As part of our ongoing surveillance of rated U.S. and Canadian regulated utilities, S&P Global Ratings monitors regulatory developments that could have ratings implications. Since our last report, published in March 2024, key developments include pending rate cases, grid modernization plans, and initiatives related to energy transition. Other important developments include storm recovery costs (New York), merger and acquisition (M&A) proceedings (Minnesota and Wisconsin), and wildfire mitigation efforts (California and Utah). We have also noted the uncertainties around recovery of capital spending, wildfire litigation, and clean energy and electrification initiatives.

We incorporate regulatory advantage into our analysis of a regulated utility's business risk profile. We make regulatory advantage determinations in rating committees for approximately 220 U.S. and 30 Canadian utilities. Utility regulation, no matter where on the continuum of our assessments, strengthens a utility's business risk profile and generally underpins our ratings. One significant aspect of it that influences credit quality is the regulatory environment in the jurisdictions where a utility operates. Therefore, we monitor many different regulatory jurisdictions and incorporate any regulatory or legislative actions that support, or do not support, a rated utility's credit quality. Our analysis covers quantitative and qualitative factors, focusing on regulatory stability, tariff-setting procedures and design, financial stability, and regulatory independence and insulation.(See Sector-Specific Corporate Methodology, published April 4, 2024, for more details on each category.)

Notable Regulatory Developments

California

On Aug. 29, 2024, Edison International (Edison) subsidiary Southern California Edison Co. (SCE) reached a settlement agreement with the California Public Advocates Office on its cost recovery application related to the 2017/2018 Thomas Fire, Koenigstein Fire, and Montecito Mudslides (TKM). If approved by the California Public Utilities Commission (CalPUC), SCE will be authorized to recover 60%, or approximately $1.6 billion of approximately $2.7 billion of losses, including approximately $1.3 billion of uninsured claims, and about $300 million of legal and financing costs paid as of May 31, 2024. SCE will also be authorized to recover 60% of losses paid after May 31, 2024, except for about $125 million of such costs previously waived under a prior agreement with the CalPUC's Safety and Enforcement Division. If approved, SCE may issue securitization bonds to recover such amounts.

Overall, we view this development as supportive of credit quality. Should the CalPUC approve the TKM settlement, it potentially signals a precedent for the recovery of prudent third-party wildfire claims to be recovered from ratepayers, which could lead us to a more favorable view of California's regulatory construct.

Separately, in March 2024 CalPUC adopted a resolution following the passage of Senate Bill 884 in 2023 that authorizes electric utilities serving 250,000 or more customers within the state to participate in an expedited utility undergrounding program. Participating utilities must submit a 10-year distribution infrastructure undergrounding plan to the Office of Energy Infrastructure Safety (OEIS). The OEIS may approve such plan after the utilities demonstrate that their plans' substantially increase reliability by reducing use of public safety power shutoffs, enhanced powerline safety settings, de-energization events, and other outage programs, and that the plan substantially reduces wildfire risk. Upon OEIS approval, the utilities may seek cost recovery from CalPUC, subject to several provisions, including utilities not exceeding approved cost caps for each specific year during the plan, ongoing progress report filings with both the OEIS and the CalPUC, and use of an independent monitor to assess utilities' compliance for each year the undergrounding plan is in effect.

Overall, while the implementation may introduce regulatory risk that participating utilities must effectively manage, we believe the resolution indicates California's proactiveness towards addressing wildfire risk, which is supportive of credit quality.

Colorado

Colorado continues to be a challenging environment for natural gas investor-owned regulated utilities (IOUs). In Public Service Co. of Colorado’s (PSCo; a subsidiary of Xcel Energy Inc.) current rate proceeding, the staff of the Colorado Public Utilities Commission (CoPUC) proposed a 7.5% equity return on capital spending related to new business and capacity expansion projects, and a 9% equity return on safety-related spending. We therefore view the staff's recommendation as negative for credit quality as it creates greater uncertainty regarding regulatory outcomes for natural gas IOUs going forward, while also weakening the ability of the regulatory framework to attract long-term capital for gas IOUs operating in the state, which include PSCo, Atmos Energy Corp., and Black Hills Corp. Overall, we believe this situation demonstrates the more challenging regulatory environment gas distribution IOUs face in a state transitioning away from fossil fuels on an accelerated basis.

On the electric side, electrification and decarbonization reduction goals continue to frame energy policy for Colorado's electric IOUs. Senate Bill 24-218, enacted during the most recent legislative session, establishes a rider for qualifying grid modernizing distribution spending deemed supportive of the state's goals. We believe this rider supports credit quality as it reduces regulatory lag and adds to the availability of recovery mechanisms in the state, which also includes a transmission rider.

The new law also requires IOUs to file plans with CoPUC by Jan. 1, 2025, to underground utility distribution infrastructure. Undergrounding distribution lines may help mitigate wildfires being started by utility equipment.

Connecticut

Earlier in 2024, Connecticut's Superior Court opined in favor of the Public Utilities Regulatory Authority (PURA) concerning the unfavorable rate case decision for Aquarion Co. The company appealed the Superior Court's decision to the Connecticut Supreme Court, where we expect further developments later this year or early next year. Furthermore, following the Superior Court's decision in the Aquarion case, Connecticut Light & Power Co. (CL&P) and The United Illuminating Co. (UIL) both initially paused their participation in the state's electric vehicle rebate program given concerns over their ability to recover related costs in a timely manner, but subsequently resumed their participation. Additionally, CL&P's parent Eversource Energy cut its capital spending plans for its electric and gas distribution operations in Connecticut by $500 million between 2024 and 2028.

Separately, in July 2024, Connecticut Water Co. (CWC) was authorized to raise its base rates by $6.4 million, based on a 9.4% return on equity (ROE) and 53% equity layer. Although PURA also authorized CWC to earn an additional $1.1 million if it achieves certain performance targets, the total potential rate increase for the company was less than one-half of the $21.4 million rate increase request.

We will continue to monitor these and other regulatory proceedings, including the pending rate cases for Southern Connecticut Gas Co. and Connecticut Natural Gas Corp. Notably, these proceedings will be decided under a new commission, as a new commissioner was recently appointed. We expect a final outcome to them by the end of November 2024. The steady erosion in cost recovery through rate increases could weaken the credit quality of certain regulated utilities.

District of Columbia

Recently, the Public Service Commission of the District of Columbia voted against the Washington Gas Light Co. (WGLC) proposed accelerated pipe replacement plan, citing misalignment with the city's climate goals. Overall, the city is primarily focused on minimizing its carbon footprint by limiting the growth of the gas distribution business. Currently we do not believe this materially weakens the D.C. regulatory environment, because in the coming months we expect WGLC to refile its plan with modifications. We will continue to monitor the proceeding regarding the refiled plan before the commission.

Federal Energy Regulatory Commission

In June 2024, The Federal Energy Regulatory Commission (FERC) issued a show cause order, finding that the existing open access transmission tariff (OATT) of certain regional transmission operators (RTOs) and independent system operators--including Midcontinent Independent System Operator Inc. (MISO), PJM Interconnection LLC (PJM), Southwest Power Pool Inc. (SPP), and ISO New England Inc. (ISO-NE)--appear to be unjust, unreasonable, and unduly discriminatory or preferential based on the transmission owner's initial funding provisions. These provisions allow transmission owners to initially fund capital costs for transmission network upgrades for interconnection service, and then subsequently recover such costs through a return on, and of, such investments. Furthermore, the order finds that there may be no risks associated with owning, operating, and maintaining network upgrades for which transmission owners are not already otherwise compensated. The order implies that such initial funding rules could be increasing interconnection costs without corresponding improvements to that service, potentially leading to barriers to interconnection and resulting in undue discrimination among interconnection customers.

From a credit perspective, we view the OATT as a key component of the FERC rate-setting process, which allows transmission utilities to earn a regulated return on their investments, supporting cash flows. As such, we will continue to monitor potential implications of these developments, including as it relates to the predictability and consistency of the rate-setting process.

Florida

A recent regulatory outcome appears to be constructive for credit quality. In August 2024, the Florida Public Service Commission (FPSC) authorized a $470 million multiyear base rate increase over the 2025-2027 period for Duke Energy Florida LLC. The increase is based on a midpoint of 10.3% ROE that we view as supportive of the company's credit quality since the ROE is modestly above the industry averages. The multiyear rate increase is about 60% of what the company had requested.

In addition, we are monitoring Tampa Electric Co.'s (TEP) pending multiyear rate case. TEP is seeking a rate increase of about $295 million in 2025, $95 million in 2026, and $69 million in 2027, and an 11.5% ROE (the company's current ROE is 9.95%). In June 2024, the Office of Public Counsel filed testimony supporting an increase in electric base rates of about $75 million in 2025, $60 million in 2026, and $24 million in 2027, based on an ROE of 9.5%. We expect a final order before year-end 2024.

Illinois

We continue to follow developments related to Commonwealth Edison Co.’s (a subsidiary of Exelon Corp.) and Ameren Illinois Co.’s (a subsidiary of Ameren Corp.) grid plans that each company refiled in March 2024. Although both utilities are operating under approved multiyear rate plans, the ultimate impact on their revenue requirements for the next four years could fluctuate depending on the Illinois Commerce Commission's (ICC) decisions regarding refiled grid plans. We anticipate the companies' approved rate base values and revenue requirements for use in each year of their plans would be updated once that process is completed. We expect ICC decisions in December 2024.

Louisiana

The Louisiana Public Service Commission (LPSC) has approved a stipulation under which it will extend Entergy Louisiana LLC's (ELL) formula rate plan (FRP) for three years and increase the company's base rates by $120 million effective September 2024, with a $140 million cap for the 2024 and 2025 test years. The rate case decision also includes a 9.7% ROE and continuation of ELL's transmission and distribution recovery mechanisms, but with certain caps. In addition, the stipulation includes a one-time refund of about $184 million over two years, mostly reflecting the benefits from IRS tax audits and a reconciliation of the prior years' FRPs.

We view the LPSC's continued adoption of FRPs as supportive for credit quality because we believe such mechanisms enhance utilities' cash flow visibility and predictability. Furthermore, they reduce regulatory risk because the companies receive periodic rate increases without having to adjudicate a full rate case.

The LPSC also announced it has approved a settlement agreement with Entergy Corp.’s subsidiary System Energy Resources Inc. (SERI) regarding multiple proceedings pending before the FERC. If adopted, we would view this as credit supportive because it will resolve substantially all proceedings against SERI. These proceedings have been pending for multiple years and could have had a significant negative credit impact on SERI.

Massachusetts

Several House and Senate bills (including HB-3237, HB-3203, SB-2105, and HB-3227) were recently introduced in Massachusetts to support the state's goal of being carbon neutral by 2050. The proposed bills include plans to prevent utilities from adding natural gas to municipalities that do not already have it, prohibiting state regulators from approving proposals to build new pipelines until at least 2026, redefining gas utilities to include thermal energy, and allowing cities and towns to prohibit fossil fuel use in new construction or major renovations. Overall, these developments suggest that future growth of gas distributions companies could be constrained, increasing the challenges for the state's natural gas local distribution companies. We will continue to monitor related developments.

Minnesota

In May 2024, ALLETE Inc. announced it had agreed to be acquired by two infrastructure funds, the Canada Pension Plan Investment Board and Global Infrastructure Partners. Regulatory approvals are required, including the Minnesota Public Utilities Commission (MPUC), which has authority over utility M&A in the state. Pursuant to state statutes, when reviewing proposed M&A deals, MPUC must consider whether the transaction is consistent with the public interest. There is no statutory time frame for MPUC to act on a merger application and we will continue to monitor the proceeding. ALLETE's credit quality could weaken if MPUC orders a significant ratepayer benefit as part of this transaction because ALLETE already has higher capital spending requirements to decarbonize its generation fleet in line with state energy policy goals, which could weaken financial performance if largely debt funded.

New Mexico

In June 2024, Public Service Co. of New Mexico (PNM) filed for a rate increase of $174 million comprising about $92 million of non-fuel costs and about $82 million of pass-through fuel costs. This rate case will be important for S&P Global Ratings to determine PNM's ability to manage its regulatory risk in New Mexico and will help us determine our view of New Mexico's credit supportiveness. Under its last rate case, which we viewed as less than credit supportive, there were unique factors in the case that made it difficult to establish a definitive long-term view of New Mexico's credit supportiveness.

New York

New York has enacted the New York Utility Corporation Securitization Act, which would allow electric utilities in the state to petition the New York Public Service Commission (NYPSC) to issue storm recovery bonds. We view this as a credit supportive development as it could expedite recovery of such costs, strengthening financial measures. In August 2024, Avangrid Inc. subsidiaries New York State Electric & Gas Corp. (NYSEG) and Rochester Gas & Electric Corp. (RG&E) petitioned for storm-recovery financing as of July 1, 2024, including upfront financing costs. NYSEG and RG&E have requested total securitization amounts of about $707 million and $75 million, respectively. We will monitor these proceedings.

Oregon

Several cities in Oregon are exploring building electrification policies. This follows a July 2023 ruling by the U.S. Court of Appeals for the 9th Circuit, which caused lawmakers in Eugene to repeal an ordinance prohibiting gas use in new low-rise construction while also prompting other cities to back away from similar gas policy plans. In particular, the city of Ashland voted to direct its Climate and Environment Policy Advisory Committee to refine possible policies aimed at advancing electrification within the city through different legal approaches. Overall, we view such overtures as indicative of energy transition risk that the affected gas local distribution utility companies (LDCs) must manage to maintain credit quality. As such, we will continue to monitor potential implications on credit quality for affected gas LDCs should legislation or policies aimed at restricting natural-gas growth gain momentum.

Pennsylvania

Pennsylvania's Act 12 (Fair market value legislation), passed in 2016, supports investor-owned water utilities' acquisitions of municipal water and sewer system. Recently it has been criticized by certain lawmakers in the state, with a proposal to repeal the law. A primary issue with the original law has largely focused on the impact on customer rates after municipal water systems are eventually acquired. Although the law remains in effect, in July 2024 the Pennsylvania Public Utility Commission (PPUC) finalized new criteria for reviewing the sale of public water and wastewater systems. This includes enhanced rate notification for customers, standardizing valuation methods, and a reasonable review ratio that assesses the fairness of acquisition prices. This new criteria has resulted in termination of previously announced transactions, including the August 2024 termination of the proposed sale of the Towamencin Township wastewater system to Pennsylvania American Water, a subsidiary of American Water.

Overall, we view this development as neutral for credit quality in the near to intermediate time frame. However, enhanced regulatory scrutiny of the process to acquire municipal water and wastewater systems or a repeal of Act 12 could make future acquisitions of such systems more onerous to execute, affecting growth prospects of investor-owned water utilities in Pennsylvania.

Texas--PUCT

We continue to surveil matters regarding CenterPoint Energy Houston Electric LLC (CEHE; a subsidiary of CenterPoint Energy Inc.) before the Public Utilities Commission of Texas (PUCT). In July 2024 the governor of Texas directed PUCT to open an investigation into CEHE's preparation and restoration efforts, following the Category 1 hurricane that led to power outages for about 80% of the utility's 2.6 million electric customers. The governor requested PUCT deliver findings by Dec. 1, 2024. There is no immediate credit impact regarding CEHE but if there are negative findings, including any penalties levied, this could be negative for CEHE's credit quality.

In conjunction with its restoration efforts and accelerated resiliency spending program, CEHE requested to withdraw its pending rate case before PUCT, even though regulation requires Texas transmission and distribution utilities' rates to be reviewed within 48 months of their most recent rate case. CEHE's previous rate case ended March 2020, so the company filed its latest rate case in March 2024. Although CEHE initially requested a rate increase, multiple intervenors proposed rate reductions. PUCT's final determination regarding the rate case will be necessary to assess the credit impact. Regardless of the PUCT determination, we do not anticipate the outcome modifying our view on the credit supportiveness of PUCT.

Lastly, in August 2024 the lieutenant governor of Texas requested that PUCT disallow costs associated with CEHE's leased mobile generation, which the company was authorized to recover through regulatory proceedings. We believe a disallowance of already authorized costs could negatively affect our view of PUCT credit supportiveness.

Utah

In March 2024, Senate Bill 224 (SB224) established a fund for electric utilities in Utah with over 200,000 retail customers (such as PacifiCorp), to help pay claims arising from a fire caused by the utility. The fund will mostly be funded by a Utah commission-approved surcharge that the utility may charge its customers for a set period, plus investment income earned on fund assets. The utility with a fund can access it regardless of whether they are deemed negligent but must pay a $10 million deductible. Any party may challenge the amount of a disbursement, although the burden of proof is on the challenger. The commission can also order the company to reimburse the fund for any imprudent disbursement amounts, up to 10% of its Utah rate base.

SB224 also clarified that wildfire damage claims against an electric utility must be brought within two years of the ignition of the event, and, importantly, SB224 also defined limitations of liability if an electric utility has an approved wildland fire protection plan in place and the commission determines that the utility complies with this plan. These caps were set at $450,000 for non-economic damages for parties with a physical injury, $100,000 for other non-economic damages, and the lesser of replacement cost or the difference between pre-post fire fair market value for economic damages. Caps still do not apply for wrongful death claims.

Overall, we view this legislation as favorable for credit quality because it provides the ability to establish a supplemental fire fund, and provides liability caps for electric utility caused wildfire damages aside from wrongful deaths. The new law has not yet been tested in practice and we will continue to monitor related developments.

Virginia

In April 2024, a law was passed that provides Virginia Electric Power Co. and Appalachian Power Co. the ability to seek Virginia State Corporation Commission approval to recover costs associated with a small modular nuclear reactor (SMR) facility of up to 500 megawatts through a limited-issue rate adjustment clause. In general, we view the building of SMRs as negative for credit quality since it entails potential construction risk due to its first-of-its kind technology. Developing new nuclear power plants is a highly complex project characterized by extensive timelines, significant capital investments, and inherent execution risks that can lead to significant cost overruns and delays. Furthermore, given our negative credit view of SMRs, we assess a regulatory framework that provides adequate and timely cost recovery for such costs as only very partially mitigating some of these risks.

Wisconsin

In April 2024, WEC Energy Group Inc.’s Wisconsin subsidiaries filed with the Public Service Commission of Wisconsin (PSCW) for electric and natural gas rate cases for a cumulative increase of approximately $825 million. The multiyear rate cases at subsidiaries Wisconsin Electric Power Co., Wisconsin Gas LLC, and Wisconsin Public Service Corp. are primarily directed towards funding investments, particularly towards transitioning the generation fleets from coal to renewables as well as reliability and safety spending. If authorized as proposed, the increase in rates will bolster financial measures. We continue to view Wisconsin as strongly credit supportive of utilities, and will continue to monitor developments around the rate cases. We expect decisions by year-end 2024.

In May 2024, ALLETE Inc. entered into a definitive agreement to be acquired by the Canada Pension Plan Investment Board and Global Infrastructure Partners, subject to certain regulatory approvals, including by the PSCW. The PSCW has authority over mergers involving Wisconsin utilities. We will monitor the proceeding and any potential impacts to ALLETE's credit quality related to the transaction.

Wyoming

In March 2024, Wyoming modified a law enacted in 2020 requiring a specified percentage of electricity to be dispatchable, reliable, and low-carbon by July 1, 2030. The modification revises the compliance year to 2033 and redefines the statutory definition of low carbon. In addition, the revised compliance standard limits it to only those utilities serving more than 10,000 electric customers, whereas previously it applied to any public utility in the state. Furthermore, the utilities must generate low-carbon electricity from an existing coal-fired generation unit or an equivalent new coal-fired generation facility.

Overall, while these developments are neutral for credit quality in the near term, longer-term energy transition risks could arise should more stringent federal environmental regulations aimed at coal-fired generation facilities result in higher costs for affected utilities.