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Regulatory Assets and Liabilities (Tables) | 12 Months Ended
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Dec. 31, 2016
Regulated Operations [Abstract] |
Schedule of Regulatory Assets | Based on previous, existing or expected regulatory orders or decisions, the Corporation’s regulated utilities have recognized the following amounts that are expected to be recovered from, or refunded to, customers in future periods.
|  |  | Remaining recovery period
(in millions) | 2016 |  | 2015 |  | (Years)
Regulatory assets |  |  |
Deferred income taxes (i) | $ | 1,260 |  | $ | 936 |  | To be determined
Employee future benefits (ii) | 576 |  | 627 |  | Various
Rate stabilization accounts (iii) | 183 |  | 119 |  | Various
Deferred energy management costs (iv) | 178 |  | 145 |  | 1-10
Manufactured gas plant (“MGP”) site remediation deferral (v) | 107 |  | 121 |  | To be determined
Deferred lease costs (vi) | 97 |  | 90 |  | Various
Deferred operating overhead costs (vii) | 78 |  | 66 |  | Various
Natural gas for transportation incentives (viii) | 40 |  | 25 |  | 10
Derivative instruments (ix) | 19 |  | 74 |  | Various
Other regulatory assets (x) | 395 |  | 329 |  | Various
Total regulatory assets | 2,933 |  | 2,532 |  |
Less: current portion | (313 | ) | (246 | ) | 1
Long-term regulatory assets | $ | 2,620 |  | $ | 2,286 |  |
Regulatory liabilities |  |  |
Non-ARO removal cost provision (xi) | $ | 1,194 |  | $ | 1,060 |  | To be determined
ROE refund liability (xii) | 346 |  | — |  | 2
Rate stabilization accounts (iii) | 230 |  | 212 |  | Various
Electric and gas moderator account (xiii) | 71 |  | 88 |  | To be determined
Renewable energy surcharge (xiv) | 53 |  | 47 |  | To be determined
Energy efficiency liability (xv) | 49 |  | 20 |  | Various
Employee future benefits (ii) | 42 |  | 44 |  | Various
Other regulatory liabilities (xvi) | 198 |  | 167 |  | Various
Total regulatory liabilities | 2,183 |  | 1,638 |  |
Less: current portion | (492 | ) | (298 | ) | 1
Long-term regulatory liabilities | $ | 1,691 |  | $ | 1,340 |  |
8. REGULATORY ASSETS AND LIABILITIES (cont’d) Description of the Nature of Regulatory Assets and Liabilities
(i) | Deferred Income Taxes
The Corporation’s regulated utilities recognize deferred income tax assets and liabilities and related regulatory liabilities and assets for the amount of deferred income taxes expected to be refunded to, or recovered from, customers in future rates. As at December 31, 2016, $596 million (December 31, 2015 - $351 million) in regulatory assets for deferred income taxes was not subject to a regulatory return.
(ii) | Employee Future Benefits
The regulatory asset and liability associated with employee future benefits includes the actuarially determined unamortized net actuarial losses, past service costs and credits, and transitional obligations associated with defined benefit pension and OPEB plans maintained by the Corporation’s regulated utilities, which are expected to be recovered from, or refunded to, customers in future rates (Note 26). At the Corporation’s regulated utilities, as approved by the respective regulators, differences between defined benefit pension and OPEB plan costs recognized under US GAAP and those which are expected to be recovered from, or refunded to, customers in future rates are subject to deferral account treatment and have been recognized as a regulatory asset or liability. These amounts would otherwise be recognized in accumulated other comprehensive income on the consolidated balance sheet. As at December 31, 2016, regulatory assets of approximately $346 million associated with employee future benefits were not subject to a regulatory return (December 31, 2015 - $367 million). As at December 31, 2016, regulatory liabilities of approximately $31 million associated with employee future benefits were not subject to a regulatory return (December 31, 2015 - $36 million).
(iii) | Rate Stabilization Accounts
Rate stabilization accounts associated with the Corporation’s regulated utilities are recovered from, or refunded to, customers in future rates, as approved by the respective regulators. Electric rate stabilization accounts primarily mitigate the effect on earnings of variability in the cost of fuel and/or purchased power above or below a forecast or predetermined level and, at certain utilities, revenue decoupling mechanisms minimize the earnings impact resulting from reduced energy consumption as energy efficiency programs are implemented. Gas rate stabilization accounts primarily mitigate the effect on earnings of unpredictable and uncontrollable factors, namely volume volatility caused principally by weather, and natural gas cost volatility. At ITC, transmission revenue requirements are set annually using cost-based formula rates that remain in effect for a one-year period. The formula rates include a true-up mechanism, whereby the actual revenue requirement is compared to billed revenue for each year to determine any over-or under-collection of revenue requirement. Revenue is recognized based on the actual revenue requirement, and revenue accrual and deferral accounts represent the difference between the actual revenue requirement and billed revenue, and are collected from, or refunded to, customers within a two-year period. Included in the rate stabilization accounts at ITC is US$29 million related to regional cost allocation recovery for refunds ITC paid to other regional transmission organizations, which will be recovered from network customers in 2017. As at December 31, 2016, approximately $135 million and $173 million of the rate stabilization accounts are expected to be recovered from, or refunded to, customers within one year and, as a result, are classified as current regulatory assets and liabilities, respectively (December 31, 2015 -approximately $49 million and $142 million, respectively). 8. REGULATORY ASSETS AND LIABILITIES (cont’d) Description of the Nature of Regulatory Assets and Liabilities (cont’d)
(iii) | Rate Stabilization Accounts (cont’d)
As at December 31, 2016, regulatory assets of approximately $139 million associated with rate stabilization accounts were not subject to a regulatory return (December 31, 2015 ‑ $44 million). As at December 31, 2016, regulatory liabilities of approximately $180 million associated with rate stabilization accounts were not subject to a regulatory return (December 31, 2015 ‑ $123 million).
(iv) | Deferred Energy Management Costs
FortisBC Energy, FortisBC Electric, Central Hudson and Newfoundland Power provide energy management services to promote energy efficiency programs to their customers. As required by their respective regulator, these regulated utilities have capitalized related expenditures and are amortizing these expenditures on a straight-line basis over periods ranging from 1 to 10 years. This regulatory asset represents the unamortized balance of the energy management costs. UNS Energy is required to implement cost-effective Demand-Side Management (“DSM”) programs to comply with the ACC’s energy efficiency standards. The energy efficiency standards provide for a DSM surcharge to recover the costs of implementing DSM programs, as well as an annual performance incentive. The existing rate orders provide for a lost fixed-cost recovery mechanism to recover certain non-fuel costs that were previously unrecoverable, due to reduced electricity sales as a result of energy efficiency programs and distributed generation. As at December 31, 2016, $42 million of the regulatory asset balance associated with deferred energy management costs was not subject to a regulatory return (December 31, 2015 - $25 million).
(v) | MGP Site Remediation Deferral
As approved by the regulator, Central Hudson is permitted to defer for future recovery from its customers the difference between actual costs for MGP site investigation and remediation and the associated rate allowances (Notes 13 and 16). Central Hudson’s MGP site remediation costs are not subject to a regulatory return. (vi) Deferred Lease Costs Deferred lease costs at FortisBC Electric primarily relate to the Brilliant Power Purchase Agreement (“BPPA”), which ends in 2056. The depreciation of the asset under capital lease and interest expense associated with the capital lease obligation are not being fully recovered in current customer rates, since those rates include only the cash payments set out under the BPPA. The deferred lease costs are expected to be recovered from customers in future rates over the term of the lease and are not subject to a regulatory return. In 2016, of the $31 million (2015 - $30 million) of interest expense related to the capital lease obligations and the $6 million (2015 - $6 million) of depreciation expense related to the assets under capital lease, $27 million (2015 - $26 million) was recognized in energy supply costs and $3 million (2015 - $3 million) was recognized in operating expenses, as approved by the regulator, with the balance of $7 million (2015 - $7 million) deferred as a regulatory asset (Note 15).
(vii) | Deferred Operating Overhead Costs
As approved by the regulator, FortisAlberta has deferred certain operating overhead costs. The deferred costs are expected to be collected in future customer rates over the lives of the related utility capital and intangible assets. 8. REGULATORY ASSETS AND LIABILITIES (cont’d) Description of the Nature of Regulatory Assets and Liabilities (cont’d)
(viii) | Natural Gas for Transportation Incentives
The deferral for natural gas transportation incentives at FortisBC Energy is comprised of subsidy payments to assist customers in purchasing natural gas vehicles in lieu of vehicles fueled by diesel as part of the incentive program pursuant to the greenhouse gas reductions regulations under the Clean Energy Act (British Columbia). The regulator has approved recovery in rates over a 10-year period.
(ix) | Derivative Instruments
As approved by the respective regulators, unrealized gains or losses associated with changes in the fair value of certain derivative instruments at UNS Energy, Central Hudson and FortisBC Energy are deferred as a regulatory asset or liability for recovery from, or refund to, customers in future rates. These unrealized losses and gains would otherwise be recognized in earnings. UNS Energy and Central Hudson’s regulatory asset balance totalling $6 million as at December 31, 2016 was not subject to a regulatory return (December 31, 2015 - $57 million).
(x) | Other Regulatory Assets
Other regulatory assets relate to all of the Corporation’s regulated utilities and are comprised of various items, each individually less than $40 million. As at December 31, 2016, $296 million (December 31, 2015 - $265 million) of the balance was approved to be recovered from customers in future rates, with the remaining balance expected to be approved. As at December 31, 2016, $217 million (December 31, 2015 ‑ $168 million) of the balance was not subject to a regulatory return.
Schedule of Regulatory Liabilities | Based on previous, existing or expected regulatory orders or decisions, the Corporation’s regulated utilities have recognized the following amounts that are expected to be recovered from, or refunded to, customers in future periods.
|  |  | Remaining recovery period
(in millions) | 2016 |  | 2015 |  | (Years)
Regulatory assets |  |  |
Deferred income taxes (i) | $ | 1,260 |  | $ | 936 |  | To be determined
Employee future benefits (ii) | 576 |  | 627 |  | Various
Rate stabilization accounts (iii) | 183 |  | 119 |  | Various
Deferred energy management costs (iv) | 178 |  | 145 |  | 1-10
Manufactured gas plant (“MGP”) site remediation deferral (v) | 107 |  | 121 |  | To be determined
Deferred lease costs (vi) | 97 |  | 90 |  | Various
Deferred operating overhead costs (vii) | 78 |  | 66 |  | Various
Natural gas for transportation incentives (viii) | 40 |  | 25 |  | 10
Derivative instruments (ix) | 19 |  | 74 |  | Various
Other regulatory assets (x) | 395 |  | 329 |  | Various
Total regulatory assets | 2,933 |  | 2,532 |  |
Less: current portion | (313 | ) | (246 | ) | 1
Long-term regulatory assets | $ | 2,620 |  | $ | 2,286 |  |
Regulatory liabilities |  |  |
Non-ARO removal cost provision (xi) | $ | 1,194 |  | $ | 1,060 |  | To be determined
ROE refund liability (xii) | 346 |  | — |  | 2
Rate stabilization accounts (iii) | 230 |  | 212 |  | Various
Electric and gas moderator account (xiii) | 71 |  | 88 |  | To be determined
Renewable energy surcharge (xiv) | 53 |  | 47 |  | To be determined
Energy efficiency liability (xv) | 49 |  | 20 |  | Various
Employee future benefits (ii) | 42 |  | 44 |  | Various
Other regulatory liabilities (xvi) | 198 |  | 167 |  | Various
Total regulatory liabilities | 2,183 |  | 1,638 |  |
Less: current portion | (492 | ) | (298 | ) | 1
Long-term regulatory liabilities | $ | 1,691 |  | $ | 1,340 |  |
8. REGULATORY ASSETS AND LIABILITIES (cont’d) Description of the Nature of Regulatory Assets and Liabilities
(i) | Deferred Income Taxes
The Corporation’s regulated utilities recognize deferred income tax assets and liabilities and related regulatory liabilities and assets for the amount of deferred income taxes expected to be refunded to, or recovered from, customers in future rates. As at December 31, 2016, $596 million (December 31, 2015 - $351 million) in regulatory assets for deferred income taxes was not subject to a regulatory return.
(ii) | Employee Future Benefits
The regulatory asset and liability associated with employee future benefits includes the actuarially determined unamortized net actuarial losses, past service costs and credits, and transitional obligations associated with defined benefit pension and OPEB plans maintained by the Corporation’s regulated utilities, which are expected to be recovered from, or refunded to, customers in future rates (Note 26). At the Corporation’s regulated utilities, as approved by the respective regulators, differences between defined benefit pension and OPEB plan costs recognized under US GAAP and those which are expected to be recovered from, or refunded to, customers in future rates are subject to deferral account treatment and have been recognized as a regulatory asset or liability. These amounts would otherwise be recognized in accumulated other comprehensive income on the consolidated balance sheet. As at December 31, 2016, regulatory assets of approximately $346 million associated with employee future benefits were not subject to a regulatory return (December 31, 2015 - $367 million). As at December 31, 2016, regulatory liabilities of approximately $31 million associated with employee future benefits were not subject to a regulatory return (December 31, 2015 - $36 million).
(iii) | Rate Stabilization Accounts
Rate stabilization accounts associated with the Corporation’s regulated utilities are recovered from, or refunded to, customers in future rates, as approved by the respective regulators. Electric rate stabilization accounts primarily mitigate the effect on earnings of variability in the cost of fuel and/or purchased power above or below a forecast or predetermined level and, at certain utilities, revenue decoupling mechanisms minimize the earnings impact resulting from reduced energy consumption as energy efficiency programs are implemented. Gas rate stabilization accounts primarily mitigate the effect on earnings of unpredictable and uncontrollable factors, namely volume volatility caused principally by weather, and natural gas cost volatility. At ITC, transmission revenue requirements are set annually using cost-based formula rates that remain in effect for a one-year period. The formula rates include a true-up mechanism, whereby the actual revenue requirement is compared to billed revenue for each year to determine any over-or under-collection of revenue requirement. Revenue is recognized based on the actual revenue requirement, and revenue accrual and deferral accounts represent the difference between the actual revenue requirement and billed revenue, and are collected from, or refunded to, customers within a two-year period. Included in the rate stabilization accounts at ITC is US$29 million related to regional cost allocation recovery for refunds ITC paid to other regional transmission organizations, which will be recovered from network customers in 2017. As at December 31, 2016, approximately $135 million and $173 million of the rate stabilization accounts are expected to be recovered from, or refunded to, customers within one year and, as a result, are classified as current regulatory assets and liabilities, respectively (December 31, 2015 -approximately $49 million and $142 million, respectively). 8. REGULATORY ASSETS AND LIABILITIES (cont’d) Description of the Nature of Regulatory Assets and Liabilities (cont’d)
(iii) | Rate Stabilization Accounts (cont’d)
As at December 31, 2016, regulatory assets of approximately $139 million associated with rate stabilization accounts were not subject to a regulatory return (December 31, 2015 ‑ $44 million). As at December 31, 2016, regulatory liabilities of approximately $180 million associated with rate stabilization accounts were not subject to a regulatory return (December 31, 2015 ‑ $123 million).
(iv) | Deferred Energy Management Costs
FortisBC Energy, FortisBC Electric, Central Hudson and Newfoundland Power provide energy management services to promote energy efficiency programs to their customers. As required by their respective regulator, these regulated utilities have capitalized related expenditures and are amortizing these expenditures on a straight-line basis over periods ranging from 1 to 10 years. This regulatory asset represents the unamortized balance of the energy management costs. UNS Energy is required to implement cost-effective Demand-Side Management (“DSM”) programs to comply with the ACC’s energy efficiency standards. The energy efficiency standards provide for a DSM surcharge to recover the costs of implementing DSM programs, as well as an annual performance incentive. The existing rate orders provide for a lost fixed-cost recovery mechanism to recover certain non-fuel costs that were previously unrecoverable, due to reduced electricity sales as a result of energy efficiency programs and distributed generation. As at December 31, 2016, $42 million of the regulatory asset balance associated with deferred energy management costs was not subject to a regulatory return (December 31, 2015 - $25 million).
(v) | MGP Site Remediation Deferral
As approved by the regulator, Central Hudson is permitted to defer for future recovery from its customers the difference between actual costs for MGP site investigation and remediation and the associated rate allowances (Notes 13 and 16). Central Hudson’s MGP site remediation costs are not subject to a regulatory return. (vi) Deferred Lease Costs Deferred lease costs at FortisBC Electric primarily relate to the Brilliant Power Purchase Agreement (“BPPA”), which ends in 2056. The depreciation of the asset under capital lease and interest expense associated with the capital lease obligation are not being fully recovered in current customer rates, since those rates include only the cash payments set out under the BPPA. The deferred lease costs are expected to be recovered from customers in future rates over the term of the lease and are not subject to a regulatory return. In 2016, of the $31 million (2015 - $30 million) of interest expense related to the capital lease obligations and the $6 million (2015 - $6 million) of depreciation expense related to the assets under capital lease, $27 million (2015 - $26 million) was recognized in energy supply costs and $3 million (2015 - $3 million) was recognized in operating expenses, as approved by the regulator, with the balance of $7 million (2015 - $7 million) deferred as a regulatory asset (Note 15).
(vii) | Deferred Operating Overhead Costs
As approved by the regulator, FortisAlberta has deferred certain operating overhead costs. The deferred costs are expected to be collected in future customer rates over the lives of the related utility capital and intangible assets. 8. REGULATORY ASSETS AND LIABILITIES (cont’d) Description of the Nature of Regulatory Assets and Liabilities (cont’d)
(viii) | Natural Gas for Transportation Incentives
The deferral for natural gas transportation incentives at FortisBC Energy is comprised of subsidy payments to assist customers in purchasing natural gas vehicles in lieu of vehicles fueled by diesel as part of the incentive program pursuant to the greenhouse gas reductions regulations under the Clean Energy Act (British Columbia). The regulator has approved recovery in rates over a 10-year period.
(ix) | Derivative Instruments
As approved by the respective regulators, unrealized gains or losses associated with changes in the fair value of certain derivative instruments at UNS Energy, Central Hudson and FortisBC Energy are deferred as a regulatory asset or liability for recovery from, or refund to, customers in future rates. These unrealized losses and gains would otherwise be recognized in earnings. UNS Energy and Central Hudson’s regulatory asset balance totalling $6 million as at December 31, 2016 was not subject to a regulatory return (December 31, 2015 - $57 million).
(x) | Other Regulatory Assets
Other regulatory assets relate to all of the Corporation’s regulated utilities and are comprised of various items, each individually less than $40 million. As at December 31, 2016, $296 million (December 31, 2015 - $265 million) of the balance was approved to be recovered from customers in future rates, with the remaining balance expected to be approved. As at December 31, 2016, $217 million (December 31, 2015 ‑ $168 million) of the balance was not subject to a regulatory return.
(xi) | Non-ARO Removal Cost Provision
As required by the respective regulators, depreciation rates include an amount allowed for regulatory purposes to accrue for non-ARO removal costs. Actual non‑ARO removal costs are recorded against the regulatory liability when incurred. This regulatory liability represents amounts collected in customer rates at the respective utilities in excess of incurred non-ARO removal costs.
(xii) | ROE Refund Liability
The ROE refund liability at ITC relates to two third-party complaints filed with FERC dating back to 2013, requesting that FERC find the MISO regional base ROE for all MISO transmission owners, including ITC for the periods November 2013 through February 2015 and February 2015 through May 2016, to no longer be just and reasonable (Note 2). As at December 31, 2016, the estimated range of refunds for both periods was between US$221 million and US$258 million and ITC has recognized an aggregate estimated regulatory liability of US$258 million, of which US$119 million has been classified as current regulatory liabilities.
(xiii) | Electric and Gas Moderator Account
Under the terms of Central Hudson’s three-year Rate Order issued in June 2015, certain of the Company’s regulatory assets and liabilities were identified and approved by the PSC for offset and a net regulatory liability electric and gas moderator account was established, which will be used for future customer rate moderation. This electric and gas moderator account is not subject to a regulatory return. 8. REGULATORY ASSETS AND LIABILITIES (cont’d) Description of the Nature of Regulatory Assets and Liabilities (cont’d)
(xiv) | Renewable Energy Surcharge
As ordered by the regulator under its Renewable Energy Standard (“RES”), UNS Energy is required to increase its use of renewable energy each year until it represents at least 15% of its total annual retail energy requirements in 2025, with distributed generation accounting for 30% of the annual renewable energy requirement. The Company must file an annual RES implementation plan for review and approval by the ACC. The approved cost of carrying out the plan is recovered from retail customers through the RES surcharge until such costs are reflected in TEP and UNS Electric’s non-fuel base rates. Any RES surcharge collections above or below the costs incurred to implement the plans are deferred as a regulatory asset or liability and is not subject to a regulatory return. The ACC measures compliance with its RES requirements through Renewable Energy Credits (“REC”). Each REC represents one kilowatt hour generated from renewable resources. When UNS Energy purchases renewable energy, the premium paid above the market cost of conventional power equals the REC recoverable through the RES surcharge. When RECs are purchased, UNS Energy records the cost of the RECs as long-term other assets and a corresponding regulatory liability, to reflect the obligation to use the RECs for future RES compliance. When RECs are reported to the ACC for compliance with RES requirements, energy supply costs and revenue are recognized in an equal amount (Note 9).
(xv) | Energy Efficiency Liability
The energy efficiency regulatory liability primarily relates to Central Hudson’s Energy Efficiency Program established to fund the costs of environmental policies associated with energy conservation programs and megawatt hour reduction goals, as approved by its regulator, and was not subject to a regulatory return.
(xvi) | Other Regulatory Liabilities
Other regulatory liabilities relate to all of the Corporation’s regulated utilities and are comprised of various items, each individually less than $40 million. As at December 31, 2016, $190 million (December 31, 2015 - $156 million) of the balance was approved for refund to customers or reduction in future rates, with the remaining balance expected to be approved. As at December 31, 2016, $51 million (December 31, 2015 – $80 million) of the balance was not subject to a regulatory return.

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