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UNITED STATES SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-K

For the Transition period from                 to                

Commission File Number:  000-26091

TC PipeLines, LP

(Exact name of registrant as specified in its charter)

877-290-2772

(Registrant’s telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act:

Securities registered pursuant to Section 12(g) of the Act:

None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.

Yes o                                                             No x

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.

Yes o                                                             No x

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Yes x                                                           No o

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 a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer”, “accelerated filer” and “small reporting company” in Rule 12b-2 of the Exchange Act.

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).

Yes o                                                             No x

The aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant as at June 30, 2008 was approximately $850.6 million.

As of February 27, 2009, there were 34,856,086 common units of the registrant outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

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TC PIPELINES, LP

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All amounts are stated in United States dollars unless otherwise indicated.

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Glossary

The abbreviations, acronyms, and industry terminology used in this annual report are defined as follows:

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PART I

FORWARD-LOOKING STATEMENTS

The statements in this report that are not historical information, including statements concerning plans and objectives of management for future operations, economic performance or related assumptions, are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Exchange Act. Forward-looking statements may include words such as “anticipate,” “estimate,” “expect,” “project,” “intend,” “plan,” “believe,” “forecast” and other words and terms of similar meaning. The absence of these words, however, does not mean that the statements are not forward-looking.

These statements reflect our current views with respect to future events, based on what we believe are reasonable assumptions. Certain factors that could cause actual results to differ materially from those contemplated in the forward-looking statements include:

Other factors described elsewhere in this document, or factors that are unknown or unpredictable, could also have material adverse effects on future results. Please also read Item 1A. “Risk Factors.” All forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by these factors. These forward-looking statements and information are made only as of the date of the filing of this report, and except as

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required by applicable law, we undertake no obligation to update these forward-looking statements and information to reflect new information, subsequent events or otherwise.

Item 1.                                     Business

OVERVIEW

We are a publicly traded Delaware limited partnership formed in 1998 by TransCanada PipeLines Limited, a wholly-owned subsidiary of TransCanada Corporation (collectively referred to as TransCanada), to acquire, own and participate in the management of North American energy infrastructure businesses. To date, our primary focus has been in the transportation of natural gas from the WCSB to a variety of downstream markets.

TC PipeLines, LP and its subsidiaries are collectively referred to herein as “TC PipeLines” or “the Partnership.” In this report, references to “we”, “us” or “our” collectively refer to TC PipeLines or the Partnership. The general partner of the Partnership is TC PipeLines GP, Inc. (TC PipeLines GP), a wholly-owned subsidiary of TransCanada.

Our strategic focus is on delivering stable, sustainable cash distributions to our unitholders and finding opportunities to increase cash distributions while maintaining a low risk profile.

The global economic slowdown is anticipated to have a short-term impact on demand for all forms of energy, including natural gas. However, when the economy returns to a growth cycle, North America’s demand for natural gas is expected to increase.

Our pipeline investments are underpinned by contracts, regulation and strong business fundamentals. Customer demand for the transportation services our pipeline systems provide is directly related to the demand for natural gas in the markets served by our pipeline systems. Although North American demand for natural gas has recently declined and is expected to further decline in 2009 with the current economic downturn, we expect the demand to increase in the long-term.

Our strong financial position, including an available unused credit facility, gives us the capacity to pursue opportunities to grow in a sustained and disciplined manner for the long-term benefit of our unitholders.

Our current portfolio of interstate natural gas pipeline investments in the U.S. consists of:

TransCanada operates Great Lakes, Northern Border and Tuscarora (collectively, “our pipeline systems”). See Item 13. “Certain Relationships and Related Transactions, and Director Independence”.

Year in Review – 2008

Northern Border Expansion Project Commencement – In September 2008, Northern Border commenced construction on its interconnect expansion project to support Northern States Power’s request for firm backhaul service from a receipt point interconnection with ANR Pipeline Company (ANR), a wholly-owned subsidiary of TransCanada, to an existing delivery point at Ventura, Iowa (Des Plaines Project). The Des Plaines Project is estimated to cost approximately $18.0 million and was placed into service in late February 2009.

Northern Border Sale of Subsidiary – In August 2008, Northern Border sold its wholly-owned subsidiary, Bison Pipeline LLC, to TransCanada PipeLine USA Ltd., a wholly-owned subsidiary of TransCanada, for $20.0 million. In

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connection with this transaction, Northern Border recognized a gain on sale of $16.2 million. TC PipeLines received a special distribution of $8.2 million in the third quarter of 2008 related to this transaction.

As part of the transaction, TransCanada has assumed the obligations of Northern Border related to the proposed Bison pipeline system (Bison Project), and continues to work with the Bison Project shippers to finalize the size and design of this project. The assets and obligations of Bison Pipeline LLC included executed precedent agreements, subject to certain shipper contingencies, as well as regulatory, environmental and engineering activities completed to date.

The proposed Bison Project would extend from natural gas gathering facilities located in the Powder River Basin in Wyoming to a point of interconnection with the Northern Border system in Morton County, North Dakota. The project has shipping commitments for approximately 407 million cubic feet per day (MMcf/d) and is projected to go into service late 2010. Shippers on the Bison Project have executed contracts for capacity on the Northern Border system from Port of Morgan, Montana to Ventura, Iowa, subject to the in-service date of the Bison Project. Project subscription that is subject to the upstream capacity condition is approximately 407 MMcf/d.

Tuscarora Expansion Project Completion – On April 1, 2008, Tuscarora’s compressor station expansion project to support Sierra Pacific Power Company’s (Sierra Pacific Power’s) Tracy Combined Cycle Power Plant went into service. Sierra Pacific Power is a subsidiary of NV Energy Inc. (formerly known as Sierra Pacific Resources).

Business Strategies

Our strategic focus is on delivering stable, sustainable cash distributions to our unitholders and finding opportunities to increase cash distributions while maintaining a low risk profile.

We seek opportunities to undertake accretive acquisitions and pursue organic growth projects to maximize the value of our existing portfolio of pipeline systems. Working with our partners in our pipeline systems, we seek to pursue policies that:

We intend to support the execution of our business strategies by:

Competitive Strengths

We believe that we are well positioned to execute our business strategies successfully because of the following competitive strengths:

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Our Relationship with TransCanada

One of our principal strengths is our relationship with TransCanada. TransCanada, a Canadian corporation, was founded in 1951 with the objective of transporting natural gas from Alberta to distant markets. Today, TransCanada is a major North American energy infrastructure company engaged in numerous aspects of the energy industry but is primarily focused on natural gas transmission and power generation services. TransCanada owns approximately 36,500 miles of wholly-owned natural gas pipelines, interests in an additional 4,800 miles of natural gas pipelines, approximately 370 Bcf of storage capacity and, including facilities that are under construction or in development, also owns, operates, and/or controls approximately 10,900 megawatts of power generation. Also, currently under construction is Keystone, an oil pipeline consisting of 2,147 miles of pipe that will initially transport crude oil from Hardisty, Alberta, Canada to U.S. Midwest markets and to Cushing, Oklahoma.

TransCanada provides access to a significant pool of management talent and strong relationships throughout the energy industry. We expect to pursue strategic acquisitions in a disciplined manner and to have the opportunity to participate jointly with TransCanada in reviewing potential acquisitions, including transactions that we would be unable to pursue on our own. Additionally, we may have the opportunity to make acquisitions directly from TransCanada in the future. TransCanada, however, is under no obligation to allow us to participate in any of its pipeline or energy infrastructure acquisitions, nor is TransCanada required to offer any of its assets to us.

See Item 5. “Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities” for more information regarding TransCanada’s ownership in us.

Our Pipeline Systems

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All of our pipeline systems are regulated by the FERC. Operating revenue is derived from the transportation of natural gas. The maximum transportation rates that our pipeline systems may charge are approved by the FERC, and in most cases, established in a FERC proceeding known as a rate case. During a rate case, a determination is reached by the FERC, either through a hearing or a settlement, on the maximum rates permissible for transportation service that include the recovery of cost-based investment, operating expenses and a reasonable return for its investors. Once maximum rates are set, the pipeline system is not permitted to adjust the maximum rates to reflect changes in costs or contract demand until new rates are approved by the FERC, usually after a rate case has been filed. The FERC also governs the general terms and conditions for natural gas transportation service on interstate natural gas pipelines. The tariff also allows for services to be provided under negotiated and discounted rates. As a result, earnings and cash flow of each pipeline system depend on costs incurred; contracted capacity and transportation path; the volume of gas transported; and the ability of each system to sell capacity at acceptable rates.

Transportation Services

Our pipeline systems’ transportation contracts include specifications regarding the receipt and delivery of natural gas at points along the pipeline system. The transportation services provided by our pipeline systems are generally categorized as firm or interruptible. The type of transportation contract, either for firm or interruptible service, determines the basis upon which each customer is charged.

Customers with firm service transportation agreements pay a fee known as a reservation charge to reserve pipeline capacity, regardless of use, for the term of their contracts. On the Great Lakes and Northern Border systems, firm service transportation customers also pay a variable usage fee known as a commodity charge (or utilization fee) that is based on distance and the volume of natural gas they transport. Transportation customers on the Northern Border system also pay a compressor usage surcharge based on the settlement of the 2005 rate case, resulting in new rates which were implemented January 1, 2007.

Customers with interruptible service transportation agreements may utilize available capacity on a pipeline system after firm service transportation requests are satisfied. Interruptible service customers are assessed commodity charges (or utilization fees) based on distance and the volume of natural gas they transport. On Great Lakes’ system, interruptible and overrun revenues in excess of $0.5 million are generally subject to a sharing mechanism whereby 90 per cent of the revenue is refunded to firm shippers paying maximum tariff rates. The table below provides information with respect to tariff revenue composition for each of our investments for the year ended December 31, 2008. The weighted average remaining contract life is determined as at January 31, 2009.

(1) Variable usage fees for Northern Border include a compressor usage surcharge which relate to both firm and interruptible contracts. Tuscarora does not have any variable usage fees as part of its tariff.

(2) Weighted average remaining contract life is weighted based upon maximum daily quantity (MDQ) in the contracts.

Business of Great Lakes

Great Lakes is a Delaware limited partnership formed in 1990 and holds the assets formerly held by Great Lakes Transmission Company. We own 46.45 per cent of Great Lakes. TransCanada owns the remaining 53.55 per cent and is also the operator.

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Great Lakes was originally constructed as an operational loop of the TransCanada Mainline Northern Ontario system. Great Lakes’ primary receipt point is with TransCanada at the Canadian border near Emerson, Manitoba. Great Lakes’ pipeline system extends across Minnesota, Northern Wisconsin and Michigan, and redelivers gas to TransCanada at the Canadian border at Sault Ste. Marie, Michigan and St. Clair, Michigan. Great Lakes also delivers gas to other storage systems and interconnects with other interstate natural gas pipelines.

The Great Lakes mainline transmission pipeline has diameters ranging from 10 inches to 36 inches. The Great Lakes system consists of approximately 2,115 miles of pipeline with a design day capacity of 2,300 MMcf/d during the summer and 2,500 MMcf/d during the winter. Annual capacity is determined by the summer design day capacity. Great Lakes has 14 compressor stations with a total of 438,000 horsepower and measurement facilities to support the 58 receipt and delivery points on the system.

The original construction of Great Lakes’ system occurred in 1967 and 1968. There have been numerous capacity system expansions since its original construction, the last one completed in 1998.

The major policies of Great Lakes are established by the management committee of Great Lakes (GL Management Committee). The current GL Management Committee consists of four appointed members, two of whom are designated by us and two of whom are designated by TransCanada. All decisions by the GL Management Committee require unanimous consent. For the day to day management of Great Lakes’ business, the GL Management Committee established an executive committee (GL Executive Committee). The GL Executive Committee currently consists of two appointed members: one Partnership GL Management Committee member, and one TransCanada GL Management Committee member, who also serves as the president of Great Lakes. The GL Executive Committee has all of the powers of the GL Management Committee in the management of Great Lakes’ business.

Business of Northern Border

Northern Border is a Texas general partnership formed in 1978. TC PipeLines and ONEOK Partners each own a 50 per cent interest in Northern Border.

Northern Border extends from the Canadian border near Port of Morgan, Montana to a terminus near North Hayden, Indiana. Northern Border’s transportation system provides pipeline access to the Midwestern U.S. from natural gas reserves in the WCSB. Additionally, Northern Border transports natural gas produced in the Williston Basin of Montana and North Dakota, and the Powder River Basin of Wyoming and Montana, and synthetic gas produced at the Dakota Gasification plant in North Dakota.

The pipeline system consists of 1,249 miles of pipeline with diameters ranging from 30 to 42 inches and a design capacity on the largest segment of the pipeline of 2,374 MMcf/d. Along the pipeline are 17 compressor stations with a total of 515,000 horsepower, measurement facilities to support the receipt and delivery of gas at 11 receipt and 52 delivery points, four field offices and a microwave communication system with 50 tower sites.

Construction of Northern Border’s system was initially completed in 1982, followed by expansions or extensions in 1991, 1992, 1998, 2001 and 2006.

Northern Border is managed by a management committee that consists of four members. Each partner designates two members, and the Partnership designates one of our members as Chairman. Each partner holds a 50 per cent voting interest on the management committee.

Des Plaines Project – In February 2008, Northern Border filed with the FERC to construct, own and operate interconnect facilities, including a 1,600 horsepower compressor facility near Joliet, Illinois. It is estimated that this project will cost approximately $18.0 million and be financed by a combination of debt and equity. Construction commenced in September 2008. The project was placed into service in late February 2009. The Des Plaines Project is fully subscribed under a long-term compression and transportation contract. The term of the contract commences with the in service date of the project and ends March 31, 2027, with estimated annual revenues of $3.0 million.

Business of Tuscarora

Tuscarora is a Nevada general partnership formed in 1993. TC PipeLines owns 100 per cent of Tuscarora.

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The Tuscarora system originates at an interconnection point with existing facilities of Gas Transmission Northwest Corporation (GTN), a wholly-owned subsidiary of TransCanada, near Malin, Oregon and runs through Northeastern California and Northwestern Nevada. The Tuscarora pipeline system terminates near Wadsworth, Nevada. Along its route, deliveries are made in Oregon, Northern California and Northwestern Nevada.

Tuscarora owns a 240-mile, 20-inch diameter pipeline system with a design capacity of approximately 230 MMcf/d. Tuscarora has three compressor stations with a total of over 17,100 horsepower, and measurement facilities at one receipt point and 16 delivery points.

The Tuscarora pipeline system was initially placed into service in 1995. Expansions or extensions were completed in 2001, 2002, 2005 and 2008.

2008 Expansion Project - In July 2007, Tuscarora received FERC approval for the construction of a compressor station and related facilities. The project was placed into service on April 1, 2008. The approximately $20.4 million project was underpinned by a 22.5 year long-term contract with Sierra Pacific Power to supply its Tracy Combined Cycle Power Plant. The contract is expected to generate approximately $5.8 million of annual revenue.

NATURAL GAS INDUSTRY OVERVIEW

North American Demand

Demand for natural gas transportation service on a pipeline system is directly related to demand for natural gas in the markets served by that system. Factors that may impact demand for natural gas include:

·                  weather conditions;

·                  economic conditions;

·                  government regulation;

·                  the availability and price of alternative energy sources versus natural gas;

·                  natural gas storage inventories for the markets served;

·                  fuel conservation measures; and

·                  technological advances in fuel economy and energy generation devices.

Natural gas demand fluctuates on an annual basis as a result of the factors described above. Although North American demand for natural gas has declined recently and is expected to continue to decline in 2009 with the current economic downturn, we expect the demand to decline only in the short-term. The impact to demand for natural gas transportation service on any one pipeline system will depend upon changes in demand in the market areas which that pipeline serves.

Other factors that may impact demand for natural gas transportation service on any one system include:

·                  availability of natural gas supply at the pipeline system’s receipt points;

·                  the ability and willingness of natural gas shippers to utilize the pipeline system over alternative pipelines;

·                  the relative transportation rates; and

·                  the volume of natural gas delivered to the markets supplied by that system from other supply sources and storage facilities.

Our pipeline systems are exposed to business risk when they are marketing their available capacity. This occurs when existing transportation contracts expire and there is available capacity on the pipeline system. Customers can then, depending on the market, either renegotiate their contract commitments, including shorter terms and discounted rates, or they may choose not to renew their contract. Customers with competitive alternatives analyze the market price spread or basis differential between receipt and delivery points along the pipeline to determine their expected gross margin. The anticipated margin and its variability are important determinants of the transportation rate customers are willing to pay.

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Our Pipeline Systems

The table below provides information on the average throughput of our pipeline systems:

(1) The average throughput for Great Lakes includes periods prior to the February 22, 2007 acquisition by us of a 46.45 per cent general partner interest in Great Lakes.

Great Lakes provides transportation services to Midwest and Northeast U.S. markets, as well as Eastern Canadian markets. Demand for natural gas in these markets has remained relatively consistent over the last three years and is expected to increase over the long-term, particularly to meet the expected growth in natural gas fired power generation. However, we believe the current economic environment could reverse this trend in the short-term. The demand for transportation on Great Lakes is mainly from local distribution companies (LDCs) and industrial customers, as well as for transportation of volumes back into Canada. Throughput on Great Lakes was down slightly in 2008 relative to 2007 and 2006 primarily due to underutilization of firm contracts.

Northern Border provides transportation services to Midwest U.S. markets directly and through major interconnections with other interstate natural gas pipelines. Demand for natural gas in these markets has been relatively flat over the past three years and is expected to grow over the long-term. The current economic environment may cause a decline in 2009 natural gas demand in this market area, but is expected to increase in the long-term. Demand for transportation on Northern Border remained relatively constant until 2008 when a drop in demand occurred related to new volumes of natural gas delivered to its markets from the Rockies natural gas basin by a competitive pipeline. This is discussed further under “Customers, Competition and Contracting”.

Tuscarora provides transportation services to markets in Oregon, Northern California and Northern Nevada. Demand for natural gas in these markets has grown over the last three years due primarily to increased demand from electric generation companies and LDCs. The major customers on Tuscarora’s system require transportation capacity to meet their obligations to their customers but are not necessarily required to flow any gas through the system. As a result, Tuscarora’s throughput is not indicative of its revenue generation. This is discussed further under “Customers, Competition and Contracting”.

Seasonality

North America

North American demand for natural gas is seasonal. In general, demand tends to be higher in the winter months for heating requirements and in the summer for power generation demand in support of cooling requirements. In the spring and fall, when there is less demand for heating and cooling requirements, gas is put in storage near industrial consuming areas for future use. Available storage capacity combined with price spreads between current and future pricing during certain periods of the year may make it more profitable to store the gas for use in the future when the price for natural gas may be more favorable.

Seasonal fluctuations in demand for natural gas between market regions will also impact supply available to a given market area.

The amount of uncontracted transportation capacity as well as transportation capacity under short-term contracts on a pipeline system determines the extent that seasonal demand will impact a pipeline system’s revenue. Revenues of pipeline systems that have a higher ratio of long-term contracts (contracts with a duration longer than one year) will be impacted less by seasonal demand. Conversely, for those pipeline systems with more available capacity, or operating under short-term contracts, fluctuations in demand between seasons can impact revenue. Pipeline systems

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which have a tariff that includes seasonal rates for short-term service may be able to mitigate the potential negative impact of seasonal fluctuations in demand.

Great Lakes - As a turbine-based pipeline system, Great Lakes’ design day capacity at the Emerson, Manitoba receipt point is approximately 2.5 Bcf/day during the winter and 2.3 Bcf/day during the summer (system fuel requirements utilize a portion of this capacity). Though the winter flow capability is higher than the summer capability, the market demand for Great Lakes’ long haul service can be higher in the summer when Great Lakes’ system has less transportation capacity.

The demand for Great Lakes’ long haul service is at its highest when natural gas is being delivered to storage areas. This is due to the approximate 880 Bcf of working gas storage located at the Eastern end of the Great Lakes system in Michigan and Ontario. The high demand period usually begins in the spring and extends through most of the summer. The transportation value across the Great Lakes pipeline system is normally at its highest in conjunction with storage fill requirements and electric power generation demand.

During the winter, there is also strong demand for Great Lakes services to meet the peak winter heating demand requirements of Northern Minnesota, Northern Wisconsin, and Michigan. These deliveries are met through Great Lakes short haul, long haul, and backhauls from storage. Approximately 13 per cent of Great Lakes’ flows were contracted on a short-term basis in 2008.

Great Lakes experiences significant winter volatility in the utilization of its long haul contracts due to downstream constraints on the Union Gas Limited and TransCanada systems. As the demand for storage withdrawals from the Dawn, Ontario storage facility increases to serve points east, so does the level of downstream constraints, which may reduce shippers’ ability to use Great Lakes’ transportation services to serve Eastern markets. This constraint may reduce demand for Great Lakes’ transportation during certain winter periods.

Northern Border – Seasonal supply and demand fundamentals are a growing influence on Northern Border’s system due to increased competition for WCSB supply and growing competition from alternate sources of supply, such as the Rockies, in the markets served by Northern Border. Approximately 24 per cent of Northern Border’s design capacity was contracted on a short-term basis in 2008. Demand for Northern Border’s transportation has traditionally been the strongest during peak winter months to serve heating demand and peak summer months to serve electric cooling demand and storage injection. Moderate winter and summer temperatures can lead to a decline in the demand for Northern Border’s service due to reduced demand for natural gas.

Northern Border’s settlement of its 2005 rate case established seasonal rates for short-term service of less than one year that provide for higher maximum rates during anticipated peak usage periods and lower maximum rates during anticipated periods of reduced demand.

Tuscarora – Tuscarora is fully contracted under long-term contracts (100 per cent contracted with a weighted average remaining contract life of 11.6 years) at January 31, 2009, with approximately two per cent of its design capacity uncontracted beginning in the second quarter of 2009. As a result, fluctuations in revenue due to seasonality are minimal.

Supply

North American Supply

The primary source of natural gas transported by all of our pipeline systems is the WCSB. In 2008, approximately 80 per cent, 79 per cent and 97 per cent of the natural gas transported by Great Lakes, Northern Border and Tuscarora, respectively, was produced in Canada. For this reason, the continuous supply of Canadian natural gas is crucial to the long-term financial condition of our pipeline systems.

The WCSB has remaining discovered natural gas reserves of approximately 57 trillion cubic feet and a reserves-to-production ratio of approximately nine years at current levels of production. Historically, additional reserves have continually been discovered to maintain the reserves-to-production ratio at close to nine years. However, supply from the WCSB has declined in recent years due to a continued reduction in drilling activity in the basin. Drilling in the WCSB is expected to reach a low point in 2009 and begin to recover in the ensuing years assuming that gas prices stabilize and that finding and development costs decrease.

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The net amount of WCSB natural gas flows available for downstream markets is the most significant factor affecting the volume of natural gas transported by our pipeline systems. “Net WCSB flows to markets” is the term we use to represent the net of the supply of and demand for WCSB natural gas. WCSB supply is made up of WCSB production with injections into WCSB storage reducing net supply, and withdrawals from WCSB storage increasing supply. The net WCSB flows to markets are determined by:

·                  WCSB natural gas production levels;

·                  Canadian demand for WCSB natural gas; and

·                  Western Canadian storage capacity for WCSB natural gas and demand for storage injection.

The extent to which net WCSB flows to markets will be transported on each pipeline system is affected by:

·                  demand for WCSB natural gas in different U.S. consumer markets;

·                  available transportation capacity and related market pricing options on our competitors’ pipelines;

·                  natural gas from other supply sources that can be transported to our customer markets;

·                  the natural gas market price spread between Alberta, Canada and the applicable downstream market which reflects the relative supply and demand for WCSB natural gas in Canada and in the U.S.; and

·                  storage capacity in the U.S. and Canada and the related demand for storage injection.

Our Pipeline Systems

Great Lakes receives natural gas primarily from interconnections with the TransCanada Mainline, ANR and from storage facilities. Gas received from the interconnection with the TransCanada Mainline at Emerson, Manitoba is WCSB supply. ANR is connected with numerous other pipelines, sourcing gas from virtually all North American basins as well as imported LNG.

Northern Border receives natural gas from its connection with one of TransCanada’s pipelines at the Canadian border near Monchy, Montana. Northern Border also transports natural gas produced in the Williston Basin of Montana and North Dakota and the Powder River Basin of Wyoming and Montana, which accounted for approximately 15 per cent of the natural gas Northern Border transported in 2008. The remaining natural gas transported by Northern Border was synthetic gas produced at the Dakota Gasification plant in North Dakota.

Tuscarora receives natural gas from its interconnection with GTN. GTN is interconnected with WCSB supply as well as natural gas from the Rockies and other U.S. basins.

CUSTOMERS, COMPETITION AND CONTRACTING

Customers

Our pipeline systems transport natural gas for a variety of customers including other natural gas pipelines, LDCs, industrial companies, electric power generation companies, natural gas producers, and natural gas marketers. Each type of customer has a different reason for using certain natural gas transportation services and routes. LDCs, industrial companies and electric power generation companies typically require a secure and reliable supply of natural gas over a sustained period of time to meet the needs of their customers. These types of customers typically enter into long-term firm transportation contracts to ensure a ready supply of natural gas and sufficient transportation capacity to meet their obligations to their customers over the life of the contracts with their customers. Natural gas producers typically enter into firm transportation contracts to ensure that they will have sufficient capacity to deliver their product to market centers. Natural gas marketers typically use transportation services to capitalize on natural gas price volatility and therefore tend to contract for shorter terms, which increases their flexibility.

Great Lakes - The largest customer for Great Lakes’ capacity is TransCanada, through its mainline pipeline system. This capacity is used by TransCanada customers to transport WCSB gas to Eastern Canadian and U.S. markets. ANR also holds capacity on Great Lakes to integrate its Michigan storage locations with its Wisconsin pipeline segments. Various LDCs in Minnesota, Wisconsin and Michigan contract for transportation on Great Lakes to diversify and add Canadian gas to their supply mix. In addition, natural gas marketers and producers hold transportation capacity on Great Lakes, either directly or through the capacity release program, and use Great Lakes’

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flexibility to deliver gas to markets, interconnecting pipelines and storage facilities along its system to maximize the value of their transportation contracts. Great Lakes’ customer profile is becoming more heavily weighted towards natural gas marketers and less towards producers and end users, such as industrial customers and LDCs; however, Great Lakes’ largest customer remains TransCanada.

For the year ended December 31, 2008, TransCanada and ANR contracts represented approximately 47 per cent and three per cent, respectively, of Great Lakes’ revenue. Great Lakes did not have any other customers contributing more than 10 per cent to their 2008 revenues.

Northern Border - Northern Border’s customers include natural gas producers, marketers, industrial companies, LDCs and electric power generating companies. Northern Border’s contract life has been declining and its customer profile over the past five years has been mainly comprised of natural gas producers and marketers.

For the year ended December 31, 2008, contracts with BP Canada Energy Marketing Corp. and Cargill Inc. represented approximately 13 per cent and 11 per cent, respectively, of Northern Border’s revenue. Northern Border did not have any other customers contributing more than 10 per cent of their 2008 revenues.

Tuscarora - Tuscarora’s main customers are a power generation company and an LDC, along with a variety of industrial, commercial, and other companies.

For the year ended December 31, 2008, contracts with Sierra Pacific Power and Southwest Gas Company represented approximately 75 per cent and 11 per cent, respectively, of Tuscarora’s revenue.

Competition

Competition among natural gas pipelines is based primarily on transportation rates and proximity to natural gas supply areas and markets. Our pipeline systems face competition at both the supply and market ends of their pipeline systems. Other pipelines access the WCSB and provide alternative routes for shippers to access markets served by our systems or take gas to markets not served by our pipeline systems. Additionally, supply sourced from other U.S. supply basins is transported by other pipelines into our pipeline systems’ market areas.

Other factors affecting the market include an increase in the number of new pipeline projects in the U.S., which may change the natural gas supply and demand competition in the markets served by our pipeline systems. This growth in natural gas infrastructure has, in the recent past, led to rising costs, both in labor and materials, associated with these new pipeline projects. However, this trend of rising costs may be reversed with the current economic environment.

Great Lakes – Great Lakes’ principal business comes from its position as a link in the chain of pipelines that facilitate the transportation of natural gas from WCSB to Midwest and Northeast U.S. markets and Eastern Canadian markets. Natural gas is transported by TransCanada from Western Canada to near Emerson, Manitoba. Great Lakes provides transportation from Emerson to the TransCanada system at St. Clair, Michigan. TransCanada transports the gas received at St. Clair to Dawn, Ontario and points further east. The primary competition for Great Lakes is the alternate route from Western Canada to Dawn on TransCanada’s Mainline. Other routes from Western Canada to Ontario, Canada, are the Foothills Pipeline to Northern Border to Vector Pipeline route, or the Alliance Pipeline which also interconnects with the Vector Pipeline. In addition, gas sourced from the U.S. Rockies, U.S. Mid-Continent and U.S. Gulf Coast can be delivered to Chicago and then to Ontario via the Vector Pipeline or via ANR’s and Great Lakes’ pipelines.

Northern Border – Northern Border’s system competes for natural gas supply with other pipelines that transport WCSB natural gas to markets in the West, Midwest and East in North America. The pipeline systems that offer primary competition include Alliance Pipeline, Great Lakes, Gas Transmission Northwest, and other pipelines that interconnect with the TransCanada mainline for WCSB supply. Northern Border also competes with other pipelines that serve Northern Border’s market areas. Most of these pipelines have access to natural gas storage facilities, and alternate sources of supply from the Rockies, the Mid-Continent, the Permian Basin and the Gulf Coast, as well as LNG. These pipeline systems that offer primary competition include Northern Natural Gas Company in Northern Border’s Ventura, Iowa market area and Alliance Pipeline, ANR, Midwestern Gas Transmission Company and Natural Gas Pipeline of America in the Chicago market region.

The Rockies Express Pipeline (REX) is a 1,679 mile pipeline originating in Rio Blanco County, Colorado to Monroe County, Ohio. Northern Border is experiencing increased competition from the Western segment (REX West), which delivers gas from the Rockies basin to Audrian County, Missouri, in the market area served by Northern

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Border. REX West was placed into service in May 2008. Northern Border experienced a reduction in its throughput and decreased demand for available capacity in 2008 related to this increased competition.

The Eastern segment (REX East) of the REX system will move gas from Audrian County, Missouri to Monroe County, Ohio and is expected to alleviate some of the excess supply in the Midwest markets. REX has announced that the REX East segment is expected to be fully in service in the fourth quarter of 2009. The combination of growing supply from the Rockies and shale developments reaching the Chicago market region through new and available pipeline capacity and reductions in demand resulting from the economic crisis has the potential to maintain competitive pressures in the Midwest markets on WCSB sourced natural gas. Any reductions in flows on Northern Border to the Chicago market will impact supply and demand fundamentals at the Ventura market.

Furthermore, overall North American natural gas flows will be impacted by pipeline projects that are anticipated to be in service in 2009 to move additional supply volumes from the lower Mid-Continent to existing Gulf Coast infrastructure.

Tuscarora - Tuscarora’s primary competition in the Northern Nevada natural gas transportation market is with Paiute Pipeline Company (Paiute), owned by Southwest Gas Co. Paiute interconnects with Northwest Pipeline Corp. at the Nevada-Idaho border and transports natural gas from British Columbia, Canada and the U.S. Rocky Mountain Basin to the Northern Nevada market.

Contracting

Transportation contracts mature at varying times and for varying amounts of throughput capacity. As existing contracts on our pipeline systems approach their expiration dates, efforts are made to extend and/or renew the contracts. The ability to extend and/or renew expiring contracts will depend upon competitive alternatives, the regulatory environment, and market and supply factors. The length of new or renegotiated contracts will be affected by current market price spreads, transportation rates, competitive conditions, and judgments concerning future market trends and volatility. Customer liquidity and capital constraints can also impact the length of contracts. If market conditions are not favorable at the time of renewal, transportation capacity may remain available until market conditions become more favorable. Subject to regulatory requirements, our pipeline systems attempt to recontract or remarket their capacity at the maximum rates allowed under their tariffs. However, a pipeline system may discount capacity under certain circumstances in order to maximize revenue.

The weighted average remaining contract life as at January 31, 2009 for each of our pipeline systems is included earlier in Item I in the table in the “Our Pipeline Systems” section.

Great Lakes – For the year ended December 31, 2008, Great Lakes’ average contracted capacity compared to average design capacity was near 100 per cent (106 per cent of summer design day capacity). Great Lakes has long-term firm transportation contracts for 88 per cent of its average design capacity, as at January 31, 2009. Approximately two per cent of contracted capacity will expire by December 31, 2009 in the absence of extensions or renewals of this capacity.

Northern Border - Northern Border’s average contracted capacity compared to design capacity for the year ended December 31, 2008 was 90 per cent. Some of this capacity was sold at a discount to maximize overall revenue on the Port of Morgan, Montana to Ventura and Harper, Iowa portions of the pipeline. As of January 31, 2009, Northern Border had 60 per cent of its design capacity uncontracted beginning in the second quarter of 2009 through the remainder of 2009. Refer to Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” for further discussion.

Tuscarora – Tuscarora’s average contracted capacity for the year ended December 31, 2008 was 98 per cent. Tuscarora has firm transportation contracts for 100 per cent of its available capacity, as at January 31, 2009. This includes contracts with Sierra Pacific Power for approximately 75 per cent of the total available capacity, the majority of which expire on October 31, 2017.

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REGULATORY ENVIRONMENT

Government Regulation

Great Lakes, Northern Border, and Tuscarora are regulated under the Natural Gas Act of 1938, Natural Gas Policy Act of 1978, and Energy Policy Act of 2005, which give the FERC jurisdiction to regulate virtually all aspects of their businesses, including:

·                  transportation of natural gas;

·                  rates and charges;

·                  terms of service and service contracts with customers, including creditworthiness requirements;

·                  certification and construction of new facilities;

·                  extension or abandonment of service and facilities;

·                  accounts and records;

·                  depreciation and amortization policies;

·                  the acquisition and disposition of facilities;

·                  initiation and discontinuation of services; and

·                  standards of conduct for business relations with certain affiliates.

Rate Case, Great Lakes – Great Lakes’ last rate settlement, filed with the FERC on July 31, 2000, was approved by FERC Order issued October 26, 2000, and was effective November 1, 2000. The settlement continued the then existing base tariff rates, and reduced Great Lakes’ depreciation rate on transmission plant from 3.00 per cent to 2.75 per cent. Great Lakes continues to operate under rates established in that settlement. Great Lakes’ last rate settlement expired on October 31, 2005 with no requirement to file a new rate proceeding or settlement.

Rate Case, Northern Border – In November 2006, the FERC approved the settlement with Northern Border’s customers of its 2005 rate case effective January 1, 2007. The settlement established maximum long-term mileage-based rates and charges for transportation on Northern Border’s system. The settlement also provided for seasonal rates for short-term transportation services. Pursuant to the terms of the settlement, there is a moratorium on the parties to the settlement of raising any proceeding regarding Northern Border’s currently effective rates until January 1, 2010 and Northern Border must file a rate case by no later than December 31, 2012.

Cost and Revenue Study, Tuscarora – As a result of an obligation to file a cost and revenue study with the FERC, the Public Utilities Commission of Nevada and Sierra Pacific Power agreed to a settlement with Tuscarora, which was approved by the FERC in July 2006. The settlement resulted in a firm transportation rate of $0.40/decatherm per day (Dth/d) beginning June 1, 2006 and included a moratorium on all rate actions before the FERC by any party to the settlement until May 31, 2010. The settlement includes a moratorium by the settlement parties on rate actions related to expansion projects where Tuscarora proposes to price the expansion at the settlement rate.

Income Tax Allowance – In December 2007, the FERC issued an order which upheld and clarified its methodology for determining a partnership’s income tax allowance in a rate case. In the future, partnerships will be required to prove (1) that their partners have an actual or potential income tax liability, which is determined by the partner’s obligation to file a return that recognizes either a taxable gain or loss; (2) their partners’ marginal Federal income tax rates, if higher than the commission’s default rates of 28 per cent for individuals and 34 per cent for corporations; and (3) the partners’ marginal state income tax rates. If the FERC were to disallow a portion of the income tax allowance for one of our pipeline systems in a rate case, it may cause its recourse rate to be set at a level that is different, or lower, than the level otherwise in effect.

Composition of Proxy Groups for Rates of Return Determinations – In July 2007, the FERC issued a policy statement proposing to update its standards regarding the composition of proxy groups for determining the appropriate returns on equity (ROE) for natural gas and oil pipelines, which is used by pipelines to establish rates for services. On April 17, 2008, the FERC issued a policy statement (2008 Policy Statement) that allows master limited partnerships (MLPs) to be included in a proxy group used to determine a pipeline’s ROE. The 2008 Policy

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Statement provides that there should be no cap on the level of distributions included in the current Discounted Cash Flow (DCF) methodology for MLPs, but there should be an adjustment to the long-term growth rate used to calculate DCF for an MLP (halving the long-term GDP factor which has a one-third weighting in the total growth rate computation in the DCF methodology). On January 15, 2009, the FERC applied its policy statement in an order rejecting a contested Kern River Gas Transmission settlement in Docket No. RP04-274, finding that the 12.50 per cent return on equity in the settlement rates was excessive based on 2004 market data and would result in unjust and unreasonable rates. The FERC determined that Kern River’s ROE should be 11.55 per cent, which was set at the median of a proxy group that included, for the first time in a litigated pipeline rate proceeding, both master limited partnerships and corporations.

The impact of applying this new policy to each of our pipeline systems will not be known until each pipeline system files a rate case.

Energy Affiliates – In October 2008, the FERC issued Order No. 717, Standards of Conduct for Transmission Providers, which amended the regulations adopted on an interim basis in Order No. 690 to refocus the rules on the areas where there is the greatest potential for abuse; the day-to-day transmission transactions and operations that may involve marketing affiliates. This order identifies those affiliate relationships where there is the greatest potential and risk for undue discrimination and preference between a natural gas pipeline company and their marketing affiliates. The rule subjects the natural gas pipeline company to certain restrictions to function independently and not act as a conduit of transmission information to a marketing affiliate.

Promotion of a More Efficient Capacity Release Market Docket No. RM08-1 – On June 19, 2008, the FERC issued a Final Rule to modify capacity release regulations (Capacity Release Final Rule). The Capacity Release Final Rule, in addition to other items, allows market-based pricing for short-term capacity releases by shippers through a permanent lifting of the maximum rate cap on short-term capacity releases (of one year or less terms). The Capacity Release Final Rule was effective July 30, 2008.

While implementation of the Capacity Release Final Rule is not expected to have a significant impact on our pipeline systems, the Interstate Natural Gas Association of America (INGAA), of which our pipeline systems are members, filed on July 21, 2008 a request for rehearing of the Capacity Release Final Rule, contending that as the FERC removed the rate cap for short-term released capacity, it should also remove the rate cap for short-term pipeline capacity. INGAA notes that short-term released capacity and short-term pipeline capacity compete in the same market, and argues that removing the rate cap for short-term released capacity and maintaining the cap for short-term pipeline capacity results in a bifurcated and distorted short-term capacity market. On November 21, 2008, the FERC issued Order No. 712-A addressing requests for clarification and rehearing. In that order, the FERC denied INGAA’s request for rehearing and continued to maintain that the maximum rate ceilings for pipeline short-term transactions is necessary to protect against the potential exercise of market power. On January 15, 2009, INGAA filed an appeal of FERC’s order with the U.S. Court of Appeals-D.C. Circuit.

Compliance with Statutes, Regulations, and Orders Docket No. PL09-1-000 – On October 16, 2008, the FERC issued a “Policy Statement on Compliance” to provide additional guidance to the public on compliance with governing statutes, regulations and orders. The policy statement sets forth the following factors which will be considered when deciding to reduce or eliminate civil penalties for violations:  1) the role of senior management in fostering compliance; 2) effective preventive measures to ensure compliance; 3) prompt detection, cessation, and reporting of violations; and 4) remediation efforts.

Environmental and Safety Matters

All of our pipeline systems’ operations are subject to stringent and complex federal, state, and local laws and regulations governing environmental protection, including air emissions, water quality, wastewater discharges, and solid waste management. Such laws and regulations generally require natural gas pipelines to obtain and comply with a wide variety of environmental registrations, licenses, permits, and other approvals. These laws and regulations also can restrict or impact business activities in many ways, such as restricting the way wastes are handled or disposed of; requiring remedial action to mitigate pollution conditions that may be caused by its operations or that are attributable to former operators; and enjoining some or all of the operations of facilities deemed in non-compliance with permits issued pursuant to such environmental laws and regulations. Failure to

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comply with these laws and regulations may result in the assessment of administrative, civil and/or criminal penalties, the imposition of remedial requirements, and the issuance of orders enjoining future operations.

Pipeline Safety – Our pipeline systems are subject to U.S. Department of Transportation pipeline integrity management regulations. The Pipeline Safety Improvement Act requires pipeline companies to perform integrity assessments on pipeline segments that exist in densely populated areas or near specifically identified sites that are designated as high consequence areas. Pipeline companies are required to perform the integrity assessments within ten years of the date of enactment and perform subsequent integrity assessments on a seven-year cycle. All of our pipeline systems had performed the required assessments of 50 per cent of the highest priority high consequence areas by the end of 2007. Inspection of the remaining 50 per cent of high consequence areas as mandated by regulation is expected to be completed, as required, by 2012.

Waste Management – The operations of our pipeline systems generate hazardous and non-hazardous solid wastes that are subject to the federal Resource Conservation and Recovery Act (RCRA) and comparable state laws, which impose detailed requirements for the handling, storage, treatment and disposal of hazardous and non-hazardous solid wastes. For instance, RCRA prohibits the disposal of certain hazardous wastes on land without prior treatment, and requires generators of wastes subject to land disposal restrictions to provide notification of pre-treatment requirements to disposal facilities that are in receipt of these wastes. Generators of hazardous wastes also must comply with certain standards for the accumulation and storage of hazardous wastes, as well as with recordkeeping and reporting requirements applicable to hazardous waste storage and disposal activities.

Site Remediation - The Comprehensive Environmental Response, Compensation and Liability Act (CERCLA), also known as “Superfund,” and comparable state laws and regulations impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons considered to be responsible for the release of hazardous substances into the environment. These persons include the current and past owner or operator of the site where the release occurred, and anyone who disposed or arranged for the disposal of a hazardous substance released at the site. Under CERCLA, such persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies.

Our pipeline systems currently own or lease properties that for many years have been used for the transportation and compression of natural gas. These properties and the substances released on them may be subject to CERCLA, RCRA and analogous state laws. Under such laws, our pipeline systems could be required to remove any previously disposed wastes, including waste disposed of by prior owners or operators; remediate contaminated property, including groundwater contamination, whether from prior owners or operators or other historic activities or spills; or perform remedial closure operations to prevent future contamination.

Air Emissions - The Clean Air Act (CAA) and comparable state laws regulate emissions of air pollutants from various industrial sources, including compressor stations, and also impose various monitoring and reporting requirements. Such laws and regulations may require pre-approval for the construction or modification of certain projects or facilities expected to produce air emissions or result in an increase of existing air emissions; application for, and strict compliance with, air permits containing various emissions and operational limitations; or the utilization of specific emission control technologies to limit emissions.

On February 2, 2009, Northern Border received a Notice of Violation from the United States Environmental Protection Agency alleging that Northern Border was in violation of certain regulations pursuant to the Clean Air Act regarding a compressor station on its system. At this time, Northern Border is unable to reasonably estimate the cost of any associated corrective action or the possibility or amount of any penalty, but does not expect such amounts to be material to its financial condition.

Water Discharges - The Clean Water Act (CWA) and analogous state laws impose strict controls with respect to the discharge of pollutants, including spills and leaks of oil and other substances, into waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the Environmental Protection Agency or an analogous state agency. The CWA and regulations implemented thereunder also prohibit the discharge of dredge and fill material into regulated waters, including wetlands, unless authorized by an appropriately issued permit. Federal and state regulatory agencies may impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the CWA and analogous state laws and regulations.

Activities on Federal Lands - Natural gas transportation activities are subject to the National Environmental Policy Act (NEPA). NEPA requires federal agencies, including the Department of the Interior, to evaluate major agency

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actions having the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an Environmental Assessment that assesses the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed Environmental Impact Statement that may be made available for public review and comment. The current activities of our pipeline systems, as well as any proposed plans for future activities, on federal lands are subject to the requirements of NEPA.

Other Laws and Regulations – The U.S. Congress or other federal government agencies may create legislation or regulations to reduce emissions of greenhouse gasses. In addition, several states have declined to wait on Congress to develop and implement climate control legislation and have already taken legal measures to reduce emissions of greenhouse gases.

Homeland Security – The Department of Homeland Security Appropriations Act of 2007 required the Department of Homeland Security to issue regulations under the Chemical Facility Anti-Terrorism Standards (CFATS) establishing risk-based performance standards for the security of chemical and industrial facilities, including oil and gas facilities that were deemed to present high levels of security risk. Our pipeline systems are not subject to the requirements of these regulations under CFATS.

The Transportation Security Administration (TSA) began in January 2009 a critical facility identification process of pipeline systems, which will include our pipeline systems. The TSA has released a second draft of the Pipeline Security Guidelines, which is likely to become regulation in 2009 or 2010. These guidelines distinguish between baseline security requirements for all pipeline facilities and enhanced measures for identified critical facilities. If our pipeline systems are deemed to be critical facilities, we do not anticipate additional costs related to compliance based on current draft guidelines.

Title to Properties

Our pipeline systems hold all rights, titles and interests in their respective pipeline systems. With respect to real property, our pipeline systems own sites for compressor stations, meter stations, pipeline field offices, microwave towers and a corporate office. Our pipeline systems also derive interests from leases, easements, rights-of-way, permits and licenses from landowners or governmental authorities permitting land use for construction and operation of their pipelines.

Great Lakes - Approximately 74 miles of Great Lakes’ pipeline system are located within the boundaries of three Indian reservations: the Leech Lake Chippewa Indian Reservation and the Fond du Lac Chippewa Indian Reservation in Minnesota, and the Bad River Chippewa Indian Reservation in Wisconsin. In 1968, Great Lakes obtained right-of-way across allotted lands located within each of the reservation’s boundaries. All of the allotted lands are subject to a 50 year easement granted by the Bureau of Indian Affairs (BIA) for and on behalf of the individual Indian owners or the reservations. These tracts are subject to right-of-way permits issued by the BIA that expire in 2018. Also, the Great Lakes pipeline crosses approximately 1,000 ft. in two tracts in Lower Michigan, which are located within the Chippewa Indian Reservation, under perpetual easements.

Northern Border - Approximately 90 miles of Northern Border’s pipeline system are located within the boundaries of the Fort Peck Indian Reservation in Montana. In 1980, Northern Border entered into a pipeline right-of-way lease with the Fort Peck Tribal Executive Board on behalf of the Assiniboine and Sioux Tribes of the Fort Peck Indian Reservation. This pipeline right-of-way lease granted Northern Border the right to construct and operate its pipeline on certain tribal lands. The pipeline right-of-way lease expires in 2011, with an option to renew the pipeline right-of-way lease through 2061. In conjunction with obtaining a right-of-way across tribal lands located within the exterior boundaries of the Fort Peck Indian Reservation, Northern Border also obtained right-of-way across allotted lands located within the reservation boundaries. Most of the allotted lands are subject to a perpetual easement granted by the BIA for and on behalf of the individual Indian owners or obtained through condemnation. Several tracts are subject to a right-of-way grant that expires in 2015.

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Insurance

The Partnership’s operations and activities are insured under TransCanada insurance programs, including property insurance, liability, automobile liability and workers compensation, in amounts which management believes are reasonable and appropriate.

Employees

The Partnership does not have any employees. In addition, none of our pipeline systems directly employ any of the persons responsible for managing or operating the pipeline systems or for providing them with services related to their day-to-day business affairs. Subsidiaries of TransCanada are the operators of our pipeline systems, in addition to providing services to the Partnership.

AVAILABLE INFORMATION

Our website is www.tcpipelineslp.com. We make available free of charge, on or through our website, our annual, quarterly and current reports, and any amendments to those reports, as soon as reasonably practicable after electronically filing or furnishing such reports with the Securities and Exchange Commission (SEC). Information contained on our web site is not part of this report.

Item 1A.  Risk Factors

Cautionary Statement Regarding Forward-Looking Information

A number of statements made by TC PipeLines, LP in this Form 10-K filing 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 current beliefs as well as assumptions made by and information currently available to the Partnership. These statements reflect the Partnership’s current views with respect to future events. The Partnership assumes no obligation to update any such forward looking statements to reflect events or circumstances occurring after the date hereof. 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, including the risk factors discussed below, 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.

Limited partner interests are inherently different from the capital stock of a corporation, although many of the business risks to which we are subject are similar to those that would be faced by a corporation engaged in a similar business. All of the information included in this report and any subsequent reports we may file with the SEC or make available to the public should be carefully considered and evaluated before investing in any securities issued by us.

Each of the risks and uncertainties described below could lead to events or circumstances that may have a material adverse effect on our business, financial condition, results of operations and cash flows, including our ability to make distributions to our unitholders.

The risks referred to herein disclose risks inherent in the Partnership and our pipeline systems.

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Risks Inherent in Our Business

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 report profits.

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;

·                  the level of capital expenditures made by our pipeline systems;

·                  the required principal and interest payments on our debt, retirement of debt and other liabilities including cost of acquisitions;

·                  the amount of cash distributed to us by the entities in which we own a non-controlling interest;

·                  our ability to borrow funds and access capital markets including the issuance of debt and equity securities; and

·                  restrictions on distributions contained in debt agreements.

We are dependent on our pipeline systems to generate sufficient cash to enable us to pay distributions.

The amount of cash we have quarterly to distribute to our common unitholders depends upon numerous factors, most of which are beyond our control and the control of our general partner, including:

·                  the rates charged and the volumes under contract for the transportation services of our pipeline systems;

·                  the quantities of natural gas available for transport and the demand for natural gas;

·                  legislative or regulatory action affecting demand for and supply of natural gas, and the rates our pipeline systems are allowed to charge in relation to their operating costs;

·                  the level of our pipeline systems’ operating costs; and

·                  the creditworthiness of our pipeline systems’ shippers.

The recent global economic and financial market crisis has had and may continue to have a negative effect on our business.

The recent global economic and financial market crisis has caused, among other things, a general tightening in the credit markets, lower levels of liquidity, increases in the rates of default and bankruptcy, lower consumer and business spending, lower consumer net worth, and reduced energy demand. As a result of the continued economic weakness, there has been less demand for natural gas by residential, industrial and other users, which could have a negative effect on the business of our pipeline systems and our results of operations, financial condition and liquidity. Many natural gas producers, natural gas marketing companies, and end users have been negatively affected by the current economic conditions. Current or potential shippers may be unable to fund contracts or meet the creditworthiness requirements of our pipeline systems or they may reduce the amount or length of their transportation commitments on our pipeline systems, all of which could impact demand for transportation services on our pipeline systems, and may cause reduced revenue and increased customer payment delays or defaults. We are also limited in our ability to reduce costs to offset the results of a prolonged or severe economic downturn given the high percentage of fixed costs associated with our operations.

The timing and nature of any recovery in the credit and financial markets remains uncertain, and there can be no assurance that market conditions will improve in the near future or that our results will not be materially and adversely affected. Such conditions make it difficult to forecast operating results, make business decisions and identify and address material business risks. The foregoing conditions may also impact the valuation of certain long-lived or intangible assets, including goodwill, that are subject to impairment testing, potentially resulting in impairment charges which may be material to our financial condition or results of operations.

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If we do not identify opportunities for accretive growth through organic growth projects or acquisitions, or our pipeline systems do not successfully complete expansion projects or make and integrate acquisitions that are accretive, our future growth may be limited.

A principal focus of our strategy is to continue to grow the cash distributions on our units by expanding our business. Our ability to grow depends on our ability to undertake acquisitions and organic growth projects, and the ability of our pipelines systems to complete expansion projects and make and integrate acquisitions that result in an increase in cash per unit generated from operations.

The long-term financial conditions of our pipeline systems are dependent on the continued availability of Western Canadian natural gas for import into the U.S. and the market demand for these volumes. Competition from pipelines that deliver natural gas from other supply sources to our pipeline systems’ market areas could cause our pipeline systems to discount their rates or otherwise experience a reduction in their revenues.

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 our pipeline systems. High exploration and production costs, low prices for natural gas, regulatory limitations such as royalty frameworks, or the lack of available capital for these projects could adversely affect the development of additional reserves in Western Canada and the production in the WCSB. The current slowdown of the economy and restricted capital markets are negatively impacting development of natural gas reserves, which is expected throughout 2009.

Net WCSB flows to markets depend in part on the internal demand for Canadian natural gas which may increase as a result of increased demand for electricity generation and other industrial requirements, including the development of oil sands projects, which may require substantial amounts of natural gas. This higher internal demand may reduce the amount of gas available for downstream markets. In the longer term, a portion of the Alberta hub gas supply may come from proposed gas pipelines from the North Slope of Alaska and the Mackenzie Delta of Canada and from the development of newly discovered natural gas plays such as the Montney and Horn River shale plays in Western Canada. Cancellation or delays in the construction of such pipelines or such projects could adversely affect the net WCSB flows to markets in the long-term.

If the availability of Alberta hub natural gas was to decline, existing shippers on our pipeline systems may be unlikely to extend their contracts and our pipeline systems 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 our pipeline systems.

Customers may not extend their contracts or contract for transportation if the cost of delivered natural gas from other producing regions into the markets served by our pipeline systems is lower than the cost of natural gas delivered by our pipeline systems. Our pipeline systems face increased competition from other pipelines that provide access for our shippers to capacity from the U.S. Rocky Mountain Region. The Rockies Express Pipeline owned by Rockies Express Pipeline LLC is being constructed in two phases and the planned terminus is in Clarington, Ohio. REX West is completed and is currently delivering gas to interconnects in the Midwest region. The full in-service of REX West in May 2008 has resulted in significant downward pressure on natural gas prices in the Mid-Continent Region, and is having a negative impact on demand for Northern Border’s transport and as REX extends east it may have an impact on Great Lakes in the future.

REX East is planned to extend from Audrain County, Missouri to Clarington in Monroe County, Ohio. Once in-service, REX East could improve the competitive position of Canadian supply with Mid-Continent sourced gas, potentially mitigating some of the excess supply in the Mid-Continent market. REX East will compete in some of Great Lakes’ markets, but will also potentially create demand for Great Lakes’ transportation of natural gas from REX East seeking access to and from storage locations in Michigan. It is now anticipated that the partial in-service and full in-service of REX East will occur in the second and fourth quarters of 2009, respectively. Although there can be no assurance on the timing or impact of REX East, we believe that any positive impact for Northern Border in the market it serves will not occur until 2010.

An increase in competition in the key markets served by our pipeline systems could arise from new ventures or expanded operations from existing competitors. The combination of growing supply from the Rockies and shale developments reaching the Chicago market region through both new and available pipeline capacity and demand

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destruction from the economic crisis has the potential to maintain competitive pressures on WCSB supply into the Midwest. Northern Border is fully contracted on its Eastern system that deliveries gas to Chicago; however, any reduction in flows to this market will impact the supply and demand fundamentals at the Ventura market.

Our financial performance depends to a large extent on the capacity contracted on our pipeline systems. Decreases in the volumes transported by our pipeline systems, whether caused by supply or demand factors in the markets these pipeline systems serve, competition or otherwise, can directly and adversely affect our business, financial position, results of operations, and ability to make distributions.

Our pipeline systems may not be able to maintain existing customers or acquire new customers when the current shipper contracts expire or customers may recontract for shorter periods or at less than maximum rates.

The ability to extend and replace contracts on terms comparable to prior contracts or on any terms at all could be adversely affected by factors, including:

·                  the supply of natural gas in Canada and the U.S.;

·                  competition from alternative sources of supply in the U.S.;

·                  competition from other pipelines, including their transportation rates or through their access to upstream supplies, as well as the proposed construction by other companies of additional pipeline capacity;

·                  the price of, and demand for, natural gas in markets served by our pipeline systems;

·                  the liquidity and willingness of shippers to contract for transportation services; and

·                  regulatory actions.

Ongoing changes in these factors and customers’ ability to adjust to changing market conditions may cause Great Lakes and Northern Border to sell a significant portion of available capacity on a short-term basis. The weighted average lives of Great Lakes’ and Northern Border’s contracts have generally declined over time. As of January 31, 2009, the weighted average remaining lives of Great Lakes’ and Northern Border’s contracts were 2.7 years and 2.1 years, respectively. Additionally, if the forward natural gas basis differentials do not support maximum rates, they may sell portions of their capacity at discounted rates. Any inability by Great Lakes and Northern Border to renew existing contracts at maximum rates or at all may have an adverse impact on their revenues and, as a result, cash distributions made to us.

If any significant shipper fails to perform its contractual obligations, our pipeline systems’ respective cash flows and financial condition could be adversely impacted.

At any time, each of our pipeline systems may have customers that account for more than ten per cent of their revenue. The loss of all or even a portion of the revenues associated with these customers, as a result of competition, creditworthiness or otherwise, could have a material adverse effect on the financial condition, results of operations and cash flows of our pipeline systems, unless they were able to contract for comparable volumes from other customers at favorable rates.

Sierra Pacific Power is Tuscarora’s largest shipper, with firm contracts for approximately 75 per cent of its capacity. NV Energy Inc. (formerly known as Sierra Pacific Resources) and its subsidiary, Sierra Pacific Power, have non-investment grade credit ratings.

Our pipeline systems are subject to regulation by agencies, including the FERC, which could have an adverse impact on our ability to establish transportation rates that would allow recovery of the full cost of operating our pipeline systems, including a reasonable return, and our ability to make distributions.

Under the Natural Gas Act (NGA), interstate transportation rates must be just, reasonable and not unduly discriminatory. Our pipeline systems are subject to extensive regulation by the FERC, the United States Department of Transportation, and other federal, state and local regulatory agencies. Regulatory actions taken by these agencies have the potential to adversely affect our pipeline systems’ profitability. Federal regulation extends to such matters as:

·                  rates and charges;

·                  operating terms and conditions of service including creditworthiness requirements;

·                  types of services our pipeline systems may offer to their customers;

·                  construction of new facilities;

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·                  extension or abandonment of service and facilities;

·                  accounts and records;

·                  depreciation and amortization policies;

·                  income tax allowance policies;

·                  the acquisition and disposition of facilities;

·                  initiation and discontinuation of services;

·                  standards of conduct business relations with certain affiliates; and

·                  the integrity and safety of our pipeline systems and related operations.

Given the extent of regulation by the FERC and potential changes to regulations, we cannot predict:

·                  the likely federal regulations under which our pipeline systems will operate in the future;

·                  the effect that regulation will have on financial position, results of operations and cash flows of our pipeline systems and ourselves; or

·                  whether our cash flow will be adequate to make distributions to unitholders.

Great Lakes’ last rate settlement expired on October 31, 2005 with no requirement to file a new rate proceeding or settlement. Northern Border and Tuscarora are currently operating under rate settlements which preclude a party to the rate settlements from bringing any rate actions prior to December 31, 2009 and May 31, 2010, respectively. Northern Border is required to file a new rate proceeding before December 31, 2012.

Action by the FERC on currently pending matters as well as matters arising in the future could adversely affect our pipeline systems’ abilities to establish or charge rates that would cover future increase in their costs, or even to continue to collect rates that cover current costs, including a reasonable return. We cannot assure unitholders that our pipeline systems will be able to recover all of their costs through existing or future rates.

Should our pipeline systems fail to comply with all applicable FERC administered statutes, rules, regulations and orders, our pipeline systems could be subject to substantial penalties and fines. Under the Energy Policy Act of 2005, the FERC has civil penalty authority under the NGA to impose penalties for current violations of up to $1.0 million per day for each violation.

Finally, we cannot give any assurance regarding the future regulations under which our pipeline systems will operate their natural gas transportation businesses or the effect such regulations could ultimately have on our financial condition, results of operations and cash flows.

If our pipeline systems do not maintain their respective rate bases, the amount of revenue attributable to the return on the rate base they collect from their shippers will decrease over time.

Our 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. In the absence of additions to the rate base through capital expenditures, the amount they collect from customers, as a result of a rate case, decreases as the rate base declines due to, among other things, depreciation and amortization.

Our pipeline systems’ pipeline integrity testing programs and any necessary pipeline repairs, or preventative or remedial measures may impose significant costs and liabilities.

The U.S. Department of Transportation has adopted regulations that require pipeline operators to develop integrity management programs to comprehensively evaluate their pipelines, and take measures to protect pipeline segments located in what the regulations refer to as “high consequence areas,” where a leak or rupture could do the most harm. The final rule resulted from the enactment of the Pipeline Safety Improvement Act of 2002. At this time, we cannot predict the total costs of compliance with this rule because those costs will depend on the extent of the pipeline testing and any subsequent repairs found to be necessary. Our pipeline systems completed the required 50 per cent inspection of their respective pipelines highest priority highest consequence segments of lines by the end of 2007. Inspection of the remaining 50 per cent of high consequence areas as mandated by regulation is expected to be completed, as required, by 2012. After that point, the inspection of high consequence areas is required to reoccur every seven years. Once 100 per cent of our pipeline systems’ high consequence areas have been inspected, we will have a better understanding of the total ongoing costs. Our pipeline systems will continue their pipeline integrity testing programs to assess and maintain the integrity of the pipelines. The results of this work could cause our

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pipeline systems to incur significant and unanticipated capital and operating expenditures for repairs or upgrades deemed necessary to ensure the continued safe and reliable operation of their pipelines. Additionally, any failure to comply with these regulations could subject our pipeline systems to penalties and fines. If these costs were significantly higher than estimated, our cash available for distribution may be correspondingly reduced.

Our pipeline systems’ operations are regulated by federal, state and local agencies responsible for environmental protection and operational safety, and costs of environmental compliance and the costs of environmental liabilities could exceed our estimates.

Risks of substantial costs and liabilities are inherent in pipeline operations and each of our pipeline systems 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 our pipeline systems’ operations. Moreover, new, stricter environmental laws, regulations or enforcement policies could be implemented that significantly increase our pipeline systems’ compliance costs or the cost of any remediation of environmental contamination that may become necessary, and these costs could be material. For instance, we may be required to obtain and maintain permits and approvals issued by various federal, state and local governmental authorities; limit or prevent releases of materials from our operations in accordance with these permits and approvals; and install pollution control equipment. Also, under certain environmental laws and regulations, we may be exposed to potentially substantial liabilities for any pollution or contamination that may result from our operations.

The U.S. Congress is actively considering federal legislation to reduce emissions of “greenhouse gases” (including carbon dioxide and methane). Several states of the U.S. have already taken legal measures to reduce emissions of greenhouse gases. At this time, it is unclear what our pipeline systems future environmental compliance costs relating to greenhouse gases will be. Various federal and state legislative proposals have been made over the last several years and it is possible that legislation will be enacted in the future that could negatively impact the operations of our pipeline systems and our financial results. The level of such impact will likely depend upon whether any of our pipeline systems’ facilities will be directly responsible for compliance with any adopted program; whether cost containment measures will be available; the ability of our pipeline systems to recover compliance costs from their customers; and the manner in which allowances are provided. At the federal regulatory level, the U.S. Environmental Protection Agency (EPA) has requested public comments on the potential regulation of greenhouse gases under the Clean Air Act. It is uncertain whether the EPA will proceed with adopting final rules or whether the regulation of greenhouse gases will be addressed in federal and state legislation.

It is uncertain what impact these actions might have on our pipeline systems until further definition is known; there is risk that such future measures could result in changes to the operations of our pipeline systems and to the consumption and demand for natural gas. Changes to the operations of our pipeline systems could include increased costs to (i) operate and maintain our facilities; (ii) install new emission controls on our facilities; (iii) construct new facilities; and (iv) administer and manage any greenhouse gas emissions reduction program that may be applicable to our operations. While we may be able to include some or all of the costs associated with our environmental liabilities and environmental compliance, including future compliance with greenhouse gas laws and regulations, in the rates charged by our pipeline systems, their ability to recover such costs is uncertain and may depend on events beyond our control including the outcome of future rate proceedings before the FERC and the provisions of any final legislation.

One of our pipeline systems, Northern Border, received a Notice of Violation (NOV) from the EPA alleging that Northern Border was in violation of certain regulations pursuant to the Clean Air Act regarding a compressor station on its system. As provided by the NOV, Northern Border has requested a conference with the EPA to discuss the violations alleged in the NOV. At this time, Northern Border is unable to reasonably estimate the cost of any associated corrective action or the possibility or amount of any penalty.

Our pipeline systems’ indebtedness may limit their ability to borrow additional funds, make distributions to us or capitalize on business opportunities.

As of December 31, 2008, Great Lakes, Northern Border and Tuscarora had $430.0 million, $631.0 million and $61.8 million of debt outstanding, respectively. Of the debt outstanding, Great Lakes, Northern Border and Tuscarora have $19.0 million, $200.0 million and $4.4 million of debt maturing in 2009, respectively. Their respective levels of debt could have important consequences to Great Lakes, Northern Border and Tuscarora, including the following:

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·                  their ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes may be impaired or such financing may not be available on favorable terms;

·                  they will need a portion of their cash flow to make interest payments on the debt, reducing the funds that would otherwise be available for operations, future business opportunities and distributions to us, which will reduce our ability to make distributions to our unitholders;

·                  their debt level may make them more vulnerable to competitive pressures or a downturn in our business or the economy generally; and

·                  their debt level may limit their flexibility in responding to changing business and economic conditions.

Our pipeline systems’ ability to service their debt will depend upon, among other things, future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond their control.

In addition, under the terms of these financing arrangements, our pipeline systems are prohibited from making cash distributions during an event of default under their debt instruments. Under Great Lakes’ debt instruments, Great Lakes has limitations on the level of indebtedness and has other restrictions, including a general prohibition against liens on pipeline facilities. Provisions in Northern Border’s debt instruments limit its ability to incur indebtedness and engage in specific transactions. This could reduce its ability to capitalize on business opportunities that arise in the course of its business. 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. In addition, the Partnership’s third party credit facility requires us to maintain certain financial ratios and contains restrictions on incurring additional debt and making distributions to unitholders.

The current capital and credit market conditions may adversely affect the Partnership’s and/or our pipeline systems’ access to capital and cost of capital.

Access to capital markets is important to the Partnership to enable it to execute its business strategies, which include seeking opportunities to undertake accretive acquisitions and organic growth projects, and maximize the value of our existing portfolio of pipeline systems. Access to capital markets is also important to our pipeline systems’ ability to meet liquidity and capital resource requirements. Additionally, market conditions will impact the ability of our pipeline systems to access capital markets for debt under reasonable terms. Northern Border expects to refinance $200.0 million of Senior Notes in 2009 with a combination of equity contributions from its partners, fixed-rate and short-term variable-rate debt.

Recently, the general economic and capital market conditions in the United States and other parts of the world have deteriorated significantly and have adversely affected access to capital and increased the cost of capital. If recent conditions in the U.S. capital markets continue or become worse, the Partnership’s and our pipeline systems’ future cost of debt and equity capital, and future access to capital markets could be adversely affected.

We do not own a controlling interest in Great Lakes or Northern Border and we may be unable to cause certain actions to take place unless the other partner agrees. As a result, we will be unable to control the amount of cash we will receive from those operations and we could be required to contribute significant cash to fund our share of their operations. If we fail to make these contributions our ownership interest would be diluted.

The major policies of Great Lakes and Northern Border are established by each of their Management Committees.

Great Lakes’ Management Committee consists of up to six members, three of whom are designated by us and three of whom are designated by TransCanada. Currently the committee consists of four appointed members, two of whom are designated by us and two of whom are designated by TransCanada. All decisions by the Management Committee require unanimous consent. An Executive Committee consists of up to three members: one Partnership Committee Member, one TransCanada Committee Member and the Great Lakes’ President, a non-voting member. Currently this committee consists of two appointed members: one Partnership Committee Member and one TransCanada Committee Member, who also serves as the Great Lakes President. The Executive Committee has all of the powers of the Management Committee in the management of Great Lakes’ business. Because of these provisions, without the concurrence of TransCanada, we may be unable to cause Great Lakes to take or not to take certain actions, even though those actions may be in the best interest of us or Great Lakes.

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Northern Border’s Management Committee consists of four members, two of whom are designated by us and two of whom are designated by an affiliate of ONEOK Partners. The Management Committee requires the affirmative vote of a majority of the partners’ ownership interests to act on most activities. Certain activities require the unanimous consent of the committee, such as the filing of the application for regulatory authority to construct and operate new facilities and any changes to the cash distribution policy. Because of these provisions, without the concurrence of ONEOK, we may be unable to cause Northern Border to take or not to take certain actions, even though those actions may be in the best interest of us or Northern Border.

Great Lakes and Northern Border may require us to make additional capital contributions. Our funding of these capital contributions would reduce the amount of cash otherwise available for distribution to our unitholders. Additionally, in the event we elect not to, or are unable to, make a required capital contribution to Great Lakes or Northern Border, our ownership interest would be diluted.

Our pipeline systems’ operations are subject to operational hazards and unforeseen interruptions, which could adversely affect their businesses and for which they may not be adequately insured.

Our pipeline systems’ operations are subject to all of the risks and hazards typically associated with the operation of natural gas transportation pipeline systems. Operating risks include, but are not limited to, leaks, pipeline ruptures, the breakdown or failure of equipment or processes, and the performance of pipeline facilities below expected levels of capacity and efficiency. Other operational hazards and unforeseen interruptions include adverse weather conditions, accidents, the collision of equipment with our pipeline systems’ pipeline facilities (which may occur if a third party were to perform excavation or construction work near these facilities), and catastrophic events such as explosions, fires, earthquakes, floods or other similar events beyond our pipeline systems’ control. It is also possible that our pipeline systems’ infrastructure facilities could be direct targets or indirect casualties of an act of terrorism. A casualty occurrence might result in injury or loss of life, extensive property damage or environmental damage. Liabilities incurred, and interruptions to the operation of our pipeline systems’ facilities, for short or extended durations, caused by such an event, could reduce revenues generated by our pipeline systems and increase expenses, thereby impairing their ability to meet their obligations. Insurance proceeds may not be adequate to cover all liabilities or expenses incurred or revenues lost. Should one of our pipeline systems experience such an event, it may have an adverse impact on our results of operations and cash flow.

Our pipeline systems do not own all of the land on which their pipelines and facilities are located, which could disrupt their operations.

Our pipeline systems do not own all of the land on which their pipelines and facilities are located, and they are, therefore, subject to the risk of increased costs to maintain necessary land use. They obtain the rights to construct and operate certain of our pipelines and related facilities on land owned by third parties, governmental agencies and Indian reservations for a specific period of time. Their loss of these rights, through their inability to renew right-of-way contracts or otherwise, or increased costs to renew such rights, could have a material adverse effect on their financial condition, results of operations and cash flows.

If we were to lose TransCanada’s management expertise, we would not have sufficient stand-alone resources to operate.

TransCanada, through wholly-owned subsidiaries, is the operator of all our pipeline systems. We do not presently have sufficient stand-alone management resources to operate without services provided by TransCanada. Additionally, should we lose the services of TransCanada, we may not be able to replace those services for the same cost and our costs could increase. Further, we would not be able to evaluate potential growth opportunities and successfully complete acquisitions without TransCanada’s resources.

Our pipeline systems may undertake or be dependent upon expansion and build projects which involve significant risks that could adversely affect our business.

Our pipeline systems have expansion and new build projects planned or underway, including Northern Border’s $18.0 million Des Plaines Project. Additionally, expansion and new build projects, such as the Bison Project that would potentially deliver gas to Northern Border, are subject to a variety of factors outside their control. Factors such as weather, natural disasters, delays in obtaining key materials and difficulties in obtaining permits and rights-of-way or other regulatory approvals, as well as the performance by third party contractors may result in increased costs or delays in construction. Cost overruns or delays in completing a project could result in reduced transportation rates and liquidated damages to customers, as well as lost revenue opportunities. In addition, we cannot be certain

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that, if completed, these projects will perform in accordance with our expectations. Each of these risks could have a material adverse effect on our results of operations and cash flows.

Risks Inherent In an Investment in the Partnership

The Partnership’s indebtedness may limit its ability to borrow additional funds, make distributions or capitalize on business opportunities. The conditions of the U.S. and international credit markets may adversely affect our ability to obtain credit or draw on our current credit facility.

As of December 31, 2008, the Partnership had $536.8 million of debt outstanding, including the revolving credit and term loan agreement (Senior Credit Facility) and Senior Notes (2007 - $573.4 million). This substantial level of debt could have important consequences to the Partnership including the following:

·                  our ability to obtain additional financing, if necessary, for working capital, acquisitions or other purposes may be impaired or such financing may not be available on favorable terms;

·                  we will need a portion of our cash flow to make interest payments on the debt, reducing the funds that would otherwise be available for operations, future business opportunities and distributions to our unitholders; and

·                  our debt level may limit our flexibility in responding to changing business and economic conditions.

Our ability to service our debt will depend upon, among other things, the future financial and operating performance of our pipeline systems, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond our control.

If the financial institutions that have extended credit commitments to us and our pipeline systems are adversely affected by the conditions of the U.S. and international capital markets, they may become unable to fund borrowings under their credit commitments, which could have a material and adverse impact on our financial condition and our ability to borrow additional funds, if needed.

In addition, our credit facilities contain restrictive covenants that may prevent us from engaging in certain transactions that are deemed beneficial. These agreements require us to comply with various affirmative and negative covenants and maintaining certain financial ratios. There are restrictions and covenants with respect to:

·                  entering into mergers, consolidations and sales of assets;

·                  granting liens;

·                  material amendments to TC PipeLines’ partnership agreement;

·                  incurring additional debt; and

·                  distributions to unitholders.

Any future debt may contain similar restrictions.

Increases in interest rates and general volatility in the financial markets and economy could adversely affect our business, our common unit price, results of operations, cash flows and financial condition.

As of December 31, 2008, TC PipeLines had $475.0 million outstanding under the Senior Credit Facility (2007 - $507.0 million), all of which was at variable interest rates. As a result, our results of operations, cash flows and financial condition could be materially adversely affected by significant increases in interest rates. From time to time, we may enter into interest rate swap arrangements, which decrease our exposure to variable interest rates. At December 31, 2008, 100 per cent of the variable interest rate exposure related to the Partnership’s $475.0 million of debt outstanding under the Senior Credit Facility was mitigated by fixed interest rate swap arrangements. However, the interest rate option on $100.0 million of the Partnership’s debt expires in May 2009.

An increase in interest rates may also cause a corresponding decline in demand for equity investments, in general, and in particular for yield-based equity investments such as our common units. Any such reduction in demand for our common units resulting from other more attractive investment opportunities may cause the trading price of our common units to decline.

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We do not have the same flexibility as other types of organizations to accumulate cash and equity to protect against illiquidity in the future.

Unlike a corporation, our partnership agreement requires us to make quarterly distributions to our unitholders of all available cash, reduced by any amounts of reserves for commitments and contingencies, including capital and operating costs and debt service requirements. The value of our units and other limited partner interests may decrease in direct correlation with decreases in the amount we distribute per unit. Accordingly, if we experience a liquidity problem in the future, we may not be able to recapitalize by issuing more equity.

Unitholders have limited voting rights and do not control our general partner.

The general partner is our manager and operator. Unlike the holders of common stock in a corporation, holders of common units have only limited voting rights on matters affecting our business. Unitholders have no right to elect our general partner on an annual or other continuing basis. Our general partner may not be removed except by the vote of the holders of at least 662/3 per cent of the outstanding units and upon the election of a successor general partner by the vote of the holders of a majority of the outstanding common units. These required votes would include the votes of units owned by our general partner and its affiliates. The ownership of an aggregate of approximately 32 per cent of the outstanding units by our general partner and its affiliates has the practical effect of making removal of our general partner difficult.

In addition, the partnership agreement contains some provisions that may have the effect of discouraging a person or group from attempting to remove our general partner or otherwise change our management. If our general partner is removed as our general partner under circumstances where cause does not exist and units held by our general partner and its affiliates are not voted in favor of that removal:

·                  any existing arrearages in the payment of the minimum quarterly distributions on the common units will be extinguished; and

·                  our general partner will have the right to convert its general partner interests and its incentive distribution rights into common units or to receive cash in exchange for those interests.

These provisions may diminish the price at which the common units will trade under some circumstances. The partnership agreement also contains provisions limiting the ability of unitholders to call meetings of unitholders or to acquire information about our operations, as well as other provisions limiting the unitholders’ ability to influence the manner or direction of management. Further, if any person or group other than our general partner or its affiliates or a direct transferee of our general partner or its affiliates acquires beneficial ownership of 20 per cent or more of any class of units then outstanding, that person or group will lose voting rights with respect to all of its units. As a result, unitholders will have limited influence on matters affecting our operations, and third parties may find it difficult to attempt to gain control of us, or influence our activities.

We may issue additional common units without unitholder approval, which would dilute the existing unitholders’ interest. In addition, issuance of additional common units may increase the risk that we will be unable to pay the full minimum quarterly distribution on all common units.

Our general partner can cause us to issue additional common units, without the approval of unitholders, in the following circumstances:

·                  under employee benefit plans, if any;

·                  upon conversion of the general partner interests and incentive distribution rights into common units as a result of the withdrawal of our general partner; or

·                  in connection with acquisitions or capital improvements that are accretive to our cash flow on a per unit basis.

In addition, we may issue an unlimited number of limited partner interests of any type without the approval of the unitholders. Based on the circumstances of each case, the issuance of additional common units or securities ranking senior to or on a parity with the common units may dilute the value of the interests of the then-existing holders of common units in the net assets of TC PipeLines and dilute the interests of unitholders in distributions by TC PipeLines. Our partnership agreement does not give the unitholders the right to approve the issuance by us of equity securities ranking junior to the common units at any time.

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Any increase in the number of outstanding common units will increase the percentage of the aggregate minimum quarterly distribution payable to the common unitholders, which will in turn have the effect of increasing the risk that we will be unable to pay the minimum quarterly distribution in full on all the common units.

Unitholders may not have limited liability in some circumstances.

The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some states. If it were to be determined that:

·                  TC PipeLines had been conducting business in any state without compliance with the applicable limited partnership statute, or

·                  the right or the exercise of the right by the unitholders as a group to remove or replace our general partner, to approve some amendments to the partnership agreement or to take other action under the partnership agreement constituted participation in the “control” of TC PipeLines’ business,

then unitholders could be held liable in some circumstances for TC PipeLines’ obligations to the same extent as a general partner. In addition, under some circumstances a unitholder may be liable to TC PipeLines for the amount of a distribution for a period of three years from the date of the distribution.

Our general partner has a limited call right that may require unitholders to sell their common units at an undesirable time or price.

If our general partner and its affiliates, who currently own an aggregate of approximately 30.7 per cent of our common units, come to own 80 per cent or more of the common units, the general partner will have the right, but not the obligation, which it may assign to any of its affiliates or us, to acquire all of the remaining common units held by unaffiliated persons at a price generally equal to the then current market price of the common units. As a consequence, unitholders may be required to sell their common units at a time when they may not desire to sell them or at a price that is less than the price they would desire to receive upon sale. Unitholders may also incur a tax liability upon a sale of their units.

Without the consent of each unitholder, Great Lakes, Northern Border or Tuscarora might be converted into a corporation, which would result in Great Lakes, Northern Border or Tuscarora, as the case may be, being subject to corporate income taxes.

If it becomes unlawful to conduct the business of Great Lakes, Northern Border or Tuscarora as a partnership and some other conditions are satisfied, the business and assets of Great Lakes, Northern Border or Tuscarora, as the case may be, will automatically be transferred to a corporation without the vote or consent of unitholders. Therefore, unitholders would not receive a proxy or consent solicitation statement in connection with that transaction. However, we believe that it is unlikely that circumstances requiring an automatic transfer will occur. A transfer to corporate form would result in Great Lakes, Northern Border or Tuscarora being subject to corporate income taxes and would likely be materially adverse to their, and therefore, our results of operations and financial condition.

TransCanada controls our general partner, which has sole responsibility for conducting our business and managing our operations. TC PipeLines GP, our general partner, and its affiliates have limited fiduciary responsibilities and may have conflicts of interest with respect to our partnership, and they may favor their own interests to the detriment of our unitholders.

The directors and officers of TC PipeLines GP and its affiliates have duties to manage TC PipeLines GP in a manner that is beneficial to its stockholders. At the same time, TC PipeLines GP has duties to manage our partnership in a manner that is beneficial to us. Therefore, TC PipeLines GP’s duties to us may conflict with the duties of its officers and directors to its stockholders. Such conflicts may include, among others, the following:

·                  expenditures, borrowings, issuances of additional common units and reserves in any quarter may affect the level of cash available to pay quarterly distributions to unitholders and TC PipeLines GP;

·                  under our partnership agreement, TC PipeLines GP determines which costs incurred by it and its affiliates are reimbursable by us;

·                  affiliates of TC PipeLines GP may compete with us in certain circumstances;

·                  TC PipeLines GP may limit our liability and reduce their fiduciary duties, while also restricting the remedies available to our unitholders for actions that might, without the limitations, constitute breaches of fiduciary duty. As a result of purchasing our units, unitholders are deemed to consent to some actions and

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conflicts of interest that might otherwise constitute a breach of fiduciary or other duties under applicable law;

·                  we do not have any employees and we rely solely on TC PipeLines GP and its affiliates to conduct our business, and

·                  TransCanada, through wholly-owned subsidiaries, is the operator of all of our pipeline systems. This operator role along with their ownership interests in our pipeline systems may force TransCanada to make decisions that may conflict as operator and/or owner of these systems.

Cost reimbursements due to our general partner may be substantial and could reduce our cash available for distribution.

Prior to making any distribution on the common units, we will reimburse our general partner and its affiliates, including officers and directors of the general partner, for all expenses incurred by our general partner and its affiliates on our behalf. During the year ended December 31, 2008, we paid fees and reimbursements to our general partner in the amount of $2.1 million (2007 — $1.9 million). Our general partner in its sole discretion will determine the amount of these expenses. In addition, our general partner and its affiliates may provide us services for which we will be charged reasonable fees as determined by the general partner. The reimbursement of expenses and the payment of fees could adversely affect our ability to make distributions.

If we were found to be an “investment company” under the Investment Company Act of 1940, our contracts may be voidable and our offers of securities may be subject to rescission.

If we were deemed to be an unregistered “investment company” under the Investment Company Act, our contracts may be voidable and our offers of securities may be subject to rescission, and we may also be subject to other materially adverse consequences.

Our assets include a 46.45 per cent partner interest in Great Lakes and a 50 per cent general partner interest in Northern Border. We could be deemed to be an “investment company” under the Investment Company Act if these interests constituted an “investment security”, as defined in the Investment Company Act. If we were deemed to be an “investment company”, then we would be required to be registered as an investment company under the Investment Company Act. In that case, there would be a substantial risk that we would be in violation of the Investment Company Act because of the practical inability to register under the Investment Company Act.

Moreover, treatment of us as an investment company would prevent our qualification as a partnership for federal income tax purposes in which case we would be treated as a corporation for federal income tax purposes. As a result, we would pay federal income tax on our taxable income at the corporate tax rate, distributions would generally be taxed again as corporate distributions and none of our income, gains, losses or deductions would flow through to unitholders. Because a tax would be imposed upon us as a corporation, our cash available for distribution would be substantially reduced. Therefore, treatment of us as an investment company would result in a material reduction in the anticipated cash flow and after-tax return to the unitholders, likely causing a substantial reduction in the value of our common units.

Tax Risks to Common Unitholders

The Internal Revenue Service (IRS) could treat us as a corporation, which would substantially reduce the cash available for distribution to unitholders.

The anticipated after-tax benefit of an investment in us depends largely on our classification as a partnership for federal income tax purposes. We have not requested, and do not plan to request, a ruling from the IRS on this or any other tax matter affecting us.

If we were treated as a corporation for federal income tax purposes, we would pay federal and state income taxes on our income at the applicable corporate tax rate. Distributions would generally be taxed again to unitholders as corporate distributions, and no income, gains, losses, deductions or credits would flow through to unitholders. Because a tax would be imposed upon us as an entity, the cash available for distribution to unitholders would be substantially reduced. Our treatment as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to unitholders and thus would likely result in a substantial reduction in the value of the common units.

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Current laws may change so as to cause us to be taxable as a corporation for federal income tax purposes or otherwise to be subject to entity level taxation. Our partnership agreement provides that, if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity level taxation for federal, state or local income tax purposes, then specified provisions of the partnership agreement relating to distributions will be subject to change. These changes would include a decrease in distributions to reflect the impact of that law on us.

If our pipeline systems were to become subject to a material amount of entity-level taxation for state tax purposes, then our pipeline systems’ operating cash flow and cash available for distribution to us and for other business needs would be reduced.

Our pipeline systems are held in the operating Partnerships, which are generally treated as flow-through entities for income tax purposes, and as such the income from the pipeline systems generally have not been subject to income tax at the entity level. Several states have either adopted or are evaluating a variety of ways to subject partnerships to entity level taxation. For example, in 2008, Great Lakes recorded a Michigan business tax of $5.5 million relating to a new partnership level tax, of which the Partnership’s share of the tax was $2.6 million. Imposition of such taxes on our pipeline systems will reduce the cash available for distribution to us and for other business needs by our pipeline systems, and adversely affect the amount of funds available for distribution to our unitholders.

We have not requested an IRS ruling with respect to our tax treatment.

We have not requested a ruling from the IRS with respect to any tax matter affecting us. The IRS may adopt positions that differ from the positions we take. It may be necessary to resort to administrative or court proceedings in an effort to sustain some or all of our counsel’s conclusions or the positions we take. Any contest with the IRS may materially and adversely impact the market for our common units and the price at which the common units trade. In addition, the costs of any contest with the IRS will be borne directly or indirectly by some or all of the unitholders and the general partner.

Unitholders may be required to pay taxes on income from us even if they receive no cash distributions.

Unitholders may be required to pay federal income taxes and, in some cases, state and local income taxes on their allocable share of our income, whether or not they receive cash distributions from us. Unitholders may not receive cash distributions equal to their allocable share of our taxable income or even the tax liability that results from that income.

Tax gains or losses on the disposition of common units could be different than expected.

If unitholders sell their common units, they will recognize a gain or loss equal to the difference between the amount realized and their tax basis in those common units. Prior distributions in excess of the total net taxable income that unitholders were allocated for a common unit which decreased their tax basis in that common unit will, in effect, become taxable income if the common unit is sold at a price greater than their tax basis in that common unit, even if the price is less than the original cost. A substantial portion of the amount realized, whether or not representing a gain, may be ordinary income to unitholders. If the IRS successfully contests some conventions we use, unitholders could recognize more gain on the sale of common units than would be the case under those conventions without the benefit of decreased income in prior years.

Tax-exempt and non-U.S. investors may have adverse tax consequences from owning common units.

An investment in common units by tax-exempt entities and foreign persons raises issues unique to these persons. For example, virtually all of our income allocated to organizations which is exempt from federal income tax, including individual retirement accounts and other retirement plans, will be unrelated business taxable income and will be taxable to them. Distributions to foreign persons will be reduced by withholding taxes, and foreign persons will be required to file federal income tax returns and pay tax on their share of our taxable income.

We treat a purchaser of common units as having the same tax benefits without regard to the actual common units purchased. A successful IRS challenge could adversely affect the value of the common units.

To maintain uniformity of the economic and tax characteristics of our common units, we have adopted depreciation and amortization conventions that do not conform to all aspects of specified Treasury Regulations. A successful challenge to those conventions by the IRS could adversely affect the amount of tax benefits available to unitholders or could affect the timing of tax benefits or the amount of gain from the sale of common units and could have a negative impact on the value of the common units or result in audit adjustments to unitholders’ tax returns.

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We have adopted certain valuation methodologies that may result in a shift of income, gain, loss and deduction between the general partner and the unitholders. The IRS may challenge this treatment, which could adversely affect the value of the common units.

For income tax purposes and pursuant to the Partnership Agreement, when we issue additional units or engage in certain other transactions, we determine the fair market value of our assets and allocate any unrealized gain or loss attributable to our assets to the capital accounts of our unitholders and our general partner. If our valuation methodology were not sustained upon an IRS challenge, there may be a shift of income, gain, loss and deduction between certain unitholders and the general partner, which may be unfavorable to such unitholders. Our valuation methodology is also used in certain computations and allocations relating to Section 743(b) adjustments and Section 751 deemed sale tax effects.

A successful IRS challenge to these methods, calculations or allocations could adversely affect the amount of taxable income or loss being allocated to our unitholders. It also could affect the amount of gain from our unitholders’ sale of common units and could have a negative impact on the value of the common units or result in audit adjustments to our unitholders’ tax returns without the benefit of additional deductions.

The sale or exchange of 50 per cent or more of the total interest in our capital and profits will result in the termination of our partnership for federal income tax purposes.

We will be considered to have terminated for federal income tax purposes if there is a sale or exchange of 50 per cent or more of the total interests in our capital and profits within a 12-month period. Our termination would, among other things, result in the closing of our taxable year for all unitholders and could result in a deferral of depreciation deductions allowable in computing our taxable income.

Unitholders will likely be subject to state and local taxes and return filing requirements in states where they do not live as a result of an investment in our common units.

In addition to federal income taxes, unitholders will likely be subject to other taxes, including state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we do business or own property. We may be required to withhold income taxes with respect to income allocable or distributions made to our unitholders. In addition, unitholders may be required to file state and local income tax returns and pay state and local income taxes in some or all of the jurisdictions in which we do business or own property and may be subject to penalties for failure to comply with those requirements. We currently own assets and conduct business in California, Illinois, Indiana, Iowa, Michigan, Minnesota, Montana, Nebraska, Nevada, North Dakota, Oregon, South Dakota, Texas, and Wisconsin. Each of these states except for Nevada, South Dakota, and Texas, currently impose personal income taxes on individuals. Generally, these states also impose income taxes on corporations and other entities. It is the unitholders’ responsibility to file all required United States federal, state and local tax returns. Counsel has not rendered an opinion on the state or local tax consequences of an investment in us.

Item 1B.                            Unresolved Staff Comments

None.

Item 2.                                    Properties

Excluding properties held directly by Tuscarora, TC PipeLines does not hold the right, title or interest in any properties.

Properties of Great Lakes Gas Transmission Limited Partnership, Northern Border Pipeline Company and Tuscarora Gas Transmission Company

See Item 1. “Business” for a description of our pipeline systems’ properties, their utilization, and how each property is held.

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Item 3.                                    Legal Proceedings

Our pipeline systems are parties to various legal actions or governmental proceedings that have arisen in the normal course of business. Management believes the disposition of all known outstanding legal actions will not have a material adverse impact on the Partnership’s financial condition, results of operations or cash flows.

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, 2008.

PART II

Item 5.                                    Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

The common units representing limited partner interests in the Partnership were issued pursuant to an initial public offering on May 28, 1999 and a private placement on February 22, 2007. The common units are quoted on the NASDAQ Global Select 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 Global Select 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.

As of February 19, 2009, there were 100 registered holders of common units and approximately 16,200 beneficial owners of common units, including common units held in street name.

The Partnership currently has 34,856,086 common units outstanding, of which 24,142,935 are held by the public, 8,678,045 are held by TransCan Northern, and 2,035,106 are held by TC PipeLines GP. The common units represent an aggregate 98 per cent limited partner interest and the general partner interest represents an aggregate two per cent general partner interest in the Partnership.

The general partner receives two per cent of all cash distributions in regards to its general partner interest and is also entitled to incentive distributions as described below. The holders of common units (collectively referred to as

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unitholders) receive the remaining portion of the cash distribution. The Partnership’s quarterly cash distributions to its unitholders comprise 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.

The general partner receives incentive distributions if the amount distributed with respect to any quarter exceeds the minimum quarterly distribution of $0.45 per common unit. Under the incentive distribution provisions, the general partner receives 15 per cent of amounts distributed in excess of $0.45 per common unit, 25 per cent of amounts distributed in excess of $0.5275 per common unit, and 50 per cent of amounts distributed in excess of $0.69 per common 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 2008, the Partnership made cash distributions to unitholders and the general partner that amounted to $108.6 million compared to $86.7 million in 2007. These payments represented $0.665 per common unit for the quarter ended December 31, 2007, $0.700 per common unit for the quarter ended March 31, 2008 and $0.705 per common unit for the quarters ended June 30, 2008 and September 30, 2008. On February 13, 2009, the Partnership paid a cash distribution of $27.8 million to unitholders and the general partner, representing a cash distribution of $0.705 per common unit for the quarter ended December 31, 2008. The distribution was allocated in the following manner: $24.6 million to the holders of common units as of the close of business on January 30, 2009 (including $1.4 million to the general partner as holder of 2,035,106 common units and $6.1 million to TransCan Northern as holder of 8,678,045 common units), $2.6 million to the general partner as holder of incentive distribution rights, and $0.6 million to the general partner in respect of its two per cent general partner interest.

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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.”

(1)TC PipeLines acquired a 46.45 per cent interest in Great Lakes on February 22, 2007.  The equity method is used to account for the Partnership’s investment in Great Lakes.

(2)TC PipeLines accounted for its investment in Tuscarora using the equity method until December 19, 2006 and began consolidating Tuscarora’s operations upon acquisition of the additional 49 per cent general partner interest.

Item 7.                                    Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discusses the results of operations and liquidity and capital resources of TC PipeLines, along with those of Great Lakes, Northern Border and Tuscarora (together “our pipeline systems”) as a result of the Partnership’s ownership interests.

The following discussions of the financial condition and results of operations of the Partnership and its pipeline systems should be read in conjunction with the financial statements and notes thereto of the Partnership, Great Lakes Gas Transmission Limited Partnership (Great Lakes) and Northern Border Pipeline Company (Northern Border) 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, Great Lakes and Northern Border. All amounts are stated in United States of America (U.S.) dollars.

PARTNERSHIP OVERVIEW

TC PipeLines was formed in 1998 as a Delaware limited partnership. TC PipeLines was formed by TransCanada PipeLines Limited, a wholly-owned subsidiary of TransCanada Corporation (collectively referred to herein as TransCanada), to acquire, own and participate in the management of energy infrastructure assets in North America. Our strategic focus is on delivering stable, sustainable cash distributions to our unitholders and finding opportunities to increase cash distributions while maintaining a low risk profile.

TC PipeLines, LP and its subsidiaries are collectively referred to herein as “TC PipeLines” or “the Partnership.” In

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this report, references to “we”, “us” or “our” collectively refer to TC PipeLines or the Partnership. The general partner of the Partnership is TC PipeLines GP, Inc., a wholly-owned subsidiary of TransCanada.

We own a 46.45 per cent general partner interest in Great Lakes, which we acquired on February 22, 2007 from El Paso Corporation. The remaining 53.55 per cent general partner interest in Great Lakes is held by TransCanada.

We own a 50 per cent general partner interest in Northern Border. The other 50 per cent general partner interest in Northern Border is held by ONEOK Partners L.P. (ONEOK Partners), a publicly traded limited partnership that is controlled by ONEOK, Inc.

As of December 31, 2007, we acquired the remaining two per cent general partner interest in Tuscarora Gas Transmission Company (Tuscarora), thereby making it a wholly-owned subsidiary.

Our general partner interests in Great Lakes, Northern Border and Tuscarora represent our only material assets at December 31, 2008. As a result, we are dependent upon Great Lakes, Northern Border and Tuscarora for all of our available cash. Our pipeline systems derive their operating revenue from the provision of natural gas transportation services.

Great Lakes Overview

Great Lakes is a Delaware limited partnership formed in 1990. Great Lakes was originally constructed as an operational loop of the TransCanada Mainline Northern Ontario system. Great Lakes receives natural gas from TransCanada at the Canadian border near Emerson, Manitoba and extends across Minnesota, Northern Wisconsin and Michigan, and redelivers gas to TransCanada at the Canadian border at Sault Ste. Marie, Michigan and St. Clair, Michigan.

Northern Border Overview

Northern Border is a Texas general partnership formed in 1978. Northern Border transports natural gas from the Canadian border near Port of Morgan, Montana to a terminus near North Hayden, Indiana. Additionally, Northern Border transports natural gas produced in the Williston Basin of Montana and North Dakota, and the Powder River Basin of Wyoming and Montana, and synthetic gas produced at the Dakota Gasification plant in North Dakota.

Tuscarora Overview

Tuscarora is a Nevada general partnership formed in 1993. Tuscarora originates at an interconnection point with existing facilities of Gas Transmission Northwest Corporation (GTN), a wholly-owned subsidiary of TransCanada, near Malin, Oregon and runs through Northeastern California and Northwestern Nevada to a terminus near Wadsworth, Nevada. Along its route, deliveries are made in Oregon, Northern California and Northwestern Nevada.

OBSERVATIONS ON CURRENT ENVIRONMENT

With the economic conditions in the U.S. having changed dramatically in the last half of 2008, there has been a tightening of the credit markets, impacting the availability and cost of financing. Both industrial production and consumer spending fell sharply in the last half of 2008. Businesses have been increasingly faced with reduced demand for their products, increased credit tightening, and deteriorating counterparty creditworthiness. In addition, commodity prices have decreased dramatically from multi-year highs in the summer of 2008 to multi-year lows by the end of the year. In short, worldwide economies have entered a recessionary period.

While the current economic environment has reduced the demand for natural gas, once the economy returns to growth mode, North America’s demand for natural gas is expected to rise, especially in light of reduced commodity prices combined with the relative environmental merits of natural gas versus other carbon based forms of energy. Natural gas supplies in North America are also expected to be impacted by the current environment, mainly due to lower prices, along with credit and liquidity impacts on natural gas producers. Production from specific natural gas basins in North America will be dependent upon relative operating costs, with reduced natural gas drilling activity expected to contribute to lower production overall.

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These reductions in natural gas demand and the changing geography and quantity of supply from various basins will impact the overall natural gas transportation infrastructure. With respect to our systems, demand for our pipeline systems’ transportation services are directly related to the demand and supply alternatives for natural gas in the markets served by our pipeline systems. In addition, the impact of any changes in demand on the revenues of our pipeline systems is dependent upon the levels of firm transportation contracts and the creditworthiness of the counterparties which hold those positions. Tuscarora has firm transportation contracts for 100 per cent of its available capacity as at January 31, 2009. Great Lakes’ average design capacity is 88 per cent contracted at January 31, 2009. Northern Border’s system has the most exposure to changes in demand with approximately 60 per cent of its capacity available for 2009.

As we are dependent upon cash flows received from our pipeline systems to fund our distributions, if there is a prolonged impact to demand for natural gas transportation services or creditworthiness of our pipeline systems’ shippers, our partnership cash flows may be negatively impacted. However, we have a strong financial position, including an available unused credit facility at favorable rates, which gives us the capacity to meet any funding commitments to our investments, along with pursuing opportunities to grow.

OUTLOOK

The Partnership

Access to capital markets is important to the Partnership to enable it to execute its business strategies, which include seeking opportunities to undertake accretive acquisitions and organic growth projects, and maximize the value of our existing portfolio of pipeline systems. Recently, the general economic and capital market conditions in the U.S. and other parts of the world have deteriorated significantly and have adversely affected access to capital and increased the cost of capital. If these conditions continue or become worse, the Partnership’s future cost of debt and equity capital, and future access to capital markets could be adversely affected.

Our strong financial position, including an available unused credit facility, gives us the capacity to pursue opportunities to grow in a sustained and disciplined manner for the long-term benefit of our unitholders.

Great Lakes

At January 31, 2009, the weighted average remaining contract life of Great Lakes’ contracts was 2.7 years and 88 per cent of its average design capacity was contracted on a firm basis for the first quarter of 2009. As of January 31, 2009, Great Lakes had approximately 12 per cent of its average design capacity uncontracted beginning in the second quarter of 2009 and 14 per cent by December 31, 2009. Dependent on competitive factors and prevailing market conditions, Great Lakes may discount transportation capacity as needed to optimize revenue.

Northern Border

At January 31, 2009, the weighted average remaining contract life of Northern Border’s contracts was 2.1 years and 82 per cent of its capacity was contracted on a firm basis for the first quarter of 2009. As of January 31, 2009, Northern Border had approximately 60 per cent of its design capacity uncontracted beginning in the second quarter of 2009 through the remainder of 2009. Prevailing market conditions and increasing competitive factors in North America expected in 2009, including REX, will continue to challenge Northern Border’s ability to market its available capacity, and may negatively impact revenue in 2009.

Tuscarora

At January 31, 2009, the weighted average remaining contract life of Tuscarora’s contracts was 11.6 years. As of January 31, 2009, Tuscarora has approximately two per cent of its design capacity uncontracted beginning in the second quarter of 2009.

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FACTORS THAT IMPACT OUR BUSINESS

Key factors that impact our business are the cash flows received from our investments and our ability to maintain a strong financial position. Cash flows from our investments are dependent upon the ability of Great Lakes and Northern Border to make distributions to us and of Tuscarora to generate positive operating cash flows. Partnership cash flows from our investments are necessary to fund distributions to our unitholders. A strong financial position will ensure that we are able to maintain a prudent level of available cash to make distributions to our unitholders.

FACTORS THAT IMPACT THE BUSINESS OF OUR PIPELINE SYSTEMS

Our pipeline systems provide natural gas transportation services to their customers. Key factors that impact their business are the supply of and demand for natural gas in the markets in which our pipeline systems operate; the customers of our pipeline systems and the mix of services they require; competition; and government regulation of natural gas pipelines. These factors are discussed in more detail below.

Supply and Demand of Natural Gas

Our pipeline systems depend upon the continued availability of natural gas production and reserves in the regions they access, primarily the Western Canada Sedimentary Basin (WCSB). Our pipeline systems provide their customers with natural gas transportation services to market demand areas. The “net WCSB flows to U.S. markets” are dependent upon natural gas production levels, demand for natural gas in Canada, and storage capacity for Canadian natural gas and demand for storage injection in Canada. The net WCSB flows to U.S. markets were lower in 2008 compared to 2007, due mainly to a decrease in production. Colder than normal weather conditions also contributed to increased Canadian demand. At the same time, there has been an increase in U.S. natural gas production, mainly due to the development of unconventional reserves in the lower-48 States.

Decreases in WCSB production are expected to continue in 2009 as there has been a decline in drilling and exploration activity by WCSB producers, mainly related to the sharp reductions in commodity prices over the last half of 2008. Decreases in WCSB production are also related to higher supply costs, including higher royalties, and competition for capital from other North American basins that have lower exploration costs. Commodity prices, combined with restrictions on liquidity and access to capital, have contributed to the postponement and/or cancellation of certain oil sands projects, which may impact Canadian demand for WCSB natural gas.

Factors which may mitigate declines related to WCSB production in the future include strengthening gas prices and decreases in oil prices as they affect demand from Alberta oil sands production. We expect WCSB producers will continue to explore and develop new fields in Western Canada as well as direct significant activity at unconventional resources such as coalbed methane and shale gas. As well, additional Canadian natural gas supply sources may be available in the future if new pipeline projects associated with the Montney and Horn River shale gas regions in Western Canada, the Mackenzie Delta in Northern Canada and the North Slope of Alaska are constructed.

Factors which may impact the overall demand for natural gas include weather conditions, economic conditions, government regulation, availability and price of alternative energy sources, fuel conservation measures, and technological advances in fuel economy and energy generation devices. Although demand for natural gas is expected to decline in North America in 2009 with the current economic downturn, we expect a demand increase in the long-term. Demand for natural gas transportation service on our pipeline systems is directly correlated to the activity in the natural gas markets served by these systems. Additionally, factors that may impact demand for transportation service on any one system include the ability and willingness of natural gas shippers to utilize one system over alternative pipelines, transportation rates, and the volume of natural gas delivered to markets from other supply sources and storage facilities.

The decline in net WCSB flows to markets in 2008 was not the primary factor which negatively impacted throughput on our pipeline systems in 2008. We cannot predict the impact of any continued declines in net WCSB flows to markets on 2009 throughput as this will depend on those net flows in the future and market conditions in the markets our pipeline systems serve.

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The impact of changes in demand for natural gas transportation services on operating revenues for our pipeline systems is dependent upon the extent to which capacity has been contracted under long-term firm contracts.

Throughput on Great Lakes’ pipeline system in 2008 was slightly lower than 2007 and 2006 primarily due to underutilization of firm contracts, and therefore had minimal impact on revenue.

The majority of Northern Border’s supply comes from the WCSB. Increased drilling and production activity, primarily in Wyoming within the Powder River Basin, has resulted in producers expressing interest in the proposed Bison Pipeline Project which, if completed, would bring approximately 407 MMcf/d of additional supply from this region to Northern Border and would increase Northern Border’s supply diversity. See the Year in Review — 2008 section of Item 1. “Business” for additional information about the Bison Pipeline Project. Growth in other producing regions such as the Williston Basin of Montana and Northern Dakota, and further development of the Rockies supply basin, may provide future opportunities for supplies being delivered from these other producing regions which would further diversify Northern Border’s supply sources. Finally, another source of supply could come from future development of coal gasification projects that would be built close to coal producing regions most likely in North Dakota.

The Midwest markets served by Northern Border were impacted in 2008 by incremental supply from the Rockies natural gas basin with the completion of the Western segment of the Rockies Express Pipeline. Demand for transportation on Northern Borders’ pipeline system in 2008 declined as a result of this increased supply competition, as discussed further under “Competition”.

The GTN system is one of the U.S. transporters of Canadian natural gas from the WCSB, effectively the sole source of gas on Tuscarora. Tuscarora’s largest customers are in the Reno-Sparks area of Washoe County, Storey County and downstream of the Paiute system, where gas consumption has increased significantly as a result of increased industrial use, population growth and gas-fired power generation.

Customers and Contracting

Our pipeline systems transport natural gas for a variety of customers including other natural gas pipelines, natural gas distribution companies, electric generation companies, natural gas producers, and natural gas marketers.

Our pipeline systems are subject to credit risk related to the ability of their customers or shippers to meet their contractual payment obligations. The tariffs on our pipeline systems allow for them to require customers to post credit support under the terms of these tariffs. This somewhat mitigates our pipeline systems’ exposure to counterparty credit risk. During 2008, the bankruptcy of Lehman Brothers Holdings Inc. and the weakening of companies within the energy industry have underscored the importance of these tariff provisions. However, in some instances it is also limiting the amount of capacity a customer can contract for, as their ability to meet or post the required support is being negatively impacted by their liquidity constraints.

Great Lakes’ average contracted capacity was near 100 per cent of its average design capacity for 2008. At January 31, 2009, 88 per cent of its average design capacity was contracted on a firm basis. In November 2008, TransCanada renewed 360 million Dth/d, or 16 per cent, of capacity on Great Lakes through October 2012. As well, Great Lakes’ transportation values increased throughout 2008, partially due to the increase in tolls from its main competitor (the TransCanada Mainline), and partially because of strong spread values between Alberta and Dawn, Ontario. As a result, Great Lakes sold new contracts as well as renewed long and short haul contracts at maximum tariff rates for the next two years. Depleted storage inventories in Eastern Canada and the U.S. supported demand for Great Lakes’ transportation, as customers utilized Great Lakes’ transportation to access and fill storage locations adjacent to its pipeline over the summer months.

Northern Border’s average contracted capacity was 90 per cent of its design capacity for 2008. Transportation values on Northern Border’s system were strong in the fourth quarter, mainly related to weather conditions, which enabled Northern Border to sell its available capacity in the fourth quarter of 2008 at maximum rates. Northern Border’s capacity to Chicago remains attractive and is substantially under contract for multiple years. Legacy contacts related to this capacity that were set to expire in the near term have been renewed. However, prevailing market conditions and increasing competitive factors in North America, including in-service of the Western segment of the Rockies

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Express Pipeline (REX West), have caused Northern Border to experience a reduction in its revenues due to lower capacity sales and greater discounting of its rates. These factors, as well as expirations of certain long-term contracts, will continue to impact Northern Border’s ability to market its available capacity into 2009. As of January 31, 2009, Northern Border had approximately 60 per cent of its design capacity uncontracted beginning in the second quarter of 2009 through the remainder of 2009.

Tuscarora operates under long-term contacts with 100 per cent of its design capacity contracted with a weighted average remaining life on those contracts of 11.6 years as of January 31, 2009. The weighted average remaining life of Tuscarora’s contracts increased during 2008 with the completion of the compressor station expansion project, which was underpinned by a 22.5-year contract.

Competition

Our pipeline systems compete primarily with other interstate and intrastate pipelines in the transportation of natural gas. Additionally, supply competition from other natural gas sources can impact demand for transportation on our pipeline systems. Growth in supplies available from other natural gas producing regions can impact prices for natural gas delivered to some of the markets our pipeline systems serve relative to other market regions.

Great Lakes competes directly with Northern Border, Alliance/Vector, Viking and the TransCanada Mainline. In addition, supply competition from other natural gas sources can impact demand for transportation on Great Lakes. Great Lakes anticipates that further growth in supplies from the Rocky Mountain region will create additional supply in the markets Great Lakes serves. Anticipated additional supplies from the Eastern segment of the Rockies Express Pipeline (REX East), discussed below, may provide opportunities for Great Lakes to market its Eastern zone capacity for storage injection and withdrawal, which has historically been underutilized.

The pipeline systems that offer primary competition to Northern Border include Alliance Pipeline, Great Lakes, Gas Transmission Northwest, and other pipelines that interconnect with the TransCanada mainline for WCSB supply. Additionally, Northern Border competes with other pipelines that serve Northern Border’s market areas, including Northern Natural Gas Company, Alliance Pipeline, ANR Pipeline Company, Midwestern Gas Transmission Company and Natural Gas Pipeline of America. Northern Border has seen growth in supplies from the Rocky Mountain region creating additional supply in the markets Northern Border serves, including Ventura, Harper and Chicago. REX West increased supply competition in Midwest markets and negatively impacted Northern Border’s flows and sales of available capacity in 2008 and is anticipated to continue to impact in 2009. REX East, from Missouri to Ohio, will transport natural gas further east, potentially mitigating excess supply in Northern Border’s Ventura market. REX has announced that REX East will be placed in service in the second and fourth quarters of 2009. As well, two other new pipeline projects are projected to go into service in 2009 that will ship growing supply volumes from the lower Mid-Continent east to the existing gulf coast infrastructure that includes transportation access to the Chicago market. As with all new pipeline projects, these will impact overall North American natural gas flows.

As of January 31, 2009, Northern Border had approximately 60 per cent of its design capacity uncontracted beginning in the second quarter of 2009 through the remainder of 2009. Additional supply in the Chicago market may impact Northern Border’s ability to contract upstream available capacity in 2009 if flows to Chicago materially decrease.

Tuscarora maintains a very strong competitive position relative to other sources of gas in the markets it serves. Tuscarora is one of only two pipelines that serves the Northern Nevada market, the other being Paiute Pipeline. Tuscarora also has access to supply regions as its upstream pipelines have excess capacity.

Government Regulation

Natural gas transportation is regulated by the Federal Energy Regulatory Commission (FERC) and other federal and state regulatory agencies, including the Department of Transportation. FERC regulatory policies govern the rates that pipelines are permitted to charge customers for interstate transportation of natural gas. The operation and maintenance of our pipeline systems are also regulated by the federal and state regulatory agencies.

The FERC-approved rate designs used by our pipeline systems are based upon firm service and interruptible services. Customers with firm service transportation agreements pay a fee known as a reservation charge to reserve pipeline capacity, regardless of use, for the term of their contracts. Firm service transportation customers may also pay a variable fee that is based on the distance and volume of natural gas they transport. Customers with interruptible service transportation agreements may utilize available capacity on a pipeline system after firm service

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transportation requests are satisfied. Interruptible service customers are assessed a variable fee based on distance and the volume of natural gas they transport. The majority of our pipeline systems’ revenue is generated by firm service transportation agreements.

HOW WE EVALUATE OUR OPERATIONS

We evaluate our business primarily on the basis of the underlying operating results for each of our pipeline systems, along with a measure of Partnership cash flows. This measure does not have any standardized meaning prescribed by U.S. generally accepted accounting principles (GAAP). It is, therefore, considered to be a non-GAAP measure and is unlikely to be comparable to similar measures presented by other entities. Partnership cash flows is the sum of net income, cash distributions received from Great Lakes, Northern Border and Tuscarora (in 2006), and cash flows provided by Tuscarora’s operating activities (in 2007 and 2008) less equity income from investments in Great Lakes, Northern Border and Tuscarora (in 2006) and Tuscarora’s net income (in 2007 and 2008).

RESULTS OF OPERATIONS OF TC PIPELINES, LP

The general partner interests in Great Lakes, Northern Border and Tuscarora were our only material sources of income in 2008; therefore, our results of operations were influenced by and reflect the same factors that influenced the financial results of Great Lakes, Northern Border and Tuscarora. See Item 1. “Business”.

Critical Accounting Policies and Estimates

The preparation of financial statements in accordance with GAAP requires us to make estimates and assumptions with respect to values or conditions which cannot be known with certainty, that affect the reported amount of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the financial statements. Such estimates and assumptions also affect the reported amounts of revenue and expenses during the reporting period. Although we believe these estimates and assumptions are reasonable, actual results could differ. The following summarizes the Partnership’s and our pipeline systems’ accounting policies and estimates, and should be read in conjunction with Note 2 of the Partnership’s Financial Statements included elsewhere in this report.

We account for our investments in Great Lakes and Northern Border using the equity method of accounting. 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. We are able to exercise significant influence over our investments in Great Lakes and Northern Border because of our ownership interests and our representation on the Great Lakes and Northern Border management committees.

We used the equity method to account for our investment in Tuscarora until December 19, 2006. On this date, we acquired an additional 49 per cent general partner interest in Tuscarora and, as a result of acquiring a controlling interest in Tuscarora, began to consolidate its operations.

Regulatory Assets

Our pipeline systems’ accounting policies conform to Statement of Financial Accounting Standards (SFAS) No. 71, Accounting for the Effects of Certain Types of Regulation (SFAS No. 71). Our pipeline systems consider several factors to evaluate their continued application of the provisions of SFAS No. 71 such as potential deregulation of their pipelines; anticipated changes from cost-based ratemaking to another form of regulation; increasing competition that limits their ability to recover costs; and regulatory actions that limit rate relief to a level insufficient to recover costs.

Certain assets that result from the ratemaking process are reflected on Northern Border’s balance sheet as regulatory assets. If Northern Border determines future recovery of these assets is no longer probable as a result of discontinuing application of SFAS No. 71 or other regulatory actions, Northern Border would be required to write off the regulatory assets at that time. As of December 31, 2008, Northern Border reflected regulatory assets of $21.7 million on its balance sheet (2007 - $20.7 million). These assets are being amortized as directed by the FERC in Northern Border’s previous regulatory proceedings over varying time periods up to 43 years.

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As at December 31, 2008 and 2007, Great Lakes and Tuscarora did not have any regulatory assets or liabilities recorded on their respective balance sheets.

Contingencies

Our pipeline systems’ accounting for contingencies covers a variety of business activities, including contingencies for legal and environmental liabilities. Our pipeline systems accrue for these contingencies when their assessments indicate that it is probable that a liability has been incurred or an asset will not be recovered and an amount can be reasonably estimated in accordance with SFAS No. 5, Accounting for Contingencies. Our pipeline systems base their estimates on currently available facts and their estimates of the ultimate outcome or resolution. Actual results may differ from our pipeline systems’ estimates resulting in an impact, positive or negative, on earnings.

Impairment of Long-Lived Assets and Goodwill

We assess our long-lived assets for impairment based on SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets. A long-lived asset is tested for impairment whenever events or changes in circumstances indicate that its carrying amount may exceed its fair value. Fair value is a market-based measure of the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date.

We assess our goodwill for impairment at least annually, based on SFAS No. 142, Goodwill and Other Intangible Assets (SFAS No. 142). An initial assessment is made by comparing the fair value of the operations with goodwill, as determined in accordance with SFAS No. 142, to the book value of each reporting unit. If the fair value is less than the book value, an impairment is indicated, and we must perform a second test to measure the amount of the impairment. In the second test, we calculate the implied fair value of the goodwill by deducting the fair value of all tangible and intangible net assets of the operations with goodwill from the fair value determined in step one of the assessment. If the carrying value of the goodwill exceeds this calculated implied fair value of the goodwill, we will record an impairment charge. At December 31, 2008 and 2007, we had $81.7 million of goodwill recorded on our balance sheet related to the Tuscarora acquisitions. No impairment of goodwill existed at December 31, 2008.

Impact of New Accounting Standards

The Partnership adopted the provisions of SFAS No. 157, Fair Value Measurements (SFAS No. 157) for its financial assets and liabilities measured at fair value on a recurring basis effective January 1, 2008. Under SFAS No. 157, the financial assets and liabilities that are recorded at fair value on a recurring basis are categorized into one of three categories based upon a fair value hierarchy. We have classified all of our derivative financial instruments as level II where the fair value is determined by using valuation techniques that refer to observable market data or estimated market prices. Refer to Note 17 of the Partnership’s financial statements for the impact to our financial statements.

The Financial Accounting Standards Board (FASB) issued FASB Staff Position No. 157-2, Effective Date of FASB Statement No. 157 (Staff Position No. 157-2), in February 2008, which delayed the effective date of SFAS No. 157 for all non-financial assets and liabilities that are measured at fair value on a non-recurring basis until fiscal years beginning after November 15, 2008. These non-financial items include assets and liabilities such as non-financial assets and liabilities assumed in a business combination, reporting units measured at fair value in a goodwill impairment test and asset retirement obligations initially measured at fair value. The effect of adopting Staff Position No. 157-2 is not expected to be material to our results of operations or financial position.

The FASB issued Staff Position No. 157-3, Determining the Fair Value of a Financial Asset When the Market for That Asset Is Not Active, in October 2008, which clarifies the application of SFAS No. 157 in a market that is not active. This Staff Position is effective upon issuance and the Partnership’s financial statements were not impacted by this standard.

The FASB issued SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities — Including an Amendment of FASB Statement No. 115 (SFAS No. 159), in February 2007, which permits entities to choose to measure selected financial assets and financial liabilities at fair value for fiscal years beginning on or after November 15, 2007. The fair value option established by SFAS No. 159 permits all entities to choose to measure

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eligible items at fair value at specified election dates. The Partnership has not elected the fair value option for any non-derivative financial assets or liabilities.

The Emerging Issues Task Force of the FASB issued EITF 07-4, “Application of the Two-Class Method under FASB Statement No. 128, Earnings per Share, to Master Limited Partnerships” (EITF 07-4) in June 2007. EITF 07-4 addresses how current period earnings of a Master Limited Partnership should be allocated to the general partner, limited partners and when applicable, incentive distribution rights when applying the two-class method under Statement 128. A conclusion was ratified by the FASB in March 2008 and is effective for fiscal years beginning after December 15, 2008. We are currently reviewing the applicability of EITF 07-4 to our results of operations and financial position.

The FASB issued SFAS No. 162, The Hierarchy of Generally Accepted Accounting Principles (SFAS No. 162), in May 2008, which codifies the sources of accounting principles and the related framework to be utilized in preparing financial statements in conformity with GAAP. The requirements of this standard are not expected to have a material impact on our results of operations or financial position.

The FASB issued SFAS No. 161, Disclosures about Derivative Instruments and Hedging Activities — an amendment of FASB Statement No. 133 (SFAS No. 161) in March 2008. SFAS No. 161 expands the disclosure requirements for derivative instruments and hedging activities with respect to how and why entities use derivative instruments, how they are accounted for under SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, and the related impact on financial position, financial performance and cash flows. The requirements of this standard will not have a material effect on the Partnership’s disclosure as a result of adoption on January 1, 2009.

The FASB issued SFAS No. 141(R), Business Combinations (SFAS No. 141(R)) in December 2007, which replaces SFAS No. 141, Business Combinations (SFAS No. 141). SFAS No. 141 (R) retains the fundamental requirements of SFAS No. 141 that the acquisition method of accounting be used for all business combinations and for an acquirer to be identified for each business combination, with the objective of improving the relevance and comparability of the information that a reporting entity provides in its financial reports about a business combination and its effects. The requirements of this standard will impact the accounting for business combinations subsequent to January 1, 2009.

YEAR IN REVIEW

TC PipeLines

Liquidity and Capital Resources

In 2008, $13.0 million of the senior term loan was repaid, leaving $475.0 million outstanding under the senior term loan at December 31, 2008. $19.0 million of the senior revolving facility was repaid in 2008, leaving no amount outstanding under the senior revolving credit facility at December 31, 2008. The Partnership has $250.0 million of capacity available under its senior revolving credit facility.

Great Lakes

Operating Revenues

Operating revenues increased in 2008 compared to 2007 primarily due to the timing of the Great Lakes acquisition, which resulted in a full first quarter of income contribution in 2008 as compared to 37 days in the first quarter of 2007. Additionally, increased sales of short-term firm transportation services at higher average transportation rates, as well as increased transport of interruptible services and storage-related services contributed to higher operating revenues, partially offset by decreased long-term services due to capacity turn back and underutilization of contracts. For the year ended December 31, 2008, Great Lakes’ average contracted capacity was near 100 per cent of its average design capacity. As of January 31, 2009, the weighted average remaining life of Great Lakes’ contracts was 2.7 years.

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(1) Great Lakes’ average contracted capacity for the comparative period is calculated for the period March 1 to December 31, 2007.

Michigan Business Tax

Beginning in 2008, the state of Michigan enacted the Michigan Business Tax (MBT) which is an income tax levied at the partnership level. Great Lakes files the MBT return on a unitary basis with certain TransCanada affiliates. A tax payment agreement between Great Lakes and these affiliates provides that Great Lakes’ MBT liability is determined as if a separate return was filed. In 2008, the MBT income tax expense was $5.5 million.

Northern Border

Operating Revenues

Operating revenues in 2008 were lower compared to 2007 primarily due to decreased contracted capacity as a result of the increase of supply competition in Northern Border’s market area, largely from REX West going in-service in 2008. Correspondingly, Northern Border’s average throughput decreased from 2007 to 2008 as shown in the table below. The weighted average life of Northern Border’s contracts increased to 2.1 years at January 31, 2009 from 1.3 years at January 31, 2008. In August 2008, Northern Border conducted a binding open season seeking interest in an expansion project from Harper, Iowa to Manhattan, Illinois and received binding shipper commitments. As a result of an open season, Northern Border renewed approximately 350 MMcf/d at maximum and discount rates, for terms ranging from 5 to 12 years for various transportation paths to Chicago, which eliminated the interest in the proposed expansion project.

Sale of Bison Pipeline LLC

A gain of $16.2 million was recognized on the sale of Northern Border’s wholly-owned subsidiary, Bison Pipeline LLC, which resulted in higher net income in 2008 compared to 2007. Distributions paid in the third quarter of 2008 included a special distribution of $16.4 million due to the sale.

Tuscarora

Operating Revenues

Operating revenues for the year ended December 31, 2008 were higher compared to 2007 primarily due to a new firm transportation service contract that supported the Likely compressor station expansion project that went into service on April 1, 2008 (2008 Expansion Project). Tuscarora’s average throughput and contracted capacity increased in 2008 compared to 2007 as shown in the table below. The weighted average remaining life of Tuscarora’s contracts increased to 11.6 years at January 31, 2009 from 10.4 years at January 31, 2008 due to the contract mentioned above.

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2008 Expansion Project

Tuscarora’s 2008 Expansion Project to support Sierra Pacific Power Company’s Tracy Combined Cycle Power Plant went into service on April 1, 2008, with a final cost of approximately $20.4 million which was within the original cost estimate. The costs will be recovered from rates charged to Sierra Pacific Power under a transportation service agreement for 40,000 Dth/d for a term of 22.5 years. The contract is expected to generate approximately $5.8 million of annual revenue.

Net Income

To supplement our financial statements, we have presented a comparison of the earnings contribution components from each of our investments. We have presented net income in this format in order to enhance investors’ understanding of the way management analyzes our financial performance. We believe this summary provides a more meaningful comparison of our net income to prior years, as we account for our partially owned pipeline systems using the equity method. The presentation of this additional information is not meant to be considered in isolation or as a substitute for results prepared in accordance with GAAP.

The shaded areas in the tables below disclose the results from Great Lakes, Northern Border and Tuscarora, representing 100 per cent of each entity’s operations for the given period.

(1) TC PipeLines owns a 100 per cent general partner interest in Tuscarora following the acqusition of an additional two per cent interest on December 31, 2007.

(2) TC PipeLines acquired a 46.45 per cent general partner interest in Great Lakes on February 22, 2007; therefore, the amounts for 2007 only include results for the period of February 23 to December 31, 2007.

(3) TC PipeLines owns a 50 per cent general partner interest in Northern Border. Equity income from Northern Border includes amortization of a $10.0 million transaction fee paid to the operator of Northern Border at the time of the additional 20 per cent acquisition in April 2006.

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(4) With the acquisition of an additional 49 per cent general partner interest in Tuscarora on December 19, 2006, TC PipeLines changed its method of accounting for this investment from equity accounting to consolidation.

(5) Equity income from TC PipeLines’ investment in Northern Border was based upon its 30 per cent ownership to April 5, 2006 and 50 per cent ownership following the acquisition of an additional 20 per cent general partner interest on April 6, 2006. Equity income from Northern Border includes amortization of a $10.0 million transaction fee paid to the operator of Northern Border at the time of the acquisition.

Year Ended December 31, 2008 Compared with the Year Ended December 31, 2007

Net income increased $18.7 million to $107.7 million in 2008 compared to $89.0 million in 2007. This increase is primarily due to increased financial results from each of our pipeline systems, combined with a reduction in financial charges, net and other at the Partnership level.

Equity income from investment in Great Lakes was $57.3 million in 2008, an increase of $8.3 million compared to $49.0 million for the period February 23 to December 31, 2007. The increase in equity income is primarily due to the timing of the Great Lakes acquisition, which resulted in a full first quarter of income contribution in 2008 as compared to 37 days in the first quarter of 2007. In addition, Great Lakes experienced an overall increase in transmission revenues in 2008 as compared to 2007, offset by increased operating expenses and the implementation of Michigan Business Tax. Transmission revenues increased primarily due to increased sales of short-term firm transportation services at higher average transportation rates, as well as increased transport of interruptible services and storage related services, offset by decreased long-term services. Operating expenses increased primarily due to integration costs related to its acquisition, employee benefit costs, and pipeline inspection costs, partially offset by decreased property and other non-income taxes and lower main engine repair costs. In 2008, Great Lakes recorded Michigan Business Tax of $5.5 million.

Equity income from investment in Northern Border increased $4.1 million to $65.3 million in 2008 compared to 2007. The increase in equity income is primarily due to a $16.2 million (Partnership share - $8.1 million) gain on the sale of Bison Pipeline LLC. Excluding this gain, Northern Border’s net income decreased $4.0 million compared to the prior year due to a $16.3 million decrease in transmission revenues, partially offset by decreased financial charges and operating expenses. Northern Border’s transmission revenues decreased in 2008 compared to the prior year primarily due to a decrease in contracted capacity as natural gas supply from the Rockies Basin into the Mid-Continent market from the in-service of the Western segment of the Rockies Express Pipeline impacted demand. Interest expense decreased in 2008 compared to the prior year due to lower interest rates. Operating expenses decreased in 2008 compared to 2007 primarily due to decreased taxes other than income and a $2.3 million transition related charge in 2007 related to the reimbursement for shared equipment and furnishings, partially offset by increased electric compressor charges..

Tuscarora’s net income was $15.0 million in 2008, an increase of $3.4 million compared to 2007. The increase in net income is primarily due to increased transmission revenues resulting from the 2008 Expansion Project.

Costs at the Partnership level decreased $2.9 million to $29.9 million in 2008 compared to 2007. This decrease relates primarily to lower financial charges as a results of lower interest rates and average debt outstanding, partially offset by losses on interest rate derivatives.

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Year Ended December 31, 2007 Compared with the Year Ended December 31, 2006

Net income increased $44.3 million to $89.0 million in 2007 compared to $44.7 million in 2006. This increase was due primarily to acquisition activities in 2007 and 2006.

Equity income in 2007 included $49.0 million from our investment in Great Lakes, of which we acquired a 46.45 per cent interest on February 22, 2007. At Great Lakes’ level, net income for the period from acquisition to December 31, 2007 was $105.5 million, in line with our expectations. In 2007, approximately 91 per cent of Great Lakes’ transportation revenues were derived from long-term firm service contracts.

Equity income from investment in Northern Border increased $4.6 million to $61.2 million in 2007 compared to 2006 due to the additional 20 per cent general partner interest in Northern Border acquired on April 6, 2006, offset by a reduction in Northern Border’s net income. At Northern Border’s level, slight increases in operating and depreciation expenses, along with a small reduction in transmission revenues contributed to the decrease in net income. Operating expenses increased compared to the prior year primarily due to a $2.3 million transition-related charge in 2007 related to the reimbursement for shared equipment and furnishings acquired by ONEOK Partners and previously used to support Northern Border’s operations. Increases in electric compression charges due to increased usage and electric rates were mostly offset by decreased taxes other than income. Depreciation expense increased compared to the prior year primarily due to the change in depreciation rates effective January 1, 2007 as a result of the 2005 rate case settlement. Excluding the positive impact of the higher ownership interest, the $5.8 million decrease in Northern Border’s net income resulted in a $2.5 million decrease to the Partnership’s net income.

The Partnership’s earnings increased $5.1 million in 2007 as a result of its ownership interest in Tuscarora. Tuscarora contributed $11.4 million to the Partnership’s earnings in 2007, including a $0.2 million non-controlling interest recorded by the Partnership. The Partnership’s earnings increased by $6.0 million due to the additional 49 per cent general partner interest in Tuscarora acquired on December 19, 2006, offset by a $0.9 million decrease due to a reduction in Tuscarora’s net income. The increase in the Partnership’s earnings as a result of acquisitions is partially offset by a $13.8 million increase in the Partnership’s financing costs.

Tuscarora’s net income decreased $1.7 million to $11.6 million in 2007. This decrease was mainly due to a full year impact of the settlement transportation rates that went into effect on June 1, 2006. The decrease in Tuscarora’s net income contributed to a $0.9 million decrease to the Partnership’s net income.

Partnership Cash Flows

The Partnership uses the non-GAAP financial measures ‘Partnership cash flows’ and ‘Partnership cash flows allocated to common units’ as financial performance measures. As the Partnership’s financial performance underpins the availability of cash flows to fund the cash distributions that the Partnership pays to its unitholders, the Partnership believes these are key measures of the available cash flows to its unitholders. The following Partnership cash flows information is presented to enhance investors’ understanding of the way that management analyzes the Partnership’s financial performance. Partnership cash flows and Partnership cash flows allocated to common units are provided as a supplement to financial results and are not meant to be considered in isolation or as substitutes for financial results prepared in accordance with GAAP.

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