TC Pipelines, LP
Annual Report 2004

Plain-text annual report

TC PIPELINES, LP is a United States limited partnership that offers investors stable cash flow and growth prospects. TC PipeLines owns a 30 per cent interest in Northern Border Pipeline Company and a 49 per cent interest in Tuscarora Gas Transmission Company. Both Northern Border Pipeline and Tuscarora own interstate pipeline systems that transport western Canadian natural gas to growing natural gas consuming markets in the midwestern United States and northern Nevada areas, respectively. The Partnership is managed by its general partner, TC PipeLines GP, Inc., a wholly owned subsidiary of TransCanada Corporation, a leading North American energy company. T C P I P E L I N E S , L P 2 0 0 4 A N N U A L R E P O R T 2004 Annual Report TC PIPELINES, LP Our goal is to deliver stable, sustainable cash flows to unitholders and to find opportunities to increase cash distributions while maintaining a low-risk profile. FINANCIAL HIGHLIGHTS Year ended December 31 2004 2003 2002 2001 2000 (millions of dollars, except per unit amounts) Income Statement Net income 55.1 48.0 45.5 43.5 37.2 Net income per unit $ 2.99 $ 2.63 $ 2.50 $ 2.40 $ 2.08 Cash Flow Cash generated from operations Cash distributions paid 55.2 41.8 49.6 39.4 52.1 37.4 42.9 35.2 40.3 32.6 Cash distributions declared per unit $ 2.275 $ 2.175 $ 2.075 $ 1.975 $ 1.850 Balance Sheet Total assets Long-term debt Partners’ equity 332.1 36.5 294.9 288.1 5.5 282.0 286.0 11.5 273.9 288.7 21.5 266.7 277.5 21.5 255.4 Our Assets 1 Letter to Unitholders 2 Form 10-K 3 Financial Statements F-1 TC PIPELINES, LP 110 Turnpike Road, Suite 203, Westborough, Massachusetts, US 01581 Telephone (508) 871-7046 Facsimile (508) 871-7047 450 – First Street SW, Calgary, Alberta, Canada T2P 5H1 Telephone (877) 290-2772 Facsimile (403) 920-2457 Investor Relations Telephone (877) 290-2772 Facsimile (403) 920-2457 E-mail: investor_relations@tcpipelineslp.com Internet Site www.tcpipelineslp.com K-1 Information Telephone (877) 699-1091 Stock Exchange Listing NASDAQ Stock Market: TCLP Auditors KPMG LLP, Calgary, Alberta Transfer Agent Mellon Investor Services LLC, Ridgefield Park, New Jersey Telephone (800) 756-3353 Please recycle April 2005 Printed in Canada Designed and produced by smith + associates www.smithandassoc.com Cash Distributions(dollars per unit)0001020401.8501.9752.075032.1752.275Net Income(dollars per unit)0001020402.082.402.50032.632.99T C P I P E L I N E S , L P 1 OUR ASSETS TC PIPELINES OWNERSHIP ACQUIRED BY TC PIPELINES COMMENCED OPERATIONS ORIGINATES NEAR TERMINATES NEAR LENGTH (MILES) RECEIPT CAPACITY (MMcfd (1)) EQUITY INCOME – TC PIPELINES’ SHARE (MILLIONS OF DOLLARS) Northern Border Pipeline Tuscarora 30% May 28, 1999 1982 Port of Morgan, MT North Hayden, IN 1,249 2,370 49% September 1, 2000 1995 Malin, OR Wadsworth, NV 240 190 Ron Turner, centre, opened the NASDAQ stock exchange on May 25, 2004 to celebrate the fifth anniversary of TC PipeLines’ listing on the exchange. Board of Directors and management team joined in the celebration. CASH FLOW – TC PIPELINES’ SHARE (MILLIONS OF DOLLARS) (1) Millions of cubic feet per day. Common units of TC PipeLines are listed on the NASDAQ Stock Market and trade under the symbol “TCLP”. Cautionary Statement Regarding Forward-Looking Information This annual report includes forward-looking statements regarding future events and our future financial performance. All forward-looking statements are based on our beliefs as well as assumptions made by and information currently available to us. Words such as “believes,” “expects,” “intends,” “forecasts,” “projects,” and similar expressions, identify forward-looking statements. These statements reflect our current views with respect to future events and are subject to various risks, uncertainties and assumptions which we discuss in detail in our Form 10-K for the year ended December 31, 2004 and other filings made with the SEC. If one or more of these risks or uncertainties materialize, or if the underlying assumptions prove incorrect, actual results may vary materially from those described in the forward-looking statement. TuscaroraNorthern Border Pipeline122100010204040.542.949.20346.261.760204000010204060204038.142.142.80344.550.00001020400.93.64.7035.37.59360001020401.52.44.6036.27.99362 T C P I P E L I N E S , L P Our investments in Northern Border Pipeline and Tuscarora Gas Transmission Company delivered strong earnings and cash flow performance again in 2004. This enabled us to increase cash distributions to unitholders by almost 5 per cent again this year, the fifth distribution increase since we began operations in 1999. LETTER TO UNITHOLDERS Changes in both the market demand and supply landscape for natural gas have become evident in recent years. We expect that North American natural gas demand will grow in large part due to the needs of the power generation sector. For Northern Border Pipeline, expiring transportation contracts, a maturing of the Western Canada Sedimentary Basin, competition from other supply basins and pipelines, and other short-term factors have increased the risk that lower-than-historical revenues could be experienced in future. Northern Border Pipeline has adjusted its capital structure to appropriately reflect the current business environment. We do, however, continue to view Northern Border Pipeline as one of the most competitive routes to transport natural gas out of western Canada and as a result, the pipeline should be able to maintain its relatively high utilization levels. Much of the success of TC PipeLines has been achieved through expansion of our existing pipeline investments. In 2004, Northern Border Pipeline announced that it has received commitments from shippers sufficient to support a proposed expansion of its pipeline system into the Chicago market area. The “Chicago III Expansion Project” would expand capacity of the Northern Border Pipeline from Harper, Iowa, to Chicago by approximately 130 mmcfd or approximately 15 per cent to meet additional demand on this segment of the pipeline system. The project would add a 16,000 horsepower compressor in Iowa and make minor modifications to existing facilities. Capital costs are estimated to be approximately $21 million and the target in-service date is spring 2006. As for Tuscarora, although the planned 2005 expansion to meet increased demand in the Reno area has been cancelled as a result of customers taking capacity on a competing pipeline, Tuscarora received full reimbursement for all costs incurred and those shippers who are also existing shippers on Tuscarora, agreed to extend their existing contracts. As a result, the weighted average transportation contract term increased from 11.5 years on December 31, 2003 to 12.6 years on December 31, 2004. Separately, Tuscarora is planning to construct in June 2005 a short lateral to provide 20 mmcfd of transportation service to a new electric generation customer located near Tracy, Nevada. Operationally, daily throughput records have been set during November and December of 2004. Since inception, TC Pipelines has focussed on investing in natural gas transmission assets that connect supply to growing natural gas consuming markets. We have grown through expanding existing facilities and have taken a disciplined approach to pursuing acquisitions. This strategy has served us well and has resulted in a very positive result for our unitholders. On behalf of TC Pipelines, LP Ronald J. Turner President and Chief Executive Officer TC PipeLines GP, Inc. March 11, 2005 2 0 0 4 A N N U A L R E P O RT 3 UNITED STATES SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 F O R M 10-K [X] Annual Report Pursuant to Section 13 or 15 (d) of the Securities Exchange Act of 1934 For the fiscal year ended December 31, 2004 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: 000-26091 TC PIPELINES, LP (Exact name of registrant as specified in its charter) DELAWARE (State or other jurisdiction of incorporation or organization) 52-2135448 (I.R.S. Employer Identification No.) 110 TURNPIKE ROAD, SUITE 203 WESTBOROUGH, MASSACHUSETTS 01581 (Address of principal executive offices) (zip code) Registrant’s telephone number, including area code: 508-871-7046 Securities registered pursuant to Section 12(b) of the Act: NONE Securities registered pursuant to Section 12(g) of the Act: COMMON UNITS REPRESENTING LIMITED PARTNER INTERESTS Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes [X] No [ ] Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [X] Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act). Yes [X] No [ ] Aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant, as at June 30, 2004, was approximately $381.7 million. As of March 3, 2005, there were 17,500,000 of the registrant’s common units outstanding. 4 T C P I P E L I N E S , L P TC PIPELINES, LP TABLE OF CONTENTS PART I Item 1. Item 2. Item 3. Item 4. PART II Business Properties Legal Proceedings Submission of Matters to a Vote of Security Holders Selected Financial Data Item 5. Market for Registrant’s Common Units and Related Security Holder Matters Item 6. Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations Item 7A. Quantitative and Qualitative Disclosures About Market Risk Item 8. Item 9. Item 9A. Controls and Procedures Item 9B. Other Information Financial Statements and Supplementary Data Changes in and Disagreements with Accountants on Accounting and Financial Disclosure PART III Item 10. Directors and Executive Officers of the General Partner of the Registrant Item 11. Item 12. Executive Compensation Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters Item 13. Certain Relationships and Related Transactions Item 14. Principal Accountants Fees and Services PART IV Item 15. Exhibits and Financial Statement Schedules All amounts are stated in United States dollars unless otherwise indicated. Page No. 5 16 17 17 18 19 20 44 45 45 45 45 46 49 50 51 52 53 2 0 0 4 A N N U A L R E P O RT 5 PA RT I Item 1. Business BUSINESS OF TC PIPELINES, LP TC PipeLines, LP was formed in 1998 as a Delaware limited partnership to acquire, own and participate in the management of United States-based pipeline assets. TC PipeLines, LP and its subsidiary limited partnerships, TC PipeLines Intermediate Limited Partnership and TC Tuscarora Intermediate Limited Partnership, are collectively referred to herein as “TC PipeLines” or “the Partnership.” TC PipeLines GP, Inc., an indirect wholly owned subsidiary of TransCanada Pipelines Limited, which is a wholly owned subsidiary of TransCanada Corporation (TransCanada), is the general partner of the Partnership. The Partnership owns a 30% general partner interest in Northern Border Pipeline Company (Northern Border Pipeline). The remaining 70% general partner interest in Northern Border Pipeline is held by Northern Border Partners, L.P., a publicly traded limited partnership that is controlled by ONEOK, Inc. (ONEOK). TransCanada holds a minority general partner interest in Northern Border Partners which entitles it to 12.25% of the voting power of Northern Border Pipeline. TC PipeLines also owns a 49% general partner interest in Tuscarora Gas Transmission Company (Tuscarora). The Partnership acquired this interest from TCPL Tuscarora Ltd., an indirect subsidiary of TransCanada, in September 2000. Tuscarora Gas Pipeline Co., a wholly owned subsidiary of Sierra Pacific Resources, holds a 50% general partner interest and TCPL Tuscarora Ltd., an indirect wholly owned subsidiary of TransCanada, holds the remaining 1% general partner interest in Tuscarora. At December 31, 2004, the Partnership had 17,500,000 common units outstanding, of which 11,890,694 were held by the public, 2,800,000 were held by an affiliate of the general partner and 2,809,306 were held by the general partner. TransCanada, by virtue of its ownership of the Partnership’s general partner, holds an aggregate 2% general partner interest in the Partnership. The general partner also owns 2,809,306 common units and receives incentive distributions if quarterly cash distributions on the common units exceed levels specified in the partnership agreement (see Item 5. “Market for Registrant’s Common Units and Related Security Holder Matters”). The Partnership’s 30% general partner interest in Northern Border Pipeline and 49% general partner interest in Tuscarora represent its only material assets. BUSINESS OF NORTHERN BORDER PIPELINE COMPANY General Northern Border Pipeline is a general partnership formed in 1978. Northern Border Pipeline’s general partners are TC PipeLines and Northern Border Partners, L.P. (Northern Border Partners), both of which are publicly traded limited partnerships. Each of TC PipeLines and Northern Border Partners holds its interest in Northern Border Pipeline, representing 30% and 70% of voting power, respectively, through a subsidiary limited partnership. The general partner of TC PipeLines, TC PipeLines GP, Inc., is an indirect subsidiary of TransCanada. The general partners of Northern Border Partners and its subsidiary limited partnership are Northern Plains Natural Gas Company (Northern Plains) and Pan Border Gas Company (Pan Border), both subsidiaries of ONEOK, and Northwest Border Pipeline Company, a subsidiary of TransCanada. 6 T C P I P E L I N E S , L P Northern Border Pipeline owns an interstate pipeline system that transports natural gas from the Montana- Saskatchewan border to natural gas markets in the midwestern United States. The Northern Border Pipeline system connects with multiple pipelines that provide shippers with access to the various natural gas markets served by those pipelines. Northern Border Pipeline advises it estimates that for the year ended December 31, 2004, it transported approximately 22% of the total amount of natural gas imported to the United States from Canada. Over the same period, approximately 88% of the natural gas transported was produced in the Western Canada Sedimentary Basin (WCSB) located in the provinces of Alberta, British Columbia and Saskatchewan. Northern Border Pipeline transports gas for shippers under a tariff regulated by the Federal Energy Regulatory Commission (FERC). The tariff specifies the maximum and minimum transportation rates and the general terms and conditions of transportation service on the pipeline system. Northern Border Pipeline’s revenues are derived from agreements for the receipt and delivery of gas at points along the pipeline system as specified in each shipper’s individual transportation contract. Northern Border Pipeline does not own the natural gas that it transports, and therefore it does not assume natural gas commodity price risk for quantities transported. Any exposure to commodity risk for imbalances on Northern Border Pipeline’s system that may result from under or over deliveries to customers or interconnecting pipelines is either recovered through provisions in Northern Border Pipeline’s tariff or is immaterial. Northern Border Pipeline owns the line pack, which is the amount of gas necessary to maintain efficient operations of the pipeline. Northern Border Pipeline’s shippers are responsible to provide fuel gas necessary for the operation of gas compressor stations. Northern Border Pipeline’s management is overseen by a four-member management committee. Three representatives are designated by Northern Border Partners, with each of its general partners selecting one representative and one representative is designated by TC PipeLines. Voting power on the management committee is allocated among Northern Border Partners’ three representatives in proportion to their general partner interests in Northern Border Partners. As a result, the 70% voting power of Northern Border Partners’ three representatives on the management committee is allocated as follows: 35% to the representative designated by Northern Plains, 22.75% to the representative designated by Pan Border and 12.25% to the representative designated by Northwest Border. Northern Plains and Pan Border are subsidiaries of ONEOK. Therefore, ONEOK controls 57.75% of the voting power of the Northern Border Pipeline management committee and has the right to select two of the members. In November 2004, ONEOK purchased Northern Plains and Pan Border from CCE Holdings, LLC (CCE Holdings). CCE Holdings, a joint venture between Southern Union Company and GE Commercial Finance Energy Financial purchased Northern Plains, Pan Border and NBP Services, LLC as part of its acquisition of CrossCountry Energy, LLC (CrossCountry). See Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations of Northern Border Pipeline Company – The Impact of Enron’s Chapter 11 Filing on Northern Border Pipeline’s Business.” The Northern Border Pipeline system is operated by Northern Plains pursuant to an operating agreement. As of December 31, 2004, Northern Plains employed approximately 230 individuals located at its headquarters in Omaha, Nebraska and at various locations along the pipeline route and also used employees and information technology systems of its affiliates to provide its services. Northern Plains’ employees are not represented by any labor union and are not covered by any collective bargaining agreements. The Northern Border Pipeline System Northern Border Pipeline owns a 1,249-mile interstate pipeline system that transports natural gas from the Montana- Saskatchewan border near Port of Morgan, Montana to natural gas markets in the midwestern United States. Construction of the pipeline was initially completed in 1982. The Northern Border Pipeline system was expanded and/or extended in 1991, 1992, 1998 and 2001. The Northern Border Pipeline system connects directly and through multiple pipelines to various natural gas markets in the United States. 2 0 0 4 A N N U A L R E P O RT 7 The Northern Border Pipeline system consists of: (i) 822 miles of 42-inch diameter pipe from the Canadian border to Ventura, Iowa, capable of transporting, on a summer design basis, a total of 2,374 million cubic feet per day (mmcfd); (ii) 30-inch diameter pipe and 36-inch diameter pipe, each approximately 147 miles in length, capable of transporting 1,484 mmcfd in total from Ventura, Iowa to Harper, Iowa; (iii) 224 miles of 36-inch diameter pipe and 21 miles of 30-inch diameter pipe capable of transporting 844 mmcfd from Harper, Iowa to Manhattan, Illinois (Chicago area); and (iv) 35 miles of 30-inch diameter pipe capable of transporting 544 mmcfd from the Chicago area to a terminus near North Hayden, Indiana. A summer design basis pipeline is capable of transporting, at a minimum, the stated capacity at all times of the year. Along the pipeline there are 16 compressor stations with total rated horsepower of 499,000 and measurement facilities to support the receipt and delivery of gas at various points. Other facilities include four field offices and a microwave communication system with 50 tower sites. The Northern Border Pipeline system has pipeline access to natural gas reserves in the WCSB in the provinces of Alberta, British Columbia and Saskatchewan in Canada, domestic natural gas produced within the Williston Basin and the Powder River Basins, and synthetic gas produced at the Dakota Gasification plant in North Dakota. In addition, the Northern Border Pipeline system is capable of physically receiving natural gas at two locations near Chicago. For the year ended December 31, 2004, of the natural gas transported on the Northern Border Pipeline system, approximately 88% was produced in Canada, approximately 4% was produced by the Dakota Gasification plant and approximately 8% was produced in the Williston Basin. Interconnects To access markets, the Northern Border Pipeline system interconnects with pipeline facilities of various interstate and intrastate pipeline companies and local distribution companies, as well as with end-users. The larger interconnections are with the pipeline facilities of: • Northern Natural Gas Company at Ventura, Iowa as well as multiple smaller interconnections in South Dakota, Minnesota and Iowa; • Natural Gas Pipeline Company of America at Harper, Iowa; • MidAmerican Energy Company at Iowa City and Davenport, Iowa and Cordova, Illinois; • Alliant Power Company at Prophetstown, Illinois; • Northern Illinois Gas Company at Troy Grove and Minooka, Illinois; • Midwestern Gas Transmission Company, a wholly owned subsidiary of Northern Border Partners, near Channahon, Illinois; • ANR Pipeline Company near Manhattan, Illinois; • Vector Pipeline L.P. in Will County, Illinois; • Guardian Pipeline, L.L.C., an affiliate of Northern Border Partners, in Will County, Illinois; • The Peoples Gas Light and Coke Company near Manhattan, Illinois; and • Northern Indiana Public Service Company near North Hayden, Indiana at the terminus of the pipeline system. Several market centers, where natural gas transported on the Northern Border Pipeline system is sold, traded and received for transport to consuming markets in the Midwest and to interconnecting pipeline facilities, have developed on the Northern Border Pipeline system. The largest of these market centers is at Northern Border Pipeline’s Ventura, Iowa interconnection with Northern Natural Gas Company. Two other market center locations are the Harper, Iowa connection with Natural Gas Pipeline Company of America and Northern Border Pipeline’s multiple interconnects in the Chicago area that include connections with Northern Illinois Gas Company, The Peoples Gas Light and Coke Company and Northern Indiana Public Service Company, as well as four interstate pipelines. 8 T C P I P E L I N E S , L P Shippers All of Northern Border Pipeline’s summer design capacity was under contract as of December 31, 2004 and assuming no extensions of existing contracts or execution of new contracts, approximately 61% and 51% of summer design capacity is under contract as of December 31, 2005 and 2006, respectively. The Northern Border Pipeline system serves approximately 40 firm transportation shippers with diverse operating and financial profiles. Based upon shippers’ contractual obligations, as of December 31, 2004, 92% of firm capacity contracted is with producers and marketers. The remaining firm capacity contracted is primarily with local distribution companies (7%) and end-users (1%). As of December 31, 2004, the termination dates of these contracts ranged from December 31, 2004 to December 21, 2013, and the weighted average contract life was approximately 2.75 years based upon contractual obligations and summer design capacity. See Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations of Northern Border Pipeline Company – Overview.” Northern Border Pipeline’s shippers may change throughout the year as a result of Northern Border Pipeline’s shippers utilizing capacity release provisions that allow them to release all or part of their capacity, either permanently for the full term of their contract or temporarily. Under the terms of Northern Border Pipeline’s tariff, a temporary capacity release does not relieve the originally contracted shipper from its payment obligations if the new shipper fails to pay. At December 31, 2004, Nexen Marketing U.S.A. Inc., BP Canada Energy Marketing Corp., EnCana Marketing U.S.A. Inc., and Cargill Incorporated were obligated for approximately 18%, 14%, 13% and 12%, respectively, of Northern Border Pipeline’s summer design capacity. Contracts for approximately 63% of the capacity contracted by these shippers are due to expire by November 1, 2005. See Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations of Northern Border Pipeline Company – Overview.” One of Northern Border Pipeline’s shippers, ONEOK Energy Services Company, LP, (ONEOK Energy), a subsidiary of ONEOK, is affiliated with Northern Border Pipeline. ONEOK Energy holds firm contracts representing 3% of summer design capacity. ONEOK Energy has also committed to be a shipper on the Chicago III Expansion project. Demand for Transportation Capacity Recent developments have resulted in a proposed expansion of Northern Border Pipeline’s system. In September 2004, Northern Border Pipeline announced it had received commitments from shippers sufficient to support a proposed expansion of its pipeline system into the Chicago market area. The “Chicago III Expansion” project, with 130 mmcfd of capacity, would involve construction of a new compressor station and minor modifications to two other compressor stations, and is estimated to cost approximately $21 million. The projected in-service date is April 1, 2006. FERC approval of this project is required and Northern Border Pipeline expects to file the required certificate application in March 2005. Northern Border Pipeline’s long-term financial condition is dependent on the continued availability of economic western Canadian natural gas supplies for import into the United States. Natural gas reserves may require significant capital expenditures by others for exploration and development drilling and the installation of production, gathering, storage, transportation and other facilities that permit natural gas to be produced and delivered to pipelines that interconnect with the interstate pipelines’ systems. Prices for natural gas, the currency exchange rate between Canada and the United States, regulatory limitations or the lack of available capital for these projects could adversely affect the development of additional reserves and production, gathering, storage and pipeline transmission of western Canadian natural gas supplies. Increased Canadian consumption of natural gas related to the extraction process for oil sands projects as well as restrictions on gas production to protect oil sand reserves could also impact supplies of natural gas for export. Additional pipeline export capacity also could accelerate depletion of these reserves. Furthermore, the availability of export capacity could also affect the demand or value of the transport on the Northern Border Pipeline system. Northern Border Pipeline’s business also depends on the level of demand for natural gas in the markets the Northern Border Pipeline system serves. The volumes of natural gas delivered to these markets from other sources affect the demand for both the natural gas supplies and the use of the Northern Border Pipeline system. Demand for natural gas to serve other markets also influences the ability and willingness of shippers to use the Northern Border Pipeline system to meet demand in the markets that it serves. A variety of factors could affect the demand for natural gas in the markets that the Northern Border Pipeline system serves. These factors include: 2 0 0 4 A N N U A L R E P O RT 9 economic conditions; fuel conservation measures; alternative energy sources’ requirements and prices; • • • • gas storage inventory levels; • • government regulation; and • climatic conditions; technological advances in fuel economy and energy generation devices. Interstate pipelines’ primary exposure to market risk occurs at the time existing transportation contracts expire and are subject to renegotiation. A key determinant of the capacity value for shippers that have competitive pipeline alternatives is the basis differential, or market price spread, between two points on the pipeline. The difference in natural gas prices between the points along the pipeline where gas enters and where gas is delivered represents the gross margin that a shipper can expect to achieve from holding transportation capacity at any point in time. This margin and its variability become important factors in determining the transportation rate customers are willing to pay when they renegotiate their transportation contracts. The basis differential between markets can be affected by trends in production, available capacity, storage inventories, weather and general market demand in the respective areas. Throughput on the Northern Border Pipeline system may experience seasonal fluctuations depending upon the level of winter heating load demand or summer electric generation usage in the markets it serves. To the extent that capacity is contracted at maximum rates under firm transportation agreements, Northern Border Pipeline advises that 98% of the expected charges are from demand charges that are not impacted materially by such seasonal throughput variations. However, as contracts terminate, renewals and replacements may be affected by seasonal fluctuations and historic usage patterns. See Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations of Northern Border Pipeline Company – Overview.” Northern Border Pipeline advises that it cannot predict whether these or other factors will have an adverse effect on demand for use of its pipeline system or how significant that adverse effect could be. Interstate Pipeline Competition Northern Border Pipeline competes with other pipeline companies that transport natural gas from the WCSB or that transport natural gas to end-use markets in the midwestern United States. Northern Border Pipeline’s competitive position is affected by the availability of Canadian natural gas for export, the availability of other sources of natural gas and demand for natural gas in the United States. Demand for transportation services on the Northern Border Pipeline system is affected by natural gas prices, the relationship between export capacity and production in the WCSB and from natural gas shipped from producing areas in the United States. Shippers of natural gas produced in the WCSB also have other options to transport Canadian natural gas to the United States, including transportation on: • Alliance Pipeline to the Chicago market area; • TransCanada’s pipeline system through various interconnections with U.S. interstate pipelines in the upper Midwest, including Viking Gas Transmission Company which is owned by Northern Border Partners; • Westcoast Pipeline and TransCanada B.C. systems; and • Various interconnections with U.S. interstate pipelines serving northwest and west coast markets. 10 T C P I P E L I N E S , L P In the near term, Northern Border Pipeline’s short-term contracted capacity competes primarily with available and short-term capacity on the TransCanada and Westcoast pipelines. Alliance Pipeline is not a competitor in the short- term for Northern Border Pipeline since substantially all of its capacity is contracted under long-term contracts. In addition, Northern Border Pipeline competes in its markets with other interstate pipelines that provide access to other supply basins. Northern Border Pipeline’s major deliveries into Northern Natural Gas at Ventura, Iowa compete with gas supplied from the Rockies and mid-continent regions. Northern Border Pipeline also competes with these supply basins at its delivery interconnect with Natural Gas Pipeline at Harper, Iowa. In the Chicago area, Northern Border Pipeline competes with many interstate pipelines that transport gas from the Gulf Coast, mid-continent, Rockies and western Canada. In December 2004, the Cheyenne Plains Pipeline system commenced service from the Cheyenne Hub in the Rocky Mountain area to the mid-continent area. The pipeline will provide additional supply and transportation competition in markets served by Northern Border Pipeline. The supply balance in the mid-continent area can impact the value of gas that is traded at the Ventura, Iowa and Harper, Iowa delivery points and gas traded in the Chicago area. A change in trading value at these market centers will affect the corresponding transportation value of that portion of the Northern Border Pipeline system upstream and downstream of these trading centers. FERC Regulation Northern Border Pipeline is subject to extensive regulation by the FERC as a “natural gas company” under the Natural Gas Act. Under the Natural Gas Act and the Natural Gas Policy Act, the FERC has jurisdiction with respect to virtually all aspects of Northern Border Pipeline’s business, including: transportation of natural gas; rates and charges; construction of new facilities; extension or abandonment of service and facilities; accounts and records; • • • • • • depreciation and amortization policies; • • the acquisition and disposition of facilities; and the initiation and discontinuation of services. Where required, Northern Border Pipeline holds certificates of public convenience and necessity issued by the FERC covering its facilities, activities and services. Under Section 8 of the Natural Gas Act, the FERC has the power to prescribe the accounting treatment for items for regulatory purposes. Northern Border Pipeline’s books and records may be periodically audited by the FERC under Section 8. The FERC regulates the rates and charges for transportation in interstate commerce. Natural gas companies may not charge rates that have been determined not to be just and reasonable by the FERC. Generally, rates are based on the cost of service including recovery of and a return on the pipeline’s actual prudent historical cost investment. In addition, the FERC prohibits natural gas companies from unduly preferring or unreasonably discriminating against any person with respect to pipeline rates or terms and conditions of service. Some types of rates may be discounted without further FERC authorization and rates may be negotiated subject to FERC approval. The rates and terms and conditions for Northern Border Pipeline’s service are found in its FERC approved tariff. Transportation rates are established in FERC proceedings known as rate cases. Under Northern Border Pipeline’s tariff, Northern Border Pipeline is allowed to charge for its services on the basis of stated transportation rates established in its 1999 rate case. Northern Border Pipeline may also provide services under negotiated and discounted rates. Generally, firm shippers are obligated to pay a monthly demand charge, regardless of the amount of natural gas they actually transport, for the term of their contracts. Approximately 98% of the revenue generated is attributed to demand charges. The remaining 2% of the agreed upon revenue level is attributed to commodity charges based on the volumes of gas actually transported. 2 0 0 4 A N N U A L R E P O RT 11 Under the terms of settlement in Northern Border Pipeline’s 1999 rate case, neither Northern Border Pipeline’s existing shippers nor Northern Border Pipeline can seek rate changes until November 1, 2005, at which time Northern Border Pipeline must file a rate case. Prior to this rate case, Northern Border Pipeline will not be permitted to increase rates if costs increase or if its contracted demand decreases, nor will Northern Border Pipeline be required to reduce rates based on cost savings. As a result, Northern Border Pipeline’s earnings and cash flow will depend on costs incurred, contracted capacity, the volumes of gas transported and its ability to recontract capacity at acceptable rates. Until new depreciation rates are approved by the FERC, Northern Border Pipeline continues to depreciate its transmission plant at the FERC approved annual depreciation rate. Northern Border Pipeline’s annual depreciation rate on transmission plant in service is 2.25%. The effects of accumulated depreciation may be offset by acquiring or constructing assets that replace or add to existing pipeline facilities or by adding new facilities or Northern Border Pipeline’s transportation rates may be decreased. In Northern Border Pipeline’s 1995 rate case, the FERC addressed the issue of whether the federal income tax allowance included in Northern Border Pipeline’s proposed cost of service was reasonable in light of previous FERC rulings. In those previous rulings, the FERC held that an interstate pipeline is not entitled to a tax allowance for income attributable to limited partnership interests held by individuals. The settlement of Northern Border Pipeline’s 1995 rate case provided that until at least December 2005, Northern Border Pipeline could continue to calculate the allowance for income taxes in the manner it had historically used. In addition, a settlement adjustment mechanism was implemented, which effectively reduced the return on rate base. These provisions of the 1995 rate case were maintained in the settlement of Northern Border Pipeline’s 1999 rate case. On July 20, 2004, the D.C. Circuit Court of Appeals issued an opinion in BP West Coast Products, LLC v. FERC that reversed the FERC decision that provided for an income tax allowance in the rates for a third party pipeline. The D.C. Circuit Court remanded the case to the FERC for its determination regarding the proper income tax allowance. On December 2, 2004, the FERC initiated an inquiry open to all interested parties on whether the court’s ruling applies only to the specific facts of BP West Coast or if it extends to other capital structures involving partnerships and other forms of ownership. The inquiry did not propose a particular rule. The FERC inquired how the decision in BP West Coast may impact investment in energy infrastructure and if there are other methods in providing an opportunity to earn an adequate return that are not dependent on the tax implications of a particular capital structure. Approximately 50 separate comments were filed by trade associations, investor groups, producers, natural gas pipelines, electric utilities, oil pipelines, and customers in January 2005. A number of comments, including Northern Border Pipeline, suggested that an income tax allowance is a proper element of a pipeline’s cost of service for all jurisdictional entities regardless of legal structure. Some producers’ and customers’ comments argued against the inclusion of an income tax allowance for partnerships and other non-tax paying entities. It is not certain how, or when, the FERC may proceed with respect to its Request for Comments or the effect on Northern Border Pipeline. In particular, Northern Border Pipeline is a general partnership whose rates include an allowance for income taxes. Northern Border Pipeline’s specific circumstances regarding its tariff, deferred income tax treatment, FERC orders, past history and underlying agreements with shippers are different from those underlying the BP West Coast case. The issue of whether the inclusion of an income tax allowance in Northern Border Pipeline’s rates is applicable, in light of the FERC and court rulings, may be addressed in Northern Border Pipeline’s 2005 rate case. Northern Border Pipeline is subject to the requirements of FERC Order Nos. 497 and 566, which prohibit preferential treatment of transportation service providers’ marketing affiliates and govern how information may be provided to those marketing affiliates. On November 25, 2003, the FERC issued a final rule, Order No. 2004, adopting new standards of conduct for transmission providers when dealing with their energy affiliates. Additional orders modifying Order 12 T C P I P E L I N E S , L P No. 2004 were issued on April 16, August 2 and December 21, 2004. Transmission providers were required to comply with the standards of conduct by September 22, 2004. The standards of conduct are designed to prevent transmission providers from giving undue preferences to any of their energy affiliates. The final rule generally requires that transmission function employees operate independently of the marketing function employees and energy affiliates. As required of all transmission providers, Northern Border Pipeline posted its standards of conduct to its website on September 22, 2004. By definition, Bear Paw Energy, LLC, a subsidiary of Northern Border Partners and ONEOK Energy, as well as other subsidiaries of ONEOK, are energy affiliates. Prior to September 22, 2004, Northern Border Pipeline’s operator, Northern Plains provided after hours and weekend gas control services for Bear Paw Energy, LLC and Crestone Energy Ventures, also a subsidiary of Northern Border Partners that resulted in some cost savings to Northern Border Pipeline. Northern Border Pipeline has requested a waiver, which is still pending at the FERC, to permit Northern Plains to resume after hours and weekend gas control services for Bear Paw Energy, LLC and Crestone Energy Ventures. On July 17, 2002, the FERC issued a Notice of Inquiry Concerning Natural Gas Pipeline Negotiated Rate Policies and Practices. Subsequently, the FERC issued an order on July 25, 2003, modifying its prior policy on negotiated rates. The FERC ruled that it would no longer permit the pricing of negotiated rates based upon natural gas commodity price indices. Negotiated rates based upon such indices may continue until the end of the contract period for which such rates were negotiated, but such rates will not be prospectively approved by FERC. FERC also imposed certain requirements on other types of negotiated rate transactions to ensure that the agreements embodying such transactions do not materially differ from the terms and conditions set forth in the tariff of the pipeline entering into the transaction. Northern Border Pipeline advises that this FERC ruling is not expected to have a material effect on Northern Border Pipeline’s business. Recent FERC orders in proceedings involving other natural gas pipelines have addressed certain aspects of a pipeline’s creditworthiness provisions set forth in its tariffs. In addition, industry groups, such as the North American Energy Standards Board (NAESB), are studying creditworthiness standards. On February 12, 2004, the FERC issued a Notice of Proposed Rulemaking to require interstate pipelines to follow standardized procedures for determining the creditworthiness of their shippers. The proposed rule would incorporate by reference ten consensus standards passed within NAESB and would adopt additional standards requiring, among other things, standardization of information shippers provide to establish credit, collateral requirements for service, procedures for suspension and termination for non-creditworthy shippers and procedures governing capacity release transactions. The enactment of some of these standards may have the effect of easing certain creditworthiness requirements and parameters currently reflected in Northern Border Pipeline’s tariffs on existing transportation capacity. However, recent FERC orders, and this proposed rule, continue to allow more stringent collateral requirements for the construction of new facilities by a pipeline. Northern Border Pipeline advises that it cannot predict the ultimate impact, if any on its business of any resulting final rule. In February 2004, the FERC adopted new quarterly financial reporting requirements and accelerated the filing date for interstate pipeline’s annual financial report. The quarterly reports include a basic set of financial statements and other selected data and are submitted electronically. Northern Border Pipeline advises that there is no impact for complying with these requirements other than the time and additional expense for preparation of these reports. In November 2004, the FERC issued a Notice of Proposed Accounting Release (PAR) to provide guidance on the accounting for costs of pipeline assessment programs required under the Pipeline Safety Improvement Act of 2002 and regulations established thereunder. The PAR concluded that such costs should be treated as maintenance costs. Comments have been filed by the Interstate Natural Gas Association of America as well as individual pipelines setting forth the arguments that these costs should be capitalized. 2 0 0 4 A N N U A L R E P O RT 13 In November 2004, the FERC issued a Notice of Inquiry on selective discounting particularly as it relates to allowing discount adjustments for contracts resulting from competition between interstate pipelines referred to as gas-on-gas competition. The FERC noted that in several proceedings, parties have objected to the FERC’s current discounting policy, allowing selective discounting for gas-on-gas competition, on the grounds that it no longer benefits captive customers by allowing fixed costs to be spread over more units of service. These parties have argued that while benefits may still exist to the extent a discount is given to a customer who would otherwise use an alternative fuel and not ship gas at all, benefits do not exist in situations where discounts are given to meet competition from other gas pipelines. Although the FERC has not disallowed discount adjustments for gas-on-gas competition, the Notice of Inquiry seeks comments and responses to a series of questions that will allow FERC to explore the potential impact of eliminating the discount adjustment for gas-on-gas competition and how the FERC should implement and monitor such a policy. In August 2003, Northern Border Pipeline filed revised tariff sheets to clarify its procedures for the awarding of capacity. Several parties protested the filing. One party requested a show cause proceeding to examine past tariff practices alleging that Northern Border Pipeline violated its tariff by denying a request for service that would have involved transportation for a distance shorter than the available distance for less than a one-year term. Northern Border Pipeline advises that its position is that selling capacity for shorter distances or on a shorter term basis may cause portions of its system to be “stranded” or not subject to firm transportation contracts on a consistent basis or may effectively constitute a discounted rate service. On September 10, 2003, the FERC rejected Northern Border Pipeline’s tariff sheets based on the conclusion that certain aspects of the proposal were not in accordance with the FERC’s policy. The FERC affirmed that, up to ninety days prior to the effective date, Northern Border Pipeline had the right not to sell capacity requested for shorter distances or on a short-term basis to shippers offering the maximum mileage-based transportation rates. Northern Border Pipeline filed a timely request for rehearing of the FERC’s Order in October 2003, which is still pending. Northern Border Pipeline also filed responses to requests for further information on the award of capacity in the summer of 2003. Northern Border Pipeline filed its compliance tariff sheets in early December 2003 and is awaiting the FERC decision on these tariff sheets. An order was issued on April 15, 2004, in which the FERC requested comments from interested parties on whether the FERC’s current policy on awarding available capacity to a short-haul shipper appropriately balances the risks to the pipeline, prospective shippers and current shippers on the pipeline. Comments from Northern Border Pipeline and other interested parties were filed on June 15, 2004. Northern Border Pipeline advises that the timing of the issuance of the FERC’s order in this proceeding is not known. Environmental and Safety Matters Northern Border Pipeline’s operations are subject to federal, state and local laws and regulations relating to safety and the protection of the environment, which include the Resource Conservation and Recovery Act, the Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended, Clean Air Act, as amended, the Clean Water Act, as amended, the Natural Gas Pipeline Safety Act of 1969, as amended, the Pipeline Safety Act of 1992 and the Pipeline Safety Improvement Act (Act) of 2002. The Act was signed into law in December 2002, providing guidelines for interstate pipelines in the areas of risk analysis and integrity management, public education programs, verification of operator qualification programs and filings with the National Pipeline Mapping System. The Act requires pipeline companies to perform integrity assessments on pipeline segments that exist in high population density areas or near specifically identified sites that are designated as high consequence areas. Pipeline companies are required to perform the integrity assessments within ten years of the date of enactment and must perform subsequent integrity assessments on a seven-year cycle. At least 50% of the highest risk segments must be assessed within five years of the enactment date. In addition, within one year of enactment, the pipeline’s operator qualification programs, in force since the mandatory compliance date of October 2002, must also conform to standards provided by the Department of Transportation. The regulations implementing the Act are final. 14 T C P I P E L I N E S , L P Rules on integrity management, direct assessment usage, and the operator qualification standards have been issued. Northern Border Pipeline has made the required filings with the National Pipeline Mapping System and has reviewed and revised its public education program. Compliance with the Act is expected to increase Northern Border Pipeline’s operating costs particularly related to integrity assessments for its pipeline. As required, Northern Border Pipeline has developed an overall plan for pipeline integrity management. Detailed analysis is being performed to determine the priorities and costs for inspecting and testing Northern Border Pipeline’s system. However, the plan will be modified as a result of the findings noted and could result in additional assessment or remediation costs. Northern Border Pipeline advises that presently, it expects its annual costs for integrity assessments to be approximately $0.5 million. Northern Border Pipeline advises that it expects to include these costs in future rate case filings, however, how these costs may be classified for all interstate pipelines is the subject of the pending proceeding before the FERC. See “FERC Regulation” above. Northern Border Pipeline advises that it believes its operations and facilities are in general compliance in all material respects with applicable environmental and safety regulations, however, risks of substantial costs and liabilities are inherent in pipeline operations, and Northern Border Pipeline cannot provide any assurances that it will not incur such costs and liabilities. Moreover, it is possible that other developments, such as the enactment of increasingly strict environmental and safety laws, regulations and enforcement policies by Congress, the FERC, the Department of Transportation and other federal agencies, state regulatory bodies and the courts, and claims for damages to property or persons resulting from Northern Border Pipeline’s operations, could result in substantial costs and liabilities to Northern Border Pipeline. If Northern Border Pipeline is unable to recover such resulting costs, earnings and cash distributions could be adversely affected. BUSINESS OF TUSCARORA GAS TRANSMISSION COMPANY General Tuscarora is a Nevada general partnership formed in 1993. Its general partners are TC Tuscarora Intermediate Limited Partnership, a direct subsidiary of TC PipeLines, which holds a 49% general partner interest, Tuscarora Gas Pipeline Co., a wholly owned subsidiary of Sierra Pacific Resources, which holds a 50% general partner interest and TCPL Tuscarora Ltd., an indirect wholly owned subsidiary of TransCanada, which holds the remaining 1% general partner interest in Tuscarora. The management of Tuscarora is overseen by a management committee that determines the policies of, has authority over the affairs of, and approves the actions of Tuscarora. The management committee participates in the management of the construction, maintenance and operation of the Tuscarora pipeline system. Under the Tuscarora partnership agreement, voting power on the management committee is allocated among Tuscarora’s three general partners in proportion to their general partner interests in Tuscarora. As a result, TC PipeLines has a 49% voting interest, Sierra Pacific Resources has a 50% voting interest, and TransCanada has a 1% voting interest on the Tuscarora management committee. Tuscarora Gas Operating Company, a subsidiary of Sierra Pacific Resources, operates the Tuscarora pipeline system pursuant to an operating agreement. Since December 1, 2002, TransCanada has been under contract to provide gas control services for the Tuscarora pipeline system, including monitoring and control of the compressor units, as well as emergency call out functions and other operational co-ordination. The Tuscarora Pipeline System The Tuscarora pipeline system was constructed in 1995 and was placed into service in December 1995. Tuscarora owns a 240-mile, 20-inch diameter, United States interstate pipeline system that originates at an interconnection point with facilities of Gas Transmission Northwest Corporation, a wholly-owned subsidiary of TransCanada, near Malin, Oregon and runs southeast through northeastern California and northwestern Nevada. The Tuscarora pipeline system terminates near Wadsworth, Nevada. Deliveries are also made directly to the local gas distribution system of Sierra 2 0 0 4 A N N U A L R E P O RT 15 Pacific Power Company (Sierra Pacific Power), a subsidiary of Sierra Pacific Resources. Along its route, deliveries are made in Oregon, northern California and northwestern Nevada. The Tuscarora pipeline system has firm capacity contracts averaging approximately 12.6 years to transport approximately 180 mmcfd of natural gas. On December 1, 2002, Tuscarora completed and placed into service an expansion of its pipeline system. This expansion consisted of two compressor stations and an 11-mile pipeline extension from a point near the previous terminus of the Tuscarora pipeline system near Reno, Nevada to Wadsworth, Nevada. The expansion increased Tuscarora’s contracted capacity from 127 mmcfd to approximately 180 mmcfd. The new capacity was contracted under long-term firm transportation contracts ranging from ten to fifteen years from the in-service date. The project was completed at a capital cost of approximately $39.0 million, $4 million less than budgeted. The Public Utilities Commission of Nevada (PUCN) filed a protest with the FERC regarding this expansion. In order to resolve this protest, Tuscarora agreed to submit a cost and revenue study to the FERC if Tuscarora’s rates were not subject to review within three years of the in- service date of December 1, 2002. The PUCN subsequently withdrew its protest based on this agreement. Tuscarora has firm transportation contracts for over 95% of its contracted capacity, including contracts held by Sierra Pacific Power for 69% of the total available capacity, the majority of which expires on October 31, 2017. As of December 31, 2004, the weighted average contract life on the Tuscarora pipeline system was approximately 12.6 years. As a result of the open season held in June 2003, Tuscarora initiated the 2005 Expansion project. Shortly after Tuscarora’s application for a Certificate of Public Convenience and Necessity for authorization to construct and operate the new pipeline facilities was filed with the FERC, the 2005 Expansion shippers were offered a lower cost alternative to Tuscarora’s proposed 2005 Expansion project by Paiute Pipeline Company (Paiute). The 2005 Expansion project was ultimately terminated on December 29, 2004 under conditions acceptable to Tuscarora, which include: • • extension of certain terms of the 2005 Expansion shippers’ existing contracts; and reimbursement of all expenses incurred on the 2005 Expansion project. Tuscarora’s competitive position is dependent on the continued availability of commercially attractive western Canadian natural gas for import into the United States and on the level of demand for western Canadian natural gas in the markets the Tuscarora pipeline system serves. Shippers of natural gas from the WCSB have other options for transporting Canadian natural gas to the United States, including transportation on pipelines eastward in Canada or to markets on the west coast of the United States and Canada. Similarly, natural gas produced in the United States serves the same markets as Tuscarora in northern Nevada. Tuscarora is able to transport both Canadian and United States natural gas, providing Tuscarora with a well-diversified supply of natural gas to serve its markets. FERC Regulation Tuscarora is subject to regulation by the FERC as a “natural gas company” under the Natural Gas Act, and is subject to the FERC’s rules, regulations and accounting procedures. Tuscarora generates revenues from individual transportation contracts with shippers that provide for the receipt and delivery of natural gas at points along the Tuscarora pipeline system. Tuscarora’s transportation rates are based on its cost of service as approved by the FERC. Tuscarora’s cost of service includes administrative and operating costs, depreciation and amortization, taxes other than income taxes, an allowance for income taxes and a regulated return on capital employed. In accordance with the FERC Order No. 2004 regarding new standards of conduct by transmission providers when dealing with their energy affiliates, all transmission providers had to comply with the standards of conduct by September 22, 2004. Tuscarora advises that it is in compliance with these new standards. 16 T C P I P E L I N E S , L P Tuscarora advises that it does not anticipate any impact from complying with the FERC’s February 2004 financial reporting regulations other than the time and additional expense for preparation of these reports. Environmental and Safety Matters Tuscarora’s operations are subject to federal, state and local laws and regulations relating to safety and protection of the environment. TC PipeLines believes that Tuscarora’s operations and facilities comply in all material respects with applicable United States environmental and safety regulations. AVAILABLE INFORMATION The Partnership’s annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and any amendments to these reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act are made available free of charge on the Partnership’s website at www.tcpipelineslp.com/investor/reports.html as soon as reasonably practicable after the Partnership electronically files these materials with, or furnishes them to, the United States Securities and Exchange Commission (SEC). Item 2. Properties TC PipeLines does not hold the right, title or interest in any properties. Properties of Northern Border Pipeline Company See Item 1. “Business – Business of Northern Border Pipeline Company – The Northern Border Pipeline System” and “Business – Business of Northern Border Pipeline Company – Interconnects” for a brief description of the location and general characteristics of Northern Border Pipeline’s important physical properties. Northern Border Pipeline holds the right, title and interest in its pipeline system. With respect to real property, the pipeline system falls into two basic categories: (a) parcels which are owned in fee, such as sites for compressor stations, meter stations, pipeline field offices, and microwave towers; and (b) parcels where the interest derives from leases, easements, rights-of-way, permits or licenses from landowners or governmental authorities permitting the use of such land for the construction and operation of the pipeline system. The right to construct and operate the pipeline system across certain property was obtained through exercise of the power of eminent domain. Northern Border Pipeline continues to have the power of eminent domain in each of the states in which it operates, although Northern Border Pipeline may not have the power of eminent domain with respect to Native American tribal lands. Approximately 90 miles of the Northern Border Pipeline system is located on fee, allotted and tribal lands within the exterior boundaries of the Fort Peck Indian Reservation in Montana. Tribal lands are lands owned in trust by the United States for the Fort Peck Tribes and allotted lands are lands owned in trust by the United States for an individual Indian or Indians. Northern Border Pipeline does have the right of eminent domain with respect to allotted lands. In 1980, Northern Border Pipeline entered into a pipeline right-of-way lease with the Fort Peck Tribal Executive Board, for and on behalf of the Assiniboine and Sioux Tribes of the Fort Peck Indian Reservation (Tribes). This pipeline right-of-way lease, which was approved by the Department of the Interior in 1981, granted Northern Border Pipeline the right and privilege to construct and operate its pipeline on certain tribal lands. This pipeline right-of-way lease expires in 2011. Northern Border Pipeline has been granted options to renew the pipeline right-of-way lease to 2061. See Item 3. “Legal Proceedings.” 2 0 0 4 A N N U A L R E P O RT 17 In conjunction with obtaining a pipeline right-of-way lease across tribal lands located within the exterior boundaries of the Fort Peck Indian Reservation, Northern Border Pipeline also obtained a right-of-way across allotted lands located within the reservation boundaries. Most of the allotted lands are subject to a perpetual easement either granted by the Bureau of Indian Affairs for and on behalf of individual Indian owners or obtained through condemnation. Several tracts are subject to a right-of-way grant that has a term of 15 years, expiring in 2015. Properties of Tuscarora Gas Transmission Company Tuscarora holds the right, title and interest in its pipeline system. Tuscarora owns all of its material equipment and personal property and leases office space in Reno, Nevada. With respect to real property, Tuscarora’s ownership falls into two basic categories: (a) parcels which it owns in fee; and (b) parcels where its interest derives from leases, easements, grants, permits or licenses from landowners or governmental authorities permitting the use of the land for the construction and operation of its pipeline system. Item 3. Legal Proceedings TC PipeLines is not currently a party to any material legal proceedings. On July 31, 2001, the Tribes filed a lawsuit in Tribal Court against Northern Border Pipeline to collect more than $3.0 million in back taxes, together with interest and penalties. The lawsuit related to a utilities tax on certain of Northern Border Pipeline’s properties within the Fort Peck Indian Reservation. The Tribes and Northern Border Pipeline, through a mediation process, reached a settlement with respect to pipeline right-of-way lease and taxation issues documented through an Option Agreement and Expanded Facilities Lease (Agreement) executed in August 2004. Through the terms of the Agreement, the settlement grants to Northern Border Pipeline, among other things: (i) an option to renew the pipeline right-of-way lease upon agreed terms and conditions on or before April 1, 2011 for a term of 25 years with a renewal right for an additional 25 years; (ii) a right to use additional tribal lands for expanded facilities; and (iii) release and satisfaction of all tribal taxes against Northern Border Pipeline. In consideration of this option and other benefits, Northern Border Pipeline paid a lump sum amount of $7.4 million and will make additional annual option payments of approximately $1.5 million thereafter through March 31, 2011. Northern Border Pipeline advises that it intends to seek regulatory recovery of the costs resulting from the settlement. See Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Risk Factors and Cautionary Statement Regarding Forward-Looking Statements.” See Item 1. “Business – Business of Northern Border Pipeline Company – FERC Regulation” for a discussion on the proceedings before the FERC. Northern Border Pipeline advises that it is not currently party to any other legal proceedings that, individually or in the aggregate, would reasonably be expected to have a material adverse impact on it or TC PipeLines’ results of operations or financial position. Tuscarora is not currently a party to any material legal proceedings. Item 4. Submission of Matters to a Vote of Security Holders There were no matters submitted to a vote of security holders, through solicitation of proxies or otherwise, during the year ended December 31, 2004. 18 T C P I P E L I N E S , L P PA RT I I Item 5. Market for Registrant’s Common Units and Related Security Holder Matters The common units representing limited partner interests in the Partnership were issued pursuant to an initial public offering on May 28, 1999 at a price of $20.50 per common unit. The common units are quoted on the Nasdaq Stock Market and trade under the symbol “TCLP.” The following table sets forth, for the periods indicated, the high and low sale prices per common unit, as reported by the Nasdaq Stock Market, and the amount of cash distributions per common unit declared with respect to the corresponding periods. Cash distributions are paid within 45 days after the end of each quarter to unitholders of record as of the record date. 2004 First Quarter Second Quarter Third Quarter Fourth Quarter 2003 First Quarter Second Quarter Third Quarter Fourth Quarter Price Range High Low Cash Distributions Declared per Unit $ 36.72 $ 36.82 $ 37.99 $ 38.80 $ 27.35 $ 30.00 $ 33.70 $ 33.70 $ 32.19 $ 29.11 $ 32.19 $ 36.69 $ 24.74 $ 25.50 $ 28.80 $ 30.60 $ 0.550 $ 0.575 $ 0.575 $ 0.575 $ 0.525 $ 0.550 $ 0.550 $ 0.550 As of March 3, 2005, there were 87 record holders of common units and approximately 7,986 beneficial owners of common units, including common units held in street name. The Partnership currently has 17,500,000 common units outstanding, of which 11,890,694 are held by the public, 2,800,000 are held by an affiliate of the general partner, and 2,809,306 are held by the general partner. The common units represent an aggregate 98% limited partner interest and the general partner interest represents an aggregate 2% general partner interest in the Partnership. The general partner receives 2% of all cash distributions and the holders of common units (collectively referred to as unitholders) receive the remaining 98%. The general partner is also entitled to incentive distributions as described below. The Partnership’s quarterly cash distributions to its unitholders are comprised of all of its Available Cash. Available Cash is defined in the partnership agreement and generally means, with respect to any quarter of the Partnership, all cash on hand at the end of a quarter less the amount of cash reserves that are necessary or appropriate, in the reasonable discretion of the general partner, to: • provide for the proper conduct of the business of the Partnership (including reserves for future capital expenditures and for anticipated credit needs); comply with applicable laws or any Partnership debt instrument or agreement; or • • provide funds for cash distributions to unitholders and the general partner in respect of any one or more of the next four quarters. 2 0 0 4 A N N U A L R E P O RT 19 The general partner receives incentive distributions if the amount distributed with respect to any quarter exceeds the minimum quarterly distribution of $0.45 per unit. Under the incentive distribution provisions, the general partner receives 15% of amounts distributed in excess of $0.45 per unit, 25% of amounts distributed in excess of $0.5275 per unit, and 50% of amounts distributed in excess of $0.69 per unit, provided the balance has been first distributed to unitholders on a pro rata basis. The amounts that trigger incentive distributions at various levels are subject to adjustment in certain events, as described in the partnership agreement. In 2004, the Partnership made cash distributions to unitholders and the general partner that amounted to $41.8 million compared to $39.4 million in 2003. These payments represented $0.55 per unit for the quarters ended December 31, 2003 and March 31, 2004 and $0.575 per unit for the quarters ended June 30, 2004 and September 30, 2004. On February 14, 2005, the Partnership paid a cash distribution of $10.7 million to unitholders and the general partner, representing a cash distribution of $0.575 per unit for the quarter ended December 31, 2004. The distribution was allocated in the following manner: $10.0 million to the holders of common units as of the close of business on January 31, 2005 (including $1.6 million to an affiliate of the general partner as holder of 2,800,000 common units and $1.6 million to the general partner as holder of 2,809,306 common units), $0.5 million to the general partner as holder of incentive distribution rights, and $0.2 million to the general partner in respect of its 2% general partner interest. Termination of Subordination Period At the time of the Partnership’s initial public offering in 1999, 2,809,306 subordinated units were issued to the general partner. Pursuant to the partnership agreement one-third of each of the subordinated units converted on August 1, 2002, August 1, 2003 and July 30, 2004. All 2,809,306 subordinated units have been converted into common units held by the general partner and the subordination period has terminated. Item 6. Selected Financial Data The selected financial data should be read in conjunction with the financial statements, including the notes thereto, and Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations.” TC PIPELINES, LP (millions of dollars, except per unit amounts) Income Data Equity income from investment in Northern Border Pipeline Equity income from investment in Tuscarora (1) General and administrative expenses Financial charges 2004 50.0 7.5 (1.9) (0.5) Year Ended December 31 2002 2003 2001 44.5 5.3 (1.7) (0.1) 42.8 4.7 (1.5) (0.5) 42.1 3.6 (1.2) (1.0) 2000 38.1 0.9 (1.3) (0.5) Net income Basic and diluted net income per unit Units outstanding (millions) Cash Flow Data Net cash provided by operating activities Distributions paid Balance Sheet Data (at December 31) Investment in Northern Border Pipeline Investment in Tuscarora (1) Total assets Long-term debt (including current maturities) Partners’ equity 55.1 $ 2.99 17.5 48.0 $ 2.63 17.5 45.5 $ 2.50 17.5 43.5 $ 2.40 17.5 37.2 $ 2.08 17.5 55.2 41.8 290.1 39.5 332.1 36.5 294.9 49.6 39.4 240.7 39.9 288.1 5.5 282.0 52.1 37.4 242.9 36.7 286.0 11.5 273.9 42.9 35.2 250.1 29.3 288.7 21.5 266.7 40.3 32.6 248.1 27.9 277.5 21.5 255.4 (1) The Partnership acquired a 49% interest in Tuscarora on September 1, 2000. 20 T C P I P E L I N E S , L P Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations As a result of the Partnership’s ownership of interests in both Northern Border Pipeline and Tuscarora, the following discusses first the results of operations and liquidity and capital resources of TC PipeLines, then those of each Northern Border Pipeline and Tuscarora in their entirety. The following discussions of the financial condition and results of operations of the Partnership, Northern Border Pipeline and Tuscarora should be read in conjunction with the financial statements and notes thereto of the Partnership and Northern Border Pipeline included elsewhere in this report (see Item 8. “Financial Statements and Supplementary Data”). For more detailed information regarding the basis of presentation for the following financial information, see the notes to the financial statements of the Partnership and Northern Border Pipeline. As of December 31, 2004, TC PipeLines’ interest in Northern Border Pipeline represented approximately 87% of TC PipeLines’ total assets and for the year ended December 31, 2004 provided approximately 87% of TC PipeLines’ total equity income. All amounts are stated in United States dollars. OVERVIEW TC PipeLines owns a 30% general partner interest in Northern Border Pipeline. The remaining 70% general partner interest in Northern Border Pipeline is held by Northern Border Partners, L.P., a publicly traded limited partnership that is controlled by ONEOK. TransCanada holds a minority general partner interest in Northern Border Partners which entitles it to 12.25% of the voting power of Northern Border Pipeline. Northern Border Pipeline owns a 1,249-mile interstate pipeline system that transports natural gas from the Montana-Saskatchewan border near Port of Morgan, Montana to natural gas markets in the midwestern United States. Construction of the pipeline was initially completed in 1982. The Northern Border Pipeline system was expanded and/or extended in 1991, 1992, 1998 and 2001. The Northern Border Pipeline system connects directly and through multiple pipelines to various natural gas markets in the United States. TC PipeLines also owns a 49% general partner interest in Tuscarora. The Partnership acquired this interest from TCPL Tuscarora Ltd., an indirect subsidiary of TransCanada, in September 2000. Tuscarora Gas Pipeline Co., a wholly owned subsidiary of Sierra Pacific Resources, holds a 50% general partner interest and TCPL Tuscarora Ltd., an indirect wholly owned subsidiary of TransCanada holds the remaining 1% general partner interest in Tuscarora. Tuscarora owns a 240-mile, 20-inch diameter, United States interstate pipeline system that originates at an interconnection point with facilities of GTN, a wholly-owned subsidiary of TransCanada, near Malin, Oregon and runs southeast through northeastern California and northwestern Nevada. The Tuscarora pipeline system terminates near Wadsworth, Nevada. Deliveries are also made directly to the local gas distribution system of Sierra Pacific Resources. Along its route, deliveries are made in Oregon, northern California and northwestern Nevada. The Tuscarora pipeline system was constructed in 1995 and was placed into service in December 1995. In January 2001, Tuscarora completed construction of the Hungry Valley lateral, a 14-mile, 16-inch pipeline extension that serves as Tuscarora’s second connection into Reno, Nevada. On December 1, 2002, Tuscarora completed and placed into service another expansion of its pipeline system. The 2002 expansion consisted of two compressor stations and an 11-mile pipeline extension from a point near the previous terminus of the Tuscarora pipeline system near Reno, Nevada to Wadsworth, Nevada. The expansion increased Tuscarora’s contracted capacity from 127 mmcfd to approximately 180 mmcfd. The new capacity is contracted under long-term firm transportation contracts. The Partnership’s 30% general partner interest in Northern Border Pipeline and 49% general partner interest in Tuscarora represent its only material assets. As a result, the Partnership is dependent upon Northern Border Pipeline and Tuscarora for all of its available cash. Northern Border Pipeline represents approximately 87% of TC PipeLines’ 2 0 0 4 A N N U A L R E P O RT 21 total equity income. For an overview discussing the important factors impacting Northern Border Pipeline’s business, such as the continued availability of western Canadian natural gas in the United States, see “Results of Operations of Northern Border Pipeline Company – Overview”. RESULTS OF OPERATIONS OF TC PIPELINES, LP Critical Accounting Policy TC PipeLines accounts for its investments in both Northern Border Pipeline and Tuscarora using the equity method of accounting as detailed in Note 3 and Note 4 to the Partnership’s Financial Statements, included elsewhere in this report. The equity method of accounting is appropriate where the investor does not control an investee, but rather is able to exercise significant influence over the operating and financial policies of an investee. TC PipeLines is able to exercise significant influence over its investments in Northern Border Pipeline and Tuscarora as evidenced by its representation on their respective management committees. Since the 30% general partner interest in Northern Border Pipeline and the 49% general partner interest in Tuscarora are currently the Partnership’s only material sources of income, the Partnership’s results of operations are influenced by and reflect the same factors that influence the financial results of Northern Border Pipeline and Tuscarora (see Item 1. “Business – Business of Northern Border Pipeline Company” and “Business – Business of Tuscarora Gas Transmission Company”). Year Ended December 31, 2004 Compared with the Year Ended December 31, 2003 Net income increased $7.1 million, or 15%, to $55.1 million for the year ended December 31, 2004, compared to $48.0 million for 2003. The increase is primarily due to higher equity income from the Partnership’s investments in Northern Border Pipeline and Tuscarora. Equity income from the Partnership’s investment in Northern Border Pipeline increased $5.5 million, or 12%, to $50.0 million for the year ended December 31, 2004 compared to $44.5 million for 2003. Northern Border Pipeline’s revenues for 2004 were higher than the same period for 2003. Northern Border Pipeline was able to generate and retain additional revenue from the sale of short-term capacity. The leap year added an additional day of transportation, which also contributed to the increase in 2004. A condition of Northern Border Pipeline’s previous rate case settlement required Northern Border Pipeline to share new service revenue with its shippers. This condition expired in October 2003 and allowed Northern Border Pipeline to realize additional revenue for the year ended December 31, 2004. These factors increased the Partnership’s 2004 equity income by $1.5 million. Operations and maintenance expense decreased in 2004 compared to the same period last year primarily due to the reversal of accruals recorded by Northern Border Pipeline in 2003 related to its share of the potential termination costs of Enron Corp. Cash Balance Plan (Cash Balance Plan) (see “Results of Operations of Northern Border Pipeline Company – Impact of Enron’s Chapter 11 Filing on Northern Border Pipeline’s Business”). Additionally in 2004, Northern Border Pipeline settled previously accrued charges for administrative services provided by Northern Plains and its affiliates, and a true-up for corporate compensation plans, also contributed to the decrease in operations and maintenance expense. Also contributing to the decrease were adjustments to allowance for doubtful accounts for estimated recoveries of claims against Enron. Also, Northern Border Pipeline’s interest expense was lower during 2004 compared to the same period last year primarily due to a decrease in average debt outstanding partially offset by an increase in average interest rates and costs incurred to ensure compliance with Section 404 of the Sarbanes-Oxley Act of 2002. These decreases resulted in an increase in equity income to the Partnership of $4.0 million in 2004. Equity income from the Partnership’s investment in Tuscarora increased $2.2 million, or 42%, to $7.5 million for the year ended December 31, 2004, compared to $5.3 million for the prior year. Tuscarora’s revenues increased primarily due to incremental revenues from long-term firm transportation contracts, which commenced in 2003, related to the 22 T C P I P E L I N E S , L P 2002 expansion, increasing the Partnership’s equity income from Tuscarora by $1.4 million. Operations and maintenance expense and depreciation expense were lower during 2004 compared to the same period last year primarily due to lower engineering and operations expenses and a lower depreciation rate applied to compressor equipment. The combined effect of these decreased expenses increased the Partnership’s equity income from Tuscarora by $0.2 million. In addition, lower interest expense during 2004 compared to the same period last year is primarily due to a decrease in average debt outstanding. Tuscarora’s other income was higher due to a one time settlement payment in 2004 related to the termination of the 2005 Expansion. A Joint Settlement Agreement filed and approved by the FERC allowed Tuscarora to withdraw its application for the proposed 2005 Expansion facilities and released the 2005 Expansion shippers from their contractual commitments. The 2005 Expansion shippers extended the terms of certain of their existing contracts with Tuscarora which effectively increased the average contract life to approximately 12.6 years. The effect of lower interest expense and higher other income resulted in $0.6 million increase in the Partnership’s equity income for the year ended December 31, 2004. The Partnership recorded general and administrative expenses of $1.9 million and $1.7 million for the years ended December 31, 2004 and 2003, respectively. The increase in 2004 was primarily due to professional fees related to compliance with Section 404 of the Sarbanes-Oxley Act of 2002, and higher employee benefits and overhead costs incurred in 2004 compared to the same period last year. The Partnership recorded financial charges of $0.5 million and $0.1 million for the years ended December 31, 2004 and 2003, respectively. This increase is primarily due to both increases in average debt outstanding and average interest rates. During 2004, the Partnership increased its net borrowings under its credit facilities by $31.0 million, which were used primarily to finance its equity contributions to Northern Border Pipeline. In aggregate, the Partnership made equity contributions of $61.5 million to Northern Border Pipeline in 2004. Year Ended December 31, 2003 Compared with the Year Ended December 31, 2002 Net income increased $2.5 million, or 5%, to $48.0 million for the year ended December 31, 2003, compared to $45.5 million for 2002. The increase is primarily due to higher equity income from the Partnership’s investments in Northern Border Pipeline and Tuscarora. Equity income from the Partnership’s investment in Northern Border Pipeline increased $1.7 million, or 4%, to $44.5 million for the year ended December 31, 2003 compared to $42.8 million for 2002. Northern Border Pipeline’s revenues for 2003 were higher than 2002 due to the uncollected revenues associated with the transportation capacity previously held by Enron North America Corp. (ENA) which reduced 2002 revenues, as well as additional incremental revenues received in 2003. These factors increased the Partnership’s 2003 equity income by $0.9 million. Also, Northern Border Pipeline’s interest expense was lower during 2003 compared to 2002 due primarily to lower average interest rates and lower average debt balances outstanding, resulting in an increase of $2.0 million to the Partnership’s equity income. These increases were partially offset by higher operations and maintenance expenses and taxes other than income as well as a decrease in other income. The increase in 2003 operations and maintenance expense is primarily due to a provision recorded by Northern Border Pipeline in 2003 related to its share of the Cash Balance Plan underfunding (see “Results of Operations of Northern Border Pipeline Company – Impact of Enron’s Chapter 11 Filing on Northern Border Pipeline’s Business”), partially offset by lower electric power costs in 2003 as compared to 2002, resulting in a net decrease to the Partnership’s equity income of $0.3 million. The increase in 2003 taxes other than income is primarily due to a refund of use taxes received by Northern Border Pipeline during 2002 as well as higher property taxes in 2003 as compared to 2002. These increases resulted in a decrease in equity income to the Partnership of $0.4 million. Other income (net of Other expense) was lower during 2003 as compared to 2002. The 2003 amount includes interest expense for refunds required by the order issued by the FERC on March 27, 2003 (see Item 1. “Business – Business of Northern Border Pipeline Company – FERC Regulation”) whereas the 2002 amount includes income mostly related to 2 0 0 4 A N N U A L R E P O RT 23 interest received on the refund of use taxes previously discussed and income for previously vacated frequency bands. The impact on the Partnership of this decrease in other income was a $0.5 million reduction in equity income from Northern Border Pipeline. Equity income from the Partnership’s investment in Tuscarora increased $0.6 million, or 13%, to $5.3 million for the year ended December 31, 2003, compared to $4.7 million for 2002. Tuscarora’s revenues increased primarily due to new increasing the Partnership’s equity income from Tuscarora by transportation contracts from the expansion, $3.2 million. This increase was partially offset by increased operations and maintenance expense and increased depreciation expense, both resulting from Tuscarora’s expansion. The combined effect of these increased expenses reduced the Partnership’s equity income from Tuscarora by $1.8 million. In addition, higher interest expense due to Tuscarora’s expansion, partially offset by a decrease in Tuscarora’s other income, resulted in a $0.8 million reduction in the Partnership’s equity income for the year ended December 31, 2003. The Partnership recorded general and administrative expenses of $1.7 million and $1.5 million for the years ended December 31, 2003 and 2002, respectively. The Partnership recorded financial charges of $0.1 million and $0.5 million for the years ended December 31, 2003 and 2002, respectively. This decrease is primarily attributed to the Partnership repaying $6.0 million of the balance outstanding on its Revolving Credit Facility during 2003, which reduced the balance outstanding from $11.5 million to $5.5 million. LIQUIDITY AND CAPITAL RESOURCES OF TC PIPELINES, LP Cash Distribution Policy of TC PipeLines During the subordination period, which ended July 30, 2004, the Partnership made distributions of Available Cash, as defined in the partnership agreement, in the following manner: • First, 98% to the common units, pro rata, and 2% to the general partner, until there is distributed for each outstanding common unit an amount equal to the minimum quarterly distribution for that quarter; • Second, 98% to the common units, pro rata, and 2% to the general partner, until there is distributed for each outstanding common unit an amount equal to any arrearages in payment of the minimum quarterly distribution on the common units for that quarter and for any prior quarters during the subordination period; • Third, 98% to the subordinated units, pro rata, and 2% to the general partner, until there is distributed for each outstanding subordinated unit an amount equal to the minimum quarterly distribution for that quarter; and • Thereafter, in a manner whereby the general partner has rights (referred to as incentive distribution rights) to receive increasing percentages of excess quarterly cash distributions over specified cash distribution thresholds. Since July 30, 2004, the Partnership has made distributions of Available Cash, as defined in the Partnership Agreement, in the following manner: • First, 98% to the common units, pro rata, and 2% to the general partner, until there is distributed for each outstanding common unit an amount equal to the minimum quarterly distribution for that quarter; and • Thereafter, in a manner whereby the general partner has rights (referred to as incentive distribution rights) to receive increasing percentages of excess quarterly cash distributions over specified cash distribution thresholds. After the distributions described above are met, additional Available Cash from Operating Surplus (as defined in the partnership agreement) for that quarter will be distributed, among the unitholders and the general partner (as incentive distribution) in the following manner: • First, 85% to all units, pro rata, and 15% to the general partner, until each unitholder has received a total of $0.5275 for that quarter; • Second, 75% to all units, pro rata, and 25% to the general partner, until each unitholder has received a total of $0.6900 for that quarter; and • Third, 50% to all units, pro rata, and 50% to the general partner. 24 T C P I P E L I N E S , L P The distribution to the general partner described above, other than in its capacity as a holder of 2,809,306 units that are in excess of its aggregate 2% general partner interest, represent the incentive distribution rights. Conversion of Subordinated Units All 2,809,306 subordinated units originally issued to the general partner have converted pursuant to and in accordance with the terms of the partnership agreement in one-third increments on August 1, 2002, August 1, 2003, and July 30, 2004. As a result, the subordination period has terminated. General On January 20, 2005, the board of directors of the general partner declared the Partnership’s 2004 fourth quarter cash distribution. The fourth quarter cash distribution, which was paid on February 14, 2005 to unitholders of record as of January 31, 2005, totaled $10.7 million and was paid in the following manner: $10.0 million to common unitholders (including $1.6 million to an affiliate of the general partner as holder of 2,800,000 common units and $1.6 million to the general partner as holder of 2,809,306 common units), $0.5 million to the general partner as holder of the of incentive distribution rights, and $0.2 million to the general partner in respect of its 2% general partner interest. Summary of Certain Contractual Obligations Payments Due by Period (millions of dollars) Revolving Credit Facility TransCanada Credit Facility Total Less Than 1 Year 1-3 Years 4-5 Years After 5 Years – 6.5 6.5 30.0 – 30.0 $ $ – – – $ – – – $ 36.5 $ Total 30.0 6.5 Debt and Credit Facilities On May 28, 2003, the Partnership renewed its $40.0 million unsecured two-year revolving credit facility (TransCanada Credit Facility) with TransCanada PipeLine USA Ltd., an affiliate of the general partner. The TransCanada Credit Facility bears interest at the London Interbank Offered Rate (LIBOR) plus 1.25%. The purpose of the TransCanada Credit Facility is to provide borrowings to fund capital expenditures, to fund capital contributions to Northern Border Pipeline, Tuscarora and any other entity in which the Partnership directly or indirectly acquires an interest, to fund working capital and for other general business purposes, including temporary funding of cash distributions to unitholders and the general partner, if necessary. At December 31, 2004 and December 31, 2003, the Partnership had $6.5 million and nil borrowings outstanding, respectively, under the TransCanada Credit Facility. The interest rate on the TransCanada Credit Facility at December 31, 2004 was 3.75%. The Partnership repaid in full the $6.5 million outstanding balance on its TransCanada Credit Facility on February 22, 2005. On March 8, 2004 the Partnership renewed its unsecured credit facility (Revolving Credit Facility) with Bank One, NA, as administrative agent. Under the Revolving Credit Facility, the Partnership may borrow up to an aggregate principal amount of $30.0 million. Loans under the Revolving Credit Facility may bear interest, at the option of the Partnership, at a one-, two-, three-, or six-month LIBOR plus 1.25%, or at a floating rate based on the higher of the federal funds effective rate plus 0.5% and the prime rate. The Revolving Credit Facility matures on February 28, 2006. Amounts borrowed may be repaid in part or in full prior to that time without penalty. The Revolving Credit Facility may be used to fund capital expenditures, to fund capital contributions to Northern Border Pipeline, Tuscarora and any other entity in which the Partnership directly or indirectly acquires an interest, to fund working capital and for other general business purposes, including temporary funding of cash distributions to unitholders and the general partner, if necessary. In 2004, the Partnership borrowed an aggregate of $30.5 million and repaid $6.0 million on the Revolving Credit Facility. The Partnership had $30.0 million and $5.5 million outstanding under the Revolving Credit Facility at December 31, 2004 and 2003, respectively. The interest rate on the Revolving Credit Facility averaged 2.76% and 2.58% for the years ended December 31, 2004 and 2003, respectively and at December 31, 2004 and 2003, the interest rate was 3.72% and 2.42%, respectively. 2 0 0 4 A N N U A L R E P O RT 25 On December 22, 2004, the Partnership filed a shelf registration statement with the SEC to sell, from time to time, up to $250.0 million of common units representing limited partner interests and/or debt securities. In addition, the Partnership’s general partner registered for sale up to 2,809,306 common units and an affiliate of the general partner registered for sale up to 2,800,000 units. Cash Flows from Operating Activities Cash flows provided by operating activities increased $5.6 million, or 11%, to $55.2 million for the year ended December 31, 2004, compared to $49.6 million for 2003. The increase is primarily due to higher cash distributions received from both Northern Border Pipeline and Tuscarora. In 2004, the Partnership’s cash from operations included cash distributions of $50.0 million from its equity investment in Northern Border Pipeline compared to $45.2 million in 2003. Total cash distributions received include $11.7 million and $1.0 million classified as return of capital in 2004 and 2003, respectively. The higher cash distributions in 2004 reflect the impact of a change in Northern Border Pipeline’s cash distribution policy effective January 1, 2004, as well as the negative impact to the 2003 cash distributions resulting from refunds paid by Northern Border Pipeline to its shippers for electricity costs. The Partnership’s cash from operations also included cash distributions of $7.6 million from its equity investment in Tuscarora compared to $6.2 million in 2003. Total cash distributions received from Tuscarora include $0.4 million classified as return of capital in 2004. The increased cash distributions from Tuscarora are primarily due to increased earnings resulting from its 2002 expansion. Cash flows provided by operating activities decreased $2.5 million, or 5%, to $49.6 million for the year ended December 31, 2003, compared to $52.1 million for 2002. In 2002, the Partnership received cash distributions of $49.2 million and $4.6 million from Northern Border Pipeline and Tuscarora, respectively. Cash Flows from Investing Activities For the year ended December 31, 2004, the Partnership made equity contributions totaling $61.5 million, representing its 30% share of two $65.0 million cash calls issued by Northern Border Pipeline to its partners on January 27, 2004 and April 27, 2004 and its 30% share of a $75.0 million cash call issued by Northern Border Pipeline to its partners on December 22, 2004. The $75.0 million cash call will reduce the previously approved 2007 cash call from $90.0 million to $15.0 million, the Partnership’s 30% share of $27.0 million and $4.5 million, respectively. These funds were used by Northern Border Pipeline to repay a portion of its existing indebtedness. The payments to Northern Border Pipeline were funded through the use of cash from operations and existing credit facilities. These cash contributions were offset by $11.7 million return of capital from Northern Border Pipeline in 2004. In 2004, the Partnership recorded a $0.4 million return of capital from Tuscarora which included a settlement payment related to the termination of the 2005 Expansion project. For the year ended December 31, 2003, the Partnership made net equity contributions totaling $4.1 million to Tuscarora related to Tuscarora’s expansion project. As well, a $1.0 million return of capital was received by the Partnership from Northern Border Pipeline in 2003. During 2002, the Partnership made net equity contributions totaling $7.4 million to Tuscarora related to Tuscarora’s expansion project. Cash Flows from Financing Activities For the year ended December 31, 2004, the Partnership paid cash distributions of $41.8 million, compared to $39.4 million in 2003. The increase is primarily due to an increase in the Partnership’s quarterly cash distribution from $0.55 per unit to $0.575 per unit beginning in the second quarter of 2004. In 2002, the Partnership paid cash distributions of $37.4 million. For the year ended December 31, 2004, the Partnership borrowed an aggregate of $30.5 million on the Revolving Credit Facility and $6.5 million on the TransCanada Credit Facility. During 2003, the Partnership had no drawings on the Revolving Credit Facility or the TransCanada Credit Facility. The Partnership repaid $6.0 million on the Revolving Credit Facility in each of 2004 and 2003, compared to repayments of $10.0 million in 2002. At December 31, 2004, the Partnership had $30.0 million and $6.5 million outstanding under the Revolving Credit Facility and TransCanada Credit Facility, respectively. The Partnership repaid $6.5 million on its TransCanada Credit Facility on February 22, 2005. 26 T C P I P E L I N E S , L P Capital Requirements To the extent TC PipeLines has any additional capital requirements with respect to its investments in Northern Border Pipeline and Tuscarora or makes acquisitions in 2005, TC PipeLines expects to finance these requirements with operating cash flows, debt and/or equity. Outlook On December 19, 2003, Northern Border Pipeline advised that its management committee had unanimously agreed to issue equity cash calls to its partners in the total amount of $130.0 million (TC PipeLines’ share is $39.0 million) in early 2004, and $90.0 million (TC PipeLines’ share is $27.0 million) in 2007 and to change the cash distribution policy of Northern Border Pipeline as of January 1, 2004. TC Pipelines made an additional equity contribution of $22.5 million, representing its 30% share of a $75.0 million cash call issued by Northern Border Pipeline to its partners on December 22, 2004. The $75.0 million cash call will reduce the previously approved 2007 cash call from $90.0 million to $15.0 million; the Partnership’s 30% share is $27.0 million and $4.5 million, respectively. Effective January 1, 2008, Northern Border Pipeline’s cash distribution policy will be adjusted to maintain a consistent capital structure. On December 16, 2004, Tuscarora’s management committee had unanimously agreed to issue equity cash calls to its partners in the total amount of $0.7 million. The Partnership will contribute $0.3 million, representing its 49% share, in July 2005. RESULTS OF OPERATIONS OF NORTHERN BORDER PIPELINE COMPANY In the following discussion of the results of Northern Border Pipeline, all amounts represent 100% of the operations of Northern Border Pipeline, in which the Partnership has held a 30% interest since May 28, 1999. The discussion and analysis of Northern Border Pipeline’s financial condition and operations are based on Northern Border Pipeline’s financial statements, which were prepared in accordance with generally accepted accounting principles in the United States of America (GAAP). The following discussion and analysis should be read in conjunction with Northern Border Pipeline’s Financial Statements and related notes included elsewhere in this report. Overview For Northern Border Pipeline, there are several major business drivers. First, a healthy long-term supply outlook is critical. Because the primary source of gas supply that is transported on its pipeline system is in the WCSB, western Canadian supply trends are particularly important to Northern Border Pipeline. The current outlook for western Canadian supply looks flat for the foreseeable future, however, production has exceeded new reserve additions in recent years. To maintain an adequate gas supply/demand balance in western Canada, production will need to grow in the future to meet anticipated demand primarily driven by gas consumption in the extraction and processing associated with Canadian oil sands development. Canada holds substantial reserves of bitumen that is extracted from sand and can be upgraded to synthesized crude oil through several processes. The extraction and processing of bitumen require significant quantities of natural gas. Northern Border Pipeline advises that it does not know how many of the announced oil sands development projects will be approved and constructed but the demand for transportation on the Northern Border Pipeline system could be adversely affected by the additional competition for Canadian gas supply that would result. The supply outlook may be enhanced over time by new proposed Alaskan and Mackenzie Delta supplies reaching the western Canadian pipeline grid potentially beginning by the end of this decade, although there is no assurance either project will be completed within that timeframe. Moreover, prices of western Canadian supply must be competitive with prices from other supply basins that serve Northern Border Pipeline’s market areas. If prices are too high, other sources of supply may satisfy demand that otherwise could be met by Northern Border Pipeline. Increased demand for western Canadian natural gas in markets other than those served by Northern Border Pipeline may also cause a reduction of demand for service on Northern Border Pipeline. 2 0 0 4 A N N U A L R E P O RT 27 Natural gas markets are also critical to Northern Border Pipeline’s financial performance. The Northern Border Pipeline system serves natural gas markets in the upper midwestern area of the United States and accesses a major trading hub in the Chicago area. Market growth has been steady with both heating load growth and direct end-user growth, such as power plants and ethanol plants. However, Northern Border Pipeline advises that competitive pipeline projects may have a negative impact on its profitability. Northern Border Pipeline charges fees for transportation which are primarily fixed and are based on the amount of capacity reserved by each shipper. Contracting with shippers to reserve the available pipeline capacity as existing contracts expire is a critical factor in Northern Border Pipeline’s success. Based on Northern Border Pipeline’s contracts in place at December 31, 2004, the percentage of summer design capacity contracted as of December 31, 2005 was 61%. During 2004, Northern Border Pipeline was successful in recontracting, at maximum rates, essentially all of the summer design capacity under contracts that expired on or before November 2004. However, most of those contracts were for terms of five to six months so Northern Border Pipeline has a significant amount of capacity, approximately 800 mmcfd or 28% of summer design capacity, under contracts that expire by May 31, 2005. Most of this capacity will become available on the pipeline system from Port of Morgan, Montana to the Ventura, Iowa delivery point. Northern Border Pipeline advises that its objective is to recontract as much of the remaining pipeline capacity at maximum transportation rates for the longest terms possible. Because the forward natural gas basis differentials between western Canada and Northern Border Pipeline’s market centers continue to be less than the total transportation cost at maximum tariff rates, Northern Border Pipeline may again sell a significant portion of this capacity on a short-term basis. Northern Border Pipeline advises that so long as it continues to provide economic value, gas will likely flow from western Canada over its system and it will maintain its relatively high utilization levels. However, in any given month, current conditions of weather and storage in supply and market areas may affect the demand for capacity on Northern Border Pipeline. This could result in lower revenues in some months. Although, Northern Border Pipeline advises that it believes a reduction in expected 2005 net income and cash flow of approximately $7.0 million to $14.0 million is possible, the impact on net income and cash flow may vary outside this range depending on actual natural gas basis differentials experienced during the year. The composition of natural gas can affect the amount of energy that is transported through a pipeline system. Beginning in 2000, the energy content of natural gas that Northern Border Pipeline receives at the Canadian border has declined modestly from 1,023 British Thermal Units (Btus) per cubic feet (cf) to 1,005 Btus/cf. Northern Border Pipeline’s transportation contracts in conjunction with its tariff define both the volume and equivalent Btu value of the gas to be transported. A reduction in the Btu level results in a higher volume of natural gas to be transported to meet an overall equivalent Btu value of the gas. This Btu decline that has been experienced was primarily the result of greater processing capacity in Alberta. The change has caused Northern Border Pipeline to reduce its available capacity by almost 2% to maintain its high standard of system reliability for its customers. During 2004, the Btu level remained near the level of 1,005 Btus/cf and Northern Border Pipeline advises that it is expected to remain at that level during 2005. This Btu variance will be addressed in Northern Border Pipeline’s November 1, 2005 rate case filing. Northern Border Pipeline advises that it will continue to focus on safe, efficient, and reliable operations and the further development of its pipeline. Northern Border Pipeline is working to maintain its position as a low cost transporter of Canadian gas to the midwestern U.S. and provide highly valued services to its customers. Growth may occur through incremental projects intended to access new markets or supply areas and supported by long-term contracts. In September 2004, Northern Border Pipeline announced sufficient customer support for a proposed expansion from various receipt points along the pipeline system for deliveries into the Chicago area. The Chicago III Expansion project, with 130 mmcfd of incremental capacity, involves construction of a new 16,000 horsepower compressor station in Iowa and minor modifications to existing compressor facilities, in Iowa and Illinois. Capital costs are estimated to be 28 T C P I P E L I N E S , L P approximately $21.0 million. An April 1, 2006 in-service date is the target and subject to timely receipt of regulatory approval, Northern Border Pipelines advises that it anticipates that approximately $15.0 million of the estimated $21.0 million capital budget will be expended in 2005, with the remaining $6.0 million to be spent in 2006. Northern Border Pipeline advises that it will focus on several regulatory matters. Under Northern Border Pipeline’s settlement agreement from the last rate case, it was agreed that it must file a proceeding under section 4 of the Natural Gas Act to determine the just and reasonable rates to be charged for its transportation services. During the rate case process, the FERC staff and Northern Border Pipeline’s customers will review the cost of service elements, (including allowed return on capital, operations and maintenance costs, depreciation and taxes) and contracted capacity levels used to determine transportation rates. As described more fully in Item 1. “Business – Business of Northern Border Pipeline Company – FERC Regulation”, there is a FERC inquiry regarding the proper income tax allowance in rates for regulated entities other than corporations. In response, a number of comments, including those of Northern Border Pipeline, suggested that an income tax allowance is proper for all jurisdictional entities regardless of legal structure. Some producers’ and customers’ comments argued against the inclusion of an income tax allowance for partnerships and other non-tax paying entities. It is not certain how, or when, the FERC may proceed with respect to its Request for Comments or any impact on the rate methodology for interstate natural gas pipelines, including Northern Border Pipeline. In particular, Northern Border Pipeline is a general partnership and one of the elements used to determine its cost of service upon which its transportation rates are derived is an allowance for income taxes. While Northern Border Pipeline cannot predict the outcome of the FERC’s inquiry, Northern Border Pipeline advises that it believes that its specific circumstances regarding its tariff, deferred income tax treatment, FERC orders, past history and underlying agreements with shippers are different from those underlying the BP West Coast case. The issue of whether Northern Border Pipeline’s rates should include an income tax allowance, and if so, the amount thereof, may be addressed in Northern Border Pipeline’s 2005 rate case. Critical Accounting Policies and Estimates Certain amounts included in or affecting Northern Border Pipeline’s financial statements and related notes disclosures must be estimated, requiring Northern Border Pipeline to make certain assumptions with respect to values or conditions that cannot be known with certainty at the time the financial statements are prepared. The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Any effects on Northern Border Pipeline’s business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the facts that gave rise to the revision become known. Northern Border Pipeline’s significant accounting policies are summarized in Note 2 – Notes to Northern Border Pipeline’s Financial Statements included elsewhere in this report. Certain of Northern Border Pipeline’s accounting policies are of more significance in its financial statement preparation process than others. Northern Border Pipeline’s accounting policies conform to Statement of Financial Accounting Standards (SFAS) No. 71, “Accounting for the Effects of Certain Types of Regulation.” Accordingly, certain assets that result from the regulated ratemaking process are recorded that would not be recorded by entities not accounting under SFAS No. 71. Northern Border Pipeline continually assesses whether the regulatory assets are probable of future recovery by considering such factors as regulatory changes and the impact of competition. If future recovery ceases to be probable, Northern Border Pipeline would be required to write-off the regulatory assets at that time. At December 31, 2004, Northern Border Pipeline has reflected regulatory assets of $11.8 million, which are being recovered, or are expected to be recovered from its shippers over varying periods up to 44 years. 2 0 0 4 A N N U A L R E P O RT 29 Northern Border Pipeline’s long-lived assets are stated at original cost. Northern Border Pipeline must use estimates in determining the economic useful lives of those assets. For utility property, no retirement gain or loss is included in income except in the case of retirements or sales of entire regulated operating units. The original cost of utility property retired is charged to accumulated depreciation and amortization, net of salvage and cost of removal. Northern Border Pipeline’s accounting for financial instruments is in accordance with SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities.” SFAS No. 133 requires that every derivative instrument be recorded on the balance sheet as either an asset or liability measured at its fair value. The statement requires that changes in the derivative’s fair value be recognized currently in earnings unless specific hedge accounting criteria are met. Special accounting for qualifying hedges allows a derivative’s gains and losses to offset related results on the hedged item in the income statement. At December 31, 2004, Northern Border Pipeline had no derivative financial instruments outstanding. Results of Operations Northern Border Pipeline’s net income to partners was $166.8 million in 2004, $148.2 million in 2003 and $142.7 million in 2002. Northern Border Pipeline’s increase in net income in 2004 resulted from increased operating revenues as a result of its ability to generate and retain revenue from the sale of short-term capacity following the expiration of a condition under the previous rate case settlement that restricted Northern Border Pipeline’s sale of short-term firm capacity and that had required it to share new service revenue with its shippers, a reduction in operations and maintenance expense due to adjustments to expenses previously recorded for termination costs of the Cash Balance Plan and the settlement of previously accrued charges for administrative services provided by Northern Plains and its affiliates and a reduction in interest expense due to a decrease in average debt outstanding. Northern Border Pipeline’s 2003 operating results benefited from increased operating revenues as a result of its ability to generate and retain revenue from the sale of short-term capacity following the expiration of a condition under the previous rate case settlement that restricted Northern Border Pipeline’s sale of short-term firm capacity and that had required it to share interruptible transmission and new service revenue with its shippers, the recontracting of capacity previously held by ENA, and a reduction in interest expense due to lower interest rates. Partially offsetting these increases to Northern Border Pipeline’s operating results were higher operations and maintenance expenses for 2003 as compared to 2002. Operating revenues were $329.1 million in 2004, $324.2 million in 2003 and $321.1 million in 2002. The $4.9 million increase in operating revenues in 2004 over 2003 was primarily due to the expiration of conditions under Northern Border Pipeline’s previous rate case settlement, which enabled Northern Border Pipeline to generate and retain approximately $2.0 million from the sale of short-term firm capacity and approximately $2.0 million due to no longer being required to share new service revenue with its shippers. In addition, Northern Border Pipeline had an additional day of transportation services due to leap year, which approximated an additional $0.9 million in revenue. The $3.1 million increase in operating revenues in 2003 over 2002 resulted primarily from additional revenues of approximately $1.8 million related to the recontracted capacity of ENA contracts. ENA filed for Chapter 11 bankruptcy protection in December 2001 (see “The Impact of Enron’s Chapter 11 Filing on Northern Border Pipeline’s Business”). In addition, Northern Border Pipeline recognized revenue from its ability to offer short-term firm contracts and also being able to retain revenue for transportation service beyond a shipper’s contracted transportation path. Operations and maintenance expenses were $33.8 million in 2004, $43.8 million in 2003 and $41.4 million in 2002. The $10.0 million decrease in expense from 2003 to 2004 included a reduction of expenses of $3.1 million, as Northern Border Pipeline determined it was no longer liable for termination costs of the Cash Balance Plan. When compared to the impact of the charges recorded in 2003, this represents a $6.2 million decrease in expense between 2003 and 2004. Additionally in 2004, Northern Border Pipeline reduced its operations and maintenance expense by approximately $1.7 million and $0.6 million related to the settlement of previously accrued charges for administrative services provided by Northern Plains and its affiliates and a true-up for corporate compensation plans, respectively. Also contributing to the decrease were adjustments to allowance for doubtful accounts of $1.1 million for estimated 30 T C P I P E L I N E S , L P recoveries of claims against Enron. Operations and maintenance expense was increased by $1.0 million related to costs incurred as part of Northern Border Pipeline’s comprehensive effort to ensure compliance with Section 404 of the Sarbanes Oxley Act of 2002. The 2003 expense included a $3.1 million charge for Northern Border Pipeline’s allocation from Northern Plains related to the Cash Balance Plan (see “The Impact of Enron’s Chapter 11 Filing on Northern Border Pipeline’s Business”). In 2003, Northern Border Pipeline had increases in salaries and benefits, rights-of-way damages and telecommunication expenses offset by decreases in electric power costs, as compared to 2002. The 2002 expense included a $10.0 million reserve for costs associated with the treatment of previously collected quantities of natural gas used in utility operations to cover electric power costs. The FERC ordered refunds for these costs in 2003. Depreciation and amortization expense was $58.3 million in 2004, $57.8 million in 2003 and $58.7 million in 2002. The increase in 2004 over 2003 is primarily related to asset additions. The decrease from 2002 to 2003 primarily reflects asset retirements. Taxes other than income were $29.4 million in 2004, $29.6 million in 2003 and $28.4 million in 2002. The increase in 2003 from 2002 is primarily due to a refund received in 2002 from Minnesota for previously paid use taxes resulting from a ruling by the Minnesota Supreme Court. Interest expense, net, was $41.4 million in 2004, $44.9 million in 2003 and $51.5 million in 2002. The $3.5 million decrease from 2003 to 2004 resulted from a decrease in average debt outstanding partially offset by an increase in average interest rates. Interest expense for 2003 decreased from 2002 due to a decrease in Northern Border Pipeline’s average interest rate as well as a decrease in its average debt outstanding. Other income (expense) was $0.5 million in 2004, $0.1 million in 2003 and $1.8 million in 2002. Significant items included in the $0.4 million increase between 2003 and 2004 are additional income of approximately $0.6 million for interconnections constructed and the reimbursement for the use of previously vacated microwave frequencies of $0.2 million partially offset by approximately $0.5 million of bad debt expense and a $0.4 million inventory write-off. In 2003, Northern Border Pipeline recorded expense of approximately $0.6 million for a repayment of amounts previously received for vacated microwave frequency bands, interest expense of $0.3 million due to the FERC ordered refunds of electric power costs and $0.2 million of interest income received related to a sales tax refund on exempt purchases. The amount for 2002 includes approximately $0.6 million for amounts received for previously vacated microwave frequency bands and income of $0.2 million due to a reduction in reserves previously established. LIQUIDITY AND CAPITAL RESOURCES OF NORTHERN BORDER PIPELINE COMPANY Cash Distribution Policy of Northern Border Pipeline In December 2003, Northern Border Pipeline’s management committee voted to (i) issue equity cash calls to its general partners in the total amount of $130 million in early 2004 and $90 million in 2007; (ii) fund future growth capital expenditures with 50% equity capital contributions from its general partners; and (iii) change its cash distribution policy to be effective January 1, 2004, when cash distributions will be based upon 100% of distributable cash flow as determined from Northern Border Pipeline’s financial statements as earnings before interest, taxes, depreciation and amortization less interest expense and less maintenance capital expenditures, until January 1, 2008 when the cash distribution policy will be adjusted to maintain a consistent capital structure. Under the previous cash distribution policy, approximately $28 to $30 million was retained annually by Northern Border Pipeline to periodically repay outstanding bank debt. The additional equity contributions in 2004 were utilized to fully repay Northern Border Pipeline’s existing bank debt and thereby reducing its debt leverage in light of existing business conditions. Upon repayment of the existing bank debt, Northern Border Pipeline’s next scheduled debt maturity is May 2007. 2 0 0 4 A N N U A L R E P O RT 31 On November 30, 2004, Northern Border Pipeline issued an equity cash call to its partners in the total amount of $75 million, which was paid on December 22, 2004. This additional equity contribution was utilized to repay Northern Border Pipeline’s existing bank debt and thereby reduce its debt leverage in light of existing business conditions. This equity contribution will reduce the previously approved 2007 equity cash call from $90 million to $15 million. Summary of Certain Contractual Obligations The following table sets forth Northern Border Pipeline’s contractual obligations as of December 31, 2004. Payments Due by Period (thousands of dollars) Senior Notes due 2007 Senior Notes due 2009 Senior Notes due 2021 Operating Leases (1) Total Total Less Than 1 Year 1-3 Years 4 -5 Years After 5 Years 150,000 200,000 250,000 78,345 $ 678,345 – – – 2,392 2,392 150,000 – – 4,784 $ 154,784 – 200,000 – 4,784 $ 204,784 – – 250,000 66,385 $ 316,385 $ (1) See Note 7 – Notes to Northern Border Pipeline’s Financial Statements. Overview Northern Border Pipeline advises that it believes it has adequate liquidity to fund future recurring operating activities and capital expenditures. Short-term liquidity needs will be met by Northern Border Pipeline’s operating cash flows and its three-year credit agreement (2002 Pipeline Credit Agreement), defined below, or similar new credit agreements. Other liquidity needs are expected to be funded through the issuance of long-term debt and capital contributions made by Northern Border Pipelines’ general partners. Northern Border Pipeline’s ability to complete future debt offerings and the timing of any such offerings will depend on various factors, including prevailing market conditions, interest rates and its financial condition and credit ratings at the time. Debt and Credit Facilities Northern Border Pipeline entered into a $175 million 2002 Pipeline Credit Agreement with certain financial institutions in May 2002. The 2002 Pipeline Credit Agreement replaced a previous credit agreement. The 2002 Pipeline Credit Agreement is to be used to refinance existing indebtedness and for general business purposes. At December 31, 2004, there were no amounts outstanding under the 2002 Pipeline Credit Agreement. The 2002 Pipeline Credit Agreement requires the maintenance of a ratio of EBITDA (net income plus interest expense, income taxes and depreciation and amortization) to interest expense of greater than 3 to 1. The 2002 Pipeline Credit Agreement also requires the maintenance of the ratio of indebtedness to EBITDA of no more than 4.5 to 1. At December 31, 2004, Northern Border Pipeline was in compliance with these covenants. With the 2002 Pipeline Credit Agreement due to expire in May 2005, Northern Border Pipeline advises that it has commenced discussions with financial institutions and expects to have a facility in place at terms and conditions similar to the current facility. In April 2002, Northern Border Pipeline completed a private offering of $225 million of 6.25% Senior Notes due 2007 (2002 Pipeline Senior Notes). The indentures under which the 2002 Pipeline Senior Notes were issued do not limit the amount of unsecured debt Northern Border Pipeline may incur, however, they do contain material financial covenants, including restrictions on incurrence of secured indebtedness. The proceeds from the 2002 Pipeline Senior Notes were used to reduce Northern Border Pipeline’s indebtedness outstanding. In December 2004, Northern Border Pipeline redeemed $75 million of the 2002 Pipeline Senior Notes. 32 T C P I P E L I N E S , L P Cash Flows from Operating Activities Cash flows provided by operating activities were $206.1 million in 2004, $193.3 million in 2003 and $224.4 million in 2002. The increase in operating revenues and lower interest expense in 2004 as compared to 2003 contributed to the increase in operating cash flow. An additional $10.3 million of the increase in 2004 over 2003 operating cash flows was due to FERC ordered refunds paid in 2003. Other cash flows from operating activities for 2004 reflect Northern Border Pipeline’s initial payment of $7.4 million to the Tribes, in accordance with the terms of the Agreement. The $31.1 million decrease in 2003 from 2002 was primarily due to the payment of the FERC ordered refunds related to the electric power costs and the discontinuance of certain shipper transportation prepayments. Cash Flows from Investing Activities Cash used in investing activities was $10.6 million for 2004 as compared to $12.9 million for 2003 and $9.2 million for 2002. The capital expenditures for 2004, 2003 and 2002 were primarily related to renewals and replacements of existing facilities. Total capital expenditures for 2005 are estimated to be approximately $40.0 million, which includes approximately $15 million for the Chicago III Expansion project. The remaining capital expenditures for 2005 are primarily related to renewals and replacements of existing facilities. Northern Border Pipeline advises that it currently anticipates funding its 2005 capital expenditures primarily by borrowing on its credit facility and using operating cash flows. Cash Flows from Financing Activities Cash flows used in financing activities were $204.0 million for the year ended December 31, 2004 as compared to $177.0 million in 2003 and $200.8 million in 2002. Distributions to Northern Border Pipeline’s partners were $205.6 million, $154.0 million and $164.1 million for 2004, 2003 and 2002, respectively. In 2004, contributions of $205.0 million were received from Northern Border Pipeline’s partners to pay existing bank debt. The increase in distributions from 2003 to 2004 was primarily due to the change to Northern Border Pipeline’s cash distribution policy in 2004 (see Note 8 – Notes to Northern Border Pipeline’s Financial Statements). The decrease from 2002 to 2003 in distributions was primarily due to the impact of the refunds ordered by FERC on March 27, 2003. For 2004, 2003 and 2002, Northern Border Pipeline’s borrowings on long-term debt totaled $107.0 million, $142.0 million and $431.9 million, respectively. In 2004 and 2003, the borrowings were made under Northern Border Pipeline’s credit agreements. For 2002, Northern Border Pipeline received net proceeds from the 2002 Pipeline Senior Notes of approximately $223.5 million and borrowed $207.0 million under its credit agreements. Total payments on debt were $313.0 million, $165.0 million and $468.0 million in 2004, 2003 and 2002, respectively. In 2004, Northern Border Pipeline redeemed $75.0 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. In November 2004, Northern Border Pipeline received $7.6 million from the termination of its interest rate swap agreements with a total notional amount of $225.0 million. In April 2002, Northern Border Pipeline received $2.4 million from the termination of forward starting interest rate swaps upon issuance of the 2002 Pipeline Senior Notes (see Note 6 – Notes to Northern Border Pipeline’s Financial Statements). Impact of Enron’s Chapter 11 Filing on Northern Border Pipeline’s Business On December 2, 2001, Enron filed a voluntary petition for bankruptcy protection under Chapter 11 of the United States Bankruptcy Code. Certain wholly owned Enron subsidiaries also filed for Chapter 11 bankruptcy protection on December 2, 2001 and thereafter. Until November 17, 2004, each of Northern Plains, Northern Border Pipeline’s operator and Pan Border, two of the general partners of Northern Border Partners, were subsidiaries of Enron. Northern Plains and Pan Border were not among the Enron companies who filed for Chapter 11 protection. 2 0 0 4 A N N U A L R E P O RT 33 Sale of Enron Entities On March 31, 2004, Enron transferred its ownership interest in Northern Plains, and Pan Border to CrossCountry. In addition, CrossCountry and Enron entered into a transition services agreement pursuant to which Enron would provide to CrossCountry, on an interim, transitional basis, various services, including but not limited to (i) information technology services, (ii) accounting system usage rights and administrative support and (iii) payroll, employee benefits and administrative services. In turn, these services are provided to Northern Border Pipeline through Northern Plains. On June 24, 2004, Enron announced that it had reached an agreement with CCE Holdings for the sale of CrossCountry. On September 1, 2004, Enron announced that it reached an amended agreement for the sale of CrossCountry to CCE Holdings (CCE Holdings Agreement). On September 10, 2004, the Bankruptcy Court issued an order (the September 10 Order) approving the CCE Holdings Agreement. On September 16, 2004, Southern Union Company and ONEOK, Inc. each announced that ONEOK had entered into an agreement (ONEOK Agreement) to purchase Northern Plains and Pan Border (collectively the Transfer Group Companies) from CCE Holdings. This acquisition closed on November 17, 2004. Under the CCE Holdings Agreement, Enron agreed to extend certain of the terms of the transition services agreement and transition services supplemental agreement between CrossCountry and Enron (together the TSA) for a period of six months from the closing date. As part of the closing, ONEOK and CCE Holdings entered a transition services agreement referred to as the “Northern Border Transition Services Agreement” covering certain transition services by and among ONEOK, CCE Holdings and Enron for a period of six months. Certain of the services previously provided by Enron are now being provided through ONEOK. As services are transitioned to Northern Plains or ONEOK, it is possible that additional costs for computer hardware, software and personnel may result. The costs estimated to date do not appear to be materially greater than the costs incurred in the past by Northern Plains from Enron and CrossCountry. Pension Liability On December 31, 2003, Enron filed a motion seeking approval of the Bankruptcy Court to provide additional funding to, and for authority to terminate, the Cash Balance Plan and certain other defined benefit plans of Enron’s affiliates (collectively the Plans) in “standard terminations” within the meaning of Section 4041 of the Employee Retirement Income Security Act of 1974, as amended (ERISA). On January 30, 2004, the Bankruptcy Court entered an order authorizing the termination, additional funding and other actions necessary to effect the relief requested. Pursuant to the Bankruptcy Court order, any contributions to the Plans are subject to the prior receipt of a favorable determination by the Internal Revenue Service that the Plans are tax-qualified as of their respective dates of termination. On July 19, 2004, Enron was served with a complaint filed by the Pension Benefits Guaranty Corporation (PBGC) in the District Court for the Southern District of Texas against Enron as the sponsor and/or administrator of the Plans (the Action). By filing the Action, the PBGC is seeking an order (i) terminating the Plans; (ii) appointing the PBGC the statutory trustee of the Plans; (iii) requiring transfer to the PBGC of all records, assets or other property of the Plans required to determine the benefits payable to the Plans’ participants; and (iv) establishing June 2, 2004 as the termination date of the Plans. In the Bankruptcy Court September 10 Order, Enron was authorized to enter into an escrow agreement with CCE Holdings and PBGC. Upon closing, Enron deposited the amount of $321.8 million to an escrow account, which is intended to ensure that none of CCE Holdings or its affiliates are exposed to liability to the PBGC under Title IV of the ERISA, as amended, for which CCE Holdings may otherwise be indemnified pursuant to the CCE Holdings Agreement. In addition, the form of escrow agreement approved pursuant to the September 10 Order provides that, under certain circumstances and upon approval by or notice to the parties to the escrow agreement, some or all of the funds placed in escrow may be paid directly in respect of the Cash Balance Plan to the PBGC. However, the September 10 Order also provides that PBGC retains any rights or claims it may have against the Transfer Group Companies. 34 T C P I P E L I N E S , L P Enron management previously informed Northern Plains that Enron would seek funding contributions from each member of its ERISA controlled group of corporations that employs, or employed, individuals who are, or were, covered under the Cash Balance Plan. Northern Plains and NBP Services are considered members of Enron’s ERISA controlled group of corporations. As of December 31, 2003, the amount of approximately $6.2 million was estimated for Northern Plains’ proportionate share of the up to $200 million estimated termination costs for the Plans authorized by the Bankruptcy Court order. Since under the operating agreement with Northern Plains, these costs could be Northern Border Pipeline’s responsibility, Northern Border Pipeline accrued $3.1 million to satisfy claims of reimbursement for these termination costs. As a result of further evaluation and negotiation of Enron’s proposed allocation of the termination costs, Northern Plains advised Northern Border Pipeline that no claim of reimbursement for the termination costs will be made, resulting in a reduction in reserves during 2004 of $3.1 million for the termination costs. Under the ONEOK Agreement, neither Northern Border Pipeline nor Northern Plains will be required to contribute to or otherwise be liable for any contributions to Enron in connection with the Cash Balance Plan. The purchase price under the agreements will be deemed to include all contributions which otherwise would have been allocable to Northern Plains. Claims Filed in Bankruptcy At the time of the filing of the bankruptcy petition, Northern Border Pipeline had a number of contractual relationships with Enron and its subsidiaries. On July 15, 2004, the Bankruptcy Court approved the amended joint Chapter 11 plan and related disclosure statement (Chapter 11 Plan). Under the approved Chapter 11 Plan, assuming the previously announced sale of Portland General Electric is consummated, Enron creditors, which should include Northern Border Pipeline as a general unsecured creditor, will receive a combination of cash and equity of Prisma Energy International, Enron’s international energy asset business. Northern Border Pipeline has previously fully reserved its claims against Enron. ENA, a wholly owned subsidiary of Enron that is in bankruptcy, was a party to transportation contracts which obligated ENA to pay for 3.5% of Northern Border Pipeline’s capacity. Through the bankruptcy proceeding in 2002, ENA rejected and terminated all of its firm transportation contracts on Northern Border Pipeline. Since Enron guaranteed the obligations of ENA under those contracts, Northern Border Pipeline filed claims against both ENA and Enron for damages in the bankruptcy proceedings. As a result of a settlement agreement between ENA, Enron and Northern Border Pipeline, each of ENA and Enron have agreed to allow Northern Border Pipeline’s claim of approximately $20.6 million. The settlement agreement is expected to be presented to the Bankruptcy Court for approval in March 2005. Based upon this settlement between the parties, at December 31, 2004, Northern Border Pipeline adjusted its allowance for doubtful accounts to reflect an estimated recovery of $1.1 million for these claims. Northern Border Pipeline advises that it estimates it could recognize, through future operating results, additional recoveries of $6.0 million to $9.0 million for the claims in the Enron bankruptcy proceedings. However, there can be no assurances on the amounts actually recovered or timing of distributions under the Chapter 11 Plan. VEBA Trust Enron is the grantor of the Enron Gas Pipeline Employee Benefit Trust (the Trust), which when taken together with the Enron Corp. Medical Plan for Inactive Participants (the Medical Plan) constitutes a “voluntary employees’ beneficiary association” or “VEBA” under Section 501(c)(9) of the Internal Revenue Code. In October 2002, Northern Plains was advised that Enron had notified the committee that has administrative and fiduciary oversight related to the Trust and the Medical Plan, that Enron had made the determination to begin necessary steps to partition the assets of the Trust and the related liabilities of the Medical Plan among all of the participating employers of the Trust. The Trust was established as a regulatory requirement for inclusion of certain costs for post-employment medical benefits in the rates established for the affected pipelines, including Northern Border Pipeline. Enron requested the enrolled actuary to 2 0 0 4 A N N U A L R E P O RT 35 prepare an analysis and recommendation for the allocation of the Trust’s assets and associated liabilities among all the participating employers. On July 22, 2003, Enron sought approval of the Bankruptcy Court to terminate the Trust and to distribute its assets among certain identified pipeline companies, one being Northern Plains. If Enron’s relief had been granted as requested, Northern Plains would have assumed retiree benefit liabilities, estimated as of June 30, 2002, of $1.9 million with an asset allocation of $0.8 million. An objection to the motion was filed. An additional actuary has been engaged by Enron to review the analysis and recommendations for allocations. The results of that review have not been provided to Northern Plains. It is anticipated that a new motion will be filed and that the allocation of liabilities and assets will change from those set forth in the prior motion. Northern Border Pipeline advises that it does not believe that those changes will be material. Public Utility Holding Company Act (PUHCA) Regulation Northern Border Pipeline was previously a subsidiary of a registered holding company. Upon consummation of the sale of Northern Plains and Pan Border to CCE Holdings and to ONEOK, Northern Border Pipeline was no longer a subsidiary of a registered holding company. RESULTS OF OPERATIONS OF TUSCARORA GAS TRANSMISSION COMPANY In the following discussion of the results of Tuscarora, all amounts represent 100% of the operations of Tuscarora, in which the Partnership has held a 49% interest since September 1, 2000. Overview Tuscarora is a Nevada general partnership formed in 1993. Its general partners are TC Tuscarora Intermediate Limited Partnership, a direct subsidiary of TC PipeLines, which holds a 49% general partner interest, Tuscarora Gas Pipeline Co., a wholly owned subsidiary of Sierra Pacific Resources, which holds a 50% general partner interest and TCPL Tuscarora Ltd., an indirect wholly owned subsidiary of TransCanada, which holds the remaining 1% general partner interest in Tuscarora. The management of Tuscarora is overseen by a management committee that determines the policies of, has authority over the affairs of, and approves the actions of Tuscarora. The management committee participates in the management of the construction, maintenance and operation of the Tuscarora pipeline system. Tuscarora owns a 240-mile, 20-inch diameter, United States interstate pipeline system that originates at an interconnection point with facilities of Gas Transmission Northwest Corporation, a wholly-owned subsidiary of TransCanada, near Malin, Oregon and runs southeast through northeastern California and northwestern Nevada. The Tuscarora pipeline system terminates near Wadsworth, Nevada. Deliveries are also made directly to the local gas distribution system of Sierra Pacific Power, a subsidiary of Sierra Pacific Resources. Along its route, deliveries are made in Oregon, northern California and northwestern Nevada. The Tuscarora pipeline system was constructed in 1995 and was placed into service in December 1995. In January 2001, Tuscarora completed construction of the Hungry Valley lateral, a 14-mile, 16-inch pipeline extension that serves as Tuscarora’s second connection into Reno, Nevada. On December 1, 2002, Tuscarora completed and placed into service another expansion of its pipeline system. The 2002 Tuscarora expansion consisted of two compressor stations and an 11-mile pipeline extension from a point near the previous terminus of the Tuscarora pipeline system near Reno, Nevada to Wadsworth, Nevada. The expansion increased Tuscarora’s contracted capacity from 127 mmcfd to approximately 180 mmcfd. The new capacity is contracted under long-term firm transportation contracts ranging from ten to fifteen years. Critical Accounting Policy Tuscarora’s accounting policies conform to SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation.” Accordingly, certain assets that result from the regulated ratemaking process are recorded that would not be recorded by entities not accounting under SFAS No. 71. 36 T C P I P E L I N E S , L P Year Ended December 31, 2004 Compared to the Year Ended December 31, 2003 Tuscarora’s net income increased $4.5 million, or 38%, to $16.3 million for the year ended December 31, 2004, compared to $11.8 million in 2003. This increase is primarily due to higher revenues, lower costs and expenses and higher other income. Revenues generated by Tuscarora increased $2.9 million, or 10%, to $32.6 million for the year ended December 31, 2004, compared to $29.7 million for 2003. This increase is primarily due to incremental revenues generated from long-term firm transportation contracts which commenced in November 2003, resulting from Tuscarora’s expansion in 2002. Costs and expenses incurred by Tuscarora decreased $0.1 million, or 2%, to $4.9 million for the year ended December 31, 2004, compared to $5.0 million for the year ended December 31, 2003, primarily due to lower compressor maintenance and labor incurred in 2004. Depreciation recorded by Tuscarora decreased $0.3 million, or 5%, to $6.1 million for the year ended December 31, 2004, compared to $6.4 million for the prior year. The decrease reflects a change in the depreciation rate applied to compressor equipment. Financial charges recorded by Tuscarora decreased $0.4 million, or 6%, to $6.1 million for the year ended December 31, 2004, compared to $6.5 million for 2003. This decrease is primarily due to lower average debt outstanding in 2004 compared to the same period last year. Tuscarora recorded other income of $0.8 million and nil for the years ended December 31, 2004 and 2003, respectively. This increase is primarily due to a one time settlement payment in 2004 related to the termination of the 2005 Expansion. A Joint Settlement Agreement was filed and approved by the FERC allowing Tuscarora to withdraw its application for the proposed 2005 Expansion facilities and released the 2005 Expansion customers from their contractual commitments. Year Ended December 31, 2003 Compared to the Year Ended December 31, 2002 Tuscarora’s net income increased $1.4 million, or 13%, to $11.8 million for the year ended December 31, 2003, compared to $10.4 million in 2002. This increase is primarily due to higher revenues, partially offset by higher costs and expenses and higher depreciation expense. Revenues generated by Tuscarora increased $6.6 million, or 29%, to $29.7 million for the year ended December 31, 2003, compared to $23.1 million for 2002. This increase is primarily due to incremental revenues generated from new transportation contracts, including those related to Tuscarora’s expansion facilities that were placed into service December 1, 2002. Costs and expenses incurred by Tuscarora increased $2.2 million, or 79%, to $5.0 million for the year ended December 31, 2003, compared to $2.8 million for the year ended December 31, 2002. This increase is primarily due to the higher costs of operating two new compressor stations that were placed into service December 1, 2002. Depreciation recorded by Tuscarora increased $1.5 million, or 31%, to $6.4 million for the year ended December 31, 2003, compared to $4.9 million for 2002. The increase reflects the larger asset base resulting from the expansion in December 2002. Financial charges recorded by Tuscarora increased $0.8 million, or 14%, to $6.5 million for the year ended December 31, 2003, compared to $5.7 million for 2002. This increase is due to the fact that no interest was capitalized in 2003. In 2002, financial charges were lower due to the capitalization of interest expense related to funds used for the expansion. Tuscarora recorded other income of nil and $0.7 million for the years ended December 31, 2003 and 2002, respectively. This decrease is primarily due to the allowance recorded in 2002 related to equity funds used during construction of the expansion. No such allowance was recorded in 2003. 2 0 0 4 A N N U A L R E P O RT 37 LIQUIDITY AND CAPITAL RESOURCES OF TUSCARORA GAS TRANSMISSION COMPANY Cash Distribution Policy of Tuscarora In September 2000, Tuscarora adopted a cash distribution policy that became effective January 1, 2001. Under the terms of the cash distribution policy and at the discretion of the Tuscarora Management Committee, Tuscarora makes quarterly cash distributions to its general partners in accordance with their respective general partner interests. Cash distributions will generally be computed as the sum of Tuscarora’s net income before taxes and depreciation and amortization, less amounts required for debt repayments, net of refinancing, maintenance capital expenditures, certain non-cash items, and any cash reserves deemed necessary by the Tuscarora management committee. Cash distributions will be computed at the end of each calendar quarter and the distribution will be made on or before the last day of the month following the quarter end. Summary of Certain Contractual Obligations Payments Due by Period (millions of dollars) Series A Senior Notes due 2010 Series B Senior Notes due 2010 Series C Senior Notes due 2012 Operating Leases Commitments (1) Total Total Less Than 1 Year 1-3 Years 4 -5 Years $ 65.3 6.8 8.7 0.4 2.0 $ 83.2 $ $ 3.7 0.4 0.7 0.1 0.7 5.6 $ $ 10.3 1.4 2.5 0.2 1.3 15.7 $ $ 51.3 5.0 1.6 0.1 – 58.0 After 5 Years $ $ – – 3.9 – – 3.9 (1) Tuscarora’s commitments relate to a contract with a third party for maintenance services on certain components of its pipeline-related equipment. The contract expires in November 2007. Debt and Credit Facilities On March 15, 2002, Tuscarora issued Series C Senior Secured Notes in the amount of $10.0 million. These notes bear interest at 6.89% and are due in 2012. The proceeds from these notes were used to finance the construction of Tuscarora’s expansion facilities. On January 4, 2002, Tuscarora entered into a $5.0 million, 364-day revolving credit facility with Bank One, which bears interest at either LIBOR plus 1% or the prime rate. The Credit Facility expired on January 3, 2003, whereupon Tuscarora elected not to renew this facility and repaid the outstanding balance. In November 2001 and January 2002, Tuscarora entered into forward starting interest rate swaps with notional amounts of $10.0 million and $8.0 million, respectively, related to the planned issuance of Series C Senior Secured Notes. The swaps were settled on February 15, 2002 for net proceeds of approximately $0.2 million. The swaps were entered into to hedge the fluctuations in treasury rates and spreads between the execution date of the swaps and the issuance date of the Series C Senior Secured Notes. Short-term liquidity needs will be met by operating cash flows. Long-term capital needs may be met through the issuance of long-term indebtedness. Cash Flows from Operating Activities Cash flows provided by operating activities increased $8.5 million, or 52%, to $24.9 million for the year ended December 31, 2004, compared to $16.4 million for 2003. This increase is primarily due to increased earnings during 2004, a decrease in working capital and write-offs related to the termination of the 2005 Expansion. Cash flows provided by operating activities increased $1.4 million, or 9%, to $16.4 million for the year ended December 31, 2003, compared to $15.0 million for 2002. This increase is the result of increased earnings during 2003, as well as decreased working capital during the same period. 38 T C P I P E L I N E S , L P Cash Flows from Investing Activities Capital expenditures of $2.2 million for the year ended December 31, 2004 are primarily due to costs related to the 2005 Expansion that has since been terminated and costs incurred to settle the shrub density mitigation that arose in 1995, representing $1.1 million and $0.8 million, respectively. The remainder of the capital expenditures relate primarily to costs incurred for the 2002 expansion and capital maintenance. Net capital expenditures of $1.2 million for the year ended December 31, 2003 primarily related to the expansion that went into service December 1, 2002. Capital expenditures of $31.9 million for the year ended December 31, 2002 included $31.6 million for Tuscarora’s 2002 expansion. Total capital expenditures for 2005 are estimated to be $1.0 million of which approximately $0.6 million relates to the construction of the Barrick Lateral, a 0.5 mile lateral that will provide transportation service to a new electric generation customer located near Tracy, Nevada. The remainder relates to renewals and replacements of existing facilities. Tuscarora anticipates funding its 2005 capital expenditures by using a combination of partner contributions and operating cash flows. Cash Flows from Financing Activities Cash flows used in financing activities were $20.9 million for the year ended December 31, 2004, compared to cash flows from financing activities of $14.1 million for the year ended December 31, 2003. Tuscarora does not currently maintain a revolving credit facility. On January 3, 2003, Tuscarora repaid its Credit Facility in full which had $4.6 million outstanding at the beginning of the year. In 2002, Tuscarora received net proceeds of $10.0 million from the issuance of its Series C Senior Secured Notes. The proceeds from these notes were used to finance the construction of Tuscarora’s expansion facilities. Also, in 2002, Tuscarora drew on its Credit Facility to partially fund its 2002 expansion. At December 31, 2002, $4.6 million was outstanding on the Credit Facility. For the years ended December 31, 2004 and 2003 Tuscarora made debt repayments of $4.6 million and $4.7 million, respectively. Tuscarora received contributions from its partners of $0.8 million and $10.0 million for the years ended December 31, 2004 and 2003, respectively. These contributions were used to fund the construction of Tuscarora’s expansion facilities. Tuscarora paid cash distributions of $17.1 million and $14.2 million to its general partners for the years ended December 31, 2004 and 2003, respectively. The cash distributions paid in 2004 includes a one time settlement payment of $1.5 million related to the termination of the 2005 Expansion. Cash flows used in financing activities were $16.5 million in 2002. In 2002, Tuscarora made debt repayments of $4.1 million and paid cash distributions of $9.3 million. Sierra Pacific Resources Sierra Pacific Power, a wholly owned subsidiary of Sierra Pacific Resources, is Tuscarora’s largest shipper with approximately 69% of the total available capacity through 2017. In August 2003, the bankruptcy court granted Enron Power Marketing Inc.’s motion for a summary judgment with respect to claims against Nevada Power Company and Sierra Pacific Power (together, the Utilities) of approximately $235 million and $102 million, respectively, of liquidated damages, for power supply contracts terminated by Enron Power Marketing in May 2002. On October 11, 2004, the U.S. District Court for the Southern District of New York vacated a prior summary judgment by the Bankruptcy Court calling for the Utilities to pay Enron a total of approximately $336 million for terminated contracts. Subsequently, the Utilities filed a motion seeking clarification of the court’s rulings with respect to certain of their claims. On December 2, 2004, the District Court enjoined the Utilities from participating in the FERC hearings that were scheduled to begin December 13, 2004 in the companies’ ongoing dispute with Enron Power Marketing over terminated power contracts. On December 23, 2004, the District Court affirmed the Bankruptcy Court’s holding that the Utilities, by failing to rescind their contracts with 2 0 0 4 A N N U A L R E P O RT 39 Enron immediately upon discovering fraud in 2001, ratified those contracts and further held that Bankruptcy Court jurisdiction over the case is proper. A trial date has been set for April 18, 2005 in the Bankruptcy Court to review the issues remanded by the District Court with respect to Enron’s claims against the Utilities. In addition to claims for termination payments described above, Nevada Power and Sierra Pacific Power had previously deposited approximately $17.7 million and $6.7 million, respectively, into an escrow account for energy delivered by Enron Power Marketing to each of Nevada Power and Sierra Pacific Power in April 2002, for which the Utilities had not paid. Sierra Pacific Power to-date remains current on its shipping contracts with Tuscarora. RISK FACTORS AND CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION Cautionary Statement Regarding Forward-Looking Information A number of statements made by TC PipeLines, LP, in this Form 10-K filing made with the SEC, are forward-looking and relate to, among other things, anticipated financial performance, business prospects, strategies, market forces and commitments. Much of this information appears in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” found herein. All forward-looking statements are based on the Partnership’s beliefs as well as assumptions made by and information currently available to the Partnership. Words such as “anticipate,” “believe,” “estimate,” “expect,” “plan,” “intend,” “forecast,” and similar expressions, identify forward-looking statements. By its nature, such forward-looking information is subject to various risks and uncertainties, which could cause TC PipeLines’ actual results and experience to differ materially from the anticipated results or other expectations expressed in this Form 10-K. Readers are cautioned not to place undue reliance on this forward-looking information, which is as of the date of this Form 10-K. Risk Factors We are dependent on Northern Border Pipeline and Tuscarora and may not be able to generate sufficient cash from the distributions from each of Northern Border Pipeline and Tuscarora to enable us to pay the expected quarterly distribution on the TC PipeLines common units every quarter While we have a significant ownership interest in each of Northern Border Pipeline and Tuscarora, we do not control or operate either of these entities. The actual amount of cash we will have available to distribute to our common unitholders will significantly depend upon numerous factors relating to each of Northern Border Pipeline’s and Tuscarora’s businesses, most of which are beyond our control and the control of our general partner, including: • • • the amount of cash distributed to us by Northern Border Pipeline and Tuscarora; the tariff and transportation charges collected by Northern Border Pipeline and Tuscarora for transportation services on their pipeline systems; the ability of Northern Border Pipeline to recontract capacity for maximum transportation rates as existing contracts terminate; the amount of cash required to be contributed by us to either Northern Border Pipeline or Tuscarora in the future; • • pipelines competing with Northern Border Pipeline and Tuscarora; • • increases in Northern Border Pipeline’s and Tuscarora’s maintenance and operating costs; and expansion costs related to these systems. Other factors that affect the actual amount of cash that we will have available for distribution to our unitholders include the following: the amount of cash set aside and the adjustment in reserves made by our general partner in its sole discretion; required principal and interest payments on our debt; the cost of acquisitions, including related debt service payments; and • • • • our issuance of debt and equity securities. 40 T C P I P E L I N E S , L P Cash distributions are dependent primarily on our cash flow, financial reserves and working capital borrowings Cash distributions are not dependent solely on our profitability, which is affected by non-cash items. Therefore, we may make cash distributions during periods when losses are reported and may not make cash distributions during periods when we record profits. Northern Border Pipeline and Tuscarora may not be able to maintain existing customers or acquire new customers when the current shipper contracts expire or may choose to recontract for shorter periods or at less than maximum rates Northern Border Pipeline and Tuscarora face competition from other pipeline systems that serve the same natural gas markets. At December 31, 2004, four of Northern Border Pipeline’s largest shippers were obligated for approximately 57% of Northern Border Pipeline’s summer design capacity. Contracts for approximately 63% of the capacity contracted by these four shippers are due to expire by November 1, 2005. With contracts scheduled to expire through May 2005, approximately 800 mmcfd or 28% of summer design capacity will become available on the Northern Border Pipeline system from port of Morgan, Montana to the Venture, Iowa delivery point. Contracts for another 21% of summer design capacity will expire by December 2006. Northern Border Pipeline may not be able to renew or replace expiring contracts. The renewal or replacement of existing contracts with customers of Northern Border Pipeline depends on a number of factors beyond Northern Border Pipeline’s control, including: • • • • the supply of natural gas in Canada and the United States; competition from alternative sources of supply in the United States; competition from other pipelines; and the price of, and demand for, natural gas in markets served by the Northern Border Pipeline system. Because the forward natural gas basis differentials between western Canada and Northern Border Pipeline’s market centers may be less than the total transportation cost at maximum tariff rates, Northern Border Pipeline may sell a significant portion of available capacity on a short-term basis. Most of the contracts renewed in 2004 were for a duration of five or six months. The weighted average contract life of Northern Border Pipeline contracts at December 31, 2004 was 2.75 years. Additionally, if the forward natural gas basis differentials do not support maximum rates, Northern Border Pipeline’s revenue may be adversely affected. Although Northern Border Pipeline advises that it believes a reduction in expected 2005 net income and cash flow of approximately $7.0 million to $14.0 million is possible ($2.1 million to $4.2 million net to us), the impact on net income and cash flow may vary outside this range depending on actual natural gas basis differentials experienced during the year. Any inability by Northern Border Pipeline to renew existing contracts at maximum rates or at all may have an adverse impact on Northern Border Pipeline’s revenue, and, as a result, cash distributions made to us. Tuscarora competes in the northern Nevada natural gas transmission market with Paiute, owned by Southwest Gas Co. of Las Vegas, Nevada. The Paiute pipeline interconnects with Northwest Pipeline Corp. at the Nevada-Idaho border and transports gas from British Columbia and the U.S. Rocky Mountain Basin to the northern Nevada market. As a result of competition from the Paiute pipeline, Tuscarora’s proposed 2005 expansion was canceled pursuant to the October 2004 settlement with the potential expansion shippers. TransCanada’s main pipeline systems transport natural gas from the same natural gas reserves in western Canada that are used by Northern Border Pipeline’s and Tuscarora’s customers. TransCanada is not prohibited from actively competing with Northern Border Pipeline for the transport of western Canadian natural gas. If the FERC requires that Northern Border Pipeline’s or Tuscarora’s tariff be changed, Northern Border Pipeline’s or Tuscarora’s respective cash flows may be adversely affected Northern Border Pipeline and Tuscarora are subject to extensive regulation by the FERC. The FERC’s regulatory authority is not limited to but extends to matters including: 2 0 0 4 A N N U A L R E P O RT 41 transportation of natural gas; rates and charges; construction of new facilities; acquisition, extension or abandonment of services and facilities; accounts and records; • • • • • • depreciation and amortization policies; and • operating terms and conditions of service. Given the extent of regulation by the FERC and potential changes to regulations, we cannot predict: • • the likely federal regulations under which Northern Border Pipeline or Tuscarora will operate in the future; the effect that regulation will have on Northern Border Pipeline’s, Tuscarora’s or our financial positions, results of operations and cash flows; or • whether our cash flow will be adequate to make distributions to unitholders. Northern Border Pipeline’s ability to file for an increase of its rates before November 2005 to recover increases in most types of costs has been substantially eliminated as a result of the settlement of its last rate case. Further, the outcome of several pending or future proceedings before the FERC may adversely affect the amount of cash Northern Border Pipeline or Tuscarora are able to distribute to us. Please read “Business – Business of Northern Border Pipeline Company – FERC Regulation’’ and “Business – Business of Tuscarora Gas Transmission Company.” • Northern Border 2005 Rate Case. Under Northern Border Pipeline’s settlement agreement from the last rate case, the parties to the settlement agreed that Northern Border Pipeline must file a proceeding (rate case) under section 4 of the Natural Gas Act to determine the just and reasonable rates to be charged for its transportation services. We cannot predict what rates Northern Border Pipeline will file in its rate case, or what opposition, if any, there may be to that filing and what determinations FERC will make regarding the rate case. Any FERC determination adverse to Northern Border Pipeline may have an adverse impact on the cash distributed to us. • Income Tax Allowances. On July 20, 2004, the D.C. Circuit Court of Appeals issued an opinion in BP West Coast Products, LLC v. FERC that reversed the FERC decision that provided for an income tax allowance in the rates for a third party pipeline that was not a corporation. The D.C. Circuit Court remanded the case to the FERC for its determination regarding the proper income tax allowance. On December 2, 2004, the FERC initiated an inquiry open to all interested parties on whether the court’s ruling applies only to the specific facts of BP West Coast or if it extends to other pipelines with capital structures involving partnerships and other forms of ownership. It is not certain how, or when, the FERC may proceed with respect to its Request for Comments or any impact the proceeding may have on the rate methodology for interstate natural gas pipelines, including Northern Border Pipeline. The issue of whether Northern Border Pipeline’s rates should include an income tax allowance, and, if so, the amount thereof, may be addressed in its 2005 rate case. We cannot predict the outcome of that rate case, FERC’s inquiry, or FERC’s decision on remand of BP West Coast. Any FERC actions regarding this issue in Northern Border Pipeline’s rate case that may adversely affect Northern Border Pipeline could have an adverse effect on the cash distributions we receive from them. • Short Haul Capacity. In 2003, the FERC rejected tariff sheets filed by Northern Border Pipeline addressing its award of capacity because the FERC concluded that certain aspects of the proposal were not in accordance with the FERC’s policy. Northern Border Pipeline requested rehearing of that rejection, and that request for rehearing is still pending. On April 15, 2004, the FERC issued an order requesting comments from interested parties on whether the FERC’s current policy on awarding available capacity to a short-haul shipper appropriately balances the risks to the pipeline of being prevented from selling capacity for longer hauls, and the risks to prospective shippers and current shippers on the pipeline. Comments from Northern Border Pipeline and other interested parties were filed on June 15, 2004. We cannot predict when the FERC will issue its order or the impact it may have on Northern Border Pipeline. If the 42 T C P I P E L I N E S , L P FERC issues a decision denying Northern Border Pipeline’s proposal regarding the awarding of capacity, and if that decision has a negative impact on Northern Border Pipeline’s ability to generate revenue, it may have an adverse effect on Northern Border Pipeline’s ability to make cash distributions to us. • Tuscarora Revenue Study Filing. Pursuant to the terms of a settlement agreement with the Public Utility Commission of Nevada, Tuscarora agreed to submit a cost and revenue study to FERC if Tuscarora’s rates were not otherwise subject to review as part of a general rate change application within three years of the in-service date of December 1, 2002. The study, when filed, will reflect Tuscarora’s assessment of its rate base, costs, including its operation and maintenance expenses, depreciation, return and taxes. This filing will be open to review and may make Tuscarora’s existing rates subject to challenge by Tuscarora’s shippers or the FERC. If such a challenge were to result in a reduction in Tuscarora’s rates, Tuscarora’s future revenues might be adversely affected. Northern Border Pipeline’s and Tuscarora’s indebtedness may limit their ability to borrow additional funds, make distributions to us or capitalize on business opportunities Northern Border Pipeline is prohibited from making cash distributions during an event of default under its debt instruments. Provisions in Northern Border Pipeline’s debt instruments limit its ability to incur indebtedness and engage in specific transactions that could reduce its ability to capitalize on business opportunities that arise in the course of its business. Similarly, Tuscarora is prohibited from making cash distributions during an event of default under its debt instruments. Under Tuscarora’s debt instruments, Tuscarora has granted a security interest in certain of its transportation contracts, which is available to noteholders upon an event of default. Any future refinancing of Northern Border Partners’ or Tuscarora’s existing indebtedness or any new indebtedness could have similar or greater restrictions. If we are unable to make acquisitions on economically and operationally acceptable terms, either from third parties or TransCanada, our future financial performance will be limited to our participation in Northern Border Pipeline and Tuscarora We may not be able to: identify attractive acquisition candidates in the future; acquire assets on economically acceptable terms; • • • make acquisitions that will not be dilutive to earnings and operating surplus; or • incur additional debt to finance an acquisition without affecting our ability to make distributions to unitholders. Future acquisitions may involve the expenditure of significant funds. Depending upon the nature, size and timing of future acquisitions, we may be required to obtain additional financing. Additional financing may not be available to us on acceptable terms. In addition, we may not be able to acquire any more of TransCanada’s United States pipeline assets. Neither our partnership agreement nor any other agreement requires TransCanada to pursue a business strategy that favors us, and TransCanada is under no obligation to make available to us business opportunities that may be beneficial to us. TransCanada’s future acquisitions may not provide acquisition opportunities to us or, if these opportunities arose, they may not be on terms attractive to us. Moreover, TransCanada is not obligated to offer to us any assets it acquires as part of any future acquisitions. Majority control of the Northern Border Pipeline management committee by affiliates of ONEOK, Inc. may limit our ability to influence Northern Border Pipeline We own a 30% general partner interest in Northern Border Pipeline. The remaining 70% general partner interest in Northern Border Pipeline is owned by Northern Border Partners, L.P., a publicly traded limited partnership, which is not affiliated with us. ONEOK controls 57.75% of the Northern Border Pipeline management committee. Except as to any matters requiring unanimity, such as significant expansions or extensions to the pipeline system, the acceptance of rate cases and changes to, or suspensions of, the cash distribution policy, management committee members designated by ONEOK have the power to approve a particular matter requiring a majority vote despite the fact that our representative may vote against the project or other matter. Conversely, with respect to any matter requiring a majority vote, management committee members designated by ONEOK may disapprove a particular matter despite the fact that our representative may vote in favor of that matter. 2 0 0 4 A N N U A L R E P O RT 43 If Northern Border Pipeline or Tuscarora do not maintain or increase their respective rate bases by successfully completing FERC-approved projects, the amount of revenue attributable to the return on the rate base they collect from their shippers will decrease over time The Northern Border and Tuscarora pipeline systems are generally allowed to collect from their customers a return on their assets or “rate base” as reflected in their financial records as well as recover that rate base through depreciation. The amount they may collect from customers decreases as the rate base declines as a result of, among other things, depreciation and amortization. In order to avoid a reduction in the level of cash available for distributions to its partners based on its current FERC-approved tariff, each of these pipelines must maintain or increase its rate base through projects that maintain or add to existing pipeline facilities. These projects will depend upon many factors including: sufficient demand for natural gas; an adequate supply of proved natural gas reserves; available capacity on pipelines that connect with these pipelines; the execution of natural gas transportation contracts; the approval of any expansion or extension of the pipeline systems by their respective management committees; • • • • • • obtaining financing for these projects; and • receipt and acceptance of necessary regulatory approvals. Northern Border Pipeline’s and Tuscarora’s ability to complete these projects is also subject to numerous business, economic, regulatory, competitive and political uncertainties beyond its control, and neither Northern Border Pipeline nor Tuscarora may be able to complete these projects. If any significant shipper fails to perform its contractual obligations, Northern Border Pipeline’s or Tuscarora’s respective cash flows and financial condition could be adversely impacted As of December 31, 2004, the four largest shippers on the Northern Border Pipeline system accounted for approximately 57% of contracted capacity. Sierra Pacific Power, a wholly owned subsidiary of Sierra Pacific Resources, is Tuscarora’s largest shipper, with firm contracts for approximately 69% of its capacity. Sierra Pacific Resources and Sierra Pacific Power have below-investment grade credit ratings. While TC PipeLines has no current indication that Sierra Pacific Power is unable to meet its ongoing contractual obligations, TC PipeLines is unable to predict the future financial condition of Sierra Pacific Power and its long-term ability to meet its obligations under existing agreements with Tuscarora. If any of the significant shippers on either Northern Border Pipeline or Tuscarora fail to meet their contractual obligations, our ability to make cash distributions to our unitholders at current levels may be adversely affected. The long-term financial conditions of Northern Border Pipeline and Tuscarora, and as a result, of TC PipeLines, are dependent on the continued availability of western Canadian natural gas for import into the United States The development of additional natural gas reserves requires significant capital expenditures by others for exploration and development drilling and the installation of production, gathering, storage, transportation and other facilities that permit natural gas to be produced and delivered to pipelines that interconnect with Northern Border’s or Tuscarora’s pipeline systems. Low prices for natural gas, regulatory limitations, or the lack of available capital for these projects could adversely affect the development of additional reserves and the production, gathering, storage, pipeline transmission, import and export of natural gas supplies. If the availability of western Canadian natural gas were to decline, existing shippers on the Northern Border and Tuscarora pipeline systems may be unlikely to extend their contracts and Northern Border Pipeline and Tuscarora may be unable to find replacement shippers for lost capacity. Furthermore, additional natural gas reserves may not be developed in commercial quantities and in sufficient amounts to fill the capacities of each of the Northern Border and Tuscarora pipeline systems. 44 T C P I P E L I N E S , L P Northern Border Pipeline’s and Tuscarora’s businesses depend in part on the level of demand for western Canadian natural gas in the markets the pipeline systems serve. If demand for western Canadian natural gas decreases, shippers may not enter into or renew contracts Northern Border Pipeline’s and Tuscarora’s businesses depend in part on the level of demand for western Canadian natural gas in the markets the pipeline systems serve. The volumes of natural gas delivered to these markets from other sources affect the demand for both western Canadian natural gas and use of these pipeline systems. Demand for western Canadian natural gas also influences the ability and willingness of shippers to use the Northern Border and Tuscarora pipeline systems to meet the demand that these pipeline systems serve. If either of the Northern Border or Tuscarora pipeline systems are used less over the long term, we may have lower revenues and less cash to distribute to our unitholders. Northern Border Pipeline’s and Tuscarora’s operations are regulated by federal and state agencies responsible for environmental protection and operational safety Risks of substantial costs and liabilities are inherent in pipeline operations and each of Northern Border Pipeline and Tuscarora may incur substantial costs and liabilities in the future as a result of stricter environmental and safety laws, regulations and enforcement policies and claims for personal or property damages resulting from Northern Border Pipeline’s or Tuscarora’s operations. If either Northern Border Pipeline or Tuscarora, as applicable, is not able to recover these costs, cash distributions to unitholders could be adversely affected. Northern Border Pipeline’s and Tuscarora’s operations are subject to operational hazards and unforeseen interruptions, including natural disasters, adverse weather, accidents or other events beyond their control. A casualty occurrence might result in a loss of equipment or life, as well as injury and extensive property or environmental damage. If we were to lose TransCanada’s management expertise, we would not have sufficient stand-alone resources to operate We do not presently have sufficient stand-alone management resources to operate without services provided by TransCanada. Further, we would not be able to evaluate potential acquisitions and successfully complete acquisitions without TransCanada’s resources. Item 7A. Quantitative and Qualitative Disclosures about Market Risk TC PipeLines may be exposed to market risk through changes in interest rates. The Partnership does not have any material foreign exchange risks. TC PipeLines’ interest rate exposure results from its Revolving Credit Facility and its TransCanada Credit Facility, which are subject to variability in LIBOR interest rates. At December 31, 2004, TC PipeLines had $30.0 million outstanding on its Revolving Credit Facility and $6.5 million outstanding on its TransCanada Credit Facility. If LIBOR interest rates change by one percent compared to the rates in effect as of December 31, 2004, annual interest expense would change by less than $0.2 million. This amount has been determined by considering the impact of the hypothetical interest rates on variable rate borrowings outstanding as of December 31, 2004. The Partnership is also influenced by the same factors that influence Northern Border Pipeline and Tuscarora. Neither Northern Border Pipeline nor Tuscarora owns any of the natural gas it transports, therefore, neither assumes any of the related natural gas commodity price risk. Northern Border Pipeline may be exposed to market risk through changes in interest rates as discussed below. A control environment has been established which includes policies and procedures for risk assessment and the approval, reporting and monitoring of financial instrument activities. Northern Border Pipeline has utilized and expects to continue to utilize financial instruments in the management of interest rate risks to achieve a more predictable cash flow by reducing its exposure to interest rate fluctuations. Northern Border Pipeline advises that it does not use these instruments for trading purposes. 2 0 0 4 A N N U A L R E P O RT 45 Northern Border Pipeline’s interest rate exposure results from variable rate borrowings from commercial banks. To mitigate potential fluctuations in interest rates, Northern Border Pipeline attempts to maintain a significant portion of its debt portfolio in fixed rate debt. Northern Border Pipeline also uses interest rate swaps as a means to manage interest expense by converting a portion of fixed rate debt into variable rate debt to take advantage of declining interest rates. At December 31, 2004, Northern Border Pipeline had no variable rate debt outstanding. For additional information on Northern Border Pipeline’s debt obligations and derivative instruments, see Note 5 and Note 6 to Northern Border Pipeline’s Financial Statements, included elsewhere in this report. Item 8. Financial Statements and Supplementary Data The information required hereunder is included in this report as set forth in the “Index to Financial Statements” on page F-1. Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure None. Item 9A. Controls and Procedures Evaluation of Disclosure Controls and Procedures Based on their evaluation of the Partnership’s disclosure controls and procedures as of the end of the year covered by this annual report, the President and Chief Executive Officer and Chief Financial Officer of the general partner of the Partnership have concluded that the Partnership’s disclosure controls and procedures were effective in ensuring that the information required to be disclosed by the Partnership in the reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. Management’s Annual Report on Internal Control Over Financial Reporting Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Rule 13a-15(f) promulgated under the Securities Exchange Act of 1934. Internal control over financial reporting, no matter how well designed, has inherent limitations and can only provide reasonable assurance with respect to the preparation and fair presentation of published financial statements. Under the supervision and with the participation of our management, including our chief executive officer and chief financial officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our assessment according to these criteria, our management concluded that our internal control over financial reporting was effective as of December 31, 2004 to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with United States generally accepted accounting principles. Our management’s assessment of the effectiveness of our internal control over financial reporting as of December 31, 2004 has been audited by our independent auditors, KPMG LLP, a registered public accounting firm, as stated in their audit report on our assessment, which is included herein on page F-3. Item 9B. Other Information None. 46 T C P I P E L I N E S , L P PA RT I I I Item 10. Directors and Executive Officers of the General Partner TC PipeLines is a limited partnership and as such has no officers, directors or employees. Set forth below is certain information concerning the directors and officers of the general partner who manages the operations of TC PipeLines. Each director holds office for a one-year term or until his or her successor is earlier appointed. All officers of the general partner serve at the discretion of the Board of Directors of the general partner which is an indirect wholly owned subsidiary of TransCanada. Name Age Position with General Partner Ronald J. Turner Russell K. Girling David L. Marshall Walentin (Val) Mirosh Jack F. Jenkins-Stark Albrecht W.A. Bellstedt Kristine L. Delkus Steven D. Becker Donald R. Marchand Ronald L. Cook Max Feldman Wendy L. Hanrahan Amy W. Leong Maryse C. St.-Laurent 51 42 65 59 53 55 47 54 42 47 56 46 37 45 President, Chief Executive Officer and Director Chief Financial Officer and Director Independent Director Independent Director Independent Director Director Director Vice-President, Business Development Vice-President and Treasurer Vice-President, Taxation Vice-President Vice-President Controller Secretary Mr. Turner has been a director of the general partner since April 1999 and was appointed President and Chief Executive Officer in December 2000. Mr. Turner’s principal occupation is Executive Vice-President, Gas Transmission of TransCanada, a position he has held since March 2003. From December 2000 until March 2003, Mr. Turner was Executive Vice-President, Operations and Engineering of TransCanada. From June 2000 until December 2000, Mr. Turner was Executive Vice-President, International of TransCanada. Prior to June 2000, Mr. Turner was Senior Vice- President, International of TransCanada. Mr. Girling was appointed Chief Financial Officer and a director of the general partner in April 1999. Mr. Girling’s principal occupation is Executive Vice-President, Corporate Development and Chief Financial Officer of TransCanada, a position he has held since March 2003. From June 2000 until March 2003, Mr. Girling was Executive Vice-President and Chief Financial Officer of TransCanada. From July 1999 until June 2000, Mr. Girling was Senior Vice-President and Chief Financial Officer of TransCanada. Mr. Marshall was appointed a director of the general partner in July 1999. Mr. Marshall was Vice-Chairman of The Brinks Company (diversified energy, security and transportation services firm) from 1994 until 1998. Mr. Mirosh was appointed a director of the general partner in September 2004. Mr. Mirosh was also a non-independent director of the general partner from October 1999 to December 2001. Mr. Mirosh’s principal occupation is Vice- President – Nova Chemicals Corporation, President of Olefins and Feedstocks (commodity chemical company) since July 2003. Mr. Mirosh was Partner, MacLeod, Dixon (law firm) from January 2002 to July 2003. From May 2001 to December 2001, Mr. Mirosh was Executive Vice-President, TransCanada. From June 2000 to April 2001, Mr. Mirosh was Executive Vice-President Regulatory Strategy and Northern Development of TransCanada. From September 1999 to April 2000, Mr. Mirosh was Senior Vice-President, Strategy and Business Development of TransCanada. 2 0 0 4 A N N U A L R E P O RT 47 Mr. Jenkins-Stark was appointed a director of the general partner in July 1999. Mr. Jenkins-Stark is currently Chief Financial Officer of Silicon Valley Bancshares (offering financial products and services, including commercial, investment, merchant and private banking and private equity services), a position he has held since April 2004. Prior to that he was Vice-President, Business Operations and Technology at Itron Inc. (a manufacturer of automated meter reading technology and a developer of energy management software), a position he has held from January 2004 to March 2004. In March 2003, Mr. Jenkins-Stark was named a Managing Director at Itron following the purchase of Silicon Energy Corp. (internet-based energy and data management software) by Itron. Prior to the acquisition, Mr. Jenkins-Stark was Chief Financial Officer of Silicon Energy, a position he held from April 2000 to March 2003. From September 1998 until April 2000, Mr. Jenkins-Stark was Senior Vice-President and Chief Financial Officer of GATX Capital (commercial finance). Mr. Bellstedt was appointed a director of the general partner in December 2001. Mr. Bellstedt’s principal occupation is Executive Vice-President, Law and General Counsel of TransCanada, a position he has held since June 2000. From April 2000 until June 2000, Mr. Bellstedt was Senior Vice-President, Law and General Counsel of TransCanada. From August 1999 until April 2000, Mr. Bellstedt was Senior Vice-President, Law and Administration of TransCanada. Ms. Delkus was appointed a director of the general partner in November 2003. Ms. Delkus’ principal occupation is Vice- President, Law, Gas Transmission of TransCanada, a position she has held since December 2004. From July 2001 to December 2004, Ms. Delkus was Vice-President, Law, Power and Regulatory. From July 2000 to July 2001, Ms. Delkus was Vice-President, Law, Trading & Business Development. From March 1997 to July 2000, Ms. Delkus was Senior Legal Counsel, U.S. Regulatory Law. Mr. Becker was appointed Vice-President, Business Development of the general partner in September 2003. Mr. Becker’s principal occupation is Vice-President, Gas Development of TransCanada, a position he has held since April 2003. From 1999 until April 2003, Mr. Becker was Vice-President, Market Development, and Vice-President, Gas Strategy. Mr. Marchand was appointed Vice-President and Treasurer of the general partner in October 1999. Mr. Marchand’s principal occupation is Vice-President, Finance and Treasurer of TransCanada, a position he has held since September 1999. Mr. Cook was appointed Vice-President, Taxation of the general partner in April 2002. Mr. Cook’s principal occupation is Vice-President, Taxation of TransCanada, a position he has held since April 2002. From June 1997 to April 2002, Mr. Cook served as Director, Taxation of TransCanada. Mr. Feldman was appointed Vice-President of the general partner in September 2003. Mr. Feldman’s principal occupation is Vice-President, Gas Transmission West of TransCanada, a position he has held since April 2003. From June 2000 until April 2003, Mr. Feldman was Senior Vice-President, Customer, Sales and Service of TransCanada. From September 1999 until June 2000, Mr. Feldman was Senior Vice-President, Customer Sales and Service, Transmission Division of TransCanada. Ms. Hanrahan was appointed Vice-President of the general partner in September 2003. Ms. Hanrahan’s principal occupation is Vice-President, Human Resources of TransCanada, held since January 2005. From May 2003 to December 2004, Ms. Hanrahan was Director, Planning, Evaluation and Rates, Gas Transmission West of TransCanada. From September 2001 until April 2003, Ms. Hanrahan was Director, Corporate Strategy of TransCanada. From July 1998 until August 2001, Ms. Hanrahan was Director, Financial Services of TransCanada. Ms. Leong was appointed Controller of the general partner in September 2003. Ms. Leong’s principal occupation is Director, Gas Transmission Accounting of TransCanada, a position she has held since January 2005. From April 2003 to December 2004, Ms. Leong was Manager, Gas Transmission Accounting of TransCanada. From January 2000 until April 2003, Ms. Leong was Manager, Regulatory Accounting and Capital Accounting of TransCanada. From February 1999 until January 2000, Ms. Leong was Manager, Corporate Planning of TransCanada. 48 T C P I P E L I N E S , L P Ms. St.-Laurent was appointed Secretary of the general partner in September 2003. Prior to her appointment, Ms. St.-Laurent acted as recording Secretary of the general partner since January 2001. Ms. St.-Laurent’s principal occupation is Senior Legal Counsel, Corporate Secretarial Department of TransCanada, a position she has held since April 2001. From June 1997 until April 2001, Ms. St.-Laurent was Legal Counsel, Corporate Secretarial Department of TransCanada. Mr. Helman retired from the board on September 21, 2004. Mr. Helman had been a director of the general partner since 1999. Management and the other board members acknowledge with gratitude the valuable contributions of Mr. Helman to the Board and to the Partnership. Upon Mr. Helman’s retirement, the board appointed Mr. Walentin (Val) Mirosh as his successor as director of the general partner. Audit Committee Financial Expert The board of directors has determined that David Marshall and Jack Jenkins-Stark are “audit committee financial experts”, are “independent” and are “financially sophisticated” as defined under applicable SEC and Nasdaq Stock Market Corporate Governance rules. The board’s affirmative determination for both David Marshall and Jack Jenkins-Stark was based on their respective education and extensive experience as chief financial officers for corporations that presented a breadth and level of complexity of accounting issues that are generally comparable to those of TC PipeLines. Identification of the Audit Committee The audit committee of the general partner is comprised of three independent board members. The members of the committee are David Marshall, as Chair, Jack Jenkins-Stark and Walentin (Val) Mirosh. At the time of Mr. Mirosh’s appointment to the board of directors and to the audit committee on September 21, 2004, Mr. Mirosh was not independent as required under the rules of the Nasdaq Stock Market but was independent as required by the rules of the SEC. The board of directors determined at the time of Mr. Mirosh’s appointment that his membership on the board and the audit committee was required and in the best interest of the Partnership due to Mr. Mirosh’s experience and knowledge of the industry taking into consideration the experience and mix of skills and knowledge of other members of the audit committee. As of January 1, 2005, all members of the audit committee, including Mr. Mirosh, meet the criteria for independence as set forth under the rules of the SEC and those of the Nasdaq Stock Market. None of the audit committee members have participated in the preparation of the financial statements of the Partnership or any of its subsidiaries at any time during the past three years. In addition, all member of the audit committee are able to read and understand fundamental financial statements, including a company’s balance sheet, income statement, and cash flow statement. Code of Ethics TC PipeLines believes that director, management and employee honesty and integrity are important factors in ensuring good corporate governance. The employees of the general partner, as employees of TransCanada, are subject to TransCanada’s code of business ethics. In addition, the general partner has adopted a code of business ethics for its President and Chief Executive Officer, Chief Financial Officer and Controller and one which applies to its independent directors, being the code of business ethics for directors. All codes are published on its website at www.tcpipelineslp.com. If any substantive amendments are made to the code for senior officers or if any waivers are granted, the amendment or waiver will be published on TC PipeLines’ website or filed in a report on Form 8-K. Corporate Governance The audit committee has adopted a charter which specifically provides that it is responsible for the appointment, compensation, retention and oversight of the work of the independent public accountants engaged in preparing or issuing TC PipeLines’ audit report, that the committee has the authority to engage independent counsel and other advisors as it determines necessary to carry out its duties and for the committee to be responsible for establishing procedures for the receipt, retention and treatment of complaints regarding accounting, internal accounting controls or auditing matters, including procedures for the confidential, anonymous submission by employees of the general partner concerns regarding questionable accounting or auditing matters. The committee has adopted TransCanada’s Ethics help line in fulfillment of 2 0 0 4 A N N U A L R E P O RT 49 its responsibility to establish a confidential and anonymous whistle blowing process. The toll free Ethics Help-Line number and the audit committee’s charter are published on TC PipeLines website at www.tcpipelineslp.com. Section 16(a) Beneficial Ownership Reporting Compliance Section 16(a) of the Exchange Act requires the Partnership’s directors and executive officers, and persons who own more than 10% of the common units, to file initial reports of ownership and reports of changes in ownership (Forms 3, 4, and 5) of the common units with the SEC and the Nasdaq Stock Market. Executive officers, directors and greater than 10% unitholders are required by SEC regulation to furnish the Partnership with copies of all such forms that they file. Based solely upon a review of reports on Forms 3 and 4 and amendments thereto furnished to the Partnership during its most recent fiscal year and reports on Form 5 and amendments thereto furnished to the Partnership with respect to its most recent fiscal year, and written representations from officers and directors of the general partner that no Form 5 was required, the Partnership believes that all filing requirements applicable to its officers, directors and beneficial owners under Section 16(a) were complied with during the year ended December 31, 2004. Item 11. Executive Compensation The following table summarizes certain information regarding the annual salary of Ronald J. Turner, President and Chief Executive Officer of the general partner of the Partnership, for the years ended December 31, 2004, 2003, and 2002 paid by TransCanada, parent company of the general partner. Mr. Turner is an employee of TransCanada. TC PipeLines reimburses TransCanada for the services contributed to its operations by Mr. Turner. Approximately 10% of Mr. Turner’s base salary listed in the table below is allocated to the Partnership. Name and Principal Position Ronald J. Turner, President and Chief Executive Officer Annual TransCanada Base Salary Year 2004 2003 2002 Canadian Dollars 450,000 447,501 436,254 United States Dollar Equivalent (1) 374,000 346,000 276,000 (1) The compensation of the Chief Executive Officer of the general partner is paid by TransCanada in Canadian dollars. The United States dollar equivalents have been calculated using the applicable December 31, 2004, 2003 and 2002 noon buying rates of 0.8308, 0.7738 and 0.6331, respectively, as reported by the Bank of Canada. Each director who is not an employee of TransCanada, the general partner or its affiliates (independent director) is entitled to a directors’ retainer fee of $15,000 per annum and an additional fee of $2,000 per annum for each committee of the board of which he is Chair. These fees are paid by the Partnership on a semi-annual basis. Each independent director is also paid a fee of $1,500 for attendance at each meeting of the Board of Directors and a fee of $750 for attendance at each meeting of a committee of the Board. The Chair of the Audit Committee receives an additional $375 per meeting for his additional duties as committee chair. The independent directors are reimbursed for out-of- pocket expenses incurred in the course of attending such meetings. Under a directors’ compensation plan adopted effective July 19, 1999, each independent director receives 50% of his annual board retainer that is payable on the applicable date in the form of common units of the Partnership. The common units are purchased by the general partner on the open market and the number of common units purchased under the directors’ compensation plan is based on the trading price of common units on the day preceding the applicable payment date. As the Partnership does not have any employees, the Audit and Compensation Committee of the Board of Directors and subsequently the Board of Directors of the general partner of TC PipeLines, have not been called upon to make any determination with respect to the amount of compensation to be paid to the Partnership’s President and CEO. The board does, however, approve the allocation of the salary of the President and CEO to the Partnership on an annual basis. The executive officers’ salaries are determined on a competitive and market basis by TransCanada. 50 T C P I P E L I N E S , L P Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters The following table sets forth the beneficial ownership of the voting securities of the Partnership as of March 3, 2005 by the general partner’s directors, officers and certain beneficial owners. Executive Officers of the general partner own shares of TransCanada, which in the aggregate amount to less than 1% of TransCanada’s issued and outstanding shares. Other than as set forth below, no person is known by the general partner to own beneficially more than 5% of the voting securities of the Partnership. Name and Business Address TC PipeLines GP, Inc. (2) (3) 450 1st Street SW Calgary, Alberta T2P 5H1 TransCan Northern Ltd. (2) 450 1st Street SW Calgary, Alberta T2P 5H1 Goldman Sachs Group Inc. (4) 85 Broad Street New York, New York 10004 David L. Marshall (5) 450 1st Street SW Calgary, Alberta T2P 5H1 Walentin (Val) Mirosh (6) 450 1st Street SW Calgary, Alberta T2P 5H1 Jack F. Jenkins-Stark (7) 3003 Tasman Drive Santa Clara, CA 95054 Ronald J. Turner 450 1st Street SW Calgary, Alberta T2P 5H1 Russell K. Girling 450 1st Street SW Calgary, Alberta T2P 5H1 Albrecht W. A. Bellstedt 450 1st Street SW Calgary, Alberta T2P 5H1 Kristine L. Delkus 450 1st Street SW Calgary, Alberta T2P 5H1 Directors and Executive Officers as a Group (8) (9) (14 persons) Amount and Nature of Beneficial Ownership Common Units Number of Units Percent of Class (1) 2,809,306 2,800,000 1,555,183 1,404 – 3,304 – – – – 4,708 16.1 16.0 8.9 * * * – – – – * 2 0 0 4 A N N U A L R E P O RT 51 (1) (2) (3) (4) (5) (6) (7) A total of 17,500,000 common units are issued and outstanding. TC PipeLines GP, Inc. and TransCan Northern Ltd. are wholly owned indirect subsidiaries of TransCanada. TC PipeLines GP, Inc. owns an aggregate 2% general partner interest of TC PipeLines. As reported on a schedule 13G/A filed on February 8, 2005, the Goldman Sachs Group, Inc. (GS Group) and Goldman, Sachs & Co. (Goldman Sachs) each disclaim beneficial ownership of the securities beneficially owned by (i) any client accounts with respect to which Goldman Sachs or employees of Goldman Sachs have voting or investment discretion, or both and (ii) certain investment entities, of which a subsidiary of GS Group or Goldman Sachs is the general partner, managing general partner or other manager, to the extent interests in such entities are held by persons other than GS Group, Goldman Sachs or their affiliates. 1,404 units are held directly by Mr. Marshall. No units are currently held by Mr. Mirosh. 3,304 units are held by the Jenkins-Stark Family Trust dated June 16, 1995. (8) With the exception of the two named directors above, none of the other directors and executive officers hold any units of TC PipeLines. (9) Ronald J. Turner holds 282,500 options and 44,584 shares of TransCanada; Russell K. Girling holds 205,000 options and 10,674 shares of TransCanada; Albrecht W.A. Bellstedt holds 46,667 options and 13,065 shares of TransCanada; Kristine L. Delkus holds 60,500 options and 2,669 shares of TransCanada; Steven D. Becker holds 136,051 options and 1,358 shares of TransCanada; Donald R. Marchand holds 111,000 options and 4,960 shares of TransCanada; Ronald L. Cook holds 59,290 options and 9,144 shares of TransCanada; Max Feldman holds 147,835 options and 24,248 shares of TransCanada; Wendy L. Hanrahan holds 19,200 options and 68 shares of TransCanada; Amy W. Leong holds 5,600 options and 2,525 shares of TransCanada; Maryse C. St.-Laurent holds 0 options and 2,275 shares of TransCanada, and Walentin (Val) Mirosh holds 10,000 options of TransCanada. The directors and executive officers as a group hold 1,083,643 options and 115,570 shares of TransCanada. * Less than 1%. Item 13. Certain Relationships and Related Transactions An indirect subsidiary of TransCanada owns 2,800,000 common units and the general partner owns 2,809,306 common units representing an aggregate 31.4% limited partner interest in the Partnership. In addition, the general partner owns an aggregate 2% general partner interest in the Partnership through which it manages and operates the Partnership. As a result, TransCanada’s aggregate ownership interest in the Partnership is 33.4% by virtue of its indirect ownership of the general partner and a 31.4% aggregate limited partner interest. The general partner is accountable to TC PipeLines and the unitholders as a fiduciary. Neither the Delaware Revised Uniform Limited Partnership Act (Delaware Act) nor case law defines with particularity the fiduciary duties owed by general partners to limited partners of a limited partnership. The Delaware Act does provide that Delaware limited partnerships may, in their partnership agreements, restrict or expand the fiduciary duties owed by a general partner to limited partners and the partnership. In order to induce the general partner to manage the business of TC PipeLines, the partnership agreement contains various provisions restricting the fiduciary duties that might otherwise be owed by the general partner. The following is a summary of the material restrictions of the fiduciary duties owed by the general partner to the limited partners: • The partnership agreement permits the general partner to make a number of decisions in its “sole discretion.” This entitles the general partner to consider only the interests and factors that it desires and it shall have no duty or obligation to give any consideration to any interest of, or factors affecting, TC PipeLines, its affiliates or any limited partner. Other provisions of the partnership agreement provide that the general partner’s actions must be made in its reasonable discretion. • The partnership agreement generally provides that affiliated transactions and resolutions of conflicts of interest not involving a required vote of unitholders must be “fair and reasonable” to TC PipeLines. In determining whether a transaction or resolution is “fair and reasonable” the general partner may consider interests of all parties involved, including its own. Unless the general partner has acted in bad faith, the action taken by the general partner shall not constitute a breach of its fiduciary duty. • The partnership agreement specifically provides that it shall not be a breach of the general partner’s fiduciary duty if its affiliates engage in business interests and activities in competition with, or in preference or to the exclusion of, TC PipeLines. Further, the general partner and its affiliates have no obligation to present business opportunities to TC PipeLines. • The partnership agreement provides that the general partner and its officers and directors will not be liable for monetary damages to TC PipeLines, the limited partners or assignees for errors of judgment or for any acts or omissions if the general partner and those other persons acted in good faith. 52 T C P I P E L I N E S , L P TC PipeLines is required to indemnify the general partner and its officers, directors, employees, affiliates, partners, members, agents and trustees (collectively referred to hereafter as the General Partner and others), to the fullest extent permitted by law, against liabilities, costs and expenses incurred by the General Partner and others. This indemnification is required if the General Partner and others acted in good faith and in a manner they reasonably believed to be in, or (in the case of a person other than the general partner) not opposed to, the best interests of TC PipeLines. Indemnification is required for criminal proceedings if the General Partner and others had no reasonable cause to believe their conduct was unlawful. The Partnership does not have any employees. The management and operating functions are provided by the general partner. The general partner does not receive a management fee or other compensation in connection with its management of the Partnership. The Partnership reimburses the general partner for all costs of services provided, including the costs of employee, officer and director compensation and benefits, and all other expenses necessary or appropriate to the conduct of the business of, and allocable to the Partnership. The partnership agreement provides that the general partner will, in its sole discretion, determine the expenses that are allocable to the Partnership in any reasonable manner determined by it. Total costs reimbursed to the general partner by the Partnership were approximately $0.9 million for the year ended December 31, 2004. Such costs include personnel costs (such as salaries and employee benefits), overhead costs (such as office space and equipment) and out-of-pocket expenses related to the provision of services to the Partnership. On May 28, 2003, the Partnership renewed its $40.0 million unsecured two-year TransCanada Credit Facility with TransCanada PipeLine USA Ltd., an affiliate of the general partner. The TransCanada Credit Facility bears interest at LIBOR plus 1.25%. The purpose of the TransCanada Credit Facility is to provide borrowings to fund capital expenditures, to fund capital contributions to Northern Border Pipeline, Tuscarora and any other entity in which the Partnership directly or indirectly acquires an interest, to fund working capital and for other general business purposes, including temporary funding of cash distributions to unitholders and the general partner, if necessary. At December 31, 2004 and December 31, 2003, the Partnership had $6.5 million and nil borrowings outstanding, respectively, under the TransCanada Credit Facility. The interest rate on the TransCanada Credit Facility at December 31, 2004 was 3.75%. The Partnership repaid in full the $6.5 million outstanding balance on its TransCanada Credit Facility on February 22, 2005. Item 14. Principal Accountant Fees and Services The following table sets forth, for the periods indicated, the fees billed by the principal accountants. Audit Fees Audit-Related Fees (3) Tax Fees (3) All Other Fees (3) 2004 2003 109,916 (2) 65,500 (1) – – – – – – (1) (2) (3) On April 23, 2002, the Partnership filed a shelf registration statement with the SEC. These charges include fees paid to KPMG, the Partnership’s external auditors, for services performed related to this filing in the amount of $3,000. 2004 Audit Fees include services performed related to Sarbanes-Oxley Act reporting requirements. The Partnership has not engaged its external auditors for any tax services, audit-related services, or other services in 2004 or 2003. PA RT I V 2 0 0 4 A N N U A L R E P O RT 53 Item 15. Exhibits, Financial Statement Schedules a) (1) and (2) Financial Statements and Financial Statement Schedules The financial statements filed as part of this report are listed in the “Index to Financial Statements” on page F-1. (3) Exhibits. No. *3.1 *3.2 *3.3 *3.4 *3.5 *3.6 *4.1 *4.2 *4.3 *4.4 *10.1 *10.2 *10.2.1 Description Amended and Restated Agreement of Limited Partnership of TC PipeLines, LP dated May 28, 1999 (Exhibit 3.1 to TC PipeLines, LP’s Form 10-K, March 28, 2000). Certificate of Limited Partnership of TC PipeLines, LP (Exhibit 3.2 to TC PipeLines, LP’s Form S-1 Registration Statement, Registration No. 333-69947, December 30, 1998). Certificate of Limited Partnership of TC PipeLines Intermediate Limited Partnership (Exhibit 3.3 to TC PipeLines, LP’s Form S-1, December 30, 1998). Certificate of Limited Partnership of TC Tuscarora Intermediate Limited Partnership (Exhibit 99.1 to TC PipeLines, LP’s Form 8-K, September 1, 2000). Agreement of Limited Partnership of TC Tuscarora Intermediate Limited Partnership dated July 19, 2000 (Exhibit 99.2 to TC PipeLines, LP’s Form 8-K, September 1, 2000). Amended and Restated Agreement of Limited Partnership of TC PipeLines Intermediate Limited Partnership dated May 28, 1999 (Exhibit 10.1 to TC PipeLines, LP’s Form 10-K, March 28, 2000). Indenture, dated as of August 17, 1999 between Northern Border Pipeline Company and Bank One Trust Company, NA, successor to The First National Bank of Chicago, as trustee (Exhibit 4.1 to Northern Border Pipeline Company, Form S-4 Registration Statement, Registration No. 333-88577, October 7, 1999). Indenture, Assignment and Security Agreement dated December 21, 1995 between Tuscarora Gas Transmission Company and Wilmington Trust Company, as trustee (Exhibit 99.1 to TC PipeLines, LP’s Form 10-Q, September 30, 2000). Indenture dated September 17, 2001, between Northern Border Pipeline Company and Bank One Trust Company, N.A. (Exhibit 4.2 to Northern Border Pipeline Company, Form S-4 Registration Statement, Registration No. 333-73282, November 13, 2001). Indenture dated April 29, 2002, between Northern Border Pipeline Company and Bank One Trust Company, NA, as trustee (Exhibit 4.1 to Northern Border Pipeline Company’s Form 10-Q, March 31, 2002). Contribution, Conveyance and Assumption Agreement among TC PipeLines, LP and certain other parties dated May 28, 1999 (Exhibit 10.2 to TC PipeLines, LP’s Form 10-K, March 28, 2000). Northern Border Pipeline Company General Partnership Agreement between Northern Border Intermediate Limited Partnership, TransCanada Border PipeLine Ltd., and TransCan Northern Ltd., effective March 9, 1978 as amended (Exhibit 3.2 to Northern Border Partners, L.P. Form S-1 Registration Statement No. 33-66158). Seventh Supplement Amending Northern Border Pipeline Company General Partnership Agreement dated as of September 23, 1993 (Exhibit 10.3.1 to TC PipeLines, LP’s Form S-1, December 30, 1998). 54 T C P I P E L I N E S , L P *10.2.2 *10.2.3 *10.2.4 *10.3 *10.4 *10.5 *10.6 *10.7 *10.8 *10.8.1 *10.8.2 *10.8.3 *10.9 *10.9.1 Eighth Supplement Amending Northern Border Pipeline Company General Partnership Agreement dated May 21, 1999 by and among TransCan Border PipeLine Ltd., TransCanada Northern Ltd., Northern Border Intermediate Limited Partnership and TC PipeLines Intermediate Limited Partnership (Exhibit 10.3.2 to TC PipeLines, LP’s Form 10-K, March 28, 2000). Ninth Supplement Amending Northern Border Pipeline Company General Partnership Agreement dated July 16, 2001 by and among Northern Border Intermediate Limited Partnership and TC PipeLines Intermediate Limited Partnership (Exhibit 10.37 to Northern Border Pipeline Company, Form S-4 Registration Statement, Registration No. 333-73282, November 13, 2001). Tenth Supplement Amending Northern Border Pipeline Company General Partnership Agreement dated March 3,2005 (Exhibit 3.5 to Northern Border Pipeline Form 10-K, December 31, 2004). Renewal of U.S. $40,000,000 Two Year Revolving Credit Facility between TC PipeLines, LP, as borrower, and TransCanada PipeLine USA Ltd., as lender dated May 28, 2003 (Exhibit 10.1 to TC PipeLines, LP’s Form 10-Q, August 14, 2003). Operating Agreement between Northern Border Pipeline Company and Northern Plains Natural Gas Company, dated February 28, 1980 (Exhibit 10.3 to Northern Border Partners, L.P.’s Form S-1 Registration Statement No. 33-66158). Northern Border Pipeline 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 (Exhibit 10.21 to Northern Border Partners, L.P.’s 1998 Form 10-K/A, March 24, 1999). Directors’ Compensation Plan of TC PipeLines, GP, Inc. dated effective July 19, 1999 (Exhibit 10.36 to TC PipeLines, LP’s Form 10-K, March 28, 2000). Credit Agreement dated as of August 22, 2000 among TC PipeLines, LP, the Lenders Party thereto and Bank One N.A., as agent (Exhibit 99.2 to TC PipeLines, LP’s Form 10-Q, September 30, 2000). First Amendment and Waiver to Credit Agreement among TC PipeLines, LP, the Lenders Party thereto and Bank One N.A., as agent, April 15, 2002 (Exhibit 10.1 to TC PipeLines, LP’s Form 10-Q, September 30, 2002). Second Amendment to Credit Agreement among TC PipeLines, LP, the Lenders Party thereto and Bank One N.A., as agent, September 30, 2002 (Exhibit 10.2 to TC PipeLines, LP’s Form 10-Q, September 30, 2002). Third Amendment to Credit Agreement among TC PipeLines, LP, the Lenders Party thereto and Bank One N.A., as agent, March 8, 2004. (Exhibit 10.8.3 to TC PipeLines, LP’s Form 10-K, December 31, 2003. Fourth Amendment to Credit Agreement among TC PipeLines, LP, the Lenders Party thereto and Bank One NA, as agent, June 1, 2004. (Exhibit 10.1 to TC PipeLines, LP’s Form 10-Q, June 30, 2004). Revolving Credit Agreement, dated as of May 16, 2002, among Northern Border Pipeline Company, Bank One, NA, Citibank, N.A., Bank of Montreal, SunTrust Bank, Wachovia Bank, National Association, Banc One Capital Markets, Inc, and Lenders (as defined therein)(Exhibit 10.1 to Northern Border Partners, L.P.’s Form 8-K June 26, 2002). First Amendment to the Revolving Credit Agreement dated as of April 9, 2004 between Northern Border Pipeline Company, Bank One, NA and the lenders names therein. (Exhibit 10.1 to Northern Border Pipeline Company’s Form 10-Q, March 31, 2004. 2 0 0 4 A N N U A L R E P O RT 55 *10.10 *10.11 *10.12 21.1 23.1 23.2 31.1 31.2 32.1 32.2 Form of Conveyance, Contribution and Assumption Agreement among Northern Plains Natural Gas Company, Northwest Border Pipeline Company, Pan Border Gas Company, Northern Border Partners, L.P., and Northern Border Intermediate Limited Partnership. (Exhibit 10.16 to Northern Border Pipeline Company’s Form S-1). Form of Contribution, Conveyance and Assumption Agreement among TC PipeLines, L.P., and Northern Border Intermediate Limited Partnership. (Exhibit 10.2 to TC PipeLines, L.P.’s Form S-1/A, May 3, 2000). Northern Border Transition Services Agreement date November 17, 2004, by and between ONEOK, Inc. and CCE Holdings, LLC. (Exhibit 10.24 to Northern Border Partners, L.P.’s Form 10-K, December 31, 2004). Subsidiaries of the Registrant. Consent of KPMG LLP with respect to the financial statements of TC PipeLines, LP. Consent of KPMG LLP with respect to the financial statements of Northern Border Pipeline Company. Certification of President and Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. Certification of President and Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. Certification of Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. * Indicates exhibits incorporated by reference. 56 T C P I P E L I N E S , L P SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized on this 11th day of March 2005. TC PIPELINES, LP (A Delaware Limited Partnership) by its general partner, TC PipeLines GP, Inc. By: Ronald J. Turner President and Chief Executive Officer TC PipeLines GP, Inc. 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 Ronald J. Turner President and Chief Executive Officer and Director (Principal Executive Officer) March 11, 2005 Russell K. Girling Chief Financial Officer and Director (Principal Financial Officer) March 11, 2005 Amy W. Leong Controller (Principal Accounting Officer) March 11, 2005 Albrecht W. A. Bellstedt Director March 11, 2005 Kristine L. Delkus Director March 11, 2005 Walentin (Val) Mirosh Director March 11, 2005 Jack F. Jenkins-Stark Director March 11, 2005 David L. Marshall Director March 11, 2005 TC PIPELINES, LP INDEX TO FINANCIAL STATEMENTS Page No. 2 0 0 4 A N N U A L R E P O RT F-1 FINANCIAL STATEMENTS OF TC PIPELINES, LP Reports of Independent Registered Public Accounting Firm Balance Sheet – December 31, 2004 and 2003 Statement of Income – Years Ended December 31, 2004, 2003 and 2002 Statement of Comprehensive Income – Years Ended December 31, 2004, 2003 and 2002 Statement of Cash Flows – Years Ended December 31, 2004, 2003 and 2002 Statement of Changes in Partners’ Equity – Years Ended December 31, 2004, 2003 and 2002 Notes to Financial Statements FINANCIAL STATEMENTS OF NORTHERN BORDER PIPELINE COMPANY Report of Independent Registered Public Accounting Firm Balance Sheet – December 31, 2004 and 2003 Statement of Income – Years Ended December 31, 2004, 2003 and 2002 Statement of Comprehensive Income – Years Ended December 31, 2004, 2003 and 2002 Statement of Cash Flows – Years Ended December 31, 2004, 2003 and 2002 Statement of Changes in Partners’ Equity – Years Ended December 31, 2004, 2003 and 2002 Notes to Financial Statements FINANCIAL STATEMENTS SCHEDULE OF NORTHERN BORDER PIPELINE COMPANY Report of Independent Registered Public Accounting Firm on Schedule Schedule II – Valuation and Qualifying Accounts F-2 F-4 F-5 F-5 F-6 F-7 F-8 F-14 F-15 F-16 F-16 F-17 F-18 F-19 S-1 S-2 F-2 T C P I P E L I N E S , L P R E P O RT O F I N D E P E N D E N T R E G I S T E R E D P U B L I C A C C O U N T I N G F I R M To the Board of Directors of TC PipeLines GP, Inc., General Partner of TC PipeLines, LP: We have audited the accompanying balance sheets of TC PipeLines, LP (a Delaware limited partnership) as of December 31, 2004 and 2003 and the related statements of income, comprehensive income, cash flows and changes in partners’ equity for each of the years in the three-year period ended December 31, 2004. These financial statements are the responsibility of the General Partner’s management. Our responsibility is to express an opinion on these financial statements based on our audits. 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 an audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of TC PipeLines, LP as of December 31, 2004 and 2003 and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2004 in conformity with accounting principles generally accepted in the United States of America. Calgary, Canada March 3, 2005 2 0 0 4 A N N U A L R E P O RT F-3 R E P O RT O F I N D E P E N D E N T R E G I S T E R E D P U B L I C A C C O U N T I N G F I R M To the Board of Directors of TC PipeLines GP, Inc., General Partner of TC PipeLines, LP: We have audited management’s assessment, included in the accompanying Management’s Annual Report on Internal Control Over Financial Reporting appearing under Item 9A, that TC PipeLines, LP maintained effective internal control over financial reporting as of December 31, 2004, based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Management of the General Partner of TC PipeLines, LP 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 Partnership’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. An entity’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. An entity’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 entity; (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 entity are being made only in accordance with authorizations of management and directors of the entity; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the entity’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 TC PipeLines, LP maintained effective internal control over financial reporting as of December 31, 2004, is fairly stated, in all material respects, based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Also, in our opinion, TC PipeLines, LP maintained, in all material respects, effective internal control over financial reporting as of December 31, 2004, based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the balance sheets of TC Pipelines, LP as of December 31, 2004 and 2003 and the related statements of income, comprehensive income, cash flows and changes in partners’ equity for each of the years in the three-year period ended December 31, 2004 and our report dated March 3, 2005 expressed an unqualified opinion on those financial statements. Calgary, Canada March 3, 2005 F-4 F-4 T C P I P E L I N E S , L P T C P I P E L I N E S , L P B A L A N C E S H E E T December 31 (millions of dollars) Assets Current assets Cash and cash equivalents Investment in Northern Border Pipeline Investment in Tuscarora Liabilities and Partners’ Equity Current liabilities Accrued liabilities Current portion of long-term debt Long-term debt Partners’ equity Common units Subordinated units General partner Other comprehensive income The accompanying notes are an integral part of these financial statements. 2004 2003 2.5 290.1 39.5 332.1 0.7 6.5 7.2 30.0 287.4 – 6.3 1.2 294.9 332.1 7.5 240.7 39.9 288.1 0.6 5.5 6.1 – 260.4 13.9 6.1 1.6 282.0 288.1 S TAT E M E N T O F I N C O M E Year ended December 31 (millions of dollars except per unit amounts) Equity income from Investment in Northern Border Pipeline Equity income from Investment in Tuscarora General and administrative expenses Financial charges Net income Net income per unit Units outstanding (millions) The accompanying notes are an integral part of these financial statements. 2 0 0 4 A N N U A L R E P O RT F-5 F-5 2004 2003 2002 50.0 7.5 (1.9) (0.5) 55.1 2.99 17.5 $ 44.5 5.3 (1.7) (0.1) 48.0 2.63 17.5 $ 42.8 4.7 (1.5) (0.5) 45.5 2.50 17.5 $ S TAT E M E N T O F C O M P R E H E N S I V E I N C O M E Year ended December 31 (millions of dollars) Net income Other comprehensive income Change associated with current period hedging transactions Total Comprehensive Income The accompanying notes are an integral part of these financial statements. 2004 2003 2002 55.1 (0.4) 54.7 48.0 (0.5) 47.5 45.5 (0.9) 44.6 F-6 F-6 T C P I P E L I N E S , L P T C P I P E L I N E S , L P S TAT E M E N T O F C A S H F L O W S Year ended December 31 (millions of dollars) Cash Generated From Operations Net income Add/(deduct): Distributions received in excess of equity income Increase in accrued liabilities Other Investing Activities Return of capital from Northern Border Pipeline Return of capital from Tuscarora Investment in Northern Border Pipeline Investment in Tuscarora Financing Activities Distributions paid Long-term debt issued Long-term debt repaid Other Increase/(decrease) in cash Cash, beginning of year Cash, end of year The accompanying notes are an integral part of these financial statements. 2004 2003 2002 55.1 – 0.1 – 55.2 11.7 0.4 (61.5) – (49.4) (41.8) 37.0 (6.0) – (10.8) (5.0) 7.5 2.5 48.0 1.6 – – 49.6 1.0 – – (4.1) (3.1) (39.4) – (6.0) – (45.4) 1.1 6.4 7.5 45.5 6.3 0.1 0.2 52.1 – – – (7.4) (7.4) (37.4) – (10.0) (0.1) (47.5) (2.8) 9.2 6.4 2 0 0 4 A N N U A L R E P O RT F-7 F-7 S TAT E M E N T O F C H A N G E S I N PA RT N E R S ’ E Q U I T Y Common Units Subordinated Units General Comprehensive Partner Income Partners’ Equity (millions of units) (millions of dollars) (millions of units) (millions of dollars) (millions of dollars) (millions of dollars) (millions of units) (millions of dollars) Accumulated Other 14.7 – – 0.9 – 15.6 – – 0.9 – 16.5 – – 1.0 – 17.5 219.0 37.5 (30.7) 13.1 – 238.9 42.1 (34.1) 13.5 – 260.4 51.0 (37.8) 13.8 – 287.4 2.8 – – (0.9) – 1.9 – – (0.9) – 1.0 – – (1.0) – – 39.2 6.2 (5.3) (13.1) – 27.0 3.9 (3.5) (13.5) – 13.9 1.4 (1.5) (13.8) – – 5.5 1.8 (1.4) – – 5.9 2.0 (1.8) – – 6.1 2.7 (2.5) – – 6.3 3.0 – – – (0.9) 2.1 – – – (0.5) 1.6 – – – (0.4) 1.2 17.5 – – – – 17.5 – – – – 17.5 – – – – 17.5 266.7 45.5 (37.4) – (0.9) 273.9 48.0 (39.4) – (0.5) 282.0 55.1 (41.8) – (0.4) 294.9 Partners’ equity at December 31, 2001 Net income Distributions paid Subordinated unit conversion Other comprehensive income Partners’ equity at December 31, 2002 Net income Distributions paid Subordinated unit conversion Other comprehensive income Partners’ equity at December 31, 2003 Net income Distributions paid Subordinated unit conversion Other comprehensive income Partners’ equity at December 31, 2004 The accompanying notes are an integral part of these financial statements. F-8 F-8 T C P I P E L I N E S , L P T C P I P E L I N E S , L P N O T E S T O F I N A N C I A L S TAT E M E N T S NOTE 1 ORGANIZATION TC PipeLines, LP, and its subsidiary limited partnerships, TC PipeLines Intermediate Limited Partnership and TC Tuscarora Intermediate Limited Partnership, all Delaware limited partnerships, are collectively referred to herein as TC PipeLines or the Partnership. TC PipeLines was formed by TransCanada PipeLines Limited, a subsidiary of TransCanada Corporation (collectively referred to herein as TransCanada), to acquire, own and participate in the management of United States-based pipeline assets. TC PipeLines, through TC PipeLines Intermediate Limited Partnership, owns a 30% general partner interest in Northern Border Pipeline Company (Northern Border Pipeline), a Texas general partnership. Northern Border Pipeline owns a 1,249-mile United States interstate pipeline system that transports natural gas from the Montana-Saskatchewan border to markets in the midwestern United States. TC PipeLines also, through TC Tuscarora Intermediate Limited Partnership, owns a 49% general partner interest in Tuscarora Gas Transmission Company (Tuscarora), a Nevada general partnership. Tuscarora owns a 240-mile United States interstate pipeline system that transports natural gas from Oregon, where it interconnects with facilities of Gas Transmission Northwest Corporation (GTN), a wholly-owned subsidiary of TransCanada, to northern Nevada. TC PipeLines is managed by its general partner, TC PipeLines GP, Inc. (general partner), an indirect wholly-owned subsidiary of TransCanada. The general partner provides certain administrative services for the Partnership and is reimbursed for its costs and expenses. In addition to its aggregate 2% general partner interest in TC PipeLines, LP and its subsidiary limited partnership on a combined basis, the general partner owns 2,809,306 common units, representing an effective 15.7% limited partner interest in the Partnership at December 31, 2004. TransCanada indirectly holds 2,800,000 common units representing an effective 15.7% limited partner interest in the Partnership at December 31, 2004 NOTE 2 SIGNIFICANT ACCOUNTING POLICIES (a) Basis of Presentation The accompanying financial statements and related notes present the financial position of the Partnership as of December 31, 2004 and 2003 and the results of its operations, cash flows and changes in partners’ equity for the years ended December 31, 2004, 2003 and 2002. The Partnership uses the equity method of accounting for its investments in Northern Border Pipeline and Tuscarora, over which it is able to exercise significant influence. Other comprehensive income recorded by TC PipeLines arises through its equity investments in Northern Border Pipeline and Tuscarora and relates to cash flow hedges transacted by Northern Border Pipeline and Tuscarora. Amounts are stated in United States dollars. (b) Use of Estimates The preparation of financial statements in conformity with generally accepted accounting principles in the United States of America (GAAP) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities as at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Although management believes these estimates are reasonable, actual results could differ from these estimates. 2 0 0 4 A N N U A L R E P O RT F-9 F-9 (c) Cash and Cash Equivalents Cash equivalents consist of highly liquid investments with original maturities of three months or less. The carrying amount of cash and cash equivalents approximates fair value because of the short maturity of these investments. (d) Partners’ Equity Costs incurred in connection with the issuance of units are deducted from the proceeds received. Costs incurred to convert subordinated units to common units were deducted from partners’ equity. (e) Income Taxes As a partnership, TC PipeLines LP is not subject to Federal or state income tax. The tax effect of the partnership’s activities accrues to its partners. NOTE 3 INVESTMENT IN NORTHERN BORDER PIPELINE The Partnership owns a 30% general partner interest in Northern Border Pipeline. The remaining 70% partnership interest in Northern Border Pipeline is held by Northern Border Partners, L.P. (Northern Border Partners), a publicly traded limited partnership. The Northern Border Pipeline system is operated by Northern Plains Natural Gas Company, a wholly-owned subsidiary of ONEOK, Inc. (ONEOK). Northern Border Pipeline is regulated by the Federal Energy Regulatory Commission (FERC). TC PipeLines Intermediate Limited Partnership, as one of the general partners, may be exposed to the commitments and contingencies of Northern Border Pipeline. TC PipeLines, LP holds a 98.9899% limited partnership interest in TC PipeLines Intermediate Limited Partnership. See Note 7. Commitments and Contingencies to the Northern Border Pipeline’s Financial Statements included elsewhere in this report. TC PipeLines’ equity income amounted to $50.0 million, $44.5 million and $42.8 million for the years ended December 31, 2004, 2003 and 2002, respectively, representing 30% of the net income of Northern Border Pipeline for the same periods. Undistributed earnings of Northern Border Pipeline amounted to nil, nil and $1.3 million for the years ended December 31, 2004, 2003 and 2002, respectively. The following sets out summarized financial information for Northern Border Pipeline as at December 31, 2004 and 2003 and for the years ended December 31, 2004, 2003 and 2002. Northern Border Pipeline Balance Sheet December 31 (millions of dollars) Assets Cash and cash equivalents Other current assets Plant, property and equipment, net Other assets Liabilities and Partners’ Equity Current liabilities Reserves and deferred credits Long-term debt Partners’ equity Partners’ capital Accumulated other comprehensive income 2004 2003 20.3 20.2 1,543.8 39.0 1,623.3 47.8 4.5 603.9 963.3 3.8 28.7 40.8 1,591.8 30.0 1,691.3 62.3 5.1 821.5 797.2 5.2 1,623.3 1,691.3 F-10 F-10 T C P I P E L I N E S , L P T C P I P E L I N E S , L P Northern Border Pipeline Income Statement Year ended December 31 (millions of dollars) Revenues Costs and expenses Depreciation Financial charges Other income Net income 2004 2003 2002 329.1 (63.2) (58.3) (41.3) 0.5 166.8 324.2 (73.4) (57.8) (44.9) 0.1 148.2 321.0 (69.9) (58.7) (51.5) 1.8 142.7 NOTE 4 INVESTMENT IN TUSCARORA The Partnership owns a 49% general partner interest in Tuscarora. The remaining general partner interests in Tuscarora are held 50% by Sierra Pacific Resources and 1% by TransCanada. Tuscarora is regulated by the FERC. On September 1, 2000, the Partnership acquired its interest in Tuscarora from a subsidiary of TransCanada. As a result of the acquisition allocation, an annual amortization of $0.4 million has been included in the Partnership’s equity income from Tuscarora. The amortization period ends in 2025. Sierra Pacific Power, a wholly-owned subsidiary of Sierra Pacific Resources, is Tuscarora’s largest shipper with approximately 69% of the total available capacity through 2017. In August 2003, the bankruptcy court granted Enron Power Marketing Inc.’s motion for a summary judgment with respect to claims against Nevada Power Company and Sierra Pacific Power (together, the Utilities) of approximately $235 million and $102 million, respectively, of liquidated damages, for power supply contracts terminated by Enron Power Marketing in May 2002. A trial date has been set for April 18, 2005 in the Bankruptcy Court to review the issues with respect to Enron’s claims against the Utilities. Sierra Pacific Power to date remains current on its shipping contracts with Tuscarora. TC PipeLines’ equity income from Tuscarora amounted to $7.5 million, $5.3 million and $4.7 million for the years ended December 31, 2004, 2003 and 2002, respectively, representing 49% of the net income of Tuscarora for the same periods. Undistributed earnings of Tuscarora amounted to nil, nil and $0.8 million for the years ended December 31, 2004, 2003 and 2002, respectively. The following sets out summarized financial information for Tuscarora as at December 31, 2004 and 2003 and for the years ended December 31, 2004, 2003 and 2002. TC PipeLines has held its general partner interest since September 1, 2000. Tuscarora Balance Sheet December 31 (millions of dollars) Assets Cash and cash equivalents Other current assets Plant, property and equipment, net Other assets Liabilities and Partners’ Equity Current liabilities Long-term debt Partners’ equity Partners’ capital Accumulated other comprehensive income 2004 2003 3.6 3.0 136.9 1.4 144.9 6.9 75.9 62.0 0.1 1.8 4.3 141.9 1.6 149.6 6.7 80.8 62.0 0.1 144.9 149.6 Tuscarora Income Statement Year ended December 31 (millions of dollars) Revenues Costs and expenses Depreciation Financial charges Other income Net income 2 0 0 4 A N N U A L R E P O RT F-11 F-11 2004 2003 2002 32.6 (4.9) (6.1) (6.1) 0.8 16.3 29.7 (5.0) (6.4) (6.5) – 11.8 23.1 (2.8) (4.9) (5.7) 0.7 10.4 NOTE 5 CREDIT FACILITIES AND LONG-TERM DEBT On May 28, 2003, the Partnership renewed its $40.0 million unsecured two-year revolving credit facility (TransCanada Credit Facility) with TransCanada PipeLine USA Ltd., an affiliate of the general partner. The TransCanada Credit Facility bears interest at the London Interbank Offered Rate (LIBOR) plus 1.25%. The purpose of the TransCanada Credit Facility is to provide borrowings to fund capital expenditures, to fund capital contributions to Northern Border Pipeline, Tuscarora and any other entity in which the Partnership directly or indirectly acquires an interest, to fund working capital and for other general business purposes, including temporary funding of cash distributions to unitholders and the general partner, if necessary. At December 31, 2004 and December 31, 2003, the Partnership had $6.5 million and nil borrowings outstanding, respectively, under the TransCanada Credit Facility. The current borrowings mature on May 28, 2005. The interest rate on the TransCanada Credit Facility at December 31, 2004 was 3.75%. On February 22, 2005, the Partnership repaid in full the $6.5 million outstanding balance on the TransCanada Credit Facility. On March 8, 2004 the Partnership renewed its unsecured credit facility (Revolving Credit Facility) with Bank One, NA, as administrative agent. Under the Revolving Credit Facility, the Partnership may borrow up to an aggregate principal amount of $30.0 million. Loans under the Revolving Credit Facility may bear interest, at the option of the Partnership, at a one-, two-, three-, or six-month LIBOR plus 1.25% or at a floating rate based on the higher of the federal funds effective rate plus 0.5% and the prime rate. The Revolving Credit Facility matures on February 28, 2006. Amounts borrowed may be repaid in part or in full prior to that time without penalty. The Revolving Credit Facility may be used to fund capital expenditures, to fund capital contributions to Northern Border Pipeline, Tuscarora and any other entity in which the Partnership directly or indirectly acquires an interest, to fund working capital and for other general business purposes, including temporary funding of cash distributions to unitholders and the general partner, if necessary. The Revolving Credit Facility requires that the Partnership’s total debt, as of the last day of any fiscal quarter, to be no more than the lesser of (i) 35% of capitalization as at the last day of such fiscal quarter, or (ii) 2.5 times the consolidated adjusted EBITDA (net income plus interest expense, income taxes and depreciation and amortization) for the period consisting of such fiscal quarter and the three preceding fiscal quarters. At December 31, 2004, the Partnership was in compliance with its financial covenant. In 2004, the Partnership borrowed an aggregate of $30.5 million and repaid $6.0 million on the Revolving Credit Facility. The Partnership had $30.0 million and $5.5 million outstanding under the Revolving Credit Facility at December 31, 2004 and 2003, respectively. The interest rate on the Revolving Credit Facility averaged 2.76% and 2.58% for December 31, 2004 and 2003, respectively and at December 31, 2004 and 2003, the interest rate was 3.72% and 2.42%, respectively. NOTE 6 PARTNERS’ CAPITAL AND CASH DISTRIBUTIONS Partners’ capital consists of 17,500,000 common units representing an aggregate 98% limited partner interest in the Partnership (which number includes 2,809,306 common units held by the general partner and 2,800,000 common units owned by an affiliate of the general partner) and an aggregate 2% general partner interest. In aggregate the general partner’s and its affiliate’s interests represent an effective 33.4% ownership in the Partnership. F-12 F-12 T C P I P E L I N E S , L P T C P I P E L I N E S , L P The Partnership makes cash distributions to its partners with respect to each calendar quarter within 45 days after the end of each quarter. Distributions are based on available cash, which includes all cash and cash equivalents of the Partnership and working capital borrowings less reserves established by the general partner. The Unitholders currently receive a quarterly distribution of $0.575 per unit if and to the extent there is sufficient available cash. Common units will not accrue arrearages with respect to distributions for any quarter after the subordination period. The subordination period ended July 30, 2004. All subordinated units were converted on a one-for-one basis into common units and will participate pro rata with all other common units in distributions after July 30, 2004. On August 1, 2002, 936,435 subordinated units, representing one-third of the outstanding subordinated units held by the general partner, converted into an equal number of common units as a result of satisfying the tests set forth in the Amended and Restated Agreement of Limited Partnership of TC PipeLines, LP (Partnership Agreement). On August 1, 2003, 936,435 subordinated units, representing an additional one third of the outstanding subordinated units held by the general partner, converted into an equal number of common units as a result of satisfying the test set forth in the Partnership Agreement. On July 30, 2004, 936,436 subordinated units, representing the remaining one-third of the originally issued 2,809,306 subordinated units issued by the general partner, converted into an equal number of common units as a result of satisfying the test set forth in the Partnership Agreement. As an incentive, the general partner’s percentage interest in quarterly distributions is increased after certain specified target levels are met. The incremental incentive distributions payable to the General Partner are 15%, 25%, and 50% of all quarterly distributions of Available Cash that exceed target levels of $0.45, $0.5275 and $0.69, respectively, per unit. For the years ended December 31, 2004, 2003 and 2002, the Partnership distributed $2.275, $2.175 and $2.075, respectively, per unit. The distributions for the year ended December 31, 2004, 2003 and 2002 included incentive distributions to the general partner in the amount of $1.7 million, $1.0 million and $0.8 million, respectively. Partnership income is allocated to the general partner and the limited partners in accordance with their respective partnership percentages, after giving effect to any priority income allocations for incentive distributions that are allocated 100% to the general partner. NOTE 7 NET INCOME PER UNIT Net income per unit is computed by dividing net income, after deduction of the general partner’s allocation, by the weighted average number of common and subordinated units outstanding. The general partner’s allocation is equal to an amount based upon the general partner’s 2% interest, adjusted to reflect an amount equal to incentive distributions. Net income per unit was determined as follows: Year ended December 31 (millions of dollars except per unit amounts) Net income Net income allocated to general partner General partner interest Incentive distribution income allocation Net income allocable to units Weighted average units outstanding (millions) Net income per unit 2004 2003 2002 55.1 48.0 45.5 (1.0) (1.7) (2.7) 52.4 17.5 (1.0) (1.0) (2.0) 46.0 17.5 $ 2.99 $ 2.63 $ (1.0) (0.8) (1.8) 43.7 17.5 2.50 2 0 0 4 A N N U A L R E P O RT F-13 F-13 NOTE 8 RELATED PARTY TRANSACTIONS The Partnership does not have any employees. The management and operating functions are provided by the general partner. The general partner does not receive a management fee or other compensation in connection with its management of the Partnership. The Partnership reimburses the general partner for all costs of services provided, including the costs of employee, officer and director compensation and benefits, and all other expenses necessary or appropriate to the conduct of the business of, and allocable to the Partnership. The Partnership Agreement provides that the general partner will determine the expenses that are allocable to the Partnership in any reasonable manner determined by the general partner in its sole discretion. Total costs reimbursed to the general partner by the Partnership were approximately $0.9 million, $0.7 million and $0.5 million for the years ended December 31, 2004, 2003 and 2002, respectively. Such costs include (i) personnel costs (such as salaries and employee benefits), (ii) overhead costs (such as office space and equipment) and (iii) out-of-pocket expenses related to the provision of such services. NOTE 9 QUARTERLY FINANCIAL DATA (unaudited) The following sets forth selected financial data for the four quarters of each of 2004 and 2003. Certain comparative figures have been redefined to conform to the 2004 presentation. Quarter ended (millions of dollars, except per unit amounts) 2004 Equity income Net income Net income per unit Cash distributions paid 2003 Equity income Net income Net income per unit Cash distributions paid NOTE 10 SUBSEQUENT EVENTS Mar 31 Jun 30 Sep 30 Dec 31 14.3 13.7 0.75 10.1 12.3 11.9 0.66 9.6 $ $ 14.2 13.6 0.74 10.2 12.5 12.0 0.66 9.6 $ $ 13.1 12.6 0.68 10.7 12.5 12.0 0.65 10.1 $ $ 15.9 15.2 0.82 10.8 12.5 12.1 0.66 10.1 $ $ On January 20, 2005, the Board of Directors of the general partner declared the Partnership’s 2004 fourth quarter cash distribution. The fourth quarter cash distribution which was paid on February 14, 2005 to unitholders of record as of January 31, 2005, totaled $10.7 million and was paid in the following manner: $10.0 million to common unitholders (including $1.6 million to an affiliate of the general partners as holder of 2,800,000 common units and $1.6 million to the general partner as holder of 2,809,306 common units), $0.5 million to the general partner as holder of the incentive distribution rights, and $0.2 million to the general partner in respect of its 2% general partner interest. On February 22, 2005, the Partnership repaid $6.5 million on its TransCanada Credit Facility. F-14 F-14 T C P I P E L I N E S , L P T C P I P E L I N E S , L P REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM Northern Border Pipeline Company We have audited the accompanying balance sheets of Northern Border Pipeline Company as of December 31, 2004 and 2003, and the related statements of income, comprehensive income, cash flows, and changes in partners’ equity for each of the years in the three-year period ended December 31, 2004. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Northern Border Pipeline Company as of December 31, 2004 and 2003, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2004, in conformity with accounting principles generally accepted in the United States of America. KPMG LLP Omaha, Nebraska March 2, 2005 2 0 0 4 A N N U A L R E P O RT F-15 F-15 NORTHERN BORDER PIPELINE COMPANY BALANCE SHEET (In Thousands) ASSETS CURRENT ASSETS Cash and cash equivalents Accounts receivables (net of allowance for doubtful accounts of $4,208 in 2004) Related party receivables (net of allowance for doubtful accounts of $4,815 in 2003) Materials and supplies, at cost Prepaid expenses and other Total current assets NATURAL GAS TRANSMISSION PLANT In service Construction work in progress Total property, plant and equipment Less: Accumulated provision for depreciation and amortization Property, plant and equipment, net OTHER ASSETS Derivative financial instruments Unamortized debt expense Regulatory asset Other Total other assets Total assets LIABILITIES AND PARTNERS’ EQUITY CURRENT LIABILITIES Accounts payable Related party payables Accrued taxes other than income Accrued interest Total current liabilities LONG-TERM DEBT RESERVES AND DEFERRED CREDITS COMMITMENTS AND CONTINGENCIES (Note 7) PARTNERS’ EQUITY Partners’ capital Accumulated other comprehensive income Total partners’ equity Total liabilities and partners’ equity The accompanying notes are an integral part of these financial statements. December 31 2004 2003 $ 20,355 $ 28,732 32,559 1,311 3,409 1,688 59,322 2,444,729 2,768 2,447,497 903,664 1,543,833 – 3,837 11,807 4,549 20,193 $ 1,623,348 4,058 5,286 27,113 11,365 47,822 603,860 4,526 33,292 395 4,818 2,267 69,504 2,434,369 4,447 2,438,816 847,061 1,591,755 16,648 5,206 8,196 – 30,050 $ 1,691,309 7,055 15,582 28,947 10,717 62,301 821,498 5,072 963,378 3,762 967,140 $ 1,623,348 797,236 5,202 802,438 $ 1,691,309 F-16 F-16 T C P I P E L I N E S , L P T C P I P E L I N E S , L P NORTHERN BORDER PIPELINE COMPANY STATEMENT OF INCOME (In Thousands) OPERATING REVENUES OPERATING EXPENSES Operations and maintenance Depreciation and amortization Taxes other than income Operating expenses OPERATING INCOME INTEREST EXPENSE Interest expense Interest expense capitalized Interest expense, net OTHER INCOME (EXPENSE) Allowance for equity funds used during construction Other income Other expense Other income (expense), net Year Ended December 31 2004 2003 2002 $ 329,115 $ 324,185 $ 321,050 33,763 58,375 29,368 121,506 43,791 57,779 29,634 131,204 207,609 192,981 41,374 (18) 41,356 31 2,552 (2,059) 524 44,903 (46) 44,857 53 1,373 (1,350) 76 41,442 58,714 28,436 128,592 192,458 51,550 (25) 51,525 26 2,476 (716) 1,786 NET INCOME TO PARTNERS $ 166,777 $ 148,200 $ 142,719 STATEMENT OF COMPREHENSIVE INCOME (In Thousands) NET INCOME TO PARTNERS OTHER COMPREHENSIVE INCOME: Change associated with current period hedging transactions Year Ended December 31 2004 2003 2002 $ 166,777 $ 148,200 $ 142,719 (1,440) (1,556) (2,415) Total comprehensive income $ 165,337 $ 146,644 $ 140,304 The accompanying notes are an integral part of these financial statements. 2 0 0 4 A N N U A L R E P O RT F-17 F-17 NORTHERN BORDER PIPELINE COMPANY STATEMENT OF CASH FLOWS (In Thousands) CASH FLOWS FROM OPERATING ACTIVITIES: Net income to partners Adjustments to reconcile net income to partners to net cash provided by operating activities: Depreciation and amortization Provision for regulatory refunds Regulatory refunds paid Allowance for equity funds used during construction Reserves and deferred credits Changes in components of working capital Other Total adjustments Net cash provided by operating activities CASH FLOWS FROM INVESTING ACTIVITIES: Capital expenditures for property, plant and equipment, net CASH FLOWS FROM FINANCING ACTIVITIES: Equity contributions from partners Distributions to partners Issuance of long-term debt Retirement of long-term debt Proceeds upon termination of derivatives Debt reacquisition costs Long-term debt financing costs Net cash used in financing activities NET CHANGE IN CASH AND CASH EQUIVALENTS Cash and cash equivalents – beginning of year Cash and cash equivalents – end of year Changes in components of working capital: Accounts receivable Materials and supplies Prepaid expenses and other Accounts payable Accrued taxes other than income Accrued interest Year Ended December 31 2004 2003 2002 $ 166,777 $ 148,200 $ 142,719 58,740 – – (31) (546) (12,611) (6,180) 39,372 206,149 58,144 261 (10,261) (53) 1,001 (3,551) (471) 45,070 193,270 59,079 10,000 – (26) (237) 13,268 (447) 81,637 224,356 (10,569) (12,918) (9,243) 205,000 (205,635) 107,000 (313,000) 7,575 (4,897) – (203,957) (8,377) 28,732 20,355 (2,969) 697 578 (9,731) (1,834) 648 $ $ – (153,978) 142,000 (165,000) – – – (176,978) 3,374 25,358 28,732 (4,908) (97) (422) 3,758 573 (2,455) $ $ – (164,126) 431,894 (468,000) 2,351 – (2,877) (200,758) 14,355 11,003 25,358 5,369 152 (113) 10,006 1,207 (3,353) $ $ Total $ (12,611) $ (3,551) $ 13,268 The accompanying notes are an integral part of these financial statements. F-18 F-18 T C P I P E L I N E S , L P T C P I P E L I N E S , L P NORTHERN BORDER PIPELINE COMPANY STATEMENT OF CHANGES IN PARTNERS’ EQUITY (In Thousands) TC PipeLines Northern Border Intermediate Intermediate Limited Limited Partnership Partnership Accumulated Other Comprehensive Income Partners’ Equity at December 31, 2001 Net income to partners Change associated with current period hedging transactions Distributions paid Partners’ Equity at December 31, 2002 Net income to partners Change associated with current period hedging transactions Distributions paid Partners’ Equity at December 31, 2003 Net income to partners Change associated with current period hedging transactions Equity contributions received Distributions paid $ 247,326 42,816 $ 577,095 99,903 $ – (49,238) 240,904 44,460 – (46,193) 239,171 50,033 – 61,500 (61,690) – (114,888) 562,110 103,740 – (107,785) 558,065 116,744 – 143,500 (143,945) 9,173 – (2,415) – 6,758 – (1,556) – 5,202 – (1,440) – – Total Partners’ Equity $ 833,594 142,719 (2,415) (164,126) 809,772 148,200 (1,556) (153,978) 802,438 166,777 (1,440) 205,000 (205,635) Partners’ Equity at December 31, 2004 $ 289,014 $ 674,364 $ 3,762 $ 967,140 The accompanying notes are an integral part of these financial statements. 2 0 0 4 A N N U A L R E P O RT F-19 F-19 NORTHERN BORDER PIPELINE COMPANY NOTES TO FINANCIAL STATEMENTS 1. ORGANIZATION AND MANAGEMENT Northern Border Pipeline Company (Northern Border Pipeline) is a Texas general partnership formed in 1978. The ownership percentages of the partners in Northern Border Pipeline (Partners) at December 31, 2004 and 2003 are as follows: Partner Northern Border Intermediate Limited Partnership TC PipeLines Intermediate Limited Partnership Ownership Percentage 70 30 Northern Border Pipeline owns a 1,249-mile natural gas transmission pipeline system extending from the United States- Canadian border near Port of Morgan, Montana, to a terminus near North Hayden, Indiana. Northern Border Pipeline is managed by a Management Committee that includes three representatives from Northern Border Intermediate Limited Partnership (Partnership) and one representative from TC PipeLines Intermediate Limited Partnership (TC PipeLines). The Partnership’s representatives are selected by its general partners, Northern Plains Natural Gas Company, LLC (Northern Plains), a wholly-owned subsidiary of ONEOK, Inc. (ONEOK), Pan Border Gas Company, LLC (Pan Border), a wholly-owned subsidiary of Northern Plains, and Northwest Border Pipeline Company, a wholly- owned subsidiary of TransCanada PipeLines Limited, which is a subsidiary of TransCanada Corporation, and affiliate of TC PipeLines, have 35%, 22.75% and 12.25%, respectively, of the voting interest on the Management Committee. The representative designated by TC PipeLines votes the remaining 30% interest. In November 2004, ONEOK purchased Northern Plains and Pan Border from CCE Holdings, LLC (CCE Holdings). CCE Holdings, a joint venture between Southern Union Company and GE Commercial Finance Energy Financial purchased Northern Plains and Pan Border as part of its acquisition of CrossCountry Energy LLC (CrossCountry). On March 31, 2004, Enron Corp. (Enron) transferred its ownership interest in Northern Plains and Pan Border to CrossCountry. In addition, CrossCountry and Enron entered into a transition services agreement pursuant to which Enron would provide to CrossCountry, on an interim, transitional basis, various services, including but not limited to (i) information technology services, (ii) accounting system usage rights and administrative support and (iii) payroll, employee benefits and administrative services. In turn, these services are provided to Northern Border Pipeline through Northern Plains. The day-to-day management of Northern Border Pipeline’s affairs is the responsibility of Northern Plains, as defined by an operating agreement between Northern Border Pipeline and Northern Plains. Northern Border Pipeline is charged for the salaries, benefits and expenses of Northern Plains. As part of the closing, ONEOK and CCE Holdings entered into a transition services agreement referred to as the “Northern Border Transition Services Agreement” covering certain transition services by and among ONEOK, CCE Holdings and Enron for a period of six months. Certain of the services previously provided by Enron are now being provided by ONEOK. For the years ended December 31, 2004, 2003, and 2002, Northern Border Pipeline’s charges from Northern Plains and its current and former affiliates totaled approximately $18.3 million, $25.6 million and $22.8 million, respectively. See Note 11 for a discussion of Northern Border Pipeline’s previous relationships with Enron and developments involving Enron. F-20 F-20 T C P I P E L I N E S , L P T C P I P E L I N E S , L P 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (A) Use of Estimates The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. (B) Government Regulation Northern Border Pipeline is subject to regulation by the Federal Energy Regulatory Commission (FERC). Northern Border Pipeline’s accounting policies conform to Statement of Financial Accounting Standards (SFAS) No. 71, “Accounting for the Effects of Certain Types of Regulation.” Accordingly, certain assets that result from the regulated ratemaking process are recorded that would not be recorded under accounting principles generally accepted in the United States of America for nonregulated entities. At December 31, 2004 and 2003, Northern Border Pipeline has reflected regulatory assets, which are currently being recovered or are expected to be recovered from its shippers, of approximately $11.8 million and $8.2 million respectively, on the balance sheet. Northern Border Pipeline is recovering these regulatory assets form its shippers over varying time periods, which range from 5 to 44 years. Northern Border Pipeline continually assesses whether the recovery of the regulatory assets is probable by considering such factors as regulatory changes and the impact of competition. Northern Border Pipeline believes the recovery of the existing regulatory assets is probable. If future recovery ceases to be probable, Northern Border Pipeline would be required to write off the regulatory assets at that time. (C) Revenue Recognition Northern Border Pipeline transports gas for shippers under a tariff regulated by the FERC. The tariff specifies the calculation of amounts to be paid by shippers and the general terms and conditions of transportation service on the pipeline system. Northern Border Pipeline’s revenues are derived from agreements for the receipt and delivery of gas at points along the pipeline system as specified in each shipper’s individual transportation contract. Revenues for Northern Border Pipeline are recognized based upon contracted capacity and actual volumes transported under transportation service agreements. An allowance for doubtful accounts is recorded in situations where collectibility is not reasonably assured. Northern Border Pipeline does not own the gas that it transports, and therefore it does not assume the related natural gas commodity risk. (D) Income Taxes Income taxes are the responsibility of the Partners and are not reflected in these financial statements. However, the Northern Border Pipeline FERC tariff establishes the method of accounting for and calculating income taxes and requires Northern Border Pipeline to reflect in its rates the income taxes, which would have been paid or accrued if Northern Border Pipeline were organized during the period as a corporation. As a result, for purposes of determining transportation rates in calculating the return allowed by the FERC, Partners’ capital and rate base are reduced by the amount equivalent to the net accumulated deferred income taxes. Such amounts were approximately $355.0 million and $350.0 million at December 31, 2004 and 2003, respectively, and are primarily related to accelerated depreciation and other plant-related differences. (E) Cash and Cash Equivalents Cash equivalents consist of highly liquid investments with original maturities of three months or less. The carrying amount of cash and cash equivalents approximates fair value because of the short maturity of these investments. 2 0 0 4 A N N U A L R E P O RT F-21 F-21 (F) Property, Plant and Equipment and Related Depreciation and Amortization Property, plant and equipment is stated at original cost. During periods of construction, Northern Border Pipeline is permitted to capitalize an allowance for funds used during construction, which represents the estimated costs of funds used for construction purposes. The original cost of property retired is charged to accumulated depreciation and amortization, net of salvage and cost of removal. No retirement gain or loss is included in income except in the case of retirements or sales of entire regulated operating units. Maintenance and repairs are charged to operations in the period incurred. The provision for depreciation and amortization of the transmission line is an integral part of Northern Border Pipeline’s FERC tariff. The effective depreciation rate applied to Northern Border Pipeline’s transmission plant is 2.25%. Composite rates are applied to all other functional groups of property having similar economic characteristics. (G) Risk Management Financial instruments are used by Northern Border Pipeline in the management of its interest rate exposure. A control environment has been established which includes policies and procedures for risk assessment and the approval, reporting and monitoring of financial instrument activities. Northern Border Pipeline does not use these instruments for trading purposes. SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended by SFAS No. 137 and SFAS No. 138, requires that every derivative instrument (including certain derivative instruments embedded in other contracts) be recorded on the balance sheet as either an asset or liability measured at its fair value. The statement requires that changes in the derivative’s fair value be recognized currently in earnings unless specific hedge accounting criteria are met. Special accounting for qualifying hedges allows a derivative’s gains and losses to offset related results on the hedged item in the income statement, and requires that a company formally document, designate and assess the effectiveness of transactions that receive hedge accounting. See Note 6 for a discussion of Northern Border Pipeline’s derivative instruments and hedging activities. (H) Reclassifications Certain reclassifications have been made to the financial statements for prior years to conform with the current year presentation. 3. RATES AND REGULATORY ISSUES The FERC regulates the rates and charges for transportation in interstate commerce. Natural gas companies may not charge rates that have been determined not to be just and reasonable by the FERC. Generally, rates for interstate pipelines are based on the cost of service including recovery of and a return on the pipeline’s actual prudent historical cost investment. The rates and terms and conditions for service are found in each pipeline’s FERC approved tariff. Under its tariff, an interstate pipeline is allowed to charge for its services on the basis of stated transportation rates. Transportation rates are established periodically in FERC proceedings known as rate cases. The tariff also allows the interstate pipeline to provide services under negotiated and discounted rates. Under the terms of settlement in Northern Border Pipeline’s 1999 rate case, neither Northern Border Pipeline nor its existing shippers can seek rate changes to the settlement base rates until November 1, 2005, at which time Northern Border Pipeline must file a new rate case. In February 2003, Northern Border Pipeline filed to amend its FERC tariff to clarify the definition of company use gas, which is gas supplied by its shippers for its operations. Northern Border Pipeline had included in its retention of company use gas, quantities that were equivalent to the cost of electric power at its electric-driven compressor stations during the period of June 2001 through January 2003. On March 27, 2003, the FERC issued an order rejecting Northern Border Pipeline’s proposed tariff sheet revision and requiring refunds with interest within 90 days of the order. Northern Border Pipeline made refunds to its shippers of $10.3 million in May 2003. F-22 F-22 T C P I P E L I N E S , L P T C P I P E L I N E S , L P 4. TRANSPORTATION SERVICE AGREEMENTS Operating revenues are collected pursuant to the FERC tariff through firm transportation service agreements. The firm service agreements extend for various terms with termination dates that range from December 2004 to December 2013. Northern Border Pipeline also has interruptible transportation service agreements and other transportation service agreements with numerous shippers. Under the capacity release provisions of Northern Border Pipeline’s FERC tariff, shippers are allowed to release all or part of their capacity either permanently for the full term of the contract or temporarily. A temporary capacity release does not relieve the original contract shipper from its payment obligations if the replacement shipper fails to pay for the capacity temporarily released to it. At December 31, 2004, Northern Border Pipeline’s largest shippers, Nexen Marketing, U.S.A. Inc (Nexen), BP Canada Energy Marketing Corp. (BP Canada), EnCana Marketing U.S.A. Inc. (EnCana) and Cargill Incorporated (Cargill), were obligated for approximately 18%, 14%, 13% and 12% of the summer design capacity, respectively. The Nexen, BP Canada, EnCana and Cargill firm service agreements extend for various terms with termination dates from March 2005 to December 2013, December 2004 to February 2012, October 2005 to June 2009 and March 2005 to December 2008, respectively. For the year ending December 31, 2004, shippers providing significant operating revenues were BP Canada and EnCana with revenues of $65.6 million and $56.3 million, respectively. For the year ended December 31, 2003, Northern Border Pipeline’s significant shippers were BP Canada, EnCana, and Pan-Alberta Gas (U.S) Inc. (Pan Alberta) with operating revenues of $54.7 million, $32.9 million and $45.5 million, respectively. For the year ended December 31, 2002, Northern Border Pipeline’s largest shippers were Pan-Alberta and Mirant Americas Energy Marketing, LP with combined operating revenues of $105.5 million. At December 31, 2004, Northern Border Pipeline had contracted firm capacity held by one shipper affiliated with its general partners. ONEOK Energy Services Company L.P. (ONEOK Energy Services), a subsidiary of ONEOK, holds firm service agreements representing 3% of summer design capacity. The firm service agreements with ONEOK Energy Services extend for various terms with termination dates that range from December 2004 to March 2009. ONEOK Energy Services became affiliated with Northern Border Pipeline, on November 17, 2004 in connection with ONEOK’s purchase of Northern Plains. Revenues from ONEOK Energy Services for the period from the date of affiliation to December 31, 2004, were $1.1 million. At December 31, 2004, Northern Border Pipeline had an outstanding receivable from ONEOK Energy Services of $0.8 million. In 2003, there were no operating revenues from affiliates. In 2002, one of Northern Border Pipeline’s shippers was affiliated with its general partners. Operating revenues from affiliates were $1.4 million for the year ended December 31, 2002. 5. CREDIT FACILITIES AND LONG-TERM DEBT Detailed information on long-term debt is as follows: (thousands of dollars) 2002 Pipeline Credit Agreement – average 1.95% at December 31, 2003, due 2005 1999 Pipeline Senior Notes – 7.75%, due 2009 2001 Pipeline Senior Notes – 7.50%, due 2021 2002 Pipeline Senior Notes – 6.25%, due 2007 Fair value adjustment for interest rate swaps (Note 6) Unamortized debt premium (discount) Long-term debt December 31, 2004 2003 $ $ – 200,000 250,000 150,000 – 3,860 603,860 $ $ 131,000 200,000 250,000 225,000 16,648 (1,150) 821,498 2 0 0 4 A N N U A L R E P O RT F-23 F-23 Northern Border Pipeline has entered into revolving credit facilities, which are used for capital expenditures, acquisitions and general business purposes and for refinancing existing indebtedness. Northern Border Pipeline entered into a $175 million three-year credit agreement (2002 Pipeline Credit Agreement) with certain financial institutions in May 2002. The 2002 Pipeline Credit Agreement permits Northern Border Pipeline to choose among various interest rate options, to specify the portion of the borrowings to be covered by specific interest rate options and to specify the interest rate period. Northern Border Pipeline is required to pay a fee on the principal commitment amount of $175 million. The 2002 Pipeline Credit Agreement will mature in 2005, and is expected to be replaced with a similar credit facility. In April 2002, Northern Border Pipeline completed a private offering of $225 million of 6.25% Senior Notes due 2007 (2002 Pipeline Senior Notes). The 2002 Pipeline Senior Notes were subsequently exchanged in registered offerings for notes with substantially identical terms. The proceeds from the senior notes were used to reduce indebtedness outstanding. On December 1, 2004, Northern Border Pipeline redeemed $75 million of the 2002 Pipeline Senior Notes. In connection with the redemption, Northern Border Pipeline was required to pay a premium of $4.8 million, incurred a $0.4 million loss related to the unamortized debt costs and discount associated with the debt and received $2.5 million from the termination of interest rate swaps associated with the debt (see Note 6). The net loss from the redemption is recorded as a loss on reacquired debt and amortized to interest expense over the remaining life of the 2002 Pipeline Senior Notes. At December 31, 2004, the net unamortized loss on reacquired debt was $2.6 million, which is recorded in regulatory assets on the balance sheet. Interest paid, net of amounts capitalized, during the years ended December 31, 2004, 2003 and 2002 was $41.1 million, $47.8 million and $55.3 million, respectively. Aggregate required repayments of long-term debt for the next five years are $150 million in 2007 and $200 million in 2009. Aggregate required repayments of long-term debt thereafter total $450 million. There are no required repayment obligations for 2005, 2006 or 2008. Certain of Northern Border Pipeline’s long-term debt and credit arrangements contain requirements as to the maintenance of minimum partners’ capital and debt to capitalization ratios, leverage ratios and interest coverage ratios that restrict the incurrence of other indebtedness by Northern Border Pipeline and also place certain restrictions on distributions to the partners of Northern Border Pipeline. The 2002 Pipeline Credit Agreement requires the maintenance of a ratio of EBITDA (net income plus interest expense, income taxes and depreciation and amortization) to interest expense of greater than 3 to 1. The 2002 Pipeline Credit Agreement also requires the maintenance of the ratio of indebtedness to EBITDA of no more than 4.5 to 1. At December 31, 2004, Northern Border Pipeline was in compliance with its financial covenants. The following estimated fair values of financial instruments represent the amount at which each instrument could be exchanged in a current transaction between willing parties. Based on quoted market prices for similar issues with similar terms and remaining maturities, the estimated fair value of the aggregate of the 1999 Pipeline Senior Notes, 2001 Pipeline Senior Notes and 2002 Pipeline Senior Notes was approximately $652 million and $739 million at December 31, 2004 and 2003, respectively. Northern Border Pipeline presently intends to maintain the current schedule of maturities for the 1999 Pipeline Senior Notes, the 2001 Pipeline Senior Notes and the 2002 Pipeline Senior Notes, which will result in no gains or losses on their respective repayments. The fair value of Northern Border Pipeline’s variable rate debt approximates the carrying value since the interest rates are periodically adjusted to reflect current market conditions. 6. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES Prior to the anticipated issuance of fixed rate debt, Northern Border Pipeline entered into forward starting interest rate swap agreements. The interest rate swap agreements were designated as cash flow hedges as they hedge the fluctuations in Treasury rates and spreads between the execution date of the swap agreements and the issuance of the fixed rate debt. The notional amount of the interest rate swap agreements did not exceed the expected principal amount of fixed rate F-24 F-24 T C P I P E L I N E S , L P T C P I P E L I N E S , L P debt to be issued. Upon issuance of the fixed rate debt, the swap agreements were terminated and the proceeds received or amounts paid to terminate the swap agreements were recorded in accumulated other comprehensive income and amortized to interest expense over the term of the debt. For the year ended December 31, 2002, Northern Border Pipeline received $2.4 million from terminated interest rate swap agreements. During the years ended December 31, 2004, 2003, and 2002, respectively, Northern Border Pipeline amortized approximately $1.4 million, $1.6 million, and $1.4 million related to the terminated interest rate swap agreements as a reduction to interest expense from accumulated other comprehensive income. Northern Border Pipeline expects to amortize approximately $1.5 million as a reduction to interest expense in 2005. Northern Border Pipeline entered into interest rate swap agreements with notional amounts totaling $225.0 million in May 2002. Under the interest rate swap agreements, Northern Border Pipeline makes payments to counterparties at variable rates based on the London Interbank Offered Rate and in return receives payments based on a 6.25% fixed rate. In November 2004, Northern Border Pipeline terminated its interest rate swap agreements with notional amounts of $225 million and received $7.5 million. Of the total proceeds, $2.5 million related to the redemption of $75 million of the 2002 Pipeline Senior Notes (see Note 5). The remaining $5.0 million is recorded in long-term debt with such amount amortized to interest expense over the remaining life of the interest rate swap agreements. During the year ended December 31, 2004, Northern Border Pipeline amortized approximately $0.2 million as a reduction to interest expense. Northern Border Pipeline expects to amortize approximately $2.2 million as a reduction of interest expense in 2005 for these agreements. At December 31, 2003, the average effective interest rate on Northern Border Pipeline’s interest rate swap agreements was 2.31%. Northern Border Pipeline’s interest rate swap agreements were designated as fair value hedges as they were entered into to hedge the fluctuations in the market value of the 2002 Pipeline Senior Notes. The accompanying balance sheet at December 31, 2003, reflects an unrealized gain of approximately $16.6 million in derivative financial assets with a corresponding increase in long-term debt. 7. COMMITMENTS AND CONTINGENCIES Operating Leases Future minimum lease payments under non-cancelable operating leases on office space and rights-of-way are as follows (in thousands): Year ending December 31, 2005 2006 2007 2008 2009 Thereafter $ $ 2,392 2,392 2,392 2,392 2,392 66,385 78,345 Expenses incurred related to these lease obligations for the years ended December 31, 2004, 2003 and 2002, were $0.6 million, $0.7 million, and $0.1 million, respectively. Cash Balance Plan As further discussed in Note 11, on December 31, 2003, Enron filed a motion seeking approval of the Bankruptcy Court to provide additional funding to, and for authority to terminate the Enron Corp. Cash Balance Plan and certain other defined benefit plans. Northern Border Pipeline recorded estimated charges associated with the termination of the Cash Balance Plan of $3.1 million in 2003. In 2004, Northern Border Pipeline reduced its expense by $3.1 million, since it determined it is no longer liable for termination costs of the Cash Balance Plan (see Note 11). 2 0 0 4 A N N U A L R E P O RT F-25 F-25 Capital Expenditures Total capital expenditures for 2005 are estimated to be $40 million. Funds required to meet the capital expenditures for 2005 are anticipated to be provided primarily by borrowings under the 2002 Pipeline Credit Agreement or similar facilities and operating cash flows. Environmental Matters Northern Border Pipeline is not aware of any material contingent liabilities with respect to compliance with applicable environmental laws and regulations. Other On July 31, 2001, the Assiniboine and Sioux Tribes of the Fort Peck Indian Reservation (Tribes) filed a lawsuit in Tribal Court against Northern Border Pipeline to collect more than $3.0 million in back taxes, together with interest and penalties. The lawsuit related to a utilities tax on certain of Northern Border Pipeline’s properties within the Fort Peck Indian Reservation. The Tribes and Northern Border Pipeline, through a mediation process, reached a settlement with respect to pipeline right-of-way lease and taxation issues documented through an Option Agreement and Expanded Facilities Lease (Agreement) executed in August 2004. Through the terms of the Agreement, the settlement grants to Northern Border Pipeline, among other things: (i) an option to renew the pipeline right-of-way lease upon agreed terms and conditions on or before April 1, 2011 for a term of 25 years with a renewal right for an additional 25 years; (ii) a right to use additional tribal lands for expanded facilities; and (iii) release and satisfaction of all tribal taxes against Northern Border Pipeline. In consideration of this option and other benefits, Northern Border Pipeline paid a lump sum amount of $7.4 million and will make additional annual option payments of approximately $1.5 million thereafter through March 31, 2011. Of the amount paid in 2004, $1.0 million was determined to be a settlement of previously accrued property taxes. The remainder has been recorded in other assets on the balance sheet. Northern Border Pipeline intends to seek regulatory recovery from the settlement in its upcoming rate case. Various legal actions that have arisen in the ordinary course of business are pending. Northern Border Pipeline believes that the resolution of these issues will not have a material adverse impact on Northern Border Pipeline’s results of operations or financial position. 8. CASH DISTRIBUTION POLICY The Northern Border Pipeline partnership agreement provides that distributions to Northern Border Pipeline’s partners are to be made on a pro rata basis according to each partner’s capital account balance. The Northern Border Pipeline Management Committee determines the amount and timing of such distributions. Any changes to, or suspension of, the cash distribution policy of Northern Border Pipeline requires the unanimous approval of the Northern Border Pipeline Management Committee. In December 2003, Northern Border Pipeline’s Management Committee voted to (i) issue equity cash calls to its partners in the total amount of $130 million in early 2004 and $90 million in 2007; (ii) fund future growth capital expenditures with 50% equity capital contributions from its partners; and (iii) change the cash distribution policy of Northern Border Pipeline. Effective January 1, 2004, cash distributions are equal to 100% of distributable cash flow as determined from Northern Border Pipeline’s financial statements based upon earnings before interest, taxes, depreciation and amortization less interest expense and maintenance capital expenditures. Effective January 2008, the cash distribution policy will be adjusted to maintain a consistent capital structure. On November 30, 2004, Northern Border Pipeline issued an equity cash call to its partners in the total amount of $75 million, which was utilized to repay existing bank debt. This equity contribution will reduce the previously approved 2007 equity cash call from $90 million to $15 million. F-26 F-26 T C P I P E L I N E S , L P T C P I P E L I N E S , L P 9. QUARTERLY FINANCIAL DATA (Unaudited) (in thousands) 2004 2003 First Quarter Second Quarter Third Quarter Fourth Quarter First Quarter Second Quarter Third Quarter Fourth Quarter 10. OTHER INCOME (EXPENSE) Operating Revenues Operating Income Net Income to Partners $ $ 83,307 81,532 81,609 82,667 79,892 80,659 81,192 82,442 $ $ 51,819 50,836 47,894 57,060 48,639 48,915 48,050 47,377 $ $ 41,757 41,297 37,580 46,143 36,734 37,617 37,195 36,654 Other income (expense) on the statement of income includes such items as investment income, nonoperating revenues and expenses, and nonrecurring other income and expense items. For the years ended December 31, 2004, 2003 and 2002, other income included income from interconnections constructed of $0.7 million, $0.1 million and $0.1 million, respectively. Other income for 2004 also included an adjustment to reserves previously established of $0.4 million. Other expense for the year ended December 31, 2004, included approximately $0.6 million due to reserves established for costs associated with a potential future project and $0.5 million of bad debt expense. For the year ended December 31, 2003, other expense included $0.6 million for a repayment of amounts previously received for vacated microwave frequency bands. For the year ended December 31, 2002, other income included $0.6 million for amounts received for previously vacated microwave frequency bands. 11. RELATIONSHIPS WITH ENRON In December 2001, Enron and certain of its subsidiaries filed voluntary petitions for Chapter 11 reorganization with the U.S. Bankruptcy Court. Until November 17, 2004, Northern Plains and Pan Border were subsidiaries of Enron. Northern Plains and Pan Border were not among the Enron companies filing for Chapter 11 protection. Enron North America (ENA), a wholly owned subsidiary of Enron that is in bankruptcy, a party to transportation contracts which obligated ENA to pay for 3.5% of Northern Border Pipeline’s capacity. Through the bankruptcy court proceeding in 2002, ENA rejected and terminated all of its firm transportation contracts on Northern Border Pipeline. Northern Border Pipeline had previously fully reserved for amounts invoiced to ENA. Since Enron guaranteed the obligations of ENA under those contacts, Northern Border Pipeline filed claims against both ENA and Enron for damages in the bankruptcy proceedings. As a result of a settlement agreement between ENA, Enron and Northern Border Pipeline, each of ENA and Enron have agreed to allow Northern Border Pipeline’s claim of approximately $20.6 million. The settlement agreement is expected to be presented to the Bankruptcy Court for approval in March 2005. Based upon this settlement between the parties, at December 31, 2004, Northern Border Pipeline adjusted its allowance for doubtful accounts to reflect an estimated recovery of $1.1 million for these claims. Northern Border Pipeline estimates that it could recognize, through future operating results, additional recoveries of $6 million to $9 million for the claims in the Enron bankruptcy proceedings. However, there can be no assurances on the amounts actually recovered or timing of distributions under the Chapter 11 Plan. 2 0 0 4 A N N U A L R E P O RT F-27 F-27 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 Cash Balance Plan and certain other defined benefit plans of Enron’s affiliates in ‘standard terminations’ within the meaning of Section 4041 of the Employee Retirement Income Security Act of 1974, as amended (ERISA). Such standard terminations would satisfy all of the obligations of Enron and its affiliates with respect to funding liabilities under the Cash Balance Plan. In addition, a standard termination would eliminate the contingent claims of Pension Benefit Guaranty Corporation (PBGC) against Enron and its affiliates with respect to funding liabilities under the Cash Balance Plan. On January 30, 2004, the Bankruptcy Court entered an order authorizing termination, additional funding and other actions necessary to effect the relief requested. Pursuant to the Bankruptcy Court order, any contributions to the Cash Balance Plan are subject to the prior receipt of a favorable determination by the Internal Revenue Service that the Plan is tax-qualified as of the date of termination. On July 19, 2004, Enron was served with a complaint filed by the PBGC in the District Court for the Southern District of Texas against Enron as the sponsor and/or administrator of the Plans (the Action). By filing the Action, the PBGC is seeking an order (i) terminating the Plans; (ii) appointing the PBGC the statutory trustee of the Plans; (iii) requiring transfer to the PBGC of all records, assets or other property of the Plans required to determine the benefits payable to the Plans’ participants; and (iv) establishing June 3, 2004 as the termination date of the Plans. In the Bankruptcy Court September 10 Order, Enron was authorized to enter into an escrow agreement with CCE Holdings and PBGC. Upon closing, Enron deposited the amount of $321.8 million to an escrow account, which is intended to ensure that none of CCE Holdings or its affiliates are exposed to liability to the PBGC under Title IV of the Employee Retirement Income Security Act of 1974, as amended, for which CCE Holdings may otherwise be indemnified pursuant to the CCE Holdings Agreement. In addition, the form of escrow agreement approved pursuant to the September 10 Order provides that, under certain circumstances and upon approval by or notice to the parties to the escrow agreement, some or all of the funds placed in escrow may be paid directly in respect of the Cash Balance Plan or to the PBGC. However, the September 10 Order also provides that PBGC retains any rights or claims it may have against the Transfer Group Companies. Enron management previously informed Northern Plains that Enron would seek funding contributions from each member of its ERISA controlled group of corporations that employs, or employed, individuals who are, or were, covered under the Cash Balance Plan. Northern Plains is considered a member of Enron’s ERISA controlled group of corporations. As of December 31, 2003, approximately $3.1 million was estimated for Northern Border Pipeline’s proportionate allocation of Northern Plains’ proportionate share of the up to $200 million estimated termination costs for the Plans authorized by the Bankruptcy Court order. Since under the operating agreement with Northern Plains, these costs could be the Northern Border Pipeline’s responsibility, $3.1 million was accrued to satisfy claims of reimbursement for these termination costs. As a result of further evaluation and negotiation of Enron’s proposed allocation of the termination costs, Northern Plains advised Northern Border Pipeline that no claim of reimbursement of the termination costs will be made, resulting in an adjustment in reserves during 2004 of $3.1 million for the termination costs. Under the ONEOK Agreement, neither Northern Plains nor Northern Border Pipeline will be required to contribute to or otherwise be liable for any contributions to Enron in connection with the Cash Balance Plan. The purchase price under the agreements will be deemed to include all contributions which otherwise would have been allocable to Northern Plains. Northern Border Pipeline continues to monitor developments at Enron, to assess the impact on Northern Border Pipeline of its existing agreements and relationships with Enron, and to take appropriate action to protect Northern Border Pipeline’s interests. 12. SUBSEQUENT EVENTS Northern Border Pipeline makes distributions to it general partners approximately one month following the end of the quarter. The distribution for the fourth quarter of 2004 of approximately $54.1 million was declared in January 2005 and paid in February 2005. S-1 T C P I P E L I N E S , L P REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM ON SCHEDULE Northern Border Pipeline Company: We have audited in accordance with the standards of the Public Company Accounting Oversight Board (United States), the financial statements of Northern Border Pipeline Company as of December 31, 2004 and 2003 and for each of the years in the three-year period ended December 31, 2004 included in this Form 10-K, and have issued our report thereon dated March 2, 2005. Our audits were made for the purpose of forming an opinion on the basic financial statements taken as a whole. The schedule of Northern Border Pipeline Company listed in Item 15 of Part IV of this Form 10-K is the responsibility of the Company’s management and is presented for purposes of complying with the Securities and Exchange Commission’s rules and is not part of the basic financial statements. This schedule has been subjected to the auditing procedures applied in the audits of the basic financial statements and, in our opinion, fairly states in all material respects, the financial data required to be set forth therein in relation to the basic financial statements taken as a whole. KPMG LLP Omaha, Nebraska March 2, 2005 2 0 0 4 A N N U A L R E P O RT S-2 NORTHERN BORDER PIPELINE COMPANY SCHEDULE II – VALUATION AND QUALIFYING ACCOUNTS FOR THE YEARS ENDED DECEMBER 31, 2004, 2003 AND 2002 (In Thousands) Column A Description Reserve for regulatory issues 2004 2003 2002 Column B Balance at Beginning of Year $ 6,315 $ 12,294 $ 2,531 Allowance for doubtful accounts 2004 2003 2002 $ 4,815 $ 4,805 $ 3,176 Column C Additions Charged to Costs and Expenses Charged to Other Accounts Column D Deductions For Purpose For Which Reserves Were Created Column E Balance at End of Year $ 640 $ 4,282 $ 9,763 523 $ 10 $ $ 3,452 $ – $ – $ – $ – $ – $ – $ 5,000 $ 10,261 – $ $ 1,130 – $ $ 1,823 $ 1,955 $ 6,315 $ 12,294 $ 4,208 $ 4,815 $ 4,805 BOARD OF DIRECTORS OF THE GENERAL PARTNER OF TC PIPELINES, LP EXECUTIVE OFFICERS OF THE GENERAL PARTNER OF TC PIPELINES, LP Albrecht W.A. Bellstedt Executive Vice-President, Law and General Counsel Ronald J. Turner President and Chief Executive Officer TransCanada Corporation Calgary, Alberta Kristine L. Delkus Vice-President, Law, Power and Regulatory TransCanada Corporation Calgary, Alberta Russell K. Girling Executive Vice-President, Corporate Development and Chief Financial Officer TransCanada Corporation Calgary, Alberta Jack F. Jenkins-Stark (2) Vice-President, Business Operations and Technology Itron Inc. Alameda, California David L. Marshall (1) Retired Vice-Chairman and Chief Financial Officer The Brinks Company Incline Village, Nevada Walentin (Val) Mirosh (2) Vice-President, Nova Chemicals Corporation President, Olefins and Feedstock Calgary, Alberta Ronald J. Turner Executive Vice-President, Gas Transmission TransCanada Corporation Calgary, Alberta Russell K. Girling Chief Financial Officer Steven D. Becker Vice-President, Business Development Donald R. Marchand Vice-President and Treasurer Ronald L. Cook Vice-President, Taxation Max Feldman Vice-President Wendy L. Hanrahan Vice-President Amy W. Leong Controller Maryse C. St.-Laurent Secretary (1) Chair, Audit Committee (2) Member, Audit Committee Our goal is to deliver stable, sustainable cash flows to unitholders and to find opportunities to increase cash distributions while maintaining a low-risk profile. FINANCIAL HIGHLIGHTS Year ended December 31 2004 2003 2002 2001 2000 (millions of dollars, except per unit amounts) Income Statement Net income 55.1 48.0 45.5 43.5 37.2 Net income per unit $ 2.99 $ 2.63 $ 2.50 $ 2.40 $ 2.08 Cash Flow Cash generated from operations Cash distributions paid 55.2 41.8 49.6 39.4 52.1 37.4 42.9 35.2 40.3 32.6 Cash distributions declared per unit $ 2.275 $ 2.175 $ 2.075 $ 1.975 $ 1.850 Balance Sheet Total assets Long-term debt Partners’ equity 332.1 36.5 294.9 288.1 5.5 282.0 286.0 11.5 273.9 288.7 21.5 266.7 277.5 21.5 255.4 Our Assets 1 Letter to Unitholders 2 Form 10-K 3 Financial Statements F-1 TC PIPELINES, LP 110 Turnpike Road, Suite 203, Westborough, Massachusetts, US 01581 Telephone (508) 871-7046 Facsimile (508) 871-7047 450 – First Street SW, Calgary, Alberta, Canada T2P 5H1 Telephone (877) 290-2772 Facsimile (403) 920-2457 Investor Relations Telephone (877) 290-2772 Facsimile (403) 920-2457 E-mail: investor_relations@tcpipelineslp.com Internet Site www.tcpipelineslp.com K-1 Information Telephone (877) 699-1091 Stock Exchange Listing NASDAQ Stock Market: TCLP Auditors KPMG LLP, Calgary, Alberta Transfer Agent Mellon Investor Services LLC, Ridgefield Park, New Jersey Telephone (800) 756-3353 Please recycle April 2005 Printed in Canada Designed and produced by smith + associates www.smithandassoc.com Cash Distributions(dollars per unit)0001020401.8501.9752.075032.1752.275Net Income(dollars per unit)0001020402.082.402.50032.632.99TC PIPELINES, LP is a United States limited partnership that offers investors stable cash flow and growth prospects. TC PipeLines owns a 30 per cent interest in Northern Border Pipeline Company and a 49 per cent interest in Tuscarora Gas Transmission Company. Both Northern Border Pipeline and Tuscarora own interstate pipeline systems that transport western Canadian natural gas to growing natural gas consuming markets in the midwestern United States and northern Nevada areas, respectively. The Partnership is managed by its general partner, TC PipeLines GP, Inc., a wholly owned subsidiary of TransCanada Corporation, a leading North American energy company. T C P I P E L I N E S , L P 2 0 0 4 A N N U A L R E P O R T 2004 Annual Report TC PIPELINES, LP 

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