S&P Global Ratings has been monitoring recent developments in various U.S. and Canadian utility regulatory jurisdictions in which the utilities we rate operate. Since our last report, published in November 2023, we have completed a review of Ontario and left our assessment unchanged. In other jurisdictions, we have noted the uncertainties of rate recovery on both completed and proposed capital spending, wildfire litigation, and updates on clean energy transitions and natural gas bans.

Our periodic assessments of regulatory jurisdictions provide a reference for determining a utility's regulatory advantage or risk. Regulatory advantage is incorporated into our analysis of a regulated utility's business risk profile. Our analysis covers quantitative and qualitative factors, focusing on regulatory stability, tariff-setting procedures and design, financial stability, and regulatory independence and insulation.(See Key Credit Factors For the Regulated Utilities Industry, published Nov. 19, 2013, for more details on each category.)

U.S. And Canadian Regulatory Utility Jurisdiction Developments

We group jurisdictions by quantitative and qualitative factors that comprise the regulatory advantage determinations we make in rating committees for approximately 220 U.S. and 30 Canadian utilities we rate.

The categories are an important starting point for assessing utility regulation and its effects on ratings. They are all credit-supportive to one degree or another because all utility regulation tends to sustain credit quality. We believe the presence of regulation, regardless of where it falls on the credit-supportive spectrum, reduces business risk and generally supports utility ratings. We therefore designate all these jurisdictions on a continuum from credit supportive to most credit supportive. These descriptions vary only in degree.

The following is a current snapshot of our assessment of each regulatory jurisdiction.

Table 1

For jurisdictions assessed in Graphics 1 and 2, colors delineate our assessment of credit supportiveness. We do not have assessments for Canadian provinces where we do not have utility ratings. The charts depict scale and offer some detail regarding our assessment of the rules and implementation of regulation. Often, our assessments designate a stable jurisdiction slightly better or worse than its closest peers in credit quality.

Reviewed, No Changes

Ontario

We concluded our review on Ontario's regulatory environment, including the Ontario Energy Board (OEB), and left our assessment unchanged at most credit supportive. OEB proactively addressed regulatory lag, particularly related to the timely recovery of rising transmission-related costs. Notably, before addressing this cost recovery lag, we had revised outlooks to negative on several Ontario electric local distribution companies (LDC). To address this lag, in July 2023, the OEB pulled forward the issuance of an inflation factor calculation that is an input to calculate uniform transmission rates (UTRs) for transmission utilities' annual rate adjustments. Typically, this had been completed in October or November. Because the inflation factor was available earlier, in September 2023, the OEB was able to approve preliminary UTRs for transmission companies.

With the updated inflation factor and revised UTRs, LDCs can file for new rates with the most current inputs, including updated transmission costs, which mitigates regulatory lag. We expect this more front-loaded rate recovery will align higher operating cash flow with LDCs' requirements to pay the higher transmission costs. In January 2024, the OEB issued its final UTRs that were largely in line with the preliminary UTRs. With this reduced lag in recovering higher transmission costs, we expect LDCs will be able to boost their financial measures.

No Revised Assessments, But Notable Developments

Arizona

In February 2024, the Arizona Corporation Commission (ACC) directed the ACC staff to draft rules to repeal both the state's energy efficiency standards and renewable generation requirements. The ACC largely cited costs to ratepayers as driving the decision. We will closely monitor the rulemaking process and its potential effect on Arizona utilities.

California

The California Public Utilities Commission (CPUC) recently approved advice letters for several regulated electric, gas, and water companies, raising the authorized return on equity (ROE) by approximately 70 basis points (bps) through the cost of capital mechanism (CCM), effective Jan. 1, 2024. In California, authorized ROEs are established separately from general rate case proceedings, based on a formula, to reflect rising bond yields. We view this as supportive of credit quality for affected regulated utilities because it helps mitigate regulatory lag, which protects utilities from the effects of rising interest rates. We believe the boost in recovery through higher rates will strengthen funds from operations (FFO) of California utilities.

Hawaii

In January 2024, House Bill 2265 was introduced in the Hawaii legislative session. This bill proposes to implement a Catastrophic Wildfire Securitization Act to allow public utilities to securitize costs from catastrophic wildfires. We expect a decision on this by June 2024. Separately, in November 2023, Hawaii's Governor announced the One Ohana Initiative, which would provide at least $150 million of public-private funds to compensate victims and their families affected by the August 2023 Lahaina wildfires. We expect this fund to be jointly funded by the State of Hawaii, Hawaiian Electric Co. Inc., Kamehameha Schools, Maui County, and other entities. While both initiatives have yet to be finalized, if approved, they would be supportive for utilities operating in Hawaii by mitigating the costs from catastrophic wildfires.

Illinois

Recent regulatory rulings by the Illinois Commerce Commission (ICC) lead us to believe the ICC may become less credit supportive toward utilities operating in the state. In November 2023, the ICC disallowed capital spending incurred by WEC Energy Group Inc.'s (WEC) subsidiary, The People's Gas Light & Coke Co. (PGL). The disallowed capital spending relates to the construction and improvement of service shops PGL owns throughout Chicago. The ICC's November 2023 rate order also rejected PGL's request to include its forecast test year safety modernization program (SMP) investment in its rate base. The ICC ordered a pause in, and an investigation of, the program, which focuses on replacing aging and at-risk pipelines (such as cast iron or ductile iron), relocating meters, and repressurizing areas of its distribution system.

The ICC recently authorized a limited rehearing of certain items, including $134 million of SMP emergency work; however, the ICC will not reconsider the disallowed spending related to its service shops. We view the disallowance as negative from a credit standpoint because parent WEC took a $179 million noncash charge to its 2023 earnings, weakening its FFO to debt in 2023. The disallowance also leads to less predictability of ratemaking under the ICC. Although PGL was able to reduce its capital spending by $700 million to $900 million over 2024-2028 to preserve its credit quality, the reduced capital spending could delay the company's progress toward replacing aging and at-risk pipelines. Cast iron and ductile iron account for roughly 25% of the company's gas distribution system.

In addition, in December 2023, the ICC within Commonwealth Edison Co.'s (ComEd) and Ameren Illinois Co.'s (AI) separate multiyear rate plans determined that their respective four-year grid plans did not adequately describe community benefits, transparency, affordability, or cost-effectiveness and did not comply with the state's Climate and Equitable Jobs Act (CEJA) of 2021. Illinois' CEJA law requires the state to transition to 50% renewable energy by 2040 and 100% clean energy by 2050 through reduced emissions and electrification. We believe the wholesale rejection of ComEd's and AI's grid plans by the ICC, which resulted in a much lower revenue increase for each company in their respective four-year rate plans, may indicate a weakening in the ICC's recent historical predictability of regulatory outcomes. Both utilities will file revised grid plans in March 2024, but there is no set deadline for the ICC to rule on the revised plans. In aggregate, the combination of disallowances and lower-than-expected rate increases may be a sign of less regulatory stability that could weaken the attractiveness of the state's regulatory framework to long-term investors.

Kansas

In January 2024, House Bill 2527 was introduced in the Kansas House of Representatives that proposes to authorize cost recovery mechanisms for certain rate base additions as well as proposed changes to the calculation of capital structures. The bill proposes that utilities be allowed to defer as a regulatory asset 100% of all depreciation expense and returns associated with all plant-in-service balances not already included in rate base.

In addition, the bill proposes that the Kansas Corporation Commission (KCC) would set rates for a public utility on a stand-alone basis when determining the revenue requirement. The KCC would be required to use a utility's test year capital structure, without regard to the capital structure or investments of any other affiliated entities, unless the utility's parent company does not hold an investment-grade credit rating from at least one nationally recognized credit rating agency.

The bill also proposes that utilities be allowed to implement a new rate adjustment mechanism to earn a return on 100% of construction work in progress for any new gas-fired generating facilities, unless the KCC determines the plant would not be a prudent addition to the utility's fleet.

We expect that the bill, if passed as presented, will provide more predictable and stable cash flows for utilities in Kansas, further strengthening credit quality. We continue to monitor the developments on the proposed legislation.

Kentucky

The Kentucky Public Service Commission (PSC) recently modified several rate case settlements to modestly lower the ROEs in the settlements, reducing the ultimate rate increases. Recently, Kentucky Power Co.'s (KPC) rate case settlement called for a base rate increase of about $75 million based on a 9.75% ROE. Separately, in KPC's recent rate case, the PSC reduced the settled rate increase by about $15 million largely to address the PSC's concerns regarding the company's transmission costs. In a separate proceeding, however, the PSC was credit supportive toward KPC by authorizing the utility to issue securitization bonds primarily for early retirement of coal generation and storm restoration costs. In aggregate, we continue to view Kentucky as most credit supportive albeit at the lower end of the category.

Maine

In November 2023, Maine voters rejected a referendum that could have resulted in the Maine government attempting to municipalize investor-owned utility transmission and distribution assets in the state. The rejection reinforces regulatory stability and reduces uncertainty, providing for the utilities in Maine to focus on strengthening infrastructure and improving reliability of operations. We view regulatory independence as one of the key attributes that underpins the credit quality of the utility industry. In general, we expect utilities to operate under a regulatory construct that is sufficiently insulated from political intervention, even during periods of economic stress, thereby protecting a utility's credit risk profile.

Massachusetts

In December 2023, the Massachusetts Department of Public Utilities (DPU) required the state's natural gas LDCs to analyze whether low- or zero-carbon non-pipeline alternatives, such as heating electrification and geothermal systems, could replace traditional gas infrastructure investments. Furthermore, the DPU ordered gas LDCs to file Climate Compliance Plans beginning in 2025 that would propose strategies to reduce greenhouse gas emissions (Scope 1 and 3). While these developments are still preliminary, we will continue to monitor them, including potential implications for the state's gas LDC's capital spending and growth prospects over the long term.

Michigan

In late 2023, Michigan passed several legislative measures that affect utilities, including Senate Bills (SB) 271, 273, 277, 502, and 519. Specifically, the actions now require 80% of power generated in the state to be derived from clean energy by 2035 and 100% by 2040; the state commits to 50% renewable energy by 2030 (60% by 2035), increases the cap on distributed generation--including rooftop solar to 10% from 1%--and a 2,500 megawatt (MW) energy storage mandate by 2030.

SB 271 includes a financial incentive for utilities that procure clean energy or storage through a purchased power agreement with third parties. Specifically, if a regulated electric utility enters into a purchase power agreement for renewable energy resources or clean energy storage with a nonaffiliated third-party, the commission shall authorize an annual financial incentive for the utility, which includes the utility's pre-tax weighted average cost of permanent capital (debt and equity) using the utility's regulated capital structure that was authorized in the most recent general rate case.

From a credit perspective, while we view the financial incentive as supportive of credit quality, the broader energy goals could also likely translate into increased capital spending by the utilities to meet the requirements of these legislative measures. As such, we will continue to monitor how affected utilities effectively navigate this development.

New Jersey

The state continues to work toward the goal of 100% of electricity sold in the state being generated from clean and renewable sources by 2035. A new proposal makes a continued effort to accelerate this by prohibiting the construction of new fossil fuel power plants. The state currently generates about 55% of its energy from fossil fuel. We do not view this as completely restrictive because it would allow for the continuation of fossil fuel peaker plants.

In addition, the commission continues to move toward its offshore wind goals of achieving 11 gigawatts (GW) of offshore wind capacity by 2040. In January 2024, the New Jersey Board of Public Utilities approved two new offshore wind proposals for a combined 3.7 GW. The 2.4 GW Leading Light Wind project is being built by Invenergy Renewables LLC and energyRE LLC, and the 1.3 GW Attentive Energy Two project is being built by TotalEnergies SE and Corio Generation Ltd. This is a positive development after the cancellation of two wind projects with Orsted A/S in 2023.

New Mexico

In January 2024, the New Mexico Public Regulation Commission (NMPRC) authorized Public Service Co. of New Mexico (PSNM) a rate increase of about $15 million based on an authorized 9.26% ROE. It also ordered a $38 million rate refund over two years of previously collected payments on an expired power plant lease. In January 2023, NMPRC transitioned to the gubernatorial appointment of commissioners. While we expected that this change could improve New Mexico's support of credit quality, PSNM's first rate order under this new construct has initially fallen short of our expectations. At the same time, we believe there were unique factors in this rate case that make it difficult to determine a long-term view of New Mexico's regulatory environment. These include the participation of only two out of three commissioners and the resolution of legacy issues concerning PSNM's generation. We expect PSNM will be filing more frequent rate cases in the future, which will inform our view of the new NMPRC.

New York

Governor Kathy Hochul introduced The Affordable Gas Transition Act (AGT) bill that, among other things, would empower the New York Public Service Commission (NYPSC) to direct utilities to manage the transition to clean energy sources responsibly and affordably. If passed, AGT would give NYPSC discretion on controlling gas utilities expansions in their existing service territory and would restrict distributors from expanding their service territories beginning in 2026. AGT would further limit growth of gas utilities in the state. This requires substantial and accelerated investments in New York's electric infrastructure consistent with the Climate Leadership and Community Protection Act.

North Carolina

We view recent regulatory outcomes in North Carolina as constructive for credit quality. In December 2023, the North Carolina Utilities Commission (NCUC) authorized a three-year cumulative rate increase for Duke Energy Carolinas LLC (DEC) totaling $769 million. The decision includes revenue increases of about of $469 million in 2024, $174 million in 2025, and $159 million in 2026. In August 2023, affiliate Duke Energy Progress LLC (DEP) also received a multiyear rate increase of $494 million through 2026. We consider both rate case decisions as supportive of credit quality because they bolster both companies' financial measures and further highlight sound management of regulatory risk.

We believe the rate increases will provide stability in cash flows through 2026, which is important given the companies' elevated capital spending. DEC and DEP received ROEs of 10.1% and 9.8% in 2023, respectively, both above industry averages. Potentially offsetting the higher ROE for DEC, the North Carolina Attorney General recently filed an appeal on the DEC rate case because they were authorized a higher ROE than DEP. We will continue to monitor the appeal and future developments and any effect on DEC's rates.

Nova Scotia

We view Nova Scotia's regulatory construct as credit supportive due to the history of political interference that weakens the regulatory jurisdiction's predictability and increases uncertainty for its utilities and stakeholders. However, recently the government of Nova Scotia proposed to compensate Nova Scotia Power Inc. (NSPI) C$117 million to offset a deferred fuel cost liability. Because any further recovery of fuel costs would have significantly pressured customer bills in Nova Scotia, the provincial government proposed to pay NSPI C$117 million up front and recover the amount from customers over the next 10 years. This compensation to NSPI from the provincial government indicates the government's willingness to extend support under challenging circumstances, thereby improving the operating environment for NSPI. We consider this supportive of credit quality in the province.

In addition, the provincial government announced its 2030 Clean Power Plan, which is largely consistent with NSPI's investment strategy. Furthermore, the provincial government also approved legislation to include battery storage projects in base rates.

West Virginia

Earlier this year, the Public Service Commission of West Virginia (WVPSC) disallowed about $232 million of under-recovered energy costs sought during Appalachian Power Co.'s and Wheeling Power Co.'s Expanded Net Energy Cost (ENEC) filing. Furthermore, the WVPSC ordered the companies to recover the remaining under-recovered balance of $321 million over a 10-year period. Previously the companies had reached a settlement with the West Virginia Energy Users Group and West Virginia Coal Association, but not the WVPSC staff, to recover all the under-recovered costs. In arriving at this decision, the WVPSC stated that the companies were imprudent in fuel planning, fuel practices, and market strategies, which caused a lack of adequate coal supplies at a time when energy was more expensive.

While we view this development as negative for Appalachian Power and Wheeling Power, we do not believe this indicates a deterioration in the broader regulatory environment in the state at this time. Other electric utilities in the state, namely Monongahela Power Co. and Potomac Edison Co., recently reached settlements with WVPSC staff, among various other intervenors, concerning the companies' rate case and ENEC filings.

Furthermore, we view both settlements in these cases as constructive. In particular, Monongahela Power's and Potomac Edison's ENEC settlements call for the recovery of the companies' ENEC under-recovered balance of about $255 million over the next three years. We will continue to monitor further developments in these proceedings to determine if they impact our view of West Virginia investor-owned utilities' credit quality.

Related Research

• WEC Energy Group Inc.'s Financial Measures Hold Up Despite Disallowances In Illinois Rate Cases, Jan. 23, 2024
• Commonwealth Edison's Rate Case Outcome Pressures Credit Measures, Dec. 21, 2023
• Key Credit Factors For The Regulated Utilities Industry, Nov. 19, 2013