Why Regulators Should Replace Electric Utility Rate Base

It is time to examine why regulators should change traditional rate-making regulation. More than sixty years ago, the United States adopted an approach to regulation known as cost-of-service (COS) regulation. The primary regulatory revenue determinant under COS is known as rate base, which is the original amount investor-owned utilities invested, less accumulated depreciation.

Regulated earnings and many of the annual revenue requirements are determined through a mechanism that provides an opportunity for IOUs to recover what is called a return on and of the rate base. Given the formula-driven COS regulation, IOUs do not earn any specific returns on the services they provide. 

Utility income and returns depend on rate base and in some states on hybrids such as performance-based regulation or PBR.¹ Some states also adjust regulated prices in response to fuel and purchase power costs, as well as deviations between actual and forecasted sales. These do not affect earnings because typically there are no mark-ups on fuel or purchase power.

The historic growth in rate base was tied to generating stations that IOUs built and owned. Some generating units are now being retired for a combination of economic and political reasons. Other utility-owned and operated generating stations are being displaced or replaced with purchases in competitive wholesale markets and purchase power agreements.

New generating stations are being built by non-regulated utility affiliates that plan to either sell electricity into wholesale markets and/or longer term PPAs. Utility sales are also lagging in much of the country.

IOUs were regulated because a regulated monopoly would avoid duplication and achieve economies of scale. Utilities were authorized franchise monopoly rights over their distribution network. The exclusive franchise authorization to either sell electricity to retail customers or to build new generation to serve an IOU's load has been eroding.

There are twenty-three regulatory jurisdictions that have replaced the vertically integrated utility/regulatory model with some degree of wholesale and/or retail competition. In a number of restructured states all or some retail customers are free to switch energy suppliers. Mostly, the utility continues to provide partial services.

The IOUs retain distribution, transmission and customer services like meter reading, billing and emergency response. Customers that eschew utility-supplied electricity cause regulators to balance the interests of remaining and departing customers. The recovery of rate base and related earnings using traditional COS methods are mostly ill-suited for customers that secure their electricity elsewhere.

Some states, such as Nevada and California, continue to regulate most retail sales of electricity. However, they permit larger customers and communities to pay exit fees that enable the departing load either to purchase electricity directly from non-utility suppliers or to invest in their own generation equipment. The loss of utility direct sales eventually will result in early retirements that reduce rate base and reduce future utility investments in generation added to rate base.

New Customer Choices

New technologies are lowering costs and helping to bring new products and services into the electricity market. A growing number of retail customers are responding, and IOUs are losing sales.

The new products include distributed energy resources (DER), conservation and energy efficiency, other demand-side investments that customers make, and storage on customers' premises, reducing the need for IOUs to invest in generation. These alternative energy sources effectively make the retail customers that invest in them what are called partial requirements customers of the IOU.

DER investments are mostly being added on customers' premises, which in the case of small volume customers often means photovoltaic solar panels on their rooftops. Indeed, all forms of solar generation are expanding, including third-party, community-owned, and utility-owned solar powered systems, because the costs of adding PV systems are sharply declining.

Wind power is also being added on customers' premises by third parties and utilities. If customers own and dispatch wind and solar to the grid, they present reliability challenges, as well as transforming former full-service retail customers into partial requirements customers that purchase backup utility-supplied electricity.

Energy efficiency, conservation and demand-side management can have similar results. Customers are investing on their side of the meter. Often IOUs lose sales, and their costs may increase. However, retail customers that secure these services typically pay less.

Customer-owned storage is also becoming more affordable. If storage is tied a hundred percent to rooftop solar, customer-owned storage is also eligible for the solar tax credit provisions in the federal tax code.

However, if the utility does not control dispatch, reliability and other costs for utilities may increase with more storage, because uncertainty may increase. Customers who own the storage save money and society likely benefits; however, IOUs and their remaining full requirements customers likely pay more, due to uncertainty in the timing of storage use.

Regulators must address decreasing utility sales, higher reliability and back-up costs and claims that some existing rate base is no longer used and useful. Any attempts to increase prices for customers that embrace and invest in the socially desirable DER and demand-side improvements will run into pushback. Also, there will be opposition to any regulatory attempts to pass on departing load costs, including lost sales, to the remaining full-service retail customers.

Unintended Consequences

Rate base regulation can also establish incentives to build and operate things, which can cause utilities to behave in an inefficient and perverse manner. Consider a business that is not regulated with rate base COS.

Management would compare leasing facilities and purchasing goods as needed without being pushed to build, own and operate facilities in order to grow rate base and increase earnings. Sometimes it is simply less expensive to purchase things from others rather than to invest capital.

Regulated utilities would not earn a return margin or income when they purchase and pass through the costs to their customers. However, investing to accomplish the same things, such asoffice space and electricity sold to retail customers, expands rate base and earnings.

Tax treatment of investments can also become a regulatory challenge. Most regulated utilities keep two sets of books for their financial statements. Regulators typically rely on straight-line depreciation, an equal deduction of the original investment annually, to spread the recovery of invested capital over the life of the utility-owned assets placed in rate base.

Federal taxes are often used to keep the overall economy in high gear. Previously, this would have meant the use of accelerated depreciation to reduce income taxes in the years immediately following capital investments.

The most recent tax changes in the Tax Cut and Jobs Act of 2017 permit expensing capital investments, which can be viewed as accelerated depreciation on steroids. Regulators typically track differences between actual tax depreciation and regulatory depreciation.

The latter typically reflects much slower cost recovery because regulators use straight-line or constant annual depreciation of rate base over an asset's economic life. Many jurisdictions also take steps to ensure that the benefits of favorable federal tax treatment related to accelerated cost recovery will inure to the benefit of retail customers.

This is not always easy, because federal tax rates and depreciation rules change over time. Under the 2017 tax changes, regulatory balancing of differences will become more complex.

Consider the utility that invests compared to the utility that leases or purchases. Federal taxes would now treat both choices as expenses. Utilities that acquire generation either through affiliates or in the market would pass through costs that competitive markets effectively regulate.

However, under current regulation, regulated utilities would not be authorized to earn a markup on the goods and services they purchase as needed. Regulators will need to account for a greater disparity between the two sets of accounting books.

Regardless of regulatory accounting complexity, the rate base model of COS regulation will remain under significant pressure from competition. IOUs are also often prohibited from direct competition out of fear they might use captive customers' contributions to earnings from rate base to subsidize the utility's competitive offerings.

Community-based DER investments face pushback because many departing customers do not want to purchase energy from a monopoly, even a regulated one. Increasingly, utilities are forced to develop utility-scale DER investments and similar programs.

Many utilities prefer to make these DER investments outside the regulated rate base COS. Instead, they often invest using unregulated affiliates that sell the electricity either directly to the utility, to departing customers, or through wholesale markets.

Societal Benefits and Regulatory Challenges

The current utilities' challenges are very significant because most regulators, political officeholders and many customers want to utilize energy efficiency, rooftop solar, and customer choice. Utilities are viewed as opposing these things, because they largely undermine utility rate base expansion and reduce earnings.

The nation benefits from energy efficiency, load management, and renewable distributed energy. Increasing numbers of customers also want to be able to choose the competitive alternative that supplies the electricity they consume. New customers who plan major expansions often seek pre-approval to secure their own electricity supplier and effectively seek partial utility status.

Customers that depart and become partial requirements customers should expect to pay the costs for the residual services the utility continues to supply. This requires regulators to unbundle the remaining utility services for departing customers. Unbundling would also require cost assignments to be transparent. 

The most direct approach would be for IOUs that provide unbundled services to partial requirements consumers to mark up the costs of the goods or services sold (COGS). This would eliminate the need for utilities to rely on rate base earnings and avoid endless debates about who should pay what.

Regulators should pay close attention to any lost income, fixed cost recovery or margins when new customer-driven choices replace traditional integrated or full-service electricity sales. Regulators, and perhaps legislators, should seek to limit their treatment of such matters to their initial decisions, and work to not re-open them over time.

There are two broad potential fixes. The rate base can expand, if IOUs invest in new renewable energy projects or services that reduce demand or shift times of use. It may also be reasonable to convert leases and PPAs to a capitalized value that could be included in rate base and earn income.

An alternate approach, discussed below, would focus on the costs of goods sold for specific unbundled services that utilities provide, and not simply the amount they invest. This approach would authorize utilities to earn a margin or markup on the COGS that utilities typically secure from others and resell. The retail mark-up or margin approach would be transparent and alleviate some of the other regulatory challenges to the related rate base.

A Pragmatic Alternative to Rate Base COS

Rate base does not work for unbundled services the utility provides to the expanding class of partial requirements customers. Unbundling is especially problematic when customers are asked to pay for services formerly fully bundled into electricity service.

Utilities retain a duty to deliver reliable electricity to end users. Regulators must balance things when some customers eschew full service and choose delivery and perhaps some form of back-up energy service.

It is not enough to simply charge customers the utilities' out of pocket costs for the services rendered, when an increasing number of customers are choosing not to take fully integrated energy supply and delivery from their regulated utility.

Utilities should have an opportunity to earn a just and reasonable return. Utility earnings do not need to be derived from their rate base. An alternate approach could be based on marking up the COGS.

Regulators generally recognize that one group of customers should not subsidize other customers unless the subsidies paid benefit the customers paying the subsidy by at least the amount paid.

In determining the relative amount each customer group pays, it is important to include a markup or margin on the out-of-pocket costs for less than the full requirements services rendered. Put more positively, when customers choose a partial list of utility services, they should pay for COGS and a markup that provides net income to the utility for the unbundled services provided to partial requirements customers.

Attaching a margin to the COGS for each unbundled service would supplant rate base COS regulation for departing load and the associated services. Tariffs would need to change for at least the departing or partial requirements customers. Transparency would support doing something similar for the remaining full-service customers. However, this might not be politically sound or necessary.

The emerging focus would be on margins on sales and margins on cost of goods sold. The former is a markup or margin applied to the full retail purchase price.

The second is a markup of the cost of goods sold, which for an energy services company would include the energy and perhaps the delivery charges for distribution and transmission that would be passed through to the consumer.

The primary regulatory question is how to establish margins for unbundled services. It is important to identify firms and industries that are comparable financially, have risks and have a similar retail customer service focus. They should have much more in common with firms such as energy service companies that buy or secure electricity in competitive wholesale markets and resell electricity to retail consumers.

An approach for establishing a just and reasonable markup would be to select a sample of a comparable firm. This would likely involve hearings to determine the industries that have similar risks to the ones the utility services provided.

Firms securing electricity at wholesale for the purposes of reselling to retail customers are similar to other "buy/resell" firms that sell goods and services. Four factors would likely emerge as useful screens to select comparable firms or industries in the determination of a regulated return margin (RM): the importance of marketing, packaging and related skills and functions; an industry's turnover ratio (TOR) of sales to total assets; financial leverage or debt to equity ratios: and how much risk the seller or customers absorb, such asprice indexing.

An alternate approach would start with how regulation currently determines an authorized return on equity (ROE). Regulators could utilize what is known as the DuPont Method to derive an after-tax return margin (RM) in a manner that is consistent with the way they determine the authorized after-tax ROE.

The following DuPont formula could be used to determine a reasonable return margin. The inputs are: authorized after-tax Return on Equity (ROE), Percent Equity (Equity / Assets), Turn Over Ratio (TOR) (Sales / Assets), and Debt Burden ((Earnings Before Interest and Taxes (EBIT) less Tax and Interest / (EBIT - Tax)).

The basic after-tax RM formula under the DuPont Method is: Return Margin=ROE / (Percent Equity X TOR X Debt Burden)

In symbols, see Figure 1.

A new return margin approach for regulating utility services would focus on markups of the cost of goods sold or sales price. This would replace the return on rate base investments. The return margin would reflect both return and profit, as well as the elements of risk not recovered from retail customers elsewhere with explicit cost-of-service adders.

The return margin can be determined directly by selecting comparable firms and industries to impute the RM or using the DuPont Method to derive RM after a regulatory finding of an authorized ROE and capital structure. Both approaches might be useful for establishing an authorized RM, much as alternate approaches are currently used to determine ROE.

Conclusion

Energy efficiency and DER services that IOUs provide and any electricity secured in wholesale markets or from PPAs would be treated as retail services that earn a return margin. Reliability and storage services should also become services for which IOUs can earn a return margin.

Regulators could apply the RM to either the cost of goods sold or sales prices.

In summary, regulated utilities should expect to earn profit margins when, like competitive firms, they supply DER, energy efficiency and electricity to retail customers, storage and reliability services to partial requirements customers.

Consumers would come to expect to pay a markup for wholesale/retail energy and other services sold. Businesses such as grocery stores, department stores, restaurants and sports or entertainment venues are predicated on a retail mark-up.

Customers have other choices. Utilities would no longer seek to assign revenue requirements to retail customers that do not purchase the newly defined unbundled services.

If rate base no longer works, it is time to consider alternatives. In competitive markets, if retailers, regulated or not, are to stay in business, they must recover a profit margin. A return margin approach such as the one proposed here could offer one of two paths. The retailer could look to margins in other retail-oriented competitive industries to establish a reasonable sales margin for energy service companies, or they could continue to use the authorized ROE to determine an authorized return margin on unbundled services.

Endnote:

1. PBR varies across the nation. However, it often adjusts the authorized returns on rate base when electric companies achieve specific things that regulators authorize.