation, the principal executive officer and principal financial officer concluded that the Partnership's disclosure controls and procedures are effective. MANAGEMENT'S ANNUAL REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING The Partnership's principal executive officer and principal financial officer are responsible for establishing and maintaining adequate internal control over financial reporting for the Partnership. The Partnership's internal control system was designed to provide reasonable assurance to the Partnership's management and members of the Partnership's Policy Committee and Audit Committee regarding the fair presentation of published financial statements. All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. The Partnership's management assessed the effectiveness of the Partnership's internal control over financial reporting as of December 31, 2005. In making this assessment, it used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control-Integrated Framework. Based on the assessment, the Partnership's management believes that, as of December 31, 2005, the Partnership's internal control over financial reporting is effective based on those criteria. The Partnership's independent registered public accounting firm has issued an attestation report on management's assessment of the Partnership's internal control over financial reporting. This report appears in the Report of Independent Registered Public Accounting Firm below. /s/ WILLIAM R. CORDES ---------------------------------------- William R. Cordes Chief Executive Officer /s/ JERRY L. PETERS ---------------------------------------- Jerry L. Peters Chief Financial and Accounting Officer 52 REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM Northern Border Partners, L.P.: We have audited management's assessment, included in the accompanying Management's Report on Internal Control over Financial Reporting, that Northern Border Partners, L.P. maintained effective internal control over financial reporting as of December 31, 2005, based on criteria established in Internal Control--Integrated Framework, issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management's assessment and an opinion on the effectiveness of the Company's internal control over financial reporting based on our audit. We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating management's assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion. A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. In our opinion, management's assessment that Northern Border Partners, L.P. maintained effective internal control over financial reporting as of December 31, 2005 is fairly stated, in all material respects, based on COSO. Also, in our opinion, Northern Border Partners, L.P. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2005, based on COSO. We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Northern Border Partners, L.P. and subsidiaries as of December 31, 2005 and 2004, and the related consolidated statements of income, comprehensive income, cash flows, and changes in partners' equity for each of the years in the three-year period ended December 31, 2005, and our report thereon dated March 2, 2006 expressed an unqualified opinion on those consolidated financial statements. /s/ KPMG LLP Omaha, Nebraska March 2, 2006 53 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. In the quarter ended December 31, 2005, however, we began implementing a new contracting and billing system to support the natural gas gathering and processing segment. The new system will automate certain transactional processes, including scheduling, plant allocations and invoicing, that are currently handled manually. Implementation is scheduled for April 2006. In conjunction with Northern Border Pipeline's rate case, we will complete system modifications to meet the proposed new transportation billing requirements. Implementation is scheduled for May 2006. These two activities will cause changes to our internal control over financial reporting. ITEM 9B. OTHER INFORMATION On January 19, 2006, the Board of Directors of ONEOK granted restricted stock units and performance units under ONEOK's Equity Compensation Plan to our Chief Executive Officer, William R. Cordes and our Chief Financial and Accounting Officer, Jerry L. Peters, as well as the following persons that have been designated as officers for purposes of Section 16 of the Exchange Act: Paul F. Miller, Raymond D. Neppl, Janet K. Place, Gaye Lynn Schaffart, Christopher R Skoog, Michel E. Nelson and Pierce H. Norton. The restricted stock units vest three years from the date of grant at which time the grantee is entitled to shares of ONEOK common stock. The performance 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 19, 2006, to January 19, 2009, compared to the total shareholder return of a peer group of 20 other companies. The grant is payable in shares of ONEOK common stock. In addition, our executive officers participate in the ONEOK Employee Stock Purchase Plan. These plans and form of award agreements are filed as exhibits to this Form 10-K and their terms and provisions are incorporated herein by reference as follows: ONEOK's Equity Compensation Plan - Exhibit 10.13; ONEOK, Inc. Form of Restricted Unit Award Agreement under Equity Compensation Plan - Exhibit 10.21; ONEOK, Inc. Form of Performance Unit Award Agreement under Equity Compensation Plan - Exhibit 10.22; and ONEOK, Inc. Employee Stock Purchase Plan, as amended February 17, 2005 - Exhibit 10.14. PART III ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT PARTNERSHIP POLICY, NORTHERN BORDER MANAGEMENT AND AUDIT COMMITTEES We are managed under the direction of the Partnership Policy Committee consisting of three members, one of whom is appointed by each of our general partners. The members appointed by Northern Plains, Pan Border and Northwest Border have 50%, 32.5% and 17.5%, respectively, of the voting power. Because we are a limited partnership, we are not required by the listing standards of the NYSE to have a majority of independent directors or a nominating/corporate governance or compensation committee. None of our Policy Committee Members are independent. We also have an Audit Committee consisting of individuals who are neither officers nor employees of any general partner nor any affiliate of a general partner. The Audit Committee members are not members of, and do not vote on matters submitted to, the Partnership Policy Committee. The Partnership Policy Committee delegated to the Audit Committee oversight responsibility with respect to the integrity of our financial statements, the performance of our internal audit function, the independent auditor's qualification and independence and compliance with legal and regulatory requirements. The Audit Committee directly appoints, retains, evaluates and may terminate our independent auditors. The Audit Committee reviews the annual financial statements and resolves, if necessary, any significant disputes between management and the independent auditor that arise in connection with the preparation of our financial statements. The Audit Committee also has the authority to review, at the request of a general partner, specific matters that a general partner believes may be a conflict of interest in order to determine if the resolution of such conflict proposed by the Partnership Policy Committee is fair and reasonable to us. The Audit Committee has all other responsibilities required by the NYSE Listing Standards and SEC rules. All members of the Partnership Policy Committee and our representatives on the Northern Border Management Committee serve at the discretion of the general partner that appointed them. The members of our Partnership Policy Committee and Audit Committee are not elected by unitholders. Accordingly, we do not have a procedure by which security holders may recommend nominees to our Partnership Policy Committee or Audit Committee. The persons designated as executive officers serve in that capacity at the discretion of the Partnership Policy Committee. The Audit Committee members are elected, and may be removed, by the Partnership Policy Committee. The members of the Partnership Policy Committee receive no management fee or other remuneration for serving on this committee. The chairman of the Audit Committee receives an annual fee of $50,000 and the other Audit Committee members each receive an annual fee of $40,000 and are paid $1,500 for each meeting attended. In lieu of meeting fees, the Audit Committee chairman may be compensated an additional amount up to $80,000 and the other members may be compensated an additional amount up to $65,000 for the review of a conflict of interest transaction, as requested by the Partnership Policy Committee. 54 There are no family relationships between any of our executive officers or members of the Partnership Policy Committee and the Audit Committee.

NAME AGE POSITION ---- --- -------- William R. Cordes 57 Chief Executive Officer Member, Partnership Policy Committee Chairman, Northern Border Management Committee David L. Kyle 53 Chairman, Partnership Policy Committee Member, Northern Border Management Committee Paul E. Miller 47 Member, Partnership Policy Committee Member, Northern Border Management Committee Jerry L. Peters 48 Chief Financial and Accounting Officer Gary N. Petersen 54 Member, Audit Committee Gerald B. Smith 55 Chairman, Audit Committee Gil J. Van Lunsen 63 Member, Audit Committee

William R. Cordes was named chief executive officer of the Partnership and appointed to the Partnership Policy Committee in 2000. He served as chairman of the Partnership Policy Committee from 2000 until 2004. Mr. Cordes was appointed president of Northern Plains and Pan Border in 2000 and president of NBP Services in 2004. Mr. Cordes was named chairman of the Northern Border Management Committee in 2000. In 1970, he started his career with Northern Natural Gas Company, an Enron subsidiary until 2002, where he worked in several management positions. From 1993 until 2000, he was president of Northern Natural Gas Company, and from 1996 until 2000, he was also president of Transwestern Pipeline, a subsidiary of Enron. David L. Kyle was named chairman of the Partnership Policy Committee and designated a member of the Northern Border Management Committee in 2004. Mr. Kyle is chairman and chief executive officer of Northern Plains, Pan Border and NBP Services. Mr. Kyle is also the chairman of the board, president, and chief executive officer of ONEOK. 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 in 1986 and executive vice president in 1990. He was elected president of Oklahoma Natural Gas Company in 1994. He was elected president of ONEOK in 1997, and elected chairman of the board and appointed the chief executive officer of ONEOK in 2000. Mr. Kyle is a member of the board of directors of Bank of Oklahoma Financial Corporation. Paul E. Miller was designated by TransCanada as its member on the Partnership Policy Committee in 2003. Mr. Miller is also a representative on the Northern Border Management Committee. In addition, Mr. Miller serves as director, Corporate Development of TransCanada, a position he has held since 2003. From 1998 to 2003, Mr. Miller was director, Finance of TransCanada. Prior to 1998, Mr. Miller was manager, Finance of TransCanada. Jerry L. Peters was named chief financial and accounting officer in 1994. Mr. Peters has held several management positions with Northern Plains since 1985 and was elected vice president of Finance in 1994 and treasurer in 1998. Mr. Peters was also elected vice president of Finance for NBP Services in 2004. Mr. Peters was 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. Gary N. Petersen was appointed to the Audit Committee in 2002. Since 1998, he has provided consulting services related to strategic and financial planning. Additionally, he is president of Endres Processing LLC. From 1977 to 1998, Mr. Petersen was employed by Reliant Energy-Minnegasco. He served as president and chief operating officer of Reliant Energy-Minnegasco from 1991 to 1998. Prior to his employment at Minnegasco, he was a senior 55 auditor with Andersen. He currently serves on the boards of the YMCA of Metropolitan Minneapolis and the Dunwoody Institute. Gerald B. Smith was appointed to the Audit Committee in 1994. He is chairman and chief executive officer and co-founder of Smith, Graham & Company Investment Advisors, a global investment management firm, which was founded in 1990. He is a member of the board of trustees of the Charles Schwab Family of Funds and a director and member of the Cooper Industries audit committee. He is a former director of the Fund Management Board of Robeco Group, Rorento N.V. (Netherlands). Gil J. Van Lunsen was appointed to the Audit Committee in March 2005. Prior to his retirement in 2000, Mr. Van Lunsen was a managing partner of KPMG LLP at the firm's Tulsa, Oklahoma office. He began his career with KPMG in 1968. He is currently a director and audit committee chairman of Array Biopharma in Boulder, Colorado and Sirenza Microdevices in Broomfield, Colorado. OFFICERS At the Partnership Policy Committee meeting on March 3, 2006, the following persons were deemed to be officers of the Partnership for purposes of Section 16 of the Exchange Act. Some of these individuals are officers at certain subsidiaries or affiliates of the Partnership.

NAME AGE POSITION ---- --- -------- Paul F. Miller 39 Vice President and General Manager, Northern Border Pipeline Northern Plains Michel E. Nelson 58 Vice President, Operations Northern Plains Raymond D. Neppl 61 Vice President, Regulatory Affairs and Market Services Northern Plains Pierce H. Norton 46 President, Bear Paw Energy Janet K. Place 57 Vice President, General Counsel and Secretary Northern Plains and NBP Services Fred G. Rimington 55 Vice President, Administration Northern Plains and NBP Services President, Black Mesa Pipeline Gaye Lynn Schaffart 46 Vice President and General Manager, Interstate Pipelines Northern Plains Christopher R Skoog 42 Executive Vice President Northern Plains and NBP Services

Paul F. Miller was elected vice president and general manager of Northern Border Pipeline by Northern Plains in January 2005. From 2002 until January 2005, Mr. Miller was vice president of Marketing for Northern Plains. Mr. Miller was previously account executive, Marketing from 1998 until 2000, when he was promoted to director, Marketing. Mr. Miller joined Northern Plains in 1990. Michel E. Nelson was elected vice president, Operations for Northern Plains in 2004. Mr. Nelson was previously vice president of Operations and Support Services for CrossCountry Energy, LLC, an Enron subsidiary, from 2002 to 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. 56 Raymond D. Neppl is vice president, Regulatory Affairs and Market Services, a position he has held since 1994. Mr. Neppl was previously vice president of Regulatory Affairs from 1991 to 1994. Mr. Neppl joined Northern Natural Gas Company, formerly affiliated with Northern Plains, in 1975 and transferred to Northern Plains in 1980. Pierce H. Norton was appointed president of Bear Paw Energy in 2003. Mr. Norton was appointed president of ONEOK's gathering and processing segment in January 2006. Mr. Norton was previously appointed senior vice president of ONEOK's gathering and processing segment in July 2005. Mr. Norton was appointed vice president and general manager for midstream businesses for NBP Services in 2003. Mr. Norton served as vice president, Business Development for Bear Paw Energy from 2001 to 2003. Prior to the Partnership's purchase of Bear Paw Energy, Mr. Norton was vice president, Business Development for Bear Paw Energy and its predecessor from 1999 to 2001. Janet K. Place is vice president, general counsel and secretary of Northern Plains. Ms. Place was elected as vice president in 1994 and secretary in 2004. She was also elected vice president, general counsel and secretary of NBP Services in 2004. In 1993, Ms. Place was named general counsel. Ms. Place joined Northern Plains in 1980 as an attorney. Fred G. Rimington was elected vice president, Administration of Northern Plains and NBP Services in February 2005. He was appointed president of Black Mesa in 2000. Mr. Rimington was director, Business Development from 1994 to 1999 for Northern Plains. Mr. Rimington joined Northern Plains in 1980. Gaye Lynn Schaffart was elected vice president and general manager, Interstate Pipelines of Northern Plains in February 2005. Ms. Schaffart was previously director, Business Development and Planning from 1993 to 2004 and was promoted to vice president, Business Development and Strategic Planning in 2004. Ms. Schaffart joined Northern Plains in 1982. Christopher R Skoog was appointed executive vice president of Northern Plains and NBP Services in February 2005. Mr. Skoog is responsible for all commercial, operational and regulatory functions of the Partnership's natural gas businesses and coordinates the Partnership's business development initiatives. From 1999 to January 2005, Mr. Skoog served as president of ONEOK Energy Services Company, II. From 1995 to 1999, he was vice president of ONEOK Gas Marketing Company. AUDIT COMMITTEE MATTERS INDEPENDENCE DETERMINATIONS The Partnership has a separately-designated standing Audit Committee in accordance with Section 3(a)(58)(A) of the Exchange Act. The Partnership's guidelines for determining independence are included in the Partnership's Governance Guidelines, which, along with the Audit Committee Charter, are available on the "Governance" section of the Partnership's website at www.northernborderpartners.com. Copies of the Governance Guidelines as well as the Audit Committee Charter are available in print to any security holder who requests them by sending a written request to Investor Relations Department, Northern Border Partners, L.P., P.O. Box 542500, Omaha, NE 68154-8500. The Governance Guidelines provide that the members of the Audit Committee shall at all times qualify as independent members under the independence standards of the NYSE, Section 10A(m)(3) of the Exchange Act, the rules and regulations of the SEC and other applicable laws. At least annually the Partnership Policy Committee reviews the relationships of each Audit Committee member with the Partnership to affirmatively determine the independence of each member. In March 2006, the Partnership Policy Committee affirmatively determined that Messrs. Petersen, Smith, and Van Lunsen meet the standards for independence set forth in the Governance Guidelines and are independent from management. FINANCIAL EXPERTS Annually, the Partnership Policy Committee reviews the financial expertise of the members of the Audit Committee. In March 2006, the Partnership Policy Committee determined that Messrs. Petersen, Smith and Van Lunsen were "audit committee financial experts," as defined by the rules and regulations of the SEC. 57 SEPARATE SESSIONS OF NON-MANAGEMENT COMMITTEE MEMBERS The Partnership Policy Committee has documented its governance practices in our Governance Guidelines, which are available on the "Governance" section of the Partnership's website at www.northernborderpartners.com. The chairman of the Audit Committee, Mr. Smith, presides at regular sessions of the non-management committee members, which include the members of the Audit Committee and Messrs. Kyle and Miller of the Partnership Policy Committee. Meetings of the non-management committee members are scheduled quarterly or as requested by any non-management committee member. Interested parties desiring to communicate with the chairman of the Audit Committee, the non-management members of the Partnership Policy Committee or the Audit Committee members regarding the Partnership may contact such member(s) directly by utilizing the Partnership Ethics and Compliance Hotline which is posted on the "Governance-Contact Information" section of our website at www.northernborderpartners.com. SERVICE ON OTHER AUDIT COMMITTEES Mr. Van Lunsen serves on the audit committees of two other public companies. The Partnership Policy Committee has determined that Mr. Van Lunsen's service on these other audit committees does not impair his ability to effectively serve on the Partnership's Audit Committee. SECTION 16(A) BENEFICIAL OWNERSHIP REPORTING COMPLIANCE Section 16(a) of the Exchange Act requires executive officers, members of the Partnership Policy Committee and persons who own more than 10% of a registered class of the equity securities issued by us to file reports of ownership and changes in ownership with the SEC and the NYSE and to furnish the Partnership with copies of all Section 16(a) forms they file. Based solely on our review of the copies of such forms received by us during and with respect to the 2005 fiscal year, or written representations from certain reporting persons that no Form 5's were required for those persons, we believe that during 2005 our reporting persons complied with all applicable filing requirements in a timely manner, except for one transaction related to the sale of units from Pierce H. Norton's trust which was not reported within two business days as required. CODE OF ETHICS AND CODE OF CONDUCT We have adopted an Accounting and Financial Reporting Code of Ethics applicable to the Partnership's chief executive officer and chief financial and accounting officer. A copy of the Accounting and Financial Reporting Code of Ethics is posted on the "Governance" section of our website at www.northernborderpartners.com and is available in print to any security holder who requests it by writing to: Investor Relations Department, Northern Border Partners, L.P., P.O. Box 542500, Omaha, NE 68154-8500. We intend to post on our website any amendment to, or waiver from, any provision of our Accounting and Financial Reporting Code of Ethics that applies to our chief executive officer and chief financial and accounting officer within four business days following such amendment or waiver, in accordance with SEC rules. We have also adopted a Code of Conduct applicable to the members of the Partnership Policy Committee and Audit Committee, our officers and deemed executive officers and the employees of Northern Plains and NBP Services. The Code of Conduct is intended to meet the requirements of a "code of business conduct and ethics" under Section 303A.10 of the NYSE Listed Company Manual. A copy of the Code of Conduct is posted on the "Governance" section of our website at www.northernborderpartners.com and is available in print to any security holder who requests it by writing to: Investor Relations Department, Northern Border Partners, L.P., P.O. Box 542500, Omaha, NE 68154-8500. We intend to promptly post on our website any amendments to, or waivers from (including any implicit waivers), any provision of our Code of Conduct according to the rules of the NYSE. CERTIFICATION As required by the NYSE corporate governance listing standards, William R. Cordes, our chief executive officer, certified on May 4, 2005, that he was not aware of any violation by the Partnership of such standards. The certifications required by Section 302 of the Sarbanes-Oxley Act are attached as exhibits 31.1 and 31.2 to this annual report. 58 ITEM 11. EXECUTIVE COMPENSATION We are managed by a three-member Partnership Policy Committee, with one member appointed by each general partner. The Partnership Policy Committee designated two executive officers to serve as officers of the Partnership at the discretion of the Partnership Policy Committee. Certain officers of the general partners and certain officers of the Partnership's subsidiaries were also deemed to be executive officers of the Partnership by the Partnership Policy Committee. The following table summarizes the compensation paid for the last three years to the chief executive officer of the Partnership and the four most highly compensated executive officers of the Partnership during 2005, which we collectively refer to as the "named executive officers." From January 1, 2003, through November 17, 2004, compensation plans were administered by Enron. Beginning November 18, 2004, compensation plans are administered by ONEOK. SUMMARY COMPENSATION TABLE

LONG-TERM ANNUAL COMPENSATION COMPENSATION ----------------------------------------------- ------------ OTHER ANNUAL RESTRICTED ALL OTHER COMPENSATION(1) STOCK AWARDS COMPENSATION NAME AND PRINCIPAL POSITION YEAR SALARY ($) BONUS ($) ($) ($) ($) --------------------------- ---- ---------- --------- --------------- ------------ ------------ William R. Cordes 2005 $330,000 $365,000 $ -- $111,760(5) $21,607(6) Chief Executive Officer 2004 325,000 175,000 -- -- 4,908 2003 324,583 200,000 -- 99,972(4) 3,000 Jerry L. Peters 2005 190,000 140,000 -- 55,880(5) 13,616(7) Chief Financial and 2004 171,380 110,000 -- -- 5,658 Accounting Officer 2003 163,324 107,500 -- -- 76,386 Christopher R Skoog (2) 2005 315,000 300,000 $71,981(3) 83,820(5) 43,294(8) Executive Vice President Janet K. Place 2005 185,000 135,000 -- 37,253(5) 13,475(9) Vice President, General 2004 182,552 115,000 -- -- 8,675 Counsel and Secretary 2003 177,592 110,000 -- -- 6,233 Paul F. Miller 2005 175,000 140,000 -- 46,566(5) 12,594(10) Vice President and General 2004 153,298 118,000 -- -- 5,335 Manager for Northern 2003 148,958 111,000 -- -- 90,325 Border Pipeline

(1) Except as specifically noted below, with respect to Mr. Skoog, the named executive officers did not receive any annual compensation not properly categorized as salary or bonus, except for certain perquisites and other personal benefits, which include vehicle allowances and country club dues. The aggregate amount of such perquisites and other personal benefits, if any, for the named executive officers during the fiscal year did not exceed the lesser of $50,000 or 10% of total salary and bonus reported for such named executive officer. The aggregate amount of perquisites and other personal benefits received in the last fiscal year, for the named executive officers other than Mr. Skoog, were as follows: Mr. Cordes, $26,340; Mr. Peters, $14,400; Ms. Place, $14,400; and Mr. Miller, $14,400. (2) Mr. Skoog was appointed as executive vice president of Northern Plains in February 2005. (3) Includes $52,500 in relocation expenses under ONEOK's relocation plan, which plan is available generally to all salaried employees, $18,000 vehicle allowance and $1,481 physical examination cost. (4) On June 1, 2003, 669 Northern Border Partners' phantom units valued at $149.4346 per unit were granted in accordance with Mr. Cordes' employment agreement. The phantom units vest on the fifth anniversary of the date of each grant. As of December 31, 2005, Mr. Cordes held 4,162 phantom units valued at $643,397 ($154.5885 per unit). Distributions accrued on the phantom units as of December 31, 2005, were $198,336. 59 (5) Represents restricted stock incentive units granted under ONEOK's Long-Term Incentive Plan. The market value of restricted stock incentive unit awards is based on the closing market price of a share of ONEOK common stock on the NYSE on the date of grant. Each grant vests 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. Since no shares of ONEOK common stock are issued under a restrictive stock incentive unit until the unit vests, no dividends are payable with respect to restricted stock incentive units. The aggregate number of restricted stock incentive units (excluding fractional shares) held by the named executive officers at December 31, 2005, and the market value of these restricted stock incentive units as of that date are indicated in the table below. In addition to restricted stock incentive units, Mr. Skoog holds 12,274 aggregate shares (excluding fractional shares) of restricted stock with a market value of $326,857 as of December 31, 2005. Restricted stock is granted under ONEOK's Long Term Incentive Plan. Each grant vests three years from the date of grant. Dividends are paid on unvested shares of restricted stock and reinvested in additional shares of restricted stock at the average of the high and low trading prices of a share of ONEOK's common stock on the NYSE on the date the dividend is paid. Restricted stock acquired as a result of the reinvestment of dividends vests at the same time as the restricted stock with respect to which the dividend was paid vests. The market value was determined based on a per share price for ONEOK common stock of $26.63, which reflects the closing market price of ONEOK common stock on the NYSE on December 30, 2005.

AGGREGATE NUMBER OF MARKET VALUE OF RESTRICTED RESTRICTED STOCK INCENTIVE UNITS HELD AT STOCK INCENTIVE UNITS HELD AT DECEMBER 31, NAME DECEMBER 31, 2005 2005 ---- ---------------------------------------- -------------------------------------------- William R. Cordes 6,000 $159,780 Christopher R Skoog 16,000 426,080 Jerry L. Peters 3,000 79,890 Janet K. Place 2,000 53,260 Paul F. Miller 2,500 66,575

(6) Amount includes: (i) $7,402 paid as a company match under ONEOK's Non-Qualified Deferred Compensation Plan; (ii) $12,600 paid as a company match under the Thrift Plan for Employees of ONEOK, Inc. and Subsidiaries; (iii) $1,276 paid as a service award; and (iv) $329 representing the value of ONEOK shares received under ONEOK's Employee Stock Award Program based on the closing market price of ONEOK's common stock on the NYSE on the date of issue. (7) Amount includes: (i) $12,485 paid as a company match under the Thrift Plan for Employees of ONEOK, Inc. and Subsidiaries; (ii) $802 paid as a service award; and (iii) $329 representing the value of ONEOK shares received under ONEOK's Employee Stock Award Program based on the closing market price of ONEOK's common stock on the NYSE on the date of issue. (8) Amount includes: (i) $30,000 paid as a company match under ONEOK's Non-Qualified Deferred Compensation Plan; (ii) $12,600 paid as a company match under the Thrift Plan for Employees of ONEOK, Inc. and Subsidiaries; (iii) $365 paid as a service award; and (iv) $329 representing the value of ONEOK shares received under ONEOK's Employee Stock Award Program based on the closing market price of ONEOK's common stock on the NYSE on the date of issue. (9) Amount includes: (i) $12,234 paid as a company match under the Thrift Plan for Employees of ONEOK, Inc. and Subsidiaries; (ii) $912 paid as a service award; and (iii) $329 representing the value of ONEOK shares received under ONEOK's Employee Stock Award Program based on the closing market price of ONEOK's common stock on the NYSE on the date of issue. (10) Amount includes: (i) $11,664 paid as a company match under the Thrift Plan for Employees of ONEOK, Inc. and Subsidiaries; (ii) $601 paid as a service award; and (iii) $329 representing the value of ONEOK shares received under ONEOK's Employee Stock Award Program based on the closing market price of ONEOK's common stock on the NYSE on the date of issue. For 1999, 2000 and 2001, employees of Northern Plains were able to elect to receive Northern Border phantom units, Enron phantom stock, and/or Enron stock options in lieu of all or a portion of an annual bonus payment. Mr. Cordes, Mr. Peters, Ms. Place and Mr. Miller elected to receive Northern Border phantom units under the Northern Border Phantom Unit Plan in lieu of a portion of the cash bonus payment. As a result of this deferral, Mr. Cordes received 1,914 units in 2001; Mr. Peters received 1,532 units in 1999, 1,450 units in 2000 and 842 units in 2001; Ms. Place received 901 units in 1999 and 240 units in 2001; and Mr. Miller received 137 units in 1999, 123 units in 2000 and 230 units in 2001. In each case, units will be released based upon the holding period selected by the participant. For the release in January 2004 Mr. Peters received 4,727 common units and $2,234 in cash and he received 6,734 common units for the release in January 2005. For the release in January 2003, Ms. Place received 1,091 common units and for the release in January 2004, she elected a redemption payment in cash of $83,232. For the release in January 2003, Mr. Miller received 329 common units and for the release in January 2004, he elected a redemption payment in cash of $25,283. As of December 31, 2005, Mr. Peters held 842 phantom units valued at $130,164 ($154.5885 per unit). 60 Distributions accrued on Mr. Peters' phantom units as of December 31, 2005, were $46,760. As of December 31, 2005, Ms. Place held 230 phantom units valued at $35,555 ($154.5885 per unit). Distributions accrued on Ms. Place's phantom units as of December 31, 2005, were $12,773. As of December 31, 2005, Mr. Miller held 115 phantom units valued at $17,778 ($154.5885 per unit). Distributions accrued on Mr. Miller's phantom units as of December 31, 2005, were $6,387. Mr. Cordes' information is included above in footnote 5 to the Summary Compensation Table. On January 19, 2006, the Board of Directors of ONEOK granted restricted stock units and performance units under ONEOK's Equity Compensation Plan to the named executive officers as follows: (i) Mr. Cordes, 6,000 restricted stock units and 10,500 performance units; Mr. Skoog, 2,500 restricted stock units and 4,000 performance units; Mr. Peters, 2,500 restricted stock units and 4,000 performance units; Ms. Place 1,500 restricted stock units and 2,500 performance units; and Mr. Miller 1,500 restricted stock units and 2,500 performance units. The restricted stock units vest three years from the date of grant at which time the grantee is entitled to shares of ONEOK common stock. The performance 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 19, 2006, to January 19, 2009, compared to the total shareholder return of a peer group of 20 other companies. The grant is payable in shares of ONEOK common stock. LONG-TERM INCENTIVE PLANS -- AWARDS IN LAST FISCAL YEAR The following table sets forth the certain information concerning performance share units granted in 2005 to the named executive officers under ONEOK's Long-Term Incentive Plan. PERFORMANCE SHARE GRANTS

ESTIMATED FUTURE PAYOUTS UNDER PERFOMANCE OR NON-STOCK PRICE-BASED PLANS NUMBER OF OTHER PERIOD ----------------------------------------------- SHARES, UNITS UNTIL TARGET MAXIMUM OR OTHER RIGHTS MATURATION OR THRESHOLD --------------- ----------------- NAME (1,2) (#) PAYOUT ($ OR #) (#) ($)(3) (#) ($)(3) ---- --------------- ------------- --------- ----- ------- ------ -------- William R. Cordes 10,500 3 Years -- 7,000 $93,205 14,000 $186,410 Christopher R Skoog 9,000 3 Years -- 6,000 79,890 12,000 159,780 Jerry L. Peters 4,500 3 Years -- 3,000 39,945 6,000 79,890 Janet K. Place 3,500 3 Years -- 2,333 31,077 4,666 62,154 Paul F. Miller 4,000 3 Years -- 2,666 35,524 5,333 71,022

(1) Restricted stock incentive units granted under ONEOK's Long-Term Incentive Plan in 2005 are set forth in the Summary Compensation Table above. (2) Reflects performance share units granted which vest three years from the date of grant. Upon vesting, a holder of performance share units is entitled to receive a number of shares of ONEOK common stock equal to a percentage (0% to 200%) of the performance share units 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 energy companies over the same period. Upon vesting, if any, the performance share awards are payable two-thirds in shares of ONEOK common stock and one-third in cash. (3) The value for the one-third of the grant payable in cash was determined based on a per share price for ONEOK common stock of $26.63, which reflects the closing market price of ONEOK common stock on the NYSE on December 30, 2005. TERMINATION AGREEMENT ONEOK has entered into termination agreements with each of the named executive officers. Each termination agreement has an initial term of one year 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. 61 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 an 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 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 their assets. ENRON CASH BALANCE PLAN Enron maintained the Enron Corp. Cash Balance Plan (Cash Balance Plan), which was a noncontributory defined benefit pension plan to provide retirement income for employees of Enron and its subsidiaries. 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. Enron's Board of Directors voted to terminate the Cash Balance Plan effective May 31, 2004. The process of terminating the Cash Balance Plan involved a series of governmental filings seeking approval for the termination and notices to participants and beneficiaries. Upon termination, all employees became fully vested in the Cash Balance Plan. In 2005, participants' cash balance accruals and accumulated interest credits were distributed as either lump sum or monthly annuities, depending upon a participant's election and particular circumstances. Lump sum payments could be rolled over to other qualified retirement plans or IRAs, or received in cash. The named executive officers received the following approximate payout amounts in 2005 pursuant to the terms of the Cash Balance Plan termination: Mr. Cordes, $77,144; Mr. Peters, $64,285; Ms. Place, $69,492; and Mr. Miller, $40,600. 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. 62 PENSION PLAN TABLE

YEARS OF SERVICE ---------------------------------------------------- REMUNERATION 15 20 25 30 35 ------------ -------- -------- -------- -------- -------- $125,000 $ 32,119 $ 42,825 $ 53,531 $ 64,238 $ 74,944 150,000 39,244 52,325 65,406 78,488 91,569 175,000 46,369 61,825 77,281 92,738 108,194 200,000 53,494 71,325 89,156 106,988 124,819 225,000 60,619 80,825 101,031 121,238 141,444 250,000 67,744 90,325 112,906 135,488 158,069 300,000 81,994 109,325 136,656 163,988 191,319 400,000 110,494 147,325 184,156 220,988 257,819 450,000 124,744 166,625 207,906 249,488 291,069 500,000 138,994 185,325 231,656 277,988 324,319

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. The credited year(s) of service under this plan for the named executive officers, other than Mr. Skoog was one year and one month. As of December 31, 2005, Mr. Skoog had 10 years and five months of credited service. For purposes of the table, the annual social security covered compensation benefit of $48,696 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 2005 cannot exceed $210,000. Amounts shown in the table are estimates only and are subject to adjustment based on rules and regulations applicable to the method of distribution and survivor benefit options selected by the retiree. The compensation covered by the retirement plan benefit formula for non-bargaining unit employees is the base salary and bonus paid to an employee within the employee's final average earnings. Final average earnings mean the employee's highest earnings during any 60 consecutive months during the last 120 months of employment. For any named executive officer who retires with vested benefits under the plan, the compensation shown as "Salary" and "Bonus" in the Summary Compensation Table could be considered covered compensation in determining benefits, except that the plan benefit formula takes into account only a fixed percentage of final average earnings which is uniformly applied to all employees. The amount of covered compensation that may be considered in calculating retirement benefits is also subject to limitations in the Internal Revenue Code of 1986, as amended, applicable to the plan. SUPPLEMENTAL EXECUTIVE RETIREMENT ONEOK maintains a Supplemental Executive Retirement Plan (SERP) for certain of its elected or appointed officers, and certain other employees in a select group of management and highly compensated employees. Participants are selected by ONEOK's chief executive officer, or, in the case of ONEOK's chief executive officer, by ONEOK's Board of Directors. All of our named officers participate in the SERP. 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 ONEOK's retirement plan, but are not offset by social security benefits. ONEOK's 63 board may amend or terminate the SERP at any time, provided that accrued benefits to current participants may not be reduced. The following table sets forth the estimated supplemental retirement benefits payable under ONEOK's SERP based on the covered participant's age at retirement. The estimates assume that a covered participant is fully vested. The amounts shown would be reduced for commencement of payments prior to age 60. SUPPLEMENTAL EXECUTIVE RETIREMENT PLAN TABLE

ESTIMATED ANNUAL BENEFITS AT INDICATED AGE OF RETIREMENT ----------------------------------------------------------- REMUNERATION 50 AND UNDER 55 60 62 65 AND OVER ------------ ------------ -------- -------- -------- ----------- $100,000 $ 50,000 $ 55,000 $ 59,000 $ 60,000 $ 60,000 150,000 75,000 82,500 88,500 90,000 90,000 200,000 100,000 110,000 118,000 120,000 120,000 250,000 125,000 137,500 147,500 150,000 150,000 300,000 150,000 165,000 177,000 180,000 180,000 350,000 175,000 192,500 206,500 210,000 210,000 400,000 200,000 220,000 236,000 240,000 240,000 450,000 225,000 247,500 265,500 270,000 270,000 500,000 250,000 275,000 295,000 300,000 300,000 550,000 275,000 302,500 324,500 330,000 330,000 600,000 300,000 330,000 354,000 360,000 360,000 650,000 325,000 357,500 383,500 390,000 390,000 700,000 350,000 385,000 413,000 420,000 420,000 750,000 375,000 412,500 442,500 450,000 450,000

ONEOK'S EMPLOYEE NON-QUALIFIED DEFERRED COMPENSATION PLAN The named executive officers are also eligible to participate in ONEOK's Non-Qualified Deferred Compensation Plan. ONEOK's Non-Qualified Deferred Compensation Plan provides select employees, as approved by the Board of Directors of ONEOK, 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% 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. ONEOK EMPLOYEE STOCK AWARD PROGRAM Under ONEOK's Employee Stock Award Program, ONEOK issued, for no consideration, to all eligible employees (all full-time employees and employees on short-term disability) one share of ONEOK common stock when the closing price on the NYSE was for the first time at or above each one dollar increment above $26 per share. The total number of shares of ONEOK common stock available for issuance under this program is 100,000 shares. 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. 64 COMPENSATION OF COMMITTEE MEMBERS The members of the Partnership Policy Committee receive no management fee or other remuneration for serving on the committee; however, they are reimbursed for their expenses related to their attendance at Partnership Policy Committee meetings. The chairman of the Audit Committee receives an annual fee of $50,000 and the other Audit Committee members receive an annual fee of $40,000. Each Audit Committee member is paid $1,500 for each meeting attended. The Audit Committee may receive additional compensation for the review of a conflict of interest transaction, as requested by the Partnership Policy Committee, in lieu of meeting fees. In connection with a review of a conflict of interest transaction, the Audit Committee chairman would be compensated up to an additional amount of $80,000 and the other members would be compensated up to an additional amount of $65,000. In addition, Audit Committee members are reimbursed for their expenses related to their attendance at Audit and Partnership Policy Committee meetings. We are required to indemnify the members of the Partnership Policy Committee and the general partners, their affiliates and their respective officers, directors, employees, agents and trustees to the fullest extent permitted by law against liabilities, costs and expenses incurred by any such person who acted in good faith and in a manner reasonably believed to be in, or (in the case of a person other than one of the general partners) not opposed to, our best interests and with respect to any criminal proceedings, had no reasonable cause to believe the conduct was unlawful. COMPENSATION COMMITTEE INTERLOCKS AND INSIDER PARTICIPATION We do not have a Compensation Committee. During 2005, the compensation of our named executive officers was determined by ONEOK's Compensation Committee consisting of the following ONEOK Board Members: James C. Day, William L. Ford, Bert H. Mackie, and Douglas Ann Newsom. No member of ONEOK's Compensation Committee is, or was formerly, an officer or employee of Northern Border Partners or any if its subsidiaries. We reimburse ONEOK for the direct and indirect compensation costs of our named executive officers. ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS BENEFICIAL OWNERSHIP The following table sets forth the beneficial ownership of our common units and the common stock of ONEOK, the parent company of two of our general partners, as of January 31, 2006, by each named executive officer, each member of the Partnership Policy Committee and Audit Committee, all executive officers and members of the Partnership Policy Committee and Audit Committee as a group and certain beneficial owners. Other than as set forth below, no person is known by the general partners to beneficially own more than 5% of our common units.

PERCENT OF PERCENT OF NAME AND ADDRESS OF COMMON COMMON ONEOK ONEOK BENEFICIAL OWNER (1) UNITS UNITS SHARES(5) SHARES -------------------- ------- ---------- ---------- ---------- William R. Cordes 1,000 * 872 * David L. Kyle -- * 553,812 * Paul F. Miller -- * 782 * ONEOK 501,603(2) 1.06 -- * Jerry L. Peters 7,734(3) * 849 * Gary N. Petersen 5,854 * -- * Janet K. Place 1,691(4) * 341 * Christopher R Skoog -- * 157,682 * All Policy Committee members, 24,001 * 716,093 * and executive officers as a group (16 persons)

* Less than 1% (1) The business address for each of the beneficial owners is c/o Northern Border Partners, L.P., 13710 FNB Parkway, Omaha, Nebraska 68154-5200, except for Mr. Kyle, whose business address is c/o ONEOK, Inc., 100 West Fifth Street, Tulsa, Oklahoma 74103-4298. 65 (2) Indirect ownership through its subsidiaries. Northern Plains is the beneficial owner of 501,603 common units which includes 1,603 common units to satisfy obligations under the Amended and Restated Northern Border Phantom Unit Plan. (3) Includes 1,000 units held by immediate family members for which Mr. Peters has shared voting or investment power. (4) Includes 500 units held by immediate family members for which Ms. Place has shared voting or investment power. (5) Includes shares of ONEOK common stock held by members of the family of the committee members or executive officer for which the committee members or executive officer has sole or shared voting or investment power, shares of common stock held in ONEOK's Direct Stock Purchase and Dividend Reinvestment Plan, shares held through ONEOK's Thrift Plan, shares of restricted stock, and shares that the committee member or executive officer had the right to acquire within 60 days of March 1, 2006. For Mr. Kyle and Mr. Skoog includes 219,355 and 87,724 respectively the number of shares of ONEOK common stock which Mr. Kyle and Mr. Skoog had the right to acquire within 60 days after March 1, 2006 (all such shares are issuable upon the exercise of stock options granted under ONEOK's Long-Term Incentive Plan). For Mr. Kyle, Mr. Cordes and Mr. Skoog includes 79,135, 638 and 15,574 respectively, which are held on each person's behalf by the Trustee of the ONEOK Thrift Plan as of March 1, 2006. EQUITY COMPENSATION PLAN INFORMATION Effective November 1, 2001, Northern Plains and NBP Services adopted the Amended and Restated Northern Border Phantom Unit Plan as an incentive to attract and retain employees who are essential to the services provided to us and our subsidiaries. By its terms, the Amended and Restated Northern Border Phantom Unit Plan terminated on December 31, 2004. The Administrative Committee under the plan, which consists of appointees of Northern Plains and NBP Services, will continue to administer the outstanding phantom units, which are based upon the general partner distribution rate. The Administrative Committee has complete authority to determine the time and provisions for settlement of the phantom units. During the duration of a grant, the participant's account is credited with distributions paid with respect to the underlying security. Upon settlement of the phantom units, the participant will receive common units, cash or a combination thereof, as determined by the Administrative Committee. The settlement value of the phantom units is determined by using a value derived from the general partner distribution rate and common unit distribution yield on the settlement date.

NUMBER OF SECURITIES WEIGHTED AVERAGE NUMBER OF UNITS TO BE ISSUED UPON EXERCISE PRICE OF REMAINING EXERCISE OF OUTSTANDING OUTSTANDING AVAILABLE FOR PLAN CATEGORY (1) PHANTOM UNITS PHANTOM UNITS FUTURE ISSUANCE ----------------- ----------------------- ----------------- --------------- Equity Compensation Plans Approved by Unitholders Equity Compensation Plans Not Approved by Unitholders 30,449(2) $42.00 179,500(3)

(1) Under our partnership agreement, the Partnership Policy Committee has the sole authority, without the approval of the unitholders, to adopt employee benefit or incentive plans, or issue common units pursuant to any employee benefit or incentive plan maintained or sponsored by a general partner or its affiliates. (2) Based on the closing price of the common units on December 31, 2005, assuming that all outstanding phantom units were settled in common units as of December 31, 2005. (3) The plan limits the number of grants of phantom units and phantom LP units to an aggregate of 200,000. This assumes all grants are phantom LP units. ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS PROPOSED TRANSACTIONS On February 15, 2006, we announced a series of transactions involving several related parties. The Audit Committee, who determined the fairness of the transactions, engaged independent legal counsel and an independent financial advisor to assist in their determination. Additional information about the proposed transactions is included under Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations-Executive Summary." RELATIONSHIP WITH ONEOK ONEOK owns two of our general partners, Northern Plains and Pan Border, and is able to elect members with a majority of the voting power on the Partnership Policy Committee and the Northern Border Management Committee. In addition, ONEOK owns NBP Services, our administrative service provider. Other relationships include the following: Cash Distributions - ONEOK owns a combined general and limited partner interest in us of 2.71% through Northern Plains and Pan Border. Northern Plains and Pan Border hold a combined 1.65% general partner interest in us. In addition, 66 Northern Plains owns 501,603 of our common units, which represents a 1.06% limited partner interest in us. In 2005, we paid ONEOK total cash distributions of $10.8 million, which included $6.6 million related to their incentive distribution rights. Additional information about our cash distribution policy is included under Item 5, "Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities." Transition Services Agreement - Upon the sale of Northern Plains and NBP Services by CCE Holdings to ONEOK in November 2004, CCE Holdings and ONEOK entered into a transition services agreement. This transition services agreement provided for the continuation of certain services, data applications, systems and infrastructure relied on by Northern Plains and NBP Services in performing under the operating agreements and administrative services agreement. The cost of the transition services was $4.4 million for the full term of the agreement, which expired on May 17, 2005, and was not extended. Operating and Administrative Agreements - Northern Plains provides certain administrative, operating and management services to us and Northern Border Pipeline, Midwestern Gas Transmission and Viking Gas Transmission through operating agreements. We and Northern Border Pipeline, Midwestern Gas Transmission and Viking Gas Transmission are charged for the salaries, benefits and expenses of Northern Plains incurred in connection with the operating agreements. NBP Services provides certain administrative, operating and management services to us and our natural gas gathering and processing and coal slurry pipeline businesses through an administrative services agreement. NBP Services is reimbursed for its direct and indirect costs and expenses. In 2005, 2004 and 2003, the aggregate amount charged by Northern Plains, NBP Services and their affiliates for their services was approximately $52.6 million, $45.8 million and $57.6 million, respectively. In 2005 and 2004, $3.6 million and $0.8 million, respectively, were related to transition services. Transportation Agreements - ONEOK Energy, a subsidiary of ONEOK, became an affiliate of Northern Border Pipeline in November 2004 in connection with ONEOK's purchase of Northern Plains. In 2005, 2% of Northern Border Pipeline's design capacity was contracted on a firm basis with ONEOK Energy. Revenue from ONEOK Energy for 2005 was $7.7 million. As of January 31, 2006, 1% of Northern Border Pipeline's design capacity was contracted on a firm basis with ONEOK Energy for 2006. In addition, ONEOK Energy entered into a precedent agreement for transportation capacity on Northern Border Pipeline's Chicago III Expansion Project for 25 MMcf/d of capacity for five and one-half years. RELATIONSHIP WITH TRANSCANADA Northwest Border, a subsidiary of TransCanada, owns a 0.35% general partner interest in us and appoints one member to the Partnership Policy Committee. In 2005, we paid TransCanada total cash distributions of $2.0 million, which included $1.4 million related to their incentive distribution rights. Additional information about our cash distribution policy is included under Item 5, "Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities." RELATIONSHIP WITH GUARDIAN PIPELINE Northern Plains provides certain administrative, operating and management services to Guardian Pipeline, of which we own a 33-1/3% interest, through an operating agreement. The annual fixed fee charged by Northern Plains for its services was $3.6 million and reimbursement for other services not included in the fixed fee was approximately $0.6 million in 2005. We guarantee the financial risks and benefits resulting from and arising out of Northern Plains' responsibilities and obligations as operator of Guardian Pipeline. CONFLICTS OF INTEREST The Partnership Policy Committee, whose members are designated by our three general partners, establishes our business policies. We also have three representatives on the Northern Border Management Committee, each of whom votes a portion of our 70% interest on the Northern Border Management Committee, with the other 30% interest being voted by a representative of TC PipeLines, which is an affiliate of one of our general partners. 67 Our general partners, which are subsidiaries of ONEOK and TransCanada, and their respective affiliates currently engage or may engage in the businesses in which we engage or in which we may engage in the future. As a result, conflicts of interest may arise between our general partners and their affiliates, and us. If such conflicts arise, the members of the Partnership Policy Committee generally have a fiduciary duty to resolve such conflicts in a manner that is in our best interest. TC PipeLines (a 30% owner of Northern Border Pipeline whose general partner is an affiliate of one of our general partners) and its affiliates are also engaged in interstate natural gas pipeline transportation in the U.S. separate from their interest in Northern Border Pipeline. As a result, conflicts also may arise between TransCanada and its affiliates or TC PipeLines and its affiliates, and Northern Border Pipeline. If such conflicts arise, the representatives on the Northern Border Management Committee generally have a fiduciary duty to resolve such conflicts in a manner that is in the best interest of Northern Border Pipeline. Unless otherwise provided for in a partnership agreement, the laws of Delaware and Texas generally require a general partner of a partnership to adhere to fiduciary duty standards under which it owes its partners the highest duties of good faith, fairness and loyalty. Similar rules apply to persons serving on the Partnership Policy Committee or the Northern Border Management Committee. Because of the competing interests identified above, our partnership agreement and the partnership agreement for Northern Border Pipeline contain provisions that modify certain of these fiduciary duties. For example: - Our partnership agreement states that our general partners, their affiliates and their officers and directors will not be liable for damages to us, our limited partners or their assignees for errors of judgment or for any acts or omissions if the general partners and such other persons acted in good faith. - Our partnership agreement allows our general partners and our Partnership Policy Committee to take into account the interests of other parties in addition to our interests in resolving conflicts of interest. - Our partnership agreement provides that the general partners will not be in breach of their obligations under our partnership agreement or their duties to us or our unitholders if the resolution of a conflict is fair and reasonable to us. The latitude given in our partnership agreement in connection with resolving conflicts of interest may significantly limit the ability of a unitholder to challenge what might otherwise be a breach of fiduciary duty. - Our partnership agreement provides that a purchaser of common units is deemed to have consented to certain conflicts of interest and actions of the general partners and their affiliates that might otherwise be prohibited and to have agreed that such conflicts of interest and actions do not constitute a breach by the general partners of any duty stated or implied by law or equity. - Our Audit Committee will, at the request of a general partner or a member of the Partnership Policy Committee, review conflicts of interest that may arise between a general partner and its affiliates (or the member of the Partnership Policy Committee designated by it), and the unitholders or us. Any resolution of a conflict approved by the Audit Committee is conclusively deemed fair and reasonable to us. - The partnership agreement of Northern Border Pipeline relieves us and TC PipeLines, each of their affiliates and each of their transferees from any duty to offer business opportunities to Northern Border Pipeline, subject to specified exceptions. We are required to indemnify the members of the Partnership Policy Committee and the general partners, their affiliates and their respective officers, directors, employees, agents and trustees to the fullest extent permitted by law against liabilities, costs and expenses incurred by any such person who acted in good faith and in a manner reasonably believed to be in, or (in the case of a person other than one of the general partners) not opposed to, our 68 best interests and with respect to any criminal proceedings, had no reasonable cause to believe the conduct was unlawful. ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES The fees for the years ended December 31, 2005, and 2004 for professional services provided by KPMG LLP were as follows:

FOR THE YEARS ENDED DECEMBER 31, ------------------- 2005 2004 -------- -------- Audit fees $787,235 $895,250 Audit-related fees -- -- Tax fees -- -- All other fees -- -- -------- -------- Total $787,235 $895,250 ======== ========

AUDIT FEES Audit fees include fees for the audit of annual financial statements and internal control over financial reporting, reviews of the related quarterly financial statements and related consents and comfort letters for documents filed with the SEC. AUDIT COMMITTEE POLICIES AND PROCEDURES FOR PRE-APPROVAL OF AUDIT AND NON-AUDIT SERVICES Consistent with SEC policies regarding auditor independence, the Audit Committee is responsible for pre-approving all audit and non-audit services performed by the independent auditor. In addition to its approval of the audit engagement, the Audit Committee takes action at least annually to authorize the performance by the independent auditor of several specific types of services within the categories of audit services, audit-related services, tax services and all other services. Audit services include assurance and related services that are reasonably related to the performance of the audit or review of the financial statements, attestations pursuant to Section 404 of the Sarbanes-Oxley Act, quarterly reviews comfort letters, consents, review of registration statements, accounting research from completed transactions and tax assistance related to the audit services. Audit-related services include due diligence related to potential business acquisitions/dispositions, accounting research and other audit or attest services. Authorized tax services include compliance-related services such as services involving tax filings, as well as consulting services such as tax planning, transaction analysis and opinions. All other services include special investigations to assist the Audit Committee or its counsel and assistance with regulatory activities. Services are subject to pre-approval of the specific engagement if they are outside the specific types of services included in the periodic approvals covering service categories or if they are in excess of specified fee limitations. The Audit Committee delegated pre-approval authority to the Audit Committee chairman. PART IV ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES (A) (1) AND (2) FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULES See "Index to Financial Statements" on page F-1. (A) (3) EXHIBITS #2.1 Contribution Agreement between ONEOK, Inc. and Northern Border Intermediate Limited Partnership dated February 14, 2006. #2.2 Purchase and Sale Agreement by and between ONEOK, Inc. and Northern Border Partners, L.P. dated February 14, 2006. #2.3 Partnership Interest Purchase and Sale Agreement by and between Northern Border Intermediate Limited Partnership and TC PipeLines Intermediate Limited Partnership dated as of December 31, 2005. 69 *3.1 Northern Border Partners, L.P. Certificate of Limited Partnership, Certificate of Amendment dated February 16, 2001, and Certificate of Amendment dated May 20, 2003 (incorporated by reference to Exhibit 3.1 to the Partnership's Form 10-K for the year ended December 31, 2004 (File No. 1-12202) ("2004 Form 10-K")). *3.2 Amended and Restated Agreement of Limited Partnership of Northern Border Partners, L.P. dated October 1, 1993 (incorporated by reference to Exhibit 3.2 to the 2004 Form 10-K). *3.3 Northern Border Intermediate Limited Partnership Certificate of Limited Partnership, Certificate of Amendment dated February 16, 2001, and Certificate of Amendment dated May 20, 2003 (incorporated by reference to Exhibit 3.3 to the 2004 10-K). *3.4 Amended and Restated Agreement of Limited Partnership for Northern Border Intermediate Limited Partnership dated October 1, 1993 (incorporated by reference to Exhibit 3.1 to the Partnership's Form 10-Q for the quarter ended March 31, 2005 (File No. 1-12202) ("March 2005 10-Q")). *4.1 Indenture, dated as of June 2, 2000, between Northern Border Partners, L.P., Northern Border Intermediate Limited Partnership and Bank One Trust Company, N.A., Trustee (incorporated by reference to Exhibit 4.1 to the Partnership's Form 10-Q for the quarter ended June 30, 2000 (File No. 1-12202) ("June 2000 10-Q")). *4.2 First Supplemental Indenture, dated as of September 14, 2000, between Northern Border Partners, L.P., Northern Border Intermediate Limited Partnership and Bank One Trust Company, N.A. (incorporated by reference to Exhibit 4.2 to the Partnership's Form S-4 Registration Statement filed on September 20, 2000, (Registration No. 333-46212) ("NBP Form S-4")). *4.3 Indenture, dated as of March 21, 2001, between Northern Border Partners, L.P. and Northern Border Intermediate Limited Partnership and Bank One Trust Company, N.A., Trustee (incorporated by reference to Exhibit 4.3 to the Partnership's Form 10-K for the year ended December 31, 2001 (File No. 1-12202)). *4.4 Indenture, dated as of August 17, 1999, between Northern Border Pipeline Company and Bank One Trust Company, NA, successor to The First National Bank of Chicago, Trustee. (incorporated by reference to Exhibit No. 4.1 to Northern Border Pipeline Company's Form S-4 Registration Statement filed on October 7, 1999, (Registration No. 333-88577) ("NB Form S-4")). *4.5 Indenture, dated as of September 17, 2001, between Northern Border Pipeline Company and Bank One Trust Company, N.A., Trustee (incorporated by reference to Exhibit 4.2 to Northern Border Pipeline Company's Registration Statement on Form S-4 filed on November 13, 2001, (Registration No. 333-73282) ("2001 NB Form S-4")). *4.6 Indenture, dated as of April 29, 2002, between Northern Border Pipeline Company and Bank One Trust Company, N.A., Trustee (incorporated by reference to Exhibit 4.1 to Northern Border Pipeline Company's Form 10-Q for the quarter ended March 31, 2002 (File No. 333-88577)). *10.1 Northern Border Pipeline Company General Partnership Agreement between Northern Plains Natural Gas Company, Northwest Border Pipeline Company, Pan Border Gas Company, TransCanada Border Pipeline Ltd. and TransCan Northern Ltd., effective March 9, 1978, as amended (incorporated by reference to Exhibit 10.2 to the Partnership's Form S-1 Registration Statement filed on July 16, 1993, (Registration No. 33-66158) ("Form S-1")). *10.2 Form of Seventh Supplement Amending Northern Border Pipeline Company General Partnership Agreement dated September 23, 1993 (incorporated by reference to Exhibit 10.15 to Form S-1). *10.3 Eighth Supplement Amending Northern Border Pipeline Company General Partnership Agreement dated May 21, 1999 (incorporated by reference to Exhibit 10.15 to NB Form S-4). *10.4 Ninth Supplement Amending Northern Border Pipeline Company General Partnership Agreement July 16, 2001 (incorporated by reference to Exhibit 10.37 to 2001 NB Form S-4). *10.5 Tenth Supplement Amending Northern Border Pipeline Company General Partnership Agreement dated March 2, 2005 (incorporated by reference to Exhibit 3.5 to Northern Border Pipeline's Form 10-K for the year ended December 31, 2004 filed on March 14, 2005 (File No. 333-88577)). *10.6 Operating Agreement between Northern Border Pipeline Company and Northern Plains Natural Gas Company, dated February 28, 1980 (incorporated by reference to Exhibit 10.3 to Form S-1). *10.7 Administrative Services Agreement between NBP Services Corporation, Northern Border Partners, L.P. and Northern Border Intermediate Limited Partnership (incorporated by reference to Exhibit 10.4 to Form S-1). *10.8 Revolving Credit Agreement, dated as of May 16, 2005, among Northern Border Partners, L.P., the lenders from time to time party thereto, SunTrust Bank, as administrative agent, Wachovia Bank, National Association, as syndication agent, Harris Nesbit Financing, Inc., Barclays Bank PLC and Citibank, N.A., as 70 co-documentation agents, and SunTrust Capital Markets, Inc. and Wachovia Capital Markets, LLC, as co-lead arrangers and book managers (incorporated by reference to Exhibit 10.1 to the Partnership's current report on Form 8-K filed on May 20, 2005 (File No. 1-12202)). *10.9 First Amendment to the Revolving Credit Agreement effective June 13, 2005, among Northern Border Partners, L.P., the lenders from time to time party thereto, SunTrust Bank, as administrative agent, Wachovia Bank, National Association, as syndication agent and Harris Nesbit Financing, Inc., Barclays Bank PLC and Citibank, N.A., as co-documentation agents (incorporated by reference to Exhibit 10.2 to the Partnership's Form 10-Q for the quarter ended June 30, 2005 (File No. 1-12202)). *10.10 Revolving Credit Agreement, dated as of May 16, 2005, among Northern Border Pipeline Company, the lenders from time to time party thereto, Wachovia Bank, National Association, as administrative agent, SunTrust Bank, as syndication agent, Harris Nesbit Financing, Inc., Barclays Bank PLC and Citibank, N.A., as co-documentation agents, and Wachovia Capital Markets, LLC and SunTrust Capital Markets, Inc., as co-lead arrangers and book managers (incorporated by reference to Exhibit 10.1 to Northern Border Pipeline Company's current report on Form 8-K (File No. 333-88577) filed on May 20, 2005 (File No. 333-88577)). *10.11 Agreement between Northern Plains and Northern Border Intermediate Limited Partnership regarding the costs, expenses and expenditures arising under the operating agreement between Northern Plains and Guardian Pipeline, LLC (incorporated by reference to Exhibit 10.3 to the Partnership's Form 10-Q for the quarter ended March 31, 2004 (File No. 1-12202)). +*10.12 Form of Termination Agreement with ONEOK, Inc. dated as of January 5, 2005 (incorporated by reference to Exhibit 99.1 to the Partnership's current report on Form 8-K filed on January 11, 2005 (File No. 1-12202)). +*10.13 ONEOK, Inc. Equity Compensation Plan (incorporated by reference to Exhibit 10.1 to ONEOK's current report on Form 8-K filed on February 23, 2005 (File No. 1-13643)). +*10.14 ONEOK, Inc. Employee Stock Purchase Plan, as amended February 17, 2005 (incorporated by reference to Exhibit 10.2 to ONEOK's current report on Form 8-K filed on February 23, 2005 (File No. 1-13643)). +*10.15 ONEOK, Inc. 2005 Supplemental Executive Retirement Plan (incorporated by reference to Exhibit 99.2 to the Partnership's current report on Form 8-K filed on January 11, 2005 (File No. 1-12202)). +*10.16 ONEOK, Inc. Long-Term Incentive Plan (incorporated by reference to Exhibit 10(a) to ONEOK's Form 10-K for the year ended December 31, 2001 (File No. 1-13643)). +*10.17 ONEOK, Inc. Form of Restricted Stock Incentive Award pursuant to Long-Term Incentive Plan (incorporated by reference to Exhibit 10.4 to ONEOK's Form 10-Q for the quarterly period ended September 30, 2004 (File No. 1-13643)). +*10.18 ONEOK, Inc. Form of Performance Shares Award pursuant to Long-Term Incentive Plan (incorporated by reference to Exhibit 10.5 to ONEOK's Form 10-Q for the quarterly period ended September 30, 2004 (File No. 1-13643)). +*10.19 ONEOK, Inc. Employee Non-Qualified Deferred Compensation Plan, as amended, dated February 15, 2001 (incorporated by reference to Exhibit 10(g) to ONEOK's Form 10-K for the year ended December 31, 2001(File No. 1-13643)). +*10.20 ONEOK, Inc. Annual Officer Incentive Plan (incorporated by reference to Exhibit 10(f) to ONEOK's Form 10-K for the year ended December 31, 2001 (File No. 1-13643)). +10.21 ONEOK, Inc. Form of Restricted Unit Award Agreement pursuant to Equity Compensation Plan. +10.22 ONEOK, Inc. Form of Performance Unit Award Agreement pursuant to Equity Compensation Plan. *10.23 Operating Agreement between Midwestern Gas Transmission Company and Northern Plains Natural Gas Company dated as of April 1, 2001 (incorporated by reference to Exhibit 10.38 to the Partnership's Form 10-K for the year ended December 31, 2001 (File No. 1-12202)). *10.24 Operating Agreement between Viking Gas Transmission Company and Northern Plains Natural Gas Company dated as of January 17, 2003 (incorporated by reference to Exhibit 10.18 to the Partnership's Form 10-K for the year ended December 31, 2002 (File No. 1-12202)). *10.25 Northern Border Pipeline Company Agreement among Northern Plains Natural Gas Company, Pan Border Gas Company, Northwest Border Pipeline Company, TransCanada Border PipeLine Ltd., TransCan Northern Ltd., Northern Border Intermediate Limited Partnership, Northern Border Partners, L.P., and the Management Committee of Northern Border Pipeline, dated as of March 17, 1999 (incorporated by reference to Exhibit 10.21 to the Partnership's Form 10-K/A for the year ended December 31, 1998 (File No. 1-12202)). 12.1 Statement re computation of ratios. 71 21 List of subsidiaries. 23.1 Consent of KPMG LLP. 31.1 Rule 13a-14(a)/15d-14(a) certification of principal executive officer. 31.2 Rule 13a-14(a)/15d-14(a) Certification of principal financial officer. 32.1 Section 1350 certification of principal executive officer. 32.2 Section 1350 certification of principal financial officer. +*99.1 Northern Border Phantom Unit Plan (incorporated by reference to Exhibit 99.1 to Amendment No. 1 to the Partnership's Form S-8, Registration Statement filed on November 15, 2000 (Registration No. 333-66949)). * Indicates exhibits incorporated by reference as indicated; all other exhibits are filed herewith. + Management contract, compensatory plan or arrangement. # The Partnership agrees to furnish supplementally to the Securities and Exchange Commission, upon request, any schedules and exhibits to this agreement, as set forth in the Table of Contents of the agreement, that have not been filed herewith pursuant to Item 601(b)(2) of Regulation S-K. The total amount of securities of the Partnership authorized under any instrument with respect to long-term debt not filed as an exhibit does not exceed 10% of the total assets of the Partnership and its subsidiaries on a consolidated basis. The Partnership agrees, upon request of the Securities and Exchange Commission, to furnish copies of any or all of such instruments to the Securities and Exchange Commission. 72 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 6th day of March, 2006. NORTHERN BORDER PARTNERS, L.P. (A Delaware Limited Partnership) By: William R. Cordes ------------------------------------ William R. Cordes Chief Executive Officer Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons in the capacities and on the dates indicated.

SIGNATURE TITLE DATE --------- ----- ---- /s/ William R. Cordes Chief Executive Officer and Partnership Policy March 6, 2006 ----------------------------- Committee Member William R. Cordes (Principal Executive Officer) /s/ David L. Kyle Chairman of the Partnership Policy Committee March 6, 2006 ----------------------------- David L. Kyle /s/ Paul E. Miller Partnership Policy Committee Member March 6, 2006 ----------------------------- Paul E. Miller /s/ Jerry L. Peters Chief Financial and Accounting Officer March 6, 2006 ----------------------------- Jerry L. Peters (Principal Financial and Accounting Officer)

73 NORTHERN BORDER PARTNERS, L.P. ANNUAL REPORT ON FORM 10-K INDEX TO FINANCIAL STATEMENTS

Page No. ----------- Consolidated Financial Statements Report of Independent Registered Public Accounting Firm........ F-2 Consolidated Balance Sheet - December 31, 2005, and 2004....... F-3 Consolidated Statement of Income - Years Ended December 31, 2005, 2004 and 2003................ F-4 Consolidated Statement of Comprehensive Income - Years Ended December 31, 2005, 2004 and 2003................ F-5 Consolidated Statement of Cash Flows - Years Ended December 31, 2005, 2004 and 2003................ F-6 Consolidated Statement of Changes in Partners' Equity - Years Ended December 31, 2005, 2004 and 2003................ F-7 Notes to Consolidated Financial Statements..................... F-8 to F-29 Financial Statements Schedule Report of Independent Registered Public Accounting Firm on Schedule.................................................... S-1 Schedule II - Valuation and Qualifying Accounts................ S-2

F-1 REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM Northern Border Partners, L.P.: We have audited the accompanying consolidated balance sheets of Northern Border Partners, L.P. and subsidiaries (the Company) as of December 31, 2005 and 2004, and the related consolidated statements of income, comprehensive income, cash flows, and changes in partners' equity for each of the years in the three-year period ended December 31, 2005. These consolidated financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Northern Border Partners, L.P. and subsidiaries as of December 31, 2005 and 2004, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2005, in conformity with U. S. generally accepted accounting principles. As discussed in note 5 to the consolidated financial statements, the Partnership adopted Statement of Financial Accounting Standards (SFAS) No. 143, Accounting for Asset Retirement Obligations, in 2003. We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of Northern Border Partners, L.P.'s internal control over financial reporting as of December 31, 2005, based on criteria established in Internal Control--Integrated Framework, issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report thereon dated March 2, 2006 expressed an unqualified opinion on management's assessment of, and the effective operation of, internal control over financial reporting. Omaha, Nebraska March 2, 2006 F-2 NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEET

DECEMBER 31, ----------------------- 2005 2004 ---------- ---------- (In thousands) ASSETS Current assets: Cash and cash equivalents $ 43,090 $ 33,980 Accounts receivable, net of allowance for doubtful accounts of $18 and $9,175 in 2005 and 2004, respectively 81,451 68,930 Related party receivables 1,397 1,077 Materials and supplies, at cost 7,273 5,654 Prepaid expenses and other 5,211 5,650 Derivative financial instruments -- 1,996 ---------- ---------- Total current assets 138,422 117,287 ---------- ---------- Property, plant and equipment: Interstate natural gas pipeline 2,668,645 2,630,713 Natural gas gathering and processing 284,199 265,484 Coal slurry pipeline 47,876 47,402 ---------- ---------- Total property, plant and equipment 3,000,720 2,943,599 Less: Accumulated provision for depreciation and amortization 1,082,210 1,002,041 ---------- ---------- Property, plant and equipment, net 1,918,510 1,941,558 ---------- ---------- Investments and other assets: Investment in unconsolidated affiliates 290,756 273,202 Goodwill 152,782 152,782 Derivative financial instruments -- 2,555 Regulatory assets 14,153 12,308 Other 13,143 14,998 ---------- ---------- Total investments and other assets 470,834 455,845 ---------- ---------- Total assets $2,527,766 $2,514,690 ========== ========== LIABILITIES AND PARTNERS' EQUITY Current liabilities: Current maturities of long-term debt $ 2,194 $ 5,126 Derivative financial instruments 4,571 -- Accounts payable 46,626 30,704 Related party payables 7,080 6,293 Accrued taxes other than income 33,081 32,563 Accrued interest 17,446 16,530 ---------- ---------- Total current liabilities 110,998 91,216 ---------- ---------- Long-term debt, net of current maturities 1,352,777 1,325,232 ---------- ---------- Minority interests in partners' equity 274,510 290,142 ---------- ---------- Reserves and deferred credits: Deferred income taxes 10,311 7,186 Derivative financial instruments 2,362 840 Regulatory liabilities 2,591 2,232 Other 8,628 8,508 ---------- ---------- Total reserves and deferred credits 23,892 18,766 ---------- ---------- Commitments and contingencies (Note 13) Partners' equity: General Partners 15,351 15,603 Common Units, 46,397,214 units outstanding at December 31, 2005, and 2004 752,191 764,550 Accumulated other comprehensive income (loss) (1,953) 9,181 ---------- ---------- Total partners' equity 765,589 789,334 ---------- ---------- Total liabilities and partners' equity $2,527,766 $2,514,690 ========== ==========

The accompanying notes are an integral part of these consolidated financial statements. F-3 NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES CONSOLIDATED STATEMENT OF INCOME

YEARS ENDED DECEMBER 31, ------------------------------ 2005 2004 2003 -------- -------- -------- (In thousands except per unit amounts) Operating revenue $678,560 $590,383 $550,948 -------- -------- -------- Operating expenses Product purchases 167,257 103,213 80,774 Operations and maintenance 129,950 111,142 127,623 Depreciation and amortization, including impairment charges of $219,080 in 2003 86,010 86,431 299,791 Taxes other than income 38,575 36,212 35,443 -------- -------- -------- Operating expenses 421,792 336,998 543,631 -------- -------- -------- Operating income 256,768 253,385 7,317 -------- -------- -------- Interest expense Interest expense 87,690 77,346 79,159 Interest expense capitalized (787) (403) (179) -------- -------- -------- Interest expense, net 86,903 76,943 78,980 -------- -------- -------- Other income (expense) Allowance for equity funds used during construction 527 117 331 Equity earnings of unconsolidated affiliates 24,736 18,015 18,815 Other income 3,552 3,654 5,992 Other expense (707) (2,138) (1,459) -------- -------- -------- Other income, net 28,108 19,648 23,679 -------- -------- -------- Minority interest in net income 45,674 50,033 44,460 -------- -------- -------- Income (loss) from continuing operations before income taxes 152,299 146,057 (92,444) Income taxes 5,792 5,136 4,705 -------- -------- -------- Income (loss) from continuing operations 146,507 140,921 (97,149) Discontinued operations, net of tax 506 3,799 9,338 Cumulative effect of change in accounting principle, net of tax -- -- (643) -------- -------- -------- Net income (loss) to partners $147,013 $144,720 $(88,454) ======== ======== ======== Calculations of limited partners' interest in net income (loss): Net income (loss) to partners $147,013 $144,720 $(88,454) Less: General partners' interest in net income (loss) 10,900 10,854 5,969 -------- -------- -------- Limited partners' interest in net income (loss) $136,113 $133,866 $(94,423) ======== ======== ======== Limited partners' per unit net income (loss): Income (loss) from continuing operations $ 2.92 $ 2.81 $ (2.27) Discontinued operations, net of tax 0.01 0.08 0.20 Cumulative effect of change in accounting principle, net of tax -- -- (0.01) -------- -------- -------- Net income (loss) $ 2.93 $ 2.89 $ (2.08) ======== ======== ======== Number of units used in computation 46,397 46,397 45,370 ======== ======== ========

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

YEARS ENDED DECEMBER 31, ------------------------------ 2005 2004 2003 -------- -------- -------- (In thousands) Net income (loss) to partners $147,013 $144,720 $(88,454) Other comprehensive income: Changes associated with current period hedging transactions (10,560) 5,263 (4,383) Changes associated with current period foreign currency translation (574) (1,558) 2,345 -------- -------- --------- Total comprehensive income (loss) $135,879 $148,425 $(90,492) ======== ======== ========

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

YEARS ENDED DECEMBER 31, --------------------------------- 2005 2004 2003 --------- --------- --------- (In thousands) CASH FLOW FROM OPERATING ACTIVITIES Net income (loss) to partners $ 147,013 $ 144,720 $ (88,454) --------- --------- ---------- Adjustments to reconcile net income (loss) to partners to net cash provided by operating activities: Depreciation and amortization, including impairment charges of $219,080 in 2003 86,361 87,203 301,977 Minority interests in net income 45,674 50,033 44,460 Non-cash gains from risk management activities (106) (460) (209) Provisions for regulatory refunds -- -- 261 Regulatory refunds paid -- -- (10,261) Cumulative effect of change in accounting principle -- -- 643 Gain on sale of gathering and processing assets -- (6,621) (4,872) Equity earnings in unconsolidated affiliates (24,736) (18,015) (18,928) Distributions received from unconsolidated affiliates 16,440 12,536 17,672 Allowance for equity funds used during construction (527) (117) (331) Reserves and deferred credits (340) (1,337) 3,062 Changes in components of working capital 3,673 (19,243) (18,592) Other (6,080) (4,041) (1,768) --------- --------- --------- Total adjustments 120,359 99,938 313,114 --------- --------- --------- Net cash provided by operating activities 267,372 244,658 224,660 --------- --------- --------- CASH FLOW FROM INVESTING ACTIVITIES Capital expenditures for property, plant and equipment (59,882) (43,477) (30,282) Acquisition of businesses -- -- (123,194) Sale of gathering and processing assets -- 22,685 40,250 Investment in unconsolidated affiliates (8,537) (84) (3,514) --------- --------- --------- Net cash used in investing activities (68,419) (20,876) (116,740) --------- --------- --------- CASH FLOW FROM FINANCING ACTIVITIES Cash distributions: General and limited partners (159,624) (159,624) (155,173) Minority interests (60,870) (61,690) (46,194) Equity contributions from minority interests -- 61,500 -- Issuance of partnership interests, net -- (40) 102,203 Issuance of long-term debt 165,000 259,000 342,000 Retirement of long-term debt (130,182) (327,521) (361,129) Proceeds upon termination of derivatives (2,785) 7,575 12,250 Debt reacquisition costs -- (4,897) -- Long-term debt financing costs (1,382) -- (671) --------- --------- --------- Net cash used in financing activities (189,843) (225,697) (106,714) --------- --------- --------- Net change in cash and cash equivalents 9,110 (1,915) 1,206 Cash and cash equivalents at beginning of year 33,980 35,895 34,689 --------- --------- --------- Cash and cash equivalents at end of year $ 43,090 $ 33,980 $ 35,895 ========= ========= ========= Changes in components of working capital: Accounts receivable (12,840) (12,992) (3,135) Materials and supplies, prepaid expenses and other (1,180) 3,355 (3,833) Accounts payable 16,260 (10,065) (8,525) Accrued taxes other than income 518 (1,145) 437 Accrued interest 915 1,604 (3,536) --------- --------- --------- Total $ 3,673 $ (19,243) $ (18,592) ========= ========= =========

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

ACCUMULATED OTHER TOTAL GENERAL COMMON COMPREHENSIVE PARTNERS' PARTNERS UNITS INCOME (LOSS) EQUITY -------- --------- ------------- --------- (In thousands) Partners' equity at December 31, 2002 $ 18,730 $ 917,791 $ 7,514 $ 944,035 Net income (loss) to partners 5,969 (94,423) -- (88,454) Changes associated with current period hedging transactions -- -- (4,383) (4,383) Changes associated with current period foreign currency translation -- -- 2,345 2,345 Issuance of partnership interests, net (2,587,500 common units) 2,044 100,159 -- 102,203 Distributions paid (10,841) (144,332) -- (155,173) -------- --------- -------- --------- Partners' equity at December 31, 2003 15,902 779,195 5,476 800,573 Net income to partners 10,854 133,866 -- 144,720 Changes associated with current period hedging transactions -- -- 5,263 5,263 Changes associated with current period foreign currency translation -- -- (1,558) (1,558) Issuance of partnership interests, net (1) (39) -- (40) Distributions paid (11,152) (148,472) -- (159,624) -------- --------- -------- --------- Partners' equity at December 31, 2004 15,603 764,550 9,181 789,334 Net income to partners 10,900 136,113 -- 147,013 Changes associated with current period hedging transactions -- -- (10,560) (10,560) Changes associated with current period foreign currency translation -- -- (574) (574) Distributions paid (11,152) (148,472) -- (159,624) -------- --------- -------- --------- Partners' equity at December 31, 2005 $ 15,351 $ 752,191 $ (1,953) $ 765,589 ======== ========= ============= =========

The accompanying notes are an integral part of these consolidated financial statements. F-7 NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 1. ORGANIZATION AND MANAGEMENT Northern Border Partners, L.P., through a subsidiary limited partnership, Northern Border Intermediate Limited Partnership, both Delaware limited partnerships, collectively referred to herein as the Partnership, owns a 70% general partner interest in Northern Border Pipeline Company (Northern Border Pipeline). The remaining 30% general partner interest in Northern Border Pipeline is owned by TC PipeLines Intermediate Limited Partnership (TC PipeLines). Crestone Energy Ventures, L.L.C. (Crestone Energy Ventures); Bear Paw Energy, LLC (Bear Paw Energy); Border Midstream Services, Ltd. (Border Midstream); Midwestern Gas Transmission Company (Midwestern Gas Transmission); Viking Gas Transmission Company (Viking Gas Transmission) and Black Mesa Pipeline, Inc. (Black Mesa) are wholly-owned subsidiaries of the Partnership. In this report, references to "we," "us," "our" or the "Partnership" collectively refer to Northern Border Partners, L.P. and our subsidiary, Northern Border Intermediate Limited Partnership and its subsidiaries. Northern Plains Natural Gas Company, LLC (Northern Plains), a wholly-owned subsidiary of ONEOK, Inc. (ONEOK), Pan Border Gas Company, LLC (Pan Border), a wholly-owned subsidiary of Northern Plains, and Northwest Border Pipeline Company (Northwest Border), a wholly-owned subsidiary of TransCanada PipeLines Limited, which is a subsidiary of TransCanada Corporation and an affiliate of TC PipeLines, serve as our General Partners and collectively own a 2% general partner interest. Northern Plains and Pan Border hold an aggregate 1.65% general partner interest and Northwest Border holds a 0.35% general partner interest. Northern Plains also owns common units representing a 1.1% limited partner interest. We are managed under the direction of the Partnership Policy Committee consisting of one person appointed by each General Partner. The members appointed by Northern Plains, Pan Border and Northwest Border have 50%, 32.5% and 17.5%, respectively, of the voting interest on the Partnership Policy Committee. In November 2004, ONEOK purchased Northern Plains, Pan Border and NBP Services LLC (NBP Services) from CCE Holdings, LLC (CCE Holdings). CCE Holdings, a joint venture between Southern Union Company and GE Commercial Finance Energy Financial, purchased Northern Plains, Pan Border and NBP Services as part of its acquisition of CrossCountry Energy, LLC (CrossCountry) from Enron Corp. On March 31, 2004, Enron Corp. (Enron) transferred its ownership interest in Northern Plains, Pan Border, and NBP Services to CrossCountry. In addition, CrossCountry and Enron entered into a transition services agreement pursuant to which Enron would provide to CrossCountry, on an interim, transitional basis, various services, including but not limited to (i) information technology services, (ii) accounting system usage rights and administrative support and (iii) payroll, employee benefits and administrative services. In turn, these services are provided to us through Northern Plains and NBP Services. As part of the closing of its purchase of Northern Plains, Pan Border, and NBP Services, 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. We have entered into an administrative services agreement with NBP Services, a wholly-owned subsidiary of ONEOK. NBP Services provides certain administrative, operating and management services to us and our gas gathering and processing and coal slurry businesses and is reimbursed for its direct and indirect costs and expenses. The day-to-day management of Northern Border Pipeline's, Midwestern Gas Transmission's and Viking Gas Transmission's affairs is the responsibility of Northern Plains, as defined by their respective operating agreements with Northern Plains. Northern Border Pipeline, Midwestern Gas Transmission and Viking Gas Transmission are charged for the salaries, benefits and expenses of Northern Plains. Northern Plains and NBP Services also utilize their affiliates for management services, including those provided through the Northern Border Transition Services Agreement. For the years ended December 31, 2005, 2004 and 2003, charges from NBP Services, Northern Plains and their affiliates totaled approximately $52.6 million, $45.8 million and $57.6 million, respectively. F-8 Northern Border Pipeline is a Texas general partnership formed in 1978. Northern Border Pipeline owns a 1,249-mile natural gas transmission pipeline system extending from the United States-Canadian border near Port of Morgan, Montana, to a terminus near North Hayden, Indiana. Northern Border Pipeline is managed by a Management Committee that includes three representatives from the Partnership (one representative appointed by each of our General Partners) and one representative from TC PipeLines. Our representatives selected by Northern Plains, Pan Border and Northwest Border have 35%, 22.75% and 12.25%, respectively, of the voting interest on the Northern Border Pipeline Management Committee. The representative designated by TC PipeLines votes the remaining 30% interest. Midwestern Gas Transmission system consists of a 350-mile interstate natural gas pipeline extending from Portland, Tennessee to Joliet, Illinois. Midwestern Gas Transmission's pipeline system connects with multiple pipeline systems, including Northern Border Pipeline. On January 17, 2003, we acquired Viking Gas Transmission (see Note 3). The Viking Gas Transmission system is a 578-mile interstate natural gas pipeline extending from the United States-Canadian border near Emerson, Manitoba to Marshfield, Wisconsin. Viking Gas Transmission connects with multiple pipeline systems. Bear Paw Energy has extensive natural gas gathering, processing and fractionation operations in the Williston Basin in Montana, North Dakota and Saskatchewan as well as gas gathering operations in the Powder River Basin in Wyoming. In the Williston Basin, Bear Paw Energy has over 3,500 miles of gathering pipelines and five processing plants with 94 million cubic feet per day of capacity. Bear Paw Energy has approximately 420 miles of high and low pressure gathering pipelines and approximately 396,000 acres of dedicated reserves in the Powder River Basin. Border Midstream previously owned the Mazeppa and Gladys gas processing plants, gas gathering systems and an undivided minority interest in the Gregg Lake/Obed Pipeline. In June 2003, we sold our Gladys and Mazeppa processing plants and related gas gathering facilities. Effective December 1, 2004, we sold our undivided minority interest in the Gregg Lake/Obed Pipeline (see Note 3). We own a 49% common membership interest in Bighorn Gas Gathering, L.L.C. (Bighorn); a 37% interest in Fort Union Gas Gathering, L.L.C. (Fort Union); a 35% interest in Lost Creek Gathering, L.L.C. (Lost Creek); and a 33-1/3% interest in Guardian Pipeline, L.L.C. (Guardian Pipeline). We acquired our interest in Guardian Pipeline in January 2003 (see Note 3). Collectively, Bighorn, Fort Union and Lost Creek own over 430 miles of gas gathering facilities in Wyoming. The gathering facilities interconnect to the interstate gas pipeline grid serving gas markets in the Rocky Mountains, the Midwest and California. Guardian Pipeline is a 143-mile interstate natural gas pipeline system that transports natural gas from Joliet, Illinois to a point west of Milwaukee, Wisconsin. Black Mesa owns a 273-mile, 18-inch diameter coal slurry pipeline that originates at a coal mine in Kayenta, Arizona and ends at the 1,500 megawatt Mohave Generating Station located in Laughlin, Nevada. On December 31, 2005, we shut down our coal slurry pipeline operation (see Note 13). F-9 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES PRINCIPLES OF CONSOLIDATION AND USE OF ESTIMATES The consolidated financial statements include the assets, liabilities and results of operations for our majority-owned subsidiaries. We operate through a subsidiary limited partnership of which the Partnership is the sole limited partner and our General Partners are the sole general partners. The 30% ownership of Northern Border Pipeline by TC PipeLines is accounted for as a minority interest. All significant intercompany balances and transactions have been eliminated in consolidation. The preparation of financial statements in conformity with U.S. generally accepted accounting principles (U.S. GAAP) requires management to make assumptions and use estimates that affect the reported amount of assets, liabilities, revenue and expenses as well as the disclosure of contingent assets and liabilities during the reporting period. Actual results could differ from these estimates if the underlying assumptions are incorrect. GOVERNMENT REGULATION Our interstate pipelines are subject to regulation by the Federal Energy Regulatory Commission (FERC). These companies' 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 reflected on the balance sheet as regulatory assets. We continually assess the potential recovery of the regulatory assets based on such factors as regulatory changes and the impact of competition to determine the probability of future recoverability of these assets. We believe the recovery of the existing regulatory assets is probable. If future recovery ceases to be probable, we would be required to write off the regulatory assets at that time. At December 31, 2005 and 2004, we have reflected regulatory assets, which are currently being recovered or are expected to be recovered from their shippers, of approximately $14.2 million and $12.3 million, respectively. The companies are recovering the regulatory assets from their shippers over varying time periods up to 44 years. The following table presents a summary of regulatory assets, net of amortization, at December 31, 2005 and 2004.

DECEMBER 31, ----------------- 2005 2004 ------- ------- (In thousands) Fort Peck lease option $ 4,402 $ 1,887 Unamortized loss on reacquired debt 1,503 2,630 Pipeline extension project 7,106 7,290 Other 1,142 501 ------- ------- Total regulatory assets $14,153 $12,308 ======= =======

Our regulatory liabilities are related to the incremental costs of removal upon retirement of an asset and represent revenue collected for asset removal costs that we expect to incur in the future. These are costs incurred in the normal course of business and are not related to asset retirement obligations. As of December 31, 2005 and 2004, we reflected regulatory liabilities of $2.6 million and $2.2 million, respectively. Although Northern Border Pipeline is a general partnership, Northern Border Pipeline's tariff establishes the method of accounting for and calculating income taxes and requires Northern Border Pipeline to reflect in its financial records the income taxes, which would have been paid or accrued if Northern Border Pipeline were organized during the period as a corporation. As a result, for purposes of determining transportation rates in calculating the return allowed by the FERC, partners' capital and rate base are reduced by the amount equivalent to the net accumulated deferred income taxes. Such amounts were approximately $360 million and $355 million at December 31, 2005 and 2004, respectively, and are primarily related to accelerated depreciation and other plant-related differences. 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 due to the short maturity of these investments. F-10 REVENUE RECOGNITION Our interstate natural gas pipelines transport gas for shippers under tariffs regulated by the FERC. For the interstate natural gas pipeline segment, we recognize revenue according to each transportation contract for transportation service that is provided to our customers. Customers with firm service transportation agreements pay a reservation fee for capacity on our pipelines, known as a demand charge, regardless of whether the shipper actually utilizes its reserved capacity. Firm service transportation customers also pay a fee based on the volume of natural gas transported. Customers with interruptible service transportation agreements may utilize available capacity on our pipelines; however, service is subject to interruption if capacity is required for customers with firm transportation agreements. Interruptible service customers are assessed a fee based only on the volume of natural gas transported. The interstate pipelines do not own the gas that they transport, and therefore do not assume the related natural gas commodity risk. For the gas gathering and processing segment, operating revenue is recorded when gas is processed in or transported through company facilities. Operating revenue of the natural gas gathering and processing segment is derived primarily from percentage-of-proceeds and fee-based contracts. Under percentage-of-proceeds contracts, we retain a percentage of the commodities that we gather and process in exchange for our services. We then sell the natural gas and natural gas liquids we retain in the open market. Product purchases reflect the amounts we paid to producers for raw natural gas. The gas gathering and processing segment also receives certain cash payments from customers in advance for gathering services to be provided in the future. These cash payments are deferred and recognized into operating revenues by using a percentage based on the depletion of natural gas reserves associated with the gathering system. Black Mesa's operating revenue is derived from a pipeline transportation agreement that expired at the end of 2005 (see Note 13). Black Mesa's revenue is recognized based on a contracted demand payment, actual tons of coal transported and direct reimbursement of certain other expenses. Accounts receivable from customers are reviewed regularly for collectibility. An allowance for doubtful accounts is recorded in situations where collectibility is not reasonably assured. INCOME TAXES We are not a taxable entity for federal income tax purposes. As such, we do not directly pay federal income tax. Our taxable income or loss, which may vary substantially from the net income or loss reported in the consolidated statement of income, is includable in the federal income tax returns of each partner. The aggregate difference in the basis of our net assets for financial and income tax purposes cannot be readily determined as we do not have access to all information about each partner's tax attributes related to us. Our corporate subsidiaries are required to pay federal and state income taxes. Income taxes are accounted for under the asset and liability method. Deferred income tax assets and liabilities are recognized by these entities for the future tax consequences attributable to differences between the financial statement carrying amount of existing assets and liabilities and their respective tax bases and operating loss carry forwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. Except for the companies whose accounting policies conform to SFAS No. 71, the effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. For the companies whose accounting policies conform to SFAS No. 71, the effect on deferred tax assets and liabilities of a change in tax rates is recorded as regulatory assets and regulatory liabilities in the period that includes the enactment date. PROPERTY, PLANT AND EQUIPMENT AND RELATED DEPRECIATION AND AMORTIZATION Property, plant and equipment are stated at original cost. During periods of construction, regulated entities are permitted to capitalize an allowance for funds used during construction (AFUDC), which represents the estimated costs of funds used for construction purposes. Property, plant and equipment on the consolidated balance sheet include construction work in progress of $27.9 million and $13.8 million at December 31, 2005 and 2004, respectively. The original cost of utility property retired is charged to accumulated depreciation and amortization, net of salvage and cost of removal. For utility property, no retirement gain or loss is included in income except in the case of retirements or sales of entire operating units. Maintenance and repairs are charged to operations in the period incurred. F-11 For utility property, the provision for depreciation and amortization is an integral part of the interstate pipelines' FERC tariffs. The effective depreciation rate applied to the interstate transmission pipelines' plant ranges from 1.9% to 2.25%. Composite rates are applied to all other functional groups of utility property having similar economic characteristics. The effective depreciation rate applied to natural gas gathering and processing assets ranges from 5% to 33%. The effective depreciation rate applied to coal slurry assets ranges from 1.87% to 20%. FOREIGN CURRENCY TRANSLATION For our Canadian subsidiary, Border Midstream, asset and liability accounts are translated from its functional currency (the Canadian dollar) at year-end rates of exchange and revenue and expenses are translated at average exchange rates prevailing during the year. Translation adjustments are included as a separate component of other comprehensive income and partners' equity. Currency transaction gains and losses, which result when Border Midstream pays Canadian dollars to us, are recorded in other income (expense) and discontinued operations on the consolidated statement of income. During the years ended December 31, 2005, 2004 and 2003, we recorded currency transaction gains of $0.6 million, $2.2 million and $6.0 million, respectively. GOODWILL The excess of cost over fair value of the net assets acquired in business acquisitions is accounted for as goodwill. We account for goodwill according to SFAS No. 142, "Goodwill and Other Intangible Assets." Among other things, SFAS No. 142 requires entities to perform annual impairment tests by applying a fair-value-based analysis on the goodwill in each reporting segment. EQUITY METHOD OF ACCOUNTING We account for our investments, which we do not control, by the equity method of accounting. Under this method, an investment is carried at its acquisition cost, plus the equity in undistributed earnings or losses since acquisition. NATURAL GAS IMBALANCES Natural gas imbalances occur when the actual amount of natural gas delivered from or received by a pipeline system or storage facility differs from the contractual amount of natural gas to be delivered or received. Imbalances due to or from shippers and operators are valued at an appropriate index price. Imbalances are settled in cash or made up in-kind, subject to the terms of the pipelines' tariffs. Imbalances due from others are reported on the balance sheet as accounts receivable. Imbalances owed to others are reported on the balance sheet as accounts payable. In addition, all imbalances are classified as current. RISK MANAGEMENT We use financial instruments in the management of our interest rate and commodity price exposure. A control environment has been established which includes policies and procedures for risk assessment and the approval, reporting and monitoring of financial instrument activities. We do not use these instruments for trading purposes. SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities," as amended by SFAS No. 137 and SFAS No. 138, requires that every derivative instrument (including certain derivative instruments embedded in other contracts) be recorded on the balance sheet as either an asset or liability measured at its fair value. We determine the fair value of a derivative instrument by the present value of its future cash flows based on market prices from third party sources. We record changes in the derivative's fair value in the current period earnings unless specific hedge accounting criteria are met. 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 us to formally document, designate and assess the effectiveness of transactions that receive hedge accounting. See Note 9 for a discussion of our derivative instruments and hedging activities. UNAMORTIZED DEBT PREMIUM, DISCOUNT AND EXPENSE We amortize premiums, discounts and expenses incurred in connection with the issuance of long-term debt consistent with the terms of the respective debt instrument. OPERATING LEASES We have non-cancelable operating leases on office space, pipeline equipment, rights-of-way and vehicles. We record rent expense over the lease term as it becomes payable. If operating leases include escalating rental payments, we determine the cumulative rental payments anticipated and recognize rent expense on a straight-line basis over the term of the lease. F-12 CONTINGENCIES Our accounting for contingencies covers a variety of business activities including contingencies for legal exposures and environmental exposures. We accrue these contingencies when our assessments indicate that it is probable that a liability has been incurred or an asset will not be recovered and an amount can be reasonably estimated in accordance with SFAS No. 5, "Accounting for Contingencies." We base our estimates on currently available facts and our estimates of the ultimate outcome or resolution. Actual results may differ from our estimates resulting in an impact, positive or negative, on earnings. IMPAIRMENT OF LONG-LIVED ASSETS We assess our long-lived assets for impairment based on SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets." A long-lived asset is tested for impairment whenever events or changes in circumstances indicate that its carrying amount may exceed its fair value. Fair values are based on the sum of the undiscounted future cash flows expected to result from the use and eventual disposition of the assets. RECLASSIFICATIONS Certain reclassifications have been made to the consolidated financial statements for prior years to conform to the current year presentation. 3. BUSINESS ACQUISITIONS AND DISPOSITIONS On January 17, 2003, we acquired all of the common stock of Viking Gas Transmission, including a one-third interest in Guardian Pipeline, for approximately $162 million, which included the assumption of $40 million of debt. We have accounted for the acquisition using the purchase method of accounting and accordingly, operations of Viking Gas Transmission have been included since the date of acquisition. The purchase price has been allocated based upon the estimated fair value of the assets and liabilities acquired as of the acquisition date. The investment in Guardian Pipeline, is reflected in investments in unconsolidated affiliates on the consolidated balance sheet. The following is a summary of the effects of the acquisition on our consolidated financial position as of December 31, 2003:

DECEMBER 31, 2003 -------------- (In thousands) Current assets $ 8,804 Property, plant and equipment 127,619 Investments in unconsolidated affiliates 27,600 Other assets 5,035 Current liabilities (5,559) Long-term debt, including current maturities (40,025) Other liabilities (280) -------- $123,194 ========

Border Midstream sold its undivided minority interest in the Gregg Lake/Obed Pipeline (Gregg Lake/Obed) for $14.0 million, effective December 1, 2004. In June 2003, Border Midstream sold its Gladys and Mazeppa processing plants and related gas gathering facilities located in Alberta, Canada for approximately $40.3 million. Operating revenues, operating expenses and other income and expense have been classified as discontinued operations. Operating revenues for discontinued operations for the years ended December 31, 2004 and 2003, were $3.0 million and $9.9 million, respectively. No operating revenues were recognized in 2005. Discontinued operations on the accompanying consolidated statement of income consists of the following: F-13

DECEMBER 31, ------------------------- 2005 2004 2003 ------ ------- ------ (In thousands) Operating income (loss) $ (58) $ 2,248 $3,259 Other income (expense) 1,319 (540) 1,747 Gain on sale of assets -- 5,026 4,056 Income tax (expense) benefit (755) (2,935) 276 ------ ------- ------ Income for discontinued operations $ 506 $ 3,799 $9,338 ====== ======= ======

4. GOODWILL AND ASSET IMPAIRMENT At December 31, 2005 and 2004, our balance sheet included goodwill of approximately $339 million and $334 million, respectively. Of the total goodwill, approximately $186 million and $182 million were recorded in our investment in unconsolidated affiliates at December 31, 2005 and 2004, respectively. We have selected the fourth quarter to perform our annual impairment testing unless conditions indicate earlier testing is needed. If testing indicates an impairment of goodwill exists in a reporting segment, the carrying value of tangible assets in that segment is also tested for impairment under SFAS No. 144. During 2003, due to lower throughput volumes experienced and anticipated in our wholly owned subsidiaries in our natural gas gathering and processing business segment, we accelerated our annual impairment test under SFAS No. 142 from the fourth quarter to the third quarter for this segment. We engaged the services of an outside independent consultant to assist in the determination of fair value, as defined by SFAS No. 142, for purposes of computing the amount of the goodwill impairment. Upon the determination of the existence of goodwill impairment, we further analyzed, under SFAS No. 144, the carrying value of the tangible assets in our wholly owned subsidiaries in our natural gas gathering and processing business segment to determine the impairment attributed to the tangible assets. We recorded total impairment charges of $219.1 million in the third quarter of 2003. This was comprised of $76.0 million related to the tangible assets in the Powder River Basin and $143.1 million for the goodwill related to the natural gas gathering and processing business segment. Beginning October 1, 2003, the estimated depreciable life of our assets in the Powder River Basin was reduced from 30 years to 15 years to reflect the results of the analysis performed. Changes in the carrying amount of goodwill for the years ended December 31, 2005 and 2004, are summarized as follows:

INTERSTATE NATURAL GAS NATURAL GAS GATHERING & COAL SLURRY PIPELINE PROCESSING PIPELINE TOTAL ----------- ----------- ----------- -------- (In thousands) Balance at December 31, 2003 $70,399 $255,567 $8,378 $334,344 Impairment losses -- -- -- -- ------- -------- ------ -------- Balance at December 31, 2004 70,399 255,567 8,378 334,344 Impairment losses -- -- -- -- Goodwill acquired -- 4,196 -- 4,196 ------- -------- ------ -------- Balance at December 31, 2005 $70,399 $259,763 $8,378 $338,540 ======= ======== ====== ========

5. ASSET RETIREMENT OBLIGATIONS In some instances, our subsidiaries are obligated by contractual terms or regulatory requirements to remove facilities or perform other remediation upon retirement. We have, where possible, developed our estimate of the retirement obligations. We have determined that asset retirement obligations exist for certain of our transmission assets and gas gathering and processing assets; however, the fair value of the obligations cannot be determined because the end of the system life is not determinable with the degree of accuracy necessary to currently establish a liability for the obligations. F-14 Effective January 1, 2003, we adopted SFAS No. 143, "Accounting for Asset Retirement Obligations." The implementation of SFAS No. 143 resulted in an increase in net property, plant and equipment of $2.5 million, an increase in reserves and deferred credits of $3.1 million and a reduction to net income of $0.6 million for the net-of-tax cumulative effect of change in accounting principle. A reconciliation of the beginning and ending aggregate carrying amount of our asset retirement obligations for the years ended December 31, 2005, 2004 and 2003, is as follows:

(In thousands) -------------- Balance at December 31, 2002 $ -- Cumulative effect of transition adjustment 3,496 Accretion expense 159 Liabilities transferred with asset sales (2,016) ------- Balance at December 31, 2003 1,639 Accretion expense 102 ------- Balance at December 31, 2004 1,741 Accretion expense 114 Revision in estimated cash flows 479 ------- Balance at December 31, 2005 $ 2,334 =======

In March 2005, the Financial Accounting Standards Board (FASB) issued Interpretation (FIN) 47, "Accounting for Conditional Asset Retirement Obligations - an interpretation of SFAS No. 143." The statement clarifies the term "conditional asset retirement obligation," as used in SFAS No. 143, and the circumstances under which an entity would have sufficient information to reasonably estimate the fair value of an asset retirement obligation. We adopted FIN 47 effective December 31, 2005. The effect of adopting FIN 47 was not material to our results of operations or financial position. 6. RATES AND REGULATORY ISSUES The FERC regulates the rates and charges for transportation on our interstate natural gas pipelines. Interstate natural gas pipeline companies may not charge rates that have been determined to be unjust and unreasonable 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, 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. As required by the provisions of the settlement of its last rate case, on November 1, 2005, Northern Border Pipeline filed a rate case with the FERC. The rate case filing proposes, among other things, a 7.8% increase to Northern Border Pipeline's revenue requirement; a change to its rate design approach with a supply zone and market area utilizing a fixed rate and a dekatherm-mile rate, respectively; a compressor usage surcharge primarily to recover costs related to powering electric compressors; and implementation of a short-term, rate structure on a prospective basis. Also included in the filing is the continuation of the inclusion of income taxes in the calculation of Northern Border Pipeline's rates. In December 2005, the FERC issued an order that identified issues that were raised in the proceeding, accepted the proposed rates but suspended their effectiveness until May 1, 2006, at which time the new rates will be collected subject to refund until final resolution of the rate case. The FERC also issued a procedural schedule which set a hearing commencement date of October 4, 2006, with an initial decision scheduled for February 2007, unless a settlement of the issues is reached with FERC and a majority of Northern Border Pipeline's customers. At this time, Northern Border Pipeline can give no assurance as to the outcome on any of these issues. 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 F-15 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. Midwestern Gas Transmission and Viking Gas Transmission have no timing requirements or restriction in regard to future rate case filings. 7. TRANSPORTATION, GATHERING AND PROCESSING AGREEMENTS Operating revenues for our interstate natural gas pipelines are collected pursuant to their FERC tariffs through transportation service agreements. Northern Border Pipeline's firm service agreements extend for various terms with termination dates that range from December 2005 to December 2013. The termination dates for Midwestern Gas Transmission's firm service agreements range from October 2006 to October 2020. The termination dates for Viking Gas Transmission's firm service agreements range from September 2006 to October 2014. Northern Border Pipeline, Midwestern Gas Transmission and Viking Gas Transmission also have interruptible transportation service agreements and other transportation service agreements with numerous shippers. Under the capacity release provisions of the interstate pipelines' FERC tariffs, shippers are allowed to release all or part of their capacity either permanently for the full term of the contract or temporarily. A temporary capacity release does not relieve the original contract shipper from its payment obligations if the replacement shipper fails to pay for the capacity temporarily released to it. For the interstate natural gas pipeline segment, Northern Border Pipeline's revenues represented approximately 85%, 86% and 86% of the segment's revenues in 2005, 2004 and 2003, respectively. At December 31, 2005, Northern Border Pipeline's largest shippers, BP Canada Energy Marketing Corp. (BP Canada) and Nexen Marketing, U.S.A. Inc (Nexen), were obligated for approximately 20% and 12% of its design capacity, respectively. The BP Canada and Nexen firm service agreements extend for various terms with termination dates from March 2006 to February 2012 and December 2005 to December 2013, respectively. For the year ended December 31, 2005, shippers providing significant operating revenues were BP Canada, Nexen, EnCana Marketing (USA) Inc. (EnCana) and Cargill Inc. (Cargill) with revenues of $56.1 million, $38.1 million, $37.9 million and $34.1 million, respectively. For the year ended 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., with operating revenues of $54.7 million, $32.9 million and $45.5 million, respectively. At December 31, 2005 and 2004, Northern Border Pipeline had contracted firm capacity held by one shipper affiliated with one of its general partners. ONEOK Energy Services Company LP (ONEOK Energy Services), a subsidiary of ONEOK, holds firm service agreements representing approximately 3% of its design capacity at December 31, 2005. The firm service agreements with ONEOK Energy Services extend for various terms with termination dates that range from February 2006 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. Revenue from ONEOK Energy Services for 2005 and the period from the date of affiliation to December 31, 2004, was $7.7 million and $1.1 million, respectively. At December 31, 2005, and 2004, Northern Border Pipeline had outstanding receivables from ONEOK Energy Services of $0.9 million and $0.8 million, respectively. In 2003, there was no operating revenue from affiliates. The gas gathering and processing businesses provide services for gathering, treating, processing and compression of natural gas and the fractionation of natural gas liquids. For the year ended December 31, 2005, Bear Paw Energy's largest customers, Lodgepole Energy Marketing (Lodgepole) and BP Canada accounted for $123.2 million (45%) and $55.8 million (20%), respectively, of Bear Paw Energy's operating revenues. For the year ended December 31, 2004, Bear Paw Energy's largest customers, Lodgepole, BP Canada and Montana Dakota Utilities accounted for $82.0 million (44%), $26.7 million (14%) and $21.7 million (12%), respectively, of Bear Paw Energy's operating revenues. For the year ended December 31, 2003, Bear Paw Energy's largest customers, Lodgepole, Tenaska Marketing Ventures (Tenaska) and BP Canada accounted for $62.4 million (40%), $27.3 million (18%) and $16.6 million (11%), respectively, of Bear Paw Energy's operating revenue. Crestone Energy Venture's revenues from affiliates totaled $0.2 million, $0.2 million and $0.1 million in 2005, 2004 and 2003, respectively. F-16 Black Mesa's operating revenue is derived from a transportation agreement with Peabody Western Coal, the coal supplier for the Mohave Generating Station that expired in December 2005. The coal slurry pipeline is the sole source of fuel for the Mohave plant. Operating revenues under the agreement totaled $24.6 million, $22.0 million and $21.4 million for the years ended December 31, 2005, 2004, and 2003, respectively. 8. CREDIT FACILITIES, LONG-TERM DEBT AND CAPITAL LEASES Detailed information on long-term debt is as follows:

DECEMBER 31, ----------------------- 2005 2004 ---------- ---------- (In thousands) Northern Border Pipeline: 2005 Pipeline Credit Agreement - average 5.11% at December 31, 2005, due 2010 $ 27,000 $ -- 1999 Pipeline Senior Notes - 7.75%, due 2009 200,000 200,000 2001 Pipeline Senior Notes - 7.50%, due 2021 250,000 250,000 2002 Pipeline Senior Notes - 6.25%, due 2007 150,000 150,000 Viking Gas Transmission: Series A Senior Notes - 6.65%, due 2008 6,045 8,178 Series B Senior Notes - 7.10%, due 2011 2,520 2,520 Series C Senior Notes - 7.31%, due 2012 7,311 7,311 Series D Senior Notes - 8.04%, due 2014 13,111 13,111 Northern Border Partners: 2005 Partnership Credit Agreement - average 5.18% at December 31, 2005, due 2010 204,000 -- 2004 Partnership Credit Agreement - average 3.20% at December 31, 2004, terminated in 2005 -- 191,000 2000 Partnership Senior Notes - 8.875%, due 2010 250,000 250,000 2001 Partnership Senior Notes - 7.10%, due 2011 225,000 225,000 Bear Paw Energy: Capital leases 61 3,110 Fair value adjustment for interst rate swaps (Note 9) (2,362) 2,555 Unamortized debt premium 22,285 27,573 ---------- ---------- Subtotal 1,354,971 1,330,358 Less: Current maturities of long-term debt 2,194 5,126 ---------- ---------- Long-term debt $1,352,777 $1,325,232 ========== ==========

The Partnership and Northern Border Pipeline have entered into revolving credit facilities, which are used for capital expenditures, acquisitions and general business purposes and for refinancing existing indebtedness. Northern Border Pipeline entered into a $175 million five-year credit agreement (2005 Pipeline Credit Agreement) with certain financial institutions in May 2005. We entered into a $500 million five-year credit agreement (2005 Partnership Credit Agreement) with certain financial institutions in May 2005. Both of the revolving credit facilities permit the Partnership and Northern Border Pipeline to choose the lender's base rate or the London Interbank Offered Rate (LIBOR) plus a spread (based on each of our long-term unsecured debt ratings) as the interest rate on our outstanding borrowings, specify the portion of the borrowings to be covered by specific interest rate options and to specify the interest rate period. Both the Partnership and Northern Border Pipeline are required to pay a fee on the principal commitment amounts. On December 1, 2004, Northern Border Pipeline redeemed $75 million of the 2002 Pipeline Senior Notes. In connection with the redemption, Northern Border Pipeline was required to pay a premium of $4.8 million and received $2.5 million from the termination of interest rate swaps associated with the debt (see Note 9). The net loss from the redemption, including unamortized debt costs and discounts associated with the debt, is recorded as a loss on reacquired debt and amortized to interest expense over the remaining life of the 2002 Pipeline Senior Notes. At December 31, 2005 and F-17 2004, the unamortized loss on reacquired debt was $1.5 million and $2.6 million respectively and is included in regulatory assets on the consolidated balance sheet. Interest paid, net of amounts capitalized, during the years ended December 31, 2005, 2004 and 2003 was $91.2 million, $77.7 million and $86.7 million, respectively. Aggregate repayments of long-term debt required for the next five years, excluding payments required under Bear Paw Energy's capital leases, are as follows: $2 million, $152 million, $2 million, $200 million and $481 million for 2006, 2007, 2008, 2009 and 2010, respectively. Each of the 2005 Partnership and Pipeline Credit Agreements require the Partnership and Northern Border Pipeline to comply with certain financial, operational and legal covenants. The agreements require, among other things, that the Partnership and Northern Border Pipeline maintain ratios of EBITDA (net income plus minority interests in net income, interest expense, income taxes and depreciation and amortization) to interest expense of greater than 3 to 1. The agreements also require the maintenance of ratios of indebtedness to adjusted EBITDA (EBITDA adjusted for pro forma operating results of acquisitions made during the year) of no more than 4.75 to 1 for the Partnership and 4.50 to 1 for Northern Border Pipeline. Pursuant to the credit agreements, if one or more acquisitions are consummated in which the aggregate purchase price is $25 million or more, the allowable ratios of indebtedness to adjusted EBITDA are increased to 5.25 to 1 for the Partnership and 5 to 1 for Northern Border Pipeline for two calendar quarters following the acquisition. Upon any breach of these covenants, amounts outstanding under the 2005 Partnership and Pipeline Credit Agreements may become due and payable immediately. As of December 31, 2005, the Partnership and Northern Border Pipeline were in compliance with these covenants. At December 31, 2005 and 2004, Viking Gas Transmission has four series of senior notes outstanding. In November 2004, Viking Gas Transmission amended the indenture on its senior notes. Prior to the amendment, Viking Gas Transmission made monthly principal and interest payments on the four series of notes. As a result of the amendment, three of the series of senior notes due between 2011 and 2014 require payment of interest quarterly and payment of principal at maturity. The senior notes due in 2008 continue to require monthly principal and interest payments. We guarantee payment of the Viking Gas Transmission senior notes. The senior notes contain certain financial covenants and at December 31, 2005, Viking Gas Transmission was in compliance with its financial covenants. Bear Paw Energy has entered into non-cancelable capital leases on compressors. The capital leases incorporate annual interest rates ranging from 7.10% to 8.85% and are for a term of five years, after which Bear Paw Energy receives ownership of the equipment. In 2006, the capital lease obligation will expire. At December 31, 2005, the capital lease obligation is $61 thousand, which is included in the current maturities of long-term debt on the consolidated balance sheet. 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 senior notes was approximately $1,167 million and $1,205 million at December 31, 2005 and 2004, respectively. We presently intend to maintain the current schedule of maturities for the senior notes, which will result in no gains or losses on their respective repayment. The fair value of the 2005 Partnership Credit Agreement and the 2005 Pipeline Credit Agreement approximates the carrying value since the interest rates are periodically adjusted to reflect current market conditions. 9. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES We reflect our 70% share of Northern Border Pipeline's accumulated other comprehensive income in our consolidated accumulated other comprehensive income. The remaining 30% is reflected as an adjustment to minority interests in partners' equity. We also reflect in consolidated accumulated other comprehensive income our ownership share of accumulated other comprehensive income of our unconsolidated affiliates (see Note 10). Prior to the anticipated issuance of fixed rate debt, both the Partnership and Northern Border Pipeline have entered into forward starting interest rate swap agreements. The interest rate swap agreements have been designated as cash flow hedges as they hedge the fluctuations in Treasury rates and spreads between the execution date of the swap agreements and the issuance of the fixed rate debt. The notional amount of the interest rate swap agreements does not exceed the expected principal amount of fixed rate debt to be issued. Upon issuance of the fixed rate debt, the swap agreements F-18 were terminated and the proceeds received or amounts paid to terminate the swap agreements were recorded in accumulated other comprehensive income and amortized to interest expense over the term of the hedged debt. We also recorded an adjustment to minority interests in partners' equity for Northern Border Pipeline's terminated swap agreements. On December 9, 2004, we entered into forward starting interest rate swap agreements with a total notional amount of $100 million in anticipation of a ten-year senior note issuance. These swap agreements expired in late May and early June of 2005, which resulted in us paying $2.7 million to counterparties. In June 2005, we entered into a Treasury lock interest rate agreement with a notional amount of $200 million in anticipation of a ten-year senior note issuance. In July 2005, we paid $0.1 million to the counterparty at expiration of the Treasury lock interest rate agreement. At December 31, 2005, the unamortized portion of these agreements in accumulated other comprehensive income was $2.7 million. In the event we do not enter into fixed rate debt, we would be required to expense the balance recorded in other accumulated comprehensive income to interest expense. During the years ended December 31, 2005, 2004 and 2003, we amortized approximately $1.9 million, $2.1 million and $2.2 million, respectively, related to the terminated interest rate swap agreements, as a reduction to interest expense from accumulated other comprehensive income. We expect to amortize approximately $1.8 million in 2006 for these agreements. At December 31, 2005 and 2004, we had outstanding interest rate swaps with notional amounts totaling $150 million. Under the interest rate swap agreements, we make payments to counterparties at variable rates based on the London Interbank Offered Rate and in return we receive payments based on a 7.10% fixed rate. At December 31, 2005 and 2004, the average effective interest rate on our interest rate swap agreements was 6.56% and 4.60%, respectively. Our interest rate swap agreements have been designated as fair value hedges as they hedge the fluctuations in the market value of the senior notes issued by us in 2001. The accompanying consolidated balance sheet at December 31, 2005 and 2004, reflects an unrealized loss and an unrealized gain of approximately $2.4 million and $2.6 million, respectively, in derivative financial instruments with a corresponding offset in long-term debt. In November 2004, Northern Border Pipeline terminated its interest rate swap agreements with notional amounts totaling $225 million and received $7.5 million. Of the total proceeds, $2.5 million related to the redemption of $75 million of the 2002 Pipeline Senior Notes (see Note 8). In March 2003, the Partnership terminated one of its interest rate swap agreements with a notional amount of $75 million and received $12.3 million. We used the proceeds to repay amounts borrowed under our credit facility. We record in long-term debt amounts received or paid related to terminated or amended interest rate swap agreements for fair value hedges with such amounts amortized to interest expense over the remaining life of the interest rate swap agreement. During the years ended December 31, 2005, 2004 and 2003, we amortized approximately $5.1 million, $3.3 million and $3.4 million, respectively, as a reduction to interest expense. We expect to amortize approximately $5.3 million as a reduction to interest expense in 2006 for these agreements. Bear Paw Energy periodically enters into commodity derivatives contracts and fixed-price physical contracts. Bear Paw Energy primarily utilizes price swaps and collars, which have been designated as cash flow hedges, to hedge its exposure to gas and natural gas liquid price volatility. During the years ended December 31, 2005, 2004 and 2003, respectively, Bear Paw Energy recognized losses of $4.8 million, $9.4 million and $8.5 million from the settlement of derivative contracts. At December 31, 2005, the consolidated balance sheet reflected an unrealized loss of approximately $4.6 million in derivative financial instruments with a corresponding decrease of $4.6 million in accumulated other comprehensive income. At December 31, 2004, the consolidated balance sheet reflected an unrealized gain of approximately $2.0 million in derivative financial instruments with a corresponding increase of $2.0 million in accumulated other comprehensive income. For 2006, if prices remain at current levels, Bear Paw Energy expects to reclassify approximately $4.6 million from accumulated other comprehensive income as a decrease to operating revenues. However, this decrease would be offset with increased operating revenues due to the higher prices assumed. F-19 10. UNCONSOLIDATED AFFILIATES Our investments in unconsolidated affiliates which are accounted for by the equity method are as follows:

NET DECEMBER 31, OWNERSHIP --------------------- INTEREST 2005 2004 --------- -------- -------- (In thousands) Bighorn Gas Gathering (a) 49% $ 96,485 $ 92,350 Fort Union Gas Gathering (c) 37% 79,319 71,710 Lost Creek Gathering (d) 35% 78,482 74,935 Guardian Pipeline 33-1/3% 36,470 34,207 -------- -------- $290,756(b) $273,202 ======== ========

(a) We held a 49% common membership interest in Bighorn and 100% of the non-voting preferred A shares of Bighorn at December 31, 2004. In July 2005, we negotiated a settlement agreement with our partner in Bighorn Gas Gathering related to provisions of the joint venture agreement that provided for cash flow incentives based on well connections to the gathering system. These incentives were provided to us through our ownership of preferred A shares in Bighorn Gas Gathering. In August 2005, as a result of the settlement, we recognized $5.4 million of equity earnings through our ownership of the preferred A shares due to us for 2004 and 2005. The settlement agreement cancelled and effectively redeemed Bighorn Gas Gathering's outstanding preferred A and B shares and eliminated future incentives and its capital accounts were adjusted accordingly. The preferred B shares were held by our partner in Bighorn Gas Gathering. (b) The unamortized excess of our investments in unconsolidated affiliates over the underlying book value of the net assets accounted for under the equity method was $185.8 million and $181.6 million at December 31, 2005 and 2004, respectively. (c) In August 2005, Crestone Energy Ventures acquired, for $5.1 million, an additional 3.7% interest in Fort Union, bringing its total interest to 37%. (d) Crestone Energy Ventures is also entitled to receive an incentive allocation of earnings from third party gathering service revenues recognized by Lost Creek Gathering. As a result of the incentive, Crestone Energy Ventures' share of Lost Creek Gathering income exceeds its 35% ownership interest. Our equity earnings of unconsolidated affiliates are as follows:

DECEMBER 31, --------------------------- 2005 2004 2003 ------- ------- ------- (In thousands) Bighorn Gas Gathering $ 9,411 $ 5,832 $ 6,467 Fort Union Gas Gathering 6,747 5,357 5,953 Lost Creek Gathering 6,315 5,176 4,403 Guardian Pipeline 2,263 1,650 1,992 ------- ------- ------- $24,736 $18,015 $18,815 ======= ======= =======

F-20 Summarized combined financial information of our unconsolidated affiliates is presented below:

DECEMBER 31, ------------------- 2005 2004 -------- -------- (In thousands) Balance Sheet: Current assets $ 41,700 $ 39,565 Property, plant and equipment, net 463,083 466,320 Other noncurrent assets 2,292 3,090 Current liabilities 44,786 39,131 Long-term debt 202,392 228,006 Other noncurrent liabilities 70 2,185 Accumulated other conmprehensive income 549 (2,136) Owners' equity 259,278 241,789

DECEMBER 31, ---------------------------- 2005 2004 2003 -------- ------- ------- (In thousands) Income Statement: Operating revenue $101,390 $92,649 $94,318 Operating expenses 34,470 34,745 31,927 Net income 49,742 39,389 42,583 Distributions paid to the Partnership $ 16,440 $12,536 $17,672

11. PARTNERS' EQUITY At December 31, 2005 and 2004, our equity consisted of 46,397,214 common units representing an effective 98% limited partner interest in the Partnership and a 2% general partner interest. At December 31, 2005 and 2004, approximately 1.1% of the limited partner interest was held by Northern Plains. Under our partnership agreement, in conjunction with the issuance of additional common units, our general partners are required to make equity contributions to us in order to maintain a 2% general partner interest. In May and June 2003, we sold 2,250,000 and 337,500 common units, respectively. The net proceeds from the sales of common units and the general partners' contributions totaled approximately $102.2 million which were primarily used to repay indebtedness outstanding. Under our partnership agreement, we make distributions to our partners with respect to each calendar quarter in an amount equal to 100% of our Available Cash. "Available Cash" generally consists of all our cash receipts adjusted for our cash disbursements and net changes to cash reserves. Available Cash will generally be distributed 98% to limited partners and 2% to the general partners. As an incentive, the General Partners' percentage interest in quarterly distributions is increased after certain specified target levels are met. Under the incentive distribution provisions, the General Partners receive 15% of amounts distributed in excess of $0.605 per common unit, 25% of amounts distributed in excess of $0.715 per unit and 50% of amounts distributed in excess of $0.935 per unit. Our income is allocated to the General Partners and the limited partners in accordance with their respective partnership percentages, after giving effect to any priority income allocations for incentive distributions that are allocated to the General Partners. For the years ended December 31, 2005, 2004 and 2003, incentive distributions to the General Partners totaled $8.0 million, $8.0 million and $7.7 million, respectively. F-21 12. NORTHERN BORDER PIPELINE CASH DISTRIBUTION POLICY The Northern Border Pipeline partnership agreement provides that distributions to Northern Border Pipeline's partners are to be made on a pro rata basis according to each partner's capital account balance. The Northern Border Pipeline Management Committee determines the amount and timing of such distributions. Any changes to, or suspension of, the cash distribution policy of Northern Border Pipeline requires the unanimous approval of the Northern Border Pipeline Management Committee. In December 2003, Northern Border Pipeline's Management Committee voted to (i) issue equity cash calls to its partners in the total amount of $130 million in early 2004 and $90 million in 2007; (ii) fund future growth capital expenditures with 50% equity capital contributions from its partners; and (iii) change the cash distribution policy of Northern Border Pipeline. Effective January 1, 2004, cash distributions are equal to 100% of distributable cash flow as determined from Northern Border Pipeline's financial statements based upon earnings before interest, taxes, depreciation and amortization less interest expense and maintenance capital expenditures. On November 30, 2004, Northern Border Pipeline issued an equity cash call to its partners in the total amount of $75 million, which was utilized to repay existing bank debt. This equity contribution will reduce the previously approved 2007 equity cash call from $90 million to $15 million. 13. COMMITMENTS AND CONTINGENCIES LEGAL PROCEEDINGS Various legal actions that have arisen in the ordinary course of business are pending. We believe that the resolution of these issues will not have a material adverse impact on our results of operations or financial position. ENVIRONMENTAL LIABILITIES We are subject to federal, state and local environmental laws and regulations. Also, it is possible that other developments, such as increasingly stringent environmental laws, regulations and enforcement policies could result in substantial costs and liabilities to us. BLACK MESA On December 31, 2005, we shut down our coal slurry pipeline operation. The Mohave Generating Station co-owners, Navajo Nation, Hopi Tribe, Peabody Western Coal Company and other interested parties continue to negotiate water source and coal supply issues and Black Mesa is working to resolve coal slurry transportation issues so that operations may resume in the future. If there are successful resolutions of these issues and the project receives a favorable Environmental Impact Statement, Black Mesa will reconstruct the coal slurry pipeline in late 2008 and 2009 for an anticipated in service date during 2010. If the pipeline is reconstructed, we anticipate Black Mesa's capital expenditures for the project will be in the range of $175 million to $200 million, supported by revenue from a new transportation contract. If the Mohave Generating Station is permanently closed, we expect to incur pipeline removal and remediation costs of approximately $1 million to $2 million, net of salvage, and a non-cash impairment charge of approximately $10 million related to the remaining undepreciated cost of the pipeline assets and goodwill. We incurred one time termination costs of $0.7 million in the fourth quarter which were reflected in the segment's operation and maintenance expense. We expect to incur an additional $4 million to $6 million of operations and maintenance expense in 2006 primarily related to employee stand by costs. We may be required to take an impairment charge in accordance with SFAS No. 142 and SFAS No. 144 prior to final resolution of the issues concerning the Mohave Generating Station even though the project may ultimately proceed. FIRM TRANSPORTATION OBLIGATIONS AND OTHER COMMITMENTS Crestone Energy Ventures has firm transportation agreements with Fort Union and Lost Creek. The Fort Union agreement expires in 2009 and the Lost Creek agreement expires in 2010. Under these agreements, Crestone Energy Ventures must make specified minimum payments each month. Crestone Energy Ventures recorded expenses of $11.7 million, $11.8 million and $11.7 million for the years ended December 31, 2005, 2004 and 2003, respectively, related to these agreements. At December 31, 2005, the estimated aggregate amounts of such required future payments were $11.7 million annually for 2006 through 2008, $11.1 million for 2009 and $3.7 million for 2010. F-22 At December 31, 2005, we have guaranteed certain of our unconsolidated affiliates performance in connection with credit agreements that expire in March 2009 and September 2009. At December 31, 2005, the collective amount of both guarantees was $4.4 million. OPERATING LEASES Future minimum lease payments under non-cancelable operating leases on office space, pipeline equipment, rights-of-way and vehicles are as follows:

Year ending December 31, (In thousands) ------------------------ -------------- 2006 $ 3,788 2007 3,458 2008 3,384 2009 2,511 2010 2,186 Thereafter 64,849 ------- $80,176 =======

Expenses incurred related to these lease obligations for the years ended December 31, 2005, 2004 and 2003, were $3.6 million, $3.8 million and $3.7 million, respectively. CASH BALANCE PLAN As further discussed in Note 19, 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. We recorded charges associated with the termination of the cash balance plan of $6.2 million in 2003. In 2004, we reduced our expenses by $6.2 million, since we determined that we were no longer liable for termination costs of the Cash Balance Plan. CAPITAL EXPENDITURES Total capital expenditures for 2006 are estimated to be $94 million. This includes approximately $59 million for interstate natural gas pipeline facilities, $32 million for natural gas gathering and processing facilities and $3 million for information technology systems. Funds required to meet the capital requirements for 2006 are anticipated to be provided from credit facilities and operating cash flows. 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 executed in August 2004. 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 is seeking regulatory recovery for the settlement in its pending rate case. F-23 14. INCOME TAXES Components of the income tax provision applicable to continuing operations and income taxes paid by our corporate subsidiaries are as follows:

YEAR ENDED DECEMBER 31, ------------------------ 2005 2004 2003 ------ ------ ------ (In thousands) Taxes currently payable: Federal $2,036 $1,346 $ 900 State 390 289 311 ------ ------ ------ Total taxes currently payable 2,426 1,635 1,211 Deferred taxes: Federal 2,639 2,789 2,842 State 727 712 652 ------ ------ ------ Total deferred taxes 3,366 3,501 3,494 ------ ------ ------ Total tax provision $5,792 $5,136 $4,705 ====== ====== ====== Income taxes paid $1,351 $5,346 $1,544 ====== ====== ======

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

YEAR ENDED DECEMBER 31, ----------------------- 2005 2004 2003 ----- ----- ----- Federal income tax rate 35.0% 35.0% 35.0% Increase (decrease) as a result of: Partnership earnings not subject to tax (35.0) (35.0) (35.0) Corporate subsidiary earnings subject to tax 3.1 2.8 (4.1) State taxes 0.7 0.7 (1.0) ----- ----- ----- Effective tax rate 3.8% 3.5% (5.1)% ===== ===== =====

Deferred tax assets and liabilities result from the following:

YEAR ENDED DECEMBER 31, ----------------------- 2005 2004 ------- ------- (In thousands) Deferred tax assets: Net operating losses $11,923 $ 6,606 Plant related differences 1,941 2,333 Other 843 410 ------- ------- Total deferred tax assets 14,707 9,349 ------- ------- Deferred tax liabilities: Goodwill 6,579 5,458 Accelerated depreciation and other plant-related differences 8,618 3,514 Partnership income 9,821 7,563 ------- ------- Total deferred tax liabilties 25,018 16,535 ------- ------- Net deferred tax liabilities $10,311 $ 7,186 ======= =======

F-24 We had available, at December 31, 2005, approximately $11.9 million of tax benefits related to net operating loss carry forwards, which will expire between the years 2021 and 2025. We believe that it is more likely than not that the tax benefits of the net operating loss carry forwards will be utilized prior to their expiration; therefore, no valuation allowance is necessary. 15. ACCOUNTING PRONOUNCEMENTS In December 2004, the FASB issued SFAS No. 123R, "Share-Based Payment" which requires companies to expense the fair value of share-based payments and includes changes related to the expense calculation for share-based payments. Northern Plains and NBP Services adopted SFAS 123R as of January 1, 2006, and will charge us for our proportionate share of the expense recorded by Northern Plains and NBP Services. The impact of adopting Statement 123R does not have a material impact on our results of operations or financial position. In June 2005, the FERC issued guidance describing how FERC-regulated companies should account for costs associated with implementing the pipeline integrity management requirements of the U.S. Department of Transportation's Office of Pipeline Safety. Under the guidance, costs to 1) prepare a plan to implement the program, 2) identify high consequence areas, 3) develop and maintain a record keeping system and 4) inspect, test and report on the condition of affected pipeline segments to determine the need for repairs or replacements, are required to be expensed. Costs of modifying pipelines to permit in-line inspections, certain costs associated with developing or enhancing computer software and costs associated with remedial and mitigation actions to correct an identified condition can be capitalized. The guidance is effective January 1, 2006, to be applied prospectively. The effect of adopting this order is not expected to be material to our results of operations or financial position. 16. BUSINESS SEGMENT INFORMATION Our business is divided into three reportable segments, defined as components of the enterprise about which financial information is available and evaluated regularly by our executive management and the Partnership Policy Committee in deciding how to allocate resources to an individual segment and in assessing performance of the segment. Our reportable segments are strategic business units that offer different services. Each is managed separately because each business requires different marketing strategies. These segments are as follows: the Interstate Natural Gas Pipeline segment provides natural gas transportation services; the Natural Gas Gathering and Processing segment provides services for the gathering, treating, processing and compression of natural gas and the fractionation of natural gas liquids; and the Coal Slurry Pipeline segment transports crushed coal suspended in water. The accounting policies of the segments are described in the summary of significant accounting policies in Note 2. We evaluate our performance based on EBITDA, earnings before interest, taxes, depreciation and amortization less the allowance for equity funds used during construction (AFUDC). Management uses EBITDA to compare the financial performance of its segments and to internally manage those business segments. Management believes that EBITDA provides useful information to investors as a measure of comparability to peer companies. EBITDA should not be considered an alternative to, or more meaningful than, net income or cash flow as determined in accordance with U.S. GAAP. EBITDA calculations may vary from company to company, so our computation of EBITDA may not be comparable to a similarly titled measure of another company. The following table shows how we calculate EBITDA: F-25 RECONCILIATION OF NET INCOME(LOSS) TO EBITDA

NATURAL GAS INTERSTATE GATHERING NATURAL GAS AND COAL SLURRY PIPELINE PROCESSING PIPELINE OTHER (A) TOTAL ----------- ----------- ----------- --------- -------- (In thousands) 2005 Net income (loss) $123,604 $ 67,552 $3,902 $(48,045) $147,013 Minority interest 45,674 -- -- -- 45,674 Interest expense, net 44,990 219 3 41,691 86,903 Depreciation and amortization 67,608 16,045 2,546 162 86,361 Income tax 4,522 24 1,246 755 6,547 AFUDC (527) -- -- -- (527) -------- --------- ------ -------- -------- EBITDA $285,871 $ 83,840 $7,697 $ (5,437) $371,971 ======== ========= ====== ======== ======== 2004 Net income (loss) $134,726 $ 44,488 $3,088 $(37,582) $144,720 Minority interest 50,033 -- -- -- 50,033 Interest expense, net 43,882 369 11 32,681 76,943 Depreciation and amortization 67,487 14,851 4,465 400 87,203 Income tax 4,783 26 327 2,935 8,071 AFUDC (117) -- -- -- (117) -------- --------- ------ -------- -------- EBITDA $300,794 $ 59,734 $7,891 $ (1,566) $366,853 ======== ========= ====== ======== ======== 2003 Net income (loss) $119,620 $(183,016) $3,658 $(28,716) $(88,454) Cumulative effect of change in accounting principle, net of tax -- -- 434 209 643 Minority interest 44,460 -- -- -- 44,460 Interest expense, net 47,577 591 33 30,779 78,980 Depreciation and amortization 66,245 232,777 1,848 1,107 301,977 Income tax 3,629 -- 1,076 (276) 4,429 AFUDC (331) -- -- -- (331) -------- --------- ------ -------- -------- EBITDA $281,200 $ 50,352 $7,049 $ 3,103 $341,704 ======== ========= ====== ======== ========

F-26 BUSINESS SEGMENT DATA

NATURAL GAS INTERSTATE GATHERING NATURAL GAS AND COAL SLURRY PIPELINE PROCESSING PIPELINE OTHER (A) TOTAL ----------- ----------- ----------- --------- ---------- (In thousands) 2005 Revenue from external customers $ 378,701 $ 275,287 $24,572 $ -- $ 678,560 Depreciation and amortization 67,257 16,045 2,546 162 86,010 Operating income (loss) 214,168 44,714 5,186 (7,300) 256,768 Interest expense, net 44,990 219 3 41,691 86,903 Equity earnings of unconsolidated affiliates 2,263 22,473 -- -- 24,736 Other income (expense), net 2,359 608 (35) 440 3,372 Income tax expense 4,522 24 1,246 -- 5,792 Capital expenditures 39,641 16,602 -- 3,639 59,882 Identifiable assets 1,852,510 340,093 16,410 27,997 2,237,010 Investments in unconsolidated affiliates 36,470 254,286 -- -- 290,756 Total assets 1,888,980 594,379 16,410 27,997 2,527,766 2004 Revenue from external customers $ 383,625 $ 184,738 $22,020 $ -- $ 590,383 Depreciation and amortization 67,115 14,851 4,465 -- 86,431 Operating income (loss) 231,027 28,278 3,446 (9,366) 253,385 Interest expense, net 43,882 369 11 32,681 76,943 Equity earnings of unconsolidated affiliates 1,649 16,366 -- -- 18,015 Other income (expense), net 748 239 (20) 666 1,633 Income tax expense 4,783 26 327 -- 5,136 Capital expenditures 16,258 25,646 1,573 -- 43,477 Identifiable assets 1,870,482 337,502 18,268 15,236 2,241,488 Investments in unconsolidated affiliates 34,207 238,995 -- -- 273,202 Total assets 1,904,689 576,497 18,268 15,236 2,514,690 2003 Revenue from external customers $ 375,256 $ 154,284 $21,408 $ -- $ 550,948 Depreciation and amortization (b) 65,881 232,063 1,847 -- 299,791 Operating income (loss) 212,841 (203,067) 5,144 (7,601) 7,317 Interest expense, net 47,577 591 33 30,779 78,980 Equity earnings of unconsolidated affiliates 1,992 16,823 -- -- 18,815 Other income (expense), net 453 3,819 57 535 4,864 Income tax expense 3,629 -- 1,076 -- 4,705 Capital expenditures 19,497 8,981 1,804 -- 30,282 Identifiable assets 1,938,249 317,182 21,319 25,667 2,302,417 Investments in unconsolidated affiliates 32,558 235,608 -- -- 268,166 Total assets 1,970,807 552,790 21,319 25,667 2,570,583

F-27 (a) Includes other items not allocable to segments. (b) Natural gas gathering and processing results includes goodwill and asset impairment charges of $219,080 (see Note 4). 17. OTHER INCOME (EXPENSE) Other income (expense) on the consolidated statement of income includes such items as investment income, nonoperating revenues and expenses, foreign currency gains and losses, and nonrecurring other income and expense items. For the year ended December 31, 2003, other income also included a $3.3 million payment received for a change in ownership of the other partner in Bighorn. 18. QUARTERLY FINANCIAL DATA (Unaudited)

PER UNIT INCOME INCOME FROM FROM OPERATING OPERATING CONTINUING CONTINUING REVENUE INCOME OPERATIONS OPERATIONS --------- --------- ---------- ---------- (In thousands) 2005 First Quarter $160,379 $63,538 $34,279 $0.68 Second Quarter 149,417 53,464 27,732 0.54 Third Quarter 183,023 74,848 48,838 0.99 Fourth Quarter 185,741 64,918 35,658 0.71 2004 First Quarter $143,773 $61,761 $35,852 $0.71 Second Quarter 142,476 60,595 32,872 0.65 Third Quarter 147,355 62,093 34,400 0.68 Fourth Quarter 156,779 68,936 37,797 0.76

19. RELATIONSHIPS WITH ENRON In December 2001, Enron and certain of its subsidiaries filed a voluntary petition for bankruptcy protection under Chapter 11 of the United States Bankruptcy Code. Until November 17, 2004, each of Northern Plains, Pan Border and NBP Services were subsidiaries of Enron. Northern Plains, Pan Border and NBP Services were not among the Enron companies filing for Chapter 11 protection. Enron North America Corp. (Enron North America), a wholly owned subsidiary of Enron that is in bankruptcy, was a party to transportation contracts which obligated Enron North America to pay for 3.5% of Northern Border Pipeline's capacity. Through the bankruptcy proceeding in 2002, Enron North America rejected and terminated all of its firm transportation contracts on Northern Border Pipeline. Northern Border Pipeline had previously fully reserved for amounts invoiced to Enron North America. Since Enron guaranteed the obligations of Enron North America under those contracts, Northern Border Pipeline filed claims against both Enron North America and Enron for damages in the bankruptcy proceedings. As a result of a settlement agreement between Enron North America, Enron and Northern Border Pipeline, each of Enron North America and Enron agreed to allow Northern Border Pipeline's claim of approximately $20.6 million. In addition, Bear Paw Energy filed claims against Enron North America relating to terminated swap agreements in the amount of $6.7 million. Also, Crestone Energy Ventures filed claims against Enron North America for unpaid gas gathering and administrative services fees in the amount of $2.3 million. In 2004, we adjusted our allowance for doubtful accounts to reflect an estimated recovery of $3.4 million ($3.0 million, net to the Partnership) for the claims. In June 2005, we executed term sheets with a third party for the sale of our bankruptcy claims for contracts and associated guarantees held against Enron Corp. and Enron North America Corp. F-28 Proceeds from the sale of the claims were $14.6 million. In the second quarter of 2005, we made an adjustment to our allowance for doubtful accounts of $1.8 million ($1.6 million, net to the Partnership) to reflect the agreements for the sale. In the third quarter of 2005, Northern Border Pipeline recognized revenue of $9.4 million ($6.6 million, net to the Partnership) as a result of the sale. 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 of Enron's affiliates (the Plans) in 'standard terminations' within the meaning of Section 4041 of the Employee Retirement Income Security Act of 1974, as amended (ERISA). Northern Plains and NBP Services were considered members of Enron's ERISA controlled group of corporations. As of December 31, 2003, the amount of approximately $6.2 million was estimated for Northern Plains' and NBP Services' proportionate share of the up to $200 million estimated termination costs for the Plans authorized by the Bankruptcy Court order. Since under the operating agreement with Northern Plains and the administrative agreement with NBP Services, these costs could be our responsibility, we accrued $6.2 million to satisfy claims of reimbursement for these termination costs. As a result of further evaluation and negotiation of Enron's proposed allocation of the termination costs, Northern Plains and NBP Services advised us that no claim of reimbursement for the termination costs would be made, resulting in a reduction in reserves during 2004 of $6.2 million for the termination costs. Pursuant to the agreement whereby ONEOK purchased Northern Plains and NBP Services, the purchase price under the agreements was deemed to include all contributions which otherwise would have been allocable to Northern Plains and NBP Services. 20. SUBSEQUENT EVENTS On January 20, 2006, we declared a cash distribution of $0.80 per unit ($3.20 per unit on an annualized basis) for the quarter ended December 31, 2005. The distribution was paid February 14, 2006, to unitholders of record at January 31, 2006. On February 15, 2006, we announced a series of transactions. In separate transactions, we will sell a 20% partnership interest in Northern Border Pipeline to TC PipeLines, for approximately $300 million. The price of the 20% interest, along with the related share of Northern Border Pipeline's outstanding debt, totals $420 million. Following completion of the sale, we will own a 50% interest in Northern Border Pipeline and TC PipeLines will own the remaining 50% interest. In 2006, Northern Border Pipeline's cash distributions will be split equally between us and TC PipeLines. In April 2007, an affiliate of TransCanada will become the operator of Northern Border Pipeline. Northern Plains will purchase TransCanada's 0.35% general partner interest in us, increasing ONEOK's general partner interest to 2%. We will acquire ONEOK's entire gathering and processing, natural gas liquids, and pipelines and storage segments in a transaction valued at approximately $3 billion. We will pay ONEOK approximately $1.35 billion in cash and 36.5 million Class B units. Upon completion of these transactions, ONEOK will own approximately 37.0 million of our limited partner units, which, when combined with the general partner interest acquired from TransCanada, will increase its total interest in us to 45.7%. The limited partner units and the related general partner interest contribution are valued at approximately $1.65 billion. Closings of the transactions are subject to regulatory approvals and other conditions, including antitrust clearance from the Federal Trade Commission under the Hart-Scott-Rodino Act. The transaction is expected to be completed by April 1, 2006. For financial reporting purposes, the transfer of the ONEOK assets to us will be accounted for at the historical cost basis of the assets being transferred, and accordingly we will not record any goodwill related to the transaction. As a result of our sale of the 20% interest in Northern Border Pipeline, we will report the pipeline's results on the equity method of accounting and therefore, will no longer report the pipeline's results on a consolidated basis since we will no longer have voting control. The change will be effective January 1, 2006. F-29 REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM ON SCHEDULE Northern Border Partners, L.P.: We have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements of Northern Border Partners, L.P. and subsidiaries as of December 31, 2005 and 2004 and for each of the years in the three-year period ended December 31, 2005 included in this Form 10-K, and have issued our report thereon dated March 2, 2006, which report includes an explanatory paragraph discussing the adoption of FASB Statement No. 143 in 2003. Our audits were made for the purpose of forming an opinion on the basic financial statements taken as a whole. The schedule of Northern Border Partners, L.P. and subsidiaries listed in Item 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. Omaha, Nebraska March 2, 2006 S-1 NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES SCHEDULEII - VALUATION AND QUALIFYING ACCOUNTS

ADDITIONS DEDUCTIONS --------------------- FOR PURPOSE BALANCE AT CHARGED TO CHARGED FOR WHICH BALANCE BEGINNING COSTS AND TO OTHER RESERVES WERE AT END OF YEAR EXPENSES ACCOUNTS CREATED OF YEAR ---------- ---------- -------- ------------- ------- (In thousands) Reserve for regulatory issues: 2005 $ 1,955 $ 25 $-- $ 1,350 $ 630 2004 7,644 640 -- 6,329 1,955 2003 12,294 5,611 -- 10,261 7,644 Allowance for doubtful accounts: 2005 $ 9,175 $ 171 $-- $ 9,328 $ 18 2004 11,988 569 -- 3,382 9,175 2003 11,936 52 -- -- 11,988

S-2 Exhibit Index #2.1 Contribution Agreement between ONEOK, Inc. and Northern Border Intermediate Limited Partnership dated February 14, 2006. #2.2 Purchase and Sale Agreement by and between ONEOK, Inc. and Northern Border Partners, L.P. dated February 14, 2006. #2.3 Partnership Interest Purchase and Sale Agreement by and between Northern Border Intermediate Limited Partnership and TC PipeLines Intermediate Limited Partnership dated as of December 31, 2005. *3.1 Northern Border Partners, L.P. Certificate of Limited Partnership, Certificate of Amendment dated February 16, 2001, and Certificate of Amendment dated May 20, 2003 (incorporated by reference to Exhibit 3.1 to the Partnership's Form 10-K for the year ended December 31, 2004 (File No. 1-12202) ("2004 Form 10-K")). *3.2 Amended and Restated Agreement of Limited Partnership of Northern Border Partners, L.P. dated October 1, 1993 (incorporated by reference to Exhibit 3.2 to the 2004 Form 10-K). *3.3 Northern Border Intermediate Limited Partnership Certificate of Limited Partnership, Certificate of Amendment dated February 16, 2001, and Certificate of Amendment dated May 20, 2003 (incorporated by reference to Exhibit 3.3 to the 2004 10-K). *3.4 Amended and Restated Agreement of Limited Partnership for Northern Border Intermediate Limited Partnership dated October 1, 1993 (incorporated by reference to Exhibit 3.1 to the Partnership's Form 10-Q for the quarter ended March 31, 2005 (File No. 1-12202) ("March 2005 10-Q")). *4.1 Indenture, dated as of June 2, 2000, between Northern Border Partners, L.P., Northern Border Intermediate Limited Partnership and Bank One Trust Company, N.A., Trustee (incorporated by reference to Exhibit 4.1 to the Partnership's Form 10-Q for the quarter ended June 30, 2000 (File No. 1-12202) ("June 2000 10-Q")). *4.2 First Supplemental Indenture, dated as of September 14, 2000, between Northern Border Partners, L.P., Northern Border Intermediate Limited Partnership and Bank One Trust Company, N.A. (incorporated by reference to Exhibit 4.2 to the Partnership's Form S-4 Registration Statement filed on September 20, 2000, (Registration No. 333-46212) ("NBP Form S-4")). *4.3 Indenture, dated as of March 21, 2001, between Northern Border Partners, L.P. and Northern Border Intermediate Limited Partnership and Bank One Trust Company, N.A., Trustee (incorporated by reference to Exhibit 4.3 to the Partnership's Form 10-K for the year ended December 31, 2001 (File No. 1-12202)). *4.4 Indenture, dated as of August 17, 1999, between Northern Border Pipeline Company and Bank One Trust Company, NA, successor to The First National Bank of Chicago, Trustee. (incorporated by reference to Exhibit No. 4.1 to Northern Border Pipeline Company's Form S-4 Registration Statement filed on October 7, 1999, (Registration No. 333-88577) ("NB Form S-4")). *4.5 Indenture, dated as of September 17, 2001, between Northern Border Pipeline Company and Bank One Trust Company, N.A., Trustee (incorporated by reference to Exhibit 4.2 to Northern Border Pipeline Company's Registration Statement on Form S-4 filed on November 13, 2001, (Registration No. 333-73282) ("2001 NB Form S-4")). *4.6 Indenture, dated as of April 29, 2002, between Northern Border Pipeline Company and Bank One Trust Company, N.A., Trustee (incorporated by reference to Exhibit 4.1 to Northern Border Pipeline Company's Form 10-Q for the quarter ended March 31, 2002 (File No. 333-88577)). *10.1 Northern Border Pipeline Company General Partnership Agreement between Northern Plains Natural Gas Company, Northwest Border Pipeline Company, Pan Border Gas Company, TransCanada Border Pipeline Ltd. and TransCan Northern Ltd., effective March 9, 1978, as amended (incorporated by reference to Exhibit 10.2 to the Partnership's Form S-1 Registration Statement filed on July 16, 1993, (Registration No. 33-66158) ("Form S-1")). *10.2 Form of Seventh Supplement Amending Northern Border Pipeline Company General Partnership Agreement dated September 23, 1993 (incorporated by reference to Exhibit 10.15 to Form S-1). *10.3 Eighth Supplement Amending Northern Border Pipeline Company General Partnership Agreement dated May 21, 1999 (incorporated by reference to Exhibit 10.15 to NB Form S-4). *10.4 Ninth Supplement Amending Northern Border Pipeline Company General Partnership Agreement July 16, 2001 (incorporated by reference to Exhibit 10.37 to 2001 NB Form S-4). *10.5 Tenth Supplement Amending Northern Border Pipeline Company General Partnership Agreement dated March 2, 2005 (incorporated by reference to Exhibit 3.5 to Northern Border Pipeline's Form 10-K for the year ended December 31, 2004 filed on March 14, 2005 (File No. 333-88577)). *10.6 Operating Agreement between Northern Border Pipeline Company and Northern Plains Natural Gas Company, dated February 28, 1980 (incorporated by reference to Exhibit 10.3 to Form S-1). *10.7 Administrative Services Agreement between NBP Services Corporation, Northern Border Partners, L.P. and Northern Border Intermediate Limited Partnership (incorporated by reference to Exhibit 10.4 to Form S-1). *10.8 Revolving Credit Agreement, dated as of May 16, 2005, among Northern Border Partners, L.P., the lenders from time to time party thereto, SunTrust Bank, as administrative agent, Wachovia Bank, National Association, as syndication agent, Harris Nesbit Financing, Inc., Barclays Bank PLC and Citibank, N.A., as co-documentation agents, and SunTrust Capital Markets, Inc. and Wachovia Capital Markets, LLC, as co-lead arrangers and book managers (incorporated by reference to Exhibit 10.1 to the Partnership's current report on Form 8-K filed on May 20, 2005 (File No. 1-12202)). *10.9 First Amendment to the Revolving Credit Agreement effective June 13, 2005, among Northern Border Partners, L.P., the lenders from time to time party thereto, SunTrust Bank, as administrative agent, Wachovia Bank, National Association, as syndication agent and Harris Nesbit Financing, Inc., Barclays Bank PLC and Citibank, N.A., as co-documentation agents (incorporated by reference to Exhibit 10.2 to the Partnership's Form 10-Q for the quarter ended June 30, 2005 (File No. 1-12202)). *10.10 Revolving Credit Agreement, dated as of May 16, 2005, among Northern Border Pipeline Company, the lenders from time to time party thereto, Wachovia Bank, National Association, as administrative agent, SunTrust Bank, as syndication agent, Harris Nesbit Financing, Inc., Barclays Bank PLC and Citibank, N.A., as co-documentation agents, and Wachovia Capital Markets, LLC and SunTrust Capital Markets, Inc., as co-lead arrangers and book managers (incorporated by reference to Exhibit 10.1 to Northern Border Pipeline Company's current report on Form 8-K (File No. 333-88577) filed on May 20, 2005 (File No. 333-88577)). *10.11 Agreement between Northern Plains and Northern Border Intermediate Limited Partnership regarding the costs, expenses and expenditures arising under the operating agreement between Northern Plains and Guardian Pipeline, LLC (incorporated by reference to Exhibit 10.3 to the Partnership's Form 10-Q for the quarter ended March 31, 2004 (File No. 1-12202)). +*10.12 Form of Termination Agreement with ONEOK, Inc. dated as of January 5, 2005 (incorporated by reference to Exhibit 99.1 to the Partnership's current report on Form 8-K filed on January 11, 2005 (File No. 1-12202)). +*10.13 ONEOK, Inc. Equity Compensation Plan (incorporated by reference to Exhibit 10.1 to ONEOK's current report on Form 8-K filed on February 23, 2005 (File No. 1-13643)). +*10.14 ONEOK, Inc. Employee Stock Purchase Plan, as amended February 17, 2005 (incorporated by reference to Exhibit 10.2 to ONEOK's current report on Form 8-K filed on February 23, 2005 (File No. 1-13643)). +*10.15 ONEOK, Inc. 2005 Supplemental Executive Retirement Plan (incorporated by reference to Exhibit 99.2 to the Partnership's current report on Form 8-K filed on January 11, 2005 (File No. 1-12202)). +*10.16 ONEOK, Inc. Long-Term Incentive Plan (incorporated by reference to Exhibit 10(a) to ONEOK's Form 10-K for the year ended December 31, 2001 (File No. 1-13643)). +*10.17 ONEOK, Inc. Form of Restricted Stock Incentive Award pursuant to Long-Term Incentive Plan (incorporated by reference to Exhibit 10.4 to ONEOK's Form 10-Q for the quarterly period ended September 30, 2004 (File No. 1-13643)). +*10.18 ONEOK, Inc. Form of Performance Shares Award pursuant to Long-Term Incentive Plan (incorporated by reference to Exhibit 10.5 to ONEOK's Form 10-Q for the quarterly period ended September 30, 2004 (File No. 1-13643)). +*10.19 ONEOK, Inc. Employee Non-Qualified Deferred Compensation Plan, as amended, dated February 15, 2001 (incorporated by reference to Exhibit 10(g) to ONEOK's Form 10-K for the year ended December 31, 2001(File No. 1-13643)). +*10.20 ONEOK, Inc. Annual Officer Incentive Plan (incorporated by reference to Exhibit 10(f) to ONEOK's Form 10-K for the year ended December 31, 2001 (File No. 1-13643)). +10.21 ONEOK, Inc. Form of Restricted Unit Award Agreement pursuant to Equity Compensation Plan. +10.22 ONEOK, Inc. Form of Performance Unit Award Agreement pursuant to Equity Compensation Plan. *10.23 Operating Agreement between Midwestern Gas Transmission Company and Northern Plains Natural Gas Company dated as of April 1, 2001 (incorporated by reference to Exhibit 10.38 to the Partnership's Form 10-K for the year ended December 31, 2001 (File No. 1-12202)). *10.24 Operating Agreement between Viking Gas Transmission Company and Northern Plains Natural Gas Company dated as of January 17, 2003 (incorporated by reference to Exhibit 10.18 to the Partnership's Form 10-K for the year ended December 31, 2002 (File No. 1-12202)). *10.25 Northern Border Pipeline Company Agreement among Northern Plains Natural Gas Company, Pan Border Gas Company, Northwest Border Pipeline Company, TransCanada Border PipeLine Ltd., TransCan Northern Ltd., Northern Border Intermediate Limited Partnership, Northern Border Partners, L.P., and the Management Committee of Northern Border Pipeline, dated as of March 17, 1999 (incorporated by reference to Exhibit 10.21 to the Partnership's Form 10-K/A for the year ended December 31, 1998 (File No. 1-12202)). 12.1 Statement re computation of ratios. 21 List of subsidiaries. 23.1 Consent of KPMG LLP. 31.1 Rule 13a-14(a)/15d-14(a) certification of principal executive officer. 31.2 Rule 13a-14(a)/15d-14(a) Certification of principal financial officer. 32.1 Section 1350 certification of principal executive officer. 32.2 Section 1350 certification of principal financial officer. +*99.1 Northern Border Phantom Unit Plan (incorporated by reference to Exhibit 99.1 to Amendment No. 1 to the Partnership's Form S-8, Registration Statement filed on November 15, 2000 (Registration No. 333-66949)). * Indicates exhibits incorporated by reference as indicated; all other exhibits are filed herewith. + Management contract, compensatory plan or arrangement. # The Partnership agrees to furnish supplementally to the Securities and Exchange Commission, upon request, any schedules and exhibits to this agreement, as set forth in the Table of Contents of the agreement, that have not been filed herewith pursuant to Item 601(b)(2) of Regulation S-K.