Natural Gas Pipelines

Natural Gas Pipelines

Financial Analysis

Canadian Mainline

The Canadian Mainline is regulated by the NEB under the National Energy Board Act (Canada). The NEB sets tolls that provide TransCanada with the opportunity to recover the costs of transporting natural gas, including a return on average investment base. The Canadian Mainline's EBITDA and net income are affected by changes in investment base, the rate of return on common equity (ROE), the level of deemed common equity, potential incentive earnings and changes in the level of depreciation, financial charges and income taxes recovered in revenue on a flow-through basis.

The Canadian Mainline currently operates under a five-year tolls settlement effective from 2007 through 2011. The cost of capital reflects an ROE as determined by the NEB's ROE formula on deemed common equity of 40 per cent. The tolls settlement established certain elements of the Canadian Mainline's fixed OM&A costs for each of the five years. The variance between actual and agreed-upon OM&A costs accrued entirely to TransCanada from 2007 to 2009, and was shared equally between TransCanada and its customers in 2010, and will be shared equally in 2011. All other cost elements of the revenue requirement are treated on a flow-through basis. The settlement also allows for performance-based incentive arrangements that the Company believes are mutually beneficial to TransCanada and its customers. In 2009, an adjustment charge account was established under a settlement with stakeholders and approved by the NEB to reduce tolls in 2010. In accordance with the terms of the settlement, balances in an adjustment charge account in any given year will be amortized at the composite depreciation rate and included in tolls commencing the following year.

Net income of $267 million in 2010 was $6 million lower than $273 million in 2009. The decrease was primarily the result of lower OM&A savings as a result of cost-sharing with customers and an ROE of 8.52 per cent in 2010 compared to 8.57 per cent in 2009. Net income in 2009 was $5 million lower than $278 million in 2008 as a result of a lower average investment base and lower ROE of 8.57 per cent in 2009 compared to 8.71 per cent in 2008.

Canadian Mainline's Comparable EBITDA of $1,054 million in 2010 was $79 million lower than $1,133 million in 2009, primarily due to reduced revenues as a result of lower income taxes and financial charges in the 2010 tolls, which are recovered on a flow-through basis and do not affect net income. The decrease in financial charges was primarily due to higher-cost debt that matured in 2009 and early 2010. The lower income taxes in 2010 were primarily due to the adjustment charge that decreased taxable income. Comparable EBITDA in 2009 declined $8 million from $1,141 million in 2008. The decrease was primarily due to lower revenues as a result of recovery of a lower overall return on a reduced average investment base and a lower ROE in 2009. The decrease in 2009 revenues was partially offset by higher OM&A cost savings and recovery of higher depreciation.

Canadian Mainline Net Income
Canadian Mainline Average Investment Base
Canadian Mainline Capital Expenditures

Alberta System

The Alberta System is also regulated by the NEB, which approves the Alberta System's tolls and revenue requirement. The Alberta System's EBITDA and net income are affected by changes in investment base, the ROE, the level of deemed common equity, potential incentive earnings and changes in the level of depreciation, financial charges and income taxes recovered in revenue on a flow-through basis.

The Alberta System currently operates under the 2010 - 2012 Revenue Requirement Settlement approved by the NEB in September 2010. In October 2010, the NEB approved TransCanada's application to establish final tolls for 2010. In 2008 and 2009, the Alberta System operated under the 2008 - 2009 Revenue Requirement Settlement approved by the Alberta Utilities Commission (AUC) in December 2008. The Alberta System was regulated by the AUC until April 2009.

The 2010 - 2012 Revenue Requirement Settlement established an ROE of 9.70 per cent on deemed common equity of 40 per cent and included an annual fixed amount of $174 million for certain OM&A costs. Variances between actual and agreed-to OM&A costs accrue to TransCanada over the three-year term. All other cost elements of the revenue requirement are treated on a flow-through basis.

The 2008 - 2009 Revenue Requirement Settlement established fixed amounts for ROE, income taxes and certain OM&A costs. Variances between actual costs and those agreed to in the settlement accrued to TransCanada, subject to an ROE and income tax adjustment mechanism that accounted for variances between actual and settlement rate base, and income tax assumptions. The other cost elements of the settlement were treated on a flow-though basis.

The Alberta System's net income of $198 million in 2010 was $30 million higher than $168 million in 2009. The increase reflects an ROE of 9.70 per cent on 40 per cent deemed common equity in 2010 and a higher average investment base, partially offset by lower incentive earnings. Net income in 2009 was $23 million higher than $145 million in 2008 primarily due to higher settlement earnings and a higher average investment base in 2009. The increased average investment base reflected capital expenditures from 2008 to 2010 to expand capacity in response to growing customer demand for service.

The Alberta System's Comparable EBITDA of $742 million in 2010 was $14 million higher than $728 million in 2009. The increase reflects an ROE of 9.70 per cent on 40 per cent deemed common equity in 2010 and a higher average investment base, partially offset by lower incentive earnings, and lower financial charges and depreciation recovered on a flow-through basis. Comparable EBITDA in 2009 was $36 million higher than $692 million in 2008 primarily due to increased settlement earnings and a higher average investment base as well as higher revenues as a result of the recovery of higher financial charges, partially offset by lower income taxes.

Alberta System Net Income
Alberta System Average Investment Base
Alberta System Capital Expenditures

Foothills

Net income and Comparable EBITDA from Foothills increased $4 million and $3 million, respectively, in 2010 from 2009 primarily due to a Foothills 2010 settlement agreement, which established an ROE of 9.70 per cent on deemed common equity of 40 per cent for 2010 through 2012. Results in 2009 and 2008 were based on the NEB ROE formula of 8.57 per cent and 8.71 per cent, respectively, on deemed common equity of 36 per cent.

Other Canadian Natural Gas Pipelines

Comparable EBITDA from Other Canadian Natural Gas Pipelines was $50 million in 2010 compared to $59 million in 2009. The decrease was primarily due to an adjustment in 2009 related to the NEB decision reached in March 2009 on Trans Québec and Maritimes' (TQM) cost of capital for 2007 and 2008. Comparable EBITDA in 2009 increased $9 million from $50 million in 2008, primarily due to the adjustment in 2009.

ANR

American Natural Resources' (ANR) natural gas storage and transportation services are regulated by the U.S. Federal Energy Regulatory Commission (FERC) and services are provided under tariffs. These tariffs include maximum and minimum rates for services and permit ANR to discount or negotiate rates on a non-discriminatory basis. ANR Pipeline Company rates were established pursuant to a settlement approved by the FERC and became effective beginning in 1997. ANR Storage Company's rates were established pursuant to a settlement approved by the FERC and became effective beginning in 1990. None of ANR's FERC-regulated operations are required to file for new rates at any time in the future, nor are any of the operations prohibited from filing a case for new rates.

ANR's EBITDA is affected by the contracting and pricing of its existing transportation and storage capacity, expansion projects, delivered volumes and incidental natural gas sales, as well as by costs for providing various services, which include OM&A costs and property taxes. Due to the seasonal nature of its business, ANR's volumes and revenues are generally higher in the winter months.

ANR's Comparable EBITDA in 2010 was US$314 million, an increase of US$14 million compared to US$300 million in 2009, primarily due to lower OM&A costs, partially offset by lower contracted firm long-haul transportation sales and storage revenues as higher regional storage inventories and marginal supply from the U.S. Gulf Coast negatively affected transportation rates and demand for natural gas. Comparable EBITDA in 2009 decreased US$27 million compared to US$327 million in 2008. The decrease was due to lower incidental natural gas sales and higher OM&A costs, partially offset by higher transportation and storage revenues resulting from expansion projects, increased utilization and favourable pricing on existing capacity.

GTN

GTN is regulated by the FERC and is operated in accordance with tariffs that establish maximum and minimum rates for various services. GTN's pipeline rates were established pursuant to a settlement approved by the FERC in January 2008. These rates were effective January 1, 2007. GTN is permitted to discount or negotiate these rates on a non-discriminatory basis. Under the settlement, a five-year moratorium commencing January 1, 2007 was established during which GTN and the settling parties are prohibited from taking certain actions, including any filings to adjust rates. The settlement also requires GTN to file for new rates that are to be in effect no later than January 1, 2014.

GTN's EBITDA is affected by variations in contracted volume levels, volumes delivered and prices charged under the various service types as well as by variations in the costs of providing services, which include OM&A costs and property taxes.

GTN's Comparable EBITDA was US$171 million in 2010, an increase of US$1 million compared to US$170 million in 2009. The increase was primarily due to lower OM&A costs and incremental proceeds accrued in 2010 relating to bankruptcy distributions with Calpine, partially offset by the impact of selling North Baja to PipeLines LP in July 2009 and the write-off of costs in 2010 related to an unsuccessful information systems project. Comparable EBITDA in 2009 decreased US$15 million, compared to US$185 million in 2008, primarily due to the sale of North Baja to PipeLines LP.

Other U.S. Natural Gas Pipelines

Comparable EBITDA for the remainder of the U.S. Natural Gas Pipelines was US$481 million in 2010 and US$488 million in 2009. The decrease was primarily due to lower Great Lakes revenues, and higher general, administrative and support costs primarily related to the start-up of Keystone. Partially offsetting these decreases were increased revenues from Northern Border and higher PipeLines LP earnings in 2010 primarily due to its acquisition of North Baja in July 2009. Comparable EBITDA in 2009 increased US$24 million from US$464 million in 2008, primarily due to PipeLines LP's acquisition of North Baja.

Business Development

Natural Gas Pipelines' Business Development Comparable EBITDA loss in 2010 was consistent with 2009. Comparable EBITDA losses increased to $62 million in 2009 from $37 million in 2008 primarily due to higher business development costs associated with the Alaska Pipeline Project.

Depreciation and Amortization

Depreciation and Amortization for Natural Gas Pipelines was $977 million in 2010, a decrease of $53 million from $1,030 million in 2009. The decrease was primarily due to a weaker U.S. dollar in 2010 and lower depreciation for Great Lakes as a result of the lower depreciation rate in its rate settlement. Depreciation and Amortization increased $41 million to $1,030 million in 2009 from $989 million in 2008 primarily due to the stronger U.S. dollar in 2009.