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Postponing review of deferral mechanics hampers one's grasp of ratemaking tools


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Six trends shaping the industries and sectors we cover in 2021

Six trends shaping the industries and sectors we cover in 2021


Essential Energy Insights - January 2021

Postponing review of deferral mechanics hampers one's grasp of ratemaking tools

Most dictionaries define "deferral" as the postponement of an event or an action. In the utility sector, this definition is only partially accurate and it is important for utility industry stakeholders to understand the mechanics of deferrals in the context of the ratemaking framework.

For utilities that seek deferral treatment for certain costs they have incurred, the key event has typically already taken place. For example, a utility that has seen a hurricane move through its service territory may have already restored power and obtained approval to defer the related costs, but actual recovery of the costs — and in certain circumstances, the revenues the company has been unable to collect during the event — is going to be addressed at some point in the future.

Regulatory assets are unique to utilities and are the product of accounting standards. A regulatory asset is typically created when the utility's regulator authorizes, through issuance of an accounting authority order, or AAO, the deferral to a future period of an expense that would normally be recorded on the company's income statement during the present period. Accounting convention dictates that the prospects for future recovery in rates of the cost item in question must be probable for an expense to be deferred. The deferred costs give rise to a regulatory asset that is recorded on the company's balance sheet and is likely, but not guaranteed, to be included in rates at some point in the future and amortized over several years. Deferrals often obviate the need for utilities to immediately file rate cases to address recovery of the costs for which they are seeking deferral treatment.

"A utility's ability to defer these costs into an AAO prevents the deterioration of the utility's earnings that would otherwise occur. To the extent that this action helps sustain the utility's continued access to low cost debt and equity capital, ratepayers receive a direct benefit because they ultimately pay these capital costs through rates. Furthermore, if a utility's request for an AAO is denied, its only other option might be to file a full general rate case, which would not be in the public interest, especially if it resulted in every utility in the state filing a rate case during the same general time." - Staff of the Kansas Corporation Commission on the merits of deferring COVID-19 costs, Docket No. 20-EKME-454-ACT

Deferrals are an interim ratemaking remedy designed to help reduce "regulatory lag." Allowing the utility to defer recovery of increases in specific costs until the commission can address them at a later date leaves the utility's earnings unaffected by the increased costs, as the increases are offset from an accounting perspective by the creation of a regulatory asset that would likely be recovered through customer rates in the future. Once the commission determines, typically in the company's next rate case, that the costs were prudently incurred and are "extraordinary" in nature, recovery will generally take place over a multiyear period and the commission may or may not permit the utility to earn a return on the unamortized balance during the recovery period. However, these deferrals do nothing to mitigate any cash flow constraints that might exist.

State utility commissions have approved the use of deferral techniques for various costs in recent years, perhaps most prominently for costs incurred to restore service after large storms. On a basic level, many utilities' fuel and gas commodity cost adjustment clauses account for differences in such costs, relative to base levels, in "balancing accounts," and these types of deferrals, although not necessarily for costs that are extraordinary in nature, are ultimately recovered through the next rate adjustment under the clause. Deferral treatment has also been accorded other types of costs, including those associated with pension plans, participation in a regional transmission organization, regulatory and compliance-related requirements, and distribution infrastructure maintenance.

For example, in Indiana, the state's transmission, distribution and storage system improvement charge ratemaking paradigm allows for certain infrastructure-related costs not recoverable under a semiannual rate rider to be deferred for inclusion in a future base rate proceeding. In Missouri, utilities are permitted to defer for future recovery 85% of the depreciation expense and return associated with "qualifying electric plant" investments and, separately, for certain costs related to electric vehicle infrastructure.

In New York, deferral treatment is being used for a variety of costs, including pension and other post-employment benefits expense, variable-rate tax-exempt debt, property taxes, municipal infrastructure support costs and the impact of new laws, and environmental site investigation and remediation. In Ohio, the deferral technique is being used for vegetation management costs. In Virginia, state law allows the gas utilities to defer certain costs related to pipeline safety programs and infrastructure expansion. In West Virginia, utilities can defer incremental operating costs associated with environmental compliance regulations. These examples are by no means exhaustive. Rather, they are intended to demonstrate the extensive use of deferral accounting in utility ratemaking.

Few industry participants ever imagined that similar measures might need to be taken to respond to the effects of a pandemic. However, several jurisdictions have been examining the merits of using deferral treatment to address changes to utility cost profiles due to COVID-19. Given the reluctance of utilities to file rate cases at a time when a broad swath of customers are experiencing hardships and the likelihood that uncollectibles/bad-debt expenses will rise even in jurisdictions where the strategy has generally been to work out payment plans with customers, deferral appears to be the likely alternative that commissions will ultimately choose. Assuming that regulators will want the companies to proceed with robust capital spending programs dedicated to reliability, resiliency, security and the deployment of clean energy resources and related technologies, an alternative recovery method such as securitization may prove to be attractive to address recovery of COVID-19-related deferred asset balances.

Some utilities have also sought and obtained approval to defer lost revenues attributable to COVID-19. However, as the Indiana Utility Regulatory Commission and other commissions have recently demonstrated, this has proven to be more controversial than deferral treatment for costs utilities incur to respond to the pandemic.

"Under the regulatory compact, at a base level, utilities are obligated to provide safe, reliable service and customers are obligated to pay just and reasonable rates for any such service they receive. ... [A]sking customers to go beyond their obligation and pay for service they did not receive is beyond reasonable utility relief based on the facts before us. A utility's customers are not the guarantors of a utility earning its authorized return." - Indiana Utility Regulatory Commission commentary on rejecting proposals to defer COVID-19 lost revenues, Cause Nos. 45377/45380.

On the other hand, regulatory liabilities are created for amounts that are likely to be returned to ratepayers at a later date. Perhaps the most prominent regulatory liability utilities have recorded over the past couple years stems from federal tax reform. Accumulated deferred income taxes, or ADIT, arise from the tax timing differences created by the alternate depreciation calculation methodologies. The utility is essentially collecting, at present, a portion of the tax liability it will owe at some point in the future, and these "cost-free" funds need to be accounted for. ADIT can be accounted for as a reduction to rate base, as is the case in most jurisdictions, or as a source of zero-cost capital in the rate-of-return calculation.

Following the 2018 reduction in the corporate income tax rate from 35% to 21%, utility financial statements were showing ADIT balances that were too high. In most circumstances, utilities have been required to establish regulatory liabilities for the "excess" balances, with these amounts to be returned to ratepayers over an extended period of time. The time period for recovery varies with certain types of excess ADIT balances required to be returned to ratepayers over the lives of the underlying assets per accounting standards and others returned to ratepayers over a shorter period of time determined by regulators. In most instances the utilities were also required to defer the "excess" revenue they were collecting on an ongoing basis because of the lower tax expense, until rates were implemented to reflect the lower federal corporate income taxes.

Regulatory Research Associates, a group within S&P Global Market Intelligence, notes that deferrals also come into play for companies that have a revenue decoupling mechanism in place. A decoupling mechanism essentially allows the utility to defer fixed costs that it fails to recoup through volumetric charges due to customers' participation in conservation programs, weather fluctuations or altered economic conditions, changes in demographics or even the departure of a large customer. The utility is then allowed to recover the deferrals associated with the unrecovered fixed costs through a mechanism over a period of time, generally with carrying charges on the deferred balance.

Case study

Fictitious Power and Light Co., or FP&L, serves electric customers in Utopia and is rate-regulated by the Utopia Public Service Commission. The company's territory was affected by two significant storms over the past year or so, namely a tropical storm in July 2019, and an ice storm in January 2020. FP&L promptly sought permission to defer the costs it incurred to restore power after both storms, and the commission approved the requests in August 2019 and March 2020. The PSC allowed the company to defer for possible future recovery $7.7 million of costs associated with the tropical storm and an additional $4.9 million of costs tied to the ice storm.

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The PSC's deferral orders did not allow FP&L to amend its rates to account for the deferrals at that time; rather, the commission's actions permitted the company to refrain from recording the restoration expenses during the periods in question, effectively preventing the company from experiencing an adverse earnings impact from the storms in 2019 and 2020.

FP&L filed a base rate case on Aug. 1, 2020, and sought to address the deferred storm costs in the case. As shown in table 1, FP&L proposed to begin recovering the aggregate $12.6 million of deferred costs.

Since the PSC has historically used a seven-year amortization period for other utilities' deferral requests, FP&L opted to use the same period, resulting in a $1.8 million annual amortization adjustment. In this instance, no carrying charges were recorded on the deferred balance. However, in many circumstances utilities are allowed to earn a return on deferred amounts, typically using a weighted average cost of capital.

This is typically accomplished by including the unamortized balance in rate base. As RRA noted in a Topical Special Report titled "Rate base: how would you rate your knowledge of this utility industry fundamental?" for electric utilities doing business in non-restructured jurisdictions, rate base includes the net value of investments in generation, transmission and distribution infrastructure. In states that have restructured their electric markets and where the generation supply is now competitively procured, the generation assets are no longer included in the rate base calculation. For gas utilities, rate base includes the pipes and mains that are used in the provision of distribution service. But when it comes to valuing rate base, many other items can be included in or used to offset the net value of the utility’s plant and equipment. Regulatory assets are often included in the rate base calculation.

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To many utility industry practitioners, it may not be clear how this $1.8 million figure is ultimately reflected in the utility's rates. As RRA pointed out in a recent Topical Special Report titled "The rate case process: a conduit to enlightenment," a utility's revenue requirement is equal to the product of its rate of return and its rate base, plus its operating expenses, depreciation and taxes.

Table 2 shows that FP&L's net operating income under existing rates, as per the company's rate case application, is $17.1 million and the $1.8 million amortization adjustment for the deferred storm costs is captured here. All else being equal, the company says the storm cost amortization, absent any approved rate change, effectively reduces its net operating income for the test period, which in this case is the 12 months ended March 31, 2020.

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It is important to note that only the storm cost deferral adjustment is shown in table 2, although the "proposed, as adjusted" column incorporates all net operating income, or NOI, adjustments put forth by the company.

As highlighted in the rate case process report, the accompanying expression is the common formula for calculating a rate change, which in industry-speak means the incremental I meant revenue the utility is proposing, or that an intervenor is recommending or that the commission is authorizing.

The equation has three variables — or four, if the tax factor is considered — and these variables are shown with an asterisk; everything else is the result of plugging the appropriate variable into the equation.

In simple terms, the commission reviews the company's revenue and prudent costs for the selected test year and considers the resulting NOI for that period.

If the company's NOI is determined to be inadequate, a rate increase is authorized. Conversely, if the NOI is found to be too high, a rate reduction can be ordered.

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Table 3 includes detailed figures pertaining to FP&L's base rate change request. As noted earlier, a utility's revenue requirement reflects the product of its rate of return and its rate base, plus its operating expenses, depreciation and taxes.

However, the process must shift to the determination of the rate change that is required so that the company can collect its total revenue requirement.

In this example, FP&L has compared its required NOI, per the company's rate of return and rate base calculations, to the $17.1 million actual NOI figure for the test period.

The difference, grossed up to arrive at a top-line rate change figure, includes the amortization amount for the two storms.

In this case, the company is seeking a $55.6 million base rate increase that is also shown in Table 4. The proposed rate increase would allow the company to earn its requested 6.15% overall return on its requested $947.4 million rate base.

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If the PSC ultimately finds the storm restoration costs to be prudent and worthy of being included in FP&L's rates, the company's revenue requirement will include the amortized amount for the storm costs once new rates take effect.

Future storms that roll through FP&L's territory would presumably be treated in a similar manner by the PSC, as commissions usually look for precedent in making important ratemaking decisions like this.

For a full listing of past and pending rate cases, rate case statistics and upcoming events, visit the S&P Global Market Intelligence Energy Research Home Page.

For a complete, searchable listing of RRA's in-depth research and analysis, please go to the S&P Global Market Intelligence Energy Research Library.

This article was published by S&P Global Market Intelligence and not by S&P Global Ratings, which is a separately managed division of S&P Global.

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