S&P Global Ratings revised its assessments of regulatory jurisdiction in three U.S. states--Colorado, Connecticut, and Washington--to reflect incremental shifts as it relates to creditworthiness of utilities we rate. We also monitored developments in other regions.

Our periodic assessments of regulatory jurisdictions in the U.S. and Canada where a rated utility operates provide a reference for determining a utility's regulatory advantage or risk. Regulatory advantage is a heavily weighted factor in our analysis of a regulated utility's business risk profile. Our analysis covers quantitative and qualitative factors, focusing on regulatory stability, tariff-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.

Sorting Through The Regulatory Jurisdictions In The U.S. And Canada

We updated our assessments of regulatory jurisdictions since we published "Updates And Insights On Regulatory Jurisdictions Shaping Policies For North American Utilities-–March 2021," on March 22, 2021. This is our current snapshot of each regulatory jurisdiction.

For the approximately 225 U.S. and 30 Canadian utilities we rate, rating committees make regulatory advantage determinations that reflect quantitative and qualitative factors as well as the committee's opinions. We group the jurisdictions by these determinations.

The categories are an important starting point for assessing utility regulation and its effect on ratings. They are all credit-supportive to one degree or another, as all utility regulation tends to sustain credit quality. The presence of regulators, no matter where on the spectrum of our assessments, reduces business risk and generally supports utility ratings. We therefore designate all these jurisdictions from credit supportive to most credit supportive, and these vary only in degree.

Table 1

Mapping Regulatory Jurisdictions

For jurisdictions assessed in Charts 1 and 2, colors delineate our assessment of credit supportiveness. (We do not have assessments on Canadian provinces where we do not have utility ratings.) They offer some scale and detail in our thinking regarding the rules and implementation of regulation. Often they simply designate a stable jurisdiction slightly better or worse than its closest peers in credit quality.

Chart 1

Chart 2

Recent Regulatory Assessment Revisions

We periodically evaluate regulatory jurisdictions to discern a shift of credit quality. Based on our most recent evaluation, these jurisdictions shifted in their credit supportiveness.

Colorado

We believe the regulatory framework in Colorado weakened over the past several years primarily due to increased politicization of the regulatory process. Frequent turnover of Public Utilities Commission (PUC) members reduced the predictability of the regulatory process. Past behavior of regulators and other participants raises questions about the balance of the interests and concerns of stakeholders. Although the use of forecast test periods is authorized, they have been contentious and not permitted outside of settled rate cases. Historically, the PUC relies upon year-end rate bases for energy utilities. But recent energy cases utilized average rate bases, and the commission has opposed utility proposals for a year-end rate base.

Also in recent years, authorized capital structure parameters including return on equity (ROE) for investor-owned natural gas and electric utilities have been below industry norms. Due to the politicization, the frequency of litigated rate proceedings has risen. We therefore revised the overall score on the Colorado PUC downward to very credit supportive from most credit supportive.

Connecticut

We revised our regulatory jurisdiction assessment on Connecticut to more credit supportive from very credit supportive. Over the past year, several incidents regarding Connecticut's electric utilities in our view increased regulatory risk in the state. For example, in July 2020, the Connecticut Light & Power Co. (CL&P) was ordered to reverse an approved and implemented rate increase pending an investigation into its rate-setting mechanisms following political pressure. In addition, CL&P and The United Illuminating Co. (UIL) were investigated for their restoration efforts following Tropical Storm Isaias in August 2020. The Connecticut Public Utilities Regulatory Authority lowered CL&P's authorized ROE 90 basis points (bps) and UIL's 15 bps. The commission also left open the possibility for storm cost disallowances and assessed civil penalties on CL&P of 2.5% of its electric distribution revenues. These penalties and ROE reductions were larger than past actions, which in our view lowers the predictability of the framework. Furthermore, given that many of these actions followed political criticism of the utilities, we believe such pressure could lead to more scrutiny and affect their ability to effectively manage regulatory risk, a key component to our analysis of credit quality.

Washington

We revised our regulatory jurisdiction assessment on Washington state to very credit supportive from more credit supportive. This reflected our view that the Washington regulatory construct has strengthened. Gov. Jay Inslee recently signed Senate Bill (SB) 5295 into law. It includes the mandatory filing of multiyear rate plans and performance-based rate making that we view as credit supportive. We expect the multiyear rate plans will enable utilities to reduce regulatory lag and smooth cash flow volatility. Utilities now must file a multiyear rate plan that is in place from two to four years. Furthermore, power costs may be trued-up after the second year, improving cash flow predictability. We view this as a more credit supportive tariff-setting design. Recoverability of operating and capital costs could improve long-term capital attraction.

No Assessment Revisions, But Notable Developments

Kansas

We believe the regulatory framework has improved incrementally in Kansas following passage of a law that authorizes the state's electric and natural gas utilities to use securitization financing to recover qualified extraordinary costs, including those during the deep freeze that swept the region in February and costs associated with a past or future retirement or abandonment of generation facilities. Notably, utilities can accrue carrying charges associated with any qualified extraordinary costs at their respective weighted-average cost of capital. We believe the prompt action taken by the Kansas legislature is highly constructive for credit quality, given the materiality of these costs--which on a combined basis surpassed $5 billion in total for ONE Gas Inc., Atmos Energy Corp., Evergy Inc., and Black Hills Corp. Although our overall view of the Kansas Corporation Commission is unchanged and we continue to assess the jurisdiction as highly credit supportive, we believe the landscape around energy policy, as it supports the long-term credit quality of utilities, has strengthened.

Nebraska

In a recent decision, Black Hills Nebraska Gas, a subsidiary of Black Hills Corp., received approval from the Nebraska Public Service Commission (PSC) to recover about $87 million in expenses from the February freeze over 36 months through a special purpose, one-time use rider. The amount to be recovered includes approximately $80 million in gas supply costs plus approximately $7 million in anticipated carrying costs. The amount was calculated at a rate of 0.92% for the period between February to September 2021 and 6.71% annually, representing the utility's weighted-average cost of capital approved in its most recent rate review, for the remainder of the 36 months. We view this blended approach as credit positive as it more accurately compensates the utility at its cost of issuing either equity or debt capital. Although our overall view of the PSC is unchanged, we believe this action demonstrates a commitment to credit quality.

Nevada

Under a new law, electric transmission should receive a boost. NV Energy Inc.--owner of the state's largest electric utilities, Nevada Power Co. and Sierra Pacific Power Co.--will likely expand its high-voltage transmission infrastructure. This accelerates completion of two new 525-kilowatt transmission lines in the state. NV Energy is a subsidiary of Berkshire Hathaway Energy Co. The law also mandates transmission providers to join a regional transmission organization by Jan. 1, 2030, and the creation of a Regional Transmission Coordination Task Force. NV Energy must also file a three-year, $100 million transportation electrification plan to build out the state's electric vehicle charging infrastructure, including stations along interstate highways.

Oklahoma

We continue to monitor developments in Oklahoma despite no change to our regulatory assessment. A law passed in April requires utilities to file with the Oklahoma Corporation Commission (OCC) for use of securitized financing for any extreme purchase costs and other extraordinary costs incurred during the February freeze. These costs include extreme fuel, purchased power, and natural gas commodity expenses, as well as certain unprecedented utility operating expenses because of that storm. We view this legislation as potentially favorable for the regulatory environment in Oklahoma due to features of the mechanism that support off-balance-sheet debt treatment. The next steps we continue to monitor include how the OCC will implement a securitization financing order consistent with the new law.

Ontario

Although we did not revise our regulatory jurisdiction assessment of most credit supportive, we believe Ontario has weakened within this category. On June 17, the Ontario Electric Board (OEB) adopted with minimal changes a staff proposal regarding guidelines for rate recovery of incremental costs incurred during the COVID-19 pandemic. To assess if a utility should be given recovery of these costs, the OEB states that only if incremental costs incurred during the COVID-19 pandemic result in a utility's authorized ROE declining by at least 300 bps, the utility would be allowed to recover up to 50%. On a case-by-case basis, if the utility demonstrates its financial viability would still be compromised should recovery be limited to 50%, the OEB could consider a higher recovery rate. The OEB's adoption weakens our assessment of recoverability of all prudently incurred operating and capital costs in full and flexibility to recover unexpected costs if they arise.

Major rate case parameters such as ROE are formula-driven, and regulated capital structures have remained consistent for years, promoting predictability. However, these parameters have become the lowest in the Canadian provinces, which could weaken investment in regulated utilities. Coupled with the OEB's report on COVID-19 pandemic cost recovery, we believe the interests of various stakeholders have become unbalanced.

Oregon

In May, the Oregon PUC issued temporary rules governing and standardizing public safety power shutoffs (PSPS), when lines are de-energized in extreme weather conditions. The rules apply to investor-owned utilities operating in the state such as Portland General Electric Co., PacifiCorp (operating as Pacific Power), and Idaho Power Co. The rules also create communication protocols between utilities and other stakeholders, including state agencies and the public, as well as reporting requirements for the 2021 wildfire season. They remain in effect until mid-November as regulators develop permanent rules in collaboration with utilities and local communities. According to the Oregon PUC, wildfires burned approximately 1 million acres in the state in 2020. Oregon's Department of Forestry officially announced in May the beginning of a new fire season in certain areas, the earliest such declaration in over 40 years. We will continue to monitor developments surrounding the implementation of the PSPS rules and the wildfire season in the state and the region.

The Oregon legislature proposed House Bill (HB) 2021, which would require retail electricity providers to reduce greenhouse gas emissions associated with electricity sold to 100% below baseline emissions by 2040. The bill also proposes interim targets of 80% below baseline emissions by 2030 and 90% by 2035. In addition, it bans new construction or expansion of power plants that burn natural gas or other fossil fuels. We will continue to monitor the bill and if it passes.

Railroad Commission of Texas (RRC)

On June 17, Texas Gov. Greg Abbott signed HB 1520 to address the over $5 billion in natural gas costs that local distribution companies (LDCs) incurred during the February storm. Natural gas LDCs can seek approval from the RRC to securitize these extraordinary costs along with carrying charges. Our view of the RRC is unchanged at highly credit supportive. However, we believe this action demonstrates a commitment to credit quality for investor-owned gas utilities in the state.

Texas Public Utilities Commission

Abbott signed HB 1510 into law June 8 for investor-owned electric utilities. It broadens legislation around the recovery of system restoration costs through securitization financing for non-Electric Reliability Council of Texas vertically integrated utilities (VIU), but it doesn't address the recovery of the extraordinary fuel and purchased power costs incurred during the freeze. Compared to the securitization route taken for other stakeholders, we view this as less favorable for credit quality primarily due to the lack of clarity around future recovery of the extraordinary fuel and purchased power costs. VIUs can normally recover fuel and purchased power costs through riders, but given the size of the costs, recovery over a short period would be too onerous on customer bills. While some utilities requested deferral treatment of these costs, approval in full, including associated holding costs, is uncertain and could contribute to regulatory lag.

In the wake of the winter storm, all three Texas PUC commissioners resigned amid pressure from some state politicians. While our overall view of the regulatory framework under the Texas PUC is unchanged at very credit supportive, we believe this demonstrates greater risk of political intervention. That ultimately can be negative for credit quality, especially with multiple rate proceedings pending at the time.

West Virginia

Gov. Jim Justice signed SB 542 in April and it becomes law July 9. It requires utilities to maintain a minimum 30-day aggregate coal supply under contract for the remainder of a plant's life, and public electric utilities are to provide notice before plant closures or permanent idling to the PSC of West Virginia, the West Virginia Office of Homeland Security and Emergency Management, and the legislature's Joint Committee on Government and Finance.

Renewable Portfolios And Clean Energy Standards

We continue to monitor developments in renewable and clean energy standards, their influence on the overall strategic direction and growth investments of regulated utilities, and their potential impact on credit quality. Since our March update, states, cities, and utilities alike have continued to make progress toward reducing carbon emissions and utilizing a greater percentage of renewable energy generation. For example, Arizona, Illinois and New Orleans also proposed or enacted legislation setting timelines to reduce emissions.

Offshore wind has picked up traction in the U.S., specifically on the East Coast. This spring, the first large commercial-scale offshore wind project received federal approval. The joint venture of Avangrid Renewables, a subsidiary of Avangrid Inc., and Copenhagen Infrastructure Partners plans to install up to 84 wind turbines in the Atlantic Ocean near Massachusetts. Another offshore wind project in the approval process is Ocean Wind, a joint venture between Orsted A/S and Public Service Enterprise Group Inc. off the coast of New Jersey that would add 1,100 megawatts (MW) of capacity. And the first offshore wind farm in New York, off Long Island, will add 132 MW of capacity. We expect this joint venture between Orsted and Eversource Energy to begin construction in 2022 and be in operation by the end of 2023.

The Biden Administration has committed to expanding offshore wind opportunities along the Atlantic Coast, Gulf of Mexico, and Pacific Coast. It aims to deploy 30,000 MW of offshore wind power by 2030 and potentially 110,000 MW by 2050. Besides these long-term goals, the Administration announced that the northern and central coasts of California would be open to an estimated 4,600 MW of offshore wind power development capacity.

Related Research

• Our View Of The Texas Railroad Commission Remains Highly Credit Supportive For Invested-Owned Utilities, June 22, 2021
• For Investor-Owned Utilities, Winter Storm Uri Hasn’t Affected Our View Of Texas’ Regulatory Framework, June 8, 2021
• Why We See Alberta’s Electricity And Gas Regulatory Framework As Highly Credit Supportive, March 3, 2021
• Why We See Ontario’s Electricity And Gas Regulatory Framework As Strong, Jan. 13, 2021
• Updates And Insights On Regulatory Jurisdictions Shaping Policies For North American Utilities—March 2021, March 22, 2021
• Key Credit Factors For The Regulated Utilities Industry, Nov. 19, 2013