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Regulatory Responses To COVID-19 Are Key To Utilities’ Credit Prospects


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Regulatory Responses To COVID-19 Are Key To Utilities’ Credit Prospects

The COVID-19 pandemic has created an unprecedented level of uncertainty and regulatory action in North America. Throughout the United States and Canada, many state and provincial governments have instituted mandatory moratoriums on utilities shutting off customers, or they have worked together to institute voluntary moratoriums during the COVID-19 pandemic. These moratoriums, along with any lost revenues due to the economic impact of COVID-19 pandemic and the potential incurrence of higher operating expenses, may weaken financial measures of utilities. S&P Global Ratings has been monitoring these actions and their impact on credit quality of U.S. and Canadian regulated utilities.

North American Moratoriums

The maps below indicate the states and provinces that have instituted mandatory and voluntary moratoriums. A few states have multiple regulators that utilize both voluntary and mandatory moratoriums.

Chart 1 


Chart 2 

Regulatory Responses & Credit Implications

While no jurisdiction's response is exactly the same, we have identified several broad categories of response. Jurisdictions and regulatory commissions have authorized utilities to:

  • Defer costs for future recovery;
  • Enter into payment arrangements with customers;
  • Enter into bill mitigation measures, such as the acceleration of refunds for fuel costs; and
  • Seek rate recovery through various mechanisms such as rate surcharges, future rate cases, or formula rate plans.

One of the main responses we've seen from commissions are the authorization of utilities to accrue COVID-19-related costs and defer them for future prudence reviews and rate recovery for both residential and nonresidential customers.


The Arkansas Public Service Commission authorized the utilities to establish regulatory assets to record costs resulting from the suspension of disconnections. In future proceedings, the commission will consider whether each utility's request for recovery of these regulatory assets is reasonable and necessary. We expect Entergy Corp. utility Entergy Arkansas LLC to file a formula rate plan in the summer of 2020, and that revenue changes and costs from COVID-19 should be captured in the new rates that take effect at the beginning of 2021.

On March 4, California Gov. Gavin Newsom declared a statewide emergency due to the COVID-19 outbreak. As a result, Edison International subsidiary Southern California Edison Co. (SCE) suspended all disconnections for nonpayment, waived late fees and deposits, and implemented flexible payment plans upon request for all residential and nonresidential customers. SCE is among the many investor-owned utilities that have suspended customer service disconnects for nonpayment during the pandemic. SCE's electric rate case request to institute interim rates this summer is being challenged by interveners with claims that the increase would be counterproductive amid the COVID-19 pandemic. Absent the interim rate increase, SCE indicated it will experience a "significant lag for cost recovery...expenses incurred to protect current customers."

In Mississippi, "The [Mississippi] Commission acknowledges that the protective measures for customers and utility employees could pose a financial strain on the utilities subject to its rate regulation and that such utilities should be provided regulatory certainty by authorizing the use of an accounting mechanism and a subsequent process through which they may seek future recovery of costs or expenses resulting from such measures, and hereby enters this order to mitigate the financial impacts of such actions." Entergy Corp. subsidiary Entergy Mississippi LLC has a pending formula rate plan that has a 2020 test period, resulting in timely rate recovery of costs when new rates take effect mid-year.

As mandated by the Alberta government in Canada, electricity providers (both competitive and regulated) are absorbing the costs for nonpaying customers for 90 days until June 18, 2020. The utility payment deferral program allows residential customers to defer electricity and natural gas bill payments regardless of the service provider.

Some jurisdictions in Canada have determined that residential and small business customers can stop paying for up to 90 days. On March 19, 2020, the Ontario government extended its winter ban on residential disconnections through July 31, 2020. The extension also applies to small businesses. Ontario local distribution utilities cannot disconnect these customers for nonpayment. Residential and small business customers on time-of-use pricing are paying 10.1 cents per kilowatt hour (kWh), the off-peak price, throughout the day and until June 1, 2020. The government indicated that order would be in place for 45 days. The Ontario province is paying generators for the loss of peak pricing. Paying for generation while not collecting from ratepayers could cause a cash flow squeeze--the local distribution companies (LDCs) continue to pay the Independent Electricity System Operator (IESO) for generation and transmission while customers may not be paying the monthly invoices. How LDCs account for losses in future rate recovery has yet to be defined.


Larger customers typically have energy charges based on consumption and demand charges that are paid even if consumption declines. Demand charges may reset more frequently; therefore, if consumption by a larger customer has dropped due to COVID-19 shutdowns, cash flow from the customer could be reduced as compared to previous periods. In North Carolina, an intervener requested that the North Carolina Utilities Commission (NCUC) suspend minimum demand charges for commercial and industrial customers during the COVID-19 crisis. The commission is reviewing the filing. If they were to accept it, utilities could lose operating cash flow until the pandemic has passed. Duke Energy Corp. subsidiary Duke Energy North Carolina, among other utilities, has petitioned the NCUC against deferring industrial demand charges. This move is indicative of the NCUC not just looking at the COVID-19 impact to residential customers but also actively considering the interests of companies in the industrial segment. That being said, a deferral of demand charges could cut down once-thought-to-be-fixed cash flows for utilities and potentially weaken their stand-alone cash flows.

Credit Implication of Cost Deferrals.  Without an additional and explicit timeline of recovery, deferrals represent a less credit-supportive regulatory response, despite any good will created with customers or their jurisdictional authority. This is due to a combination of the immediate near-term impact and the prolonged uncertainty of future recovery. Once costs are deferred, utilities may face an immediate reduction to operating cash flow in the near term, which may bring them close to or below their outlook downgrade threshold. Compounded with the increased uncertainty of when the utility will recover any deferred costs, this method--without any explicit notion of when costs will be recovered from their jurisdictional authority--has the potential to increase the risk the utility takes on more than any other response.

Payment Arrangements

The next category of response we've identified is situated around payment arrangements that utilities created for their customers. These allow utilities to resolve payments proactively instead of deferring them for future recovery, as well as interact directly with customers through an agreed-upon payment schedule or payment assistance program.

An example of this response can be seen in North Carolina. On March 19, an order issued by the NCUC, with respect to the moratorium on service terminations during the COVID-19 state of emergency, states: "At the end of the State of Emergency, customers having arrearages accrued during the State of Emergency shall be provided the opportunity to make a reasonable payment arrangement over no less than a six month period and shall not be charged any late fees for late payment for arrearages accrued during the State of Emergency. No provision in this Order shall be construed as relieving a customer of their obligation to pay bills for receipt of any utility service covered by this Order." This order removes additional uncertainty in terms of recovery for utilities as it allows the applicable utilities to plan and coordinate with customers, contrasted with the need to go through additional NCUC proceedings (although they still may be necessary).

As opposed to direct agreements between utilities and their customers to address arrearages, some jurisdictions have leaned upon federally funded programs to stave off the effect of the COVID-19 outbreak on the customer bill. The Colorado governor's March 5, 2020, order placed a moratorium on service disconnections. The Colorado Public Utilities Commission was directed to work with all public utilities to develop and provide payment assistance programs to aid customers. Since the initial orders, utilities including Black Hills Corp. utility Black Hills Energy, Xcel Energy Inc.'s utility Public Service Co. of Colorado, and Atmos Energy Corp. have made efforts to set up payments for low-income customers during the state of emergency through the Colorado Low-income Energy Assistance Program (LEAP), a federally funded state-supervised, county-administered system. To the south, the Arizona Corporation Commission has urged utility customers to work with their utility providers, such as Pinnacle West Capital Corp. subsidiary Arizona Public Service Co., and take advantage of payment assistance programs like the Low-Income Home Energy Assistance Program (LIHEAP) as costs have not formally been deferred. While not isolated to just Colorado and Arizona, the response in these states is reflective of the heightened coordination of commissions and utilities with their customers through federal, state, and local programs to alleviate financial hardships and allow for the recovery energy costs.

Credit Implication of Payment Arrangements.  As compared to deferrals without any cost recovery timing, payment arrangements provide greater certainty regarding the timing of cost recovery for utilities. Regardless of greater certainty, the utility may still face a reduced operating cash flow as these payment arrangements may not come into effect until after the COIVD-19 state of emergencies. Therefore, the utility may still face the same short-term immediate impact deferrals.

Bill Mitigation

In many of the jurisdictions in which payment arrangements are utilized, the onus of a payment solution is placed on the consumer to contact their utilities and payment assistance programs to reduce their energy bills. Even if these payment arrangements are made, there is a degree of lag between when utilities will start receiving payment, causing a lapse in recovery. Other jurisdictions have chosen to take more proactive roles in reducing customer bills through bill mitigation actions during the COVID-19 outbreak. While there could still be a lag in payment, these actions make customer bills more affordable, which we believe increases the probability of the ultimate cost recovery through rates.

An example of this occurred in Washington. As part of an authorized electric rate increase of about $29 million for utility Avista Corp., the Washington Utilities and Transportation Commission (WUTC) wanted to ease the financial impact on electric and gas customers during the COVID-19 pandemic, and fast-tracked customer rate refunds. The WUTC expects to mitigate the authorized rate increase and achieve a roughly net-zero impact on electric customers in the first year of the new rates. The refund largely consists of a rebate of energy costs through the company's energy recovery mechanism.

A similar approach was also taken in Florida, where the commission allows for the issuance of a bill credit for the state's four largest utilities. Approved by the Florida Public Service Commission in April, customers of Florida Power & Light Co., Duke Energy Florida LLC, and Gulf Power Co. will receive a one-time bill reduction in May to reflect over collection of fuel and capacity cost recovery factors. Tampa Electric Co.'s approved proposal will pass fuel-cost savings to customers from June through August, with smaller monthly savings through December. The credits reduce customer bills, which mitigates customers' financial hardships during the COVID-19 pandemic.

Credit Implication of Bill Mitigation  Bill mitigation provides utilities the ability to collect payment in the near term and while retaining the ability to set up payment arrangements with customers to collect in the long term. While this response does not completely remove uncertainty around the collection of costs, it takes a meaningful step to mitigate risk for the utility while ensuring the customer is benefiting as well.

Table 1

North American Jurisdictional Responses
As of May 14, 2020
Collecting Costs / Deferral Customer Payment Arrangements Pending
Alaska Alabama Arizona
Alberta Alberta Delaware
Arkansas Colorado Idaho
British Columbia Florida * Illinois
California Indiana Kansas
Connecticut Montana Kentucky
District of Columbia New Foundland & Labrador * Louisiana
Georgia New Hampshire Maine
Hawaii New Jersey Massachusetts
Idaho North Carolina Michigan
Iowa Ohio Minnesota
Kansas Prince Edward Island Missouri
Maryland Quebec Nebraska
Michigan Rhode Island New Mexico
Minnesota Saskatchewan * Pennsylvania
Mississippi South Carolina Utah
Nebraska South Dakota Virginia
Nevada Washington * West Virginia
Oklahoma Wisconsin
South Carolina
* States have a bill credit program in place that will ultimately reduce customer bill but payment arrangement will still have to be made with reduced bill.
Options Of Regulatory Recovery

Options of rate recovery for COVID-19 costs by utilities can include rate cases and various rate riders.

Rate Cases

Recovery could be addressed through a rate case, although our data suggests that many utilities are reluctant to file new rate cases during this period of hardship for rate payers (see RRA chart below). Still, there are several rate cases underway. For example, Columbia Gas of Pennsylvania Inc., a subsidiary of NiSource Inc., filed for a rate increase that should capture the impact of COVID-19 when new rates go into effect later in 2020. Ameren Corp. subsidiary Ameren Illinois Co. recently filed a gas rate case in Illinois that will reflect a projected test period and will likely include the impact of COVID-19 on the utility's test period revenues.

Chart 3


For electric, Ameren Illinois has a formula rate plan that is updated periodically. The utility has been submitting annual filings for its formula rate plan based on a test period composed of the previous calendar year. Therefore, in a 2021 filing, we would expect COVID-19-related costs to be incorporated within a test period of calendar 2020. Another recovery option could be through decoupling mechanisms whereby revenues are reset; this could capture the weaker cash flows from bad debt expense and reduced revenues from COVID-19 inactivity.

In addition to the requested rate increase, Columbia Gas of Pennsylvania wants to implement a revenue normalization adjustment, or RNA, that would allow the gas utility to adjust rates for changes in revenue for reasons such as customer participation in energy conservation programs and overall economic conditions. The company is also proposing to increase the fixed monthly customer charges for residential and small commercial customers to allow a greater proportion of fixed costs to be recovered through these fixed charges. Mechanisms such as these will further decouple the utility's revenue from weak economic activity and customer conservation.

To alleviate the impact of COVID-19 on ratepayers, utilities could seek to remain out of or delay rate case proceedings. For example, Wisconsin Power & Light Co. recently proposed not to submit its expected rate review that Wisconsin utilities typically file every two years with the state commission. Duke Energy Kentucky Inc. notified the Kentucky commission in March that the company was "keenly aware" of the "great strain upon government agencies at the federal, state, and local levels," and would therefore "avoid placing further burdens upon the commission, and to help customers who are affected by present circumstances, by delaying the potential effective date of new rates in the company's pending electric rate case" before the month of May. This allowed an additional month before new rate as the decision was expected April 2. Under these actions, rates would remain largely in line with current levels, mitigating utility costs to ratepayers during the pandemic. Utilities may seek such an approach if they can maintain financial measures while remaining out of rate cases for an extended period.

Credit Implications of Rate Cases.  Rate cases may prove effective at recovering lost revenue or COVID-19 costs but are likely to take months or years to complete, thereby exposing the utilities to lag. We also note that very few utilities are filing rate cases in the current environment and opting to suspend and even forgo review this year.

Rider Recovery

Some jurisdictions have bad debt expense riders, or something similar, that provide more timely cost recovery. In Illinois, gas distribution companies are authorized to recover uncollectible debt expense through a surcharge. Multiple gas utilities, including Ameren Illinois Co., Southern Co. subsidiary Northern Illinois Gas Co., and Exelon Corp. utility Commonwealth Edison Co. use rate riders to recover this cost. The rider provides for cost recovery or refund of uncollectible expense based on the difference between actual uncollectible write-offs and the amounts recovered in current base rates.

A recent Georgia commission rate case authorized Southern Co. subsidiary Georgia Power Co. to defer all lost revenue and increased costs associated with COVID-19. In contrast, gas utility Atlanta Gas Light Co. (AGL) and the Georgia commission staff have proposed a revenue true-up process within the Georgia Rate Adjustment Mechanism. The mechanism was initially approved in 2017. In addition, AGL uses a modified straight-fixed-variable rate design that enables the company to recover non-gas costs throughout the year, consistent with the incurrence of these costs, essentially eliminating the need for a revenue decoupling mechanism.

Texas regulators took a different approach for electric utilities within the Electric Reliability Council of Texas (ERCOT). For residential electricity customers that have retail choice of electricity providers and are in danger of disconnection, late fees will be suspended and deferred payment plans will be offered. A COVID-19 Electricity Relief Program has been established with $15 million from ERCOT. This fund will reimburse retail electricity providers (REPs) for unpaid energy charges and transmission and distribution utilities (TDUs) for unpaid delivery charges of customers certified as experiencing COVID-19-related hardship and not disconnected. This would pertain to CenterPoint Energy Houston Electric LLC, Oncor Electric Delivery Co. LLC, and AEP Texas Inc. ERCOT and each TDU will enter into an interest-free loan associated with the COVID-19 Electricity Relief Program. TDUs will establish rate riders in which all customer classes will pay a 33 cent per megawatt hour charge to reimburse REPs for unpaid energy charges and TDUs for unpaid delivery charges, and to repay ERCOT's initial contribution. The riders will stay in effect until the TDUs have been reimbursed and ERCOT has been repaid.

Water utilities and vertically-integrated electric utilities outside ERCOT, such as Entergy Texas Inc., El Paso Electric Co., Southwestern Public Service Co., and Southwestern Electric Power Co., may not charge late fees or disconnect customers for nonpayment during the COVID-19 pandemic.

Credit Implications of Rider Recovery.  Regulatory responsiveness through rate riders may prove more effective at recovering lost revenue or COVID-19 costs as they may provide for stronger cash flow and reduced uncertainty around ultimate recovery, and may strengthen a utility's credit quality. Rate recovery through riders may efficiently adjust rates for the impact of COVID-19 on the company, bolstering revenues and cash flow to the benefit of creditors.

Impact To Credit Quality From COVID-19 On U.S. And Canadian Utilities

The effects on credit quality from the COVID-19 pandemic and regulatory responses have been occurring in real time across the industry. These effects include weakening of operating cash flow and capital structures, access to liquidity, and alterations in capital spending plans.

Weaker Operating Cash Flow

Utilities that had weaker financial measures, possibly close to the downgrade triggers in their rating outlook, could see financial measures further degrade due to COVID-19. Without improved operating cash flow or any strengthening of the balance sheet, we could revise the outlook or change the ratings. Rebalancing a capital structure could be challenging, particularly for those with weakened operating cash flow, because issuing equity in times of financial stress can be especially difficult.

Looking ahead, several companies have assumed equity issuance as part of their 2020 plans, given the industry's high capital spending that we estimate at about $150 billion. While the capital markets remained mostly accessible to the industry during the first two months of 2020, we anticipate a significant decline in equity issuances over the remainder of 2020 given the level of uncertainty surrounding COVID-19. When combined with our expectation of reduced volumetric sales, increased bad debt expense, and delayed rate case filings, the industry could experience a weakening of credit measures. Given that many companies are already strategically operating with minimal financial cushion at current rating levels, weaker financial measures could lead to downgrades (See "COVID-19: While Most Of The U.S. Is Shut Down, Utilities Are Open For Business," May 4, 2020).

For the most strained issuers, or those that may not fare as well in front of regulators vis-à-vis COVID-19 costs, this is where the rubber will hit the road in terms of evaluating financial policy priorities. Companies will have to consider tough tradeoffs, and some may even need to take proactive steps to forestall downgrades (see "North American Regulated Utilities Face Tough Financial Policy Tradeoffs To Avoid Ratings Pressure Amid The COVID-19 Pandemic," May 11, 2020).


Operating cash flow will decline and operating income will be squeezed as revenues erode, while costs of goods sold and operating expenses continue to be incurred. This will make liquidity critical to cover expenses. Despite the challenges associated with the economic downturn, the utility industry has preserved its investment-grade profile and maintained adequate liquidity in part by securing multiyear revolving credit facilities that are sized to sufficiently cover cash needs over a 12-month period. Also, as commercial paper interest rates spike to levels last seen during the 2008 financial crisis, we saw many utilities enter into 364-day term loans to lock-in liquidity at reasonable rates. We view this as allowing the industry to circumvent the volatile commercial paper markets, strengthening the industry's near-term liquidity position.

Greater Uncertainty Could Drive Capital Expenditure Changes

The combination of weaker operating cash flow and uncertainty could result in lower capital spending and delays in projects spread out over a longer period. An example is CenterPoint Energy Inc., which, in response to a large distribution cut from its investment in a midstream energy company Enable Midstream Partners LP, lowered 2020 capital spending $300 million. Enable Midstream cut its distributions after oil and gas prices dropped. In its first-quarter 2020 earnings call, American Electric Power Co. Inc. lowered 2020 capital spending by $500 million following lower revenue due to warmer-than-normal weather. Less capital spending should free up cash to partly offset expected revenue loss. Although Unitil Corp. is continuing its capital spending program, it stated in its first-quarter 2020 earnings call that COVID-19 had the potential to cut revenues by about $400,000 for every 1% drop in power usage in its operations. The company can offset these losses and increase cash if it can reduce capital spending.

Moreover, a major target of capital spending in the utility sector, clean and renewable energy projects (such as the offshore wind projects that Eversource Energy, Dominion Energy Inc., and AVANGRID Inc. are engaged in), could see forms of delay in construction and operation. AVANGRID recently stated on its 2020 first quarter earnings call that while its offshore wind project is slated to be operable on time, the company has experienced a number of force majeure events from suppliers due to COVID-19, a trend that may affect other offshore wind project providers. In order to maintain credit quality, utilities with similar projects may need to adjust capital investment to preserve assets while ensuring adequate liquidity.

That being said, despite the effect of the COVID-19 pandemic, several jurisdictions have pushed to ensure the trajectory of their clean energy goals. In April, the New York Public Service Commission authorized the New York State Energy Research and Development Authority to procure at least an additional 1,000 megawatts of offshore wind energy in 2020. In the same month, the Virginia legislature passed the Clean Energy Economy Act, mandating that by 2045 100% of the power supplied by any competitive retail electric provider, including Dominion Energy Inc. subsidiary Virginia Electric & Power Co., must be sourced from renewable and carbon-free resources. The aggressive standards for clean energy goals in these jurisdictions and others around the country may provide enough incentive for utilities to continue to advance such projects.

This report does not constitute a rating action.

Primary Credit Analysts:Gerrit W Jepsen, CFA, New York (1) 212-438-2529;
Dimitri Henry, New York + 1 (212) 438 1032;

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