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Credit FAQ: S&P Global Ratings' Evolving View Of Ontario's Regulatory Construct

The regulatory framework is one of the most important credit assessments when determining a utility's credit quality. The financial performance, cash flow volatility, and financial predictability for Ontario's local distribution companies (LDCs), regulated by the Ontario Energy Board (OEB), have gradually weakened. This primarily reflects regulatory lag, the timing difference between when costs are incurred and when regulators allow those costs to be fully recovered from ratepayers. The risks associated with Ontario's regulatory lag have become increasingly evident as higher transmission costs and wholesale market charges have taken as long as 24 months to fully recover from ratepayers. While we expect the LDCs will ultimately fully recover these costs from ratepayers, the recent cost increases and the excessive time required to recover these rising costs necessitates our review of the Ontario regulatory construct. In general, regulatory jurisdictions like Ontario that we assess as most credit supportive should have a regulatory construct in place that consistently minimizes regulatory lag. Below, we address frequently asked questions about Ontario's regulatory construct and how it affects our credit assessments of Ontario's LDCs.

Frequently Asked Questions

How have we historically assessed the regulatory framework for Ontario?

Historically, we considered the Ontario regulatory framework as one of the most credit-supportive regulatory jurisdictions. Despite the OEB only authorizing average returns on equity (ROE) and below-average capital structures, reflecting a 40% equity ratio, S&P Global Ratings has focused on the LDCs consistent ability to generally earn at, or close to, their authorized ROE. As regulatory lag has become more problematic, the stability of earnings has diminished.

Because of these concerns and our potential downward reassessment of the Ontario regulatory jurisdiction, we revised the outlooks for Ontario's LDCs, including Alectra Inc., Entegrus Powerlines Inc., GrandBridge Energy Inc., London Hydro Inc., and Windsor Canada Utilities Ltd. to negative from stable. We also revised the outlook on Toronto Hydro Corp. (THC) to developing from positive.

How do LDCs recover transmission costs?

Typically, the OEB approves the revenue requirements for the transmitters in separate annual proceedings at year end. The higher costs are then recovered from all market participants, including LDCs, over the subsequent 12 months. However, the OEB only allows LDCs to update their rates annually, not corresponding to the transmitters' year-end approval for higher rates. The regulatory lag associated with the time delay from when LDCs incur the higher transmission costs to when they recover these costs from ratepayers has led to weaker financial measures for Ontario's LDCs. Additionally, while the LDCs are allowed to defer the higher transmission costs incurred until the OEB approves the LDCs' higher rates, the OEB only allows for these deferred costs to be recovered over 24 months, adding to the regulatory lag. Furthermore, recently rising transmission costs and the OEB approving higher transmission costs more than once annually have only exacerbated the situation, materially weakening the LDCs' earned ROEs.

Why did Ontario's LDCs recover less than expected under the WMS rate in 2022?

The wholesale market services (WMS) rate is designed to recover from ratepayers the independent electricity system operator's (IESO) costs associated with operating the electricity system and administering the wholesale market. Previously, the IESO charge to Ontario's LDCs was generally in line with the WMS rate that the LDC's collect from ratepayers, allowing the LDCs to fully recover IESO costs in a timely manner. Beginning in 2022, the IESO charge materially increased, averaging C$0.63 per kilowatt hour (/kWh); however, the LDCs were only authorized to collect C$0.34/kWh from ratepayers, weakening the LDC's financial performance. Furthermore, while the LDCs are allowed to defer the higher IESO charges, the OEB only authorizes the LDCs to recover these deferred costs over 24 months, contributing to the regulatory lag.

Could the recovery of energy costs affect the LDCs' regulatory lag in the future?

Like transmission costs and WMS rates, there is an estimated 18- to 24-month period for Ontario's LDCs to recover these costs from customers compared to when the LDCs incur these costs. Volatile commodity prices have had only a limited effect on total energy costs because Ontario's electricity is mostly from nuclear power (53%), hydroelectric (26%), and renewables (10%). However, because of nuclear power plant refurbishments, we expect Ontario's reliance on electricity from natural gas-fired generation will significantly rise over the next five years, increasing its susceptibility to volatile commodity prices and potentially increasing regulatory lag for Ontario's LDCs.

Why do we have a developing outlook on THC but a negative outlook on the remaining Ontario LDCs?

We assess THC as having a moderate likelihood of extraordinary support from its parent, the city of Toronto. The city demonstrated its willingness to provide financial support to THC by giving a cash injection in 2017. We expect the city to provide ongoing support to THC as necessary because the utility provides essential infrastructure services to the population of Toronto. Currently, the outlook for the city of Toronto is positive and an upgrade of the city would directly support THC's issuer credit rating (Toronto Hydro Corp. Outlook Revised To Developing From Positive Due To Heightened Regulatory Lag; Ratings Affirmed, May 11, 2023). Ontario's other LDCs are assessed as only having a low likelihood of support from their parent and do not benefit from their parent's higher rating.

Why is Hydro One Ltd. (HOL) not affected by our evolving view of Ontario's regulatory framework?

HOL’s regulated utility operations generate cash flows from its transmission and distribution businesses. The transmission segment contributes about 60% of the operating cash flows and is not exposed to the regulatory lag associated with transmission costs or WMS rates that have hurt LDCs. Because distribution represents a smaller component of HOL, the lag impairs HOL less than a pure LDC that is fully exposed to these risks.

Why is Enbridge Gas Inc. (EGI) not affected by our evolving view of Ontario's regulatory framework?

EGI is Ontario's largest regulated natural gas distribution utility and has not experienced the regulatory lag that has impacted the financial performance of Ontario's electric LDCs. EGI's regulatory framework as a natural gas distribution company is different from the electric LDCs. EGI defers the variance between actual and forecasted natural gas prices for future recovery but is allowed to update these costs quarterly. Furthermore, it typically recovers any under- or over-recovery experienced within a quarter over a 12-month period, limiting the regulatory lag.

Why is Ontario Power Generation Inc. (OPG) not affected by our evolving view of Ontario's regulatory framework?

OPG is the largest regulated electric generation utility in Ontario and derives about 70% of its total cash flows from regulated nuclear and hydro generation. Most of the remaining cash flow comes from long-term contracted generation with counterparties that have high credit qualities. As such, the company is not subject to the regulatory lag associated with transmission costs, WMS rates, or energy costs. OPG's financial performance has improved over the past several years compared with weakening financial performance at Ontario's LDCs.

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This report does not constitute a rating action.

Primary Credit Analysts:Mayur Deval, Toronto (1) 416-507-3271;
Omar El Gamal, CFA, Toronto +1 4165072523;
Secondary Contacts:David S De Juliis, Toronto +1 (416) 276-2610;
Matthew L O'Neill, New York + 1 (212) 438 4295;

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