Notes to Consolidated Financial Statements

1. Description of TransCanada's Business
2. Accounting Policies
3. Accounting Changes
4. Segmented Information
5. Plant, Property and Equipment
6. Goodwill
7. Rate-Regulated Businesses
8. Joint Venture Investments
9. Intangibles and Other Assets
10. Notes Payable
11. Deferred Amounts
12. Income Taxes
13. Long-Term Debt
14. Long-Term Debt of Joint Ventures
15. Junior Subordinated Notes
16. Non-Controlling Interests
17. Common Shares
18. Preferred Shares
19. Asset Retirement Obligations
20. Employee Future Benefits
21. Risk Management and Financial Instruments
22. Changes in Operating Working Capital
23. Acquisitions and Dispositions
24. Commitments, Contingencies and Guarantees
25. United States Accounting Principles and Reporting

Note 7: Rate-Regulated Businesses

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TransCanada's businesses that apply RRA currently include Canadian and U.S. natural gas pipelines and regulated U.S. natural gas storage. Regulatory assets and liabilities represent future revenues that are expected to be recovered from or refunded to customers based on decisions and approvals by the applicable regulatory authorities.

Canadian Regulated Operations

Canadian natural gas transmission services are supplied under natural gas transportation tariffs that provide for cost recovery, including return of and return on capital as approved by the applicable regulatory authorities.

Rates charged by TransCanada's Canadian regulated pipelines are typically set through a process that involves filing an application with the regulators for a change in rates. Regulated rates are underpinned by the total annual revenue requirement, which comprises a specified annual return on capital, including debt and equity, and all necessary operating expenses, taxes and depreciation.

TransCanada's Canadian regulated natural gas pipelines have generally been subject to a cost-of-service model wherein forecasted costs, including a return on capital, determine the revenues for the upcoming year. To the extent that actual costs and revenues are more or less than the forecasted costs and revenues, the regulators generally allow the difference to be deferred to a future period and recovered or refunded in rates at that time. Differences between actual and forecasted costs that the regulator does not allow to be deferred are included in the determination of net income in the year they are incurred.

The Canadian Mainline, Alberta System, Foothills and TQM pipelines are regulated by the NEB under the National Energy Board Act (Canada). The NEB regulates the construction and operation of facilities, and the terms and conditions of services, including rates, for the Company's Canadian regulated natural gas transmission systems.

In October 2009, the NEB issued a decision that its RH-2-94 Decision, which established a rate of return on common equity (ROE) formula that had formed the basis of determining tolls for natural gas pipelines under NEB jurisdiction since 1995, would no longer be in effect. The decision meant a company's cost of capital will now be determined by negotiations between pipeline companies and their shippers or by the NEB if a pipeline company files a cost of capital application. The decision has affected TransCanada's NEB regulated pipelines. However, the Canadian Mainline continues to base its return on the RH-2-94 ROE formula in accordance with the terms of the current Canadian Mainline tolls settlement, described below.

Canadian Mainline

In 2011, the Canadian Mainline operated under its five-year settlement, which was effective January 1, 2007 to December 31, 2011. The Canadian Mainline's cost of capital for establishing tolls under the settlement reflects ROE as determined by the NEB's RH-2-94 ROE formula on a deemed common equity of 40 per cent. The allowed ROE in 2011 for the Canadian Mainline was 8.08 per cent (2010 – 8.52 per cent). The balance of the capital structure is comprised of short and long-term debt.

The settlement also established the Canadian Mainline's fixed operating, maintenance and administration (OM&A) costs for each of the five years. Variances between actual OM&A costs and those agreed to in the settlement accrued fully to TransCanada from 2007 to 2009. Variances in OM&A costs were shared equally between TransCanada and its customers in 2010 and 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. In 2009, the NEB approved an adjustment account, which was established to reduce tolls in 2010 under a settlement with stakeholders. In accordance with the terms of the settlement, balances in the adjustment account are to be amortized at the composite depreciation rate and included in tolls beginning in 2011.

In September 2011, the NEB approved the Canadian Mainline's interim tolls as final for 2011, including TransCanada's proposal to carry forward any revenue variances into the determination of 2012 tolls. However, the NEB determined that TransCanada's inclusion of certain elements in the proposed 2011 revenue requirement derived in accordance with the 2007-2011 settlement will be examined with TransCanada's 2012-2013 Tolls Application before a final decision is rendered on the 2011 revenue requirement.

Alberta System

In September 2010, the NEB approved the Alberta System's 2010-2012 Revenue Requirement Settlement Application. The settlement provides for a 9.70 per cent ROE on a deemed common equity of 40 per cent and fixes certain annual OM&A costs during the term. Any variances between actual costs and those agreed to in the settlement accrue to TransCanada. All other costs are treated on a flow-through basis.

Foothills

In June 2010, TransCanada reached an agreement to establish a cost of capital for Foothills that reflects a 9.70 per cent ROE on a deemed common equity of 40 per cent for 2010 to 2012. A component of OM&A is fixed, subject to the terms of the B.C System/Foothills Integration Settlement, and variances between actual and fixed amounts were shared with customers up to and including June 2011 when the OM&A savings cap was reached.

TQM

In November 2010, the NEB approved TQM's multi-year settlement with its interested parties regarding its annual revenue requirements for 2010 to 2012. As part of the settlement, the annual revenue requirement comprises fixed and flow-through components. The fixed component includes certain OM&A costs, return on rate base, depreciation and municipal taxes. Any variances between actual costs and those included in the fixed component accrue to TQM.

U.S. Regulated Operations

TransCanada's U.S. natural gas pipelines are "natural gas companies" operating under the provisions of the Natural Gas Act of 1938, the Natural Gas Policy Act of 1978 (NGA) and the Energy Policy Act of 2005, and are subject to the jurisdiction of the FERC. The NGA grants the FERC authority over the construction and operation of pipelines and related facilities. The FERC also has authority to regulate rates for natural gas transportation in interstate commerce. The Company's significant regulated U.S. natural gas pipelines are described below.

ANR

ANR's natural gas transportation and storage services are provided for under tariffs regulated by the FERC. These tariffs include maximum and minimum rates for services and allow 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 that was effective beginning in 1997. ANR Pipeline Company is not required to conduct a review of currently effective rates with the FERC at any time in the future but is not prohibited from filing for new rates if necessary. ANR Storage Company, which is another FERC regulated entity that owns and operates storage fields in Michigan, has rates that were established pursuant to a settlement approved by the FERC that were effective beginning in 1990. ANR Storage Company is currently subject to a review, initiated by the FERC in late 2011, of its existing rates.

In 2011, ANR Pipeline Company filed an application with the FERC to sell its offshore Gulf of Mexico assets and certain related onshore facilities to its wholly owned subsidiary, TC Offshore LLC. At the same time, TC Offshore LLC requested authorization from the FERC to acquire, own and operate those facilities under the FERC's regulations. These filings are currently pending before the FERC and a decision is expected in second or third quarter 2012.

GTN

GTN is regulated by the FERC and operates in accordance with a FERC-approved tariff that establishes maximum and minimum rates for various services. GTN is permitted to discount or negotiate these rates on a non-discriminatory basis. GTN's rates were established pursuant to a settlement approved by the FERC in January 2008. That settlement required GTN to file a rate case within seven years of the effective date. In November 2011, the FERC approved, without modification, GTN's new settlement with its shippers regarding GTN's rates, terms and conditions of service which will become effective January 1, 2012. This new settlement provides for a four year moratorium during which GTN and the settling parties are prohibited from taking certain actions under the NGA, including filings to adjust rates. GTN is required to file for new rates to be effective January 1, 2016.

Great Lakes

Great Lakes is regulated by the FERC and operates in accordance with a FERC-approved tariff that establishes maximum and minimum rates for its various services and permits Great Lakes to discount or negotiate rates on a non-discriminatory basis. Great Lakes rates were established pursuant to a settlement approved by the FERC in July 2010. The settlement included a moratorium on participants and customers from initiating a NGA Section 5 rate case to adjust rates prior to November 1, 2012. In addition, Great Lakes is required to file a NGA Section 4 general rate case no later than November 1, 2013.

Bison

Bison is regulated by the FERC and operates in accordance with a FERC-approved tariff that establishes maximum and minimum rates for various services. Bison is permitted to discount or negotiate these rates on a non-discriminatory basis. Bison's rates were established pursuant to its initial certificate to construct and operate the pipeline that initiated service in January 2011.

Regulatory Assets and Liabilities

Year ended December 31 (millions of dollars) 2011 2010 Remaining Recovery/
Settlement Period (years)
Regulatory Assets      
Future income taxes(1) 1,178 1,256 n/a
Operating and debt-service regulatory assets(2) 172 237 1
Adjustment account(3) 82 85 31
Other(4) 151 174 n/a
  1,583 1,752  
Less: Current portion included in Other Current Assets 178 240  
  1,405 1,512  
       
Regulatory Liabilities      
Foreign exchange on long-term debt(5) 184 200 1 - 18
Operating and debt-service regulatory liabilities(2) 135 98 1
Other(4) 123 150 n/a
  442 448  
Less: Current portion included in Accounts Payable 139 134  
  303 314  
(1) These regulatory assets are underpinned by non-cash transactions or are recovered without an allowance for return as approved by the regulator. Accordingly, these regulatory assets are not included in rate base and do not yield a return on investment during the recovery period.
(2) Operating and debt-service regulatory assets and liabilities represent the accumulation of cost and revenue variances approved by the regulatory authority for inclusion in determining tolls for the following calendar year. Pre-tax operating results in 2011 would have been $102 million higher (2010 – $51 million higher) had these amounts not been recorded as regulatory assets and liabilities.
(3) A regulatory adjustment account of $85 million was established and agreed upon by Canadian Mainline stakeholders to reduce tolls in 2010. Amortization of the adjustment account commenced in 2011 at the composite depreciation rate.
(4) Pre-tax operating results in 2011 would have been $4 million lower (2010 – $28 million higher) had these amounts not been recorded as regulatory assets and liabilities.
(5) Foreign exchange on long-term debt of the Canadian Mainline, Alberta System and Foothills represents the variance resulting from revaluing foreign currency-denominated debt instruments to the current foreign exchange rate from the historical foreign exchange rate at the time of issue. Foreign exchange gains and losses realized when foreign debt matures or is redeemed early are expected to be recovered or refunded through the determination of future tolls. In the absence of RRA, CGAAP would have required the inclusion of these unrealized gains or losses in Net Income.