RATE-REGULATED BUSINESSES

TCPL's businesses that apply RRA currently include Canadian, U.S. and Mexican natural gas pipelines, regulated U.S. natural gas storage and certain Canadian liquids pipelines. Rate-regulated businesses account for and report assets and liabilities consistent with the economic impact of the way in which regulators establish rates, provided the rates established are designed to recover the costs of providing the regulated service and the competitive environment makes it probable that such rates can be charged and collected. Certain expenses and credits subject to utility regulation or rate determination normally reflected in the income statement are deferred on the balance sheet and are recognized in the income statement as the related amounts are included in service rates and recovered from or refunded to customers.

Canadian Regulated Operations

TCPL's Canadian natural gas pipelines are regulated by the NEB under the National Energy Board Act. 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.

TCPL's 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 NEB. Rates charged for these services are typically set through a process that involves filing an application with the regulator wherein forecasted operating costs, including a return of and on capital, determine the revenue requirement for the upcoming year or multiple years. 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 occur. The Company's significant Canadian natural gas pipelines are described below.

NGTL System

In April 2016, the NEB approved the NGTL System’s 2016-2017 Revenue Requirement Settlement. The terms of the two-year settlement include an ROE of 10.1 per cent on 40 per cent deemed equity, a continuation of the 2015 depreciation rates, a mechanism for sharing variances above and below a fixed annual operating, maintenance and administration (OM&A) cost amount and flow-through treatment of all other costs.

The NGTL System’s 2015 results reflect the terms of the 2015 Revenue Requirement Settlement. This one year settlement included a 10.1 per cent ROE on deemed common equity of 40 per cent, a continuation of the 2014 depreciation rates, a mechanism for sharing variances above and below a fixed annual OM&A cost amount that was based on an escalation of 2014 actual costs and flow-through treatment of all other costs.

The NGTL System’s 2014 results reflect the terms of the 2013-2014 Revenue Requirement Settlement Application. This settlement included fixed annual OM&A costs and a 10.1 per cent ROE on a deemed common equity of 40 per cent and a continuation of 2013 depreciation rates. Any variance between fixed OM&A costs in the settlement and actual costs accrued to TCPL.

Canadian Mainline

The Canadian Mainline currently operates under the terms of the 2015-2030 Tolls Application approved in 2014 (the NEB 2014 Decision). The terms of the settlement include an ROE of 10.1 per cent on deemed common equity of 40 per cent, an incentive mechanism that has both upside and downside risk and a $20 million after-tax annual TCPL contribution to reduce the revenue requirement. Toll stabilization is achieved through the continued use of deferral accounts, namely the long-term adjustment account (LTAA) and the bridging amortization account, to capture the surplus or the shortfall between the Company's revenues and cost of service for each year over the six-year fixed toll term of the NEB 2014 Decision. A toll review filing will be required for the 2018 to 2020 period.

The Canadian Mainline's 2014 results reflect the terms of the NEB 2013 Decision. The decision established an ROE of 11.5 per cent on deemed common equity of 40 per cent and included mechanisms to achieve fixed tolls through use of the LTAA as well as establishment of a Tolls Stabilization Account (TSA) to capture the surplus or the shortfall between revenues and cost of service for each year over the five-year term of the decision. In addition, the NEB 2013 Decision provided an opportunity to generate incentive earnings by increasing revenues and reducing costs.

U.S. Regulated Operations

TCPL's U.S. natural gas pipelines operate 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, including the regulation of tariffs which incorporates maximum and minimum rates for services and allows U.S. natural gas pipelines to discount or negotiate rates on a non-discriminatory basis. The Company's significant regulated U.S. natural gas pipelines, based on effective ownership and total operated pipe length, are described below.

Columbia Gas

Columbia Gas' natural gas transportation and storage services are provided under a tariff at rates subject to FERC approval. In 2013, the FERC approved a modernization settlement which provides for cost recovery and return on investment of up to

US$1.5 billion over a five-year period to modernize the Columbia Gas system to improve system integrity and enhance service reliability and flexibility. In March 2016, an extension of this settlement was approved by the FERC, which will allow for the cost recovery and return on additional expanded scope investment of US$1.1 billion over a three-year period through 2020.

Columbia Gulf

Columbia Gulf’s natural gas transportation services are provided under a tariff at rates subject to FERC approval. In September 2016, the FERC issued an order approving an uncontested settlement following a FERC-initiated rate proceeding pursuant to section 5 of the NGA, which required a reduction in Columbia Gulf’s daily maximum recourse rate and addressed treatment of post-retirement benefits other than pensions, pension expense, and regulatory expenses. The FERC order also requires Columbia Gulf to file a general rate case under section 4 of the NGA by January 31, 2020, for rates to take effect by August 1, 2020.

ANR Pipeline Company

ANR Pipeline Company previously operated under rates established pursuant to a settlement approved by the FERC that was effective for all periods presented, beginning in 1997 through July 31, 2016. Effective August 1, 2016, ANR Pipeline Company began operating under new rates pursuant to a FERC-approved rate settlement in September 2016. Under terms of the September 2016 settlement, neither ANR Pipeline Company nor the settling parties can file to change or modify the new settlement rates to become effective earlier than August 1, 2019. However, ANR Pipeline Company is required to file for new rates to be effective no later than August 1, 2022.

Great Lakes

Great Lakes operates under rates established pursuant to a settlement approved by the FERC in November 2013. Under the settlement, Great Lakes is required to file for new rates to be effective no later than January 1, 2018.

Mexico Regulated Operations

TCPL's Mexican operations are regulated by the CRE and operate in accordance with CRE-approved tariffs. The rates in effect on TCPL's Mexican gas pipelines were established based on CRE-approved contracts that provide for the recovery of costs of providing services.

Regulatory Assets and Liabilities



at December 31	2016	2015	Remaining Recovery/ Settlement Period (years)
(millions of Canadian $)	2016	2015	Remaining Recovery/ Settlement Period (years)

Regulatory Assets
Deferred income taxes¹	861	894	n/a
Operating and debt-service regulatory assets²	1	47	1
Pensions and other post retirement benefits³	382	210	n/a
Foreign exchange on long-term debt^1,4	37	54	1-13
Other	74	64	n/a
	1,355	1,269
Less: Current portion included in Other current assets (Note 7)	33	85
	1,322	1,184

Regulatory Liabilities
Operating and debt-service regulatory liabilities²	47	32	1
Pensions and other post retirement benefits³	180	—	n/a
ANR related post-employment and retirement benefits other than pension⁵	141	147	n/a
Long term adjustment account⁶	659	231	45
Pipeline abandonment costs	541	285	n/a
Bridging amortization account⁶	451	456	14
Cost of removal⁷	226	36	n/a
Other	54	16	n/a
	2,299	1,203
Less: Current portion included in Accounts payable and other (Note 14)	178	44
	2,121	1,159


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.


3	These balances represent the regulatory offset to pension plan and other post-retirement obligations to the extent the amounts are expected to be collected from customers in future rates. The balances are excluded from the rate base and do not earn a return on investment.

Foreign exchange on long-term debt of the NGTL System 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.

This balance represents what ANR estimated that it would be required to refund to its customers for post-retirement and post-employment benefit amounts collected through its FERC-approved rates that have not been used to pay benefits to its employees since a 1997 rate settlement. Pursuant to a FERC-approved September 2016 rate settlement, $106 million of the regulatory liability balance that accumulated between January 2007 and July 2016 will be resolved through a refund of $53 million to its customers and ANR amortizing $53 million over a three year period that began August 1, 2016. A remaining $41 million balance accumulated prior to 2007 is subject to resolution through future regulatory proceedings, and accordingly a settlement period cannot be determined at this time.


6	These regulatory accounts are used to capture Canadian Mainline revenue and cost variances and stabilize tolls during the 2015-2030 settlement term.


7	This balance represents anticipated costs of removal that have been, and continue to be, included in depreciation rates and collected in the service rates of certain rate-regulated subsidiaries for future costs to be incurred.