S&P Global Ratings considers the province of Ontario to have predictable and stable regulatory frameworks for electricity and gas transmission system operators (TSOs) and distribution system operators (DSOs). This results in our assessment of Ontario regulation--which is administered largely by the Ontario Energy Board (OEB), the key source of our information--as strong (the most credit supportive assessment). We evaluate jurisdictions by the qualitative and quantitative factors that affect the regulatory advantage for the utilities we rate. We view the regulatory framework as the single most important factor in assessing a regulated utility's competitive position (see "Key Credit Factors For The Regulated Utilities Industry," published Nov. 19, 2013, on RatingsDirect).
- Regulatory frameworks for electricity and gas transmission and distribution networks in Ontario exhibit characteristics that are consistent with our most credit supportive (strong) regulatory advantage assessment.
- The regulation allows TSOs and DSOs to recover their capital and operational costs in a comprehensive and stable manner, and timely reviews ensure the adequacy of the regulation.
- TSOs and DSOs benefit from the regulator's solid track record of stability and political independence.
|Key Factors Of The Ontarian Regulatory Framework (Electricity And Gas)|
|Regulation has been in place since 1997, using the performance-based ratemaking (PBR) since 2001 for electric utilities and 2009 gas utilities.|
|Predictable and transparent framework, currently on the fourth generation of PBR, with well-defined parameters.|
|Tariff-Setting Procedures And Design|
|The tariff structure is stable and aims for fair returns for operators.|
|Remuneration for transmission and distribution operators allows for investment recovery, financial remuneration, and ongoing operational expense recovery.|
|Sector can recover most of its costs.|
|Regulatory Independence And Insulation|
|The Ontario Energy Board is a regulatory body independent from the government with no indications of material political interference.|
|Rising generation costs towards a political ceiling of 10% annual increase may put pressure on the autonomy of the regulation.|
OEB is the provincial regulatory body responsible for the regulation of the natural gas and electricity sectors and executing the main energy policies established by the government. It protects the interests of consumers with respect to prices and adequacy, reliability, and quality of electricity service. It also ensures the financial and economic equilibrium of the regulated companies, guarantees that the activities of the regulated sectors are exercised in the public interest, and promotes use of electricity from renewable energy sources.
Other supervisory bodies
Government of Ontario-owned Independent Electricity System Operator (IESO) is responsible for directing the flow of electricity across the transmission lines, as well as planning the Ontario power system and coordinating conservation efforts across the province. OEB licenses IESO and sets the maximum fees IESO can charge.
Ontario Power Generation (OPG)
Province of Ontario-owned Ontario Power Generation is the largest electricity generator in the province, providing roughly half of the power to Ontarians through nuclear, hydroelectric, wind, gas, and biomass facilities.
Transmission system operators
Hydro One Limited, through its subsidiaries, is the largest electricity TSO in Ontario. It owns the electricity transmission network of the province, delivering electricity to over 1.4 million customers. Hydro One also owns various DSOs in the province. Hydro One is about 47.3% owned by the government of Ontario and 52.7% publicly traded on the Toronto Stock Exchange.
Distribution system operators
Over 80 gas and electric utilities operate in the province. In April 2015, revenue decoupling was implemented for distribution operators with a fixed rate distribution tariff structure. Local distribution companies (LDCs) had four years to transition, and upon completion would have no exposure to volume risk. For electric distributors, it reduces cash flow volatility, while for gas distributors there is no need for weather normalization. In Ontario, most LDCs are owned by local governments.
For gas LDCs, no intermediate party like IESO exists. The gas LDCs purchase gas from upstream pipeline companies, and the commodity cost related to purchased natural gas is passed directly to the customers with no markup. In addition, the federal carbon levy flows through to customers.
In Ontario, regulatory frameworks provide incentive regulation and encourage utilities to become more efficient in ways that benefit customers and minimize rate increases. The first performance-based regulation (PBR) framework for electricity distribution was implemented in 2001 and gas distribution adopted the framework in 2009. OEB is currently on its fourth generation of the PBR framework. OEB typically resets transmission rates every two years based on cost of service (COS). Distribution rates are typically based on the PBR framework for 4-5 years between COS reset filings. In 2012, the Renewed Regulatory Framework for Electricity (RRFE) created three incentive rate-setting (IR) methodologies. The provincial utilities can choose from Price Cap IR, Custom IR, and Annual IR Index. All regulatory frameworks are based around a standardized return on equity (ROE) and capital structure. The PBR framework has a re-opener clause that allows utilities to re-base if they are under or over the authorized ROE threshold by 300 basis points (bps), eliminating large swings.
|Key Features of Utility Methodologies|
|Price Cap Incentive Rate-Setting||Electric DSOs, Gas DSOs, Electric TSOs||COS process first year, then price cap index formula. Productivity factor calculated by inflation minus stretch factor.|
|Custom Incentive Rate-Setting||Electric DSOs, Gas DSOs, Electric TSOs||Five-year forecast of utility's cost and sales volumes.|
|Annual Incentive Rate-Setting Index||Electric TSOs||Maximum stretch factor used. Price Cap IR formula used.|
Price Cap IR The Price Cap incentive rate (IR)-setting methodology is the most frequently used and allows for base rates to be set through a COS process for the first year. The following four years are indexed by the fourth-generation price cap index formula. A productivity factor, calculated by inflation minus a stretch (or efficiency) factor, is included in the Price Cap IR annual adjustment mechanism. The lower the stretch factor (a scale set from 0% to 0.6%), the more efficient the utility. The assessment of the stretch factor is formula-driven but takes into consideration the size and scope of a utility too. It ensures a utility's rate will increase modestly below the inflation rate. Unique to the Price Cap IR method is the Incremental Capital Module (ICM). While a utility is operating under its PBR it can seek incremental rate recovery of additional capital spending above the originally approved capital spending in the base rate setting. Because of this flexibility of recovering incremental capital spending, OPG uses this methodology for their hydroelectric operations due to ongoing capital spending. Starting in early 2019, Enbridge Gas Inc. (EGI) operates under the Price Cap IR methodology. EGI's rates will increase based on inflation minus productivity, and the company will rely on harvesting synergies from the amalgamation of Enbridge Gas Distribution Inc. and Union Gas Ltd.
Custom IR Custom incentive rate-setting methodology sets base rates for five years using a five-year forecast based on a specific utility's costs and sales volumes. This methodology allows the utility to start earning on its rate base within the PBR period without having to wait for the next COS application. Custom IR is most suitable for entities with significantly large multi-year capital spending commitments with relatively certain timing and predictability of costs. Because of this, Hydro One uses this methodology for the transmission assets and OPG uses it for its nuclear business.
Annual IR Index Annual incentive-rating methodology uses the same annual adjustment formula as Price Cap IR, but the stretch factor is set at the highest level of 0.6%. This methodology does not require a periodic rate base reset using the COS process. The framework is most appropriate for distributors with limited incremental capital requirements and relatively steady investment needs.
The availability of the above methodologies allows utilities to recover costs. The ability to recover all operating and capital costs in a timely manner is very supportive of credit quality.
When assessing regulatory stability, we review the transparency of the key components of rate setting, the predictability of the framework, and the consistency of the framework over time. OEB publishes details of all hearings and rationales online and works with consultants and shareholders if there are any potential regulatory changes. This high level of transparency aligns with our most credit supportive (strong) assessment of the regulatory environment.
Given its track record of consistency and stability, we view the OEB's regulation as supportive and it underpins our expectation of consistent regulation across the regulatory cycle. This stability supports a utility's cost recovery and return on capital combined with lower-than-average volatility of earnings and cash flows. Regulatory lag is minimal since the OEB typically renders rate decisions within six to eight months.
The deemed capital structure for ratemaking is consistent across the electric TSOs and DSOs with 40% equity, 56% long-term debt, and 4% short-term debt. For OPG's nuclear and hydro generation assets, the deemed capital structure is set at 45% equity and 55% debt. We view the overall regulatory framework for generation, which is typically considered riskier, as generally credit supportive with a modestly higher authorized return on total investment. For gas LDCs, the risk is considered less than electricity-related businesses, given the deemed capital structure is set at 36% equity and 64% debt. Additionally, gas LDCs must share over-earnings with ratepayers under an earnings sharing mechanism.
Cost of capital parameters, including the deemed (or authorized) long-term debt rate, deemed short-term debt rate, ROE, and weighted average cost of capital (WACC), have also seen relative levels of stability. OEB formulaically updates these rates every year, as shown in the chart below. The parameters have been modestly declining over the decade with 2021 parameters being the lowest on record. The current reference ROE is 8.52% and 40% equity based on the 2020 cost-of-capital update.
Tariff-Setting Procedures And Design
When assessing the tariff-setting, procedures, and design of a regulatory framework, we analyze whether all operating and capital costs are fully recoverable; the balance of interests and concerns of all stakeholders affected; and whether incentives are achievable and contained.
In Ontario, the rate-setting frameworks are based on regulatory periods with a fixed base ROE. The ROE is set annually according to a formulaic approach based on the Long Canada Bond Forecast (LCBF), 'A'-rated utility spread, and the initial ROE. In 2010, OEB addressed the relatively low return-on-equity levels and high sensitivity to changes in Canadian government long bond yields with a cost-of-capital reset decision. An adjustment of 50% was applied to the LCBF and 'A'-rated utility spread. This decision to reset cost-of-capital produced a 135 bps improvement in ROE levels.
Once a year, typically in September, OEB contacts the prime Canadian banks for estimates of the spreads. The LCBF is calculated by subtracting the base LCBF from the change in LCBF. The change in LCBF is estimated by adding the 10-year government of Canada bond yield forecast and the actual spread of 30-year over 10-year government of Canada bond yield. The 'A' utility spread is calculated by the difference of the change in 'A' utility bond yield spread and base 'A'-rated utility bond yield spread. The change in 'A' utility bond yield spread is calculated by the 30-year 'A' rated utility yield spread over the 30-year government of Canada yield spread. The LCBF and 'A' utility bond yield spread are then multiplied by a 0.5 equity risk premium, which was determined during the reset of cost-of-capital parameters in 2010. Then they are subtracted from the initial ROE, to get to the annual calculated ROE.
This formula-based approach enables predictable, transparent and consistent return on investments (ROI), or cost of capital, across the sector. It allows for rate-setting to be dynamic, especially with recent interest rate fluctuations. This approach only takes into consideration the spreads for 'A' rated utilities. Ontario has three utilities rated below 'A', indicated in the chart below. These utilities typically will generate a lower ROI, as their cost of debt may be relatively higher as compared to 'A' rated utilities. In addition, the formulaic approach for calculating the approved ROE may result in lower approved ROEs in the currently prevailing low-interest-rate environment and pressure the financial metrics.
When assessing the financial stability of a regulatory framework, we look at the timeliness of cost recovery and cash flow volatility; how much flexibility there is in the framework to allow the recovery of unexpected costs; the attractiveness of the framework to long-term capital; and capital support during construction to alleviate funding and cash flow pressure during periods of heavy investments.
We believe the OEB's regulatory environment facilitates supportive financial stability in the sector. Limited commodity risk exists since electricity costs and natural gas prices are ultimately passed through to the ratepayers. Companies can recover most of their costs, including operating expenditures, depreciation, and capital returns. Additionally, a significant level of protection exists against volume risk and non-controllable costs. Transmission operators have a limited history of stranded costs.
OEB allows utilities to recover all prudently incurred operating and capital costs in a timely manner. Variance accounts track any shortfalls and are trued up annually. OEB preapproves capital programs and has no history of significant disallowances, and utilities typically do not spend on unapproved capital programs. Preapproval of capital investment programs and large projects lowers the risk of subsequent disallowances of capital costs. Major capital costs are added to rate base after completion of the project.
In addition, OEB has established deferral and variance accounts (DVAs) for specific duration and purposes. There is a perpetual DVA in place for electricity LDCs for pass-through of commodity and transmission costs. The DVAs for the pass-through of electricity commodity and transmission costs ensure the utilities experience little risk on the commodity charge except for possible bad debts.
The settlement process in Ontario exposes the electricity LDCs to the potential bad debts risks that include commodity costs. In light on the current pandemic, the OEB directed the electricity LDCs to extend the winter disconnection ban due to non-payment of electricity bills by three months. Although the OEB established three separate DVAs for tracking incremental costs, the electricity LDCs may face liquidity drawdowns due to incremental deferred payments or bad debts. OEB acknowledged that the utilities may incur incremental costs as a result of the ongoing COVID-19 emergency and has launched consultation to study the impact of it. In order to mitigate the impact, the initial steps included the approval of a situational DVA to track the incremental costs for future recovery. Although, the recovery of these tracked costs will depend on causality, materiality and prudency tests, it does provide financial stability to the utilities facing cost overruns to maintain the essential services under challenging circumstances. Furthermore, the electricity LDCs with more exposure to commercial and industrial customers may face higher headwinds compared with LDCs with operations in more metropolitan areas with larger composition of residential customers. OEB's vigilant monitoring, transparent policies, and timely measures during the COVID-19 emergency to address the potential cash flow and liquidity risks to the utilities supports our assessment of highly supportive financial stability.
Regulatory Independence And Insulation
When assessing regulatory independence and insulation, we look at the market framework and how the law preserves and separates the regulator's powers, as well as any risks of political intervention. The Ontarian market framework was established in 1999, in which legislation outline OEB's framework regarding electricity and natural gas regulation and competitive electricity marketplace. OEB is very transparent about its framework, and its processes are generally governed by the Statutory Powers Procedure Act.
The Board of directors (BoD), Chief Executive Officer (CEO), and Commissioners are appointed by the Lieutenant Governor in Council, providing relatively more regulatory independence. The BoD oversees the management of the OEB's business and affairs and is responsible for the governance of the OEB.
OEB has had considerable political independence since its inception in the late 1990s. Within the past decade, no overarching government interference has occurred, and the Ontarian government in recent years has strengthened this barrier.
In 2017 Hydro One announced an acquisition of U.S.-based utility Avista Corp. However, the deal was halted after Hydro One's then-CEO retired and the company's entire board of directors resigned. These actions occurred after the premier of Ontario opposed the acquisition of Avista due to an expectation of increased rates for Hydro One ratepayers to recover the acquisition premium to buy the U.S. utility. The government of Ontario, subsequently in 2018 through the Hydro One Accountability Act, established a new executive compensation framework for the board, CEO, and other executives. With the newly appointed individuals, the Ontario government exercised its legislative ability to lower electricity rates, which was consistent with the governor's election campaign promises. Ultimately, the acquisition was terminated in late 2018 after the Washington Utilities and Transportation Commission denied the merger.
Following the termination of the Hydro One's acquisition of Avista, in 2019 the Ontario government enacted Bill 87: Fixing the Hydro Mess Act. This legislation modernized OEB, addressed governance and efficiency issues, and amended the OEB Act, Electricity Act and Fair Hydro Act. A board of directors and new chair were established, creating an interface for the Ontarian government, and the position of CEO of the OEB was created to provide executive leadership for operational and policy aspects. Commissioners are now expected to take an independent adjudicative role in hearing and determining matters within the jurisdiction. Broadly, the Board of directors are allowed to exercise the powers of the Board with respect to administrative functions while panels of commissioners assigned by the chief commissioner for the purpose exercise the powers of the Board with respect to its adjudicative and regulatory functions.
Regulatory Impact On Utilities' Credit Quality
The four pillars--regulatory stability, tariff-setting procedures, financial stability, and regulatory independence--are the key elements in the Ontario's natural gas and electricity regulatory environment. We believe the Ontarian regulatory framework is the most credit supportive kind, benefiting all key stakeholders. Regulatory stability comes from the choice of the three IR methodologies, in which utilities can maximize efficiency and recover prudent costs in a timely manner. OEB establishes a high level of stability, setting a uniform ROE level for all utilities. With its high level of transparency, OEB lays the groundwork for a better regulatory environment as key stakeholders become more confident in OEB's decisions. Since 1998, utilities operating in Ontario have a well-established track record of recovering their operating and capital costs.
We are following ongoing rate applications, specifically for Enbridge Gas Inc., Hydro Ottawa Limited, and Hydro One Networks. Enbridge Gas has numerous rate applications, including several projects, one to raise natural gas rates, and a dispute regarding 2019 utility earnings and deferral variance disposition. Hydro Ottawa Ltd. is currently going through its 2021 rate application, and Hydro One Networks is waiting for OEB's decision on eliminating the Hydro One seasonal rate class.
During the COVID-19 pandemic, OEB established an account for utilities to track any incremental costs and lost revenues as a result of the economic repercussions. Within the account, OEB will assess any claimed costs and/or lost revenues within established materiality thresholds. Submissions needed to be filed by late May 2020 to be considered. This is a recent example of OEB's prompt response to deal with credit pressures in a balanced manner for all key stakeholders.
We could reassess our regulatory assessment if:
- The formulaic approach for calculating the authorized ROE on the approved capital structure becomes ineffective under the current low-interest-rate environment and the OEB fails to adjust its approach.
- There was a loss of regulatory independence or instances of political interference in the framework.
- Any material changes in regulation likely to decrease transparency, consistency and timely recovery of costs.
- A material increase in provincial or sovereign risk factors that could negatively affect the operator's financial compensation.
- Criteria | Corporates | Utilities: Key Credit Factors For The Regulated Utilities Industry, Nov. 19, 2013
- Criteria | Corporates | General: Corporate Methodology, Nov. 19, 2013
- Updates And Insights On Regulatory Jurisdictions Shaping Policies For North American Utilities--November 2020, Nov. 9, 2020
This report does not constitute a rating action.
|Primary Credit Analysts:||Mayur Deval, Toronto (1) 416-507-3271;|
|Daria Babitsch, New York;|
|Secondary Contacts:||Gerrit W Jepsen, CFA, New York + 1 (212) 438 2529;|
|Andrew Ng, Toronto + 1 (416) 507 2545;|
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